CN115346346B

CN115346346B - Natural gas alarm equipment control method, device, equipment and computer readable medium

Info

Publication number: CN115346346B
Application number: CN202210025193.0A
Authority: CN
Inventors: 陈光宇; 毕忠伟; 杜江涛; 薛亮
Original assignee: Beijing Huanyu Boya Technology Co ltd
Current assignee: Beijing Huanyu Boya Technology Co ltd
Priority date: 2022-01-11
Filing date: 2022-01-11
Publication date: 2023-09-19
Anticipated expiration: 2042-01-11
Also published as: CN115346346A

Abstract

Embodiments of the present disclosure disclose a natural gas warning device control method, apparatus, device, and computer readable medium. One embodiment of the method comprises the following steps: responding to the detection that the sound velocity checking operation information records or the current time meets the preset sound velocity checking cycle time condition, the detection flow rate meets the preset flow rate threshold condition, the detection temperature meets the preset temperature stability condition, the detection pressure meets the preset pressure stability condition, the gas component detection information meets the preset gas component stability condition, and a sound velocity checking information set and a sound velocity group set are obtained; generating a detection sound speed according to the sound channel sound speed group set; generating a checked sound speed according to the sound speed checking information set; and controlling the natural gas alarm equipment to execute ultrasonic flowmeter sound velocity abnormality alarm operation in response to the checked sound velocity and the detected sound velocity meeting the ultrasonic flowmeter sound velocity abnormality conditions. According to the embodiment, the natural gas metering equipment does not need to be disassembled, and sound velocity checking can be automatically conducted on the natural gas metering equipment.

Description

Natural gas alarm equipment control method, device, equipment and computer readable medium

Technical Field

Embodiments of the present disclosure relate to the field of computer technology, and in particular, to a method, an apparatus, a device, and a computer readable medium for controlling a natural gas alarm device.

Background

The natural gas metering device can provide metering data when natural gas is transported, and can further provide a handover basis for production and trade. Thus, the metering accuracy of the natural gas metering facility affects the reliability of the metering data at the time of handover. At present, when measuring the accuracy of natural gas metering equipment, the mode that usually adopts is: and (3) the natural gas metering equipment (such as an ultrasonic flowmeter) is disassembled and then conveyed to a metering center for detection.

However, when the metering equipment of a natural gas station is detected in the above manner, there are often the following technical problems:

firstly, the detection operation is complicated, automatic sound velocity checking cannot be performed on the natural gas metering equipment, and metering data cannot be continuously recorded after the natural gas metering equipment is sent to be detected;

secondly, automatic flow verification cannot be performed on the natural gas metering equipment;

third, automated metering loop verification of natural gas metering equipment is not possible.

Disclosure of Invention

The disclosure is in part intended to introduce concepts in a simplified form that are further described below in the detailed description. The disclosure is not intended to identify key features or essential features of the claimed subject matter, nor is it intended to be used to limit the scope of the claimed subject matter.

Some embodiments of the present disclosure propose a natural gas warning device control method, apparatus, electronic device, and computer readable medium to solve one or more of the technical problems mentioned in the background section above.

In a first aspect, some embodiments of the present disclosure provide a natural gas warning device control method, the method comprising: responding to detection that a sound velocity checking operation information record of a user aiming at a target natural gas station or the current time meets a preset sound velocity checking period time condition, and determining whether the detection temperature of a temperature transmitter corresponding to the target natural gas station meets a preset temperature stabilizing condition or not, wherein the detection flow velocity of an ultrasonic flowmeter corresponding to the target natural gas station meets a preset flow velocity threshold condition; in response to determining that the detected temperature meets the preset temperature stabilizing condition, determining whether the detected pressure of the pressure transmitter corresponding to the target natural gas station meets the preset pressure stabilizing condition; determining whether gas component detection information of a gas chromatograph corresponding to the target natural gas station meets a preset gas component stabilization condition in response to determining that the detection pressure meets the preset pressure stabilization condition; responding to the fact that the gas component detection information meets the preset gas component stability condition, acquiring a sound velocity check information set of the target natural gas station and a sound channel sound velocity group set of the ultrasonic flowmeter in a preset time period, wherein sound velocity check information in the sound velocity check information set comprises detection temperature, detection pressure and gas component detection information; generating a detection sound velocity according to the sound velocity group set of the sound channels; generating checked sound velocity according to each detected temperature, detected pressure and gas composition detection information included in the sound velocity checking information set; and controlling the associated natural gas alarm equipment to execute ultrasonic flowmeter sound velocity abnormality alarm operation representing ultrasonic flowmeter sound velocity abnormality of the target natural gas station in response to the checked sound velocity and the detected sound velocity meeting ultrasonic flowmeter sound velocity abnormality conditions.

In a second aspect, some embodiments of the present disclosure provide a natural gas warning device control apparatus, the apparatus comprising: a first determining unit configured to determine, in response to detecting that a sound speed checking operation information record of a user for the target natural gas station or a current time satisfies a preset sound speed checking cycle time condition, and a detected flow rate of an ultrasonic flowmeter corresponding to the target natural gas station satisfies a preset flow rate threshold condition, whether a detected temperature of a temperature transmitter corresponding to the target natural gas station satisfies a preset temperature stabilizing condition; a second determining unit configured to determine whether a detected pressure of a pressure transmitter corresponding to the target natural gas field station satisfies a preset pressure stabilizing condition in response to determining that the detected temperature satisfies the preset temperature stabilizing condition; a third determining unit configured to determine whether gas component detection information of a gas chromatograph corresponding to the target natural gas station satisfies a preset gas component stabilization condition in response to determining that the detection pressure satisfies the preset pressure stabilization condition; an acquisition unit configured to acquire a sound velocity check information set of the target natural gas station and a sound channel sound velocity group set of the ultrasonic flowmeter within a preset period of time in response to determining that the gas composition detection information satisfies the preset gas composition stability condition, wherein sound velocity check information in the sound velocity check information set includes detection temperature, detection pressure, and gas composition detection information; a first generation unit configured to generate a detected sound velocity from the set of sound velocity groups of the channels; a second generation unit configured to generate a checked sound speed based on each of the detected temperature, the detected pressure, and the gas composition detection information included in the sound speed check information set; and a control unit configured to control the associated natural gas alarm device to perform an ultrasonic flowmeter sound speed abnormality alarm operation that characterizes an ultrasonic flowmeter sound speed abnormality of the target natural gas station in response to the check sound speed and the detected sound speed satisfying an ultrasonic flowmeter sound speed abnormality condition.

In a third aspect, some embodiments of the present disclosure provide an electronic device comprising: one or more processors; a storage device having one or more programs stored thereon, which when executed by one or more processors causes the one or more processors to implement the method described in any of the implementations of the first aspect above.

In a fourth aspect, some embodiments of the present disclosure provide a computer readable medium having a computer program stored thereon, wherein the program, when executed by a processor, implements the method described in any of the implementations of the first aspect above.

The above embodiments of the present disclosure have the following advantageous effects: according to the natural gas alarm equipment control method, the fact that the natural gas metering equipment is not required to be disassembled, metering data are continuously recorded, and sound velocity checking can be automatically conducted on the natural gas metering equipment. Specifically, the reason why the metering data cannot be continuously recorded and the sound velocity check of the natural gas metering apparatus cannot be automated is that: the detection operation is comparatively loaded down with trivial details, can't carry out automatic sound velocity to natural gas metering equipment and check, and after natural gas metering equipment sent to the detection, can't continue to record metering data. Based on this, the control method of the natural gas alarm device of some embodiments of the present disclosure first determines, in response to detecting that a sound velocity checking operation information record of a user for a target natural gas station or a current time satisfies a preset sound velocity checking cycle time condition, and a detected flow rate of an ultrasonic flowmeter corresponding to the target natural gas station satisfies a preset flow rate threshold condition, whether a detected temperature of a temperature transmitter corresponding to the target natural gas station satisfies a preset temperature stabilizing condition. Therefore, when the user selects the time for checking the sound velocity of the target natural gas station or reaching the checked sound velocity, and the flow velocity detected by the ultrasonic flowmeter of the target natural gas station meets the preset flow velocity threshold condition, whether the temperature detected by the temperature transmitter of the target natural gas station meets the preset temperature stability condition or not can be determined. Then, in response to determining that the detected temperature satisfies the preset temperature stabilizing condition, determining whether a detected pressure of a pressure transmitter corresponding to the target natural gas station satisfies the preset pressure stabilizing condition. Therefore, when the temperature detected by the temperature transmitter meets the preset temperature stability condition, whether the pressure detected by the pressure transmitter of the target natural gas station meets the preset pressure stability condition or not can be determined. And then, in response to determining that the detected pressure meets the preset pressure stabilizing condition, determining whether gas component detection information of a gas chromatograph corresponding to the target natural gas station meets the preset gas component stabilizing condition. Therefore, when the pressure detected by the pressure transmitter of the target natural gas station meets the preset pressure stabilizing condition, whether the gas component detection information of the gas chromatograph of the target natural gas station meets the preset gas component stabilizing condition can be determined. And secondly, acquiring a sound velocity checking information set of the target natural gas station and a sound channel sound velocity group set of the ultrasonic flowmeter in a preset time period in response to determining that the gas component detection information meets the preset gas component stability condition. The sound velocity checking information in the sound velocity checking information set comprises detection temperature, detection pressure and gas component detection information. Therefore, when the gas component detection information of the gas chromatograph of the target natural gas station meets the preset gas component stability condition, a sound velocity checking information set and a sound velocity group set can be obtained and used for checking the sound velocity of the ultrasonic flowmeter. Then, a detected sound velocity is generated from the set of the above-described sound velocity groups. Thus, detecting the speed of sound may characterize the speed of sound when the ultrasonic flow meter detects the flow of natural gas. And secondly, generating checked sound velocity according to each detected temperature, detected pressure and gas composition detection information included in the sound velocity checking information set. Thus, the verification sound speed may characterize the standard sound speed determined by the sound speed verification information set. And finally, in response to the checked sound speed and the detected sound speed meeting the ultrasonic flowmeter sound speed abnormal conditions, controlling the associated natural gas alarm equipment to execute ultrasonic flowmeter sound speed abnormal alarm operation for representing ultrasonic flowmeter sound speed abnormality of the target natural gas station. Therefore, when the checked sound speed and the detected sound speed meet the abnormal sound speed condition of the ultrasonic flowmeter, the associated natural gas alarm equipment can be controlled to execute abnormal sound speed alarm operation of the ultrasonic flowmeter. Therefore, the method can realize continuous recording of metering data without disassembling the natural gas metering equipment, and can automatically check the sound velocity of the natural gas metering equipment.

Drawings

The above and other features, advantages, and aspects of embodiments of the present disclosure will become more apparent by reference to the following detailed description when taken in conjunction with the accompanying drawings. The same or similar reference numbers will be used throughout the drawings to refer to the same or like elements. It should be understood that the figures are schematic and that elements and components are not necessarily drawn to scale.

FIG. 1 is a schematic illustration of one application scenario of a natural gas alarm device control method according to some embodiments of the present disclosure;

FIG. 2 is a flow chart of some embodiments of a natural gas alarm device control method according to the present disclosure;

FIG. 3 is a schematic structural view of some embodiments of a natural gas warning device control apparatus according to the present disclosure;

fig. 4 is a schematic structural diagram of an electronic device suitable for use in implementing some embodiments of the present disclosure.

Detailed Description

Embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. While certain embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be embodied in various forms and should not be construed as limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete. It should be understood that the drawings and embodiments of the present disclosure are for illustration purposes only and are not intended to limit the scope of the present disclosure.

It should be noted that, for convenience of description, only the portions related to the present invention are shown in the drawings. Embodiments of the present disclosure and features of embodiments may be combined with each other without conflict.

It should be noted that the terms "first," "second," and the like in this disclosure are merely used to distinguish between different devices, modules, or units and are not used to define an order or interdependence of functions performed by the devices, modules, or units.

It should be noted that references to "one", "a plurality" and "a plurality" in this disclosure are intended to be illustrative rather than limiting, and those of ordinary skill in the art will appreciate that "one or more" is intended to be understood as "one or more" unless the context clearly indicates otherwise.

The names of messages or information interacted between the various devices in the embodiments of the present disclosure are for illustrative purposes only and are not intended to limit the scope of such messages or information.

The present disclosure will be described in detail below with reference to the accompanying drawings in conjunction with embodiments.

Fig. 1 is a schematic diagram of an application scenario of a natural gas alarm device control method according to some embodiments of the present disclosure.

In the application scenario of fig. 1, first, the computing device 101 may determine, in response to detecting that the sound speed checking operation information record 102 of the user for the target natural gas station or the current time satisfies the preset sound speed checking cycle time condition, whether the detected flow rate 103 of the ultrasonic flowmeter corresponding to the target natural gas station satisfies the preset flow rate threshold condition 104, and whether the detected temperature 105 of the temperature transmitter corresponding to the target natural gas station satisfies the preset temperature stabilizing condition 106. Then, the computing device 101 may determine, in response to determining that the detected temperature 105 satisfies the preset temperature stability condition 106, whether the detected pressure 107 of the pressure transmitter corresponding to the target natural gas field station satisfies the preset pressure stability condition 108. Thereafter, the computing device 101 may determine whether the gas composition detection information 109 of the gas chromatograph corresponding to the target natural gas station satisfies the preset gas composition stability condition 110 in response to determining that the detection pressure 107 satisfies the preset pressure stability condition 108. Next, the computing device 101 may acquire a sound speed check information set 111 of the target natural gas station and a sound channel sound speed group set 112 of the ultrasonic flowmeter for a preset period of time in response to determining that the gas composition detection information 109 satisfies the preset gas composition stability condition 110. The sound velocity check information in the sound velocity check information set 111 includes detected temperature, detected pressure, and gas composition detection information. The computing device 101 may then generate a detected sound velocity 113 from the set of channel sound velocity groups 112 described above. Thereafter, the computing device 101 may generate the checked sound velocity 114 from the respective detected temperatures, detected pressures, and gas composition detection information included in the above-described sound velocity check information set 111. Finally, the computing device 101 may control the associated natural gas alerting device 116 to perform an ultrasonic flow meter sound speed anomaly alert operation that characterizes the ultrasonic flow meter sound speed anomaly of the target natural gas station in response to the check sound speed 114 and the detected sound speed 113 satisfying the ultrasonic flow meter sound speed anomaly condition 115.

The computing device 101 may be hardware or software. When the computing device is hardware, the computing device may be implemented as a distributed cluster formed by a plurality of servers or terminal devices, or may be implemented as a single server or a single terminal device. When the computing device is embodied as software, it may be installed in the hardware devices listed above. It may be implemented as a plurality of software or software modules, for example, for providing distributed services, or as a single software or software module. The present invention is not particularly limited herein.

It should be understood that the number of computing devices in fig. 1 is merely illustrative. There may be any number of computing devices, as desired for an implementation.

With continued reference to fig. 2, a flow 200 of some embodiments of a natural gas warning device control method according to the present disclosure is shown. The control method of the natural gas alarm equipment comprises the following steps:

step 201, in response to detecting that the sound velocity checking operation information record of the user for the target natural gas station or the current time meets a preset sound velocity checking period time condition, and the detected flow velocity of the ultrasonic flowmeter corresponding to the target natural gas station meets a preset flow velocity threshold condition, determining whether the detected temperature of the temperature transmitter corresponding to the target natural gas station meets a preset temperature stabilizing condition.

In some embodiments, the execution body of the control method of the natural gas alarm device (for example, the computing device 101 shown in fig. 1) may determine, in response to detecting that the sound speed checking operation information record of the target natural gas station by the user or the current time satisfies a preset sound speed checking cycle time condition, that the detected flow rate of the ultrasonic flowmeter corresponding to the target natural gas station satisfies a preset flow rate threshold condition, whether the detected temperature of the temperature transmitter corresponding to the target natural gas station satisfies a preset temperature stabilizing condition. The target natural gas station may be any natural gas station. The sound velocity checking operation information record may be an information record sent to the execution subject by the terminal device after the user performs the operation of checking the sound velocity by the terminal device. The operation of confirming the sound velocity checking by the user through the terminal equipment can be the selection operation of the control for carrying out sound velocity checking on the characterization displayed on the terminal equipment. The preset sound speed check cycle time condition may be "the current time is the preset sound speed check cycle time". The above-described sound speed check cycle time may be a preset cycle time for periodically checking the sound speed, and may include various cycle time points. For example, the above sound speed check cycle time may be "8 points, 12 points, 16 points, 20 points per day". Here, the setting of the specific cycle time point included in the above-described sound speed check cycle time is not limited. The ultrasonic flowmeter may be a metering device for measuring natural gas flow provided at the target natural gas station. The detected flow rate may be a flow rate of natural gas currently detected by the ultrasonic flowmeter. The predetermined flow rate threshold condition may be "the detected flow rate is greater than a predetermined flow rate threshold". Here, the specific setting of the preset flow rate threshold is not limited. For example, the preset flow rate threshold may be "1 m/s". The temperature transmitter is arranged at the target natural gas station. The detected temperature may be a temperature currently detected by the temperature transmitter. The preset temperature stabilizing condition may be "the difference between the detected temperature and the detected temperature at the target history time point is smaller than a preset temperature difference". The target historical time point may be a time point of a preset duration before the current time point. For example, the target history time point may be a time point 2 minutes before the current time point. Here, specific settings of the preset time period and the preset temperature difference are not limited. Therefore, when the user selects the time for checking the sound velocity of the target natural gas station or reaching the checked sound velocity, and the flow velocity detected by the ultrasonic flowmeter of the target natural gas station meets the preset flow velocity threshold condition, whether the temperature detected by the temperature transmitter of the target natural gas station meets the preset temperature stability condition or not can be determined.

Step 202, in response to determining that the detected temperature meets a preset temperature stability condition, determining whether the detected pressure of the pressure transmitter corresponding to the target natural gas station meets the preset pressure stability condition.

In some embodiments, the executing entity may determine whether the detected pressure of the pressure transmitter corresponding to the target natural gas station meets the preset pressure stabilizing condition in response to determining that the detected temperature meets the preset temperature stabilizing condition. Wherein the pressure transmitter is disposed at the target natural gas field station. The sensed pressure may be a pressure currently sensed by the pressure transmitter. The preset pressure stabilizing condition may be that "the difference between the detected pressure and the detected pressure at the target history time point is smaller than a preset pressure difference". Here, the specific setting of the preset pressure difference is not limited. Therefore, when the temperature detected by the temperature transmitter meets the preset temperature stability condition, whether the pressure detected by the pressure transmitter of the target natural gas station meets the preset pressure stability condition or not can be determined.

In step 203, in response to determining that the detected pressure meets the preset pressure stabilizing condition, it is determined whether the gas component detection information of the gas chromatograph corresponding to the target natural gas station meets the preset gas component stabilizing condition.

In some embodiments, the executing entity may determine whether the gas composition detection information of the gas chromatograph corresponding to the target natural gas station satisfies a preset gas composition stability condition in response to determining that the detected pressure satisfies the preset pressure stability condition. Wherein the gas chromatograph is disposed at the target natural gas station. The gas component detection information may be information of a gas component currently detected by the gas chromatograph, and may include component values of various gases. The component values may be molar masses. The sum of the normalized component values of the above gases may be the normalized component value sum. The predetermined gas composition stability condition may be "the normalized composition value and within a predetermined numerical range". The preset gas component stabilizing condition can also comprise that the component values of various gases are all in the corresponding component value interval. I.e. a component value interval for each type of gas. Here, specific settings of the preset numerical range and the component value range of each type of gas are not limited. It is understood that, when the preset gas component stabilization conditions include "the component values of each type of gas are all within the corresponding component value intervals", the preset gas component stabilization conditions are "the normalized component values and within the preset numerical value intervals", and the component values of each type of gas are all within the corresponding component value intervals ". Therefore, when the pressure detected by the pressure transmitter of the target natural gas station meets the preset pressure stabilizing condition, whether the gas component detection information of the gas chromatograph of the target natural gas station meets the preset gas component stabilizing condition can be determined.

And 204, responding to the fact that the gas component detection information meets the preset gas component stability condition, and acquiring a sound velocity checking information set of the target natural gas station and a sound channel sound velocity group set of the ultrasonic flowmeter in a preset time period.

In some embodiments, the executing body may acquire, from the flow computer, a sound speed check information set of the target natural gas station and a sound channel sound speed group set of the ultrasonic flowmeter in a preset period of time through a wired connection or a wireless connection in response to determining that the gas component detection information satisfies the preset gas component stability condition. The flow computer can be used for storing metering data of various metering devices of each natural gas station. The preset time period may be a preset future time period or a preset history time period. Here, the specific setting of the above-described preset period is not limited. It is understood that, when the preset time period is a preset future time period, the executing body may obtain the sound speed check information set of the target natural gas station and the sound speed group set of the ultrasonic flowmeter in the preset time period in response to the ending time point that the current time is greater (later) than the preset time period. The sound speed check information in the above-described sound speed check information set may be a sequence of related information for checking the sound speed. The sound velocity checking information in the sound velocity checking information set includes detection temperature, detection pressure, and gas composition detection information. Each sound speed check information in the sound speed check information set corresponds to a point in time. The time points corresponding to the sound velocity checking information in the sound velocity checking information set are continuous. The set of sound velocity groups of channels may be a set of sound velocity groups of respective channels within the preset period. Each of the set of channel sound speed groups corresponds to a point in time. The set of sound velocity of channels in the set of sound velocity of channels may be sound velocities of the channels. Therefore, when the gas component detection information of the gas chromatograph of the target natural gas station meets the preset gas component stability condition, a sound velocity checking information set and a sound velocity group set can be obtained and used for checking the sound velocity of the ultrasonic flowmeter.

It should be noted that the wireless connection may include, but is not limited to, 3G/4G connections, wiFi connections, bluetooth connections, wiMAX connections, zigbee connections, UWB (ultra wideband) connections, and other now known or later developed wireless connection means.

Alternatively, the execution subject may determine whether the sound speed check information set satisfies a preset stability condition. The preset stability condition is that the difference of detected flow rates included in every two adjacent sound velocity checking information in the sound velocity checking information set is smaller than the preset flow rate, the difference of the included detected temperatures is smaller than the preset temperature, the difference of the included detected pressures is smaller than the preset pressure, and the corresponding normalized component values of the included gas component detection information are within a preset numerical interval. Here, specific settings for the preset flow rate, the preset temperature, the preset pressure, and the preset numerical range are not limited. Therefore, the stability of the sound speed checking information set can be checked after the sound speed checking information set is acquired.

Step 205, generating a detected sound velocity according to the sound velocity group set of the sound channels.

In some embodiments, the executing body may generate the detected sound velocity according to the set of sound velocity groups. In practice, the execution body may determine an average value of the sound speeds of the respective channels included in the channel sound speed group set as the detection sound speed. Thus, detecting the speed of sound may characterize the speed of sound when the ultrasonic flow meter detects the flow of natural gas.

In some optional implementations of some embodiments, the executing entity may generate the detected sound speed according to the set of sound channel sound speed groups in response to determining that the set of sound speed check information satisfies the preset stability condition. Thus, the detected sound speed can be generated after it is determined that the sound speed check information set is stable.

And 206, generating checked sound velocity according to each detected temperature, detected pressure and gas composition detection information included in the sound velocity checking information set.

In some embodiments, the executing body may generate the checked sound speed according to respective detected temperature, detected pressure, and gas composition detection information included in the sound speed check information set. In practice, first, the execution subject may determine the average value of the respective detected temperatures as an average detected temperature. Then, the average value of the respective detected pressures included in the above-described sound speed check information set may be determined as an average detected pressure. Then, for each type of gas corresponding to the gas component detection information included in the sound speed check information set, an average value of the respective component values corresponding to the gas among the component values included in the sound speed check information set may be determined as an average detection component value. Finally, a check sound speed may be generated based on the average detected temperature, the average detected pressure, and the determined average detected component value. Wherein the determined average detection component value is the average detection component value of corresponding various gases. In practice, the executing body may use the average detected temperature, the average detected pressure, and the determined average detected component value as input parameters of a check sound speed generating method corresponding to the check sound speed interface, and call the check sound speed generating method of the check sound speed interface to obtain the check sound speed. The above-mentioned check sound speed interface may be an interface that implements the check sound speed generating method as an interface form for call. The above-described check sound speed generation method may be a method of generating a check sound speed implemented according to the AGA (American Gas Association) standard. Thus, the verification sound speed may characterize the standard sound speed determined by the sound speed verification information set.

In step 207, in response to the checking that the sound speed and the detected sound speed meet the ultrasonic flow meter sound speed anomaly condition, controlling the associated natural gas alarm device to perform an ultrasonic flow meter sound speed anomaly alarm operation that characterizes an ultrasonic flow meter sound speed anomaly of the target natural gas station.

In some embodiments, the executing body may control the associated natural gas warning device to execute an ultrasonic flow meter sound speed abnormality warning operation that characterizes an ultrasonic flow meter sound speed abnormality of the target natural gas station in response to the check sound speed and the detected sound speed satisfying an ultrasonic flow meter sound speed abnormality condition. The abnormal sound velocity condition of the ultrasonic flowmeter may be that "an absolute value of a difference between the check sound velocity and the detected sound velocity is greater than a preset sound velocity difference value". Here, the specific setting of the preset sound speed difference value is not limited. The natural gas alarm device may be a terminal device having an alarm function. For example, the natural gas alarm device may be a mobile phone of an maintainer. The ultrasonic flowmeter sound speed abnormality alarm operation may be an alarm operation that characterizes an ultrasonic flowmeter sound speed abnormality of the target natural gas station. For example, the ultrasonic meter sound speed abnormality warning operation may be to display ultrasonic meter sound speed abnormality information indicating an ultrasonic meter sound speed abnormality of the target natural gas station on a display screen of the natural gas warning device. For example, the ultrasonic flowmeter sound speed abnormality information may be "natural gas station 001, ultrasonic flowmeter sound speed abnormality". The ultrasonic flow meter sound speed abnormality alarm operation may further include playing the ultrasonic flow meter sound speed abnormality information. "001" can be used to uniquely identify a natural gas field station. Therefore, when the checked sound speed and the detected sound speed meet the abnormal sound speed condition of the ultrasonic flowmeter, the associated natural gas alarm equipment can be controlled to execute abnormal sound speed alarm operation of the ultrasonic flowmeter.

Alternatively, the executing body may send a preset gas flow rate abnormality notification to the natural gas alarm device in response to determining that the detected flow rate does not satisfy the preset flow rate threshold condition. The preset gas flow rate abnormality prompting information may be information representing that the gas flow rate needs to be lifted. For example, the preset gas flow rate increase prompt message may be "the gas flow rate is low, it is not suitable to perform sound velocity check, and wait for the gas flow rate to increase.

The execution body may further send a preset gas temperature stability abnormality notification to the natural gas alarm device in response to determining that the detected temperature does not satisfy the preset temperature stability condition. The preset abnormal prompt information of the gas temperature stability can be information representing that the gas temperature is unstable. For example, the preset abnormal gas temperature stability prompt message may be "the gas temperature is unstable, it is not suitable to perform sound velocity check, and wait for the gas temperature to be stable.

The execution body may further send a preset gas pressure stability abnormality notification to the natural gas warning device in response to determining that the detected pressure does not satisfy the preset pressure stability condition. The preset gas pressure stability abnormality prompting information may be information indicating that the gas pressure is unstable. The preset gas pressure stability abnormality prompting message may be "gas pressure is unstable, it is not suitable to perform sound velocity check, and wait for gas pressure to be stable.

The execution body may further transmit a preset gas component stability abnormality notification to the natural gas alarm device in response to determining that the gas component detection information does not satisfy the preset gas component stability condition. The preset gas component stability abnormality prompting information can be information representing that the gas component is unstable. For example, when the gas composition detection information does not satisfy the preset gas composition stability condition "the normalized composition value is within the preset value interval", the preset gas composition stability anomaly prompting information may be "the gas composition is unstable, it is not easy to perform sound velocity check, and wait for the gas composition to be stable. When the gas component detection information does not meet the preset gas component stability condition, namely the normalized component value is within a preset value interval, and the component values of various gases are within a corresponding component value interval, the preset gas component stability abnormality prompting information can be that the gas component is unstable, the gas component is overrun, sound velocity check is not easy to be carried out, and waiting for the gas component to be stable.

The execution body may further control the natural gas alarm device to execute an ultrasonic flow meter sound speed check cancellation alarm operation of characterizing cancellation of sound speed check on the ultrasonic flow meter in response to determining that the sound speed check information set does not satisfy the preset stability condition. The operation of canceling the alarm for checking the sound velocity of the ultrasonic flowmeter may be an operation of canceling the alarm for checking the sound velocity of the ultrasonic flowmeter. For example, the ultrasonic flow meter sound speed check cancellation alarm operation may display ultrasonic flow meter sound speed check cancellation information characterizing cancellation of sound speed check on the ultrasonic flow meter on a display screen of the natural gas alarm device. For example, the above ultrasonic flow meter sound speed check cancellation information may be "natural gas station 001, cancel ultrasonic flow meter sound speed check".

Optionally, in the first step, the executing body may obtain the flow checking information set of the target natural gas station and the accounting flow set of the corresponding ultrasonic flowmeter in the preset time period in response to detecting that the flow checking operation information record of the target natural gas station is checked by the user or that the current time meets a preset flow checking cycle time condition.

In some embodiments, the executing body may obtain, from the flow computer, the flow verification information set of the target natural gas station and the accounting flow set corresponding to the ultrasonic flowmeter in the preset time period through wired connection or wireless connection in response to detecting that the flow verification operation information record of the target natural gas station by the user or the current time satisfies a preset flow verification cycle time condition. The flow checking operation information record may be an information record sent to the execution body by the terminal device after the user performs the operation of confirming the flow checking through the terminal device. The operation of confirming the flow checking by the user through the terminal equipment can be the selection operation of the control for carrying out the flow checking on the characterization displayed on the terminal equipment. The preset flow rate checking cycle time condition may be "the current time is the preset flow rate checking cycle time". The flow checking cycle time may be a preset cycle time for checking the flow periodically, and may include each cycle time point. For example, the flow rate check cycle time may be "8 points, 12 points, 16 points, 20 points per day". Here, the setting of the specific cycle time point included in the above-described flow rate verification cycle time is not limited. The above-described set of traffic verification information may be a set of traffic verification information for verifying traffic. The flow rate verification information in the flow rate verification information set may include a detected flow rate, a detected temperature, and a detected pressure. Each flow check information in the flow check information set corresponds to a time point. The detected flow rate may be a flow rate detected by the ultrasonic flowmeter. The set of calculated flow rates corresponding to the ultrasonic flow meter may be various kinds of calculated flow rates generated by the flow rate computer and used for counting the flow rate of the ultrasonic flow meter, and may include, but is not limited to: working condition flow and standard condition flow.

Second, for each accounting flow in the set of accounting flows, performing the steps of:

and a first sub-step of generating check flow corresponding to the check flow according to the flow check information set.

In some embodiments, the executing entity may generate the verification traffic corresponding to the accounting traffic according to the traffic verification information set. In practice, in response to the accounting flow being the working condition flow, for each flow checking information in the flow checking information set, the executing body may use the detected flow, the detected temperature and the detected pressure included in the flow checking information as input parameters of the working condition flow generating method corresponding to the checking working condition flow interface, and call the working condition flow generating method of the checking working condition flow interface to obtain the working condition flow. Then, the average value of the obtained flow rates of the respective working conditions can be determined as the check flow rate. In practice, in response to the accounting traffic being the standard traffic, for each traffic verification information in the traffic verification information set, the executing body may use the detected traffic, the detected temperature and the detected pressure included in the traffic verification information as input parameters of a standard traffic generating method corresponding to the checked standard traffic interface, and call the standard traffic generating method of the checked standard traffic interface to obtain the standard traffic. The resulting average of the individual standard flow rates may then be determined as the check flow rate.

And a second sub-step of controlling the natural gas alarm device to execute ultrasonic flowmeter flow abnormality alarm operation representing ultrasonic flowmeter flow abnormality of the target natural gas station in response to the difference between the check flow and the accounting flow meeting a preset ultrasonic flowmeter flow abnormality condition.

In some embodiments, the executing body may control the natural gas alarm device to execute an ultrasonic flowmeter flow anomaly alarm operation that characterizes an ultrasonic flowmeter flow anomaly of the target natural gas station in response to the difference between the check flow rate and the accounting flow rate satisfying a preset ultrasonic flowmeter flow anomaly condition. The abnormal flow condition of the preset ultrasonic flowmeter may be that "an absolute value of a difference between the check flow rate and the accounting flow rate is greater than a preset flow rate". Here, the specific setting of the preset flow rate is not limited. The ultrasonic flowmeter flow anomaly alarm operation may be an alarm operation that characterizes an ultrasonic flowmeter flow anomaly of the target natural gas station. For example, the ultrasonic meter flow anomaly alarm operation may be displaying ultrasonic meter flow anomaly information characterizing ultrasonic meter flow anomalies of the target natural gas farm on a display screen of the natural gas alarm device. For example, when the calculated flow rate is the operating condition flow rate, the ultrasonic flowmeter flow rate abnormality information may be "natural gas station 001, ultrasonic flowmeter operating condition flow rate abnormality". In another example, when the calculated flow rate is the standard flow rate, the ultrasonic flowmeter flow rate abnormality information may be "the natural gas station 001, the ultrasonic flowmeter standard flow rate is abnormal".

The first step and the second step are taken as an invention point of the embodiment of the disclosure, and solve the second technical problem that the automatic flow check cannot be performed on the natural gas metering equipment in the background art. The factors that lead to the inability to automate flow verification of natural gas metering equipment are often as follows: the natural gas metering equipment (such as an ultrasonic flowmeter) is required to be disassembled and then conveyed to a metering center for detection, the detection operation is complicated, and automatic flow checking cannot be performed on the natural gas metering equipment. If the above factors are solved, the effect of automatically checking the flow of the natural gas metering equipment can be achieved. To achieve this effect, the present disclosure generates a check flow for each of the check flows in the set of check flows by the acquired set of flow check information and the set of check flows of the corresponding ultrasonic flow meter. So that it is possible to automatically determine whether the above-mentioned accounting flow rate of the ultrasonic flowmeter is abnormal or not based on the difference between the check flow rate and the accounting flow rate. And further, the related natural gas alarm equipment can be automatically controlled to execute the abnormal flow alarm operation of the ultrasonic flowmeter.

Alternatively, first, the executing body may obtain, in response to detecting that the metering loop checking operation information record of the target natural gas station by the user or that the current time meets a preset metering loop checking cycle time condition, real-time metering loop checking information of the target natural gas station from the flow computer through a wired connection manner or a wireless connection manner. The metering loop checking operation information record may be an information record sent to the execution subject through the terminal device after the user performs the operation of confirming the metering loop checking through the terminal device. The operation of confirming the metering loop checking by the user through the terminal equipment can be the selection operation of the control for the metering loop checking of the characterization displayed on the terminal equipment. The preset metering loop checking cycle time condition may be "the current time is the preset metering loop checking cycle time". The above-mentioned cycle time for checking the metering loop may be a preset cycle time for checking the metering loop at regular time, and may include each cycle time point. For example, the above-described metering loop check cycle time may be "8 points, 12 points, 16 points, 20 points per day". Here, the setting of the specific cycle time point included in the above-described metering circuit check cycle time is not limited. The real-time metering loop checking information comprises real-time detection flow velocity, real-time detection temperature, real-time detection pressure and real-time gas component detection information. The real-time detected flow rate may be a real-time flow rate detected by the ultrasonic flowmeter. The real-time detected temperature may be a real-time temperature detected by the temperature transmitter. The real-time detected pressure may be a real-time pressure detected by the pressure transmitter. The real-time gas component information may be real-time gas component detection information detected by the gas chromatograph. Then, flow metering circuit anomaly information may be generated in response to determining that the real-time detected flow rate is outside of a preset flow rate range. The predetermined flow rate range may be a predetermined normal flow rate range. Here, the specific setting of the preset flow rate range is not limited. The above-described flow rate metering circuit abnormality information may be information characterizing an abnormality of a metering device (i.e., an ultrasonic flow meter) for detecting a flow rate. For example, the flow rate measurement circuit abnormality information may be "natural gas station 001, ultrasonic flowmeter flow rate overrun". And finally, controlling the natural gas alarm equipment to execute abnormal alarm operation of the flow rate metering circuit according to the abnormal information of the flow rate metering circuit. In practice, the execution body may control the natural gas warning device to display the flow rate metering circuit abnormality information on a display screen of the natural gas warning device. Thus, the metering device for detecting the flow rate in the metering loop can be automatically detected in real time.

Then, the executing body may generate temperature measurement loop abnormality information in response to determining that the real-time detected temperature is outside a preset temperature range, and control the natural gas alarm device to execute a temperature measurement loop abnormality alarm operation according to the temperature measurement loop abnormality information. The preset temperature range may be a preset normal temperature range. Here, the specific setting of the preset temperature range is not limited. The above temperature measurement loop abnormality information may be information characterizing an abnormality of a measurement device (i.e., a temperature transmitter) for detecting temperature. For example, the temperature measurement loop abnormality information may be "natural gas field 001, temperature transmitter temperature overrun". In practice, the executing body may control the natural gas alarm device to display the temperature metering loop abnormality information on a display screen of the natural gas alarm device. Thus, the real-time detection of the metering device for detecting the temperature in the metering loop can be automatically performed.

Then, the executing body may generate pressure measurement loop abnormality information in response to determining that the real-time detected pressure is outside a preset pressure range, and control the natural gas alarm device to execute a pressure measurement loop abnormality alarm operation according to the pressure measurement loop abnormality information. The preset pressure range may be a preset normal pressure range. Here, the specific setting of the preset pressure range is not limited. The above-described pressure gauge circuit anomaly information may be information that characterizes anomalies in a gauge device (i.e., pressure transmitter) used to detect pressure. For example, the pressure gauge circuit anomaly information may be "natural gas field 001, pressure transmitter pressure overrun". In practice, the execution body may control the natural gas warning device to display the pressure metering circuit abnormality information on a display screen of the natural gas warning device. Thus, the metering device for detecting the pressure in the metering circuit can be automatically detected in real time.

Finally, the executing body can generate abnormal information of the gas component metering loop in response to determining the normalized component value corresponding to the real-time gas component detection information and the value outside a preset value range, and control the natural gas alarming device to execute abnormal alarming operation of the gas component metering loop according to the abnormal information of the gas component metering loop. The preset numerical range may be a preset normal normalized component value sum range. Here, the specific setting of the preset numerical range is not limited. The above-described gas component measurement circuit abnormality information may be information that characterizes abnormality of a measurement device (i.e., a gas chromatograph) for detecting a gas component. For example, the above-described gas component measurement circuit abnormality information may be "natural gas field 001, normalized component value and overrun of gas chromatograph". In practice, the executing body may control the natural gas warning device to display the abnormal information of the gas component metering circuit on a display screen of the natural gas warning device. Therefore, the metering device for detecting the gas component in the metering loop can be automatically detected in real time.

The foregoing is provided as an invention point of an embodiment of the present disclosure, and solves the third technical problem mentioned in the background art, namely "automatic metering loop checking cannot be performed on a natural gas metering device". Factors that lead to a failure to automate the metering circuit check of a natural gas metering plant are often as follows: the natural gas metering equipment (such as an ultrasonic flowmeter) is required to be disassembled and then conveyed to a metering center for detection, the detection operation is complicated, and an automatic metering loop of the natural gas metering equipment cannot be checked. If the above factors are solved, the effect of automatically checking the metering loop of the natural gas metering equipment can be achieved. To achieve this effect, the present disclosure performs automated real-time detection of flow rate, temperature, pressure, and composition detection information of a metering circuit, respectively, by acquiring real-time detection flow rate, real-time detection temperature, real-time detection pressure, and real-time gas composition detection information included in real-time metering circuit verification information. So that it can be automatically determined whether the metering circuit is abnormal, and the specific part of the abnormality. And the related natural gas alarm equipment can be automatically controlled to execute corresponding metering loop abnormality alarm operation, such as flow velocity metering loop abnormality alarm operation, temperature metering loop abnormality alarm operation or pressure metering loop abnormality alarm operation.

With further reference to fig. 3, as an implementation of the method shown in the above figures, the present disclosure provides some embodiments of a natural gas warning device control apparatus, which apparatus embodiments correspond to those method embodiments shown in fig. 2, and the apparatus is particularly applicable to various electronic devices.

As shown in fig. 3, a natural gas warning device control apparatus 300 of some embodiments includes: a first determination unit 301, a second determination unit 302, a third determination unit 303, an acquisition unit 304, a first generation unit 305, a second generation unit 306, and a control unit 307. Wherein, the first determining unit 301 is configured to determine, in response to detecting that the sound speed checking operation information record of the user for the target natural gas station, or the current time satisfies a preset sound speed checking cycle time condition, and the detected flow rate of the ultrasonic flowmeter corresponding to the target natural gas station satisfies a preset flow rate threshold condition, whether the detected temperature of the temperature transmitter corresponding to the target natural gas station satisfies a preset temperature stabilizing condition; the second determining unit 302 is configured to determine, in response to determining that the detected temperature meets the preset temperature stabilizing condition, whether the detected pressure of the pressure transmitter corresponding to the target natural gas field station meets the preset pressure stabilizing condition; the third determining unit 303 is configured to determine whether the gas component detection information of the gas chromatograph corresponding to the target natural gas station satisfies a preset gas component stabilization condition in response to determining that the detected pressure satisfies the preset pressure stabilization condition; the obtaining unit 304 is configured to obtain a sound velocity check information set of the target natural gas station and a sound channel sound velocity group set of the ultrasonic flowmeter in a preset period in response to determining that the gas component detection information meets the preset gas component stability condition, wherein the sound velocity check information in the sound velocity check information set includes detection temperature, detection pressure and gas component detection information; the first generation unit 305 is configured to generate a detected sound velocity from the above-described set of channel sound velocity groups; the second generation unit 306 is configured to generate a checked sound speed from the respective detected temperatures, detected pressures, and gas composition detection information included in the above-described sound speed check information set; the control unit 307 is configured to control the associated natural gas warning device to perform an ultrasonic flow meter sound speed abnormality warning operation that characterizes an ultrasonic flow meter sound speed abnormality of the target natural gas station in response to the check sound speed and the detected sound speed satisfying an ultrasonic flow meter sound speed abnormality condition.

It will be appreciated that the elements described in the apparatus 300 correspond to the various steps in the method described with reference to fig. 2. Thus, the operations, features and resulting benefits described above with respect to the method are equally applicable to the apparatus 300 and the units contained therein, and are not described in detail herein.

Referring now to FIG. 4, a schematic diagram of an electronic device 400 (e.g., computing device 101 of FIG. 1) suitable for use in implementing some embodiments of the present disclosure is shown. The electronic device shown in fig. 4 is merely an example and should not impose any limitations on the functionality and scope of use of embodiments of the present disclosure.

As shown in fig. 4, the electronic device 400 may include a processing means (e.g., a central processing unit, a graphics processor, etc.) 401, which may perform various suitable actions and processes according to a program stored in a Read Only Memory (ROM) 402 or a program loaded from a storage means 408 into a Random Access Memory (RAM) 403. In the RAM 403, various programs and data necessary for the operation of the electronic device 400 are also stored. The processing device 401, the ROM 402, and the RAM 403 are connected to each other by a bus 404. An input/output (I/O) interface 405 is also connected to bus 404.

In general, the following devices may be connected to the I/O interface 405: input devices 406 including, for example, a touch screen, touchpad, keyboard, mouse, camera, microphone, accelerometer, gyroscope, etc.; an output device 407 including, for example, a Liquid Crystal Display (LCD), a speaker, a vibrator, and the like; storage 408 including, for example, magnetic tape, hard disk, etc.; and a communication device 409. The communication means 409 may allow the electronic device 400 to communicate with other devices wirelessly or by wire to exchange data. While fig. 4 shows an electronic device 400 having various means, it is to be understood that not all of the illustrated means are required to be implemented or provided. More or fewer devices may be implemented or provided instead. Each block shown in fig. 4 may represent one device or a plurality of devices as needed.

In particular, according to some embodiments of the present disclosure, the processes described above with reference to flowcharts may be implemented as computer software programs. For example, some embodiments of the present disclosure include a computer program product comprising a computer program embodied on a computer readable medium, the computer program comprising program code for performing the method shown in the flow chart. In such embodiments, the computer program may be downloaded and installed from a network via communications device 409, or from storage 408, or from ROM 402. The above-described functions defined in the methods of some embodiments of the present disclosure are performed when the computer program is executed by the processing device 401.

It should be noted that, the computer readable medium described in some embodiments of the present disclosure may be a computer readable signal medium or a computer readable storage medium, or any combination of the two. The computer readable storage medium can be, for example, but not limited to, an electronic, magnetic, optical, electromagnetic, infrared, or semiconductor system, apparatus, or device, or a combination of any of the foregoing. More specific examples of the computer-readable storage medium may include, but are not limited to: an electrical connection having one or more wires, a portable computer diskette, a hard disk, a Random Access Memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or flash memory), an optical fiber, a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In some embodiments of the present disclosure, a computer readable storage medium may be any tangible medium that can contain, or store a program for use by or in connection with an instruction execution system, apparatus, or device. In some embodiments of the present disclosure, however, the computer-readable signal medium may comprise a data signal propagated in baseband or as part of a carrier wave, with the computer-readable program code embodied therein. Such a propagated data signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination of the foregoing. A computer readable signal medium may also be any computer readable medium that is not a computer readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device. Program code embodied on a computer readable medium may be transmitted using any appropriate medium, including but not limited to: electrical wires, fiber optic cables, RF (radio frequency), and the like, or any suitable combination of the foregoing.

In some implementations, the clients, servers may communicate using any currently known or future developed network protocol, such as HTTP (HyperText Transfer Protocol ), and may be interconnected with any form or medium of digital data communication (e.g., a communication network). Examples of communication networks include a local area network ("LAN"), a wide area network ("WAN"), the internet (e.g., the internet), and peer-to-peer networks (e.g., ad hoc peer-to-peer networks), as well as any currently known or future developed networks.

The computer readable medium may be contained in the electronic device; or may exist alone without being incorporated into the electronic device. The computer readable medium carries one or more programs which, when executed by the electronic device, cause the electronic device to: responding to detection that a sound velocity checking operation information record of a user aiming at a target natural gas station or the current time meets a preset sound velocity checking period time condition, and determining whether the detection temperature of a temperature transmitter corresponding to the target natural gas station meets a preset temperature stabilizing condition or not, wherein the detection flow velocity of an ultrasonic flowmeter corresponding to the target natural gas station meets a preset flow velocity threshold condition; in response to determining that the detected temperature meets the preset temperature stabilizing condition, determining whether the detected pressure of the pressure transmitter corresponding to the target natural gas station meets the preset pressure stabilizing condition; determining whether gas component detection information of a gas chromatograph corresponding to the target natural gas station meets a preset gas component stabilization condition in response to determining that the detection pressure meets the preset pressure stabilization condition; responding to the fact that the gas component detection information meets the preset gas component stability condition, acquiring a sound velocity check information set of the target natural gas station and a sound channel sound velocity group set of the ultrasonic flowmeter in a preset time period, wherein sound velocity check information in the sound velocity check information set comprises detection temperature, detection pressure and gas component detection information; generating a detection sound velocity according to the sound velocity group set of the sound channels; generating checked sound velocity according to each detected temperature, detected pressure and gas composition detection information included in the sound velocity checking information set; and controlling the associated natural gas alarm equipment to execute ultrasonic flowmeter sound velocity abnormality alarm operation representing ultrasonic flowmeter sound velocity abnormality of the target natural gas station in response to the checked sound velocity and the detected sound velocity meeting ultrasonic flowmeter sound velocity abnormality conditions.

Computer program code for carrying out operations for some embodiments of the present disclosure may be written in one or more programming languages, including an object oriented programming language such as Java, smalltalk, C ++ and conventional procedural programming languages, such as the "C" programming language or similar programming languages. The program code may execute entirely on the user's computer, partly on the user's computer, as a stand-alone software package, partly on the user's computer and partly on a remote computer or entirely on the remote computer or server. In the case of a remote computer, the remote computer may be connected to the user's computer through any kind of network, including a Local Area Network (LAN) or a Wide Area Network (WAN), or may be connected to an external computer (for example, through the Internet using an Internet service provider).

The flowcharts and block diagrams in the figures illustrate the architecture, functionality, and operation of possible implementations of systems, methods and computer program products according to various embodiments of the present disclosure. In this regard, each block in the flowchart or block diagrams may represent a module, segment, or portion of code, which comprises one or more executable instructions for implementing the specified logical function(s). It should also be noted that, in some alternative implementations, the functions noted in the block may occur out of the order noted in the figures. For example, two blocks shown in succession may, in fact, be executed substantially concurrently, or the blocks may sometimes be executed in the reverse order, depending upon the functionality involved. It will also be noted that each block of the block diagrams and/or flowchart illustration, and combinations of blocks in the block diagrams and/or flowchart illustration, can be implemented by special purpose hardware-based systems which perform the specified functions or acts, or combinations of special purpose hardware and computer instructions.

The units described in some embodiments of the present disclosure may be implemented by means of software, or may be implemented by means of hardware. The described units may also be provided in a processor, for example, described as: a processor includes a first determination unit, a second determination unit, a third determination unit, an acquisition unit, a first generation unit, a second generation unit, and a control unit. The names of these units do not constitute a limitation on the unit itself in some cases, and for example, the first generation unit may also be described as "a unit that generates a detected sound velocity from the above-described channel sound velocity group set".

The functions described above herein may be performed, at least in part, by one or more hardware logic components. For example, without limitation, exemplary types of hardware logic components that may be used include: a Field Programmable Gate Array (FPGA), an Application Specific Integrated Circuit (ASIC), an Application Specific Standard Product (ASSP), a system on a chip (SOC), a Complex Programmable Logic Device (CPLD), and the like.

The foregoing description is only of the preferred embodiments of the present disclosure and description of the principles of the technology being employed. It will be appreciated by those skilled in the art that the scope of the invention in the embodiments of the present disclosure is not limited to the specific combination of the above technical features, but encompasses other technical features formed by any combination of the above technical features or their equivalents without departing from the spirit of the invention. Such as the above-described features, are mutually substituted with (but not limited to) the features having similar functions disclosed in the embodiments of the present disclosure.

Claims

1. A natural gas warning device control method comprising:

responding to detection that a sound velocity checking operation information record of a user aiming at a target natural gas station or the current time meets a preset sound velocity checking period time condition, and determining whether the detection temperature of a temperature transmitter corresponding to the target natural gas station meets a preset temperature stabilizing condition or not, wherein the detection flow velocity of an ultrasonic flowmeter corresponding to the target natural gas station meets a preset flow velocity threshold condition;

in response to determining that the detected temperature meets the preset temperature stability condition, determining whether the detected pressure of the pressure transmitter corresponding to the target natural gas station meets the preset pressure stability condition;

in response to determining that the detected pressure meets the preset pressure stabilizing condition, determining whether gas component detection information of a gas chromatograph corresponding to the target natural gas station meets the preset gas component stabilizing condition;

responding to the fact that the gas component detection information meets the preset gas component stability condition, acquiring a sound velocity check information set of the target natural gas station and a sound channel sound velocity group set of the ultrasonic flowmeter in a preset time period, wherein sound velocity check information in the sound velocity check information set comprises detection temperature, detection pressure and gas component detection information;

Generating a detection sound speed according to the sound channel sound speed group set;

generating checked sound velocity according to each detected temperature, detected pressure and gas composition detection information included in the sound velocity checking information set;

responsive to the checked sound speed and the detected sound speed satisfying an ultrasonic flow meter sound speed anomaly condition, controlling an associated natural gas alarm device to perform an ultrasonic flow meter sound speed anomaly alarm operation that characterizes an ultrasonic flow meter sound speed anomaly of the target natural gas station;

responding to detection of flow checking operation information record of a user aiming at a target natural gas station, or that the current time meets the condition of a preset flow checking period time, and acquiring a flow checking information set of the target natural gas station and a check flow set of a corresponding ultrasonic flowmeter in a preset time period;

for each accounting flow in the set of accounting flows, performing the steps of:

generating check flow corresponding to the check flow according to a flow check information set, wherein, responding to the check flow as working condition flow, for each flow check information in the flow check information set, taking the detected flow, the detected temperature and the detected pressure included in the flow check information as input parameters of a working condition flow generating method corresponding to a check working condition flow interface, calling the working condition flow generating method of the check working condition flow interface to obtain working condition flow, determining the average value of each working condition flow as check flow, responding to the check flow as standard condition flow, taking the detected flow, the detected temperature and the detected pressure included in the flow check information as input parameters of the standard condition flow generating method corresponding to the check standard condition flow interface for each flow check information in the flow check information set, calling the standard condition flow generating method of the check standard condition flow interface to obtain standard condition flow, and determining the average value of each obtained standard condition flow as check flow;

Controlling the natural gas alarm equipment to execute ultrasonic flowmeter flow abnormality alarm operation representing ultrasonic flowmeter flow abnormality of the target natural gas station in response to the difference between the checked flow and the accounting flow meeting a preset ultrasonic flowmeter flow abnormality condition;

in response to detecting that a metering loop checking operation information record of a user aiming at the target natural gas station or the current time meets a preset metering loop checking period time condition, acquiring real-time metering loop checking information of the target natural gas station from a flow computer in a wired connection mode or a wireless connection mode, wherein the real-time metering loop checking information comprises real-time detection temperature, real-time detection pressure and real-time gas component detection information;

generating temperature metering loop abnormality information in response to determining that the real-time detected temperature is outside a preset temperature range, and controlling the natural gas alarm equipment to execute temperature metering loop abnormality alarm operation according to the temperature metering loop abnormality information;

generating pressure metering loop abnormality information in response to determining that the real-time detected pressure is outside a preset pressure range, and controlling the natural gas alarm equipment to execute pressure metering loop abnormality alarm operation according to the pressure metering loop abnormality information;

And generating abnormal information of the gas component metering loop in response to determining the normalized component value corresponding to the real-time gas component detection information and being out of a preset numerical range, and controlling the natural gas alarm equipment to execute abnormal alarm operation of the gas component metering loop according to the abnormal information of the gas component metering loop.

2. The method of claim 1, wherein prior to the generating a detected sound speed from the set of channel sound speed sets, the method further comprises:

determining whether the sound speed checking information set meets a preset stability condition, wherein the preset stability condition is that the difference of detection flow rates included in every two adjacent sound speed checking information in the sound speed checking information set is smaller than a preset flow rate, the difference of detection temperatures included in the sound speed checking information set is smaller than a preset temperature, the difference of detection pressures included in the sound speed checking information set is smaller than a preset pressure, and the corresponding normalized component values of the included gas component detection information are within a preset numerical interval.

3. The method of claim 2, wherein the generating a detected sound speed from the set of channel sound speed groups comprises:

and generating a detection sound speed according to the sound speed group set of the sound speed in response to determining that the sound speed checking information set meets the preset stability condition.

4. A method according to claim 3, wherein the method further comprises:

transmitting a preset gas flow rate abnormality prompt message to the natural gas alarm device in response to determining that the detected flow rate does not meet the preset flow rate threshold condition;

transmitting a preset gas temperature stability abnormality prompt message to the natural gas alarm device in response to determining that the detected temperature does not meet the preset temperature stability condition;

in response to determining that the detected pressure does not meet the preset pressure stability condition, sending preset gas pressure stability abnormality prompting information to the natural gas alarm device;

transmitting a preset gas component stability abnormality prompt message to the natural gas alarm device in response to determining that the gas component detection information does not meet the preset gas component stability condition;

and controlling the natural gas alarm equipment to execute ultrasonic flowmeter sound speed check cancellation alarm operation for characterizing cancellation of sound speed check of the ultrasonic flowmeter in response to the fact that the sound speed check information set does not meet the preset stability condition.

5. A natural gas warning device control apparatus comprising:

a first determining unit configured to determine whether a detected temperature of a temperature transmitter corresponding to a target natural gas station satisfies a preset temperature stabilizing condition in response to detecting that a sound speed checking operation information record of a user for the target natural gas station or a current time satisfies a preset sound speed checking cycle time condition, and a detected flow rate of an ultrasonic flowmeter corresponding to the target natural gas station satisfies a preset flow rate threshold condition;

A second determining unit configured to determine whether a detected pressure of a pressure transmitter corresponding to the target natural gas field station satisfies a preset pressure stabilizing condition in response to determining that the detected temperature satisfies the preset temperature stabilizing condition;

a third determining unit configured to determine whether gas component detection information of a gas chromatograph corresponding to the target natural gas station satisfies a preset gas component stabilization condition in response to determining that the detection pressure satisfies the preset pressure stabilization condition;

an acquisition unit configured to acquire a sound speed check information set of the target natural gas station and a sound channel sound speed group set of the ultrasonic flowmeter in a preset period of time in response to determining that the gas composition detection information satisfies the preset gas composition stability condition, wherein sound speed check information in the sound speed check information set includes detection temperature, detection pressure, and gas composition detection information;

a first generation unit configured to generate a detected sound velocity from the set of channel sound velocity groups;

a second generation unit configured to generate a check sound speed from each of the detected temperature, the detected pressure, and the gas composition detection information included in the sound speed check information set;

A control unit configured to control an associated natural gas warning device to perform an ultrasonic flow meter sound speed anomaly warning operation that characterizes an ultrasonic flow meter sound speed anomaly of the target natural gas station in response to the check sound speed and the detected sound speed satisfying an ultrasonic flow meter sound speed anomaly condition;

the flow checking information set acquisition unit is configured to acquire a flow checking information set of the target natural gas station and an accounting flow set of a corresponding ultrasonic flowmeter in a preset time period in response to detection that the flow checking operation information record of the user for the target natural gas station or the current time meets a preset flow checking cycle time condition;

an execution unit configured to, for each accounting flow in the set of accounting flows, perform the steps of: generating check flow corresponding to the check flow according to a flow check information set, wherein, responding to the check flow as working condition flow, for each flow check information in the flow check information set, taking the detected flow, the detected temperature and the detected pressure included in the flow check information as input parameters of a working condition flow generating method corresponding to a check working condition flow interface, calling the working condition flow generating method of the check working condition flow interface to obtain working condition flow, determining the average value of each working condition flow as check flow, responding to the check flow as standard condition flow, taking the detected flow, the detected temperature and the detected pressure included in the flow check information as input parameters of the standard condition flow generating method corresponding to the check standard condition flow interface for each flow check information in the flow check information set, calling the standard condition flow generating method of the check standard condition flow interface to obtain standard condition flow, and determining the average value of each obtained standard condition flow as check flow; controlling the natural gas alarm equipment to execute ultrasonic flowmeter flow abnormality alarm operation representing ultrasonic flowmeter flow abnormality of the target natural gas station in response to the difference between the checked flow and the accounting flow meeting a preset ultrasonic flowmeter flow abnormality condition;

A real-time metering loop checking information acquisition unit configured to acquire real-time metering loop checking information of the target natural gas station from a flow computer through a wired connection mode or a wireless connection mode in response to detection of a metering loop checking operation information record of a user for the target natural gas station or that the current time meets a preset metering loop checking period time condition, wherein the real-time metering loop checking information comprises real-time detection temperature, real-time detection pressure and real-time gas component detection information;

a temperature measurement loop abnormality alert operation control unit configured to generate temperature measurement loop abnormality information in response to determining that the real-time detected temperature is outside a preset temperature range, and control the natural gas alert device to perform a temperature measurement loop abnormality alert operation according to the temperature measurement loop abnormality information;

a pressure measurement loop abnormality alert operation control unit configured to generate pressure measurement loop abnormality information in response to determining that the real-time detected pressure is outside a preset pressure range, and control the natural gas alert device to perform a pressure measurement loop abnormality alert operation according to the pressure measurement loop abnormality information;

And the gas component metering loop abnormality alarming operation control unit is configured to generate gas component metering loop abnormality information in response to determining that the normalized component value corresponding to the real-time gas component detection information is outside a preset numerical range, and control the natural gas alarming device to execute gas component metering loop abnormality alarming operation according to the gas component metering loop abnormality information.

6. An electronic device, comprising:

one or more processors;

a storage device having one or more programs stored thereon,

when executed by the one or more processors, causes the one or more processors to implement the method of any of claims 1-4.

7. A computer readable medium having stored thereon a computer program, wherein the program when executed by a processor implements the method of any of claims 1-4.