Method and system for preferably selecting leakage monitoring points of gathering and transportation pipeline

Abstract

The invention discloses a method and a system for preferably selecting a gathering and transportation pipeline leakage monitoring point position. The method comprises the following steps of: dividing a gathering and transportation pipeline network of a high-sulfur natural gas field into a plurality of pipelines; evaluating the pipeline effusion corrosion risk, the geological disaster risk and the third-party damage risk of each pipeline; according to the actual operation working conditions of different pipelines, leakage amount estimation is carried out on the pipeline with at least one risk, so that a corresponding failure leakage mode is obtained; and according to the leakage mode of the failed pipeline, positioning a leakage monitoring point position from the failed pipeline in combination with the surrounding population distribution characteristics of the corresponding pipeline. The pertinence of leakage monitoring can be enhanced, and the pipeline leakage monitoring effect is effectively improved.

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] As a clean, environmentally friendly, and high-quality energy source, natural gas has gradually occupied an important position in my country's energy structure. Its consumption has also continued to rise sharply. The scale of the natural gas pipeline network has continued to expand. Gas field gathering and transportation pipelines, long-distance natural gas pipelines, and urban natural gas pipelines have jointly formed a "trunk interconnection and local network" pattern. Therefore, timely and accurate detection of leaks and identification of leak points are crucial for the safe collection and transportation of (high-sulfur) natural gas.

[0003] At present, there are many leakage monitoring methods applied to oil and gas pipelines in my country, and their classification methods are also diverse. According to the different parameters detected, they are mainly divided into mass / volume balance method, applied statistical method, negative pressure wave method, transient model method, distributed optical fiber method and acoustic wave method. However, the layout of these traditional monitoring methods is mainly based on full-line laying. Specifically, the mass / volume balance method realizes monitoring by setting embedded pressure / flow sensors on the whole line, and the distributed optical fiber method realizes monitoring by laying optical fibers in the same trench as the pipeline; the acoustic wave method realizes monitoring by setting embedded acoustic wave sensors on the whole line. Under this layout method, the monitoring accuracy of the monitoring method is greatly affected by the density of sensor layout, that is, if you want to obtain high-precision monitoring effects, you must increase the density of sensor layout. This layout method is very costly. The full-line deployment of high-precision monitoring methods in low-risk areas will lead to increased costs and waste of resources. Therefore, it is very important to establish a leakage monitoring point selection and application method suitable for high-acid gas field gathering and transportation pipelines.

[0004] In the prior art CN111578154A, a method for optimizing the layout of multiple leakage pressure sensors in a water supply network based on LSDR-JMI is disclosed. The method uses a pressure sensor to initially measure the pressure under a non-leakage condition to form a pressure matrix; uses a pressure sensor to initially measure the pressure under a leakage condition to form an abnormal pressure matrix, and constructs a pressure sensitivity matrix based on the pressure matrix and the abnormal pressure matrix; and uses the clustering result as the pseudo label L corresponding to the pressure sensitivity matrix; converts the complete label space Y into a sub-label space according to the LSDR method; uses the Group-JMI method based on mutual information to reduce the dimension of the label space Y, and calculates according to the LSDR-JMI feature selection method.

[0005] In the prior art CN105975702A, a method for optimizing the arrangement of health monitoring sensors for cable-stayed bridges is disclosed. The method comprises the following steps: according to the correlation between the damage factors of all beam segment units of the cable-stayed bridge and the node degree of freedom vibration mode, a node degree of freedom damage information index containing damage information of all beam segments is obtained; according to the amount of damage information contained, the node degree of freedom damage information index is sorted; through a sensor optimization arrangement method based on modal observability, the sorted node degree of freedom damage information index is processed to obtain the arrangement position of the sensor.

[0006] In the prior art CN113139584A, a sensor optimization layout method for identifying pollution intrusion points in a water supply network is provided. The method first performs risk assessment on pollution intrusion nodes and selects and clusters the pollution intrusion nodes, and obtains a set of sensor layout schemes based on a hierarchical algorithm to meet the identifiability of the sensor network; then, various schemes are compared based on the number of sensors and the impact of sensor failures on the sensor network to obtain the optimal scheme, and the change in pollution probability is taken into account when comparing various schemes.

[0007] Therefore, in the existing leakage monitoring technology for high-sulfur gas field gathering and transportation pipelines, except for the distributed optical fiber monitoring which is laid in the same trench on the front line, the deployment of other sensors is based on the selection of points (i.e., monitoring points) according to the distribution distance, and 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 not 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, which is crucial to ensure the safe and smooth operation of high-sulfur gas fields. Summary of the invention

[0009] The purpose of the present invention is to provide a leakage monitoring pipe section and point optimization scheme 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 pertinence.

[0010] In order to solve the above technical problems, an embodiment of the present invention provides a method for optimizing leakage monitoring points of 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 respectively; estimating the leakage volume of pipelines with at least one risk according to the actual operating conditions of different pipelines, so as to obtain the corresponding failure leakage mode; locating the leakage monitoring point from the failed pipeline according to the leakage mode 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 risk of pipeline liquid accumulation corrosion, 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 pipe diameter, pipe flow velocity, pipe temperature and pipeline water content of the current pipeline, based on which, combined with the pipeline inclination angle of each straight section, evaluating whether there is a risk of pipeline liquid accumulation corrosion in the current pipeline; evaluating the disaster levels of multiple geological disasters in each straight section in the current pipeline separately, based on In this way, an evaluation is completed on whether there is a geological disaster risk in the current pipeline, wherein the multiple geological disasters include but are not limited to landslides, collapses, mud-rock flows and river channel water damage; multiple destructive factors of each straight pipe section in the current pipeline are scored respectively, so as to evaluate whether there is a third-party damage risk in the current pipeline based on the scoring results of each factor of each straight pipe section, wherein the multiple destructive factors include but are not limited to pipeline burial depth, daily inspection frequency, pipeline identification location, abnormal movement level above the pipeline, communication status and intrusion monitoring method.

[0012] Preferably, in the process of determining whether the current pipeline has a risk of liquid accumulation corrosion, the process 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, determining that the current straight pipe section does not have a risk of liquid accumulation corrosion, 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.

[0013] Preferably, 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. In the process of determining whether there is a geological disaster risk in the current pipeline, it includes: judging whether there is a geological disaster with a geological disaster level of level one in each straight pipe section; when there is a straight pipe section with a level one geological disaster item in the current pipeline, determining that there is a geological disaster risk in the current pipeline, or when there is no straight pipe section with a level one geological disaster item in the current pipeline, determining that there is no geological disaster risk in the current pipeline.

[0014] Preferably, 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, 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 score evaluation threshold, it is determined that the current pipeline has a third-party damage risk; or when there is no straight pipe section in the current pipeline whose total score of various damage factors exceeds the score evaluation threshold, it is determined that the current pipeline does not have a third-party damage risk.

[0015] Preferably, in the step of estimating the leakage amount of a pipeline with at least one risk according to the actual operating conditions of different pipelines, the step includes: determining the leakage size of the current pipeline according to the risk type of the current pipeline, the leakage size including leakage form, leakage area and leakage scale; calculating the leakage rate of the medium in the current pipeline according to 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 currently having at least one risk according to 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, respectively, 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 according to the predicted leakage mode 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 length, 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, 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; 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: 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, the leakage duration of the medium in the current pipeline is estimated.

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

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

[0022] In addition, an embodiment of the present invention further provides a system for optimizing leakage monitoring points of 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 according to the actual operating conditions of different pipelines, so as to obtain the corresponding failure leakage mode; a point confirmation module, which is configured to locate the leakage monitoring point from the failed pipeline according to the leakage mode 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 scheme may have the following advantages or beneficial effects:

[0024] The present invention proposes a method and system for optimizing the monitoring points for leakage in a gathering and transportation pipeline. The method and system solve the problem that the existing leakage monitoring system for high-sulfur gas fields does not combine the actual risks and operating conditions of the pipeline to arrange the sensor points (monitoring points), resulting in insufficient leakage monitoring coverage and pertinence. Through the three key risks (liquid corrosion, geological disasters, and third-party damage) existing in the gathering and transportation pipeline of high-sulfur gas fields, combined with the actual operating conditions such as pressure, hydrogen sulfide content, and elevation, a pipeline failure leakage model is established, and a targeted optimization plan for sensor arrangement pipe sections and points (monitoring points) is formulated. The present invention can enhance the pertinence of leakage monitoring and effectively improve the effect of pipeline leakage monitoring.

[0025] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose 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 This is a 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 location of leakage monitoring points in a 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 It is a 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 It is a schematic diagram of the principle of the point confirmation operation in the method for optimizing the gathering and transportation pipeline leakage monitoring point 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 the monitoring points for leakage 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] Fig. 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] Fig.10 It is a structural schematic diagram of a system for optimizing leakage monitoring points of gathering and transportation pipelines according to an embodiment of the present application. DETAILED DESCRIPTION

[0037] The following will describe the implementation methods of the present invention in detail with reference to the accompanying drawings and embodiments, so that the implementation process of how the present invention applies technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that as long as there is no conflict, the various embodiments of the present invention and the various features in the embodiments can be combined with each other, and the technical solutions formed are all within the protection scope 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 sequence is shown in the flowchart, in some cases, the steps shown or described can be performed in a sequence different from that here.

[0039] The terms used herein are only for describing specific embodiments and are not intended to limit exemplary embodiments. Unless the context clearly indicates otherwise, the singular forms "one", "one" and "item" used herein are also intended to include plural numbers. It should also be understood that the terms "include" and / or "comprise" used herein specify the existence of stated features, integers, steps, operations, units and / or components, without excluding the existence 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 embodiment of the present application proposes a method and system for optimizing the leakage monitoring points of the gathering and transportation pipeline. The method and system combine the three key risks (liquid corrosion, geological disasters, and third-party damage) of the gathering and transportation pipeline of the high-sulfur gas field, and the actual operating conditions such as pressure, hydrogen sulfide content, and elevation to establish a pipeline failure leakage mode 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 population. The gathering and transportation pipelines are mainly laid underground and through-and-through. In order to achieve the above-mentioned purpose of the present invention, the method and system for optimizing the leakage monitoring points of the gathering and transportation pipelines provided by the present invention are as follows.

[0042] Embodiment 1

[0043] Figure 1 This is a 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 of gathering and transportation pipelines disclosed in an embodiment of the present invention (also referred to as "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 current high-sulfur natural gas field gathering and transportation pipeline network is initially divided into multiple pipeline sections using the cut-off valve (i.e., valve chamber) in the current high-sulfur natural gas field gathering and transportation pipeline network as the dividing point; then, if there are pipelines with a laying method different from that of buried pipelines, the current pipelines are further divided into multiple pipeline sections according to different laying types, thereby dividing the entire high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines. Among them, the 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 in the embodiment of the present application. Figure 3 As shown, in step S110, the gathering and transportation pipeline network is first divided into n sections using the cut-off valves (valve chambers) of the high-sulfur gas field gathering and transportation pipeline network as the dividing point. For example, the gathering and transportation pipeline between two cut-off valves (valve chambers) is one route.

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

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

[0049] In step S120, it is necessary to perform multiple risk assessments on each pipeline one by one, and determine 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 pipe sections with elbows as nodes, and the pipeline liquid corrosion risk, geological disaster risk and third-party damage risk of each straight pipe section in each pipeline are evaluated separately.

[0051] At present, my country's high-sulfur gas fields are mainly distributed in Sichuan and Chongqing. The operating conditions of the sour gas gathering and transportation pipelines in high-sulfur gas fields are harsh and the external environment is complex. The risk of H2S gas leakage and injury caused by pipeline failure is high, and integrity management is difficult. The main risks include: pipeline corrosion, geological disasters and third-party damage.

[0052] Liquid accumulation and corrosion in pipelines: 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 the large height difference of the gathering and transportation pipeline network, liquid accumulation occurs in pipelines in low-lying areas, which makes it easy for corrosion and perforation to occur in the pipe wall.

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

[0054] Third-party damage: The population in the region is dense 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 the elbow as a node to identify and analyze the above three risks. Since the three risk assessment methods for each pipeline are similar, the present invention uses one pipeline as an example to illustrate the three risk identification and analysis processes.

[0056] First, according to the current pipeline diameter, pipe flow velocity, pipe temperature and pipeline water content, the critical liquid accumulation angle θ0 of the current pipeline is calculated, and according to the critical liquid accumulation angle, the pipeline inclination angle θ of each straight pipe section (the i-th straight pipe section, i represents the serial number of the divided straight pipe section) is combined 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 inclination 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 a gas well, in kg / m 3 ; g represents the acceleration due to gravity (9.81 m / 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 It represents the molecular mass of 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 They 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. i ≥θ0 condition, 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 disaster levels of multiple geological disasters in each straight pipe section in the current pipeline are evaluated respectively, and according to the evaluation results of multiple geological disaster levels of each straight pipe section, the evaluation of whether there is a geological disaster risk in the current pipeline is completed. In the embodiment of the present invention, the multiple geological disasters include but are not limited to: landslide, collapse, mud-rock flow and river channel water damage.

[0066] In the embodiment of the present invention, the disaster level of each geological disaster is 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 the current pipeline has a geological hazard risk (unacceptable), or when there is no straight pipe section with a first-level geological hazard item in the current pipeline, determining that the current pipeline does not have a geological hazard risk (acceptable).

[0068] For high-sulfur gas fields, the geological disasters are mainly landslides, collapses, mud-rock flows, and river channel water damage. Therefore, the embodiment of the present invention mainly uses these four geological disasters as the evaluation basis, and grades the susceptibility of each geological disaster (where level 1 is the most prone geological disaster). Table 1 shows the conditions for judging the disaster level of each geological disaster.

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

[0070] In another embodiment, when there is no geological disaster with the highest level (level one) of susceptibility level 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, the multiple destructive factors of each straight pipe section in the current pipeline are scored respectively, so as to evaluate whether the current pipeline has a third-party destructive risk according to the scoring results of each factor corresponding to each straight pipe section. In the embodiment of the present invention, 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.

[0077] Furthermore, in the process of determining whether the current pipeline has a risk of third-party damage, the process includes: calculating the total score of the scoring results of various damage factors corresponding to each straight pipe section; and 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 risk of third-party damage based on the comparison result.

[0078] When there is a straight pipe section in the current pipeline where the total score of various destructive factors exceeds the score evaluation threshold (e.g., 20 points), it is determined that the current pipeline has a third-party destructive risk. Alternatively, when there is no straight pipe section in the current pipeline where the total score of various destructive factors exceeds the score evaluation threshold, it is determined that the current pipeline does not have a third-party destructive risk.

[0079] For high-sulfur gas fields, the third-party risks of their pipelines are mainly local residents' farming damage to the pipelines and third-party large-scale machinery excavation damage to the pipelines. Therefore, the embodiment of the present invention proposes an evaluation method for third-party damage risk, as shown in Table 2 below. Table 2 shows the scoring of different damage degrees of various damage factors.

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

[0081]

[0082]

[0083] As shown in Table 2, the scoring result of each damage factor can be determined according to the actual conditions of the corresponding pipeline burial depth, daily inspection frequency, pipeline identification position, abnormal movement level above the pipeline, communication status and intrusion monitoring method in the corresponding straight pipe section, so as to obtain the total score (i.e., the total score of each factor) representing the third-party damage risk assessment result of the current straight pipe section by adding the scoring results of the six factors obtained according to the actual situation.

[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 has no third-party damage risk (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 a third-party damage risk (unacceptable, which means that the current pipeline has a large third-party damage risk).

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

[0086] In the embodiment of the present invention, if the current pipeline does not have any risk of pipeline liquid accumulation corrosion, geological disaster risk, and third-party damage risk, there is no need to set monitoring points for the current pipeline. In addition, if the current pipeline has one or more of the risks of pipeline liquid accumulation corrosion, geological disaster risk, and third-party damage risk, it is necessary to set monitoring points for the current pipeline, thereby entering step S130.

[0087] Step S130: according to 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 the 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-acid gas field gathering and transportation pipelines is generally between 168.3 mm and 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 sizes 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 reference threshold of the gas critical pressure, 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, Specific heat capacity of ideal gas (adiabatic index), dimensionless; P trans Indicates the critical pressure of gas, in MPa; P a Indicates standard atmospheric pressure, in MPa; C P It represents the specific heat of an ideal gas at constant pressure, in J·g -1 / K;C V It represents the constant product specific heat of ideal gas, in J·g -1 / K.

[0097] In one embodiment, if the pipeline gas pressure P of the current pipeline 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, in MPa; R represents the gas constant, usually 8.314 J mol -1 K -1 ; g c represents the transformation 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, determine the leakage duration t of the medium in the current pipeline.

[0103] In actual application, the duration of leakage can be determined according to the actual situation of the risk pipeline to be assessed. If it cannot be determined according to the actual situation, the duration of leakage of the medium in the current pipeline can be estimated based on the measurement accuracy level of the monitoring system equipped with the current risk pipeline (as shown in Table 4) and the automation control level of the cut-off system equipped with the current risk pipeline (as shown in Table 5), combined with the leakage scale, parameter 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 monitoring system type grade Special equipment to monitor changes in key parameters and thus indirectly monitor medium loss A Sensitive detectors for direct monitoring of 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 the 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 according to the type of the cut-off or venting system equipped for the current risk pipeline.

[0109] Table 5 Shutoff / vent system levels

[0110] Target pipe segment cut-off 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 location 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 according to the measurement accuracy level of the monitoring system equipped with the current risk pipeline, the automation control level of the cut-off system equipped with 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 embodiments of the present invention, referring to Table 3, small scale refers to a leakage area less than 100 mm 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 that currently has 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 gases 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 calculated as the estimated actual gas leakage amount of the current pipeline.

[0118] Specifically, the gas leakage Q of the gathering and transportation pipeline of the 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 shut-off valves;

[0121] In addition, it should be noted that for ultra-large-scale pipeline leakage caused by geological disasters, there is no need to consider the leakage time. If a pipeline tearing accident caused by a geological disaster occurs, the leakage volume is directly estimated as all the gas in the pipeline between the two cut-off valves as the actual gas leakage volume, that is, the total amount of all the gas in the pipeline of the corresponding risk pipeline 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, according to the actual gas leakage estimation result of the current risk pipeline (failed pipeline), the first hydrogen sulfide diffusion radius corresponding to the case where the concentration of the leaked hydrogen sulfide reaches a first concentration level and the hydrogen sulfide diffusion radius corresponding to the case where the concentration of the leaked hydrogen sulfide reaches a second concentration level are determined respectively, 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 It 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 m.

[0130] Therefore, after obtaining the diffusion radius corresponding to 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 the leakage monitoring point in the current failed pipeline according to the leakage mode of the failed pipeline and the population distribution characteristics around the corresponding pipeline.

[0132] According to the calculation result of the above step S130, the exposure radius of hydrogen sulfide 100ppm is L1, and the exposure radius of hydrogen sulfide 500ppm is L2. A population survey is conducted on the areas within the distance range of L1 and L2 on both sides of the target pipeline (failed pipeline) to obtain the surrounding population along the target pipeline section. At the same time, semicircular areas with L1 and L2 as radii are drawn at both ends of the target pipeline section and 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 leakage in the embodiment of the present application. Figure 4 As shown, the embodiment of the present invention will first take one of the endpoints 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 endpoint according to a preset step length, and determine whether the population distribution state 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, which is recorded as the abnormal pipeline length.

[0134] In the embodiment of the present invention, 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 (for example, 3 persons) or the number of permanent residents in the circular area formed by the first hydrogen sulfide diffusion radius reaches a second number (for example, 30 persons), wherein the second number is higher 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), so as to mark the abnormal pipeline 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 according to the number of abnormal pipelines in the current risk pipeline and the length of each abnormal pipeline.

[0138] Figure 5 It is a schematic diagram of the principle of the point confirmation operation in the method for optimizing the gathering and transportation pipeline leakage monitoring point 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 first distance is smaller than the second distance. Specifically, when the population of the double circular area within a certain continuous pipeline length on the target pipe section is greater than or equal to 30 people within the hydrogen sulfide 100ppm exposure radius or greater than or equal to 3 people within the hydrogen sulfide 500ppm exposure radius, and when the length of the continuous pipeline 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 respectively set at both ends of the current abnormal pipe (see Figure 5 The second distance is less than the third distance. Specifically, when the population of the double circular area within a certain continuous pipeline length on the target pipe section is greater than or equal to 30 people within the hydrogen sulfide 100ppm exposure radius or greater than or equal to 3 people within the hydrogen sulfide 500ppm exposure radius, and when the length of the continuous pipeline 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, when, on the target pipe section, in a double circular area within a certain continuous pipeline length, the population within the hydrogen sulfide 100ppm exposure radius is greater than or equal to 30 people or the population within the hydrogen sulfide 500ppm exposure radius is greater than or equal to 3 people, and when the length of the continuous pipeline 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 end points 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, when there are multiple single points within the 100-meter length of the pipeline on the target pipe section where the population within the double circular area of ​​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, or the length is less than or equal to 30 meters, a leakage monitoring point is set at the point closest to the two ends within the 100-meter pipe section.

[0143] In the fifth embodiment, when there are multiple abnormal pipelines in the current pipeline and the total length of the actual pipelines occupied by each section of the abnormal pipeline (i.e., the length of the pipeline between the outermost two end points 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 pipelines occupied by all abnormal pipelines in the current risk pipeline (see Figure 5 Specifically, when there are multiple single points within the 300-meter length of the target pipeline section where the population within the double circular area of ​​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, or the length is less than or equal to 30 meters, leakage monitoring points are set at the points closest to the two ends and the center of the two points within the 300-meter pipeline section.

[0144] Embodiment 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 one section. However, if there is a tunnel, truss or other pipeline section in a certain section of the gathering and transportation pipeline that is laid differently from 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 wellhead and the well are equipped with safety valves with switch functions, which can be used as cut-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] Embodiment 3

[0149] Based on the above-mentioned first embodiment, the following provides an analysis and setting of monitoring points for a pipeline in a high-sulfur gas field in northeastern Sichuan (mainly for 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 8.6MPa. The average relative density of sour natural gas is 0.6455, and the average density of produced water is 1.135kg / m 3 , length 1000m, pipe inner diameter 300mm, pipe flow velocity 3.0m / s.

[0151] After risk assessment, the risk of geological disasters and third-party damage to the pipeline is acceptable. The formula for calculating the critical liquid accumulation angle of the pipeline is then used to calculate that the critical liquid accumulation angle of the 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 of hydrogen sulfide 500ppm is 15m, and the exposure radius of hydrogen sulfide 100ppm is 60m;

[0156] Taking the 60° elbow as the starting point, 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 there was no need to set up leakage monitoring points on the pipeline.

[0157] Embodiment 4

[0158] Based on the above-mentioned first embodiment, 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 5 elbows and 5 straight pipe sections, with an operating pressure of 8.6MPa, an average relative density of sour natural gas of 0.6455, an average density of produced water of 1.135kg / m3, a length of 500m, an inner diameter of 500mm, and a pipe flow velocity of 3.0m / s.

[0160] After risk assessment, the risk of geological disasters and corrosion perforation caused by liquid accumulation in the pipeline is acceptable. Then, taking the elbow as the node, a third-party damage assessment was conducted on the five straight pipe sections of the pipeline 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 considered that the risk of third-party damage to the 4th straight pipe section was unacceptable. The length of the 4th straight pipe section was 168 meters.

[0164] Calculation and analysis were performed based on the process and method of "S3 pipeline failure leakage scale determination":

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

[0166] 2) The 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 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 radii of 100m and 350m were drawn respectively and included in the population survey area. The specific survey scope 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 in 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] Embodiment 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 based on 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 2 elbows and 3 straight pipe sections, with an operating pressure of 8.6MPa, an average relative density of sour natural gas of 0.6455, an average density of produced water of 1.135kg / m3, a length of 1600m, an inner diameter of 150mm, and a pipe flow velocity of 3.8.0m / s.

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

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

[0174]

[0175] According to the process and method of "determining the scale of pipeline failure leakage", 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: Fig. 9 In the example shown, a population survey scope 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 of Example 5

[0180]

[0181] Embodiment 6

[0182] Based on the above-mentioned embodiments 1 to 5 of the method for optimizing the monitoring points for leakage of a gathering and transportation pipeline, the embodiment of the present invention also provides a computer-readable storage medium, on which a computer program is stored, and the computer program is executed to run a method for optimizing the monitoring points for leakage of a gathering and transportation pipeline. The computer program can run computer instructions, and the computer instructions include computer program code, which can be in source code form, object code form, executable file, or some intermediate form, etc.

[0183] Computer-readable storage media may include: any entity or device that can carry computer program code, recording media, USB flash drives, mobile hard disks, 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 electrical carrier signals and telecommunication signals.

[0185] Embodiment 7

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

[0187] Fig.10 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. Fig.10 As shown, the monitoring point optimization system described in 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 the above step S110, 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 the above step S120, 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 the above step S130, and is configured to estimate the leakage volume of the pipeline with at least one risk according to 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 the above step S140, and is configured to locate the leakage monitoring point from the failed pipeline according to 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 monitoring points for leakage in a gathering and transportation pipeline. The method and system solve the problem that the existing leakage monitoring system for high-sulfur gas fields does not combine the actual risks and operating conditions of the pipeline to arrange the sensor points (monitoring points), resulting in insufficient leakage monitoring coverage and pertinence. The method and system establish a pipeline failure leakage mode by combining the three key risks (liquid corrosion, geological disasters, and third-party damage) in the gathering and transportation pipeline of high-sulfur gas fields, pressure, hydrogen sulfide content, elevation and other actual operating conditions, and formulate a targeted optimization plan for sensor arrangement pipe sections and points (monitoring points). The present invention can enhance the pertinence of leakage monitoring and effectively improve the effect of pipeline leakage monitoring.

[0190] The above is only a preferred specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Any changes or substitutions that can be easily thought of by any person familiar with the technology within the technical scope disclosed by the present invention should be included in the protection scope of the present invention. Therefore, the protection scope of the present invention should be based on the protection scope of the claims.

[0191] In the description of the present invention, unless otherwise specified, "plurality" means two or more than two; the orientations or positional relationships indicated by the terms "upper", "lower", "left", "right", "inner", "outer", "front end", "rear end", "head", "tail", etc. are based on the orientations or positional relationships shown in the drawings, and are only for the convenience of describing the present invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operate in a specific orientation, and therefore cannot be understood as limiting the present invention. In addition, the terms "first", "second", "third", etc. are only used for descriptive purposes and cannot be understood as indicating or implying relative importance.

[0192] In the description of the present invention, it should be noted that, unless otherwise clearly specified and limited, the terms "connected" and "connection" should be understood in a broad sense, for example, it can be a fixed connection, a detachable connection, or an integral connection; it can be a mechanical connection or an electrical connection; it can be a direct connection or an indirect connection through an intermediate medium. For ordinary technicians in this field, the specific meanings of the above terms in the present invention can be understood according to specific circumstances.

[0193] It should be understood that the embodiments disclosed in the present invention are not limited to the specific structures, processing steps or materials disclosed herein, but should be extended to equivalent substitutions of these features understood by ordinary technicians in the relevant field. It should also be understood that the terms used herein are only used for the purpose of describing specific embodiments and are not meant to be limiting.

[0194] The "one embodiment" or "embodiment" mentioned in the specification means that the specific features, structures or characteristics described in conjunction with the embodiment are included in at least one embodiment of the present invention. Therefore, the phrases "one embodiment" or "embodiment" appearing in various places throughout the specification do not necessarily refer to the same embodiment.

[0195] The embodiments of the present invention are given for the purpose 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 of ordinary skill in the art. The embodiments are selected and described in order to better illustrate the principles and practical applications of the present invention and to enable those of ordinary skill in the art to understand the present invention and thereby design various embodiments with various modifications suitable for specific uses.

[0196] Although the embodiments disclosed in the present invention are as above, the contents described are only embodiments adopted for facilitating the understanding of the present invention and are not intended to limit the present invention. Any technician in the technical field to which the present invention belongs can make any modifications and changes in the form and details of the implementation without departing from the spirit and scope disclosed in the present invention, but the patent protection scope of the present invention shall still be subject to the scope defined in the attached claims.

Claims

1. A method for optimizing the location of 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 the risk of pipeline corrosion due to liquid accumulation, geological disaster risk and third-party damage risk for each pipeline; According to 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 mode of the failed pipeline and in combination with the population distribution characteristics around the corresponding pipeline, the leakage monitoring point is located from the failed pipeline.

2. The method according to claim 1, characterized in that 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: The critical liquid accumulation inclination angle of the current pipeline is calculated based on the pipe diameter, pipe flow velocity, pipe temperature and pipe moisture content. Based on this, combined with the pipe inclination angle of each straight pipe section, the risk of pipeline liquid accumulation corrosion is evaluated. Evaluate the disaster levels of multiple geological disasters in each straight section of the current pipeline, and based on this, complete the evaluation of whether there is a geological disaster risk in the current pipeline, wherein the multiple geological disasters include but are not limited to landslides, collapses, mud-rock flows and river channel water damage; Scores are given to multiple destructive factors of each straight pipe section in the current pipeline respectively, so as to evaluate whether there is a third-party destructive risk in the current pipeline according to 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.

3. The method according to claim 2, characterized in that In the process of determining whether there is a risk of corrosion due to pipeline accumulation, the following are included: The pipeline inclination angle of each straight pipe section is compared 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 there is no risk of liquid accumulation corrosion in the current straight pipe section, otherwise there is; 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.

4. The method according to claim 2 or 3, characterized in that: The disaster levels of various geological disasters 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 disaster risk in the current pipeline, it includes: Determine whether there is a geological disaster of level 1 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 the current pipeline does not have a geological hazard risk.

5. The method according to any one of claims 2 to 4, characterized in that: In the process of checking whether there is a third-party sabotage risk in the current pipeline, the following are included: 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 the preset score evaluation threshold. When there is a straight pipe section in the current pipeline whose total score of various destructive factors exceeds the score evaluation threshold, it is determined that the current pipeline has a third-party destructive risk; or when there is no straight pipe section in the current pipeline whose total score of various destructive factors exceeds the score evaluation threshold, it is determined that the current pipeline does not have a third-party destructive risk.

6. The method according to any one of claims 1 to 5, 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: According to the risk type of the current pipeline, the leakage size of the current pipeline is determined, and the leakage size includes 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 according to the comparison result combined with the leakage area; Determine the leakage duration of the medium in the current pipeline; According to the medium leakage rate and the leakage duration, a theoretical value of gas leakage in the pipeline currently having at least one risk is calculated, so as to estimate 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.

7. The method according to claim 6, characterized in that In the process of determining the failure leakage mode, include: According to the actual gas leakage estimation result of the current risk pipeline, the hydrogen sulfide diffusion radius corresponding to the case where the concentration of the leaked hydrogen sulfide 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.

8. The method according to claim 7, characterized in that The step of locating leakage monitoring points in the failed pipeline according to the predicted leakage mode 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 satisfies the first condition, so as to count the total pipeline length at the step position that satisfies 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; The leakage monitoring point is determined according to the number of abnormal pipelines in the current risk pipeline and the length of each section of the abnormal pipeline.

9. The method according to claim 8, 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 the 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 pipelines 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.

10. The method according to any one of claims 6 to 9, characterized in that: The leakage duration is determined as follows: According to 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, the duration of the medium leakage in the current pipeline is estimated.

11. The method according to any one of claims 1 to 10, characterized in that: The steps of dividing the high-sulfur natural gas field gathering and transportation pipeline network into multiple pipelines include: Taking the cut-off valve in the gathering and transportation pipeline network of the high-sulfur natural gas field as the dividing point, the current pipeline network is preliminarily divided into multiple pipeline sections; If there are pipelines with a laying method different from that of buried pipelines, the current pipeline 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.

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

13. A system for optimizing the location of 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 into multiple pipelines according to the cut-off valves of the high-sulfur natural gas field gathering and transportation pipeline network; A risk assessment module configured to assess the risk of pipeline corrosion due to liquid accumulation, geological disaster risk and third-party damage risk for each pipeline; A leakage identification module configured to estimate the leakage amount of pipelines with at least one risk according to the actual operating conditions of different pipelines, thereby obtaining a corresponding failure leakage mode; The point confirmation module is configured to locate the leakage monitoring point in the failed pipeline according to the leakage mode of the failed pipeline and the population distribution characteristics around the corresponding pipeline.

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