System for automatically detecting power system configuration

Detailed description of the invention

(Technical field) The present invention generally relates to a method of automatically detecting the configuration of an electrical network.

(Background technology) With rising energy prices, environmental concerns, and the ever-increasing importance of energy savings, there is growing interest in detecting and preventing electricity theft. Direct theft from high-voltage distribution lines is carried out by installing distribution transformers, which are not the property of the power company, on the distribution lines without permission. Power companies are not always aware of the existence of such transformers, so this type of electricity theft compares the energy supplied by a distribution transformer owned by the power company with the energy consumed by the end user. But it is not detected. In order to detect this type of theft, it is necessary to measure consumption at the level of distribution lines. In current technology, distribution line meters measure the energy supplied by distribution lines. For this purpose, it is necessary to obtain the electric power by multiplying the voltage and the current, and to integrate this electric power for a certain period to obtain the energy. Theft can be detected by comparing the energy supplied by the distribution line with the energy supplied by the distribution transformer of that distribution line. The main drawback of this approach is that the distribution line meter must be designed and manufactured to operate at high voltages. High voltage devices are expensive and dangerous to install depending on the design. Furthermore, a voltage drop occurs for each distribution line due to the presence of current and wire resistance, and this voltage drop causes a measurement error during comparison. Increased measurement errors mean that extra distribution line meters are needed for any number of distribution transformers to be able to distinguish between measurement errors and theft.

The configuration information is important as an input value for the theft detection formula. It is necessary to know which end user is connected to which distribution transformer and how which distribution transformer is associated with which distribution meter. The conventional method of continuously retaining configuration information is to create a series of maps showing the devices that make up the power distribution system and how the devices are connected to each other. This method is costly and laborious , and often results in outdated maps.

(Outline of the invention) According to one aspect of the present invention, there is provided a method for detecting the configuration of a network having a distribution line including a plurality of distribution line meters and a plurality of distribution transformer meters connected thereto. The method comprises a step of transmitting a uniquely identifiable signal having a phase from each of the distribution line meters via the distribution line. Next, each distribution transformer meter identifies the phase of each uniquely identifiable signal, and transmits the phase of the uniquely identifiable signal to the data acquisition device together with the distribution transformer meter unique identifier. Next, the phases recorded by each distribution transformer meter are compared to determine where on the distribution line the distribution transformer is connected to the distribution line meter.

According to another aspect of the present invention, there is provided a method for detecting the configuration of a network having a distribution line in which a plurality of distribution transformer meters are connected and at least one customer meter connected to each of the above distribution transformer meters. To do. The above method involves transmitting a distribution transformer meter unique identifier from each of the distribution transformer meters to all the customer meters connected to the distribution transformer meter, and then from each of the customer meters, the distribution transformer meter. It includes a step of transmitting a unique identifier and a unique customer meter identifier to a data collection device at another location. Then, the distribution transformer meter unique identifier and the corresponding customer meter identifier are stored in the database. In this way, it is possible to determine which distribution transformer each customer meter is connected to.

According to another aspect of the present invention, there is provided a method of detecting the configuration of a network having distribution lines connected to a plurality of distribution line meters and customer configuration modules arranged at customers. In the above method, first, each distribution line meter transmits a uniquely identifiable signal having a phase via the distribution line, and then each of the customer configuration modules has a phase of each uniquely identifiable signal. It has a step to identify. Next, each of the customer configuration modules transmits the phase of each of the uniquely identifiable signals to the data collection device together with the customer configuration module identifier, and the phases recorded by the configuration modules are compared to compare the customer. Determine where each component module is connected to the distribution line meter on the supply line (indirectly via a distribution transformer).

According to another aspect of the present invention, there is provided a method of determining in which phase of a multiphase distribution wire the distribution transformer meter is connected. The method comprises a step of transmitting a distribution line meter signal modulated by the power frequency of the phase to which the distribution line meter is connected from the distribution line meter connected to the distribution line. Next, the distribution transformer meter receives the modulated distribution line meter signal, demodulates the signal, and reproduces the distribution line meter signal. To calculate which phase the distribution transformer meter itself is connected to, the difference between the phase angle of the demodulated distribution line meter signal and the phase angle of the voltage to which the distribution transformer meter is connected. Determined by.

According to another aspect of the present invention, there is provided a method of determining in which phase of a multi-phase distribution wire the customer meter is connected. The method comprises a step of transmitting a distribution line meter signal modulated by the power system frequency in the phase of the distribution line meter from the distribution line meter. Next, the customer meter receives the modulated distribution line meter signal, demodulates the modulated distribution line meter signal, and reproduces the distribution line meter signal. Next, the customer meter calculates the phase angle of the demodulated distribution line meter signal and the phase angle of the voltage to which the customer meter is connected to determine in which phase the customer meter itself is connected. Determined by.

According to another aspect of the present invention, there is provided a method of determining in which phase of a multi-phase distribution wire the customer meter is connected. The above method includes a step of causing a data acquisition device connected to each phase of the distribution line to record a first voltage profile for each phase for a certain period of time, and a step of causing a customer meter to record a second voltage profile for the same period of time. Which of the customer meters each customer meter is then by having the second voltage profile transmitted from the customer meter to the data acquisition device and then comparing the first voltage profile of each customer meter with the second voltage profile. It includes a step to determine if it is connected in phase.

In light of the above effects and other effects that will become apparent to those skilled in the art to which the present invention relates as the description of the specification progresses, the following description provides the accompanying drawings that form part of the specification. The present invention will be described with reference to this. This description includes a description of a preferred exemplary embodiment of the principles of the invention.

(A brief description of the drawing) FIG. 1 is a schematic diagram of an electrical network that implements the method of the invention.

FIG. 2 is a schematic diagram of an electrical network that implements the method of the invention, showing the relationship between an end user (EU) and a distribution transformer (DT).

In drawings, similar reference characters indicate corresponding parts of different figures.

(Best mode for carrying out the invention) The energy balance account as a method of detecting electricity theft is very effective at the distribution transformer level because the number of target customers is small. The error caused by the track loss is probably about 0.5% to 3%, and it can be considered that the number of customers does not exceed 10. In this case, the total amount of energy line loss is only a small amount compared to the amount consumed by one customer, and is small compared to any conceivable amount of theft.

The situation is different at the distribution line level as it targets a large number of customers. Here, the energy lost on railroad tracks is expected to be many times greater than the amount consumed by a single customer. Therefore, theft is more difficult to detect, and the sensitivity and reliability of the method is highly dependent on the accuracy of the energy balance accounting process.

The accuracy of the energy balance account process is improved by estimating the line loss and compensating for the line loss, but there is a problem in the serious idea that constrains the advantages of this solution. The problem is that the line loss is proportional to the square of the current level and therefore varies from load to load. Moreover, this problem has already occurred at a time when the non-constant loss due to the linear resistance that changes with temperature is not taken into consideration. Due to such problems, it is very difficult to know the loss with sufficient accuracy.

For example, if there is a distribution line that supplies 100A to a stable and constant load consisting of residential customers, the line loss will be 1%. However, during one measurement period, the load changes to 200A for half the time and zero for the remaining time. As a result, the line loss during the measurement period is doubled. Track loss is 2% instead of 1%. This change occurs between measurements and is therefore undetectable from the meter data.

For distribution lines connected to 1000 customers, a change in line loss from 1% to 2% reduces the flow of energy to the customers by 10 of the average customer's load.

There are multiple solutions to this problem. First, errors can be reduced by shortening the measurement interval. However, this method increases the amount of data that must be sent and processed, and does not solve all the problems. Second, it can be statistically averaged, but this method does not always work. Therefore, there remains a method of balancing sensitivity and false alarm prevention. That is, if the threshold is set too low, false alarms will increase, and if the threshold is set too high, actual theft will not be detected. Between these two levels is a range of thresholds that cause a large number of false alarms and thresholds that fail to detect actual theft.

Thus, the energy balance account as a theft detection method has an inherent error cause that is independent of the accuracy of the measuring instrument used. Even assuming no errors occur in distribution line meters, distribution transformer meters, and customer meters, this method still has major error sources that limit its sensitivity and thus its ability to detect electricity theft. ..

Another method that does not have this error cause is to use an Accumulated In-Phase Current (AIPC). AIPC is simply a non-voltage component of energy, which can be used to eliminate the voltage term from the equation. This method is largely unaffected by the effects of line loss, as line loss is characterized by voltage loss rather than current loss. This means that the level of accuracy will be raised as a whole. The higher the level of accuracy, the higher the sensitivity, and therefore the higher theft detection capability, and the theft detection capability is mainly constrained by the accuracy of the meter measurement. In this way, AIPC provides better theft detection means and methods than methods that utilize energy consumption (kWh).

The term "feeder meter" broadly refers to a meter that measures electricity at the level of distribution lines. The feeder current meter is a type of feeder meter and is designed for specific applications that measure supply current. Therefore, the supply current meter is ideally suitable for AIPC measurement, and unlike other feeder meters, it does not need to measure voltage.

In systems that include feeder current meters (FCMs), distribution transformer meters (DTMs), and customer meters (CMs), AIPC is independent of variable line losses. Therefore, we provide the best means of detecting theft. One difficulty with this idea is that commercials generally do not provide AIPC data, and, of course, AIPC cannot be compared to kWh. However, DTM can be used to program DTM to provide both AIPC and kWh. Then use kWh to coordinate between DTM and CM (small number of target customers), while using AIPC to coordinate between FCM and DTM (large number of target customers). Make adjustments.

In situations where there is only one customer for each transformer, such as in rural areas, it may seem undesirable to install a DTM. In this case, the customer meter may also have the ability to transmit both energy consumption readings and integrated common mode current readings. Energy consumption readings are used for billing, while AIPC readings are used with feeder current meter readings to detect theft with greater sensitivity and reliability than when using energy consumption data.

The most accurate, most sensitive to theft and least likely to cause false alarms is to add true AIPC capabilities to commercials. The problem with this approach is that it requires a great deal of development from meter manufacturers to achieve this capability. However, by using the existing capacity of the meter, a function close to the above capacity can be realized. The CM transmits the integrated kWh number for each hour, and also transmits the maximum voltage and the minimum voltage. From this data, the maximum and minimum values that AIPC can take are calculated as follows.

Maximum AIPC value = kWh / minimum voltage value Minimum AIPC value = kWh / maximum voltage value In order to compare the AIPC at the supply level with the AIPC at the secondary level of the transformer, it is necessary to take into account the transformer ratio (the value obtained by dividing the primary voltage by the secondary voltage). This can be easily done by converting the AIPC to normalized active energy (NAE) by multiplying the AIPC value by the nominal voltage value. That is, it becomes as follows.

NAE = Normalized Active Energy = AIPC x Nominal Voltage If the balance obtained by subtracting the error margin from the NAE value of the feeder current meter is larger than the sum of the NAE readings in each CM, the theft alarm device is activated. The hourly sensitivity of this technique is expressed as follows using the minimum theft load required for detection.

Detectable minimum theft load = voltage x (maximum AIPC value-minimum AIPC value) + error margin This method is most sensitive when the voltage is constant, but false alarms are minimized even when the voltage changes. Since the targeted theft load is effectively the base load, the theft load should be easily detectable during the sensitive period. Furthermore, the sensitivity can be significantly increased by simply dividing the one hour into a further five minute measurement period in any one hour measurement period. Sensitivity is limited by the magnitude of the voltage change that occurs during that 5 minute, but since this voltage change is usually considered small, it is generally possible to maintain high sensitivity with this technique at all times.

The sensitivity of any theft detection system decreases as the number of customers increases, so using multiple FCMs for a single distribution line allows each FCM (Feeder Current Meter) to cover a different subset of customers on that distribution line. It is advantageous. This configuration works only when the tip of the distribution line is branched into different sections. In this case, a separate feeder meter can be installed on each branch line. Even if this configuration is possible, there is still a problem, the wire from the substation to the first branch line (or customer) needs to be protected, and even on this wire the number of customers is further divided. You can't. This section of wire can be protected by two FCMs (one in the substation, one in front of the first customer) that measure the RMS (root mean squared) current. RMS current can be measured more accurately than kWh and even more accurately than AIPC, as there is only one input during the measurement process. Accuracy can be further improved by calibrating two identical FCMs together, which provides the best possible protection against theft in this section of the wire.

A standard feeder current meter does not have a connection terminal to which a high voltage is applied, but voltage information is needed to calculate kWh. Shielded resistor dividers or potential transformers may be used as standard methods, but both methods have their own advantages and disadvantages. Although each method can provide excellent accuracy, it is costly and inconvenient if accuracy is required. An alternative method is to measure the voltage on the secondary side of an existing distribution transformer and multiply it by the turns ratio.

This method can be performed on a device mounted on a distribution transformer near the location of the feeder current meter (FCM). The device measures voltage and current and combines them to generate voltage data for the primary side. This data is continuously transmitted to the FCM in real time using short-range radio, which the FCM uses to provide kWh data.

There are two main causes of error in this technique. The first is the accuracy of the turns ratio, and the second is the voltage output drop that occurs when the transformer is loaded.

If the transformer complies with the CSA standard, the turn ratio (rated high voltage / rated low voltage on the nameplate) is within ± 0.5%. Also, the transformer impedance (usually 1% to 3%) on the nameplate is within ± 5%. Therefore, the load current can be measured and this data can be used to compensate for the transformer voltage drop. Assuming a 0.15% instrument error for both voltage and current measurements, the overall worst case high voltage measurement error for a transformer with an impedance of 3% is

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Will be.

This level of accuracy is only suitable when the number of targeted customers is small, which is true for any theft detection system based on kWh. Ironically, this kWh theft detection system is based on AIPC (Integrated Common Phase Current) theft due to the extra cost and other disadvantages associated with providing a feeder current meter with kWh capability. A theft detection system that is mathematically superior to the detection system cannot be realized. Using AIPC instead improves theft detection and false alarm reduction capabilities, and the feeder current meter eliminates the need for expensive voltage measuring equipment.

There are other advantages as well. Since the feeder current meter does not need to measure the voltage, the meter can be significantly reduced in size and weight, and the safety is improved. Since the feeder current meter does not need to be connected to which a high voltage is applied, a high voltage fuse is not required, and therefore the size and weight of the feeder current meter can be reduced. The light weight means that it can be attached directly to the distribution line without using other weight supporting means. By doing so, the meter can be installed quickly, and the installation location can be flexibly selected. Finally, the meter is structurally safe. In other words, unlike connected devices where high voltage is applied, this meter completely eliminates the risk of arc discharge around the fuse enclosure inside the device and therefore explodes during installation. The risk of doing so has been removed.

AIPC (Integrated common mode current) AIPC is simply the non-voltage component of energy.

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Here, I = active current = non-reactive current = in-phase current, energy is measured in kWh (kilowatt hour), and AIPC is measured in Ah (amp-hour).

If you have a 7.2kV distribution line (between phase and ground) that supplies 100A to a stable, constant load, and the supply line from the substation to the customer has 0.72Ω, the voltage drop that occurs across this distribution line. Is 72V. If the voltage at the substation is 7200V, the voltage at the customer is 7200-72 = 7128V. The amount of energy recorded in one hour at the substation is 7.2 x 100 = 720kWh. At load, the measured amount of energy is 7.128 x 100 = 712.8kWh. In this case, ((720-712.8) / 720) x 100% = 1% of energy is lost due to line loss.

During the next hour interval, the substation will supply 200A for the first 30 minutes and no current for the rest of the time. 200 x 7.2 x 30/60 = 720kWh is recorded on the substation for the first 30 minutes, so 720kWh is recorded on the substation for the entire hour. However, for loads, the voltage drop is proportional to the current, and the customer voltage is 7200- (200 x 0.72) = 7056V for the first 30 minutes and 7200V for the next 30 minutes, so the voltage drop is doubled. At this time, the amount of energy measured by the customer is 7056 × 200 × 30/60 = 705.6kWh for the first 30 minutes, and therefore the same applies to the entire 1 hour. In this case, ((720-705.6) / 720) x 100% = 2% of energy is lost due to line loss.

In both cases, the substation records the same amount of energy (720kWh), so this measurement cannot be used to predict the amount of energy lost on the wire. It cannot be used for the same reason when bolted by the customer. On the customer side, 7128 volts is recorded in the above hour in both cases, but in the second case, kWh is 7.2 less. In this way, even if you try to estimate AIPC by dividing the watt hour for one hour by the bolt hour for the same hour, the same mathematical error that the load-induced line loss variation causes will occur.

With true AIPC, 100 Ah is recorded on both the substation and the customer side (unless stolen) in both cases. If AIPC cannot be used, the next best solution is to use the maximum and minimum voltages to calculate the minimum and maximum AIPC values.

The system of the present invention is schematically shown in FIG. 1 as a configuration 10. The system 10 is composed of a plurality of distribution transformers 20 connected to a distribution transformer meter 22 capable of measuring and recording AIPC. The co-pending distribution transformer meters disclosed in US Application No. 60 / 949,606 are suitable for use in the present invention. The distribution transformer 20 is connected to a load 18 (for example, a plurality of residential power consumers) and a high voltage distribution line 12 respectively. The high voltage distribution line 12 is connected to the substation transformer 17 in the substation 14. The distribution transformer 34 is also connected to the distribution line 12, and the data collection device 16 is connected to the distribution transformer 34. Each distribution transformer meter 22 records the AIPC consumed at any time with the corresponding load 18 and sends this information to the data collector 16. The substation transformer 17 is connected to the feeder current meter 24. Like the distribution transformer meter 22, the feeder current meter 24 is configured to calculate and record AIPC for an arbitrary period. The feeder current meter 24 is further configured to transmit AIPC measurements to the data acquisition device 16, preferably using a power line communication signal. The distribution transformer meter 22 is also configured to transmit AIPC measurements to the data acquisition device 16, preferably via power line communication. The data collection device 16 then sends these AIPC measurements to the central computer 32. The central computer 32 does not have to be located near the data collection device 16 and may be connected to another data collection device. Each distribution transformer meter 22 sends a unique identifier code along with AIPC measurements. In this way, the central computer 32 can compare the above AIPC measurements received by each distribution transformer meter 22, and also compare these AIPC measurements with the AIPC measurements for the same period obtained from the feeder current meter 24. be able to.

This comparison is made by first converting AIPC to normalized active energy (ie NAE). NAE is simply AIPC multiplied by a nominal voltage. For the distribution transformer meter 22, the nominal voltage is typically 240V. In the case of a feeder current meter, for example, if the transformer ratio is 30, the nominal voltage is 7200V. The sum of the NAEs obtained from the plurality of distribution transformer meters 22 should be equal to the NAEs obtained from the measurements recorded by the feeder current meter 24 over the same period within an appropriate measurement error margin. If there is a large difference between the sum of the two NAEs, this may mean that there is an unknown load attached to the distribution line. In this case, the power company operating the central computer 32 may check the extra load.

This current balance accounting system is unaffected by line loss and is therefore more accurate than metering energy. In addition, a device that measures only AIPC with the feeder current meter 24 does not require high-voltage operation. For this reason, AIPC meter measurements on distribution line 12 are much safer and less expensive than energy meter measurements.

Connection status information The system of the present invention can be used to detect two different types of electric theft. The first type of theft is stealing electricity from a distribution transformer owned by a power company. The second type of theft steals electricity directly from the distribution line and occurs by connecting the distribution transformer directly to the high voltage distribution line without permission. The distribution transformer meter works with an electric meter installed at the end user to detect the first type of theft. The electricity consumption of the distribution transformer should be approximately equal to the total electricity consumption of the end user. However, in order to make this comparison, the utility must know which end user is connected to which distribution transformer. Connection status information is needed to detect the second type of theft. This information can be collected by creating a map. Creating this map produces a two-dimensional image or diagram that symbolizes the distribution lines, distribution transformers, end users, and the interconnections between them (even if printed on paper, electronically displayed on a computer monitor). May be). Creating these maps requires a great deal of work not only at the time of initial creation, but also to keep them up to date with each change to the power system. Even if these maps are created and maintained, further work is required to interpret the maps in order to generate equations used to check whether unauthorized electricity use has occurred.

It is not necessary to create and interpret a map in the system of the present invention. Instead, it automatically generates a connection status matrix, which customer meter (CM) is connected to which distribution transformer meter (DTM), and each distribution transformer is distributed relative to the feeder meter (FM). Indicates where it is located on the wire. The basic method is as follows. That is, the power line carrier signal is sent to the grid at various points, and this signal is received by a device at another point. This received signal is processed to provide the connection status information required for matrix formation. The software then uses this matrix to automatically generate the equations it uses to check for unauthorized electricity usage.

Connection status information requirements are divided into three categories: 1. DTM to customer meter, 2. FCM to DTM, and 3. FCM to CCM (Customer Configuration Module). In the following, we will explain how to define all three parts of the connection status matrix using the method of the present invention. 1. From DTM to customer meter You need to know which customer meter is connected to which distribution transformer. One approach is power line communication, in which the data collector sends command signals to all DTMs in the phase of the distribution line. The distribution transformer meter unique identifier (for example, DTM number) is transmitted to the customer meter at the same time by PLC). In response, the DTM sends the serial number at the same time on the PLC. The customer meter receives this serial number from the corresponding DTM (that is, the DTM connected to the distribution transformer that powers the customer meter) and puts the received serial number in a different location along with the customer meter's unique identifier. Send to a corresponding data collector. This connection status information is preferably stored in a database linked to a data collection device at another location.

PLC signals transmitted on the secondary side of one transformer are received at low levels on the secondary side of another transformer, but in practice the signal strength of these signals is low enough to be the desired signal (ie). , The signal transmitted and received on the same secondary side), and only the correct serial number should be received. A signal strength measurement of the received signal is still needed to know if the DTM transmitter has failed to transmit. 2. From FCM to DTM You need to know which section of the distribution line the distribution transformer is connected to. The interface of the distribution section section corresponds to the point on the distribution line where the FCM is installed. This can be achieved by dividing an hour into a series of time windows. Each FCM sends a uniquely identifiable signal in its own specified time window. In fact, no two FCMs on a single distribution line transmit at the same frequency within the same time window, so a particular time window makes up part of the uniquely identifiable part of the signal from the FCM. ing. FCM does not transmit at the same frequency in the same time window, but in a certain order. The signal traveling upstream from each FCM is a positive signal (phase + ve), and the signal traveling downstream from each FCM is a negative signal (phase -ve). DTM's PLC receiver can not only detect the presence of a signal, but also tell from the time window which FCM transmitted the signal and the phase of the signal (ie whether the signal has a positive phase or a negative phase). You can also decide. This data is transmitted by each DTM to a data collection device at a different location together with the unique DTM identifier of each DTM (for example, the serial number of the DTM). From this data it is possible to determine which section of the distribution line each DTM is connected to. For example, suppose the DTM receives the following FCM data: FM1- FM2- FM3 + FM4 + In this case, it can be seen that the DTM was connected to the section of the distribution line between FM2 and FM3.

In this determination method, each DTM is associated with multiple feeder meters, which is shown in Figure 1. The process begins with the data acquisition device 16 sending carrier replication instructions to all feeder meters on the distribution line via power line carrier communication. Following this instruction, a pure carrier wave is transmitted by the data collector for a period of time. Then, the feeder meter sequentially transmits duplicate carriers having substantially the same frequency and phase by using inductive coupling to the distribution line. As a result of inductive coupling used by the feeder meter power line carrier transmitter, the signal travels upstream from the feeder meter 180 degrees out of phase with the signal traveling downstream. By doing so, these signals can be classified as positive signals or negative signals. Record for each feeder whether all DTMs on the distribution line have received a positive signal or a negative signal. This information is relayed to the data collection device upon request. Therefore, the data collector not only receives AIPC (or energy, or both) measurements from all feeder meters and DTMs, but also receives all the information needed to make the above comparisons and detect theft. This eliminates the need for any mapping.

Next, as illustrated in FIG. 2, all DTMs connected to the distribution line between the feeder FM2 and the feeder FM3 receive a negative signal from the feeder FM2 and a positive signal from the feeder FM3. Receive the signal of. On the other side of the feeder meter FM3, any DTM receives a negative signal from both of the feeder meters. Also, on the other side of the feeder meter FM2, any DTM receives a positive signal from both of the feeder meters. Therefore, the sum of the NAE (or energy) measurements of all DTMs that receive a negative signal from the feeder FM2 and a positive signal from the feeder FM3 is from the NAE (or energy) measurements of the feeder FM2. It should be substantially equal to the NAE (or energy) reading of the feeder meter FM3 minus.

Potential problems can occur if there is a three-phase capacitor bank that transfers the above signal from one distribution line phase to the other two distribution line phases. In this case, it is necessary to be able to determine not only which phase each FCM is set to, but also which phase each DTM is set to. But without a capacitor bank, this is easy to determine. This is because the signal transmitted in one distribution line phase is not received in the other two distribution line phases.

Any component that couples a signal from one distribution line phase with two other phases, such as a capacitor bank, complicates this task. One solution to this problem is to have the FCM transmit a signal modulated by a 60Hz power signal on the distribution line phase. In this case, the DTM receiver demodulates this signal and reproduces the original 60 Hz signal, measuring the phase angle between this signal and the voltage to which it is connected. If the phase angle difference is close to 0 ° or 180 °, it is known that this signal comes from an FCM on the same distribution line phase. If the phase angle difference is close to 120 ° or 60 °, it is known that the signal is derived from one of the other two distribution line phases. Further, by determining whether the phase difference of 120 ° or 60 ° is advancing or lagging, it is determined in which of the other two distribution line phases the FCM is arranged. 3. From FCM to customer configuration module In sparsely populated rural areas, each distribution transformer typically has only one customer. For cost reasons, installing DTMs on these transformers should be avoided. Therefore, another device, the Customer Configuration Module (CCM), needs to perform the functions described in Section 2 above. This unit is similar to a DTM installed in a distribution transformer, except that it does not sense or measure current. Alternatively, it may be a module that can be plugged into an outlet somewhere in the customer's house.

Signal processing requirements 1. Accurate time base (low drift) In order for the CCM to detect and process the signal from the FCM and for the meter to detect and process the signal from the DTM, a demodulation algorithm with an accurate time base is needed. An example of a suitable time-based algorithm is described in US Pat. No. 6,549,120. 2. Signal and phase detection It is necessary to determine in which phase of the distribution line the DTM or CCM is connected. This is done by placing the feeder meter signal on a carrier wave and sending it from the distribution line to the DTM or CCM. This reference signal is transmitted for a period of time, which may require up to 10 minutes to give the DTM or CCM a chance to find the phase angle of the carrier. The feeder meter signal needs to be modulated by the power system frequency in the phase in which the signal is transmitted. The DTM or CCM receives this modulated feeder meter signal and demodulates it. Demodulation can be done by DTM or CCM, producing a demodulation frequency with a small frequency offset from the normal carrier frequency. At this time, the demodulated output becomes a slow sine wave, and the zero intersection can be determined. One way is to wait for such a zero intersection and then remove the frequency offset. Then, a 90 ° phase offset can be added to the demodulated signal to align the demodulated signal with the received signal. Additional phase offsets may need to be added to compensate for the delays that occur when filtering the demodulated signal. Once this phase alignment is complete, the time-based accuracy is so high that the demodulated signal does not drift throughout the duration of the configuration detection process.

When the reference frequency transmission is complete, the received signal is demodulated to determine the configuration. Single-phase distribution line In order to detect the phase connection status, it is necessary for the DTM or CCM to be able to distinguish between positive and negative signals (phase angle 0 ° or 180 °), and reject signals from other distribution lines. It is also necessary to be able to distinguish signals of other phase angles in order to do so. 3. Time window detection It is necessary for the DTM or CCM to be able to determine the time window in which the signal is received. To achieve this, the DTM or CCM is required to have a clock with an error of less than half the time window length. This requirement for errors is a minimum requirement, ideally less than one-sixteenth of the time window length for good performance. In some cases, clock resynchronization may be required to avoid requiring long windows and resulting in a very slow configuration detection process. 4. Data decryption In order to communicate from the DTM to the meter, it is necessary for the customer meter to be able to decode the data in the form of a serial number. 5. Signal level In order for a DTM on the same distribution transformer as a customer meter to be able to reject signals from DTMs in other distribution transformers when transmission fails, the customer meter needs to be able to determine the signal strength. 6. Rejection of three-phase crosstalk A three-phase circuit in which signals are coupled requires a method of rejecting signals from either of the other two phases. To do this, a data collector or other device decodes the above 60Hz frequency modulation for the FCM transmit signal and the phase of the demodulated signal is 60Hz power connected to the customer meter (or distribution transformer meter). It is required to be able to determine whether it matches the phase of the signal. In order to pick up the signal from the background noise, it is necessary to proceed with demodulation filtering slowly, so it may be necessary to demodulate the above 60Hz waveform piece by piece. The possible resolutions when performing this demodulation are limited by the sampling frequency.

The rejection of crosstalk does not necessarily have to occur at the same time as other constituent processes, and may be an independent function. However, the system must know either which phase the customer meter is connected to or which customer meter is combined with which FCM. Since all FCMs, including FCMs of other phases, have different time windows, there should be no interference between FCMs of different phases.

Another way to determine which of the three phases the meter is connected to is to use voltage profiling. The voltage is affected when the load on the distribution line increases or decreases during the day. This voltage can be profiled with a customer meter. Since the three phases of the distribution line do not see exactly the same load, each phase has a unique voltage signature, which can be recorded on a customer meter or CCM and sent to the central computer. The central computer then compares the signature recorded on the customer meter or CCM with the three-phase voltage signature to determine which is the best match. The central computer also determines how well the match is. If the meters do not match well enough to be confident about which distribution line phase they are connected to, the central computer will repeat the above process until the required level of certainty is achieved. Continue using.

Multiple feeder meters (FM1, FM2, FM3, FM4), distribution transformers (DT), and end users (EU) are illustrated in Figure 2. Just as it is necessary to know which end user is connected to which distribution transformer, it is necessary to know how which distribution transformer is associated with which feeder meter. In the case of connection status detection, the status is more complex at the distribution line level. The simplest feeder topology is one in which one feeder monitors all distribution lines and compares their NAE (or energy) values with the NAE (or energy) values of all distribution transformers. However, as a result of limited accuracy, the total measurement error may be greater than the theft amount, in which case the theft will not be detected. Therefore, it is necessary to install two or more feeder meters along the distribution line and its branch lines. In this case, the distribution transformer is not associated with any feeder meter, but instead is associated with a part of the distribution line sandwiched between the two feeder meters. The difference between the NAE (or energy) readings of the two feeder meters is the DTM NAE (DTM NAE) of all distribution transformers owned by the utility, located on part of the distribution line between the two feeder meters. Or energy) approximately equal to the sum of the measurements.

Although specific embodiments of the present invention have been disclosed, it is assumed that modifications of the disclosed embodiments are also within the scope of the rights of the present invention. The present invention is not limited to the above-described embodiment, and various modifications can be made within the scope of the claims.

<figref num="1">FIG. 1 is a schematic diagram of an electrical network that implements the method of the invention.</figref><figref num="2">FIG. 2 is a schematic diagram of an electrical network that implements the method of the invention, showing the relationship between an end user (EU) and a distribution transformer (DT).</figref>