A system and method for establishing a leak signature for a natural gas gathering pipeline

Abstract

The application discloses a system and method for establishing a natural gas gathering pipeline leakage feature, comprising: a gas supply device for providing a required leakage pressure to an experimental gathering pipeline; a leakage simulation device forming a leakage point and being arranged on the outer wall of the experimental gathering pipeline in the form of a preset leakage mode, the preset leakage mode including a leakage point shape corresponding to a leakage type, a leakage point size and a leakage pressure; a vibration signal acquisition device having a vibration sensor array arranged at a to-be-tested leakage point, for acquiring a leakage vibration signal corresponding to a current leakage mode when pressure is applied to the pipeline; and a sample library establishing device for collecting leakage vibration signals under different leakage modes and performing feature extraction, and constructing a leakage identification sample library matched with the modes and the features. The application constructs the leakage identification sample library, and solves the problem of lacking scientific and comprehensive leakage identification basis for pipeline leakage detection of pipe body vibration.

Description

Technical Field

[0001] This invention relates to the field of natural gas gathering and transmission pipeline safety monitoring technology, and in particular to a system and method for establishing leakage characteristics of natural gas gathering and transmission pipelines. Background Technology

[0002] In recent years, with the continuous aggravation of environmental pollution and its widespread attention, natural gas, as a clean and environmentally friendly high-quality energy source, has gradually occupied an important position in the energy structure. The scale of natural gas pipeline networks has been continuously expanding, with gas field gathering and transmission pipelines, long-distance natural gas pipelines, and urban natural gas pipelines forming a pattern of "interconnected trunk lines and localized networks." As operating time continues to extend, natural gas leaks caused by factors such as pipeline corrosion, wear, terrain subsidence, and third-party damage will intensify. If natural gas leaks are not detected and properly handled in a timely manner, they can easily cause fires or explosions. Therefore, timely and accurate detection of leaks and identification of leak points are crucial for the safe gathering and transmission of natural gas.

[0003] Currently, there are many methods for leak monitoring in oil and gas pipelines, and their classification methods are also diverse. Based on the different parameters being detected, they are mainly divided into mass / volume balance methods, applied statistical methods, negative pressure wave methods, transient model methods, distributed optical fiber methods, and acoustic methods. The deployment of monitoring methods primarily involves laying sensors along the entire pipeline. Mass / volume balance methods achieve monitoring by installing embedded pressure / flow sensors along the entire pipeline; distributed optical fiber methods achieve monitoring by laying optical fibers in the same trench as the pipeline; acoustic methods achieve monitoring by installing embedded acoustic sensors along the entire pipeline. Under this deployment method, the monitoring accuracy is greatly affected by the sensor deployment density. That is, to obtain high-precision monitoring results, the sensor deployment density must be increased. This deployment method is very costly, and deploying high-precision monitoring methods throughout low-risk areas leads to increased costs and wasted resources.

[0004] A system for measuring the propagation velocity of vibration waves from natural gas pipeline leaks is disclosed in an existing patent document (publication number CN102997053A). This system improves the accuracy of measuring the propagation velocity of vibration waves from natural gas pipeline leaks by densely deploying fiber optic vibration sensing units. However, this solution does not consider leaks caused by stress cracking and liquid corrosion, nor does it identify leaks in natural gas gathering and transmission pipelines using leakage vibration signals.

[0005] A pipeline leak monitoring method and system are disclosed in an existing patent document (publication number CN112432061A). This method calculates the leak location based on the distance between secondary sensors and the time difference in detecting infrasound, thereby ultimately achieving leak monitoring and leak location calculation. However, this method does not consider leaks caused by stress cracking and liquid corrosion, nor does it utilize leak vibration signals to identify leaks in natural gas gathering and transmission pipelines.

[0006] An existing patent document (publication number CN216345464U) discloses an online monitoring device for locating pipeline leaks based on MEMS accelerometers. This device solves the management and technical problems of locating leaks in water supply pipelines, reducing the size and workload of leak detection teams. However, this solution does not consider leaks caused by stress cracking and liquid corrosion, nor does it consider identifying leaks in natural gas gathering and transmission pipelines through leakage vibration signals.

[0007] Therefore, existing technologies for monitoring leaks in natural gas gathering and transmission pipelines, such as infrasound, negative pressure wave, and pressure / flow balance methods, have relatively fixed application scenarios and all require modifications to the pipeline structure. Furthermore, existing technologies all use a single method for leak monitoring, achieving sufficient accuracy for pipeline leaks caused by geological disasters, but failing to accurately and effectively monitor leaks due to stress cracking or fluid corrosion.

[0008] In summary, the existing technology needs to provide a method that comprehensively considers the factors affecting leakage in natural gas gathering and transmission pipelines and can identify leakage in natural gas gathering and transmission pipelines through leakage vibration signals. Summary of the Invention

[0009] The purpose of this invention is to provide a solution that comprehensively considers the factors affecting leakage in natural gas gathering and transmission pipelines and can identify leakage in natural gas gathering and transmission pipelines through leakage vibration signals, thereby solving the problem that existing natural gas gathering and transmission pipeline leakage monitoring technologies lack scientific and comprehensive leakage identification basis.

[0010] To address the aforementioned technical problems, this invention provides a system for establishing leakage characteristics of a natural gas gathering and transmission pipeline, comprising: a gas supply device for providing the required leakage pressure to the experimental gathering and transmission pipeline; a leakage simulation device for forming a leakage point and setting it on the outer wall of the experimental gathering and transmission pipeline in the form of a preset leakage pattern, wherein the preset leakage pattern includes the leakage point shape, leakage point size, and leakage pressure corresponding to the leakage type; a vibration signal acquisition device comprising a vibration sensor array, wherein the vibration sensor array is set at the leakage point to be tested, for acquiring leakage vibration signals corresponding to the current leakage pattern when pressure is applied to the pipeline; and a sample library establishment device for collecting leakage vibration signals under different leakage patterns and extracting features to construct a leakage identification sample library that matches patterns with features.

[0011] Preferably, the gas supply device includes: a gas storage device for storing a gaseous medium; a pressure reducing valve connected to the gas storage device for adjusting the pressure of the gaseous medium; a delivery pipeline with its two ends connected to the gas storage device and the gas injection port of the experimental gathering and transportation pipeline, respectively, for delivering the gaseous medium to the experimental gathering and transportation pipeline; and a pressure sensor installed on the delivery pipeline for monitoring the gas injection pressure.

[0012] Preferably, the leakage simulation device is disposed on a leakage stub in the experimental gathering and transportation pipeline. The leakage simulation device includes at least two leakage through holes, which are formed at least two phases along the circumferential direction of the outer wall of the pipeline at a first axial position on the leakage stub. The shape of the leakage through holes matches the type of leakage currently being simulated.

[0013] Preferably, the leakage simulation device further includes: a short pipe disposed outside the pipe and covering the leakage through hole with an opening at the first end; and a rupture disc disposed at the second end of the short pipe, which is the leakage point to be tested, wherein the bursting pressure of the rupture disc matches the leakage pressure required for the current simulation.

[0014] Preferably, when the leakage type is corrosion perforation, the corresponding leakage through-hole is a round hole; when the leakage type is stress cracking, the corresponding leakage through-hole is a crevice.

[0015] Preferably, the vibration sensor array includes two vibration sensor units arranged on both sides of the leak point to be tested along the axial direction of the pipe. Each vibration sensor unit includes at least one set of vibration sensor assemblies, which are respectively arranged on pipe sections at different distances from the leak point to be tested. The vibration sensor assemblies include vibration sensors arranged in different orientations, and each vibration sensor has an acceleration sensor that measures different vibration directions at the current leak location.

[0016] Preferably, the vibration signal acquisition device further includes: an adhesive block, which couples to the outer surface of the experimental collection and transportation pipeline via a vibration coupling agent; and connecting bolts, which mount the vibration sensor on the adhesive block.

[0017] Preferably, the sample library building device is configured to construct the leak identification sample library using the following steps: extracting the signal energy of the leak vibration signals from different vibration sensors under different leak modes using the root mean square (RMS) processing method; performing spectral analysis on the signal energy of the leak vibration signals to obtain the frequency domain feature information of the leak vibration signals, the frequency domain feature information including signal amplitude energy, vibration range, and vibration frequency distribution; extracting pipeline leak identification criteria from the frequency domain feature information of the leak vibration signals, so as to form a leak identification sample library using the pipeline leak identification criteria under different leak modes and the frequency domain feature information.

[0018] Preferably, the sample library establishment device is further configured to: select the optimal vibration signal acquisition position from the signal energy of leakage vibration signals from different vibration sensors under the same leakage mode; and determine the frequency domain feature information and pipeline leakage identification basis corresponding to the corresponding leakage mode based on the leakage vibration signal at the optimal vibration signal acquisition position.

[0019] Preferably, the root mean square frequency is extracted from the frequency domain feature information of the leakage vibration signal, and the root mean square frequency is used as the basis for identifying the corresponding pipeline leakage.

[0020] Preferably, the sample library establishment device is further used to collect and store leakage identification thresholds of the experimental collection and transportation pipeline in different pipeline burial areas, including: using the vibration signal acquisition device to collect natural noise signals for a preset duration and using the feature values ​​of the natural noise signals as the leakage identification thresholds, wherein the feature values ​​of the natural noise signals are the average value of the root mean square energy of the natural noise signals.

[0021] Preferably, the system further includes a leakage identification module, which is used to monitor whether a leakage has occurred in the current pipeline based on the signal energy of the real-time leakage vibration signal of the pipeline to be detected and the leakage identification threshold corresponding to the burial area of ​​the pipeline to be detected. When the signal energy of the real-time leakage vibration signal reaches or exceeds the leakage identification threshold of the corresponding area, the leakage identification sample library is used to identify the leakage characteristics of the current pipeline leakage event.

[0022] On the other hand, embodiments of the present invention also provide a method for establishing leakage characteristics of natural gas gathering and transmission pipelines, the method being implemented using the system described above.

[0023] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0024] This invention proposes a system and method for establishing leakage characteristics of natural gas gathering and transmission pipelines. The system and method utilize a leakage simulation device and vibration signal acquisition devices deployed along the pipeline to excite and capture pipe vibration signals caused by different leakage conditions, achieving full coverage of leakage modes. Furthermore, by optimizing the installation location of the vibration signal acquisition devices, the phase of the leakage point is ensured to not affect the leakage signal acquisition, guaranteeing the scientific validity and reliability of the signal acquisition. Finally, based on the analysis results of the leakage vibration signals, the criteria for pipeline leakage identification are clarified, and a leakage identification sample library matching patterns and features is constructed, solving the problem that pipeline leakage monitoring technology based on pipe vibration lacks a scientific and comprehensive basis for leakage identification.

[0025] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention may be realized and obtained by means of the structures particularly pointed out in the description, claims, and drawings. Attached Figure Description

[0026] The accompanying drawings are provided to further illustrate the invention and form part of the specification. They are used in conjunction with the embodiments of the invention to explain the invention and do not constitute a limitation thereof. In the drawings:

[0027] Figure 1 This is a schematic diagram of the overall structure of a system for establishing leakage characteristics of a natural gas gathering and transmission pipeline according to an embodiment of this application.

[0028] Figure 2 This is a schematic diagram of the specific structure of a system for establishing leakage characteristics of a natural gas gathering and transmission pipeline according to an embodiment of this application.

[0029] Figure 3 This is a schematic diagram of the leakage simulation device in a system for establishing leakage characteristics of natural gas gathering and transmission pipelines, according to an embodiment of this application.

[0030] Figure 4 This is an example diagram showing the leakage location, vibration direction, and installation phase of a vibration signal acquisition device in a system for establishing leakage characteristics of a natural gas gathering and transmission pipeline, according to an embodiment of this application.

[0031] Figure 5 This is a schematic diagram of the vibration signal acquisition device in a system for establishing leakage characteristics of natural gas gathering and transmission pipelines, according to an embodiment of this application.

[0032] Figure 6 This is a schematic diagram illustrating the principle of extracting the basis for identifying pipeline leaks in a system for establishing leakage characteristics of natural gas gathering and transmission pipelines, as described in an embodiment of this application.

[0033] Figure 7This is an example diagram illustrating the layout structure of a vibration signal acquisition device in a system for establishing leakage characteristics of a natural gas gathering and transmission pipeline, as described in an embodiment of this application.

[0034] Figure 8 The waveform of the leakage vibration signal collected by the vibration signal acquisition device at the first location in the system for establishing leakage characteristics of a natural gas gathering and transmission pipeline according to an embodiment of this application is shown.

[0035] Figure 9 The waveform of the leakage vibration signal collected by the vibration signal acquisition device at the second position in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application is shown.

[0036] Figure 10 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the first leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0037] Figure 11 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the second leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0038] Figure 12 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the third leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0039] Figure 13 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the fourth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0040] Figure 14 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the fifth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0041] Figure 15 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the sixth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0042] Figure 16 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the seventh leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0043] Figure 17 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the eighth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0044] Figure 18 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the ninth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0045] Figure 19 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the tenth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0046] Figure 20 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the eleventh leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0047] Figure 21 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the twelfth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0048] Figure 22 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the thirteenth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0049] Figure 23 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the fourteenth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application.

[0050] Figure 24 This is an example diagram showing the leakage vibration signal and frequency domain characteristic information corresponding to the fifteenth leakage mode in the system for establishing leakage characteristics of natural gas gathering and transmission pipelines according to an embodiment of this application. Detailed Implementation

[0051] The embodiments of the present invention will be described in detail below with reference to the accompanying drawings and examples, so that the process of how the present invention uses technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that, as long as there is no conflict, the various embodiments and features in the various embodiments of the present invention can be combined with each other, and the resulting technical solutions are all within the protection scope of the present invention.

[0052] Furthermore, the steps illustrated in the flowcharts of the accompanying drawings can be executed in a computer system such as a set of computer-executable instructions. Also, although a logical order is shown in the flowcharts, in some cases the steps shown or described may be performed in a different order than that presented here.

[0053] The terminology used herein is for the purpose of describing particular embodiments only and is not intended to limit the exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms “a” and “an” as used herein are also intended to include the plural. It should also be understood that the terms “comprising” and / or “including” as used herein specify the presence of the stated features, integers, steps, operations, units, and / or components, without excluding the presence or addition of one or more other features, integers, steps, operations, units, components, and / or combinations thereof.

[0054] A system for measuring the propagation velocity of vibration waves from natural gas pipeline leaks is disclosed in an existing patent document (publication number CN102997053A). This system improves the accuracy of measuring the propagation velocity of vibration waves from natural gas pipeline leaks by densely deploying fiber optic vibration sensing units. However, this solution does not consider leaks caused by stress cracking and liquid corrosion, nor does it identify leaks in natural gas gathering and transmission pipelines using leakage vibration signals.

[0055] A pipeline leak monitoring method and system are disclosed in an existing patent document (publication number CN112432061A). This method calculates the leak location based on the distance between secondary sensors and the time difference in detecting infrasound, thereby ultimately achieving leak monitoring and leak location calculation. However, this method does not consider leaks caused by stress cracking and liquid corrosion, nor does it utilize leak vibration signals to identify leaks in natural gas gathering and transmission pipelines.

[0056] An existing patent document (publication number CN216345464U) discloses an online monitoring device for locating pipeline leaks based on MEMS accelerometers. This device solves the management and technical problems of locating leaks in water supply pipelines, reducing the size and workload of leak detection teams. However, this solution does not consider leaks caused by stress cracking and liquid corrosion, nor does it consider identifying leaks in natural gas gathering and transmission pipelines through leakage vibration signals.

[0057] Therefore, existing technologies for monitoring leaks in natural gas gathering and transmission pipelines, such as infrasound, negative pressure wave, and pressure / flow balance methods, have relatively fixed application scenarios and all require modifications to the pipeline structure. Furthermore, existing technologies all use a single method for leak monitoring, achieving sufficient accuracy for pipeline leaks caused by geological disasters, but failing to accurately and effectively monitor leaks due to stress cracking or fluid corrosion.

[0058] In summary, the existing technology needs to provide a method that comprehensively considers the factors affecting leakage in natural gas gathering and transmission pipelines and can identify leakage in natural gas gathering and transmission pipelines through leakage vibration signals.

[0059] Example 1

[0060] Figure 1 This is a schematic diagram of the overall structure of a system for establishing leakage characteristics of a natural gas gathering and transmission pipeline according to an embodiment of this application. Figure 2 This is a schematic diagram of the specific structure of a system for establishing leakage characteristics of a natural gas gathering and transmission pipeline, according to an embodiment of this application. (Combined with...) Figure 1 and Figure 2 The specific structure of the system for establishing leakage characteristics of natural gas gathering and transmission pipelines (hereinafter referred to as the "gathering and transmission pipeline leakage characteristic establishment system") described in the embodiments of the present invention will be explained.

[0061] like Figure 1 As shown, the system for establishing leakage characteristics of a gathering and transportation pipeline includes: a gas supply device A, a leakage simulation device B, a vibration signal acquisition device C, and a sample library establishment device D. The leakage simulation device B sets up a leak point on the outer wall of the experimental gathering and transportation pipeline in the form of a preset leakage pattern. The vibration signal acquisition device C has a vibration sensor array, which is positioned at the leak point to be tested.

[0062] Gas supply device A is configured to provide the required leakage pressure to the experimental gathering and transmission pipeline.

[0063] Vibration signal acquisition device C is configured to acquire leakage vibration signals corresponding to the current leakage mode when pressure is applied to the experimental collection and transmission pipeline.

[0064] The sample library building device D is configured to collect leakage vibration signals under different leakage modes, extract features from the leakage vibration signals under different leakage modes, and build a leakage identification sample library that matches the modes and features.

[0065] In this embodiment, the preset leakage mode includes: the leakage point morphology, leakage point size, and leakage pressure corresponding to the leakage type. Leakage types include, but are not limited to: corrosion perforation and stress cracking.

[0066] Specifically, the core cause of perforation leaks in natural gas pipelines is fluid accumulation corrosion. After water is produced from gas wells, due to complex terrain and significant elevation differences in the gathering and transmission pipeline network, formation water containing corrosive media such as elemental sulfur and lithium ions accumulates in low-lying areas of the pipeline, leading to internal corrosion and perforation. Therefore, the perforation morphology of natural gas gathering and transmission pipelines is typically circular, with a size generally ranging from 2 to 10 mm, and the leakage phase is uncertain.

[0067] The core cause of natural gas pipeline cracking and leakage is stress cracking, which is cracking caused by the pipeline being under high stress conditions for a long time due to factors such as temperature and external stress. Therefore, the morphology of stress cracking in natural gas gathering and transmission pipelines is slit-like, with a slit width ≤1mm and a slit length generally between 20 and 50mm, and the leakage phase is uncertain.

[0068] In one embodiment, reference Figure 2The gas supply device A includes: a gas storage device 1, a pressure reducing valve 2, a delivery pipeline 3, and a pressure sensor 4. The pressure reducing valve 2 is connected to the gas storage device 1, and both ends of the delivery pipeline 3 are connected to the gas storage device 1 and the gas injection port of the experimental gathering and transmission pipeline, respectively. The pressure sensor 4 is installed on the delivery pipeline 3.

[0069] The gas storage device 1 is configured to store a gaseous medium. Optionally, to reduce the impact of external environmental noise on the acquisition of leakage vibration signals, the gas storage device 1 may preferably be a nitrogen container.

[0070] Pressure reducing valve 2 is configured to adjust the pressure of the gaseous medium.

[0071] Delivery line 3 is configured to deliver gaseous medium to the experimental gathering and delivery line. Optionally, to reduce the impact of external environmental noise on the acquisition of leakage vibration signals, delivery line 3 may preferably be a high-pressure hose.

[0072] Pressure sensor 4 is configured to monitor the injection pressure.

[0073] In one embodiment, combined Figure 2 and Figure 3 Leakage simulation device B is installed on a leaking section of the experimental gathering and transportation pipeline. Leakage simulation device B includes at least two leakage through holes. The at least two leakage through holes are formed at a first axial position of the leaking section along at least two phases in the circumferential direction of the outer wall of the pipeline.

[0074] In this model, each leak point corresponds to a leaking through-hole. The shape of the leaking through-hole matches the type of leak being simulated. Specifically, when the leak type is corrosion perforation, the corresponding leaking through-hole is a round hole; when the leak type is stress cracking, the corresponding leaking through-hole is a crack.

[0075] The specific setting of the first axial position is not limited and can be reasonably selected according to actual application needs.

[0076] The specific phase setting method is not limited and can be reasonably selected according to the actual application requirements.

[0077] In one embodiment, continue to combine Figure 2 and Figure 3 The leakage simulation device B includes: short pipe 5 and rupture disc.

[0078] The short pipe 5 is set outside the experimental collection and transportation pipeline, and the opening at the first end is used to cover the leakage through hole so that the leakage through hole is located inside the opening circle.

[0079] A rupture disc is positioned at the second end of the short pipe 5, which serves as the leak point to be tested. The burst pressure of the rupture disc is matched to the leak pressure required for the current simulation.

[0080] Specifically, when simulating leakage at a specific leak / slot, only the welded short pipe 5 of the experimental leak / slot is fitted with a rupture disc corresponding to the pressure; the welded short pipes 5 of other leaks / slots are sealed with threaded plugs. The leaking short sections are not simultaneously installed on the experimental gathering and transport pipeline; they are replaced during use. To ensure the convenience and operability of the experiment, an operating pit is provided at the leaking short section, without backfilling. The preferred dimensions of the operating pit are 1.0m * 1.0m * 1.5m.

[0081] Optionally, refer to Figure 3 Leakage simulation device B may also include: a leakage short section, a short pipe 5, and a rupture disc.

[0082] Specifically, leakage signal excitation mainly takes two forms: corrosion perforation leakage and stress cracking leakage. A customized experimental gathering and transportation pipeline is buried at a depth of 1.0m. Leakage holes / slots are set on the main body of the experimental gathering and transportation pipeline at different phases of the leakage short section. Short pipes 5 are welded to the leakage holes / slots, and rupture discs with different burst pressures are installed at the ends of the short pipes 5. When the burst pressure of the rupture disc matches the leakage pressure required for the current simulation, the rupture disc cracks, gas leaks, and leakage vibration signals are excited.

[0083] In one embodiment, the vibration signal acquisition device C includes a vibration sensor array. The vibration sensor array includes two vibration sensor units respectively arranged on both sides of the leak point to be tested along the axial direction of the experimental gathering and transportation pipeline.

[0084] The vibration sensor unit includes at least one set of vibration sensor components, and the at least one set of vibration sensor components are respectively disposed on the pipe cross-section at different distances from the leak point to be tested.

[0085] The vibration sensor assembly includes vibration sensors positioned at different locations. Each vibration sensor includes an acceleration sensor that measures vibration in different directions at the current leak location.

[0086] When a natural gas gathering and transmission pipeline leaks, medium- and high-pressure gas is ejected at high speed through the leak hole, causing intense friction with the pipe wall at the leak hole and generating mechanical wave characteristic signals propagating along the pipe wall. Therefore, it is generally believed that the pipeline vibration signal caused by a natural gas leak is a broadband signal with a large proportion of high-frequency components. As the vibration signal propagates along the natural gas gathering and transmission pipeline, the high-frequency components gradually attenuate, but still account for most of the energy. Therefore, the technical parameters of the accelerometer used need to be specified as follows:

[0087] (1) Bandwidth: 0.2~6000Hz;

[0088] (2) Sensitivity: 500mV / g;

[0089] (3) Resonant frequency: 15kHz;

[0090] (4) Sampling frequency: 5000-15000 times / second, which can be set and adjusted independently.

[0091] Optionally, when a natural gas gathering and transmission pipeline leaks, the internal pressure system of the pipeline changes, and gas is ejected at high speed from the leak hole, generating mechanical waves that propagate along the pipeline. Since mechanical waves may propagate simultaneously in both axial and radial directions, a systematic study of the propagation law of the leakage vibration signal requires simultaneous acquisition and analysis of vibration signals propagating in both directions. Therefore, the preferred vibration direction can be a direction parallel to the pipeline axis and a direction perpendicular to the pipeline axis. Figure 4 (a) shows example diagrams for different vibration directions. (Refer to...) Figure 4 The accelerometer can be installed in vibration directions that are parallel to or perpendicular to the pipe axis.

[0092] Optionally, when a natural gas gathering and transmission pipeline leaks, the internal pressure system of the natural gas gathering and transmission pipeline changes, and gas is ejected at high speed from the leak hole, generating mechanical waves that propagate along the natural gas gathering and transmission pipeline. Because mechanical waves propagate in the form of body waves on the pipeline wall, they may exhibit different characteristic parameters and propagation characteristics in different directions. At the same time, since the location of the leak point is unpredictable, it is necessary to collect leak signals from multiple directions of the same leak point. Figure 4 (b) shows example diagrams from different orientations. (Refer to) Figure 4 The vibration sensor can be installed at the 0 o'clock, 3 o'clock, or 9 o'clock position.

[0093] The specific value of the spacing is not limited and can be reasonably selected according to the actual application requirements.

[0094] Specifically, when the vibration sensor array collects the leakage vibration signal corresponding to the current leakage mode, it is necessary to first connect the accelerometer to the chassis and signal acquisition software to enable the accelerometer to enter the signal acquisition state. Then, a hammer or drop shot method is used to tap any point on the experimental collection and transmission pipeline to verify the acquisition state of the accelerometer and ensure that the acquisition state of the accelerometer is normal.

[0095] In one embodiment, combined Figure 2 and Figure 5 The vibration signal acquisition device C also includes: adhesive block 6 and connecting bolt 7.

[0096] The adhesive block 6 is coupled to the outer surface of the experimental gathering and transportation pipeline through a vibration coupling agent.

[0097] Connecting bolt 7 mounts the vibration sensor onto the patch.

[0098] Specifically, please refer to Figure 5 Since the vibration sensor needs to be fixed on the outer surface of the experimental gathering and transportation pipeline without damaging the anti-corrosion layer of the pipeline, in order to increase the coupling between the vibration sensor and the experimental gathering and transportation pipeline and improve the signal acquisition effect, a special adhesive block 6 is fixed on the outer surface of the experimental gathering and transportation pipeline using a vibration coupling agent. Then, the vibration sensor is coupled by mounting it on the adhesive block 6 with connecting bolts 7.

[0099] Optionally, continue to refer to Figure 5 In order to improve the coupling between the vibration sensor and the experimental collection and transportation pipeline, the lower surface of the adhesive block 6 is designed into a corresponding arc shape according to the size of the experimental collection and transportation pipeline.

[0100] Example 2

[0101] Based on the above embodiment one, the implementation function of the sample library establishment device of the present invention will be specifically described below.

[0102] In one embodiment, the sample library building apparatus D is configured to build a leak identification sample library using the following steps:

[0103] Step S1: Based on the leakage vibration signals from different vibration sensors under different leakage modes, the root mean square (RMS) processing method is used to extract the signal energy of the leakage vibration signals.

[0104] Step S2: Perform spectrum analysis on the signal energy of the leakage vibration signal to obtain the frequency domain characteristic information of the leakage vibration signal.

[0105] Step S3: Extract pipeline leakage identification criteria from the frequency domain feature information of the leakage vibration signal, so as to form a leakage identification sample library by using the pipeline leakage identification criteria and frequency domain feature information under different leakage modes.

[0106] Specifically, in step S1, the root mean square (RMS) processing method is first used to extract signal energy, and the target signal is selected based on the extracted signal energy. First, the leakage vibration signal (sgy) data collected by the vibration signal sensor is exported, and the signal amplitude data is processed using the RMS method to obtain the signal energy. The signal energy is calculated using the following expression:

[0107]

[0108] In step S2, the frequency domain feature information includes: signal amplitude energy, vibration range, and vibration frequency distribution.

[0109] Specifically, in step S2, conventional Fourier transform is used to perform spectral analysis on the leakage vibration signal and the natural noise signal. First, according to Euler's formula:

[0110] e it =cos(t)+isin(t) (2)

[0111] The solution is:

[0112]

[0113] Substitute the calculated result into the Fourier series formula:

[0114]

[0115] Right now:

[0116]

[0117] in:

[0118]

[0119] As T approaches infinity, we can obtain:

[0120]

[0121] F(ω) can be derived from C when T approaches ∞. n ,available:

[0122]

[0123] Based on the Fourier transform described above, the leakage vibration signal collected by the vibration sensor can be converted to the frequency domain for analysis to obtain frequency domain feature information. This frequency domain feature information mainly includes signal amplitude energy, vibration range, and vibration distribution.

[0124] In step S3, the pipeline leakage is identified based on the root mean square frequency (RMS frequency). Specifically, the RMS frequency is extracted from the frequency domain characteristics of the leakage vibration signal and used as the basis for identifying the pipeline leakage.

[0125] Specifically, in step S3, the root mean square frequency (RMS frequency) is selected as the basis for identifying pipeline leaks. The RMS frequency is the square root of the calculated RMS frequency. (Reference) Figure 6 The auxiliary physical meaning is as follows: if we consider the area enclosed by the frequency and amplitude as a wooden board, then when this board rotates around the Y-axis, the distance from the origin to the location of the root-mean-square frequency is the radius of inertia of the rotation. The root-mean-square frequency is calculated using the following expression:

[0126]

[0127] Where RMSF represents the root mean square frequency, MSF represents the mean square frequency, and P(f) represents the power spectrum of the leakage vibration signal.

[0128] Specifically, in step S3, the leak identification sample library includes: leak patterns, pipeline leak identification criteria under different leak patterns, and frequency domain feature information.

[0129] In one embodiment, to reduce workload and improve efficiency while lowering costs during implementation, the optimal installation method for vibration sensors during leakage monitoring of experimental gathering and transportation pipelines is selected. Specifically, the sample library establishment device D is also configured to: select the optimal vibration signal acquisition location from the signal energy of leakage vibration signals from different vibration sensors under the same leakage mode; and determine the frequency domain characteristic information and pipeline leakage identification criteria corresponding to the corresponding leakage mode based on the leakage vibration signal at the optimal vibration signal acquisition location.

[0130] In one embodiment, leakage monitoring and identification presupposes that the vibration sensor can collect leakage vibration signals. Therefore, it is first necessary to define the leakage identification threshold. Leakage identification can only be achieved when the leakage vibration signal collected by the vibration sensor exceeds the leakage identification threshold. Specifically, the sample library establishment device D is also used to collect and store leakage identification thresholds for the experimental gathering and transportation pipeline in different pipeline burial areas.

[0131] The leakage detection thresholds for different pipeline burial areas are obtained using the following steps:

[0132] A vibration signal acquisition device is used to collect natural noise signals for a preset duration, and the characteristic values ​​of the natural noise signals are used as the leakage identification threshold.

[0133] The specific value of the preset duration is not limited and can be selected reasonably according to the actual application needs. For example, it can be 10 minutes.

[0134] Among them, the characteristic value of the natural noise signal is the average value of the root mean square energy of the natural noise signal.

[0135] Specifically, after all vibration sensors are installed, natural noise signals are collected for at least one hour under conditions where there is no continuous construction work or personnel gathering around the pipeline burial area. Stable 10-minute signal segments with no obvious external interference are extracted from the signals collected by each vibration sensor, and their root mean square energy is calculated and averaged. The average root mean square energy of the natural noise signals is used as the leakage detection threshold. When the signal energy of the leakage vibration signal is less than the leakage detection threshold, the leakage vibration signal cannot be detected.

[0136] In particular, since the vibration sensor needs to be installed against the wall after breaking through the pipe insulation layer, and is covered with more than 1.0m of soil above it, there is no need to distinguish between day and night.

[0137] Example 3

[0138] Based on the above embodiments one and two, the specific structure of the system for establishing leakage characteristics of gathering and transportation pipelines of the present invention will be described below.

[0139] In one embodiment, the gathering and transportation pipeline leakage feature establishment system includes: a leakage identification module E.

[0140] The leakage identification module E is configured to monitor whether a leak has occurred in the pipeline by using the signal energy of the real-time leakage vibration signal of the pipeline to be detected and the leakage identification threshold corresponding to the burial area of ​​the pipeline.

[0141] Specifically, when the signal energy of the real-time leakage vibration signal reaches or exceeds the leakage identification threshold of the corresponding area, the leakage identification sample library is used to identify the leakage characteristics of the current pipeline leakage event.

[0142] Example 4

[0143] Based on the above embodiments one, two, and three, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the leakage identification threshold in a certain region.

[0144] To address potential minor leaks (corrosion perforation, stress cracking) in natural gas gathering and transmission pipelines, a leak simulation device B is used to excite pipe vibration signals caused by different leak modes. Vibration signal acquisition devices C, deployed along the natural gas gathering and transmission pipeline, capture these leak vibration signals. By analyzing the characteristic parameters of different leak vibration signals, a corresponding leak identification sample library matching the modes and features is established. This solves the problem of the lack of scientific and comprehensive leak identification basis in pipeline leak monitoring technology based on pipe vibration, ensuring the safe and stable operation of natural gas pipelines.

[0145] This embodiment takes a natural gas gathering and transmission pipeline in a certain region as an example to illustrate the specific process of determining the leakage identification threshold of the system used to establish the leakage characteristics of the natural gas gathering and transmission pipeline.

[0146] 1) The leakage modes involved in a certain natural gas gathering and transmission pipeline in a certain region are shown in Table 1 below:

[0147] Table 1 Leakage Mode Table

[0148] serial number Cause of leak Leakage pressure (MPa) Leakage hole size (mm) Leakage hole phase 1 Corrosion perforation 1 2 9 o'clock 2 Corrosion perforation 2 2 9 o'clock 3 Corrosion perforation 3 2 9 o'clock 4 Corrosion perforation 4 2 9 o'clock 5 Corrosion perforation 1 5 0:00 6 Corrosion perforation 2 5 0:00 7 Corrosion perforation 3 5 0:00 8 Corrosion perforation 4 5 0:00 9 Corrosion perforation 1 10 3 o'clock 10 Corrosion perforation 2 10 3 o'clock 11 Corrosion perforation 3 10 3 o'clock 12 Corrosion perforation 4 10 3 o'clock 13 Stress cracking 3 20 9 o'clock 14 Stress cracking 3 30 0:00 15 Stress cracking 3 50 3 o'clock

[0149] 2) The type, size, and leakage orifice phase information of a leaking section in a certain gathering and transportation pipeline are shown in Table 2 below:

[0150] Table 2 Leakage Section Information Table

[0151]

[0152] 3) To study the energy attenuation and spectral variation of the leakage vibration signal as it propagates along the pipeline, it is necessary to deploy vibration sensor arrays on both sides of the leak hole. Therefore, with the leak hole as the zero point, sensor installation points are set at distances of 0.1m, 5m, 10m, 20m, 30m, 40m, and 50m on both sides of it. The information of each point is shown in Table 3 below:

[0153] Table 3 Installation Point Information Table

[0154] Point number Distance from the leak point Plane coordinates Point number Distance from the leak point Plane coordinates A1 0.1 (0.1，0) B1 0.1 (-0.1，0) A2 5 (5，0) B2 5 (-5，0) A3 10 (10，0) B3 10 (-10，0) A4 20 (20，0) B4 20 (-20，0) A5 30 (30，0) B5 30 (-30，0) A6 40 (40，0) B6 40 (-40，0) A7 50 (50，0) B7 50 (-50，0)

[0155] Furthermore, refer to Figure 4 (a) When a pipeline leaks, the internal pressure system changes, and gas is ejected at high speed from the leak hole, generating mechanical waves that propagate along the pipeline. Therefore, the mechanical waves may propagate simultaneously in the axial and radial directions. To systematically study the propagation law of the leakage vibration signal, it is necessary to collect and analyze the vibration signals propagating in both the axial and radial directions at the same installation point. Therefore, two acceleration sensors in two directions are installed on the outer wall of the pipeline using adhesive block 6 at the same installation point to achieve this purpose.

[0156] When a pipeline leaks, the internal pressure system changes, causing gas to be ejected at high speed from the leak, generating mechanical waves that propagate along the pipeline. These mechanical waves propagate along the pipeline wall as volume waves, exhibiting different characteristic parameters and propagation properties at different phases. Furthermore, since the phase of the leak is unpredictable, it is necessary to collect leak signals from multiple phases at the same leak point. (Reference) Figure 4 (b) In this embodiment, the vibration sensor is installed at the 0 o'clock, 3 o'clock and 9 o'clock positions.

[0157] In particular, it is worth noting that a maximum of 6 sensors (i.e., 3 phases * 2 directions) can be installed at each sensor installation point, and the number can be reduced as needed in actual work.

[0158] 4) Determine the optimal vibration signal acquisition location

[0159] To reduce workload and improve efficiency while lowering costs during the implementation of this embodiment, the optimal installation method for vibration sensors during natural gas pipeline leak monitoring is selected. Vibration sensors are installed at installation points A3 and A4 in three phases and two directions, respectively. The layout of a single installation point is as follows: Figure 7 As shown, the waveforms of the leakage vibration signals acquired at point A3 in the X and Y directions in three phases are as follows: Figure 8 As shown, the waveforms of the leakage vibration signals acquired at point A4 in the X and Y directions of the three phases are as follows: Figure 9 As shown.

[0160] To ensure the scientific rigor of the leakage vibration signal analysis, 20,000 sampling points after the explosive disc ruptured were analyzed using the root mean square amplitude processing method. The influence of installation location, orientation, and direction on signal energy was analyzed, and the calculation results are shown in Table 4 below.

[0161] Table 4 Leakage Signal Energy Table for Different Directions and Installation Orientations

[0162]

[0163] Analysis shows that, for the same leakage mode, the signal energy received by the Y-direction accelerometer is greater than that in the X-direction when signal acquisition is performed from different orientations. Furthermore, the signal strengths collected by the Y-direction accelerometers installed at the same location at different orientations are basically consistent, while the signal energy collected in the X-direction shows varying fluctuations. Therefore, it can be concluded that the accelerometer installed in the Y-direction has a better acquisition effect on leakage vibration signals generated by leak holes at different locations, and the signal acquisition effect is not affected by the sensor's installation phase.

[0164] It is worth noting that for the same leakage vibration signal, the acquisition effect of the Y-direction installation is significantly better than that of the X-direction. Therefore, the Y-direction is the optimal installation direction for the accelerometer. The signal acquisition effect is not affected by the sensor installation orientation, but considering the convenience of sensor installation, the optimal installation orientation of the sensor is the 0-point direction.

[0165] It is worth noting that in this embodiment, the sensor installation for the leakage vibration signal acquisition during the subsequent establishment of the leakage identification sample library is based on the 0 o'clock and Y directions.

[0166] 5) Determine the leakage detection threshold

[0167] Vibration sensors were installed at 14 points (A1-A7 and B1-B7) in the 0-axis and Y-axis directions. After confirming good coupling between the vibration sensors and the natural gas gathering and transmission pipeline, natural noise signals were collected for more than one hour under conditions of no continuous construction work or personnel gathering in the vicinity. Stable 10-minute signal segments with no obvious external interference were extracted from the signals collected by all sensors, and their root mean square energy was calculated and averaged to obtain a leakage detection threshold of 1.8162 * 10⁻⁶. - 4 When the vibration signal energy is less than this value (mV), the vibration signal is submerged in the background noise and cannot be distinguished.

[0168] Example 5

[0169] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for the first leakage mode of a certain natural gas gathering and transmission pipeline.

[0170] The first leakage mode: the leakage type is corrosion perforation, the leakage pressure is 1 MPa, and the leakage point size is 2 mm.

[0171] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0172] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 1MPa and leakage point size of 2mm) were completed.

[0173] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0174] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 10 As shown in (a), 20,000 sampling points were selected after the leakage began for energy analysis. The analysis results are shown in Table 5 below:

[0175] Table 5. Energy of Leakage Vibration Signal from Different Vibration Sensors

[0176]

[0177] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 10 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the first leakage mode was calculated to be 2381 Hz.

[0178] Example 6

[0179] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for a second leakage mode in a certain natural gas gathering and transmission pipeline.

[0180] The second leakage mode: the leakage type is corrosion perforation, the leakage pressure is 2 MPa, and the leakage point size is 2 mm.

[0181] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0182] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 2MPa and leakage point size of 2mm) were completed.

[0183] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0184] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 11 As shown in (a), 20,000 sampling points were selected after the leakage began for energy analysis. The analysis results are shown in Table 6 below:

[0185] Table 6. Energy of Leakage Vibration Signal from Different Vibration Sensors

[0186]

[0187] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 11 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the second leakage mode was calculated to be 2478 Hz.

[0188] Example 7

[0189] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for a third leakage mode in a certain natural gas gathering and transmission pipeline.

[0190] The third leakage mode: the leakage type is corrosion perforation, the leakage pressure is 3 MPa, and the leakage point size is 2 mm.

[0191] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0192] S2: Collect natural noise from buried natural gas gathering and transmission pipelines, determine the leakage detection threshold as 1.8162*10-4mV, and complete the installation of vibration sensors at points A1 to A6 according to the technical solution requirements, and complete the excitation and collection of leakage vibration signals (i.e., leakage pressure of 3MPa and leakage point size of 2mm).

[0193] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0194] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 12 As shown in (a), 20,000 sampling points were selected after the leakage began for energy analysis. The analysis results are shown in Table 7 below:

[0195] Table 7 Energy of Leakage Vibration Signal from Different Vibration Sensors

[0196]

[0197] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 12 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the third leakage mode was calculated to be 2751 Hz.

[0198] Example 8

[0199] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification basis for the fourth leakage mode of a certain natural gas gathering and transmission pipeline.

[0200] The fourth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 4 MPa, and the leakage point size is 2 mm.

[0201] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0202] S2: Collect natural noise from buried natural gas gathering and transmission pipelines, determine the leakage detection threshold as 1.8162*10-4mV, and complete the installation of vibration sensors at points A1 to A6 according to the technical requirements, and complete the excitation and collection of leakage vibration signals (i.e., leakage pressure of 4MPa and leakage point size of 2mm).

[0203] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0204] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 13 As shown in (a), 20,000 sampling points were selected after the leakage began for energy analysis. The analysis results are shown in Table 8 below:

[0205] Table 8. Energy of Leakage Vibration Signal from Different Vibration Sensors

[0206]

[0207] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 13 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the fourth leakage mode was calculated to be 2253Hz.

[0208] Example 9

[0209] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for the fifth leakage mode of a certain natural gas gathering and transmission pipeline.

[0210] The fifth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 1 MPa, and the leakage point size is 5 mm.

[0211] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0212] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 1MPa and leakage point size of 5mm) were completed.

[0213] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0214] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 14 As shown in (a), 20,000 sampling points were selected after the leakage began for energy analysis. The analysis results are shown in Table 9 below:

[0215] Table 9. Energy of Leakage Vibration Signal from Different Vibration Sensors

[0216]

[0217] The vibration signal of the leaking body collected by the vibration sensor closest to the leak point was subjected to time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 14 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the fifth leakage mode was calculated to be 2298 Hz.

[0218] Example 10

[0219] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification basis for the sixth leakage mode of a certain natural gas gathering and transmission pipeline.

[0220] The sixth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 2 MPa, and the leakage point size is 5 mm.

[0221] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0222] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points B1 to B6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 2MPa and leakage point size of 5mm) were completed.

[0223] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0224] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 15 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 10 below:

[0225] Table 10 Energy of Leakage Vibration Signal from Different Vibration Sensors

[0226]

[0227]

[0228] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 15 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the sixth leakage mode was calculated to be 2353Hz.

[0229] Example 11

[0230] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for the seventh leakage mode of a certain natural gas gathering and transmission pipeline.

[0231] The seventh leakage mode: the leakage type is corrosion perforation, the leakage pressure is 3 MPa, and the leakage point size is 5 mm.

[0232] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0233] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points B1 to B6, and the leakage vibration signal (i.e., leakage pressure of 3MPa and leakage point size of 5mm) was excited and collected.

[0234] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0235] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 16 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 11 below:

[0236] Table 11 Energy of Leakage Vibration Signal from Different Vibration Sensors

[0237]

[0238] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 16 As shown in (b), the root mean square frequency (RMS) of the seventh leakage mode (i.e., the basis for pipeline leakage identification) was calculated to be 2566 Hz. (Continue to refer to...) Figure 16 (b) A wideband signal with a bandwidth of 800 to 4000 Hz, with extreme values ​​at 1000 Hz and 2583 Hz.

[0239] Example 12

[0240] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for the eighth leakage mode of a certain natural gas gathering and transmission pipeline.

[0241] The eighth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 4 MPa, and the leakage point size is 5 mm.

[0242] S1: Select a sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0243] S2: Collect natural noise from buried pipelines and determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 4MPa and leakage point size of 5mm) were completed.

[0244] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0245] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 17 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 12 below:

[0246] Table 12 Energy of Leakage Vibration Signal from Different Vibration Sensors

[0247]

[0248] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 17 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the eighth leakage mode was calculated to be 2424Hz.

[0249] Example 13

[0250] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for the ninth leakage mode in a certain natural gas gathering and transmission pipeline.

[0251] The ninth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 1 MPa, and the leakage point size is 10 mm.

[0252] S1: Select a sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0253] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, the sensor was installed at points A1 to A6, and the leakage vibration signal (i.e., leakage pressure of 1MPa and leakage point size of 10mm) was excited and collected.

[0254] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0255] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 18 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 13 below:

[0256] Table 13 Vibration signal energy of different vibration sensors

[0257]

[0258] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 18 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the ninth leakage mode was calculated to be 2712 Hz.

[0259] Example 14

[0260] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification basis for the tenth leakage mode of a certain natural gas gathering and transmission pipeline.

[0261] The tenth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 1 MPa, and the leakage point size is 10 mm.

[0262] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, sensitivity of 500 mV / g, and sampling rate of 12000 times / second.

[0263] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4According to the technical solution requirements, vibration sensors were installed at points B1 to B6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 1MPa and leakage point size of 10mm) were completed.

[0264] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0265] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 19 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 14 below:

[0266] Table 14 Vibration signal energy of different vibration sensors

[0267]

[0268] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 19 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the tenth leakage mode was calculated to be 2774 Hz.

[0269] Example 15

[0270] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification basis for the eleventh leakage mode of a certain natural gas gathering and transmission pipeline.

[0271] Eleventh leakage mode: The leakage type is corrosion perforation, the leakage pressure is 3 MPa, and the leakage point size is 10 mm.

[0272] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, sensitivity of 500 mV / g, and sampling rate of 12000 times / second.

[0273] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A5, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 3MPa and leakage point size of 10mm) were completed.

[0274] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0275] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 20 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 15 below:

[0276] Table 15 Vibration signal energy of different vibration sensors

[0277]

[0278] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 20 As shown in (b), the root mean square frequency of the target leakage vibration signal (i.e., the basis for pipeline leakage identification) was calculated to be 2800Hz.

[0279] Example 16

[0280] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification basis for the twelfth leakage mode of a certain natural gas gathering and transmission pipeline.

[0281] The twelfth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 4 MPa, and the leakage point size is 10 mm.

[0282] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, sensitivity of 500 mV / g, and sampling rate of 12000 times / second.

[0283] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A5, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 4MPa and leakage point size of 10mm) were completed.

[0284] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0285] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 21 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 16 below:

[0286] Table 16 Vibration signal energy of different vibration sensors

[0287]

[0288] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 21 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the twelfth leakage mode was calculated to be 2691 Hz.

[0289] Example 17

[0290] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification basis for the thirteenth leakage mode of a certain natural gas gathering and transmission pipeline.

[0291] The thirteenth leakage mode: the leakage type is stress cracking, the leakage pressure is 3 MPa, and the leakage point size is 20 mm.

[0292] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, sensitivity of 500 mV / g, and sampling rate of 12000 times / second.

[0293] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 3MPa and leakage point size of 20mm) were completed.

[0294] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0295] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 22 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 17 below:

[0296] Table 17 Vibration signal energy of different vibration sensors

[0297]

[0298] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 22 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the thirteenth leakage mode was calculated to be 3356 Hz.

[0299] Example 18

[0300] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification basis for the fourteenth leakage mode of a certain natural gas gathering and transmission pipeline.

[0301] The fourteenth leakage mode: the leakage type is stress cracking, the leakage pressure is 3 MPa, and the leakage point size is 30 mm.

[0302] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0303] S2: Collect natural noise from buried natural gas gathering and transmission pipelines to determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points A1 to A6, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 2MPa and leakage point size of 30mm) were completed.

[0304] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0305] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 23 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 18 below:

[0306] Table 18 Vibration signal energy of different vibration sensors

[0307]

[0308] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 23 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the fourteenth leakage mode was calculated to be 3343Hz.

[0309] Example 19

[0310] Based on the above embodiments one through four, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to determine the pipeline leakage identification criteria for the fifteenth leakage mode of a certain natural gas gathering and transmission pipeline.

[0311] The fifteenth leakage mode: the leakage type is stress cracking, the leakage pressure is 3 MPa, and the leakage point size is 50 mm.

[0312] S1: Select a vibration sensor with a bandwidth of 0.2 to 6000 Hz, a sensitivity of 500 mV / g, and a sampling rate of 12000 times / second.

[0313] S2: Collect natural noise from buried natural gas gathering and transmission pipelines, and determine the leakage signal identification threshold as 1.8162*10. -4 According to the technical solution requirements, vibration sensors were installed at points B1 to B5, and the excitation and acquisition of leakage vibration signals (i.e., leakage pressure of 3MPa and leakage point size of 50mm) were completed.

[0314] S3: Establish a leak identification sample library by matching the patterns and features of the target leak patterns.

[0315] The vibration signals from the natural gas gathering and transmission pipeline leak, collected by various vibration sensors, are shown in the waveform diagram below. Figure 24 As shown in (a), 20,000 sampling points were selected after the leakage started for energy analysis. The analysis results are shown in Table 19 below:

[0316] Table 19 Vibration signal energy of different vibration sensors

[0317]

[0318] The leakage vibration signal collected by the vibration sensor closest to the leak point was selected for time-frequency analysis to obtain the vibration signal spectrum, as shown below. Figure 24 As shown in (b), the root mean square frequency (i.e., the basis for pipeline leakage identification) of the fifteenth leakage mode was calculated to be 3229 Hz.

[0319] Example 20

[0320] Based on the above embodiments one through nineteen, the following describes the process of applying the system for establishing leakage characteristics of natural gas gathering and transmission pipelines described in the embodiments of the present invention to a leakage identification sample library for establishing patterns and characteristics of a certain natural gas gathering and transmission pipeline.

[0321] Establish a sample library for leak identification based on pattern and feature matching of a certain natural gas gathering and transmission pipeline.

[0322] For the possible leakage patterns in a specific area, the leakage identification threshold is 1.8162*10. -4 The following table 20 shows the leak identification sample library obtained by analyzing the pattern and feature matching of a certain natural gas gathering and transmission pipeline:

[0323] Table 20 Leakage Identification Sample Library Based on Pattern and Feature Matching

[0324]

[0325] Example 21

[0326] Based on the systems for establishing leakage characteristics of natural gas gathering and transmission pipelines provided in Embodiments 1-20 above, this invention also provides a method for establishing leakage characteristics of natural gas gathering and transmission pipelines. This method utilizes the system for establishing leakage characteristics of natural gas gathering and transmission pipelines as described above.

[0327] This invention proposes a system and method for establishing leakage characteristics of natural gas gathering and transmission pipelines. The system and method utilize a leakage simulation device and vibration signal acquisition devices deployed along the pipeline to excite and capture pipe vibration signals caused by different leakage conditions, achieving full coverage of leakage modes. Furthermore, by optimizing the installation location of the vibration signal acquisition devices, the phase of the leakage point is ensured to not affect the leakage signal acquisition, guaranteeing the scientific validity and reliability of the signal acquisition. Finally, based on the analysis results of the leakage vibration signals, the criteria for pipeline leakage identification are clarified, and a leakage identification sample library matching patterns and features is constructed, solving the problem that pipeline leakage monitoring technology based on pipe vibration lacks a scientific and comprehensive basis for leakage identification.

[0328] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

[0329] In the description of this invention, unless otherwise stated, "a plurality of" means two or more; the terms "upper," "lower," "left," "right," "inner," "outer," "front end," "rear end," "head," "tail," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, and are only for the convenience of describing the invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of the invention. Furthermore, the terms "first," "second," "third," etc., are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0330] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "connected" and "linked" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0331] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should be extended to equivalent substitutions of these features as understood by those skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing particular embodiments only and is not intended to be limiting.

[0332] The phrase "an embodiment" or "an embodiment" used in this specification means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Therefore, the phrase "an embodiment" or "an embodiment" appearing in various places throughout the specification does not necessarily refer to the same embodiment.

[0333] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection of this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A system for establishing leakage characteristics of natural gas gathering and transmission pipelines, characterized in that, include: A gas supply device, used to provide the required leakage pressure to the experimental gathering and transmission pipeline; A leakage simulation device is set on the outer wall of the experimental gathering and transportation pipeline to form a leakage point in the form of a preset leakage pattern. The preset leakage pattern includes the leakage point shape, leakage point size and leakage pressure corresponding to the leakage type. A vibration signal acquisition device includes a vibration sensor array, which is set at the leak point to be tested and is used to acquire the leakage vibration signal corresponding to the current leakage mode when pressure is applied to the pipeline. The sample library building device is used to collect leakage vibration signals under different leakage modes and extract features to build a leakage identification sample library that matches the modes and features.

2. The system according to claim 1, characterized in that, The gas supply device includes: Gas storage equipment used to store gaseous media; A pressure reducing valve, connected to the gas storage device, is used to adjust the pressure of the gaseous medium; A delivery pipeline, with its two ends connected to the gas storage device and the gas injection port of the experimental gathering and transportation pipeline respectively, is used to deliver gaseous medium to the experimental gathering and transportation pipeline. A pressure sensor, installed on the delivery pipeline, is used to monitor the injection pressure.

3. The system according to claim 1 or 2, characterized in that, The leakage simulation device is installed on the leakage section in the experimental gathering and transportation pipeline. The leakage simulation device includes at least two leakage through holes, which are formed at least two phases along the circumferential direction of the outer wall of the pipeline at a first axial position on the leakage section. The shape of the leakage through holes matches the leakage type currently being simulated.

4. The system according to claim 3, characterized in that, The leakage simulation device also includes: A short pipe is placed outside the pipe and uses the opening at the first end to cover the leakage through hole; A rupture disc is disposed at the second end of a short tube at the leak point to be tested, wherein the burst pressure of the rupture disc is matched with the leak pressure required for the current simulation.

5. The system according to claim 3 or 4, characterized in that, When the leakage type is corrosion perforation, the corresponding leakage through-hole shape is a round hole; When the leakage type is stress cracking, the corresponding leakage through-hole morphology is a crack.

6. The system according to any one of claims 1 to 5, characterized in that, The vibration sensor array includes two vibration sensor units arranged on both sides of the leak point to be tested along the axial direction of the pipe. Each vibration sensor unit includes at least one set of vibration sensor assemblies, which are respectively arranged on pipe sections at different distances from the leak point to be tested. The vibration sensor assemblies include vibration sensors arranged in different orientations, and each vibration sensor has an acceleration sensor that measures different vibration directions at the current leak location.

7. The system according to claim 6, characterized in that, The vibration signal acquisition device also includes: The adhesive block is coupled to the outer surface of the experimental gathering and transportation pipeline via a vibration coupling agent; Connecting bolts are used to mount the vibration sensor onto the adhesive block.

8. The system according to claim 6 or 7, characterized in that, The sample library building device is configured to construct the leakage identification sample library using the following steps: Based on the leakage vibration signals from different vibration sensors under different leakage modes, the root mean square processing method is used to extract the signal energy of the leakage vibration signals. The frequency domain characteristics of the leakage vibration signal are obtained by performing spectral analysis on the signal energy. The frequency domain characteristics include signal amplitude energy, vibration range, and vibration frequency distribution. Extract pipeline leakage identification criteria from the frequency domain feature information of leakage vibration signals, and use the pipeline leakage identification criteria under different leakage modes and the frequency domain feature information to form a leakage identification sample library.

9. The system according to claim 8, characterized in that, The sample library establishment device is also configured to: The optimal vibration signal acquisition location is selected from the signal energy of leakage vibration signals from different vibration sensors under the same leakage mode. Based on the leakage vibration signal at the optimal vibration signal acquisition location, determine the frequency domain characteristic information corresponding to the leakage mode and the basis for pipeline leakage identification.

10. The system according to claim 8 or 9, characterized in that, The root mean square frequency is extracted from the frequency domain characteristics of the leakage vibration signal, and the root mean square frequency is used as the basis for identifying the corresponding pipeline leakage.

11. The system according to any one of claims 1 to 10, characterized in that, The sample library establishment device is also used to collect and store leakage identification thresholds for the experimental gathering and transportation pipeline in different pipeline burial areas, including: The vibration signal acquisition device is used to acquire a natural noise signal for a preset duration and the characteristic value of the natural noise signal is used as the leakage identification threshold, wherein the characteristic value of the natural noise signal is the average value of the root mean square energy of the natural noise signal.

12. The system according to claim 11, characterized in that, The system also includes: The leak detection module is used to monitor whether a leak has occurred in the pipeline based on the signal energy of the real-time leakage vibration signal of the pipeline under test, and using the leakage identification threshold corresponding to the burial area of ​​the pipeline. When the signal energy of the real-time leakage vibration signal reaches or exceeds the leakage identification threshold of the corresponding region, the leakage identification sample library is used to identify the leakage characteristics of the current pipeline leakage event.

13. A method for establishing leakage characteristics of natural gas gathering and transmission pipelines, characterized in that, The method is implemented using the system as described in any one of claims 1 to 12.

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