Fault detection method and system for natural gas pipeline

Abstract

The invention discloses a fault detection method and system for a natural gas pipeline, and relates to the technical field of fault detection, and the method comprises the steps: collecting corresponding pressure parameters based on a plurality of pressure detection points in each pipeline region; the fault area of the pipeline area is determined according to the sub natural gas conveying path, each pressure parameter and the variable quantity of the two adjacent pressure parameters, and the corresponding pipeline fault event is determined based on the identification of the fault area, so that the accuracy of the fault area and the accuracy of the pipeline fault event are ensured. Therefore, according to the fault levels of the multiple pipeline fault events, the positions of the pipeline fault events and the current working state of the natural gas pipeline, pipeline regulation and control measures of the natural gas pipeline are determined; the pipeline state signal of the natural gas pipeline is triggered based on the pipeline regulation and control measures, the corresponding pipeline area is closed according to the pipeline state signal, normal use of the natural gas pipeline is guaranteed, and dynamic updating of the natural gas conveying path of the natural gas pipeline is achieved.

Description

Technical Field

[0001] This invention relates to the technical field of fault detection, and more particularly to a fault detection method and system for natural gas pipelines. Background Technology

[0002] With the development of technology, natural gas pipelines are used to transport natural gas and are distributed underground in natural gas supply stations. Natural gas pipelines have multiple sections and are laid along the natural gas transportation path of the natural gas supply station. In the existing technology, natural gas pipelines have multiple pipeline areas, and the overall pressure parameters are determined based on the detection of multiple pipeline areas. However, the pressure parameters at multiple locations in the pipeline area are not taken into account, and fault areas in each pipeline area are ignored. This results in poor fault detection effect of natural gas pipelines and makes it impossible to achieve dynamic updates of the natural gas transportation path of natural gas pipelines. Summary of the Invention

[0003] The purpose of this invention is to overcome the shortcomings of the prior art. This invention provides a method and system for detecting faults in natural gas pipelines.

[0004] This invention provides a method for fault detection in a natural gas pipeline, comprising: Collect pipeline distribution maps of natural gas pipelines, and determine multiple pipeline areas based on the pipeline distribution maps and natural gas pipeline transportation instructions; In each pipeline region, multiple pressure detection points are set up along the sub-natural gas transmission path of the pipeline region, and corresponding pressure parameters are collected based on multiple pressure detection points; The fault areas of the pipeline region are determined based on the sub-natural gas transmission path, the changes of various pressure parameters and two adjacent pressure parameters, and the corresponding pipeline fault events are determined based on the identification of the fault areas. Collect multiple pipeline failure events and determine pipeline control measures for natural gas pipelines based on the failure level, location, and current operating status of the natural gas pipelines. The pipeline status signal of the natural gas pipeline is triggered by pipeline control measures, and the corresponding pipeline area is closed according to the pipeline status signal to dynamically update the natural gas transmission path of the natural gas pipeline.

[0005] This invention provides a fault detection system for natural gas pipelines, which is applied to the aforementioned fault detection method for natural gas pipelines. The fault detection system for natural gas pipelines includes: The pipeline area module is used to collect pipeline distribution maps of natural gas pipelines and determine multiple pipeline areas based on the pipeline distribution maps and natural gas pipeline transportation instructions. The pressure parameter module is used to collect corresponding pressure parameters based on multiple pressure detection points in each pipeline area and the sub-natural gas transmission path of the pipeline area. The pipeline fault event module is used to determine the fault area of ​​the pipeline region based on the sub-natural gas transmission path, various pressure parameters and the changes of two adjacent pressure parameters, and to determine the corresponding pipeline fault event based on the identification of the fault area; The pipeline control measures module is used to collect multiple pipeline fault events and determine pipeline control measures for the natural gas pipeline based on the fault level of the multiple pipeline fault events, the location of the pipeline fault events, and the current operating status of the natural gas pipeline. The path update module is used to trigger the pipeline status signal of the natural gas pipeline based on pipeline control measures, and close the corresponding pipeline area according to the pipeline status signal to dynamically update the natural gas transmission path of the natural gas pipeline.

[0006] Compared with the prior art, the beneficial effects of the present invention are: In this embodiment of the invention, the method described herein establishes multiple pressure detection points along the sub-natural gas transmission path in each pipeline region, and collects corresponding pressure parameters based on these multiple pressure detection points. The fault region of the pipeline region is determined based on the sub-natural gas transmission path, the various pressure parameters, and the changes in two adjacent pressure parameters. The corresponding pipeline fault event is then determined based on the identification of the fault region. This approach considers the overall changes in the sub-natural gas transmission path, the various pressure parameters, and the changes in two adjacent pressure parameters, ensuring the accuracy of the fault region and further guaranteeing the accuracy of the pipeline fault event, thereby improving the fault detection effect of the natural gas pipeline.

[0007] Therefore, multiple pipeline fault events are collected, and pipeline control measures are determined based on the fault level, location, and current operating status of the natural gas pipeline. Based on these control measures, pipeline status signals are triggered, and corresponding pipeline areas are closed to dynamically update the natural gas delivery path. This process introduces pipeline control measures and triggers the closure of corresponding pipeline areas, ensuring the normal operation of the natural gas pipeline and achieving dynamic updates to the natural gas delivery path. Attached Figure Description

[0008] Figure 1 This is a flowchart illustrating the fault detection method for natural gas pipelines in an embodiment of the present invention. Figure 2 This is a flowchart illustrating step S11 of the natural gas pipeline fault detection method in this embodiment of the invention. Figure 3This is a flowchart illustrating step S12 of the natural gas pipeline fault detection method in this embodiment of the invention. Figure 4 This is a flowchart illustrating step S13 in the natural gas pipeline fault detection method according to an embodiment of the present invention. Figure 5 This is a flowchart illustrating step S14 of the natural gas pipeline fault detection method in this embodiment of the invention. Figure 6 This is a flowchart illustrating step S15 of the natural gas pipeline fault detection method in this embodiment of the invention. Figure 7 This is a schematic diagram of the structural composition of a natural gas pipeline fault detection system according to an embodiment of the present invention. Detailed Implementation

[0009] The technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present invention.

[0010] Please see Figures 1 to 7 A fault detection method for natural gas pipelines, applied to fault detection scenarios in natural gas pipelines; the fault detection method for natural gas pipelines includes: Step S11: Collect the pipeline distribution map of the natural gas pipeline, and determine multiple pipeline areas based on the pipeline distribution map and the natural gas pipeline transportation instructions; Step S12: In each pipeline area, multiple pressure detection points are set up along the sub-natural gas transmission path of the pipeline area, and corresponding pressure parameters are collected based on the multiple pressure detection points; Step S13: Determine the fault area of ​​the pipeline region based on the sub-natural gas transmission path, the changes of each pressure parameter and two adjacent pressure parameters, and determine the corresponding pipeline fault event based on the identification of the fault area; Step S14: Collect multiple pipeline fault events, and determine pipeline control measures for the natural gas pipeline based on the fault level of the multiple pipeline fault events, the location of the pipeline fault events, and the current operating status of the natural gas pipeline. Step S15: Trigger the pipeline status signal of the natural gas pipeline based on pipeline control measures, and close the corresponding pipeline area according to the pipeline status signal to dynamically update the natural gas transmission path of the natural gas pipeline; refer to Figure 2 In step S11, a pipeline distribution map of the natural gas pipeline is collected, and multiple pipeline areas are determined based on the pipeline distribution map and the transportation instructions of the natural gas pipeline. In the specific implementation of this invention, the specific steps are as follows: S111: Collect the location of natural gas pipelines, determine the pipeline distribution map of natural gas pipelines based on the tracing of the natural gas pipeline locations, and determine the pipeline path of natural gas pipelines based on the traversal of the pipeline distribution map. S112: Determine the main pipeline route and multiple branch pipeline routes based on the division of the natural gas pipeline route, and determine multiple natural gas transmission routes based on the main pipeline route and multiple branch pipeline routes; S113: Collect the natural gas pipeline transportation instructions, determine the natural gas transportation target based on the parsing of the natural gas pipeline transportation instructions, determine multiple pipeline areas based on the matching of the natural gas transportation target and multiple natural gas transportation paths, and then transport the natural gas along the multiple pipeline areas in sequence.

[0011] In the embodiments of this application, the location of natural gas pipelines is collected, a pipeline distribution map of natural gas pipelines is determined based on the tracing of the location of natural gas pipelines, and the pipeline path of natural gas pipelines is determined based on the traversal of the pipeline distribution map. This approach takes into account the overall consideration of tracing the location of natural gas pipelines and ensures the accuracy of the pipeline distribution map of natural gas pipelines.

[0012] At this point, the location of the natural gas pipeline is collected. After obtaining the pipeline location information, the next step is to integrate this information into a pipeline distribution map. This map should clearly show the pipeline's direction, connection points, branch points, and other key information. Typically, this requires the use of GIS software or specialized pipeline management software. Optionally, the natural gas company imports the collected pipeline location information into GIS software. Through software processing, these coordinate points are converted into continuous pipeline segments, forming a preliminary pipeline distribution map. Subsequently, the company's staff further revise and improve the pipeline distribution map based on the results of on-site surveys and existing design drawings to ensure the accuracy and completeness of the map.

[0013] Pipeline routes refer to the flow paths of natural gas within a pipeline network. After determining the pipeline distribution map, it is necessary to traverse this map to identify all pipeline routes. This typically involves analyzing the topology of the pipeline network to determine all flow paths of natural gas from the starting point to the end point. At this point, the natural gas company uses GIS software to traverse and analyze the pipeline distribution map. The software automatically identifies all main pipelines and branch pipelines and generates corresponding pipeline route maps. These route maps clearly show the flow direction, branch points, and confluence points of natural gas within the pipeline network. By comparing and analyzing these route maps, the company can more accurately understand the operational status of the pipeline network and provides strong support for subsequent fault detection and maintenance work.

[0014] Specifically, suppose a natural gas company's pipeline network covers four areas in city A: east, south, west, and north. To optimize pipeline management, the company decides to upgrade its pipeline network digitally. In step S111, the company first collects all location information of the pipeline network by reviewing design drawings and conducting on-site surveys. Then, this information is imported into GIS software to generate a preliminary pipeline distribution map. Next, the software performs a comprehensive analysis of the pipeline distribution map, identifying all pipeline paths. Finally, the company obtains a clear and accurate pipeline network map, which details the pipeline routes, connection points, branch points, and the flow paths of natural gas within the pipeline network.

[0015] Furthermore, the main pipeline route and multiple branch pipeline routes are determined based on the division of the natural gas pipeline path. Multiple natural gas transmission routes are then determined based on the main pipeline route and multiple branch pipeline routes, which takes into account the overall consideration of the main pipeline route and multiple branch pipeline routes, and ensures the accuracy of multiple natural gas transmission routes.

[0016] At this point, the main transmission route, or main pipeline route, is identified from the established pipeline network. The main pipeline route is typically the route with the largest diameter and highest transmission capacity in the pipeline network, responsible for transporting natural gas from its source (such as a gas field or receiving station) to major distribution points or city gate stations. The determination of the main pipeline route is usually based on parameters such as pipeline diameter, transmission pressure, and design flow rate, as well as the pipeline network topology. In this case, suppose there is a natural gas pipeline network covering multiple cities and regions. Within this network, there are several pipelines with larger diameters and higher design flow rates, responsible for transporting natural gas from gas fields to the major city gate stations. To determine the main pipeline route, these larger diameter pipelines with higher design flow rates are first selected. Then, combined with the pipeline network topology, their connections and transmission directions are identified, thus determining the main pipeline route.

[0017] Branch pipeline routes are paths that branch off from the main pipeline route. They are responsible for transporting natural gas from the main pipeline to various end users or smaller distribution stations. The determination of branch pipeline routes needs to consider factors such as user distribution, transportation demand, pipeline safety, and economics. Typically, branch pipeline routes extend from the branch points of the main pipeline route, forming multiple branch routes that eventually connect to various end users or distribution stations. Once the main pipeline route is determined, the search for branch pipeline routes begins along the branch points of the main pipeline. These branch pipeline routes extend along city streets, highways, or other transportation lines to better serve various end users.

[0018] Main pipeline routes and branch pipeline routes combine to form multiple complete natural gas transmission routes. These routes start from the natural gas source, transport it along the main pipeline route to the main distribution point, and then along the branch pipeline routes to various end users or distribution stations. Each transmission route is independent, and they are interconnected through nodes in the pipeline network. At this point, combining the main pipeline routes and branch pipeline routes forms multiple complete natural gas transmission routes. For example, starting from a gas field, natural gas is transported along the main pipeline route to the main gate station in city A, and then along the branch pipeline routes to various end users or distribution stations in city A. Similarly, natural gas is also transported along other main pipeline routes and branch pipeline routes to other cities and regions. These transmission routes together constitute the transmission network of the natural gas pipeline network.

[0019] Therefore, by collecting the natural gas pipeline's transport instructions, determining the natural gas transport target based on the parsing of the natural gas pipeline's transport instructions, and determining multiple pipeline regions based on the matching of the natural gas transport target and multiple natural gas transport paths, natural gas is then transported sequentially along multiple pipeline regions. This approach takes into account the overall consideration of matching the natural gas transport target and multiple natural gas transport paths, ensuring the accuracy of multiple pipeline regions.

[0020] At this point, natural gas pipeline transportation instructions are obtained from the natural gas dispatch center or relevant management departments. These instructions typically contain key information such as the natural gas transportation target (e.g., a specific city, industrial area, or end user), transportation volume, and transportation time. This information is usually provided in the form of electronic documents, emails, or dedicated software systems. For example, the natural gas dispatch center may issue transportation instructions through dedicated pipeline management system software. These instructions include daily or weekly transportation plans, detailing the natural gas demand of each transportation target, the start and end times of transportation, etc. To obtain these instructions, it is necessary to log in to the pipeline management system regularly to download and save the latest transportation plans.

[0021] After obtaining the delivery instructions, these instructions need to be parsed to determine the specific natural gas delivery targets. This usually involves reading and understanding the text, numbers, or charts in the instructions to extract key information; for example, it is necessary to identify the names of specific cities, industrial areas, or end users, as well as their corresponding natural gas demand from the instructions.

[0022] After identifying the natural gas transportation targets, these targets need to be matched with multiple previously determined natural gas transportation routes. This typically involves understanding the pipeline network topology and analyzing the relationship between the transportation targets and routes. Through matching, it is determined which pipeline areas will participate in natural gas transportation, as well as their connections and transportation directions. At this point, GIS software or a pipeline management system is used to assist in the matching process. First, the previously determined pipeline network map and transportation routes are loaded into the software. Then, the transportation targets (such as the names of cities, industrial areas, or end users) are used as query criteria to search for matching transportation routes in the software. Through this process, it is determined which pipeline areas will participate in natural gas transportation and corresponding pipeline area maps or reports are generated.

[0023] refer to Figure 3 In step S12, in each pipeline area, multiple pressure detection points are set in the sub-natural gas transmission path of the pipeline area, and corresponding pressure parameters are collected based on the multiple pressure detection points. In the specific implementation of this invention, the specific steps are as follows: S121: Real-time monitoring of each pipeline area, and determination of the corresponding sub-natural gas transmission path based on the autonomous detection of each pipeline area; S122: In each sub-natural gas transmission path, multiple pressure detection points are determined based on the path length of the sub-natural gas transmission path, the shape of the pipeline area, and the corresponding natural gas transmission volume. At this time, multiple pressure detection points are distributed in different locations within the same pipeline area. S123: Real-time monitoring of multiple pressure detection points, collection of corresponding parameter sets based on online detection of multiple pressure detection points, determination of corresponding pressure parameters based on traversal of parameter sets, and collection of corresponding pressure parameters.

[0024] In the embodiments of this application, each pipeline area is monitored in real time, and the corresponding sub-natural gas transmission path is determined based on the autonomous detection of each pipeline area. This approach takes into account the overall consideration of autonomous detection of each pipeline area and ensures the accuracy of the corresponding sub-natural gas transmission path.

[0025] At this time, real-time monitoring of each pipeline area is carried out. Temperature sensors, pressure sensors, flow sensors, etc. are installed at key locations in the pipeline to monitor parameters such as temperature, pressure, and flow in real time. Cameras are installed along the pipeline to monitor the surrounding environment and traffic conditions in real time so as to detect potential threats in a timely manner. Data collected by sensors and cameras is transmitted to the monitoring center in real time through satellite communication, fiber optic communication, etc., for centralized management and analysis.

[0026] Based on real-time monitoring of each pipeline area, natural gas companies or management agencies need to use autonomous detection systems (such as intelligent sensor networks and data analysis software) to analyze and process data from the pipeline areas. By analyzing the changing trends of parameters such as temperature, pressure, and flow rate in the pipeline areas, as well as information such as video images of the surrounding environment, the operational status and health of each pipeline area can be determined. Based on this information, the corresponding sub-natural gas transmission paths, i.e., the specific channels through which natural gas flows in the pipeline network, can be further determined. At this point, data analysis software is used to analyze the data collected by the sensors in real time to identify abnormal data or trends, such as abnormal increases or decreases in pressure or abnormal changes in temperature. Based on the results of the data analysis, combined with the topology of the pipeline network and the transmission plan, each sub-natural gas transmission path is determined. These paths should avoid potentially dangerous areas, such as areas prone to geological disasters or densely populated areas, to ensure the safety and stability of the transmission process.

[0027] Specifically, suppose a natural gas company has a main pipeline from a gas source to city A. This pipeline passes through multiple pipeline areas, including mountainous areas, rivers, and urban suburbs. To ensure the safety and stability of natural gas transportation, the company has installed temperature sensors, pressure sensors, and flow sensors at key locations along the pipeline, as well as cameras along the pipeline route. These devices transmit the collected data to the company's monitoring center in real time via fiber optic communication. The company then uses its autonomous detection system to analyze and process the collected data. Through data analysis software, the company discovers abnormal fluctuations in pressure data in a certain mountainous pipeline area. Simultaneously, the cameras in that area have captured some abnormal phenomena, such as ground subsidence and vegetation damage. Based on this information, the company determines that the area poses a geological hazard risk and therefore decides to exclude it from the natural gas transportation route.

[0028] Finally, based on the data analysis results and the pipeline network topology, the company redefined the sub-natural gas transmission routes. The new routes avoided potentially hazardous areas and ensured the safety and stability of natural gas transmission. Simultaneously, the company decided to strengthen monitoring and inspection of the area to promptly identify and address potential problems. This example demonstrates the crucial role of step S121 in natural gas pipeline management. By monitoring the status of each pipeline area in real time and utilizing the autonomous detection system for data analysis and processing, the corresponding sub-natural gas transmission routes are determined, thereby ensuring the safety and stability of natural gas transmission.

[0029] Furthermore, in each sub-natural gas transmission path, multiple pressure detection points are determined based on the path length of the sub-natural gas transmission path, the shape of the pipeline area, and the corresponding natural gas transmission volume. At this time, multiple pressure detection points are distributed in different locations within the same pipeline area, which takes into account the overall consideration of the path length of the sub-natural gas transmission path, the shape of the pipeline area, and the corresponding natural gas transmission volume, ensuring the accuracy of multiple pressure detection points.

[0030] At this point, it is essential to first identify the various sub-paths within the natural gas transmission network. Sub-paths are smaller transmission channels divided from the main transmission pipeline, and they are categorized based on factors such as geography, urban distribution, and user demand. Each sub-path undertakes a specific natural gas transmission task, and the path length is a crucial factor in determining the number of pressure monitoring points. Generally, the longer the path, the more problems the natural gas encounters during transmission, such as pressure loss and leakage risks. Therefore, for longer sub-paths, more pressure monitoring points are needed to monitor pressure changes and ensure safe transmission.

[0031] The morphology of the pipeline network, such as its curvature and whether it traverses complex terrain (e.g., mountains, rivers), also affects the efficiency and safety of natural gas transportation. In areas with complex morphologies, natural gas flow is obstructed, leading to pressure variations. Therefore, additional pressure monitoring points are needed in these areas to promptly detect and address potential problems. Simultaneously, the natural gas transport volume is a key factor in determining the location of pressure monitoring points. Higher transport volumes result in higher pressure within the pipeline, leading to more severe wear and tear on the pipeline and its components. Therefore, on high-volume sub-paths, more pressure monitoring points are required to monitor pressure changes and ensure safe pipeline operation. Based on a comprehensive consideration of these factors, multiple pressure monitoring points are determined on each sub-natural gas transport path. These points should be evenly distributed across different locations within the pipeline to comprehensively monitor pressure changes. Furthermore, the number and location of monitoring points should be flexibly adjusted according to the actual conditions of the pipeline area and variations in transport volume.

[0032] Specifically, suppose there is a natural gas transmission route from the gas source to city B, which is about 50 kilometers long and passes through a mountainous and plain area; the natural gas transmission volume of this route is large, requiring the transmission of millions of cubic meters of natural gas per day; in order to ensure transmission safety, it is decided to set up pressure detection points on this route.

[0033] First, the route was divided into several segments, each approximately 10 kilometers long. Pressure monitoring points were set up at key locations in each segment (such as the starting point, ending point, and the boundary between mountainous and plain areas). Second, considering the complex terrain in mountainous areas that hindered natural gas flow, the number of pressure monitoring points was increased in the mountainous sections to ensure timely detection and handling of potential problems. Finally, based on the natural gas transport volume of the route, it was decided to install high-precision pressure sensors at each monitoring point to monitor pressure changes within the pipeline in real time. Simultaneously, a remote monitoring system was established to transmit data from each monitoring point to the monitoring center in real time for centralized management and analysis.

[0034] Therefore, by monitoring multiple pressure detection points in real time, collecting corresponding parameter sets based on the online detection of multiple pressure detection points, and determining the corresponding pressure parameters according to the traversal of the parameter sets, the system can collect the corresponding pressure parameters. This approach takes into account the overall consideration of parameter set traversal and ensures the accuracy of the corresponding pressure parameters.

[0035] At this time, there are multiple pressure monitoring points distributed in the natural gas pipeline network. Each monitoring point is equipped with a high-precision pressure sensor and other necessary monitoring equipment. These devices need to operate in real time to continuously monitor pressure changes in the pipeline. In order to achieve real-time monitoring, a remote monitoring center or cloud platform is usually needed to centrally receive and process data from various monitoring points.

[0036] Online monitoring refers to the process by which pressure sensors and other monitoring devices automatically collect data during real-time operation. This data includes, but is not limited to, key parameters such as pressure values, temperature values, and timestamps. Each monitoring point periodically or continuously sends these parameters to the remote monitoring center, forming a corresponding parameter set. This parameter set is the basis for subsequent analysis and processing, as it records detailed information about the pressure changes within the pipeline over time.

[0037] After receiving the parameter sets from each monitoring point, the remote monitoring center needs to perform a traversal process. Traversal refers to accessing each element in the parameter set (i.e., the data of each monitoring point) in a certain order. Through traversal, the pressure parameters of each monitoring point at a specific time point are extracted. These pressure parameters are important bases for assessing the pipeline's operating status, identifying potential problems, and formulating countermeasures. At the same time, the pressure parameters obtained through traversal are organized, stored, and analyzed. These parameters are used to monitor the pipeline's operating status in real time and promptly detect problems such as pressure anomalies or leaks. In addition, they are also used as historical data for subsequent pipeline maintenance, optimization, and troubleshooting.

[0038] Specifically, suppose there is a natural gas pipeline from the gas source to city C. There are 10 pressure detection points on the pipeline, numbered D1 to D10. These detection points are equipped with high-precision pressure sensors and send the data to a remote monitoring center in real time.

[0039] One day, the remote monitoring center received a set of parameters from various monitoring points. For example, the pressure at monitoring point D1 was 1.2 MPa and the temperature was 25°C at 8:00 AM; the pressure at monitoring point D2 was 1.15 MPa and the temperature was 24°C at 8:00 AM; and so on, up to monitoring point D10. By traversing these parameter sets, the staff at the monitoring center extracted the pressure parameters of each monitoring point at a specific time. They found that the pressure at monitoring point D5 suddenly dropped to 0.9 MPa, while the pressure values ​​at other monitoring points remained relatively stable. This abnormal change caught the staff's attention, and they immediately activated the emergency plan and inspected the pipelines near monitoring point D5.

[0040] An inspection revealed a leak in the pipeline near monitoring point D5 due to aging. Staff quickly implemented repair measures, preventing further escalation. This incident was also analyzed and summarized as a case study to better address similar issues in future pipeline management. This example demonstrates the crucial role of steps S123 in natural gas pipeline management. By real-time monitoring of multiple pressure monitoring points, collecting corresponding parameter sets, traversing and determining pressure parameters, and collecting relevant pressure data, abnormalities in pipeline operation can be detected promptly, allowing for timely countermeasures and ensuring the safety and stability of natural gas transmission.

[0041] In some embodiments of this application, a detection point matching table is collected, as shown in Table 1: Table 1. Detection Point Matching Table testing point Timestamp Pressure value (MPa) Temperature value (°C) D1 2023-05-01 08:00 1.2 25 D2 2023-05-01 08:00 1.15 24 ... ... ... ... Dn 2023-05-01 08:00 1.18 26 For each detection point, a score is calculated by comparing its pressure value with the preset normal pressure range. The score can be a simple binary value (e.g., 1 point for normal, 0 points for abnormal) or a more complex value (e.g., scoring based on the degree to which the pressure deviates from the normal range). Then, the score for each detection point is multiplied by its weight to obtain a weighted score. Finally, all weighted scores are summed to obtain the overall operating status score of the pipeline. Assuming that after traversal and calculation, a weighted score matching table is obtained, as shown in Table 2: Table 2 Detection Point Matching Table Inspection point number Pressure value (MPa) Score Weight Weighted score D1 1.2 1 0.15 0.15 D2 1.05 0 0.1 0 ... ... ... ... ... Dn 1.18 1 0.05 0.05 The overall operational status score of the pipeline is S = 0.15 + 0 + ... + 0.05 = 0.35. This score is used to assess the overall operational status of the pipeline. If the score is low, it indicates that there is an abnormality in the pipeline, which requires further inspection and handling.

[0042] refer to Figure 4 In step S13, the fault area of ​​the pipeline region is determined based on the sub-natural gas transmission path, the changes of each pressure parameter and two adjacent pressure parameters, and the corresponding pipeline fault event is determined based on the identification of the fault area. In the specific implementation of this invention, the specific steps are as follows: S131: In each sub-natural gas transmission path, collect pressure parameters corresponding to multiple pressure detection points, and determine the change in two adjacent pressure parameters based on the comparison of two adjacent pressure parameters. S132: Determine the first sub-fault area based on the location of the sub-natural gas transmission path and the pressure parameters corresponding to multiple pressure detection points; determine the second sub-fault area based on the location of the natural gas transmission path and the change in two adjacent pressure parameters. S133: In each pipeline region, the fault region of the pipeline region is determined based on the combination of the first sub-fault region and the second sub-fault region. The corresponding fault identification logic is determined according to the regional location and regional shape of the pipeline region and the natural gas pipeline database. The corresponding pipeline fault event is determined according to the matching of the fault identification logic and the fault region.

[0043] In the embodiments of this application, pressure parameters corresponding to multiple pressure detection points are collected in each sub-natural gas transmission path, and the change in two adjacent pressure parameters is determined by comparing the two adjacent pressure parameters. This approach takes into account the overall comparison of two adjacent pressure parameters and ensures the accuracy of the change in two adjacent pressure parameters.

[0044] At this time, pressure parameters are collected at pressure detection points arranged in each sub-natural gas transmission path. These detection points are usually set at key locations in the pipeline, such as starting points, branch points, bends, and areas prone to failure. Each detection point is equipped with a high-precision pressure sensor to monitor and record the pressure values ​​in the pipeline in real time. These pressure values ​​are usually collected and transmitted to the remote monitoring center at certain time intervals (such as every minute, every hour, etc.) for subsequent analysis and processing.

[0045] After collecting pressure parameters from multiple pressure detection points, these parameters need to be compared and analyzed. In particular, attention should be paid to the pressure parameters of two adjacent detection points, because the pressure change between these two points reflects the state of natural gas flow in the pipeline and any existing problems. During the comparison, the pressure difference (i.e., the change) between two adjacent detection points is usually calculated, and it is observed whether this difference exceeds a preset threshold. If it exceeds the threshold, further investigation is needed to determine whether there is a fault.

[0046] After comparing the pressure parameters of two adjacent detection points, it is necessary to determine the amount of change between them. This amount of change is obtained through simple mathematical calculation, which is the pressure value of the later detection point minus the pressure value of the earlier detection point (or vice versa, depending on the defined positive direction). The sign and magnitude of the change reflect the trend and amplitude of pressure change in the pipeline. If the change is large and persistent, further action is needed to find out the cause and solve the problem.

[0047] Specifically, suppose there is a natural gas pipeline from a gas source to city E, with 10 pressure monitoring points (D1 to D10) set up on the pipeline; at a certain point in time, the pressure parameters of these monitoring points are collected, and it is found that there is a significant change in the pressure parameters between two adjacent monitoring points D4 and D5.

[0048] Pressure values ​​at two monitoring points, D4 and D5, were collected at a certain moment, measuring 1.2 MPa and 1.0 MPa respectively. Comparing these pressure values ​​revealed a pressure difference of 0.2 MPa. Based on this comparison, the pressure variation between monitoring points D4 and D5 was determined to be 0.2 MPa, exceeding a preset threshold (assumed to be 0.1 MPa), thus indicating a fault in this area. Further investigation of the pipeline area between D4 and D5 will determine if there are any leaks, blockages, or other issues affecting natural gas transmission. This includes dispatching maintenance personnel to the site for inspection, using specialized testing equipment, and analyzing historical data. Finally, appropriate measures will be taken based on the investigation results to resolve the problem and ensure the safe and stable transmission of natural gas.

[0049] Furthermore, the first sub-fault area is determined based on the location of the natural gas transmission path and the pressure parameters corresponding to multiple pressure detection points, and the second sub-fault area is determined based on the location of the natural gas transmission path and the change in two adjacent pressure parameters. This comprehensive consideration of the location of the natural gas transmission path and the change in two adjacent pressure parameters ensures the accuracy of the second sub-fault area.

[0050] At this point, the first sub-fault area is determined based on the location information of the sub-natural gas transmission path and the pressure parameters recorded by multiple pressure monitoring points. First, it is necessary to understand the layout of the entire natural gas transmission network, especially the positional relationship of each sub-path. Then, by analyzing the data of each pressure monitoring point, it is identified which points have pressure parameters deviating from the normal range. These abnormal points indicate potential problem areas. Optionally, to determine the first sub-fault area, the following factors are usually considered: the greater the deviation of the abnormal value from the normal range, the higher the probability of indicating a fault; if the abnormal value persists rather than fluctuates briefly, it indicates a more persistent fault. By combining the map of the natural gas transmission path, the location of the sub-path where the abnormal value is located is determined, thereby initially locking in the fault area and drawing one or more potential first sub-fault areas.

[0051] After identifying the first sub-fault area, it is necessary to further refine the fault location, which is the process of determining the second sub-fault area. This step mainly relies on the change in pressure parameters between two adjacent pressure detection points. Anomalies in the change (such as a sudden increase or decrease) indicate pressure fluctuations in the pipeline, which are caused by leaks, blockages or other faults.

[0052] To determine the second sub-fault area, the following steps are typically performed: For each pair of adjacent detection points, calculate the pressure difference between them, i.e., the change; compare the calculated change with a preset threshold to identify which changes exceed the normal range; for the identified abnormal changes, determine their sub-path locations by combining the map of the natural gas transmission path; since abnormal changes usually indicate the location of the fault more accurately, this area is designated as the second sub-fault area.

[0053] Specifically, suppose there is a natural gas pipeline from a gas source to city F, with 5 pressure monitoring points (P1 to P5) distributed along two sub-paths (sub-path A and sub-path B). At a certain point in time, the pressure parameters of these monitoring points were collected, and the following analysis was performed: Identifying the first sub-fault area: The pressure parameters at point P3 were found to be significantly lower than the normal range, and this anomaly had persisted for some time. Based on the map of the natural gas transmission path, it was determined that point P3 is located on sub-path A. Therefore, the area near point P3 on sub-path A was designated as the first sub-fault area. The second sub-fault area was identified: the pressure change between adjacent detection points was calculated, and an abnormally large change was found between P2 and P3. This change was compared with a preset threshold, confirming that it exceeded the normal range. Based on the map of the natural gas transmission path, the area between P2 and P3 was located on sub-path A and adjacent to the first sub-fault area. Therefore, the area between P2 and P3 was designated as the second sub-fault area, which more accurately indicates the fault location. Next, maintenance personnel were dispatched to the second sub-fault area for on-site inspection, using professional detection equipment to further confirm the fault point and take corresponding repair measures.

[0054] Therefore, in each pipeline region, the fault region of the pipeline region is determined by the synthesis of the first sub-fault region and the second sub-fault region. The corresponding fault identification logic is determined according to the regional location and shape of the pipeline region and the natural gas pipeline database. The corresponding pipeline fault event is determined by matching the fault identification logic with the fault region. This approach takes into account the overall consideration of the regional location and shape of the pipeline region and the natural gas pipeline database, ensuring the accuracy of the corresponding fault identification logic. At the same time, it takes into account the overall consideration of the sub-natural gas transmission path, various pressure parameters, and the changes in two adjacent pressure parameters, ensuring the accuracy of the fault region and further ensuring the accuracy of the pipeline fault event, thereby improving the fault detection effect of natural gas pipelines.

[0055] At this point, the previously identified first and second sub-fault regions are combined to obtain a more accurate and comprehensive pipeline fault region. The combination process usually involves comprehensive consideration of factors such as the geographical location, size, and shape of the two regions. If the two regions overlap in space, the overlapping part will be taken as the location of the fault. If the two regions are separate, it is necessary to determine whether the fault affects both regions simultaneously or whether they indicate different fault points based on their relative positions and distances, as well as the layout and characteristics of the natural gas pipeline. The combined fault region will serve as the basis for subsequent fault identification and analysis.

[0056] After identifying the fault area, fault identification logic needs to be developed based on the area's geographical location, shape, and information from the natural gas pipeline database. Fault identification logic is a set of rules or algorithms used to identify the fault type, location, and severity based on specific inputs (such as pressure parameters, temperature changes, sound signals, etc.).

[0057] Optionally, when developing fault identification logic, the following factors are typically considered: pipeline materials, structure, and historical data: this information helps to understand the pipeline's performance under different conditions and the patterns of similar faults that have occurred in the past; geographical features of the fault area: such as soil type, groundwater level, and ground activity, these factors affect the stability of the pipeline and the occurrence of faults; fault type: such as leakage, blockage, corrosion, mechanical damage, etc., each fault type has its specific identification characteristics and impacts, in order to build a fault identification model or rule set to match the input data with known fault patterns, thereby identifying fault events.

[0058] After establishing the fault identification logic, it needs to be applied to the previously identified fault areas to identify specific pipeline fault events. This process typically involves matching real-time data from the fault area with the rules or algorithms in the fault identification logic to find the most suitable fault type, location, and severity. The matching process needs to consider multiple data sources and various analysis methods to ensure the accuracy and reliability of the identification. Once a fault event is identified, appropriate countermeasures are taken, such as dispatching maintenance personnel, shutting down the affected pipeline section, and activating emergency plans.

[0059] Specifically, suppose there is a natural gas pipeline from the gas source to city G. There are multiple pressure detection points on the pipeline, and the first sub-fault area (sub-area A) and the second sub-fault area (sub-area B) have been identified through the previous steps.

[0060] Sub-regions A and B overlap spatially and are both located at a bend in the pipeline. Therefore, the overlapping area is considered the final fault area and the location of the fault. Based on information from the natural gas pipeline database, it is known that this bend uses older pipeline materials and has a history of leaks. Combining the geographical features of the fault area (such as loose soil and a high groundwater level), the following fault identification logic is established: if the pressure parameter suddenly drops and remains unchanged, and the sound sensor detects an abnormal sound (such as the hissing sound of a gas leak), then a leak fault is identified.

[0061] The real-time data of the fault area was matched with the fault identification logic; it was found that the pressure parameter suddenly dropped by about 20% in the overlapping part of sub-regions A and B, and the sound sensor detected a continuous hissing sound in the area; according to the fault identification logic, this was identified as a leakage fault event; next, the leakage emergency plan was immediately activated, the affected pipeline section was shut down, and maintenance personnel were dispatched to the site for emergency repair work; at the same time, this opportunity was also used to conduct a more comprehensive inspection and maintenance of the pipeline to prevent similar faults from happening again.

[0062] In some embodiments of this application, it is assumed that the fault area has the following attributes: located at a bend, near a river, and using old pipe materials; the fault type is searched in a matching table based on these attributes, and a weight or score is assigned to each type based on the degree of matching; Leakage: Bend (High, 3 points) + Proximity to River (High, 3 points) + Old Pipe Material (Medium, 2 points) = Total Score 8 points; Blockage: Straight line segment (medium, 2 points) (mismatch, no score) + ... = lower total score (assuming other attributes do not match); Corrosion: Proximity to river (high, 3 points) + old pipe materials (medium, 2 points) (Corrosion is less affected at bends, so high marks are not awarded) = Total score 5 points; Mechanical damage: Old pipe materials (medium, 2 points) (Bends and areas near rivers have less impact on mechanical damage and do not receive high marks) = Low total score; Based on the weights and scores, the leak fault type received the highest total score (8 points), thus identifying the current pipeline fault event as a leak.

[0063] refer to Figure 5 In step S14, multiple pipeline fault events are collected, and pipeline control measures for the natural gas pipeline are determined based on the fault level of the multiple pipeline fault events, the location of the pipeline fault events, and the current working status of the natural gas pipeline. In the specific implementation of this invention, the specific steps are as follows: S141: Multiple pipeline failure events are introduced. Among these events, the corresponding failure content is determined by tracing each event. The corresponding failure level is determined based on the failure content, the location of the pipeline area, and the type of natural gas transported by the pipeline. S142: Mark the location of pipeline failure events, determine the first control measure based on the failure level of multiple pipeline failure events and the location of the pipeline failure events; determine the second control measure based on the failure level of multiple pipeline failure events and the current operating status of the natural gas pipeline. S143: Based on the first control measure, the second control measure, and the mapping relationship between the measures, the pipeline control measures for natural gas pipelines are determined. At this time, the pipeline control measures include pipeline opening and closing measures, pipeline maintenance measures, and pipeline speed limiting measures for natural gas.

[0064] In the embodiments of this application, multiple pipeline failure events are introduced. Among the multiple pipeline failure events, the corresponding failure content is determined based on the tracing of each pipeline failure event. The corresponding failure level is determined according to the failure content, the location of the pipeline area, and the type of natural gas transported by the natural gas pipeline. This approach takes into account the overall consideration of the failure content, the location of the pipeline area, and the type of natural gas transported by the natural gas pipeline, ensuring the accuracy of the corresponding failure level.

[0065] At this point, multiple pipeline failure events are introduced, and each event is analyzed in depth to determine the specific nature of the failure. This typically involves investigating the failure site, analyzing monitoring data, and understanding the pipeline system. Professional personnel are dispatched to the failure site for on-site observation and measurement to obtain more detailed information. Data from the monitoring system is used to analyze changes in the pipeline's state before and after the failure, such as changes in parameters like pressure, flow rate, and temperature. Combined with an understanding of the pipeline system, the cause and scope of the failure are analyzed. Based on the above analysis, the specific nature of the failure is determined, including its type, location, and scale.

[0066] Based on the nature of the fault, the location of the pipeline area, and the type of natural gas transported by the pipeline, a fault level is assigned to each fault event. The fault level typically reflects the severity and urgency of the fault. At this point, the severity of the fault is assessed by considering the type, scale, and impact on the pipeline system. The location of the fault is analyzed, taking into account whether it is close to residential areas, important facilities, or environmentally sensitive areas, and whether it is easily accessible and repairable. The type of natural gas being transported, such as domestic natural gas, industrial natural gas, or liquefied natural gas, and its impact on safety and the environment, is considered to determine a fault level for each fault event, typically categorized as high, medium, or low.

[0067] Specifically, suppose the following three pipeline failure events occur in a certain natural gas transmission network: Fault Event A: A small-scale leak was discovered in a section of pipeline on the outskirts of the city. The leaking natural gas was for domestic use. After on-site investigation and data analysis, it was determined that the leak point was located in an easily accessible location and the leak was small in scale, with limited impact on the surrounding environment and residents. Therefore, the fault was assessed as a low-level fault. Fault Event B: A large-scale leak occurred on a section of pipeline within an industrial area. The leaked natural gas was industrial natural gas. On-site investigation revealed that the leak point was located in a difficult-to-access location, and the leak was large in scale, causing serious impact on the surrounding environment and facilities within the industrial area. In addition, industrial natural gas has a high risk of combustion and explosion. Therefore, this fault was assessed as a high-level fault. Fault Event C: A blockage occurred on a section of liquefied natural gas pipeline in a mountainous area; although the blockage itself did not cause a leak, considering the special properties of liquefied natural gas, the complex terrain conditions in the mountainous area, and the long-term impact of the blockage on the pipeline system, the fault was assessed as a medium-level fault.

[0068] Furthermore, the locations of pipeline failure events are marked, and a first control measure is determined based on the failure level and location of multiple pipeline failure events. A second control measure is determined based on the failure level of multiple pipeline failure events and the current operating status of the natural gas pipeline. This comprehensive consideration of the failure level of multiple pipeline failure events and the current operating status of the natural gas pipeline ensures the accuracy of the second control measure.

[0069] At this point, the specific location of each pipeline failure event is marked, which is usually done through a Geographic Information System (GIS) or similar positioning technology to ensure that the exact section of the pipeline where the failure occurred can be known. Data on the location of the failure event is then collected, which comes from reports from field personnel, alarm information from monitoring systems, or pipeline layout maps in GIS systems. Using GIS systems or related software, the location of the failure event is marked on the pipeline layout map, which usually involves marking latitude and longitude coordinates on the map or using other positioning identifiers.

[0070] The first control measures are determined based on the fault severity and location of multiple pipeline failure events. These measures are typically designed to immediately reduce the impact of the failure on the pipeline system and the surrounding environment. At this point, the fault severity of each failure event is considered; higher-severity failures require more rapid and stringent control measures. The location of the failure event is also considered; if the failure occurs in a densely populated or environmentally sensitive area, more cautious control measures are required to reduce the potential impact on people and the environment. Based on the analysis of the fault severity and location, the first control measures are developed, which include shutting down the affected pipeline section, activating emergency plans, and evacuating nearby personnel.

[0071] Secondary control measures are determined based on the fault levels of multiple pipeline failure events and the current operating status of the natural gas pipeline. These measures aim to further reduce the impact of failures on the pipeline system and ensure its safe operation. At this stage, the current operating status of the natural gas pipeline is considered, including parameters such as pressure, flow rate, and temperature, which help understand the overall operating condition of the pipeline system. The fault level is combined with the current operating status of the pipeline. If the pipeline is under high pressure or high flow rate, more stringent control measures are required to prevent further deterioration of the fault. Based on the analysis of the fault level and the current operating status, secondary control measures are formulated, including adjusting pipeline operating parameters, activating backup pipelines, and strengthening the monitoring system.

[0072] Specifically, suppose the following two pipeline failure events occur in a certain natural gas transmission network: Fault Event A: A small-scale leak occurred on a section of high-pressure pipeline in the city center. The leaked natural gas was for domestic use. Analysis determined the fault to be of medium severity. Given that the fault occurred in the city center and the pipeline was under high pressure, the following control measures were implemented: First control measure: Immediately shut down the affected pipeline section, activate the emergency plan, and evacuate nearby personnel; The second control measure is to adjust the operating parameters of surrounding pipelines to reduce pressure and minimize the impact on the affected area; at the same time, backup pipelines will be activated to ensure that the natural gas supply is not affected. Fault Event B: A blockage occurred on a section of liquefied natural gas pipeline in a remote mountainous area, where the pipeline was operating at low flow rates. Analysis determined this fault to be of low severity. Due to the remote location and low flow rate, the following control measures were implemented: First control measure: Mark the location of the fault and dispatch maintenance personnel to the site for investigation and repair; The second control measure is to temporarily shut down the pipeline section and restore it to operation after maintenance personnel have repaired it; at the same time, the monitoring system for the pipeline section will be strengthened to prevent similar failures from happening again.

[0073] Therefore, pipeline control measures for natural gas pipelines are determined based on the first control measure, the second control measure, and the mapping relationship between the measures. At this time, the pipeline control measures include pipeline opening and closing measures, pipeline maintenance measures, and pipeline speed limiting measures for natural gas. This approach takes into account the overall consideration of the first control measure, the second control measure, and the mapping relationship between the measures, thus ensuring the accuracy of the pipeline control measures for natural gas pipelines.

[0074] At this point, it is crucial to clearly understand the previously established primary and secondary control measures. These measures are determined based on the fault level and location of the pipeline failure event, as well as the current operating status of the natural gas pipeline. Their aim is to respond quickly to the failure and minimize its impact on the pipeline system and the surrounding environment. The primary control measures typically involve emergency response actions, such as shutting down the affected pipeline segment to prevent the fault from spreading, activating emergency plans to evacuate nearby personnel, or taking other immediate measures to mitigate the consequences of the failure. The secondary control measures, on the other hand, focus more on long-term or continuous response strategies, such as adjusting pipeline operating parameters, activating backup pipelines, and strengthening monitoring systems to ensure the safe and stable operation of the pipeline system.

[0075] The action mapping relationship refers to a logic or rule that associates specific fault conditions with corresponding control measures. This mapping relationship helps to quickly determine the control measures to be taken when a fault occurs. At this time, the mapping rule is formulated based on various factors such as fault level, fault type, pipeline location, and natural gas type. For example, a high-level leakage fault requires immediate pipeline shutdown and activation of emergency plans, while a low-level blockage fault only requires dispatching maintenance personnel to the site for repair. The action mapping relationship is not static; it is dynamically adjusted and optimized based on actual conditions and lessons learned.

[0076] Based on the first control measure, the second control measure, and the mapping relationship between the measures, the final pipeline control measures are comprehensively determined. These measures include pipeline opening and closing measures, pipeline maintenance measures, and pipeline flow rate limiting measures for natural gas. At this point, pipeline opening and closing measures involve closing or opening specific pipeline valves to isolate the fault area or restore natural gas supply; pipeline maintenance measures include dispatching maintenance personnel to the site for maintenance work, such as repairing leaks and clearing blockages; and pipeline flow rate limiting measures for natural gas adjust the flow rate of natural gas in the pipeline to reduce the risk of failure or mitigate the impact of failure.

[0077] Specifically, suppose the following pipeline failure event occurs in a certain natural gas transmission network: a leak occurs in a high-pressure pipeline that passes through a residential area, and the leaked natural gas is domestic natural gas; after analysis, the failure is assessed as a high-level failure; based on this failure event, the following first and second control measures are formulated.

[0078] First control measure: Immediately shut down the affected pipeline section, activate the emergency plan, and evacuate nearby residents; Second control measure: Adjust the operating parameters of surrounding pipelines to reduce pressure and minimize the impact on the affected area; Simultaneously, activate backup pipelines to ensure uninterrupted natural gas supply; Based on the mapping relationship of the measures, the following pipeline control measures were determined: Pipeline opening and closing measures: Close pipeline valves near the leak point to isolate the fault area and prevent the leak from spreading; Pipeline maintenance measures: Dispatch professional maintenance personnel to the site to locate and repair the leak; at the same time, strengthen on-site monitoring to ensure the safe conduct of maintenance work; Pipeline natural gas flow rate limiting measures: During maintenance, the natural gas flow rate in surrounding pipelines is adjusted to reduce pressure fluctuations and leakage risks; once maintenance is completed and safety is confirmed, the pipeline's normal operating parameters are gradually restored.

[0079] In some embodiments of this application, a pipeline control measure matching table is collected, as shown in Table 3: Table 3. Matching Table of Pipeline Regulation Measures Fault Level Fault type Position characteristics Types of natural gas First regulatory measure Second regulatory measures Pipeline regulation measures High level leakage Residential area Household natural gas Closed pipeline section Adjust operating parameters and start the backup pipeline. Pipeline opening and closing + maintenance + speed limiting Intermediate level blockage Industrial Zone Industrial natural gas Mark the location and dispatch maintenance personnel. Strengthen monitoring system Pipeline maintenance + speed limit low level Small-scale leak remote areas liquefied natural gas Mark location, remote monitoring No additional measures required Pipeline maintenance The pipeline control measures matching table lists the corresponding first control measures, second control measures, and comprehensive pipeline control measures for each situation, based on the fault level, fault type, location characteristics, and natural gas type.

[0080] refer to Figure 6 In step S15, the pipeline status signal of the natural gas pipeline is triggered based on the pipeline control measures, and the corresponding pipeline area is closed according to the pipeline status signal to dynamically update the natural gas transmission path of the natural gas pipeline. In the specific implementation of this invention, the specific steps are as follows: S151: Real-time monitoring of pipeline control measures, and outputting pipeline status signals of natural gas pipelines based on the execution of pipeline control measures. Based on the analysis of the pipeline status signals of natural gas pipelines, the corresponding pipeline area is determined, and closure measures are taken for the pipeline area to mark the closure mark of the pipeline area. S152: Define the corresponding sub-natural gas transmission path as an abnormal transmission path based on the closure mark of the pipeline area; S153: Based on the abnormal transport path and the pipeline distribution map of the natural gas pipeline, determine the alternative transport path; based on the alternative transport path, the remaining sub-natural gas transport path and the pipeline distribution map, dynamically update the natural gas transport path of the natural gas pipeline.

[0081] In the embodiments of this application, pipeline control measures are monitored in real time, and pipeline status signals of natural gas pipelines are output according to the execution of pipeline control measures. Based on the analysis of pipeline status signals of natural gas pipelines, corresponding pipeline areas are determined, and closure measures are taken for pipeline areas to mark the closure of pipeline areas. This approach is compatible with the overall consideration of the analysis of pipeline status signals of natural gas pipelines and ensures the accuracy of the corresponding pipeline areas.

[0082] At this point, real-time monitoring of the implementation of established pipeline control measures is crucial. This typically involves real-time monitoring of various sensors and monitoring equipment within the pipeline system to ensure the correct execution of the control measures. The system needs to collect pipeline status data, such as pressure, flow rate, and temperature, to evaluate the effectiveness of the control measures. The system collects real-time data through sensors connected to the pipeline. This data is transmitted to a central monitoring system for real-time analysis and processing. The monitoring system tracks the implementation of the control measures to ensure their effective execution.

[0083] After collecting pipeline status data, the system needs to convert this data into pipeline status signals, which can be digital, graphical, or any other form, to represent the current operating status of the pipeline. The system needs to ensure that these signals accurately reflect the actual state of the pipeline for subsequent analysis and decision-making. At this point, the system processes and analyzes the collected data to generate pipeline status signals. The signals display parameters such as pipeline pressure and flow rate in digital form, or show the overall status of the pipeline in graphical form. The system stores these signals in a database for subsequent querying and analysis.

[0084] The system needs to analyze pipeline status signals to determine which pipeline areas are affected. This typically involves algorithmic processing of the signals to identify areas of abnormality or potential problems. The system needs to accurately identify affected pipeline areas in order to take appropriate shutdown measures. At this point, the system uses a preset algorithm to analyze the pipeline status signals. The algorithm identifies abnormal signals, such as pressure drops or reduced flow, to determine the affected pipeline areas. The system marks these areas as potential problem areas for subsequent processing.

[0085] After identifying the affected pipeline area, the system needs to take shutdown measures to isolate the fault area and prevent the problem from spreading. This typically involves closing the relevant pipeline valves or activating emergency plans. The system also needs to mark these shutdown measures in the system for subsequent tracking and recording. At this point, the system determines the valves that need to be closed or other shutdown measures to be taken based on the affected pipeline area. The system sends instructions to the relevant actuators, such as valve controllers, to execute the shutdown operation. The system marks these shutdown measures in the database and records the shutdown symbols for subsequent querying and analysis.

[0086] Specifically, suppose a section of pipeline located in an industrial area in a natural gas transmission network leaks; the system monitors this fault in real time and handles it according to the following steps: the system collects data on pressure drop and flow reduction in the leak area through sensors connected to the pipeline; the system converts this data into pipeline status signals and displays them graphically on the monitoring screen, showing the abnormal status of the leak area; the system analyzes the signals, identifies the leak area, and marks it as a potential problem area.

[0087] The system determines that valves near the leak area need to be closed and sends instructions to the valve controllers to perform the closure operation. At the same time, the system marks these closure measures in the database and records the closure symbols for subsequent tracking and recording. Through this series of steps, the system can respond quickly to pipeline faults and take appropriate closure measures to ensure the safe and stable operation of the natural gas transmission network.

[0088] Furthermore, based on the closure marker of the pipeline area, the corresponding sub-natural gas transmission path is defined as an abnormal transmission path.

[0089] At this point, the system needs to identify which pipe areas are marked with closure symbols. These closure symbols are usually automatically generated by the system or manually entered in previous steps (such as S151) to indicate which pipe areas need to be closed or isolated due to faults, maintenance, or other reasons. The system needs to be able to accurately identify these closure symbols for subsequent processing. At this time, the system will periodically scan or query the database to find pipe areas marked as closed. These closure symbols exist in the form of specific identifiers, status codes, or color markings. The system will verify the authenticity and validity of these closure symbols to ensure the accuracy of subsequent steps.

[0090] After identifying the closed pipeline areas, the system needs to define the corresponding sub-natural gas transmission paths as abnormal transmission paths. An abnormal transmission path is a natural gas transmission path that cannot operate normally due to some reason (such as pipeline failure, maintenance, closure, etc.). The system needs to be able to automatically identify and define these abnormal paths so that appropriate measures can be taken to ensure the stability and security of natural gas supply. At this time, the system will determine which sub-natural gas transmission paths are affected based on the closure markers. The system will mark these paths as abnormal transmission paths and record them in the system. The system will generate alarms or notifications to remind operators to pay attention to these abnormal paths.

[0091] Specifically, suppose that in a certain natural gas transmission network, a section of pipeline located in the city center needs to be shut down due to construction. The system processes the situation according to the following steps: The system scans the database and finds that a section of pipeline in the city center is marked with a closure symbol. This symbol was manually entered by the construction personnel in previous steps to indicate that the pipeline section needs to be shut down due to construction. After identifying the closed pipeline area, the system defines the corresponding sub-natural gas transmission path as an abnormal transmission path. This path starts from a gas source station in the city center, passes through the closed pipeline section, and then delivers gas to various areas of the city. Because the pipeline is closed, this path is now unable to function normally.

[0092] The system generates an alarm to notify operators of this abnormal transmission path. Operators will then take other measures, such as activating backup pipelines or adjusting the natural gas transmission plan, to ensure the stability and security of the natural gas supply. This example demonstrates the importance of step S152 in natural gas transmission network management. The system can automatically identify and define abnormal transmission paths, providing operators with timely alarms and notifications, thereby helping them take appropriate measures to ensure the stability and security of the natural gas supply.

[0093] Therefore, alternative transportation routes are determined based on the abnormal transportation path and the pipeline distribution map of the natural gas pipeline. The natural gas transportation path of the natural gas pipeline is dynamically updated based on the autonomous synthesis of the alternative transportation path, the remaining sub-natural gas transportation path, and the pipeline distribution map. This takes into account the overall consideration of the abnormal transportation path and the pipeline distribution map of the natural gas pipeline, ensuring the accuracy of the alternative transportation path. At the same time, pipeline control measures are introduced and the corresponding pipeline area is closed, ensuring the normal use of the natural gas pipeline and realizing the dynamic updating of the natural gas transportation path of the natural gas pipeline.

[0094] At this point, the system needs to automatically search for and determine alternative transportation routes based on the abnormal transportation path and the pipeline distribution map of the natural gas pipeline. This typically involves in-depth analysis of the pipeline distribution map and the application of intelligent algorithms to ensure that the found alternative routes meet both technical requirements (such as pressure and flow rate) and are feasible in actual operation. The system needs to comprehensively consider multiple factors such as pipeline material, diameter, length, and connection points to find the optimal alternative route. At this stage, the system loads the pipeline distribution map and identifies the start and end points of the abnormal transportation path. The system applies intelligent algorithms (such as shortest path algorithms and multi-objective optimization algorithms) to search for potential alternative routes in the pipeline distribution map. The system performs a technical evaluation of each potential alternative route, including considerations such as pressure loss, flow limitations, and safety. Finally, the system selects one or more optimal alternative routes for operators to choose from or as the basis for automatic adjustments.

[0095] After identifying an alternative transmission route, the system needs to autonomously synthesize a new natural gas transmission route based on this route, the remaining sub-natural gas transmission routes, and the pipeline distribution map. This process requires ensuring that the new transmission route seamlessly connects with the existing transmission network while maintaining stable overall transmission efficiency. Furthermore, the system needs to dynamically update the natural gas pipeline transmission route information for subsequent operation and management. At this point, the system will adjust the original natural gas transmission route according to the selected alternative route. The system will recalculate and adjust relevant pipeline parameters (such as pressure and flow rate) to ensure that the new transmission route meets technical requirements. The system will update the pipeline distribution map to incorporate the new transmission route information. Finally, the system will generate a new natural gas transmission route report for operators to view and confirm.

[0096] Specifically, suppose that in a certain natural gas transmission network, a section of pipeline located in the suburbs needs to be shut down due to aging, causing the original transmission route to be interrupted; the system will handle this according to the following steps: the system identifies the starting point (suburban gas source station) and the ending point (city center user area) of the abnormal transmission route; then, the system applies an intelligent algorithm to search for potential alternative routes in the pipeline distribution map, and finally finds a new route passing through the edge of the city. The pipeline material and diameter of this route meet the technical requirements, and the pressure loss and flow limit are within acceptable ranges.

[0097] The system adjusted the original natural gas transmission route based on the selected alternative path; it recalculated the pipeline parameters on the new route and ensured the stability of overall transmission efficiency; then, it updated the pipeline distribution map to incorporate the new transmission route information; finally, it generated a new natural gas transmission route report, showing the new transmission route, relevant pipeline parameters, and the updated pipeline distribution map. This example demonstrates the importance of step S153 in natural gas transmission network management. The system can automatically identify and determine alternative transmission routes, while autonomously synthesizing and dynamically updating natural gas transmission routes to ensure the stability and security of natural gas supply. This not only improves the reliability and flexibility of the natural gas transmission network but also reduces the cost and risk of manual intervention.

[0098] In some embodiments of this application, it is assumed that there is a natural gas transmission network, which includes multiple pipelines and several key gas source stations and user areas; the system detects an abnormal transmission path from gas source station A to user area B because a section of the pipeline on this path needs maintenance; an abnormal path matching table is collected, as shown in Table 4: Table 4. Abnormal Path Matching Table abnormal path Alternative paths Synthesis steps Gas source station A - user area B (original route) Gas source station A - Transfer station C - User area B 1. Close the valves on the original path; 2. Open the connecting valve at transfer station C; 3. Adjust the flow control parameters at transfer station C. Based on the abnormal path matching table, the system quickly finds an alternative path from gas source station A to user area B, which is the path through transfer station C. Then, the system operates according to the synthesis steps, closing the valves on the original path, opening the connection valves of transfer station C, and adjusting the flow control parameters to ensure that the new delivery path can work normally.

[0099] Please see Figure 7 , Figure 7 This is a schematic diagram of the structural composition of a natural gas pipeline fault detection system according to an embodiment of the present invention; the natural gas pipeline fault detection system includes: Pipeline area module 21 is used to collect pipeline distribution maps of natural gas pipelines and determine multiple pipeline areas based on the pipeline distribution maps and natural gas pipeline transportation instructions. The pressure parameter module 22 is used to collect corresponding pressure parameters based on multiple pressure detection points in each pipeline area and in the sub-natural gas transmission path of the pipeline area. The pipeline fault event module 23 is used to determine the fault area of ​​the pipeline region based on the sub-natural gas transmission path, various pressure parameters and the changes of two adjacent pressure parameters, and to determine the corresponding pipeline fault event based on the identification of the fault area. The pipeline control measures module 24 is used to collect multiple pipeline fault events and determine the pipeline control measures for the natural gas pipeline based on the fault level of the multiple pipeline fault events, the location of the pipeline fault events and the current working status of the natural gas pipeline. The path update module 25 is used to trigger the pipeline status signal of the natural gas pipeline based on pipeline control measures, and close the corresponding pipeline area according to the pipeline status signal to dynamically update the natural gas transmission path of the natural gas pipeline.

[0100] The technical features of the above embodiments can be combined arbitrarily. For the sake of brevity, not all combinations of the technical features in the above embodiments are described. However, as long as there is no contradiction in the combination of these technical features, they should be considered to be within the scope of this specification.

Claims

1. A method for fault detection in a natural gas pipeline, characterized in that, include: Collect pipeline distribution maps of natural gas pipelines, and determine multiple pipeline areas based on the pipeline distribution maps and natural gas pipeline transportation instructions; In each pipeline region, multiple pressure detection points are set up along the sub-natural gas transmission path of the pipeline region, and corresponding pressure parameters are collected based on multiple pressure detection points; The fault areas of the pipeline region are determined based on the sub-natural gas transmission path, the changes of various pressure parameters and two adjacent pressure parameters, and the corresponding pipeline fault events are determined based on the identification of the fault areas. Collect multiple pipeline failure events and determine pipeline control measures for natural gas pipelines based on the failure level, location, and current operating status of the natural gas pipelines. The pipeline status signal of the natural gas pipeline is triggered by pipeline control measures, and the corresponding pipeline area is closed according to the pipeline status signal to dynamically update the natural gas transmission path of the natural gas pipeline.

2. The fault detection method for natural gas pipelines according to claim 1, characterized in that, The method involves collecting a pipeline distribution map of the natural gas pipelines and determining multiple pipeline areas based on the pipeline distribution map and the natural gas pipeline transportation instructions, including: The location of natural gas pipelines is collected, and a pipeline distribution map is determined based on the tracing of the natural gas pipeline locations. The pipeline path of the natural gas pipeline is determined based on the traversal of the pipeline distribution map. The main pipeline route and multiple branch pipeline routes are determined based on the division of the natural gas pipeline route, and multiple natural gas transmission routes are determined based on the main pipeline route and multiple branch pipeline routes. The system collects the natural gas pipeline transportation instructions, determines the natural gas transportation target based on the parsing of the natural gas pipeline transportation instructions, and determines multiple pipeline regions based on the matching of the natural gas transportation target and multiple natural gas transportation paths. At this time, natural gas is transported sequentially along multiple pipeline regions.

3. The fault detection method for natural gas pipelines according to claim 1, characterized in that, In each pipeline region, multiple pressure detection points are set up along the sub-natural gas transmission path within the pipeline region, and corresponding pressure parameters are collected based on these multiple pressure detection points, including: Real-time monitoring of each pipeline area, and determination of the corresponding sub-natural gas transmission path based on the autonomous detection of each pipeline area; In each sub-natural gas transmission path, multiple pressure detection points are determined based on the path length of the sub-natural gas transmission path, the shape of the pipeline area, and the corresponding natural gas transmission volume. At this time, multiple pressure detection points are distributed in different locations within the same pipeline area. The system monitors multiple pressure detection points in real time, collects corresponding parameter sets based on online detection of multiple pressure detection points, and determines the corresponding pressure parameters by traversing the parameter sets.

4. The fault detection method for natural gas pipelines according to claim 1, characterized in that, The process of determining the pipeline fault area based on the sub-natural gas transmission path, various pressure parameters, and the changes in two adjacent pressure parameters, and determining the corresponding pipeline fault event based on the identification of the fault area, includes: In each sub-natural gas transmission path, pressure parameters corresponding to multiple pressure detection points are collected, and the change in two adjacent pressure parameters is determined by comparing the two adjacent pressure parameters. The first sub-fault area is determined based on the location of the natural gas transmission path and the pressure parameters corresponding to multiple pressure detection points. The second sub-fault area is determined based on the location of the natural gas transmission path and the change in two adjacent pressure parameters.

5. The fault detection method for natural gas pipelines according to claim 4, characterized in that, The method of determining the fault area of ​​the pipeline region based on the sub-natural gas transmission path, the changes in various pressure parameters and two adjacent pressure parameters, and determining the corresponding pipeline fault event based on the identification of the fault area, further includes: In each pipeline region, the fault region of the pipeline region is determined by the combination of the first sub-fault region and the second sub-fault region. The corresponding fault identification logic is determined according to the regional location and regional shape of the pipeline region and the natural gas pipeline database. The corresponding pipeline fault event is determined by matching the fault identification logic with the fault region.

6. The fault detection method for natural gas pipelines according to claim 1, characterized in that, The process involves collecting multiple pipeline fault events and determining pipeline control measures based on the fault level, location, and current operating status of the natural gas pipeline. This includes: Multiple pipeline failure events were introduced. Based on the tracing of each pipeline failure event, the corresponding failure content was determined. The corresponding failure level was determined according to the failure content, the location of the pipeline area, and the type of natural gas transported by the natural gas pipeline.

7. The fault detection method for natural gas pipelines according to claim 6, characterized in that, The process of collecting multiple pipeline fault events and determining pipeline control measures for the natural gas pipeline based on the fault level, location, and current operating status of the natural gas pipeline also includes: The location of pipeline failure events is marked, and the first control measure is determined based on the failure level of multiple pipeline failure events and the location of the pipeline failure events; the second control measure is determined based on the failure level of multiple pipeline failure events and the current operating status of the natural gas pipeline. The pipeline control measures for natural gas pipelines are determined based on the first control measure, the second control measure, and the mapping relationship between the measures. At this time, the pipeline control measures include pipeline opening and closing measures, pipeline maintenance measures, and pipeline speed limiting measures for natural gas.

8. The fault detection method for natural gas pipelines according to claim 1, characterized in that, The method of triggering pipeline status signals based on pipeline control measures and closing corresponding pipeline areas according to the pipeline status signals to dynamically update the natural gas transmission path of the natural gas pipeline includes: The system monitors pipeline control measures in real time and outputs pipeline status signals for natural gas pipelines based on the execution of these measures. It then determines the corresponding pipeline area based on the analysis of the pipeline status signals and implements closure measures for the pipeline area, marking the closure of that area with a closure symbol.

9. The fault detection method for natural gas pipelines according to claim 8, characterized in that, The method of triggering pipeline status signals based on pipeline control measures and closing corresponding pipeline areas according to the pipeline status signals to dynamically update the natural gas transmission path of the natural gas pipeline also includes: The corresponding sub-natural gas transmission path is defined as an abnormal transmission path based on the closure mark of the pipeline area; Based on the abnormal transport path and the pipeline distribution map of the natural gas pipeline, alternative transport paths are determined; the natural gas transport path of the natural gas pipeline is dynamically updated based on the autonomous synthesis of the alternative transport paths, the remaining sub-natural gas transport paths, and the pipeline distribution map.

10. A fault detection system for a natural gas pipeline, characterized in that, The fault detection system for the natural gas pipeline is applied to the fault detection method for the natural gas pipeline as described in any one of claims 1-9, and the fault detection system for the natural gas pipeline includes: The pipeline area module is used to collect pipeline distribution maps of natural gas pipelines and determine multiple pipeline areas based on the pipeline distribution maps and natural gas pipeline transportation instructions. The pressure parameter module is used to collect corresponding pressure parameters based on multiple pressure detection points in each pipeline area and the sub-natural gas transmission path of the pipeline area. The pipeline fault event module is used to determine the fault area of ​​the pipeline region based on the sub-natural gas transmission path, various pressure parameters and the changes of two adjacent pressure parameters, and to determine the corresponding pipeline fault event based on the identification of the fault area; The pipeline control measures module is used to collect multiple pipeline fault events and determine pipeline control measures for the natural gas pipeline based on the fault level of the multiple pipeline fault events, the location of the pipeline fault events, and the current operating status of the natural gas pipeline. The path update module is used to trigger the pipeline status signal of the natural gas pipeline based on pipeline control measures, and close the corresponding pipeline area according to the pipeline status signal to dynamically update the natural gas transmission path of the natural gas pipeline.

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