Layered flow pipeline leakage positioning method based on multi-source sensing system

Abstract

The embodiment of the invention provides a stratified 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 the step of calculating the in-pipe sound velocity according to the average pipeline section gas content, the gas density, the liquid density, the pure gas sound velocity and the pure liquid sound velocity. And calculating the actual flow velocity of the gas in the pipe according to the average pipeline section gas content and the gas volume flow. And obtaining a leakage positioning result according to the leakage signal time difference, the in-pipe sound velocity and the in-pipe gas actual flow velocity. The gas-liquid phase distribution state and the gas-liquid phase flow state in the pipe are comprehensively considered, the sound velocity calculation model and the leakage positioning model in the gas-liquid two-phase stratified flow are improved, the stratified flow pipeline leakage positioning precision is improved, and the problem that the current stratified flow pipeline leakage positioning error is large is solved. The leakage positioning capability in a complex environment is improved, and particularly, the positioning precision of an acoustic wave method leakage detection technology applied to a multiphase flow pipeline is improved.

Description

Technical Field

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

[0002] Multiphase flow pipelines are widely used in subsea pipelines and oil and gas gathering and transportation pipelines. Due to the complexity of the media inside the pipelines, these pipelines are more prone to pipeline corrosion and leakage. Leakage in oil and gas pipelines not only causes economic losses, but also seriously damages the surrounding ecological environment. Moreover, fire and explosion accidents caused by the further development of oil and gas leakage accidents are more likely to pose a threat to the lives and safety of surrounding personnel.

[0003] Currently, there are various leakage monitoring and location technologies, such as the negative pressure wave method, the acoustic wave method, the transient model method, and the distributed optical fiber method, etc. Exemplarily, by introducing a pressure wave in the pipeline and monitoring the propagation of the pressure wave. When a leak occurs in the pipeline, the characteristics of the pressure wave propagation will change, thereby enabling the identification of the leak location. This method is usually applicable to long pipeline systems. For another example, the acoustic wave propagation characteristics are used to detect pipeline leaks. When a pipeline leaks, the flow of liquid or gas will generate acoustic waves. The monitoring system analyzes the leak location by receiving these acoustic wave signals and combining the transmission time and frequency. This method is applicable to relatively small leaks and has a fast response speed.

[0004] However, distributed optical fibers are difficult to apply to situations where the pipeline surrounding environment is complex, such as the ocean, and both the negative pressure wave method and the acoustic wave method have defects in location accuracy due to the inaccuracy of the current sound speed calculation model. Summary of the Invention

[0005] The embodiments of this application provide a method for locating leaks in stratified flow pipelines based on a multi-source sensing system, which can solve the technical problem of poor leak location ability in complex environments.

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

[0007] First aspect, embodiments of the present application provide a method for locating leaks in a stratified flow pipeline based on a multi-source sensing system. The method for locating leaks in a stratified flow pipeline based on a multi-source sensing system includes: collecting the gas holdup of the cross-sections at the first end and the second end of the pipeline to be measured; the gas holdup of the cross-sections is used to calculate the average cross-sectional gas holdup; the first end is the starting end of the pipeline to be measured; the second end is the termination end of the pipeline to be measured; collecting the internal pressure of the pipeline at the first end and the second end of the pipeline to be measured; the internal pressure of the pipeline is used to calculate the average internal pressure of the pipeline; collecting the internal temperature of the pipeline at the first end and the second end of the pipeline to be measured; the internal temperature of the pipeline is used to calculate the average internal temperature of the pipeline; collecting the dynamic pressure signals at the first end and the second end of the pipeline to be measured; the dynamic pressure signals are used to calculate the leakage signal time difference; collecting the gas volume flow rate at the second end of the pipeline to be measured; calculating the pure gas sound speed according to a correction coefficient; the correction coefficient is related to the average cross-sectional gas holdup of the pipeline; under the conditions of the average internal pressure and the average internal temperature of the pipeline, confirming the gas density, liquid density, pure gas sound speed, and pure liquid sound speed according to the gas-liquid two-phase separation results at the first end and the second end of the pipeline to be measured; calculating the internal sound speed of the pipeline according to the average cross-sectional gas holdup of the pipeline, gas density, liquid density, pure gas sound speed, and pure liquid sound speed; calculating the actual gas flow velocity in the pipeline according to the average cross-sectional gas holdup of the pipeline and the gas volume flow rate; obtaining the leakage location result according to the leakage signal time difference, the internal sound speed of the pipeline, and the actual gas flow velocity in the pipeline.

[0008] Based on the above description of the method for locating leaks in a stratified flow pipeline based on a multi-source sensing system provided by the embodiments of the present application, it can be seen that the method for locating leaks in a stratified flow pipeline based on a multi-source sensing system includes calculating the internal sound speed of the pipeline according to the average cross-sectional gas holdup of the pipeline, gas density, liquid density, pure gas sound speed, and pure liquid sound speed. Calculating the actual gas flow velocity in the pipeline according to the average cross-sectional gas holdup of the pipeline and the gas volume flow rate. Obtaining the leakage location result according to the leakage signal time difference, the internal sound speed of the pipeline, and the actual gas flow velocity in the pipeline, and thus the leakage point can be located. Considering the gas-liquid phase distribution state and gas-liquid phase flow state in the pipeline comprehensively, the sound speed calculation model and leakage location model in the gas-liquid two-phase stratified flow are improved, the accuracy of leakage location in the stratified flow pipeline is improved, and the problem of large leakage location error in the current stratified flow pipeline is solved. The leakage location ability in a complex environment is improved, especially the location accuracy of the acoustic wave method leakage detection technology in the application of multiphase flow pipelines is improved.

[0009] Moreover, by introducing a correction coefficient, the improved stratified flow sound speed calculation formula and the fusion of multiple measurement devices effectively improve the accuracy of leakage location in the stratified flow pipeline.

[0010] In a feasible implementation manner of the first aspect, the calculation formula of the correction coefficient includes:

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

[0012] Among them, f T represents the correction coefficient; a represents the average gas holdup in the pipe cross-section.

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

[0014]

[0015] Among them, c G represents the pure gas sound speed in the pure gas medium; f T represents the correction coefficient; n = 1.4; Z represents the compression 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 temperature in the pipe.

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

[0017]

[0018] Among them, u represents the actual gas flow velocity in the pipe; Q G represents the gas volume flow rate; D represents the pipe diameter; aα represents the average gas holdup in the pipe cross-section.

[0019] In a feasible implementation of the first aspect, the calculation formula for the sound speed in the pipe includes:

[0020]

[0021] Among them, c represents the sound speed in the pipe; aa represents the average gas holdup in the pipe cross-section; ρ G represents the gas density; ρ L represents the liquid density; c G represents the pure gas sound speed in the pure gas medium; c L represents the pure liquid sound speed in the pure liquid medium.

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

[0023]

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

[0025] In a feasible implementation of the first aspect, the time difference of the leakage signal is the time when the leakage signal propagates to the first end minus the time when the leakage signal propagates to the second end.

[0026] In a second aspect, an embodiment of the present application provides a leakage location system for a stratified flow pipeline based on a multi-source sensing system. The leakage location system for a stratified flow pipeline based on a multi-source sensing system includes: a first cross-section gas holdup measurement device, a second cross-section gas holdup measurement 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 flowmeter, and a leakage location calculation module; the first cross-section gas holdup measurement device is arranged at the first end of the pipeline to be measured; the first end is the starting end of the pipeline to be measured; the second cross-section gas holdup measurement device is arranged at the second end of the pipeline to be measured; the second end is the terminating end of the pipeline to be measured; the first cross-section gas holdup measurement device and the second cross-section gas holdup measurement device are configured to collect the cross-section gas holdup; the cross-section gas holdup is used to calculate the average cross-section gas holdup; the first pressure sensor is arranged at the first end of the pipeline to be measured; the second pressure sensor is arranged at the second end of the pipeline to be measured; the first pressure sensor and the second pressure sensor are configured to collect the pipeline internal pressure; the pressure is used to calculate the average pipeline internal pressure; the first temperature sensor is arranged at the first end of the pipeline to be measured; the second temperature sensor is arranged at the second end of the pipeline to be measured; the first temperature sensor and the second temperature sensor are configured to collect the pipeline internal temperature; the temperature is used to calculate the average pipeline internal temperature; the first dynamic pressure sensor is arranged at the first end of the pipeline to be measured; the second dynamic pressure sensor is arranged at the second end of the pipeline to be measured; the first dynamic pressure sensor and the second dynamic pressure sensor are configured to collect the dynamic pressure signal; the dynamic pressure signal is used to calculate the time difference of the leakage signal; the gas-liquid two-phase separator is arranged at the second end of the pipeline to be measured 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 density, liquid density, pure gas sound speed, and pure liquid sound speed under the conditions of the average pipeline internal pressure and the average pipeline internal temperature; the gas volume flowmeter is arranged at the second end of the pipeline to be measured and is configured to collect the gas volume flow; the leakage location calculation module is configured to calculate the pure gas sound speed according to the correction coefficient; the correction coefficient is related to the average pipeline cross-section gas holdup; calculate the pipeline internal sound speed according to the average pipeline cross-section gas holdup, gas density, liquid density, pure gas sound speed, and pure liquid sound speed; calculate the actual pipeline internal gas flow velocity according to the average pipeline cross-section gas holdup and the gas volume flow; obtain the leakage location result according to the time difference of the leakage signal, the pipeline internal sound speed, and the actual pipeline internal gas flow velocity.

[0027] The sound velocity in the pipe is calculated based on the average gas holdup in the pipe cross-section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity in the pipe is calculated based on the average gas holdup in the pipe cross-section and gas volume flow rate. According to the leakage signal time difference, the sound velocity in the pipe, and the actual gas velocity in the pipe, the leakage location result is obtained. By comprehensively considering the gas-liquid phase distribution state and gas-liquid phase flow state in the pipe, the sound velocity calculation model and leakage location model in gas-liquid two-phase stratified flow are improved, the accuracy of leakage location in stratified flow pipes is increased, and the problem of large leakage location error in current stratified flow pipes is solved. The leakage location ability in complex environments is improved, especially the location accuracy of acoustic wave method leakage detection technology when applied to multiphase flow pipes.

[0028] In a third aspect, an embodiment of the present application provides a leakage location system for a stratified flow pipe based on a multi-source sensing system. The leakage location system for a stratified flow pipe 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 so that the at least one processor can execute the method provided in the first aspect.

[0029] The leakage location system for a stratified flow pipe based on a multi-source sensing system executes the method provided in the first aspect. The sound velocity in the pipe is calculated based on the average gas holdup in the pipe cross-section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity in the pipe is calculated based on the average gas holdup in the pipe cross-section and gas volume flow rate. According to the leakage signal time difference, the sound velocity in the pipe, and the actual gas velocity in the pipe, the leakage location result is obtained. By comprehensively considering the gas-liquid phase distribution state and gas-liquid phase flow state in the pipe, the sound velocity calculation model and leakage location model in gas-liquid two-phase stratified flow are improved, the accuracy of leakage location in stratified flow pipes is increased, and the problem of large leakage location error in current stratified flow pipes is solved. The leakage location ability in complex environments is improved, especially the location accuracy of acoustic wave method leakage detection technology when applied to multiphase flow pipes.

[0030] In a fourth aspect, an embodiment of the present application provides a computer-readable medium, on which computer program instructions are stored, and the computer program instructions can be executed by a processor to implement the method provided in the first aspect.

[0031] Computer program instructions in a computer-readable medium provide a method according to the first aspect, calculating the sound speed in the pipe by calculating based on the average gas holdup in the pipe cross-section, gas density, liquid density, pure gas sound speed, and pure liquid sound speed. Calculating the actual gas flow velocity in the pipe according to the average gas holdup in the pipe cross-section and the gas volume flow rate. Obtaining the leakage location result according to the leakage signal time difference, the sound speed in the pipe, and the actual gas flow velocity in the pipe. Considering comprehensively the gas-liquid phase distribution state and the gas-liquid phase flow state in the pipe, improving the sound speed calculation model and the leakage location model in gas-liquid two-phase stratified flow, improving the accuracy of leakage location in stratified flow pipelines, and solving the problem of large leakage location error in current stratified flow pipelines. Improving the leakage location ability in complex environments, especially improving the location accuracy of the acoustic wave method leakage detection technology when applied to multiphase flow pipelines. Brief Description of the Drawings

[0032] Figure 1 It is a schematic structural diagram of a stratified flow pipeline leakage location system based on a multi-source sensing system provided by an embodiment of the present application;

[0033] Figure 2 It is a schematic flowchart of a stratified flow pipeline leakage location method based on a multi-source sensing system provided by an embodiment of the present application;

[0034] Figure 3 It is a schematic diagram of a scenario of a stratified flow pipeline leakage location method based on a multi-source sensing system provided by an embodiment of the present application. Detailed Embodiments

[0035] Next, the technical solutions in the embodiments of the present invention will be described with reference to the accompanying drawings in the embodiments of the present invention. Among them, in the description of the embodiments of the present invention, unless otherwise specified, "a plurality" means two or more than two. "At least one (item)" or its similar expression refers to any combination of these items, including any combination of single item (item) or plural items (items). For example, at least one (item) of a, b, or c can represent: a, b, c, a - b, a - c, b - c, or a - b - c, where a, b, c can be single or multiple.

[0036] In addition, for the convenience of clearly describing the technical solutions of the embodiments of the present invention, in the embodiments of the present invention, terms such as "first" and "second" are used to distinguish identical or similar items with basically the same functions and effects. Those skilled in the art can understand that terms such as "first" and "second" do not limit the quantity and execution order, and "first", "second", etc. do not necessarily mean different. At the same time, in the embodiments of the present invention, words such as "exemplary" or "for example" are used to indicate examples, illustrations or explanations. Any embodiment or design solution described as "exemplary" or "for example" in the embodiments of the present invention should not be construed as being more preferred or having more advantages than other embodiments or design solutions. Rather, the use of words such as "exemplary" or "for example" is intended to present relevant concepts in a specific manner for easy understanding.

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

[0038] The embodiment of the present application provides a method for locating leaks in a stratified flow pipeline based on a multi-source sensing system, which is applicable to improving the leak location scenario in a complex environment, especially in the application scenario of a multiphase flow pipeline. The sound velocity in the pipeline is calculated according to the gas holdup in the average pipeline cross-section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. The actual gas velocity in the pipeline is calculated according to the gas holdup in the average pipeline cross-section and the gas volume flow rate. According to the time difference of the leakage signal, the sound velocity in the pipeline, and the actual gas velocity in the pipeline, the leakage location result is obtained. By comprehensively considering the gas-liquid phase distribution state and gas-liquid phase flow state in the pipeline, the sound velocity calculation model and leakage location model in the gas-liquid two-phase stratified flow are improved, the accuracy of leak location in the stratified flow pipeline is improved, and the problem of large leak location error in the current stratified flow pipeline is solved. The leak location ability in a complex environment is improved, especially the location accuracy of the acoustic wave method leak detection technology in the application of multiphase flow pipelines.

[0039] The embodiment of the present application provides a system for locating leaks in a stratified flow pipeline based on a multi-source sensing system, which can execute the method for locating leaks in a stratified flow pipeline based on a multi-source sensing system provided by the embodiment of the present application. Figure 1 It is a schematic structural diagram of a system for locating leaks in a stratified flow pipeline based on a multi-source sensing system provided by the embodiment of the present application.

[0040] As Figure 1As shown, the hierarchical flow pipeline leakage location system based on a multi-source sensing system 001 includes at least one processor 011 and a memory 012 communicatively connected to the at least one processor; wherein, the memory 012 stores instructions executable by the at least one processor 011, and when the instructions are executed by the at least one processor 011, the at least one processor 011 is enabled to execute the hierarchical flow pipeline leakage location method provided in the embodiments of the present application.

[0041] As Figure 3 As shown, in some embodiments, the embodiments of the present application provide a hierarchical flow pipeline leakage location system based on a multi-source sensing system. The hierarchical flow pipeline leakage location system based on a multi-source sensing system includes: a first cross-section gas holdup measurement device 10, a second cross-section gas holdup measurement 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 flowmeter 19, and a leakage location calculation module 20.

[0042] The first cross-section gas holdup measurement device 10 is arranged at the first end of the pipeline to be measured. The first end is the starting end of the pipeline to be measured.

[0043] The second cross-section gas holdup measurement device 11 is arranged at the second end of the pipeline to be measured. The second end is the termination end of the pipeline to be measured.

[0044] The first cross-section gas holdup measurement device 10 and the second cross-section gas holdup measurement device 11 are configured to collect the cross-section gas holdup. The cross-section gas holdup is used to calculate the average cross-section gas holdup.

[0045] The first pressure sensor 12 is arranged at the first end of the pipeline to be measured.

[0046] The second pressure sensor 13 is arranged at the second end of the pipeline to be measured.

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

[0048] The first temperature sensor 14 is arranged at the first end of the pipeline to be measured.

[0049] The second temperature sensor 15 is arranged at the second end of the pipeline to be measured.

[0050] The first temperature sensor 14 and the second temperature sensor 15 are configured to collect the in-pipe temperature. The temperature is used to calculate the average in-pipe temperature.

[0051] The first dynamic pressure sensor 16 is arranged at the first end of the pipeline to be measured.

[0052] The second dynamic pressure sensor 17 is disposed at the second end of the pipeline to be measured.

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

[0054] The gas-liquid two-phase separator 18 is disposed at the second end of the pipeline to be measured 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 density, liquid density, pure gas sound velocity, and pure liquid sound velocity under the conditions of the average in-pipe pressure and average in-pipe temperature.

[0055] The gas volume flowmeter 19 is disposed at the second end of the pipeline to be measured and is configured to collect the gas volume flow.

[0056] The leakage location calculation module 20 is configured to calculate the pure gas sound velocity according to the correction factor. The correction factor is related to the gas holdup in the average pipeline cross-section. Calculate the in-pipe sound velocity according to the gas holdup in the average pipeline cross-section, gas density, liquid density, pure gas sound velocity, and pure liquid sound velocity. Calculate the actual in-pipe gas velocity according to the gas holdup in the average pipeline cross-section and the gas volume flow. Obtain the leakage location result according to the leakage signal time difference, in-pipe sound velocity, and actual in-pipe gas velocity.

[0057] Figure 2 It is a schematic flow diagram of a method for locating leakage in a stratified flow pipeline based on a multi-source sensing system provided by an embodiment of the present application. As Figure 2 shown, in some embodiments, the method for locating leakage in a stratified flow pipeline based on a multi-source sensing system includes the following steps:

[0058] S1. Collect the gas holdup in the cross-sections at the first end and the second end of the pipeline to be measured.

[0059] The gas holdup is used to calculate the average cross-section gas holdup.

[0060] As Figure 3 shown, the first end is the starting end of the pipeline to be measured. The second end is the terminating end of the pipeline to be measured. Exemplarily, the gas holdup measuring devices installed at the starting point and the ending point of the pipeline estimate the in-pipe cross-section gas holdup with the average value of the measurement values of the two.

[0061] S2. Collect the in-pipe pressures at the first end and the second end of the pipeline to be measured.

[0062] The in-pipe pressures are used to calculate the average in-pipe pressure. Exemplarily, the pressure sensors installed at the starting point and the ending point of the pipeline estimate the in-pipe pressure with the average value of the measurement values at the starting and ending points.

[0063] S3. Collect the in-pipe temperatures at the first end and the second end of the pipeline to be measured.

[0064] The temperature inside the pipe is used to calculate the average temperature inside the pipe. Exemplarily, temperature sensors installed at the starting point and the ending point of the pipeline estimate the temperature inside the pipe by taking the average of the measured values at the starting and ending points.

[0065] By performing Step S1 to Step S3, the pressure, cross-sectional gas holdup, and the temperature of the medium inside the pipe are measured in real time at the starting point and the ending point of the pipeline to be measured.

[0066] S4, Collect the dynamic pressure signals at the first end and the second end of the pipeline to be measured.

[0067] The dynamic pressure signals are used to calculate the leakage signal time difference. In some embodiments, dynamic pressure sensors installed at both ends of the pipeline are both installed on the upper part of the pipeline to collect the dynamic pressure signals during the leakage process. Exemplarily, the leakage signal time difference is the time when the leakage signal propagates to the first end minus the time when the leakage signal propagates to the second end.

[0068] S5, Collect the gas volume flow rate at the second end of the pipeline to be measured.

[0069] Exemplarily, a gas-liquid two-phase separator and a gas flow meter installed at the end of the pipeline are used to measure the gas flow rate inside the pipe and calculate the gas flow velocity inside the pipe based on the cross-sectional gas holdup inside the pipe.

[0070] S6, Calculate the pure gas sound speed according to the correction factor.

[0071] The correction factor is related to the average cross-sectional gas holdup of the pipeline. Exemplarily, the calculation formula of the correction factor includes:

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

[0073] Wherein, f T represents the correction factor; a represents the average cross-sectional gas holdup of the pipeline.

[0074] In some embodiments, the calculation formula of the pure gas sound speed includes:

[0075]

[0076] Wherein, c G represents the pure gas sound speed in the pure gas medium; f T represents the correction factor; n = 1.4; Z represents the compression 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 temperature inside the pipe.

[0077] S7. Under the conditions of the average pipe pressure and the average pipe temperature, confirm the gas density, liquid density, pure gas sound speed, and pure liquid sound speed according to the gas-liquid two-phase separation results at the first end and the second end of the pipeline to be measured.

[0078] S8. Calculate the sound speed in the pipe according to the average gas holdup in the pipe cross-section, gas density, liquid density, pure gas sound speed, and pure liquid sound speed.

[0079] In some embodiments, the calculation formula for the sound speed in the pipe includes:

[0080]

[0081] where c represents the sound speed in the pipe; α represents the average gas holdup in the pipe cross-section; ρ G represents the gas density; ρ L represents the liquid density; c G represents the pure gas sound speed in the pure gas medium; c L represents the pure liquid sound speed in the pure liquid medium.

[0082] S9. Calculate the actual gas flow velocity in the pipe according to the average gas holdup in the pipe cross-section and the gas volume flow rate.

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

[0084]

[0085] where u represents the actual gas flow velocity in the pipe; Q G represents the gas volume flow rate; D represents the pipe diameter; α represents the average gas holdup in the pipe cross-section.

[0086] S10. Obtain the leakage location result according to the leakage signal time difference, the sound speed in the pipe, and the actual gas flow velocity in the pipe.

[0087] In some embodiments, the calculation formula for the leakage location result includes:

[0088]

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

[0090] In this way, the dynamic pressure signals generated by the leakage are collected at the starting point and the ending point of the pipeline respectively. Calculate the time delay of the two dynamic pressure signals. Locate the leakage point according to the time delay of the two signals, the propagation speed of the sound wave in the gas-liquid two-phase stratified flow, and the gas flow velocity in the pipeline.

[0091] As can be seen from the above embodiments, the present application comprehensively considers the gas-liquid phase distribution state and gas-liquid phase flow state in the pipeline, improves the sound speed calculation model and leakage location model in gas-liquid two-phase stratified flow, improves the accuracy of leakage location in stratified flow pipelines, and solves the problem of large leakage location error in current stratified flow pipelines. It improves the leakage location ability in complex environments, especially improves the location accuracy of acoustic wave method leakage detection technology when applied to multiphase flow pipelines.

[0092] Based on the same inventive concept, an embodiment of the present application also provides a stratified flow pipeline leakage location system based on a multi-source sensing system. The method corresponding to the stratified flow pipeline leakage location system based on the multi-source sensing system may be the stratified flow pipeline leakage location method based on the multi-source sensing system in the foregoing embodiments, and the principle of solving problems is similar to that of this method. The stratified flow pipeline leakage location system based on the multi-source sensing system provided in the embodiment of the present 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 so that the at least one processor can execute the methods and / or technical solutions of multiple embodiments of the present application described above.

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

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

[0095] A computer-readable signal medium may include a data signal propagated in a baseband or as part of a carrier wave, in which computer-readable program code is carried. Such a propagated data signal may take various forms, including - but not limited to - electromagnetic signals, optical signals, or any suitable combination of the foregoing. The computer-readable signal medium may also be any computer-readable medium other than a computer-readable storage medium, which can send, propagate, or transmit a program for use by or in connection with an instruction execution system, apparatus, or device.

[0096] The program code contained on a computer-readable medium can be transmitted using any appropriate medium, including - but not limited to - wireless, wire, optical fiber cable, RF, etc., or any suitable combination of the foregoing.

[0097] The computer program code for performing the operations of this application can be written in one or more programming languages or combinations thereof. The programming languages include object-oriented programming languages such as Java, Smalltalk, C++, and also include conventional procedural programming languages such as the "C" language or similar programming languages. The program code can be executed entirely on the user's computer, partially on the user's computer, executed as a stand-alone software package, partially on the user's computer and partially on a remote computer, or entirely on a remote computer or server. In the case of a remote computer, the remote computer can be connected to the user's computer through 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., using an Internet service provider to connect through the Internet).

[0098] The flowcharts or block diagrams in the accompanying drawings illustrate the possible architectures, functions, and operations of devices, methods, and computer program products according to various embodiments of this application. In this regard, each block in the flowchart or block diagram may represent a module, a program segment, or a part of code that contains one or more executable instructions for implementing the specified logical function. It should also be noted that in some alternative implementations, the functions marked in the blocks may occur in a different order than marked in the accompanying drawings. For example, two consecutive blocks shown may actually be executed substantially in parallel, and they may sometimes be executed in the reverse order, depending on the functions involved. It should also be noted that each block in the block diagram and / or flowchart, and the combination of blocks in the block diagram and / or flowchart, can be implemented by a dedicated hardware-based system for performing the specified functions or operations, or can be implemented by a combination of dedicated hardware and computer instructions.

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

[0100] In several embodiments provided in the present application, it should be understood that the disclosed systems, devices, and methods can be implemented in other ways. For example, the device embodiments described above are merely illustrative. For example, the division of the units is only a logical function division, and there may be other division methods in actual implementation. For example, multiple units or page components can be combined or integrated into another system, or some features can be ignored or not executed. Another point is that the displayed or discussed couplings or direct couplings or communication connections to each other can be through some interfaces, and the indirect couplings or communication connections of devices or units can be in electrical, mechanical, or other forms.

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

[0102] In addition, the functional units in each embodiment of the present application can be integrated into one processing unit, or each unit can exist physically alone, or two or more units can be integrated into one unit. The above-mentioned integrated units can be implemented in the form of hardware or in the form of a combination of hardware and software functional units.

[0103] The above-mentioned integrated units implemented in the form of software functional units can be stored in a computer-readable storage medium. The above-mentioned software functional units stored in a storage medium include several instructions to enable a computer device (which can be a personal computer, a server, or a network device, etc.) or a processor to execute some steps of the methods described in each embodiment of the present application. The foregoing storage medium includes: various media such as USB flash drives, mobile hard disks, read-only memories (ROMs), random access memories (RAMs), magnetic disks, or optical discs that can store program codes.

[0104] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present application, rather than limiting them; although the present application has been described in detail with reference to the foregoing embodiments, those of ordinary skill in the art should understand that they can still modify the technical solutions described in the foregoing embodiments, or perform equivalent replacements for some of the technical features; and these modifications or replacements 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 the present application.

[0105] In addition, it is obvious that the word "including" does not exclude other units or steps, and the singular does not exclude the plural. The multiple units or devices stated in the apparatus claims can also be implemented by one unit or device through software or hardware. The terms such as first and second are used to denote names, rather than indicating any particular order.

Claims

1. A method for locating leakage in a stratified flow pipeline based on a multi-source sensing system, characterized in that: include: Collecting the cross-sectional gas content of the first end and the second end of the pipeline to be tested; the cross-sectional gas content is used to calculate the average cross-sectional gas content; the first end is the starting end of the pipeline to be tested; the second end is the terminating end of the pipeline to be tested; Collecting the in-pipe pressure at the first end and the second end of the pipeline to be tested; the in-pipe pressure is used to calculate the average in-pipe pressure; Collecting the internal temperature of the first end and the second end of the pipeline to be measured; the internal temperature of the pipeline is used to calculate the average internal temperature of the pipeline; Collecting dynamic pressure signals from the first end and the second end of the pipeline to be tested; the dynamic pressure signals are used to calculate the leakage signal time difference; Collecting the gas volume flow rate at the second end of the pipeline to be tested; Calculating the pure gas sound velocity according to the correction coefficient; the correction coefficient is related to the average pipeline cross-section gas content; Under the conditions of the average in-pipe pressure and the average in-pipe temperature, confirm the gas density, the liquid density, the pure gas sound velocity and the pure liquid sound velocity according to the gas-liquid two-phase separation results at the first end and the second end of the pipeline to be tested; Calculate the sound velocity in the pipe according to the average pipe cross-section gas content, the gas density, the liquid density, the pure gas sound velocity, and the pure liquid sound velocity; Calculating the actual flow rate of the gas in the pipe according to the average pipe cross-section gas content and the gas volume flow rate; The leakage location result is obtained according to the leakage signal time difference, the sound velocity in the pipe and the actual flow velocity of the gas in the pipe.

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

3. The method for locating leakage in a stratified flow pipeline based on a multi-source sensing system according to claim 2, characterized in that: The calculation formula of the pure gas sound velocity includes: Among them, c G Expressed as the pure gas sound speed in a pure gas medium; f T It is expressed as the correction coefficient; n=1.4; Z is the compression factor of the gas in the gas-liquid two-phase separation result; R is 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 is the average tube temperature.

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

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

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

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

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

9. A stratified flow pipeline leakage location system based on a multi-source sensing system, characterized in that: include: at least one processor; a memory communicatively coupled to the at least one processor; The memory stores instructions that can be executed by the at least one processor, and the instructions are executed by the at least one processor so that the at least one processor can execute the method according to any one of claims 1 to 7.

10. A computer readable medium having computer program instructions stored thereon, wherein the computer program instructions can be executed by a processor to implement the method according to any one of claims 1 to 7.

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