A system and method for discriminating risk states of a natural gas pipeline

Abstract

This invention discloses a system and method for determining the risk status of natural gas pipelines, comprising: a dual-function signal acquisition device equipped with multiple dual-function signal detectors for acquiring real-time seismic / vibration signals of the gathering and transportation pipeline to be inspected; an intrusion accident determination device for performing feature analysis on the real-time seismic signals and diagnosing whether an intrusion accident has occurred in the gathering and transportation pipeline to be inspected based on the seismic feature analysis results; a leakage accident determination device for performing feature analysis on the real-time vibration signals and determining whether a leakage risk exists based on the vibration feature analysis results, identifying the location of the leakage source if a leakage risk exists, and diagnosing whether a leakage accident has occurred in the gathering and transportation pipeline to be inspected based on the location of the leakage source; and a status determination device for determining the risk status of the gathering and transportation pipeline to be inspected based on the intrusion accident diagnosis results and the leakage accident diagnosis results. This invention can identify pipeline intrusion events and leakage events, realizing the monitoring of the safety status of gathering and transportation pipelines.

Description

Technical Field

[0001] This invention relates to the field of natural gas pipeline safety monitoring technology, and in particular to a system and method for determining the risk status of natural gas pipelines. Background Technology

[0002] Pipelines, as a primary mode of oil and gas transportation, offer advantages such as high stability and low cost. However, with the rapid development of oil and gas pipeline networks, leaks due to various factors are becoming increasingly frequent. Currently, the main causes of leaks in gathering and transportation pipelines include external human intrusion and corrosion and stress cracking.

[0003] Monitoring for production and safety accidents caused by third-party intrusion is primarily achieved through on-site video surveillance or infrared camera identification. However, on-site video surveillance requires significant manpower and resources, and its effectiveness is affected by factors such as the responsibility and attention of the personnel, making it prone to missed detections. Infrared camera identification can detect abnormal heat sources, but it still cannot achieve 100% identification of intruders wearing professional protective clothing.

[0004] Monitoring methods for leaks caused by corrosion and stress cracking 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. However, the deployment of these monitoring methods primarily involves laying them along the entire pipeline. The mass / volume balance method achieves monitoring by installing embedded pressure / flow sensors along the entire pipeline; the distributed optical fiber method requires laying optical fibers in the same trench as the pipeline; and the acoustic method achieves monitoring by installing embedded acoustic sensors along the entire pipeline, but the cost of such a comprehensive deployment is enormous.

[0005] Currently, almost all pipeline operators have adopted safety monitoring systems, but existing technologies and inventions for monitoring oil and gas gathering and transportation pipeline leakage risks only target a single factor.

[0006] An existing patent document (publication number CN1 16488652B) discloses an intelligent monitoring device and method for the safety status of oil and gas pipelines. This solution collects strain data of the oil and gas pipeline body and various environmental parameter data of the surrounding environment through a data acquisition module, but it does not simultaneously achieve effective monitoring of abnormal external activities (i.e., third-party intrusion) and pipeline leakage (i.e., corrosion and stress cracking).

[0007] A low-frequency ultra-high sensitivity detector is disclosed in an existing patent document (publication number CN1 17471522A). This patent aims to improve the sensitivity of the detector while ensuring that the DC resistance of the detector does not increase significantly, thus addressing the problem of decreased overall conversion capability of the detector. However, it does not simultaneously achieve effective monitoring of abnormal external activities (i.e., third-party intrusion) and pipeline leakage (i.e., corrosion and stress cracking).

[0008] A microseismic sensor suitable for highly corrosive deep-sea environments is disclosed in an existing patent document (publication number CN104360378B). It overcomes the shortcomings of existing technologies in terms of general corrosion resistance when used in highly corrosive environments, and can be used stably and reliably for extended periods in such environments. However, it does not simultaneously achieve effective monitoring of both external abnormal activities (i.e., third-party intrusion) and pipeline leakage (i.e., corrosion and stress cracking).

[0009] Therefore, there is currently no solution that can simultaneously and effectively monitor abnormal external activities (third-party intrusion) and pipeline leakage (corrosion and stress cracking).

[0010] In summary, there is a need in the existing technology to provide a solution that can simultaneously achieve real-time monitoring of external abnormal activities and internal leakage, so as to ensure effective control over the safety status of buried gathering and transmission pipelines. Summary of the Invention

[0011] The purpose of this invention is to provide a solution that can simultaneously achieve real-time monitoring of external abnormal activities and internal leakage, so as to ensure effective control over the safety status of buried gathering and transmission pipelines.

[0012] To address the aforementioned technical problems, embodiments of the present invention provide a system for determining the risk status of a natural gas pipeline, comprising: a dual-function signal acquisition device, which includes multiple dual-function signal detectors arranged at different axial positions along the pipeline to be inspected; the dual-function signal detectors include a vibration signal acquisition device and a seismic signal acquisition device, the vibration / seismic signal acquisition device being used to acquire real-time seismic / vibration signals of the pipeline to be inspected; an intrusion accident determination device, which is used to perform feature analysis on the real-time seismic signals and, based on the seismic feature analysis results and using preset intrusion risk conditions, diagnose whether an intrusion accident has occurred in the pipeline to be inspected; a leakage accident determination device, which is used to perform feature analysis on the real-time vibration signals and, based on the vibration feature analysis results and using preset leakage risk conditions, determine whether a leakage risk exists, identify the location of the leakage source if a leakage risk exists, and diagnose whether a leakage accident has occurred in the pipeline to be inspected based on the location of the leakage source; and a status determination device, which is used to determine the risk status of the pipeline to be inspected based on the intrusion accident diagnosis results and the leakage accident diagnosis results.

[0013] Preferably, the vibration signal acquisition device is installed on the outer wall of the pipeline to be tested. The vibration signal acquisition device includes at least one set of vibration signal acquisition components, which are respectively installed on the pipeline cross-section at different locations. The vibration signal acquisition components include vibration sensors installed at different locations, and the vibration sensors are equipped with acceleration sensors that measure different vibration directions at the current location.

[0014] Preferably, the seismic signal acquisition device is buried in the soil layer where the pipeline to be detected is located, and the seismic signal acquisition device includes at least one set of seismic signal acquisition components, wherein the at least one set of seismic signal acquisition components includes three detectors arranged in orthogonal directions of different axes.

[0015] Preferably, the dual-function signal acquisition device further includes a protective housing, which comprises: an outer shell having an upper cover and a lower bucket; the upper cover having a first interface connected to the vibration signal acquisition device; the lower bucket housing the seismic signal acquisition device within its internal cavity; the lower bucket having a threaded hole at its bottom for detachable connection to a base; and a base for fixing the seismic signal acquisition device in the soil layer where the collection and transmission pipeline to be tested is located by inserting itself into the soil when connected to the lower bucket.

[0016] Preferably, the preset intrusion risk conditions include a preset seismic signal risk identification threshold, a preset centroid frequency range, and a preset dominant frequency range. The intrusion accident detection device is configured to diagnose whether an intrusion accident has occurred in the pipeline to be detected through the following steps: extracting signal energy from real-time seismic signals using a root mean square (RMS) processing method; performing spectral analysis on the signal energy to obtain seismic characteristic analysis results, including signal energy, dominant frequency range, and centroid frequency; comparing the signal energy and seismic characteristic analysis results with the preset intrusion risk conditions, and obtaining an intrusion accident diagnosis result based on the comparison results. The preset seismic data risk identification threshold is the seismic signal intensity of natural noise in the area where the pipeline to be detected is located. Specifically, if the signal energy of the seismic signal within a preset time period reaches or exceeds the preset seismic signal risk identification threshold, and the centroid frequency meets the preset centroid frequency range, and the dominant frequency range meets the preset dominant frequency range, an intrusion accident is determined to have occurred in the pipeline to be detected.

[0017] Preferably, the preset leakage risk conditions include: a preset vibration signal risk identification threshold, a preset wideband range, a preset high-frequency range, and a preset root-mean-square (RMS) frequency range. The leakage accident identification device is configured to determine the leakage source location through the following steps: extracting signal energy from the real-time vibration signal using a RMS processing method; performing spectral analysis on the signal energy to obtain vibration characteristic analysis results, including signal energy, bandwidth, dominant frequency range, and RMS frequency; comparing the signal energy and vibration characteristic analysis results of the vibration signal with the preset leakage risk conditions, and obtaining a leakage risk determination result based on the comparison results. Specifically, when the vibration signal within a preset time period is a continuous vibration signal, and the signal energy reaches or exceeds the preset vibration signal risk identification threshold, and the bandwidth satisfies the preset wideband range, the dominant frequency range satisfies the preset high-frequency range, and the RMS frequency satisfies the preset RMS frequency range, the signal acquisition location meeting the conditions is taken as the leakage risk location; and the target leakage source location is identified from the leakage risk locations.

[0018] Preferably, the leakage accident identification device is further configured to identify the location of the leakage source through the following steps: obtaining the normalized cross-correlation function value of the vibration signal at the leakage risk location based on the vibration signal at different leakage risk locations, and calculating the observation time difference between the vibration signals related to the normalized cross-correlation function value based on the vibration signal normalized cross-correlation function value; determining the search range of the leakage source location based on multiple leakage risk locations, and obtaining multiple candidate locations based on the search range and a preset location search step size; determining the velocity search range based on the propagation velocity of the vibration signal at different leakage risk locations, and determining multiple candidate velocities based on the velocity search range and a preset velocity search step size; obtaining at least one location target function value using a preset target function based on the multiple candidate locations and multiple candidate velocities, combined with the vibration signal normalized cross-correlation function value and the observation time difference; and obtaining the target leakage source location based on the location corresponding to the location target function value with the smallest value among all location target function values.

[0019] Preferably, the normalized cross-correlation function value is calculated using the following expression:

[0020]

[0021] Among them, R ij (τ) represents the normalized cross-correlation function value, N represents the number of sampling points of the vibration signal, and x i (n) represents the vibration signal at the target risk location, x j (n) represents the vibration signal at the j-th remaining leakage risk location, and τ is the time lag.

[0022] Preferably, the location target function value is calculated using the following steps:

[0023]

[0024] Where g represents the objective function value of the positioning parameters, K represents the number of sensors, and R ij Δt represents the normalized cross-correlation function value. ii Δat represents the theoretical time difference. ij tt represents the observation time difference. k This represents the arrival time (in seconds) of the vibration signal collected by the k-th sensor at a specified candidate location and speed. m Let a represent the m-th position value among all candidate positions. k v represents the position of the k-th sensor. n At represents the nth speed value among all candidate speeds. i At represents the arrival time of the vibration signal at the target risk location of the i-th sensor. j Let t represent the arrival time of the vibration signal from the j-th sensor. i Let t represent the arrival time of the vibration signal at the selected position and velocity on the i-th sensor. j This represents the arrival time of the vibration signal on the j-th sensor, given the candidate position and candidate velocity.

[0025] Preferably, the leakage accident detection device is further configured to determine that a leakage accident has occurred in the gathering and transportation pipeline to be detected through the following steps: determining at least one leakage risk location related to the current leakage source location; calculating the duration corresponding to when the vibration characteristic analysis result of the relevant leakage risk location meets the preset leakage risk condition; locating the dynamic leakage source location within the duration based on the relevant leakage risk location, and then determining the leakage accident diagnosis result based on the distance deviation standard deviation between the dynamic leakage source location and the current target leakage source location; and obtaining the leakage accident diagnosis result based on the distance deviation standard deviation and the duration, wherein a leakage accident is determined to have occurred in the gathering and transportation pipeline to be detected when the duration is greater than a preset time threshold and the distance standard deviation is less than a preset distance deviation threshold.

[0026] Preferably, the vibration signal acquisition device further includes: an adhesive block, which couples to the outer surface of the pipeline to be tested via a vibration coupling agent; and connecting bolts, which mount the vibration sensor on the adhesive block.

[0027] On the other hand, embodiments of the present invention also provide a method for determining the risk status of a natural gas pipeline, 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 risk status of natural gas pipelines. The system and method install a dual-function signal acquisition device on high-risk pipeline sections in accident-prone or high-consequence areas. By real-time acquisition, transmission, and analysis of seismic wave signals and pipe vibration signals around the natural gas gathering and transmission pipeline, it identifies third-party intrusion activities and persistent leakage events. It can simultaneously and effectively identify and alarm on both pipeline section leaks and third-party intrusions, achieving safety status monitoring of buried gathering and transmission 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 risk status of a natural gas pipeline, 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 risk status of a natural gas pipeline, according to an embodiment of this application.

[0034] Figure 3 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 risk status of a natural gas pipeline, according to an embodiment of this application.

[0035] Figure 4 This is a schematic diagram of the specific structure of the vibration signal acquisition device in the system for determining the risk status of natural gas pipelines according to an embodiment of this application.

[0036] Figure 5 This is a schematic diagram of the specific structure of a dual-function signal acquisition device in a system for determining the risk status of a natural gas pipeline, according to an embodiment of this application.

[0037] Figure 6 This is a schematic diagram of the specific structure of the top cover in the system for determining the risk status of a natural gas pipeline according to an embodiment of this application.

[0038] Figure 7This is a schematic diagram of the specific structure of the base in the system for determining the risk status of a natural gas pipeline, according to an embodiment of this application.

[0039] Figure 8 This is an example diagram illustrating the installation method of a dual-function signal acquisition device in a system for determining the risk status of a natural gas pipeline, according to an embodiment of this application.

[0040] Figure 9 This is a flowchart illustrating the workflow of the main control module in a system used to determine the risk status of a natural gas pipeline, as described in this application embodiment.

[0041] Figure 10 This is a flowchart illustrating the operation of a clock synchronization unit in a system used to determine the risk status of a natural gas pipeline, as described in an embodiment of this application.

[0042] Figure 11 This is a flowchart illustrating the self-test function of the main control unit in a system used to determine the risk status of a natural gas pipeline, as described in this application embodiment.

[0043] Figure 12 This is a flowchart illustrating the signal preprocessing process performed by a control device in a system for determining the risk status of a natural gas pipeline, as described in an embodiment of this application.

[0044] Figure 13 This is a flowchart illustrating the operation of a power supply module in a system for determining the risk status of a natural gas pipeline, as described in an embodiment of this application.

[0045] Figure 14 This is an example diagram illustrating the deployment scheme and data acquisition coverage of a dual-function signal acquisition device and a single-function detector in a system for determining the risk status of a natural gas pipeline, as described in an embodiment of this application.

[0046] Figure 15 This is a schematic diagram illustrating the principle of preprocessing real-time vibration signals in a system for determining the risk status of natural gas pipelines, as described in an embodiment of this application.

[0047] Figure 16 This is a schematic diagram illustrating the principle of extracting the root mean square frequency in a system for determining the risk status of a natural gas pipeline, according to an embodiment of this application.

[0048] Figure 17 This is an example diagram illustrating the deployment scheme of a dual-function signal acquisition device and a single-function detector for a first example pipe segment in a system for determining the risk status of a natural gas pipeline, as described in an embodiment of this application.

[0049] Figure 18 This is an example diagram illustrating the deployment scheme of the dual-function signal acquisition device and single-function detector corresponding to the second example pipe section in the system for determining the risk status of a natural gas pipeline, as described in this application embodiment.

[0050] Figure 19 This is an example diagram illustrating the deployment scheme of the dual-function signal acquisition device and single-function detector corresponding to the third example pipe section in the system for determining the risk status of a natural gas pipeline according to an embodiment of this application.

[0051] Figure 20 This is an example diagram illustrating the deployment scheme of the dual-function signal acquisition device and single-function detector corresponding to the fourth example pipe section in the system for determining the risk status of a natural gas pipeline according to an embodiment of this application.

[0052] Figure 21 This is an example diagram of the seismic signal waveform and frequency domain characteristic information collected from a first example pipe segment in a system for determining the risk status of a natural gas pipeline, as described in an embodiment of this application.

[0053] Figure 22 This is an example diagram of the waveform and frequency domain characteristic information of the seismic signal corresponding to the third example pipe segment in the system for determining the risk status of a natural gas pipeline, as described in this application embodiment.

[0054] Figure 23 This is an example diagram of the waveform and frequency domain characteristic information of the vibration signal corresponding to the first example pipe segment in the system for determining the risk status of a natural gas pipeline, as described in this application embodiment.

[0055] Figure 24 This is an example diagram of the vibration signal and frequency domain characteristic information corresponding to the fourth example pipe segment of the system for determining the risk status of a natural gas pipeline, as described in this application embodiment. Detailed Implementation

[0056] 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.

[0057] 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.

[0058] 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.

[0059] An existing patent document (publication number CN1 16488652B) discloses an intelligent monitoring device and method for the safety status of oil and gas pipelines. This solution collects strain data of the oil and gas pipeline body and various environmental parameter data of the surrounding environment through a data acquisition module, but it does not simultaneously achieve effective monitoring of abnormal external activities (i.e., third-party intrusion) and pipeline leakage (i.e., corrosion and stress cracking).

[0060] A low-frequency ultra-high sensitivity detector is disclosed in an existing patent document (publication number CN1 17471522A). This patent aims to improve the sensitivity of the detector while ensuring that the DC resistance of the detector does not increase significantly, thus addressing the problem of decreased overall conversion capability of the detector. However, it does not simultaneously achieve effective monitoring of abnormal external activities (i.e., third-party intrusion) and pipeline leakage (i.e., corrosion and stress cracking).

[0061] A microseismic sensor suitable for highly corrosive deep-sea environments is disclosed in an existing patent document (publication number CN104360378B). It overcomes the shortcomings of existing technologies in terms of general corrosion resistance when used in highly corrosive environments, and can be used stably and reliably for extended periods in such environments. However, it does not simultaneously achieve effective monitoring of both external abnormal activities (i.e., third-party intrusion) and pipeline leakage (i.e., corrosion and stress cracking).

[0062] Therefore, there is currently no solution that can simultaneously and effectively monitor abnormal external activities (third-party intrusion) and pipeline leakage (corrosion and stress cracking).

[0063] In summary, there is a need in the existing technology to provide a solution that can simultaneously achieve real-time monitoring of external abnormal activities and internal leakage, so as to ensure effective control over the safety status of buried gathering and transmission pipelines.

[0064] Example 1

[0065] Figure 1 This is a schematic diagram of the overall structure of a system for determining the risk status of a natural gas pipeline, according to an embodiment of this application. Figure 2 This is a schematic diagram of the specific structure of a system for determining the risk status of a natural gas pipeline, according to an embodiment of this application. (Combined with...) Figure 1 and Figure 2 The specific structure of the system for determining the risk status of natural gas pipelines (hereinafter referred to as the "determination system") described in the embodiments of the present invention will be explained.

[0066] like Figure 1 As shown, the discrimination system includes: a dual-function signal acquisition device A, an intrusion accident discrimination device B, a leakage accident discrimination device C, and a status discrimination device D. The dual-function signal acquisition device A has multiple dual-function signal detectors installed at different axial positions along the pipeline to be inspected. These dual-function signal detectors include a vibration signal acquisition device A1 and a seismic signal acquisition device A2.

[0067] Vibration signal acquisition device A1 is configured to acquire real-time vibration signals of the gathering and transportation pipeline under inspection. Seismic signal acquisition device A2 is configured to acquire real-time seismic signals of the gathering and transportation pipeline under inspection.

[0068] The intrusion accident detection device B is configured to perform feature analysis on real-time seismic signals and, based on the seismic feature analysis results, use preset intrusion risk conditions to diagnose whether an intrusion accident has occurred in the gathering and transportation pipeline to be detected.

[0069] Leakage accident detection device C is configured to perform feature analysis on real-time vibration signals, and based on the vibration feature analysis results, use preset leakage risk conditions to determine whether there is a leakage risk. If there is a leakage risk, the location of the leakage source is identified, and based on the location of the leakage source, the leakage accident of the collection and transportation pipeline to be detected is diagnosed.

[0070] The status determination device D is configured to determine the risk status of the gathering and transportation pipeline to be inspected based on the diagnostic results of intrusion accidents and leakage accidents. Specifically, it determines that the gathering and transportation pipeline to be inspected is in a risky state when intrusion accidents and leakage accidents occur.

[0071] In one embodiment, reference Figure 2 The vibration signal acquisition device A1 is installed on the outer wall of the pipeline to be inspected. The vibration signal acquisition device A1 includes at least one set of vibration signal acquisition components, which are respectively installed on different sections of the pipeline. Each vibration signal acquisition component includes vibration sensors installed at different locations, and each vibration sensor has an acceleration sensor that measures different vibration directions at the current location.

[0072] Specifically, the vibration signal acquisition device A1 is attached to the pipeline to be tested, either individually or in pairs, to identify the continuous high-frequency vibration signal of the pipeline caused by leakage. The vibration signal acquisition device A1 mainly uses multiple acceleration sensors connected to the first interface on the top cover 3 via external cables. The vibration sensors themselves are attached to the outer wall of the pipeline to be tested via adhesive blocks 1.

[0073] When a leak occurs in the pipeline under inspection, 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 comprehensively monitor the leak vibration signal, it is necessary to simultaneously collect and analyze the vibration signals propagating in both the axial and radial directions. Therefore, refer to... Figure 3 (a) Two accelerometers (parallel to the pipe axis and perpendicular to the pipe axis) need to be installed on the outer wall of the collection and transportation pipeline to be tested via adhesive block 1 in the X and Y directions. The installation phase is as follows: Figure 3 As shown in (b).

[0074] In particular, when the number of acceleration sensors is limited or the installation conditions do not allow it, only one acceleration sensor can be installed in the direction perpendicular to the pipeline axis (i.e., the Y direction). The installation phase of the acceleration sensor on the collection and transportation pipeline to be tested is all at the 0 point position.

[0075] Optionally, the vibration signal of the pipeline body to be detected can be acquired unidirectionally or bidirectionally. In order to ensure the acquisition effect of the pipeline vibration signal, the vibration sensor is preferably an accelerometer with a bandwidth of 1 to 6000 Hz, a sensitivity of 300 to 500 mV / s, and a resonant frequency of 10 to 15 kHz.

[0076] Furthermore, combined Figure 2 and Figure 4 The vibration signal acquisition device A1 also includes: adhesive block 1 and connecting bolt 2.

[0077] The adhesive block 1 is coupled to the outer surface of the gathering and transportation pipeline to be tested through a vibration coupling agent.

[0078] Connecting bolt 2 mounts the vibration sensor onto adhesive block 1.

[0079] Specifically, please refer to Figure 4 The vibration sensor primarily collects real-time vibration signals caused by pipeline leaks using single or paired accelerometers. Therefore, it is installed by fixing it to the outer surface of the pipeline under inspection without damaging the pipeline's anti-corrosion layer. To increase the coupling between the vibration sensor and the pipeline and improve signal acquisition, a specially designed adhesive block 1 is fixed to the outer surface of the pipeline using a vibration coupling agent. The vibration sensor is then mounted on the adhesive block 1 for coupling. Specifically, to further enhance the coupling between the vibration sensor and the pipeline, the lower surface of the adhesive block 1 is designed with a corresponding arc shape based on the pipeline dimensions.

[0080] In one embodiment, the seismic signal acquisition device A2 is buried in the soil layer where the pipeline to be inspected is located. The seismic signal acquisition device A2 includes at least one set of seismic signal acquisition components. The at least one set of seismic signal acquisition components includes three geophones arranged in orthogonal directions on different axes.

[0081] Specifically, the seismic signal acquisition device A2 is mainly responsible for acquiring seismic signals around the pipeline under test caused by third-party intrusion, and for identifying and alarming external abnormal activities. The seismic signal acquisition device A2 consists of three detectors, which are orthogonally arranged along the X, Y, and Z axes to acquire seismic signals around the pipeline under test in three directions.

[0082] Optionally, in order to ensure the acquisition effect of third-party intrusive seismic signals, the seismic signal acquisition device A2 uses a detector with a bandwidth of 0.2 to 300 Hz, a sensitivity of 200 to 300 mV / s, a maximum dip angle of less than or equal to 5°, an inter-channel amplitude consistency of less than 5%, and an inter-channel phase consistency of less than 0.1 s.

[0083] In one embodiment, the dual-function signal acquisition device A further includes a protective housing. The protective housing includes an outer shell and a base.

[0084] refer to Figure 5 The outer casing comprises an upper cover 3 and a lower bucket 4. The upper cover 3 has a first interface, which is connected to the vibration signal acquisition device A1. The seismic signal acquisition device A2 is placed inside the internal cavity of the lower bucket 4. The bottom of the lower bucket 4 has a threaded hole, and the lower bucket 4 is detachably connected to the base through the threaded hole.

[0085] The base is configured to fix the seismic signal acquisition device A2 in the soil layer where the collection and transmission pipeline to be tested is located by inserting itself into the soil when connected to the lower bucket 4.

[0086] Specifically, the dual-function signal acquisition device A is the core component of the natural gas pipeline condition monitoring system, mainly composed of vibration signal acquisition device A1, seismic signal acquisition device A2, and a protective shell. In particular, the dual-function signal acquisition device A integrates the vibration signal acquisition device A1 and the seismic signal acquisition device A2 through its independently designed protective shell and internal structure, achieving synchronous data acquisition.

[0087] The outer casing consists of two parts: an upper cover 3 and a lower bucket 4. The seismic signal acquisition device A2 is placed inside the internal cavity of the lower bucket 4.

[0088] refer to Figure 6 The top cover 3 includes: a first interface, a charging and transmission interface, a horizontal adjustment bubble, and an observation window.

[0089] The first interface is connected to a vibration signal acquisition device A1 via a specific cable.

[0090] The charging and data interface is used to connect the charger for charging when the seismic signal acquisition device A2 is low on power. It can also be used to connect the 4G communication module when signals acquired by the seismic signal acquisition device A2 and the vibration signal acquisition device A1 need to be transmitted remotely in real time. Furthermore, it can be used to export locally stored data after all monitoring work is completed. Note that these three functions require different cables; therefore, only one operation can be performed at a time.

[0091] The observation window is used to observe the data acquisition status indicator lights and confirm that the dual-function signal acquisition device A is in normal data acquisition mode.

[0092] When setting up the seismic signal acquisition device A2, it is necessary to keep it horizontal. This can be determined by observing the level adjustment bubble.

[0093] Meanwhile, the bottom of the lower bucket 4 is provided with threaded holes for installing a coupling base to increase the ground coupling of the dual-function signal acquisition device A and improve the data acquisition quality.

[0094] In one embodiment, reference Figure 7 The base includes a cone 5 and a nut 6. The nut 6 is mounted on the threaded section.

[0095] The non-pointed part of nut 5 is provided with a threaded section.

[0096] Nut 6 is configured to enable a detachable connection between cone 5 and the bottom of lower barrel 4 by mating the threaded section with the threaded hole.

[0097] Specifically, in combination Figure 7 and Figure 8 The seismic signal acquisition equipment primarily collects seismic signals triggered by third-party intrusion activities into the pipeline under test. Furthermore, the seismic signal acquisition equipment is installed inside the lower bucket 4. Therefore, referring to... Figure 8 The installation method for the seismic signal acquisition equipment is as follows: under the condition of not affecting satellite timing, it is shallowly buried below the ground surface around the pipeline to be tested, and the distance between the top of the cover 3 and the ground surface (i.e., the thickness of the soil cover) should be less than 20cm.

[0098] To improve the coupling between the protective shell of the dual-function signal acquisition device and the stratum, and to enhance the data acquisition quality of the seismic signal acquisition device A2, a single-cone-shaped cone is provided at the bottom, and a nut 6 is added between the cone 5 and the threaded section to increase stability.

[0099] Optionally, the length of the vertebral body 5 can be between 130 and 180 mm, the diameter of the top end (i.e., the thicker end) of the vertebral body 5 is 12 to 15 mm, and the diameter of the tail end (i.e., the thinner end) is 2 to 3 mm.

[0100] Specifically, the thickness of the surface medium should be sufficient to ensure that the cone 5 is fully inserted and that the seismic signal acquisition device A2 is in contact with the surface. During installation, first dig a pit with a diameter of 250-280 mm and a depth of 350-500 mm at the deployment point, and level the bottom of the pit. Connect the cone 5 to the threaded hole at the bottom of the lower bucket 4, and then insert the cone 5 into the surface of the pit bottom. Indicate that the level adjustment bubble on the upper cover 3 is within the circle and the ground is in contact with the surface of the pit bottom. Then fill the soil to cover it.

[0101] Furthermore, the dual-function signal acquisition device A also includes: a main control module, a data acquisition module, a communication module, a power supply module, and a control module.

[0102] Specifically, since the protective housing is divided into an upper cover 3 and a lower casing 4, the main control module, data acquisition module, and communication module are installed in the upper cover 3, and a flexible buffer connection is used to separate the stacked circuit board from the inner wall of the upper cover 3. Meanwhile, the seismic signal acquisition device A2 and the power supply module are installed in the lower casing 4. Specifically, the power supply module is a toroidal lithium battery, which is tightly attached to the lower end cover, while the seismic signal acquisition device A2 is installed in the cylindrical space in the middle of the toroidal lithium battery.

[0103] The system uses a low-power ARM microprocessor as the core of the main control module, which is responsible for determining the system's workflow control and data recording and storage, and provides communication and control interfaces for the seismic signal acquisition equipment A2, memory, GNSS module, etc.

[0104] refer to Figure 9 The main control module is responsible for determining the system's workflow control and data recording and storage. It mainly consists of a main control unit, a GNSS clock synchronization unit, and a data storage unit. The main control unit uses high-speed storage circuitry to solve the problems of large data volume transmission and internal formatting. It can also perform self-checks on the working status of the A2 seismic signal acquisition equipment. In the event of abnormal data, communication failures, or storage space anomalies, it can autonomously analyze the cause of the fault and implement control and emergency handling. (Reference) Figure 10 The GNSS clock synchronization unit uses GNSS satellite time stamps to provide a unified time reference for multiple dual-function signal detectors distributed in different locations. It adopts a satellite positioning, high-precision clock joint timing module and corresponding system timing algorithm. The satellite positioning module provides the synchronization time reference, and the high-stability clock source provides the compensation clock when the satellite synchronization is lost. It establishes a local area time synchronization reference under low power consumption conditions, and together they achieve a wide-area system-level synchronous acquisition in a strict sense.

[0105] The main control unit's self-test function can automatically analyze and handle faults. The self-test items cover key parameters of the detector, key indicators of the acquisition system, clock zero offset, and temperature drift, among other main detection contents. In the event of a fault, it can autonomously analyze the cause and implement control and emergency handling. Its design framework is as follows: Figure 11 As shown.

[0106] The data acquisition module is responsible for continuously acquiring data from seismic signal acquisition device A2 and vibration signal acquisition device A1, and storing the acquired data in a large-capacity non-volatile memory. The main control module can perform self-checks to monitor the working status of the dual-function signal detectors. When abnormal data, communication failures, or storage space anomalies occur, it can autonomously analyze the cause of the fault and implement control and emergency handling. After local storage, the data acquired by seismic signal acquisition device A2 and vibration signal acquisition device A1 are also transmitted to a remote server via the communication module.

[0107] The control module, housed in a stacked circuit board configuration inside the upper cover 3, is primarily responsible for controlling the workflow of the signal acquisition device and recording and storing real-time seismic and vibration signals. The control module includes data acquisition and storage, GNSS clock synchronization, and device status self-checking functions. To ensure the quality of real-time seismic and vibration data acquisition, the control module employs a fourth-order Δ-Σ incremental modulator, consisting of a high-resolution, low-noise analog-to-digital conversion channel and surrounding analog signal conditioning and input protection circuitry.

[0108] refer to Figure 12 First, a preamplifier circuit is used to amplify the real-time vibration signal and the real-time seismic signal with low noise and high common-mode rejection ratio to improve the sensitivity of weak signals. Then, a differential amplifier circuit is used to amplify the real-time vibration signal and the real-time seismic signal after the low noise and high common-mode rejection ratio processing through gain adjustment. Finally, an analog-to-digital converter circuit is used to convert the differentially amplified real-time seismic signal and the real-time vibration signal into digital signals.

[0109] The power supply module uses a battery pack assembled from multiple lithium batteries, forming a circular ring. It is installed and fixed to the inner wall of the lower tank 4 of the engineering structure. It provides overvoltage, undervoltage, overcurrent, and short-circuit protection; specifically, it provides overvoltage / overcurrent protection during charging and undervoltage protection during discharging. The battery pack output is conditioned by a DC / DC step-down controller and then regulated by a linear voltage regulator (LDO), ultimately generating three regulated power supplies: one to power the main control system module, one to provide stable power to the data acquisition circuit board, and one dedicated to powering the 4G communication module. During operation, after the monitoring sensor is powered on, the main control system module powers on first, followed by power to the data acquisition module and the 4G communication module. The operation and design framework of the power supply module are as follows: Figure 13 As shown.

[0110] In one embodiment, the natural gas pipeline condition monitoring system further includes at least one single-function detector disposed between dual-function signal detectors.

[0111] The single-function detector includes a seismic signal acquisition device A2 and a protective housing.

[0112] In one embodiment, the first interval between adjacent dual-function signal detectors is determined based on the length of the gathering and transportation pipeline to be detected and the effective propagation distance of the leakage vibration signal.

[0113] The first interval satisfies the following expression:

[0114] n*B <L<(n+1)*B(1)

[0115] Where n represents the number of dual-function signal detectors configured, L represents the effective propagation distance of the leakage vibration signal on the pipeline to be tested, and B represents the length of the pipeline to be tested.

[0116] Specifically, the core of deploying dual-function signal detectors lies in defining their deployment intervals. Therefore, it is first necessary to determine the effective propagation distance of the dual-function signal detectors for seismic signals caused by third-party intrusion activities around the pipeline and vibration signals caused by continuous pipe vibrations due to pipeline leaks. In particular, the effective propagation distance is the propagation distance at which the signal energy of the seismic or vibration signal is equal to the natural noise after propagation.

[0117] In particular, the seismic signals caused by third-party intrusion activities around the gathering and transportation pipeline to be detected propagate along the surface soil layer, featuring fast attenuation speed and short effective monitoring distance; while the continuous vibration signals of the pipeline body propagate along the pipeline本体, and barriers such as thermal insulation layer and covering soil layer outside the gathering and transportation pipeline to be detected isolate natural noise, so the attenuation speed is slow and the effective propagation distance is long. Therefore, in the layout process of dual-function signal detectors, in order to achieve full coverage of the state monitoring of the gathering and transportation pipeline to be detected at a reasonable cost, dual-function signal detectors and single-function detectors can be arranged simultaneously.

[0118] First, determine the main possible third-party intrusion activities around the gathering and transportation pipeline to be detected according to the natural and social environment outside the pipeline, and determine the effective propagation distance A of the third-party intrusion activities through experiments or other methods; then determine the effective propagation distance B of the leakage vibration signal on the gathering and transportation pipeline to be detected. Assuming the length of the target pipe section is L, the layout scheme is as follows:

[0119] Assuming that the number of arranged dual-function signal detectors is n, when n*B<L<(n+1)*B, n+1 dual-function signal detectors need to be arranged on the gathering and transportation pipeline to be detected. With reference to Figure 13 , the dual-function signal detectors are numbered n1, n2......ni, and the first interval C between dual-function signal detectors is [L / (n+1)].[[-END]]

[0120] In particular, with reference to Figure 13 in the section on the coverage of seismic data acquisition, this layout can ensure that all positions of the gathering and transportation pipeline to be detected are covered by vibration monitoring of at least two dual-function signal detectors, which can realize effective monitoring and positioning of pipeline leakage.

[0121] Secondly, by arranging dual-function signal detectors, the gathering and transportation pipeline to be detected is evenly divided into (n-1) small sections, and full coverage of pipeline leakage monitoring is realized, so it is necessary to add a single-function detector in each section.

[0122] Assuming that the number of single-function detectors arranged in each small section is m, when m*A<C<(m+1)*A, m single-function detectors need to be arranged in each small section, and (n-1)*m single-function detectors need to be arranged on the gathering and transportation pipeline to be detected. Wherein, with reference to Figure 13 , the single-function detectors are numbered m1, m2.....mj, and the second interval D is [L / (m+1)].[[-END]]

[0123] In particular, this layout can ensure that all positions of the gathering and transportation pipeline to be detected are covered by seismic monitoring of at least one seismic signal acquisition device A2. According to the seismic signal acquisition device A2 that has detected the third-party intrusion's seismic signal, rapid regional positioning of external intrusion can be realized, so as to facilitate inspection and intervention.

[0124] Example 2

[0125] Based on the above embodiment one, the implementation function of the intrusion incident detection device B of the present invention will be specifically described below.

[0126] In one embodiment, the intrusion incident detection device B is configured to diagnose whether an intrusion incident has occurred in the gathering and transportation pipeline to be detected through the following steps:

[0127] Step A1: The root mean square (RMS) processing method is used to extract the signal energy from the real-time seismic signal.

[0128] Step A2 involves performing spectral analysis on the signal energy to obtain the seismic characteristic analysis results of the seismic signal.

[0129] Step A3: Compare the signal energy and seismic characteristic analysis results of the seismic signal with the preset intrusion risk conditions, and obtain the intrusion accident diagnosis results based on the comparison results.

[0130] In step A1, the root mean square (RMS) processing method is used to extract signal energy. A leak in the gathering and transmission pipeline can only be identified if the signal energy of the seismic signal is higher than the natural noise. The signal energy is obtained using the following expression:

[0131]

[0132] In step A2, the seismic characteristic analysis results include signal energy, dominant frequency range, and centroid frequency.

[0133] Specifically, in step A2, the classical Fourier transform method is used to select typical seismic signals per unit time for spectral analysis to obtain the bandwidth and dominant frequency range of the seismic signals, and at the same time, the centroid frequency of the real-time seismic data is calculated.

[0134] The centroid frequency of real-time seismic data is calculated using the following expression:

[0135]

[0136] Where FC represents the centroid frequency, P(f) represents the power spectrum of the seismic signal, and f represents the vibration frequency of the seismic signal, in Hz.

[0137] In step A3, the preset intrusion risk conditions include a preset seismic signal risk identification threshold, a preset centroid frequency range, and a preset dominant frequency range. The preset seismic data risk identification threshold is the seismic signal intensity of natural noise in the area where the gathering and transmission pipeline to be detected is located.

[0138] Optionally, in step A3, when the signal energy of the seismic signal within a preset time period reaches or exceeds a preset seismic signal risk identification threshold, and the centroid frequency meets a preset centroid frequency range, and the dominant frequency range meets the preset dominant frequency range, it is determined that an intrusion accident has occurred in the gathering and transportation pipeline to be detected.

[0139] Specifically, determining whether an intrusion incident has occurred requires the following conditions to be met: 1) The seismic signal is a periodic, sudden seismic signal, characterized by the generation of sudden seismic signals at a certain frequency within a certain time period, and the signal energy is much greater than the preset seismic data risk identification threshold; 2) The dominant frequency range of the seismic data is between 30 and 80 Hz; 3) The centroid frequency range of the seismic signal is between 40 and 60 Hz. Meeting all three conditions simultaneously can determine that an intrusion incident has occurred within the pipeline to be monitored.

[0140] Example 3

[0141] Based on the above embodiment one, the implementation function of the leakage accident detection device C of the present invention will be specifically described below.

[0142] In one embodiment, the leak detection device C is configured to determine the location of the leak source by means of the following steps:

[0143] Step B1: The root mean square (RMS) processing method is used to extract the signal energy from the real-time vibration signal.

[0144] Step B2 involves performing a spectral analysis on the signal energy to obtain the vibrational characteristics analysis results of the signal energy.

[0145] Step B3: Compare the signal energy and vibration characteristic analysis results of the vibration signal with the preset leakage risk conditions, and obtain the leakage risk judgment result based on the comparison results.

[0146] Step B4: Identify the location of the target leak source from the leak risk locations.

[0147] Specifically, refer to Figure 15 The noise reduction of the acquired vibration signal is performed using the variational mode decomposition (VMD) method. In the process of obtaining the decomposed components, the method determines the frequency center and bandwidth of each component by iteratively searching for the optimal solution of the variational model, thereby adaptively realizing the frequency domain partitioning of the signal and the effective separation of each component.

[0148] In step B1, the root mean square (RMS) processing method is used to extract the signal energy. A leak in the pipeline can only be identified if the signal energy of the vibration signal is higher than the natural noise. The signal energy is obtained using the following expression:

[0149]

[0150] In step B2, the vibration characteristic analysis results include signal energy, bandwidth, dominant frequency range, and root mean square frequency.

[0151] Specifically, refer to Figure 16 Using the classical Fourier transform method, a typical vibration signal within a unit time period is selected for spectral analysis to obtain the bandwidth and dominant frequency range of the vibration signal. Simultaneously, the root mean square (RMS) frequency of the vibration signal is calculated. The RMS frequency is calculated using the following expression:

[0152]

[0153] Where RMSF represents the root mean square frequency, MSF represents the mean square frequency, and P(f) represents the power spectrum of the leakage vibration signal.

[0154] In step B3, the preset leakage risk conditions include: a preset vibration signal risk identification threshold, a preset wideband range, a preset high-frequency range, and a preset root-mean-square frequency range. The preset vibration data risk identification threshold is the vibration signal intensity of the natural noise in the area where the pipeline to be detected is located.

[0155] In step B3, when the vibration signal within a preset time period is a continuous vibration signal, and the signal energy reaches or exceeds a preset vibration signal risk identification threshold, and the bandwidth meets a preset wideband range, the main frequency range meets a preset high-frequency range, and the root mean square frequency meets a preset root mean square frequency range, the signal acquisition location that meets the conditions is taken as the leakage risk location.

[0156] Specifically, in step B3, when determining whether a leakage risk has occurred, the following conditions must be met: 1) The signal energy of the vibration signal reaches or exceeds the preset vibration data risk identification threshold, and the vibration data is a continuous vibration signal, exhibiting characteristics such as long period, continuity and wide bandwidth, and is indistinguishable in time; 2) The vibration data is a wideband, high-frequency signal, and the root mean square frequency is within the range of (2200, 3500).

[0157] In step B4, there are multiple locations where leakage risks may occur.

[0158] In one embodiment, the leak incident detection device C is also configured to identify the location of the leak source by means of the following steps:

[0159] Step C1: Based on the vibration signals at different leakage risk locations, obtain the normalized cross-correlation function values ​​of the vibration signals at the leakage risk locations, and calculate the observation time difference between the vibration signals related to the normalized cross-correlation function values ​​based on the normalized cross-correlation function values.

[0160] Step C2: Based on multiple leakage risk locations, determine the search range for the leakage source location, and based on the search range and the preset location search step size, obtain multiple candidate locations.

[0161] Step C3: Determine the velocity search range based on the propagation speed of the vibration signal at different leakage risk locations, and determine multiple alternative velocities based on the velocity search range and the preset velocity search step size.

[0162] Step C4: Based on multiple candidate locations and multiple candidate velocities, combined with the normalized cross-correlation function values ​​of the vibration signals and the observation time difference, at least one positioning target function value is obtained using a preset target function.

[0163] Step C5: Based on the location corresponding to the smallest location target function value among all location target function values, the location of the target leakage source is obtained.

[0164] Furthermore, the normalized cross-correlation function value is calculated using the following expression:

[0165]

[0166] Among them, R ij (τ) represents the normalized cross-correlation function value, N represents the number of sampling points of the vibration signal, and x i (n) represents the vibration signal at the target risk location, x j (n) represents the vibration signal at the j-th remaining leakage risk location, and τ is the time lag.

[0167] In particular, R ij (τ) represents the normalized cross-correlation function value, that is, the correlation between two signals with a time lag of τ.

[0168] In step C2, the specific value of the preset position search step size is not limited and can be reasonably selected according to the actual application requirements.

[0169] In step C3, the specific value of the preset speed search step size is not limited and can be reasonably selected according to the actual application requirements.

[0170] In step C4, the target function value is calculated using the following steps:

[0171]

[0172] Where g represents the objective function value of the positioning parameters, K represents the number of sensors, and R ij Δt represents the normalized cross-correlation function value. ij Δat represents the theoretical time difference. ij tt represents the observation time difference. kThis represents the arrival time (in seconds) of the vibration signal collected by the k-th sensor at a specified candidate location and speed. m Let a represent the m-th position value among all candidate positions. k v represents the position of the k-th sensor. n At represents the nth speed value among all candidate speeds. i At represents the arrival time of the vibration signal at the target risk location of the i-th sensor. j Let t represent the arrival time of the vibration signal from the j-th sensor. i Let t represent the arrival time of the vibration signal at the selected position and velocity on the i-th sensor. j This represents the arrival time of the vibration signal on the j-th sensor, given the candidate position and candidate velocity.

[0173] Specifically, the target leak location is obtained through the following steps:

[0174] Suppose that sensors at K measurement points detect an abnormal event, and the position of the kth measurement point is denoted as a. k The normalized cross-correlation function value is obtained for the vibration records of each pair of sensors. Its expression is shown in expression (7), which will not be repeated here.

[0175] Where x i and x j R represents the vibration records at the first leakage risk location and any other measuring point, respectively. ij The maximum value Rm corresponding to (k) ij Let be the similarity coefficient between two vibration signals, corresponding to the time Δat. ij Let t be the time difference between two vibration signals. The location of abnormal event signals is achieved by superimposing multi-channel cross-correlation functions. The method sets the search range and step size of the event source as [s1, s2, Δs], and the search range and step size of the event signal propagation velocity as [v1, v2, Δv]. The arrival time tt of the k-th sensor corresponding to each possible event source and velocity value is calculated. k Then, through the obtained theory, the time difference Δtt ij and observation time difference Δat ij The positioning objective function is constructed, and the calculation formula is shown in expression (8). The calculation formulas for the arrival time of the event and the arrival time difference are shown in expression (9).

[0176] In one embodiment, to eliminate the possibility of abnormal vibrations in the pipeline caused by processes such as air filling during maintenance and resumption of production, and to prevent these situations from being mistaken for pipeline leaks, the leak detection device C is also configured to determine whether a leak has occurred in the pipeline to be inspected through the following steps:

[0177] Step D1: Identify at least one leak risk location related to the current leak source location.

[0178] Step D2: Calculate the duration corresponding to the vibration characteristic analysis results of the relevant leakage risk location meeting the preset leakage risk conditions.

[0179] Step D3: Based on the relevant leakage risk location, locate the dynamic leakage source location within the duration, and then calculate the standard deviation of the distance deviation between the dynamic leakage source location and the current target leakage source location.

[0180] Step D4: Obtain the leakage accident diagnosis result based on the distance deviation standard deviation and the duration. Specifically, if the duration is greater than a preset time threshold and the distance standard deviation is less than a preset distance deviation threshold, it is determined that a leakage accident has occurred in the gathering and transportation pipeline to be inspected.

[0181] In step D4, the value of the preset time threshold is not limited and can be reasonably selected according to the actual application requirements.

[0182] In step D4, the value of the preset distance deviation threshold is not limited and can be reasonably selected according to actual application needs. For example, it can be 10% of the maximum monitoring distance.

[0183] Specifically, a time threshold is set. If the duration of a leak risk event exceeds this threshold continuously and the standard deviation of the event location result is less than 10% of the maximum monitoring distance within this time, the event is determined to be a leak event.

[0184] Example 4

[0185] Based on the above embodiments one, two, and three, the specific process of applying the system for determining the risk status of natural gas pipelines described in the embodiments of the present invention to determine the deployment scheme of dual-function signal acquisition devices and single-function detectors in the first example pipeline section will be described below.

[0186] The surface medium of the first example pipe section is relatively homogeneous clay soil, and the pipe section is laid in a mountainous area, making it difficult for vehicles and excavators to approach. Due to its proximity to farmland, the main third-party intrusion activity in the first example pipe section is manual excavation. Monitoring showed that the effective propagation distance of seismic signals caused by manual excavation along the surface soil in the monitoring area was 45m, and the effective propagation distance of leakage vibration signals along the first example pipe section was 300m. The length of the pipeline requiring safety status monitoring is 800m. Therefore, the deployment scheme of dual-function signal detectors and single-function detectors is as follows:

[0187] refer to Figure 17Simultaneously, four dual-function signal detectors (n1, n2, n3, and n4) of both the seismic signal acquisition device A2 and the vibration signal acquisition device A1 are activated. The first example pipe section is divided into three equal segments, with a first interval of 267m between the dual-function signal detectors. At the same time, two single-function detectors, used only for activating the seismic signal acquisition device A2, are deployed at equal intervals in each segment, dividing the first example pipe section into three equal parts. The second interval of the single-function detectors is 89m. A total of six single-function detectors (m1, m2, m3, m4, m5, and m6) are used in the three segments.

[0188] Example 5

[0189] Based on the above embodiments one, two, and three, the following describes the specific process of applying the system for determining the risk status of natural gas pipelines described in the embodiments of the present invention to the second example pipeline section to determine the deployment scheme of dual-function signal acquisition devices and single-function detectors.

[0190] The second example pipe section is located in a relatively homogeneous clayey soil, and it is laid beside a road in a mountainous area. The main third-party intrusion activities in this section are mechanical excavation caused by road maintenance, infrastructure construction, and other engineering activities. Monitoring showed that the effective propagation distance of seismic signals caused by mechanical excavation along the surface soil in the monitored area was 150m, and the effective propagation distance of leakage vibration signals along the second example pipe section was 400m. The length of the pipeline requiring safety status monitoring is 1200m. Therefore, the deployment scheme for dual-function signal detectors and single-function detectors is as follows:

[0191] refer to Figure 18 Simultaneously, four dual-function signal detectors (n1, n2, n3, and n4) of both seismic signal acquisition device A2 and vibration signal acquisition device A1 are activated. The second example pipe section is divided into three equal segments, with a first interval of 400m between the dual-function signal detectors. At the same time, one single-function detector used only for activating seismic signal acquisition device A2 is deployed at equal intervals in each segment, dividing the second example pipe section into two equal parts. The second interval of the single-function detectors is 200m. A total of three single-function detectors (m1, m2, and m3) are used in the three segments.

[0192] Example 6

[0193] Based on the above embodiments one, two, and three, the following describes the specific process of applying the system for determining the risk status of natural gas pipelines described in the embodiments of the present invention to the deployment scheme of dual-function signal acquisition devices and single-function detectors in the third example pipeline section.

[0194] The surface medium of the third example pipeline section is relatively homogeneous sandy soil, and it is laid in a desert area far from densely populated areas, with very few people approaching and vehicles unable to drive near the pipeline. Therefore, the main third-party intrusion activity in the third example pipeline section is the approach or loitering of people caused by drilling for oil theft. Monitoring showed that the effective propagation distance of seismic signals caused by people approaching or loitering in the monitoring area along the surface soil is 30m, and the effective propagation distance of leakage vibration signals along the third example pipeline section is 200m. The pipeline length requiring safety status monitoring is 400m. Therefore, the deployment scheme of dual-function signal detectors and single-function detectors is as follows:

[0195] refer to Figure 19 Simultaneously, three dual-function signal detectors (n1, n2, and n3) of both seismic signal acquisition device A2 and vibration signal acquisition device A1 are activated. The third example pipe section is divided into three equal segments, with a first interval of 200m between the dual-function signal detectors. At the same time, three single-function detectors, used only for activating seismic signal acquisition device A2, are deployed at equal intervals in each segment, dividing the third example pipe section into four equal parts. The second interval of the single-function detectors is 50m. A total of six single-function detectors (m1, m2, m3, m4, m5, and m6) are used in the three segments.

[0196] Example 7

[0197] Based on the above embodiments one, two, and three, the specific process of applying the system for determining the risk status of natural gas pipelines described in the embodiments of the present invention to the fourth example pipeline section to determine the deployment scheme of dual-function signal acquisition devices and single-function detectors will be explained below.

[0198] The surface medium of the fourth example pipe section is relatively homogeneous sandy soil, and the pipe section is laid near a road. Therefore, the main third-party intrusion activity of the fourth example pipe section is mechanical excavation caused by road maintenance, infrastructure construction, and other engineering activities. Monitoring showed that the effective propagation distance of seismic signals caused by mechanical excavation along the surface soil in the monitoring area was 120m, and the effective propagation distance of leakage vibration signals along the fourth example pipe section was 240m. The length of the pipeline requiring safety status monitoring is 900m. Therefore, the deployment scheme of dual-function signal detectors and single-function detectors is as follows:

[0199] refer to Figure 20 (a) The number of dual-function signal detectors simultaneously activated by the seismic signal acquisition device A2 and the vibration signal acquisition device A1 is 5 (i.e., n1, n2, n3, n4, n5), dividing the fourth example pipe segment into 4 equal segments, with the first interval of the dual-function signal detectors being 225m; and referencing Figure 20(b) Each segment does not require the placement of a single-function detector solely for activating the seismic signal acquisition device A2, thus enabling monitoring coverage.

[0200] Example 8

[0201] Based on the above embodiments one through four, the specific process of applying the system for determining the risk status of a natural gas pipeline described in the embodiments of the present invention to the first example pipeline section to determine whether an intrusion accident has occurred will be explained below.

[0202] The first example pipe section is located in a relatively homogeneous clay soil. The length of the pipe that needs to be monitored for safety status is 800m, and a total of 4 dual-function signal detectors and 6 single-function detectors are used.

[0203] During the condition monitoring process, the dual-function signal detector n2 collected signal energy far exceeding the preset seismic data risk identification threshold. The waveform of the seismic signal is shown in the figure below. Figure 21 As shown in the figure. Processing and analyzing the acquired seismic data through state discrimination device B reveals that the waveform oscillation time is approximately 820ms, and it appears periodically at a certain frequency. For sudden seismic signals, local amplification is performed, and then seismic data within a preset time period is selected for feature analysis. The analysis results are as follows. Figure 21 As shown in (b) and (c), the earthquake characteristic analysis results are as follows: the dominant frequency range is 35-45Hz, the centroid frequency is 41.5Hz, which meets the preset risk conditions. It can be determined that there is an intrusion accident within 45m on both sides of the dual-function signal detector n2.

[0204] Example 9

[0205] Based on the above embodiments one, two, three and six, the specific process of applying the system for determining the risk status of natural gas pipelines described in the embodiments of the present invention to the third example pipeline section to determine whether an intrusion accident has occurred will be explained below.

[0206] The third example pipe section is located on a relatively homogeneous sandy soil surface. The pipe length that needs to be monitored for safety status is 400m, and a total of 3 dual-function signal detectors and 6 single-function detectors are used.

[0207] During the condition monitoring process, the signal energy acquired by the single-function detector m4 was much greater than the preset seismic data risk identification threshold. The waveform of the seismic signal is shown in the figure below. Figure 22 As shown in the figure. Processing and analyzing the acquired seismic data through state discrimination device B reveals that the waveform oscillation time is approximately 300ms, and it appears periodically at a certain frequency. For sudden seismic signals, local amplification is performed, and then seismic data within a preset time period is selected for feature analysis. The analysis results are as follows. Figure 22 As shown in (b) and (c), the earthquake characteristic analysis results are as follows: the dominant frequency range is 30-40Hz, the centroid frequency is 34.8Hz, which meets the preset risk conditions. It can be determined that there is an intrusion accident within 30m on both sides of the single-function detector m4.

[0208] Example 10

[0209] Based on the above embodiments one, two, three and six, the specific process of applying the system for determining the risk status of a natural gas pipeline described in the embodiments of the present invention to the first example pipeline section to determine whether an intrusion accident has occurred will be explained below.

[0210] The fourth example pipe section is located on a relatively homogeneous clay soil. The length of the pipe that needs to be monitored for safety status is 800m, and a total of 4 dual-function signal detectors and 6 single-function detectors are used.

[0211] The preset vibration data risk identification threshold for the first example pipe section was measured to be 1.8162*10. -4 During the condition monitoring process, dual-function signal detectors n2 and n3 simultaneously acquired continuous vibration signals with energy significantly exceeding the preset vibration data risk identification threshold. The waveform of the vibration signal is shown in the figure below. Figure 23 As shown in (a), the collected seismic data, after being processed and analyzed by the state discrimination device B, reveals that the vibration signal exhibits characteristics of long period, continuity, wide bandwidth, and temporal indistinguishability. The results of frequency domain analysis of the vibration signal are as follows: Figure 23 As shown in (b). Reference Figure 23 (b) The frequency domain characteristics of the vibration signal are: 1) The vibration signal is a wideband, high-frequency signal with energy distribution in the range of 1100 to 5000 Hz, and the signal energy distribution is in the range of 1100 to 4300 Hz; 2) The root mean square frequency of the vibration signal is 2403 Hz, which is within the range of (2200, 2800), which meets the preset risk conditions, and it is determined that there is a leakage accident between the dual-function signal detectors n2 and n3.

[0212] Example 11

[0213] Based on the above embodiments 1, 2, 3 and 7, the specific process of applying the system for determining the risk status of natural gas pipelines described in the embodiments of the present invention to the fourth example pipeline section to determine whether a leakage accident has occurred will be explained below.

[0214] The fourth example pipe section is located on a relatively homogeneous sandy soil surface. The pipe length that needs to be monitored for safety status is 900m, and a total of 5 dual-function signal detectors are used.

[0215] The preset vibration data risk identification threshold for the fourth example pipe section was measured to be 1.7983*10. -4 During the condition monitoring process, dual-function signal detectors n3 and n4 simultaneously acquired continuous vibration signals with energy significantly exceeding the preset vibration data risk identification threshold. The waveform of the vibration signal is shown in the figure below. Figure 24 As shown in (a), the collected seismic data, after being processed and analyzed by the state discrimination device B, reveals that the vibration signal exhibits characteristics of long period, continuity, wide bandwidth, and temporal indistinguishability. The results of frequency domain analysis of the vibration signal are as follows: Figure 24 As shown in (b). Reference Figure 24 (b) The frequency domain characteristics of the vibration signal are as follows: 1) The vibration signal is a wideband, high-frequency signal with energy distribution in the range of 500–4000 Hz, and the signal energy distribution is in the range of 1500–3500 Hz; 2) The root mean square frequency of the vibration signal is 271.1 Hz, which is within the range of (2200, 2800), meeting the preset risk conditions. (Reference) Figure 24 (c) It was determined that there was a leakage accident between the dual-function signal detectors n3 and n4, and the leakage source was located 108m to the right of n3.

[0216] Example 12

[0217] Based on the systems for determining the risk status of natural gas pipelines provided in Embodiments 1-11 above, this invention also provides a method for determining the risk status of natural gas pipelines. This method for determining the risk status of natural gas pipelines is implemented using the system for determining the risk status of natural gas pipelines as described above.

[0218] This invention proposes a system and method for determining the risk status of natural gas pipelines. The system and method install a dual-function signal acquisition device on high-risk pipeline sections in accident-prone or high-consequence areas. By real-time acquisition, transmission, and analysis of seismic wave signals and pipe vibration signals around the natural gas gathering and transmission pipeline, it identifies third-party intrusion activities and persistent leakage events. It can simultaneously and effectively identify and alarm on both pipeline section leaks and third-party intrusions, achieving safety status monitoring of buried gathering and transmission pipelines.

[0219] 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.

[0220] 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.

[0221] 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.

[0222] 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.

[0223] 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.

[0224] While the embodiments disclosed in this invention are as described above, the content is merely for the purpose of facilitating understanding of the invention and is not intended to limit the invention. Any person skilled in the art to which this invention pertains may make any modifications and changes in form and detail of the implementation without departing from the spirit and scope disclosed herein; however, the scope of patent protection of this invention shall still be determined by the scope defined in the appended claims.

Claims

1. A system for determining the risk status of a natural gas pipeline, characterized in that, include: A dual-function signal acquisition device is provided, which has multiple dual-function signal detectors arranged at different axial positions along the pipeline to be tested. The dual-function signal detectors include a vibration signal acquisition device and a seismic signal acquisition device. The vibration / seismic signal acquisition device is used to acquire real-time seismic / vibration signals of the pipeline to be tested. An intrusion accident detection device is used to perform feature analysis on the real-time seismic signal and, based on the seismic feature analysis results and using preset intrusion risk conditions, diagnose whether an intrusion accident has occurred in the collection and transportation pipeline to be detected. The leakage accident detection device is used to perform feature analysis on the real-time vibration signal, and based on the vibration feature analysis results, use preset leakage risk conditions to determine whether there is a leakage risk, identify the location of the leakage source when it exists, and diagnose whether the collection and transportation pipeline to be detected has experienced a leakage accident based on the location of the leakage source. A status determination device is used to determine the risk status of the gathering and transportation pipeline to be inspected based on the results of intrusion accident diagnosis and leakage accident diagnosis.

2. The system according to claim 1, characterized in that, The vibration signal acquisition device is installed on the outer wall of the pipeline to be tested. The vibration signal acquisition device includes at least one set of vibration signal acquisition components. The at least one set of vibration signal acquisition components are respectively installed on the pipeline cross-section at different positions. The vibration signal acquisition components include vibration sensors installed at different positions. The vibration sensors are equipped with acceleration sensors that measure different vibration directions at the current position.

3. The system according to claim 1 or 2, characterized in that, The seismic signal acquisition device is buried in the soil layer where the pipeline to be detected is located. The seismic signal acquisition device includes at least one set of seismic signal acquisition components, wherein the at least one set of seismic signal acquisition components includes three detectors arranged in orthogonal directions of different axes.

4. The system according to any one of claims 1 to 3, characterized in that, The dual-function signal acquisition device also includes a protective housing, which has the following features: The outer casing has an upper cover and a lower barrel. The upper cover is provided with a first interface, which is connected to the vibration signal acquisition device. The seismic signal acquisition device is placed in the internal cavity of the lower barrel. The bottom of the lower barrel is provided with a threaded hole, and the lower barrel is detachably connected to the base through the threaded hole. The base is used to fix the seismic signal acquisition device in the soil layer where the collection and transmission pipeline to be tested is located by inserting itself into the soil when connected to the lower bucket.

5. The system according to any one of claims 1 to 4, characterized in that, The preset intrusion risk conditions include a preset seismic signal risk identification threshold, a preset centroid frequency range, and a preset dominant frequency range. The intrusion accident detection device is configured to diagnose whether an intrusion accident has occurred within the pipeline to be detected through the following steps: The root mean square (RMS) processing method is used to extract signal energy from real-time seismic signals. The signal energy is subjected to spectral analysis to obtain the seismic characteristic analysis results of the seismic signal, which include signal energy, dominant frequency range, and centroid frequency; The signal energy and seismic characteristics analysis results of the seismic signal are compared with the preset intrusion risk conditions. Based on the comparison results, an intrusion accident diagnosis is obtained. The preset seismic data risk identification threshold is the seismic signal intensity of natural noise in the area where the pipeline to be detected is located. When the signal energy of an earthquake signal within a preset time period reaches or exceeds the preset earthquake signal risk identification threshold, and the centroid frequency meets the preset centroid frequency range, and the dominant frequency range meets the preset dominant frequency range, an intrusion accident is determined to have occurred in the pipeline to be detected.

6. The system according to any one of claims 1 to 5, characterized in that, The preset leakage risk conditions include: a preset vibration signal risk identification threshold, a preset wideband range, a preset high-frequency range, and a preset root-mean-square frequency range. The leakage accident detection device is configured to determine the location of the leakage source through the following steps: The root mean square (RMS) processing method is used to extract the signal energy from the real-time vibration signal; The signal energy is subjected to spectral analysis to obtain the vibration characteristic analysis results of the signal energy, which include signal energy, bandwidth, dominant frequency range and root mean square frequency; The signal energy and vibration characteristics analysis results of the vibration signal are compared with the preset leakage risk conditions. The leakage risk judgment result is obtained based on the comparison results. Specifically, when the vibration signal within the preset time period is a continuous vibration signal, and the signal energy reaches or exceeds the preset vibration signal risk identification threshold, and the bandwidth meets the preset wideband range, the main frequency range meets the preset high frequency range, and the root mean square frequency meets the preset root mean square frequency range, the signal acquisition location that meets the conditions is taken as the leakage risk location. Identify the location of the target leak source from the leak risk locations.

7. The system according to claim 6, characterized in that, The leakage accident detection device is also configured to identify the location of the leakage source through the following steps: Based on the vibration signals at different leakage risk locations, the normalized cross-correlation function values ​​of the vibration signals at the leakage risk locations are obtained, and the observation time difference between the vibration signals related to the normalized cross-correlation function values ​​is calculated based on the normalized cross-correlation function values. Based on multiple leakage risk locations, the search range for the leakage source location is determined, and based on the search range and a preset location search step size, multiple candidate locations are obtained. Based on the propagation speed of vibration signals at different leakage risk locations, a speed search range is determined, and based on the speed search range and a preset speed search step size, multiple candidate speeds are determined. Based on multiple candidate locations and multiple candidate velocities, combined with the normalized cross-correlation function value of the vibration signal and the observation time difference, at least one positioning target function value is obtained using a preset target function; The location of the target leakage source is obtained by identifying the location corresponding to the smallest target function value among all the target function values.

8. The system according to claim 7, characterized in that, The normalized cross-correlation function value is calculated using the following expression: Among them, R ij (τ) represents the normalized cross-correlation function value, N represents the number of sampling points of the vibration signal, and x i (n) represents the vibration signal at the target risk location, x j (n) represents the vibration signal at the j-th remaining leakage risk location, and τ is the time lag.

9. The system according to any one of claims 6 to 8, characterized in that, The location objective function value is calculated using the following steps: Where g represents the objective function value of the positioning parameters, K represents the number of sensors, and R ij Δt represents the normalized cross-correlation function value. ij Δat represents the theoretical time difference. ij tt represents the observation time difference. k This represents the arrival time (in seconds) of the vibration signal collected by the k-th sensor at a specified alternative location and speed. m Let a represent the m-th position value among all candidate positions. k v represents the position of the k-th sensor. n At represents the nth speed value among all candidate speeds. i At represents the arrival time of the vibration signal at the target risk location of the i-th sensor. j Let t represent the arrival time of the vibration signal from the j-th sensor. i Let t represent the arrival time of the vibration signal determined by the candidate position and candidate velocity on the i-th sensor. j This represents the arrival time of the vibration signal on the j-th sensor, given the candidate position and candidate velocity.

10. The system according to any one of claims 5 to 9, characterized in that, The leakage accident detection device is also configured to determine whether a leakage accident has occurred in the gathering and transportation pipeline to be detected through the following steps: Identify at least one leak risk location related to the current leak source location; Calculate the duration corresponding to the vibration characteristic analysis results of the relevant leakage risk location that meet the preset leakage risk conditions; Based on the relevant leakage risk location, locate the dynamic leakage source location within the said duration, and then calculate the standard deviation of the distance deviation between the dynamic leakage source location and the current target leakage source location; Based on the distance deviation standard deviation and the duration, a leakage accident diagnosis result is obtained, wherein when the duration is greater than a preset time threshold and the distance standard deviation is less than a preset distance deviation threshold, it is determined that a leakage accident has occurred in the gathering and transportation pipeline to be detected.

11. The system according to any one of claims 2 to 10, characterized in that, The vibration signal acquisition device also includes: An adhesive block is attached to the outer surface of the collection and transportation pipeline to be tested via a vibration coupling agent; Connecting bolts are used to mount the vibration sensor onto the adhesive block.

12. A method for determining the risk status of a natural gas pipeline, characterized in that, The method is implemented using the system as described in any one of claims 1 to 11.

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