Method and system for identifying non-networked electric meter courts

Abstract

The invention discloses a method and system for identifying a zone area of an electricity meter without network access, and the method comprises the steps: 1, distributing a first characteristic current transmission frequency to the electricity meter without network access, and enabling the first characteristic current transmission frequency to be different from the characteristic current transmission frequency of the electricity meter with network access; step 2, the electricity meter which is not accessed to the network encodes the sending information, determines the sending time, and sends the sending information to the receiving equipment through the characteristic current; and step 3, the receiving device receives the characteristic current sent by the electricity meter which is not accessed to the network, decodes and verifies the characteristic current, analyzes the complete communication address of the electricity meter which is not accessed to the network, and completes the area identification of the electricity meter which is not accessed to the network. According to the method, on the basis that hardware cost is not increased, sending of characteristic current is dispersed through reasonable coding, the peak value of temperature rise is effectively reduced, the highest temperature of device temperature rise is still controlled within the range required by the device after the characteristic current carrying complete electricity meter communication address information is sent, and the reliability of the device is improved. Therefore, on the basis of not increasing the cost, the identification of the electricity meter which is not accessed to the network is realized.

Description

Technical Field

[0001] The present invention belongs to the technical field of power line carrier communication, and in particular relates to a method and system for identifying an off-grid electric meter area. Background Art

[0002] A low-voltage distribution substation area refers to the range or area of ​​power supplied by a transformer. The user-to-transformer relationship describes the power supply relationship between individual electricity users within the substation area and the transformer supplying the substation area. Users within the transformer's power supply range or area belong to the substation area; otherwise, they do not. This user-to-transformer relationship forms the basis for power distribution plan planning and substation line loss calculations.

[0003] Due to new installations, line upgrades, meter replacements, and other reasons, the relationship between households and transformers often changes. Previously, the relationship between households and transformers in the substation area mainly relied on the following methods:

[0004] 1. The production department provides installation record data saved during the construction of the substation, but the data is often quite different from the actual situation and is not updated in a timely manner.

[0005] 2. Manual survey, but the low-voltage distribution network has complex distribution lines, low inspection efficiency, high cost, and cannot accurately obtain transformer information.

[0006] However, the above methods, which rely on manual surveys or original construction data, are inefficient and have extremely low matching rates. In recent years, low-voltage substation automatic identification technology has developed rapidly. State Grid and Southern Grid have both implemented low-voltage substation automatic identification technology in some areas. Currently, the most widely used substation-to-substation relationship identification technology is based on characteristic current. Its basic principle is to add a characteristic current-related transmission circuit to the smart meter communication module. The smart meter uses a resistor switching method to generate a current signal with characteristic code bits that meet certain frequency domain rules between the neutral and live wires of the line. The terminal with cross-sampling performs real-time sampling and analysis of the line current signal, and determines whether the target characteristic code bits are successfully detected within the set time to determine whether the smart meter belongs to this substation. Due to the need to perform some control actions on the smart meter, the current automatic household-to-substation relationship identification solution requires that all smart meters be connected to the network. There is no solution for automatic household-to-substation identification of smart meters that are not connected to the network. Summary of the Invention

[0007] Purpose of the invention: The technical problem to be solved by the present invention is to provide a method and system for identifying non-grid meter areas in response to the shortcomings of the existing technology.

[0008] In order to solve the above technical problems, in a first aspect, a method for identifying a non-networked electricity meter area is disclosed, comprising the following steps:

[0009] Step 1: Allocate a first characteristic current transmission frequency to an off-grid electric meter, where the first characteristic current transmission frequency is different from the characteristic current transmission frequency of an on-grid electric meter;

[0010] Step 2: The non-networked meter encodes the transmission information, determines the transmission time according to its own meter communication address, and transmits the encoded transmission information to the receiving device via the characteristic current at the transmission time;

[0011] Step 3: The receiving device receives the characteristic current sent by the off-grid meter, decodes and verifies it, parses out the complete communication address of the sending meter, and completes the off-grid meter area identification.

[0012] Furthermore, in step 2, the non-networked electric meter encodes the information to be sent, and the information sent includes an information header, a complete electric meter communication address and verification information. The information header is used to indicate the start of sending the information, and the verification information is used to verify the correctness of the electric meter communication address.

[0013] Furthermore, the non-networked electricity meter encoding the transmitted information in step 2 includes: encoding the information to be transmitted so that the encoded information includes a plurality of N-bit binary data, wherein the N-bit binary data includes only one bit of data that is 1, and the other N-1 bits are 0, where N is set according to the number of bits of the transmitted information;

[0014] When the encoded transmission information is transmitted to the receiving device via the characteristic current, the characteristic current is only enabled when the N-bit binary data is 1, and is disabled at all other times. The characteristic current is only enabled for a single bit, ensuring that after the characteristic current is enabled for a single bit, the device remains in a cooling phase for N-1 bits, effectively reducing the peak device temperature.

[0015] Furthermore, in step 2, N is set to 16, and the encoding rule is to encode the hexadecimal 0x0 to 0xf as 0x0001, 0x0002, 0x0004, 0x0008, 0x0010, 0x0020, 0x0040, 0x0080, 0x0100, 0x0200, 0x0400, 0x0800, 0x1000, 0x2000, 0x4000, and 0x8000, respectively. The encoded 16-bit binary data only contains one bit of data that is 1. Therefore, regardless of the data sent, it can ensure an average transmission time of 1 bit and an idle cooling time of 15 bits, thereby effectively reducing the temperature rise. Experimental tests show that when N is 16, the temperature rise of sending 10 bytes of data in the encoded manner is equivalent to the temperature rise of sending 2 bytes at a time with the existing solution.

[0016] Furthermore, determining the sending time according to the communication address of the electric meter itself in step 2 includes:

[0017] First, the hour of the day (h) is determined based on the modulo 24 calculation of the last four digits of the meter's BCD (Binary-Coded Decimal) address. The hour is then divided into N equal parts based on the duration of the characteristic current transmission. A value (m) is randomly selected from 0 to (N-1), resulting in a transmission time of h hours and m*60 / N minutes. If more than N meters are assigned to a given hour, resulting in multiple meters transmitting simultaneously and causing identification failure, multiple transmissions are performed, each generating a new random number m, thus avoiding collisions and ultimately achieving successful identification.

[0018] Furthermore, the decoding and verification in step 3 include: receiving the information header length data and decoding the information header using a rule opposite to the encoding rule, comparing the decoded data and confirming whether it is an information header, if it is not an information header, restarting to receive the information header, if it is an information header, starting to receive all the data according to the agreed length, and then decoding using a rule opposite to the encoding rule; obtaining verification information from the decoded data, and verifying whether the complete meter communication address is correct based on the verification information. If correct, saving the complete meter communication address to complete the identification of the non-networked meter station.

[0019] In a second aspect, a non-networked electricity meter area identification system is disclosed, including a sending module and a receiving module. The sending module is used for the non-networked electricity meter to encode the transmission information, determine the transmission time according to the communication address of the electricity meter itself, and transmit the encoded transmission information to the receiving device at the transmission time via a characteristic current at a first characteristic current transmission frequency; the first characteristic current transmission frequency is different from the characteristic current transmission frequency of the networked electricity meter;

[0020] The receiving module is used to receive the characteristic current sent by the non-networked electricity meter, perform decoding and verification, parse out the complete communication address of the sending electricity meter, and complete the non-networked electricity meter station area identification.

[0021] Furthermore, the sending module includes a sending information generation unit, an encoding unit and a sending unit, wherein the sending information generation unit is used to assemble an information header, a complete meter communication address and verification information to generate the sending information;

[0022] The encoding unit is used to encode the information to be sent so that the encoded information includes multiple N-bit binary data, where only one bit of the N-bit binary data is 1 and the other N-1 bits are 0, where N is set according to the number of bits of the information to be sent;

[0023] The sending unit is used to send the encoded sending information. When sending the N-bit binary data, the characteristic current sending is turned on only when the data is 1, and the characteristic current sending is turned off at other times.

[0024] Furthermore, the sending module also includes a sending time determination unit, which is used to determine the sending time according to its own meter communication address, so that meters with different meter communication addresses are assigned to different times for sending, and avoid the situation where multiple non-networked meters send at the same time as much as possible.

[0025] Furthermore, the receiving module includes a receiving unit, a decoding unit, a checking unit and a storage unit.

[0026] The receiving unit is used to receive the characteristic current sent by the non-networked electricity meter;

[0027] The decoding unit is used to decode the received characteristic current information using a rule opposite to the encoding rule;

[0028] The verification unit is configured to obtain verification information from the decoded data and verify whether the complete meter communication address is correct based on the verification information;

[0029] The storage unit is used to store the complete meter communication address after verification.

[0030] Beneficial effects: Due to the large number of meters actually deployed on-site and the complex environment, there are always some meters that cannot be connected to the network. If there are technical means to know the substations to which these meters belong, it will be beneficial to the operation and maintenance of these meters and the analysis and judgment of line loss calculation results.

[0031] Since off-grid meters cannot be controlled via the network to proactively transmit characteristic current signals at designated times, they must instead be sent automatically at specific times. Existing solutions, when the identification device receives the signal, it only receives a signature code, not the complete meter communication address. Clearly, it cannot determine from this information which meter sent the signal; the identification device only knows that a meter has transmitted characteristic current information. Therefore, to identify off-grid meters, the information must carry the complete meter communication address, requiring the transmission of more characteristic current information.

[0032] In the existing solution, in order to send the complete address, it is necessary to increase the high temperature resistance limit of components and add heat dissipation measures in order to meet the temperature rise requirements, which greatly increases the hardware cost and the size of the equipment.

[0033] Without increasing the hardware cost, this application disperses the transmission of characteristic current through reasonable coding, effectively reducing the peak value of temperature rise, so that after sending the characteristic current carrying the complete communication address information of the meter, the maximum temperature rise of the device is still controlled within the required range of the device. This achieves the identification of non-networked meters without increasing the cost. At the same time, this application adopts frequency division technology, that is, networked meters and non-networked meters use different frequencies to send characteristic currents. While achieving the identification of non-networked meters, it has no effect on the identification of the original networked meters, thereby achieving non-interference. BRIEF DESCRIPTION OF THE DRAWINGS

[0034] The present invention will be further described below in conjunction with the accompanying drawings and specific embodiments, and the above and / or other advantages of the present invention will become more apparent.

[0035] Figure 1 A flowchart of a method for identifying off-grid electricity meter areas provided in an embodiment of the present application.

[0036] Figure 2 A schematic diagram of sending characteristic current in a method for identifying a non-networked electricity meter area provided in an embodiment of the present application.

[0037] Figure 3 A schematic diagram of the process of sending and receiving characteristic current of an off-grid meter in a method for identifying an off-grid meter area provided in an embodiment of the present application.

[0038] Figure 4 A schematic diagram of 16-bit data with only one bit being 1 in a method for identifying a non-networked electricity meter area provided in an embodiment of the present application.

[0039] Figure 5 A schematic diagram of the structure of a non-grid meter area identification system provided in an embodiment of the present application. DETAILED DESCRIPTION

[0040] The embodiments of the present invention will be described below with reference to the accompanying drawings.

[0041] The present invention solves the problem that the station-transformer relationship of non-networked electric meters cannot be identified in a remote intelligent meter reading system at a relatively low cost based on the existing characteristic current technology.

[0042] In order to calculate line loss results more accurately and respond quickly to on-site operation and maintenance, we have gradually begun to focus on identifying household-to-transformer relationships for smart meters that are not connected to the grid.

[0043] Smart meters use resistor switching when transmitting their signature current, which can cause heating of related components. Continuous transmission can lead to rapid temperature increases, which can damage components. Therefore, to control the temperature during transmission, the length of the transmitted signature current information must be controlled. Current solutions use a 2-byte signature code. Since most smart meters currently use 6-byte addresses, 2 bytes are insufficient to fully represent the smart meter's communication address.

[0044] Therefore, most existing usage scenarios involve smart meters transmitting a two-byte current signature code. The receiving end determines whether the signature current signal is received. If received, it indicates that a smart meter in the distribution area is transmitting the signature current. To determine the specific meter transmitting, it is also necessary to be able to specify the meter at a specific time. The specific meter is then determined by combining the time the meter transmits the signature current and the time the receiving end recognizes it. To control the transmission of a meter's signature current, the meter must be connected to the network. Therefore, this method can only be applied to distribution area identification for meters already connected to the network; it cannot be applied to meters not already connected to the network. For example, a prior art method and system for identifying household-to-substation relationships based on signature current signals discloses a master station issuing a household-to-substation relationship identification command to a smart meter equipped with a signature current signal transmission function based on the meter's communication address. After receiving the household-to-substation relationship identification command, the smart meter uses a resistor switching device to generate a current signal corresponding to the signature code bit in the power grid and locally records the switching completion time. Upon receiving the household-to-substation relationship identification command, the terminal device with interrogation begins detecting the target signature code bit on the power line. The terminal with cross-detection determines whether the target signature is successfully detected. If it is detected within the set time, the identification result and identification time are saved locally on the terminal. If it is not detected within the set time, the information is not saved. The master station calls the meter switching time and the terminal identification time, and determines the household-to-user relationship based on the time stamp comparison.

[0045] Existing solutions for transmitting long-duration characteristic current information rely on selecting high-temperature-resistant components and adding heat sinks to support the transmission of more bytes of characteristic current information. This allows for the transmission of the complete meter communication address and identification of meters not connected to the network. However, this solution incurs high costs, is bulky, and is difficult to mass-produce.

[0046] 1) When smart meters transmit their signature current, they use a resistor switching method, which can cause heating of related components. Continuous transmission can lead to a rapid temperature rise, and excessive temperatures can damage components. Therefore, to control the temperature during transmission, the length of the transmitted signature current information must be controlled. Considering hardware costs and temperature rise, existing solutions typically use a 2-byte signature code. Since most smart meters currently use 6-byte addresses, these 2 bytes cannot fully represent the smart meter's communication address. Therefore, the receiving end cannot determine which meter is transmitting. To address this issue, meter-side transmission must be planned and controlled in advance, targeting a specific meter for transmission within a set timeframe. The specific meter can then be determined by combining the time the meter transmits the signature current and the time the receiver recognizes it. This requires that the smart meter is connected to the network and in a communicative state.

[0047] 2) Because existing solutions can only transmit a 2-byte signature code, the receiving device can only identify whether a signature meter signal is present on the line, but cannot further identify which meter is sending the signature current signal. Misidentification can occur when a meter connects to the grid across transformers. For example, meter a, which is actually at transformer A, connects to transformer B, while meter b, which is actually at transformer B, connects to transformer A. In this case, transformer A controls meter b to transmit the signature current, while transformer B controls meter a to transmit the signature current. The receiving devices at both transformers A and B can normally receive the signature signal, and both consider the identification successful. This can lead to meter b being mistakenly identified as the meter at transformer A, and meter a being mistakenly identified as the meter at transformer B.

[0048] 3) Although some existing solutions can send characteristic current information of more than 6 bytes, it requires a considerable cost and the device size is relatively large, making it difficult to use in practice.

[0049] To address the shortcomings of existing methods, the present invention builds on the original method for identifying substation topology relationships based on characteristic currents by improving the algorithm. This method leverages spread spectrum and frequency division techniques on existing hardware to transmit more data within a controllable temperature rise range, thereby enabling the complete identification of the communication address of meters not connected to the network. Furthermore, the present invention incorporates verification information into the data to avoid the potential false detections in step 2).

[0050] The first embodiment of the present application discloses a method for identifying a non-networked electricity meter area, such as Figure 1 As shown, the following steps are included:

[0051] Step 1: Allocate a first characteristic current transmission frequency to an off-grid electric meter, where the first characteristic current transmission frequency is different from the characteristic current transmission frequency of an on-grid electric meter;

[0052] Two suitable different characteristic current transmission frequencies are allocated to the connected and non-connected electricity meters respectively, and frequency division technology is used to avoid interference between the connected and non-connected electricity meters.

[0053] Because non-networked meters cannot transmit their characteristic currents under controlled conditions, they are likely to interfere with the identification of the characteristic currents of networked meters. To address this issue, two different transmission frequencies are used for networked and non-networked meters, and the identification device recognizes both frequencies simultaneously. By selecting appropriate frequencies so that the two frequencies do not interfere with each other, the effect of the characteristic current transmission of non-networked meters on networked meters is avoided. For example, a characteristic current transmission frequency of 833.3333 Hz can be used for networked meters, while a characteristic current transmission frequency of 983.3333 Hz can be used for non-networked meters.

[0054] Step 2: The non-networked meter encodes the transmission information, determines the transmission time according to its own meter communication address, and transmits the encoded transmission information to the receiving device via the characteristic current at the transmission time;

[0055] The electricity meters that have been connected to the network send characteristic current under control, and the electricity meters that are not connected to the network determine the sending time according to their own meter communication address and send characteristic current at the determined sending time, such as Figure 2 shown.

[0056] When an off-grid meter transmits its characteristic current, it carries a header, the complete meter communication address, and verification information. The header indicates the start of the message, and the verification information verifies the correctness of the meter communication address. For example, the header can be set to two bytes: aae9, and the CRC16 verification method can be selected.

[0057] Because the number of bytes sent is large, using existing solutions can cause device temperatures to overheat and damage the device. To address this issue, a special encoding process is first performed on the transmitted information to control the number of 1s sent within a certain period of time, distributing the transmitted energy and reducing the peak temperature rise of the device. The specially encoded information is then transmitted using a characteristic current.

[0058] The process of sending and receiving characteristic current of non-grid-connected electricity meters is as follows: Figure 3 shown.

[0059] To transmit the complete meter communication address, it is necessary to support the transmission of characteristic current information greater than 6 bytes. However, the existing method of continuous transmission causes a rapid temperature rise, and components may burn out before the characteristic current information is completely transmitted. Therefore, to achieve the transmission of relatively large information, the temperature rise issue must be resolved first.

[0060] When identifying characteristic current information, if the characteristic current is detected within a 1-bit width, that bit is considered 1; if not, it is considered 0. Therefore, when transmitting, the characteristic current transmission circuit is activated only when the information bit is 1; it is deactivated when the bit is 0. Only when the characteristic current transmission circuit is activated and resistors are switched on and off does the component heat up, causing the temperature to rise. In other words, the temperature only rises when the transmitted characteristic information code bit is 1. When the code bit is 0 and no characteristic current is transmitted, the temperature gradually decreases over time due to natural heat dissipation. The time when the information code bit is 1 represents the temperature rise period, and the time when the information code bit is 0 represents the temperature drop period.

[0061] At the same time, according to experiments, it is known that when the characteristic current is continuously turned on for transmission, that is, when there are multiple consecutive bits of 1 in the data, the temperature rises very quickly. To control the temperature rise, the code stream of the information can be changed to avoid the continuous appearance of many 1s, and at the same time limit the number of 1s that appear in a code stream. The information to be sent is encoded so that it includes multiple N-bit binary data after encoding, and the N-bit binary data only contains 1 bit of data that is 1, and the other N-1 bits are 0, and N is set according to the number of bits of the information to be sent; when the encoded transmission information is sent to the receiving device through the characteristic current, when sending the N-bit binary data, the characteristic current is turned on only when the data is 1, ensuring that within a certain period of time, the characteristic current is turned on for only 1 bit of time, and the characteristic current is turned off for the rest of the time. This ensures that after the characteristic current is turned on for 1 bit of time, there must be N-1 bits of time in the cooling stage, effectively reducing the peak temperature of the device.

[0062] The following describes the encoding and decoding process in detail, assuming that N is 16.

[0063] The encoding rules are shown in the following table:

[0064]

[0065] From the table above, we can see that no matter what the previous data is, after encoding, the 16-bit data only contains one 1-bit data. Therefore, no matter what data is sent, it can ensure an average of 1 bit of time to send and 15 bits of time to cool down during idle time, thus effectively reducing the temperature rise. Figure 4 As shown, the transmission time of 1 bit (0.6s) and the idle cooling time of 15 bits (9s) are shown. The experimental test shows that when N is 16, the temperature rise of sending 10 bytes of data in an encoded manner is equivalent to the temperature rise of sending 2 bytes once in the existing solution.

[0066] Determining the sending time according to the communication address of the electric meter itself includes:

[0067] First, determine the hour of the day when the transmission time is h based on the modulo 24 of the last 4 digits of the BCD code of the meter communication address. Then, divide one hour into N equal parts based on the transmission duration of the primary characteristic current. Then, randomly select a value m from 0 to (N-1) to determine the transmission time as h hour m*60 / N minutes.

[0068] Step 3: The receiving device receives the characteristic current sent by the off-grid meter, decodes and verifies it, parses out the complete communication address of the sending meter, and completes the off-grid meter area identification.

[0069] The received characteristic current is decoded using rules opposite to the encoding rules. First, the header length data is received and decoded. The decoded data is then compared to confirm whether it is a header. If it is not a header, the header is received again. If it is a header, all data is received according to the agreed length and then decoded. Verification information is obtained from the decoded data. The complete meter communication address is verified to be correct based on the verification information. If correct, the complete meter communication address is saved, completing the identification of the off-grid meter area.

[0070] The decoding rules are shown in the following table:

[0071] Before decoding After decoding Hexadecimal (16 bits) Hexadecimal (16 bits) 0x0001 0x0 0x0002 0x1 0x0004 0x2 0x0008 0x3 0x0010 0x4 ... ... 0x4000 0xe 0x8000 0xf

[0072] The receiving device analyzes the characteristic current signals at two frequencies simultaneously and in real time. The characteristic current signals at the two frequencies are completely independent and do not affect each other. When the receiving device receives the characteristic current sent by the non-networked meter, it decodes and verifies the information according to the agreed rules. If successful, it parses out the complete communication address of the sending meter. The result is saved or reported to the terminal. Since the non-networked meter in this embodiment carries the complete communication address of the meter when sending, as long as the station transformer corresponding to the meter is installed with a receiving device and correctly receives the characteristic current information, it can know which meter sent it. Therefore, there is no need to know in advance which meter is sending, so for the receiving device, there is no need for the meter to send in a controlled state, and there is no need for the meter to be connected to the network.

[0073] The second embodiment of the present application discloses a non-networked electricity meter area identification system, such as Figure 5 As shown, it includes a sending module and a receiving module. The sending module is used for the non-networked electricity meter to encode the sending information, determine the sending time according to the communication address of the electricity meter itself, and send the encoded sending information to the receiving device through the characteristic current at the first characteristic current sending frequency at the sending time; the first characteristic current sending frequency is different from the characteristic current sending frequency of the networked electricity meter;

[0074] The receiving module is used to receive the characteristic current sent by the non-networked electricity meter, perform decoding and verification, and if successful, parse out the complete communication address of the sending electricity meter to complete the non-networked electricity meter area identification.

[0075] The sending module includes a sending information generation unit, an encoding unit and a sending unit, wherein the sending information generation unit is used to assemble an information header, a complete meter communication address and verification information to generate sending information;

[0076] The encoding unit is used to encode the information to be sent so that the encoded information includes multiple N-bit binary data, where only one bit of the N-bit binary data is 1 and the other N-1 bits are 0, where N is set according to the number of bits of the information to be sent;

[0077] The sending unit is used to send the encoded sending information. When sending the N-bit binary data, the characteristic current sending is turned on only when the data is 1, and the characteristic current sending is turned off at other times.

[0078] The sending module further includes a sending time determining unit, which is used to determine the sending time according to the communication address of the electric meter itself, so that electric meters with different communication addresses are assigned to different times for sending.

[0079] The receiving module includes a receiving unit, a decoding unit, a checking unit and a storage unit.

[0080] The receiving unit is used to receive the characteristic current sent by the non-networked electricity meter;

[0081] The decoding unit is used to decode the received characteristic current information using a rule opposite to the encoding rule;

[0082] The verification unit is configured to obtain verification information from the decoded data and verify whether the complete meter communication address is correct based on the verification information;

[0083] The storage unit is used to store the complete meter communication address after verification.

[0084] In a specific implementation, the present application provides a computer storage medium and a corresponding data processing unit, wherein the computer storage medium is capable of storing a computer program that, when executed by the data processing unit, can execute the invention content of the method for identifying a non-networked electricity meter area provided by the present invention and some or all of the steps in each embodiment. The storage medium can be a magnetic disk, an optical disk, a read-only memory (ROM), or a random access memory (RAM).

[0085] Those skilled in the art can clearly understand that the technical solutions in the embodiments of the present invention can be implemented by means of computer programs and their corresponding general hardware platforms. Based on this understanding, the technical solutions in the embodiments of the present invention, in essence or in other words, the part that contributes to the prior art, can be embodied in the form of a computer program, i.e., a software product. The computer program software product can be stored in a storage medium and includes a number of instructions for enabling a device including a data processing unit (which can be a personal computer, server, single-chip microcomputer, MUU or network device, etc.) to execute the methods described in various embodiments of the present invention or certain parts of the embodiments.

[0086] The present invention provides a method and system for identifying off-grid electricity meter stations. There are numerous methods and approaches for implementing this technical solution. The above is merely a preferred embodiment of the present invention. It should be noted that those skilled in the art may make various improvements and modifications without departing from the principles of the present invention, and such improvements and modifications are also within the scope of protection of the present invention. Any components not specified in this embodiment may be implemented using existing technologies.

Claims

1. A method for identifying non-networked electric meter areas, characterized in that: The following steps are involved: Step 1: Allocate a first characteristic current transmission frequency to an off-grid electric meter, where the first characteristic current transmission frequency is different from the characteristic current transmission frequency of an on-grid electric meter; Step 2: The non-networked meter encodes the transmission information, determines the transmission time according to its own meter communication address, and transmits the encoded transmission information to the receiving device via the characteristic current at the transmission time; Step 3: The receiving device receives the characteristic current sent by the off-grid meter, decodes and verifies it, parses out the complete communication address of the sending meter, and completes the off-grid meter area identification.

2. The method for identifying non-networked electric meter areas according to claim 1, characterized in that: In step 2, the non-networked meter encodes the information to be sent, and the information sent includes an information header, a complete meter communication address and verification information. The information header is used to indicate the start of sending the information, and the verification information is used to verify the correctness of the meter communication address.

3. The method for identifying non-networked electric meter areas according to claim 2, characterized in that: The non-networked electricity meter encoding the transmitted information in step 2 includes: encoding the information to be transmitted so that the encoded information includes a plurality of N-bit binary data, wherein only one of the N-bit binary data is 1, and the other N-1 bits are 0, where N is set according to the number of bits of the transmitted information; When the encoded transmission information is sent to the receiving device through the characteristic current, when sending the N-bit binary data, the characteristic current transmission is turned on only when the data is 1, and the characteristic current transmission is turned off at other times.

4. The method for identifying non-networked electric meter areas according to claim 3, characterized in that: In step 2, N is 16. The encoding rule is to encode the hexadecimal 0x0 to 0xf as 0x0001, 0x0002, 0x0004, 0x0008, 0x0010, 0x0020, 0x0040, 0x0080, 0x0100, 0x0200, 0x0400, 0x0800, 0x1000, 0x2000, 0x4000, and 0x8000, respectively. The encoded 16-bit binary data contains only one bit of data that is 1.

5. The method for identifying non-networked electric meter areas according to claim 4, characterized in that: Determining the sending time based on the meter's own communication address in step 2 includes: first determining the hour of the day when the sending time is h based on the last 4 digits of the meter's communication address modulo 24, then dividing one hour into N equal parts based on the sending duration of a characteristic current; then randomly selecting a value m from 0 to (N-1) to determine the sending time as h hours and m*60 / N minutes.

6. A method for identifying non-networked electric meter areas according to claim 5, characterized in that: The decoding and verification in step 3 include: receiving the information header length data and decoding the information header using a rule opposite to the encoding rule, comparing the decoded data and confirming whether it is an information header, if it is not an information header, restarting to receive the information header, if it is an information header, starting to receive all the data according to the agreed length, and then decoding using a rule opposite to the encoding rule; obtaining verification information from the decoded data, and verifying whether the complete meter communication address is correct based on the verification information. If correct, saving the complete meter communication address to complete the identification of the non-networked meter station.

7. A non-grid meter area identification system, characterized in that: The system comprises a sending module and a receiving module. The sending module is used for encoding the transmission information of the non-networked electricity meter, determining the transmission time according to the communication address of the electricity meter itself, and transmitting the encoded transmission information to the receiving device at the transmission time through the characteristic current at a first characteristic current transmission frequency; the first characteristic current transmission frequency is different from the characteristic current transmission frequency of the networked electricity meter; The receiving module is used to receive the characteristic current sent by the non-networked electricity meter, perform decoding and verification, parse out the complete communication address of the sending electricity meter, and complete the non-networked electricity meter station area identification.

8. The non-grid-connected electric meter area identification system according to claim 7 is characterized in that: The sending module includes a sending information generation unit, an encoding unit and a sending unit, wherein the sending information generation unit is used to assemble an information header, a complete meter communication address and verification information to generate sending information; The encoding unit is used to encode the information to be sent so that the encoded information includes multiple N-bit binary data, where only one bit of the N-bit binary data is 1 and the other N-1 bits are 0, where N is set according to the number of bits of the information to be sent; The sending unit is used to send the encoded sending information. When sending the N-bit binary data, the characteristic current sending is turned on only when the data is 1, and the characteristic current sending is turned off at other times.

9. The non-grid meter area identification system according to claim 8 is characterized in that: The sending module further includes a sending time determining unit, which is used to determine the sending time according to the communication address of the electric meter itself, so that electric meters with different communication addresses are assigned to different times for sending.

10. The non-grid-connected electric meter area identification system according to claim 9, characterized in that: The receiving module includes a receiving unit, a decoding unit, a checking unit and a storage unit. The receiving unit is used to receive the characteristic current sent by the non-networked electricity meter; The decoding unit is used to decode the received characteristic current information using a rule opposite to the encoding rule; The verification unit is configured to obtain verification information from the decoded data and verify whether the complete meter communication address is correct based on the verification information; The storage unit is used to store the complete meter communication address after verification.

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