Non-technical losses in a power distribution grid

Detailed description of the invention

[Cross-reference of related applications] The present application claims the benefit of US Provisional Patent Application No. 61 / 834,567 filed June 13, 2013, the disclosure of which is incorporated herein by reference in its entirety. [Field of invention] The present invention relates to on-grid communication applications for optimizing power distribution, and specifically to real-time identification and locating of non-technical losses occurring in service transformer area networks. [Background of invention] Distribution substations can step down the voltage from high transmission line levels (usually 130kV to 700kV) to intermediate voltage levels (usually 4kV to about 35kV) where power is distributed to consumers in the distribution service area. Includes substation transformers. At the edge of the distribution grid, there are numerous service transformers, which provide the intermediate voltage of the distribution grid to the low voltage required by commercial, industrial, and household consumers (usually in the United States). Convert to 120, 208, 240, 277, or 480). Other voltages in addition to some of these can be used elsewhere in the world. Each service transformer powers one or more measured loads. The load can be a residential, commercial or industrial building, an element of the municipal infrastructure, such as a series of street lights, or an agricultural device, such as an irrigation system.

With the exception of the wires that connect the consumer load and the associated meters to the service transformer, the service transformer is the outermost element of the distribution grid before the actual power is sent to the consumer. The meter is usually installed where the power from the service transformer is sent to the consumer. Service transformers can be three-phase, two-phase, or single-phase, as meters can. As used herein, a collection of electrical appliances, including a service transformer to a collection of at least two communication electric meters, is referred to as a transformer area network (TAN). The TAN can have a radial topology, as is common in the United States, for example, or it can have a linear or "bus" topology that is more common in Europe and elsewhere in the world.

Reading meters has traditionally been one of the largest operating costs borne by electric companies. The original electric meter was an analog device with a visual reader, which had to be manually inspected every month to carry out the utility billing process. In the early 1970s, mechanisms began to be deployed to digitize meter data and automate its collection. These mechanisms have evolved from walk-by or drive-by systems, where the meter is supposed to broadcast its current measurements using short-range radio signals. The short-range radio signal was received by a device carried by the person reading the meter. These early systems were known as automated meter reading systems, or AMRs. Later, various dedicated data acquisition networks began to be deployed that commonly used a combination of short-range RF repeaters in a mesh configuration and collection points with wideband backhaul means for transferring the collected measurements.

These networks, commonly referred to as advanced measurement infrastructures, or AMIs, allow bidirectional communication between the "measurement headend" at the utility service center and the meters at the edge of this data acquisition network. Met. The AMI can collect and store measurements frequently, usually on a frequency of about every 15 minutes, and can report those measurements approximately as often. The AMI can read any meter on demand and similarly connect or disconnect any meter on demand if this feature is used sparingly. AMI meters can pass signals to consumer devices for energy savings, requirements management, and variable rate billing. Since the AMI network is separate from the distribution grid except at the intersections in the meter, the AMI meter does not recognize or perceive changes in the grid topology or changes in certain conditions on the grid. Nevertheless, the introduction of AMIs is generally considered to be the beginning of a distributed smart grid. In addition, the mesh architecture commonly used in US AMIs severely limits the bandwidth available to individual electric meters to transmit data for the electric meters themselves.

The total billable kilowatt-hours produced by ordinary distribution grids anywhere in the world are substantially lower than the actual power distributed at distribution substations over the billing period. Power loss can be divided into two groups. Technical losses result from the overall impedance of the distribution infrastructure and from the power factor mismatch between what the load aggregate requires and what the grid produces at each load location, and is unpredictable. It arises from the use of excess supply voltage to ensure that no instantaneous power drops occur during peak loads. Businesses can work to minimize these technical losses, but some technical losses are unavoidable.

Non-technical loss of actual energy (as opposed to revenue) is power from the consumer who avoids or interferes with the measurement process by tampering with the meter or tapping the power line over the area under test. It results from theft. Non-technical loss of revenue also includes unpaid invoices by consumers and accounting errors by businesses. However, these types of revenue losses are addressed by meter data management systems integrated with advanced measurement infrastructure. These automated systems have the ability to prevent clerical errors, to prompt unpaid consumers to discontinue service immediately, and to require customers with inadequate payment history to enter a prepaid billing plan. Have. Because the AMI provides little or no information about the grid wiring diagram relationship between one electric meter and another, and the relationship between the electric meter and the service transformer that powers this electric meter. Little value in identifying the source of power theft. Some smart meters can detect and report tampering. On the other hand, the absence of meter readers in the suburbs reduces the chances of illegal taps being witnessed and reported.

The social and financial costs of electricity theft can be very variable. In the developing world, these costs are very high, sometimes exceeding 50% of the electricity sent from substations. In India, according to the Maharashtra State Electrical Regulatory Commission (MERC) of India, for example, major sole proprietorships (Reliance and Tata) report about 10% non-technical loss, while state-owned utilities , In most cases have a loss of over 30%.

In the developed world, theft losses represent a relatively small percentage of total power generation costs. In the United States, theft losses have traditionally been estimated at 1-3 percent of revenue, but this figure will increase during the recession.

Electricity theft represents safety and quality of service issues as well as financial issues. First aid power taps are dangerous and often result in injury or even death. In addition, first aid taps represent a fire hazard. Most significantly, the resulting unpredictable load on the distribution grid can result in transformer fires and explosions, which can lead to not only dangerous situations, but also major power outages. There is.

Prior art methods for detecting power theft can be divided into three categories. One category involves comparing the voltage and current in the meter to the voltage and current at the origin of transmission, for example service distribution transformers for suburbs. Since the technical loss due to the resistance of the low voltage line between the origin and each meter is estimated to be less than a given amount, any difference in power loss above a given amount is a theft or wiring defect. It can be presumed to be due to either. System and Method for Single and Multizonal Optimization of Utility Services Delivery and US Patent Application Publication No. 2012/0265355, entitled "Utilization", describes this type of system in which intelligent software agents in service transformers are positioned in transformer measurements and in electric meters or in electric meters. Collect both measurements from other instruments that are incorporated. Theft detection is described as one of the applications of this system. However, a system that involves installing agents and instruments in the transformer is less desirable than a system that does not require any devices in the transformer. The reason is that the transformer is not physically much more accessible than the socket of the meter, and the transformer is added by adding equipment inside the transformer housing or on the high voltage side of the transformer. Improvements can be costly and even more dangerous.

The second category includes measuring current and voltage outside the meter of the load under test and inside the facility of the load under test. If more power is being used at the facility than is delivered through the meter, the power is either locally generated at the facility or the meter is bypassed. This type of method is problematic for utilities. The reason is that service providers usually do not have access to data from within the measured load. Consumers will have to agree to install the device inside the facility.

The third category includes detecting momentary changes in power usage or minor power outages caused by tampering with distribution lines to install unmeasured taps. The mechanism in this category is inadequate. The reason is that tampering can be hidden by major events such as legal power outages or service interruptions, and tampering is likely to produce many false positives. [Outline of Invention] The present invention is a device and method for detecting and reporting power theft in real time or near real time so that the tampering site can be determined to have occurred on the low voltage side of a particular service transformer. In the case of meter tampering, one or more specific meters involved may be identified. The present invention does not require transformers (service transformers) at service delivery points. Performing measurements, collecting measurement results, processing the collected data, and finding evidence of power theft, all instruments and intelligent agents are electric where instruments and intelligence are likely to exist anyway. Positioned on the meter. This is because meter sockets are usually easily accessible, and the ability of smart meters to already include memory and processors for hosting software agents and to perform many of the measurements used by the methods of the invention. Most smart meters have additional circuits because they already have, and when the unique instruments, communication functions, and / or memory and processing functions are insufficient to support the methods described herein. It is advantageous because it is designed to accommodate the substrate.

A System and Method for inferring Schematic and Topological Properties of an Electrical Distribution, incorporated herein by reference. U.S. Patent Application No. 13 / 871,944, entitled "Grid," is smart with long-range (edge-substation) on-grid transmitters and similarly short-range (low-voltage local-service transformer-to-service transformer) on-grid transmitters and receivers. It states that the meter will be augmented. A smart meter that has both short-range and long-range on-grid transmission functions is called a remote hub. A smart meter that has only a short-range on-grid transmission function is called a lower remote. The term remote is used to generically refer to both subordinate remotes and remote hubs. A service transformer that has one remote hub and no subordinate remotes or has multiple subordinate remotes is defined as a transformer area network, or TAN. In addition, the application discloses a method for determining the feeders and phases that power the remote hub based on the characteristics of the long-range message sent from the remote hub.

Also incorporated herein by reference, "Methods for Discovering, Partitioning, Organizing, US Patent Application No. 13 / 888,102, entitled "and Administering Communication Devices in a Transformer Area Network," states that all remote hubs and subordinate remotes in the TAN are actually powered by the same service transformer. And teaches how to determine which remotes are in the same phase as remote hubs and which remotes are in different phases in the case of multiphase transformers. In addition, "A System and Method for Inferring Schematic Relationships between Load Points and Service US Pat. No. 13,911,849, incorporated herein by reference under the name Transformers, identifies, correlates, and associates with specific service transformers that supply a given meter socket and their geospatial coordinates. Describes how to incorporate the coordinates into the map of the distribution grid. Utilities already know at least the address of all meters, unless they have precise geospatial coordinates. Using the information obtained from the systems and methods in the applications referenced above, the physical and schematic sources of reports from the remote hub and the physical and schematic extent of the transformer area network represented by the remote hub. It may be defined very precisely. These inventions teach a transformer area network architecture that is essentially a master-slave, in which one remote, usually a remote hub, contains most of the intelligence and provides a simpler agent on the lower remote. Poll and organize the TAN and implement the application on the TAN. The system and method of the present invention are mainly described from the viewpoint of such TAN organization. However, the master-slave network organization is only one of the possible network organizations suitable for hosting the present invention. For example, peer-to-peer transformer area networks are also suitable. Wider peer-to-peer networks, such as AMI mesh networks, are also as described below in a) sufficient information for nodes in the network to logically divide the nodes themselves by transformer areas. And b) if there is sufficient bandwidth to share the measurements obtained by the measurement agents of the present invention.

The present invention provides a method for a remote hub that communicates with at least one subordinate remote, each remote installing the device in a TAN service transformer or inside a facility with a load powered by the TAN. Without having to measure and store the voltage in the meter and the current passing from the meter to the load under test, it can operate to identify signs of power theft occurring in the TAN. To this end, the TAN comprises at least two nodes on each phase of the TAN, for example one remote hub and one or more subordinate remotes. All loads on the TAN (measured service points) have a remote (or another type of communication meter) if complete anti-theft protection is achieved. The method can be used with some meters that do not have a remote, in which case some theft remains undetected, depending on the TAN topology and the location of unauthorized taps on the communication meter. Can be. Methods are taught to infer the presence and location of illegal taps that do not require measurement in TAN's service transformers. It is desirable to avoid the need to make measurements in service transformers. The reason is that the cost of simply adding fixtures in a meter is the cost of maintaining a network when all instruments and intelligence are only present in the meter, as is the cost of adding fixtures in both meters and transformers. This is because it is significantly lower than the cost of adding it. It is desirable to avoid the need to install equipment inside the facility at the service location to be measured. The reason is that the consent of the consumer is required to install the equipment inside the facility, and the maintenance of the equipment inside the facility is usually outside the scope of the utility's approval. Because there is.

The accompanying drawings, which are incorporated herein by reference and which form part of this specification, serve to illustrate and explain embodiments of the present invention as well as explain the principles of the present invention.<figref num="1">A radial topology transformer area with a transformer above the ground, power lines and three facilities under test is illustrated.</figref><figref num="2">It illustrates a bus topology transformer area with a pad-mounted transformer, an underground power line along a single tap, and three facilities under test.</figref><figref num="3">It illustrates a pad-mounted transformer, an underground power line, each with its own tap, and a radial topology transformer area with three facilities under test.</figref><figref num="4">The area of Figure 1 augmented to form a transformer area network with the addition of remote hubs and subordinate remotes is illustrated.</figref><figref num="5">It shows the transformer area network in Figure 4 with the addition of illegal non-measurement taps used to power the greenhouse.</figref><figref num="6">It shows the electrical details of a radial transformer area network, such as the radial transformer area network of FIGS. 4 and 5, which has an arbitrary number of N measured facilities (nodes).</figref>

[Detailed description of the invention] See FIG. 1, which illustrates a typical single-phase pole transformer 101 connected to a house 103 via an aerial power line 102. In the United States and many other places, this is a common configuration, especially in older areas. The power line to the house is usually attached to the eaves of the roof, and the power line runs down to the meter 104 in the conduit outside the house 103. Figure 2 symmetrically illustrates the bus topology for the transformer area, which is more common in parts of the world outside the United States. In FIG. 2, the pad-mounted transformer 201 is connected to the meters 206, 207, and 208 via a linear embedded wire 202 connected to the houses 203, 204, and 205, respectively. This topology is common in Europe and elsewhere in the world. A typical installation can accommodate more meters than shown. That is, the average number of meters per single-phase transformer in the United States is about six (6), while the average in Europe is several tens. FIG. 3 shows a typical US embedded cable installation, where the pad-mounted transformer 301 is radially connected to the meter 304 via the embedded cable 302 leading to the residential 303. These three basic configurations represent most distribution networks around the world with small local and polyphase variants for industrial and commercial applications. The present invention works with small variations on all three of these general topologies, as taught herein below. To teach this, each phase of a three-phase transformer could actually be organized as a single TAN, even if the three-phase transformer area is described in 13 / 888,102. Can also be considered as a separate TAN, but in 13 / 888,102, the phase of each node (eg, remote) in the TAN is known, and the transmission from the edge to the substation from the TAN is transmitted. Is sent on the relevant phase.

Reference here is FIG. 4 in which the transformer area of FIG. 1 is transformed into a transformer area network by replacing the ordinary meter in FIG. 1 with two lower remotes 402 and 404 and one remote hub 403. The clocks of the communication meters of the transformer area network were synchronized within known tolerances, as described in No. 13 / 871,944. The service transformer 401 is identical to the service transformer of FIG. 1 without any additional communication equipment or instruments. Note that the service location / house 405 has a nearby outlying house 406, such as a barn, which is not powered.

In one embodiment of the invention, measurement agents are present on each of the remotes 402, 404, and 403. Each agent periodically measures the voltage V sent and the current I flowing at its service location. A monitoring agent that may reside on the remote hub 403 periodically collects time-stamped current and voltage measurements from lower remotes 402 and 404 and from its own measurement agent. The period of the monitoring agent does not have to be the same as the period of the measurement agent, but the time during which the measurement is made is synchronized to the narrowest possible margin of error given the functionality of the TAN. Both cycles are very small with respect to the time scale of events in a typical AMI network, for example, meter measurements may be transmitted simply every 15 minutes or even less frequently. The monitoring agent compares current and voltage measurements taken simultaneously on different meters and uses the measurements to determine when unmeasured current is between the transformer and one or more measured service points. Execute a software algorithm that guesses if it is occurring.

In FIG. 5, a non-measurement tap 507 is electrically added at facility 505 between transformer 501 and meter 504. This tap has been used to electrify the detached house 506. Not only do these taps cause financial losses for utilities, but at peak loads they can pose a risk of transformer fires and explosions. The reason is that TAN as a whole may be drawing more power than the transformer's maximum rating.

FIG. 6 provides electrical details of a radial transformer area network, such as the networks of FIGS. 4 and 5. The TAN in FIG. 6 includes at least two service points, ie nodes, labeled 1 ... N herein. Power source 601 supplies transformer 607 with an intermediate voltage, which is indicated here by meter 627 at node 1 (605) and meter 629 at node N (610), within the transformer area. The voltage is stepped down by the transformer 607 to the low voltage range allowed by the meter. Current 604 represents the current flowing from the power source by all loads on the grid supported by power source 601. Impedance 603 represents the impedance of the intermediate voltage grid. The voltage on the low voltage side of transformer 607 fluctuates with changes in voltage 602, impedance 603, and current 604. None of these quantities are constant, not measurable, or known to software agents in meters (eg, 627 and 629, etc.), but voltage 602 is a known range of acceptable values. It can be expected to change around the nominal value within. For example, the general nominal value for voltage 602 may be 13.4KV in the United States (although other values are possible), while the general nominal value for voltage 606 may be 240V. , Other values are also possible. These nominal values may be known to the software agent.

Now consider the component inside the rectangle 605 that represents node 1. Node 1 comprises a device that powers the service transformer 607 to the meter 627. Interesting measurable quantities are marked on the diagram. Impedance 616 represents the legal measured load of the facility at Node 1, which can change over time depending on which instruments and devices are in use at the facility. Location 626 represents not the actual piece of equipment, but anywhere on the power line from transformer 607 to meter 627 where illegal taps can be installed. Impedance 612, which is usually significantly higher when no theft occurs, represents a possible unapproved unmeasured load. Impedances 609 and 613 represent the normal impedance of the power line from transformer 607 to meter 627. The voltage 611 represents the voltage of the virtual tap point 626. None of these quantities are known to or measurable by the software agent present on the meter 627. The current 614 and the voltage 615 are periodically measured by the measurement agent present on the meter 627 and shared on the TAN by the communication equipment on the meter 627. Regardless of TAN's network architecture, sharing is always done so that the identification of the meter from which the measurement was made and the time the measurement was made are known to any recipient of the message to which the measurement is sent. Note that element 622 in Figure 6 is not a feature of TAN, but an abbreviation indicating that any number of additional nodes may exist between node 1 605 and node N 610. ..

Similarly, consider the component within the rectangle 620 that represents node N. This is a device that sends power from the service transformer 607 to the meter 629. Impedance 625 represents the legal measured load of the facility at Node N, which can change over time depending on which instruments and devices are in use at the facility. Location 628 is not an actual feature of TAN, but represents anywhere on the power line from transformer 607 to meter 629 where illegal taps can be installed. Impedance 623, which is usually significantly higher when no theft occurs, represents a possible unapproved unmeasured load. Impedances 618 and 620 represent the normal impedance of the power line from transformer 607 to meter 629. The voltage 619 represents the voltage at the virtual tap point 628. None of these quantities are known to or measurable by the software agent present on the meter 627. The current 621 and the voltage 624 are periodically measured by the measuring agent present at the meter 629 and shared on the TAN by the communication device at the meter 629.

Due to the monitoring agent's algorithm, it does not matter whether the meter 629, meter 627, or the meter of another node between 1 and N has a remote hub, and which meter has a subordinate remote. In practice, as mentioned earlier herein, as long as all TAN meters provide sufficient bandwidth to share their measurements within a sufficiently short period of time. , Can be used as a whole. The TAN may host at least one monitoring agent somewhere on the TAN and a measurement agent on each communication meter. Some network architectures can make it more efficient to host a monitoring agent on every node. Alternatively, the work of the monitoring agent may be distributed among multiple communication meters. If the monitoring agent is not present on a meter that has the ability to send wide area messages, such as messages from the edge to the substation, the monitoring agent must send a command to send an anomaly report to the wide area capable device. It doesn't become.

It is assumed here that an unlicensed load, represented by impedance 612, is installed at location 626. More current (current drawn by an unlicensed load at 612) flows through impedance 609, resulting in a drop in voltage 611. This will also result in a drop in voltage of 615. However, the current 614 flowing through the impedance 613 does not drop correspondingly. The measurement agent on the meter 627, which can only measure current 614 and voltage 615, is that the drop in voltage 615 is simply due to the drop in voltage 606, or the drop in voltage 615 is with the drop in voltage 611 (always very very). It would be impossible to speculate whether it was caused by the theft represented by the decrease in impedance 612 (which should be large). However, consider the observations made by the measurement agent on the meter 629. For simplicity, it is assumed that the impedance 623 at node N (610) is reasonably high, i.e. power is not stolen at node N. The measurement agent on the meter 629 will observe the drop in voltage 624 due to the drop in voltage 606. The monitoring agent uses the measured currents 614 and 621 on the meters 627 and 629 (and yet another meter if there are more communication nodes in the TAN), respectively, and the appropriate voltage resulting from each measured load. The descent can be estimated. Once the effect of the load under test (616, 624) is removed, the adjusted magnitude of the voltage measured on each meter can be compared. Even if there are small differences in line impedance between the transformer 607 and each meter, these differences are expected to be negligible. (This example compares the impedance 609 + 613 to the meter 627 with the impedance 618 + 620 to the meter 629.) One meter, in this example 627, is within the tolerance that represents the normal difference in line impedance. Adjusted larger than the meter

In addition, this method of comparing current and voltage from each available "viewpoint" detects theft within the TAN, even in the presence of multiple theft locations. Even if there is an unmeasured load installed between all meters and transformers, the stolen location will be each measurement agent unless the impedances 612, 623, etc. due to the unlicensed load are always the same. Current and voltage readings can still be inferred by monitoring agents available. The reason is that the voltage drop at some measurement points will not be proportional to the current at the same point.

When a monitoring agent on the TAN remote hub detects a presumed theft, the remote hub may send a message from the edge to the substation that warns the utility about the anomaly. The message from the edge to the substation is a distribution substation that powers the substation transformer, here transformer 607, from a remote hub, as described in US Patent Application No. 13 / 871,944 referred to earlier. It is transmitted to the place. From the substation, messages are transferred over traditional networks to data centers provided by utilities or energy management service providers. Theft warnings can also be propagated via a remote hub, or another available network connected to another communication meter, such as an AMI network. Such a message may contain at least one unique identifier of a service transformer or meter in which an anomalous current-voltage relationship has been detected, which identifier to match the source of the message with the data in the gridmap database. May be used.

The method described herein above with slight computational adjustment may also be applied to transformer areas with bus topologies as shown, for example, in FIG. 2 rather than the radial topology as shown in FIGS. 1 and 3. .. In bus topology, the voltage drop from the transformer to the meter is additive as each node gets farther from the transformer. The reason is that the loads under test are connected in series rather than in parallel. Nevertheless, the contribution of each load under test to the voltage drop should be proportional to the current drawn at each meter. Whether the voltage drop in a given meter is greater than proportional to the measured current between the transformer and that meter is determined by the other meter, in this case specifically, among those connected in series with respect to the transformer. Based on time-stamped current and voltage measurements shared on the TAN by meters earlier than the measurement point in.

To apply this method in a TAN with a bus topology, the order of the nodes in the TAN with respect to the transformer needs to be known (at least) by the monitoring agent. This can be inferred by the monitoring agent. The ordering of the ones connected in series corresponds to the measured voltage at each measurement point, and the lowest voltage is the farthest from the transformer in the schematic. Referencing FIG. 2 again, the closest meter in the schematic to transformer 201 is 206 and the farthest meter in series is 208. This would be true even if facility 205 was geographically and spatially closer to transformer 201 than facility 203, which is certainly possible. This condition is also illustrated in FIG. Moreover, this schematic inference remains correct even in the event of power theft. The reason is that the resulting voltage drop is still cumulative.

U.S. Patent Applications 13 / 871,944, 13 / 888, 102, and 13 / 911, 849, all referenced above, teach methods for recording accurate grid maps of distribution networks. The grid mapping method taught by these inventions is to the feeder lines and phases of each substation that can operate to power each measured load supplied by the network, and to the transformer area network of the network's meters. Includes the correct current split of. To perform theft detection, the grid map of the TAN with the bus topology may be augmented by the order of the TAN meters connected in series, in which the meter and load are added to the TAN and removed from the TAN. Sometimes it can be kept up to date. In the case of theft detection, this information may only need to be maintained by the monitoring agents within each TAN, and in fact may be periodically recalculated by each monitoring agent. However, it may be useful to record this further information in a centralized grid map database, which is taught by No. 13 / 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 meters on the power line bus from the transformer. Similarly, if it is observed that the order of the nodes changes, for example after the expansion of the TAN due to a power outage or construction work, the new ordering may be reported in the edge-to-substation message recorded in the grid map database. Good.

Other methods of power theft that do not involve making illegal taps may be used. This method involves generating an erroneous order by a nearby person switching meters before increasing consumption. Any type of communication meter is already enabled to report disconnection from the meter socket if it is replugged into the meter socket (whether in the same socket or in a different socket) while power is available. Can be done. However, ambitious power theft can wait for a natural power outage to replace the meter for another facility, or can deliberately disrupt the network to cause a power outage to replace. There is. However, intelligent meters participating in transformer area networks with real-time grid mapping, as described in the related inventions also referred to herein, can detect illegal movement in a variety of ways: If two meters are swapped between two separate TANs, both TANs have discovered a new meter and lost communication with the meter that was previously part of the TAN. You may report. If the two meters are swapped so that the meters are out of phase, this change may be reported by the grid mapping agent. If two meters are switched in the same TAN and in the same phase, and if the TAN has a bus architecture, both meters will be detected as having a modified position with respect to their own service transformer. This may be reported by the monitoring agent. If the meter has geospatial position signals available, the grid mapping agent on the meter may report changes in position.

This leaves only one case of exchanging two meters that are not enabled to receive geospatial position signals between two facilities for the same phase of the same radial TAN, which case is not easily detected. This case may be undesirable in terms of theft due to the proximity of the facility, which better tampers with meter sockets several blocks away than the meter sockets of neighbors.

To manage the detection process, agents such as monitoring agents on at least one communication meter (such as a remote hub) on each TAN utilize edge-to-substation messages or an integrated grid map. Each of the detected anomalies may be reported using another available wide area network capable of forwarding messages to software programs residing in the data center where it is possible. The software program also receives reports of planned grid changes from other applications used to manage the grid. An example of such a report could be a job order used to dispatch a field engineer to make the required changes and repairs to the distribution grid. The software program avoids reporting false signs of theft by matching anomalous reports from communication meters with job orders or similar reports. The anomaly described by the job order is not reported as a possible indicator of theft. Anomalies that cannot be matched to job orders generate a warning that possible theft may have occurred, regardless of whether the anomaly is a grid map change or a voltage anomaly reported by a monitoring agent. To do. Theft warnings include account numbers and addresses of affected facilities, identities and geospatial coordinates of affected transformers and meters, and unlicensed unmeasured taps, even if stolen by moving the meter. Even if the theft is made by making it, it can contain any other relevant information that can be used to locate the theft.

The prior description of the invention is presented for illustration and illustration and is not intended to limit the invention to the exact form that is exhaustive or disclosed. Many modifications and modifications are possible in light of the above teachings. Embodiments have been selected and described to best illustrate the principles of the invention and its practical applications, thereby allowing those skilled in the art to use in various embodiments and as intended specific uses. Various modifications suitable for the present invention make it possible to make the best use of the present invention. It is intended that the scope of the invention is defined by the appended claims.