A layered flow pipeline leakage positioning method based on a multi-source sensing system

Abstract

The embodiment of the application provides a layered flow pipeline leakage positioning method based on a multi-source sensing system, which can solve the technical problem of poor leakage positioning capability in a complex environment. The method comprises calculating the sound speed in the pipeline according to the average pipeline cross-section gas content, gas density, liquid density, pure gas sound speed and pure liquid sound speed. The actual gas flow rate in the pipeline is calculated according to the average pipeline cross-section gas content and the gas volume flow rate. The leakage positioning result is obtained according to the leakage signal time difference, the sound speed in the pipeline and the actual gas flow rate in the pipeline. The sound speed calculation model and the leakage positioning model in the gas-liquid two-phase stratified flow are improved by comprehensively considering the gas-liquid phase distribution state and the gas-liquid phase flow state, the accuracy of the stratified flow pipeline leakage positioning is improved, and the problem of large leakage positioning error of the current stratified flow pipeline leakage positioning is solved. The leakage positioning capability in a complex environment is improved, and in particular, the positioning accuracy of the acoustic wave method leakage detection technology when applied to multiphase flow pipelines is improved.

Description

Technical Field

[0001] This application relates to the field of oil and gas pipeline technology, and in particular to a method for locating leaks in stratified flow pipelines based on a multi-source sensing system. Background Technology

[0002] Multiphase flow pipelines are widely used in subsea pipelines and oil and gas gathering pipelines. These pipelines are more prone to corrosion and leakage due to the complexity of the media inside them. Leaks in oil and gas pipelines not only cause economic losses but also severely damage the surrounding ecological environment. Furthermore, fires and explosions caused by oil and gas leaks can pose a greater threat to the lives of people in the vicinity.

[0003] Currently, various leak detection and location technologies exist, such as the negative pressure wave method, the acoustic wave method, the transient model method, and the distributed optical fiber method. For example, a pressure wave is introduced into a pipeline, and its propagation is monitored. When a leak occurs in the pipeline, the propagation characteristics of the pressure wave change, thus identifying the leak location. This method is typically suitable for long pipeline systems. Another example is using the propagation characteristics of acoustic waves to detect pipeline leaks. When a pipeline leaks, the flow of liquid or gas generates sound waves. The monitoring system receives these sound wave signals and analyzes the leak location by combining the transmission time and frequency. This method is suitable for relatively small leaks and has a fast response time.

[0004] However, distributed optical fibers are difficult to apply to complex environments such as oceans and pipelines, while both the negative pressure wave method and the acoustic wave method have shortcomings in positioning accuracy due to the inaccuracy of the current sound velocity calculation model. Summary of the Invention

[0005] This application provides a method for locating leaks in a layered flow pipeline based on a multi-source sensing system, which can solve the technical problem of poor leak location capability in complex environments.

[0006] To achieve the above objectives, the embodiments of this application adopt the following technical solutions:

[0007] In a first aspect, embodiments of this application provide a method for locating leaks in a stratified flow pipeline based on a multi-source sensing system. This method includes: acquiring the cross-sectional gas content at a first end and a second end of the pipeline under test; using the cross-sectional gas content to calculate an average cross-sectional gas content; the first end being the starting end of the pipeline under test; and the second end being the ending end of the pipeline under test; acquiring the internal pressure at the first end and the second end of the pipeline under test; using the internal pressure to calculate an average internal pressure; acquiring the internal temperature at the first end and the second end of the pipeline under test; using the internal temperature to calculate an average internal temperature; and acquiring dynamic pressure signals at the first end and the second end of the pipeline under test; using the dynamic pressure signals to calculate the leak. The leak signal time difference is calculated; the gas volumetric flow rate at the second end of the pipe under test is collected; the pure gas sound velocity is calculated based on the correction factor; the correction factor is related to the average gas content of the pipe cross section; under the conditions of average pipe pressure and average pipe temperature, the gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity are confirmed based on the gas-liquid two-phase separation results at the first and second ends of the pipe under test; the sound velocity inside the pipe is calculated based on the average gas content of the pipe cross section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity; the actual gas velocity inside the pipe is calculated based on the average gas content of the pipe cross section and the gas volumetric flow rate; the leak location result is obtained based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe.

[0008] Based on the above description of the stratified flow pipeline leakage location method based on a multi-source sensing system provided in this application embodiment, it can be seen that this stratified flow pipeline leakage location method based on a multi-source sensing system includes calculating the sound velocity inside the pipe based on the average pipe cross-sectional gas content, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity inside the pipe is calculated based on the average pipe cross-sectional gas content and gas volumetric flow rate. The leakage location result is obtained based on the leakage signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe, thus allowing the leakage point to be located. By comprehensively considering the gas-liquid phase distribution and flow state inside the pipe, the sound velocity calculation model and leakage location model in gas-liquid two-phase stratified flow are improved, increasing the accuracy of stratified flow pipeline leakage location and solving the problem of large leakage location errors in current stratified flow pipelines. This enhances the leakage location capability in complex environments, especially improving the location accuracy of acoustic leakage detection technology when applied to multiphase flow pipelines.

[0009] Furthermore, by incorporating correction coefficients, the improved formula for calculating the sound velocity of stratified flow and the integration of multiple measuring devices effectively enhance the accuracy of locating leaks in stratified flow pipelines.

[0010] In the feasible implementation of the first aspect, the formula for calculating the correction coefficient includes:

[0011] f T = -0.07164α 2 +0.1435α+0.9215;

[0012] Among them, f T denoted as the correction factor; a represents the average gas content of the pipe section.

[0013] In the feasible implementation of the first aspect, the formula for calculating the speed of sound in pure gas includes:

[0014]

[0015] Among them, c G Expressed as the speed of sound of a pure gas in a pure gas medium; f T The value is represented as the correction factor; n = 1.4; Z represents the compressibility factor of the gas in the gas-liquid two-phase separation result; R represents the gas constant of the gas in the gas-liquid two-phase separation result; M is the relative molecular mass of the gas in the gas-liquid two-phase separation result; T represents the average tube temperature.

[0016] In the feasible implementation of the first aspect, the formula for calculating the actual gas flow velocity inside the pipe includes:

[0017]

[0018] Where u represents the actual flow velocity of the gas inside the pipe; Q G It represents the gas volumetric flow rate; D represents the pipe diameter; aα represents the average gas content of the pipe cross section.

[0019] In the feasible implementation of the first aspect, the formula for calculating the velocity of sound inside the pipe includes:

[0020]

[0021] Where c represents the velocity of sound inside the pipe; aa represents the average gas content of the pipe cross section; ρ G Represented as gas density; ρ L c represents the liquid density. G Expressed as the velocity of sound in a pure gas medium; c L It is expressed as the pure liquid sound velocity in a pure liquid medium.

[0022] In the feasible implementation of the first aspect, the formula for calculating the leak location result includes:

[0023]

[0024] Where x represents the distance from the leak point to the starting sensor; L represents the distance between the two sensors; Δt represents the time difference of the leak signal; c represents the speed of sound in the pipe; and u represents the actual flow velocity of the gas in the pipe.

[0025] In the feasible implementation of the first aspect, the leakage signal time difference is the time it takes for the leakage signal to propagate to the first end minus the time it takes for the leakage signal to propagate to the second end.

[0026] Secondly, embodiments of this application provide a layered flow pipeline leak location system based on a multi-source sensing system. This system includes: a first cross-sectional gas content measuring device, a second cross-sectional gas content measuring device, a first pressure sensor, a second pressure sensor, a first temperature sensor, a second temperature sensor, a first dynamic pressure sensor, a second dynamic pressure sensor, a gas-liquid two-phase separator, a gas volume flow meter, and a leak location calculation module. The first cross-sectional gas content measuring device is disposed at the first end of the pipeline to be tested; the first end is the starting end of the pipeline. The second cross-sectional gas content measuring device is disposed at the second end of the pipeline to be tested; the second end is the ending end of the pipeline. The first and second cross-sectional gas content measuring devices are configured to collect cross-sectional gas content; the cross-sectional gas content is used to calculate the average cross-sectional gas content. The first pressure sensor is disposed at the first end of the pipeline to be tested; the second pressure sensor is disposed at the second end of the pipeline to be tested. The first and second pressure sensors are configured to collect intra-pipe pressure; the pressure is used to calculate the average intra-pipe pressure. The first temperature sensor is disposed at the first end of the pipeline to be tested; the second temperature sensor is disposed at the second end of the pipeline to be tested. A first temperature sensor and a second temperature sensor are configured to collect the temperature inside the pipe; the temperature is used to calculate the average temperature inside the pipe; a first dynamic pressure sensor is located at the first end of the pipe under test; a second dynamic pressure sensor is located at the second end of the pipe under test; the first and second dynamic pressure sensors are configured to collect dynamic pressure signals; the dynamic pressure signals are used to calculate the time difference of the leakage signal; a gas-liquid two-phase separator is located at the second end of the pipe under test and is configured to obtain the gas-liquid two-phase separation result; the gas-liquid two-phase separation result is used to confirm the gas under the average pipe pressure and average pipe temperature. The system collects volumetric density, liquid density, pure gas sound velocity, and pure liquid sound velocity. A gas volumetric flow meter is installed at the second end of the pipe to be measured and configured to collect gas volumetric flow rate. A leak location calculation module is configured to calculate the pure gas sound velocity based on a correction factor, which is related to the average gas content of the pipe cross-section. The module calculates the sound velocity inside the pipe based on the average gas content of the pipe cross-section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. It calculates the actual gas velocity inside the pipe based on the average gas content of the pipe cross-section and the gas volumetric flow rate. The leak location result is obtained based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe.

[0027] The sound velocity inside the pipe is calculated based on the average pipe cross-sectional gas holdup, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity inside the pipe is calculated based on the average pipe cross-sectional gas holdup and gas volumetric flow rate. The leak location result is obtained based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe. By comprehensively considering the gas-liquid phase distribution and flow state inside the pipe, the sound velocity calculation model and leak location model in gas-liquid two-phase stratified flow are improved, thus increasing the accuracy of leak location in stratified flow pipelines and solving the problem of large leak location errors in current stratified flow pipelines. This enhances the leak location capability in complex environments, especially improving the location accuracy of acoustic leak detection technology in multiphase flow pipelines.

[0028] Thirdly, embodiments of this application provide a layered flow pipe leak location system based on a multi-source sensing system. The layered flow pipe leak location system based on a multi-source sensing system includes: at least one processor; a memory communicatively connected to the at least one processor; wherein the memory stores instructions executable by the at least one processor, and the instructions are executed by the at least one processor to enable the at least one processor to perform the method provided in the first aspect.

[0029] The stratified flow pipeline leak location system based on a multi-source sensing system executes the method provided in the first aspect, calculating the sound velocity inside the pipe based on the average pipe cross-sectional gas holdup, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. It then calculates the actual gas velocity inside the pipe based on the average pipe cross-sectional gas holdup and gas volumetric flow rate. Finally, it obtains the leak location result based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe. By comprehensively considering the gas-liquid phase distribution and flow state inside the pipe, it improves the sound velocity calculation model and leak location model in gas-liquid two-phase stratified flow, thereby increasing the accuracy of leak location in stratified flow pipelines and solving the problem of large leak location errors in current stratified flow pipeline leak location systems. This enhances the leak location capability in complex environments, particularly improving the location accuracy of acoustic leak detection technology in multiphase flow pipelines.

[0030] Fourthly, embodiments of this application provide a computer-readable medium having computer program instructions stored thereon, which can be executed by a processor to implement the method as provided in the first aspect.

[0031] The computer program instructions in the computer-readable medium implement the method provided in the first aspect, calculating the sound velocity inside the pipe based on the average pipe cross-sectional gas holdup, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity inside the pipe is calculated based on the average pipe cross-sectional gas holdup and gas volumetric flow rate. The leak location result is obtained based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe. By comprehensively considering the gas-liquid phase distribution and flow state inside the pipe, the sound velocity calculation model and leak location model in gas-liquid two-phase stratified flow are improved, increasing the accuracy of leak location in stratified flow pipelines and solving the problem of large leak location errors in current stratified flow pipelines. This enhances the leak location capability in complex environments, particularly improving the location accuracy of acoustic leak detection technology in multiphase flow pipelines. Attached Figure Description

[0032] Figure 1 A schematic diagram of a layered flow pipeline leakage location system based on a multi-source sensing system provided in this application embodiment;

[0033] Figure 2 A flowchart illustrating a method for locating leaks in a layered flow pipeline based on a multi-source sensing system, provided in an embodiment of this application;

[0034] Figure 3 This is a schematic diagram of a scenario for a method for locating leaks in a layered flow pipeline based on a multi-source sensing system, provided in an embodiment of this application. Detailed Implementation

[0035] The technical solutions of the embodiments of the present invention will be described below with reference to the accompanying drawings. In the description of the embodiments of the present invention, unless otherwise stated, "multiple" refers to two or more. "At least one of the following" or similar expressions refer to any combination of these items, including any combination of a single item or a plurality of items. For example, at least one of a, b, or c can represent: a, b, c, ab, ac, bc, or abc, where a, b, and c can be single or multiple.

[0036] Furthermore, to facilitate a clear description of the technical solutions in the embodiments of the present invention, the terms "first" and "second" are used to distinguish identical or similar items with substantially the same function and effect. Those skilled in the art will understand that the terms "first" and "second" do not limit the quantity or execution order, and that "first" and "second" are not necessarily different. Meanwhile, in the embodiments of the present invention, the terms "exemplary" or "for example" are used to indicate that something is being used as an example, illustration, or description. Any embodiment or design scheme described as "exemplary" or "for example" in the embodiments of the present invention should not be construed as being more preferred or advantageous than other embodiments or design schemes. Specifically, the use of terms such as "exemplary" or "for example" is intended to present the relevant concepts in a concrete manner for ease of understanding.

[0037] The principles and features of this application are described below. The examples given are only for explaining this application and are not intended to limit the scope of this application.

[0038] This application provides a method for locating leaks in stratified flow pipelines based on a multi-source sensing system. This method is suitable for improving leak location in complex environments, particularly in multiphase flow pipelines. The method calculates the sound velocity inside the pipe based on the average pipe cross-sectional gas holdup, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity inside the pipe is calculated based on the average pipe cross-sectional gas holdup and gas volumetric flow rate. The leak location result is obtained based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe. By comprehensively considering the gas-liquid phase distribution and flow state inside the pipe, the method improves the sound velocity calculation model and leak location model in gas-liquid two-phase stratified flow, thereby increasing the accuracy of leak location in stratified flow pipelines and solving the problem of large leak location errors in current stratified flow pipelines. This enhances the leak location capability in complex environments, especially improving the location accuracy of acoustic leak detection technology in multiphase flow pipelines.

[0039] This application provides a layered flow pipeline leak location system based on a multi-source sensing system, which can execute the layered flow pipeline leak location method based on a multi-source sensing system provided in this application. Figure 1 This is a schematic diagram of a layered flow pipeline leakage location system based on a multi-source sensing system, provided as an embodiment of this application.

[0040] like Figure 1As shown, the hierarchical flow pipeline leak location system 001 based on a multi-source sensing system includes at least one processor 011 and a memory 012 communicatively connected to the at least one processor; wherein, the memory 012 stores instructions that can be executed by the at least one processor 011, and the instructions are executed by the at least one processor 011 to enable the at least one processor 011 to execute the hierarchical flow pipeline leak location method based on a multi-source sensing system provided in the embodiments of this application.

[0041] like Figure 3 As shown, in some embodiments, this application provides a stratified flow pipeline leak location system based on a multi-source sensing system. The stratified flow pipeline leak location system based on a multi-source sensing system includes: a first cross-section gas content measuring device 10, a second cross-section gas content measuring device 11, a first pressure sensor 12, a second pressure sensor 13, a first temperature sensor 14, a second temperature sensor 15, a first dynamic pressure sensor 16, a second dynamic pressure sensor 17, a gas-liquid two-phase separator 18, a gas volume flow meter 19, and a leak location calculation module 20.

[0042] The first section gas content measuring device 10 is installed at the first end of the pipeline to be tested. The first end is the starting end of the pipeline to be tested.

[0043] The second section gas content measuring device 11 is installed at the second end of the pipe to be tested. The second end is the terminal end of the pipe to be tested.

[0044] The first cross-sectional gas content measuring device 10 and the second cross-sectional gas content measuring device 11 are configured to collect cross-sectional gas content. The cross-sectional gas content is used to calculate the average cross-sectional gas content.

[0045] The first pressure sensor 12 is installed at the first end of the pipe to be tested.

[0046] The second pressure sensor 13 is installed at the second end of the pipe to be tested.

[0047] The first pressure sensor 12 and the second pressure sensor 13 are configured to collect the pressure inside the tube. The pressure is used to calculate the average pressure inside the tube.

[0048] The first temperature sensor 14 is installed at the first end of the pipe to be tested.

[0049] The second temperature sensor 15 is located at the second end of the pipe to be tested.

[0050] A first temperature sensor 14 and a second temperature sensor 15 are configured to collect the temperature inside the tube. The temperature is used to calculate the average temperature inside the tube.

[0051] The first dynamic pressure sensor 16 is installed at the first end of the pipe to be tested.

[0052] The second dynamic pressure sensor 17 is installed at the second end of the pipe to be tested.

[0053] A first dynamic pressure sensor 16 and a second dynamic pressure sensor 17 are configured to acquire dynamic pressure signals. The dynamic pressure signals are used to calculate the time difference of the leakage signal.

[0054] A gas-liquid two-phase separator 18 is disposed at the second end of the pipe to be tested and is configured to obtain gas-liquid two-phase separation results. The gas-liquid two-phase separation results are used to confirm the gas density, liquid density, pure gas velocity, and pure liquid velocity under average pipe pressure and average pipe temperature.

[0055] The gas volume flow meter 19 is installed at the second end of the pipe to be measured and is configured to collect gas volume flow rate.

[0056] The leak location calculation module 20 is configured to calculate the pure gas sound velocity based on a correction factor. This correction factor is related to the average gas content of the pipe cross-section. The sound velocity inside the pipe is calculated based on the average gas content of the pipe cross-section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity inside the pipe is calculated based on the average gas content of the pipe cross-section and the gas volumetric flow rate. The leak location result is obtained based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas velocity inside the pipe.

[0057] Figure 2 This is a flowchart illustrating a method for locating leaks in a layered flow pipeline based on a multi-source sensing system, as provided in an embodiment of this application. Figure 2 As shown, in some embodiments, the method for locating leaks in a stratified flow pipeline based on a multi-source sensing system includes the following steps:

[0058] S1, collect the gas content of the cross-sections at the first and second ends of the pipe to be tested.

[0059] The cross-sectional gas content is used to calculate the average cross-sectional gas content.

[0060] like Figure 3 As shown, the first end is the starting end of the pipe to be tested. The second end is the ending end of the pipe to be tested. For example, gas content measurement devices installed at the starting and ending points of the pipe estimate the gas content within the pipe cross-section by averaging the two measurements.

[0061] S2 collects the pressure inside the first and second ends of the pipe to be tested.

[0062] The pressure inside the pipe is used to calculate the average pressure inside the pipe. For example, pressure sensors installed at the beginning and end of the pipe are used to estimate the pressure inside the pipe by averaging the measurements at the beginning and end.

[0063] S3 collects the internal temperature of the first and second ends of the pipe under test.

[0064] The pipe temperature is used to calculate the average pipe temperature. For example, temperature sensors installed at the beginning and end of the pipe are used to estimate the pipe temperature by averaging the measurements from the beginning and end.

[0065] By executing steps S1 to S3, the pressure, cross-sectional gas content, and temperature of the medium inside the pipe are measured in real time at the starting and ending points of the pipe to be tested.

[0066] S4 collects dynamic pressure signals from the first and second ends of the pipe under test.

[0067] Dynamic pressure signals are used to calculate the time difference of leakage signals. In some embodiments, dynamic pressure sensors are installed at both ends of the pipeline, with the sensors mounted on the upper part of the pipeline, to collect dynamic pressure signals during the leakage process. For example, the leakage signal time difference is the time it takes for the leakage signal to propagate to the first end minus the time it takes for the leakage signal to propagate to the second end.

[0068] S5 collects the gas volumetric flow rate at the second end of the pipe to be tested.

[0069] For example, a gas-liquid two-phase separator and a gas flow meter installed at the end of a pipe are used to measure the gas flow rate in the pipe and calculate the gas velocity in the pipe based on the gas content of the pipe cross section.

[0070] S6, calculate the speed of sound in pure gas based on the correction factor.

[0071] The correction factor is related to the average gas content of the pipe section. For example, the formula for calculating the correction factor includes:

[0072] f T = -0.07164α 2 +0.1435α+0.9215;

[0073] Among them, f T denoted as the correction factor; a represents the average gas content of the pipe section.

[0074] In some embodiments, the formula for calculating the speed of sound in a pure gas includes:

[0075]

[0076] Among them, c G Expressed as the speed of sound of a pure gas in a pure gas medium; f T The value is represented as the correction factor; n = 1.4; Z represents the compressibility factor of the gas in the gas-liquid two-phase separation result; R represents the gas constant of the gas in the gas-liquid two-phase separation result; M is the relative molecular mass of the gas in the gas-liquid two-phase separation result; T represents the average tube temperature.

[0077] S7. Under the conditions of average pipe pressure and average pipe temperature, based on the gas-liquid two-phase separation results at the first and second ends of the pipe under test, confirm the gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity.

[0078] S8. Calculate the sound velocity inside the pipe based on the average gas content of the pipe cross section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity.

[0079] In some embodiments, the formula for calculating the velocity of sound inside the pipe includes:

[0080]

[0081] Where c represents the velocity of sound inside the pipe; α represents the average gas content of the pipe cross section; ρ G Represented as gas density; ρ L c represents the liquid density. G Expressed as the velocity of sound in a pure gas medium; c L It is expressed as the pure liquid sound velocity in a pure liquid medium.

[0082] S9. Calculate the actual gas velocity inside the pipe based on the average gas content of the pipe section and the gas volumetric flow rate.

[0083] In some embodiments, the formula for calculating the actual gas flow velocity inside the pipe includes:

[0084]

[0085] Where u represents the actual flow velocity of the gas inside the pipe; Q G It represents the gas volumetric flow rate; D represents the pipe diameter; α represents the average gas content of the pipe cross section.

[0086] S10. Based on the time difference of the leakage signal, the sound velocity inside the pipe, and the actual flow velocity of the gas inside the pipe, the leakage location result is obtained.

[0087] In some embodiments, the formula for calculating the leak location result includes:

[0088]

[0089] Where x represents the distance from the leak point to the starting sensor; L represents the distance between the two sensors; Δt represents the time difference of the leak signal; c represents the speed of sound in the pipe; and u represents the actual flow velocity of the gas in the pipe.

[0090] In this way, dynamic pressure signals generated by the leak are collected at both the beginning and end of the pipeline. The time delays of the two dynamic pressure signals are calculated. Based on the time delays of the two signals, the propagation speed of sound waves in the gas-liquid two-phase stratified flow, and the gas flow velocity in the pipeline, the leak point is located.

[0091] As can be seen from the above embodiments, this application comprehensively considers the gas-liquid phase distribution and flow state within the pipe, improving the sound velocity calculation model and leak location model in gas-liquid two-phase stratified flow, thereby increasing the accuracy of leak location in stratified flow pipelines and solving the problem of large leak location errors in current stratified flow pipelines. It enhances leak location capabilities in complex environments, particularly improving the location accuracy of acoustic leak detection technology in multiphase flow pipelines.

[0092] Based on the same concept, this application also provides a layered flow pipe leak location system based on a multi-source sensing system. The method corresponding to the layered flow pipe leak location system based on a multi-source sensing system can be the layered flow pipe leak location method based on a multi-source sensing system in the aforementioned embodiments, and its problem-solving principle is similar to that method. The layered flow pipe leak location system based on a multi-source sensing system provided in this application includes: at least one processor; and a memory communicatively connected to the at least one processor; wherein, the memory stores instructions executable by the at least one processor, and the instructions are executed by the at least one processor to enable the at least one processor to execute the methods and / or technical solutions of the various embodiments of this application.

[0093] Another embodiment of this application provides a computer-readable storage medium having computer program instructions stored thereon, which can be executed by a processor to implement the methods and / or technical solutions of any one or more embodiments of this application described above.

[0094] Specifically, this embodiment may employ any combination of one or more computer-readable media. A computer-readable medium may be a computer-readable signal medium or a computer-readable storage medium. A computer-readable storage medium may be, for example,—but not limited to—an electrical, magnetic, optical, electromagnetic, infrared, or semiconductor system, apparatus, or device, or any combination thereof. More specific examples of computer-readable storage media (a non-exhaustive list) include: an electrical connection having one or more wires, a portable computer disk, a hard disk, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), optical fiber, portable compact disk read-only memory (CD-ROM), optical storage device, magnetic storage device, or any suitable combination thereof. In this document, a computer-readable storage medium may be any tangible medium that contains or stores a program that can be used by or in connection with an instruction execution system, apparatus, or device.

[0095] Computer-readable signal media may include data signals propagated in baseband or as part of a carrier wave, carrying computer-readable program code. Such propagated data signals may take various forms, including—but not limited to—electromagnetic signals, optical signals, or any suitable combination thereof. Computer-readable signal media may also be any computer-readable medium other than computer-readable storage media, capable of sending, propagating, or transmitting programs for use by or in connection with an instruction execution system, apparatus, or device.

[0096] The program code contained on a computer-readable medium may be transmitted using any suitable medium, including—but not limited to—wireless, wire, optical fiber, RF, etc., or any suitable combination thereof.

[0097] Computer program code for performing the operations of this application can be written in one or more programming languages ​​or a combination thereof, including object-oriented programming languages ​​such as Java, Smalltalk, and C++, and conventional procedural programming languages ​​such as "C" or similar programming languages. The program code can be executed entirely on the user's computer, partially on the user's computer, as a standalone software package, partially on the user's computer and partially on a remote computer, or entirely on a remote computer or server. In cases involving remote computers, the remote computer can be connected to the user's computer via any type of network—including a local area network (LAN) or a wide area network (WAN)—or can be connected to an external computer (e.g., via the Internet using an Internet service provider).

[0098] The flowcharts or block diagrams in the accompanying drawings illustrate the architecture, functionality, and operation of possible implementations of devices, methods, and computer program products according to various embodiments of this application. In this regard, each block in a flowchart or block diagram may represent a module, segment, or portion of code containing one or more executable instructions for implementing a specified logical function. It should also be noted that in some alternative implementations, the functions indicated in the blocks may occur in a different order than those indicated in the drawings. For example, two consecutively indicated blocks may actually be executed substantially in parallel, and they may sometimes be executed in reverse order, depending on the functions involved. It should also be noted that each block in the block diagrams and / or flowcharts, and combinations of blocks in the block diagrams and / or flowcharts, can be implemented using a dedicated hardware-specific system that performs the specified function or operation, or using a combination of dedicated hardware and computer instructions.

[0099] Those skilled in the art will clearly understand that, for the sake of convenience and brevity, the specific working processes of the systems, devices, and units described above can be referred to the corresponding processes in the foregoing method embodiments, and will not be repeated here.

[0100] In the several embodiments provided in this application, it should be understood that the disclosed systems, apparatuses, and methods can be implemented in other ways. For example, the apparatus embodiments described above are merely illustrative; for instance, the division of units is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple units or page components may be combined or integrated into another system, or some features may be ignored or not executed. Furthermore, the coupling or direct coupling or communication connection shown or discussed may be an indirect coupling or communication connection between devices or units through some interfaces, and may be electrical, mechanical, or other forms.

[0101] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of this embodiment according to actual needs.

[0102] Furthermore, the functional units in the various embodiments of this application can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit. The integrated unit can be implemented in hardware or in a combination of hardware and software functional units.

[0103] The integrated units implemented as software functional units described above can be stored in a computer-readable storage medium. These software functional units, stored in a storage medium, include several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) or processor to execute some steps of the methods described in the various embodiments of this application. The aforementioned storage medium includes various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM), random access memory (RAM), magnetic disks, or optical disks.

[0104] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of this application.

[0105] Furthermore, it is clear that the word "comprising" does not exclude other units or steps, and the singular does not exclude the plural. Multiple units or devices recited in a device claim may also be implemented by a single unit or device through software or hardware. The terms "first," "second," etc., are used to indicate names and do not indicate any specific order.

Claims

1. A method for locating leaks in a stratified flow pipeline based on a multi-source sensing system, characterized in that, include: The gas content of the cross-section at the first and second ends of the pipeline under test is collected; the gas content of the cross-section is used to calculate the average gas content of the pipeline cross-section; the first end is the starting end of the pipeline under test; the second end is the ending end of the pipeline under test. The pressure inside the first and second ends of the pipe under test is collected; the pressure inside the pipe is used to calculate the average pressure inside the pipe. The temperatures inside the first and second ends of the pipe under test are collected; these temperatures are used to calculate the average temperature inside the pipe. The dynamic pressure signals of the first and second ends of the pipe under test are collected; the dynamic pressure signals are used to calculate the time difference of the leakage signal. Collect the gas volumetric flow rate at the second end of the pipe under test; The velocity of sound in pure gas is calculated based on a correction factor; the correction factor is related to the gas content of the average pipe cross-section. Under the conditions of the average pipe pressure and the average pipe temperature, the gas density, liquid density, pure gas sound velocity and pure liquid sound velocity are confirmed based on the gas-liquid two-phase separation results at the first and second ends of the pipe under test. The velocity of sound inside the pipe is calculated based on the average gas content of the pipe cross section, the gas density, the liquid density, the sound velocity of the pure gas, and the sound velocity of the pure liquid. The actual gas velocity inside the pipe is calculated based on the average gas content of the pipe cross section and the gas volumetric flow rate. The leak location result is obtained based on the time difference of the leak signal, the sound velocity inside the pipe, and the actual flow velocity of the gas inside the pipe.

2. The method for locating leaks in a stratified flow pipeline based on a multi-source sensing system according to claim 1, characterized in that, The formula for calculating the correction factor includes: f T ＝-0.07164α 2 +0.1435α+0.9215； Among them, f T It is represented as a correction factor; α represents the average gas content of the pipe section.

3. The method for locating leaks in a stratified flow pipeline based on a multi-source sensing system according to claim 2, characterized in that, The formula for calculating the speed of sound in a pure gas includes: Among them, c G Expressed as the speed of sound of a pure gas in a pure gas medium; f T The value is represented as the correction factor; n = 1.4; Z represents the compressibility factor of the gas in the gas-liquid two-phase separation result; R represents the gas constant of the gas in the gas-liquid two-phase separation result; M is the relative molecular mass of the gas in the gas-liquid two-phase separation result; T represents the average tube temperature.

4. The method for locating leaks in a stratified flow pipeline based on a multi-source sensing system according to any one of claims 1-3, characterized in that, The formula for calculating the actual flow velocity of the gas inside the pipe includes: Where u represents the actual flow velocity of the gas inside the pipe; Q G It represents the gas volumetric flow rate; D represents the pipe diameter; α represents the average gas content of the pipe cross section.

5. The method for locating leaks in a stratified flow pipeline based on a multi-source sensing system according to any one of claims 1-3, characterized in that, The formula for calculating the velocity of sound inside the pipe includes: Where c represents the velocity of sound inside the pipe; α represents the average gas content of the pipe cross section; ρ G Represented as gas density; ρ L c represents the liquid density. G Expressed as the velocity of sound in a pure gas medium; c L It is expressed as the pure liquid sound velocity in a pure liquid medium.

6. The method for locating leaks in a stratified flow pipeline based on a multi-source sensing system according to any one of claims 1-3, characterized in that, The formula for calculating the leak location result includes: Where x represents the distance from the leak point to the starting sensor; L represents the distance between the two sensors; Δt represents the time difference of the leak signal; c represents the speed of sound in the pipe; and u represents the actual flow velocity of the gas in the pipe.

7. The method for locating leaks in a stratified flow pipeline based on a multi-source sensing system according to claim 6, characterized in that, The time difference of the leakage signal is the time it takes for the leakage signal to propagate to the first end minus the time it takes for the leakage signal to propagate to the second end.

8. A stratified flow pipeline leak location system based on a multi-source sensing system, characterized in that, include: The system comprises a first cross-section gas content measuring device, a second cross-section gas content measuring device, a first pressure sensor, a second pressure sensor, a first temperature sensor, a second temperature sensor, a first dynamic pressure sensor, a second dynamic pressure sensor, a gas-liquid two-phase separator, a gas volume flow meter, and a leak location calculation module. The first cross-sectional gas content measuring device is installed at the first end of the pipeline to be tested; the first end is the starting end of the pipeline to be tested; the second cross-sectional gas content measuring device is installed at the second end of the pipeline to be tested; the second end is the ending end of the pipeline to be tested; the first cross-sectional gas content measuring device and the second cross-sectional gas content measuring device are configured to collect cross-sectional gas content; the cross-sectional gas content is used to calculate the average cross-sectional gas content of the pipeline. The first pressure sensor is disposed at the first end of the pipe to be tested; the second pressure sensor is disposed at the second end of the pipe to be tested; the first pressure sensor and the second pressure sensor are configured to collect the pressure inside the pipe; the pressure inside the pipe is used to calculate the average pressure inside the pipe; The first temperature sensor is disposed at the first end of the pipe to be tested; the second temperature sensor is disposed at the second end of the pipe to be tested; the first temperature sensor and the second temperature sensor are configured to collect the temperature inside the pipe; the temperature inside the pipe is used to calculate the average temperature inside the pipe. The first dynamic pressure sensor is disposed at the first end of the pipe under test; the second dynamic pressure sensor is disposed at the second end of the pipe under test; the first dynamic pressure sensor and the second dynamic pressure sensor are configured to acquire dynamic pressure signals; the dynamic pressure signals are used to calculate the time difference of leakage signals. The gas-liquid two-phase separator is disposed at the second end of the pipe to be tested and is configured to obtain gas-liquid two-phase separation results; the gas-liquid two-phase separation results are used to confirm the gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity under the conditions of the average pipe pressure and the average pipe temperature. The gas volume flow meter is installed at the second end of the pipe to be measured and is configured to collect gas volume flow rate. The leak location calculation module is configured to calculate the pure gas sound velocity based on a correction coefficient, wherein the correction coefficient is related to the average gas content of the pipe cross section; calculate the sound velocity inside the pipe based on the average gas content of the pipe cross section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity; calculate the actual gas flow velocity inside the pipe based on the average gas content of the pipe cross section and the gas volumetric flow rate; and obtain the leak location result based on the leak signal time difference, the sound velocity inside the pipe, and the actual gas flow velocity inside the pipe.

9. A stratified flow pipeline leak location system based on a multi-source sensing system, characterized in that, include: At least one processor; A memory that is communicatively connected to the at least one processor; The memory stores instructions that can be executed by the at least one processor to enable the at least one processor to perform the method of any one of claims 1 to 7.

10. A computer-readable medium having stored thereon computer program instructions that can be executed by a processor to implement the method as described in any one of claims 1 to 7.

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