WO2015120141A1

WO2015120141A1 - Location mapping of grid devices using features of passively-observed current disturbances

Info

Publication number: WO2015120141A1
Application number: PCT/US2015/014603
Authority: WO
Inventors: James SHIMA; Stan Mcclellan
Original assignee: Texas State University
Current assignee: Texas State University
Priority date: 2014-02-05
Filing date: 2015-02-05
Publication date: 2015-08-13
Anticipated expiration: 2016-08-05

Abstract

A method of assessing an electrical grid includes measuring an electrical signal at downstream and upstream locations 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 the downstream locations. Based on measurements in at least one of the upstream locations, an upstream current profile is determined for 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. In some embodiments, a grid map is generated based on comparisons between upstream current profiles and downstream current profiles.

Description

TITLE: LOCATION MAPPING OF GRID DEVICES USING FEATURES OF

PASSIVELY-OBSERVED CURRENT DISTURBANCES BACKGROUND Field

[ 0001] 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.

Description of the Related Art

[ 0002 ] Establishing the location of devices in an electric power distribution network, such as the electric power distribution network known as "the grid", is an important capability. 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.

[ 0003 ] For example, even in today's "Smart Grid", utility companies may be unable to definitively map a device such as a "smart meter" to an exact electrical location in the distribution grid. Further, the geo-spatial location of grid resident devices (which can be resolved via GPS, etc.) may not accurately reflect their electrical location.

[ 0004 ] Conventional devices downstream from a substation are deployed in a fixed location, on a specific feeder, lateral, and phase. However, deviations between the initial design of the system ("as-designed"), the initial deployment of the system ("as-built"), and the present configuration of the system ("as-modified") often create ambiguities between the geo- spatial and electrical location of particular grid-resident devices. These ambiguities are problematic, and can be difficult to resolve without significant manual intervention and expense.

[ 0005 ] From the utility's perspective, "smart meters" allow for remote billing and automatic, network-based retrieval of electrical meter data. This type of Automated Meter Infrastructure ("AMI") is more economical than periodic manual reading of electric meters. However, smart meters typically rely on an external network such as cellular telephony to transport meter data to a central location. Here, we call this an "extrinsic" network. The use of such extrinsic networks may result in significant ambiguity between the physical location of the meter and its electrical location (i.e. feeder, lateral, phase).

[ 0006 ] In some deployments of a smart grid system, 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.). In this paradigm, the physical location of the meter is assumed to stay constant after installation, and the electrical location of the meter is derived from static logs and schematic drawings. Such logs and drawings may, however, be incomplete or inaccurate. [ 0007 ] In some cases, the geo-spatial location and electrical location of each meter on the grid is logged during installation, resulting in a static or "as-built" map of the grid. However, the upstream electrical connections are often changed during outages or seasonal load balancing, destroying important information regarding actual grid connectivity, and resulting in an "as-modified" configuration. Furthermore, older or manual logs of equipment location and circuit architecture may have been inaccurate, resulting in differences between the "as-designed" and "as-built" perspectives. This situation is often exacerbated by the realities of several subsequent "as-modified" conditions. Additionally, in the present model of system management for the distribution grid, service failures are often determined primarily via customer feedback, such as phone calls from customers reporting outages. Utility technicians must then search for the area where the problem occurred by correlating customer feedback with sometimes outdated or otherwise inaccurate schematics of the local grid.

SUMMARY

[ 0008 ] In an embodiment, 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. 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, a likely electrical location is determined for the device. In some embodiments, a grid map is generated based on comparisons between upstream current profiles and downstream current profiles.

[ 0009 ] In some embodiments, 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.

[ 0010 ] In an embodiment, 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.

[ 0011] In an embodiment, 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. 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.

[ 0012 ] In an embodiment, 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. In some embodiments, the electrical location for one or more particular devices is reconciled with the physical location for the device.

[ 0013 ] In an embodiment, 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. In some embodiments, the electrical location for one or more particular devices is reconciled with the physical location for the device.

BRIEF DESCRIPTION OF THE DRAWINGS

[ 0014 ] FIG. 1 illustrates network architecture for one embodiment of a power distribution system including a grid mapping computer.

[ 0015 ] FIG. 2 illustrates one example of signal anomalies in an electric distribution grid,

[ 0016 ] FIG. 3 shows time-domain plot and spectrogram of a TV turn-on current transient.

[ 0017 ] FIG. 4 illustrates a generic architecture of an AMR/AMI system.

[ 0018 ] FIG. 5 illustrates current injected upstream in a power distribution system. [ 0019 ] 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.

[ 0020 ] FIG. 7 illustrates one embodiment of assessing an electrical grid using a combination of electrical location and physical location.

[ 0021] 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.

[ 0022 ] FIG. 9 illustrates a computer system that may be used to implement mapping of devices on an electrical grid in various embodiments. [ 0023 ] While the invention is described herein by way of example for several embodiments and illustrative drawings, those skilled in the art will recognize that the invention is not limited to the embodiments or drawings described. It should be understood, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims. The headings used herein are for organizational purposes only and are not meant to be used to limit the scope of the description or the claims. As used throughout this application, 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). Similarly, the words "include", "including", and "includes" mean including, but not limited to.

DETAILED DESCRIPTION OF EMBODIMENTS

[ 0024 ] As used herein, in the context of power distribution, one component is

"downstream" from another component if the one component receives power from the other component or is at a lower level in a power distribution system than the other component. [ 0025 ] As used herein, a "grid" or "electrical grid" is an interconnected network for delivering electricity.

[ 0026 ] As used herein, "grid location" refers to a location that reconciles a device's geo-spatial location and its electrical location. [ 0027 ] As used herein, in the context of power distribution, one component is

"upstream" from another component if the one component supplies power to the other component or is at a higher level in a power distribution system than the other component.

[ 0028 ] In some embodiments, 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. In some embodiments, the information includes large, mobile source/load devices such as electric vehicles. [ 0029 ] In some embodiments, 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. In some embodiments, the system is passive, in that it does not require additional hardware or communication signals to be introduced to grid infrastructure. In some embodiments, the techniques are implemented using existing smart meter data acquisition facilities and computer/software processing at the utility's datacenter.

[ 0030 ] In some embodiments, 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". In some embodiments, additional communication systems, such as smart transformers, voltage regulators, and the like, augment a grid map via targeted or scheduled updates. [ 0031] In some embodiments, an electrical map of an electrical power system includes knowledge of the specific feeder, lateral, and electrical phase where particular devices resides. For example, feeders are typically 3-phase, medium-voltage links (13-30kV) which begin at the substation bus and traverse several miles of local distribution territory. In rural settings, feeders can be 50 miles in length and may service hundreds of loads. In urban settings, 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.

[ 0032 ] In some embodiments, 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. In some embodiments, discrepancies between physical and electrical locations of grid resident devices are reconciled using data generated from grid maps.

[ 0033 ] 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. [ 0034 ] 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.

[ 0035 ] For illustrative purposes, 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. In some embodiments, a grid mapping computer is included at each step down transformer substation in a grid.

[ 0036 ] For illustrative purposes, only a single substation, transmission customer facility 1 16, subtransmission customer facility 1 18, primary customer facility 120, and secondary customer facility 122 are shown in grid 102. A grid may, however, have any number of substations any number of various customer facilities and load devices.

[ 0037 ] A single substation, as shown by the junction between power transmission lines 1 12 (long-dashed lines) and power distribution lines 114, 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. The MV may be distributed over the local distribution grid, and converted to low voltage (LV) at the endpoints. The LV power is used in households, commercial buildings, etc.

[ 0038 ] 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. As a result, 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.

[ 0039 ] 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. [ 0040 ] FIG. 3 shows time-domain plot and spectrogram of a TV turn-on current transient. In FIG. 3, a spectrogram is used to jointly analyze time and frequency anomalies. In 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. During this 13-second period, 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. 2, 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.

[ 0041] In the case of the TV power supply, the even harmonics contain a clearly recognizable and stable pattern which is noted on in FIG. 3 by artifact 132. In addition to artifact 131, 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. In the process, 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.

[ 0042 ] In some embodiments, current disturbances that occur downstream from the substation (e.g. at the meter) are detected upstream at the substation. For example, 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. For example, 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.

[ 0043 ] FIG. 4 illustrates a generic architecture of an AMR/AMI system. System

150 includes power generation system 152, transmission systems 154, distribution system 156, and consumption devices 158. Data aggregator 160 acquires information from consumption devices 158. Data aggregator 160 transmits information to cellular devices 162 to central office/billing 164. At the substation, HV is converted to MV through step-down transformers that lower the voltage but increase the current. As electrical power is distributed through the feeders and to the loads, 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.

[ 0044 ] 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. For example, 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. Thus, 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.

[ 0045 ] Signal propagation as described above is subject to additional noise in the system and the native attenuation characteristic of the distribution transformers. This phenomenon is true for current signals which are purposefully injected (such as communication signals), and it is true for current disturbances which are caused natively or accidentally by other grid-resident devices. In some cases, low-level signals with recognizable features may be readily detectable at the substation. Current disturbances with attenuation over 99% of the initial amplitude may, for example, be detected at the substation.

[ 0046 ] In various embodiments, frequency content of the disturbance provides characteristics for identifying a device. On any given distribution grid, there may be a time- varying window of frequencies that are amenable to good transmission. For example, 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. However, 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.

[ 0047 ] In some embodiments, 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. When 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.

[ 0048 ] In this approach, 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. Thus, 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. Thus, in this example, the feature correlation task can include a best-fit classification problem over a time-varying channel.

[ 0049 ] 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. At 200, 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. [ 0050 ] At 202, 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.

[ 0051] At 204, 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. At 206, upstream current profiles are determined for the upstream locations. The upstream current profiles have characteristics produced by the devices in the downstream locations.

[ 0052 ] 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.

[ 0054 ] FIG. 7 illustrates one embodiment of assessing an electrical grid using a combination of electrical location and physical location. At 220, 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.

[ 0055 ] At 222, 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.

[ 0056 ] At 224, a map is generated based in part on assessed physical locations for the devices and electrical locations determined for the devices. In some embodiments, the map is determined by reconciling information about physical location and electrical location for particular devices receiving power from the grid. [ 0057 ] 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. [ 0058 ] 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 (or "upstream current profiles", UCP) may be sampled, time-stamped, and stored in grid mapping computer 256. In certain embodiments, the grid mapping computer is at a location other than a substation, such as a service provider's data center.

[ 0059 ] Devices 246 may be connected to smart meters 260. At each of smart meter 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.

[ 0060 ] In certain embodiments, 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. For example, assuming a 20kHz sampling rate at the meter with 16-bit resolution per-sample, 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. As a result, to perform the described grid mapping operation using DCP data, some form of (lossy) compression of the DCP prior to transmission and processing at the upstream location may be performed.

[ 0061] In various embodiments, 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.

[ 0062 ] 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. In some embodiments, 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. In the context of grid mapping and detection of current disturbances, techniques for DCP processing (or feature extraction) may include lossless data compression (e.g. LZW or other variant), transform coding (e.g. FFT/DCT/KLT), or other dimensionality reduction via parametric modeling (e.g. AR/MA models, eigenvalue decomposition, signal-space techniques) followed by 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. Thus, 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.

[ 0063 ] 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. As a result, 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. In one implementation, 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.

[ 0064 ] 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.

[ 0065 ] 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. Over time, an accurate grid location of each device may emerge from the periodic mapping computations. As such, developing complex models for compression or feature extraction schemes, based on grid topology, are unnecessary. Error correction via periodic mappings inherently improves the probability of detection for each device's grid location.

[ 0066 ] The approach may lend itself to a self-organizing network topology.

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. In these cases, 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.

[ 0067 ] In some embodiments, downstream current profiles (DCP) 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). In some embodiments, 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.

[ 0068 ] In some embodiments, 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.

[ 0069 ] 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.

[ 0070 ] Applications that may implement grid mapping, in various embodiments, include energy management systems (residential, commercial, or industrial), smart metering applications, manufacturing (for example, semiconductor manufacturing), and home area networks (including, for example, enhanced communication with smart appliances in the home). In some embodiments, a power distribution system provides power to one or more systems using the grid mapping. The grid mapping may be used to control one or more operating parameters of the power distribution system. Operating parameters may be configured or modified based on the grid mapping information. In some embodiments, one or more components of the power distribution system are serviced (e.g., replaced or repaired) based in on the grid mapping. [ 0071] 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. In some embodiments, messages are exchanged between computer system 900 and other devices 916, for example, via a transport protocol, such as internet protocol.

[ 0072 ] 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.

[ 0073 ] 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. In addition, 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. In some embodiments, 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. For example, 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.

[ 0074 ] 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. For example, 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.

[ 0075 ] Further modifications and alternative embodiments of various aspects of the invention may be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Methods may be implemented manually, in software, in hardware, or a combination thereof. The order of any method may be changed, and various elements may be added, reordered, combined, omitted, modified, etc. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims.

Claims

WHAT IS CLAIMED IS:

1. A method of assessing an electrical grid, comprising: measuring an electrical signal at one or more downstream locations in the grid, wherein at least one of the downstream locations includes one or more devices that receive electrical power from the grid; measuring an electrical signal at one or more upstream locations in the grid, wherein the upstream location is in the power distribution system upstream from the one or more downstream locations; determining, based on measurements in at least one of the downstream locations, a

downstream current profile for at least one of the downstream locations, wherein the downstream current profile has characteristics produced by at least one of the devices; determining, based on measurements in at least one of the upstream locations, an

upstream current profile for at least one of the upstream locations, wherein the upstream current profile has characteristics produced by at least one of the devices; comparing at least one of the downstream current profiles to at least one of the upstream current profiles; and determining, based at least in part on the comparisons, an electrical location of at least one of the devices in the downstream locations.

2. The method of claim 1, further comprising generating a map of the grid based at least in part on at least one determined electrical location of at least one devices.

3. The method of claim 1, further comprising determining a correlation between a physical location and an electrical location for at least one of the devices.

4. The method of claim 3, wherein the correlation is based at least in part on geo-spatial information of at least one of the devices.

5. The method of claim 3, wherein the correlation is based at least in part on GPS data

acquired for at least one the devices over a communication network.

6. The method of claim 3, wherein the correlation is based at least in part on location

information logged by one or more persons about a physical location.

7. The method of claim 1, further comprising generating a map of the grid based at least in part on at least one determined electrical locations of a plurality of devices receiving power from the grid.

8. The method of claim 1, wherein the electrical grid is a utility power system supplying power to consumers, wherein the downstream current profiles and the upstream current profiles include characteristics produced by at least one consumer device receiving power from the grid.

9. The method of claim 8, wherein at least one of the upstream current profiles is

determined from measurements taken at a power substation, wherein the upstream current profile is based on a signal super-positioned on one or more power lines that supply power to the device producing the signal.

10. The method of claim 8, wherein the downstream current profile is determined from

measurements acquired by a smart meter at a consumer location.

11. The method of claim 8, wherein at least one of the downstream current profiles comprises a current waveform.

12. The method of claim 1, wherein at least one downstream current profile and a

corresponding upstream current profile are generated from signals produced passively by one of the devices.

13. The method of claim 1, wherein determining at least one of the downstream current profiles comprises extracting one or more features from a signal produced by the at least one device.

14. The method of claim 1, further comprising identifying one or more modifications to a location of at least one of the devices attached to the grid.

15. The method of claim 1, further comprising identifying one or more deviations between an as-designed system and an as-built system based at least in part on at least one of the determined electrical locations.

16. The method of claim 1, wherein the electrical location comprises a feeder, a lateral, and a phase in the grid.

17. The method of claim 1, wherein the electrical location comprises at least one of a feeder, a lateral, and a phase in the grid.

18. The method of claim 1, wherein comparing at least one of the downstream current

profiles to at least one of the upstream current profiles comprises: compressing data relating to at least one of the downstream current profiles determined from measurements in at least one of the downstream locations; and transmitting compressed data associated with the at least one downstream current profile over a communication network, wherein at least one of the comparisons between upstream current profiles and downstream current profiles is based on the compressed data transmitted over the communication network.

19. A system, comprising: a power distribution system comprising a grid mapping computer implemented on one or more computer systems, wherein the power distribution system is configured to implment: measuring an electrical signal at one or more downstream locations in the grid, wherein at least one of the downstream locations includes one or more devices that receive electrical power from the grid; measuring an electrical signal at one or more upstream locations in the grid, wherein the upstream location is in the power distribution system upstream from the one or more downstream locations; wherein the grid mapping computer is configured to implement:

determining, based on measurements in at least one of the downstream locations, a downstream current profile for at least one of the downstream locations, wherein the downstream current profile has characteristics produced by at least one of the devices; determining, based on measurements in at least one of the upstream locations, an upstream current profile for at least one of the upstream locations, wherein the upstream current profile has characteristics produced by at least one of the devices; comparing at least one of the downstream current profiles to at least one of the

upstream current profiles; and determining, based at least in part on the comparisons, an electrical location of at least one of the devices in the downstream locations.

20. A non-transitory, computer-readable storage medium comprising program instructions stored thereon, wherein the program instructions, when executed on one or more computers, cause the one or more computers to implement a system configured to: measure an electrical signal at one or more downstream locations in the grid, wherein at least one of the downstream locations includes one or more devices that receive electrical power from the grid; measure an electrical signal at one or more upstream locations in the grid, wherein the upstream location is in the power distribution system upstream from the one or more downstream locations; determine, by a grid mapping computer of the system, based on measurements in at least one of the downstream locations, a downstream current profile for at least one of the downstream locations, wherein the downstream current profile has characteristics produced by at least one of the devices; determining, by the grid mapping computer, based on measurements in at least one of the upstream locations, an upstream current profile for at least one of the upstream locations, wherein the upstream current profile has characteristics produced by at least one of the devices; compare, by the grid mapping computer, at least one of the downstream current profiles to at least one of the upstream current profiles; and determine, by the grid mapping computer, based at least in part on the comparisons, an electrical location of at least one of the devices in the downstream locations.

21. A method of assessing an electrical grid, comprising: determining an electrical location of one or more devices receiving electrical power from the grid;

assessing a physical location for at least one of the devices; and

generating one or more maps, wherein at least one of the maps is based in part on an assessed physical location for at least one of the devices and in part on the electrical location determined for the at least one device.

22. The method of assessing of claim 21, wherein generating at least one of the maps

comprises reconciling, by the computer system, an electrical location and a physical location of least one of the devices.

23. The method of claim 21, wherein generating at least one of the maps comprises determining a correlation between a physical location and an electrical location for at least one of the devices.

24. The method of claim 23, wherein the correlation is based at least in part on geo-spatial information of at least one of the devices.

25. The method of claim 23, wherein the correlation is based at least in part on GPS data acquired for at least one the devices over a communication network.

26. The method of claim 23, wherein the correlation is based at least in part on location information logged by one or more persons about a physical location.

27. The method of claim 21, wherein the map of the grid based at least in part on determined electrical locations of a plurality of devices receiving power from the grid.

28. The method of claim 21, wherein determining the electrical location of at least one of the devices comprises: determining, based on measurements in one or more downstream locations, a downstream current profile for at least one of the downstream locations, wherein the downstream current profile has characteristics produced by at least one of the devices; determining, based on measurements in one or more upstream locations, an upstream current profile for at least one of the upstream locations, wherein the upstream current profile has characteristics produced by at least one of the devices; comparing one or more downstream current profiles to one or more upstream current profiles; and

determining, based at least in part on the comparisons, an electrical location of at least one device in at least one of the downstream locations.

29. The method of claim 28, wherein the electrical grid is a utility power system supplying power to consumers, wherein the downstream current profiles and the upstream current profiles include characteristics produced by at least one consumer device receiving power from the grid.

30. The method of claim 28, wherein the electrical grid is a utility power system supplying power to consumers, wherein the downstream current profiles and the upstream current profiles include characteristics produced by at least one consumer device receiving power from the grid.

31. The method of claim 28, wherein at least one of the upstream current profiles is

determined from measurements taken at a power substation, wherein the upstream current profile is based on a signal super-positioned on one or more power lines that supply power to a device producing the signal.

32. The method of claim 28, wherein at least one of the downstream current profiles is

determined from measurements acquired by a smart meter at a consumer location.

33. The method of claim 28, wherein at least one of the downstream current profiles

comprises a current waveform.

34. The method of claim 28, wherein at least one downstream current profile and a

35. The method of claim 28, wherein determining at least one of the downstream current profiles comprises extracting one or more features from a signal produced by the at least one device.

36. The method of claim 21, further comprising identifying one or more modifications to a location of at least one of the devices attached to the grid.

37. The method of claim 21, further comprising identifying one or more deviations between an as-designed system and an as-built system based at least in part on at least one of the determined electrical locations.

38. The method of claim 21, wherein at least one of the electrical locations comprises a feeder, a lateral, and a phase in the grid.

39. The method of claim 21, wherein at least one of the electrical locations comprises at least one of a feeder, a lateral, and a phase in the grid.

40. The method of claim 21, wherein comparing at least one of the downstream current profiles to at least one of the upstream current profiles comprises: compressing data relating to at least one of the downstream current profiles determined from measurements in at least one of the downstream locations; and transmitting compressed data associated with the at least one downstream current profile over a communication network, wherein at least one of the comparisons between upstream current profiles and downstream current profiles is based on the compressed data transmitted over the communication network.

41. A system, comprising: a grid mapping computer implemented on one or more computer systems, wherein the grid mapping computer is configured to implement: determining an electrical location of one or more devices receiving electrical power from the grid; assessing a physical location for at least one of the devices; and generating one or more maps, wherein at least one of the maps is based in part on an assessed physical location for at least one of the devices and in part on the electrical location determined for the at least one device.

42. A non-transitory, computer-readable storage medium comprising program instructions stored thereon, wherein the program instructions, when executed on one or more computers, cause the one or more computers to implement a system configured to: determine an electrical location of one or more devices receiving electrical power from the grid; assess a physical location for at least one of the devices; and generate one or more maps, wherein at least one of the maps is based in part on an

assessed physical location for at least one of the devices and in part on the electrical location determined for the at least one device.

43. A power distribution system, comprising: a substation comprising feeders distributing electricity to one or more locations; and a grid mapping computer implemented on one or more computer systems, wherein the grid mapping computer is configured to implement: determining an electrical location of one or more devices receiving electrical power from the grid; assessing a physical location for at least one of the devices; and generating one or more maps, wherein at least one of the maps is based in part on an assessed physical location for at least one of the devices and in part on the electrical location determined for the at least one device.