Corrosion analysis method and device for gas pipeline integrity management and medium

Abstract

The invention relates to the technical field of pipeline detection, and particularly discloses a corrosion analysis method and device for gas pipeline integrity management and a medium. The method comprises the following steps: determining a key corrosion risk position; acquiring pipeline state data of the key corrosion risk position; analyzing the pipeline state data based on a preset corrosion prediction model to generate a corrosion degree; determining the residual strength of the key corrosion risk position based on the corrosion degree and the pipeline attribute data; and evaluating the structural integrity of the key corrosion risk position based on the residual strength, and generating a corrosion analysis result. Through corrosion degree analysis and structural integrity analysis of a key corrosion risk position, fundamental conversion from static general detection to dynamic fine detection is realized, a real high-risk position in a current state can be actively identified, the number of unnecessary excavation verification times is greatly reduced, and the construction efficiency is improved. And the maintenance cost is obviously saved, and secondary damage to the pipeline due to excessive detection is avoided.

Description

Technical Field

[0001] This invention relates to the field of pipeline inspection technology, specifically to a corrosion analysis method, apparatus, and medium for the integrity management of gas transmission pipelines. Background Technology

[0002] Natural gas pipelines are critical infrastructure for ensuring national energy security, and their long-term safe operation is of paramount importance. Internal corrosion is one of the main risks threatening their integrity; therefore, accurate assessment and effective management of corrosion risks have always been a focus of industry research. Currently, the standard method widely used in the industry is Internal Corrosion Direct Assessment (ICDA). ICDA is a structured assessment process that uses comprehensive analysis of relevant pipeline data to determine the locations where corrosion risks are most likely to occur.

[0003] However, the locations most likely to be at risk, identified using this method, are fixed after one assessment cycle. In subsequent pipeline operation and maintenance, regardless of the pipeline's operating time or the dynamic changes in internal conditions and environment, inspection and maintenance activities are primarily carried out periodically around the locations most likely to be at risk of corrosion as determined by ICDA. This static characteristic sharply contradicts the dynamic nature of corrosion, leading to two prominent technical problems:

[0004] On the one hand, corrosion of gas pipelines is a gradual process, and its development rate and severity are closely related to operating time, subtle changes in the composition of the medium, and fluctuations in environmental factors. A location identified as high-risk by ICDA in the initial assessment may not experience severe corrosion for a considerable period; while the actual development of corrosion may accelerate in other locations due to changes in operating conditions. Monitoring fixed locations cannot capture this dynamic change, leading to a serious disconnect between the monitoring plan and the actual corrosion risk.

[0005] On the other hand, the need for periodic verification of risk locations identified by ICDA results in frequent unnecessary excavation and opening inspections of many locations that have not yet experienced severe corrosion or have very low corrosion rates. This not only leads to a huge waste of human and material resources and reduces maintenance efficiency, but more seriously, each unnecessary excavation damages the pipeline's original anti-corrosion layer, insulation system, and surrounding soil environment, potentially introducing new corrosion threats and thus compromising the pipeline's inherent airtightness and long-term safety. Summary of the Invention

[0006] In order to overcome the above-mentioned technical problems in the prior art, the present invention provides a corrosion analysis method, apparatus and medium for integrity management of gas transmission pipelines.

[0007] In a first aspect, the present invention provides a corrosion analysis method for integrity management of gas transmission pipelines, the method comprising: identifying key corrosion risk locations; acquiring pipeline status data at the key corrosion risk locations; analyzing the pipeline status data based on a preset corrosion prediction model to generate corrosion degree; determining the remaining strength of the key corrosion risk locations based on the corrosion degree and pipeline attribute data; and evaluating the structural integrity of the key corrosion risk locations based on the remaining strength to generate corrosion analysis results.

[0008] Preferably, determining the location of critical corrosion risks includes: acquiring static and dynamic data of the gas pipeline; constructing a pipeline elevation model based on the static data; determining the local lowest elevation point and inclined pipe sections based on the pipeline elevation model; performing risk prediction on the pipeline elevation model based on the local lowest elevation point, the inclined pipe sections, and the dynamic data to obtain a pre-assessed risk map; determining potential corrosion source pipe sections based on the pre-assessed risk map; and determining the location of critical corrosion risks based on the potential corrosion source pipe sections.

[0009] Preferably, determining the location of critical corrosion risk based on the potential corrosion source pipe section includes:

[0010] Obtain gas property data of the gas transported by the potential corrosion source pipe section; perform liquid carrying capacity analysis on the potential corrosion source pipe section based on the gas property data; determine the critical tilt point based on the liquid carrying capacity analysis results; and determine the key corrosion risk location from the potential corrosion source pipe section based on the critical tilt point.

[0011] Preferably, determining the critical corrosion risk location from the potential corrosion source pipe section based on the critical inclination point includes: determining whether the current critical inclination point is located in a continuous rising segment or a continuous falling segment; if the current critical inclination point is located in the continuous rising segment or the continuous falling segment, determining whether there are other critical inclination points adjacent to the current critical inclination point in the continuous rising segment or the continuous falling segment; if there are other critical inclination points, determining the highest point among the current critical inclination point and the other critical inclination points, and determining the highest point as the critical corrosion risk location; if there are no other critical inclination points, determining the current critical inclination point as the critical corrosion risk location.

[0012] Preferably, the method further includes: constructing an initial corrosion prediction model; acquiring historical pipeline condition data and corresponding historical corrosion data; determining a corrosion enhancement factor based on the historical corrosion data and a standard corrosion rate; and training the initial corrosion prediction model based on the historical pipeline condition data and the corrosion enhancement factor to generate the preset corrosion prediction model.

[0013] Preferably, the assessment of the structural integrity of the critical corrosion risk location based on the remaining strength to generate corrosion analysis results includes: determining whether the current critical corrosion risk location meets the preset structural integrity requirements based on the remaining strength; if so, removing the current critical corrosion risk location to obtain the removed critical corrosion risk location; performing structural integrity analysis on the critical corrosion risk location to generate integrity analysis results; and generating corrosion analysis results based on the integrity analysis results.

[0014] Preferably, the step of performing structural integrity analysis on key corrosion risk locations and generating integrity analysis results includes: when the remaining strength is greater than a preset strength threshold, acquiring stress corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data for the key corrosion risk location; performing structural integrity analysis based on the corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data to generate a first integrity analysis result; when the remaining strength is less than or equal to the preset strength threshold, determining whether the key corrosion risk location is located in a high-consequence zone: if so, performing structural integrity analysis based on the remaining strength, the high-consequence zone, the corrosion cracking detection data, the corrosion rate data, the corrosion size data, and the pipeline deformation data to generate a second integrity analysis result; otherwise, performing structural integrity analysis based on the remaining strength, the corrosion cracking detection data, the corrosion rate data, the corrosion size data, and the pipeline deformation data to generate a third integrity analysis result.

[0015] Preferably, the method further includes: in the case of generating the first integrity analysis result:

[0016] The current critical corrosion risk location is identified as a long-term maintenance location. A ring-shaped ultrasonic sensor array is configured at this location to detect defect expansion information in real time. A long-term maintenance strategy is generated based on this defect expansion information. In the case of generating the second integrity analysis result: the current critical corrosion risk location is identified as a low-risk, high-monitoring location. An internal monitoring system is configured inside the gas pipeline at this low-risk, high-monitoring location. This internal monitoring system includes corrosion probes, gas chromatography-mass spectrometry (GC-MS) sensors, and microbial monitoring sensors. The internal monitoring system acquires internal corrosion rate, GC-MS data, and microbial data in real time. Based on the internal corrosion rate, GC-MS data, and microbial data... The system generates short-term maintenance strategies for current critical corrosion risk locations based on sensor data. Upon generating the third integrity analysis results: the current critical corrosion risk location is identified as a high-risk, heavily monitored location. An internal monitoring system and an external monitoring system are configured on the gas pipeline at the high-risk, heavily monitored location. The external monitoring system includes a cathodic protection monitoring device, a soil sensing device, and a distributed optical fiber sensing device. Based on the external monitoring system, real-time pipeline-to-ground electrical data, soil monitoring data, and optical sensing data are acquired. Based on the optical sensing data, liquid accumulation prediction locations and acoustic vibration data are generated. Based on the internal corrosion rate, the internal gas chromatography-mass spectrometry data, the internal microbial sensing data, the pipeline-to-ground electrical data, the soil monitoring data, the liquid accumulation prediction locations, and the acoustic vibration data, a maintenance strategy is generated for the current critical corrosion risk location.

[0017] Secondly, the present invention provides a corrosion analysis device for integrity management of gas transmission pipelines. The device includes: a location determination module for determining key corrosion risk locations; a corrosion degree determination module for acquiring pipeline state data at the key corrosion risk locations, analyzing the pipeline state data based on a preset corrosion prediction model, and generating a corrosion degree; a remaining strength determination module for determining the remaining strength at the key corrosion risk locations based on the corrosion degree and pipeline attribute data; and an analysis result generation module for evaluating the structural integrity of the key corrosion risk locations based on the remaining strength and generating corrosion analysis results.

[0018] Thirdly, the present invention also provides a computer-readable storage medium having a computer program stored thereon, characterized in that the program, when executed by a processor, implements the method described in any of the preceding claims.

[0019] The present invention has at least the following technical effects through the technical solution provided by the present invention:

[0020] By analyzing the corrosion degree and structural integrity of key corrosion risk locations, a fundamental shift from static general inspection to dynamic precision inspection has been achieved. This proactively identifies truly high-risk locations under the current conditions, greatly reducing unnecessary excavation verification times, significantly saving maintenance costs, and avoiding secondary damage to pipelines caused by excessive inspection.

[0021] Other features and advantages of the embodiments of the present invention will be described in detail in the following detailed description section. Attached Figure Description

[0022] The accompanying drawings are provided to further illustrate embodiments of the present invention and form part of the specification. They are used together with the following detailed description to explain the embodiments of the present invention, but do not constitute a limitation thereof. In the drawings:

[0023] Figure 1 This is a flowchart of a corrosion analysis method for gas pipeline integrity management provided by an embodiment of the present invention;

[0024] Figure 2 This is a schematic diagram of a corrosion analysis device for integrity management of gas pipelines provided in an embodiment of the present invention. Detailed Implementation

[0025] The specific embodiments of the present invention will be described in detail below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are for illustration and explanation only and are not intended to limit the scope of the present invention.

[0026] In this invention, the terms "system" and "network" are used interchangeably. "Multiple" refers to two or more; therefore, in this invention, "multiple" can also be understood as "at least two." "And / or" describes the relationship between related objects, indicating that three relationships can exist. For example, A and / or B can represent: A alone, A and B simultaneously, or B alone. Additionally, the character " / ", unless otherwise specified, generally indicates that the preceding and following related objects have an "or" relationship. Furthermore, it should be understood that in the description of this invention, terms such as "first" and "second" are used only for descriptive purposes and should not be construed as indicating or implying relative importance or order.

[0027] Example 1

[0028] On the one hand, corrosion of gas pipelines is a gradual process, and its development rate and severity are closely related to operating time, subtle changes in medium composition, and fluctuations in environmental factors. A location identified as high-risk by ICDA in the initial assessment may not experience severe corrosion for a considerable period; while the actual development of corrosion may accelerate in other locations due to changes in operating conditions. Monitoring fixed locations cannot capture this dynamic change, leading to a significant disconnect between the monitoring plan and the actual corrosion risk. On the other hand, the need for periodic verification of risk locations identified by ICDA results in numerous locations that have not yet experienced severe corrosion or have very low corrosion rates undergoing frequent unnecessary excavation and opening inspections. This not only wastes enormous human and material resources and reduces maintenance efficiency, but more seriously, each unnecessary excavation damages the pipeline's original anti-corrosion layer, insulation system, and surrounding soil environment, potentially introducing new corrosion threats and compromising the pipeline's inherent airtightness and long-term safety.

[0029] For the reasons mentioned above, please refer to Figure 1 This invention provides a corrosion analysis method for the integrity management of gas transmission pipelines, the method comprising the following steps:

[0030] Step 1: Identify key corrosion risk locations;

[0031] The location of critical corrosion risk can be determined based on the Internal Corrosion Direct Assessment (ICDA) method, based on fluid dynamics simulation, or any other method known in the art.

[0032] Step 2: Obtain pipeline condition data at the key corrosion risk locations. Analyze the pipeline condition data based on a preset corrosion prediction model to generate corrosion levels.

[0033] After identifying the critical corrosion risk locations, further analysis is needed to make them more consistent with actual operating conditions and environment, and to reduce the excavation verification operations at these locations. For example, corrosion analysis can be performed on the critical corrosion risk locations by combining the pipeline status data of the corresponding pipelines.

[0034] In one possible implementation, pipeline status data includes pipeline attribute data, operational status data, and environmental data, such as usage time, pipeline material, slope, internal pipe temperature data, external pipe temperature data, and external soil sensor data. This data is input into a preset corrosion prediction model to predict the corrosion level at corresponding key corrosion risk locations. The preset corrosion prediction model is obtained by training a pre-determined deep learning model based on historical pipeline status data and historical corrosion data. The deep learning model can be a random forest or similar model, and this embodiment of the invention is not limited to any particular model.

[0035] Step 4: Based on the corrosion rate and pipeline property data, determine the remaining strength of the critical corrosion risk locations.

[0036] After conducting corrosion analysis, in order to better reflect the dynamic process of corrosion changes, it is also necessary to perform residual strength analysis on key corrosion locations.

[0037] In one possible implementation, pipeline attribute data includes pipeline thickness, pipeline diameter, and pipeline material. Based on the corrosion degree and pipeline attribute data corresponding to the critical corrosion risk location, relevant mechanical calculation formulas and strength assessment standards, such as ASME B31G, are used to accurately calculate the remaining strength of the critical corrosion risk location, i.e., the maximum pressure it can safely withstand under the current corrosion state.

[0038] Step 5: Assess the structural integrity of the critical corrosion risk locations based on the remaining strength, and generate corrosion analysis results.

[0039] Once the remaining strength is determined, the structural integrity of critical corrosion risk locations can be assessed based on the remaining strength without the need for actual excavation verification.

[0040] This invention, through corrosion analysis and structural integrity analysis of key corrosion risk locations, achieves a fundamental shift from static general inspection to dynamic precision inspection. It can proactively identify truly high-risk locations under the current conditions, greatly reducing unnecessary excavation verification times, significantly saving maintenance costs, and avoiding secondary damage to pipelines caused by excessive testing.

[0041] Example 2

[0042] Traditional Internal Corrosion Direct Assessment (ICDA) methods identify critical corrosion risk locations through a standardized process, relying heavily on a combination of theoretical calculations and empirical judgment. This method begins with analysts using pipeline design drawings, historical operating data, and gas chromatography-mass spectrometry reports, combined with empirical criteria, to mark potential corrosion source sections, such as geographically low points, sections with low flow rates, or specific fittings. Then, a simplified critical liquid-carrying velocity formula is applied, based on average operating parameters, to calculate and screen sections where actual flow rates may be insufficient. Finally, based on the principle of "dry upstream, safe downstream," analysts select a theoretically dry point upstream of the potential corrosion source section as the verification location, i.e., the critical risk location. However, this approach is heavily influenced by the individual experience of technical personnel, and different analysts may reach significantly different conclusions. Furthermore, due to the lack of systematic data analysis tools, traditional methods struggle to effectively integrate multi-dimensional pipeline information and accurately reflect the impact of dynamic changes in operating parameters on risk distribution.

[0043] In this embodiment of the invention, determining the location of critical corrosion risks includes: acquiring static and dynamic data of the gas pipeline; constructing a pipeline elevation model based on the static data; determining the local lowest elevation point and inclined pipe sections based on the pipeline elevation model; performing risk prediction on the pipeline elevation model based on the local lowest elevation point, the inclined pipe sections, and the dynamic data to obtain a pre-assessed risk map; determining potential corrosion source pipe sections based on the pre-assessed risk map; and determining the location of critical corrosion risks based on the potential corrosion source pipe sections.

[0044] Specifically, the static data refers to data describing the spatial geometric characteristics of the pipeline, primarily derived from pipeline design drawings, as-built documentation, and high-precision field survey reports. This data provides the necessary three-dimensional spatial coordinate sequence (i.e., longitude, latitude, and elevation) and mileage markers for constructing a pipeline elevation model. Using specialized geographic information system (GIS) software or pipeline-specific design software, these discrete three-dimensional spatial coordinate points of the pipeline centerline are connected and smoothly interpolated to generate a high-precision digital pipeline longitudinal profile model. This model accurately reflects the actual terrain undulations along the pipeline route and can calculate the slope and inclination angle of each pipeline segment, providing an accurate geometric basis for subsequent simulation models. Furthermore, the dynamic data refers to parameters that change over time during pipeline operation, and the sources include: SCADA system, which provides historical and real-time time-series data such as pressure, temperature, gas velocity, and instantaneous flow rate for each station, valve chamber, and key monitoring point; gas quality analysis reports, which provide key data such as H2S and CO2 concentrations and water vapor content in natural gas, and the water content can be calculated based on the water dew point temperature at a specific operating pressure; and historical maintenance records and internal inspection reports, which provide previous reports of pipeline cleaning and liquid accumulation, leak repair locations, and the coordinates and depth data of corrosion defects on the inner wall of the pipeline.

[0045] In one possible implementation, a pipeline elevation model is established based on static data such as pipeline design drawings, GIS geographic information systems, and actual surveying data. Based on this model, local lowest elevation points and inclined pipe sections are determined. The constructed pipeline elevation model is imported into simulation software, and the corresponding local lowest elevation points and inclined pipe sections are marked as the base scene. A mapping relationship between dynamic data and the geographical location of the pipeline elevation model is then established. For example, SCADA data is matched to corresponding coordinate points on the model based on its measurement point locations. For pipe sections without direct measurement points, hydraulic calculations are used for interpolation to assign corresponding pressure, temperature, and flow velocity values ​​to each calculation unit in the pipeline elevation model. Similarly, the calculated water dew point temperature is also assigned as an attribute value to each unit. The simulation software's built-in simulation engine is then run. This simulation engine, based on fluid mechanics, thermodynamics, and multiphase flow theory, simulates the flow state, temperature drop process, and potential free water precipitation and accumulation behavior of natural gas under specific terrain and operating conditions. After the simulation, a pre-assessment risk map is generated. This map typically uses the pipeline longitudinal profile as a base map, overlaid with different colors, legends, and risk layers. Furthermore, based on built-in preset risk feature rules, high-risk areas are automatically identified and highlighted. For example: geographical low points (the lowest elevation point after a continuous downhill slope) are marked with red triangles; low-flow-rate pipe sections (segments where the flow rate is consistently lower than the minimum allowable flow rate calculated by the software) are filled with yellow areas; pipe sections with wall temperatures below the water dew point (i.e., sections where condensation may exist) are highlighted with blue shading; pipe sections with internal geometric features (such as valves, tees, elbows, and reducers) located in low-lying areas are marked with special icons; and areas with historical liquid accumulation or corrosion records are overlaid with the above layers for verification. Finally, all continuous pipe segments in the diagram that meet one or more of the above high-risk characteristics are delineated and formally identified as potential corrosion source segments that require further detailed analysis. At the same time, a detailed report is generated that includes the location, length, type and number of risk characteristics met by each potential corrosion source segment, providing precise targets for subsequent analysis.

[0046] This invention, through the construction of a pipeline elevation model and the performance of multi-data overlay simulation, achieves the systematization and automation of the pre-assessment process. Compared to traditional manual experience-based judgment, it can objectively and efficiently integrate massive amounts of static and dynamic data and output a visualized risk map; it greatly improves the accuracy, comprehensiveness, and consistency of identifying potential corrosion source pipe sections, providing a reliable and clear target range for the entire corrosion analysis process and laying an efficient data foundation.

[0047] Furthermore, after identifying potential corrosion source sections, it is necessary to precisely locate the most likely corrosion risk locations within these sections. Potential corrosion source sections typically cover a wide area, with significant differences in the likelihood and severity of corrosion at different internal locations. Without further refinement, it remains difficult to conduct targeted analysis and maintenance. In gas pipelines, liquid accumulation is a key factor accelerating corrosion because liquids often contain significant amounts of corrosive components. When liquid accumulates within a pipe section, it comes into prolonged contact with the pipe wall, creating a localized high-corrosion environment and accelerating the corrosion process. Therefore, the ICDA (Integrated Circuit Assessment) for direct internal corrosion assessment uses simplified formulas to provide a uniform, averaged assessment of the entire pipeline or a large section, such as a rough comparison between average flow velocity and empirical critical values. However, in practical applications, this method cannot accurately capture the abrupt changes in flow patterns caused by dramatic local topographical variations. Consequently, it is difficult to accurately locate the critical mechanical boundary point that leads to the initial stabilization of the liquid film. This results in a lack of precise guidance for the verification principle based on "dry upstream means safe downstream," potentially leading to the incorrect selection of invalid verification points.

[0048] In this embodiment of the invention, determining the location of critical corrosion risk based on the potential corrosion source pipe section includes: acquiring gas property data of the gas transported by the potential corrosion source pipe section; performing liquid carrying capacity analysis on the potential corrosion source pipe section based on the gas property data; determining the critical tilt point based on the liquid carrying capacity analysis results; and determining the location of critical corrosion risk from the potential corrosion source pipe section based on the critical tilt point.

[0049] In one possible implementation, gas property data of the gas transported in the potential corrosion source pipe section is collected, including gas density, viscosity, flow velocity, water content, and corrosive component content. Based on this gas property data, fluid mechanics principles and calculation methods are used to analyze the liquid-carrying capacity of the gas in the potential corrosion source pipe section, determining whether the gas can effectively carry liquid flow at different locations in the potential corrosion source pipe section. Based on the liquid-carrying capacity analysis results, a critical inclination angle point is determined. This point is the upstream point where the gas can no longer continuously carry away liquid due to an excessively steep inclination angle, thus initiating a liquid accumulation trend. Finally, the critical corrosion risk locations are determined based on the critical inclination angle point.

[0050] For example, gas property data of the gas transported in the pipeline section at the potential corrosion source are collected, including gas density, viscosity, actual operating flow rate, water content, and corrosive component content. Simultaneously, pipeline parameters such as pipe diameter, inclination angle, and surface tension are also collected. Based on these gas property data and pipeline parameters, using professional oil and gas multiphase flow simulation software (such as Schlumberger's OLGA or Baker Hughes's PIPESIM), and applying multiphase flow mechanism models from fluid mechanics, the liquid-carrying capacity of the gas in the pipeline section at the potential corrosion source is analyzed. Specifically, this is achieved by calculating and comparing the actual gas flow rate with the critical liquid-carrying flow rate, where the critical liquid-carrying flow rate adopts an industry-recognized model (such as the improved Turner model or Eaton model). The model (either a built-in mechanism model or a simulation engine) is used to calculate the minimum gas velocity required to continuously carry away droplets generated in the pipeline and prevent their accumulation, taking into account factors such as gas density, liquid density, surface tension, pipe diameter, and pipe section inclination angle. Based on the liquid-carrying capacity analysis results, the critical inclination angle is determined. The analysis process follows the order from upstream to downstream, discretizing the potential corrosion source pipe section into several nodes. Starting from the inlet of the potential corrosion source pipe section, the software calculates the liquid-carrying capacity of the airflow point by point along the gas flow direction. The simulation engine continuously calculates and judges the airflow state at each calculation node. The node where the actual gas velocity begins to continuously fall below the critical liquid-carrying velocity calculated at that point during the downstream flow of the airflow is defined as the critical inclination angle, and the critical inclination angle is identified as a key risk location.

[0051] This invention, through point-by-point detailed liquid-carrying capacity analysis of potential corrosion source pipe sections, can accurately locate critical inclination points, overcoming the limitations of traditional averaging estimation. It clearly reveals the flow state transition location from liquid-carrying to liquid-incapable, providing reliable physical basis and precise coordinate guidance for determining key corrosion risk locations, enabling subsequent analysis to be carried out efficiently and accurately.

[0052] Furthermore, after determining the critical inclination point, it can be directly used as the key corrosion risk location. However, this method does not consider the specific distribution of the critical inclination point in the pipe section, such as whether it is located in a continuous rising or falling section, or whether there are other adjacent critical inclination points. It simply treats all critical inclination points as key corrosion risk locations, resulting in an overly complex list of key corrosion risk locations. These locations may include some with relatively low actual corrosion risk, increasing the workload of subsequent analysis and maintenance. It may also affect the focus on truly high-risk locations. Therefore, the process of determining key corrosion risk locations based on critical inclination points needs to be optimized.

[0053] In this embodiment of the invention, determining the critical corrosion risk location from the potential corrosion source pipe section based on the critical inclination point includes: determining whether the current critical inclination point is located in a continuous rising segment or a continuous falling segment; if the current critical inclination point is located in the continuous rising segment or the continuous falling segment, determining whether there are other critical inclination points adjacent to the current critical inclination point in the continuous rising segment or the continuous falling segment; if there are other critical inclination points, determining the highest point among the current critical inclination point and the other critical inclination points, and determining the highest point as the critical corrosion risk location; if there are no other critical inclination points, determining the current critical inclination point as the critical corrosion risk location.

[0054] In one possible implementation, a detailed segmental analysis is first conducted on the pipe section at the potential corrosion source to clarify the specific range and direction of the continuous ascending and descending sections. Then, each critical inclination point is checked one by one to determine whether it is located within these continuous ascending or descending sections. If the current critical inclination point is found to be located within a continuous ascending or descending section, a comprehensive investigation is then conducted on that section to check for any other critical inclination points adjacent to the current critical inclination point. The criteria for determining adjacency can be reasonably set based on the actual situation of the pipe section and engineering experience. If other critical inclination points exist within the continuous ascending or descending section, the elevations of the current critical inclination point and the other critical inclination points are compared and analyzed to determine the highest point, which is then identified as the critical corrosion risk location. If no other critical inclination points exist within the continuous ascending or descending section, it indicates that the current critical inclination point is a relatively independent high-risk point within that section, and it is directly identified as the critical corrosion risk location.

[0055] The embodiments of the present invention fully consider the distribution of critical inclination points in the pipe section and the influence of adjacent critical inclination points. By analyzing and screening the critical inclination points in the continuous rising and continuous falling sections, the location with the real high corrosion risk can be accurately identified from a large number of critical inclination points.

[0056] Example 3

[0057] After identifying key corrosion risk locations, corrosion intensity analysis is required for these locations, and a pre-defined corrosion prediction model is the crucial foundation for this analysis. While existing corrosion prediction models can output corrosion intensity based on pipeline condition data, they lack a specific factor to correct for discrepancies between standard corrosion rates and actual corrosion conditions. Due to differences in medium characteristics and operating environments, actual corrosion rates in different gas pipelines often differ significantly from standard values. For example, corrosion rates in high-sulfur environments far exceed standard values, leading to distorted corrosion intensity calculations using only a general model. Therefore, a method is urgently needed that can determine corrosion enhancement factors using historical data and use them to optimize the model, thereby improving the accuracy of corrosion intensity prediction.

[0058] In this embodiment of the invention, the method further includes: constructing an initial corrosion prediction model; acquiring historical pipeline condition data and corresponding historical corrosion data; determining a corrosion enhancement factor based on the historical corrosion data and a standard corrosion rate; and training the initial corrosion prediction model based on the historical pipeline condition data and the corrosion enhancement factor to generate the preset corrosion prediction model.

[0059] In one possible implementation, when constructing a preset corrosion prediction model, an initial model is first built based on the electrochemical and chemical mechanisms of gas pipeline corrosion, combined with influencing factors such as medium composition and temperature, using algorithms such as neural networks. The input is pipeline state data, and the output is corrosion degree. Next, a large amount of historical pipeline state data is collected, including pipeline material, pipeline usage time, pipeline slope, pipeline angle, flow rate inside the pipe, flow velocity inside the pipe, temperature inside the pipe, temperature outside the pipe, soil sensor data, and corresponding historical corrosion data such as historical corrosion degree. Then, a historical corrosion degree enhancement factor is calculated. Based on the historical corrosion degree and time information, the historical corrosion rate is calculated. The historical corrosion rate is compared with the standard corrosion rate to obtain a corrosion degree enhancement factor that reflects the difference between actual and standard corrosion. If the actual corrosion rate is 1.5 times the standard corrosion rate, the corrosion degree enhancement factor is 1.5. Afterwards, using historical pipeline state data as input and the historical corrosion degree enhancement factor as the adjustment basis, the initial model is trained, and the parameters are continuously corrected so that the corrosion degree output by the model, after adjustment by the corrosion degree factor, is consistent with the actual corrosion situation, ultimately obtaining the preset corrosion prediction model.

[0060] This embodiment introduces a historical corrosion enhancement factor for model training, enabling the preset corrosion prediction model to accurately capture the actual corrosion characteristics of specific pipelines and effectively correct the deviation between the standard corrosion rate and the actual situation. The corrosion calculated based on this model is closer to the actual corrosion state of the pipeline, providing accurate data for determining the remaining strength and assessing the structural integrity.

[0061] Example 4

[0062] In practical applications, if a comprehensive structural integrity analysis is performed on all identified key corrosion risk locations, a significant amount of time and resources will be wasted on locations that actually meet structural integrity requirements but do not require special attention. This can lead to a waste of resources and may also affect the depth and efficiency of the analysis of locations with actual structural integrity problems due to the large number of analysis objects. Consequently, it may be impossible to generate targeted corrosion analysis results in a timely and accurate manner. Therefore, it is necessary to optimize the structural integrity assessment process based on residual strength.

[0063] In this embodiment of the invention, the structural integrity of the critical corrosion risk location is evaluated based on the remaining strength to generate corrosion analysis results, including: determining whether the current critical corrosion risk location meets the preset structural integrity requirements based on the remaining strength; if so, removing the current critical corrosion risk location to obtain the removed critical corrosion risk location; performing structural integrity analysis on the critical corrosion risk location to generate integrity analysis results; and generating corrosion analysis results based on the integrity analysis results.

[0064] By first determining whether the preset structural integrity requirements are met and eliminating positions that do not meet the requirements, the present invention effectively reduces the workload of subsequent structural integrity analysis, avoids waste of resources, improves the efficiency of analysis work, and makes the generated corrosion analysis results more targeted and practical.

[0065] Furthermore, during the integrity analysis process, analysis results can be directly generated based on the remaining strength and a preset remaining strength threshold. For example, if the remaining strength is greater than the preset threshold, the structure at the critical corrosion risk location is determined to be relatively intact; conversely, if it is less than the threshold, the structure at the critical corrosion risk location is determined to be incomplete. However, this method lacks sufficient focus and depth, failing to fully reflect the structural integrity of critical locations under different remaining strength conditions. Additionally, it does not provide special attention or a more comprehensive analysis for critical locations in high-consequence zones, potentially leading to inaccurate risk assessments of these locations. Therefore, the structural integrity analysis process needs optimization.

[0066] In this embodiment of the invention, the step of performing structural integrity analysis on critical corrosion risk locations and generating integrity analysis results includes: when the remaining strength is greater than a preset strength threshold, acquiring stress corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data for the critical corrosion risk location; performing structural integrity analysis based on the corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data to generate a first integrity analysis result; when the remaining strength is less than or equal to the preset strength threshold, determining whether the critical corrosion risk location is located in a high-consequence zone: if so, performing structural integrity analysis based on the remaining strength, the high-consequence zone, the corrosion cracking detection data, the corrosion rate data, the corrosion size data, and the pipeline deformation data to generate a second integrity analysis result; otherwise, performing structural integrity analysis based on the remaining strength, the corrosion cracking detection data, the corrosion rate data, the corrosion size data, and the pipeline deformation data to generate a third integrity analysis result.

[0067] In one possible implementation, after eliminating key corrosion risk locations that meet preset structural integrity requirements based on remaining strength, to achieve accurate analysis of these eliminated key corrosion risk locations, before conducting structural integrity analysis, an integrity analysis model adapted to different remaining strength ranges is constructed based on the different relationships between remaining strength and preset strength thresholds. This integrity analysis model can be selected as a model incorporating machine learning algorithms. Specifically, after eliminating key corrosion risk locations that meet preset structural integrity requirements based on remaining strength, differentiated structural integrity analysis is first conducted for the eliminated key corrosion risk locations based on the relationship between remaining strength and preset strength thresholds: if the remaining strength is greater than the preset strength threshold, stress corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data are collected at this location using professional testing equipment. The stress corrosion cracking detection data includes crack length, the corrosion rate data includes annual corrosion rate, the corrosion size data includes corrosion depth, corrosion length, corrosion width, corrosion location, and corrosion direction data, and the pipeline deformation data includes radial deformation and curvature. These data are then input into the corresponding integrity analysis model for further analysis. The system analyzes and generates the corresponding first integrity analysis result. If the remaining strength is less than or equal to the preset strength threshold, it first compares the pipeline geographic information system with the high-consequence area database to determine whether the location is in a high-consequence area. High-consequence areas include densely populated areas and ecologically sensitive areas. The risk weight coefficient of high-consequence areas includes population density weight and environmental sensitivity weight. If yes, the remaining strength data, the risk weight coefficient of the high-consequence area, corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data are input into the corresponding integrity analysis model to generate the corresponding second integrity analysis result. If no, the remaining strength, corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data are input into the corresponding integrity analysis model to generate the third integrity analysis result.

[0068] This invention employs differentiated analysis strategies based on the remaining strength at key corrosion risk locations and whether they are located in high-consequence zones, making the analysis process more targeted and reasonable. For locations with remaining strength greater than a preset strength threshold, the focus is on potential corrosion impacts, enabling the timely detection of early corrosion hazards. For locations with remaining strength less than or equal to the preset strength threshold, especially those located in high-consequence zones, a more comprehensive and rigorous analysis is conducted to fully assess their risk status and avoid serious consequences due to insufficient analysis.

[0069] Furthermore, after generating more reasonable integrity analysis results, corresponding operation and maintenance strategies can be generated based on the integrity analysis results, including at least monitoring configuration and maintenance strategies.

[0070] In this embodiment of the invention, the method further includes: when generating the first integrity analysis result: determining the current critical corrosion risk location as a long-term maintenance location, configuring a ring-shaped ultrasonic sensor array at the long-term maintenance location, the ring-shaped ultrasonic sensor array being used to detect defect expansion information at the current critical corrosion risk location in real time; generating a long-term maintenance strategy for the current critical corrosion risk location based on the defect expansion information; when generating the second integrity analysis result: determining the current critical corrosion risk location as a low-risk, high-monitoring location, configuring an internal monitoring system inside the gas pipeline at the low-risk, high-monitoring location, the internal monitoring system including a corrosion probe, a gas chromatography-mass spectrometry (GC-MS) sensor, and a microbial monitoring sensor; acquiring internal corrosion rate, internal GC-MS sensor data, and internal microbial sensor data in real time based on the internal monitoring system; and based on the internal corrosion rate, the... The internal gas chromatography-mass spectrometry (GCMS) data and the internal microbial sensing data are used to generate a short-term maintenance strategy for the current critical corrosion risk location. Based on the third integrity analysis results, the current critical corrosion risk location is identified as a high-risk, heavily monitored location. An internal monitoring system and an external monitoring system are configured at the gas pipeline in the high-risk, heavily monitored location. The external monitoring system includes a cathodic protection monitoring device, a soil sensing device, and a distributed optical fiber sensing device. Based on the external monitoring system, real-time pipeline-to-ground electrical data, soil monitoring data, and optical sensing data are acquired. Based on the optical sensing data, a predicted location for liquid accumulation and acoustic vibration data are generated. Based on the internal corrosion rate, the internal GCMS data, the internal microbial sensing data, the pipeline-to-ground electrical data, the soil monitoring data, the predicted location for liquid accumulation, and the acoustic vibration data, a maintenance strategy for the current critical corrosion risk location is generated.

[0071] In one possible implementation, after generating different types of integrity analysis results, appropriate monitoring configurations and maintenance strategies are developed for each type of result:

[0072] When the first integrity analysis result is generated, the location corresponding to the remaining strength exceeding the preset strength threshold and requiring attention to potential corrosion risk is identified as the long-term maintenance location. A ring-shaped ultrasonic sensor array is uniformly arranged along the circumference of the pipeline. The sensor installation density is adjusted according to the pipeline diameter and the areas prone to potential defects to ensure full coverage of the pipeline circumference. This array collects defect expansion information of the pipeline inner wall in real time, including changes in crack length and the increase in corrosion pit depth. The collection frequency is set to once per hour, and the data is uploaded to the back-end management system in real time. The back-end system analyzes the defect development rate based on historical defect expansion data and trend prediction algorithms, determines whether it is close to the preset intervention threshold, and then generates a long-term maintenance strategy. The strategy includes suggestions for dynamic adjustment of the monitoring cycle, annual maintenance inspection time windows (determined in conjunction with the pipeline shutdown plan), and potential risk intervention measures (such as initiating local anti-corrosion reinforcement when the defect approaches the threshold). When the second integrity analysis results are generated, locations with residual strength less than or equal to the preset strength threshold and located in high-consequence zones are designated as low-risk, high-monitoring locations. An internal monitoring system is embedded within the gas pipeline: corrosion probes are installed at locations prone to corrosion on the pipeline's inner wall to collect internal corrosion rates in real time; gas chromatography-mass spectrometry (GC-MS) sensors are positioned in sections with stable media flow to monitor key parameters such as moisture content and sulfur content; and microbial monitoring sensors are installed at the bottom of the pipeline in areas prone to liquid accumulation to detect the types and quantities of microorganisms on the inner wall. The data acquisition frequency for all three sensors is set to once every 30 minutes, and the data is uploaded wirelessly. Based on the real-time acquired internal corrosion rates, GC-MS data, and microbial data, the impact of abnormal parameter changes (such as a sudden increase in moisture content or excessive microbial numbers) on accelerating corrosion is analyzed, and short-term maintenance strategies are generated. These strategies include short-term inspection frequencies (such as weekly on-site checks), media parameter control recommendations (such as adjusting the dehydration process to reduce moisture content), and microbial inhibition measures (such as injecting corrosion inhibitors).

[0073] When the third integrity analysis results are generated, locations with residual strength less than or equal to the preset strength threshold and not located in high-consequence zones are identified as high-risk, high-monitoring locations. In addition to the aforementioned internal monitoring system, an external monitoring system is installed outside the pipeline: a cathodic protection monitoring device is installed near the cathodic protection station on the outer wall of the pipeline to collect pipe-to-ground potential and protection current; a soil sensor is buried in the soil within 1 meter of the pipeline perimeter to monitor soil moisture content, pH value, and resistivity; a distributed fiber optic sensor is laid along the pipeline axis inside the pipeline insulation layer to collect pipeline temperature distribution and vibration signals. The data acquisition frequency of the external system is consistent with that of the internal system, both occurring every 30 minutes. The distributed fiber optic sensor data requires further processing: liquid accumulation prediction locations are located based on temperature anomaly points; areas with temperatures below the medium dew point are identified as potential liquid accumulation zones; acoustic vibration data is generated through vibration signal spectrum analysis to identify abnormal pipeline vibration frequencies and amplitudes; finally, the internal and external monitoring data are integrated to analyze internal and external factors (such as internal medium corrosion + ...). The synergistic effect of enhanced external soil corrosivity generates a maintenance strategy, which includes emergency maintenance priority ranking (e.g., listing abnormal pipe-to-ground potential as the highest priority), repair scheme selection suggestions (e.g., partial replacement of pipes or use of lining repair), and 24-hour real-time monitoring alarm thresholds (e.g., triggering audible and visual alarms when the corrosion rate exceeds the limit).

[0074] This invention, through matching appropriate monitoring configurations and maintenance strategies to different integrity analysis results, accurately addresses the needs of different risk levels, avoiding the resource waste and data bias issues of traditional single monitoring. It also allows maintenance personnel to operate directly according to the strategies, shortening the "analysis-execution" cycle. At the same time, internal and external collaborative monitoring of high-risk locations can promptly capture multi-factor corrosion risks. Combined with maintenance priority recommendations, it effectively reduces the probability of pipeline failure and ensures the safe operation of pipelines.

[0075] Please refer to Figure 2 This invention provides a corrosion analysis device for integrity management of gas transmission pipelines. The device includes: a location determination module for determining key corrosion risk locations; a corrosion degree determination module for acquiring pipeline state data at the key corrosion risk locations, analyzing the pipeline state data based on a preset corrosion prediction model, and generating a corrosion degree; a remaining strength determination module for determining the remaining strength at the key corrosion risk locations based on the corrosion degree and pipeline attribute data; and an analysis result generation module for evaluating the structural integrity of the key corrosion risk locations based on the remaining strength and generating corrosion analysis results.

[0076] It should be understood that the corrosion analysis device for gas pipeline integrity management provided in this embodiment of the invention and the corrosion analysis method for gas pipeline integrity management provided in the above embodiments are based on the same inventive concept. For more specific working principles of each module in this embodiment of the invention, please refer to the above embodiments, which will not be repeated in this embodiment of the invention.

[0077] Furthermore, embodiments of the present invention also provide a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the method described in any one of the above embodiments.

[0078] The optional embodiments of the present invention have been described in detail above with reference to the accompanying drawings. However, the embodiments of the present invention are not limited to the specific details in the above embodiments. Within the scope of the technical concept of the embodiments of the present invention, various simple modifications can be made to the technical solutions of the embodiments of the present invention, and these simple modifications all fall within the protection scope of the embodiments of the present invention.

[0079] It should also be noted that the various specific technical features described in the above embodiments can be combined in any suitable manner without contradiction. To avoid unnecessary repetition, the embodiments of the present invention will not describe the various possible combinations separately.

[0080] Those skilled in the art will understand that all or part of the steps in the methods of the above embodiments can be implemented by a program instructing related hardware. This program is stored in a storage medium and includes several instructions to cause a microcontroller, chip, or processor to execute all or part of the steps of the methods described in the various embodiments of this application. The aforementioned storage medium includes various media capable of storing program code, such as a USB flash drive, a portable hard drive, a read-only memory (ROM), a random access memory (RAM), a magnetic disk, or an optical disk.

[0081] Furthermore, various different implementations of the present invention can be combined arbitrarily, as long as they do not violate the spirit of the present invention, they should also be regarded as the content disclosed in the present invention.

Claims

1. A corrosion analysis method for integrity management of gas transmission pipelines, characterized in that, The method includes: Identify key corrosion risk locations; Obtain pipeline status data at the key corrosion risk locations; The corrosion level is generated by analyzing the pipeline condition data based on a preset corrosion prediction model. Based on the corrosion rate and pipeline property data, the remaining strength at the critical corrosion risk locations is determined; The structural integrity of the critical corrosion risk locations is assessed based on the remaining strength, and corrosion analysis results are generated.

2. The corrosion analysis method for gas pipeline integrity management according to claim 1, characterized in that, Identify key corrosion risk locations, including: Acquire static and dynamic data of gas pipelines; A pipeline elevation model is constructed based on the static data; Based on the pipeline elevation model, the local lowest elevation point and the inclined pipe section are determined. Based on the local lowest elevation point, the inclined pipe section, and the dynamic data, the pipeline elevation model is used to perform risk prediction, resulting in a pre-assessment risk map. Based on the aforementioned pre-assessment risk map, potential corrosion source pipe sections are identified; Based on the potential corrosion source pipe sections, the locations of key corrosion risks were identified.

3. The corrosion analysis method for gas pipeline integrity management according to claim 2, characterized in that, Based on the aforementioned potential corrosion source pipe sections, key corrosion risk locations were identified, including: Obtain gas property data of the gas transported by the pipeline segment at the potential source of corrosion; Based on the gas property data, the liquid carrying capacity of the potential corrosion source pipe section is analyzed. The critical tilt point was determined based on the liquid carrying capacity analysis results. The critical corrosion risk location is determined from the potential corrosion source pipe section based on the critical inclination point.

4. The corrosion analysis method for gas pipeline integrity management according to claim 3, characterized in that, Based on the critical inclination point, the location of the critical corrosion risk is determined from the potential corrosion source pipe section, including: Determine whether the current critical tilt point is located in a continuous rising segment or a continuous falling segment; If the current critical tilt point is located in the continuous rising segment or the continuous falling segment, determine whether there are other critical tilt points adjacent to the current critical tilt point in the continuous rising segment or the continuous falling segment. If other critical dip points exist, determine the highest point among the current critical dip point and the remaining critical dip points, and identify the highest point as the key corrosion risk location; If no other critical dip points exist, the current critical dip point will be identified as the location of critical corrosion risk.

5. The corrosion analysis method for gas pipeline integrity management according to claim 1, characterized in that, The method further includes: Construct an initial corrosion prediction model; Acquire historical pipeline status data and corresponding historical corrosion data; The corrosion enhancement factor is determined based on the historical corrosion data and the standard corrosion rate. The initial corrosion prediction model is trained based on the historical pipeline condition data and the corrosion enhancement factor to generate the preset corrosion prediction model.

6. The corrosion analysis method for gas pipeline integrity management according to claim 1, characterized in that, The structural integrity of the critical corrosion risk locations is assessed based on the remaining strength, generating corrosion analysis results, including: Based on the remaining strength, determine whether the current critical corrosion risk location meets the preset structural integrity requirements; If so, remove the current critical corrosion risk locations to obtain the removed critical corrosion risk locations; Structural integrity analysis is performed on key corrosion risk locations, and integrity analysis results are generated. Corrosion analysis results are generated based on the integrity analysis results.

7. The corrosion analysis method for gas pipeline integrity management according to claim 6, characterized in that, The structural integrity analysis of key corrosion risk locations generates integrity analysis results, including: When the remaining strength is greater than a preset strength threshold, stress corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data are acquired for the key corrosion risk locations. Based on the corrosion cracking detection data, corrosion rate data, corrosion size data, and pipeline deformation data, structural integrity analysis is performed to generate a first integrity analysis result. If the remaining strength is less than or equal to the preset strength threshold, determine whether the critical corrosion risk location is located in a high-consequence zone: If so, a structural integrity analysis is performed based on the remaining strength, the high-consequence zone, the corrosion cracking detection data, the corrosion rate data, the corrosion size data, and the pipeline deformation data to generate a second integrity analysis result; Otherwise, a third integrity analysis result is generated based on the remaining strength, the corrosion cracking detection data, the corrosion rate data, the corrosion size data, and the pipeline deformation data.

8. The corrosion analysis method for gas pipeline integrity management according to claim 7, characterized in that, The method further includes: In the case of generating the first integrity analysis result: The current critical corrosion risk location is identified as a long-term maintenance location, and a ring-shaped ultrasonic sensor array is configured at the long-term maintenance location. The ring-shaped ultrasonic sensor array is used to detect the defect expansion information at the current critical corrosion risk location in real time. Based on the defect extension information, a long-term maintenance strategy is generated for the current critical corrosion risk locations; In the case of generating the second integrity analysis result: The current critical corrosion risk location is identified as a low-risk, high-monitoring location. An internal monitoring system is installed inside the gas pipeline at the low-risk, high-monitoring location. The internal monitoring system includes corrosion probes, gas chromatography-mass spectrometry sensors, and microbial monitoring sensors. The internal monitoring system acquires internal corrosion rate, internal gas atmosphere sensor data, and internal microbial sensor data in real time. Based on the internal corrosion rate, the internal gas chromatography-mass spectrometry data, and the internal microbial sensing data, a short-term maintenance strategy is generated for the current critical corrosion risk locations. In the case of generating the third integrity analysis result: The current critical corrosion risk location is identified as a high-risk, high-monitoring location. The gas pipeline at the high-risk, high-monitoring location is equipped with the internal monitoring system and the external monitoring system. The external monitoring system includes a cathodic protection monitoring device, a soil sensing device, and a distributed optical fiber sensing device. Based on the external monitoring system, real-time data of pipe-to-ground electricity, soil monitoring data, and optical sensing data are acquired, and the predicted location of liquid accumulation and acoustic vibration data are generated based on the optical sensing data. Based on the internal corrosion rate, internal gas chromatography-mass spectrometry data, internal microbial sensing data, pipe-to-ground electrical data, soil monitoring data, predicted liquid accumulation location, and acoustic-vibration data, a maintenance strategy is generated for the current critical corrosion risk location.

9. A corrosion analysis device for integrity management of gas pipelines, characterized in that, The device includes: Location determination module, used to identify key corrosion risk locations; The corrosion determination module is used to acquire pipeline status data at the key corrosion risk locations, analyze the pipeline status data based on a preset corrosion prediction model, and generate corrosion degree. The remaining strength determination module is used to determine the remaining strength of the critical corrosion risk locations based on the corrosion degree and pipeline attribute data. The analysis results generation module is used to assess the structural integrity of the critical corrosion risk locations based on the remaining strength and generate corrosion analysis results.

10. A computer-readable storage medium having a computer program stored thereon, characterized in that, When the program is executed by the processor, it implements the method of any one of claims 1-8.

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