WO2015120141A1 - Cartographie d'emplacements de dispositifs de réseau en utilisant des caractéristiques des perturbations de courant observées de manière passive - Google Patents

Cartographie d'emplacements de dispositifs de réseau en utilisant des caractéristiques des perturbations de courant observées de manière passive Download PDF

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Publication number
WO2015120141A1
WO2015120141A1 PCT/US2015/014603 US2015014603W WO2015120141A1 WO 2015120141 A1 WO2015120141 A1 WO 2015120141A1 US 2015014603 W US2015014603 W US 2015014603W WO 2015120141 A1 WO2015120141 A1 WO 2015120141A1
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WIPO (PCT)
Prior art keywords
grid
downstream
devices
electrical
upstream
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PCT/US2015/014603
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English (en)
Inventor
James SHIMA
Stan Mcclellan
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Texas State University
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Publication of WO2015120141A1 publication Critical patent/WO2015120141A1/fr

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Classifications

    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B60—VEHICLES IN GENERAL
    • B60L—PROPULSION OF ELECTRICALLY-PROPELLED VEHICLES; SUPPLYING ELECTRIC POWER FOR AUXILIARY EQUIPMENT OF ELECTRICALLY-PROPELLED VEHICLES; ELECTRODYNAMIC BRAKE SYSTEMS FOR VEHICLES IN GENERAL; MAGNETIC SUSPENSION OR LEVITATION FOR VEHICLES; MONITORING OPERATING VARIABLES OF ELECTRICALLY-PROPELLED VEHICLES; ELECTRIC SAFETY DEVICES FOR ELECTRICALLY-PROPELLED VEHICLES
    • B60L53/00—Methods of charging batteries, specially adapted for electric vehicles; Charging stations or on-board charging equipment therefor; Exchange of energy storage elements in electric vehicles
    • B60L53/60—Monitoring or controlling charging stations
    • B60L53/63—Monitoring or controlling charging stations in response to network capacity
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B60—VEHICLES IN GENERAL
    • B60L—PROPULSION OF ELECTRICALLY-PROPELLED VEHICLES; SUPPLYING ELECTRIC POWER FOR AUXILIARY EQUIPMENT OF ELECTRICALLY-PROPELLED VEHICLES; ELECTRODYNAMIC BRAKE SYSTEMS FOR VEHICLES IN GENERAL; MAGNETIC SUSPENSION OR LEVITATION FOR VEHICLES; MONITORING OPERATING VARIABLES OF ELECTRICALLY-PROPELLED VEHICLES; ELECTRIC SAFETY DEVICES FOR ELECTRICALLY-PROPELLED VEHICLES
    • B60L55/00—Arrangements for supplying energy stored within a vehicle to a power network, i.e. vehicle-to-grid [V2G] arrangements
    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
    • H02J13/00—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network
    • H02J13/00006—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment
    • H02J13/00016—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment using a wired telecommunication network or a data transmission bus
    • H02J13/00017—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment using a wired telecommunication network or a data transmission bus using optical fiber
    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
    • H02J13/00—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network
    • H02J13/00032—Systems characterised by the controlled or operated power network elements or equipment, the power network elements or equipment not otherwise provided for
    • H02J13/00034—Systems characterised by the controlled or operated power network elements or equipment, the power network elements or equipment not otherwise provided for the elements or equipment being or involving an electric power substation
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01R—MEASURING ELECTRIC VARIABLES; MEASURING MAGNETIC VARIABLES
    • G01R19/00—Arrangements for measuring currents or voltages or for indicating presence or sign thereof
    • G01R19/25—Arrangements for measuring currents or voltages or for indicating presence or sign thereof using digital measurement techniques
    • G01R19/2513—Arrangements for monitoring electric power systems, e.g. power lines or loads; Logging
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01R—MEASURING ELECTRIC VARIABLES; MEASURING MAGNETIC VARIABLES
    • G01R31/00—Arrangements for testing electric properties; Arrangements for locating electric faults; Arrangements for electrical testing characterised by what is being tested not provided for elsewhere
    • G01R31/50—Testing of electric apparatus, lines, cables or components for short-circuits, continuity, leakage current or incorrect line connections
    • G01R31/66—Testing of connections, e.g. of plugs or non-disconnectable joints
    • G01R31/67—Testing the correctness of wire connections in electric apparatus or circuits
    • H—ELECTRICITY
    • H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
    • H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
    • H02J13/00—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network
    • H02J13/00006—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment
    • H02J13/00028—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment involving the use of Internet protocols
    • 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
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E60/00—Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
    • 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
    • Y02T—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO TRANSPORTATION
    • Y02T10/00—Road transport of goods or passengers
    • Y02T10/60—Other road transportation technologies with climate change mitigation effect
    • Y02T10/70—Energy storage systems for electromobility, e.g. batteries
    • 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
    • Y02T—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO TRANSPORTATION
    • Y02T10/00—Road transport of goods or passengers
    • Y02T10/60—Other road transportation technologies with climate change mitigation effect
    • Y02T10/7072—Electromobility specific charging systems or methods for batteries, ultracapacitors, supercapacitors or double-layer capacitors
    • 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
    • Y02T—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO TRANSPORTATION
    • Y02T90/00—Enabling technologies or technologies with a potential or indirect contribution to GHG emissions mitigation
    • Y02T90/10—Technologies relating to charging of electric vehicles
    • Y02T90/12—Electric charging stations
    • 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
    • Y04S10/00—Systems supporting electrical power generation, transmission or distribution
    • Y04S10/12—Monitoring or controlling equipment for energy generation units, e.g. distributed energy generation [DER] or load-side generation
    • Y04S10/126—Monitoring or controlling equipment for energy generation units, e.g. distributed energy generation [DER] or load-side generation the energy generation units being or involving electric vehicles [EV] or hybrid vehicles [HEV], i.e. power aggregation of EV or HEV, vehicle to grid arrangements [V2G]
    • 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
    • Y04S40/00—Systems for electrical power generation, transmission, distribution or end-user application management characterised by the use of communication or information technologies, or communication or information technology specific aspects supporting them
    • Y04S40/12—Systems for electrical power generation, transmission, distribution or end-user application management characterised by the use of communication or information technologies, or communication or information technology specific aspects supporting them characterised by data transport means between the monitoring, controlling or managing units and monitored, controlled or operated electrical equipment
    • Y04S40/124—Systems for electrical power generation, transmission, distribution or end-user application management characterised by the use of communication or information technologies, or communication or information technology specific aspects supporting them characterised by data transport means between the monitoring, controlling or managing units and monitored, controlled or operated electrical equipment using wired telecommunication networks or data transmission busses

Definitions

  • This invention relates to power distribution systems. More particularly, the invention relates to methods and systems for mapping devices receiving power from an electrical grid.
  • the location in a network may be considered to have at least two independent components: (a) geo-spatial or physical location, and (b) electrical or schematic location.
  • the data used to define these components in the grid may be difficult to accurately determine, and effective correlation between the components may be difficult to achieve.
  • the system collects electricity usage from the consumer's meter and passes that information to a datacenter owned by the service provider or utility.
  • the network system that collects and transports this utilization data is commonly called an AMR/AMI system (automatic meter reading/advanced metering infrastructure).
  • Data collected from the meters may be transmitted via one or more data networks, using unlicensed wireless spectrum (e.g. WiFi, RF aggregators, etc.), licensed wireless spectrum (e.g. cellular telephony), or some form of wired network (e.g. private fiber optic links, conventional power line communications, etc.).
  • unlicensed wireless spectrum e.g. WiFi, RF aggregators, etc.
  • licensed wireless spectrum e.g. cellular telephony
  • wired network e.g. private fiber optic links, conventional power line communications, etc.
  • a method of assessing an electrical grid includes measuring an electrical signal at downstream locations in the grid and at one or more upstream locations in the grid.
  • the downstream locations include devices that receive electrical power from the grid.
  • a downstream current profile is determined for one or more of the downstream locations.
  • an upstream current profile is determined for one or more of the upstream locations.
  • the downstream current profiles and the upstream current profiles have characteristics produced by at least one of the devices.
  • the downstream current profile is compared to one or more of the upstream current profiles. Based on the comparison, a likely electrical location is determined for the device.
  • a grid map is generated based on comparisons between upstream current profiles and downstream current profiles.
  • a method of assessing an electrical grid includes determining an electrical location of one or more devices receiving electrical power from the grid and assessing a physical location for the devices. A map is generated based on the assessed physical locations for the devices and the electrical locations determined for the devices. In some embodiments, the electrical location for one or more particular devices is reconciled with the physical location for the device.
  • a system includes a processor and a memory coupled to the processor.
  • the memory program instructions are executable by the processor to implement assessing an electrical grid includes measuring an electrical signal at downstream locations in the grid and one or more upstream locations in the grid.
  • the downstream locations include devices that receive electrical power from the grid. Based on measurements in the downstream locations, a downstream current profile is determined for one or more of the downstream locations. Based on measurements in at least one of the upstream locations, an upstream current profile is determined for one or more of the upstream locations.
  • the downstream current profiles and the upstream current profiles have characteristics produced by at least one of the devices. For at least one of the devices, the downstream current profile is compared to one or more of the upstream current profiles. Based on the comparison, an electrical location is determined for the device.
  • a non-transitory, computer-readable storage medium includes program instructions stored thereon.
  • the program instructions implement assessing an electrical grid includes measuring an electrical signal at downstream locations in the grid and one or more upstream locations in the grid.
  • the downstream locations include devices that receive electrical power from the grid.
  • a downstream current profile is determined for one or more of the downstream locations.
  • an upstream current profile is determined for one or more of the upstream locations.
  • the downstream current profiles and the upstream current profiles have characteristics produced by at least one of the devices.
  • the downstream current profile is compared to one or more of the upstream current profiles. Based on the comparison, an electrical location is determined for the device.
  • a system includes a processor and a memory coupled to the processor.
  • the memory program instructions are executable by the processor to implement assessing an electrical grid includes determining an electrical location of one or more devices receiving electrical power from the grid and assessing a physical location for the devices.
  • a map is generated based on the assessed physical locations for the devices and the electrical locations determined for the devices.
  • the electrical location for one or more particular devices is reconciled with the physical location for the device.
  • a non-transitory, computer-readable storage medium includes program instructions stored thereon.
  • the program instructions implement assessing an electrical grid includes determining an electrical location of one or more devices receiving electrical power from the grid and assessing a physical location for the devices.
  • a map is generated based on the assessed physical locations for the devices and the electrical locations determined for the devices.
  • the electrical location for one or more particular devices is reconciled with the physical location for the device.
  • FIG. 1 illustrates network architecture for one embodiment of a power distribution system including a grid mapping computer.
  • FIG. 2 illustrates one example of signal anomalies in an electric distribution grid
  • FIG. 3 shows time-domain plot and spectrogram of a TV turn-on current transient.
  • FIG. 4 illustrates a generic architecture of an AMR/AMI system.
  • FIG. 5 illustrates current injected upstream in a power distribution system.
  • FIG. 6 illustrates one embodiment of assessing an electrical grid that includes determining an electrical location of devices on the grid using upstream and downstream current profiles.
  • FIG. 7 illustrates one embodiment of assessing an electrical grid using a combination of electrical location and physical location.
  • FIG. 8 illustrates one embodiment of system including a substation with feeders distributing electricity to a neighborhood and a grid mapping computer at the substation.
  • FIG. 9 illustrates a computer system that may be used to implement mapping of devices on an electrical grid in various embodiments.
  • the word “may” is used in a permissive sense (i.e., meaning having the potential to), rather than the mandatory sense (i.e., meaning must).
  • the words “include”, “including”, and “includes” mean including, but not limited to.
  • a "grid” or “electrical grid” is an interconnected network for delivering electricity.
  • grid location refers to a location that reconciles a device's geo-spatial location and its electrical location.
  • a system provides up-to-date, immediately validated information of the feeder, lateral, and phase for grid-resident devices.
  • the information provides feedback to a utility company regarding grid attributes, such as the aggregate loading of specific circuits or phases, the location and health of sub-circuits and devices, and the presence or absence of load activity.
  • the information includes large, mobile source/load devices such as electric vehicles.
  • physical location and electrical location of grid- resident devices are automatically reconciled. A map of the grid may be generated based on the reconciled locations. The map may be updated on a continuous or periodic basis.
  • the system is passive, in that it does not require additional hardware or communication signals to be introduced to grid infrastructure.
  • the techniques are implemented using existing smart meter data acquisition facilities and computer/software processing at the utility's datacenter.
  • a system automatically resolves the geo-spatial location and electrical location of devices on a grid.
  • An up-to-date grid map may be maintained without manual intervention (even, for example, in the face of multiple changes in downstream devices or grid architecture). For example, the installation of new meters may automatically refresh the grid map via communication with the central office, or the re-connection of upstream links after an outage would be automatically reconciled in the centrally-located "grid map".
  • additional communication systems such as smart transformers, voltage regulators, and the like, augment a grid map via targeted or scheduled updates.
  • an electrical map of an electrical power system includes knowledge of the specific feeder, lateral, and electrical phase where particular devices resides.
  • feeders are typically 3-phase, medium-voltage links (13-30kV) which begin at the substation bus and traverse several miles of local distribution territory.
  • feeders can be 50 miles in length and may service hundreds of loads.
  • feeders may be 5-10 miles in length, and may service several thousand loads.
  • Lateral lines branch off from a feeder at downstream locations, and may be 3-phase or 1- phase links which terminate in a distribution transformer.
  • Distribution transformers typically service 3-10 loads, where a load may be a residence or business with an electrical meter. Electrical service to a residence may be, as an example, a single-phase link taken from the 3-phase feeder which began at the substation servicing the residence.
  • the feeder, lateral, and phase data for a particular load or device may be dependent on the actual physical construction of the distribution network at any point in time.
  • Grid mapping may include correlation between physical & electrical activity at the substation and physical and electrical activity at the load.
  • correlation/coherence of electrical signals is used to determine the exact point (e.g. feeder/phase/lateral) where an electrical disturbance has occurred, and the proximity of the device that may have caused the disturbance.
  • Electrical location data may be used in combination with other geo-spatial information to determine a set of electrical and spatial coordinates of a disturbance location and one or more devices associated with the disturbance.
  • discrepancies between physical and electrical locations of grid resident devices are reconciled using data generated from grid maps.
  • FIG. 1 illustrates network architecture for one embodiment of a power distribution system including a grid mapping computer.
  • System 100 includes grid 102, load facilities 104, grid mapping system 105, and network 106.
  • Grid 102 includes generating station 107, generating step up transformer 108, and substation 1 10.
  • Power from generating station is power transmission lines 1 12 (long-dashed lines) and power distribution lines 1 14 (short-dashed lines).
  • Load facilities 104 include transmission customer facility 1 16, subtransmission customer facility 118, primary customer facility 120, and secondary customer facility 122.
  • Each of transmission customer facility 116, subtransmission customer facility 1 18, primary customer facility 120, and secondary customer facility 122 may include devices that receive electrical power from grid 102, such as industrial equipment, power transmission equipment, instrumentation, appliances, lights, computing systems, and HVAC systems.
  • Grid mapping system 105 may include one or more computing systems that acquire information from devices and power transmission components over network 106.
  • Devices at load facilities 104 may include instrumentation, such as current meters, that provide data for generating current profiles to be used in grid mapping.
  • grid mapping system 105 is separate from the power transmission elements of grid 102 and load facilities 105.
  • a grid mapping system may, however, be provided in one or more elements of a grid, such as one or more substations.
  • a grid mapping computer is included at each step down transformer substation in a grid.
  • a single substation may service a distribution grid composed of several thousand loads of various sizes.
  • Substation 1 10 may be a distribution point for medium voltage (MV) electrical service, which has been converted from a high voltage (HV) transmission/generating plant.
  • MV medium voltage
  • HV high voltage
  • LV low voltage
  • the LV power is used in households, commercial buildings, etc.
  • a distribution grid such as grid 102, is a complex, time-varying system.
  • the spectra of voltage, current, and impedance all change in real time based on load and activity profiles.
  • the signal environment of the LV power line may be very "dirty".
  • the signal environment may contain, for example, a large voltage at the fundamental frequency (50Hz in Europe, etc. or 60Hz in the U.S.) as well as odd and even harmonics of this frequency.
  • the LV system may also contain non-stationary noise from other connected loads and sources. For example, large electric motors create anomalies at collections of frequencies related to their angular velocity, or large appliances create correlated noise bursts during specific operational events.
  • FIG. 2 illustrates one example of signal anomalies in an electric distribution grid.
  • Plot 126 shows the time and plot 127 shows frequency (magnitude) representation of the turn-on current transient of a television set.
  • the highlighted signal in the spectral plot is the anomaly, which, due to system characteristics, is recursively replicated at 120 Hz spacings.
  • the noise burst shown in FIG. 2 reflects the turn-on current transient of a television set, as seen from the electric meter. In this case, time-based and frequency-based artifacts may be evident for several seconds as the power supply of the appliance boots up and the system begins operation.
  • FIG. 3 shows time-domain plot and spectrogram of a TV turn-on current transient.
  • a spectrogram is used to jointly analyze time and frequency anomalies.
  • bottom section 128 of the figure (a "spectrogram"), the spectrum of the unfiltered current signal is shown on the vertical axis between 0 Hz and 2000 Hz, and the signal evolves over time along the horizontal axis for roughly 13 seconds.
  • the time-domain perspective of the signal is shown in top section 130.
  • the TV set was turned on ( ⁇ 0 sec), allowed to stabilize (2-10 sec), and then turned off ( ⁇ 11 sec).
  • the bottom section of the figure shows stable even-harmonic features during the time that the TV is on and the lack of these same features during the time that the TV is off. Referring to FIG.
  • the instantaneous spectral shape of the features is evident (and highlighted) as two closely-spaced peaks near 120 Hz and -25 dB down from the 60 Hz fundamental and 3rd harmonic.
  • a collection of specific features of the time envelope and spectral envelope of these anomalies may be used as a digital fingerprint of the power supply for the TV system.
  • the even harmonics contain a clearly recognizable and stable pattern which is noted on in FIG. 3 by artifact 132.
  • the TV current transient exhibits multiple temporal frequency artifacts, the most prominent of which is a downward-sweeping chirp near the beginning of the excitation period. This feature is labeled artifact 132.
  • Each of these artifacts contains consistent and recognizable features. Further, since the turn-on transient is created by the inrush of current while the system's power supply "boots up" and engages other system components, the features of this current disturbance travel backwards along the power line, toward the substation.
  • the signal features can be acquired by an upstream device, such as a conventional AMI meter, analyzed, feature- extracted, compressed, and transmitted to the service provider's datacenter for analysis and comparison with attenuated and obscured current disturbances which are similarly acquired at the substation or other upstream location.
  • an upstream device such as a conventional AMI meter
  • the TV data of FIG. 2 and FIG. 3 may be collected upstream of the actual location of the system. This upstream flow of electrical current allows a unique signal, originating from a given meter, to be detected at the serving substation. Only signals with frequency content which passes through all the transformers on the feeder are detectable, since higher frequencies are filtered out by the inherent low-pass nature of large series inductors, such as transformers.
  • the TV data of FIG. 2 and FIG. 3 is dominated by low-frequency features or artifacts, such as the odd harmonics at multiples of 120Hz (artifact 131) and the "chirp" (artifact 132) which contains significant activity and amplitude below 1000Hz.
  • FIG. 4 illustrates a generic architecture of an AMR/AMI system.
  • HV is converted to MV through step-down transformers that lower the voltage but increase the current.
  • downstream distribution transformers reduce the voltage from several thousand volts to several hundred volts. This process maintains constant power, and as a result downstream current must increase. Looking at this system backwards from the endpoint (smart meter) toward the substation, disturbances in the LV-side current that flows upstream must be reduced by the aggregate turns-ratio of the intervening transformers on the feeder.
  • FIG. 5 illustrates current injected upstream in a power distribution system.
  • System 180 includes LV system 182, MV system 184, and substation 186.
  • This physical reality causes the distribution grid to behave as a stable and predictable current attenuator for current disturbances which flow upstream, or from the meter toward the substation.
  • a substation that operates at an MV of 38.4 kV and delivers 120V to the consumer has an effective turns-ratio of 1 :320. So, a current disturbance created at the meter would show up at the substation with amplitude of approximately 0.3% of its initial value, assuming no other losses.
  • a current disturbance with amplitude of 10 A at the meter may be detectable at the substation with amplitude of approximately 31 mA. In this fashion, recognizable features of current perturbations in the distribution grid propagate towards the substation.
  • frequency content of the disturbance provides characteristics for identifying a device.
  • low- frequency signals (below 400 Hz) may be swamped by the low-order power line harmonics and resonances from lumped reactive elements on the line, and higher frequency signals (above 3000 Hz) may be filtered out by the aggregate low-pass effect of power transformers and other system characteristics.
  • current disturbances with frequency content between 200 Hz and 3000 Hz may be transported directly and predictably towards to substation bus, through intervening distribution transformers, and in spite of additive or time-variant noise due to other grid-resident devices.
  • current disturbances detected at the substation are used in conjunction with features of current disturbances observed at the meter (or other endpoint) to determine the electrical location of grid-resident devices.
  • the correlation/coherence of signals and/or signal characteristics at both points produces a unique feature set which can be used to determine which feeder, phase, and lateral to which the device is attached.
  • this information is used in conjunction with geo-spatial information from the set of meters which initially detected the disturbance, the grid location (including electrical and spatial location) of the device which created the disturbance can be extracted.
  • each of the devices on the grid may create a composite signal that is dependent on its location.
  • a plurality of devices on the grid may create a superposition of their unique electrical signals that is dependent on their shared electrical location.
  • the direct path from the meter location to the substation must produce the best correlation of signals.
  • Crosstalk signals from feeder to feeder, or phase to phase lines will experience phase and time shifts due to the extra electrical length and additional transformer couplings (on the high side). This phenomenon may reduce the effective correlation between the signals, and emphasizes the correct electrical location of the device.
  • the line fundamental is 120-degrees out of phase on each per-phase link.
  • the feature correlation task can include a best-fit classification problem over a time-varying channel.
  • FIG. 6 illustrates one embodiment of assessing an electrical grid that includes determining an electrical location of devices on the grid using upstream and downstream current profiles.
  • an electrical signal at one or more downstream locations in the grid is measured.
  • the downstream locations include devices that receive electrical power from the grid.
  • downstream current profiles for downstream locations are determined based on measurements in downstream locations.
  • the downstream current profiles have characteristics produced by at least one of the devices.
  • an electrical signal at one or more upstream locations in the grid is measured.
  • the upstream locations are in the power distribution system upstream from one or more of the downstream locations.
  • upstream current profiles are determined for the upstream locations.
  • the upstream current profiles have characteristics produced by the devices in the downstream locations.
  • Upstream current profiles and downstream current profiles may reflect characteristics of load devices at a downstream location. Characteristics may be, for example, such as the characteristics of the signal described above relative to FIGS. 2 and 3. In some embodiments, patterns of current profiles over time may be used for grid mapping. For example, a consumer may exhibit a pattern of turning on a washing machine at a certain time of day every day of the week. [ 0053 ] At 208, some or all of the downstream current profiles are compared to some or all of the upstream current profiles. At 210, electrical locations of the devices in the downstream locations are determined based at least in part on the comparisons. In some embodiments, a map is generated from the determined electrical locations.
  • FIG. 7 illustrates one embodiment of assessing an electrical grid using a combination of electrical location and physical location.
  • electrical locations of devices receiving electrical power from a grid are determined. Electrical locations of devices may be determined, for example, as described above relative to FIG. 6.
  • physical locations are assessed for devices receiving power from the grid.
  • the location may be assessed, for example, using GPS data from GPS-enabled instruments at the location of the devices, or from manually generated logs.
  • FIG. 8 illustrates one embodiment of a system including a substation with feeders distributing electricity to a neighborhood and a grid mapping computer at the substation.
  • System 240 includes substation 242, phase distribution systems 244, and devices 246 in neighborhood 248.
  • Substation 242 supplies power to devices 246.
  • Substation 242 includes bus bar 250, feeder lines 252, transformer 254, and grid mapping computer 256.
  • Current transformers (CT) 258 are installed to measure the current signals present on each feeder.
  • Current waveforms may be sampled, time-stamped, and stored in grid mapping computer 256.
  • the grid mapping computer is at a location other than a substation, such as a service provider's data center.
  • Devices 246 may be connected to smart meters 260.
  • the local current signal (or "downstream current profile", DCP) may be sampled, time-stamped, processed, and transmitted along with the AMR/AMI meter data to the utility datacenter via network 262.
  • Grid mapping computer 256 stores the UCPs also receives the DCPs from each meter. By aligning time stamps on the DCP and UCP data, the substation computer can compare all permutations of feeder and phase between the UCPs and DCPs. The resulting best match between DCP and UCP is flagged as the actual feeder/phase where the endpoint meter is located.
  • a maximization computation may be performed over a set of signal features. For example, automatic target recognition systems use similar processing to extract specific target locations from audio/video data via a known feature vector for each target of interest.
  • a system performs high-sampling-rate acquisition of DCP signals and transmission of uncompressed DCP signals to an upstream location for comparison with multiple UCPs.
  • This processing may establish an estimate for presence/absence of the downstream device (represented by its DCP) in the aggregated current profiles of several feeders (the UCPs).
  • Cross-correlation and time-coherence between a specific, uncompressed DCP and multiple UCPs may be determined and/or assessed.
  • High-rate acquisition and transmission of DCP data from multiple meters may, however, not be feasible using conventional AMR/AMI network infrastructure.
  • the uncompressed bandwidth required for transmission of each DCP would exceed 320kbps.
  • This data bandwidth may not be supported within existing remote metering infrastructure networks, particularly if thousands of meters were attempting to transmit usage data in addition to DCP profiles.
  • some form of (lossy) compression of the DCP prior to transmission and processing at the upstream location may be performed.
  • compression or feature extraction operations are performed on DCP data (which is subject to the upstream fidelity criteria). Compression or feature extraction may allow for a smaller data transmission bandwidth between downstream and upstream locations. Compression methods or feature extraction methods may be implemented at the downstream meters to preserve transmission bandwidth while simultaneously preserving recognizable features of the DCP.
  • Processing of the DCP prior to transmission may include a data compression or feature extraction operation. This operation may produce a set of features or compressed data which, when processed by upstream devices and compared with UCP data, indicate the presence or absence of a downstream device.
  • a reduced- fidelity representation of a signal is captured, extracted, and stored. Then, the feature vector which uniquely identifies the signal is compared to high-fidelity versions of a candidate signal to create an indication of matching or similarity.
  • techniques for DCP processing may include lossless data compression (e.g. LZW or other variant), transform coding (e.g.
  • FFT/DCT/KLT FFT/DCT/KLT
  • parametric modeling e.g. AR/MA models, eigenvalue decomposition, signal-space techniques
  • lossy compression including scalar/vector quantization or signal-space representations optimizing a weighted time domain or frequency- domain fidelity criterion.
  • the upstream system may consume DCP data from all meters without exceeding system transmission capacity or interfering with bandwidth dedicated for AMR/ AMI links.
  • some feature extraction using raw sampled DCP data may be used at the meter to reduce the size of the DCP data set to be transmitted.
  • the compression/extraction operations retain sufficient information in the signal for the mapping operation via multiple DCP and UCP samples.
  • Transport of encoded, compressed, feature-extracted DCP data can be performed in-band using power line communications techniques intrinsic to grid infrastructure, or it can be performed out-of-band using communications infrastructure that is extrinsic to grid infrastructure.
  • embodiments described herein do not require communication via the power line (for example, from the meter to the substation). As such, no large amplifiers or coupling circuits are needed inside the smart meter itself. Thus most, if not all, of the required circuitry may already available inside a revenue-grade meter.
  • the DCP detected at the meter is sampled, processed for compression or feature extraction, and packaged for upstream transmission as part of the AMR/AMI meter data.
  • the DCP data from each meter can be aggregated at the utility central office or datacenter where the AMR/AMI data is received. In this fashion, computer hardware/software in the datacenter can analyze the UCP and DCP data and estimate each meter's grid location. The estimated grid location data is then stored in the utility's database updating their electrical grid map.
  • a benefit of the approach described above is that electrical mapping may be done at a very slow rate. In some cases, mapping only needs to be performed once, and then periodic updates can happen much later.
  • the DCP data can trickle out over the AMR/AMI wireless link for later analysis and registration using UCP information. Further, location errors due to DCP data snapshots can easily be corrected over time by keeping statistics on all computed locations and maximizing a likelihood function for meter or device location updates. In some cases, current disturbances detected at the meter and the substation feeder may be different, and the grid location computed/estimated for specific meters may be anomalous. However, errors in calculations may be automatically corrected as additional DCP and UCP data is collected and analyzed.
  • Performing advanced system-level analysis- such as power outage detection, power theft, power quality, or the like may require faster updates of the DCP data, and repeated comparisons with UCP data.
  • data compression or sub-sampled DCP data sets may be used to mitigate any wireless capacity issues in a mesh network or other capacity-limited AMR/ AMI system.
  • downstream current profiles are compared with the superposition of current profiles at the substation (UCP).
  • Noise current and perturbations due to active devices on the grid may be detected at the substation.
  • the electrical location of each meter may be determined by comparing passive line data from the meter location (DCP) against substation feeder lines (UCP).
  • passive line data is compared to all substation feeder lines in the system. Grid characteristics may change over time, producing multivariate non-stationary noise in the signal space of the grid. Temporal comparisons of data may be performed at both the DCP and UCP.
  • feature extraction or compression of the sampled data at the meter or downstream location is used to reduce the size of the transmitted DCP. This may allow the method to scale easily, given that it must service a large number of meters (and other devices) connected to each substation. GPS data from each smart meter is already available to assist in the reconciliation of geo-spatial location with electrical location.
  • the DCP feature vector collected at each smart meter may be sent to the utility's datacenter through the existing AMR/ AMI wireless network- utilizing the already- installed infrastructure. Having special equipment that may be required for grid mapping at the substation-level (acquisition system, GPS, network, etc.) may be cost effective, since one substation typically services thousands of loads. In such a centralized architecture, computational resources in the utility datacenter may perform all the DCP/UCP comparison calculations for each meter and feeder in the utility's service territory.
  • FIG. 9 illustrates a computer system that may be used to implement mapping of devices on a grid in various embodiments.
  • Computer system 900 includes one or more processors 902, system memory 904, and data storage device 906.
  • Program instructions may be stored on system memory 904.
  • Processors 902 may access program instructions on system memory 904.
  • Processors 902 may access data storage device 906.
  • Users may be provided with information from computer system 900 by way of monitor 908. Users interact with computer system 900 by way of I O devices 910.
  • An I/O device 910 may be, for example, a keyboard or a mouse.
  • Computer system 900 may include, or connect with, other devices 916.
  • Elements of computer system 900 may connect with other instrumentation 916 (for example, smart meters, current transformers) by way of network 914 via network interface 912.
  • Network interface 912 may be, for example, a network interface card.
  • messages are exchanged between computer system 900 and other devices 916, for example, via a transport protocol, such as internet protocol.
  • Computer systems may, in various embodiments, include components such as a CPU with an associated memory medium such as Compact Disc Read-Only Memory (CD-ROM).
  • the memory medium may store program instructions for computer programs.
  • the program instructions may be executable by the CPU.
  • Computer systems may further include a display device such as monitor, an alphanumeric input device such as keyboard, and a directional input device such as mouse.
  • Computing systems may be operable to execute the computer programs to implement computer- implemented systems and methods.
  • a computer system may allow access to users by way of any browser or operating system.
  • Embodiments of a subset or all (and portions or all) of the above may be implemented by program instructions stored in a memory medium or carrier medium and executed by a processor.
  • a memory medium may include any of various types of memory devices or storage devices.
  • the term "memory medium” is intended to include an installation medium, e.g., a Compact Disc Read Only Memory (CD-ROM), floppy disks, or tape device; a computer system memory or random access memory such as Dynamic Random Access Memory (DRAM), Double Data Rate Random Access Memory (DDR RAM), Static Random Access Memory (SRAM), Extended Data Out Random Access Memory (EDO RAM), Rambus Random Access Memory (RAM), etc.; or a non-volatile memory such as a magnetic media, e.g., a hard drive, or optical storage.
  • the memory medium may comprise other types of memory as well, or combinations thereof.
  • the memory medium may be located in a first computer in which the programs are executed, or may be located in a second different computer that connects to the first computer over a network, such as the Internet. In the latter instance, the second computer may provide program instructions to the first computer for execution.
  • the term "memory medium" may include two or more memory mediums that may reside in different locations, e.g., in different computers that are connected over a network.
  • a computer system at a respective participant location may include a memory medium(s) on which one or more computer programs or software components according to one embodiment may be stored.
  • the memory medium may store one or more programs that are executable to perform the methods described herein.
  • the memory medium may also store operating system software, as well as other software for operation of the computer system.
  • the memory medium may store a software program or programs operable to implement embodiments as described herein.
  • the software program(s) may be implemented in various ways, including, but not limited to, procedure-based techniques, component-based techniques, and/or object-oriented techniques, among others.
  • the software programs may be implemented using ActiveX controls, C++ objects, JavaBeans, Microsoft Foundation Classes (MFC), browser-based applications (e.g., Java applets), traditional programs, or other technologies or methodologies, as desired.
  • a CPU executing code and data from the memory medium may include a means for creating and executing the software program or programs according to the embodiments described herein.

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  • Remote Monitoring And Control Of Power-Distribution Networks (AREA)

Abstract

L'invention concerne un procédé d'évaluation d'un réseau électrique qui comprend mesurer un signal électrique à des emplacements en amont et en aval dans le réseau. Les emplacements en aval comprennent des dispositifs qui reçoivent de l'énergie électrique à partir du réseau. Sur la base de mesures dans les emplacements situés en aval, un profil de courant en aval est déterminé pour les emplacements situés en aval. Sur la base de mesures effectuées dans au moins l'un des emplacements situés en amont, un profil de courant en amont est déterminé pour les emplacements en amont. Les profils de courant en aval et les profils de courant en amont ont des caractéristiques produites par au moins l'un des dispositifs. Pour au moins l'un des dispositifs, le profil de courant en aval est comparé à un ou plusieurs des profils de courant amont. Sur la base de cette comparaison, un emplacement électrique est déterminé pour le dispositif. Dans certains modes de réalisation, une carte de réseau est générée sur la base des comparaisons entre les profils de courant en amont et les profils de courant en aval.
PCT/US2015/014603 2014-02-05 2015-02-05 Cartographie d'emplacements de dispositifs de réseau en utilisant des caractéristiques des perturbations de courant observées de manière passive WO2015120141A1 (fr)

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