Method and system for dynamic fault detection in electric grid

Abstract

To provide electric transmission and distribution networks.SOLUTION: A system for detecting faults in an electric grid is provided, comprising: a plurality of grid measuring devices distributed in the electric grid and configured to be operative to measure current and / or voltage with their respective time of occurrence, enabling a user to define at least one fault type; and at least one rule for detecting the fault type, where the rule associates the fault type with at least one of the measurements, executes measurement, and analyzes the measurements according to the rule to detect a fault.SELECTED DRAWING: None

Description

[Technical Field]

[0001] The methods and apparatus disclosed herein relate to the field of electrical grids, and more particularly, but not exclusively, to electrical power transmission and distribution networks, and more particularly, but not exclusively, to detecting faults in electrical grids. [Background technology]

[0002] Electrical grids can have many faults. Various components of the electrical grid can fail, and faults can be instantaneous, gradual, or intermittent. Some faults can be caused by environmental factors such as humidity, smoke, dust, wind, trees, etc. Various faults and faults can have different characteristics and affect the network in different ways. Characterizing, detecting, identifying, and locating faults in electrical grids is a known problem. Therefore, it would be highly advantageous to not have the above limitations. Summary of the Invention [Means for solving the problem]

[0003] According to an exemplary embodiment, a system, method, and / or computer program is provided for detecting faults in an electrical grid, the system including a plurality of electrical grid measurement devices distributed within the electrical grid, the electrical grid measurement devices including current measurement sensors and / or voltage measurement sensors, the electrical grid measurement devices operative to measure at least one of current measurements and voltage measurements to form a plurality of measurements at their respective times of occurrence, the method, device, and computer program including the electrical grid measurement devices allowing a user to define at least one fault type, and at least one rule for detecting the at least one fault type, the rule associating the fault type with at least one of the measurements, performing the measurement, analyzing the measurement according to the at least one rule, and detecting the fault.

[0004] According to another exemplary embodiment, the measurements include at least one of absolute value, change in value, rate of change of value, instantaneous change of at least one of voltage, current, and power, transients, spikes, and surges.

[0005] According to yet another exemplary embodiment, the rule includes at least one of multiple measurements by a single grid measurement device performed substantially simultaneously, multiple measurements by a single grid measurement device performed at different times, and multiple measurements by multiple grid measurement devices performed during substantially the same time.

[0006] According to yet another exemplary embodiment, the system additionally measures at least one of cable temperature, wind speed, humidity, cable movement, cable height, cable depression, and cable angle. Furthermore, according to another exemplary embodiment, analyzing the measurements according to the rules and detecting faults includes correlating the current and / or voltage measurements with measurements of any of cable temperature, wind speed, humidity, cable movement, cable height, cable depression, cable angle, and time of day.

[0007] Still further, according to another exemplary embodiment, the fault is at least one of a cable of the power distribution network being contacted by an object, corrosion occurring on the cable, corrosion occurring on the clamp, damaged insulation on the cable, an ongoing current leakage associated with the cable, a bad connection, a hot spot, and a frayed cable.

[0008] Furthermore, according to another exemplary embodiment, the rule additionally includes measuring a difference between measurements of at least two electrical grid measurement devices, detecting a time-dependent change in the difference, and associating a fault with the time-dependent change.

[0009] Furthermore, according to another exemplary embodiment, the time-dependent change is at least one of monotonic, periodic, and repetitive.

[0010] Additionally, according to another exemplary embodiment, the rules determine a fault when two or more grid measurement devices each detect a time-dependent change, and if the two or more grid measurement devices detect time-dependent changes of different values.

[0011] According to yet another exemplary embodiment, the time-dependent change is repetitive and the fault is a cable of the power grid being contacted by the object.

[0012] According to yet another exemplary embodiment, the time-dependent change is monotonic and the fault is a current leakage occurring.

[0013] Furthermore, according to another exemplary embodiment, the time-dependent changes are periodic and correlated with at least one of time of day and temperature, and the failure is at least one of developing corrosion and damaged insulation.

[0014] Still further, according to another exemplary embodiment, rules can be defined to perform, collect, and communicate measurements, the rules and / or measurements being associated with a given fault.

[0015] Furthermore, according to another exemplary embodiment, the system communicates at least one of the measurements, results of analysis of the measurements according to the rules, and faults.

[0016] Furthermore, according to another exemplary embodiment, the system may request the first grid measurement device to perform at least one of the steps of performing at least one measurement, storing the at least one measurement, analyzing the at least one measurement and forming an analysis result, and communicating at least one of the at least one measurement and the analysis result, the request resulting from analysis of the at least one measurement performed by the second grid measurement device.

[0017] Additionally, according to another example embodiment, the request includes a time of measurement, the time of measurement being associated with a time of at least one measurement performed by the second grid measurement device.

[0018] According to yet another exemplary embodiment, the requested measurements are associated with a period surrounding the time of at least one measurement performed by the second grid measurement device.

[0019] According to yet another exemplary embodiment, the predetermined period of time is less than or equal to the transit time of the transient between the measuring device detecting the transient and the proximal measuring device according to the speed of the electrical signals in the cables of the power distribution network.

[0020] Furthermore, according to another exemplary embodiment, the step of communicating at least one of the measurements includes a plurality of low-resolution measurements and the request includes a request for a plurality of high-resolution measurements.

[0021] Still further, according to another exemplary embodiment, the resolution includes the time resolution and / or repetition rate of the multiple measurements.

[0022] Furthermore, according to another exemplary embodiment, the system may detect the time of multiple transients and corresponding measurements of the transients by a first measuring device, and report a transient in response to at least one of: a second measuring device located downstream of the first measuring device not detecting the transient within a predetermined period around the time of measurement of the transient detected by the first measuring device; and / or a second measuring device located downstream of the first measuring device detecting a repeating counter-transient within a predetermined period around the time of measurement of the transient detected by the first measuring device.

[0023] Furthermore, according to another exemplary embodiment, the predetermined period of time is less than or equal to the transit time of a transient between the first measuring device and the second measuring device according to the speed of the electrical signal in the cables of the power distribution network.

[0024] Additionally, according to another exemplary embodiment method, the system may detect repeated changes in value between successive measurements performed by a first measuring device within a period of time, and thus the rule may determine a fault where the repeated changes in value are substantially different from the changes in value between successive measurements within the period of time of at least one second measuring device proximal to the first measuring device.

[0025] Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by those skilled in the relevant art.The materials, methods, and examples provided herein are illustrative only and are not intended to be limiting.Except as necessary or inherent in the process itself, no particular order of steps or stages of the methods and processes described in this disclosure, including the figures, is intended or implied.In many cases, the order of process steps can be varied without changing the purpose or effect of the described method. The present invention provides, for example, the following items. (Item 1) 1. A method for detecting faults in an electrical grid, the method comprising: distributing, within the electrical grid, a plurality of electrical grid measurement devices comprising at least one of a current measuring sensor and a voltage measuring sensor, the electrical grid measurement devices operative to measure at least one of a current measurement and a voltage measurement to form a plurality of measurements at their respective times of occurrence; defining at least one fault type; defining at least one rule for detecting the at least one fault type, the rule associating the fault type with at least one of the measurements; performing said measurements; analyzing the measurements according to the at least one rule to detect faults; A method comprising: (Item 2) Item 10. The method of item 1, wherein the measurements comprise at least one of absolute value, change in value, rate of change of value, instantaneous change of at least one of voltage, current, and power, transients, spikes, and surges. (Item 3) The said rule is: a plurality of measurements by a single electrical grid measurement device, the measurements being performed substantially simultaneously; multiple measurements from a single grid measurement device, the measurements being performed at different times; a plurality of measurements by a plurality of electrical grid measurement devices, the measurements being performed substantially simultaneously; Item 1, the method comprising at least one of: (Item 4) In addition, Measuring at least one of cable temperature, wind speed, humidity, cable movement, cable height, cable depression, and cable angle Including, 4. The method of claim 3, wherein analyzing the measurements and detecting faults according to the at least one rule includes correlating at least one of the current measurements and the voltage measurements with at least one of the measurements of cable temperature, wind speed, humidity, cable movement, cable height, cable depression, cable angle, and time of day. (Item 5) The failure is a cable of the power distribution network being contacted by an object; Corrosion occurring in the cable; Corrosion occurring on clamps and damaged insulation of the cable; an ongoing current leakage associated with said cable; and Bad connections and Hot spots and Frayed cables and Item 5. The method according to item 4, wherein the method is at least one of the following: (Item 6) The said rule additionally provides: measuring a difference between measurements of at least two electrical grid measurement devices; detecting a time-dependent change in said difference; Associating a fault with said time-dependent change; Item 3. The method according to item 3, comprising: (Item 7) 7. The method of claim 6, wherein the time-dependent change is at least one of monotonic, periodic, and repetitive. (Item 8) Item 7. The method of item 6, wherein at least two electrical grid measurement devices each detect the time-dependent change, and the at least two electrical grid measurement devices detect the time-dependent change of different values. (Item 9) 7. The method according to claim 6, wherein the time-dependent change is repetitive and the fault is a cable of the power distribution network being contacted by an object. (Item 10) 7. The method of claim 6, wherein the time-dependent change is monotonic and the fault is an ongoing current leakage. (Item 11) 7. The method of claim 6, wherein the time-dependent change is periodic and correlated with at least one of time of day and temperature, and the failure is at least one of developing corrosion and damaged insulation. (Item 12) In addition, Item 10. The method of item 1, further comprising defining rules for at least one of performing the measurements, collecting the measurements, and communicating the measurements, the rules being associated with faults. (Item 13) In addition, Item 10. The method of item 1, including communicating at least one of the measurement, the results of the analysis of the measurement according to the rules, and the fault. (Item 14) In addition, a first electrical grid measurement device; performing at least one measurement; storing said at least one measurement; analyzing said at least one measurement to form an analysis result; communicating at least one of the at least one measurement and the analysis result; Requesting that at least one of the following be performed: Including, Item 14. The method of item 13, wherein the request results from an analysis of at least one measurement performed by a second electrical grid measurement device. (Item 15) Item 15. The method of item 14, wherein the request comprises a time of measurement, the time of measurement being associated with a time of at least one measurement performed by the second grid measurement device. (Item 16) Item 16. The method of item 15, wherein the requested measurements are associated with a period surrounding the time of at least one measurement performed by the second grid measurement device. (Item 17) 17. The method of claim 16, wherein the predetermined period of time is less than or equal to the travel time of the transient between the measuring device detecting the transient and the proximal measuring device according to the speed of electrical signals in the cables of the power distribution network. (Item 18) communicating at least one of the measurements comprises a plurality of low-resolution measurements; Item 15. The method of item 14, wherein the request comprises a request for a plurality of high-resolution measurements. (Item 19) Item 19. The method of item 18, wherein the resolution comprises at least one of a time resolution and a repetition rate of the plurality of measurements. (Item 20) In addition, Detecting a plurality of transients detected by a first measurement device and times of corresponding measurements of said transients; reporting the transient, said reporting comprising: a second measuring device located downstream of the first measuring device does not detect a transient within a predetermined period of time around the time of the measurement of the transient detected by the first measuring device; a second measuring device located downstream of the first measuring device detects a repeating counter transient within a predetermined period around the time of the measurement of the transient detected by the first measuring device; and Item 1. The method according to item 1, comprising: (Item 21) 21. The method according to claim 20, wherein the predetermined period of time is less than or equal to the travel time of the transient between the first measuring device and the second measuring device according to the speed of the electrical signal in the cables of the power distribution network. (Item 22) In addition, Detecting repeated changes in value between successive measurements performed by the first measuring device within a period of time; determining a fault where the repeated change in value is substantially different from a change in value between successive measurements within the period of time of at least one second measuring device proximal to the first measuring device; Item 1. The method according to item 1, comprising: (Item 23) A computer program product embodied on a non-transitory computer-readable medium, the non-transitory computer-readable medium including instructions that, when executed by at least one processor, cause the processor to: defining at least one fault type in the electrical grid; defining at least one rule for detecting the at least one fault type, the rule associating the fault type with at least one type of measurement; performing a plurality of measurements, the measurements being performed by a plurality of grid measurement devices distributed within the grid, the grid measurement devices comprising at least one of a current measurement sensor and a voltage measurement sensor, the grid measurement devices operative to measure at least one of a current measurement and a voltage measurement and form a plurality of measurements at their respective times of occurrence; analyzing the measurements according to the at least one rule to detect faults; 2. A computer program product for causing a computer to perform operations including: (Item 24) 24. The computer program product of claim 23, wherein the measurements comprise at least one of absolute value, change in value, rate of change of value, instantaneous change of at least one of voltage, current, and power, transient, spike, and surge. (Item 25) The said rule is: a plurality of measurements by a single electrical grid measurement device, the measurements being performed substantially simultaneously; multiple measurements from a single grid measurement device, the measurements being performed at different times; a plurality of measurements by a plurality of electrical grid measurement devices, the measurements being performed substantially simultaneously; 24. The computer program product of claim 23, comprising at least one of: (Item 26) In addition, measuring at least one of cable temperature, wind speed, humidity, cable movement, cable height, cable depression, and cable angle; 26. The computer program product of claim 25, wherein analyzing the measurements and detecting faults according to the at least one rule includes correlating at least one of the current measurements and the voltage measurements with at least one of the measurements of cable temperature, wind speed, humidity, cable movement, cable height, cable depression, cable angle, and time of day. (Item 27) The failure is a cable of the power distribution network being contacted by an object; Corrosion occurring in the cable; Corrosion occurring on clamps and damaged insulation of the cable; an ongoing current leakage associated with said cable; and Bad connections and Hot spots and Frayed cables and 27. The computer program product of item 26, wherein the computer program product is at least one of: (Item 28) The said rule additionally provides: measuring a difference between measurements of at least two electrical grid measurement devices; detecting a time-dependent change in said difference; Associating a fault with said time-dependent change; 26. The computer program product of item 25, comprising: (Item 29) Item 29. The computer program product of item 28, wherein the time-dependent change is at least one of monotonic, periodic, and repetitive. (Item 30) Item 29. The computer program product of item 28, wherein at least two electrical grid measurement devices each detect the time-dependent change, and wherein the at least two electrical grid measurement devices detect the time-dependent change of different values. (Item 31) Item 29. The computer program product of item 28, wherein the time-dependent change is repetitive and the fault is a cable of the power distribution network being contacted by an object. (Item 32) Item 29. The computer program product of item 28, wherein the time-dependent change is monotonic and the fault is a current leakage occurring. (Item 33) Item 29. The computer program product of item 28, wherein the time-dependent changes are periodic and correlated with at least one of time of day and temperature, and the failure is at least one of developing corrosion and damaged insulation. (Item 34) In addition, 24. The computer program product of claim 23, further comprising defining rules for at least one of performing the measurements, collecting the measurements, and communicating the measurements, the rules being associated with faults. (Item 35) In addition, Item 24. The computer program product of item 23, including communicating at least one of the measurement, the results of the analysis of the measurement according to the rules, and the fault. (Item 36) In addition, a first electrical grid measurement device; performing at least one measurement; storing said at least one measurement; analyzing said at least one measurement to form an analysis result; communicating at least one of the at least one measurement and the analysis result; Requesting that at least one of the following be performed: Including, Item 36. The method of item 35, wherein the request results from an analysis of at least one measurement performed by a second electrical grid measurement device. (Item 37) Item 37. The computer program product of item 36, wherein the request comprises a time of measurement, the time of measurement being associated with a time of at least one measurement performed by the second electrical grid measurement device. (Item 38) Item 38. The computer program product of item 37, wherein the requested measurements are associated with a period surrounding the time of at least one measurement performed by the second electrical grid measurement device. (Item 39) Item 39. The computer program product of item 38, wherein the predetermined period of time is less than or equal to a travel time of the transient between the measuring device detecting the transient and the proximal measuring device according to a speed of electrical signals in cables of the power distribution network. (Item 40) communicating at least one of the measurements comprises a plurality of low-resolution measurements; Item 37. The computer program product of item 36, wherein the request comprises a request for a plurality of high-resolution measurements. (Item 41) Item 41. The computer program product of item 40, wherein the resolution comprises at least one of a time resolution and a repetition rate of the plurality of measurements. (Item 42) In addition, Detecting a plurality of transients detected by a first measurement device and times of corresponding measurements of said transients; reporting the transient, said reporting comprising: a second measuring device located downstream of the first measuring device does not detect a transient within a predetermined period of time around the time of the measurement of the transient detected by the first measuring device; a second measuring device located downstream of the first measuring device detects a repeating counter transient within a predetermined period around the time of the measurement of the transient detected by the first measuring device; and 24. The computer program product of item 23, comprising: (Item 43) Item 43. The computer program product of item 42, wherein the predetermined period of time is less than or equal to a travel time of the transient between the first measuring device and the second measuring device according to a speed of an electrical signal in a cable of the power distribution network. (Item 44) In addition, Detecting repeated changes in value between successive measurements performed by the first measuring device within a period of time; determining a fault where the repeated change in value is substantially different from a change in value between successive measurements within the period of time of at least one second measuring device proximal to the first measuring device; 24. The computer program product of item 23, comprising: (Item 45) 1. A system for detecting faults in an electrical grid, the system comprising: a plurality of grid measurement devices distributed within the grid, each of the grid measurement devices comprising at least one of a current measurement sensor and a voltage measurement sensor, the grid measurement devices operative to measure at least one of a current measurement and a voltage measurement and form a plurality of measurements at their respective times of occurrence; at least one computing device communicatively coupled to the plurality of electrical grid measurement devices and configured to receive the plurality of measurements from the plurality of electrical grid measurement devices at their respective times of occurrence; Equipped with the at least one computing device is configured to analyze the measurements and detect faults according to the at least one rule, the rule being configured to associate a fault type with at least one of the measurements. (Item 46) Item 46. The system of item 45, wherein the measurements comprise at least one of absolute value, change in value, rate of change of value, instantaneous change of at least one of voltage, current, and power, transient, spike, and surge. (Item 47) The said rule is: a plurality of measurements by a single electrical grid measurement device, the measurements being performed substantially simultaneously; multiple measurements from a single grid measurement device, the measurements being performed at different times; a plurality of measurements by a plurality of electrical grid measurement devices, the measurements being performed substantially simultaneously; Item 46. The system of item 45, comprising at least one of: (Item 48) At least one of the plurality of electrical grid measurement devices additionally comprises: at least one sensor configured to measure at least one of a cable temperature, a wind speed, a humidity, a cable movement, a cable height, a cable depression angle, and a cable angle; Item 48. The system of item 47, wherein the rules additionally include correlating at least one of the current measurements and the voltage measurements with at least one of the measurements of cable temperature, wind speed, humidity, cable movement, cable height, cable depression, cable angle, and time of day. (Item 49) The failure is a cable of the power distribution network being contacted by an object; Corrosion occurring in the cable; Corrosion occurring on clamps and damaged insulation of the cable; an ongoing current leakage associated with said cable; and Bad connections and Hot spots and Frayed cables and Item 5. The system according to item 4, wherein the system is at least one of: (Item 50) The said rule additionally provides: measuring a difference between measurements of at least two electrical grid measurement devices; detecting a time-dependent change in said difference; Associating a fault with said time-dependent change; Item 48. The system of item 47, comprising: (Item 51) Item 51. The system of item 50, wherein the time-dependent change is at least one of monotonic, periodic, and repetitive. (Item 52) Item 51. The system of item 50, wherein at least two electrical grid measurement devices each detect the time-dependent change, and wherein the at least two electrical grid measurement devices detect the time-dependent change of different values. (Item 53) Item 51. The system of item 50, wherein the time-dependent change is repetitive and the fault is a cable of the power grid being contacted by an object. (Item 54) Item 51. The system of item 50, wherein the time-dependent change is monotonic and the fault is a current leakage occurring. (Item 55) Item 51. The system of item 50, wherein the time-dependent change is periodic and correlated with at least one of time of day and temperature, and the failure is at least one of developing corrosion and damaged insulation. (Item 56) Item 46. The system of item 45, wherein the rules additionally include at least one of performing the measurements, collecting the measurements, and communicating the measurements, and the rules are associated with a fault. (Item 57) At least one of the computing device and a first electrical grid measurement device: analyzing at least one measurement performed by a second electrical grid measurement device; and communicating a request to the second grid measurement device, the request comprising: performing at least one measurement; storing said at least one measurement; analyzing said at least one measurement to form an analysis result; communicating at least one of the measurements and the analysis results to the at least one of the computing device and a first electrical grid measurement device; and Item 46. The system of item 45, operative to implement (Item 58) Item 58. The system of item 57, wherein the request comprises a time of measurement, the time of measurement being associated with a time of at least one measurement performed by the second electrical grid measurement device. (Item 59) Item 59. The system of item 58, wherein the requested measurements are associated with a period surrounding the time of at least one measurement performed by the second electrical grid measurement device. (Item 60) Item 59. The system of item 59, wherein the predetermined period of time is less than or equal to the travel time of the transient between the measuring device detecting the transient and the proximal measuring device according to the speed of electrical signals in the cables of the power distribution network. (Item 61) Item 58. The system of item 57, wherein at least one of the computing device and the first electrical grid measurement device operates to communicate a request for a plurality of high-resolution measurements. (Item 62) Item 62. The system of item 61, wherein the resolution comprises at least one of a time resolution and a repetition rate of the plurality of measurements. (Item 63) The measurements may additionally comprise transient measurements, and the rules may additionally include: Detecting a fault, said detecting comprising: a first measuring device located downstream of a second measuring device does not detect a transient within a predetermined period of time around the time of measurement of the transient detected by said second measuring device; a first measuring device located downstream of a second measuring device detecting a repetitive counter-transient within a predetermined period around the time of measurement of the transient detected by said second measuring device; and Item 46. The system of item 45, comprising: (Item 64) Item 64. The system of item 63, wherein the predetermined period of time is less than or equal to the travel time of the transient between the first measuring device and the second measuring device according to the speed of the electrical signal in the cables of the power distribution network. (Item 65) Item 46. The system of item 45, wherein the rules additionally include determining a fault when a repeated change in value is substantially different from a change in value between successive measurements within a period of time of at least one second measuring device proximal to the first measuring device, the first measuring device detecting the repeated change in value between successive measurements performed within the period of time. [Brief explanation of the drawings]

[0026] Various embodiments are described herein, by way of example only, with reference to the accompanying drawings. Referring now specifically to the drawings in detail, it is emphasized that the details shown are for purposes of illustration and are solely for purposes of illustrative discussion of preferred embodiments, and are presented to provide what is believed to be the most useful and readily understood explanation of the principles and conceptual aspects of the embodiments. In this regard, no attempt is made to show structural details of the embodiments in more detail than is necessary for a fundamental understanding of the subject matter; the description taken in conjunction with the drawings will make apparent to those skilled in the art how several forms and structures may be embodied in practice.

[0027] [Figure 1] FIG. 1 is a simplified illustration of an electrical grid measurement device mounted on an electrical cable. [Figure 2] FIG. 2 is a simplified illustration of multiple grid measurement devices distributed over various cable sections of an electric power transmission or distribution network. [Figure 3] FIG. 3 is a simplified schematic diagram of an electrical grid measurement system. [Figure 4] FIG. 4 is a simplified block diagram of a computing device or system used within an electrical grid metering system. [Figure 5] FIG. 5 is a block diagram of a dynamic fault detection software program used by the electrical grid measurement system. [Figure 6] Figure 6 is a flow chart of the measurement analysis. [Figure 7] FIG. 7 is a flow chart of the measurement scan procedure. [Figure 8] FIG. 8 is a schematic diagram of a portion of an electrical grid having a fault, where the location of the fault is determined by two or more electrical grid measurement devices. DETAILED DESCRIPTION OF THE INVENTION

[0028] The present embodiments comprise methods and systems for detecting faults in electrical networks, and more particularly, but not exclusively, for detecting dynamic faults. The principles and operation of devices and methods for detecting dynamic faults, according to some illustrative embodiments, may be further understood with reference to the following drawings and accompanying description.

[0029] Before describing at least one embodiment in detail, it is to be understood that the embodiments are not limited in their application to the details of construction and the arrangements of components set forth in the following description or illustrated in the drawings. Other embodiments may be practiced or carried out in various ways. Also, it is to be understood that the phraseology and terminology employed herein is for the purpose of description and should not be regarded as limiting.

[0030] Herein, elements of a drawing labeled with a number that is not described within the drawing but is described in a previous drawing have the same use and description as the previous drawing. Similarly, elements identified in the text by a number that does not appear in the drawing described by the text have the same use and description as the previous drawing in which it is described.

[0031] The drawings herein may not be to any particular scale. Different figures may use different scales, and different scales, for example, different scales for different views of the same object, or different scales for two adjacent objects, may be used even within the same drawing.

[0032] The objective of the embodiment is to determine the presence of a fault, the type or characteristics of the fault, and its location by measuring various electrical parameters at multiple locations in the electrical network and comparing the multiple measurements.

[0033] The term "electric grid" may refer to an electric transmission network and / or distribution network, and any portion of such a network between one or more power plants and loads or consumers.

[0034] The terms "measurement" or "electrical measurement" may refer to any type of measurement of any electrical parameter, such as voltage, current, electric field, magnetic field, resistance, capacitance, inductance, charge, etc.

[0035] The terms "physical measurement" or "mechanical measurement" may refer to any type of measurement of any physical parameter other than an electrical parameter. Such parameters may be temperature, wind, humidity, movement, height, (cable) depression, (cable) angle, etc.

[0036] Reference is now made to FIG. 1, which is a simplified illustration of an electrical grid measurement device 10 mounted on an electrical cable 11, according to one exemplary embodiment.

[0037] 1, the electric grid measurement device 10 may include a box or body 12 through which an electric cable 11 passes. The electric cable 11 may be part of an electric grid, transmission network, or distribution network such as that maintained by an electric utility company to provide electricity to the public, factories, etc. The electric grid measurement device 10 may therefore be mounted on a live cable 11, i.e., the cable 11 is fully powered and / or carries voltage and / or current.

[0038] Box 12 is therefore constructed in two pieces that can be opened and then closed around cable 11. Alternatively, box 12 may be constructed in one piece that encloses most of the cable diameter and has an opening on one side to allow the box to be fitted over cable 11.

[0039] 1 , electric grid measurement device 10 may include a power supply module 13, a controller module 14, one or more electrical measurement devices 15, one or more physical measurement devices 16, and a backhaul communication module 17. Optionally, electric grid measurement device 10 may also include a local area communication module 18, a remote sensing module 19, and a propulsion control module 20.

[0040] 1, the electric grid measurement device 10 may include a magnetic core 21 around which at least one coil is wound to form a winding 22. The magnetic core 21 may be mounted around the electric cable 11. The magnetic core 21 may be constructed from two pieces, one piece in each of the two pieces of the box 12, and the two pieces of the magnetic core 21 are closed around the electric cable 11 when the box 12 is closed around the electric cable 11. FIG. 1 shows the electric grid measurement device 10 in an open state with one piece of the box 12 removed but with the magnetic core 21 closed around the electric cable 11.

[0041] The magnetic core 21 typically derives a magnetic field from the current flowing in the electrical cable 11. The windings 22 typically derive a current from the magnetic flux in the magnetic core 21. The windings 22 may be electrically coupled to a power supply module 13, which typically provides voltage to the other modules of the electrical grid measurement device 10, as shown in FIG. 1. It is understood that the electrical grid measurement device 10 may derive power from a single electrical cable 11.

[0042] Alternatively, for example, when used with insulated high-voltage cables and / or underground cables and / or low-voltage power grids, the power supply module 13 may be connected to sensors attached to electrical cables deriving power from a main unit connected to the low-voltage output of a transformer. Such a configuration of the power grid measuring device 10 may have only one part with an opening at the bottom.

[0043] The backhaul communication module 17 and the local area communication module 18 may each and / or both be coupled to one or more antennas 23. The remote sensing module 19 may be coupled to and control various sensors, one or more cameras 24, one or more microphones 25, etc. It will be appreciated that the cameras may be mounted on an axel system that provides three-dimensional rotation. Alternatively, multiple or numerous fixed cameras may be mounted to cover a wide field of view as needed.

[0044] The backhaul communication module 17 and the local area communication module 18 may use any type of communication technology and / or communication network, such as, but not limited to, the terms “communication technology” or “communication network,” or simply “network,” refer to any type of communication medium, including, but not limited to, fixed (wire, cable) networks, wireless networks, and / or satellite networks, fixed or wireless wide area networks (WANs) including various types of cellular networks, fixed or wireless local area networks (LANs) including Wi-Fi, and fixed or wireless personal area networks (PANs) including Bluetooth, ZigBee, and NFC, power line carrier (PLC) communication technologies, etc. The terms “communication network” or “network” may refer to any number of networks and any combination of networks and / or communication technologies.

[0045] Optionally, the electrical grid measurement device 10 may also include a Global Positioning Service (GPS) module 26, which may be used to measure, monitor, and / or control the position of the electrical grid measurement device 10 along the electrical cable 11. The GPS module 26 may also provide an accurate general-purpose clock, for example, to accurately determine the absolute time of a measurement.

[0046] The controller module 14 may include a processor unit, one or more memory units (e.g., random access memory (RAM), non-volatile memory such as flash memory, etc.), and one or more storage units (e.g., including hard disk drives and / or non-removable storage drives, etc.) that may be used to store and / or execute software programs and associated data and to communicate with external devices.

[0047] The propulsion control module 20 may be coupled to one or more actuation devices, such as an electric motor 27, which may be coupled to one or more wheels 28. The wheels 28 may be mounted on the cable 11 such that the propulsion control module 20 can control the electric motor 27 to move the electric grid measurement device 10 along the cable 11.

[0048] It will be understood that the propulsion system of the electrical grid measurement device 10 (including, but not limited to, the propulsion control module 20, one or more electric motors 27, one or more wheels 28, etc.) may operate to move the electrical grid measurement device 10 along the cable 11 and / or to rotate the electrical grid measurement device 10 around the cable 11.

[0049] Electric motor 27 is understood herein to represent any type of technology suitable for operating electrical grid measurement device 10 along and / or around cable 11, including, but not limited to, an AC motor, a DC motor, a stepper motor, a pneumatic pump and / or motor, a hydraulic pump and / or motor, or any other type of actuator.

[0050] Reference is now made to Figure 2, which is a simplified illustration of a plurality of electrical grid measurement devices 10 distributed across various cable sections of an electrical transmission or distribution network 29, according to one exemplary embodiment. Optionally, the illustration of Figure 2 may be viewed in conjunction with the details of the previous figure. However, of course, the illustration of Figure 2 may be viewed in conjunction with any desired environment. Furthermore, the foregoing definitions may be equally applicable to the following description.

[0051] As shown in FIG. 2, the power transmission or distribution network 29 may include multiple sections of electrical cable 11, and the power distribution grid measurement device 10 may be mounted on any section of the electrical cable 11, including consecutive sections (carrying the same electrical phase) and parallel sections (carrying different electrical phases).

[0052] As shown in Figure 2, the grid measurement devices 10 may communicate among themselves using, for example, the backhaul communication module 17 shown and described with reference to Figure 1. The grid measurement devices 10 may, for example, form a mesh network 30.

[0053] 2, the grid metering devices 10 may use their backhaul communication modules 17 and / or mesh network 30 to communicate with an area controller 31. The area controller 31 may communicate with, for example, a central controller or server 32 using a wide area wireless communication network (e.g., a WAN) such as a cellular network 33. It will be appreciated that, optionally, the grid metering devices 10 may also communicate directly with the central controller or server 32 via the WAN.

[0054] As shown in FIG. 2, the power grid measurement devices 10 may also use their local area communication modules 18 shown and described with reference to FIG. 1 to communicate with a communication terminal 34, such as a smartphone, within the range of a local area network 35.

[0055] As the grid measurement devices 10 move about their individual cable segments, the mesh network 30 may change its topology. It is understood that such changes in the topology of the mesh network 30 may cause one or more of the grid measurement devices 10 to disconnect from the mesh network 30 and, consequently, from the area controllers 31 and / or the central controller 32. It is also understood that when a first grid measurement device 10 is disconnected, it may also disconnect other grid measurement devices 10 that rely on the first grid measurement device 10 for connectivity with the mesh network 30. It is also understood that a grid measurement device 10 may fail, disconnecting a portion of the mesh network 30 (e.g., one or more grid measurement devices 10) from the remainder of the mesh network 30.

[0056] When multiple grid measurement devices 10 are mounted within a particular portion of the power transmission or distribution network 29, they arrange themselves in at least one particular topology (structure) of the mesh network 30, with all grid measurement devices 10 within range of the mesh network 30. This particular topology or structure of the mesh network 30 is recorded by the individual grid measurement devices 10 as the standard or default topology. The grid measurement devices 10 record their locations within their respective segments of the electrical cable 11, for example, by recording their respective GPS data in non-volatile memory.

[0057] The process of organizing and recording one or more standard or default topologies or structures of the mesh network 30 and the individual locations of each of the electric grid measurement devices 10 may be performed under the control or supervision of the local area controller 31.

[0058] It will be appreciated that some such standard or default topologies or structures of mesh network 30 are created with the goal that any failed grid measurement device 10 cannot disconnect its portion of the mesh network 30. For example, there may be a standard or default topology or structure of mesh network 30 such that if a particular grid measurement device 10 fails, all other grid measurement devices 10 can communicate.

[0059] When the grid measurement device 10 is disconnected from the network, it may automatically position itself at its individual location within such a standard or default topology or structure of the mesh network 30. Specifically, when the grid measurement device 10 senses that it has been disconnected from the mesh network 30, it automatically returns to its default location, for example, as indicated by GPS data stored in non-volatile memory as described above.

[0060] The multiple standard or default topologies or structures may be ordered, and the electrical grid measurement device 10 may scan the standard or default topologies or structures according to their order when disconnected from the network.

[0061] To resolve a situation where one or more grid measurement devices 10 are disconnected, some of the grid measurement devices 10 may select a particular standard topology, and other portions of the grid measurement devices 10 may scan the standard topologies until all operational grid measurement devices 10 are in communication.

[0062] For example, the area controller 31 may select a standard topology according to the identification of the one or more disconnected grid measurement devices 10, and instruct the connected grid measurement devices 10 to form this standard topology and wait for the one or more disconnected grid measurement devices 10 to connect. This process may be repeated until all of the one or more disconnected grid measurement devices 10 connect to the mesh network 30 or until it is determined that one or more of the grid measurement devices 10 has failed.

[0063] Alternatively, to reduce the risk of losing connectivity with a majority of the grid measurement devices 10, the area controller 31 may operate a single grid measurement device 10 at a time. The area controller 31 may instruct all other grid measurement devices 10 to position themselves in their default locations or in a particular standard topology, for example, selected to allow the operating grid measurement device 10 to progress along its cable segment without interrupting its connectivity to the mesh network 30.

[0064] When the grid measurement device 10 performs an action such as "positioning itself", "returning (to a default location)", "moving along its cable section", "changing topology", "forming a topology", "scanning a topology", etc., it is understood that the action refers to the grid measurement device 10 maneuvering itself along the cable 11 using its propulsion control module 20, electric motors 27, wheels 28, etc.

[0065] Reference is now made to FIG. 3, which is a simplified schematic diagram of an electrical grid measurement system 36, according to one embodiment.

[0066] 3, the grid measurement system 36 may include a plurality of grid measurement devices 37 distributed across a power transmission network 38. The grid measurement system 36 may also include at least one area controller 39. One of the area controllers 39 may be, for example, a master central controller 40 located upstream.

[0067] Some of the electrical grid measurement devices 37 may be single-phase devices, such as electrical grid measurement device 10 of Figure 1, and connected to a single cable 11, while other electrical grid measurement devices 37 are three-phase devices. Three-phase devices differ from single-phase devices by having at least one electrical measurement device for each phase, and therefore connected to three cables 11.

[0068] The area controllers 39 may communicate with the grid measurement devices 37 using any suitable communication technology. The area controllers 39 may each control a different section of the power transmission network 38. Optionally, the sections controlled by different area controllers 39 are at least partially overlapping, providing redundancy, so that the grid measurement system 36 is resilient to failure of one or more area controllers 39.

[0069] It is understood that the area controllers 39 may be connected to a cable-based communication network, which may be an Internet Protocol (IP)-based communication network. It is understood that one or more of the multiple area controllers 39 are used as a master central controller for controlling the other area controllers 39.

[0070] The grid metering system 36 can use short-range or long-range communication technologies, whether using wired, wireless, PLC, or any other communication technology. Using long-range communication technologies (wired, wireless, PLC, etc.), the grid metering devices 37 may communicate directly with their area controllers 39.

[0071] Alternatively, using short-range communication technologies (wired, wireless, PLC, etc.), the grid metering devices 37 may communicate with their neighboring grid metering devices 37, which relay the communication upstream until it reaches the master central controller 40, and vice versa. Figure 3 shows an area controller 39 communicating with the grid metering devices 37 using a communication unit 41. The communication unit 41 may use any type of communication technology, including wired, wireless, and / or PLC technologies, and specifically cellular, Wi-Fi, Bluetooth, ZigBee, etc.

[0072] For example, the grid metering devices 37 may use PLC or RF communication technologies such as Wi-Fi, Bluetooth, and / or ZigBee to communicate with the area controllers 39, while the area controllers 39 may use wired, WiMAX, and / or cellular technologies to communicate with the master central controller 40. Each of these devices may include two different communication technologies to provide redundancy and backup.

[0073] The grid measurement devices 37 may communicate directly with the master central controller 40 or indirectly through the area controllers 39. The area controllers 39 may communicate with the master central controller 40.

[0074] The power transmission network 38 is a three-phase transmission network, however, it will be understood that other configurations are possible.

[0075] Reference is now made to Figure 4, which is a simplified block diagram of a computing device or system 42, according to one exemplary embodiment. Optionally, the block diagram of Figure 4 may be viewed in the context of the details of previous figures. However, it should be understood that the block diagram of Figure 4 may be viewed in the context of any desired environment. Furthermore, the foregoing definitions may apply equally to the following description.

[0076] Computing system 42 is a block diagram of a computing device that may be used for area controller 31 and / or central controller 32, and area controller 39 and / or central controller 40 of Figure 2. Computing system 42 may execute any software program, such as for analyzing measurements made by any one or more of electrical grid measurement devices 10 of Figure 2 and / or electrical grid measurement device 37 of Figure 3.

[0077] As shown in FIG. 4, the computing system 42 may include at least one processor unit 43, one or more memory units 44 (e.g., random access memory (RAM), non-volatile memory such as flash memory, etc.), and one or more storage units 45 (e.g., including hard disk drives and / or removable storage drives representing floppy disk drives, magnetic tape drives, compact disk drives, flash memory devices, etc.).

[0078] The computing system 42 may also include one or more communication units 46, one or more graphics processors 47 and displays 48, and one or more communication buses 49 connecting the above units.

[0079] Computing system 42 may also include one or more computer programs 50 or computer control logic algorithms, which may be stored in any of memory unit 44 and / or storage unit 45. Such computer programs, when executed, enable computing system 42 to perform various functions as described herein. Memory unit 44 and / or storage unit 45 and / or any other storage device are possible examples of tangible computer-readable media. Specifically, computer program 50 may include a software program for analyzing one or more measurements received from one or more electrical grid measurement devices 10 of FIG. 2 and / or electrical grid measurement device 37 of FIG. 3.

[0080] Reference is now made to FIG. 5, which is a block diagram of a dynamic fault detection software program 51, according to one exemplary embodiment.

[0081] Optionally, the block diagram of the dynamic fault detection software program 51 of Figure 5 may be viewed in the context of the details of the previous figure. However, of course, the dynamic fault detection software program 51 of Figure 5 may be viewed in the context of any desired environment. Furthermore, the foregoing definitions may be equally applied to the following description.

[0082] The dynamic fault detection software program 51 may be executed by the computing system 42 and / or by the area controller 31 or 39 and / or by the central controller or server 32 or 40 and by the electrical grid measurement device 10 or 37. As shown in FIG. 5, the dynamic fault detection software program 51 may have the following modules:

[0083] Communications module 52 may communicate with one or more grid measurement devices 10 of Figure 2 and / or grid measurement device 37 of Figure 3. Communications module 52 may receive various measurements from one or more grid measurement devices and / or instruct any such one or more grid measurement devices to make one or more particular measurements in a particular manner. Communications module 52 may store such measurements 53 in database module 54.

[0084] It is understood that the use of a database, such as database module 54, is an example of a possible implementation, and other implementations for recording and storing data are also contemplated, including any type of memory or storage device, including temporary memory (RAM).

[0085] Measurement analysis module 55 may load measurements 53 from database module 54 , generate analysis results 56 , and store the analysis results in database module 54 .

[0086] The user interface module 57 may enable a user 58 to manage the dynamic fault detection software program 51, for example, by determining one or more operating parameters of the dynamic fault detection software program 51. The user interface module 57 may enable a user 58 to access analysis results 56. The user interface module 57 may also automatically alert the user 58 in response to certain events as determined by the user 58. The user interface module 57 may enable a user 58 to determine operating parameters such as measurement collection rules 59, measurement analysis rules 60, and event alarm rules 61.

[0087] The database module 54 may include a measurement database 62 containing measurements collected by the communication module 52, an operation database 63 containing collection rules 59, analysis rules 60, event alarm rules 61, and scan schedules, and an analysis results database 64.

[0088] It will be understood that the use of stored rules such as rules 59, 60, and 61 are examples of possible implementations, and that other implementations are contemplated. For example, the logic of such rules can be embedded in the code of a separate module.

[0089] The dynamic fault detection software program 51 may analyze measurements in various ways. For example, the dynamic fault detection software program 51 may compare two or more measurements made by the same grid measurement device at different times. For example, the dynamic fault detection software program 51 may compare two or more measurements made by different grid measurement devices at substantially the same time. For example, the dynamic fault detection software program 51 may compare two or more measurement changes detected by the same or different grid measurement devices. For example, the dynamic fault detection software program 51 may compare two or more measurements of transients detected by the same or different grid measurement devices.

[0090] The term "transient" may refer to any type of brief or instantaneous change in voltage and / or current and / or power, such as a spike, surge, or the like.

[0091] The measurement analysis module 55 scans the measurement database 62 according to the measurement analysis rules 60 to detect anomalies or faults. Different faults may have different characteristics in the form of typical measurements or associations between measurements made by the same and / or different grid measurement devices.

[0092] Measurement analysis rules 60 may be designed to detect and / or identify specific faults. Measurement analysis rules 60 may also trigger the use of one or more specific measurement collection rules 59. For example, to collect measurements with higher accuracy, for example, a set of measurements made by a specific grid measurement device around a specific time.

[0093] Reference is now made to FIG. 6, which is a flow chart of the measurement analysis module 55, according to one exemplary embodiment.

[0094] Optionally, the flow chart of the measurement analysis module 55 of Figure 6 may be viewed in the context of the details of the previous figure. However, it should be understood that the flow chart of the measurement analysis module 55 of Figure 6 may be viewed in the context of any desired environment. Furthermore, the foregoing definitions may be equally applied to the following description.

[0095] 6, measurement analysis module 55 may begin at step 65 by loading rules, for example, from operational database 63. Measurement analysis module 55 may then proceed to step 66 and scan measurements in measurement database 62. Measurement analysis module 55 may then proceed to step 67 and compare each measurement against all anomaly identification rules.

[0096] Anomaly identification rules may associate measurements with specific types of anomalies. Typically, an anomaly type associates a measurement with one or more possible faults. (Step 68) If a measurement is identified as an anomaly, associated measurements of neighboring grid measurement devices should be investigated to determine whether a fault exists and the type of fault.

[0097] If an abnormal measurement is detected (step 68), measurement analysis module 55 may then proceed to step 69 and load one or more analysis rules from operational database 63 that are associated with one or more anomaly types, as determined in step 67. The analysis rules may, for example, indicate other measurements that should be analyzed and how. The analysis rules may request one or more previous measurements of the same grid measurement device and / or one or more previous measurements of another grid measurement device. Measurement analysis module 55 may then proceed to step 70 and scan and compare the measurements according to the analysis rules.

[0098] If the measurement analysis module 55 identifies a fault using an analysis rule (step 71), the measurement analysis module 55 may report the fault by entering a fault record in the analysis results database 64, typically according to an event alarm rule associated with the identified fault (step 72).

[0099] The measurement analysis module 55 may repeat steps 69 through 72 for all rules associated with the identified anomaly (step 73). The measurement analysis module 55 may repeat steps 66 through 72 for all measurements in the measurement database 62.

[0100] Measurement analysis module 55 may continuously and / or repeatedly scan measurement database 62 according to a particular schedule, and / or after an alert from a grid metering device, and / or after an alert from a grid metering device, and / or after an alert from communications module 52, and / or after a manual request, for example, by user 52. The scan schedule may be determined by user 52 or by analysis rules.

[0101] Reference is now made to Figure 7, which is a flowchart of a measurement scan procedure 74, according to one exemplary embodiment. Measurement scan procedure 74 may be a possible implementation of step 70 of Figure 6.

[0102] Optionally, the measurement scan procedure 74 flowchart of Figure 7 may be viewed in the context of the details of the previous figure. However, it should be understood that the measurement scan procedure 74 flowchart of Figure 7 may be viewed in the context of any desired environment. Furthermore, the foregoing definitions may be equally applied to the following description.

[0103] The measurement scan procedure 74 may be executed by the computing system 42, by the central controller or server 32 or 40, and / or by the area controller 31 or 39, and by the power grid measurement device 10 or 37. The measurement scan procedure 74 is typically executed by (for example) the same device as part of the dynamic fault detection software program 51.

[0104] However, the dynamic fault detection software program 51 and the measurement scan procedure 74 may be executed by different devices. For example, the dynamic fault detection software program 51 may be executed by the central controller or server 32 or 40 with the measurement scan procedure 74 executed by one or more area controllers 31 or 39. For example, the dynamic fault detection software program 51 may be executed by the area controller 31 or 39 with the measurement scan procedure 74 executed by one or more electric grid measurement devices 10 or 37.

[0105] 7, the measurement scan procedure 74 may begin at step 75 by determining the grid measurement device whose measurements are to be evaluated. Typically, such grid measurement devices may be located downstream and proximate (e.g., toward the power load and / or power consumer). Alternatively, or in addition, such grid measurement devices may be located upstream and proximate (e.g., toward the power generating station).

[0106] Alternatively or additionally, such grid measurement devices may be located in parallel and proximate, for example, on parallel power carrying conductors of the same phase, or on power carrying conductors carrying different phases, or on the neutral conductor, etc. Alternatively or additionally, if the grid branches (upstream or downstream), such grid measurement devices may be located in the parallel branch. The grid measurement device whose measurement should be evaluated may be determined according to the anomaly type detected in step 67 of FIG. 6 and / or according to the analysis rules loaded in step 69 of FIG. 6. The grid measurement device whose measurement should be evaluated may be determined according to the type and / or characteristics of the evaluated measurement of the neighboring device. Thus, the evaluation may cover any number of grid measurement devices.

[0107] It is understood that the dynamic fault detection software program 51 may detect the direction of power flow and / or generator side. For example, consider a power line carrying power from a primary generator in a power plant connected to one side of the line, and a solar power generating unit connected to the second side of the same line. The grid measurement device 10 may measure the power flow for the two power sources separately. The measurement scan procedure 74 may proceed to step 76 to determine whether a suitable measurement exists for one or more grid measurement devices selected in step 75. Such a measurement may be suitable if the measurement is of the required type, and / or was made at a particular time, and / or has the appropriate accuracy, etc.

[0108] The measurements can be of different types such as voltage, current, phase between voltage and current, frequency, temperature, wind, etc., instantaneous measurements, averages over any particular period of time, absolute values, variations, slopes, etc.

[0109] For example, if no suitable measurements exist in the measurement database 62, the measurement scan procedure 74 may proceed to request suitable measurements from the appropriate grid measurement devices (as determined in step 75).

[0110] The measurement scan procedure 74 may typically proceed to step 77 and load measurement collection rules 59 from the operational database 63. The measurement scan procedure 74 may then proceed to step 78 and request specific measurements from the grid measurement devices, as determined in step 75.

[0111] For example, step 78 may be implemented by a measurement scan procedure 74 that sends appropriate measurement collection rules 59 via the dynamic fault detection software program 51 and via the communication module 52 to the appropriate area controllers (31, 39) and / or electrical grid measurement devices (10, 37).

[0112] The measurement scan procedure 74 may then proceed to step 79 and reschedule the scan when suitable measurements are available. The measurement scan procedure 74 may then proceed to step 80 and determine that no faults are identified (given the lack of suitable measurements and the scan scheduling).

[0113] The dynamic fault detection software program 51 and measurement scan procedure 74 may be executed by the master central controller 40, and / or by the area controllers 39 and / or both of FIG. 3, and / or by the central controller or server 32 and / or area controllers 31 of FIG. 2. Steps 77-80 are typically performed by these entities. However, alternatively or in addition, the dynamic fault detection software program 51 and measurement scan procedure 74 may be executed in whole or in part by any of the electric grid measurement devices 10 of FIGS. 1 and 2 and / or the electric grid measurement devices 37 of FIG. 3.

[0114] An advantage of running the dynamic fault detection software program 51 and measurement scan procedure 74 by the master central controller 40 and / or central controller or server 32 is the availability of a comprehensive measurement database 62 that covers the entire electrical grid, or a large portion of the electrical grid, and a long period of measurement collection.

[0115] An advantage of having the area controllers (31, 39) execute the dynamic fault detection software program 51 and the measurement scan procedure 74 is that measurements are scanned in parallel and therefore faults and / or suspicious situations can be detected more quickly, at least for the limited area managed by a particular area controller.

[0116] An advantage of executing the dynamic fault detection software program 51 and measurement scan procedure 74 by the electrical grid measurement device (10, 37) is that at least some faults and / or suspicious conditions may be detected more quickly, at least with respect to the direct proximity of a particular electrical grid measurement device.

[0117] Each grid measurement device may internally store measurements that are not communicated to the area controllers (31, 39) and / or master central controller 40 and / or central controller or server 32. Similarly, the area controllers (31, 39) may internally store measurements that are not communicated to the master central controller 40 and / or central controller or server 32.

[0118] Thus, if steps 76-78 are performed by an area controller (31, 39), the area controller may send the request to an appropriate grid measurement device (10, 37) in its area or to a neighboring area controller (31, 39) that monitors the grid measurement device. Similarly, if steps 76-78 are performed by a grid measurement device (10, 37), it may send the request directly to an appropriate neighboring grid measurement device. In such a case, the request may be provided substantially immediately, and the measurement scan procedure 74 may proceed directly to step 81.

[0119] In step 81, the measurement scan procedure 74 may load the required measurements of adjacent grid measurement devices, for example, according to the associated analysis rules 60. If all required measurements are available (step 82), the measurement scan procedure 74 may proceed to step 83 and determine whether a fault exists and the type of fault (steps 84 and 85).

[0120] Thus, for example, a first grid measurement device 10 or 37 may analyze data, which it typically collects in real time, and determine that one or more additional measurements are required from a particular adjacent second grid measurement device 10 or 37. For example, the first grid measurement device may detect a change in a particular value at a particular time and request the second grid measurement device to measure a more detailed measurement, which the second grid measurement device stores internally for a predetermined period of time. After the first grid measurement device receives the detailed measurement from the second grid measurement device, it may determine a particular fault and notify the area controller 31 or 39, which may initiate a wider scan for the fault. The same applies to the first area controller 31 or 39 interrogating the adjacent second area controller 31 or 39.

[0121] This arrangement allows the grid metering system 36 to instantaneously monitor events such as transients. The grid metering system 36 may detect suspected faults in real time and use these detailed measurements without having to communicate very detailed measurements to a central database. Instead, time-limited detailed measurements are stored internally by the grid metering device and can be requested by neighboring grid metering devices for immediate use.

[0122] It will be understood that all units in the grid metering system 36 may request any other unit to collect detailed measurements and / or transmit detailed measurements to any other unit in the grid metering system 36. Specifically, the master central controller 40 may therefore request one or more area controllers 31 or 39 and / or grid metering devices 10 or 37 to transmit detailed measurements to it. Similarly, an area controller 31 or 39 may request one or more area controllers 31 or 39 and / or one or more grid metering devices 10 or 37 to transmit detailed measurements to it or to transmit detailed measurements to the master central controller 40. Similarly, a metering device 10 or 37 may request one or more grid metering devices 10 or 37 to transmit detailed measurements to it or to transmit detailed measurements to an area controller 31 or 39 or to the master central controller 40. Thus, the grid metering system 36 may not need to communicate all detailed measurements to the master central controller 40. Instead, the detailed measurements are processed by the grid metering device 10 or 37 that collects the measurements, and if the grid metering device 10 or 37 suspects a fault, a request is made to neighboring devices (e.g., one or more grid metering devices 10 or 37, or area controllers 31 or 39) to communicate those detailed measurements (to the grid metering device 10 or 37, area controller 31 or 39, or master central controller 40) for detailed analysis. Thus, the network and databases are not loaded with unnecessary data.

[0123] It will be appreciated that processing the analysis by each of the grid metering devices 10 or 37 (e.g., step 70 of FIG. 6 ) allows for processing the analysis in real time or near real time, and thus requests for detailed measurements from one or more neighboring devices may be issued quickly (e.g., in real time or near real time), and thus the grid metering device 10 or 37 may need to store such detailed measurements internally for a relatively short period of time. Thus, the memory and / or storage requirements of the grid metering device 10 or 37 may be reduced, and / or more (types of) detailed measurements may be stored by the grid metering device 10 or 37.

[0124] It is understood that the term "adjacent device" can refer to devices on the same phase-carrying conductor (e.g., cable 11) and / or on parallel conductors, such as parallel phase-carrying conductors of a three-phase network (e.g., one or more grid measurement devices 10 or 37, or area controllers 31 or 39). Similarly, the term "adjacent device" can also refer to one or more devices on a parallel branch of a network or grid.

[0125] The analysis rules 60 may have different forms depending on the possible faults. Typically, a particular type of fault may have one or more analysis rules 60 that detect the fault.

[0126] Analysis rules 60 may, for example, correlate or compare measurements of the same type, typically consecutive measurements, of the same grid metering device taken at different times. Analysis rules 60 may, for example, correlate or compare measurements of the same type of different grid metering devices taken at the same time. Analysis rules 60 may, for example, correlate or compare measurements of different types of the same or different grid metering devices. Analysis rules 60 may also include any combination of the above correlations or comparisons.

[0127] For example, wind may cause a tree or similar object to touch the electrical grid, or otherwise cause a momentary surge, pulse, spike, change in current, or change in voltage. Such a surge or change may be detected by two or more electrical grid monitoring devices. For example, two electrical grid monitoring devices are upstream and downstream of the point where the tree touches the electrical grid. However, the values ​​of the measured parameters (e.g., current change or voltage spike) may be different or even opposite.

[0128] Wind parameters may be measured directly or indirectly. For example, wind may be measured as air velocity or as the effect of wind on a cable. For example, the cable may be deflected, sway, oscillate, etc. Such cable deflection, sway, and oscillation may be measured, for example, using an accelerometer, gravimeter, or similar device.

[0129] Such changes in current or voltage are time-dependent and may be detected over the same time (or nearly the same time) by two or more electrical grid measurement devices. Such measurement devices may detect the same time-dependent change, or each electrical grid measurement device may measure a different value of the time-dependent change. Thus, the difference between the measurements of two electrical grid measurement devices is also a time-dependent change or pulse.

[0130] For example, an analysis rule 60 detecting a current increase in a first grid monitoring device and a current decrease in a proximal grid monitoring device may indicate a fault between the grid monitoring devices, the fault indicating a momentary short circuit caused by an object touching the grid. For example, such a fault indication (e.g., analysis rule 60) may also require a sufficient value of wind measurement, or a sufficient value of humidity measurement, or a sufficient value of air conductivity measurement. Analysis rule 60 may further require that additional upstream and / or downstream grid monitoring devices detect no, or a much lower, value of the relevant parameter (e.g., a current decrease or increase).

[0131] For example, analysis rules 60 may detect leakage between two grid monitoring devices, e.g., by comparing current measurements of the two grid monitoring devices. For example, if the current measurement of the upstream grid monitoring device is higher than the current measurement of the downstream grid monitoring device, the difference may be considered some type of leakage between the grid monitoring devices. The leakage value may fall below a threshold, requiring a fault to be reported (e.g., step 72).

[0132] However, based on continuous measurements, analysis rules 60 may further detect that the leak value is increasing over time. Such an indication may call for reporting an apparent fault (e.g., step 72), but the absolute leak value may still be below a threshold. Analysis rules 60 may also indicate a correlation with another parameter, such as wind, temperature, humidity, and / or air conductivity.

[0133] Thus, the dynamic fault detection software program 51 may detect the onset of, for example, a transformer or insulator leakage deterioration process suitably early.

[0134] The dynamic fault detection software program 51 may also detect discontinuities in the cable. The dynamic fault detection software program 51 may detect faults that are in a particular branch downstream of a particular electrical grid measurement device and that do not appear in other branches.

[0135] Some sensors may be inaccurate or variable, or may lose their calibration due to dust, humidity, or aging. The dynamic fault detection software program 51 may overcome such situations by using analysis rules 60 to compensate for different accuracies, slow fluctuations, or counter-calibration spikes of two or more electrical grid measurement devices.

[0136] For example, analysis rule 60 may detect a fault associated with corrosion in a connection between two elements of cable 11. For example, analysis rule 60 may detect a difference between current measurements of two adjacent grid monitoring devices, which may be due to a small leak, but which is correlated with, for example, temperature. For example, the current difference value is periodic, increasing with temperature during the day and decreasing with temperature at night. Step 72 may therefore report a fault indicating possible corrosion in the cable connection between two adjacent grid monitoring devices.

[0137] The grid measurement devices may measure various parameters (e.g., electrical parameters, physical parameters, etc.) at high resolution, e.g., at high speed (e.g., measurements per second) and / or high accuracy. In accordance with one or more collection rules 59, the grid measurement devices (10, 37) may then transmit selected lower-resolution samples and / or averages of the individual measurements to upstream grid measurement devices, and / or to individual area controllers (31, 39), and / or to the central controller or server 32, and / or to the master central controller 40.

[0138] Each grid measurement device (10, 37) may store selected high-resolution measurements internally, for example, in the memory or storage of the controller module 14 of Figure 1. For example, the grid measurement device (10, 37) may internally store a particular number of the most recent measurements, or measurements over a particular recent time period, or measurements of any particular characterization.

[0139] For example, an electrical grid measurement device (10, 37) may internally store measurements associated with a particular irregularity, such as a transient. Such associated measurements may be, for example, measurements of the same parameter immediately before and after the transient, or measurements of different types of parameters simultaneously with the transient. Such measurements may not be transmitted upstream unless requested.

[0140] Analysis rules 60 may include, for example, requests for such high-resolution measurements from the grid measurement device reporting the transient and / or from neighboring grid measurement devices.

[0141] Analysis rules 60 may then, for example, compare detailed high-resolution measurements of two or more electrical grid measurement devices to analyze, for example, the nature of the transient and / or the location of the transient.

[0142] The location of the transient may be determined, for example, by comparing the precise time at which the transient is measured by two or more grid measurement devices, e.g., located upstream and downstream of where the transient occurred (alternatively, the grid measurement devices are located on the same side of where the transient occurred). The precise time of the measurement may be obtained via GPS module 26.

[0143] However, when two grid measurement devices measure different shapes of the same transient, it is important to compare time measurements of the same feature of the transient. This can be achieved by comparing detailed high-resolution measurements. Analysis rules 60 may, for example, include a request for such high-resolution measurements from two or more grid measurement devices. Such a request may include, for example, high-resolution measurements of one or more types of parameters, such as voltage and current, to assess instantaneous power.

[0144] The GPS module 26 allows for time measurements of approximately 10 nanoseconds, and therefore allows for the location of a fault to be estimated to within approximately 3 meters. The GPS module 26 also allows for the synchronization of measurements from multiple power grid measurement devices.

[0145] Reference is now made to FIG. 8, which is a schematic diagram of a portion of an electrical grid having a fault, where the location of the fault is determined by two or more electrical grid measurement devices, according to one exemplary embodiment.

[0146] Optionally, the schematic diagram of Figure 8 may be viewed in the context of the details of the previous figures. However, of course, the schematic diagram of Figure 8 may be viewed in the context of any desired environment. Furthermore, the foregoing definitions may apply equally to the following description.

[0147] Figure 8 shows an electrical grid measurement device (10, 37) connected to a single phase carrier conductor (e.g., cable 11). However, it is understood that the arrangements, systems, and methods disclosed with reference to Figure 8 may also be applied to three-phase networks and / or multiple conductors.

[0148] The location of the fault may be determined according to the locations of two or more grid measurement devices (10, 37) involved in measuring and / or detecting the fault. The location of the fault may be determined according to the precise locations of the grid measurement devices (10, 37), for example, provided using precise GPS measurements. For example, as described below, the location of the fault relative to the grid measurement devices (10, 37) may be determined using precisely synchronized clocks among these grid measurement devices (10, 37) using GPS clock signals. If precise (e.g., on the order of 10 nanoseconds) clock synchronization is not available, the location of the fault may be roughly determined, for example, midway between two grid measurement devices (10, 37).

[0149] Using hardware and / or software for high accuracy fault location, the grid measurement system 36 or dynamic fault detection software program 51 may first find the rough location of the fault, for example, between two grid measurement devices (10, 37). The grid measurement system 36 or dynamic fault detection software program 51 may then use one of the following test cases to determine the exact location of the fault using the highly accurate time of measurement associated with the fault as provided by the grid measurement device (10, 37) closest to the fault:

[0150] In a first test case shown in FIG. 8, the grid measurement system 36 or dynamic fault detection software program 51 may locate a fault 86 between two grid measurement devices (10, 37), such as the grid measurement devices designated by numerals 87 and 88, using the following equation: Equation 1: L1=L-L2 Equation 2: L2=(L-(T1-T2) * C) / 2

[0151] where C is the speed of radio waves in a conductor, typically the speed of light, which is 300 meters / microsecond.

[0152] L is the distance between the two grid measuring devices 87 and 88.

[0153] L1 and L2 are the distances of the fault location from the grid measuring devices 87 and 88, respectively.

[0154] In a second test case, one of the two grid measurement devices 87 and 88 does not provide a time measurement of the relevant event or parameter. For example, grid measurement device 88 measures a normal current or voltage, or measures no current or voltage, etc. For example, there is no grid measurement device associated with a fault, such as a broken wire or a short to ground, or on that side of fault 86.

[0155] The grid measurement system 36 or the dynamic fault detection software program 51 may identify the location of the fault 86 using, for example, the grid measurement devices designated by numerals 87 and 89 using the following equation: Equation 3: L2=L+L1 Equation 4: L1=(L+(T1-T2) * C) / 2

[0156] where C is the speed of radio waves in a conductor, typically the speed of light, which is 300 meters / microsecond.

[0157] L is the distance between the two grid measuring devices 87 and 88.

[0158] L1 and L2 are the distances of the fault location from the grid measuring devices 87 and 88, respectively.

[0159] The above formula calculates the fault location along the cable. The fault location in absolute terms (such as GPS location) may be determined according to the actual progression of the cable above or below the ground. For example, if there is no bending of the cable (e.g., due to a grid pole), the fault coordinates may be calculated according to the GPS coordinates of the grid measurement device, calculating the cable along a straight line. If the cable is bent, the fault coordinates may be calculated according to the actual wire route using the actual wire section.

[0160] Electrical grid measurement system 36 may therefore operate multiple measurement devices distributed across the electrical grid, each capable of measuring at least current or voltage and recording the current and / or voltage measurements along with their respective times of occurrence.

[0161] The dynamic fault detection software program 51 may therefore first detect faults in the electrical grid by recording a plurality of such measurements, including transients, as detected by any of a plurality of measurement devices. The measurements and / or transients may include changes in current values ​​and / or changes in voltage values. Typically, such measurements are recorded if such changes are greater than respective predetermined values.

[0162] The dynamic fault detection software program 51 may then detect a first transient detected by the first measurement device and a second transient detected by the second measurement device, the second transient occurring within a predetermined period of time after the first transient.

[0163] The dynamic fault detection software program 51 may then calculate the source location of the transient according to the time of measurement of the transient by two or more measurement devices.

[0164] The predetermined period of time may be, for example, less than or equal to the travel time of such a transient between the first and second measuring devices according to the speed of the electrical signals in the cables of the power distribution network.

[0165] The dynamic fault detection software program 51 may calculate the source location by calculating the time difference between the occurrence times of the individual transients, calculating the travel distance of the transients during the time difference according to the speed of the electrical signals in the cables of the power distribution network, calculating an intermediate location between the first measuring device and the second measuring device, and determining the source location at half the travel distance from the intermediate location closer to the measuring device having the earlier occurrence time of the individual transient.

[0166] The dynamic fault detection software program 51 may also detect multiple such transients and the times of the corresponding measurements of the transients detected by the first measuring device and report a transient if a second measuring device installed downstream of the source location does not detect the transient within a predetermined period around the time of the measurement of the transient detected by the first measuring device. Alternatively, the dynamic fault detection software program 51 may report a transient if a second measuring device installed downstream detects a repeating counter-transient within a predetermined period around the time of the measurement of the transient detected by the first measuring device.

[0167] In this case too, the predetermined period of time may be less than or equal to the travel time of the transient between the first and second measuring devices according to the speed of the electrical signals in the cables of the power distribution network.

[0168] The dynamic fault detection software program 51 may also calculate the source location of the transient detected by the second measuring device by first calculating the time difference between the occurrence times of the individual transients detected by the first and second measuring devices, then calculating the travel distance of the transient during the time difference according to the speed of the electrical signal in the cables of the power distribution network, then calculating the location between the first measuring device and the second measuring device, and then determining the source location as half the travel distance from an intermediate location closer to the measuring device having the earlier occurrence time of the individual transient.

[0169] The dynamic fault detection software program 51 may also measure and record temperatures at the time of individual measurements and then detect repeated changes in the value of the measurement of a particular measuring device, which repeated changes in the value of the measurement correlate with individual temperature values ​​or changes in temperature of the cables of the power distribution network.

[0170] The dynamic fault detection software program 51 may further detect faults in the electrical grid by detecting a transient with at least one measuring device and then requesting from at least one proximal measuring device to report at least one measurement recorded within a predetermined period around the time of the measurement of the transient. The predetermined period may be less than or equal to the travel time of the transient between two measuring devices according to the speed of electrical signals in the cables of the electrical grid.

[0171] It will be understood that certain features that are, for clarity, described in the context of separate embodiments, may also be provided in combination in a single embodiment. Conversely, various features that are, for brevity, described in the context of a single embodiment, may also be provided separately or in any suitable subcombination.

[0172] While a description has been provided above in conjunction with specific embodiments thereof, it is evident that many alternatives, modifications, and variations will be apparent to those skilled in the art. Accordingly, it is intended to embrace all such alternatives, modifications, and variations that fall within the spirit and broad scope of the appended claims. All publications, patents, and patent applications mentioned herein are incorporated by reference in their entirety to the same extent as if each individual publication, patent, or patent application was specifically and individually indicated to be incorporated by reference herein. In addition, citation or identification of any reference in this application shall not be construed as an admission that such reference is available as prior art.

Claims

1. A method for detecting faults in an electrical grid, the method comprising: distributing, within the electrical grid, a plurality of electrical grid measurement devices comprising at least one of a current measuring sensor and a voltage measuring sensor, the plurality of electrical grid measurement devices operative to measure at least one of a current measurement and a voltage measurement to form a plurality of measurements at their respective times of occurrence; detecting a plurality of voltage and / or current transients detected by a first measuring device and times of corresponding measurements of said voltage and / or current transients; reporting the voltage and / or current transients, said reporting step comprising: a second measuring device located downstream of the first measuring device does not detect a voltage and / or current transient within a predetermined period around the time of the measurement of the voltage and / or current transient detected by the first measuring device; a second measuring device located downstream of the first measuring device detects a repetitive counter transient in voltage and / or current within a predetermined period around the time of the measurement of the voltage and / or current transient detected by the first measuring device; and A method comprising:

2. The method described in claim 1, wherein the predetermined period is less than or equal to the progression time of the voltage and / or current transient between the first measuring device and the second measuring device according to the speed of the electrical signal in the cables of the power distribution network.

3. A computer program product embodied on a non-transitory computer-readable medium, the non-transitory computer-readable medium comprising instructions that, when executed by at least one processor, cause the processor to: detecting a plurality of voltage and / or current transients detected by a first measurement device and times of corresponding measurements of the voltage and / or current transients, the detecting operation being performed by at least one grid measurement device of a plurality of grid measurement devices distributed within an electrical grid, the plurality of grid measurement devices operative to measure at least one of current and voltage measurements and form a plurality of measurements at their respective times of occurrence; reporting the voltage and / or current transients, wherein the reporting includes: a second measuring device located downstream of the first measuring device does not detect a voltage and / or current transient within a predetermined period around the time of the measurement of the voltage and / or current transient detected by the first measuring device; a second measuring device located downstream of the first measuring device detects a repetitive counter transient in voltage and / or current within a predetermined period around the time of the measurement of the voltage and / or current transient detected by the first measuring device; and 2. A computer program product for causing a computer to perform operations including:

4. The computer program product of claim 3, wherein the predetermined period is less than or equal to the progression time of the voltage and / or current transient between the first measuring device and the second measuring device according to the speed of the electrical signal in the cables of the power distribution network.

5. A system for detecting faults in an electrical grid, the system comprising: a plurality of grid measurement devices distributed within the grid, each of the plurality of grid measurement devices comprising at least one of a current measurement sensor and a voltage measurement sensor, the plurality of grid measurement devices operative to measure at least one of a current measurement and a voltage measurement and form a plurality of measurements at their respective times of occurrence; at least one computing device communicatively coupled to the plurality of electrical grid measurement devices, the at least one computing device configured to receive the plurality of measurements from the plurality of electrical grid measurement devices at their respective times of occurrence, the at least one computing device configured to analyze the measurements according to at least one rule to detect faults, the rule configured to associate at least one of the measurements with a fault type; and wherein the measurements comprise measurements of voltage and / or current transients, and the rules comprise: Detecting a fault, said detecting comprising: a first measuring device located downstream of a second measuring device does not detect a voltage and / or current transient within a predetermined period around the time of measurement of the voltage and / or current transient detected by said second measuring device; a first measuring device located downstream of a second measuring device detecting a repetitive counter-transient in voltage and / or current within a predetermined period around the time of measurement of the voltage and / or current transient detected by said second measuring device; In response to at least one of the following: The system further includes:

6. The system described in claim 5, wherein the predetermined period is less than or equal to the progression time of the voltage and / or current transient between the first measuring device and the second measuring device according to the speed of the electrical signal in the cables of the power distribution network.

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