|Title of Invention||
APPARATUS AND METHODS FOR MULTI-CHANNEL METERING
|Abstract||In one aspect, the invention comprises a device for measuring electricity usage, comprising: means for remote disconnection via power line communication; means for detection of electricity theft; means for tamper detection; and means for reverse voltage detection. In another aspect, the invention comprises an apparatus for multi-channel metering of electricity, comprising: (a) a meter head operable to measure electricity usage for a plurality of electricity consumer lines; (b) a transponder operable to transmit data received from the meter head via power line communication to a remotely located computer, and to transmit data received via power line communication from the remotely located computer to the meter head; and (c) a load control module operable to actuate connection and disconnection of each of a plurality of relays, each relay of the plurality of relays corresponding to one of the plurality of electricity consumer lines.|
|Full Text||APPARATUS AND METHODS FOR MULTI-CHANNEL METERING
Cross-reference to Related Applications
This application claims the benefit of U.S. Provisional Patent Application No.
60/737,580, filed November 15,2005, U.S. Provisional Patent Application No.
60/739,375, filed November 23,2005, and U.S. Provisional Application No.
60/813,901, filed June 15,2006, and is a continuation-in-part of U.S. Pat. App. No.
11/431,849, filed May 9, 2006, which is a divisional of U.S. Pat. App. No.
11/030,417, filed January 6,2005 (now U.S. Pat. No. 7,054,770), which is a
divisional of U.S. Pat. App. No. 09/795,838, filed February 28, 2001 (now U.S. Pat.
No. 6,947,854). Theentrre contents of each of those applications are incorporated
herein by reference.
Background and Summary
One embodiment of the present invention comprises a metering device that is
related to the Quadlogic ASIC-based family of meters (see U.S. Pat. No. 6,947,854,
and U.S. Pat. App. Pub. No. 20060036388, the entire contents of which are
incorporated herein by reference). Specifically, this embodiment (referred to herein
for convenience as "Energy Guard") is a multi-channel meter that preferably is
capable of providing much of the functionality of the above-mentioned family of
meters, and further provides the improvements, features, and components listed
Used in at least one embodiment, a MiniCloset is a 24-channel metering
device that can measure electric usage for up to 24 single-phase customers, 12 two-
phase customer, or 8 three-phase customers. Preferably connected to the MiniCloset
are one or more Load Control Modules (LCMs), discussed below.
Energy Guard preferably comprises a MiniCloset meter head module and two
LCMs mounted into a steel box. Relays that allow for an electricity customer to be
remotely disconnected and reconnected, along with current transformers, also are
mounted into the box. See FIG. 1.
Upon installation, an electricity customer's electricity supply line is tapped off
the main electric feeder, passed through the Energy Guard apparatus, and run directly
to the customer's home. The construction and usage of the Energy Guard will be
apparent to those skilled in the art upon review of the description below and related
figures. Source code is supplied in the attached Appendix.
Energy Guard meters preferably are operable to provide:
(A) Remote Disconnect/Reconnect: The meter supports full duplex (bidirectional)
communication via power line communication ("PLC") and may be
equipped with remotely operated relays (60 amp, 100 amp, or 200 amp) that allow for
disconnect and reconnect of electric users remotely.
(B) Theft Prevention: The system is designed with three specific features to
prevent theft. First, an Energy Guard apparatus preferably is installed on a utility pole
above the medium-tension lines, making it difficult for customers to reach and tamper
with. Second, because there are no additional signal wires with the system (i.e., all
communication is via the power line), any severed communication wires are
immediately detectable. That is, if a communication wire is cut, service is cut, which
is readily apparent. A third theft prevention feature is that the meter may be used to
measure the transformer energy in order to validate the measured totals of individual
clients. Discrepancies can indicate theft of power.
(C) Tamper Detection: The Energy Guard preferably provides two modes of
optical tamper detection. Each unit contains a light that reflects against a small
mirror-like adhesive sticker. The absence of this reflective light indicates that the box
has been opened. This detection will automatically disconnect all clients measured by
that Energy Guard unit. In addition, if the Energy Guard enclosure is opened and
ambient light enters, this will also automatically disconnect all clients measured by
that Energy Guard unit. These two modes of tamper detection are continuously
engaged and alternate multiple times per second for maximum security.
(D) Reverse Voltage Detection: In some cases, a utility company can
disconnect power to an individual client and that client is able to obtain power via an
alternative feed. If the utility were to reconnect power under these conditions,
damage could occur to the metering equipment and/or the distribution system.
Energy Guard preferably is able to detect this fault condition. The Energy Guard can
detect any voltage that feeds back into the open disconnect through the lines that
connect to the customers' premises. If voltage is detected, the firmware of the Energy
Guard will automatically prevent the reconnection.
(E) Pre-Payment: Pre-payment for energy can be done via phone, electronic
transaction, or in person. The amount of kWh purchased is transmitted to the meter
and stored in its memory. The meter will count down, showing how much energy is
still available before reaching zero and disconnecting. As long as the customer
continues to purchase energy, there will be no interruption in service, and the utility
company will have a daily activity report.
(F) Load Limiting: As an alternative to disconnection for nonpayment or part
of a pre-payment system, Energy Guard meters can allow the utility to remotely limit
the power delivered to a set level, disconnecting when that load is exceeded. If the
customer exceeds that load and is disconnected, the customer can reset a button on the
optional remote display unit to restore load as long as the connected load is less than
the pre-set limit. Alternatively, clients can call an electric utility service line by
telephone to have the service restored. This feature allows electric utilities to provide
electricity for critical systems even, for example, in the case of a non-paying
(G) Monthly Consumption Limiting: Some customers benefit from subsidized
rates and are given a maximum total consumption per month. The Energy Guard
firmware is capable of shutting down power when a certain consumption level is
reached. However, this type of program is best implemented when advanced
notification to customers is provided. This can be achieved either with a display in
the home whereby a message or series of messages notifies customers that their rate
of consumption is approaching the projected consumption for the month.
Alternatively (or in conjunction) timed service interruptions can be programmed so
that as the limit is approaching, power is disconnected for periods of time with longer
and longer increments to notify the residents. These planned interruptions in service
act as a warning to customers that their limit is nearing so that they have time to alter
their consumption patterns.
(H) MeteT Validation: The integrated module of the system preferably is
removable. This permits easy laboratory re-validation of meter accuracy in the event
of client billing disputes.
(I) Operational Benefits for Utility: The Energy Guard has extensive onboard
event logs and diagnostic functions, providing field technicians with a wealth of data
for commissioning and trouble shooting the electrical and communication systems.
Non billing parameters include: amps, volts, temperature, total harmonic distortion,
frequency, instantaneous values of watts, vars and volt-amperes, V2 hrs, 12 hrs, power
factor, and phase angle.
These features and others will be apparent to those skilled in the art after
reviewing the attached descriptions, software code, and schematics.
In one aspect, the invention comprises a device for measuring electricity
usage, comprising: means for remote disconnection via power line communication;
means for detection of electricity theft; means for tamper detection; and means for
reverse voltage detection.
In another aspect, the invention comprises an apparatus for multi-channel
metering of electricity, comprising: (a) a meter head operable to measure electricity
usage for a plurality of electricity consumer lines; (b) a transponder in
communication with the meter head and operable to transmit data received from the
meter head via power line communication to a remotely located computer, and to
transmit data received via power line communication from the remotely located
computer to the meter head; and (c) a load control module in communication with the
meter head and operable to actuate connection and disconnection of each of a
plurality of relays, each relay of the plurality of relays corresponding to one of the
plurality of electricity consumer lines.
In various embodiments: (1) the apparatus further comprises a tamper
detector in communication with the meter head; (2) the tamper detector comprises a
light and a reflective surface, and the meter head is operable to instruct the load
control module to disconnect all of the customer lines if the tamper detector provides
notification that the light is not detected reflecting from the reflective surface; (3) the
apparatus further comprises a box containing the meter head, the load control module,
and the relays, and wherein the tamper detector comprises a detector of ambient light
entering the box; (4) the apparatus further comprises a box containing the meter head,
the load control module, and the relays, and wherein the box is installed on a utility
pole; (5) the apparatus further comprises means for comparing transformer energy to
total energy used by the consumer lines; (6) the apparatus further comprises means for
detecting reverse voltage flow through the consumer lines; (7) the apparatus further
comprises a computer readable memory in communication with the meter head and a
counter in communication with the meter head, the counter corresponding to a
customer line and operable to count down an amount of energy stored in the memory,
and the meter head operable to send a disconnect signal to the load control module to
disconnect the customer line when the counter reaches zero; (8) the apparatus further
comprises a computer readable memory in communication with the meter head, the
memory operable to store a load limit for a customer line, and the meter head operable
to send a disconnect signal to the load control module to disconnect the customer line
•when the load limit is exceeded; (9) the apparatus further comprises a computer
readable memory in communication with the meter head, the memory operable to
store a usage limit for a customer line, and the meter head operable to send a
disconnect signal to the load control module to disconnect the customer line when the
usage limit is exceeded; (10) the transponder is operable to communicate with the
remotely located computer over medium tension power lines; (11) the apparatus
further comprises a display unit in communication with the meter head and operable
to display data received from the meter head; (12) the display unit is operable to
display information regarding a customer's energy consumption; (13) the display unit
is operable to display warnings regarding a customer's energy usage or suspected
theft of energy; and (14) the display unit is operable to transmit to said meter head
information entered by a customer.
Brief Description of the Drawings
FIG. 1 is a block/wiring diagram showing connection of preferred
FIG. 2 is a block diagram showing physical configuration of preferred
FIGS. 3A-3B are schematic diagrams of a preferred CPU board of a Scan
Transponder and MiniCloset.
FIG. 4 is a schematic diagram of a preferred Scan Transponder power supply.
FIG. 5 is a schematic diagram of a preferred MiniCloset power supply.
FIG. 6 is a schematic diagram of a preferred circuit board for returning current
transformer information to a MiniCloset meter head.
FIGS. 7A-7C are schematic diagrams of a preferred Load Control Module
FIGS. 8A-8D are schematic diagrams of a preferred power supply board that
provides for optical tamper detection.
FIGS. 9A-9C are schematic diagrams of a preferred Energy Guard connection
FIG. 10 is a schematic diagram for a control circuitry board operable to
provide relay control.
FIG. 11 is a diagram of preferred Energy Guard base assembly.
FIGS. 12 and 13 are diagrams of preferred phase bus bars and construction of
FIG. 14 is a diagram depicting preferred neutral bar frame construction and
FIG. 15 depicts preferred transition bars; FIG. 16 depicts preferred placement
of transition bars.
FIGS. 17 and depict preferred acceptor module constructiono.
FIG. 19 depicts a preferred integrated current sensing and relay module.
FIG. 20 depicts an exploded view of a preferred integrated current sensing and
FIG. 21 shows exploded views of preferred metering modules.
FIG. 22 shows the metering modules placed in an EG frame assembly and
FIG. 23 shows an exploded view a preferred embodiment of Energy Guard.
FIG. 24 shows an exploded view of a preferred EG assembly and base
FIG. 25 shows a preferred EG layout
FIGS. 26 and 27 are preferred metering module schematics.
FIG. 28 has preferred schematics for a back place board.
FIG. 29 has preferred schematics for a power board.
FIG. 30 has preferred schematics for an I/O extension board.
FIG. 31 has preferred schematics for a CPU board.
FIG. 32 has preferred schematics for a control module.
FIG. 33 has preferred schematics for metering and power supply circuitry for a
customer display module; FIG. 34 has preferred schematics for a display board for the
FIG. 35 is a block diagram of a preferred analog front end for metering.
FIGS. 36 and 37 depict preferred DSP implementations.
FIG. 38 illustrates preferred in-phase filter frequency and implulse response
FIG. 39 illustrates injecting PLC signals at half-odd harmonics of 60 Hz.
FIG. 40 depicts 12 possible ways in which an FFT frame received by a meter
can be out of phase with a scan transponded FFT frame.
FIG. 41 illustrates preferred FIR filter specifications.
FIG. 42 depicts voltage and current resulting from a preferred FFT.
Detailed Description of Preferred Embodiments
In one embodiment, an Energy Guard metering apparatus comprises a
Mini Closet (that is, a metering apparatus operable to meter a plurality of customer
lines); a Scan Transponder; one or more relays operable to disconnect service to
selected customers; a Load Control Module; and optical tamper detection means.
The MiniCloset and Scan Transponder referred to herein are largely the same
as described in U.S. Pat. No. 6,947,854. That is, although each has been improved
over the years, the functionality and structure relevant to this description may be taken
to be the same as described in that patent
One aspect of the invention comprises taking existing multichannel metering
functionality found in the MiniCloset and adding remote connect and disconnect via
PLC. Providing such additional functionality required adding new hardware and
software. The added hardware comprises a Load Control Module (LCM) and
connect/disconnect relays. Also added was support circuitry to route signal traces to
and from the main meter processor- the MiniCloset5 Meter Head. The software
additions include code modules that communicate with the added hardware, as
described in the tables below.
FIG. 1 is a block diagram of connections of a preferred embodiment. Medium
voltage power lines A, B, C, and N (neutral) feed into Distribution Transformer 110.
Low voltage lines connect (via current transformers 120) Distribution Transformer
110 to Energy Guard unit 140. Energy Guard unit 140 monitors current transformers
120, and feeds single phase customer lines 1-24.
FIG. 2 is a block diagram of preferred structure of an Energy Guard unit 140.
Scan Transponder 210 is the preferred data collector for the unit 140, may be
located external to or inside the MiniCloset, and may be the main data collector for
more than one MiniCloset at a time. The Scan Transponder 210 preferably : (a)
verifies data (each communication preferably begins with clock and meter identity
verification to ensure data integrity); (b) collects data (periodically it collects a data
block from each meter unit, with each block containing previously collected meter
readings, interval readings, and event logs); (c) stores data (preferably the data is
stored in non-volatile memory for a specified period (e.g., 40 days)); and (d) reports
data (either via PLC, telephone modem, RS-232 connection, or other means).
The slide plate 280 comprises a Minicloset meter head and a load control
module 240 that provides the control signals to activate the relays. All of the
electronics preferably is powered up by power supply 250. The back plate assembly
270 comprises multiple (e.g., 24) Current Transformers and relays - grouped, in this
example, as three sets of 8 CTs and relays. Customer cables are wired through the
CTs and connect to the circuit on customer premises 290. The remotely located Scan
Transponder 210 accesses the Energy Guard meter head and bi-directionally
communicates using power line carrier communication.
The signal flow shown in FIGS. 1 and 2 preferably is accomplished by
implementing different software code modules that work concurrently to enable
remote connect/disconnect ability in the Minicloset. These software modules,
provided in the Appendix below, are:
FIGS. 3-10 are schematics of preferred components, as described below. The
preferred connect/disconnect relays are series K850 KG relays, but those skilled in the
art will recognize that other relays may be used without departing from the scope of
In another embodiment, the implementation of Energy Guard takes advantage
of the similarity of architecture of traditional circuit breaker panels, with the
multichannel metering environment. In a circuit breaker panel, electricity is fed to the
panel and distributed among various customer circuits via circuit breakers that
provide the ability to connect or disconnect the customer circuits.
In the MiniCloset/Energy Guard, multiple current transformers measure the
current in customer circuits and bring this data back to a central processing unit where
the metering quantities are calculated. However, the MiniClosefEnergy Guard has
several key differences with a circuit breaker panel. For example, whereas circuit
breakers are found near customer premises, the Energy Guard typically is installed
near the utility distribution transformer. The advantages offered by this alternate
embodiment will be apparent to those skilled in the art. For example, this
embodiment offers improved dimensions and overall size over the embodiments
discussed above. Space is always a constraint when equipment additions are made to
existing electrical installations. This version of the Energy Guard ("EG"), with
preferred dimensions of 28" X 22" X 11" provides a substantial advantage in
situations where volumetric constraints exist.
The following description includes preferred construction details, detailed
schematics, and software descriptions. As with the embodiments discussed above,
this embodiment is operable to providing remote disconnect/connect operations,
preventing theft, detecting tampering, detecting reverse voltage, performing pre-
payment and limiting load, and performing meter validation.
Preferred EG Construction Details
In this embodiment, primary components of the EG are :
1. Energy Guard Base Assembly
2. Energy Guard Assembly
a. Phase Bus Bars and Neutral Bars
b. Transition Bars
c. Acceptor Module
3. Energy Guard Metering Modules
a. Metering Modules
i. Integrated Current Sensing and Relay Modules
4. Energy Guard Electronics
b. PCB 204
c. PCB 234
d. PCB 235
e. PCB 202
f. PCB 210
g. PCB 230
h. PCB 206
EG Base Assembly
The EG base comprises an enclosure bottom with screws and retaining
washers as a locking mechanism for the top cover of EG, which is connected on one
side by piano hinges. See FIG. 11. The enclosure bottom provides routing for the
EG Assembly- Phase Bus Bars
Three aluminum phase bus bars are placed towards the center of the Energy
Guard assembly and staggered. See FIGS. 12 and 13. These provide connection to
the customer metering modules by the use of transition bars. A staggered bus bar
layout is depicted in FIG. 13. Bus bars are shown in black.
The EG preferably comprises 4 neutral bars that form a frame for EG
assembly, thereby providing a path for the neutral current. This is shown in FIG. 14.
The lug on the cross bar provides the neutral feed from the utility distribution
transformer. Also, there are 2 mother board neutral bars that carry the neutral current
to the control module.
The transition bars complete the mechanical and electrical connection between
the customer metering modules and the phase bus bars. See FIG. 15. A transition bar
for phase A and C is shown in FIG. 15 A; a transition bar for phase B is shown in FIG.
15B. FIG. 16 shows the transition bars in black.
An acceptor module preferably is made of plastic and mechanically accepts
the metering modules that can be easily fitted in the EG assembly. Each EG has 4
acceptor modules that are stacked together and can accommodate either 12 two-phase
or 8 three-phase metering modules. See FIG. 17. The acceptor module also provides
a mechanical route for the motherboard neutral bar which connects to the control
module. See FIG. 18.
Customer Metering Modules
Preferred customer metering modules provide metrology required to measure
the consumption for a single phase, two phase, or three phase customer. An
individual module functions as a complete stand-alone meter that can he tested and
evaluated as a separate metering unit. Each module preferably comprises an
integrated current sensing and relay module and metrology electronics, and provides a
connection between the customer circuit and the phase bus bars. FIG. 19 depicts a
preferred integrated current sensing and relay module. FIG. 20 depicts an exploded
view of a preferred integrated current sensing and relay module.
FIG. 21 shows exploded views of preferred metering modules. FIG. 22 shows
the metering modules (shown in black) placed in the EG frame assembly and acceptor
FIG. 23 shows an exploded view of Energy Guard, and FIG. 24 shows an
exploded view of a preferred EG Assembly and EG Base Assembly.
The Control Module boxes preferably comprise various PCBs that work
concurrently to collect metering data from the individual metering modules and
communicate over power lines to transmit this data to a master device, such as a Scan
FIG. 25 shows a preferred Energy Guard layout for this embodiment. Each
customer line has a corresponding Metering Module (PCB 203 and PCB 204,
discussed below) (schematics shown in FIGS. 26 and 27).
A Back Place Board 2510 shown in FIG. 25 (PCB 234; see FIG. 28 for
construction diagram and schematic) is the common bus that routes signals within the
EG. There are two kinds of communication options on the Back Place Board 2510 to
enable data transfer from Control Module 2520 to individual Metering Modules PCB
203. This can be done either using the 2 wire I2C option or the 1 wire serial option.
The Control Module 2520 comprises a Power Board (PCB 210; see FIG. 29
for schematic) is the power supply board that also has the PLC transmit and receive
circuitry on it. The Power Board provides power to the CPU board and the
electronics of 203 boards. The Control Module 2520 also comprises an I/O Extension
Board (PCB 230; see FIG. 30 for schematic) is a board with several I/O extension
options that enable communication from Metering Modules to the CPU board.
Control Module 2520 also comprises a CPU Board (PCB 202; see FIG. 31 for
schematic), which has a Digital Signal Processing (DSP) processor on board.
Finally, Control Module 2520 comprises a foliting board (PCB 235; see FIG.
32 for schematic) with traces and a header with no electronic components on it.
Each Customer Display Module (CDM) 2530 is installed at the customer's
premises and can bidirectionally communicate with the EG installed at the
distribution transformer serving the customer. Two-way PLC enables utility-
customer communication over low voltage power lines and allows the utility to send
regular information, warnings, special information about outages, etc. to the customer.
Each CDM 2530 comprises a selected combination of metering and power
supply along with PLC circuitry on the same board (PCB 240; see FIG. 33 for
schematic). Each CDM preferably also has a 9-digit display board (PCB 220; see
FIG. 34 for schematic). This display communicates with EG and shows information
about consumption, cautions, warnings, and other utility messages.
In one embodiment, the Energy Guard implements Fast Fourier Transform
(FFT) on the PLC communication signal both at the ST and the meter, and for
metering purposes performs detailed harmonic analysis. This section discusses an
implementation scheme of the Metering Modules, communication with Control
Modules and PLC communication of the Control Module with a remotely located
The Control Module 2520 comprises power supply and PLC circuitry (PCB
210; see FIGS. 25 and 29); I/O extension (PCB 230; see FIG. 30) and CPU board
named D Meter (PCB 202; see FIG. 31). The power supply supplies power to the D
meter and I/O extension and contains the PLC transmitter and receiver circuitry. PCB
235 provides a trace routing and header connection between various boards.
The Metering Module may have two versions: 2-phase or 3-phase. The 2-
phase version can be programmed by software to function as a single 2-phase meter or
two 1-phase meters. The 2-phase version comprises a B2 meter (PCB 203 schematic
shown in FIG. 26), whereas the 3-phase version comprises a B3 meter (PCB204
schematic shown in FIG. 27). The B meters act as slaves to the D meter in Control
Module 2520. The D and B meters can communicate via a serial ASCII protocol.
The various B meters are interconnected via BPB 2510 to 2520 that provides power, a
I Hz reference and serial communications to the D meter. The preferred DSP engine
for the B meter is the Freescale 56F8014VFAE chip. The preferred microprocessor
used for implementing the CPU on the D meter is one among the family of ColdFire
Integrated Microprocessors, MCF5207. The use of a specific processor is determined
by RAM and Flash requirements dictated by the meter version. A separate power
supply and LCD board complete the electronic portion of the D meter as a product.
Apart from acting as a master for B meters, the D meter is also a 3-phase meter and
measures fee total transformer output on which the EG is installed. As an anti-theft
feature, this total is compared with the total consumption reported by the various B
The signal streams constituency is as follows:
B2: Two voltage, Two current, and No Power Line Carrier (PLC) Channel.
B3: Three voltage, Three current, and No PLC Channel.
D: Three voltage, Three current, and one PLC Channel.
Each stream has an associated circuit to effect analog amplification and anti-
Specific to the D meter is the preferred implementation of:
A Phase Locked Loop (PLL) to lock the sampling of the signal streams
to a multiple of the incoming A/C line (synchronous sampling to the power line).
A Voltage Controlled Oscillator (VCO) at 90-100 MHz controlled by
DSP processor via two PWM modules directly driving the system clock hence making
the DSP coherent with the PLL.
• A synchronous phase detector that responds only to the fundamental of
the incoming line frequency wave and not to its harmonics.
• Option for performing FSK and PSK modulation schemes.
Each metering and communication channel preferably comprises front-end
analog circuitry followed by the signal processing. Unique to the analog circuitry is
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. This is discussed next, and then a preferred signal processing
implementation is discussed.
Voltage and Current Analog Signal Chain
The analog front-end for voltage (current) channels comprises voltage
(current) sensing elements and a programmable attenuator, followed by an antialiasing
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 Analog to Digital Converter (ADC). For
metering, the anti-aliasing filter cuts off frequencies above 5 kHz. The inputs are then
ted into the ADC which is a part of the DSP. See FIG. 35, which is a block diagram
of a preferred analog front-end for metering.
Whereas a typical implementation would include a Programmable Gain
Amplifier (PGA) followed by a low gain anti-aliasing filter, the invention, in this
embodiment, implements a programmable attenuator followed by a large fixed-gain
filter. In addition, the implementation of both the anti-aliasing filters on a single chip
is the same using the same Quad Op Amps along with 25 ppm resistors and
NPO/COG capacitors. This unique implementation by 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. This provides a means for both V and I channels to
track temperature drifts up to first order without recalibrating the meter.
In contrast, using a PGA along with a low gain filter cannot track the phase
shift in the V and I signals introduced due to temperature. This is because the phase
shift introduced by PGA is a function of the gain.
Voltage, Current and PLC Digital Signal Chain
FIG. 36 is a block diagram of the PCB 202 board; the functions of each block
will be apparent to those skilled in the art. FIG. 36 shows a preferred DSP
This embodiment preferably uses a PLL to lock the sampling of the signal
streams to a multiple of the incoming A/C line frequency. In the embodiment
discussed above, the sampling is at a rate asynchronous to the power line. In the D
meter, there is a VCO at 90-100 MHz which is controlled by the DSP engine via two
PWM modules. The VCO directly drives the system clock of the DSP chip (disabling
the internal PLL), so the DSP becomes an integral part of the PLL. Locking the
system clock of the DSP to the power line facilitates the alignment of the sampling to
the waveform of thepower line. The phase detector should function so as to respond
only to the fundamental of the incoming 60Hz wave and not to it harmonics. FIG. 37
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 a I2C driver. The MSP430F2002 integrated circuit
measures the power supplies, tamper port, temperature and battery voltage. The tasks
of the MSP430F2002 include:
i. maintain an RTC;
ii. measure the battery voltage;
iii. measure the temperature;
iv. measure the +U power supply;
v. reset the DSP on brown out;
vi. provide an additional watchdog circuit; and
vii. provide a 1-second reference to go into the DSP for a time reference to
measure the 1-second reference against the system clock from the VCO.
D Meter PLC Communication Signal Chain
A typical installation consists of multiple EGs and STs communicating over
the power lines. The D meter communicates bi-directionally with a remotely located
Scan Transponder through the distribution transformer. To enable this, this
embodiment uses a 10-25 kHz band for PLC communication. The PLC signal is
sampled at about 240 kHz (212 * 60), synchronous with line voltage, following which
a Finite Impulse Response (FIR) filter is applied to decimate the data. Preferred FIR
specifications are given below:
10-25 kHz Band
See FIG. 38 for preferred inphase filter frequency response and impulse
After the decimation is done to 60 kHz (211 * 30), a 2048-point FFT is then
performed on the decimated data. The data rate is thus determined to be 30 baud
depending on the choice of FIR filters. Every FFT yields two bits approximately
every 66 msec when using FIR in the 10-25 kHz band to communicate through
To circumvent the problem of communicating in the presence of line noise,
this embodiment preferably implements a unique technique for robust and reliable
communication. This is done by injecting PLC signals at frequencies that are half odd
harmonics of the line frequency (60Hz). This is discussed below, for an embodiment
using a typical noise spectrum found on AC lines in the range 12-12.2 kHz.
FIG. 39 illustrates injecting PLC signals at half-odd harmonics of 60 Hz.
Since FFT is done every 30 Hz and the harmonics are separated by 60 Hz, the data
bits reside in the bin corresponding to the 201.5th and 202.5th harmonic of 60 Hz in
FIG. 39. The 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. Alternatively, QFSK, which uses 4
frequencies, can be implemented to yield 60 baud.
When traversing through transformers, both STs and D meters preferably
perform FFT on the PLC and data signals every 30 Hz in a 10-25 kHZ range.
Because the Phase Lock Loops (PLLs) implemented in both the ST and the D meter
are locked to the line, the data frames are synchronized to the line frequency (60 Hz)
as well. However, the data frames can shift in phase due to:
1. various transformer configurations that can exist in the path between
the ST and meter (delta-Wye, etc.); and
2. a shift in phase due to the fact that STs are locked on a particular
phase, whereas single and polyphase meters can be powered up by other phases.
The signal to noise ratio (SNR) is maximized when the meter data frame and-
ST data frames are aligned close to perfection. From a meter's standpoint, this
requires receiving PLC signal from all possible STs that it can "hear," decoding the
signal, checking for SNR by aligning data frames, and then responding to the ST that
is yielding maximum SNR. FIG. 40 depicts the 12 possible ways in which the FFT
frame received by the meter can be out of phase with ST FFT frame. Dotted lines
correspond to a 30 degree rotation accounting for a delta transformer in the signal
path between ST and the meter.
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.
In each frame of the ST, there are an odd integral number of cycles of the
carrier frequency. Since the preferred modulation scheme is Frequency Shift Keying
(FSK), if there are n cycles for transmitting bit 1, bit 0 is transmitted using n+2 cycles
of the carrier frequency. It becomes vital for the meter to recognize its own 2 cycles
of 60 Hz in order to be able to decode its data bits which are available every 1/3 Oth of
If the D meter decodes signals with misaligned data frames, there is energy
that spills over into the adjacent (half-odd separated) frequencies. If the signal level
that falls into 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, the
ability to distinguish between 1 and 0 decreases, and hence the overall SNR drops,
resulting in an error in decoding. In conclusion:
a. If the frames are misaligned, smearing of data bits occurs and the SNR
b. In the event that the frequency changes and there are misaligned data
frames, there is a substantial amount of energy that spills over into the adjacent FFT
bins, hence interfering with the other STs in the system that communicate using
frequencies in that specific bins.
Once the clock shift is determined corresponding to the highest SNR, the
meter then locks until a significant change in SNR ratio is encountered by the meter,
in which case the process repeats.
Implementation of Metering in D and B Meter using FFT
Whereas versions of the B meter and the D meter perform metering, the D
meter also is responsible for collecting the metering information from the various B
meters via PCB 234. Each data stream in the meters 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 (210 * 60) and then an FIR filter is applied to decimate the data
stream to ~15 kHz (28 * 60). Preferred filter specifications are shown in the table
below and FIG. 41.
Since only the data up to 3 kHz is of interest, praferably a 3-12 kHz rolloff on
the decimating FIR is used with ~15KHZ sample rate. The frequencies from 0-3 kHz
or 12-15 kHz are mapped into 0-3 kHZ. A real FFTs 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. Alternatively, 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.
The results of performing either FFT are the voltage and current shown in
FIG. 42, where the notation Vm,n denotes the mth harmonic of the nth cycle number.
For example, V11 and I11 correspond to the fundamental of the first cycle, and V21 and
I21 to the first harmonic of the first cycle, etc., as shown in FIG. 42, which depicts
FFT frames for voltage, indicating the harmonics.
The real and imaginary parts of the harmonic content of any k?h cycle are given
Vink=Re(Vink)+i Im(Vink);m = l...M
Iink = Re(Vink)+i Im(Vink);k = l...n
The imaginary part of voltage is the measure of lack of synchronization
between the PLL and the line frequency. In order to calculate metering quantities, the
calculations are done in the time domain. In the time domain, the FFT functionality
offers the flexibility to calculate metering quantities either using only the fundamental
or including the harmonics. Using the complex form of voltage and current obtained
from the FFT, the metering quantities are calculated as:
P = Vink*Iink
W = Re(P) = Re(Vink) * Re(Iink) + Im(Iink) * Im(Vink)
Var = Im(P) = Re(Vink) * Im(Vink) + Re(Iink) * Im(Vink)
PowerFactor = W/P
However, in the above formulas, when the harmonics are included
(Vink & Iink; m = 1.. .M, k = 1...n), all metering quantities include the effects of
harmonics. On the other hand, when only the fundamental is used (Vlk & Itk), all
calculated quantities represent only the 60 Hz contribution. As an example, we show
the calculations when only the fundamental is used to perform calculations. Only V1
and I1 are used from all FFT data frames. The following quantities are calculated for
a given set of N frames and a line frequency of fline:
The displacement power factor is given by:
This flexibility to either include or exclude the harmonics when calculating
metering quantities translates to a significant improvement over the capabilities
offered by the above-described embodiment. Yet another feature offered by this
embodiment is the calculation of Total Harmonic Distortion (THD). The THD is the
measurement of the harmonic distortion present, and is defined as the ratio of the sum
of the powers of all harmonic components to the power of the fundamental. For the
n'h cycle, this is evaluated as:
Customer Display Module
The customer display module is installed at the customer premises,
communicates with Energy Guard near the transformer, and comprises: PCB 240,
power supply and PLC circuitry (see FIG. 33); and PCB 220, LCD display (see FIG.
34). In one embodiment, the customer display unit installed at customer's residence is
a bidirectional PLC unit that communicates with EG. For'example, not only can the
utility send messages, the customer can also request a consumption verification with
the EG installed at the pole.
While certain specific embodiments of the invention have been described
herein for illustrative purposes, the invention is not limited to the specific details,
representative devices, and illustrative examples shown and described herein.
Various modifications may be made without departing from the spirit or scope of the
invention defined by the appended claims and their equivalents.
1. An apparatus for multi-channel metering of electricity, comprising:
a meter head operable to measure electricity usage for a plurality of electricity
a transponder in communication with said meter head and operable to transmit
data received from said meter head via power line communication to a remotely
located computer, and to transmit data received via power line communication from
said remotely located computer to said meter head; and
a load control module in communication with said meter head and operable to
actuate connection and disconnection of each of a plurality of relays, each relay of
said plurality of relays corresponding to one of said plurality of electricity consumer
2. An apparatus as in claim 1, further comprising a tamper detector in
communication with said meter head.
3. An apparatus as in claim 2, wherein said tamper detector comprises a light
and a reflective surface, and wherein said meter head is operable to instruct
said load control module to disconnect all of said customer lines if said tamper
detector provides notification that said light is not detected reflecting from
said reflective surface.
4. An apparatus as in claim 2, further comprising a box containing said .
meter head, said load control module, and said relays, and wherein said tamper
detector comprises a detector of ambient light entering said box.
5. An apparatus as in claim 1, further comprising a box containing said
meter head, said load control module, and said relays, and wherein said box is
installed on a utility pole.
6. An apparatus as in claim 1, further comprising means for comparing
transformer energy to total energy used by said consumer lines.
7. An apparatus as in claim 1, further comprising means for detecting
reverse voltage flow through said consumer lines.
8. An apparatus as in claim 1, further comprising a computer readable
memory in communication with said meter head and a counter in
communication with said meter head, said counter corresponding to a
customer line and operable to count down an amount of energy stored in said
memory, and said meter head operable to send a disconnect signal to said load
control module to disconnect said customer line when said counter reaches
9. An apparatus as in claim 1, further comprising a computer readable
memory in communication with said meter head, said memory operable to
store a load limit for a customer line, and said meter head operable to send a
disconnect signal to said load control module to disconnect said customer line
when said load limit is exceeded.
10. An apparatus as in claim 1, further comprising a computer readable
memory in communication with said meter head, said memory operable to
store a usage limit for a customer line, and said-meter head operable to send a
disconnect signal to said load control module to disconnect said customer line
when said usage limit is exceeded.
11. An apparatus as in claim 1, wherein said transponder is operable to
communicate with said remotely located, computer over medium tension
12. An apparatus as in claim 1, further comprising a display unit in
communication with said meter head and operable to display data received
from said meter head.
13. An apparatus as in claim 12, wherein said display unit is operable to
display information regarding a customer's energy consumption.
14. An apparatus as in claim 12, wherein said display unit is operable to
display warnings regarding a customer's energy usage or suspected theft of
15. An apparatus as in claim 12, wherein said display unit is operable to
transmit to said meter head information entered by a customer.
In one aspect, the invention comprises a device for measuring electricity usage, comprising: means for remote disconnection
via power line communication; means for detection of electricity theft; means for tamper detection; and means for reverse
voltage detection. In another aspect, the invention comprises an apparatus for multi-channel metering of electricity, comprising: (a)
a meter head operable to measure electricity usage for a plurality of electricity consumer lines; (b) a transponder operable to transmit
data received from the meter head via power line communication to a remotely located computer, and to transmit data received via
power line communication from the remotely located computer to the meter head; and (c) a load control module operable to actuate
connection and disconnection of each of a plurality of relays, each relay of the plurality of relays corresponding to one of the plurality
of electricity consumer lines.
|Indian Patent Application Number||2403/KOLNP/2008|
|PG Journal Number||06/2017|
|Date of Filing||13-Jun-2008|
|Name of Patentee||QUADLOGIC CONTROLS CORPORATION|
|Applicant Address||33-00 NORTHERN BLVD., 2ND FL. LONG ISLAND CITY, NY|
|PCT International Classification Number||G06F 19/00|
|PCT International Application Number||PCT/US2006/044762|
|PCT International Filing date||2006-11-15|