A system and method for determining a pipeline leak monitoring sensor deployment scheme

Abstract

The application discloses a system and method for determining a pipeline leakage monitoring sensor layout scheme, comprising: a gas supply device for providing a required leakage pressure to an experimental gathering pipeline; a leakage simulation device which forms a leakage point and is arranged on the outer wall of the experimental gathering pipeline in the form of a preset leakage mode; a vibration signal acquisition device which is provided with a vibration sensor array arranged at a leakage point to be tested, and is used for collecting leakage vibration signals corresponding to the current leakage mode when pressure is applied to the pipeline; and a layout scheme determination device which is used for collecting leakage vibration signals under different leakage modes, extracting features, and determining a layout scheme of a leakage monitoring sensor under a corresponding leakage mode. The application obtains an optimal layout mode of the leakage monitoring sensor, and solves the problems of great difficulty and high cost caused by pipe body punching or full-line excavation when a leakage monitoring system is added to an existing natural gas pipeline.

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 determining the deployment scheme of pipeline leakage monitoring sensors. 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] An existing patent document (publication number CN102997053A) discloses a system for measuring the propagation velocity of vibration waves from a natural gas pipeline leak. This system improves the accuracy of measuring the propagation velocity of vibration waves from a natural gas pipeline leak by densely deploying fiber optic vibration sensing units. However, this solution does not consider the deployment scheme of the fiber optic sensing units.

[0005] An existing patent document (publication number CN11243206lA) discloses a pipeline leak monitoring method and system. This method calculates the leak location based on the distance between secondary sensors and the time difference in the detection of infrasound waves, thereby ultimately achieving leak detection and leak location calculation. However, this method does not consider the sensor deployment scheme.

[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 also does not consider the sensor deployment scheme.

[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, these existing technologies all use a single method for leak monitoring, achieving sufficient accuracy for pipeline leaks caused by geological disasters, but they cannot accurately and effectively monitor leaks caused by stress cracking or fluid corrosion. Additionally, they do not consider the placement of monitoring points.

[0008] In summary, the existing technology needs to provide a solution that considers the location of monitoring sensors to ensure the safe and stable operation of the gathering and transportation pipeline. Summary of the Invention

[0009] The purpose of this invention is to provide a scheme that considers the placement of monitoring sensors, thereby ensuring the safe and stable operation of the gathering and transportation pipeline.

[0010] To address the aforementioned technical problems, this invention provides a system for determining the deployment scheme of pipeline leak monitoring sensors, comprising: a gas supply device for providing the required leakage pressure to the experimental gathering and transportation pipeline; a leak simulation device for forming a leak point and setting it on the outer wall of the experimental gathering and transportation pipeline in the form of a preset leak mode, wherein the preset leak mode includes: the shape of the leak point, the size of the leak point, and the leakage pressure corresponding to the leak type; a vibration signal acquisition device comprising a vibration sensor array, wherein the vibration sensor array is set at the leak point to be tested, for acquiring the leakage vibration signal corresponding to the current leak mode when pressure is applied to the pipeline; and a deployment scheme determination device for collecting leakage vibration signals under different leak modes and performing feature extraction to determine the deployment scheme of the leak monitoring sensors under the corresponding leak modes.

[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 pipeline 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 serves as the leak point to be tested, wherein the burst 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 deployment scheme determination device is further configured to obtain a curve characterizing the relationship between the vibration sensor installation position and the energy change of the leakage vibration signal based on the leakage vibration signals collected at different vibration sensor installation positions during the leakage test phase. Based on this curve, and combined with natural noise signals of a preset duration collected from the vibration sensor array during the non-leakage test phase, the deployment scheme of the leakage monitoring sensors under the corresponding leakage mode is determined. The curve characterizing the relationship between the vibration sensor installation position and the energy change of the leakage vibration signal is obtained using the following steps: Based on the leakage vibration signals from different vibration sensors under the current leakage mode, the signal energy of the leakage vibration signal is extracted using a root mean square (RMS) processing method; based on the signal energy of the leakage vibration signal and the distance between the vibration sensor installation position and the leak point to be tested, the curve characterizing the relationship between the vibration sensor installation position and the energy change of the leakage vibration signal is obtained using an exponential fitting method.

[0018] Preferably, the deployment scheme determination device is further configured to determine the deployment scheme of leakage monitoring sensors under the current leakage mode through the following steps: determining the leakage identification threshold of the experimental gathering and transportation pipeline in the current buried pipeline area based on the natural noise signal, wherein the leakage identification threshold is the average value of the root mean square energy of the natural noise signal; obtaining the effective leakage propagation distance of the current leakage mode based on the curve representing the relationship between the installation position of the vibration sensor and the energy change of the leakage vibration signal corresponding to the current leakage mode, combined with the leakage identification threshold; determining the number of leakage monitoring sensors to be deployed based on the effective leakage propagation distance and the risk distance of the current leakage mode; and determining the deployment spacing of the leakage monitoring sensors based on the number of sensors and the risk distance, so as to form a deployment scheme of leakage monitoring sensors for the current leakage mode using the number of sensors and the deployment spacing.

[0019] Preferably, the deployment scheme determination device is further configured to generate the effective leakage propagation distance of the current leakage mode through the following steps: based on the curve characterizing the relationship between the installation position of the vibration sensor and the change in leakage vibration signal energy, identify the distance corresponding to when the signal energy in the current curve reaches the leakage identification threshold, and record it as the effective leakage propagation distance.

[0020] Preferably, the number of deployments is determined using the following expression:

[0021] n×2A<H<(n+1)×2A

[0022] k = n + 1

[0023] Where A represents the effective leakage propagation distance, H represents the risk distance, k represents the number of deployments, and n represents the proportionality coefficient; the deployment spacing is determined using the following expression:

[0024]

[0025] Where L represents the deployment spacing, H represents the risk distance, and k represents the number of deployments.

[0026] Preferably, the deployment scheme determining device is further configured to: select the optimal vibration signal acquisition position based on the signal energy of leakage vibration signals from different vibration sensor components under the current leakage mode; and determine the deployment position of the leakage monitoring sensor under the current leakage mode based on the optimal vibration signal acquisition position, wherein the deployment position includes the deployment orientation and deployment direction, so as to form a deployment scheme for the leakage monitoring sensor for the current leakage mode by using the number of sensors, the deployment spacing and the deployment position.

[0027] On the other hand, embodiments of the present invention also provide a method for determining a pipeline leak monitoring sensor deployment scheme, the method being implemented using the system described above.

[0028] Compared with the prior art, one or more embodiments of the above solutions may have the following advantages or beneficial effects:

[0029] This invention proposes a system and method for determining the deployment scheme of pipeline leak monitoring sensors. By optimizing the installation location of the vibration signal acquisition device, this system and method ensures that the phase of the leak point does not affect the acquisition of the leak signal, thus guaranteeing the scientific validity and reliability of the leak vibration signal acquisition. Secondly, by determining the deployment scheme of the leak monitoring sensors under corresponding leak modes, this invention solves the problem of high difficulty and cost associated with drilling holes in the pipe body or excavating the entire pipeline when adding leak monitoring sensors to existing natural gas pipelines.

[0030] 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

[0031] 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:

[0032] Figure 1 This is a schematic diagram of the overall structure of a system for determining the deployment scheme of pipeline leak monitoring sensors according to an embodiment of this application.

[0033] Figure 2 This is a schematic diagram of the specific structure of a system for determining the deployment scheme of pipeline leak monitoring sensors according to an embodiment of this application.

[0034] Figure 3 This is a schematic diagram of the leakage simulation device in a system for determining the deployment scheme of pipeline leakage monitoring sensors, according to an embodiment of this application.

[0035] 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 determining the deployment scheme of pipeline leakage monitoring sensors, as described in an embodiment of this application.

[0036] Figure 5 This is a schematic diagram of the vibration signal acquisition device in a system for determining the deployment scheme of pipeline leakage monitoring sensors, according to an embodiment of this application.

[0037] Figure 6This is an example diagram of the layout structure of a vibration signal acquisition device in a system for determining the layout scheme of pipeline leakage monitoring sensors, as described in an embodiment of this application.

[0038] Figure 7 This is a waveform diagram of the leakage vibration signal collected by the vibration signal acquisition device at the first position in the system for determining the deployment scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0039] Figure 8 The waveform of the leakage vibration signal collected by the vibration signal acquisition device at the second position in the system for determining the deployment scheme of pipeline leakage monitoring sensors according to an embodiment of this application is shown.

[0040] Figure 9 The figures shown are curves representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and example diagrams of the leakage monitoring sensor layout scheme, corresponding to the first leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to embodiments of this application.

[0041] Figure 10 The figures shown are curves representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and example diagrams of the leakage monitoring sensor layout scheme, corresponding to the second leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to embodiments of this application.

[0042] Figure 11 The figures shown are curves representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and example diagrams of the leakage monitoring sensor layout scheme, corresponding to the third leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to embodiments of this application.

[0043] Figure 12 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the change in the energy of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the fourth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0044] Figure 13 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the fifth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0045] Figure 14 The diagram shows a curve representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the sixth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0046] Figure 15 The diagram shows a curve representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the seventh leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0047] Figure 16 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the eighth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0048] Figure 17 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the change in the energy of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the ninth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0049] Figure 18 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the change in the energy of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the tenth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0050] Figure 19 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the change in the energy of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the eleventh leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0051] Figure 20 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the change in the energy of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the twelfth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0052] Figure 21 This is an example diagram of the leakage monitoring sensor deployment scheme, which represents the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal in the system for determining the deployment scheme of pipeline leakage monitoring sensors according to an embodiment of this application.

[0053] Figure 22 This is an example diagram of the fourteenth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application. The curves represent the relationship between the installation location of the vibration sensor and the change in the energy of the leakage vibration signal, and the layout scheme of the leakage monitoring sensor are shown.

[0054] Figure 23 The figure shows a curve representing the relationship between the installation location of the vibration sensor and the change in the energy of the leakage vibration signal, and an example diagram of the leakage monitoring sensor layout scheme, corresponding to the fifteenth leakage mode in the system for determining the layout scheme of pipeline leakage monitoring sensors according to an embodiment of this application. Detailed Implementation

[0055] 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.

[0056] 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.

[0057] 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.

[0058] An existing patent document (publication number CN102997053A) discloses a system for measuring the propagation velocity of vibration waves from a natural gas pipeline leak. This system improves the accuracy of measuring the propagation velocity of vibration waves from a natural gas pipeline leak by densely deploying fiber optic vibration sensing units. However, this solution does not consider the deployment scheme of the fiber optic sensing units.

[0059] An existing patent document (publication number CN112432061A) discloses a pipeline leak monitoring method and system. This method calculates the leak location based on the distance between secondary sensors and the time difference in detecting infrasound waves, thereby ultimately achieving leak detection and leak location calculation. However, this method does not consider the sensor deployment scheme.

[0060] 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 also does not consider the sensor deployment scheme.

[0061] 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, these existing technologies all use a single method for leak monitoring, achieving sufficient accuracy for pipeline leaks caused by geological disasters, but they cannot accurately and effectively monitor leaks caused by stress cracking or fluid corrosion. Additionally, they do not consider the placement of monitoring points.

[0062] In summary, the existing technology needs to provide a solution that considers the location of monitoring sensors to ensure the safe and stable operation of the gathering and transportation pipeline.

[0063] Example 1

[0064] Figure 1 This is a schematic diagram of the overall structure of a system for determining the deployment scheme of pipeline leak monitoring sensors according to an embodiment of this application. Figure 2 This is a schematic diagram of the specific structure of a system for determining the deployment scheme of pipeline leak monitoring sensors, according to an embodiment of this application. (Combined with...) Figure 1 and Figure 2 The specific structure of the system for determining the deployment scheme of pipeline leakage monitoring sensors (hereinafter referred to as the "pipeline leakage monitoring sensor deployment scheme determination system") described in the embodiments of the present invention will be explained.

[0065] like Figure 1 As shown, the pipeline leak monitoring sensor deployment scheme determination system includes: a gas supply device A, a leak simulation device B, a vibration signal acquisition device C, and a deployment scheme determination device D. The leak simulation device B establishes a leak point and is installed on the outer wall of the experimental gathering and transportation pipeline in a preset leak pattern. The vibration signal acquisition device C has a vibration sensor array, which is installed at the leak point to be tested.

[0066] Gas supply device A is configured to provide the required leakage pressure to the experimental gathering and transmission pipeline.

[0067] 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.

[0068] The deployment scheme determination device D is configured to collect leakage vibration signals under different leakage modes and extract features to determine the deployment scheme of leakage monitoring sensors under the corresponding leakage modes.

[0069] 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.

[0070] 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.

[0071] 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.

[0072] In one embodiment, reference Figure 2 The 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.

[0073] 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.

[0074] Pressure reducing valve 2 is configured to adjust the pressure of the gaseous medium.

[0075] 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.

[0076] Pressure sensor 4 is configured to monitor the injection pressure.

[0077] 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.

[0078] 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.

[0079] The specific setting of the first axial position is not limited and can be reasonably selected according to actual application needs.

[0080] The specific phase setting method is not limited and can be reasonably selected according to the actual application requirements.

[0081] In one embodiment, continue to combine Figure 2 and Figure 3 The leakage simulation device B includes: short pipe 5 and rupture disc.

[0082] 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.

[0083] 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.

[0084] 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.

[0085] Optionally, refer to Figure 3 Leakage simulation device B may also include: a leakage short section, a short pipe 5, and a rupture disc.

[0086] 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.

[0087] In one embodiment, the vibration signal acquisition device C includes a vibration sensor array. The vibration sensor array comprises 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.

[0088] 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.

[0089] 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.

[0090] 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:

[0091] (1) Bandwidth: 0.2~6000Hz;

[0092] (2) Sensitivity: 500mV / g;

[0093] (3) Resonant frequency: 15kHz;

[0094] (4) Sampling frequency: 5000-15000 times / second, which can be set and adjusted independently.

[0095] 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 vibration direction in which the accelerometer can be installed can be parallel to the pipe axis or perpendicular to the pipe axis.

[0096] 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.

[0097] The specific value of the spacing is not limited and can be reasonably selected according to the actual application requirements.

[0098] 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.

[0099] In one embodiment, combined Figure 2 and Figure 5 The vibration signal acquisition device C also includes: adhesive block 6 and connecting bolt 7.

[0100] The adhesive block 6 is coupled to the outer surface of the experimental gathering and transportation pipeline through a vibration coupling agent.

[0101] Connecting bolt 7 mounts the vibration sensor onto the patch.

[0102] Specifically, there are currently six main methods for installing sensors on equipment and pipeline surfaces: probe-type connection, two-stage magnet installation, horizontal mounting block installation, installation after pasting mounting pads, direct pasting, and welding connection. Analysis of collected signals from the same leakage vibration signal shows that welding connectors to the equipment / pipeline surface and mounting the sensor on the connectors provides the best coupling effect and the weakest signal attenuation, but it can damage the equipment / pipeline surface and easily lead to cathodic corrosion and other issues. Secondly, installation after pasting mounting pads and direct sensor bonding have similar coupling effects, but due to the non-planar nature of the pipeline surface, direct pasting can easily lead to poor coupling. Therefore, since the vibration sensor needs to be fixed to the outer surface of the experimental gathering and transportation pipeline without damaging the anti-corrosion layer, to increase the coupling between the vibration sensor and the experimental gathering and transportation pipeline and improve the signal acquisition effect, [further details are needed]. Figure 5A specially designed adhesive block 6 was fixed to the outer surface of the experimental collection and transportation pipeline using a vibration coupling agent, and then the vibration sensor was coupled by mounting it on the adhesive block 6 with connecting bolts 7.

[0103] 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.

[0104] Example 2

[0105] Based on the above embodiment one, the implementation function of the layout scheme determination device of the present invention will be specifically described below.

[0106] In one embodiment, the deployment scheme determination device D is configured to obtain a curve characterizing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal based on the leakage vibration signals collected at different vibration sensor installation locations during the leakage test phase. Based on the curve characterizing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal, and combined with the natural noise signal of a preset duration collected from the vibration sensor array during the non-leakage test phase, the deployment scheme of the leakage monitoring sensor under the corresponding leakage mode is determined.

[0107] Optionally, the following steps can be used to obtain a curve characterizing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy:

[0108] Step S1: Based on the leakage vibration signals from different vibration sensors under the current leakage mode, extract the signal energy of the leakage vibration signals using the root mean square processing method.

[0109] Step S2: Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leakage point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy.

[0110] In one embodiment, the deployment scheme determination device D is further configured to determine the deployment scheme of the leak monitoring sensors under the current leak mode by means of the following steps:

[0111] Step A1: Determine the leakage detection threshold of the experimental gathering and transportation pipeline in the current buried pipeline area based on the natural noise signal.

[0112] Step A2: Based on the curve representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal corresponding to the current leakage mode, and combined with the leakage identification threshold, the effective leakage propagation distance of the current leakage mode is obtained.

[0113] Step A3: Determine the number of leak monitoring sensors to be deployed based on the effective leak propagation distance and the risk distance of the current leak mode.

[0114] Step A4: Determine the spacing between leak monitoring sensors based on the number of sensors deployed and the risk distance, so as to form a deployment plan for leak monitoring sensors for the current leak mode using the number of sensors deployed and the spacing between them.

[0115] Specifically, in step A1, to study the propagation law of the vibration signal of the leaking pipe, it is necessary to first determine the leakage signal identification threshold. Leakage identification is only possible when the vibration signal collected by the vibration sensor exceeds the leakage identification threshold. Typically, the leakage identification threshold is the natural noise of the pipeline burial area. In obtaining the leakage identification threshold, after all vibration sensors are installed, natural noise signals are collected for more than 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 all vibration sensors, and their root mean square energy is calculated and averaged. The average value of the root mean square energy of the natural noise signals is used as the leakage identification threshold. When the signal energy of the leaking vibration signal is less than the leakage identification threshold, the leaking vibration signal cannot be distinguished.

[0116] 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.

[0117] In step A1, the leakage detection threshold is the average value of the root mean square energy of the natural noise signal.

[0118] Specifically, in step A2, for each leakage condition, the leakage vibration signal propagating along the experimental collection and transmission pipeline collected by the vibration sensor is used to extract and analyze the signal energy and characteristic parameters. When the signal energy of the leakage signal collected by the vibration sensor at a distance D from the leakage point is lower than the leakage identification threshold, the effective leakage propagation distance of the leakage signal under the leakage condition can be considered to be D.

[0119] In step A2, when the effective leakage propagation distance is obtained, the distance at which the signal energy in the curve representing the relationship between the vibration sensor installation location and the leakage vibration signal energy reaches the leakage identification threshold is determined. Specifically, based on the curve representing the relationship between the vibration sensor installation location and the leakage vibration signal energy, the distance at which the signal energy in the current curve representing the relationship between the vibration sensor installation location and the leakage vibration signal energy reaches the leakage identification threshold is identified and recorded as the effective leakage propagation distance.

[0120] Specifically, in steps A3 and A4, since the main monitoring targets of this invention are pipeline perforation leakage caused by corrosion and cracking leakage caused by stress concentration, the sensors are mainly deployed in the liquid accumulation corrosion risk section and stress concentration risk section of the natural gas gathering and transmission pipeline. First, the effective leakage propagation distance A corresponding to the current leakage mode is obtained, which is used as the deployment spacing L = 2A for the vibration sensors. Assuming the risk distance is H, when n*L < H < (n+1)*L, n+1 vibration sensors need to be deployed on the experimental gathering and transmission pipeline, and the deployment spacing L of the vibration sensors should be changed to [H / (n+1)].

[0121] In step A3, the number of deployments is determined using the following expression:

[0122] n×2A<H<(n+1)×2A (1)

[0123] k = n + 1 (2)

[0124] Where A represents the effective leakage propagation distance, H represents the risk distance, k represents the number of deployments, and n represents the proportionality coefficient.

[0125] In step A4, the spacing between the installations is determined using the following expression:

[0126]

[0127] Where L represents the deployment spacing, H represents the risk distance, and k represents the number of deployments.

[0128] In one embodiment, to reduce workload and improve efficiency while lowering costs during actual operation, the placement of vibration sensors for natural gas pipeline leak monitoring is optimized. Specifically, the placement scheme determination device D is further configured to determine the placement scheme of the leak monitoring sensors under the current leak mode through the following steps:

[0129] Step B1: Select the optimal vibration signal acquisition location based on the signal energy of the leakage vibration signals from different vibration sensor components under the current leakage mode.

[0130] Step B2: Based on the optimal vibration signal acquisition location, determine the deployment location of the leakage monitoring sensor under the current leakage mode, so as to form a deployment scheme for the leakage monitoring sensor for the current leakage mode by utilizing the number of sensors, the spacing between sensors, and the deployment location.

[0131] In step B2, the deployment location includes the deployment orientation and the deployment direction.

[0132] Specifically, when the leak monitoring sensor receives a continuous vibration signal with frequency characteristics matching the leak signal, it can be determined that a leak may have occurred in the pipe section within a 0.5L distance range on both sides of the sensor, and immediate investigation and confirmation are required.

[0133] Example 3

[0134] Based on the above embodiments one and two, the following describes the process of applying the system for determining the deployment scheme of pipeline leakage monitoring sensors described in the embodiments of the present invention to determine the leakage identification threshold in a certain area.

[0135] 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 determine the deployment scheme of pipeline leakage monitoring sensors.

[0136] 1) The leakage modes involved in a certain natural gas gathering and transmission pipeline in a certain region are shown in Table 1 below:

[0137] Table 1 Leakage Mode Table

[0138] 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

[0139] 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.

[0140] Table 2 Leakage Section Information Table

[0141]

[0142] 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 a vibration sensor array on both sides of the leak hole. Therefore, with the leak hole as the zero point (i.e., the location of pit 6), sensor installation points are set at distances of 0.1m, 5m, 10m (point A3, i.e., the location of pit 5), 20m (point A4, i.e., the location of pit 4), 30m, 40m, and 50m on both sides of it. The information of each point is shown in Table 3 below:

[0143] Table 3 Installation Point Information Table

[0144] 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)

[0145] Furthermore, 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, these mechanical waves may propagate simultaneously in both the axial and radial directions. To systematically study the propagation patterns of leakage vibration signals, it is necessary to simultaneously collect and analyze vibration signals propagating in both the axial and radial directions. Therefore, two accelerometers in two directions are installed on the outer wall of the pipeline at the same installation point using adhesive blocks 6 to achieve this purpose.

[0146] 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, 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.

[0147] 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.

[0148] 4) Determine the optimal vibration signal acquisition location

[0149] 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 6 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 7 As shown, the waveforms of the leakage vibration signals acquired at point A4 in the X and Y directions in three phases are as follows. Figure 8 As shown.

[0150] 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.

[0151] Table 4 Leakage Signal Energy Table for Different Directions and Installation Orientations

[0152]

[0153] 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.

[0154] 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.

[0155] 5) Determine the leakage detection threshold

[0156] Vibration sensors were installed at 14 locations (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.

[0157] Example 4

[0158] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of leakage monitoring sensors by applying the system described in the embodiments of the present invention to a natural gas gathering and transmission pipeline to determine the first leakage mode.

[0159] The first leakage mode is: the leakage type is corrosion perforation, the leakage pressure is 1 MPa, the leakage size is 2 mm, and the risk distance is 300 m.

[0160] 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.

[0161] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 1MPa and leakage hole size of 2mm) was excited and collected.

[0162] S3: Effective leakage propagation distance of the leakage signal.

[0163] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 9(a) shows the curve representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the first leakage mode. (Continue to refer to...) Figure 9 (a) The analysis suggests that the effective leakage propagation distance A for the first leakage mode is 96.43m.

[0164] S4: Deployment scheme for leak detection sensors

[0165] The effective propagation distance A for the first leakage mode is 96.43m, therefore L is 192.86m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only 3 leakage monitoring sensors need to be deployed on this corroded section, with an actual spacing of 100m between sensors. Figure 9 (b) shows an example result of the deployment scheme of the leak monitoring sensor for the first leak mode.

[0166] Example 5

[0167] Based on the above embodiments one through three, the following describes the process of determining the deployment scheme of leakage monitoring sensors by applying the system described in the embodiments of the present invention to a natural gas gathering and transmission pipeline to determine the second leakage mode.

[0168] The second leakage mode: the leakage type is corrosion perforation, the leakage pressure is 2 MPa, the leakage size is 2 mm, and the risk distance is 500 m.

[0169] 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.

[0170] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 2MPa and leakage hole size of 2mm) was excited and collected.

[0171] S3: Effective leakage propagation distance of the leakage signal.

[0172] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 10 (a) shows the curve representing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal for the second leakage mode. (Continue to refer to...) Figure 10(a) The analysis suggests that the effective leakage propagation distance A for the second leakage mode is 104.05m.

[0173] S4: Deployment scheme for leak detection sensors

[0174] The effective propagation distance A for the second leakage mode is 104.05m, therefore L is 208.1m. Leakage monitoring sensors are then deployed along the natural gas gathering and transmission pipeline wall according to L. Therefore, only 3 leakage monitoring sensors need to be deployed on this corroded section, with an actual spacing of 167m between sensors. Figure 10 (b) shows an example of the deployment scheme for the leak monitoring sensor for the second leak mode.

[0175] Example 6

[0176] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of leakage monitoring sensors in a natural gas gathering and transmission pipeline to determine a third leakage mode.

[0177] The third leakage mode: the leakage type is corrosion perforation, the leakage pressure is 3 MPa, the leakage size is 2 mm, and the risk distance is 400 m.

[0178] 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.

[0179] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 3MPa and leakage hole size of 2mm) was excited and collected.

[0180] S3: Effective leakage propagation distance of the leakage signal.

[0181] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 11 (a) shows the curve representing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal for the third leakage mode. (Continue to refer to...) Figure 11 (a) The analysis suggests that the effective leakage propagation distance A for the third leakage mode is 117.1m.

[0182] S4: Deployment scheme for leak detection sensors

[0183] The effective propagation distance A for the third leakage mode is 117.1m, therefore L is 234.2m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only two leakage monitoring sensors need to be deployed on this corroded section, with an actual deployment spacing of 200m. Figure 11 (b) shows an example of the deployment scheme for the leak monitoring sensor for the third leak mode.

[0184] Example 7

[0185] Based on the above embodiments one through three, the following describes the process of determining the deployment scheme of leakage monitoring sensors by applying the system described in the embodiments of the present invention to a natural gas gathering and transmission pipeline to determine the fourth leakage mode.

[0186] The fourth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 4 MPa, the leakage size is 2 mm, and the risk distance is 600 m.

[0187] 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.

[0188] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 4MPa and leakage hole size of 2mm) was excited and collected.

[0189] S3: Effective leakage propagation distance of the leakage signal.

[0190] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 12 (a) shows the curves representing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal for the fourth leakage mode. (Continue to refer to...) Figure 12 (a) The analysis suggests that the effective leakage propagation distance A for the fourth leakage mode is 126.06m.

[0191] S4: Deployment scheme for leak detection sensors

[0192] The effective propagation distance A for the fourth leakage mode is 126.06m, therefore L is 252.12m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only 3 leakage monitoring sensors need to be deployed on this liquid accumulation and corrosion section, with an actual deployment spacing of 200m. Figure 12 (b) shows an example of the deployment scheme for the leak monitoring sensor for the fourth leak mode.

[0193] Example 8

[0194] Based on the above embodiments one through three, the following describes the process of determining the deployment scheme of leakage monitoring sensors by the system described in the embodiments of the present invention for determining the fifth leakage mode in a natural gas gathering and transmission pipeline.

[0195] The fifth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 1 MPa, the leakage size is 5 mm, and the risk distance is 350 m.

[0196] 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.

[0197] S2: Collect natural noise from buried natural gas pipelines and determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, the sensors were installed at points A1 to A6, and the leakage vibration signal (operating pressure of 1MPa and leakage hole size of 5mm) was excited and collected.

[0198] S3: Effective leakage propagation distance of the leakage signal.

[0199] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 13 (a) shows the curves representing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal for the fifth leakage mode. (Continue to refer to...) Figure 13 (a) The analysis suggests that the effective leakage propagation distance A for the fifth leakage mode is 134.27m.

[0200] S4: Deployment scheme for leak detection sensors

[0201] The effective propagation distance A for the fifth leakage mode is 134.27m, therefore L is 268.54m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only two leakage monitoring sensors need to be deployed on this corroded section, with an actual spacing of 175m between the sensors. Figure 13 (b) shows an example of the deployment scheme for the leak monitoring sensor for the fifth leak mode.

[0202] Example 9

[0203] Based on the above embodiments one through three, the following describes the process of determining the deployment scheme of leakage monitoring sensors by applying the system described in the embodiments of the present invention to a natural gas gathering and transmission pipeline to determine the sixth leakage mode.

[0204] The sixth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 2 MPa, the leakage size is 5 mm, and the risk distance is 580 m.

[0205] 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.

[0206] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 2MPa and leakage hole size of 5mm) was excited and collected.

[0207] S3: Effective leakage propagation distance of the leakage signal.

[0208] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 14 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the sixth leakage mode. (Continue to refer to...) Figure 14 (a) The analysis suggests that the effective leakage propagation distance A for the sixth leakage mode is 112.97m.

[0209] S4: Deployment scheme for leak detection sensors

[0210] The effective propagation distance A for the sixth leakage mode is 112.97m, therefore L is 225.94m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only 3 leakage monitoring sensors need to be deployed on this liquid accumulation and corrosion section. The actual spacing between the leakage monitoring sensors is 193m. Figure 14 (b) shows an example of the deployment scheme for the leak monitoring sensor for the sixth leak mode.

[0211] Example 10

[0212] Based on the above embodiments one through three, the following describes the process of determining the deployment scheme of leakage monitoring sensors by applying the system described in the embodiments of the present invention to a certain natural gas gathering and transmission pipeline to determine the seventh leakage mode.

[0213] The seventh leakage mode: the leakage type is corrosion perforation, the leakage pressure is 3 MPa, the leakage size is 5 mm, and the risk distance is 430 m.

[0214] 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.

[0215] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 3MPa and leakage hole size of 5mm) was excited and collected.

[0216] S3: Effective leakage propagation distance of the leakage signal.

[0217] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 15 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the seventh leakage mode. (Continue to refer to...) Figure 15 (a) The analysis suggests that the effective leakage propagation distance A for the seventh leakage mode is 86.85m.

[0218] S4: Deployment scheme for leak detection sensors

[0219] The effective propagation distance A for the seventh leakage mode is 86.85m, therefore L is 173.7m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only 3 leakage monitoring sensors need to be deployed on this corroded section, with an actual spacing of 143m between the sensors. Figure 15 (b) shows an example of the deployment scheme for the leak monitoring sensor for the seventh leak mode.

[0220] Example 11

[0221] Based on the above embodiments one through three, the following describes the process of determining the deployment scheme of leakage monitoring sensors by the system described in the embodiments of the present invention for determining the eighth leakage mode in a natural gas gathering and transmission pipeline.

[0222] The eighth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 4 MPa, the leakage size is 5 mm, and the risk distance is 780 m.

[0223] 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.

[0224] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 4MPa and leakage hole size of 5mm) was excited and collected.

[0225] S3: Effective leakage propagation distance of the leakage signal.

[0226] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 16 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the eighth leakage mode. (Continue to refer to...) Figure 16 (a) The analysis suggests that the effective leakage propagation distance A for the eighth leakage mode is 99.83m.

[0227] S4: Deployment scheme for leak detection sensors

[0228] The effective propagation distance A for the eighth leakage mode is 99.83m, therefore L is 199.66m. Leakage monitoring sensors are then deployed along the natural gas gathering and transmission pipeline wall according to L. Therefore, four leakage monitoring sensors are sufficient to cover this corroded section, with an actual spacing of 195m between them. Figure 16 (b) shows an example of the deployment scheme for the leak monitoring sensor for the eighth leak mode.

[0229] Example 12

[0230] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of leakage monitoring sensors for a pipeline leakage monitoring system as described in the embodiments of the present invention, applied to a natural gas gathering and transmission pipeline to determine the ninth leakage mode.

[0231] The ninth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 1 MPa, the leakage size is 10 mm, and the risk distance is 980 m.

[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 pipelines and determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, the sensors were installed at points A1 to A6, and the leakage vibration signal (operating pressure of 1MPa and leakage hole size of 10mm) was excited and collected.

[0234] S3: Effective leakage propagation distance of the leakage signal.

[0235] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 17 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal for the ninth leakage mode. (Continue to refer to...) Figure 17 (a) The analysis suggests that the effective leakage propagation distance A for the ninth leakage mode is 117.45m.

[0236] S4: Deployment scheme for leak detection sensors

[0237] The effective propagation distance A for the ninth leakage mode is 117.45m, therefore L is 235m. Leakage monitoring sensors are then deployed along the natural gas gathering and transmission pipeline wall-mounted according to L. Therefore, only 5 leakage monitoring sensors need to be deployed on this corroded section, with an actual spacing of 196m between sensors. Figure 17 (b) shows an example of the deployment scheme for the leak monitoring sensor for the ninth leak mode.

[0238] Example 13

[0239] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of leakage monitoring sensors for a certain natural gas gathering and transmission pipeline to determine the tenth leakage mode.

[0240] The tenth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 2 MPa, the leakage size is 10 mm, and the risk distance is 600 m.

[0241] 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.

[0242] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 2MPa and leakage hole size of 10mm) was excited and collected.

[0243] S3: Effective leakage propagation distance of the leakage signal.

[0244] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 18 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the tenth leakage mode. (Continue to refer to...) Figure 18 (a) Analysis suggests that the effective leakage propagation distance A for the tenth leakage mode is 150m.

[0245] S4: Deployment scheme for leak detection sensors

[0246] The effective propagation distance A for the tenth leakage mode is 150m, therefore L is 300m. Leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall according to L. Therefore, only two leakage monitoring sensors need to be deployed on this corroded section, with an actual deployment spacing of 300m. Figure 18 (b) shows an example of the deployment scheme for the leak monitoring sensor for the tenth leak mode.

[0247] Example 14

[0248] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of the leakage monitoring sensor of the system for determining the pipeline leakage monitoring sensor described in the embodiments of the present invention, applied to a natural gas gathering and transmission pipeline to determine the eleventh leakage mode.

[0249] Eleventh leakage mode: The leakage type is corrosion perforation, the leakage pressure is 3 MPa, the leakage size is 10 mm, and the risk distance is 700 m.

[0250] 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.

[0251] S2: Collect natural noise from buried natural gas pipelines and determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, the sensor was installed at points A1 to A5, and the leakage vibration signal (operating pressure of 3MPa and leakage hole size of 10mm) was excited and collected.

[0252] S3: Effective leakage propagation distance of the leakage signal.

[0253] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 19 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the eleventh leakage mode. (Continue to refer to...) Figure 19 (a) The analysis suggests that the effective leakage propagation distance A for the eleventh leakage mode is 158.2m.

[0254] S4: Deployment scheme for leak detection sensors

[0255] The effective propagation distance A for the eleventh leakage mode is 158.2m, therefore L is 316.4m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only three leakage monitoring sensors need to be deployed on this corroded section, with an actual deployment spacing of 233m. Figure 19 (b) shows an example of the deployment scheme for the leak monitoring sensor for the eleventh leak mode.

[0256] Example 15

[0257] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of leakage monitoring sensors by applying the system described in the embodiments of the present invention to a natural gas gathering and transmission pipeline to determine the twelfth leakage mode.

[0258] The twelfth leakage mode: the leakage type is corrosion perforation, the leakage pressure is 4 MPa, the leakage size is 10 mm, and the risk distance is 1000 m.

[0259] 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.

[0260] S2: Collect natural noise from buried natural gas pipelines and determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, the sensors were installed at points A1 to A6, and the leakage vibration signal (operating pressure of 4MPa and leakage hole size of 10mm) was excited and collected.

[0261] S3: Effective leakage propagation distance of the leakage signal.

[0262] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 20 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the twelfth leakage mode. (Continue to refer to...) Figure 20 (a) Analysis suggests that the effective leakage propagation distance A for the twelfth leakage mode is 176.5m.

[0263] S4: Deployment scheme for leak detection sensors

[0264] The effective propagation distance A for the twelfth leakage mode is 176.5m, therefore L is 353m. Leakage monitoring sensors are then deployed along the natural gas gathering and transmission pipeline wall-mounted according to L. Therefore, only three leakage monitoring sensors need to be deployed on this corroded section, with an actual spacing of 333m between sensors. Figure 20 (b) shows an example of the deployment scheme for the leak monitoring sensor for the twelfth leak mode.

[0265] Example 16

[0266] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of the leakage monitoring sensor of the system for determining the pipeline leakage monitoring sensor described in the embodiments of the present invention, applied to a natural gas gathering and transmission pipeline to determine the thirteenth leakage mode.

[0267] The thirteenth leakage mode: the leakage type is stress cracking, the leakage pressure is 3 MPa, the leakage size is 20 mm, and the risk distance is 1100 m.

[0268] 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.

[0269] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 3MPa and leakage hole size of 20mm) was excited and collected.

[0270] S3: Effective leakage propagation distance of the leakage signal.

[0271] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 21 (a) shows the curves representing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal for the thirteenth leakage mode. (Continue to refer to...) Figure 21 (a) The analysis suggests that the effective leakage propagation distance A of the thirteenth leakage mode is 187.65m.

[0272] S4: Deployment scheme for leak detection sensors

[0273] The effective propagation distance A for the thirteenth leakage mode is 187.65m, therefore L is 375.3m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only three leakage monitoring sensors need to be deployed on this corroded section, with an actual deployment spacing of 367m. Figure 21 (b) shows an example of the deployment scheme for the leak monitoring sensor for the thirteenth leak mode.

[0274] Example 17

[0275] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of the leakage monitoring sensor of the system for determining the pipeline leakage monitoring sensor described in the embodiments of the present invention, applied to a natural gas gathering and transmission pipeline to determine the fourteenth leakage mode.

[0276] The fourteenth leakage mode: the leakage type is stress cracking, the leakage pressure is 3 MPa, the leakage size is 30 mm, and the risk distance is 960 m.

[0277] 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.

[0278] S2: Collect natural noise from buried natural gas pipelines and 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 (operating pressure of 3MPa and leakage hole size of 30mm) was excited and collected.

[0279] S3: Effective leakage propagation distance of the leakage signal.

[0280] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 22 (a) shows the curve representing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal for the fourteenth leakage mode. (Continue to refer to...) Figure 22 (a) Analysis suggests that the effective leakage propagation distance A for the fourteenth leakage mode is 182.66m.

[0281] S4: Deployment scheme for leak detection sensors

[0282] The effective propagation distance A for the fourteenth leakage mode is 182.66m, therefore L is 365.32m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only three leakage monitoring sensors need to be deployed on this corroded section, with an actual spacing of 320m between sensors. Figure 22 (b) shows an example of the deployment scheme for the leak monitoring sensor for the fourteenth leak mode.

[0283] Example 18

[0284] Based on the above embodiments one through three, the following describes the process of determining the layout scheme of leakage monitoring sensors by applying the system for determining the pipeline leakage monitoring sensor layout scheme to a certain natural gas gathering and transmission pipeline to determine the fifteenth leakage mode.

[0285] The fifteenth leakage mode: the leakage type is stress cracking, the leakage pressure is 3 MPa, the leakage size is 50 mm, and the risk distance is 1500 m.

[0286] 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.

[0287] S2: Collect natural noise from buried natural gas pipelines and determine the leakage detection threshold as 1.8162*10. -4 According to the technical solution requirements, the sensors were installed at points A1 to A6, and the leakage vibration signal (operating pressure of 3MPa and leakage hole size of 50mm) was excited and collected.

[0288] S3: Effective leakage propagation distance of the leakage signal.

[0289] Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leak point to be tested, an exponential fitting method is used to obtain a curve characterizing the relationship between the installation position of the vibration sensor and the change in the leakage vibration signal energy. Figure 23 (a) shows the curves representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy for the fifteenth leakage mode. (Continue to refer to...) Figure 23 (a) Analysis suggests that the effective leakage propagation distance A for the fifteenth leakage mode is 177.23m.

[0290] S4: Deployment scheme for leak detection sensors

[0291] The effective propagation distance A for the fifteenth leakage mode is 177.23m, therefore L is 354.5m. Based on L, the leakage monitoring sensors are deployed along the natural gas gathering and transmission pipeline wall-mounted. Therefore, only 5 leakage monitoring sensors need to be deployed on this liquid accumulation and corrosion section, with an actual deployment spacing of 300m. Figure 23 (b) shows an example of the deployment scheme for the leak monitoring sensor for the fifteenth leak mode.

[0292] Example 19

[0293] Based on the systems for determining pipeline leak monitoring sensor deployment schemes provided in Embodiments 1-18 above, this invention also provides a method for determining pipeline leak monitoring sensor deployment schemes. This method for determining pipeline leak monitoring sensor deployment schemes is implemented using the systems described above.

[0294] This invention proposes a system and method for determining the deployment scheme of pipeline leak monitoring sensors. By optimizing the installation location of the vibration signal acquisition device, this system and method ensures that the phase of the leak point does not affect the acquisition of the leak signal, thus guaranteeing the scientific validity and reliability of the leak vibration signal acquisition. Secondly, by determining the deployment scheme of the leak monitoring sensors under corresponding leak modes, this invention solves the problem of high difficulty and cost associated with drilling holes in the pipe body or excavating the entire pipeline when adding leak monitoring sensors to existing natural gas pipelines.

[0295] 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.

[0296] 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.

[0297] 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.

[0298] 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.

[0299] 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.

[0300] 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 variations in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection for this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A system for determining the deployment scheme of pipeline leak monitoring sensors, 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 shape of the leakage point, the size of the leakage point and the 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 deployment scheme determination device is used to collect leakage vibration signals under different leakage modes and extract features to determine the deployment scheme of leakage monitoring sensors under the corresponding leakage modes.

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, which is 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 deployment scheme determination device is further configured to obtain a curve characterizing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal based on the leakage vibration signals collected at different vibration sensor installation locations during the leakage test phase. Based on this curve, and combined with natural noise signals of a preset duration collected from the vibration sensor array during the non-leakage test phase, the device determines the deployment scheme of the leakage monitoring sensors under the corresponding leakage mode. The curve characterizing the relationship between the vibration sensor installation location and the energy change of the leakage vibration signal is obtained using the following steps: Based on the leakage vibration signals from different vibration sensors under the current leakage mode, the signal energy of the leakage vibration signal is extracted using the root mean square processing method. Based on the signal energy of the leakage vibration signal and the distance between the installation position of the vibration sensor and the leakage point to be tested, the curve characterizing the relationship between the installation position of the vibration sensor and the change in leakage vibration signal energy is obtained using the exponential fitting method.

9. The system according to claim 8, characterized in that, The deployment scheme determination device is also configured to determine the deployment scheme of the leakage monitoring sensors under the current leakage mode through the following steps: Based on the natural noise signal, a leakage detection threshold for the experimental gathering and transportation pipeline in the current buried pipeline area is determined, wherein the leakage detection threshold is the average value of the root mean square energy of the natural noise signal; Based on the curve representing the relationship between the installation location of the vibration sensor and the energy change of the leakage vibration signal corresponding to the current leakage mode, and combined with the leakage identification threshold, the effective leakage propagation distance of the current leakage mode is obtained. The number of leak monitoring sensors to be deployed is determined based on the effective leak propagation distance and the risk distance of the current leak mode. Based on the number of sensors deployed and the risk distance, the deployment spacing of the leak monitoring sensors is determined, so as to form a deployment scheme for the leak monitoring sensors for the current leak mode using the number of sensors deployed and the deployment spacing.

10. The system according to claim 9, characterized in that, The deployment scheme determination device is also configured to generate the effective leakage propagation distance of the current leakage mode through the following steps: Based on the curve representing the relationship between the installation location of the vibration sensor and the change in leakage vibration signal energy, the distance corresponding to when the signal energy in the current curve reaches the leakage identification threshold is identified and recorded as the effective leakage propagation distance.

11. The system according to claim 9 or 10, characterized in that, The number of deployments is determined using the following expression: n×2A <H<(n+1)×2A k = n + 1 Where A represents the effective leakage propagation distance, H represents the risk distance, k represents the number of deployments, and n represents the proportionality coefficient; The layout spacing is determined using the following expression: Where L represents the deployment spacing, H represents the risk distance, and k represents the number of deployments.

12. The system according to any one of claims 9 to 11, characterized in that, The deployment scheme determination device is also configured to: Based on the signal energy of the leakage vibration signals from different vibration sensor components under the current leakage mode, the optimal vibration signal acquisition location is selected; Based on the optimal vibration signal acquisition location, the deployment location of the leakage monitoring sensor under the current leakage mode is determined. The deployment location includes the deployment orientation and direction, so as to form a deployment scheme for the leakage monitoring sensor for the current leakage mode by using the number of sensors, the deployment spacing and the deployment location.

13. A method for determining the deployment scheme of pipeline leak monitoring sensors, characterized in that, The method is implemented using the system as described in any one of claims 1 to 12.

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