EA037144B1 - Systems and methods for measuring electrical power usage in a structure and systems and methods of calibrating the same - Google Patents

Abstract

Some embodiments can concern a method of using a power consumption measurement device. The power consumption measurement device can be mechanically coupled to a surface of a circuit breaker box overlying at least part of one or more main electrical supply conductors for an electrical power infrastructure of a structure. The method can include determining one or more first magnetic field readings from the one or more main electrical supply conductors using one or more sensors in the power consumption measurement device; after determining the one or more first magnetic field readings, electrically coupling a first calibration load to the electrical power infrastructure; while the first calibration load remains electrically coupled to the electrical power infrastructure, determining one or more second magnetic field readings from the one or more main electrical supply conductors using the one or more sensors in the power consumption measurement device; calibrating the power consumption measurement device using at least in part the one or more first magnetic field readings and the one or more second magnetic field readings, after calibrating the power consumption measurement device, determining one or more third magnetic field readings from the one or more main electrical supply conductors using the one or more sensors in the power consumption measurement device; and determining an electrical power used by the electrical power infrastructure of the structure using at least the one or more third magnetic field readings and the one or more calibration coefficients. Calibrating the power consumption measurement device can include determining one or more first calibration coefficients for the power consumption measurement device using at least in part the one or more first magnetic field readings and the one or more second magnetic field readings. Other embodiments are disclosed.

Description

(54) SYSTEMS AND METHODS FOR MEASURING ELECTRIC ENERGY CONSUMPTION IN A STRUCTURE AND SYSTEMS AND METHODS FOR THEIR CALIBRATION

037144 Bl

(31) 61 / 361.296; 61 / 380,174 (74) Representative: (32) 2010.07.02; 2010.09.03 Lebedev V.V., Ugryumov V.M., (33) US Glukhareva A.O., Gizatullina E.M., (43) 2019.11.29 Strokova O.V., Kostyushenkova M.Yu., (62) 201790486; 2011.07.01 Gizatullin Sh.F., Paramonova K.V. (71) (73) Applicant and patentee: (RU) BELKIN INTERNATIONAL, INC. (US) (56) JP-A-10282161 (72) Inventor: Patel Shvetak N., Gupta Sidhunt, Reynolds Matthew S., Iojisuaran Kartik (US) US-A1-20040140908 KR-A-1020080114143 US-A-4891587

(57) Some embodiments may relate to a method of using a device for measuring energy consumption. The device for measuring energy consumption may be mechanically coupled to the surface of the circuit breaker box located on top of at least a portion of one or more main power supply conductors for the electrical infrastructure of the structure. The method may include an operation of determining one or more first readings of a magnetic field from one or more main power supply wires using one or more sensors in a device for measuring energy consumption; a work step in which, after determining one or more of the first readings of the magnetic field, electrically couple the first calibration load to the power electrical infrastructure; an operation in which, while the first calibration load remains electrically connected to the power electrical infrastructure, one or more second readings of the magnetic field from one or more main power supply wires are determined using one or more sensors in the device for measuring power consumption; an operation in which the device for measuring energy consumption is calibrated using, at least in part, one or more of the first readings of the magnetic field and one or more of the second readings of the magnetic field; a step in which, after calibrating the energy consumption measuring device, one or more third magnetic field readings from one or more main power supply wires are determined using one or more sensors in the energy consumption measuring device; and an operating step in which the electrical energy consumed by the power electrical infrastructure of the structure is determined using, at least in part, one or more third magnetic field readings and one or more calibration coefficients. Calibrating the device for measuring energy consumption may include determining one or more first calibration coefficients for the device for measuring energy consumption using, at least in part, one or more first readings of the magnetic field and one or more second readings of the magnetic field. Other embodiments are disclosed.

037144 B1

Cross-reference to related claims

This application claims priority reserved by US Provisional Application No. 61/361296, filed July 2, 2010, and US Provisional Application No. 61/380174, filed September 3, 2010. This application is also a partial continuation of US Application No. 12/567561. filed September 25, 2009. The disclosures of US Provisional Applications Nos. 61/361296 and 61/380174 and US Application Nos. 12/567561 are incorporated herein by reference.

The technical field to which the invention relates

The present invention relates generally to devices, devices, systems and methods for controlling electrical energy and, in particular, relates to such devices, devices, systems and methods that control electrical energy in one or more main power electrical wires on an automatic electrical panel. switches of the structure.

Prior art

A structure (for example, a residential or office building) may have one or more main electrical power wires that supply electrical energy to electrical appliances (i.e., a load) in the structure. Many facilities use a split-phase electrical distribution system with up to three main power conductors. The main power wires enter the structure through the circuit breaker board. The board of automatic electrical switches is the main distribution point of electrical energy in the structure. In addition, circuit breaker panels provide protection against overcurrents that could otherwise cause fire or damage to electrical appliances in the structure. Circuit breaker panels may be connected to and positioned on top of at least a portion of the three main power wires.

Various manufacturers of circuit breaker panels, including, for example, Square-D, Eaton, Cutler-Hammer, General Electric, Siemens and Murray, have chosen different wire spacings and designs for their circuit breaker panels. In addition, each manufacturer produces different designs of automatic switchboards for indoor installation, for outdoor installation and for different total rated currents, of which 100 A and 200 A power supplies are the most common.

The different wire layouts in many different types of circuit breaker boards have resulted in different magnetic field profiles on the metal surfaces of the circuit breaker boards. In addition, the layout of the internal wires (for example, the main power electrical wires) is not visible without opening the switchboard, and how the layout of the internal wires translates into the magnetic field profile on the surface of the circuit breaker board requires deep interpretation and modeling. knowledge of electromagnetic theory. Therefore, it is difficult to accurately measure the magnetic field of one or more main electrical power wires on the surface of the circuit breaker board. If the magnetic field of one or more main power wires on the surface of the circuit breaker board could be accurately determined, it would be possible to determine the electrical current and energy consumed by the load in the structure.

Accordingly, it is an object of the present invention to provide an apparatus, system, and / or method that enables a non-electrician to accurately determine the magnetic field and other parameters associated with one or more main power wires on the surface of a circuit breaker board.

The essence of the invention

To facilitate the following description of embodiments of the present invention, drawings are provided in which FIG. 1 illustrates a view of an exemplary electrical energy monitoring system connected to an electrical switchboard in accordance with a first embodiment;

in fig. 2 is a block diagram of the electrical energy monitoring system shown in FIG. 1 in accordance with the first embodiment;

in fig. 3 is a sectional view of the circuit breaker board of FIG. 1 along line 3-3 in accordance with the first embodiment;

in fig. 4 is an example of magnetic field wires generated by one wire;

in fig. 5 shows an example of magnetic field wires generated by main power wires in the circuit breaker of FIG. 1 in accordance with the first embodiment;

in fig. 6 shows an example of the sensor device of FIG. 2 in accordance with the first embodiment;

in fig. 7 illustrates an exemplary arrangement of the sensor device of FIG. 2 above the main power line of the circuit breaker of FIG. 1 in accordance with a first embodiment;

in fig. 8 is an exemplary graph of voltage versus time of electric current sensors in accordance with one embodiment;

in fig. 9 shows an example of a sensor device according to a second embodiment;

in fig. 10 shows an example of the sensor device of FIG. 9 above the main power lines of the circuit breaker of FIG. 1 in accordance with a second embodiment;

in fig. 11 shows an example of the calibration device of FIG. 1 in accordance with a first embodiment;

in fig. 12 is an exemplary graph of a potential low voltage input signal to the controller of FIG. 11 from the level translator of FIG. 11 in accordance with one embodiment;

in fig. 13 are exemplary graphs illustrating the relationship of a rectangular low voltage signal used to develop a phase reference and a low voltage signal in FIG. 12 in accordance with one embodiment;

in fig. 14 illustrates an example of a switched load according to the third embodiment;

in fig. 15 illustrates an example of a switched load in accordance with a fourth embodiment;

in fig. 16 illustrates an example of a switched load according to the fifth embodiment;

in fig. 17 illustrates an example of a switched load according to the sixth embodiment;

in fig. 18 is a roadmap for a method for calibrating an electrical energy monitoring system in accordance with one embodiment;

in fig. 19 is a roadmap for a method for determining calibration factors in accordance with one embodiment;

in fig. 20 is a flowchart of a method for determining a predicted current in main power electrical wires in accordance with one embodiment;

Fig. 21 illustrates an example of a first location of two electric current sensors with respect to main power wires in an exemplary sensing device in accordance with one embodiment;

in fig. 22 is a graph comparing predicted current versus measured currents for the electric current sensors of FIG. 21;

in fig. 23 illustrates an example of a second location of two electric current sensors with respect to main power wires in an exemplary sensing device in accordance with one embodiment; and in FIG. 24 is a graph comparing predicted current versus measured currents for the electric current sensors of FIG. 23.

For simplicity and clarity, the illustrations in the figures of the drawings illustrate the general principle of construction, and descriptions and details of well-known features and techniques may be omitted to avoid unnecessarily complicating the understanding of the invention. In addition, elements in the figures in the graphics are not necessarily drawn to scale. For example, the dimensions of some of the features in the figures may be exaggerated relative to other features to aid understanding of embodiments of the present invention. Identical elements in different figures are designated with the same reference numbers.

Expressions first, second, third, fourth, etc. in the appropriate number, gender and case in the description and the claims, if any, are used to distinguish between like elements and not necessarily to describe a specific sequential or chronological order. It should be understood that expressions used in this manner are, in appropriate circumstances, interchangeable so that embodiments described herein may, for example, be able to operate in sequences other than those illustrated or otherwise described herein. In addition, expressions to contain and be in appropriate number, gender, and case are intended to cover non-exclusive inclusion; so, for example, a process, method, system, product, device or apparatus, which (which or which) contains a certain list of elements, is not necessarily limited to these elements, but may contain other elements not specifically listed or inherent in this process, method, system, product, device or apparatus.

Expressions left, right, front, back, top, bottom, above, below, etc. in the corresponding number, gender and case in the description and the claims, if any, are used for descriptive purposes and not necessarily to describe constant relative provisions. It should be understood that expressions used in this manner, in appropriate circumstances, are interchangeable so that embodiments described herein may, for example, be able to operate in orientations other than those illustrated or otherwise described herein.

Expressions bind, bound, bind, link, etc. in the appropriate number, gender and

- 2 037144 should be understood broadly and refer to the connection of two or more elements or signals electrically, mechanically and / or otherwise. Two or more electrical elements can be connected electrically, but not mechanically or otherwise; two or more mechanical elements may be connected mechanically, but not electrically or otherwise; two or more electrical elements can be connected mechanically, but not electrically or otherwise. The connection can be of any duration in time, for example, permanent, or semi-permanent, or only for a moment.

Electrical connection, etc. is to be understood broadly and includes communications including any electrical signal, be it a power signal, a data signal, and / or other types or combinations of electrical signals. Mechanical connection, etc. is to be understood broadly and contains mechanical linkages of all types.

The absence of a word is detachable, detachable, etc. next to the word connected, etc. does not mean that a given compound, etc. is or is not detachable.

Information confirming the possibility of carrying out the invention

Some embodiments may relate to a method of using a device for measuring energy consumption. The device for measuring energy consumption may be mechanically coupled to the surface of the circuit breaker box located on top of at least a portion of one or more main power supply conductors for the electrical infrastructure of the structure. The method may comprise determining one or more first readings of a magnetic field from one or more main power supply wires using one or more sensors in a device for measuring energy consumption; electrically binding the first calibration load to the power electrical infrastructure after one or more first readings of the magnetic field have been determined; determining one or more second magnetic field readings from one or more main power supply wires using one or more sensors in the power consumption meter while the first calibration load remains electrically connected to the power electrical infrastructure; calibrating the device for measuring energy consumption using, at least in part, one or more of the first readings of the magnetic field and one or more of the second readings of the magnetic field; determining one or more third magnetic field readings from one or more main power supply wires using one or more sensors in the energy consumption measuring device after calibrating the energy consumption measuring device; and determining the electrical energy consumed by the power electrical infrastructure of the structure using, at least in part, one or more third magnetic field readings and one or more calibration factors. Calibrating the device for measuring energy consumption may comprise determining one or more first calibration coefficients for the device for measuring energy consumption using, at least in part, one or more first readings of the magnetic field and one or more second readings of the magnetic field.

Other embodiments may relate to a method for calibrating a magnetic field sensor device. The magnetic field sensing device is associated with the first surface of the circuit breaker box. The circuit breaker box is located on top of the building's power electrical infrastructure. The power electrical infrastructure has a first phase branch and a second phase branch. The magnetic field sensor device may comprise two or more magnetic field sensors. The method may comprise determining a first amplitude and a first phase angle of a first magnetic field in two or more magnetic field sensors of a magnetic field sensor device; receiving messages that the first load is associated with the first phase branch of the power electrical infrastructure; determining a second amplitude and a second phase angle of the second magnetic field in two or more magnetic field sensors of the magnetic field sensor device while the first load is associated with the first phase arm; receiving messages that the second load is associated with the second phase branch of the power electrical infrastructure; determining a third amplitude and a third phase angle of the third magnetic field in two or more magnetic field sensors of the magnetic field sensor device while the second load is associated with the second phase arm; and determining one or more calibration coefficients for the magnetic field sensor device, at least in part, using the first amplitude and the first phase angle of the first magnetic field in two or more magnetic field sensors, the second amplitude and the second phase angle of the second magnetic field in two or more magnetic field sensors, and a third amplitude and third phase angle of the third magnetic field in two or more magnetic field sensors.

Additional options may relate to a system for monitoring the consumption of electrical energy in the power electrical infrastructure of the building. The building contains the circuit breaker box and the power supply wires of the building's power electrical infrastructure. The system may comprise: (a) a device for measuring energy consumption for communication with the first surface of the circuit breaker box, the circuit breaker box being distributed

- 3 037144 is laid on top of at least part of the power supply wires of the power electrical infrastructure, and the device for measuring energy consumption has one or more magnetic field sensors; (b) a first calibration device for electrically communicating with the power electrical infrastructure, the first calibration module comprising one or more first calibration loads; and (c) a calibration module for running on the first processor and for at least partially calibrating the power consumption measuring device using data from one or more magnetic field sensors of the power consumption measuring device. The energy consumption measuring device can be configured to acquire at least a portion of the data while at least one or more of the first calibration loads are electrically connected to the power electrical infrastructure and while the energy consumption measuring device is connected to the first surface of the circuit breaker box.

In still further embodiments, the magnetic field sensing device may comprise: (a) at least two magnetic field sensors for detecting a magnetic field in a current-carrying wire; (b) a phase detector electrically coupled to the outputs of at least two magnetic field sensors; and (c) a phase indicator electrically coupled to the phase detector. The phase indicator may include a display indicating when at least two magnetic field sensors are in a predetermined position relative to the current carrying wire.

FIG. 1 illustrates a view of an exemplary electrical energy monitoring system 100 connected to a circuit breaker board 190 in accordance with a first embodiment. FIG. 2, a block diagram of an electrical power monitoring system 100 is illustrated in accordance with the first embodiment. FIG. 3 illustrates a cross-sectional view of a circuit breaker board 190 taken along line 3-3 in accordance with the first embodiment.

The electrical energy control system 100 can also be viewed as a system for monitoring the consumption of electrical energy in a structure (i.e., a building). The electrical energy monitoring system 100 can also be viewed as a device and system for determining the predicted current consumed by one or more electrical devices (ie, a load) in a structure. The electrical energy monitoring system 100 is exemplary only and is not limited to the embodiments described herein. The electrical energy monitoring system 100 can be used in many different embodiments or examples not specifically shown or described herein.

In some examples, the electrical energy monitoring system 100 may comprise: (a) at least one sensor device 110 (i.e., a device for measuring energy consumption), (b) at least one computing unit 120, and (c) at least one one calibration device 180.

In some examples, system 100 can be applied to switchboards from different manufacturers and to different types of switchboards from the same manufacturer. In addition, in some examples, the system 100 can be easily installed by an untrained person (i.e., non-electrician) without opening the switch cabinet and exposing the bare electrical power wires within it.

Also, as shown in FIG. 1, a conventional switch box or circuit breaker panel 190 may comprise: (a) two or more individual circuit breakers 191, (b) two or more main circuit breakers 192, (c) an outer panel 196, and (d) a door 197, providing access to the circuit breakers 191 and 192. Inside the circuit breaker board 190 there may be at least a portion of the main power wires 193, 194, and 195. The circuit breaker board may be (and contain) fuse boxes that are still common in buildings with older electrical systems. The structure's electrical power infrastructure may include at least a circuit breaker panel 190 and main power wires 193, 194, and 195. In some examples, the circuit breaker panels may also refer to any type of electrical distribution panel used to power the structure.

The main power wires 193, 194 and 195 are electrically connected to the main circuit breakers 192 and supply electrical energy to the electrical devices (i.e., the load) in the structure. A shield 196 is positioned over at least a portion of the main power wires 193, 194, and 195 and associated wiring to protect people from accidentally touching these energized power wires. Usually shield 196 consists of steel or other metal.

Door 197 covers circuit breakers 191 and 192 and. is generally closed for aesthetic reasons, but can be opened to provide access to the arms of the circuit breakers 191 and 192 within the circuit breaker cabinet 190. As shown in FIG. 3, when door 197 is closed, shield zone 398 has a shield zone depth 399. The depth 399 of the shield zone is usually 13-20 mm, which allows the door 197 to close without hitting the levers 189 automatically

- 4 037144 switches. The depth 399 of the shield zone limits the allowable thickness of the sensor device 110 installed in the zone 398 of the shield. That is, in various examples, the sensor device 110 may correspond to the depth 399 of the shield zone, and the switch cabinet door may be kept closed while the sensor device 110 is operating. In many examples, the sensor device 110 has a depth of less than 20 mm. In the same or different examples, the sensor device 110 may have a depth of less than 13 mm.

The power supply for residential and small office buildings is usually a split-phase power supply of 240V. This is a public electrical system that provides two 120V AC outgoing wires (for example, power wires 193 and 194), shifted along phase 180 °, along with a neutral wire (for example, power wire 195), which can be used to reverse current from any of the power wires 193 or 194. Power wires 193, 194 and 195 are feeder or main electrical power wires carrying the incoming energy from the public electrical system before splitting into branches supplying energy to different loads. By reading the magnetic fields generated by power wires 193, 194, and 195, system 100 can read the total current drawn by all loads from the public electrical system since all loads in the structure are connected in parallel to power wires 193, 194, and / or 195.

In the United States, a structure with a split-phase 240 volt power supply from the public electrical system contains many different types of electrical loads. Electrical loads can be classified into two load categories: (a) 120 V loads and (b) 240 V loads.

Loads of 120 V can mainly contain loads of lower power, i. E. loads connected to standard 3-pin 120V and 15A or 120V and 20A outlets, and small household appliances less than ~ 2 kW. These loads are wired into separate circuits between a pair of power wires 193 and 195 (first phase leg or arm 193-195 of the wiring diagram) or a pair of power wires 194 and 195 (second phase leg or arm 194-195 of the wiring diagram). When wiring, electricians try to balance the expected wattage of the loads and outlets in each arm, but this process is imprecise, and therefore the currents in arm 193-195 and arm 194-195 are probably unbalanced, since different power is usually drawn from each pair. When the 120 V load is turned on, its current flows from the public electrical system through the power wire 193 or 194 through the main and individual circuit breakers to the load, and then back to the power wire 195 and back to the public electrical system.

240V loads are typically large electrical appliances (e.g. electric dryer, oven, air conditioning compressor, electric floor heaters) that consume more than 2 kW. In this case, the load current flows between the power wires 193 and 194 and no load current flows into the power wire 195. Due to the 180 ° phase shift between the voltages of the power wires 193 and 194, the total voltage is 240 V.

Referring back to FIG. 1 and 2, computing unit 120 may comprise: (a) communication module 221, (b) processing module 222, (c) power supply 223 with electrical connector 128, (d) user communication device 134, (e) controller 225, ( f) memory 226, (g) calibration load module 227, (h) calibration calculation module 229, (i) control mechanism 132, and (j) voltage sensor 228.

Computing unit 120 may be configured to receive an output signal from calibration device 180 and / or sensor device 110 via communication module 221 and process the output signal to determine one or more parameters associated with electrical energy consumption in a structure (e.g., electrical energy consumed structure, and electric current in the main power electrical wires 193, 194 and 195). In some embodiments, computing unit 120 may be a personal computer (PC).

Controller 225 may be a microcontroller such as the MSP430 microcontroller manufactured by Texas Instruments, Inc. In another embodiment, controller 225 is a digital signal processor (DSP) such as a TMS320VC5505 digital signal processor manufactured by Texas Instruments, Inc. or a Blackfin digital signal processor manufactured by Analog Devices, Inc.

Processing module 222 may be configured to use current measurements from sensor device 110 to determine one or more parameters associated with electrical energy consumption in a structure (eg, electrical current and electrical power from main power wires 193, 194, and 195). As will be explained below, the calibration calculation module 229 may be configured to use the current measurements from the sensor device 110 to calibrate the electrical energy monitoring system 100 (eg, to calculate the calibration coefficients for the sensor device 110).

In some examples, processing module 222 and calibration calculation module 229 may be stored in memory 226 and constructively executed for run in controller 225.

- 5 037144

When computing unit 120 is in operation, controller 225 executes program instructions (e.g., processing module 222 and / or calibration module 229) stored in memory 226. The proportion of program instructions stored in memory 226 may be suitable for performing methods 1800 and 2000 (FIGS. 18 and 20, respectively), as described below.

Calibration load module 227 may contain one or more calibration loads. As will be explained below, one or more calibration loads may be temporarily electrically coupled, for example, to the first phase leg of the structure's power electrical infrastructure to help calibrate the electrical energy monitoring system 100.

In some examples, user communications device 134 and control mechanism 132 may be detachable from the rest of computing unit 120 and may wirelessly communicate with the rest of computing unit 120.

Voltage transducer 228 can be used to determine the amplitude and phase angle of the voltage from the power electrical infrastructure. The sweeping current phase angle is equal to the phase angle measured by the electric current sensor 211, from which the voltage phase angle measured by the voltage sensor 228 was subtracted. That is, the phase angle of the current can be calculated relative to the voltage zero crossing point.

In some examples, the sensor device 110 may report the current measurement made by the electric current sensors 211 to the calculator 120 so that the phase angle of the current can be calculated. In other examples, computing device 120 may report a voltage measurement made by voltage sensor 228 to sensor device 110 so that current phase angle can be calculated. In other examples, voltage sensor 228 may be located in calibrator 180.

Power supply 223 may provide electrical power to communication module 221, processing module 222, user communication device 134, controller 225, memory 226, calibration load module 227, and / or control mechanism 132. In some examples power supply 223 may be associated with an electrical connector 128 that may be associated with a power electrical infrastructure electrical wall outlet.

User communication device 134 may be structurally implemented to display information to a user. In one example, the communication device 134 may be a monitor, a touch screen, and / or one or more LEDs (Light Emitting Diodes).

The control mechanism 132 may include one or more buttons configured to at least partially control the computing unit 120 or at least a device for communicating with the user 134. In one example, the control mechanism 132 may include a power switch (i.e. on / off switch) and / or a display switch for control, which is displayed on the user communication device 134.

Referring still to FIG. 1 and 2, the sensor device 110 may comprise: (a) two or more magnetic field sensors or electric current sensors 211, (b) a controller 213, (c) a communication module with a user 214, (d) a communication module 215, (e) a source power supply 216 and (f) linkage mechanism 219. Controller 213 may be used to control current sensors 211, user communications module 214, communications module 215, and power supply 216.

Electric current sensors 211 may include an inductive sensor, a Hall effect sensor, a magnetoresistive sensor, or any other type of sensor designed to respond to the time-varying magnetic field generated by the wires inside the switchboard 190.

In various examples, the sensor device 110 may be configured to communicate with the surface of the shield 190 via the link mechanism 219. In some examples, the link mechanism 219 may comprise an adhesive, Velcro® material, a magnet, or other attachment mechanism.

Communication module 215 may be electrically coupled to current sensors 211 and controller 213. In some examples, communication module 215 communicates voltages or other parameters measured by electric current sensors 211 to communication module 221 of computing unit 120. In many examples, communication module 215 and communication module 221 can be wireless transceivers. In some examples, electrical signals may be transmitted using WI-FI (Wireless Precision), IEEE (Institute of Electrical and Electronics Engineers) 802.11 wireless communications, or Bluetooth 3.0 + HS (High Speed) wireless communications. In additional examples, these signals may be transmitted using Zigbee (IEEE 802.15.4 wireless protocol), Z-Wave, or a proprietary wireless standard. In other examples, communications module 215 and communications module 221 may transmit electrical signals using cellular or wired communications.

User communication module 214 may be constructively executed to display information to a user. In one example, the user communication module 214 may be an LCD (liquid crystal display) and / or one or more LEDs (light emitting diodes).

Controller 213 can be configured to control electric current sensors

- 6 037144

211, communications module 215, user communications module 214, and / or power supply 216.

Calibration device 180 may comprise: (a) communication module 281, (b) electrical connector 282, (c) calibration load module 283, (d) user communication device 184, (e) controller 285, and (f) power supply 289. In some examples, communications module 281 may be the same or the same as communications module 215 and / or 221. Electrical connector 282 may be an electrical power plug in some examples. User communication device 184 may be structurally implemented to display information to a user. In one example, communication device 184 may be one or more LEDs.

According to Ampere's law, current-carrying wires create magnetic fields as shown in FIG. 4. That is, the magnetic field created by this wire is a three-dimensional vector field that can be decomposed into components along each of the X, Y, and Z axes. In an alternating current system, these magnetic fields vary with time in magnitude, but keep the vector angle unchanged relative to the origin. Thus, when referenced to the X-axis, for example, the field can be directed in the + X direction or in the -X direction at any time when the alternating current is reversed at a linear frequency of, for example, 60 Hz. It is assumed that the component of the magnetic field in the X direction may refer to either + X or -X, depending on the direction of current flow at a particular time.

The lines of force of the magnetic field obey the right-hand rule of Ampere's law; if the thumb of the right hand of a person is directed along the direction of current flow in the conductor, the field lines of force twist around the conductor perpendicular to this conductor and in the direction of the fingers of the person's hand.

Some embodiments mainly relate to the magnetic field component oriented perpendicular to the plane of the circuit breaker board (Z-axis), since these are field components that can be readily read by a magnetic field sensor (i.e., sensor device 110) outside the shield metal cover. circuit breakers 190.

As shown in FIG. 5, since the power wires 193 and 194 have a phase angle of 180 °, the direction of the magnetic field lines loops in opposite directions.

Thus, in accordance with the first Kirchhoff's law, the total current through a given supply wire (i.e., power wires 193, 194 and / or 195) is the sum of all load currents drawn from this wire. Therefore, the magnitude of the magnetic field produced by each of the wires (i.e., the power wire 193, 194, or 195) is directly proportional to the sum of the currents flowing through all the branches connected to that wire. The direction of the lines of force of the magnetic field from a given wire does not change, like the currents in the branches.

System 100 may be configured to read magnetic fields generated by at least the power wires 193 and 194 to consider three possible load cases: (a) 120 V load in arm 193-195, (b) 120 V load. arm 194-195 and (c) 240 V load in arm 193194. In most cases, it is not necessary to read the magnetic field generated by power wire 195 (i.e. neutral wire), since any current flowing out of power wire 195 flows first on the power line 193 or 194.

FIG. 6 illustrates an example of an electric current sensor 211 in accordance with the first embodiment. In these examples, an electric current sensor may comprise: (a) one or more sensors 641 and 642, (b) one or more amplifiers 647 and 648, (c) one or more filters 649 and 650, (d) one or more phase detectors 651, (e) at least one differential amplifier 652, and (f) at least one digitizer 653.

In some examples, system 100 may be structurally implemented to assist a user in the correct placement of sensor device 110 by indicating the correct placement via a user communication module 214. In some examples, system 100 may determine correct placement by detecting an approximately 180 degree phase shift between sensors 641 and 642 located on opposite sides of the wire (i.e., electrical power wire 193 or 194). In the same or different examples, the user communication module 214 may be co-located with the sensor device 110, or the user communication module 214 may be used, which may be remote and communicated with the sensor device 110 over a wireless network.

Sensor 641 may include: (a) a ferromagnetic core 643 and (b) a pickup coil 644 wound around a ferromagnetic core 643. Sensor 642 may include: (a) a ferromagnetic core 645 and (b) a pickup coil 646 wound around a ferromagnetic core 645. In various examples, probes 641 and 642 may have diameters ranging from 2.5 mm to 12.7 mm. In other examples, electric current sensor 211 comprises only sensor 641 without sensor 642, amplifier 647, filter 649, phase detector 651, and / or differential amplifier 652. In this alternative embodiment, filter 649 or 650 is associated with digitizer 653. In further embodiments electric current sensor 211 contains four, six, eight, or ten sensors.

The purpose of the ferromagnetic cores 643 and 645 is to concentrate the magnetic field from the pickup coils 644 and 646 in order to obtain a higher output voltage of the sensor at the output terminals.

- 7 037144 reading coils 644 and 646. The voltage at the output of the reading coils 644 and 646 is set according to Faraday's law. That is, the voltage depends on the applied AC magnetic field, the physical dimensions of the coil and wire, the number of turns of the wire in the coil, and the magnetic permeability of the core. In other examples, sensors 641 and 642 do not have ferromagnetic cores 643 and 645, respectively.

As shown in FIG. 7, when an electric current sensor 211 is coupled to the circuit breaker board 190, one of the sensors 641 and 642 may be located on either side of the wire (ie, the electrical power wire 193 or 194). In this embodiment, the induced voltage across sensor 641 is 180 ° out of phase with respect to sensor 642 because the magnetic field enters sensor 642 from below while magnetic field enters sensor 641 from above.

FIG. 8 is a plot of the phase relationship between the voltage across sensors 641 and 642. When referring to FIG. 8, an alternating current flowing in the wire (i.e., electrical power wire 193 or 194) induces a voltage V (sensor) in sense coils 644 and 646. This voltage V (sensor) is proportional to the current I (sensor) carried by the wire ( i.e. electrical power wire 193 or 194), i.e. V (sensor) = k I (sensor). The proportionality constant k can be found by passing a known current through a wire by temporarily connecting a calibration load (i.e., calibration load module 283 or 227 (FIG. 2) to the circuit fed by the wire (i.e., electrical power wire 193 or 194), and measuring the voltage induced at sensors 641 and 642 in Fig. 6. In some cases, more than one known current may be tapped to establish a multipoint constant proportional calibration.

Referring back to FIG. 6, this dual-sensor design (i.e., sensors 641 and 642) can be used to provide a sensor device 110 that automatically informs the user that it is correctly positioned relative to a given current-carrying wire, while suppressing interference from other sources, including others. adjacent wires. This ability is useful in an electrically noisy environment in a circuit breaker switchboard where there are many wires near a particular wire of interest.

Specifically, in some embodiment, the output of each of sensors 641 and 642 may be amplified by amplifiers 648 and 647, respectively, and then filtered by filters 650 and 649, respectively. The output of filters 650 and 649 may be provided to a phase detector 651 coupled to a phase indicator 619 in a user communications module 214 (eg, one or more LEDs). User communication module 214 is intended to indicate to the user that sensors 641 and 642 are correctly positioned with respect to a given current carrying wire. The user can be instructed to move the sensor around the area where the main power wires are to be located and stop moving as soon as the phase indicator indicates that the phase shift between the signals of the sensors 641 and 642 is approximately 180 °. For example, when the signals from sensors 641 and 642 are approximately 180 ° out of phase, a green LED at the top of the sensor device 110 may illuminate.

Amplifiers 648 and 647 and filters 650 and 649 are optional in some examples. The purpose of amplifiers 648 and 647 and filters 650 and 649 is to increase the signal level with suppression of interference at unwanted frequencies and thereby increase the signal-to-noise ratio of signals from sensors 641 and 642 in noisy environments. The amplifiers 648 and 647 can be operational amplifiers such as the TL082 type manufactured by Texas Instruments, Inc. Filters 650 and 649 can be either passive lumped element filters or active filters implemented with operational amplifiers. Typically, filters 650 and 649 are bandpass filters designed to pass the AC line frequency (for example, 60 Hz in the US and Canada, or 50 Hz in Europe and Japan) while rejecting out-of-band noise.

The phase detector 651 can be either an analog phase detector circuit or a digital phase detector. The digital phase detector can be implemented using combinatorial logic, programmable logic, or software in the controller. In one embodiment, an integrated circuit phase detector may be used, such as the phase detector contained in a 4046 or 74HC4046 phase locked controller manufactured by Texas Instruments, Inc. In another embodiment, the phase detector 651 is implemented by digitizing the sensor signals using an analog-to-digital converter and then fitting the arctangent function to the vector of the received samples from the sensors 641 and 642. In a further embodiment, the filtering and phase detection functions are combined by using a periodogram-based maximum likelihood estimate , such as a complex fast Fourier transform (FFT) algorithm, for finding the signal magnitude and phase angle only at the linear AC frequency, while suppressing noise at other frequencies.

The phase indicator 619 can be any device that indicates to the user that the required

- 8 037144 the phase relationship between the inputs of the sensors 641 and 642 has been reached. In some embodiments, the phase indicator may be one or more LEDs. In other embodiments, the phase indicator 619 may be a graphic or digital display, such as a liquid crystal display (LCD), or an audible signal to indicate to the user that the voltages of the sensors 641 and 642 are out of phase by about 180 degrees.

Differential amplifier 652 can be used to combine signals from sensors 641 and 642 to obtain a current or voltage signal proportional to the current in the main electrical power wire, once the correct phase relationship has been established. This signal can be used as input for calculations performed by controller 213. In the same or different example, communication module 215 can be used to transmit data to the computing unit, including: (a) the correct location of sensors 641 and 642, as indicated in the phase relationship of the sensors; and (b) a differentially read signal from sensors 641 and 642.

Referring to another embodiment in FIG. 9 illustrates an example of a sensor 910 in accordance with a second embodiment. FIG. 10 illustrates an example of a sensor 910 above power lines 193 and 194 in accordance with a second embodiment. In this example, linear sensor array 941 | can be used. 9412, ..., 941N, where N is a number between 2 and 10. In other examples, N can be another number, such as 4, 6, 8, 20, 50, or 100. One of the purposes of this linear group of sensors is to allow the controller 213 to automatically select one or more pairs of sensors 9411 9412, ..., 941N, so that the user does not have to manually place the sensor 910 in the correct position. In some embodiments, sensor 910 may be used in place of sensor 110 in system 100 of FIG. one.

Referring to FIG. 9 and 10 in this example, the sensor 910 may contain: (a) sensors 9411, 9412, ..., 941N, (b) amplifiers 647 and 648, (c) filters 649 and 650, (d) phase detectors 651, (e ) a differential amplifier 652, (f) a digitizer 653, and (g) at least one multiplexer 955 and 956.

As shown in FIG. 10, a linear group of sensors 941 ₁ , 9412, ..., 941N is associated with multiplexers 955 and 956, which select from sensors 941 ₁ , 9412, ..., 941N at least one sensor for use as a magnetic field sensor to obtain a signal proportional to the current in the main power lines 193 and / or 194.

In another embodiment, the sensor 910 simultaneously reads more than one wire from the electrical power wires 193 and 194. In this embodiment, the controller 213 controls the multiplexers 955 and 956 such that _{two distinctives are selected from the sensors 941 1} , 9412, ..., 941N. sensors located adjacent to two different current carrying power wires 193 and 194. In this embodiment, the controller 213 controls the multiplexers to select sensors based on the amplitude or phase angle of the sensor signal. In some embodiments, under the control of controller 213, multiple sensors from sensors 941 ₁ , 9412, ..., 941N are multiplexed to select discriminating sensors, each of which has a preferred magnetic field communication with the discriminating current-carrying wire.

Referring back to FIG. 1, in some examples, calibration may be applied to system 100 to achieve accurate current measurement in electrical power wires 193 and 194. The possible need for calibration may be due to poorly controlled mounting geometry, for example, if the sensor device 110 or 910 (FIG. 9) is installed by an untrained user.

FIG. 11, an example of a calibration device 180 according to the first embodiment is illustrated. Calibration device 180 is shown in FIG. 11 as a single-circuit calibration device designed to connect a single calibration load to a single input wire (i.e. electrical power wire 193 or 194) to close the circuit between the input wire, single calibration load and neutral or return wire (i.e. electrical power wire 195). To temporarily close the loop with the calibration load used in the calibration method 1800 of FIG. 18, a switching signal is applied.

In some examples, calibration load module 283 may comprise: (a) switched load 1105, (b) transformer 1171, (c) filter 1172, (d) level translator 1173, and (e) square wave shaper 1174. Switching load 1105 may comprise : (a) switch 1187 and (b) calibration load 1188. Controller 285 may comprise: (a) analog-to-digital converter 1177; (b) digital input 1176 and (c) temperature sensor 1186.

In the embodiment of FIG. 11, the calibration load module 283 may be configured to calibrate a single live wire (branch circuit feeder) measurement measured by the sensor device 110. In this embodiment, the single calibration load 1188 is switched by a switch 1187 between a line wire (e.g., main power wires 193 and 194) and a neutral wire (e.g. main power wire 195) controlled by a switching signal from controller 285. In the USA, the 1105 switched load can be used with a 120V outlet. In other countries, the 1105 switched load can be used with 240V outlets, and more. voltage.

- 9 037144

It should be understood that although the calibration load 1188 and the calibration loads in FIG. 14-17 are drawn as resistor, calibration load 1188, and other calibration loads in FIG. 14-17 can be any load, including a reactive load such as an inductor or capacitor, with or without an active component. In addition, the calibration load can be a variable resistance load. In addition, it should be understood that although switch 1187 and other switches in FIG. 14-17 are drawn as mechanical relay switches, switches may be related to other types of switching devices. For example, the switches can be semiconductor switches such as solid state relays, symmetrical triode thyristors, transistors such as FETs (field effect transistors), SCRs (triode thyristors), BJTs (bipolar junction transistors), or IGBTs (insulated gate bipolar transistors). or other controlled switching devices.

As shown in FIG. 11, communication module 281 is coupled to controller 285 to transmit calibrated current measurements from calibration device 180 to computing unit 120. In some examples, communication module 281 may include a receiver and transmitter. Communications module 281 may comprise any kind of wired and wireless communications device operating on any frequency and with any data link protocol. In one embodiment, communications module 281 includes a 2.4 GHz transceiver with part number CC2500, available from Texas Instruments, Inc. In another embodiment, communications module 281 comprises a 900 MHz transceiver with part number CC2010 available from Texas Instruments, Inc. In some embodiments, communications module 281 may transmit messages using any of the following communications protocols: WiFi (IEEE 802.11), Zigbee (IEEE 802.15.4), ZWave, or SimpliciTI. In another embodiment, a proprietary communication protocol is used. In another embodiment, the communication link between the communication module 215 and the communication modules 281 and / or 221 is provided via a monitored wire. In this embodiment, the communication channel is a power line communication created by injecting the transmitted signal into at least one wire of the branch circuit to which the calibration device is connected.

In the example shown in FIG. 11, power supply 289 may include a power supply 289. Power supply 289 may include an isolation transformer and a DC power supply. The 289 power supply converts the incoming line voltage from AC power line voltage, such as 120 V in the US and Canada, or 220 V in Europe, to a low DC voltage, such as 3.3 V or 5 V, to power the 213 controller and others. elements of the calibration device 180.

Controller 285 may receive a sample of the incoming AC power line voltage converted by level translator 1173 to a lower AC voltage signal proportional to the incoming AC power line voltage. In some embodiments, the AC input power line voltage is 120 V with the lower AC voltage signal in the 0-3.3 V range. In some embodiments, a level translator 1173 is used to switch the low voltage signal from a bipolar signal that is intermittently between + V and -V, to a unipolar signal between 0 V and VDD, or to another range of a unipolar signal within the voltage range of A / D converter 1177. A / D converter 1177 may sample the incoming low voltage signal as shown in FIG. 12. In the same or different embodiments, filter 1172 may limit the frequency range of the low voltage signal to the frequency of the AC line.

In many examples, A / D converter 1177 may be integrated with controller 285, or may be separate from controller 213 but associated with controller 285. The sampled AC line voltage allows controller 213 to measure the incoming AC line voltage to more accurately calibrate system 100 by calculating current taken by the 1188 calibration load, given a sampled low voltage signal proportional to the incoming AC line voltage. The additionally sampled low voltage signal can be used to design a phase reference synchronous with the AC line voltage.

In some embodiments, controller 285 uses a low voltage square wave to develop the phase reference. In these embodiments, the low voltage square wave is generated by the square wave shaper 1174. The low voltage square wave may be a square wave having the same period and zero crossing time as the low voltage AC signal. This relationship between the square waveform and the low voltage signal is shown in FIG. 13. In some embodiment, square wave shaper 1174 may include a Schmidt flip-flop, comparator, or digital logic gate such as an inverter or transistor level shifter. The amplitude of the square wave is selected by a logic level compatible with controller 285. The square wave does not contain information about the voltage amplitude of the incoming AC line, but contains phase information because the rising and falling edges of the square wave are synchronous with zero crossings.

- 10 037144 AC input line voltage.

In some embodiments, a phase reference obtained from either a low voltage signal or a square wave analog thereof is used to measure the relative phase angle between the calibrated current measured by the sensor device 110 and the incoming power line voltage. This measurement of the relative phase angle between voltage and current is used to accurately account for the power factor of reactive loads connected to the power wire as varied by the sensor device 110. The power factor is the cosine of the phase angle between the voltage and current waveforms. This power factor can be calculated directly from the sampled low voltage signal or, in the case of a low voltage square wave, can be calculated indirectly by fitting a sine wave of the desired frequency to the edge transitions in the square wave.

The power factor is the ratio of the active power flowing in the wire to the total power flowing in the wire. In some embodiments, it is preferred for the user of system 100 to report the active power flowing in electrical power wires 193, 194, and 195 for better understanding of the electrical energy meter read by the electricians. In these embodiments, the phase information provided by the low voltage signal is critical for correctly calculating the predicted energy.

Since the 1188 calibration load dissipates current when connected using switch 1187, the 1188 calibration load is prone to heat. This heating can jeopardize the safe operation of the calibration load 1188 by causing thermal damage to the calibration load 1188 itself or other components in the housing of the calibration device 180 or to people or objects in the vicinity of the calibration device 180.

In some embodiments, controller 285 includes a temperature sensor 1186, such as a bimetallic thermostat, thermistor, or semiconductor temperature sensor. In some embodiments, the temperature sensor 1186 interrupts the connect signal to disconnect the calibration load 1188 when the calibration load 1188 or the body of the calibrator 180 becomes too hot.

In additional embodiments, the controller 285 checks the temperature reading at the temperature sensor 1186 prior to connecting the calibration load 1188 to ensure that the calibration load 1188 or the body of the calibrator 180 is not too hot at the beginning of the calibration process. In still further embodiments, the controller 285 may extrapolate to determine if the calibration load 1188 is likely to become too hot after the normal running time of the calibration load 1188. In this embodiment, the controller 285 acts to delay the calibration process until the process cannot will complete without the 1188 calibration load or the housing of the calibrator 180 getting too hot.

In some embodiments, there are two different control mechanisms through which the controller controls the signal to connect to switch 1187. These two methods correspond to two different locations in the processor where the calibration is run to obtain a calibrated current measurement.

In the first method, the controller 285 is co-located with and controls the calibration load module 283. In addition, controller 285 may receive sensor readings from sensor device 110 (via communication module 281) and controller 213. Controller 285 performs a calibration process (described below with reference to FIG. 18) and obtains a calibrated current measurement. In these examples, the calibration calculation module 229 may be located in the calibration device 180 rather than in the computing unit 120.

In the first method, if the calibration process is run by controller 285, communications module 281 receives measurements of an input signal from sensor 110 and / or computing unit 120. Controller 285 may calculate calibrated current measurements using method 2000 of FIG. 20. After calculating the calibrated current measurements, the calibration device 180 may report the calibrated current measurements to the computing unit 120 for display and other uses.

In the second method, a remote processor, such as controller 225 (FIG. 2) or controller 213 (FIG. 2), issues a command to connect or disconnect the calibration load 1188, and this controller (controller 225 or controller 213) performs the calibration method 1800 in FIG. ... 18 and obtains a calibrated current measurement as described in method 2000 of FIG. twenty.

If the second method is applied to the controller 225 in the calibration control, the controller 225 receives a communication message from the controller 285. In some embodiments, the controller 225 sends a message to connect the calibration load for a specified period of time. In some embodiments, a given time period is selected from one or more predetermined time periods. In other embodiments, the implementation of the calibration load 1188 is enabled until the controller 285 receives a trip message, or until

- 11 037144 maximum timer wait time or 1186 temperature sensor trip indicating that the 1188 calibration load or its housing is too hot.

In additional embodiments, the controller 285 independently decides to connect the calibration load for a specific period of time. In some examples, controller 285 connects and disconnects calibration load 1188 for a specified period of time while simultaneously sending a notification to controller 225 in advance or later indicating that calibration load 1188 is connected. In this embodiment, controller 213 applies a known time offset between messages received from controller 285 to synchronize the flow of the calibration procedure with the connection / disconnection time of the calibration load 118 indicated in the message received from the controller 285 via the communication channel. In other examples, controller 285 connects and disconnects calibration load 1188 in a sequence that is known to controller 213 and / or 225 (FIG. 2).

FIG. 11 illustrates one example of a switched load 1105 in a calibrator 180. Other possible switch load designs are shown in FIG. 14-17.

In particular, in FIG. 14 illustrates an example of a switched load 1405 in accordance with the third embodiment. The switched load 1405 may comprise: (a) switches 1187 and 1442 and (b) calibration loads 1188 and 1441. In this embodiment, the switched load 1405 replaces the switched load 1105 in calibrator 180 of FIG. 2 and 11.

In this embodiment, the switched load 1405 may be configured to calibrate the measurement of a single current carrying wire (a feeder in a branch circuit, indicated as a line) measured by the sensor device 110. In this embodiment, the controller 285 can switch between calibration loads 1188 and 1441 to provide two different sets of measurements for use in the calibration process. In other examples, the switched load 1405 may include three or more switches of three or more calibration loads.

FIG. 15 illustrates an example of a switched load 1505 in accordance with a fourth embodiment. The switched load 1505 may comprise: (a) switches 1587 and 1542 and (b) calibration loads 1588 and 1541. In this embodiment, the switched load 1505 replaces the switched load 1105 in calibrator 180 of FIG. 2 and 11.

In this embodiment, the switched load 1505 may be configured to calibrate the measurement result of the two current-carrying wires (branch circuit feeders, designated line 1 and line 2) as measured by the sensor device 110. In this embodiment, the two differential calibration loads 1588 and 1541 may connect between the individual line wires and the neutral wire under the control of the connect signal from controller 285. Controller 285 can control the connect signals to electrically couple the calibration loads as described below

Closed switch Connected calibration loads Result Switch 1587 closed Calibration load 1541 Possible to calibrate the measurement result of the feeder in the branch circuit designated as line 1 Switch 1542 closed Calibration load 1588 Possible to calibrate the measurement result of the feeder in the branch circuit designated as line 2 Switches 1587 and 1542 closed Calibration loads 1541 and 1588 Possible to calibrate feeders in branch circuits designated as line 1 and line 2 Neither switch 1587 nor switch 1542 is closed Absent Is absent

FIG. 16 illustrates an example of a switched load 1605 in accordance with a fifth embodiment. The 1605 switched load may contain: (a) switches 1687, 1642, and

- 12 037144

1643 and (b) calibration loads 1588 and 1541. In this embodiment, the switched load 1605 replaces the switched load 1105 in the calibrator 180 of FIG. 2 and 11.

In this embodiment, the switched load 1605 may also be configured to calibrate the measurement result of more than one current carrying wire (branch circuit feeders, designated line 1 and line 2) as measured by the sensor device 110. In this embodiment, two different calibration loads The 1588 and 1541 are wired to allow the 1588 and 1541 calibration loads to be connected either individually to the return neutral or as a pair to a line 1-line 2 pair, which is common in split-phase power systems. The 285 controller can control connect signals to electrically couple calibration loads as indicated below.

Closed switch Connected calibration loads Result Switches 1643 and 1642 closed Calibration load 1541 with return neutral Possible to calibrate the measurement result of the feeder in the branch circuit designated as line 1 Switches 1643 and 1687 closed Calibration load 1588 return neutral wire Possible to calibrate the measurement result of the feeder in the branch circuit designated as line 2 Switches 1643, 1642, and 1687 closed Calibration Loads 1541 and 1588 with Return Neutral Possible to calibrate feeders in branch circuits designated as line 1 and line 2 Switches 1642 and 1687 are closed, but switch 1643 is not closed. Calibration loads 1541 and 1588 are connected in series between line 1 and line 2 Split-phase electrical system can be calibrated from a single split-phase calibrator None of switches 1643, 1642, and 1687 are closed Absent Is absent

FIG. 17 illustrates an example of a switched load 1705 in accordance with a sixth embodiment. The switched load 1705 may comprise: (a) switches 1787, 1742, and 1743 and (b) a calibration load 1788. In this embodiment, the switched load 1705 replaces the switched load 1105 in calibrator 180 of FIG. 2 and 11.

In this embodiment, the switched load 1705 is also configured to calibrate the measurement result of more than one current-carrying wire (the feeders in the branch circuits indicated as line 1 and line 2) measured by the sensor device 110. In this embodiment, one calibration load 1788 is connected to calibrate the two wires plus neutral, which is common in split-phase power systems. The 1787 and 1743 switches can be single pole double throw (SPDT) switches. The 1787 and 1743 switches can be used with a 1788 calibration load to link different combinations of branch circuit wires. The switched load 1705 can be cheaper to implement than the switched load 1605 (FIG. 16) due to the use of a single calibration load. The 285 controller can control connect signals to electrically couple calibration loads as indicated below.

- 13 037144

Closed switch Connected calibration loads Result 1787 switch in position 1, 1743 switch in position 1, and 1742 switch in position 1. 1788 Gauge Load with Reverse Neutral Possible to calibrate the measurement result of the feeder in the branch circuit designated as line 2 1787 switch in position 0, switch 1743 in position 1, switch 1742 in position 1. 1788 Gauge Load with Reverse Neutral Possible to calibrate the measurement result of the feeder in the branch circuit designated as line 1 Switch 1787 in position 0, switch 1743 in position 0, switch 1742 in position 1. 1788 Gauge Load in series between line 1 and line 2 with no return neutral Split-phase electrical system can be calibrated from a single split-phase calibrator Switch 1787 in position 0 or 1, switch 1743 in position 0 or 1, and switch 1742 in position 0 (i.e., open position). Absent Is absent

In many examples, it is necessary to calibrate both phase lines of the electrical infrastructure. Accordingly, one of the calibration devices in FIG. 11 and 14-17 would need to be inserted into the first phase arm and the second phase arm. In the example shown in FIG. 2, the calibrator 180 is the first calibrator, and the second calibrator is contained in the computing unit 120. In other examples, a single calibrator (for example, a calibrator with one of the switched loads 1505, 1605, or 1705) can be plugged into a 240 volt outlet. connected to both the first and second phase branches.

In an embodiment in which one of the calibration devices in FIG. 11 and 14-17 is inserted into the first phase branch and the second phase branch, the calibration devices must be able to communicate with each other, with the sensor device and the computing unit. A number of different communication methods could be implemented. For example, all calibration devices could receive and transmit data. In other examples, one calibration device (eg, calibrator 180 of FIG. 1) can transmit data and a second calibration device (eg, computing unit 120 of FIG. 2) can receive data.

In some embodiments, the two calibration devices may be in radio communication. For example, communication module 281 and communication module 221 in FIG. 2 may contain radio. The calibration devices are designed in such a way as to determine if they are on different electrical phase branches by communicating the phase angle of the observed cycle of 60 Hz to other calibrators. In some examples, one calibration device can wirelessly communicate to another calibration device when a zero crossing of an electric current or voltage occurs. Overlapping of received radio messages will occur in messages when both calibration devices are installed in the same electrical phase branch. If there is an offset between the observed zero crossing and the received message, the calibration devices are installed in different electrical phase branches.

In the same or different example, the user communication device 184 in the calibrator 180 (FIG. 1) may include a single red / green LED. A green LED can indicate that the two calibration devices are installed correctly in two different phases. On the

14 037144 example, the user first sets up the calibration device 180 of FIG. 1 (i.e. the transmitting calibration device) into an arbitrary electrical outlet. The user then sets up the computing unit 120 of FIG. 1 (i.e. the calibration receptacle) into a different electrical outlet. The user communication device LED 184 may illuminate red to indicate that they are both in the same phase, or green if they are in different phase branches. The user can move the second calibrator to other outlets until the green indicator of the user communication device 184 appears.

In other embodiments, wireless communication may also exist between each of the sensor device 110, the calibrator 180, and the computing unit 120. In this embodiment, the sensor device 110 may detect two electrical phases in the switch cabinet. As the calibration device 180 cycles through its electrical loads, the calibration device 180 can notify the sensor device 110, and the sensor device 110 can determine which phase the calibration device 180 is connected to. The computing unit 120 can also inform the sensor device 110 when it begins its cycle according to loads. The sensor device 110 observes at what phase angles these changes occur to conclude that the calibrators are installed in two different phases.

In yet another example, a non-wireless communication method may be used for communication between the calibration device 180 and the computing unit 120. In these examples, communication modules 221 and / or 281 may comprise a signal generator and / or a signal receiver. In this example, calibrator 180 and computing unit 120 may send a signal over the power electrical infrastructure. For example, a simple 1 kHz tone burst may be used. In the same or different examples, the signal is an amplitude modulated voltage applied to one or more wires of the power electrical infrastructure. In another embodiment, the signal is an amplitude modulated current drawn from the power electrical infrastructure. In another embodiment, the signal is an amplitude modulated voltage or current. In one embodiment, the computing unit 120 may serve as a signal transmitter, while the calibration device 180 may act as a receiver. If the calibrator 180 is plugged into an electrical outlet, the user communication device 184 may illuminate a green LED if it cannot detect the presence of a signal from the first device. If the calibration device 180 and computing unit 120 are connected to separate phase branches, the calibration device 180 and computing unit 120 cannot detect signals transmitted over the power electrical infrastructure to others.

If the calibrator 180 detects a signal, then a red LED may indicate that the two calibrators are in the same phase. In this case, the user can be instructed to transfer the calibration device 180 or computing unit 120 to another electrical outlet. In yet another embodiment, instead of communication modules 221 and 281 containing a signal generator and / or receiver, communication modules 221 and 281 may comprise power line communication (PLC) modules to allow calibrator 180 and computing unit 120 to communicate over a power electrical infrastructure. ...

Referring to another embodiment in FIG. 18 illustrates a route map of an embodiment of a method 1800 for calibrating an electrical energy monitoring system in accordance with an embodiment. Method 1800 is exemplary only and is not limited to the embodiments presented herein. Method 1800 can be used in many different embodiments or examples not specifically shown or described herein. In some embodiments, the steps, procedures, and / or processes of method 1800 may be performed in the order presented. In other embodiments, the steps, procedures, and / or processes of method 1800 may be performed in any other suitable order. In still other embodiments, one or more work steps, procedures, and / or processes in method 1800 may be combined or omitted.

Method 1800 can be viewed as a general method for calibrating a sensor device. This method can include determining one or more calibration factors that can be used to calculate the predicted current in the power electrical infrastructure of the structure in the method 2000 of FIG. 20. The method described below can be used to accurately calculate the calibration coefficients regardless of the position of the sensor device 110 (FIG. 1) on the shield 196 (FIG. 1), except for the following points: (a) if the electric current sensors 211 (FIG. 2 ) are located so far from the main power wires 193 and 194 (Fig. 1) that an almost indistinguishable signal is measured from the main power wires 193 and 194, and (b) if all the electric current sensors 211 (Fig. 2) are located too close to neutral electrical power wire 195 (FIG. 1) and away from electrical power wires 193 and 194.

Method 1800 in FIG. 18 includes the step 1860 of obtaining and storing one or more first baseline measurements. In some examples, the sensor device 110 (FIG. 2) may be

- 15 037144 used to obtain the first basic measurements using electric current sensors 211 (Fig. 2). These first baseline measurements may contain the rated current flowing through at least one power wire 193 or 194 (FIG. 1) due to the presence of electrical devices that take electrical energy. In addition, amplitude and phase measurements can be performed on each sensor (eg, sensors 641 and 642 (FIG. 6) or sensors 9411, 9412, ..., 941N (FIG. 9)). Each L amplitude reading is stored under the name Lcτa _р-N , and each phase 0 reading is stored under the name 0cτa _PN , where N is the sensor number. In some examples, the first baseline measurements are made in both the first phase branch and the second phase branch.

In some examples, operation 1860 also includes determining the amplitude and phase angle of the voltage. The phase angle of the voltage can be used to help calculate the phase angle of the current. In some examples, voltage sensor 228 of FIG. 1 may be used to determine the phase angle of the voltage. 2.

Next, the method 1800 of FIG. 18 includes an operating step 1861 of temporarily connecting a first known calibration load to a first phase branch. In some examples, the calibration device 180 (FIGS. 1 and 11) may be connected to one of the calibration loads in the switched loads 1105, 1405, 1505, 1605, or 1705 of FIG. 11, 14, 15, 16 and 17, respectively.

Then, the method 1800 of FIG. 18 includes a step 1862 of obtaining and storing one or more first calibration measurements in a first phase branch. In some examples, sensor device 110 (FIG. 2) may be used to obtain first calibration measurements from electric current sensors 211 (FIG. 2). In some examples, the first calibration measurements are made when the known calibration load from the switched load 1105, 1405, 1505, 1605, or 1705 of FIG. 11, 14, 15, 16 and 17 are respectively connected to the first phase branch (for example, to line 1 in FIGS. 15-17). This first known calibration load will take the known current L _cal-1 . These first calibration measurements may comprise a nominal current flowing through at least one of the power leads 193 or 194 (FIG. 1) due to the presence of electrical devices taking electrical energy and the first known calibration load.

For example, on each sensor (eg, sensors 641 and 642 (FIG. 6) or sensors 9411, 9412, ..., 941N (FIG. 9)), an amplitude and phase angle measurement is performed. Each L amplitude reading is stored under the name L _new-N- l, and each phase angle reading 0 is stored under a name such as 0 _new-N- l, where N is the sensor number.

In some examples, operation 1862 also includes determining the amplitude and phase angle of the voltage. The phase angle of the voltage can be used to help calculate the phase angle of the current. In some examples, voltage sensor 228 of FIG. 2 may be used to determine the phase angle of the voltage. 2.

Method 1800 of FIG. 18 continues with operation 1863 in which the first known calibration load is disconnected and a second known calibration load is temporarily connected to the second phase branch. In some examples, calibration device 180 (FIGS. 1 and 11 may be connected to one of the calibration loads in switched loads 1405, 1505, or 1605 in FIGS. 14, 15, and 16, respectively. In some examples, a second known calibration load is connected to a second phase branch ( for example, to line 2 in Figs. 15-17).

Next, the method 1800 of FIG. 18 includes a step 1864 of obtaining and storing second calibration measurements in the second phase branch. In some examples, sensor device 110 (FIG. 2) may be used to obtain second calibration measurements from electric current sensors 211 (FIG. 2). These second calibration measurements may comprise a nominal current flowing through at least one of the power leads 193 or 194 (FIG. 1) due to the presence of electrical power drawers and a second known calibration load. In some examples, the second calibration measurements are made when a known calibration load is connected to the second phase branch (eg, line 2 in FIGS. 15-17). This second known calibration load will take the known current L _cal-2 .

For example, on each sensor (eg, sensors 641 and 642 (FIG. 6) or sensors 9411, 9412, ..., 941N (FIG. 9)), an amplitude and phase angle measurement is performed. Each L amplitude reading is stored under the name L _new-N-2 , and each phase angle reading 0 is stored under a name such as 0 _new-N-2 , where N is the sensor number.

In some examples, operation 1864 includes determining the amplitude and phase angle of the voltage. The phase angle of the voltage can be used to help calculate the phase angle of the current. In some examples, voltage sensor 228 of FIG. 2 may be used to determine the phase angle of the voltage. 2.

Then, the method 1800 of FIG. 18 includes step 1865 of disconnecting any known calibration loads (ie, second calibration load) from power leads 193, 194, and / or 195 (FIG. 1).

Method 1800 in FIG. 18 continue with the operation 1866 of receiving and storing one or

- 16 037144 of several second baseline measurements. In some examples, sensor device 110 (FIG. 2) may be used to obtain second baseline measurements from electric current sensors 211 (FIG. 2). These second baseline measurements may comprise a nominal current flowing through at least one of the power leads 193 or 194 (FIG. 1) due to the presence of electrical devices that draw electrical energy. The purpose of this second baseline reading is to ensure that the base load observed in step 1861 does not change during calibration. If the measurements in step 1866 are equal to the measurement in step 1861 within a predetermined value, the measurements in step 1866 can be discarded. If the measurements in work step 1866 are outside the specified range, the measurement in work step 1861 can be discarded. In other examples, work step 1866 may be omitted.

In some examples, operation 1866 also includes the operation of determining the amplitude and phase angle of the voltage. The phase angle of the voltage can be used to help calculate the phase angle of the current. In some examples, voltage sensor 228 of FIG. 2 may be used to determine the phase angle of the voltage. 2.

Next, the method 1800 of FIG. 18 includes step 1867 of determining calibration coefficients. In some examples, operation 1867 includes applying the sensor calibration equation (s) to the reference measurement and each of the calibration measurements to calculate the calibration factors of the sensor device 110 (FIG. 1) to obtain a calibrated current measurement on at least one wire that is being read. sensor device 110. In some examples, calibration coefficients may be determined using calibration calculation module 229 (FIG. 2), as described below.

FIG. 19 illustrates a route map of an exemplary embodiment of a calibration factor determination operation 1867 in accordance with the first embodiment. In some examples, operation 1867 may broadly include performing a calculation of the calibration factors 0 _M , K1, K ₂ , Y _1, and Y ₂ . In other examples, you can define other calibration factors.

Referring to FIG. 19, operation 1867 includes a procedure 1971 for determining potential calibration factors for the first phase branch. In some examples, for each sensor from 1 to N (where N is the number of sensors in the electric current sensor), routine 1971 may involve performing a calculation of X _N-1 and 0 _{M. N} .1 using L _hundred p. _N , 0 _сma p- _N , L _cal-1 , L Hoe-N-1 and 0 _H o _BN-1 , where Xn-1 - [^ {bstar - ^ + bnov-N -1 ^{2 -} 2 * LcTap - N * Lhob-N-1 * COS (0cTap-N ^- 0nov-K-1)}] / Gcal-1

AND

0M-N-1 ^- 0HOB-N-1 ^- Sill 1 [(LcTap-N * Sin (0cmap-N ^- 0hob-N-1)) / (Xn-1 * Gcal-1)] ·

Also, in some examples, if 0 _{M. N} .1> 180 °, then

0M-N-1 = 0M-N-1 - 180 °

Xn-i = Xn-i * (-1).

Working step 1867 in FIG. 19 continues with the 1972 procedure for determining potential calibration factors for the second phase branch. In some examples, for each sensor 1 through N, procedure 1972 may involve performing a calculation of X _N-2 and 0 _MN-2 using L _old . _N , old-N, L cal-2, L new-N-2 ^{and 0} new-N-2 ^{, where}

Xn-2 [J {Gstar-Ν T Lhob-N-2 ² - 2 * LcTap-Ν * Lhob-N-2 * COS (0cTap-N - 0HOB-N-2)}] / Gcal-2

0M-N-2 0hob-N-2 ^- Sin 1 [(Lcrap-Ν * Sin (0star-S ^_ 0hob-N-2)) / (Xn-2 * Gcal-2)] ·

Also, in some examples, if 0 _{M. N. 2} > 180 °, then

0M-N-2 = 0M-N-2- 180 °

Xn-2 = Xn-2 * (-1).

Then step 1867 in FIG. 19 includes a 1973 procedure that checks the validity of measurements. In the 1973 procedure, if 0 _{M. N} .1 = 0 _MN-2 within the specified tolerance (for example, 0.1%, 1%, 5%, 10% or 20%) for each sensor from 1 to N, the measurement results for this sensor are saved. If 0 _MN-2 A 0 _MN-2 is within the specified tolerance, the phase angles for this sensor are discarded.

Then step 1867 in FIG. 19 includes a procedure 1974, which determines the statistical mode 0 _mode for 0 _MN-1 for sensors not discarded in procedure 1973. In some examples, the statistical mode is the most frequently repeated phase angle within a given tolerance for the sensors. not discarded on the 1973 procedure.

Working step 1867 in FIG. 19 continues with the 1975 procedure, in which the first part of the calibration coefficients is determined. In some examples, from the remaining sensors in the 1975 procedure, the sensor with the highest value X _{N-1 is} selected and X _N-1 = K _b X _n-2 = K2 AND 0 _M -ni = 0 _mK For the remainder of Procedure 1867, the K sensor may be dropped from the candidate sensor list.

Then step 1867 in FIG. 19 includes a 1976 procedure in which the second portion of the calibration coefficients is determined. In some examples, the sensor with the highest value of X _{n-2 is} selected from the remaining sensors in procedure 1976 and is assigned X _n-2 = Y _b X _n-2 = Y2 and 0 _mn-2 = 0 _m . _{Y In the} following, this selected sensor will be referred to as Y sensor.

Then step 1867 in FIG. 19 includes a 1977 procedure in which one third of the calibration coefficients are determined. In some examples, 0 _{m is} calculated, where

0m = [0m-υ + 0m-k] / 2

The above formulas used to determine the calibration factors are only indicative. In other examples, other formulas (eg, linear, nonlinear, quadratic, and / or iterative equations) may be used to calculate the same or different calibration factors.

For example, a sensor device can calibrate (and determine a predicted current) with a single sensor. In this example, the sensor is placed at a location where the magnetic field from the main power wires 193 and 194 (FIG. 1) is symmetrical about the sensor. That is, the magnetic field from the main power wires 193 and 194 (FIG. 1) is symmetrical about the sensor. In addition, in this example, the sensor Z is located at a location where the magnetic field from the main power electric wire 195 (FIG. 1) representing the neutral return wire is negligible.

Let's call the sensor in this place, where the magnetic fields are symmetrical, the Z sensor.In this example, the current measured in the Z sensor is

L _z ^- Kz * Forecast where L _z is the current measured by the sensor Z, K _z is constant, and L _forecast is the predicted combined current in the first phase branch and the second phase branch.

In this example, the baseline current measurement taken at sensor Z at work _{step 1860 or 1866 can be stored as L z-} b αcU c The first calibration measurements taken at sensor Z can be stored as L _z-cal , and the current from the first known calibration load can be ΔΡ. In this example, K _z can be calculated, where

Kz ^- (Lz-cal Lz-basis) / ΔΡ

In other examples, other calibration equations may be used that require more than two calibration measurements. In these examples, work steps 1861-1866 (FIG. 18) may be repeated as many times as required for different calibration loads to obtain the desired number of calibration points.

Upon completion of the 1977 procedure, work step 1867 is also completed, the calibrations of which calculate the calibration factors.

Returning again to FIG. 18, method 1800 in FIG. 18 continues with step 1868 in which the calibration coefficients are stored. In some examples, calibration coefficients may be stored in memory 226 of computing unit 120 in FIG. 1 and 2. In the same or different examples, the calibration coefficients may be stored in the memory of the sensor device 110 and / or the calibration device 180 in FIG. 1. In still other embodiments, the implementation of the calibration coefficients can be transmitted to a remote server for storage and use. After work step 1868, method 1800 is completed

FIG. 20 illustrates a flow diagram for an embodiment of a method 2000 for determining predicted current in electrical power wires. Method 2000 is purely exemplary and not limited to the embodiments presented herein. Method 2000 can be used in many different embodiments or examples not specifically shown or described herein. In some embodiments, the steps, procedures, and / or processes of method 2000 may be performed in the order presented. In other embodiments, the steps, procedures, and / or processes of method 2000 may be performed in any other suitable order. In still other embodiments, one or more of the work steps, procedures, and / or processes in method 2000 can be combined or skipped.

Method 2000 is a general method for determining predicted electrical energy (and / or electrical current) consumed in electrical power wires. This method includes using several predefined calibration factors (see method 18 in FIG. 18) to determine the predicted current in the power electrical infrastructure of the structure. Spo

- 18 037144 sob, described below, can be used to accurately calculate the calibration coefficients regardless of the position of the sensor device 110 (Fig. 1) on the shield 196 (Fig. 1), except for the following: (a) if the electric current sensors 211 (Fig. 2 ) are located so far from the main power wires 193 and 194 (FIG. 1) that an almost indistinguishable signal from the main power wires is measured, and (b) if all the electric current sensors 211 (FIG. 2) are located too close to the neutral electric power wire 195 (FIG. 1) and away from electrical power wires 193 and 194. In some examples, method 2000 may, in general terms, include a work step that calculates the predicted current L ₁ - _forecast and L ₂ - _forecast (as commonly reported by the electrical system common use, supplying electrical energy) in each branch of the power electrical infrastructure (for example, in the first and second phase branches).

In some examples, method 1800 in FIG. 18 and method 2000 can be combined to provide a method for using a device for measuring energy consumption. Alternatively, method 1800 in FIG. 18, combined with method 2000, can be viewed as a method for determining predicted current (and / or electrical energy) in electrical power wires. In these embodiments, method 1800 may be performed once to determine calibration factors, and method 2000 may be repeated to determine predicted current (and / or electrical energy) consumed by the structure load at different times.

Referring to FIG. 20. Method 2000 includes step 2061 in which a first series of measurements is performed using a first electric current sensor. In various embodiments, one of the electric current sensors 211 (FIG. 2) may be used to perform the first series of measurements. In some examples, step 2061 may include a procedure that measures the amplitude and phase angle at the K sensor. The amplitude reading may be stored as L _K and the phase angle reading as 0K.

In some examples, operation 2061 also includes a routine that determines the amplitude and phase angle of the voltage. The phase angle of the voltage can be used to help calculate the phase angle of the current. In some examples, voltage sensor 228 of FIG. 1 may be used to determine the phase angle of the voltage. 2.

Then, the method 2000 in FIG. 20 includes step 2062 in which a first series of measurements is performed using a first electric current sensor. In various embodiments, one of the electric current sensors 211 (FIG. 2) may be used to perform the first series of measurements. In some examples, step 2063 may include a procedure that measures the amplitude and phase angle at the Y sensor. The amplitude reading may be stored as L _Y and the phase angle reading as 0Y.

In some examples, operation 2062 also includes a routine that determines the amplitude and phase angle of the voltage. As already noted, the phase angle of the current is equal to the phase angle measured by the sensor, minus the phase angle of the voltage. In some examples, voltage sensor 228 of FIG. 1 may be used to determine the phase angle of the voltage. 2.

Then, the method 2000 in FIG. 20 includes an operation step 2063, in which the predicted electrical energy consumed in the first phase branch is determined. In some examples, operation 2063 may include a procedure that determines the amplitude L _{1 of the} first phase branch and the phase angle of 01, the first phase branch using the calibration factors 0M, K1, K ₂ , Y1, and Y ₂ , where

Li = [^ {(L _K / K ₂ ) ² + (LY / Y2) ² - 2 * (Lk / K2) * (L _y / Y ₂ ) * Cos (0k - 0γ)}] / [(Κ1 / Κ2) (Υι / Υ ₂ )] and

0ι = Tg · ¹ [{(L _K / K ₂ ) * Sin (0K - 0m) - (L _Y / Y ₂ ) * Sin (0Y - 0m)} / {(L _k / K ₂ ) * Cos (0k - 0m) (L _y / Y ₂ ) * Cos (0y - 0m)}]

In some examples, the predicted energy P1. _pr about _G but _z in the first phase branch may be electrical energy in the first phase branch, which is usually communicated by the public electrical system. In some embodiments, the predicted current L ₁ . first phase branch _prediction

Prediction Pl = V * Li * Cos (0i) where V is the voltage measured at work step 2062.

Method 2000 in FIG. 20 continues with operation 2064, which determines the predicted electrical energy consumed in the second phase branch. In some examples, operation 2064 may include a procedure that determines the amplitude L _{2 of the} second phase branch and the phase angle 0 _{2 of the} second phase branch using the calibration coefficients 0M, K1, K ₂ , Y1, and Y ₂ , where

- 19 037144

L ₂ = [V {(L _K / KO ² + (LY / Y1) ² - 2 * (LK / Ki) * (Ly / Yi) * Cos (0k - 0y)}] / [(K ₂ / Ki) (Y2 / Y1)] and

0 ₂ = Tg ' ¹ [{(LK / Ki) * Sin (0 _K - 0m) - (L _Y / Yi) * Sin (0 _Y - 0m)} / {(Lk / Ki) * Cos (0k - 0m ) - (Ly / Yi) * Cos (0y - 0m)}]

In some examples, the predicted electrical energy P _{2 -predicted} in the second phase branch may be electrical energy in the second phase branch, which is usually communicated by the public electrical system. In some embodiments, the predicted current P _{2 is the prediction} , in the second phase branch

Pr-irogno ^ V * L ₂ * Cos (0 ₂ ) where V is the voltage measured at work step 2062.

In the second example, wherein the sensor device uses only one sensor Z, determining the predicted power P _prognosis it is relatively simple. In this example, the Z sensor is placed at a location where the magnetic field from the main power wires 193 and 194 (FIG. 1) is symmetrical about the Z sensor, and the Z sensor is located at a location where the magnetic field from the main power wire 195 ( Fig. 1) is negligible. In this example, the electrical energy measured in the Z sensor can be calculated using the formula

Pprognosis ⁼ B * L _Z / Kz where V is the voltage measured at work step 2062, L _z is the current measured by sensor Z at work step 2061, K _z is a constant (already determined at work step 1867 in FIG. 18).

Method 2000 in FIG. 20 continues with operation 2065 in which the predicted current in the first and second phase branches is used and / or reported. The total predicted electrical energy P _forecast is the sum of the predicted electrical energy in the first phase branch and the predicted electrical energy in the second phase branch

^{P-forecast -} P2-forecast + P1-forecast

In some examples, the electrical energy consumed by the load in the structure (ie, the P _forecast ) may be displayed to the user on the communication device with the user 134 of the computing unit 120 (FIGS. 1 and 2). In other examples, the consumed electrical energy (and / or predicted current) may be reported to a public electrical system supplying electrical energy, or may be communicated to other entities.

In still other embodiments, the predicted current can be used to disaggregate loads based on step and phase angle between the observed current and voltage. Computing unit 120 may determine and set a step change (current increase or decrease) in one or more electrical devices in the structure to indicate its use. Further disaggregation can be done by observing the presence of 120 V and 240 V electrical appliances from the current in each phase branch. In addition to the step changes in the total current, the step changes in each individual phase branch also identify the presence of a different load or appliance (i.e. similar loads installed at different locations in the building). The change in phase angle observed due to the internal reactance of the device allows the identification of reactive loads (i.e. fans, electric motors, microwave ovens, compressors). Predictive reactance is not required - the observed raw phase angles are sufficient as long as they are a priori related to the device. In some examples, the instantaneous change in current consumption in the power electrical infrastructure may reflect the starting characteristic of the device, which may be characteristic of household electrical appliances. This method involves using pattern matching in a known trigger signature library to classify unknown loads. This feature space is much less sensitive to overlapping device categories and is capable of separating many devices with similar loading characteristics. For example, two electric motors with a similar consumption of active and reactive power can show very different starting characteristics and, due to this, become disaggregated. This approach may be acceptable for electrical devices that draw large current loads, or at least draw large currents when starting. Using these work steps, loads in the power electrical infrastructure can be disaggregated.

After work step 2065, method 2000 is complete.

FIG. 21 illustrates an example of a first location of two electric current sensors relative to main power wires 193, 194, and 195 (FIG. 1), in accordance with one embodiment. The location of the two electric current sensors shown in FIG. 21 was used to test the calibration method 1800 in FIG. 18 and the method for determining current 2000 in FIG. 20. Loads connected to main power lines 193, 194 and 195 (FIG. 1) were randomly turned on and off. During these random switching on and off of the loads, the actual current was monitored using the power of the current monitor. After measurements were taken with two electric current sensors, predicted currents were calculated using methods 1800 and 2000 in FIG. 18 and 20 respectively. FIG. 22 illustrates a graph comparing the currents predicted by the methods of FIG. 18 and 20, with measured currents. As shown in FIG. 22, the predicted currents closely reflect the measured currents.

FIG. 23 illustrates an example of a second location of two electric current sensors with respect to main power wires 193, 194, and 195 (FIG. 1), in accordance with one embodiment. The location of the two electric current sensors shown in FIG. 23 was also used to test the calibration method 1800 in FIG. 18 and the method for determining current 2000 in FIG. 20. Loads connected to main power lines 193, 194 and 195 (FIG. 1) were randomly turned on and off. During these random switching on and off of the loads, the actual current was monitored using the current monitor. After measurements were taken with the two electric current sensors, the predicted currents were calculated using methods 1800 and 2000. FIG. 24 illustrates a graph comparing the currents predicted by the methods of FIG. 18 and 20, with measured currents. As shown in FIG. 24, the predicted currents closely reflect the measured currents.

While the invention has been described with reference to specific embodiments, it will be apparent to those skilled in the art that various variations are possible within the spirit and scope of the invention. Accordingly, the disclosure of the embodiments is intended to serve as an illustration of the scope of the invention, and is not intended to limit it. The authors intend that the scope of the invention should be limited only to the extent required by the appended claims. For example, one of ordinary skill in the art will readily understand that steps 1860, 1861, 1862, 1863, 1864, 1865, 1866, 1867, and 1868 in FIG. 18, Procedures 1971, 1972, 1973, 1974, 1975, 1976 and 1977 in FIG. 17 and steps 2061, 2062, 2063, 2064, and 2065 in FIG. 20 may consist of many different operating steps and procedures, and may be performed by many different modules, in many different orders, such that any item in FIG. 1 is subject to change, and that the above discussion of some of these embodiments does not necessarily represent a complete description of all possible embodiments.

All elements claimed in any particular claim are essential to the embodiment claimed in that particular claim. Consequently, the replacement of one or more of the claimed elements is a reconstruction and not a repair. In addition, benefits, other advantages, and solutions to problems are described with respect to specific embodiments. It should be noted, however, that these benefits, advantages, solutions to problems, and any element or elements that may cause or enhance any benefit, advantage or solution, should not be construed as critical, required, or essential features or elements of any or all of the clauses if these benefits, advantages, solutions or elements are not specified in this clause.

In addition, the embodiments and limitations disclosed herein are not publicized under the public domain doctrine unless those embodiments and / or limitations: (1) are not positively expressed in the claims and (2) are or are potentially equivalents of the positively expressed elements and / or limitations in the claims on the theory (doctrine) of equivalents.

Claims (5)

1. A method for calibrating a magnetic field sensor device connected to a first surface of a circuit breaker box located on top of at least part of a building's power electrical infrastructure, wherein the power electrical infrastructure comprises one or more main power supply wires, a first phase branch and a second phase branch, while the magnetic field sensor device contains two or more magnetic field sensors, and the method provides for determining, using the sensor device, the magnetic field of the first amplitude and the first phase angle of the first magnetic field in two or more magnetic field sensors included in the magnetic field sensor device, while the magnetic field sensing device is connected to the first surface of the circuit breaker box; after the first load has been connected to the first phase branch of the power electrical infrastructure, the sensor device determines the magnetic field of the second amplitude and the second phase angle of the second magnetic field in two or more magnetic field sensors included in the magnetic field sensor device, while the sensor the magnetic field device is connected to the first surface of the circuit breaker box, and the first load is connected to the first phase branch; after the first load was disconnected from the first phase branch of the power electrical infrastructure and the second load was connected to the second phase branch of the power electrical infrastructure, determination of the third amplitude magnetic field and the third phase angle of the third magnetic field in two or more magnetic field sensors included in the magnetic field sensor device, wherein the magnetic field sensor device is connected to the first surface of the circuit breaker box, and the second load is connected to the second phase branch; and determining, using a computer processor, one or more calibration coefficients for the magnetic field sensor device using, at least in part, the first amplitude and the first phase angle of the first magnetic field in the two or more magnetic field sensors, the second amplitude and the second phase angle of the second magnetic field in two or more magnetic field sensors and a third amplitude and third phase angle of a third magnetic field in two or more magnetic field sensors, wherein the magnetic field sensor device is not electrically in series or physically directly connected to one or more main power wires in the box the circuit breaker when the magnetic field sensing device is connected to the first surface of the circuit breaker box. 2. The method according to claim 1, further comprising, after the first load has been disconnected from the first phase branch of the power electrical infrastructure and the second load has been disconnected from the second phase branch of the power electrical infrastructure, the sensor device determines the magnetic field of the fourth amplitude and the fourth phase angle of the fourth a magnetic field in two or more magnetic field sensors included in the magnetic field sensor device, the magnetic field sensor device being connected to the first surface of the circuit breaker box; and determining whether the fourth amplitude and the fourth phase angle of the fourth magnetic field in the two or more magnetic field sensors are within a predetermined value of the first amplitude and the first phase angle of the first magnetic field in the two or more magnetic field sensors. 3. The method according to any one of claims 1 or 2, further comprising electrically connecting the first load to the first phase branch of the power electrical infrastructure; electrically disconnecting the first load from the first phase branch of the power electrical infrastructure before the second load is connected to the second phase branch of the power electrical infrastructure; and electrically connecting the second load to the second phase leg of the power electrical infrastructure after the first load is disconnected from the first phase leg of the power electrical infrastructure. 4. The method according to any one of claims 1, 2 or 3, in which the determination by the computer processor of one or more calibration coefficients for the magnetic field sensor device provides for the determination for each of the two or more magnetic field sensors the calibration coefficients of the first branch for the first phase branch ; determining, for each of the two or more magnetic field sensors, calibration coefficients of the second branch for the second phase branch; determining, for each of the two or more magnetic field sensors, a comparison result of at least a portion of the calibration coefficients of the first branch and at least a portion of the calibration coefficients of the second branch; determining a statistical mode for the remaining sensors, each of which is selected from two or more magnetic field sensors, where for each of the remaining sensors the result of comparing at least part of the calibration coefficients of the first branch and at least part of the calibration coefficients of the second branch is within a predetermined tolerance; and determining a first portion of one or more calibration coefficients, a second portion of one or more calibration coefficients, and a third portion of one or more calibration coefficients based at least in part on the calibration coefficients of the first branch and the calibration coefficients of the second branch of the remaining sensors. 5. The method according to any one of claims 1, 2, 3 or 4, in which the magnetic field sensor device further comprises a phase detector electrically connected to the outputs of two or more magnetic field sensors; and the phase detector is configured to determine when the phase angle of the first signal in the first magnetic field sensor of the two or more magnetic field sensors is offset by approximately 180 ° relative to the phase angle of the second signal in the second magnetic field sensor of the two or more magnetic field sensors.