Flow metering system and method based on intelligent sensor

Abstract

The invention provides a flow metering system and method based on an intelligent sensor. The method comprises the following steps: determining a gas flow field of natural gas at each bending position in a pipeline according to pressure difference characteristics in pressure data; determining the flow velocity gradient of natural gas in the pipeline according to all the gas flow fields, and determining a sudden change area of the flow velocity through the flow velocity gradient; determining the compression ratio when the natural gas flows in the pipeline according to the change trend characteristics of all the gas densities; performing fluctuation analysis on the flow of the natural gas in the pipeline according to the sudden change area of the flow velocity and the compression ratio to obtain a plurality of flow fluctuation values in the flowing process of the natural gas in the pipeline, and determining the credible volume flow of the natural gas output in the pipeline according to all the flow fluctuation values. By the adoption of the scheme, the influence of flow field disturbance on the natural gas flow in the metering pipeline can be reduced.

Description

Technical Field

[0001] This application relates to the technical field of equipment metrology. More specifically, this application relates to a flow metering system and method based on intelligent sensors. Background Art

[0002] Equipment metrology refers to the process of precisely measuring, evaluating, and managing equipment to ensure its accuracy, reliability, and stability. In a highly technological society, equipment plays an important role in all walks of life, and their performance and accuracy directly affect production efficiency and product quality. Therefore, equipment metrology is an important means to ensure the normal operation and effective management of equipment.

[0003] The flow metering of natural gas refers to the process of precisely measuring gas flow rate, pressure, and other related parameters in a centralized gas supply system specifically used to supply gases such as oxygen in hospitals or other medical facilities. This process ensures that the oxygen supply system can provide sufficient, stable, and appropriate amounts of oxygen to patients according to predetermined standards, and ensures the safety, accuracy, and reliability during the gas transportation process; in the existing process of natural gas flow metering, by measuring the flow velocity of natural gas at the straight pipe position in the pipeline, and then analyzing the volume flow rate of natural gas through this gas flow rate. Since there are both elbow positions and straight pipe positions in the pipeline, and there is laminar fluid at the elbow position, that is, laminar fluid indicates that the flow of the fluid presents a smooth and hierarchical flow pattern, where each layer of fluid slides smoothly along the axial direction of the pipeline, and there is almost no relative movement between fluid molecules, thus causing flow field disturbances in the natural gas in the pipeline. If the volume flow rate is calculated according to the horizontal straight pipe flow field, a large error will occur. Therefore, how to reduce the influence of flow field disturbances on the natural gas flow rate in the metering pipeline has become a problem faced by the industry. Summary of the Invention

[0004] This application provides a flow metering system and method based on intelligent sensors, which can reduce the influence of flow field disturbances on the natural gas flow rate in the metering pipeline.

[0005] In a first aspect, this application provides a method for flow metering of natural gas in a pipeline, including the following steps: Arrange a plurality of sensor nodes on the inner wall of the pipeline for transporting natural gas, and collect the pressures of each sensing node in the inner wall of the pipeline during the transportation of natural gas through a pressure sensor to obtain pressure data; Determine the gas flow field at each bending position of the natural gas in the pipeline based on the differential characteristics of the pressures in the pressure data and the bending characteristics of the pipeline; Conduct a gradient analysis on the flow velocity of the natural gas in the pipeline based on all the gas flow fields to obtain the flow velocity gradient of the natural gas in the pipeline, and determine the sudden change region of the flow velocity during the flow of the natural gas in the pipeline through the flow velocity gradient; The gas density at each sensing node of natural gas in the pipeline is collected by a density sensor, and the compression ratio during the flow of natural gas in the pipeline is determined based on the change trend characteristics of all gas densities; Perform fluctuation analysis on the flow rate of natural gas in the pipeline according to the mutation region of the flow rate and the compression ratio, obtain multiple flow rate fluctuation values during the flow of natural gas in the pipeline, and determine the credible volume flow rate of the output natural gas in the pipeline through all the flow rate fluctuation values.

[0006] In some embodiments, determining the specific gas flow field at each bending position of natural gas in the pipeline through the difference characteristics of the pressure in the pressure data and the bending characteristics of the pipeline specifically includes: Determine the difference characteristics of the pressure in the pressure data; Determine the bending characteristics of the pipeline; Determine multiple flow rate difference amounts of natural gas in the pipeline according to the difference characteristics; Determine the gas flow field at each bending position of natural gas in the pipeline through all the flow rate difference amounts and the bending characteristics.

[0007] In some embodiments, performing gradient analysis on the flow rate of natural gas in the pipeline according to all the gas flow fields to obtain the flow rate gradient of natural gas in the pipeline specifically includes: Determine the gas boundary layer at each bending position of natural gas in the pipeline according to all the gas flow fields; Determine the straight-channel gas flow rate of each straight channel in the pipeline; Determine multiple gas compression amounts of natural gas in the pipeline according to all the gas boundary layers and all the straight-channel gas flow rates; Determine the flow rate gradient of natural gas in the pipeline through all the gas compression amounts.

[0008] In some embodiments, determining the mutation region of the flow rate during the flow of natural gas in the pipeline through the flow rate gradient specifically includes: Determine multiple fluctuating flow rates during the flow of natural gas in the pipeline according to the flow rate gradient; Determine the mutation region of the flow rate during the flow of natural gas in the pipeline through all the fluctuating flow rates.

[0009] In some embodiments, determining the compression ratio during the flow of natural gas in the pipeline through the change trend characteristics of all gas densities specifically includes: Determine the change trend characteristics of all gas densities; Determine multiple dynamic densities of natural gas in the pipeline according to the change trend characteristics; Determine the compression ratio during the flow of natural gas in the pipeline through all the dynamic densities.

[0010] In some embodiments, performing fluctuation analysis on the flow rate of natural gas in the pipeline according to the mutation region of the flow velocity and the compression ratio to obtain multiple flow rate fluctuation values during the flow of natural gas in the pipeline specifically includes: Determining multiple region ratios according to the mutation region of the flow velocity; Obtaining the flow velocities of each straight section and bend during the flow of natural gas in the pipeline Determining multiple flow rate fluctuation values during the flow of natural gas in the pipeline based on all the region ratios, the compression ratio, and all the flow velocities.

[0011] In some embodiments, determining the credible volume flow rate of the natural gas output from the pipeline based on all the flow rate fluctuation values specifically includes: Determining a flow rate correction coefficient according to all the flow rate fluctuation values; Determining the credible volume flow rate of the natural gas output from the pipeline based on the average value of all the flow rate fluctuation values and the flow rate correction coefficient.

[0012] In a second aspect, the present application provides a flow rate measurement system based on intelligent sensors. The flow rate measurement system based on intelligent sensors includes a flow rate measurement unit, and the flow rate measurement unit includes: An acquisition module, configured to, after arranging a plurality of sensor nodes on the inner wall of the pipeline for transporting natural gas, collect the pressures of each sensing node in the inner wall of the pipeline during the transportation of natural gas through a pressure sensor to obtain pressure data; A processing module, configured to determine the gas flow field at each bending position of the natural gas in the pipeline according to the difference characteristics of the pressures in the pressure data and the bending characteristics of the pipeline; The processing module is further configured to perform gradient analysis on the flow velocity of the natural gas in the pipeline based on all the gas flow fields to obtain the flow velocity gradient of the natural gas in the pipeline, and determine the mutation region of the flow velocity during the flow of the natural gas in the pipeline through the flow velocity gradient; The processing module is further configured to collect the gas density of the natural gas at each sensing node in the pipeline through a density sensor, and determine the compression ratio during the flow of the natural gas in the pipeline based on the change trend characteristics of all the gas densities; An execution module, configured to perform fluctuation analysis on the flow rate of the natural gas in the pipeline according to the mutation region of the flow velocity and the compression ratio to obtain multiple flow rate fluctuation values during the flow of the natural gas in the pipeline, and determine the credible volume flow rate of the natural gas output from the pipeline based on all the flow rate fluctuation values.

[0013] In a third aspect, the present application provides a computer device, which includes a memory and a processor. The memory stores code, and the processor is configured to obtain the code and execute the above-mentioned method for measuring the flow rate of natural gas in the pipeline.

[0014] Fourthly, the present application provides a computer-readable storage medium storing a computer program, which when executed by a processor implements the above-mentioned flow measurement method for natural gas in a pipeline.

[0015] The technical solutions provided by the embodiments disclosed in the present application have the following beneficial effects: In the flow measurement system and method based on intelligent sensors provided by the present application, first, a plurality of sensor nodes are arranged on the inner wall of the pipeline for transporting natural gas, and the pressure of each sensing node in the inner wall of the pipeline during the transportation of natural gas is collected by a pressure sensor to obtain pressure data; the gas flow field at each bending position of the natural gas in the pipeline is determined by the difference characteristics of the pressure in the pressure data and the bending characteristics of the pipeline; the flow velocity gradient of the natural gas in the pipeline is obtained by performing gradient analysis on the flow velocity of the natural gas in the pipeline according to all the gas flow fields, and the mutation region of the flow velocity during the flow of the natural gas in the pipeline is determined by the flow velocity gradient; the gas density of the natural gas at each sensing node in the pipeline is collected by a density sensor, and the compression ratio during the flow of the natural gas in the pipeline is determined by the change trend characteristics of all the gas densities; the flow rate of the natural gas in the pipeline is analyzed for fluctuations according to the mutation region of the flow velocity and the compression ratio to obtain a plurality of flow rate fluctuation values during the flow of the natural gas in the pipeline, and the credible volume flow rate of the output natural gas in the pipeline is determined by all the flow rate fluctuation values.

[0016] It can be seen that in the process of flow measurement of this application, first, by analyzing the pressure on the inner wall of the pipeline when natural gas transports gas, the gas flow field at each bending position in the pipeline is determined. The gas flow field represents the distribution of gas flow velocity at the bending positions in the natural gas pipeline, which can be used to analyze the change of flow velocity at the bending positions, facilitating the elimination of the influence of the flow velocity change at the bending positions on other flows. Secondly, the gas boundary layer at each bending position in the natural gas pipeline is determined from all the gas flow fields. The gas boundary layer represents the boundary region where the gas velocity in the pipeline gradually increases from zero (relative to the inner side of the pipeline) to the gas velocity in the straight section of the pipeline. By performing gradient analysis on the gas flow velocity in the pipeline from all the gas boundary layers, the mutation region of the flow velocity during the flow of natural gas in the pipeline is obtained. The mutation region represents the region where the gas flow velocity in the pipeline undergoes a mutation, that is, the change of the gas flow velocity is relatively large. The mutation region includes regions where the flow velocity mutates at multiple positions in the pipeline, which can be used to analyze the change of gas flow velocity in the pipeline and reduce the influence of the pipeline characteristics of the pipeline itself on the measurement of gas flow. Thus, by analyzing all the collected gas densities and determining the compression ratio when natural gas flows in the pipeline, the compression ratio represents the parameter value of the compression degree of the gas in the pipeline during flow, which can be used to analyze other flows in the pipeline and reduce the influence of the compression of the gas during flow on the measurement of gas flow. Then, according to the mutation region of the flow velocity and the compression ratio, fluctuation analysis is performed on the flow of natural gas in the pipeline to obtain multiple flow fluctuation values during the flow of natural gas in the pipeline. The flow fluctuation value represents the parameter value of the fluctuation degree of the gas flow in the pipeline during flow. Since the flow velocity and density of the gas in the pipeline both change during transmission, there are flow fluctuation values when gas fluctuations occur in multiple regions of the pipeline, which can be used to calculate the gas flow in the pipeline and reduce the influence of the disturbance of the flow field in the pipeline on the calculation of the volumetric flow in the pipeline. Finally, the credible volumetric flow of the natural gas output from the pipeline is determined through all the flow fluctuation values. The above solution can reduce the influence of flow field disturbance on the measurement of natural gas flow in the pipeline. BRIEF DESCRIPTION OF THE DRAWINGS

[0017] Figure 1 is an exemplary flowchart of a method for measuring the flow of natural gas in a pipeline according to some embodiments of the present application; Figure 2 is a distribution diagram of gas flow velocity in a pipeline according to some embodiments of the present application; Figure 3 is an exemplary flowchart of determining the velocity gradient of gas according to some embodiments of the present application; Figure 4 is a schematic structural diagram of a flow measurement unit according to some embodiments of the present application; Figure 5It is a schematic structural diagram of a computer device for implementing a method for measuring the flow rate of natural gas in a pipeline according to some embodiments of the present application. Detailed implementation manners

[0018] To better understand the technical solutions of the present application, the technical solutions of the present application will be described in detail below in conjunction with the accompanying drawings of the specification and specific implementation manners.

[0019] Refer to Figure 1 , this figure is an exemplary flowchart of a method for measuring the flow rate of natural gas in a pipeline according to some embodiments of the present application. The method 100 for measuring the flow rate of natural gas in a pipeline mainly includes the following steps: In step 101, a plurality of sensor nodes are arranged on the inner wall of the pipeline for transporting natural gas, and the pressure of each sensing node on the inner wall of the pipeline during the transportation of natural gas is collected through a pressure sensor to obtain pressure data.

[0020] In specific implementation, after arranging a plurality of sensor nodes on the inner wall of the pipeline for transporting natural gas, the pressure of each sensing node on the inner wall of the pipeline during the transportation of natural gas is collected through a pressure sensor, and the set of all collected pressures is used as pressure data. Wherein, the pressure in the pressure data represents the pressure of natural gas in the pipeline on the inner wall during the transportation of natural gas; in other embodiments, other collection methods may also be used, which are not limited herein.

[0021] It should be noted that in the present application, the historical pressure data of natural gas in the pipeline is analyzed by gradient analysis method to analyze each area where the pressure changes, and the center point of each area is set as a sensing node. The pressure of each sensing node on the inner wall of the pipeline is collected through a pressure sensor, and all the collected pressures are transmitted to the control center of natural gas, and all the collected pressures are analyzed.

[0022] In step 102, the gas flow field at each bending position of natural gas in the pipeline is determined based on the difference characteristics of the pressure in the pressure data and the bending characteristics of the pipeline.

[0023] In some embodiments, the gas flow field at each bending position of natural gas in the pipeline can be determined based on the difference characteristics of the pressure in the pressure data and the bending characteristics of the pipeline by the following steps: Determine the difference characteristics of the pressure in the pressure data; Determine the bending characteristics of the pipeline; Determine a plurality of flow velocity difference amounts of natural gas in the pipeline according to the difference characteristics; Determine the gas flow field at each bending position of natural gas in the pipeline through all the flow velocity difference amounts and the bending characteristics.

[0024] In specific implementation, the differential features of the pressure in the pressure data can be determined in the following manner: select the pressures on both sides of the same cross-section in the pipeline as the selected pressures on both sides, subtract the first pressure from the second pressure among the selected pressures on both sides, and use the obtained difference value as the pressure difference value of the selected pressures on both sides. Then, continue to determine the pressure difference values of the remaining adjacent pressures in the pressure sequence. Among them, the pressure difference value is a parameter value representing the degree of difference in pressure between both sides of the same cross-section in the pipeline, which can be used to analyze the flow rates of other parts in the pipeline. Take the set of all pressure difference values as the differential features of the pressure in the pressure data, where the differential features represent the features of the degree of pressure difference in the pipeline. The bending features of the pipeline can be determined in the following manner: collect the bending angles at each bending position in the pipeline through an angle sensor, and take the set of all collected bending angles as the bending features of the pipeline in natural gas, where the bending features are the features describing the bending situation of the pipeline. In other embodiments, other methods can also be used for determination, which are not limited herein.

[0025] In specific implementation, the multiple flow rate differences of natural gas in the pipeline can be determined according to the differential features in the following manner: select one pressure difference value from the differential features as the selected pressure difference value, calculate the flow rate difference value of the selected pressure difference value by combining the selected pressure difference value and the cross-sectional area of the pipeline through the Venturi equation in the prior art, and then continue to determine the flow rate difference values of the remaining pressure difference values in the differential features. Among them, the flow rate difference value is a parameter value representing the degree of difference in gas flow rate between adjacent sensors in the pipeline, which can be used to predict the gas flow rate in the pipeline. In other embodiments, other methods can also be used for determination, which are not limited herein.

[0026] In specific implementation, the gas flow field of natural gas at each bending position in the pipeline can be determined by all the flow rate difference amounts and the bending features in the following manner: Select a bending position as the selected bending position, calculate the flow rate of the gas outside the selected bending position at the selected bending position through the Venturi equation in the prior art in combination with the pressure data at the selected bending position, extract the bending angle at the selected bending position from the bending features, perform a natural exponential operation on the bending angle, multiply the reciprocal of the value obtained from the natural exponential operation by the flow rate difference amount corresponding to the selected bending position, subtract the value obtained from the multiplication from the flow rate of the gas outside the selected bending position, use the value obtained from the subtraction as the flow rate of the gas inside the selected bending position, divide the difference between the flow rate of the gas outside the selected bending position and the flow rate of the gas inside the selected bending position by 10, use the value obtained from the division as the difference value of the velocity change between the outside and the inside of the selected bending position, subtract the difference value from the flow rate of the gas outside the selected bending position, use the value obtained from the subtraction as the first flow rate, subtract the difference value from the first flow rate, use the value obtained from the subtraction as the second flow rate, and so on until the value obtained from the subtraction is the same as the flow rate of the gas inside the selected bending position, distribute the flow rate of the gas outside the selected bending position, all the flow rates obtained from the above subtractions, and the flow rate of the gas inside the selected bending position in the order from the outside to the inside, use the result of the distribution as the gas flow field of natural gas at the selected bending position in the pipeline, and continue to determine the gas flow fields at the remaining bending positions in the pipeline; in other embodiments, other methods can also be used for determination, which are not limited here.

[0027] It should be noted that the gas flow field in this application represents the distribution of the gas flow rate of natural gas at the bending positions in the pipeline, which can be used to analyze the flow rate change at the bending positions and facilitate excluding the influence of the flow rate change at the bending positions on other flow rates.

[0028] In some embodiments, referring to Figure 2 as shown, this figure is the distribution diagram of the gas flow rate in the pipeline in some embodiments of this application. As Figure 2 described, due to the viscosity of the pipeline inner wall to the gas in the straight pipe position, there is a difference in the flow rate between the center of the pipeline and the part close to the inner wall. In the bending position, due to the action of the centrifugal force when the gas flows, the so-called "secondary flow" phenomenon will occur, which will cause the uneven distribution of the flow rate of the fluid in the bend, resulting in the sequential increase of the flow rate from the outside to the inside of the bending position.

[0029] In step 103, perform a gradient analysis on the flow rate of natural gas in the pipeline according to all the gas flow fields to obtain the flow rate gradient of natural gas in the pipeline, and determine the sudden change region of the flow rate during the flow of natural gas in the pipeline through the flow rate gradient.

[0030] In some embodiments, referring toFigure 3 As shown, this figure is an exemplary flowchart for determining the velocity gradient of gas in some embodiments of the present application. In this embodiment, gradient analysis is performed on the velocity of natural gas in the pipeline based on all gas flow fields. The velocity gradient of natural gas in the pipeline can be achieved by the following steps: First, in step 1031, the gas boundary layer at each bending position in the natural gas pipeline is determined according to all gas flow fields. Second, in step 1032, the straight - section gas velocity of each straight section in the pipeline is determined. Furthermore, in step 1033, multiple gas compression amounts of natural gas in the pipeline are determined based on all gas boundary layers and all straight - section gas velocities. Finally, in step 1034, the velocity gradient of natural gas in the pipeline is determined through all gas compression amounts.

[0031] In addition, in some embodiments, the gas boundary layer at each bending position in the natural gas pipeline determined according to all gas flow fields can be achieved by the following steps: Select a bending position as the selected bending position, and determine multiple buffer velocities at the selected bending position according to the gas flow field corresponding to the selected bending position. Determine the gas boundary layer at the selected bending position in the natural gas pipeline through all buffer velocities. Continue to determine the gas boundary layers at the remaining bending positions in the natural gas pipeline.

[0032] Specifically, when implemented, determining multiple buffer velocities at the selected bending position according to the gas flow field corresponding to the selected bending position can be achieved in the following way: that is, calculate the velocity of the gas in the straight section of the pipeline through the Venturi equation in the prior art combined with the pressure in the straight section of the pipeline, extract all velocities less than the velocity in the straight section from the gas flow field corresponding to the selected bending position, and take each extracted velocity as the buffer velocity at the bending position. Here, the buffer velocity represents the velocity with buffering at the bending position, that is, the velocity lower than the velocity in the straight section, which can be used to analyze the gas flow condition at the bend. Determining the gas boundary layer at the selected bending position in the natural gas pipeline through all buffer velocities can be achieved in the following way: that is, take the distance from the position corresponding to the maximum buffer velocity to the outside of the selected bending position as the thickness of the gas boundary layer, take the lateral length corresponding to the position of the maximum buffer velocity as the width of the gas boundary layer, take the distance from the entrance to the exit of the selected bending position as the length of the gas boundary layer, and take the area surrounded by the thickness, width, and length of the gas boundary layer as the gas boundary layer. In other embodiments, other methods can also be used to determine it, which is not limited here.

[0033] It should be noted that the gas boundary layer in this application represents the boundary region where the gas velocity in the pipeline gradually increases from zero (relative to the outside of the pipeline) to the gas velocity in the straight section of the pipeline, which can be used to analyze the gas velocity change at the bending position of the gas, facilitating the determination of the gas flow velocity.

[0034] In specific implementation, the straight-section gas flow velocity of each straight section in the pipeline can be determined in the following manner: select a straight section as the selected straight section, extract all the pressures of the selected straight section from the pressure data, and determine the flow velocity at the corresponding position of each pressure by combining the extracted pressures with the continuity equation in the prior art. Take the average value of all the determined flow velocities as the straight-section gas flow velocity of the selected straight section, and continue to determine the straight-section gas flow velocities of the remaining straight sections, where the straight-section gas flow velocity represents the flow velocity of the gas in the pipeline in the straight section; the multiple gas compression amounts of the natural gas in the pipeline can be determined according to all the gas boundary layers and all the straight-section gas flow velocities in the following manner: select a group of adjacent straight sections of the pipeline as the selected adjacent straight sections, subtract the straight-section gas flow velocity corresponding to the second straight section in the selected adjacent straight sections from the straight-section gas flow velocity corresponding to the first straight section, and calculate the gas compression amount between the selected adjacent straight sections by combining the obtained value by subtraction with the classical bend flow theory in the prior art (such as the Dean number correlation formula), the thickness of the gas boundary layer corresponding to the bend between the selected adjacent straight sections, and the radius of this bend. Continue to determine the gas compression amounts between the remaining groups of adjacent straight sections, thereby obtaining the multiple gas compression amounts of the natural gas in the pipeline, where the gas compression amount represents the parameter value of the compression degree of the gas between adjacent straight sections; the flow velocity gradient of the natural gas in the pipeline can be determined by all the gas compression amounts in the following manner: calculate the ratio of the flow velocity difference to the spacing between each adjacent straight section, multiply each gas compression amount by the ratio of the flow velocity difference to the spacing between the corresponding adjacent straight sections, and take the set of all the obtained values as the flow velocity gradient of the natural gas in the pipeline; in other embodiments, it can also be determined in other ways, which are not limited here.

[0035] It should be noted that the flow velocity gradient in this application represents the gradient of the change in the natural gas flow velocity between each adjacent straight section in the pipeline, which can be used to predict the change in the natural gas flow velocity in the pipeline, facilitating the reduction of the influence on the measurement of the natural gas flow rate at the bending position of the pipeline.

[0036] In some embodiments, the following steps can be used to determine the sudden change region of the flow velocity during the flow of natural gas in the pipeline through the flow velocity gradient: Determine multiple fluctuating flow velocities during the flow of natural gas in the pipeline according to the flow velocity gradient; Determine the sudden change region of the flow velocity during the flow of natural gas in the pipeline through all the fluctuating flow velocities.

[0037] In specific implementation, to determine multiple fluctuating flow velocities during the flow of natural gas in the pipeline according to the flow velocity gradient, the following method can be adopted, that is: calculate the average value of all gas compressions in the flow velocity gradient, extract all gas compressions greater than this average value from the flow velocity gradient, and regard the straight - through gas flow velocities of the two straight sections corresponding to each extracted gas compression and the flow velocity of the natural gas outside at the bending position between the two straight sections as the fluctuating flow velocities. Among them, the fluctuating flow velocity represents the flow velocity when there are fluctuations in the natural gas in the pipeline, that is: when the natural gas flow velocity changes, it can be used to judge the change in the natural gas flow velocity in the pipeline; to determine the mutation region of the flow velocity during the flow of natural gas in the pipeline through all the fluctuating flow velocities, the following method can be adopted, that is: initialize a mutation region model, regard all the fluctuating flow velocities as the constraint parameters of this mutation region model, regard the length and width of the pipeline as the initialization parameters of this mutation region model, and output the mutation region of the flow velocity during the flow of natural gas in the pipeline through this mutation region model. The mutation region model is to use a convolutional neural network to identify the flow velocity mutation pattern in the pipeline and establish a mutation region model for the mutation region. The mutation region model is, for example: mutation region = all the fluctuating flow velocities * A + the length and width of the pipeline * B, where A and B are weight coefficients, and A and B can be determined according to parameters such as the density, viscosity, pipe diameter, and flow rate of the natural gas in the pipeline. In other embodiments, other methods can also be used to determine them, which are not limited here.

[0038] It should be noted that the mutation region in this application represents the region where the natural gas flow velocity in the pipeline undergoes a mutation, that is: the change in the natural gas flow velocity is large, and the mutation region includes the regions where the flow velocities at multiple positions in the pipeline mutate. It can be used to analyze the change situation of the natural gas flow velocity in the pipeline and can reduce the influence of the pipeline characteristics of the pipeline itself on the measurement of the natural gas flow rate.

[0039] In step 104, a density sensor is used to collect the gas density at each sensing node in the pipeline for the natural gas, and the compression ratio during the flow of the natural gas in the pipeline is determined through the change trend characteristics of all the gas densities.

[0040] In specific implementation, a density sensor is used to collect the gas density at each sensing node in the pipeline for the natural gas. After starting the natural gas, the density sensor is used to collect the gas density of each sensing node arranged in the pipeline, and all the collected densities are transmitted to the control center of the natural gas, and all the collected densities are analyzed.

[0041] In some embodiments, to determine the compression ratio during the flow of natural gas in the pipeline through the change trend characteristics of all the gas densities, the following steps can be adopted: Determine the change trend characteristics of all the gas densities; Determine multiple dynamic densities of the natural gas in the pipeline according to the change trend characteristics; Determine the compression ratio during the flow of natural gas in the pipeline through all dynamic densities.

[0042]

[0043] When specifically implemented, the change trend characteristics of all gas densities can be determined in the following manner: Arrange all gas densities according to the positions of the corresponding density sensors in the pipeline, and use the obtained sequence as the gas density sequence. Select a set of adjacent gas densities in the gas density sequence as the selected adjacent gas densities. Subtract the first gas density from the second gas density in the selected adjacent gas densities, and use the obtained value as the density difference value of the selected adjacent gas densities. Continue to determine the density difference values of the remaining groups of adjacent gas densities in the gas density sequence. Among them, the density difference value is a parameter value representing the degree of difference in gas density between adjacent density sensors in the pipeline. Use the set of all density difference values as the change trend characteristics of all gas densities. Among them, the change trend characteristics represent the characteristics of the trend degree of gas density change in the pipeline; in other embodiments, other methods can also be used to determine, which are not limited here.

[0044]

[0045] When specifically implemented, the multiple dynamic densities of natural gas in the pipeline can be determined according to the change trend characteristics in the following manner: Extract all density difference values greater than 0 from the change trend characteristics, calculate the average value of the extracted density difference values, and use the two gas densities corresponding to each density difference value greater than the average value as dynamic densities; Extract all density difference values less than 0 from the change trend characteristics, calculate the average value of the extracted density difference values, and use the two gas densities corresponding to each density difference value less than the average value as dynamic densities. Among them, the dynamic density represents the gas density with a relatively large degree of difference from adjacent densities; Determine the compression ratio during the flow of natural gas in the pipeline through all dynamic densities in the following manner: Divide the maximum dynamic density by the minimum dynamic density, perform a logarithmic operation with the obtained value as the base of 2, and use the obtained value as the first value. Divide the maximum dynamic density by the minimum dynamic density, multiply the obtained value by the first value, and use the obtained value as the compression ratio during the flow of natural gas in the pipeline; in other embodiments, other methods can also be used to determine, which are not limited here. It should be noted that the compression ratio in this application is a parameter value representing the degree of compression of natural gas during flow in the pipeline, which can be used to analyze other flows in the pipeline and reduce the impact of the compression of gas during flow on the measurement of natural gas flow.In step 105, fluctuation analysis is performed on the flow rate of natural gas in the pipeline according to the mutation region of the flow rate and the compression ratio to obtain multiple flow rate fluctuation values during the flow of natural gas in the pipeline, and the credible volume flow rate of the output natural gas in the pipeline is determined through all the flow rate fluctuation values.

[0046] In some embodiments, the fluctuation analysis of the flow rate of natural gas in the pipeline according to the mutation region of the flow rate and the compression ratio to obtain multiple flow rate fluctuation values during the flow of natural gas in the pipeline can be implemented by the following steps: Determine multiple region ratios according to the mutation region of the flow rate; Obtain the flow rates of each straight section and bend during the flow of natural gas in the pipeline Determine multiple flow rate fluctuation values during the flow of natural gas in the pipeline through all the region ratios, the compression ratio, and all the flow rates.

[0047] Specifically, when implemented, determining multiple region ratios according to the mutation region of the flow rate can be achieved in the following manner: select a region in the mutation region of the flow rate as the selected region, divide the length of the selected region by the length of the pipeline, and use the obtained value as the region ratio of the selected region. Then continue to determine the region ratios of each region in the remaining mutation regions of the flow rate, where the region ratio represents the ratio of the region in the mutation region in the pipeline; determining multiple flow rate fluctuation values during the flow of natural gas in the pipeline through all the region ratios, the compression ratio, and all the flow rates can be achieved in the following manner: initialize a flow rate fluctuation value model, use all the region ratios and the compression ratio as the constraint parameters of this flow rate fluctuation value model, use all the flow rates as the initialization parameters of this flow rate fluctuation value model, and output multiple flow rate fluctuation values of natural gas in the pipeline through this flow rate fluctuation value model. The flow rate fluctuation value model is a flow rate fluctuation value model that uses machine learning algorithms (such as regression algorithms, neural networks, etc.) to establish flow rate fluctuation values. For example, the flow rate fluctuation value model: multiple flow rate fluctuation values = all the region ratios and compression ratio * C + all the flow rates * D, where C and D are weight coefficients, and C and D can be determined according to a large number of mutation regions. In other embodiments, other methods can also be used to determine them, which are not limited here.

[0048] It should be noted that the flow rate fluctuation value in this application represents a parameter value of the fluctuation degree of the flow rate of natural gas in the pipeline. Since the flow rate and density of natural gas in the pipeline change during transmission, there are flow rate fluctuation values when there are natural gas fluctuations in multiple regions of the pipeline. Therefore, it can be used to calculate the gas flow rate in the pipeline, reducing the influence of the disturbance of the flow field in the pipeline on the calculation of the volume flow rate in the pipeline.

[0049] In some embodiments, the reliable volumetric flow rate of the natural gas output in the pipeline can be determined through all the flow rate fluctuation values by the following steps: Determine a flow rate correction coefficient according to all the flow rate fluctuation values; Determine the reliable volumetric flow rate of the natural gas output in the pipeline based on the average value of all the flow rate fluctuation values and the flow rate correction coefficient.

[0050] Specifically, when implemented, determining the flow rate correction coefficient according to all the flow rate fluctuation values can be achieved in the following manner: subtract the maximum flow rate fluctuation value from the minimum flow rate fluctuation value, perform a natural exponential operation on the obtained subtracted value, and use the value obtained from the natural exponential operation as the flow rate correction coefficient. Here, the flow rate correction coefficient is a parameter representing the correction degree of the flow rate of natural gas during the flow in the pipeline, and can be used to correct the flow rate in the pipeline; determining the reliable volumetric flow rate of the natural gas output in the pipeline based on the average fluctuation value of all the flow rate fluctuation values and the flow rate correction coefficient can be achieved in the following manner: multiply the average value of all the flow rate fluctuation values by the flow rate correction coefficient, and use the obtained multiplied value as the reliable volumetric flow rate when the natural gas is output in the pipeline; in other embodiments, other methods can also be used for determination, which are not limited herein.

[0051] It should be noted that the reliable volumetric flow rate in this application represents the reliable volumetric flow rate when the natural gas is output in the pipeline, which can be used to predict the flow rate of the natural gas in the pipeline and reduce the influence of pipeline bending on the measurement of the natural gas flow rate.

[0052] In addition, on the other hand of this application, in some embodiments, this application provides a flow rate measurement system based on intelligent sensors. The flow rate measurement system based on intelligent sensors includes a flow rate measurement unit. Refer to Figure 4 , this figure is a schematic structural diagram of the flow rate measurement unit shown in some embodiments of this application. The flow rate measurement unit 400 includes: a collection module 401, a processing module 402, and an execution module 403, which are described as follows: Collection module 401. In this application, the collection module 401 is mainly used to arrange a plurality of sensor nodes on the inner wall of the pipeline for transporting natural gas, and then collect the pressures of each sensing node on the inner wall of the pipeline during the transportation of natural gas through a pressure sensor to obtain pressure data; Processing module 402. In this application, the processing module 402 is used to determine the gas flow field at each bending position of the natural gas in the pipeline through the difference characteristics of the pressures in the pressure data and the bending characteristics of the pipeline; It should be noted that the processing module 402 in this application is also used to perform a gradient analysis on the flow rate of the natural gas in the pipeline according to all the gas flow fields to obtain the flow rate gradient of the natural gas in the pipeline, and determine the mutation region of the flow rate during the flow of the natural gas in the pipeline through the flow rate gradient. In addition, it should be noted that the processing module 402 in the present application is further configured to collect the gas density of natural gas at each sensing node in the pipeline by a density sensor, and determine the compression ratio when the natural gas flows in the pipeline according to the change trend characteristics of all the gas densities; The execution module 403, in the present application, the execution module 403 is mainly configured to perform a fluctuation analysis on the flow rate of natural gas in the pipeline according to the mutation region of the flow rate and the compression ratio, obtain multiple flow rate fluctuation values during the flow of natural gas in the pipeline, and determine the credible volume flow rate of the output natural gas in the pipeline through all the flow rate fluctuation values.

[0053] In addition, the present application also provides a computer device, which includes a memory and a processor. The memory stores code, and the processor is configured to obtain the code and execute the above-mentioned flow rate measurement method for natural gas in the pipeline.

[0054] In some embodiments, refer to Figure 5 , this figure is a schematic structural diagram of a computer device for implementing the flow rate measurement method for natural gas in the pipeline according to some embodiments of the present application. The flow rate measurement method for natural gas in the pipeline in the above embodiments can be implemented by Figure 5 the computer device shown. The computer device 500 includes at least one processor 501, a communication bus 502, a memory 503, and at least one communication interface 504.

[0055] The processor 501 may be a general-purpose central processing unit (CPU) or an application-specific integrated circuit (ASIC).

[0056] The communication bus 502 can be used to transmit information between the above components.

[0057] The memory 503 can be a read-only memory (ROM) or other types of static storage devices that can store static information and instructions, a random access memory (RAM) or other types of dynamic storage devices that can store information and instructions, or can also be an electrically erasable programmable read-only memory (EEPROM), a compact disc read-only memory (CD-ROM) or other optical disc storage, optical disc storage (including compact discs, laser discs, optical discs, digital versatile discs, Blu-ray discs, etc.), magnetic disks or other magnetic storage devices, or any other medium that can be used to carry or store the desired program code in the form of instructions or data structures and can be accessed by a computer, but is not limited thereto. The memory 503 can exist independently and be connected to the processor 501 through the communication bus 502. The memory 503 can also be integrated with the processor 501.

[0058] Among them, the memory 503 is used to store the program code for executing the solution of this application and is controlled by the processor 501 for execution. The processor 501 is used to execute the program code stored in the memory 503. The program code can include one or more software modules. The methods used in the above embodiments can be implemented by one or more software modules in the program code in the processor 501 and the memory 503.

[0059] The communication interface 504 uses any device such as a transceiver to communicate with other devices or communication networks, such as Ethernet, radio access network (RAN), wireless local area networks (WLAN), etc.

[0060] In a specific implementation, as an embodiment, the computer device can include multiple processors, and each of these processors can be a single-core (single-CPU) processor or a multi-core (multi-CPU) processor. Here, the processor can refer to one or more devices, circuits, and / or processing cores for processing data (such as computer program instructions).

[0061] The computer device described above can be a general-purpose computer device or a special-purpose computer device. In specific implementations, the computer device can be a desktop computer, a laptop computer, a network server, a personal digital assistant (PDA), a mobile phone, a tablet computer, a wireless terminal device, a communication device, or an embedded device. The embodiments of the present application do not limit the type of the computer device.

[0062] In addition, the present application also provides a computer-readable storage medium storing a computer program, and when the computer program is executed by a processor, it implements the above-mentioned flow measurement method for natural gas in a pipeline.

[0063] Although the preferred embodiments of the present application have been described, those skilled in the art can make additional changes and modifications once they know the basic creative concept. Therefore, the appended claims are intended to be construed to include the preferred embodiments as well as all changes and modifications falling within the scope of the present application.

[0064] Obviously, those skilled in the art can make various changes and modifications to the present application without departing from the spirit and scope of the present application. Thus, if these modifications and variations of the present application fall within the scope of the claims of the present application and their equivalent technologies, the present application also intends to include these modifications and variations.

Claims

1. A method for measuring the flow of natural gas in a pipeline, characterized in that: The steps include: Arrange multiple sensor nodes on the inner wall of the pipeline for transporting natural gas, and collect the pressure of each sensor node on the inner wall of the pipeline when transporting natural gas through the pressure sensor to obtain pressure data; Determining the gas flow field of the natural gas at each bending position in the pipeline by using the pressure difference characteristics in the pressure data and the bending characteristics of the pipeline; Performing gradient analysis on the flow velocity of the natural gas in the pipeline according to all gas flow fields to obtain the flow velocity gradient of the natural gas in the pipeline, and determining the sudden change area of ​​the flow velocity during the flow of the natural gas in the pipeline through the flow velocity gradient; The density sensor collects the gas density of natural gas at each sensing node in the pipeline, and determines the compression ratio of natural gas flowing in the pipeline through the change trend characteristics of all gas densities; The flow rate of the natural gas in the pipeline is subjected to fluctuation analysis according to the mutation area of ​​the flow velocity and the compression ratio to obtain multiple flow rate fluctuation values ​​during the flow of the natural gas in the pipeline, and the credible volume flow rate of the output natural gas in the pipeline is determined through all the flow rate fluctuation values.

2. The method according to claim 1, characterized in that Determining the gas flow field of the natural gas at each bending position in the pipeline by using the pressure difference characteristics in the pressure data and the bending characteristics of the pipeline specifically includes: determining differential characteristics of pressure in the pressure data; Determine the bending characteristics of the pipe; Determining multiple flow rate difference amounts of natural gas in the pipeline according to the difference characteristics; The gas flow field of the natural gas at each bending position in the pipeline is determined by all flow velocity differences and the bending characteristics.

3. The method according to claim 1, characterized in that The velocity gradient of the natural gas in the pipeline is analyzed based on all gas flow fields, and the velocity gradient of the natural gas in the pipeline is obtained, including: Determine the gas boundary layer at each bending position in the natural gas pipeline according to all gas flow fields; Determine the straight gas velocity for each straight channel in the pipeline; determining multiple gas compressions of natural gas in the pipeline based on all gas boundary layers and all straight-path gas velocities; The velocity gradient of the natural gas in the pipeline is determined by the total gas compression.

4. The method according to claim 1, characterized in that Determining the sudden change area of ​​the flow velocity during the flow of natural gas in the pipeline by the flow velocity gradient specifically includes: determining a plurality of fluctuating flow rates during the flow of natural gas in the pipeline according to the flow rate gradient; The area of ​​sudden change in flow velocity during the flow of natural gas in the pipeline is determined by all fluctuating flow velocities.

5. The method according to claim 1, characterized in that The compression ratio of natural gas flowing in the pipeline is determined by the change trend characteristics of all gas densities, including: Determine the changing trend characteristics of all gas densities; determining a plurality of dynamic densities of the natural gas in the pipeline according to the change trend characteristics; The overall dynamic density determines the compression ratio of natural gas as it flows in a pipeline.

6. The method according to claim 1, characterized in that The flow rate fluctuation analysis of the natural gas in the pipeline is performed according to the flow velocity mutation area and the compression ratio, and multiple flow rate fluctuation values ​​obtained during the flow of the natural gas in the pipeline specifically include: Determine multiple area proportions according to the sudden change area of ​​the flow velocity; Obtain the flow velocity of each straight and curved path during the flow of natural gas in the pipeline Multiple flow fluctuation values ​​during the flow of natural gas in the pipeline are determined by all area proportions, the compression ratios and all flow velocities.

7. The method according to claim 1, characterized in that The reliable volume flow rate of natural gas output in the pipeline is determined by all flow fluctuation values, including: Determine the flow correction factor based on all flow fluctuation values; The reliable volume flow rate of the natural gas output in the pipeline is determined based on the average value of all flow fluctuation values ​​and the flow correction coefficient.

8. A flow metering system based on an intelligent sensor, the flow metering system based on an intelligent sensor comprising a flow metering unit, characterized in that: The flow metering unit comprises: The acquisition module is used to arrange multiple sensor nodes on the inner wall of the pipeline for transporting natural gas, collect the pressure of each sensor node in the inner wall of the pipeline when transporting natural gas through the pressure sensor, and obtain pressure data; A processing module, used for determining the gas flow field of the natural gas at each bending position in the pipeline according to the pressure difference characteristics in the pressure data and the bending characteristics of the pipeline; The processing module is further used to perform gradient analysis on the flow velocity of the natural gas in the pipeline according to all gas flow fields to obtain the flow velocity gradient of the natural gas in the pipeline, and determine the sudden change area of ​​the flow velocity during the flow of the natural gas in the pipeline through the flow velocity gradient; The processing module is also used to collect the gas density of the natural gas at each sensing node in the pipeline by the density sensor, and determine the compression ratio of the natural gas flowing in the pipeline through the change trend characteristics of all gas densities; The execution module is used to perform fluctuation analysis on the flow rate of the natural gas in the pipeline according to the mutation area of ​​the flow rate and the compression ratio, obtain multiple flow fluctuation values ​​during the flow of the natural gas in the pipeline, and determine the reliable volume flow rate of the natural gas output in the pipeline through all the flow fluctuation values.

9. A computer device, characterized in that: The computer device comprises a memory and a processor, wherein the memory stores codes, and the processor is configured to obtain the codes and execute the flow metering method for natural gas in a pipeline according to any one of claims 1 to 7.

10. A computer-readable storage medium storing a computer program, characterized in that: When the computer program is executed by a processor, the method for measuring flow rate of natural gas in a pipeline as claimed in any one of claims 1 to 7 is implemented.

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