US20070194949A1 - Systems and methods for electricity metering - Google Patents

Systems and methods for electricity metering Download PDF

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Publication number
US20070194949A1
US20070194949A1 US11/604,043 US60404306A US2007194949A1 US 20070194949 A1 US20070194949 A1 US 20070194949A1 US 60404306 A US60404306 A US 60404306A US 2007194949 A1 US2007194949 A1 US 2007194949A1
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United States
Prior art keywords
data
meter
phase
meters
frequency
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US11/604,043
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English (en)
Inventor
Sayre Swarztrauber
Siddharth Malik
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Quadlogic Controls Corp
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Quadlogic Controls Corp
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Priority to US11/604,043 priority Critical patent/US20070194949A1/en
Publication of US20070194949A1 publication Critical patent/US20070194949A1/en
Priority to US12/713,030 priority patent/US8026628B2/en
Assigned to QUADLOGIC CONTROLS CORPORATION reassignment QUADLOGIC CONTROLS CORPORATION ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: MALIK, SIDDHARTH, SWARZTRAUBER, SAYRE A.
Priority to US13/217,388 priority patent/US8417471B2/en
Abandoned legal-status Critical Current

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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D4/00—Tariff metering apparatus
    • G01D4/002—Remote reading of utility meters
    • G01D4/004—Remote reading of utility meters to a fixed location
    • H—ELECTRICITY
    • H04—ELECTRIC COMMUNICATION TECHNIQUE
    • H04B—TRANSMISSION
    • H04B3/00—Line transmission systems
    • H04B3/54—Systems for transmission via power distribution lines
    • H04B3/546—Combination of signalling, telemetering, protection
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01D—MEASURING NOT SPECIALLY ADAPTED FOR A SPECIFIC VARIABLE; ARRANGEMENTS FOR MEASURING TWO OR MORE VARIABLES NOT COVERED IN A SINGLE OTHER SUBCLASS; TARIFF METERING APPARATUS; MEASURING OR TESTING NOT OTHERWISE PROVIDED FOR
    • G01D2204/00—Indexing scheme relating to details of tariff-metering apparatus
    • G01D2204/40—Networks; Topology
    • G01D2204/45—Utility meters networked together within a single building
    • H—ELECTRICITY
    • H04—ELECTRIC COMMUNICATION TECHNIQUE
    • H04B—TRANSMISSION
    • H04B2203/00—Indexing scheme relating to line transmission systems
    • H04B2203/54—Aspects of powerline communications not already covered by H04B3/54 and its subgroups
    • H04B2203/5429—Applications for powerline communications
    • H04B2203/5433—Remote metering
    • H—ELECTRICITY
    • H04—ELECTRIC COMMUNICATION TECHNIQUE
    • H04B—TRANSMISSION
    • H04B2203/00—Indexing scheme relating to line transmission systems
    • H04B2203/54—Aspects of powerline communications not already covered by H04B3/54 and its subgroups
    • H04B2203/5462—Systems for power line communications
    • H04B2203/5466—Systems for power line communications using three phases conductors
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02B—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO BUILDINGS, e.g. HOUSING, HOUSE APPLIANCES OR RELATED END-USER APPLICATIONS
    • Y02B90/00—Enabling technologies or technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y02B90/20—Smart grids as enabling technology in buildings sector
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
    • Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
    • Y04S20/00—Management or operation of end-user stationary applications or the last stages of power distribution; Controlling, monitoring or operating thereof
    • Y04S20/30—Smart metering, e.g. specially adapted for remote reading

Definitions

  • AMR automated meter reading
  • PLC power line carrier
  • PLC systems make it possible to analyze network disturbances using electrical connectivity. Using PLC systems, the supply of electricity can be much more directly verified, as compared to systems that depend on wireless coverage.
  • Various prior art PLC have used polling mechanisms to detect outages, while others have kept the meter and data collector continuously in communication.
  • polling mechanisms to detect outages
  • others have kept the meter and data collector continuously in communication.
  • prior art systems that report an outage event by a battery-backed up system that senses loss of power and activates a modem that relays the power loss information.
  • One disadvantage of such systems is that when many meters simultaneously lose power, the concurrent “last gasp” messages can create considerable collisions and noise.
  • SCADA-like systems use transceivers at substations and various infrastructure points (e.g., distribution transformers and substation feeders) to check the status of the power transmission network. These transceivers constantly monitor the operation of such instruments and relay information when a fault is encountered.
  • infrastructure points e.g., distribution transformers and substation feeders
  • AMR systems that require minimal manual intervention and are scalable as the number of installed meters increases, either due to mandatory procedures in place or due to high energy costs and the need to eliminate unmetered services.
  • utilities strive to reduce operating costs, a system that is economically scalable and overcomes some or all of the above-mentioned problems is highly desirable.
  • the scalability issue also implies that an automated system that the utility can install across the entire service territory (including multiple generating stations) or a subsection thereof (including multiple substations), which provides a single-point control which provides data and status of installed meters, is needed.
  • any technological progress that lowers the cost per metering point for a large system (e.g., more than 500 meters) by eliminating any additional equipment required at each transformer for PLC signaling is always welcomed by utilities.
  • the current invention in at least one embodiment, comprises a two-way communication system for reading interval metering data over medium tension distribution lines (4-33 kV), traversing distribution transformers to the metering devices on low tension lines (120-600 volts), without requiring any special equipment at the distribution transformers, while maintaining a reliable and cost effective AMR solution.
  • the transponder could remotely program the channel of each meter by utilizing a “base channel” that all meters could recognize, to direct each meter to its proper “resting” channel, isolated from the other channels by a sufficient frequency difference to allow simultaneous communications of each transponder to each meter.
  • each transponder requires at least two unique frequencies to avoid interference from other installed devices using RF communication over power lines.
  • the system maintains a cross reference list at the transponder, listing the meters for which the transponder is responsible.
  • cross coupling of PLC signals can result in degradation of the overall throughput.
  • SNR signal to noise ratio
  • FSK Frequency Shift Keying
  • PSK Phase Shift Keying
  • FFT Fast Fourier Transform
  • This may include, but is not limited to, a comprehensive meter-territory map that the system dynamically and automatically updates as changes occur in the meter territory.
  • the dynamic solution is uniquely determined by the ability of meters to decode PLC signals from multiple scan transponders (STs) simultaneously.
  • the invention provides an improvement over the prior-art technology to use FFT as the basis for simultaneous decoding of a plurality of transponder communications.
  • FFT Fast Fourier Transistor
  • a typical installation includes more than one ST located at each of remotely located substations feeding a section of utility service territory via medium tension lines terminating at distribution transformers from which low voltage lines emanate.
  • meters are generally installed at customer premises, utilities may install a meter at the output of every distribution transformer, hence increasing the meter population in the service territory.
  • More than one meter typically is located in the low voltage service territory and communicates with its ST.
  • All the STs in a system preferably are connected to a remote server that has a high speed data link in a LAN or WAN configuration and constantly communicates with all the STs.
  • the remote server may itself operate on a clock that is derived from the utility line frequency.
  • RTC circuits that use the 60 Hz line frequency as a reference (such as Intersil CDP68HC68T1, a multifunctional CMOS real time clock).
  • a network protocol such as Network Time Protocol
  • the current invention enables individual meters to receive, demodulate, and interpret simultaneous communications from all of the Transponders on all bands, communicating on different frequencies at once, eliminating the need for a “base channel” and for programming of a “resting channel.”
  • Each meter can listen to all of the STs and respond to the one that requests data from it.
  • each meter can communicate information regarding the signal strength of each Transponder that it can hear to the one transponder that is requesting data. This enables moving meters to the “best” transponder for each meter.
  • the present invention utilizes the installed PLC AMR infrastructure to provide an Event Management System (EMS) that provides a more extensive, practical, and efficient means for reporting events and tracking faults.
  • EMS Event Management System
  • the invention thus helps utilities and metering entities to: (1) reduce the number of dispatches made in error based on verification algorithms; (2) automate the integration of an AMR infrastructure to provide a dynamically updated network map; (3) integrate power quality information; (4) use algorithms and back-end processing to proactively verify status of several parts of network; (5) include load profile information for energy forecasting; (6) perform preventive maintenance; (7) indicate status change of network switches, feeder changers, and reclosers; and (8) report such changes to a utility's central control center.
  • EMS Event Management System
  • collecting network information about power quality may provide information on parts of a network territory with transients.
  • One embodiment provides a Dynamic Mapping Mode of PLC AMR system operation that selects meters (either randomly or based on strategically predetermined criteria) and initiates probing.
  • the invention comprises a system comprising: a master data clock source; one or more transponders; and a plurality of remote power line transceivers; wherein all of said plurality of transceivers are connected to a common alternating current power distribution grid; and wherein each of said plurality of transceivers has a location is operable to monitor a voltage waveform of a power line prevailing at said location.
  • the system is operable to generate a local data clock from said local power line waveform of a frequency of p/q times the frequency of said power line where p and q are positive integers greater than or equal to 1;
  • the master data clock source operable to transmit information regarding the phase and frequency its own local clock to said transponders; the local data clock of the master data clock source being called the master data clock;
  • said transponders and said remote transceivers each operable to inject and receive signals on the power line;
  • said transponder is operable to (a) reconstruct the master data clock from the phase and frequency information received from the master data clock source and its own local data clock; and (b) utilize the reconstructed master data clock to align data bits injected onto the power line;
  • said remote power line transceiver is operable to: (a) receive signals from at least one, but not necessarily all, of the transponders; and/or (b) measure the difference in phase of the local data clock and the master clock by monitoring the signals transmitted from any one or more the trans
  • the invention comprises a system comprising: one or more transponders and a plurality of remote power line transceivers each connected to a common alternating current power distribution grid each operable to monitor the voltage waveform of the power line prevailing at its own location, and generate selectable frequencies from said local power line waveform of a frequency of p/q times the frequency of said power line where p and q are positive integers greater than or equal to 1.
  • said transponders and said remote transceivers are each operable to inject and receive signals on the power line; (2) said signals each have a frequency of p/q times the line frequency where p and q are selectable from the set of whole integers; (3) said transponders and said remote transceivers alternate among different frequencies by changing the factor p or invert the phase of a fixed frequency so as to effect FSK or PSK modulation; (4) the frames of the data bits are uniform across the population of transponders and remote transceivers and correspond to the period and phase of the master data clock; (5) binary FSK modulation is used by selecting two values of p, p1 and p2 for the frequencies of the ones and zeros; (6) the receiver of either a transponder or a remote transceiver: (a) utilizes FFT or DFT algorithms calculated successively over the sequential data bit frames; and/or (b) demodulates the data bit at during each data frame by comparing the amplitudes of the signals corresponding to p1 and
  • the invention comprises an apparatus to implement a PLL comprising a input signal source, a VCO, a microprocessor, a DAC, an ADC wherein the VCO is used to drive the clock of the microprocessor; the microprocessor controls the sampling time of the ADC at times determined by its system clock; the ADC monitors the input signal source; the microprocessor reads the ADC; the microprocessor performs some filtering calculations on the signal from the ADC; the microprocessor controls the output of the DAC based upon the said calculations; and the DAC controls the input of the VCO so as to close a PLL around all of the aforementioned elements.
  • the input signal is a conditioned copy of the waveform of the A/C power line; and (2) the DAC is a pulse width modulator followed by a low pass filter.
  • a remotely located computer is operable to identify changes in operation or connectivity of electricity distribution network components.
  • said components comprise one or more of: meters, transformers, transponders, switches, and feeders;
  • said remotely located computer is operable to distinguish meter changes from transformer changes;
  • said changes comprise outages;
  • said remotely located computer is operable to calculate current output at each of a plurality of transformers;
  • said remotely located computer is operable to calculate current output at each of said plurality of transformers based on a vector sum of signals on each phase.
  • FIG. 2 is a block diagram of a preferred automatic tuning module.
  • FIG. 3 depicts a preferred substation installation, indicating equipment on each phase of the feeder in a substation.
  • FIG. 4 depicts preferred FIR specifications for 10-25 kHz.
  • FIG. 5 depicts preferred FIR specifications for 25-50 kHz.
  • FIG. 6 depicts preferred FIR specifications for 70-90 kHz.
  • FIG. 7 illustrates line noise spectra for 10-100 kHz.
  • FIG. 8 illustrates injecting PLC signals at half-odd harmonics of 60 Hz.
  • FIG. 9 depicts the 12 possibilities in which an FFT frame received by the meter can be out of phase with an ST FFT frame. Dotted lines correspond to a 30 degree rotation to account for a delta transformer in the signal path between the ST and the meter.
  • FIG. 11 illustrates SNR degradation effects of FSK decoding by meter when the data frames are aligned and not aligned.
  • FIG. 12 depicts distribution of SNR as meter M 1 tries to align its data frames to incoming ST's data frames.
  • FIG. 13 ( a ) depicts zeros of a Sinc function
  • 13 ( b ) depicts overlapping zeros of multiple Sinc functions when meter data frames are aligned with ST data frames.
  • FIG. 14 is a block diagram of a preferred analog front-end for metering.
  • FIG. 15 depicts preferred FIR specs for decimating metering data.
  • FIG. 16 depicts FFT frames for voltage indicating the harmonics
  • FIG. 17 depicts an exemplary directory structure of a system map.
  • FIG. 18 is a flowchart of an example of logical analysis on received PLC data.
  • FIG. 19 is a block diagram of a preferred D meter (this is one of at least two versions of a D meter).
  • FIG. 20 depicts schematics for a preferred board for implementing the FFT embodiments.
  • FIG. 21 has preferred schematics for a power board.
  • FIG. 22 has preferred schematics for an I/O extension board.
  • FIG. 23 has preferred schematics for a CPU board (PCB 202 ).
  • FIG. 24 has preferred schematics for metering, power supply, and PLC transmit and receive circuitry for a residential meter (PCB 240 ).
  • FIG. 25 has preferred schematics for a display board (PCB 220 ).
  • FIG. 26 illustrates a microprocessor being part of a phase locked loop.
  • FIG. 20 TABLE 1 Key to FIG. 20 Hierarchical interconnections SDRAM memory MCF5271 CPU Debug Ethernet interface Maxim chip Flash memory Power supply unit Reset configuration and clocking circuitry Serial I/O interfaces Meter-V PLC
  • the transponders use frequencies which are multiples of 60 Hz in the range of 15-35 kHz.
  • the Transponders preferably use two adjacent frequencies, for PSK, they preferably use just one frequency.
  • the STs must have accurate system clocks from which they generate the carrier frequencies—especially in the case of PSK. By sharing one common clock with 1 ppm accuracy using a device such as the Maxim DS4000 TCXO, these conditions are easily met.
  • a bank of transponders derives a data clock by synchronizing to a particular phase (e.g., the “A” phase of a trunk line with phases A, B, and C). All STs (even the ones in different banks) can utilize the same data clock to separate the bits of the FSK or PSK transmission.
  • a particular phase e.g., the “A” phase of a trunk line with phases A, B, and C. All STs (even the ones in different banks) can utilize the same data clock to separate the bits of the FSK or PSK transmission.
  • the Meters receive the data, pass it through an anti-aliasing filter and sample it:
  • One exemplary method of hunting for valid preambles comprises dividing the 60 Hz line into 8 phases and trying each of the 8 phases until the correct phase is found. In one embodiment of the present invention, this method is only employed once by the meter until it determines the correct phase of the 60 Hz line, because once connected the meter will never change phase.
  • the present invention in at least one embodiment, divides the line frequency into more than 12 parts, to allow for a minimum of 30 degree resolution in the line frequency. This allows for the possible phase shifts that may occur in distribution transformers.
  • the prior art suffers from a disadvantage of not being able to pass high frequency signals (starting in the kHz range) through existing distribution transformers without using any additional equipment at the transformer.
  • the transformer is bypassed using expensive additional equipment, thereby increasing overall system cost.
  • One embodiment comprises an arrangement for making the PLC signal go through the Distribution Transformers (DTs). It is well-established that the magnetic field in the DTs and noise on the line present far from ideal conditions for the PLC signal to propagate to the meters. Solving this problem preferably involves, in one embodiment, a two step process:
  • the coupler introduces a small inductance in the MT line, which then is tuned for a given carrier frequency by a bank of capacitors, thus providing a high SNR for communication.
  • the signal tuning preferably utilizes a tank circuit that automatically maximizes the impedance match of PLC signals on the line by mounting a coupler at the point where the trunk begins. No additional installation is required near the transformer. This has the effect of maximizing the signal on the line as the low impedance of the trunk line provides a return path for the current.
  • the coupler which preferably comprises a ferrite core with calculated wire turns wound on it, provides a fixed inductance for the PLC signal.
  • the capacitance for the tank circuit is provided by a Capacitor Relay bank (CRB).
  • An Automatic Tuning Module (ATM) comprises circuitry to control the capacitors and relays in the CRB.
  • FIG. 2 A simplified diagram of the ATM is given in FIG. 2 , where CV is Communication Voltage and CN is Communication Neutral.
  • a typical operation involves the following steps: choose capacitance value, send signal to relay, wait for relay operation, wait for relay settling, calculate the ratio, compare with other ratios and send signal to disconnect relay and wait for relay operation to settle, store the result in memory, and repeat the process with other capacitance values.
  • ATU Automatic Tuning Unit
  • Relays M, 1, and 2 are closed, whereas Relay R is open.
  • the 50 Ohm resistor is selected in the series path of transponder and coupler. This is done to avoid damage to the ST transmitter so that if for some reason the impedance of the coupler is infinitely small, the signal still sees a load of at least 50 Ohm to perform the tuning.
  • Relay M selects the coupler and the tuning process is initiated. Preferred steps comprise:
  • the PLC signal injected on a particular phase of a feeder in a substation can couple with other phases of either the same or different feeders of other substations. It becomes important to ensure the appropriate return PLC signal path.
  • a Bypass Capacitor preferably is installed on each phase across the neutral on the main medium tension bus in the substation as shown in FIG. 3 . This installation not only ensures that the return path of the PLC signal is the same feeder, but also that the majority of injected PLC signal flows towards the load.
  • a unique feature of these embodiments is that the transponders use communication frequencies in the kHz range that are rational multiples of the line frequency (that is, of the form (p/q) ⁇ f line , where p and q are positive integers).
  • the PLC signal is sampled at about 240 kHz (2 12 *60).
  • the appropriate Finite Impulse Response (FIR) filter is applied to decimate the data.
  • the FIR specifications are given in FIGS. 4 and 5 .
  • Embodiments of the current invention use this frequency range to enable communication between multiple scan transponders on medium tension lines for long distances.
  • the FIR specifications are given in FIG. 6 .
  • the decimation is done to either 120 kHz (2 11 *60) or 60 kHz (2 11 *30), in the case of communicating through transformers.
  • a 2048 point FFT is then performed on the decimated data.
  • the data rate is thus determined to be either 60 baud or 30 baud depending on the choice of FIR filters. Every FFT yields two bits approximately every 66 msec when traversing through distribution transformers.
  • transponders and meters This unique ability of both transponders and meters to perform FFT allows the meters to receive, demodulate, and interpret simultaneous communications from all of the transponders on all of the bands at once, eliminating the need for base and resting channels. Each meter can thus listen to all of the transponders and respond to the one that requests data from it. In addition, each meter can communicate information regarding the signal strength of each transponder that it can hear to the one to which it responds for data requests.
  • Embodiments of this invention overcome the historical challenge of performing PLC communication in a high line-noise environment.
  • FIG. 7 Shown in FIG. 7 is a snapshot of averaged low voltage noise spectrum in 60 Hz power lines from 0-100 kHz. Whereas the noise levels are sufficiently low at the higher end of the frequency range, at 10-25 kHz the noise rises faster than the signal. At least one embodiment of the invention comprises a method to solve this problem by injecting PLC signals at half odd harmonics of line frequency. This is shown in FIG. 8 .
  • the data bits reside in the bin corresponding to the 201.5 th and 202.5 th harmonic of 60 Hz as shown in FIG. 8 .
  • the preferred algorithm considers these two bins of frequencies and compares the amplitude of the signal in the two to determine 1 or 0.
  • This FSK scheme uses two frequencies and yields a data rate of 30 baud. It will be apparent to the skilled in the art that other schemes such as QFSK can be implemented to yield 60 baud.
  • the transponders communicate by allocating time windows for each meter.
  • the time window is one line-cycle wide.
  • the time slot can be two line-cycles wide, as shown in FIG. 10 .
  • each meter performs a shift in its internal clock to align its data frames with the incoming data frames from the transponders. This preferably is achieved by:
  • both STs and meters When traversing through transformers, both STs and meters perform FFT on the PLC and data signals every 30 Hz in the 10-25 kHz range. Because the PLLs implemented in both the ST and the meter are locked to the line, the data frames are synchronized to the 60 Hz line as well. However the data frames can shift in phase due to:
  • the SNR ratio is maximized when the meter data frame and ST data frames are most closely aligned. From a meter's standpoint, this requires receiving PLC signals from all possible STs that it can “hear,” decoding the signal, checking the SNR ratio by aligning data frames and then responding to the ST yielding maximum SNR.
  • FIG. 9 shows the 12 possible ways in which the data frames can be off in phase. In addition, because the data frames are available every 30 Hz on a 60 Hz line, there are two possibilities corresponding to the 2 possible phases obtained by dividing 60 Hz by 2. Hence there are 24 ways that meter data frames can be misaligned with ST data frames.
  • a remote server may assign the global clock (which maybe derived from the line frequency) to all STs; (2) meters receive data simultaneously from multiple STs; (3) meters determine the shift in their data clocks to align data frames with multiple STs; and (4) meters lock to the ST that results in highest SNR.
  • the global clock which maybe derived from the line frequency
  • FFT preferably is performed every 30 Hz or 2 cycles of line frequency of 60 Hz in the 10-25 kHz frequency band.
  • the preferred modulation scheme being Frequency Shift Keying (FSK)
  • FSK Frequency Shift Keying
  • ST1 and ST2 two STs (ST1 and ST2) that transmit bits are intercepted by a meter (M1) for the case when data frames are aligned (Case I) and when they are misaligned by different degrees (Cases II and III). Both STs use different frequencies to communicate.
  • FSK is used to decode the signal for bits.
  • M 1 decodes signals with misaligned data frames; hence, there is energy that spills over in the adjacent (half-odd separated) frequencies. If the signal level that falls in the “adjacent” frequency bin is less than the noise floor, the signal can be decoded correctly. However, if the spill-over is more than the noise floor (as with Case III), the ability to distinguish between 1 and 0 decreases, and hence the overall SNR drops, resulting in an error in decoding.
  • the SNR distribution is expected to look like a modified normal distribution, with one of the STs with which the meter data frames are aligned resulting in the max SNR.
  • the meter then locks to this ST for further communication ( FIG. 12 ).
  • the meter locks until a significant change in SNR ratio is encountered by the meter, in which case the process repeats.
  • the above technique provides a substantial improvement over the existing art of performing PLC through distribution transformers without bypassing these transformers while maintaining robust and reliable communication resulting in high throughput.
  • Each metering and communication channel preferably comprises front-end analog circuitry followed by the signal processing.
  • the current embodiment uses an anti-aliasing filter with fixed gain which provides first-order temperature tracking, hence eliminating the need to recalibrate meters when temperature drifts are encountered.
  • the analog front-end for voltage (current) channels preferably comprises voltage (current) sensing elements and a programmable attenuator followed by an anti-aliasing filter.
  • the attenuator reduces the incoming signal level so that no clipping occurs after the anti-aliasing filter.
  • the constant gain anti-aliasing filter restores the signal to full value at the input of the ADC.
  • the anti-aliasing filter cuts off frequencies above 5 kHz. The inputs are then fed into the ADC, which is part of the DSP.
  • This unique implementation that includes pairing the anti-aliasing filters ensures that the phase drifts encountered in both voltage and current channels are exactly identical and hence accuracy of the power calculation (given by the product of V and I) is not compromised.
  • At least one embodiment preferably uses a Phase Lock Loop (PLL) to lock the sampling of the signal streams to a multiple of the incoming AC line frequency.
  • PLL Phase Lock Loop
  • the sampling is at a rate asynchronous to the power line.
  • VCO Voltage Controlled Oscillator
  • DSP Digital Signal Processing
  • PWMs Pulse Width Modulators
  • FIG. 19 is a block diagram of this preferred DSP implementation.
  • a DSP BIOS or voluntary context switching code provides three stacks, each for background, PLC communications and serial communications.
  • the small micro communicates with the DSP using an I 2 C driver.
  • the MSP430F2002 integrated circuit measures the power supplies, tamper port, temperature and battery voltage.
  • the tasks of the MSP430F2002 include:
  • vii. provide a 1-second reference to go into the DSP for a time reference to measure against the system clock from the VCO.
  • Each data stream has an associated circuit to effect analog amplification and anti-aliasing.
  • Each of the analog front end sections has a programmable attenuator that is controlled by the higher level code.
  • the data stream is sampled at 60 kHz (2 10 *60) and then a FIR filter is applied to decimate the data stream to ⁇ 15 kHz (2 8 *60).
  • the filter specifications are shown in FIG. 15 .
  • a 3-12 kHz rolloff on the decimating FIR is used with ⁇ 15 kHz sample rate.
  • the frequencies from 0-3 or 12-15 kHz are mapped into 0-3 kHz.
  • a real FFT is performed to yield 2 streams of data which can be further decomposed into 4 streams of data: Real and Imaginary Voltage and Real and Imaginary Current. This is achieved by adding and subtracting positive and negative mirror frequencies for the real and imaginary parts, respectively. Since the aliased signal in the 12-15 kHz range falls below 80 dB, the accuracy is achieved using the above discussed FIR filter.
  • a 256-point complex FFT can be performed on every phase of the decimated data stream. This yields 2 pairs of data streams—a real part, which is the voltage, and an imaginary part, which is the current. This approach requires a 256 complex FFT every 16.667 milliseconds.
  • V m,n denotes the m th harmonic of the n th cycle number.
  • V 11 and I 11 correspond to the fundamental of the first cycle and V 21 and I 21 to the first harmonic of the first cycle etc., as shown in FIG. 16 .
  • the imaginary part of voltage is the measure of lack of synchronization between the PLL and the line frequency.
  • the calculations are done in the time-domain.
  • the FFT capability offers the flexibility to calculate metering quantities using only the fundamental or including the harmonics.
  • This provides the flexibility to either include or exclude the harmonics when calculating metering quantities.
  • Embodiments of the current invention permit demodulation of messages from multiple scan transponders and meters simultaneously, thus providing a significant improvement in communications.
  • Branch B 1 can be fed from feeders emanating from any one of the three substations by the use of switches U 1 , U 2 , U 3 , and U 4 .
  • meters connected to B 2 can be fed either from substation 2 or substation 3 by using switches U 5 and U 6 .
  • Sub-branch that can be fed from any of the substations by using Sub Branch switches SB 1 and SB 2 .
  • the remote server to which the system of STs is connected maintains a directory (for example, Lightweight Directory Access Protocol or LDAP) which is essentially a hierarchical framework of objects with each object representing a shared entity.
  • a directory for example, Lightweight Directory Access Protocol or LDAP
  • LDAP Lightweight Directory Access Protocol
  • the algorithm constantly updates this map as changes are made in the territory. This involves communicating with the meters and automatically mapping the system configuration by including information on primary and alternate paths to every meter. See FIG. 17 .
  • the directory thus contains information regarding various abstraction levels in the network- feeder level, phase level, distribution transformer level, and meter level.
  • the server runs a program that monitors the communication performance of the various STs deriving their master clocks from it. Every transformer is assigned a primary meter (typically the first-connected meter, m 1 ) with which the STs constantly communicate in order to detect outage and other changes in the service territory.
  • m 1 the primary meter
  • SS 1 feeds B 1 by switch U 1 .
  • the directory comprises the following information for meter ml connected to TI in a look-up table: TABLE 2 Scan m1 Path Substation Feeder Switch Transformer Transponder Primary 1 F1 U1 T1 ST1F1 1 Alternate 1 1 F2 U2 T1 ST1F2 1 Alternate 2 2 F1 U3 T1 ST2F 1 Alternate 3 3 F2 U4 T1 ST3F2 1
  • the scan transponders preferably are named such that the first number is indicative of the corresponding substation and the number following F is indicative of the feeder number emanating from that substation, and the subscript indicates the phase on which it is installed.
  • FIG. 17 depicts an exemplary directory structure implemented in the server, which can be configured for various event information. These events may include: (1) basic consumption data; (2) outage data; (3) power quality information; (4) status verification flags of several parts of a network; (5) load profile information for certain meters; (6) preventive maintenance flags for part of network infrastructure; and (7) status change flags of network elements such as switches, feeder changers, and reclosers. A preferred algorithm to raise status change flags of several network elements and for localizing outages is discussed below.
  • the server After a typical data collection operation period, the server preferably creates a list of meters that failed communication with their respective STs and hence failed to report consumption data.
  • LIST is a preferred data structure listing meters that failed communication. Referring to FIG. 18 , preferably,
  • the utility By implementing the above process steps, not only is the system map dynamically updated, the utility also gets immediate notifications of changes made in a service territory (outages, feeder switching, etc.). In addition, if the utility decides to discontinue power to some customers (typically due to sustained failure of payment), the corresponding meters fail to communicate. This change, once noticed by the EMS, can be verified with the utility by interfacing the remote server with a utility Customer Information System (CIS). This eliminates manual updating of the meter cross reference list for STs, thus making the system scalable for both utility and submetering installations.
  • CIS Utility Customer Information System
  • one unique feature of certain embodiments of this invention is the synchronization of all transponder data clocks to a global data clock, which may be derived from a remote server that may derive its own clock from one of the phases of the line frequency.
  • the slave devices typically meters
  • they preferably shift their own data clocks to align their FFT frames with the incoming data bits (see FIG. 9 ).
  • each meter has knowledge of the absolute phase (absolute phase with 0 degrees referred to as “phase A,” absolute phase with 120 degrees lead referred to as “Phase B,” and absolute phase with 240 degree lead referred to as “phase C”).
  • phase A absolute phase with 0 degrees
  • Phase B absolute phase with 120 degrees lead
  • phase C absolute phase with 240 degree lead
  • Prior art systems do not allow for such a determination of absolute phase for a meter.
  • the meters in some systems contain some information regarding phases, but only of relative phases, since the meter “sees” three phases 120 degrees apart. This lack of information regarding in phase continuity is also why it becomes difficult to exactly determine the absolute phase that feeds a wall socket, in a room with multiple sockets, on a given floor with multiple rooms, in a multi floor building being fed from three utility phases.
  • Embodiments of the current invention provide the continuity of phase information throughout the territory, from the remote server to transponders installed in substations down to meters installed in the low voltage territory. This capability enables identification of the absolute phase by which each single phase meter is powered up in the service territory.
  • embodiments of the current invention enable reconstructing the load of a distribution transformer by phase, without actually installing a three phase meter at the transformer's secondary output. For a typical utility installation consisting of multiple transformers, this reduces system costs while providing value added service. By performing a vector sum of the currents on the three phases, the total load on the distribution transformer can be accurately determined at the substation.
  • Submetering involves the allocation of energy costs within a multi-tenant property according to the energy consumption by individual tenants.
  • the meters measure electricity consumed by individual tenants and communicate the consumption data to a Scan Transponder, preferably installed at an entry point to the property, using the power lines in the property. This data then may be accessed from the transponder by a host of communication infrastructures (e.g., wireless, phone line, GPRS, etc.).
  • a host of communication infrastructures e.g., wireless, phone line, GPRS, etc.
  • a preferred submetering control module comprises a Power Board (see FIG. 21 for schematic) that also has the PLC transmit and receive circuitry on it.
  • the Power Board provides power to the CPU board.
  • the control module also comprises an I/O extension board (see FIG. 22 for schematic), which has several I/O extension options that enable communication from metering modules to the CPU board.
  • a preferred control module also comprises a CPU Board (see FIG. 23 for schematic), which has a Digital Signal Processing (DSP) processor.
  • DSP Digital Signal Processing
  • Another embodiment may include a low-cost meter with reduced resources compared to that presented in FIG. 23 .
  • This meter circuit is PCB 240 , presented in FIG. 24 .
  • Each residential meter preferably also has a 9-digit display board (PCB 220 ; see FIG. 25 for schematic).
  • PCB 220 9-digit display board

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  • Engineering & Computer Science (AREA)
  • Physics & Mathematics (AREA)
  • General Physics & Mathematics (AREA)
  • Power Engineering (AREA)
  • Computer Networks & Wireless Communication (AREA)
  • Signal Processing (AREA)
  • Cable Transmission Systems, Equalization Of Radio And Reduction Of Echo (AREA)
  • Arrangements For Transmission Of Measured Signals (AREA)
  • Remote Monitoring And Control Of Power-Distribution Networks (AREA)
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BRPI0618932A2 (pt) 2011-09-27
AR057930A1 (es) 2007-12-26
IL191657A0 (en) 2008-12-29
US8026628B2 (en) 2011-09-27
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US20120019297A1 (en) 2012-01-26
WO2007062232A2 (en) 2007-05-31

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