Method and device for determining size of oil pipe leakage point

Abstract

The invention discloses a method and a device for determining the size of a leakage point of an oil pipe. The method comprises the steps that pressure change information of an oil pipe of a target gas well and pressure change information of a casing pipe of the oil pipe in a plugging state and a releasing state are obtained respectively, and a target well section containing a leakage point in the oil pipe is determined according to the pressure change information of the oil pipe and the pressure change information of the casing pipe; target pressure states of the oil pipe at a plurality of target positions in the target well section are obtained, and local leakage point sizes corresponding to the leakage points in the oil pipe at the target positions are determined according to the target pressure states; and determining the target leakage point size corresponding to the leakage point in the oil pipe according to the local leakage point sizes determined at the plurality of target positions, thereby comprehensively and accurately evaluating the severity and the distribution condition of the leakage point, improving the reliability and the precision of leakage point detection, optimizing the maintenance scheme, reducing the maintenance cost, and improving the detection efficiency. And safe and efficient operation of the oil-gas well is ensured.

Description

Technical Field

[0001] This invention relates to the field of gas well exploration technology, and in particular to a method and apparatus for determining the size of a leak in an oil pipe. Background Technology

[0002] As gas wells age, corrosion can cause leaks in the tubing, leading to connections between the tubing and casing. In severe cases, this can result in tubing rupture, causing debris to fall into the well and ultimately hindering gas well production or rendering the well unusable. Therefore, detecting and locating tubing leaks is a crucial task in the daily management and maintenance of oil and gas wells.

[0003] In related technologies, leak detection often relies on experience-based judgment and simple pressure tests, which are not only inaccurate but also complex and costly to operate. Furthermore, the detection methods in these technologies struggle to accurately determine the specific location and size of leaks, leading to low repair efficiency and high repair costs. Summary of the Invention

[0004] This invention provides a method and apparatus for determining the size of a leak in an oil pipe, thereby solving the problems of complex operation and low accuracy in locating and determining the size of leaks in related technologies.

[0005] According to one aspect of the present invention, a method for determining the size of a leak point in an oil pipe is provided, the method comprising:

[0006] The pressure change information of the tubing and casing of the target gas well in the plugged and released states is obtained respectively. Based on the pressure change information of the tubing and casing, the target well section containing the leak point in the tubing is determined.

[0007] The target pressure status of the tubing at multiple target locations within the target well section is obtained respectively, and the size of the local leak point corresponding to the leak point in the tubing at the target location is determined based on the target pressure status;

[0008] The target leak size corresponding to the leak in the tubing is determined based on the local leak size determined at multiple target locations.

[0009] According to another aspect of the present invention, an apparatus for determining the size of a pipe leak is provided, the apparatus comprising:

[0010] The leak point well section determination module is used to acquire pressure change information of the tubing and casing of the target gas well in the plugged and released states, respectively, and determine the target well section containing the leak point in the tubing based on the pressure change information of the tubing and casing.

[0011] The local leak point size determination module is used to obtain the target pressure status of the tubing at multiple target locations within the target well section, and determine the local leak point size corresponding to the leak point in the tubing at the target location based on the target pressure status.

[0012] The target leak size determination module is used to determine the target leak size corresponding to the leak in the oil pipe based on the local leak size determined at multiple target locations.

[0013] According to another aspect of the present invention, an electronic device is provided, the electronic device comprising:

[0014] At least one processor; and

[0015] A memory communicatively connected to the at least one processor; wherein,

[0016] The memory stores a computer program that can be executed by the at least one processor, which enables the at least one processor to perform the method for determining the size of a leak in an oil pipe according to any embodiment of the present invention.

[0017] According to another aspect of the present invention, a computer-readable storage medium is provided, the computer-readable storage medium storing computer instructions for causing a processor to execute and implement the method for determining the size of a leak in an oil pipe according to any embodiment of the present invention.

[0018] According to another aspect of the present invention, a computer program product is provided, the computer program product comprising a computer program that, when executed by a processor, implements the method for determining the size of an oil pipe leak point as described in any embodiment of the present invention.

[0019] The technical solution of this invention firstly acquires pressure change information of the tubing and casing of the target gas well in both plugged and released states. Based on this pressure change information, the target well section containing the leak in the tubing is determined, allowing for precise location of the leak. Next, by acquiring the target pressure state of the tubing at multiple target locations within the target well section and determining the local leak size corresponding to the leak at each target location, the local leak size at each target location can be accurately determined. This enables precise location and quantitative assessment of leaks. Finally, by determining the target leak size in the tubing based on the local leak sizes identified at multiple target locations, the target leak size in the tubing can be determined. This allows for a comprehensive and accurate assessment of the severity and distribution of leaks, solving the problems of low accuracy, complex operation, and high cost in leak location and size determination in related technologies. It enables a comprehensive and accurate assessment of the severity and distribution of leaks, improves the reliability and accuracy of leak detection, optimizes maintenance plans, reduces maintenance costs, and ensures the safe and efficient operation of oil and gas wells.

[0020] It should be understood that the description in this section is not intended to identify key or essential features of the embodiments of the present invention, nor is it intended to limit the scope of the invention. Other features of the invention will become readily apparent from the following description. Attached Figure Description

[0021] To more clearly illustrate the technical solutions in the embodiments of the present invention, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the accompanying drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0022] Figure 1 This is a flowchart of a method for determining the size of an oil pipe leak point according to Embodiment 1 of the present invention;

[0023] Figure 2 This is a flowchart of a method for determining the size of an oil pipe leak point according to Embodiment 2 of the present invention;

[0024] Figure 3 This is a flowchart of a method for determining the size of an oil pipe leak point according to Embodiment 3 of the present invention;

[0025] Figure 4 This is a schematic diagram of a device for determining the size of an oil pipe leak according to Embodiment 3 of the present invention;

[0026] Figure 5This is a schematic diagram of the structure of an electronic device that implements the method for determining the size of an oil pipe leak point according to an embodiment of the present invention. Detailed Implementation

[0027] To enable those skilled in the art to better understand the present invention, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings of the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort should fall within the scope of protection of the present invention.

[0028] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings of this invention are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments of the invention described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, system, product, or apparatus that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or apparatus.

[0029] It should be noted that the terms "a" and "a plurality of" used in this disclosure are illustrative rather than restrictive, and those skilled in the art should understand that, unless otherwise expressly indicated in the context, they should be understood as "one or more".

[0030] The names of messages or information exchanged between multiple devices in the embodiments of this disclosure are for illustrative purposes only and are not intended to limit the scope of such messages or information.

[0031] It is understood that before using the technical solutions disclosed in the various embodiments of this disclosure, users should be informed of the types, scope of use, and usage scenarios of the personal information involved in this disclosure in an appropriate manner in accordance with relevant laws and regulations, and user authorization should be obtained.

[0032] For example, upon receiving a user's active request, a prompt message is sent to the user to explicitly inform them that the requested operation will require the acquisition and use of the user's personal information. This allows the user to independently choose whether to provide personal information to the software or hardware, such as the electronic device, application, server, or storage medium performing the operations of this disclosed technical solution, based on the prompt message.

[0033] As an optional but non-limiting implementation, in response to a user's active request, sending a prompt message to the user can be done via a pop-up window, where the prompt message can be presented in text format. Furthermore, the pop-up window can also include a selection control allowing the user to choose "agree" or "disagree" to provide personal information to the electronic device.

[0034] It is understood that the above notification and user authorization process are merely illustrative and do not constitute a limitation on the implementation of this disclosure. Other methods that comply with relevant laws and regulations may also be applied to the implementation of this disclosure.

[0035] It is understood that the data involved in this technical solution (including but not limited to the data itself, the acquisition or use of the data) shall comply with the requirements of relevant laws, regulations and related provisions.

[0036] Example 1

[0037] Figure 1 The flowchart of a method for determining the size of a pipe leak point is provided in Embodiment 1 of the present invention. This embodiment is applicable to the location of pipe leak points and the determination of the size of the leak points. The method can be executed by a device for determining the size of the pipe leak point. The device for determining the size of the pipe leak point can be implemented in hardware and / or software. Optionally, it can be implemented by an electronic device, such as a mobile terminal, a PC, or a server.

[0038] like Figure 1 As shown, the method may specifically include:

[0039] S110. Obtain pressure change information of the tubing and casing of the target gas well in the plugged and released states respectively, and determine the target well section containing the leak point in the tubing based on the pressure change information of the tubing and casing.

[0040] The target gas well can be understood as the gas well where the size of the leak in the tubing is determined. The target gas well can be a borehole used to extract natural gas from underground reservoirs. The tubing can be understood as a pipe extending from the surface to the producing formation in the gas well, used to transport underground oil and gas resources to the surface during production. The casing can be understood as a protective pipe surrounding the tubing, used to support the well wall and provide a closed space for the tubing, protecting it from formation pressure and helping to isolate different formations, preventing corrosion of the tubing by substances in the formation. The plugging state can be understood as temporarily sealing a portion of the casing using mechanical methods to stop fluid flow. It is understood that when detecting leaks, certain sections may be plugged to observe pressure changes. Correspondingly, the release state can be understood as the state where, relative to the plugging state, the plugging of a specific area within the casing is released, allowing fluid to flow freely. The pressure change information can be understood as recording pressure change data inside the tubing and casing in both the plugging and release states. The pressure change information can be used to determine the target well section containing the leak in the tubing. The leak point can be understood as a crack or hole in the tubing, which may lead to oil and gas leakage, affecting production efficiency and potentially causing safety issues. The target well section can be understood as the location of the leak in the tubing, and the leak point can be located by comparing the pressure changes in the tubing and casing under sealed and released conditions.

[0041] Based on the above scheme, optionally, the step of acquiring pressure change information of the tubing and casing of the target gas well in the plugged and released states, and determining the target well section containing the leak in the tubing based on the pressure change information of the tubing and casing, may include: plugging the tubing at at least one location in the tubing of the target gas well using a plugger; acquiring the tubing plugging pressure and casing plugging pressure of the tubing in the plugged well section; releasing gas in the plugged tubing area to acquire the tubing release pressure and casing release pressure of the tubing in the plugged well section; determining the tubing pressure change information of the tubing based on the tubing plugging pressure and tubing release pressure; and determining the casing pressure change information of the casing based on the casing plugging pressure and casing release pressure; and determining the target well section containing the leak in the tubing based on the plugged well section and the corresponding tubing pressure change information and casing pressure change information.

[0042] The plugging device can be understood as a tool used to seal a portion of a gas well. It is understood that when detecting leaks, the plugging device can be placed at a specific location in the tubing to create a closed test area. The tubing sealing pressure can be understood as the internal pressure of the tubing measured in the sealed section after the tubing is sealed, reflecting the pressure state of the fluid within the sealed area. The casing sealing pressure can be understood as the internal pressure of the casing measured when the tubing is sealed. The tubing release pressure can be understood as the internal pressure of the tubing measured after the tubing is unsealed. Correspondingly, the casing release pressure can be understood as the internal pressure of the casing measured after the tubing is unsealed.

[0043] For example, the process of identifying a target well section containing a leak in the tubing may specifically include:

[0044] First, well cleaning. When performing well cleaning operations, the appropriate well cleaning gauge should be selected based on the inner diameter of the tubing. First, install the blowout preventer at the wellhead, then lower the well cleaning gauge to begin cleaning. If resistance is encountered, record the location of the resistance and replace the gauge with a smaller size to continue cleaning. If resistance is encountered again, continue replacing the gauge with an even smaller size until well cleaning is successful. In subsequent operations, the maximum outer diameter of the well cleaning gauge lowered should be greater than 110% of the outer diameter of the plug.

[0045] Next, set the plug. After well cleaning, run the plug at the appropriate location and set it, then pull the tool string out of the blowout preventer. Inspect the tool string to confirm the setting. After confirming setting, release the gas from the tubing and observe the pressure changes in the tubing and casing. If the tubing pressure drops to 0 while the casing pressure changes little, it indicates that the tubing section from the wellhead to the setting position is intact.

[0046] Then, unseal the well. Remove the plug from the well, replace it with another pre-determined plug, and repeat the setting and tool string operation. Record the pressure changes in the tubing and casing. Record the pressure changes in the tubing and casing at each pre-determined insertion position.

[0047] Assume the gas reservoir water level is above the tubing and remains constant. After the plug is applied, monitor the pressure release process. If the tubing pressure is 0 and remains constant after unsealing, it indicates there are no leaks in the tubing between the wellhead and the plug depth. If the tubing pressure is not 0 after unsealing, and the casing pressure continues to decrease, it means that after all the gas in the tubing has been expelled, the subsequent gas entering the tubing is a channeling volume.

[0048] The above solution analyzes the pressure changes of the tubing and casing in the gas well under different conditions to identify potential leak locations, effectively locating leakage problems in the gas well and ensuring the safe and efficient operation of the gas well.

[0049] It should be noted that the more times the setting is performed, the higher the accuracy of the determined oil pipe leak size. However, considering the cost of setting, in practical applications, the number of setting operations can be determined based on actual needs.

[0050] For example, the accuracy of the tubing leak size can be determined using the following formula:

[0051] μ = H / 2 n ;

[0052] Where μ represents the accuracy of the determined tubing leak size, n represents the number of times the tubing was set, and H represents the tubing depth at which the tubing was set.

[0053] As an optional implementation of this invention, in the process of determining the target well section containing the leak in the tubing, the blocking location of the gas well can be determined by a binary method to quickly locate the target well section. For example, a gas well with a depth of 3000 meters can be first sealed at a depth of 1500 meters.

[0054] As another optional implementation of this invention, when multiple plugged well sections are found to have leaks, and if the first plugged well section among the multiple plugged well sections includes the second plugged well section (i.e., there are two nested plugged well sections among the multiple plugged well sections with leaks), the target well section among the two nested plugged well sections is determined based on the target leak size corresponding to the first plugged well section and the second plugged well section. Specifically, the size difference between the target leak sizes corresponding to the first plugged well section and the second plugged well section is determined; if the size difference is within a preset error range, the second plugged well section is determined as the target well section; if the size difference is not within the preset error range, the first plugged well section is determined as the target well section.

[0055] For example, a gas well at a depth of 3000 meters can be initially sealed at a depth of 1500 meters. If a leak is found in the 0-1500 meter depth range, it can then be sealed at a depth of 750 meters. If no leak is found in the 0-750 meter depth range, the 750-1500 meter depth range can be designated as the target well section. If a leak is found in the 0-750 meter depth range, the size of the first target leak for the 0-1500 meter depth range and the size of the second target leak for the -750 meter depth range can be determined. If the difference between the first and second target leak sizes is small, the 0-750 meter depth range can be designated as the target well section; if the difference is large, the 0-1500 meter depth range can be designated as the target well section. Of course, after the target well section is determined, it can be set at different depths, for example, at 375 meters, to further determine a more precise target well section.

[0056] S120. Obtain the target pressure status of the tubing at multiple target locations within the target well section, and determine the size of the local leak point corresponding to the leak point in the tubing at the target location based on the target pressure status.

[0057] The multiple target locations can be understood as locations corresponding to multiple depth values ​​within a target well section. These multiple target locations can be determined based on information such as a preset depth interval between every two adjacent target locations and / or a pre-set total number of target locations to be acquired. The target pressure state can be understood as the pressure state inside the tubing measured at each target location, used to assess the sealing and integrity of the tubing at different locations. The local leak size can be understood as the specific size of the leak determined at each target location, typically expressed as area or diameter. Determining the local leak size helps assess the severity of the leak at that location. It is understood that the specific size of the leak can be determined by analyzing pressure changes at the target location. Generally, larger leaks may lead to a larger pressure drop, while smaller leaks may lead to a smaller pressure drop.

[0058] S130. Determine the target leak size corresponding to the leak in the oil pipe based on the local leak size determined at multiple target locations.

[0059] The target leak size can be understood as the overall size of the leak in the tubing, determined by combining the sizes of local leaks at multiple target locations. The target leak size reflects the severity and extent of the leak in the tubing. For example, the target leak size includes the equivalent diameter and / or equivalent area of ​​the leak.

[0060] Based on the above solution, optionally, determining the target leak size corresponding to the leak in the tubing based on the local leak size determined at multiple target locations includes: determining the median, mode, average, or maximum value of the local leak sizes determined at multiple target locations as the target leak size corresponding to the leak in the tubing. Using this technical solution, the severity and extent of leaks in the tubing can be assessed more accurately, thereby enabling effective repair measures to be taken to ensure the safe and efficient operation of the gas well.

[0061] In one alternative implementation, a well section where leakage may occur is identified, multiple target locations are selected within the target well section, and at each target location, the target pressure state of the tubing is measured, the pressure changes are analyzed, the size of the local leakage point is determined, the sizes of the local leakage points determined at the multiple target locations are sorted, the median or average value is determined, and the determined median or average value is used as the target leakage point size of the leakage point in the tubing.

[0062] The technical solution of this invention firstly acquires pressure change information of the tubing and casing of the target gas well in both plugged and released states. Based on this pressure change information, the target well section containing the leak in the tubing is determined, allowing for precise location of the leak. Next, by acquiring the target pressure state of the tubing at multiple target locations within the target well section and determining the local leak size corresponding to the leak at each target location, the local leak size at each target location can be accurately determined. This enables precise location and quantitative assessment of leaks. Finally, by determining the target leak size in the tubing based on the local leak sizes identified at multiple target locations, the target leak size in the tubing can be determined. This allows for a comprehensive and accurate assessment of the severity and distribution of leaks, solving the problems of low accuracy, complex operation, and high cost in leak location and size determination in related technologies. It enables a comprehensive and accurate assessment of the severity and distribution of leaks, improves the reliability and accuracy of leak detection, optimizes maintenance plans, reduces maintenance costs, and ensures the safe and efficient operation of oil and gas wells.

[0063] Example 2

[0064] Figure 2 This is a flowchart of a method for determining the size of a tubing leak point according to Embodiment 2 of the present invention. Based on the above embodiments, this embodiment further refines how to obtain the target pressure state of the tubing at multiple target locations within the target well section. Optionally, obtaining the target pressure state of the tubing at multiple target locations within the target well section includes: obtaining the inner wall pressure and outer wall pressure of the tubing at multiple target locations within the target well section, and determining the target pressure state of the tubing at the target location based on the inner wall pressure and outer wall pressure. For detailed implementation, please refer to the description of this embodiment. Technical features that are the same as or similar to those in the foregoing embodiments will not be repeated here.

[0065] like Figure 2 As shown, the method may specifically include:

[0066] S210. Obtain pressure change information of the tubing and casing of the target gas well in the plugged and released states respectively, and determine the target well section containing the leak point in the tubing based on the pressure change information of the tubing and casing.

[0067] S220. Obtain the inner wall pressure and outer wall pressure of the tubing at multiple target locations within the target well section, determine the target pressure state of the tubing at the target location based on the inner wall pressure and outer wall pressure, and determine the size of the local leak point corresponding to the leak point in the tubing at the target location based on the target pressure state.

[0068] The pressure on the inner wall of the tubing can be understood as the pressure inside the tubing, specifically the pressure near the leak. Similarly, the pressure on the outer wall of the tubing can be understood as the pressure outside the tubing, specifically the pressure near the leak.

[0069] Based on the above scheme, optionally, obtaining the tubing inner wall pressure and tubing outer wall pressure at multiple target locations within the target well section may include: for each target location within the target well section, determining the tubing inner wall pressure at the target location based on the gas pressure at the wellhead of the target gas well within the annular space formed by the tubing and the casing, the gas density in the tubing, the gravitational acceleration, and the depth information corresponding to the target location; and determining the tubing outer wall pressure at the target location based on the gas pressure at the wellhead of the target gas well within the tubing, the gas density in the tubing, the gravitational acceleration, and the depth information corresponding to the target location.

[0070] The annular space can be understood as the space between the tubing and casing, used to contain fluids or gases. It is understood that pressure changes within the annular space can provide important information when detecting leaks. The depth information can be understood as the vertical distance of the target location relative to the wellhead location, used to determine the influence of the pressure gradient.

[0071] Based on the above scheme, specifically, the pressure on the inner wall of the tubing and the pressure on the outer wall of the tubing can be determined using the following formulas, including:

[0072] p1 = p out +ρgH,p2=p in +ρgH;

[0073] Where p1 represents the pressure inside the tubing wall, p out The pressure of the gas within the annular space formed by the tubing and the casing at the wellhead of the target gas well is represented by ρ, where ρ represents the gas density within the tubing, g represents the acceleration due to gravity, H represents the depth information corresponding to the target location, and p2 represents the pressure on the outer wall of the tubing. in This indicates the pressure of the gas inside the tubing at the wellhead of the target gas well.

[0074] The above method determines the pressure on the inner and outer walls of the tubing at each target location, which helps in analyzing the specific location and size of the leak.

[0075] Based on the above scheme, optionally, the target pressure state includes subcritical flow state and critical flow state, etc. Determining the target pressure state of the oil pipe at the target location based on the pressure on the inner wall of the oil pipe and the pressure on the outer wall of the oil pipe may include: if the ratio of the pressure on the outer wall of the oil pipe to the pressure on the inner wall of the oil pipe is greater than or equal to the critical pressure, determining the target pressure state of the oil pipe at the target location as subcritical flow state; if the ratio of the pressure on the outer wall of the oil pipe to the pressure on the inner wall of the oil pipe is less than the critical pressure, determining the target pressure state of the oil pipe at the target location as critical flow state, wherein the critical pressure is determined based on the gas adiabatic index.

[0076] Based on the above scheme, specifically, the critical pressure can be determined using the following formula:

[0077]

[0078] Where C represents the critical pressure and k represents the gas adiabatic index.

[0079] The critical pressure can be understood as a specific pressure value used to distinguish between subcritical and critical flow states. The critical pressure can be determined based on the gas adiabatic index. The gas adiabatic index can be understood as the specific heat ratio of the gas, i.e., the ratio of the specific heat capacity at constant pressure to the specific heat capacity at constant volume. For example, in the case of natural gas, the value of k is typically between 1.2 and 1.3. The subcritical flow state can be understood as the flow state of the fluid in the nozzle channel when the flow velocity is less than the speed of sound. The subcritical flow state can be determined based on the ratio of the pressure on the outer wall of the tubing to the pressure on the inner wall of the tubing being greater than or equal to the critical pressure. For example, in the subcritical flow state, the fluid velocity is lower than the speed of sound. Correspondingly, the critical flow state can be understood as the flow state of the fluid in the nozzle channel when it is accelerated to the speed of sound. The critical flow state can be determined based on the ratio of the pressure on the outer wall of the tubing to the pressure on the inner wall of the tubing being less than the critical pressure. For example, in the critical flow state, the fluid velocity exceeds the speed of sound.

[0080] The above scheme, based on the calculation formula of critical pressure, can distinguish between subcritical flow state and critical flow state, thereby improving the accuracy and reliability of detection, helping to take timely and effective repair measures, and ensuring the safe and efficient operation of gas wells.

[0081] Based on the above scheme, optionally, when the target pressure state is a subcritical flow state and the target leak size includes the equivalent diameter of the leak, the target leak size corresponding to the leak in the tubing can be determined according to the target pressure state based on the following formula, including:

[0082]

[0083] Where, q sc p1 represents the volumetric flow rate of gas passing through the nozzle under standard conditions, p2 represents the pressure inside the oil pipe, d represents the equivalent diameter of the leak, T1 represents the temperature, and γ represents the pressure outside the oil pipe. g Z1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

[0084] Where, q sc This can be the gas flow rate through the leak point under standard conditions (typically 0°C and 1 atmosphere). Since it is difficult to accurately determine the number of leak points in the target well section and the specific size of each leak point, 'd' can be used to describe the equal diameter of the leak points; that is, all leak points in the target well section are equivalent to leak points with diameter 'd'. The relative density of natural gas can be understood as the ratio of the density of natural gas to the density of air at the same temperature and pressure. For example, the value of the relative density of natural gas can be between 0.5 and 0.7. In some cases, the relative density of natural gas may be greater than 1; for example, the relative density of natural gas from oil fields with high heavy hydrocarbon content or other non-hydrocarbon components may be greater than 1. The natural gas deviation coefficient Z1 can be understood as a value used to correct for ideal gas behavior. It is understood that the gas properties of natural gas differ from those of an ideal gas, and the deviation coefficient Z1 is used to correct for these differences and improve the accuracy of the calculation.

[0085] The above method, by using measured pressure data and other parameters under subcritical flow conditions, determines the relationship between gas volumetric flow rate and pressure ratio, which helps to more accurately assess the severity of leaks and thus take effective repair measures.

[0086] Based on the above scheme, optionally, when the target pressure state includes a critical flow state and the target leak size includes the equivalent diameter of the leak, the target leak size corresponding to the leak in the tubing can be determined according to the target pressure state based on the following formula, including:

[0087]

[0088] Where, q max The maximum gas flow rate through the nozzle is represented by p1, the pressure inside the oil pipe is represented by d, the equivalent diameter of the leak is represented by T1, and the temperature is represented by γ. gZ1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

[0089] The above method, by using measured pressure data and other parameters under critical flow conditions, determines the relationship between the maximum gas flow rate and the pressure ratio, which helps to more accurately assess the severity of the leak and thus take effective repair measures.

[0090] S230. Determine the target leak size corresponding to the leak in the oil pipe based on the local leak size determined at multiple target locations.

[0091] The technical solution of this invention obtains the inner wall pressure and outer wall pressure of the tubing at multiple target locations within the target well section, determines the target pressure state (subcritical flow state or critical flow state) at each location, and determines the local leak size based on the target pressure state. By combining the local leak sizes of multiple target locations, the target leak size of the leak in the tubing is determined, which significantly improves the efficiency and safety of oil and gas well maintenance, optimizes the maintenance plan, and reduces maintenance costs.

[0092] Example 3

[0093] Figure 3 The flowchart of a method for determining the size of an oil pipe leak point provided in Embodiment 3 of the present invention is an optional embodiment of the above embodiments. Figure 3 As shown, the method may specifically include:

[0094] For example, gas well X is suspected of having a connection between the casing and tubing, with gas leakage in the tubing. The well is currently in an intermittent production phase, and the recent production pressure of the casing and tubing has shown a trend of rising and falling together, which indicates a connection between the casing and tubing. Therefore, a plugging device is used to locate the connection point (the location of the leak in the tubing) by running a plug into the tubing.

[0095] Step 1: Well Cleaning. Select the appropriate well cleaning gauge based on the inner diameter of the tubing. Choose a well cleaning gauge with an outer diameter of 48mm. Install the blowout preventer at the wellhead and lower the well cleaning gauge. Use the 48mm well cleaning gauge to clean the well to 2500 meters.

[0096] Step 2: After well cleaning, run a plugging device at 2455 meters and set it. Pull out the blowout preventer from the tool string. Inspect the tool string to confirm the setting. After confirming setting, release the gas from the tubing and observe the changes in casing and oil pressure. The tubing pressure increases. After 40 minutes of observation, the casing pressure drops from 2.99 MPa to 2.79 MPa; the oil pressure rises from 0.003 MPa to 1.3 MPa. A leak is found at 0-2455 m.

[0097] Step 3: Retrieve the plug. Pull the plug out of the wellhead and lower it to 1455m. Set the plug. After confirming setting, release the gas in the tubing and observe the changes in casing and oil pressure. The tubing pressure increases. After 40 minutes of observation, the casing pressure drops from 2.99 MPa to 2.79 MPa; the oil pressure rises from 0.003 MPa to 1.3 MPa. A leak is found at the 0-1455m location.

[0098] Step 4: Calculate the diameter of the leak point.

[0099] Since the tubing fluid level was measured at 600m during the insertion of the plug, it is assumed that the gas layer water level is above the tubing and remains constant regardless of changes. After the plug is applied, the pressure release process is monitored. If the tubing pressure is 0 and remains constant after pressure release, then there is no leak in the tubing at the depth of the plug; if the tubing pressure is not 0 after pressure release and the casing pressure continues to decrease, then after the gas in the tubing volume is discharged, the subsequent gas entering the tubing is a crossflow volume. The specific calculation method for the leak diameter includes:

[0100] First, based on the oil-casing pressure difference and the predetermined target well section H, calculate the pressure difference between the two sides of the leak point, i.e., the pressure difference between the oil-casing pipe at the leak point.

[0101] p1 = p out +ρgH,p2=p in +ρgH;

[0102] Where p1 represents the pressure inside the tubing wall, p out The pressure of the gas within the annular space formed by the tubing and the casing at the wellhead of the target gas well is represented by ρ, where ρ represents the gas density within the tubing, g represents the acceleration due to gravity, H represents the depth information corresponding to the target location, and p2 represents the pressure on the outer wall of the tubing. in This indicates the pressure of the gas inside the tubing at the wellhead of the target gas well.

[0103] Furthermore, the pressure state can be determined as subcritical or critical flow using the following formula:

[0104]

[0105] If the above formula is met, it is a critical flow; otherwise, it is a subcritical flow.

[0106] Under subcritical flow conditions, the relationship between volumetric flow rate and pressure ratio is as follows:

[0107]

[0108] Where, q scp1 represents the volumetric flow rate of gas passing through the nozzle under standard conditions, p2 represents the pressure inside the oil pipe, d represents the equivalent diameter of the leak, T1 represents the temperature, and γ represents the pressure outside the oil pipe. g Z1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

[0109] Under critical flow conditions, the relationship between the maximum gas flow rate and the pressure ratio is as follows:

[0110]

[0111] Where, q max The maximum gas flow rate through the oil pipe is represented by p1, the pressure inside the oil pipe wall is represented by d, the equivalent diameter of the leak point is represented by T1, and the temperature is represented by γ. g Z1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

[0112] By tracking and maintaining the discharge flow rate within a small range, the pressure changes in the tubing and casing are kept relatively stable. For different depths H, the pressure is adjusted to a subcritical flow pressure state, thereby determining the equivalent diameter d of the leak point. The median or average of multiple leak point dimensions can be determined as the equivalent diameter of the leak point in the tubing. The calculation results are as follows:

[0113]

[0114]

[0115] The above calculations determine that the equivalent diameter of the leak point within the seepage range is approximately 0.87-0.88 mm. A tubing plug successfully detected a connection point between the tubing and casing (i.e., a tubing leak) between 0 and 1455 m. During wireline drilling, the well fluid level was measured at approximately 600 m. Therefore, preliminary analysis suggests that the tubing-casing connection point is likely between 0 and 600 m, with an equivalent diameter of 0.87-0.88 mm.

[0116] The technical solution of this invention ensures unobstructed wellbore flow through well cleaning operations, avoiding misjudgments caused by wellbore blockage. Then, plugs are inserted at different depths for setting, and pressure changes in the tubing and casing are monitored to determine the specific location of the leak. Multiple setting and unsetting operations improve detection accuracy. After determining the leak location, the equivalent diameter of the leak is accurately calculated by judging subcritical and critical flow states and combining specific flow rate and pressure formulas. This allows for precise location and assessment of leaks in the tubing of oil and gas wells. The operation is simple, reduces detection and maintenance costs, and improves the operational safety and reliability of oil and gas wells.

[0117] Example 4

[0118] Figure 4 This is a schematic diagram of a device for determining the size of an oil pipe leak according to Embodiment 4 of the present invention. Figure 4 As shown, the device includes: a leak point well section determination module 410, a local leak point size determination module 420, and a target leak point size determination module 430.

[0119] The well section leakage point determination module 410 is used to acquire pressure change information of the tubing and casing of the target gas well in the plugged and released states, respectively, and to determine the target well section containing the leakage point in the tubing based on the pressure change information of the tubing and casing; the local leakage point size determination module 420 is used to acquire the target pressure state of the tubing at multiple target locations within the target well section, respectively, and to determine the local leakage point size corresponding to the leakage point in the tubing at the target location based on the target pressure state; the target leakage point size determination module 430 is used to determine the target leakage point size corresponding to the leakage point in the tubing based on the local leakage point sizes determined at multiple target locations.

[0120] The technical solution of this invention firstly involves acquiring pressure change information of the tubing and casing of the target gas well in both plugged and released states using a leak-point well section determination module 410. Based on this pressure change information, the target well section containing the leak in the tubing is determined, enabling precise location of the leak-point. Next, a local leak-point size determination module 420 acquires the target pressure state of the tubing at multiple target locations within the target well section and determines the local leak-point size corresponding to the leak at each target location based on the target pressure state, thus accurately determining the local leak-point size at each target location. The system determines the size of the leak points, thereby enabling precise location and quantitative assessment of the leaks. Finally, the target leak size determination module 430 determines the target leak size corresponding to the leak in the tubing based on the local leak size determined at multiple target locations. This allows for a comprehensive and accurate assessment of the severity and distribution of leaks, solving the problems of low accuracy, complex operation, and high cost in leak location and size determination in related technologies. It also improves the reliability and accuracy of leak detection, optimizes maintenance plans, reduces maintenance costs, and ensures the safe and efficient operation of oil and gas wells.

[0121] Based on the above scheme, optionally, the well section determination module for leak points may include: a plugging pressure acquisition submodule, a release pressure acquisition submodule, a pressure change information determination submodule, and a target well section determination submodule. The plugging pressure acquisition submodule is used to plug the tubing at at least one location in the tubing of the target gas well using a plugger, and acquire the tubing plugging pressure and the casing plugging pressure of the tubing in the plugged section; the release pressure acquisition submodule is used to release gas in the plugged tubing area to acquire the tubing release pressure and the casing release pressure of the tubing in the plugged section; the pressure change information determination submodule is used to determine the tubing pressure change information of the tubing based on the tubing plugging pressure and the tubing release pressure, and to determine the casing pressure change information of the casing based on the casing plugging pressure and the casing release pressure; the target well section determination submodule is used to determine the target well section in the tubing, including the leak point, based on the plugged well section and the corresponding tubing pressure change information and casing pressure change information.

[0122] Based on the above scheme, optionally, the local leak point size determination module may include a target pressure state determination submodule. The target pressure state determination submodule is used to acquire the inner wall pressure and outer wall pressure of the tubing at multiple target locations within the target well section, and determine the target pressure state of the tubing at the target location based on the inner wall pressure and outer wall pressure.

[0123] Based on the above scheme, optionally, the target pressure state determination submodule may include: an inner and outer wall pressure acquisition unit. The inner and outer wall pressure acquisition unit is used to determine, for each target location within the target well section, the inner wall pressure of the tubing at the target location based on the pressure of the gas in the annular space formed by the tubing and the casing at the wellhead of the target gas well, the gas density in the tubing, the gravitational acceleration, and the depth information corresponding to the target location; and to determine the outer wall pressure of the tubing at the target location based on the pressure of the gas in the tubing at the wellhead of the target gas well, the gas density in the tubing, the gravitational acceleration, and the depth information corresponding to the target location.

[0124] Based on the above scheme, optionally, the target pressure state determination submodule may include: a target pressure state determination unit. The target pressure state determination unit is used to determine the target pressure state of the oil pipe at the target location as a subcritical flow state when the ratio of the pressure on the outer wall of the oil pipe to the pressure on the inner wall of the oil pipe is greater than or equal to the critical pressure; and to determine the target pressure state of the oil pipe at the target location as a critical flow state when the ratio of the pressure on the outer wall of the oil pipe to the pressure on the inner wall of the oil pipe is less than the critical pressure, wherein the critical pressure is determined based on the gas adiabatic index.

[0125] Based on the above scheme, optionally, the target pressure state determination unit can determine the critical pressure based on the following formula:

[0126]

[0127] Where C represents the critical pressure and k represents the gas adiabatic index.

[0128] Based on the above scheme, optionally, the target leak point size includes the equivalent diameter of the leak point; the target pressure state includes a subcritical flow state; the target leak point size corresponding to the leak point in the tubing can be determined based on the target pressure state according to the following formula, including:

[0129]

[0130] Where, q sc p1 represents the volumetric flow rate of gas passing through the nozzle under standard conditions, p2 represents the pressure inside the oil pipe, d represents the equivalent diameter of the leak, T1 represents the temperature, and γ represents the pressure outside the oil pipe. g Z1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

[0131] Based on the above scheme, optionally, and wherein the target leak size includes the equivalent diameter of the leak; and the target pressure state includes the critical flow state, the target leak size corresponding to the leak in the tubing can be determined based on the target pressure state according to the following formula, including:

[0132]

[0133] Where, q max The maximum gas flow rate through the nozzle is represented by p1, the pressure inside the oil pipe is represented by d, the equivalent diameter of the leak is represented by T1, and the temperature is represented by γ. g Z1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

[0134] Based on the above scheme, optionally, the target leak size determination module is specifically used to: determine the median or average of the local leak size determined at multiple target locations as the target leak size corresponding to the leak in the oil pipe.

[0135] The device for determining the size of a leak in a pipe provided in this embodiment of the invention can execute the method for determining the size of a leak in a pipe provided in any embodiment of the invention, and has the corresponding functional modules and beneficial effects of executing the method.

[0136] Example 5

[0137] Figure 5 A schematic diagram of an electronic device 10 that can be used to implement embodiments of the present invention is shown. The electronic device is intended to represent various forms of digital computers, such as laptop computers, desktop computers, workstations, personal digital assistants, servers, blade servers, mainframe computers, and other suitable computers. The electronic device can also represent various forms of mobile devices, such as personal digital processors, cellular phones, smartphones, wearable devices (e.g., helmets, glasses, watches, etc.), and other similar computing devices. The components shown herein, their connections and relationships, and their functions are merely illustrative and are not intended to limit the implementation of the invention described and / or claimed herein.

[0138] like Figure 5 As shown, the electronic device 10 includes at least one processor 11 and a memory, such as a read-only memory (ROM) 12 or a random access memory (RAM) 13, communicatively connected to the at least one processor 11. The memory stores computer programs executable by the at least one processor. The processor 11 can perform various appropriate actions and processes based on the computer program stored in the ROM 12 or loaded from storage unit 18 into the RAM 13. The RAM 13 may also store various programs and data required for the operation of the electronic device 10. The processor 11, ROM 12, and RAM 13 are interconnected via a bus 14. An input / output (I / O) interface 15 is also connected to the bus 14.

[0139] Multiple components in electronic device 10 are connected to I / O interface 15, including: input unit 16, such as keyboard, mouse, etc.; output unit 17, such as various types of displays, speakers, etc.; storage unit 18, such as disk, optical disk, etc.; and communication unit 19, such as network card, modem, wireless transceiver, etc. Communication unit 19 allows electronic device 10 to exchange information / data with other devices through computer networks such as the Internet and / or various telecommunications networks.

[0140] Processor 11 can be a variety of general-purpose and / or special-purpose processing components with processing and computing capabilities. Some examples of processor 11 include, but are not limited to, a central processing unit (CPU), a graphics processing unit (GPU), various special-purpose artificial intelligence (AI) computing chips, various processors running machine learning model algorithms, a digital signal processor (DSP), and any suitable processor, controller, microcontroller, etc. Processor 11 performs the various methods and processes described above, such as a method for determining the size of a pipe leak.

[0141] In some embodiments, a method for determining the size of a pipe leak can be implemented as a computer program tangibly contained in a computer-readable storage medium, such as storage unit 18. In some embodiments, part or all of the computer program can be loaded and / or installed on electronic device 10 via ROM 12 and / or communication unit 19. When the computer program is loaded into RAM 13 and executed by processor 11, one or more steps of the method for determining the size of a pipe leak described above can be performed. Alternatively, in other embodiments, processor 11 can be configured to perform a method for determining the size of a pipe leak by any other suitable means (e.g., by means of firmware).

[0142] Various embodiments of the systems and techniques described above herein can be implemented in digital electronic circuit systems, integrated circuit systems, field-programmable gate arrays (FPGAs), application-specific integrated circuits (ASICs), application-specific standard products (ASSPs), systems-on-a-chip (SoCs), payload-programmable logic devices (CPLDs), computer hardware, firmware, software, and / or combinations thereof. These various embodiments may include implementations in one or more computer programs that can be executed and / or interpreted on a programmable system including at least one programmable processor, which may be a dedicated or general-purpose programmable processor, capable of receiving data and instructions from a storage system, at least one input device, and at least one output device, and transmitting data and instructions to the storage system, the at least one input device, and the at least one output device.

[0143] Computer programs used to implement the methods of the present invention may be written in any combination of one or more programming languages. These computer programs may be provided to a processor of a general-purpose computer, a special-purpose computer, or other programmable data processing device, such that when executed by the processor, the computer programs cause the functions / operations specified in the flowcharts and / or block diagrams to be performed. The computer programs may be executed entirely on a machine, partially on a machine, or as a standalone software package, partially on a machine and partially on a remote machine, or entirely on a remote machine or server.

[0144] In the context of this invention, a computer-readable storage medium can be a tangible medium that may contain or store a computer program for use by or in conjunction with an instruction execution system, apparatus, or device. A computer-readable storage medium may include, but is not limited to, electronic, magnetic, optical, electromagnetic, infrared, or semiconductor systems, apparatus, or devices, or any suitable combination thereof. Alternatively, a computer-readable storage medium may be a machine-readable signal medium. More specific examples of machine-readable storage media include electrical connections based on one or more wires, portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fibers, portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof.

[0145] To provide interaction with a user, the systems and techniques described herein can be implemented on an electronic device having: a display device (e.g., a CRT (cathode ray tube) or LCD (liquid crystal display) monitor) for displaying information to the user; and a keyboard and pointing device (e.g., a mouse or trackball) through which the user provides input to the electronic device. Other types of devices can also be used to provide interaction with the user; for example, feedback provided to the user can be any form of sensory feedback (e.g., visual feedback, auditory feedback, or tactile feedback); and input from the user can be received in any form (including sound input, voice input, or tactile input).

[0146] The systems and technologies described herein can be implemented in computing systems that include backend components (e.g., as data servers), or computing systems that include middleware components (e.g., application servers), or computing systems that include frontend components (e.g., user computers with graphical user interfaces or web browsers through which users can interact with implementations of the systems and technologies described herein), or any combination of such backend, middleware, or frontend components. The components of the system can be interconnected via digital data communication of any form or medium (e.g., communication networks). Examples of communication networks include local area networks (LANs), wide area networks (WANs), blockchain networks, and the Internet.

[0147] A computing system can include clients and servers. Clients and servers are generally located far apart and typically interact through communication networks. The client-server relationship is created by computer programs running on the respective computers and having a client-server relationship with each other. The server can be a cloud server, also known as a cloud computing server or cloud host, which is a hosting product within the cloud computing service system to address the shortcomings of traditional physical hosts and VPS services, such as high management difficulty and weak business scalability.

[0148] It should be understood that the various forms of processes shown above can be used, with steps reordered, added, or deleted. For example, the steps described in this invention can be executed in parallel, sequentially, or in different orders, as long as the desired result of the technical solution of this invention can be achieved, and no limitation is imposed herein.

[0149] The specific embodiments described above do not constitute a limitation on the scope of protection of this invention. Those skilled in the art should understand that various modifications, combinations, sub-combinations, and substitutions can be made according to design requirements and other factors. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of this invention should be included within the scope of protection of this invention.

Claims

1. A method for determining the size of a leak point in an oil pipe, characterized in that, include: The pressure change information of the tubing and casing of the target gas well in the plugged and released states is obtained respectively. Based on the pressure change information of the tubing and casing, the target well section containing the leak point in the tubing is determined. The target pressure status of the tubing at multiple target locations within the target well section is obtained respectively, and the size of the local leak point corresponding to the leak point in the tubing at the target location is determined based on the target pressure status; The target leak size corresponding to the leak in the tubing is determined based on the local leak size determined at multiple target locations.

2. The method according to claim 1, characterized in that, The process of acquiring pressure change information of the target gas well's tubing and casing in plugged and released states, and determining the target well section containing the leak point in the tubing based on the pressure change information of the tubing and casing, includes: By plugging the tubing at at least one location in the tubing of the target gas well using a plugger, the tubing plugging pressure and the casing plugging pressure of the tubing in the plugged section are obtained. By releasing the gas in the tubing blockage area, the tubing release pressure and the casing release pressure of the casing in the blocked well section are obtained. The tubing pressure change information is determined based on the tubing plugging pressure and the tubing release pressure, and the casing pressure change information is determined based on the casing plugging pressure and the casing release pressure. The target well section in the tubing containing the leak is determined based on the plugged well section and the corresponding tubing pressure change information and casing pressure change information.

3. The method according to claim 1, characterized in that, The step of acquiring the target pressure status of the tubing at multiple target locations within the target well section includes: The inner wall pressure and outer wall pressure of the tubing at multiple target locations within the target well section are obtained respectively, and the target pressure state of the tubing at the target location is determined based on the inner wall pressure and outer wall pressure of the tubing.

4. The method according to claim 3, characterized in that, The step of obtaining the inner wall pressure and outer wall pressure of the tubing at multiple target locations within the target well section includes: For each target location within the target well section, the inner wall pressure of the tubing at the target location is determined based on the gas pressure in the annular space formed by the tubing and the casing at the wellhead of the target gas well, the gas density in the tubing, the gravitational acceleration, and the depth information corresponding to the target location. Additionally, the outer wall pressure of the tubing at the target location is determined based on the gas pressure in the tubing at the wellhead of the target gas well, the gas density in the tubing, the gravitational acceleration, and the depth information corresponding to the target location.

5. The method according to claim 3, characterized in that, Determining the target pressure state of the oil pipe at the target location based on the pressure on the inner wall of the oil pipe and the pressure on the outer wall of the oil pipe includes: When the ratio of the pressure on the outer wall of the tubing to the pressure on the inner wall of the tubing is greater than or equal to the critical pressure, the target pressure state of the tubing at the target location is determined as a subcritical flow state. When the ratio of the pressure on the outer wall of the tubing to the pressure on the inner wall of the tubing is less than the critical pressure, the target pressure state of the tubing at the target location is determined as the critical flow state, wherein the critical pressure is determined based on the gas adiabatic index.

6. The method according to claim 5, characterized in that, The critical pressure is determined based on the following formula: Where C represents the critical pressure and k represents the gas adiabatic index.

7. The method according to claim 1, characterized in that, The target leak size includes the equivalent diameter of the leak; the target pressure state includes a subcritical flow state; the target leak size corresponding to the leak in the tubing is determined based on the target pressure state according to the following formula: Where, q sc p1 represents the volumetric flow rate of gas passing through the nozzle under standard conditions, p2 represents the pressure inside the oil pipe, d represents the equivalent diameter of the leak, T1 represents the temperature, and γ represents the pressure outside the oil pipe. g Z1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

8. The method according to claim 1, characterized in that, The target leak size includes the equivalent diameter of the leak; the target pressure state includes the critical flow state; the target leak size corresponding to the leak in the tubing is determined based on the target pressure state according to the following formula: Where, q max The maximum gas flow rate through the nozzle is represented by p1, the pressure inside the oil pipe is represented by d, the equivalent diameter of the leak is represented by T1, and the temperature is represented by γ. g Z1 represents the relative density of natural gas, Z1 represents the deviation coefficient of natural gas, and k represents the adiabatic index of the gas.

9. The method according to claim 1, characterized in that, Determining the target leak size corresponding to the leak in the tubing based on the local leak size determined at multiple target locations includes: The median or average of the local leak sizes determined at multiple target locations is used to determine the target leak size corresponding to the leak in the tubing.

10. A device for determining the size of an oil pipe leak, characterized in that, include: The leak point well section determination module is used to acquire pressure change information of the tubing and casing of the target gas well in the plugged and released states, respectively, and determine the target well section containing the leak point in the tubing based on the pressure change information of the tubing and casing. The local leak point size determination module is used to obtain the target pressure status of the tubing at multiple target locations within the target well section, and determine the local leak point size corresponding to the leak point in the tubing at the target location based on the target pressure status. The target leak size determination module is used to determine the target leak size corresponding to the leak in the oil pipe based on the local leak size determined at multiple target locations.

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