A method and system for optimizing leakage monitoring points in a gathering and transportation pipeline

Abstract

The present invention discloses a method and system for optimizing leakage monitoring points in gathering and transportation pipelines. The method comprises: dividing the gathering and transportation pipeline network of a high-sulfur natural gas field into multiple pipelines; evaluating each pipeline's risk of corrosion due to liquid accumulation, geological disasters, and third-party sabotage; estimating the leakage volume of pipelines with at least one of these risks based on the actual operating conditions of the different pipelines, thereby obtaining the corresponding failure leakage pattern; and locating leakage monitoring points within the failed pipelines based on the leakage pattern of the failed pipelines and the population distribution characteristics surrounding the corresponding pipelines. The present invention can enhance the targeted nature of leakage monitoring and effectively improve the effectiveness of pipeline leakage monitoring.

Description

Technical Field

[0001] The present invention relates to the technical field of gathering and transportation pipeline leakage monitoring, and in particular to a method and system for optimizing gathering and transportation pipeline leakage monitoring points. Background Art

[0002] In recent years, as environmental pollution in my country has intensified and garnered widespread attention, natural gas, as a clean, environmentally friendly, and high-quality energy source, has gradually assumed a crucial position in my country's energy mix. Consumption has also continued to rise significantly, leading to the continuous expansion of the natural gas pipeline network. Gas field gathering and transmission pipelines, long-distance natural gas transmission pipelines, and urban natural gas pipelines have formed a "trunk interconnected, localized network" structure, totaling over one million kilometers. As pipeline operation continues, natural gas leaks caused by factors such as pipeline corrosion, wear, terrain subsidence, and third-party sabotage are becoming increasingly common. If leaks are not promptly detected and properly addressed, they can easily cause fires or explosions, posing a significant threat to business safety, production, life, and property. As my country continues to intensify its efforts in natural gas exploration and development, high-hydrogen sulfide gas fields are also being developed and utilized. Statistics show that high-sulfur gas fields are primarily located in the Sichuan and Chongqing regions, which are densely populated and face complex terrain. Compared to ordinary natural gas, high-sulfur gas generally contains 5% to 15% hydrogen sulfide. Due to its highly toxic nature, leaks during extraction, gathering, transportation, and processing can have serious consequences. Therefore, timely and accurate detection of leaks and identification of leak points are crucial for the safe gathering and transportation of (high-sulfur) natural gas.

[0003] Currently, numerous leak monitoring methods are used in oil and gas pipelines in my country, with diverse classification methods. These methods are primarily categorized based on the parameters being monitored, including mass / volume balance, applied statistics, negative pressure wave, transient model, distributed fiber optic, and acoustic wave. However, these traditional monitoring methods are primarily deployed along the entire pipeline. Specifically, the mass / volume balance method uses embedded pressure / flow sensors installed along the entire pipeline, while the distributed fiber optic method uses optical fibers laid in the same trench as the pipeline. The acoustic wave method uses embedded acoustic wave sensors installed along the entire pipeline. Under these deployment methods, the accuracy of these monitoring methods is significantly affected by the density of sensor placement. To achieve high-precision monitoring, the density of sensors must be increased, which is costly. Deploying high-precision monitoring methods throughout low-risk areas increases costs and wastes resources. Therefore, it is crucial to develop a method for selecting and applying leak monitoring points for gathering and transportation pipelines in highly sour gas fields.

[0004] Prior art CN111578154A discloses a method for optimizing the placement of multiple leak pressure sensors in a water supply network based on LSDR-JMI. This method uses pressure sensors to initially measure pressure under leak-free conditions to form a pressure matrix. It then uses pressure sensors to initially measure pressure under leak conditions to form an abnormal pressure matrix. A pressure sensitivity matrix is ​​constructed based on the pressure matrix and the abnormal pressure matrix. The clustering results are used as pseudo-labels L corresponding to the pressure sensitivity matrix. The complete label space Y is converted into a sub-label space using the LSDR method. The mutual information-based Group-JMI method is used to reduce the dimensionality of the label space Y, which is then calculated using the LSDR-JMI feature selection method.

[0005] Prior art CN105975702A discloses a method for optimizing the placement of sensors for cable-stayed bridge health monitoring. This method includes the following steps: deriving a node degree of freedom damage information index containing damage information for all beam segments based on the correlation between the damage factors and the node degree of freedom mode shapes of all beam segments of the cable-stayed bridge; sorting the node degree of freedom damage information indexes according to the amount of damage information included; and processing the sorted node degree of freedom damage information indexes using a sensor optimization placement method based on modal observability to determine the placement of sensors.

[0006] Prior art CN113139584A provides a sensor optimization layout method for identifying contamination intrusion points in water supply networks. This method first assesses the risk of contamination intrusion nodes and selects and clusters them. Using a hierarchical algorithm, a set of sensor layout schemes is derived to ensure the identifiability of the sensor network. Next, the optimal solution is determined by comparing the number of sensors and the impact of sensor failures on the sensor network. This comparison takes into account variations in contamination probability.

[0007] Therefore, in the existing leakage monitoring technology for high-sulfur gas field gathering and transportation pipelines, except for distributed optical fiber monitoring which is laid in the same trench on the front line, the deployment of other sensors is based on the distribution distance (i.e., monitoring points). The monitoring points are not selected in combination with the risks and actual operating conditions of the high-sulfur gas field, which may lead to the monitoring system being less targeted and / or having blind spots.

[0008] In summary, the existing technology needs to establish a leakage monitoring pipe section and point optimization scheme for high-sulfur natural gas gathering and transportation pipelines that conforms to the actual pipeline operation conditions. This is crucial to ensuring the safe and stable operation of high-sulfur gas fields. Summary of the Invention

[0009] The purpose of the present invention is to provide an optimal solution for leakage monitoring pipe sections and points for high-sulfur natural gas gathering and transportation pipelines, so as to solve the problem that the sensor layout points (i.e., monitoring points) of the current high-sulfur gas field leakage monitoring system are not combined with the actual risks and operating conditions of the pipeline, resulting in insufficient leakage monitoring coverage and targeting.

[0010] In order to solve the above technical problems, an embodiment of the present invention provides a method for optimizing leakage monitoring points in gathering and transportation pipelines, including: dividing the gathering and transportation pipeline network of a high-sulfur natural gas field into multiple pipelines; evaluating the pipeline liquid corrosion risk, geological disaster risk, and third-party damage risk of each pipeline separately; estimating the leakage volume of pipelines with at least one risk based on the actual operating conditions of different pipelines, thereby obtaining the corresponding failure leakage pattern; and locating the leakage monitoring point in the failed pipeline based on the leakage pattern of the failed pipeline and the population distribution characteristics around the corresponding pipeline.

[0011] Preferably, each pipeline is divided into multiple straight sections with elbows as nodes, and the pipeline liquid corrosion risk, geological disaster risk and third-party damage risk of each straight section in each pipeline are evaluated separately, including: calculating the critical liquid accumulation inclination angle of the current pipeline according to the current pipeline diameter, pipe flow velocity, pipe temperature and pipeline water content, based on this, combined with the pipeline inclination angle of each straight section, evaluating whether the current pipeline has the risk of pipeline liquid corrosion; evaluating the disaster level of multiple geological disasters in each straight section in the current pipeline separately, based on In this way, an evaluation is completed on whether the current pipeline has geological disaster risks, wherein the multiple geological disasters include but are not limited to landslides, collapses, mudslides and river water damage; multiple destructive factors of each straight pipe section in the current pipeline are scored respectively, and then an evaluation is made on whether the current pipeline has third-party damage risks based on the scoring results of various factors of each straight pipe section, wherein the multiple destructive factors include but are not limited to pipeline burial depth, daily inspection frequency, pipeline identification position, abnormal movement level above the pipeline, communication status and intrusion monitoring method.

[0012] Preferably, in the process of determining whether the current pipeline has the risk of pipeline liquid accumulation corrosion, it includes: comparing the pipeline inclination angle of each straight pipe section with the critical liquid accumulation inclination angle of the current pipeline; when the pipeline inclination angle of the straight pipe section does not exceed the critical liquid accumulation inclination angle of the current pipeline, it is determined that the current straight pipe section does not have the risk of liquid accumulation corrosion, otherwise it does; if there is a straight pipe section with the risk of liquid accumulation corrosion in the current pipeline, then the current pipeline has the risk of pipeline liquid accumulation corrosion, or if there is no straight pipe section with the risk of liquid accumulation corrosion in the current pipeline, then the current pipeline does not have the risk of pipeline liquid accumulation corrosion.

[0013] Preferably, the disaster levels of various geological hazards are divided into level one, level two and level three according to the severity from high to low. In the process of determining whether there is a geological hazard risk in the current pipeline, it includes: judging whether there is a geological hazard with a geological hazard level of level one in each straight pipe section; when there is a straight pipe section with a level one geological hazard item in the current pipeline, determining that there is a geological hazard risk in the current pipeline, or when there is no straight pipe section with a level one geological hazard item in the current pipeline, determining that there is no geological hazard risk in the current pipeline.

[0014] Preferably, in the process of determining whether there is a third-party damage risk in the current pipeline, the process includes: calculating the total score of the scoring results of various damage factors corresponding to each straight pipe section, and comparing the total score of each factor of each straight pipe section with a preset score evaluation threshold. When there is a straight pipe section in the current pipeline whose total score of various damage factors exceeds the said score evaluation threshold, it is determined that there is a third-party damage risk in the current pipeline; or when there is no straight pipe section in the current pipeline whose total score of various damage factors exceeds the said score evaluation threshold, it is determined that there is no third-party damage risk in the current pipeline.

[0015] Preferably, in the step of estimating the leakage amount of a pipeline with at least one risk based on the actual operating conditions of different pipelines, the step includes: determining the leakage size of the current pipeline based on the risk type of the current pipeline, the leakage size including the leakage shape, leakage area and leakage scale; calculating the leakage rate of the medium in the current pipeline based on the comparison result combined with the leakage area by comparing the pressure of the straight pipe section at the risk position in the current pipeline with the gas critical pressure reference threshold; determining the leakage duration of the medium in the current pipeline; calculating the theoretical value of gas leakage in the pipeline with at least one risk based on the medium leakage rate and the leakage duration, thereby estimating the actual gas leakage amount of the current pipeline by comparing the theoretical value of gas leakage with the total amount of all hydrogen sulfide gases in the current pipeline.

[0016] Preferably, in the process of determining the failure leakage mode, it includes: according to the actual gas leakage estimation result of the current risk pipeline, determining the hydrogen sulfide diffusion radius corresponding to the case where the leaked hydrogen sulfide concentration reaches a first concentration level and a second concentration level, wherein the first concentration level is higher than the second concentration level.

[0017] Preferably, in the step of locating the leakage monitoring point from the failed pipeline based on the predicted leakage pattern of the failed pipeline and the population distribution characteristics around the corresponding pipeline, the step includes: taking one of the end points of the risk straight pipe section in the current risk pipeline as the starting point, moving the center of the double circular area formed by the first hydrogen sulfide diffusion radius and the second hydrogen sulfide diffusion radius from the starting point to the other end point according to a preset step size, determining whether the population distribution state in the corresponding double circular area at each step meets the first condition, and thus counting the total pipeline length at the step position that meets the first condition in the current risk straight pipe section, which is recorded as the abnormal pipeline length, wherein the first condition is that the number of permanent residents in the circular area formed by the second hydrogen sulfide diffusion radius reaches a first number or the number of permanent residents in the circular area formed by the first hydrogen sulfide diffusion radius reaches a second number, wherein the second number is higher than the first number; and determining the leakage monitoring point according to the number of abnormal pipelines in the current risk pipeline and the length of each section of the abnormal pipeline.

[0018] Preferably, when the number of abnormal pipelines is 1 and the length of the current abnormal pipeline is greater than the first distance and less than the second distance, a leakage monitoring point is set at the center of the current abnormal pipeline, wherein the first distance is less than the second distance; when the number of abnormal pipelines is 1 and the length of the current abnormal pipeline is greater than or equal to the second distance and less than the third distance, leakage monitoring points are respectively set at both ends of the current abnormal pipeline, wherein the second distance is less than the third distance; when the number of abnormal pipelines is 1 and the length of the current abnormal pipeline is greater than or equal to the third distance, leakage monitoring points are respectively set at the center and both ends of the current abnormal pipeline; when the number of abnormal pipelines is multiple and the total length of the actual pipeline occupied by each section of the abnormal pipeline is less than or equal to the second distance, leakage monitoring points are respectively set at both ends of all abnormal pipelines in the current risk pipeline; when the number of abnormal pipelines is multiple and the total length of the actual pipeline occupied by each section of the abnormal pipeline is less than or equal to the third distance, leakage monitoring points are respectively set at the center and both ends of all abnormal pipelines in the current risk pipeline.

[0019] Preferably, the leakage duration is determined as follows: the leakage duration of the medium in the current pipeline is estimated based on the measurement accuracy level of the monitoring system equipped for the current risk pipeline and the automation control level of the cut-off system equipped for the current risk pipeline, combined with the leakage scale.

[0020] Preferably, the step of dividing the high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines includes: using the shut-off valve in the high-sulfur natural gas field gathering and transportation pipeline network as a dividing point to preliminarily divide the current pipeline network into multiple pipeline sections; if there are pipelines whose laying methods are different from those of buried pipelines, the current pipelines are further divided into multiple sections according to different laying types, thereby dividing the entire high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines, and the laying types include but are not limited to buried pipelines, tunnels and trusses.

[0021] On the other hand, an embodiment of the present invention provides a computer-readable storage medium comprising a series of instructions for executing the method steps as described above.

[0022] In addition, an embodiment of the present invention also provides a system for optimizing leakage monitoring points in gathering and transportation pipelines, including: a pipeline division module, which is configured to divide the pipeline network into multiple pipelines according to the shut-off valves of the gathering and transportation pipeline network of a high-sulfur natural gas field; a risk assessment module, which is configured to evaluate the pipeline liquid corrosion risk, geological disaster risk and third-party damage risk of each pipeline respectively; a leakage identification module, which is configured to estimate the leakage volume of pipelines with at least one risk based on the actual operating conditions of different pipelines, thereby obtaining a corresponding failure leakage pattern; a point confirmation module, which is configured to locate the leakage monitoring point from the failed pipeline based on the leakage pattern of the failed pipeline and the population distribution characteristics around the corresponding pipeline.

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

[0024] The present invention proposes a method and system for optimizing the location of leakage monitoring points in gathering and transportation pipelines. This method and system solves the problem of insufficient leakage monitoring coverage and pertinence, as existing high-sulfur gas field leakage monitoring systems fail to integrate sensor placement points (monitoring points) with the actual risks and operating conditions of the pipelines. By considering three key risks present in high-sulfur gas field gathering and transportation pipelines (liquid corrosion, geological disasters, and third-party sabotage), combined with actual operating conditions such as pressure, hydrogen sulfide content, and elevation, a pipeline failure leakage model is established, and a targeted optimization scheme for sensor placement pipe sections and points (monitoring points) is formulated. The present invention can enhance the pertinence of leakage monitoring and effectively improve the effectiveness of pipeline leakage monitoring.

[0025] Other features and advantages of the present invention will be described in the following description, and in part will become apparent from the description, or will be understood by practicing the present invention. The purposes and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0026] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0027] Figure 1 Schematic diagram of the steps of a method for optimizing leakage monitoring points in a gathering and transportation pipeline according to an embodiment of the present application.

[0028] Figure 2 This is a specific flow chart of the method for optimizing the leakage monitoring points of the gathering and transportation pipeline according to an embodiment of the present application.

[0029] Figure 3 This is an example diagram of the principle of pipeline segmentation processing in the method for optimizing the leakage monitoring points of the gathering and transportation pipeline according to an embodiment of the present application.

[0030] Figure 4 Schematic diagram of the effect of the movement of the double circular area in the method for optimizing the monitoring points for leakage of gathering and transportation pipelines according to an embodiment of the present application.

[0031] Figure 5 This is a schematic diagram of the principle of the point confirmation operation in the method for optimizing the gathering and transportation pipeline leakage monitoring points according to an embodiment of the present application.

[0032] Figure 6 This is an example diagram of pipeline segmentation processing in the second embodiment of the method for optimizing leakage monitoring points in a gathering and transportation pipeline according to an embodiment of the present application.

[0033] Figure 7 This is an example diagram of pipeline segmentation processing in the third embodiment of the method for optimizing leakage monitoring points in a gathering and transportation pipeline according to an embodiment of the present application.

[0034] Figure 8 This is an example diagram of the effect of the point confirmation operation in the fourth embodiment of the method for optimizing the gathering and transportation pipeline leakage monitoring points according to the embodiment of the present application.

[0035] Figure 9 This is an example diagram of the effect of the point confirmation operation in the fifth embodiment of the method for optimizing the gathering and transportation pipeline leakage monitoring points according to the embodiment of the present application.

[0036] Figure 10 This is a structural diagram of a system for optimizing leakage monitoring points in gathering and transportation pipelines according to an embodiment of the present application. DETAILED DESCRIPTION

[0037] The following describes the embodiments of the present invention in detail with reference to the accompanying drawings and examples, so that the present invention can fully understand how to apply technical means to solve technical problems and achieve technical effects, and thus implement the invention accordingly. It should be noted that, as long as no conflict exists, the various embodiments of the present invention and the various features of the embodiments can be combined with each other, and the resulting technical solutions are all within the scope of protection of the present invention.

[0038] In addition, the steps shown in the flowchart of the accompanying drawings can be executed in a computer system such as a set of computer executable instructions. Also, although a logical order is shown in the flowchart, in some cases, the steps shown or described can be performed in a different order than here.

[0039] The terms used herein are intended only to describe specific embodiments and are not intended to limit exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms "a", "an", "an item" used herein are also intended to include the plural. It should also be understood that the terms "comprise" and / or "include" used herein specify the presence of stated features, integers, steps, operations, units and / or components, and do not preclude the presence or addition of one or more other features, integers, steps, operations, units, components and / or combinations thereof.

[0040] In order to solve the technical problems in the above-mentioned background technology, the embodiments of the present application propose a method and system for optimizing the leakage monitoring points of the gathering and transportation pipeline. The method and system establish a pipeline failure leakage model by combining the three key risks of the gathering and transportation pipeline of high-sulfur gas fields (liquid corrosion, geological disasters, and third-party damage) with actual operating conditions such as pressure, hydrogen sulfide content, and elevation, and formulate a targeted sensor layout pipe section and point (monitoring point) optimization plan. The present invention enhances the pertinence of leakage monitoring and effectively improves the pipeline leakage monitoring effect.

[0041] my country's high-sulfur gas fields are mainly distributed in the Sichuan and Chongqing regions, which are characterized by complex terrain and dense populations. Gathering and transportation pipelines are mainly laid underground and through-and-over. To achieve the above-mentioned objectives of the present invention, the method and system for optimizing leakage monitoring points for gathering and transportation pipelines provided by the present invention are as follows.

[0042] Example 1

[0043] Figure 1 Schematic diagram of the steps of a method for optimizing leakage monitoring points in a gathering and transportation pipeline according to an embodiment of the present application. Figure 2 This is a specific flow chart of the method for optimizing the monitoring points of leakage in the gathering and transportation pipeline according to the embodiment of the present application. Figure 1 and Figure 2, the specific process of the method for optimizing the monitoring points for leakage in a gathering and transportation pipeline disclosed in an embodiment of the present invention (also referred to as the "monitoring point optimization method") is described.

[0044] Step S110: Divide the high-sulfur natural gas field gathering and transportation pipeline network into multiple (n) pipelines.

[0045] First, the existing high-sulfur natural gas field gathering and transportation pipeline network is initially divided into multiple pipeline segments, using the block valves (i.e., valve chambers) in the network as the dividing points. Then, if there are pipelines with different laying methods than buried pipelines, the existing pipelines are further divided into multiple pipeline segments according to different laying types, thus dividing the entire high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines. Laying types include but are not limited to buried pipelines, tunnels, and trusses.

[0046] Figure 3 This is an example diagram of the principle of pipeline segmentation processing in the method for optimizing the monitoring points of the gathering and transportation pipeline according to the embodiment of the present application. Figure 3 As shown, in step S110, the gathering and transportation network is first divided into n sections using the cut-off valves (valve chambers) of the high-sulfur gas field gathering and transportation network as the dividing points. For example, the gathering and transportation pipeline between two cut-off valves (valve chambers) is one line.

[0047] If a certain gathering and transportation pipeline contains sections with different laying methods such as tunnels and trusses from those of buried pipelines, such sections with different laying methods shall be listed as one separate route. Figure 3 As shown, if there is an unconnected tunnel pipeline section and a river-crossing truss pipeline section between the two valve chambers, the two valve chambers are divided into 5 sections.

[0048] Step S120: Evaluate the pipeline liquid corrosion risk, geological disaster risk, and third-party damage risk of each pipeline respectively.

[0049] In step S120, multiple risk assessments need to be performed on each pipeline one by one, and it is determined whether each pipeline has one or more of the above risk items.

[0050] In an embodiment of the present invention, each pipeline is divided into multiple straight sections with elbows as nodes, and the pipeline liquid corrosion risk, geological disaster risk and third-party damage risk of each straight section in each pipeline are evaluated separately.

[0051] Currently, my country's high-sulfur gas fields are primarily located in the Sichuan and Chongqing regions. Sour gas gathering and transmission pipelines from these fields operate in harsh conditions and complex external environments. The risk of H2S gas leaks and injuries from pipeline failures is high, and integrity management is challenging. Key risks include pipeline corrosion due to fluid accumulation, geological disasters, and third-party sabotage.

[0052] Pipeline liquid corrosion: The raw gas from high-sulfur gas fields generally contains highly corrosive substances such as H2S, CO2, elemental sulfur, and formation water. Due to the complex terrain and large height differences in the gathering and transportation pipeline network, liquid accumulation occurs in pipelines in low-lying areas, which makes it easy for corrosion perforation to occur in the pipe wall.

[0053] Geological disasters: Geological disasters occur frequently in the Sichuan-Chongqing region. The areas where high-sulfur gas fields are located have complex terrain and numerous gullies. The rainfall during the flood season is heavy, making them prone to geological disasters such as landslides and mud-rock flows, which may cause the acid gas gathering and transmission pipelines to rupture.

[0054] Third-party damage: The region is densely populated and relatively concentrated, and the layout of acid gas gathering and transmission pipelines is scattered. They may pass through farmland, villages, roads, etc., and face many pipeline damage risks such as farming excavation, vehicle crushing, and third-party construction.

[0055] Therefore, each pipeline needs to use elbows as nodes to identify and analyze the above three risks. Since the three risk assessment methods for each pipeline are similar, this invention uses one pipeline as an example to illustrate the three risk identification and analysis processes.

[0056] First, the critical liquid accumulation angle θ0 of the current pipeline is calculated based on the current pipeline diameter, pipe flow velocity, pipe temperature and pipe water content. Then, based on the critical liquid accumulation angle, the pipeline inclination angle θ of each straight pipe section (i-th straight pipe section, i represents the serial number of the divided straight pipe section) is calculated. i , evaluate whether there is a risk of pipeline liquid accumulation and corrosion in the current pipeline.

[0057] The critical liquid accumulation angle θ0 of the current pipeline is calculated using the following expression:

[0058]

[0059]

[0060]

[0061]

[0062] Where θ0 represents the critical effusion angle; ρ g Indicates the average density of high-sulfur natural gas in kg / m 3 ρ l Indicates the average density of water produced from gas wells, in kg / m 3 ; g represents the acceleration due to gravity (9.81m / s 2 );D i Indicates the inner diameter of the pipe, in mm; H p Indicates the pipe flow velocity in m / s; Q p Indicates the flow rate at standard temperature and pressure, in m / s2 ;M W represents the molecular mass of the gas in kg / mol; R represents the ideal gas constant; Z represents the compressibility factor; P represents the gas pressure; and T represents the gas temperature.

[0063] In the process of determining whether there is a risk of corrosion due to liquid accumulation in the current pipeline, the following steps are included: i The straight pipe sections are compared with the critical liquid accumulation inclination angle θ0 of the current pipeline respectively. When the pipeline inclination angle of the straight pipe section does not exceed the critical liquid accumulation inclination angle of the current pipeline, it is determined that the current straight pipe section does not have the risk of liquid accumulation corrosion. When the pipeline inclination angle of the straight pipe section reaches or exceeds the critical liquid accumulation inclination angle of the current pipeline, it is determined that the current straight pipe section has the risk of liquid accumulation corrosion. Then, if there is a straight pipe section with the risk of liquid accumulation corrosion in the current pipeline, the current pipeline has the risk of pipeline liquid accumulation corrosion (unacceptable), or if there is no straight pipe section with the risk of liquid accumulation corrosion in the current pipeline, the current pipeline does not have the risk of pipeline liquid accumulation corrosion (acceptable).

[0064] Each straight pipe section in the current pipeline satisfies θ i <θ0, the corresponding pipe section will not be corroded by liquid accumulation. At this time, there is no risk of perforation caused by liquid accumulation in the current pipeline. When one or more sections meet the θ i When the straight pipe section does not meet the condition of ≥θ0, the corresponding pipe section has the risk of corrosion perforation due to liquid accumulation. At this time, the current pipeline has the risk of corrosion perforation due to liquid accumulation.

[0065] Then, the hazard levels of multiple geological hazards in each straight section of the current pipeline are evaluated. Based on the evaluation results of the multiple geological hazard levels of each straight section, an assessment is completed to determine whether the current pipeline is at risk of geological hazards. In this embodiment of the present invention, the multiple geological hazards include, but are not limited to, landslides, collapses, debris flows, and river and channel flooding.

[0066] In the embodiment of the present invention, the disaster levels of various geological disasters are divided into level one, level two and level three according to the severity from high to low.

[0067] Furthermore, in the process of determining whether there is a geological hazard risk in the current pipeline, it includes: first determining whether there is a geological hazard with a geological hazard level of one in each straight pipe section; then, when there is a straight pipe section with a first-level geological hazard item in the current pipeline, determining that there is a geological hazard risk in the current pipeline (unacceptable), or when there is no straight pipe section with a first-level geological hazard item in the current pipeline, determining that there is no geological hazard risk in the current pipeline (acceptable).

[0068] For high-sulfur gas fields, the primary geological hazards are landslides, collapses, debris flows, and river and channel flooding. Therefore, the present invention primarily uses these four types of geological hazards as the evaluation basis and grades the susceptibility of each hazard (with level 1 being the most susceptible). Table 1 shows the criteria for determining the hazard level of each hazard.

[0069] In one embodiment, when the single or multiple geological hazard susceptibility levels at the location of a straight pipe section are at the highest level (level 1), it is considered that the current pipeline has a geological hazard risk.

[0070] In another embodiment, when there is no geological disaster with the highest level (level 1) of susceptibility at the location of each straight pipe section in the current pipeline, it is considered that there is no geological disaster risk in the current pipeline.

[0071] Table 1 The basis for judging the disaster level of various geological disasters

[0072]

[0073]

[0074]

[0075] As shown in Table 1, the disaster level of each geological disaster can be determined based on meeting all the conditions in the corresponding level classification basis.

[0076] Finally, each straight section of the pipeline is scored for multiple destructive factors. Based on the scores for each factor, the pipeline's risk of third-party destructive activity is assessed. In this embodiment of the present invention, these destructive factors include, but are not limited to, pipeline depth, frequency of routine inspections, pipeline marker location, level of disturbance above the pipeline, communication status, and intrusion monitoring methods.

[0077] Furthermore, in the process of determining whether the current pipeline has a third-party damage risk, the process includes: calculating the total score of the scoring results of various damage factors corresponding to each straight pipe section; then, comparing the total score of each factor of each straight pipe section with a preset score evaluation threshold, so as to determine whether the current pipeline has a third-party damage risk based on the comparison result.

[0078] If there is a straight pipe section in the current pipeline where the total score of all damage factors exceeds the score evaluation threshold (for example, 20 points), the current pipeline is determined to have a third-party damage risk. Alternatively, if there is no straight pipe section in the current pipeline where the total score of all damage factors exceeds the score evaluation threshold, the current pipeline is determined to have no third-party damage risk.

[0079] For high-sulfur gas fields, the main third-party risks to pipelines are damage from local farmers farming and damage from large-scale excavation machinery by third parties. Therefore, this embodiment of the present invention proposes a third-party damage risk assessment method, as shown in Table 2 below. Table 2 shows the scores for various damage factors at different levels of damage.

[0080] Table 2 Scoring of different damage levels of various damage factors

[0081]

[0082]

[0083] As shown in Table 2, the scoring result for each damage factor can be determined based on the actual conditions of the corresponding straight pipe section, including the pipeline depth, daily inspection frequency, pipeline marking location, abnormal movement level above the pipeline, communication status, and intrusion monitoring method. By summing the scores of the six factors based on the actual conditions, a total score representing the third-party damage risk assessment result for the current straight pipe section (i.e., the total score of each factor) is obtained.

[0084] For example, the scores of the six evaluation items are added together. When the total score is less than 20, it is considered that the current pipeline does not have the risk of third-party damage (acceptable, which means that there is no third-party damage risk); when the total score reaches or exceeds 20, it is considered that the current pipeline has the risk of third-party damage (unacceptable, which means that the current pipeline is considered to have a large third-party damage risk).

[0085] After risk assessment, if all three risks are within the acceptable range, the next section of the pipeline will be analyzed. If one or more risks are not within the acceptable range, a judgment will be made based on the operating conditions of the pipeline and a survey of the surrounding population.

[0086] In this embodiment of the present invention, if the current pipeline does not have any risk of pipeline fluid accumulation corrosion, geological disaster risk, or third-party sabotage risk, then there is no need to set monitoring points for the current pipeline. On the other hand, if the current pipeline has one or more of the risks of pipeline fluid accumulation corrosion, geological disaster risk, and third-party sabotage risk, then it is necessary to set monitoring points for the current pipeline, and the process proceeds to step S130.

[0087] Step S130: Based on the actual operating conditions of different pipelines, the leakage amount of the (risky) pipeline with at least one risk is estimated, so as to obtain a corresponding failure leakage mode according to the estimated leakage amount.

[0088] In step S130, first, the leakage size of the current pipeline is determined according to the risk type of the current pipeline, wherein the leakage size includes leakage form, leakage area and leakage scale.

[0089] Since the outer diameter of existing high-sour gas field gathering and transportation pipelines generally ranges from 168.3 mm to 329.9 mm, the leakage size determination for the three failure modes of pipeline liquid corrosion, geological disasters, and third-party damage is shown in Table 3. Table 3 shows the leakage size corresponding to different risks.

[0090] Table 3 Leakage size at different risks

[0091]

[0092] Then, by comparing the pressure of the risky straight pipe section in the current pipeline with the gas critical pressure reference threshold, the leakage rate of the medium in the current pipeline is calculated based on the comparison result and the leakage area.

[0093] Specifically, for high-sulfur natural gas (gas medium), the leakage rate W of the gas medium is calculated as follows: g :

[0094] First calculate the critical pressure P of the gas according to the following expression trans :

[0095]

[0096] in, Ideal gas specific heat capacity (adiabatic index), dimensionless; P trans Indicates the critical pressure of gas, in MPa; P a Indicates standard atmospheric pressure, unit is MPa; C P The specific heat of an ideal gas at constant pressure, in J·g -1 / K;C V The constant product specific heat of an ideal gas, in J·g -1 / K.

[0097] In one embodiment, if the current pipeline gas pressure P is less than the gas critical pressure reference threshold P trans , that is, P <P trans , then the medium leakage rate W g Calculated using the following expression:

[0098]

[0099] Among them, W g Indicates the leakage rate of the medium, in kg / s; C d Indicates the leakage coefficient, usually 0.85; S k Indicates the leakage area in mm 2 , S can be conservatively taken kCalculate the cross-sectional area of ​​the pipe, but the maximum shall not exceed 129717mm 2 ; P represents the medium operating pressure, the unit is MPa; R represents the gas constant, usually 8.314J mol -1 K -1 ;g c represents the conversion coefficient, which is usually 32.2; M represents the molar mass of the medium, in g / mol; T represents the operating temperature of the medium, in K.

[0100] If P ≥ P trans , then the medium leakage rate W g Calculate as follows:

[0101]

[0102] Next, the leakage duration t of the medium in the current pipeline is determined.

[0103] In actual applications, the duration of a leak can be determined based on the actual conditions of the risk pipeline being assessed. If this cannot be determined based on the actual conditions, the duration of the medium leak in the current pipeline, t, can be estimated based on the measurement accuracy level of the monitoring system equipped for the current risk pipeline (as shown in Table 4), the automation control level of the shutoff system equipped for the current risk pipeline (as shown in Table 5), and the scale of the leak. Parameters are shown in Table 5.

[0104] In the embodiment of the present invention, Table 4 shows the measurement accuracy levels corresponding to the types of monitoring systems equipped for different risk pipelines. The corresponding monitoring system measurement accuracy level can be determined according to the type of monitoring system equipped for the current risk pipeline.

[0105] Table 4 Monitoring system levels

[0106] Target pipe section monitoring system type grade Special equipment for monitoring changes in key parameters and indirectly monitoring media loss A Sensitive detectors that directly monitor actual medium loss B Visual inspection, camera, fixed hydrogen sulfide probe, etc. C

[0107] As shown in Table 4, the embodiment of the present invention divides the measurement accuracy levels corresponding to the monitoring system types into three levels: A, B, and C, from high to low, according to the measurement accuracy of the monitoring system.

[0108] In this embodiment of the present invention, Table 5 shows the automation control levels corresponding to the types of cut-off or venting systems equipped for different risk pipelines. The automation control level of the corresponding cut-off or venting system can be determined based on the type of cut-off or venting system equipped for the current risk pipeline.

[0109] Table 5 Shutoff / vent system levels

[0110] Target pipe segment cutting system type grade Automatic shut-off / venting devices activated by monitoring equipment or detectors A The operator manually cuts off / vents the device in the operating room or other locations far away from the leak point B Manually operated shut-off and vent valves C

[0111] As shown in Table 5, the embodiment of the present invention divides the automation control levels corresponding to the types of cut-off / venting systems into three levels: A, B, and C, from high to low, according to the automation control levels of the cut-off / venting systems.

[0112] Finally, the embodiment of the present invention can estimate the leakage time based on the measurement accuracy level of the monitoring system equipped for the current risk pipeline, the automation control level of the cut-off system equipped for the current risk pipeline, and the leakage scale of the risk type of the current risk pipeline, see Table 6. Table 6 shows the leakage time estimation results

[0113] Table 6 Leakage time estimation

[0114]

[0115] It should be noted that, in the embodiment of the present invention, referring to Table 3, small scale means that the leakage area is less than 100mm 2 Medium / large scale refers to leakage area of ​​100~1000mm 2 , super-large-scale leakage refers to leakage area greater than 1000mm 2 .

[0116] Finally, the embodiment of the present invention also calculates the theoretical value of gas leakage (Wg×t) in the pipeline currently having at least one risk based on the medium leakage rate and leakage duration (estimated leakage time) calculated above, thereby estimating the actual gas leakage amount of the current pipeline by comparing the theoretical value of gas leakage with the total amount of all hydrogen sulfide gas in the current pipeline.

[0117] In one embodiment, the minimum value of the theoretical gas leakage value and the total amount of all hydrogen sulfide gases in the current pipeline is obtained as the estimated actual gas leakage amount of the current pipeline.

[0118] Specifically, the gas leakage Q of the gathering and transportation pipeline of a high-sulfur gas field is estimated using the following expression:

[0119] Q = min(Wg × t, q) (8)

[0120] Where q represents the total amount of hydrogen sulfide gas in the pipeline between the two block valves;

[0121] It should also be noted that for extremely large-scale pipeline leaks caused by geological disasters, the duration of the leak does not need to be considered. If a pipeline rupture accident occurs due to a geological disaster, the leakage volume is directly estimated as the total gas in the pipeline between the two shut-off valves as the actual gas leakage volume. In other words, the total amount of all gas in the pipeline at risk is used as the estimated actual gas leakage volume of the current pipeline.

[0122] Continue to refer Figure 2 In step S130, after the leakage amount of each risk pipeline (failed pipeline) is estimated, the corresponding failure leakage mode is determined for each failed pipeline.

[0123] Specifically, based on the actual gas leakage estimation result of the current risk pipeline (failed pipeline), a first hydrogen sulfide diffusion radius corresponding to when the leaked hydrogen sulfide concentration reaches a first concentration level and a hydrogen sulfide diffusion radius corresponding to when the leaked hydrogen sulfide concentration reaches a second concentration level are determined, wherein the first concentration level is higher than the second concentration level.

[0124] The exposure radius (also called “leakage radius”) refers to the maximum dangerous distance from the release point when the hydrogen sulfide concentration at the release point reaches a certain level, determined based on dispersion calculations.

[0125] In the first embodiment, after diffusion, the concentration of hydrogen sulfide (H2S) at the release point reaches 100 ppm (i.e. 144 mg / m 3 ) is calculated using the following expression:

[0126] L1=(8.404MQ m ) 0.6258 (9)

[0127] In the second example, after diffusion, the concentration of hydrogen sulfide (H2S) at the release point reaches 500 ppm (i.e. 720 mg / m 3 ) is calculated using the following expression:

[0128] L2=(2.404MQ m ) 0.6258 (10)

[0129] Wherein, M represents the percentage (mol) of hydrogen sulfide (H2S) in the mixed gas medium; Q m Indicates the discharge volume under standard atmospheric pressure and 15.6℃, in m 3 ; L1 and L2 represent the first hydrogen sulfide diffusion radius (ROE) and the second hydrogen sulfide diffusion radius, respectively, in meters.

[0130] Therefore, after obtaining the corresponding diffusion radius of the risk pipeline (target pipeline) at different hydrogen sulfide levels (gas medium concentration in the pipeline), the process proceeds to step S140.

[0131] Step S140: Locate leakage monitoring points in the current failed pipeline based on the leakage pattern of the failed pipeline and the population distribution characteristics around the corresponding pipeline.

[0132] Based on the calculation results of step S130, a population survey is conducted on the areas within the distances L1 and L2 on both sides of the target pipeline (failed pipeline), with the exposure radius of 100 ppm hydrogen sulfide as L1 and the exposure radius of 500 ppm hydrogen sulfide as L2, to obtain the surrounding population situation along the target pipeline section. At the same time, semicircular areas with radii L1 and L2 at both ends of the target pipeline section are also included in the population survey area. Figure 4 shown.

[0133] Figure 4 This is a schematic diagram of the effect of the movement of the double circular area in the method for optimizing the monitoring point of the gathering and transportation pipeline in an embodiment of the present application. Figure 4 As shown, the embodiment of the present invention will first take one of the end points of the risk straight pipe section in the current risk pipeline as the starting point, and move the center of the double circular area formed by the first hydrogen sulfide diffusion radius and the second hydrogen sulfide diffusion radius (the center of the double circular area is located on the pipeline) from the current starting point (the center of the circle coincides with the starting point) to the other end point according to the preset step length, and determine whether the population distribution status in the corresponding double circular area at each step meets the preset first condition, so as to count the total pipeline length involved in the step position that meets the first condition in the current risk straight pipe section, and record it as the abnormal pipeline length.

[0134] In an embodiment of the present invention, the first condition is that the number of permanent residents within the circular area formed by the second hydrogen sulfide diffusion radius reaches a first number (e.g., 3 persons) or the number of permanent residents within the circular area formed by the first hydrogen sulfide diffusion radius reaches a second number (e.g., 30 persons), wherein the second number is greater than the first number.

[0135] Specifically, taking one end of the risky straight pipe section in the target pipe section (risky pipeline) as the starting point, a double circular area with radii L1 and L2 respectively is moved along the target pipeline to the other end point, so as to confirm the permanent population in the double circular area. When the population within the exposure radius of hydrogen sulfide 100ppm is greater than or equal to 30 people or the population within the exposure radius of hydrogen sulfide 500ppm is greater than or equal to 3 people, the monitoring point position can be confirmed (marked as an abnormal pipeline position), and the abnormal pipeline can be marked by counting the total length of the abnormal pipeline in the current risky straight pipe section.

[0136] In addition, if there is no abnormal pipeline in the current risk pipeline, there is no need to set up leakage monitoring points in the current risk pipeline.

[0137] Then, the leakage monitoring point is determined based on the number of abnormal pipelines in the current risk pipeline and the length of each abnormal pipeline.

[0138] Figure 5 This is a schematic diagram of the principle of the point confirmation operation in the method for optimizing the gathering and transportation pipeline leakage monitoring points according to an embodiment of the present application.

[0139] like Figure 5 As shown, in the first embodiment, when the number of abnormal pipes in the current pipeline is 1 and the length of the current abnormal pipe is greater than the first distance (for example, 30m) and less than the second distance (for example, 100m), a leakage monitoring point is set at the center of the current abnormal pipe (see Figure 5 (The triangle mark in the figure). The first distance is less than the second distance. Specifically, if, within a double-circular area within a certain continuous pipeline length on the target pipeline segment, the population within the 100 ppm hydrogen sulfide exposure radius is greater than or equal to 30 people, or the population within the 500 ppm hydrogen sulfide exposure radius is greater than or equal to 3 people, and if the continuous pipeline length is greater than 30 meters and less than 100 meters, a leakage monitoring point is set at the center of the continuous pipeline.

[0140] In the second embodiment, when the number of abnormal pipes in the current pipeline is 1 and the length of the current abnormal pipe is greater than or equal to the second distance and less than the third distance, leakage monitoring points are set at both ends of the current abnormal pipe (see Figure 5 (The triangle mark in the middle). The second distance is less than the third distance. Specifically, if, within a certain continuous pipeline length on the target pipeline segment, the double-circular area has a population of 30 or more within a 100 ppm hydrogen sulfide exposure radius or 3 or more within a 500 ppm hydrogen sulfide exposure radius, and if the continuous pipeline length is less than 300 meters, leakage monitoring points are set at both ends of the continuous pipeline.

[0141] In the third embodiment, when the number of abnormal pipes in the current pipeline is 1 and the length of the current abnormal pipe is greater than or equal to the third distance, leakage monitoring points are respectively set at the center and both ends of the current abnormal pipe (see Figure 5 Specifically, if, in a double-circular area within a certain continuous pipeline length on the target pipeline section, the population within the 100 ppm hydrogen sulfide exposure radius is greater than or equal to 30 people, or the population within the 500 ppm hydrogen sulfide exposure radius is greater than or equal to 3 people, and if the continuous pipeline length is greater than or equal to 300 meters, leakage monitoring points are set at both ends and the center of the continuous pipeline.

[0142] In the fourth embodiment, when there are multiple abnormal pipelines in the current pipeline and the total length of the actual pipeline occupied by each section of the abnormal pipeline (i.e., the length of the pipeline between the outermost two ends of the first section of the abnormal pipeline and the last section of the abnormal pipeline) is less than or equal to the second distance, leakage monitoring points are respectively set at both ends of the actual pipeline occupied by all abnormal pipelines in the current risk pipeline (see Figure 5Specifically, if there are multiple double-circular areas within a 100-meter length of the target pipeline segment with a population of 30 or more people within a 100-ppm hydrogen sulfide exposure radius or a population of 3 or more people within a 500-ppm hydrogen sulfide exposure radius, or if the length is less than or equal to 30 meters, a leakage monitoring point is set at the point closest to both ends within the 100-meter pipeline segment.

[0143] In the fifth embodiment, when there are multiple abnormal pipelines in the current pipeline and the total length of the actual pipeline occupied by each section of the abnormal pipeline (i.e., the length of the pipeline between the outermost two ends of the first section of the abnormal pipeline and the last section of the abnormal pipeline) is less than or equal to the third distance, leakage monitoring points are respectively set at the center and both ends of the actual pipeline occupied by all abnormal pipelines in the current risk pipeline (see Figure 5 Specifically, if there are multiple double-circular areas within a 300-meter length of the target pipeline segment with a population of 30 or more people within a 100-ppm hydrogen sulfide exposure radius or 3 or more people within a 500-ppm hydrogen sulfide exposure radius, or if the length is less than or equal to 30 meters, leakage monitoring points are set at the points closest to both ends and at the center of the two points within the 300-meter pipeline segment.

[0144] Example 2

[0145] Based on the above-mentioned first embodiment, an example of dividing the evaluation pipe section of a high-sulfur gas field in northeastern Sichuan is given below.

[0146] According to the principle of segmentation of evaluation pipeline sections, the gathering and transportation pipeline network of high-sulfur gas fields is divided into n sections with the cut-off valve (valve chamber) as the dividing point. The gathering and transportation pipeline between two cut-off valves (valve chambers) is a section. However, if a section of the gathering and transportation pipeline contains a section with a tunnel, truss or other laying method different from that of the buried pipeline, it will be listed as a separate section. Figure 6 As shown, circles represent single wells and squares represent valve chambers.

[0147] Since the terrain of the laying area of ​​this section of pipe is relatively flat, there are no trusses, tunnels or other pipeline crossing structures. Since the gas wellhead and the well are equipped with safety valves with on / off functions, which can be used as shut-off valves, the pipe section between the single well and the valve chamber, the pipe section between the valve chambers, and the pipe section between the valve chamber and the gas gathering station can be evaluated as a single section. Figure 6 The high-sulfur gas field gathering and transportation pipeline network shown can be divided into 16 sections.

[0148] Example 3

[0149] Based on the above-mentioned embodiment 1, the following provides an analysis and setting of monitoring points for a pipeline in a high-sulfur gas field in northeastern Sichuan (mainly focusing on liquid accumulation risk).

[0150] The pipeline between two valve chambers in a high-sulfur gas field is selected as the evaluation object, such as Figure 7 The pipeline consists of 3 elbows and 4 straight pipe sections. The inclination angles of the straight pipe sections are 30°, 0°, 60°, and -45° respectively. The operating pressure of the pipeline is 8.6 MPa. The average relative density of sour natural gas is 0.6455, and the average density of produced water is 1.135 kg / m 3 , length 1000m, pipe inner diameter 300mm, pipe flow velocity 3.0m / s.

[0151] After risk assessment, the risks of geological disasters and third-party damage to the pipeline are acceptable. Then, the formula for calculating the critical liquid accumulation angle of the pipeline is used to calculate that the critical liquid accumulation angle of this pipeline is 48°. Therefore, liquid accumulation will form at the 60° elbows in the second and third sections, and there is a risk of corrosion, perforation and leakage due to liquid accumulation.

[0152] Calculation and analysis are performed based on the process and method of "determining the scale of pipeline failure leakage":

[0153] 1) The leakage scale is small-scale leakage;

[0154] 2) The leakage time is 2400s;

[0155] 3) The exposure radius for hydrogen sulfide 500ppm is 15m, and the exposure radius for hydrogen sulfide 100ppm is 60m;

[0156] Starting from the 60° elbow, circular areas with radii of 15m and 60m were delineated for population surveys. The results showed that there were no permanent residents within the range, so leakage monitoring points were not required for the pipeline.

[0157] Example 4

[0158] Based on the above-mentioned embodiment 1, the following provides an analysis and setting of monitoring points for a pipeline in a high-sulfur gas field in northeastern Sichuan (mainly considering the risk of third-party damage).

[0159] The pipeline between two valve chambers in a high-sulfur gas field was selected as the evaluation object. The pipeline consists of five elbows and five straight sections. The operating pressure is 8.6 MPa, the average relative density of the sour natural gas is 0.6455, and the average density of the produced water is 1.135 kg / m³. The length is 500 m, the inner diameter is 500 mm, and the flow velocity is 3.0 m / s.

[0160] After risk assessment, the risk of geological disasters and corrosion perforation due to fluid accumulation in the pipeline was found to be acceptable. Subsequently, a third-party damage assessment was conducted on the five straight pipe sections of the pipeline, using the elbows as nodes, as shown in Table 7 below:

[0161] Table 7 Third-party damage assessment results of Example 4

[0162]

[0163] After a third-party risk assessment, it was determined that the third-party damage risk of the fourth straight pipe section was unacceptable. The length of the fourth straight pipe section was 168 meters.

[0164] Calculation and analysis were performed based on the process and method of "Determining the Scale of S3 Pipeline Failure Leakage":

[0165] 1) The leakage scale is medium / large-scale;

[0166] 2) Leakage time is 1800s;

[0167] 3) The exposure radius of hydrogen sulfide 500ppm is 100m, and the exposure radius of hydrogen sulfide 100ppm is 350m;

[0168] Starting from the third elbow of this pipe section, a population survey was conducted on the areas within a distance of 100m and 350m on both sides of the 4th straight pipe section. At the same time, the third elbow and the fourth elbow were used as the center of the circle, and semicircular areas with a radius of 100m and 350m were drawn respectively and included in the population survey area. The specific survey range is shown in the figure below. After investigation, it was found that there was a 56-meter-long pipeline starting from 66 meters away from the third elbow in the 4th straight pipe section. The population survey results were: 0 permanent residents within 100 meters of the pipeline, and 38 permanent residents within 350 meters of the pipeline. Therefore, it is necessary to set up monitoring points on this section of the pipeline. When the pipeline length is greater than 30 meters and less than 100 meters, a leakage monitoring point is set at the center of the pipe section, that is, a leakage monitoring point is set at a position 94 meters away from the third elbow. Figure 8 shown.

[0169] Example 5

[0170] Based on the above-mentioned embodiment 1, the following provides an analysis and setting of monitoring points for a pipeline in a high-sulfur gas field in northeastern Sichuan (mainly considering the risk of geological disaster damage).

[0171] The pipeline between two valve chambers in a high-sulfur gas field was selected as the evaluation object. The pipeline consists of two elbows and three straight sections. The operating pressure is 8.6 MPa, the average relative density of sour natural gas is 0.6455, the average density of produced water is 1.135 kg / m³, the length is 1600 m, the inner diameter of the pipeline is 150 mm, and the flow velocity is 3.8 m / s.

[0172] After risk assessment, the risks of third-party damage and corrosion perforation of the pipeline were found to be acceptable. Subsequently, a geological hazard assessment was conducted on the pipeline, as shown in Table 8 below:

[0173] Table 8 Geological hazard assessment results of Example 5

[0174]

[0175] Calculation and analysis were performed based on the process and method of "Determination of Pipeline Failure Leakage Scale", and the calculation results are shown in Table 9:

[0176] Table 9 Calculation results of failure leakage mode of Example 5

[0177]

[0178] Take two straight pipe sections prone to geological disasters as the target, with a distance of 360m and 890m, as follows Figure 9 In the example shown, a population survey area is defined and a population survey is conducted on the surrounding population. The survey results are shown in Table 10 below:

[0179] Table 10 Population survey statistics results of Example 5

[0180]

[0181] Example 6

[0182] Based on the above-described methods for selecting leakage monitoring points for gathering and transportation pipelines in Embodiments 1 to 5, embodiments of the present invention also provide a computer-readable storage medium having a computer program stored thereon. The computer program is executed to implement a method for selecting leakage monitoring points for gathering and transportation pipelines. The computer program is capable of executing computer instructions, which include computer program code. The computer program code may be in source code form, object code form, an executable file, or some intermediate form.

[0183] Computer-readable storage media may include: any entity or device that can carry computer program code, recording media, USB flash drives, mobile hard drives, magnetic disks, optical disks, computer memory, read-only memory (ROM), random access memory (RAM), electrical carrier signals, telecommunication signals, and software distribution media, etc.

[0184] It should be noted that the content contained in computer-readable storage media can be appropriately increased or decreased according to the requirements of legislation and patent practice in the jurisdiction. For example, in some jurisdictions, the content contained in computer-readable storage media does not include electric carrier signals and telecommunication signals.

[0185] Example 7

[0186] Based on the monitoring point optimization methods described in Examples 1 to 5 above, the present invention further provides a system for optimizing monitoring points for leakage in gathering and transportation pipelines (also referred to as a "monitoring point optimization system"). The monitoring point optimization system is used to implement the monitoring point optimization methods described in Examples 1 to 5 above.

[0187] Figure 10 This is a schematic diagram of the structure of the system for optimizing the monitoring points of leakage in the gathering and transportation pipeline according to the embodiment of the present application. Figure 10 As shown, the monitoring point optimization system according to the embodiment of the present invention includes: a pipeline division module 1001 , a risk assessment module 1002 , a leakage identification module 1003 and a point confirmation module 1004 .

[0188] Specifically, the pipeline division module 1001 is implemented according to the method described in step S110 above, and is configured to divide the shut-off valves of the high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines; the risk assessment module 1002 is implemented according to the method described in step S120 above, and is configured to evaluate the pipeline liquid corrosion risk, geological disaster risk and third-party damage risk of each pipeline respectively; the leakage identification module 1003 is implemented according to the method described in step S130 above, and is configured to estimate the leakage volume of pipelines with at least one risk based on the actual operating conditions of different pipelines, so as to obtain the corresponding failure leakage mode; the point confirmation module 1004 is implemented according to the method described in step S140 above, and is configured to locate the leakage monitoring point from the failed pipeline based on the leakage mode of the failed pipeline and the population distribution characteristics around the corresponding pipeline.

[0189] The present invention discloses a method and system for optimizing the location of leakage monitoring points in gathering and transportation pipelines. This method and system solves the problem of insufficient leakage monitoring coverage and pertinence, as existing high-sulfur gas field leakage monitoring systems fail to integrate sensor placement points (monitoring points) with the actual risks and operating conditions of the pipelines. By considering three key risks present in high-sulfur gas field gathering and transportation pipelines (liquid accumulation corrosion, geological disasters, and third-party sabotage), combined with actual operating conditions such as pressure, hydrogen sulfide content, and elevation, a pipeline failure leakage model is established, and a targeted optimization scheme for sensor placement pipe sections and points (monitoring points) is formulated. This method and system can enhance the pertinence of leakage monitoring and effectively improve the effectiveness of pipeline leakage monitoring.

[0190] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any changes or substitutions that can be easily conceived by anyone skilled in the art within the technical scope disclosed in the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be based on the scope of protection of the claims.

[0191] In the description of the present invention, unless otherwise specified, "plurality" means two or more; terms such as "upper," "lower," "left," "right," "inner," "outer," "front end," "rear end," "head," and "tail" indicate positions or relationships based on those shown in the accompanying drawings. These terms are intended solely to facilitate the description of the present invention and simplify the description. They do not indicate or imply that the devices or components referred to must have a specific orientation, be constructed, or operate in a specific orientation. Therefore, they should not be construed as limiting the present invention. Furthermore, terms such as "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0192] In the description of the present invention, it should be noted that, unless otherwise expressly specified or limited, the terms "connected" and "connection" should be understood in a broad sense. For example, they can refer to fixed connection, detachable connection, or integral connection; mechanical connection, electrical connection; direct connection, or indirect connection through an intermediary. Those skilled in the art will understand the specific meanings of the above terms in the present invention based on the specific circumstances.

[0193] It should be understood that the embodiments disclosed herein are not limited to the specific structures, processing steps, or materials disclosed herein, but should extend to equivalent substitutions of these features understood by those skilled in the relevant art. It should also be understood that the terminology used herein is for the purpose of describing specific embodiments only and is not intended to be limiting.

[0194] References in this specification to "one embodiment" or "an embodiment" mean that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment of the present invention. Therefore, appearances of the phrases "one embodiment" or "an embodiment" in various places throughout this specification do not necessarily refer to the same embodiment.

[0195] The embodiments of the present invention are presented for purposes of illustration and description and are not intended to be exhaustive or to limit the invention to the disclosed forms. Many modifications and variations will be apparent to those skilled in the art. The embodiments are chosen and described in order to better illustrate the principles of the invention and its practical application and to enable those skilled in the art to understand the invention and design various embodiments with various modifications as suited for specific applications.

[0196] Although the embodiments disclosed above are for facilitating understanding of the present invention, the contents described are merely embodiments adopted for facilitating understanding of the present invention and are not intended to limit the present invention. Any person skilled in the art of the present invention may make any modifications and changes in the form and details of the implementation without departing from the spirit and scope of the present invention. However, the scope of patent protection of the present invention shall still be subject to the scope defined by the appended claims.

Claims

1. A method for optimizing leakage monitoring points in a gathering and transportation pipeline, characterized in that: include: Divide the gathering and transportation pipeline network of high-sulfur natural gas fields into multiple pipelines; Evaluate each pipeline's risk of corrosion due to fluid accumulation, geological disasters, and third-party damage; Based on the actual operating conditions of different pipelines, the leakage volume of pipelines with at least one risk is estimated to obtain the corresponding failure leakage mode; According to the leakage pattern of the failed pipeline and the population distribution characteristics around the corresponding pipeline, the leakage monitoring point is located from the failed pipeline, wherein: Each pipeline is divided into multiple straight sections using elbows as nodes. Each straight section in each pipeline is evaluated for its risk of corrosion due to liquid accumulation, geological hazards, and third-party damage, including: Calculate the critical liquid accumulation angle of the pipeline based on the current pipeline diameter, flow velocity, internal temperature, and moisture content. Based on this, and combined with the pipeline inclination angle of each straight pipe section, evaluate whether the current pipeline has the risk of liquid accumulation corrosion. Evaluate the hazard levels of multiple geological hazards in each straight section of the current pipeline, and based on this, complete the assessment of whether the current pipeline has geological hazard risks, where the multiple geological hazards include but are not limited to landslides, collapses, debris flows, and river channel flooding; Scores are given for multiple destructive factors for each straight pipe section in the current pipeline, and based on the scoring results of each factor in each straight pipe section, an assessment is made as to whether the current pipeline is at risk of third-party destructive risk. The multiple destructive factors include, but are not limited to, pipeline burial depth, frequency of daily inspections, pipeline marking location, abnormal movement level above the pipeline, communication status, and intrusion monitoring method.

2. The method according to claim 1, characterized in that The process of determining whether there is a risk of corrosion due to fluid accumulation in the current pipeline includes: Comparing the pipeline inclination angle of each straight pipe section with the critical liquid accumulation inclination angle of the current pipeline, and determining that the current straight pipe section does not have the risk of liquid accumulation corrosion when the pipeline inclination angle of the straight pipe section does not exceed the critical liquid accumulation inclination angle of the current pipeline, otherwise it does; If there is a straight pipe section with a risk of liquid accumulation corrosion in the current pipeline, then the current pipeline has a risk of pipeline liquid accumulation corrosion; or if there is no straight pipe section with a risk of liquid accumulation corrosion in the current pipeline, then the current pipeline does not have a risk of pipeline liquid accumulation corrosion.

3. The method according to claim 1 or 2, characterized in that The hazard levels of various geological hazards are divided into Level 1, Level 2 and Level 3 according to the severity from high to low. Among them, in the process of checking whether there is a geological hazard risk in the current pipeline, the following are included: Determine whether there is a geological disaster of level one in each straight pipe section; When there is a straight pipe section with a first-level geological hazard item in the current pipeline, it is determined that the current pipeline has a geological hazard risk, or when there is no straight pipe section with a first-level geological hazard item in the current pipeline, it is determined that there is no geological hazard risk in the current pipeline.

4. The method according to claim 1 or 2, characterized in that The process of examining the current pipeline for third-party sabotage risks includes: The total score of the scoring results of various destructive factors corresponding to each straight pipe section is calculated, and the total score of each factor of each straight pipe section is compared with a preset score evaluation threshold. When there is a straight pipe section in the current pipeline whose total score of various destructive factors exceeds the said score evaluation threshold, it is determined that the current pipeline has a third-party destructive risk; when there is no straight pipe section in the current pipeline whose total score of various destructive factors exceeds the said score evaluation threshold, it is determined that the current pipeline does not have a third-party destructive risk.

5. The method according to claim 1 or 2, characterized in that The steps of estimating the leakage volume of pipelines with at least one risk based on the actual operating conditions of different pipelines include: Determine the leakage size of the current pipeline based on the risk type of the current pipeline, including leakage shape, leakage area and leakage scale; By comparing the pressure of the risky straight pipe section in the current pipeline with the gas critical pressure reference threshold, the leakage rate of the medium in the current pipeline is calculated based on the comparison result and the leakage area; Determine the leakage duration of the medium in the current pipeline; A theoretical value of gas leakage in a pipeline currently experiencing at least one risk is calculated based on the medium leakage rate and the leakage duration, thereby estimating an actual gas leakage amount in the current pipeline by comparing the theoretical value of gas leakage with the total amount of all hydrogen sulfide gases in the current pipeline.

6. The method according to claim 5, characterized in that The process of determining the failure leakage mode includes: According to the actual gas leakage estimation result of the current risk pipeline, the hydrogen sulfide diffusion radius corresponding to the case where the leakage hydrogen sulfide concentration reaches a first concentration level and a second concentration level is determined respectively, wherein the first concentration level is higher than the second concentration level.

7. The method according to claim 6, characterized in that The step of locating leakage monitoring points in the failed pipeline based on the predicted leakage pattern of the failed pipeline and the population distribution characteristics around the corresponding pipeline includes: Taking one of the endpoints of the risk straight pipe section in the current risk pipeline as the starting point, the center of the double circular area formed by the first hydrogen sulfide diffusion radius and the second hydrogen sulfide diffusion radius is moved from the starting point to the other endpoint according to a preset step length, and determining whether the population distribution state in the corresponding double circular area at each step meets the first condition, thereby counting the total pipeline length at the step position that meets the first condition in the current risk straight pipe section, and recording it as the abnormal pipeline length, wherein the first condition is that the number of permanent residents in the circular area formed by the second hydrogen sulfide diffusion radius reaches a first number or the number of permanent residents in the circular area formed by the first hydrogen sulfide diffusion radius reaches a second number, wherein the second number is higher than the first number; The leakage monitoring point is determined according to the number of abnormal pipelines in the current risk pipeline and the length of each abnormal pipeline.

8. The method according to claim 7, characterized in that When the number of the abnormal pipelines is 1 and the length of the current abnormal pipeline is greater than the first distance and less than the second distance, a leakage monitoring point is set at the center of the current abnormal pipeline, wherein the first distance is less than the second distance; When the number of abnormal pipelines is 1 and the length of the current abnormal pipeline is greater than or equal to the second distance and less than the third distance, leakage monitoring points are respectively set at both ends of the current abnormal pipeline, wherein the second distance is less than the third distance; When the number of the abnormal pipelines is 1 and the length of the current abnormal pipeline is greater than or equal to the third distance, leakage monitoring points are respectively set at the center and both ends of the current abnormal pipeline; When there are multiple abnormal pipelines and the total length of the actual pipeline occupied by each section of the abnormal pipeline is less than or equal to the second distance, leakage monitoring points are respectively set at both ends of all abnormal pipelines in the current risk pipeline; When there are multiple abnormal pipelines and the total length of the actual pipelines occupied by each section of the abnormal pipeline is less than or equal to the third distance, leakage monitoring points are respectively set at the center and both ends of all abnormal pipelines in the current risk pipeline.

9. The method according to claim 5, characterized in that The leakage duration is determined as follows: The duration of the medium leakage in the current pipeline is estimated based on the measurement accuracy level of the monitoring system equipped for the current risk pipeline and the automation control level of the cut-off system equipped for the current risk pipeline, combined with the leakage scale.

10. The method according to claim 1 or 2, characterized in that The steps of dividing the high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines include: Using the cutoff valve in the gathering and transportation pipeline network of the high-sulfur natural gas field as a dividing point, the current pipeline network is preliminarily divided into multiple pipeline sections; If there are pipelines with laying methods different from those of buried pipelines, the current pipelines will be further divided into multiple sections according to different laying types, thereby dividing the entire high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines. The laying types include but are not limited to buried pipelines, tunnels and trusses.

11. A computer-readable storage medium, characterized in that It contains a series of instructions for executing the method steps according to any one of claims 1 to 10.

12. A system for optimizing leakage monitoring points in a gathering and transportation pipeline, characterized in that: include: A pipeline division module, which is configured to divide the pipeline network of a high-sulfur natural gas field gathering and transportation network into multiple pipelines based on the cutoff valves; A risk assessment module configured to separately assess each pipeline's risk of corrosion due to fluid accumulation, geological disaster risk, and third-party damage risk; A leakage identification module is configured to estimate the leakage volume of pipelines with at least one risk based on the actual operating conditions of different pipelines, thereby obtaining corresponding failure leakage modes; The point confirmation module is configured to locate the leakage monitoring point in the failed pipeline based on the leakage pattern of the failed pipeline and the population distribution characteristics around the corresponding pipeline. The risk assessment module is further configured to: Each pipeline is divided into multiple straight sections using elbows as nodes. Each straight section in each pipeline is evaluated for its risk of corrosion due to liquid accumulation, geological hazards, and third-party damage, including: Calculate the critical liquid accumulation angle of the pipeline based on the current pipeline diameter, flow velocity, internal temperature, and moisture content. Based on this, and combined with the pipeline inclination angle of each straight pipe section, evaluate whether the current pipeline has the risk of liquid accumulation corrosion. Evaluate the hazard levels of multiple geological hazards in each straight section of the current pipeline, and based on this, complete the assessment of whether the current pipeline has geological hazard risks, where the multiple geological hazards include but are not limited to landslides, collapses, debris flows, and river channel flooding; Scores are given for multiple destructive factors for each straight pipe section in the current pipeline, and based on the scoring results of each factor in each straight pipe section, an assessment is made as to whether the current pipeline is at risk of third-party destructive risk. The multiple destructive factors include, but are not limited to, pipeline burial depth, frequency of daily inspections, pipeline marking location, abnormal movement level above the pipeline, communication status, and intrusion monitoring method.

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