Non-technical losses in a power distribution grid.

(54) Title: NON-TECHNICAL LOSSES IN A PUBLIC ELECTRIC GRILLE. (54) Title: NON-TECHNICAL LOSSES IN A POWER DISTRIBUTION GRID.

(57) Summary

A system and the method to detect the theft of energy in an electrical distribution network are described. The system may include at least two communication meters that form a transformer area network, a mechanism to measure current and voltage in the meters, a mechanism to transmit the measured current and voltage data to a data center with access to a database of the electrical network, and a mechanism that analyzes the transmitted data to infer the unauthorized withdrawal of electrical energy.

(57) Abstract

A system and method for detecting theft of power in an electrical distribution grid. The system may inelude at least two communicating meters which form a transformer area network, a mechanism for measuring current and voltage at the meters, a mechanism for transmitting the measured current and voltage data to a data center with access to an electric grid database, and a mechanism that analyzes the transmitted data to infer unauthorized taking of electrical power.

PATENT TITLE No. 357831

Headlines):

IMPIC

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ASTROLINK INTERNATIONAL LLC; DOMINION ENERGY TECHNOLOGIES, INC.

c / o Lockheed Martin Corporation, 6801 Rockledge Drive, Bethesda, Maryland, USA 20817

Home:

Name: NON-TECHNICAL LOSSES ON A PUBLIC ELECTRIC GRID.

Classification:

Inventor (s):

CIP: G01R22 / 06; GQ1FÍ19 / ¡2 $ ¿

CPC: G0tR22 / 0eSj G01R19 / 2513; G01 R2t / O53

HENRICK F, BÉRNHEIM; JERF ^ WU ^ ANSELL; MARCIA REID MARTIN

Number:

MX / a / 2015 / 0T7231

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Country:

US

Validity: Twenty years Date of Meiri $ lies ¿1 $ Φζ Date of EMpédfción: ¿é (jé ^ hlio d £ ¡2,018

The reference patent is ^ tc ^ ga based on the

In accordance with arttfcjÉp '^ of the Law leaves PrtípieaaAJ from the date of filing &amp; soh3He «rintemaci ^ a 1 * / * ·' Who subscribes the present title lo Mc &amp; cqip fum (Official Gazette of the Federation 4 &amp; €&gt; ξ * ϊ * 27 / Ι 01/25/2006, 06/05/2009, 06/01/2010, Í6T *** '

Regulations of the Mexican Institute CKL.

Articles 1, 3, 4, 5, section V, subsection a).

12/27/1999, amended on 10/10/2002, 29/0 '

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I affirmed. w ·,

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International:

2014

Núpiero:

61/884,567

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Industrial.

lénto en lo di¡ 9§T'Morm¡ J&gt; i 27 / (d haflbjótrídt &lt;i teste par Sj &amp; afti

Gives the |) 2B8Í1994, / 2012¾ (W (J »/ 2O1: IF 14/1% 1S99 i. Counted to pqjU * tflgencujde twenty || W0it&gt; fonOeabtes, ritaxará m ^ Btfner viger ^ s wrwechos.

III y7MÍsJ ^ gplaYWy of the Industrial Property 12 / 1S $? Í * 17 ^ 5/1999, 26/01/2004, 16/06/2005,, 3 ° fraódóó a), 4 ° and 12 ° fractions I and III of

01&gt; 7 / §m®í, J® »7/2004. 07/28/2004 and 09/07/2007);

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Deputy Generals, Coordinator, Directors * · Departmental and other subordinates of the Institute 08/04/2004 and 09/13/2007).

accionj ^ l ¡^ lll and SO'Ytek'fiteúul ^^ rgánicp ^ hJnstituW'MeRteefl'o of Industrial Property (DOF ~ '52jfaáSi * TWiAoe ^ do that delegates powers to the Directors

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It is, Divisional Deputy Directors, Coordinators 2/1999, amended on 02/04/2000, 07/29/2004,

This letter is signed with an advanced electronic signature (FIEL), based on articles 7 BIS 2 of the Industrial Property Law; 3 of its Regulations, and 1 fraction III, 2 fraction V, 26 BIS and 26 TER of the Agreement establishing the guidelines for the use of the Electronic Payment and Services Portal (PASE) of the Mexican Institute of Industrial Property, in the procedures indicated.

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DIVISIONAL DIRECTOR OF PATENTS NAHANNY CANAL REYES

ΠΠ Original Chain:

NAHANNY MARISOL CANAL REYES | 00001000000403252793 | Tax Administration Service | 1695 || MX / 2018/62644 | MX / a / 2015/017231 | Patent title PCT | 1027 | RGZ | Page (s) | losoGjKsEd8uA1 Av / wvZZppT + dc =

Digital stamp:

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IMPI

Mexican Institute of Industrial Property

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NON-TECHNICAL LOSSES ON A PUBLIC ELECTRIC GRID

CROSS REFERENCE TO RELATED REQUESTS

This application claims the benefit of United States Provisional Patent Application No. 61 / 834,567, filed on June 13, 2013, the disclosure of which is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The present invention is directed to requests for communications on the grid to optimize electrical distribution, and specifically for the real-time identification and location of non-technical losses that occur in a service transformer area network.

BACKGROUND OF THE INVENTION

Electrical Distribution Substations contain one or more Substation Transformers, which reduces the voltage from the high transmission line levels (normally 130kV to 700kV) to the medium voltage levels (normally from 4KV to approximately 35kV) at which the power I know

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distributes to consumers within a distribution service area. At the edge of the Distribution Grid are a series of Service Transformers, which transform the average voltage of the distribution grid to low voltages (in the US, typically 120, 208, 240, 277, or 480 ) that are required for commercial, industrial and residential use. Other voltages, in addition to some of these, can be used in other parts of the world. Each Service Transformer supplies one or more measured loads. A load may be a home, a commercial or industrial building, an item of municipal infrastructure, such as a series of street lamps, or an agricultural appliance, such as irrigation systems.

Aside from the cables connecting a consumer load and the meter associated with the service transformer, the service transformer is the furthest element from the distribution grid before the power is actually supplied to a consumer. A meter is normally attached to the point where the power from the utility transformer is delivered to the consumer. Service transformers can be three-phase, two-phase or single-phase, such as meters.

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Herein, the collection of electrical appliances, including from a service transformer to the collection of at least two electrical communication meters is known as a Transformer Area Network (TAN). A TAN can have a radial topology, as is common in the US, or it can have a linear or bus topology, as is more common in Europe and other parts of the world.

Traditionally, reading meters was one of the highest operating costs incurred by electric companies. The original electrical meters were analog devices with an optical readout that had to be manually examined on a monthly basis to lead to the utility billing process. In the early 1970s, mechanisms for digitizing data and automating its collection began to be used. These mechanisms evolved from walk-by or drive-by systems where the meter would broadcast its current reading using a short-range radio signal, which was received by a device carried by the meter's reader. These early systems were known as Automated Meter Reading Systems or AMRS. Later, a variety of collection nets began to unfold

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specially designed data sources, generally employing a combination of short-range radio frequency repeaters in a mesh configuration with collection points equipped with broadband backhaul (return) means to carry aggregate readings.

These networks were capable of two-way communication between the metering headend at a utility center and the meters at the end of this data collection network, generally called an Advanced Metering Infrastructure, or AMI. AMIs can collect and store readings frequently, typically every 15 minutes, and can report on them almost as often. They can read any meter on demand as long as this feature is used sparingly, and they can also connect or disconnect any meter on demand. AMI meters can transmit signals to consumer devices for purposes of energy savings, demand management, and billing at variable rates. Because the AMI network is independent of the power distribution grid except for the intersection on the meters, the AMI meters are not aware of or sensitive to changes in the grid topology or to certain

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conditions on the grid. However!,¹ 1 &amp; AMI inLrocíícciori is generally considered to be the principle of the Smart Grid distribution. Furthermore, due to the mesh architecture normally used in AMIs in the United States, the bandwidth available for an individual electric meter to send its own data is quite limited.

The total billable kilowatt-hours produced by a normal electrical distribution grid, anywhere in the world, is substantially less than the actual energy distributed, measured in a distribution substation, during the billing period. Energy loss can be classified into two groups. The technical losses resulting from the total impedance of the distribution infrastructure, from the mismatch of the energy factor between the loads required by the population and what the grid produces at each load point, and the fact that public services exceed the power capacity to ensure that power outages will not occur during unpredictable peak loads. Public services can work to minimize these technical losses, but some technical losses are inevitable.

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Non-technical actual electricity-hour losses (as opposed to revenue) as a result of energy theft by consumers who avoid or subvert the measurement process by altering meters or touching power lines above the measured load points. Non-technical revenue losses also include non-payment of bills by customers, and accounting errors by utilities. However, these types of revenue losses are addressed by Meter Data Management systems integrated with the Advanced Metering Infrastructure. These automated systems have the ability to avoid administrative errors to immediately cut service to non-paying customers, and require customers with poor payment histories to be on a prepaid billing plan. Because AMI provides little or no information on the schematic relationship of the grid from one electrical meter to another and the relationship between the electrical meter and the utility transformer supplying it with power, AMIs are of little value in source location. energy theft. Some Smart Meters can detect and report the alteration. On the other hand, the absence of neighborhood meter readers reduces the chance that illegal seizures will be seen and reported.

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MEXICAN INSTITUTE OF INDUST RIAL PROPERTY

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The social and financial costs of energy theft are highly variable. In developing countries, these costs are quite high: sometimes more than 50% of the energy delivered from the substations. In India, for example, large private companies (Reliance and Tata) report non-technical losses of around 1%, but state public services have losses of over 30% in most cases, according to the Regulatory Commission of Maharashtra Electricity of India (MERC).

In developed countries, theft losses represent a relatively small percentage of the total cost of generation. In the United States, theft losses have traditionally been estimated at three percent of income, although this figure increases during difficult economic times.

Theft of energy represents an issue of security and quality of service as well as an economic issue. Improvised electrical outlets are dangerous and often cause injury and even death. Furthermore, the

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makeshift shots pose a fire hazard. Most significantly, the unpredictable load resulting from the distribution grid can cause transformer fires and explosions that can result not only in dangerous situations, but in major power outages.

The prior art methods of detecting energy theft can be divided into three categories. One category involves comparing the voltage and current on a meter with the source point voltage and current for the supply, such as a utility distribution transformer for a neighborhood. The technical losses due to the resistance of the low voltage line between the origin point and each meter are assumed to be less than a predetermined amount, so any difference in energy loss above the predetermined amount can be assumed which is due to either theft or line defects. United States Patent Application Publication No. 2012/0265355, entitled System and Method for Single and Multizonal Optimization of Utility Services Delivery and Utilization (incorporated herein by reference), describes such a system, in which intelligent software agents in the transformer

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Service personnel collect measurements on the transformer and other instruments located or incorporated in the electrical meters. Theft detection is cited as one of the applications of this system. However, systems involving placing agents and instruments in the transformer are less desirable than a system that requires no device in the transformer would be, because transformers are much less accessible than meter plugs, and their modification by Adding instrumentation inside the transformer housing or on the high voltage side of the transformer can be costly and even dangerous.

A second category is to measure the current and voltage outside the meter of a measured load, and within the facilities of the measured load. If more energy is being used in the facility than is supplied by the meter, then either power is locally generated in the facility or the meter is bypassing (bridging). Methods of this type are problematic for utilities because utilities typically do not have access to data from within the metered load.

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MEXICAN INSTITUTE OF INDUSTRIAL PROPERTY

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The consumer would have to be “acuéFdü uun the placement of devices within the facilities.

A third category is to detect instantaneous changes in energy use or minor blackouts caused by disruption of distribution lines in order to install an outlet without metering. This category of mechanism falls short, because the disruption can be masked by larger events, such as a legitimate outage or interruption in service, and because it would create many false positives.

SUMMARY OF THE INVENTION

The present invention relates to an apparatus and methods for detecting and reporting, in real time or almost in real time, the theft of energy in such a way that the point of alteration that has occurred on the low voltage side of Specific service transformer, in cases of meter alteration, the specific meter or meters involved can be identified. The present invention does not require the instrumentation of the transformer at the service supply point (service transformer). All the instruments and intelligence agents that

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perform and collect measurements and process collected data to find evidence of energy theft, they are located where smart instruments and devices will reside anyway: on the electric meter. This is beneficial in that the meter plug is commonly easily accessible, and because a smart meter already contains memory and processors to host software agents, it already has the ability to make many of the measurements used by the methods of the present invention, and because most smart meters are designed to accommodate an additional circuit board where national instruments, communication capabilities, and / or memory and processing capacities are insufficient to support the methods described herein.

United States Patent Application No. 13 / 871,944, entitled A System and Method for inferring Schematic and, Topological Properties of an Electrical Distribution Grid, which is incorporated herein by reference, describes increasing Long Range Smart Meters (edge-a -Substation) transmitters connected to the grid, and also short-range transceivers (low voltage, local for the service transformer)

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on the rack. A Smart Meter that has both short range and long range grid transmission capabilities is called a Remote Hub. A Smart Meter that has only the short-range capability on the network is called a Subordinate Remote. The term Remotes is used to refer jointly to Subordinate Remotes and Remote Hubs. A service transformer that has a Remote Hub and none or more Subordinate Remotes is defined as a Transformer Area Network, or TAN. In addition, the application describes a method of determining the feeder and supply phase to a Remote Concentrator with power based on characteristics of a long-range message transmitted from a

Remote Hub.

United States Patent Application No. 13 / 888,102, titled Methods for Discovering, Partitioning. Organizing, and Administering Communication Devices in a Transformer Area NetWork, also incorporated herein by reference, teaches a method of ensuring that all Remote and Subordinate Remote Hubs in a TAN are, in fact, powered by the same utility transformer and, in the case of a multi-phase transformer,

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determine which Remotes are in the same phase as a Remote Hub and which Remotes are in a different phase. In addition, United States Patent Application No. 13 / 911,849, entitled A System and Method, for Inferring Schematic Relationships between Load Points and Service Transformers and which is incorporated herein by reference, describes a method of identifying the specific service transformer and its geospatial coordinates supplied by a meter plug given, and incorporating the association and coordinates into a map of the distribution grid. Public services already know at least the street address, if not the precise geospatial coordinates of each meter. Using the information obtained from the systems and methods in the aforementioned applications, it is possible to define with great precision the physical and schematic origin of a report from a Remote Concentrator, and the physical and schematic extension of the Transformer Area Network that represents the Remote Hub. These inventions teach a Transformer Area Network Architecture that is master-slave type, where one Remote, usually the Remote Hub, contains most of the intelligence, and survey simpler agents on the Subordinate Remotes to both organize the TAN , how to implement applications in

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SO. The system and methods of the present invention are mainly described in terms of a TAN organization. However, a master-slave network organization is only one of the possible network organizations suitable for practicing the present invention. For example, a transformer area network between peers is also suitable. A wider peer-to-peer network, such as an AMI mesh network, may also be appropriate since a) the nodes in the network have enough information to logically partition themselves around the transformer area, and b) there is width bandwidth sufficient to share the measurements taken by the measurement agents of the present invention, as described herein below.

The present invention provides a method for a Remote Concentrator in communication with at least one Subordinate Remote, each Remote being operated to measure and store a voltage on the meter and the current passing from the meter to the measured load, to identify indications that Theft of energy is taking place in the TAN, without placing the apparatus, either in the service transformer of the TAN or inside the facilities of the loads powered by the TAN. For

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For this purpose, the TAN comprises at least two nodes, such as a Remote Hub and one or more Subordinate Remotes, in each phase of the TAN. In addition, each load (metered service point) on the TAN has a Remote (or other type of communication meter) if complete theft protection is to be achieved. The method can be used with some meters that do not have Remote, but some thefts can go unnoticed in that case, depending on the TAN topology and the location of unauthorized outlets with respect to the communication meters. Methods are taught to infer the existence and location of illegal taps that do not require taking taps on the TAN service transformer. It is desirable to avoid the need to take measurements on the service transformer because the cost of adding instrumentation on the meters alone is significantly less than the cost of adding instrumentation, both on the meter and on the transformer, as is the cost to maintain the network when all instruments and intelligence reside only in the meter. It is desirable to avoid the need to place a device within the facilities of the measured service point because the consent of the consumer is required to place devices within the facilities, and because the

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Equipment maintenance within facilities is normally outside the nature of public services.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and form a part of the specification, show the embodiments of the present invention and, together with the description, serve to explain the principles of the invention. In the drawings:

Figure 1 shows a transformer area with radial topology, with a transformer and overhead power lines and three metered buildings.

Figure 2 shows a bus topology transformer area with a pedestal type transformer, underground power lines, and three buildings measured along a single tap.

Figure 3 shows a radial topology transformer area with a pedestal type transformer, underground power lines, and three metered buildings each with its own tap.

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Figure 4 shows the area of ​​Figure 1 improved to form a Transformer Area Network by adding a Remote Hub, and for Remotes

Subordinates.

Figure 5 shows the Transformer Area Network of Figure 4 with the addition of an illegal no-measure tap used to power a greenhouse.

Figure 6 shows the electrical detail of a Radial Transformer Area Network like that of Figures 4 and 5, with an arbitrary number of buildings measured (Nodes) N.

DETAILED DESCRIPTION OF THE INVENTION

Referring to Figure 1, a typical single-phase pole-mounted transformer 101 is shown connected through overhead power lines 102 to the 103 residences. In the United States and in many other places, this is a typical configuration, especially in older areas. The power lines to the residences are normally attached to the eaves of the roof, with the feed spikes traveling down to the meters 104 in the conduit outside the residences 103. Figure 2, by

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rather, it displays a bus topology for the transformer area, which is more typical in other parts of the world than in the United States. In Figure 2, a pedestal type transformer 201 is connected through a linear buried line 202 connected to residences 203, 204, and 205 at meters 206, 207, and 208, respectively. This topology is common in Europe and other parts of the world. A typical installation can serve many more meters than shown: the average number of meters per single phase transformer in the US. it is approximately six (6), but the European average is dozens. Figure 3 shows a typical United States buried cable installation, where pedestal type transformer 301 is connected radially via buried cable 302 to residences 303 on meters 304. These three bask configurations, with minor local variations and multi-phase variations for industrial and commercial applications, represent the majority of electrical distribution networks worldwide. The present invention works with minor variations on all three of these common topologies, as taught herein below. For the purpose of this teaching, each phase of a three phase transformer can be considered as a separate TAN, despite the fact that, as described

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at 13 / 888,102, you can actually organize a three-phase transformer ~ area as a single TAN, but where the phase of each node (for example, Remote) in the TAN is known, and edge-to-substation transmissions of the

SO they are shipped in the phase to which they belong.

Referring now to Figure 4, the transformer area of ​​Figure 1 has been converted to a Transformer Area Network by replacing ordinary meters in Figure 1 with two Subordinate Remotes 402 and 404, and a Remote Hub 403. Transformer Area Network communication meter clocks have been synchronized within a known tolerance, as described in 13 / 871,944. Service Transformer 401 does not contain any added communication equipment or instruments, and is identical to the Service Transformer in Figure 1. Note that service / residence point 405 has a non-powered building 406 nearby, such as a barn.

In one embodiment of the invention, a metering agent resides in each of Remotes 402, 404, and 403. Each agent periodically measures the supplied voltage V and the current flowing / at its service point. A surveillance agent who may reside in

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<td>Remote Hub 403 collects</td><td>poriód-loumoPÍte · —í-oo</td>

<td>current and voltage measurements with</td><td>date and time of</td>

<td>402 and 404 Subordinate Remotes and</td><td>his own agent</td>

measurement. The surveillance agent period does not need to be the same as the measurement agent period, but the time measurements are taken is timed to the closest tolerance possible given the capabilities of the TAN. Timbos periods are very small with respect to the time scale of events in a normal AMI network, in which, for example, meter readings can be transmitted only every fifteen minutes or even less frequently. The surveillance agent runs a software algorithm that compares current and voltage measurements taken on the different meters at the same time and uses them to infer when an unmeasured current flow is occurring between the transformer and one or more of the points of measured service.

In Figure 5, an unmetered outlet 507 has been electrically added to building 505 between transformer 501 and meter 504. The outlet has been used to electrify an attached building 506. Not only these types of outlets cause monetary losses for

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Utilities in hours create a fire explosion hazard because the TAN is drawing more energy than transformer.

of maximum load can of transformers and as a whole, can the maximum nominal of the

Figure 6 provides electrical details of a Radial Transformer Area Network such as that of Figures 4 and 5. The TAN of Figure 6 contains at least two measured service points, or nodes, in the present labeling 1 ... N . Power source 601 supplies transformer 607 with power at a medium voltage, which is reduced by transformer 607 to the low voltage range accepted by the meters in the transformer area, represented herein by meter 627 at Node 1 (605) and the 629 meter at Node N (610). Current 604 represents the current flowing from the power source due to all grid loads supplied by power source 601. Impedance 603 represents the impedance of the medium voltage grid. The voltage of 606 on the low side of transformer 607 fluctuates with changes in voltage 602, impedance 603, and current 604. None of these amounts are constant, measurable, or known to software agents on meters (such as 627 and 629),

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but the voltage 602 can be expected to vary around a nominal value within a known range of acceptable values. For example, a common voltage rating 602 may be 13.4 V in the United States (although others are possible), and a common voltage rating 606 may be 240V, although again others are possible. These nominal values ​​may be known to software agents.

Now consider the components in rectangle 605 representing Node 1. Node 1 comprises the apparatus supplying power from service transformer 607 to meter 627. On the diagram, measurable amounts of interest are marked. Impedance 616 represents the legitimate measured load of the Node 1 building, which can vary over time depending on the appliances and devices that are in use in the building. Item 626 is not a true piece of equipment, but represents an arbitrary location on the power line from transformer 607 to meter 627, where an illegal outlet could be installed. Impedance 612, which is typically extremely large when no theft is occurring, represents a potential, unmeasured, unauthorized load. Impedances 609 and 613 represent the normal impedance of the power line

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from transformer 607 to meter 627. Voltage 611 represents the voltage at the hypothetical tap point

626. Neither of these amounts is known or measurable by the software agents residing on the meter.

627. Current 614 and voltage 615 are periodically measured by the measurement agent residing in meter 62 7 and are shared in the TAN by the communication equipment in meter 627. Regardless of the TAN network architecture, the exchange it is always carried out in such a way that the identity of the meter from which the measurements originate and the time in which the measurements were taken for any receiver of the messages in which the measurements are transmitted are known. Note that element 622 in Figure 6 is not a characteristic of TAN, but is an ellipse indicating that an arbitrary number of additional Nodes could exist between Node 1 605 and Node N 610.

Similarly, consider the components in rectangle 620 representing Node N. This is the apparatus supplying power from service transformer 607 to meter 629. Impedance 625 represents the legitimate measured load of the Node N building, which can vary over time according to the appliances and devices that are in use in the building. Point

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628 not a real feature of Ta T7T, 'pyicr represents an arbitrary place on the power line from transformer 607 to meter 629, where an illegal outlet could be installed. Impedance 623, which is typically extremely large when no theft is occurring, represents a potential unauthorized, unmeasured load. Impedances 618 and 620 represent the normal impedance of the transformer power line from 607 to meter 629. Voltage 619 represents the voltage at hypothetical tap point 628. Neither of these quantities are known or measurable by software agents residing in meter 629. Current 621 and voltage 624 are periodically measured by the measurement agent. residing on the 629 meter and shared on the TAN by the communication equipment on the 629 meter.

For the purposes of the watchdog algorithm, it does not matter if the 629 meter, 627 meter, or another Node meter between 1 and N has the Remote Hub and which meters have subordinate Remotes. Indeed, as noted herein above, another type of TAN communication can be fully employed as long as it provides enough bandwidth for all TAN meters to share

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your measurements within a sufficiently small period. The TAN can host at least one surveillance agent somewhere on the TAN and one measurement agent on each communication meter. With some network architectures, it may be more effective to host a surveillance agent on each node. On the other hand, the work of the surveillance agent can be distributed among several communication meters. If the surveillance agent does not reside on a meter that has the ability to send a wide area message, such as an Edge-to-Substation message, then the surveillance agent must transmit a command to a wide area device enabled to transmit the anomaly report.

Suppose an unauthorized load represented by impedance 612 is set at point 626. Voltage 611 will drop because more current (the current consumed by the unauthorized load at 612) is flowing through impedance 609. This will also cause a drop in voltage 615. However, current 614 flowing through impedance 613 does not drop correspondingly. A measuring agent in meter 627, capable of measuring only current 614 and voltage 615, will not be able to infer whether the drop in

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Voltage 615 is simply due to a drop in Fen'sióñ 606, or if it is caused by theft represented by a drop in voltage 611 and a decrease in impedance 612 (which should always be very large). However, note the observations made by a measuring agent on the 629 meter. For simplicity, suppose that the impedance 623 at Node N (610) is suitably large, no power is being stolen from Node N. A measuring agent on meter 629 will observe a voltage drop 624, due to voltage drop 606. A monitoring agent can use measured currents 614 and 621 on meters 627 and 629, respectively (and others if there are more nodes. communication in the TAN) to estimate the adequate voltage drop due to each measured load. Once the effects of the measured loads have been removed (616, 624), the adjusted magnitudes of the measured voltages on each meter can be compared. Although there will be slight differences in line impedance between transformer 607 and each meter, these are expected to be negligible. (In this example, compare the impedances 609 + 613 for the 627 meter with the impedances 618 + 620 for the 629 meter.) If a meter, in this example 627, sees a higher adjusted voltage drop than the other meters, within a

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tolerance representing normal differences in line impedance, then there is expected to be an unmeasured load between that meter and transformer 607.

In addition, this method of comparing the current and voltage from each available viewpoint detects theft in the TAN even if there are multiple theft points. Even if there was an unmeasured load attached between each meter and the transformer, unless impedances 612, 623, etc., due to unauthorized loads, are identical at all times, then theft points could still be inferred by a monitoring agent with access to the current and voltage measurements of each measurement agent, because the voltage drops at some measurement points would not be proportional to the current at the same point.

When the surveillance agent residing in the TAN Remote Hub detects a probable theft, then the Remote Hub can send an Edge-to-Substation message to alert utilities to the anomaly, Edge-to-Substation messages, as described in the Patent Application of the

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United States No. 13 / 871,944 referenced above, travels from a Remote Concentrator to an electrical distribution substation that supplies power to the substation transformer, in this case, transformer 607. From the substation, the message is transmitted over a conventional network to a data center provided by utilities or an energy management service provider. A theft alert can also be propagated through another available network connected to the Remote Hub or other communication meter, such as an AMI network. Such a message can include at least a unique identifier of the service transformer or a meter in which the abnormal current-voltage relationship was detected, which can be used to match the origin of the message with the data in the database of the map of the grating.

The method described hereinabove with minor computational adjustments can be applied in the same way to an area of ​​the transformer that has a bus topology as shown in Figure 2 instead of a radial topology as in Figures 1 and 3. In In a bus topology, the voltage drop from the transformer to the meter is additive, since each node is further from the transformer, since the loads

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measurements are connected in series instead of parallel. However, each contribution of the measured load to the voltage drop must be proportional to the current being taken in each meter. If the voltage drop on a given meter is greater than proportional to the currents measured between the transformer and that meter, based on the date-stamped current and voltage measurements shared in TAN by the other meters - in this case, specifically the earlier meters in the series with respect to the transformer than the given measurement point.

In order to apply this method in a TAN with a bus topology, it is necessary that the order of the nodes in the TAN with respect to the transformer is known to the surveillance agent (at least). This can be deduced by the surveillance agent. The order of the series will correspond to the voltage measured at each measured point, with the lowest voltage being schematically farthest from the transformer. Referring again to Figure 2, the meter, schematically closest to transformer 201 is 206, and the farthest in the series is 208. This would still be true even if building 205 were

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Geospatially closer to transformer 201 than to building 203, which is certainly possible. This condition is also illustrated in Figure 2. Furthermore, this schematic inference remains correct even if power theft is occurring, because the resulting brownouts remain cumulative.

United States Patent Applications Nos. 13 / 871,944, 13 / 888,102, and 13 / 911,849, referred to above, teach methods of engraving an accurate grid map of an electrical distribution network. The grid mapping method taught by these inventions includes the feeder and phase of each operable substation to feed each measured load supplied by the network and a correct and current distribution of the network meters in the Transformer Area Networks. In order to perform theft detection, the grid map of a TAN with a bus topology can be increased with the order of the TAN meter series, and this order can be kept up to date as the meters and the loads are added and removed from the TAN. For theft detection, this information may only need to be maintained by one surveillance agent at each TAN, and in fact, can be recalculated periodically by each agent.

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of vigilance. However, it may be beneficial to record this additional information in a centralized grid map database, which centralized grid map database is taught by 3 / 871,944. To do this, the Edge-to-Substation message sent when a new node is discovered in the TAN may include the schematic order of the meter on the transformer power line bus. Similarly, if you observe the order of the nodes to change, for example, after a power outage or the extent of i

TAN due to construction, so the new arrangement could be reported in a Bordea-Subestacion message to be recorded in a grid map database.

Another method of energy theft that is sometimes used does not involve creating an illegal outlet. This method involves creating disorientation by switching meters with a neighborhood before increasing consumption. A communication meter of any type may already be enabled to report if it is disconnected from the meter socket and if it is reconnected to a new meter socket (either the same or a different socket), while power is available. However, an energy thief with a lot of initiative can

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Expect a natural power outage to swap meters with another building, or you can tear the grid apart to create a power outage in which to swap. A smart meter, however, that participates in a Transformer Area Network with real-time grid mapping, as described herein and related inventions such as

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SO.

• If two meters are interchanged in such a way that the phase of the meters is reversed, then this change can be reported by the grid mapping agents.

• If two meters are changed within the same TAN and the same phase, then if the TAN has a bus architecture, both meters will be detected for having changed positions with respect to their service transformer, and this can be reported by the agent of vigilance.

• If a meter has access to a geospatial location signal, then a grid mapping agent on the meter can report the location change.

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This leaves only one case where it is not necessary to exchange two meters not enabled to receive a geospatial location signal, between two buildings in the same phase of the same radial TAN. This case may be undesirable, from the thief's point of view, due to the proximity of the buildings: better to alter with a plug of the meter several blocks away than with that of the next door neighbor.

To manage the detection process, an agent such as the surveillance agent of at least one communication meter (such as a Remote Hub) in each TAN, can report each of the anomalous conditions detected by an Edge-to-Substation message or other Available wide area network capable of forwarding the message to a software program residing in a data center with access to the consolidated grid map. The software program also receives reports of planned grid changes from other applications used to manage the grid. An example of such reports could be work orders that are used to send to field engineers to make necessary changes and repairs to the distribution grid. The software program avoids reporting false indications of theft by matching the

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meter failure reports ¹ udnitmi'CddlÜTT against work orders or similar reports. Anomalies explained by work orders are not reported as potential indicators of theft. Anomalies that match a work order create alerts that a potential theft may be occurring, regardless of whether the anomaly is a change in the grid map or a voltage anomaly reported by a surveillance agent. The theft alert may contain the account numbers and addresses of the affected establishments, the identity and geospatial coordinates of the affected transformers and meters, and any other relevant information that can be used to locate the theft, whether the theft is kite by moving gauges or by creating an unauthorized take without measurement.

The foregoing description of the invention has been presented for purposes of illustration and description and is not intended to be exhaustive or limit the invention to the precise forms described. Many modifications and variations are possible in light of the above teachings. The modalities were chosen and described in order to better explain the principles of the

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Invention and its practical application thereby enabling other experts in the art to make better use of the invention in various embodiments and with various modifications that are suitable for the particular use contemplated. The scope of the invention is intended to be defined by the claims appended hereto.

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