System for monitoring electrical power usage of a structure and method of same

Cross-reference of related applications This application benefits from US Provisional Patent Application No. 61 / 361,296 filed on July 2, 2010 and US Provisional Patent Application No. 61 / 380,174 filed on September 3, 2010. It is an assertion. This application is also a partial continuation of US Patent Application No. 12 / 567,561 filed on September 25, 2009. US Provisional Patent Application Nos. 61 / 361,296 and 61 / 380,174 and US Patent Application No. 12 / 567,561 are incorporated herein by reference.

The present invention relates generally to devices, devices, systems, and methods for monitoring power, and particularly to devices, devices, devices, devices that monitor the power of one or more mains conductors, especially in electrical circuit breaker panels of structures. Regarding the system and method.

A structure (eg, a home or commercial building) may have one or more mains conductors that supply power to an electrical device (ie, load) within the structure. Most structures use a phase-dividing power distribution system with up to three mains conductors. The main power conductor enters the structure through the electrical circuit breaker panel. The electric circuit breaker panel is the main distribution point of power in the structure. Electrical circuit breaker panels also provide protection from overcurrents that can cause a fire or damage electrical devices within the structure. The electrical circuit breaker panel can be connected to and overlap with at least a portion of the three mains conductors.

For example, different manufacturers of electrical circuit breaker panels, including Square-D, Eaton, Cutler-Hammer, General Electric, Siemens, and Murray, have chosen different conductor spacing and configurations for their respective electrical circuit breaker panels. In addition, manufacturers have many different configurations of electrical circuit breaker panels for indoor and outdoor installations, with different total amperage ratings (of which 100 amps (A) and 200 amps are most common). Manufacture.

<p num="0005"><patcit num="1"><text>Japanese Unexamined Patent Publication No. 2007-107972</text></patcit><patcit num="2"><text>Japanese Unexamined Patent Publication No. 2001-103622</text></patcit><patcit num="3"><text>Japanese Unexamined Patent Publication No. 10-153625</text></patcit><patcit num="4"><text>Japanese Unexamined Patent Publication No. 11-101831</text></patcit><patcit num="5"><text>Japanese Unexamined Patent Publication No. 2008-196950</text></patcit><patcit num="6"><text>Japanese Patent Application Laid-Open No. 2005-147755</text></patcit></p>

<p num="0006"> Different conductor layouts in many different types of electrical circuit breaker panels result in different magnetic field profiles on the metal surface of the electrical circuit breaker panels. Furthermore, it is precisely understood that the layout of the inner conductor (eg, the mains conductor) is invisible without opening the breaker panel, and that the inner conductor layout is transformed into a magnetic field profile on the surface of the electrical circuit breaker panel. And in order to model, detailed knowledge of electromagnetic theory is required. Therefore, it is difficult to accurately measure the magnetic field of one or more main power conductors on the surface of an electric circuit breaker panel. If the magnetic field of one or more mains conductors can be accurately determined on the surface of the electrical circuit breaker panel, the current and power used by the load in the structure can be determined.</p><p num="0007"> Thus, devices, systems, and / or devices that allow non-electricians to accurately determine the magnetic field and other parameters associated with one or more mains conductors on the surface of an electrical circuit breaker panel. There is a need or potential for benefit to the method.</p>

<p num="0008"> Some embodiments may relate to a method of using a power consumption measuring device. The power consumption measuring device can be mechanically connected to the surface of a circuit breaker box that overlaps at least a portion of one or more main feed conductors of the structure's power infrastructure. This method uses one or more sensors of a power measurement device to determine one or more first magnetic field readings from one or more main feed conductors and one or more. After determining the first magnetic field power of the power consumption measuring device, with the step of electrically connecting the first calibration load to the power infrastructure and the state of electrically connecting the first calibration load to the power infrastructure. The step of determining one or more second magnetic field powers from one or more main feed conductors using one or more sensors and at least partly one or more first magnetic fields. The step of calibrating the power measurement device with the power and one or more second magnetic field powers, and after calibrating the power measurement device, with one or more sensors in the power measurement device. Using the step of determining one or more third magnetic field powers from one or more main feed conductors, and at least one or more third magnetic field powers and one or more calibration coefficients. It may include the step of determining the power used by the power infrastructure of the structure. Calibration of the power measuring device is performed by using at least one or more first magnetic field readings and one or more second magnetic field readings of the power measuring device. It may include the determination of a calibration factor of 1.</p><p num="0009"> Other embodiments may relate to methods of calibrating magnetic field sensor devices. The magnetic field sensor device is connected to the first surface of the circuit breaker box. The circuit breaker box overlaps the power infrastructure of the building. The power infrastructure has a first phase branch and a second phase branch. The magnetic field sensor device may include two or more magnetic field sensors. This method involves determining the first amplitude and first phase angle of the first magnetic field in two or more magnetic field sensors in a magnetic field sensor device, and the first load is the first phase branch of the power infrastructure. The second of the second magnetic field in the two or more magnetic field sensors of the magnetic field sensor device while receiving the communication to be connected to and while the first load is connected to the first phase branch. The step of determining the amplitude and the second phase angle of the, the step of receiving the communication that the second load is connected to the second phase branch of the power infrastructure, and the step that the second load is the first phase branch. In the two or more magnetic field sensors of the magnetic field sensor device, while connected to, the step of determining the third amplitude and the third phase angle of the third magnetic field, and at least in part, two or more. The first amplitude and first phase angle of the first magnetic field in the magnetic field sensor, the second amplitude and second phase angle of the second magnetic field in the two or more magnetic field sensors, and the two or more magnetic field sensors. It may include the step of determining one or more calibration coefficients of the magnetic field sensor device using the third amplitude and the third phase angle of the third magnetic field in.</p><p num="0010"> A further embodiment may relate to a system for monitoring power usage in a building's power infrastructure. The building includes circuit breaker boxes and power supply conductors for the building's power infrastructure. This system is (a) a power consumption measuring device configured to be connected to the first surface of a circuit breaker box. The circuit breaker box overlaps at least a part of the power supply conductor of the power infrastructure and is configured to be electrically connected to (b) the power infrastructure with a power measurement device having one or more magnetic field sensors. One calibration device, the first calibration module containing one or more first calibration loads, and (c) one of the power measurement devices configured to boot on the first processor. It may include a calibration module configured to at least partially calibrate the power measurement device using data obtained from one or more magnetic field sensors. With at least one of the first calibration loads electrically connected to the power infrastructure and the power measuring device connected to the first surface of the circuit breaker box, the power measuring device is , Can be configured to obtain at least a portion of the data.</p><p num="0011"> In a further embodiment, the magnetic field detection device is electrically coupled to (a) at least two magnetic field sensors configured to detect the magnetic field in a conducting conductor and (b) the outputs of at least two magnetic field sensors. It may include a phase detector 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 place relative to the energizing conductor.</p><p num="0012"> The following drawings are provided to facilitate further description of the embodiments.</p>

<figref num="1">The figure of the power monitoring system example connected to the electric breaker panel by 1st Embodiment is shown.</figref><figref num="2">The block diagram of the power monitoring system of FIG. 1 according to the first embodiment is shown.</figref><figref num="3">It is sectional drawing of the circuit breaker panel of FIG. 1 along the conductor 3-3 according to 1st Embodiment.</figref><figref num="4">An example of a magnetic field conductor generated by a conductor is shown.</figref><figref num="5">An example of a magnetic field conductor generated by the main power conductor of the circuit breaker of FIG. 1 according to the first embodiment is shown.</figref><figref num="6">An example of the detection device of FIG. 2 according to the first embodiment is shown.</figref><figref num="7">An example of arranging the detection device of FIG. 2 on the main power conductor of the circuit breaker of FIG. 1 according to the first embodiment is shown.</figref><figref num="8">A graph example of the voltage vs. time of the current sensor according to one embodiment is shown.</figref><figref num="9">An example of the detection device according to the second embodiment is shown.</figref><figref num="10">An example of the detection device of FIG. 9 on the main power conductor of the circuit breaker of FIG. 1 according to the second embodiment is shown.</figref><figref num="11">An example of the calibration device of FIG. 1 according to the first embodiment is shown.</figref><figref num="12">A graph example of possible incoming low voltage signals from the level converter of FIG. 11 to the controller of FIG. 11 according to one embodiment is shown.</figref><figref num="13">A graph example showing the relationship between the square wave low voltage signal used to create the phase reference and the low voltage signal of FIG. 12 according to one embodiment is shown.</figref><figref num="14">An example of the switched load according to the third embodiment is shown.</figref><figref num="15">An example of the switched load according to the fourth embodiment is shown.</figref><figref num="16">An example of the switched load according to the fifth embodiment is shown.</figref><figref num="17">An example of the switched load according to the sixth embodiment is shown.</figref><figref num="18">The flowchart of the calibration method of the electric monitoring system according to one Embodiment is shown.</figref><figref num="19">A flowchart of a work for determining a calibration coefficient according to an embodiment is shown.</figref><figref num="20">A flowchart of a method for determining a predicted current of a main power conductor according to an embodiment is shown.</figref><figref num="21">An example of the first position of the two current sensors with respect to the main power conductor in the detection device example according to one embodiment is shown.</figref><figref num="22">The comparison graph of the predicted current with respect to the measured current of the current sensor of FIG. 21 is shown.</figref><figref num="23">An example of the second position of the two current sensors with respect to the main power conductor in the detection device example according to one embodiment is shown.</figref><figref num="24">The comparison graph of the predicted current with respect to the measured current of the current sensor of FIG. 23 is shown.</figref>

For the sake of simplicity and clarity, the drawings show general structural modalities, where well-known features and technical descriptions and details are omitted to avoid unnecessarily obscuring the invention. There is. Moreover, the elements of the drawing are not always drawn to a constant scale. For example, some dimensions of elements in the drawings may be exaggerated compared to other elements to enhance understanding of embodiments of the present invention. The same reference numerals in different drawings indicate the same elements.

Terms such as "first," "second," "third," and "fourth" in the specification and claims are used to distinguish similar elements when used. It is not necessarily intended to represent a particular sequential or temporal order. The terms used in this way are compatible under appropriate circumstances such that the embodiments described herein can operate in an order other than those shown or described herein, for example. Please note that. In addition, the terms "include" and "have" and their variants are not necessarily limited to those elements in the process, method, system, article, device, or device that wraps the element list. Intended to cover non-exclusive inclusions that are not explicitly listed or may include other elements that are not unique to such processes, methods, systems, articles, devices, or devices. ..

"Left", "Right", "Front", "Back", "Top", "Bottom", "Top" in the specification and claims Terms such as "over" and "under", when used, are used for explanatory purposes and are not necessarily meant to represent a permanent relative position. The terms used in this way are used in appropriate circumstances such that the embodiments of the invention described herein can operate in other orientations other than those shown or described herein, for example. Please note that they are compatible.

Terms such as "couple," "coupled," "couples," and "coupling" are broadly interpreted to electrify two or more elements or signals. It shall mean connecting in an objective, mechanical and / or other way. Two or more electrical elements are electrically connected but may not be mechanically or otherwise connected, and two or more mechanical elements are mechanically connected but electrically or otherwise. It may not be connected by the method, and the two or more electrical elements may be mechanically connected but not electrically or otherwise connected. The connection may be of any length of time, eg, permanent or semi-permanent, or only for a moment.

"Electrical connection" and the like are broadly interpreted and shall include connections involved in any electrical signal, such as power signals, data signals, and / or other types or combinations of electrical signals. "Mechanical connection" and the like are broadly interpreted and shall include all types of mechanical connection.

The concatenation of the problem can be removed even if there are no words such as "removably" and "removable" near words such as "concatenated". Or it does not mean that it is not removable.

FIG. 1 shows a diagram of an exemplary power monitoring system 100 coupled to a circuit breaker panel 190 according to a first embodiment. FIG. 2 shows a block diagram of the power monitoring system 100 according to the first embodiment. FIG. 3 shows a cross-sectional view of the circuit breaker panel 190 along conductors 3-3 according to the first embodiment.

The power monitoring system 100 can also be thought of as a system for monitoring the power usage status of a structure (that is, a building). The power monitoring system 100 can also be thought of as a device and system for determining the predicted current used by one or more electrical devices (ie, loads) in a structure. The power monitoring system 100 is merely exemplary and is not limited to the embodiments presented herein. The power monitoring system 100 can be used in many different embodiments or examples not specifically described or described herein.

In some embodiments, the power monitoring system 100 comprises (a) at least one detection device 110 (ie, power consumption measuring device), (b) at least one arithmetic unit 120, and (c) at least one calibration device. Can include 180.

In some embodiments, the system 100 can be used on breaker panels from different manufacturers and on different types of breaker panels from the same manufacturer. In addition, in some embodiments, System 100 makes it easy for an untrained person (ie, a non-electrician) to open the breaker panel box and expose the internal non-insulated power conductors. Can be installed.

As also shown in FIG. 1, a conventional breaker box or circuit breaker panel 190 has (a) two or more separate circuit breakers 191, (b) two, or a main circuit breaker 192, (c) an outer surface. It may include a panel 196 equipped and (d) a door 197 that provides access to circuit breakers 191 and 192. At least some of the main power conductors 193, 194, and 195 can be placed inside the circuit breaker panel 190. "Circuit breaker panel" means a fuse box that is still common in buildings with older electrical systems and may include it. The power infrastructure of the structure may include at least the circuit breaker panel 190 and the main power conductors 193, 194, and 195. In some embodiments, the circuit breaker panel can also mean any kind of power distribution panel used to supply electricity to a structure.

The main power conductors 193, 194, and 195 are electrically connected to the main circuit breaker 192 to power an electrical device (ie, a load) in the structure. To prevent human inadvertent contact with these energized power conductors, the panel 196 overlaps at least some of the main power conductors 193, 194, and 195 and related circuit components. Panel 196 is usually made of steel or another metal.

The door 197 covers the circuit breakers 191 and 192 and is normally closed for aesthetic reasons, but can be opened to allow access to the levers of the circuit breakers 191 and 192 within the circuit breaker panel 190. As shown in FIG. 3, when the door 197 is closed, the panel area 398 may have a panel area depth 399. The panel area depth 399 is typically 13 mm (mm) to 20 mm so that the door 197 can be closed without hitting the circuit breaker lever 189. The depth of the panel area depth 399 limits the allowable thickness of the detection device 110 attached to the panel area 398. That is, in various embodiments, the detection device 110 may fit within the panel area depth 399 so that the detection device 110 can keep the breaker panel door closed during operation. In many embodiments, the detection device 110 has a depth of less than 20 mm. In the same or different embodiments, the detection device 110 may have a depth of less than 13 mm.

Residential and small commercial electrical installations are typically 240 volt phase splitting equipment. It is a neutral conductor that allows two 120V alternating current (AC) source conductors that are 180 degrees out of phase (eg, power conductors 193 and 194) to return current from either power conductor 193 or 194. Refers to utilities provided with (eg, power conductor 195). Power conductors 193, 194, and 195 are "feed" or "main" power conductors that carry incoming power from the utility before being split into branch circuits for different loads. By detecting the magnetic fields generated by the power conductors 193, 194, and 195, the system 100 is a utility because all loads in the structure are connected in parallel with the power conductors 193, 194, and / or 195. The total current drawn by all loads from can be detected.

In the United States, many different types of electrical loads can be found in buildings supplied with 240V phase separation utility equipment. Electrical loads can be divided into two categories: (a) 120V load and (b) 240V load.

The 120V load is primarily a low wattage load, that is, a standard 3-pole 120V load plugged into a 15A or 120V 20A outlet, and a small appliance that draws less than about 2kW (kilowatt) of power. May include. These loads can be a pair of power conductors 193 and 195 (first phase branch or parts 193-195 of the wiring circuit) or a pair of power conductors 194 and 195 (second phase branch or wiring. Wired in individual circuits between "194-195 parts") of the circuit. When wiring the structure, the electrician attempts to balance the expected wattage of the load and outlet in each part, but since different total wattages are usually drawn from each pair, parts 193-195. And this is not an accurate process as the currents in the 194-195 section are prone to imbalance. When a 120V load is turned on, its current flows from the utility through the main and circuit level circuit breakers through power conductors 193 or 194 to the load and then back to power conductor 195 for the utility. Flow back to.

A 240V load is typically a large appliance that consumes more than 2kW (kilowatt) (eg, an electric dryer, stove, air conditioner compressor, electric baseboard heater). In this case, the load current flows between the power conductors 193 and 194, and the load current does not flow in the power conductor 195. Due to the 180 degree phase relationship between the voltages on the power conductors 193 and 194, the total voltage is 240V.

With reference to FIGS. 1 and 2 again, the arithmetic unit 120 includes (a) communication module 221, (b) processing module 222, (c) power supply 223 with electrical connector 128, and (d) user communication device 134, It may include (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.

The arithmetic unit 120 receives an output signal from the calibration device 180 and / or the detection device 110 via the communication module 221 and uses one or more parameters related to the power usage of the structure (eg, used by the structure). It can be configured to process the output signal to determine the power to be and the currents of the mains conductors 193, 194, and 195). In some embodiments, the arithmetic unit 120 may be a personal computer (PC).

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

The processing module 222 uses current measurements from the detection device 110 to determine one or more parameters related to the power usage of the structure (eg, current and power of mains conductors 193, 194, and 195). It may be configured to determine. As described below, the calibration calculation module 229 is configured to calibrate the power monitoring system 100 (eg, calculate the calibration coefficient for the detection device 110) using the current measurements from the detection device 110. You may.

In some embodiments, the processing module 222 and the calibration calculation module 229 may be stored in memory 226 or configured to be invoked by controller 225. While the arithmetic unit 120 is booting, the controller 225 executes program instructions (eg, processing module 222 and / or calibration calculation module 229) stored in memory 226. Some of the program instructions stored in memory 226 may be suitable for implementing methods 1800 and 2000 (FIGS. 18 and 20, respectively) as described below.

The calibration load module 227 may include one or more calibration loads. As described below, one or more calibration loads can aid in the calibration of the power monitoring system 100, for example by being temporarily electrically coupled to the first phase branch of the power infrastructure of the structure. Can be done.

In some embodiments, the user communication device 134 and the control mechanism 132 may be separable from other parts of the arithmetic unit 120 and may wirelessly communicate with other parts of the arithmetic unit 120.

By using the voltage sensor 228, it is possible to determine the amplitude and phase angle of the voltage across the power infrastructure. The overall current phase angle is equal to the phase angle measured by the current sensor 211 minus the voltage phase angle measured by the voltage sensor 228. That is, the phase angle of the current can be calculated in relation to the intersection of the zeros of the voltage.

In some embodiments, the detection device 110 can calculate the phase angle of the current by being able to transmit the current measurement value obtained by the current sensor 211 to the arithmetic unit 120. In another embodiment, the arithmetic device 120 can calculate the phase angle of the current by being able to transmit the voltage measurement by the voltage sensor 228 to the detection device 110. In another embodiment, the voltage sensor 228 may be located within the calibration device 180.

The power supply 223 can supply power to the communication module 221, the processing module 222, the user communication device 134, the controller 225, the memory 226, the calibration load module 227, and / or the control mechanism 132. In some embodiments, the power source 223 can be connected to an electrical connector 128 that can be connected to a wall electrical outlet in the power infrastructure.

The user communication device 134 can be configured to display information to the user. In some embodiments, the user 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, at least in part, one or more buttons configured to control the arithmetic unit 120 or at least the user communication device 134. In some embodiments, the control mechanism 132 may include a power switch (ie, an on / off switch) and / or a display switch configured to control a display on the user communication device 134.

Further referring to FIGS. 1 and 2, the detection device 110 may include (a) two or more or magnetic field sensors or current sensors 211, (b) controller 213, (c) user communication module 214, (d) communication module. 215, (e) power supply 216, and (f) coupling mechanism 219 may be included. The controller 213 can be used to control the current sensor 211, the user communication module 214, the communication module 215, and the power supply 216.

The current sensor 211 may include an inductive pickup, a Hall effect sensor, a magnetic resistance sensor, or any other type of sensor configured to respond to a time-varying magnetic field generated by a conductor in the circuit breaker panel 190.

In various embodiments, the detection device 110 can be configured to be coupled to the surface of the panel 196 using a coupling mechanism 219. In some embodiments, the coupling mechanism 219 may include an adhesive, a Velcro® material, a magnet, or another attachment mechanism.

The communication module 215 can be electrically connected to the current sensor 211 and the controller 213. In some embodiments, the communication module 215 transmits the voltage or other parameters measured using the current sensor 211 to the communication module 211 of the arithmetic unit 120. In many embodiments, the communication module 215 and the communication module 221 may be wireless transmitters and receivers. In some embodiments, electrical signals are transmitted using WI-FI (Wireless Fidelity), IEEE (Institute of Electrical and Electronics Engineers) 802.11 wireless protocol or Bluetooth® 3.0 + HS (High Speed) wireless protocol. can do. In a further embodiment, these signals can be transmitted via Zigbee® (IEEE 802.15.4 Wireless Protocol), Z-Wave, or proprietary wireless standards. In another embodiment, the communication module 215 and the communication module 221 can communicate electrical signals using a cellular system or a wired connection.

The user communication module 214 can be configured to display information to the user. In one embodiment, the user communication module 214 may be an LCD (Liquid Crystal Display) and / or one or more LEDs (Light Emitting Diodes).

The controller 213 can be configured to control the current sensor 211, the communication module 215, the user communication module 214, and / or the power supply 216.

The calibration device 180 may include (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 embodiments, the communication module 281 may be similar or the same as the communication modules 215 and / or 221. The electrical connector 282 may be a power plug in some embodiments. The user communication device 184 can be configured to display information to the user. In some embodiments, the user communication device 184 may be one or more LEDs.

According to Ampere's law, a magnetic field is generated by an energizing conductor, as shown in FIG. That is, the magnetic field generated by a conductor is a three-dimensional vector field that can be decomposed into each component of the X, Y, and Z axes. In an alternating current system, these magnetic fields vary in magnitude over time but maintain the same vector angle with respect to the coordinate base. Thus, for example with respect to the X-axis, the field can point in the + X or -X direction at any moment, as the AC current reverses direction at a line frequency of, for example, 60 Hz. The magnetic field component in the X direction may point to either + X or -X, depending on the direction of the current flow at a particular moment.

The lines of magnetic force follow Ampere's Law, "Right-Hand Rule," and when the thumb of a person's right hand is aligned with the direction of the current flow of the conductor, the lines of magnetic force wrap around the conductor in the direction of the human finger and perpendicular to the conductor.

Some embodiments primarily relate to magnetic field components (along the "Z" axis) oriented perpendicular to the plane of the circuit breaker panel, because they are magnetic fields outside the metal cover of the circuit breaker panel 190. This is because it is a magnetic field component that can be easily detected by a sensor (that is, the detection device 110).

As shown in FIG. 5, the power conductors 193 and 194 have a phase difference of 180 degrees, so that the direction of the magnetic field line loop is opposite at any time point.

Therefore, according to Kirchhoff's Law of Current, the total current through a feed conductor (ie, power conductors 193, 194, and / or 195) is the sum of all load currents drawn from that conductor. Therefore, the magnitude of the magnetic field generated by each conductor (ie, power conductor 193, 194, or 195) is directly proportional to the sum of the currents drawn on all the branch circuits connected to that conductor. The direction of the lines of magnetic force from a conductor does not change in response to the branching current.

System 100 has three possible load cases: (a) 120V load between 193-195 parts, (b) 120V load between 194-195 parts, and (c) 240V load between 193-194 parts. Can be configured to detect at least the magnetic fields generated by the power conductors 193 and 194. In most cases, any current drawn through the power conductor 195 is sourced from either the power conductor 193 or 194, so there is no need to detect the magnetic field generated by the power conductor 195 (ie, the neutral conductor).

FIG. 6 shows an example of the current sensor 211 according to the first embodiment. In these examples, the current sensors are (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) It may include one or more phase detectors 651, (e) at least one differential amplifier 652, and (f) at least one digitizer 653.

In some embodiments, the system 100 can be configured to assist the user with respect to the proper placement of the detection device 110 by showing the proper placement with the user communication module 214. In some embodiments, system 100 determines the proper placement by detecting a phase difference of approximately 180 degrees between sensors 641 and 642 placed on either side of the conductor (ie, power conductor 193 or 194). be able to. In the same or different embodiments, the user communication module 214 may be co-located with the detection device 110, or the user communication module 214 may be used and remotely coupled to the detection device 100 on a wireless network. May be good.

The sensor 641 may include (a) a ferromagnetic core 643 and (b) a detection coil 644 that encloses the ferromagnetic core 643. The sensor 642 may include (a) a ferromagnetic core 645 and (b) a detection coil 646 that encloses the ferromagnetic core 645. In various embodiments, the sensors 641 and 642 may be 2.5 mm (mm) to 12.7 mm in diameter. In another embodiment, the current sensor 211 includes only the sensor 641 and does not include the sensor 642, the amplifier 647, the filter 649, the phase detector 651, and / or the differential amplifier 652. In this alternative embodiment, the filter 649 or 650 is coupled to the digitizer 653. In a further embodiment, the current sensor 211 includes 4, 6, 8, or 10 sensors.

The purpose of the ferromagnetic cores 643 and 645 is to produce a larger sensor output voltage at the output ends of the detection coils 644 and 646 by concentrating the magnetic fields from the detection coils 644 and 646. The voltage at the output of the detection coils 644 and 646 is obtained by Faraday's law. That is, the voltage is determined by the applied AC magnetic field, the physical dimensions of the coil and wire, the number of wire turns in the coil, and the magnetic permeability of the core. In another embodiment, sensors 641 and 642 do not include ferromagnetic cores 643 and 645, respectively.

As shown in FIG. 7, when the current sensor 211 is connected to the circuit breaker panel 190, one of the sensors 641 and 642 can be placed on one side of the conductor (ie, the power conductor 193 or 194). In this embodiment, the induced voltage of the sensor 641 is 180 degrees out of phase with the sensor 642 because the magnetic field enters the sensor 642 from the bottom while the magnetic field enters the sensor 641 from the top. ..

A plot of the phase relationship between the voltages of sensors 641 and 642 is shown in Figure 8. With reference to FIG. 8, when an AC current flows through a conductor (ie, power conductor 193 or 194), a voltage V (sensor) is induced in the detection coils 644 and 646. This voltage V (sensor) is proportional to the current I (sensor) carried by the conductor (ie the power conductor 193 or 194), i.e. V (sensor) = k * I (sensor). The proportionality constant k temporarily connects the calibration load (ie the calibration load module 283 or 227 (FIG. 2)) to the circuit supplied by the conductor (ie the power conductor 193 or 194) and the sensors 641 and 642 (FIG. 6). It can be found by drawing a known current through a conductor by measuring the voltage induced in. In some cases, two or more known currents can be drawn to establish a multipoint calibration of the constant of proportionality.

Seeing FIG. 6 again, this configuration of the two sensors (ie, sensors 641 and 642) is used against a given current-carrying conductor while rejecting interference from other sources, including other conductors in the vicinity. You can get a detection device 110 that automatically tells the user that it has been placed correctly. This capability is useful in the electrically noisy environment found in circuit breaker panels where many conductors are present near a particular conductor of interest.

Specifically, in one embodiment, the outputs of sensors 641 and 642, respectively, can be amplified using amplifiers 648 and 647, respectively, and then filtered using filters 650 and 649, respectively. The output of filters 650 and 649 may be presented to phase detector 651 coupled to phase indicator 619 in user communication module 214 (eg, one or more LEDs). The user communication module 214 is configured to indicate to the user that the sensors 641 and 642 are correctly placed with respect to a given current conductor. The user may be instructed to move the sensor within a range where the mains conductor can be found and stop moving when the phase indicator indicates that the phase difference between the signals of sensors 641 and 642 is about 180 degrees. For example, if the signals from sensors 641 and 642 are out of phase by about 180 degrees, a green LED may light up at the top of the detection device 110.

Amplifiers 648 and 647 and filters 650 and 649 are optional in some embodiments. The purpose of the amplifiers 648 and 647 and the filters 650 and 649 is to raise the signal level while rejecting noise of unwanted frequencies, and thus in a noisy environment, the signal-to-noise of the sensors 641 and 642 signals. To increase the ratio. The amplifiers 648 and 647 may be operational amplifiers such as the TL082 type manufactured by Texas Instruments, Inc. Filters 650 and 649 may be centralized element passive filters or active filters performed with operational amplifiers. Generally, filters 650 and 649 are bandpass filters configured to pass AC line frequencies (eg 60Hz in the United States and Canada, or 50Hz in Europe and Japan) while rejecting out-of-band noise. ..

The phase detector 651 may be either an analog phase detector circuit or a digital phase detector. Execution of the digital phase detector can be performed using combinatorial logic, programmable logic, or in controller software. In certain embodiments, an integrated phase detector circuit, such as a phase detector included in a 4046 or 74HC 4046 type phase lock loop integrated controller manufactured by Texas Instruments, Inc., can be used. In another embodiment, the execution of phase detector 651 is performed by digitizing the sensor signal with an analog-to-digital converter and then adapting the inverse trigonometric function to the sample vectors received from sensors 641 and 642. It is said. In a further embodiment, the filtering and phase detector functions are in a periodogram such as a complex Fast Fourier Transform (FFT) algorithm that finds the signal magnitude and phase angle only at the AC line frequency while rejecting noise at other frequencies. Combined by using the based most probable estimate.

The phase indicator 619 can be any device that indicates to the user that the desired phase relationship between the input signals of 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 graphical or numerical display such as a liquid crystal display (LCD), or an audio tone that indicates to the user that the voltages of the sensors 641 and 642 are out of phase by approximately 180 degrees.

Once the correct phase relationship is established, the differential amplifier 652 can be used to combine the signals from sensors 641 and 642 to produce a voltage or current signal proportional to the current of the mains conductor. This signal can be used as an input for calculations performed by controller 213. In the same or different embodiments, the communication module 215 is used to (a) properly position the sensors 641 and 642 as indicated by the phase relationship of the sensors, and (b) data including differential detection signals from the sensors 641 and 642. It can be transmitted to the arithmetic unit.

Next, moving to another embodiment, FIG. 9 shows an example of the detection device 910 according to the second embodiment. FIG. 10 shows an example of the detection device 910 on the power conductors 193 and 194 according to the second embodiment. In this example, sensor 941 where N is a number from 2 to 10.₁、941₂、・・・、941_NYou can use a linear array of. In other embodiments, N may be another number such as 4, 6, 8, 20, 50, or 100. One of the purposes of this linear array of sensors is that controller 213 does sensor 941 so that the user does not have to manually place the detection device 910 in the correct position.₁、941₂、・・・、941_NTo be able to automatically select one or more pairs of. In some embodiments, the detection device 910 can be used in place of the detection device 110 in system 100 of FIG.

With reference to FIGS. 9 and 10, in this embodiment, the detection device 910 is (a) sensor 941.₁、941₂、・・・、941_N, (B) Amplifiers 647 and 648, (c) Filters 649 and 650, (d) Phase Detector 651, (e) Differential Amplifier 652, (f) Digitizer 653, and (g) At least one multiplexer 955 and 956. May include.

Sensor 941 as shown in Figure 10.₁、941₂、・・・、941_NA linear array of sensors 941 at least one sensor used as a magnetic field sensor to generate a signal proportional to the current of the mains conductors 193 and / or 194.₁、941₂、・・・、941_NConnected to multiplexers 955 and 956 to choose from.

In another embodiment, two or more conductors of power conductors 193 and 194 are simultaneously detected by the detection device 910. In this embodiment, sensor 941₁、941₂、・・・、941_NController 213 controls multiplexers 955 and 956 so that two separate sensors adjacent to two different energizing power conductors 193 and 194 are selected from. In this embodiment, the controller 213 controls the multiplexer to select the sensor based on the amplitude or phase angle of the sensor signal. In some embodiments, sensor 941₁、941₂、・・・、941_NMultiple sensors from are multiplexed under the control of controller 213 to select separate sensors, each with a selective magnetic field connection to a different energizing conductor.

With reference to FIG. 1 again, the system 100 can use calibration in some embodiments to achieve accurate current measurements in power conductors 193 and 194. The potential need for calibration can be, for example, due to poorly controlled installation geometries when the detection device 110 or 910 (FIG. 9) is installed by an untrained user.

FIG. 11 shows an example of the calibration device 180 according to the first embodiment. The calibration device 180 switches a single calibration load to a single lead-in conductor (ie, power conductor 193 or 194) to provide one lead-in conductor, a single calibration load, and a neutral or return conductor (ie, power). It is shown in FIG. 11 as a single circuit calibration device configured to complete the circuit between conductors 195). The switching signal is used to temporarily complete the circuit with the calibration load used by calibration method 1800 in FIG.

In some embodiments, the calibration load module 283 comprises (a) a switched load 1105, (b) a transformer 1171, (c) a filter 1172, (d) a level transducer 1173, and (e) a square ring device 1174. May include. The switched load 1105 may include (a) switch 1187 and (b) calibration load 1188. The controller 285 may include (a) an analog-to-digital converter 1177, (b) a digital input 1176, and (c) a temperature sensor 1186.

In the embodiment of FIG. 11, the calibration load module 283 can be designed by the detection device 110 to calibrate the measurements of a single conducting conductor (feed line to the branch circuit) being measured. In this embodiment, a single calibration load 1188 switches between line conductors (eg, mains conductors 193 and 194) and neutral conductors (eg, mains conductors 195) under the control of the switching signal of controller 285. Is performed by switch 1187. In the United States, the switched load 1105 can be used with a 120V outlet. In other countries, the switched load 1105 can be used with 240V and other voltage outlets.

The calibration load 1188 and the other calibration loads of FIGS. 14-17 are depicted as registers, while the calibration load 1188 and the other calibration loads of FIGS. 14-17 are inductors or with or without resistance components. It should be understood that any load, including an ineffective load such as a capacitor, may be used. In addition, the calibration load may be a load with a variable resistor. Further, although the switch 1187 and the other switches in FIGS. 14-17 are depicted as mechanical relay switches, it should be understood that the switches may be other forms of switching devices. For example, the switch may be a semiconductor switch such as a solid-state relay, a transistor such as a triac, a FET (field effect transistor), an SCR (silicon controlled rectifier), a BJT (bipolar junction transistor), or an IGBT (insulated gate bipolar transistor), or other transistors. It may be a controllable switching device.

As shown in FIG. 11, the communication module 281 can be connected to the controller 285 to transfer the calibrated current measurement from the calibration device 180 to the arithmetic unit 120. In some embodiments, the communication module 281 may include a receiver and a transmitter. Communication module 281 may include any form of wired or wireless communication device operating at any frequency using any data link protocol. In one embodiment, the communication module 281 comprises a 2.4 GHz transmitter / receiver with part number CC2500 available from Texas Instruments, Inc. In another embodiment, the communication module 281 is Texas. Includes 900MHz transmitter / receiver with part number CC2010 available from Instruments, Inc. In some embodiments, the communication module 281 is capable of communicating using any of the following communication protocols: WiFi (IEEE802.11), Zigbee® (IEEE802.15.4), ZWave, or SimpliciTI protocol. .. In another embodiment, a proprietary data communication protocol is used. In a further embodiment, the communication link between the communication module 215 and the communication modules 281 and / or 221 is achieved by a monitoring conductor. In this embodiment, the communication link consists of power line communication (PLC) formed by inputting a transmitted signal to at least one conductor of the branch circuit to which the calibration device is connected.

In the embodiment shown in FIG. 11, the power supply 289 may include a power supply 289. The power supply 289 may include an isolated transformer and a DC power supply. The power supply 289 is an incoming line voltage from an AC power line voltage such as 120V in the United States and Canada or 220V in Europe, and a low DC voltage such as 3.3V or 5VDC to the power controller 213 and other elements of the calibration device 180. Convert to.

The controller 285 can receive a sample of the input AC power line voltage converted by the level converter 1173 to a lower voltage AC signal that is proportional to the input AC power line voltage. In some embodiments, the input AC power line voltage is 120VAC, but the lower voltage AC signal is in the range 0-3.3V. In some embodiments, level converter 1173 is used to separate + V and -V alternating bipolar signals from 0V and VDD unipolar signals or within the effective voltage range of analog-to-digital converter 1177. Converts the low voltage signal to the unipolar signal range of. The analog-to-digital converter 1177 is capable of sampling incoming low voltage signals, as shown in FIG. In the same or different embodiments, the filter 1172 can limit the frequency range of the low voltage signal to the AC line frequency.

In many embodiments, the analog-to-digital converter 1177 can be integrated into controller 285 or is separate from controller 213 but may be coupled to controller 285. The sampled AC line voltage allowed the controller 213 to enter and measure the AC line voltage, which was pulled out by the calibration load 1188 given a sampled low voltage signal proportional to the AC line voltage. By calculating the current, the system 100 is calibrated more accurately. Further, the sampled low voltage signal may be used to create a phase reference synchronized with the AC line voltage.

In some embodiments, the controller 285 uses a square wave low voltage signal to create a phase reference. In these embodiments, the square ring device 1174 produces a square wave low voltage signal. The square wave low voltage signal may be a square wave having the same period and zero crossing timing as the low voltage AC signal. This relationship between the square wave signal and the low voltage signal is shown in FIG. In certain embodiments, the square ring device 1174 may include a Schmitt trigger, a comparator, or a digital logic gate such as an inverter or transistor level shifter. For the square wave amplitude, a logic level compatible with controller 285 is selected. The square wave signal does not contain information about the amplitude of the incoming AC line voltage, but it does contain phase information because the positive and negative edges of the square wave signal are synchronized with the zero intersection of the incoming AC line voltage.

In some embodiments, the calibrated current measurement reported by the detection device 110 and the incoming power line voltage are used with a phase reference obtained from either a low voltage signal or its square wave equivalent. Measure the relative phase angle. This relative phase angle measurement between voltage and current is used to accurately grasp the power factor of the ineffective load connected to the power conductor as measured by the detection device 110. Power factor is the cosine of the phase angle between voltage and current waveforms. This power factor can be calculated directly from the sampled low voltage signal, or in the case of a square wave low voltage signal, by adapting a sinusoidal curve of appropriate frequency to the edge transition of the square wave signal. It may be calculated indirectly.

The power factor is the ratio of the actual power flowing through the conductor to the apparent power flowing through the conductor. In some embodiments, reporting the actual power flowing through the power conductors 193, 194, and 195 to the user of system 100 is prioritized in order to improve the approximation of the power meter reading provided by the utility. In these embodiments, the phase information provided by the low voltage signal is important for accurate calculation of the predicted power.

The calibration load 1188 is heated because it wastes current when it is switched on with the switch 1187. This heating is calibrated by causing thermal damage to the calibration load 1188 itself, to other components within the housing of the calibration device 180, or to people or objects in the vicinity of the calibration device 180. May threaten the safe operation of load 1188.

In some embodiments, the controller 285 includes a temperature sensor 1186, such as a bimetal thermostat, thermistor, or semiconductor temperature sensor. In some embodiments, the temperature sensor 1186 interrupts the switching signal and turns off the calibration load 1188 if the calibration load 1188 or the housing of the calibration device 180 is too hot.

In a further embodiment, the controller 285 heats the temperature sensor 1186 before turning on the calibration load 1188 to ensure that the housing of the calibration load 1188 or the calibration device 180 is not too hot at the beginning of the calibration process. Check the reading. In a further embodiment, the controller 285 may be extrapolated to determine if the calibration load 1188 is likely to become too hot after a typical operating period of the calibration load 1188. In this embodiment, the controller 285 functions to defer the calibration process until the calibration load 1188 or the housing of the calibration device 180 can complete the process without becoming too hot.

In some embodiments, there are two different control mechanisms for the controller to control the switch signal to switch 1187. These two methods correspond to two different processor positions that perform the calibration process to obtain calibration current measurements.

In the first method, the controller 285 is co-located and controls the calibration load module 283. Controller 285 can also obtain sensor readings from detection device 110 (via communication module 281) and controller 213. Controller 285 performs a calibration process (described below with reference to FIG. 18) to obtain calibration current measurements. In these embodiments, the calibration calculation module 229 can be located within the calibration device 180 instead of the arithmetic unit 120.

In a first method in which controller 285 performs the calibration process, communication module 281 receives incoming signal measurements from detection device 110 and / or arithmetic unit 120. Controller 285 can calculate calibration current measurements using method 2000 in FIG. After calculating the calibration current measurement, the calibration device 180 may transmit the calibration current measurement to the arithmetic unit 120 for display or other purposes.

In the second method, a remote processor such as controller 225 (Figure 2) or controller 213 (Figure 2) commands the calibration load 1188 to turn the switch on and off, and this controller (controller 225 or controller 213) is shown in the figure. 18 calibration methods 1800 are performed and calibration current measurements are obtained as described in method 2000 of FIG.

When the second method is used with controller 225 in managing calibration, controller 225 receives a message from controller 285 over the communication link. In some embodiments, controller 225 sends a message that turns on the calibration load for a specified period of time. In some embodiments, this period is selected from one or more predetermined periods. In other embodiments, the calibration load 1188 is turned on until a turn-off message is received by the controller 285, or until the timeout timer expires or the calibration load 1188 or the temperature sensor 1186, which indicates that its housing is too hot, is activated. Will be done.

In a further embodiment, controller 285 makes the decision to turn on the calibration load for a specific period of time alone. In some embodiments, the controller 285 switches on and off the calibration load 1188 for a specific period of time, while simultaneously indicating that the calibration load 1188 has been switched on, either in advance or later. Send a notification to controller 225. In this embodiment, controller 213 uses a known time offset between messages received from controller 285 to ensure that the calibration load 1188 is on / off at the time indicated by the message received from controller 285 over the communication link. Synchronize the flow of the calibration procedure. In a further embodiment, controller 285 switches on and off calibration load 1188 in the order known to controllers 213 and / or 225 (FIG. 2).

FIG. 11 shows an example of a switched load 1105 in the calibration device 180. Other possible configurations of the switched load are shown in FIGS. 14-17.

Specifically, FIG. 14 shows an example of the switched load 1405 according to the third embodiment. The switched load 1405 may include (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 the calibration device 180 of FIGS. 2 and 11.

In this embodiment, the switched load 1405 can be designed to calibrate the measurements of a single energizing conductor (feed line to the branch circuit labeled "line") being measured by the detection device 110. .. In this embodiment, the controller 285 can switch between calibration loads 1188 and 1441 to provide two different sets of measurements used in the calibration process. In another embodiment, the switched load 1405 may include three or more switches with three or more calibration loads.

FIG. 15 shows an example of the switched load 1505 according to the fourth embodiment. The switched load 1505 may include (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 the calibration device 180 of FIGS. 2 and 11.

In this embodiment, the switched load 1505 calibrates the measurements of the two energizing conductors being measured by the detection device 110 (feed lines to the branch circuits labeled "Line 1" and "Line 2"). Can be designed to. In this embodiment, two separate calibration loads 1588 and 1541 can switch between individual line conductors and neutral conductors under the control of a switching signal from controller 285. The controller 285 can control the switching signal in order to electrically connect the calibration load as follows.

<tables num="1"><img id="000002" he="57" wi="159" file="JP6152437B2_D0001.tif" img-format="tif" img-content="drawing" /></tables>

FIG. 16 shows an example of the switched load 1605 according to the fifth embodiment. The switched load 1605 may include (a) switches 1687, 1642, and 1643, and (b) calibration loads 1588 and 1541. In this embodiment, the switched load 1605 replaces the switched load 1105 in the calibration device 180 of FIGS. 2 and 11.

In this embodiment, the switched load 1605 calibrates the measurements of two or more current-carrying conductors (feeding lines to the branch circuits labeled "line 1" and "line 2") being measured by the detection device 110. It can also be configured as follows. In this embodiment, two separate calibration loads 1588 and 1541 are switched on so that the calibration loads 1588 and 1541 can be individually connected to the neutral return line, or are common in phase-distributed power systems. As is the case, it is possible to connect to the pair of line 1 and line 2 as a pair. The controller 285 can electrically connect the calibration load as follows by controlling the switching signal.

<tables num="2"><img id="000003" he="70" wi="159" file="JP6152437B2_D0001.tif" img-format="tif" img-content="drawing" /></tables>

FIG. 17 shows an example of the switched load 1705 according to the sixth embodiment. The switched load 1705 may include (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 the calibration device 180 of FIGS. 2 and 11.

In this embodiment, the switched load 1705 calibrates the measurements of two or more energizing conductors (feeding lines to the branch circuits labeled "Line 1" and "Line 2") being measured by the detection device 110. It can also be configured to do so. In this embodiment, switching on a single calibration load 1788 allows the calibration of two conductor plus neutral wires, as is common in phase-dividing power systems. The switches 1787 and 1743 may be single pole double throw (SPDT) switches. Switches 1787 and 1743 can be used with the calibration load 1788 to connect various combinations of branch circuit conductors. The switched load 1705 can be implemented at a lower cost than the switched load 1605 (Fig. 16) by using a single calibration load. The controller 285 can electrically connect the calibration load as follows by controlling the switching signal.

<tables num="3"><img id="000004" he="78" wi="159" file="JP6152437B2_D0001.tif" img-format="tif" img-content="drawing" /></tables>

In many embodiments, it is necessary to calibrate both phase lines of the electrical infrastructure. Therefore, one of the calibration devices of FIGS. 11 and 14-17 needs to be plugged into the first phase branch and the second phrase branch. In the embodiment shown in FIG. 2, the calibration device 180 is the first calibration device, and the arithmetic unit 120 includes the second calibration device. In another embodiment, a single calibration device (eg, a calibration device with one of the switched loads 1505, 1605, or 1705) is a 240V outlet coupled to both the first and second phase branches. Can be connected to.

In an embodiment in which one of the calibration devices of FIGS. 11 and 14 to 17 is plugged into each of the first phase branch and the second phrase branch, the calibration devices are of each other, the detection device, and the arithmetic unit. You need to be able to communicate. Several different communication methods are feasible. For example, all calibration devices can receive and transmit data. In another embodiment, one calibration device (eg, calibration device 180 in FIG. 1) can transmit data and a second calibration device (eg, arithmetic unit 120 in FIG. 2) can receive data. is there.

In some embodiments, the two calibration devices can communicate wirelessly. For example, the communication module 281 and communication module 221 of FIG. 2 may include a radio. The calibration device is configured to report the observed phase angles of the 60 Hz period to other calibrators to determine if they are on different electrical phase branches. In some embodiments, one calibration device can wirelessly report to another calibration device when a zero crossover occurs at current or voltage. If both calibration devices are installed on the same electrical phase branch, there will be overlapping parts of the received radio message in the message. If there is an offset between the observed zero intersection and the received message, the calibration device is installed on a different electrical phase branch.

In the same or different embodiments, the user communication device 184 on the calibration device 180 (FIG. 1) may include a single red / green LED. A green LED may indicate that the two calibration devices are properly installed in two different phases. For example, the user first plugs the calibration device 180 of FIG. 1 (ie, the transmitting calibration device) into any electrical outlet. The user then plugs the arithmetic unit 120 of FIG. 1 (ie, the receiving calibration device) into another electrical outlet. The LEDs on the user communication device 184 may be lit in red to indicate that they are both in the same phase, or if they are in different phase branches, they are lit in green. May be good. The user can move the second calibrator to another outlet until the green indicator on the user communication device 184 appears.

In other embodiments, wireless communication may also be present between the detection device 110, the calibration device 180, and the arithmetic unit 120, respectively. In this embodiment, the detection device 110 is capable of detecting two electrical phases in the breaker panel. When the calibration device 180 periodically repeats its electrical load, the calibration device 180 notifies the detection device 110, and the detection device 110 can determine which phase calibration device 180 to connect. The arithmetic unit 120 can also report to the detection device 110 when to start its load cycle. The detection device 110 infers that the calibrators are installed in two different phases by observing at which phase angle these changes occur.

In yet another embodiment, a non-wireless communication method can be used to communicate between the calibration device 180 and the arithmetic unit 120. In these embodiments, the communication modules 221 and / or 281 may include a signal injector and / or a signal receiver. In this embodiment, the calibration device 180 and the arithmetic unit 120 can send signals over the power infrastructure. For example, a simple 1kHz (kilohertz) tone can be used. In the same or different embodiments, the signal consists of an amplitude modulated voltage applied to one or more conductors of the power infrastructure. In another embodiment, the signal consists of an amplitude modulated current drawn from the power infrastructure. In a further embodiment, the signal consists of a frequency modulated voltage or current. In certain embodiments, the arithmetic unit 120 can be designated as a signal transmitter and the calibration device 180 can be designed as a receiver. When the calibration device 180 is plugged into an electrical outlet, the user communication device 184 may turn on the green LED if it cannot detect the presence of the signal being transmitted by the first device. If the calibration device 180 and the arithmetic unit 120 are coupled in separate phase branches, the calibration device 180 and the arithmetic unit 120 cannot detect the signal placed on the power infrastructure by the other.

When the calibration device 180 detects the signal, a red light may indicate that the two calibration devices are in phase. At this point, the user can be instructed to move one of the calibration device 180 or the arithmetic unit 120 to another electrical outlet. In yet another embodiment, instead of communication modules 221 and 281 including signal injectors and / or receivers, communication modules 221 and 281 allow the calibration device 180 and arithmetic unit 120 to communicate on the power infrastructure. , Power line communication (PLC) modules may be included.

Moving on to another embodiment, FIG. 18 shows a flowchart of one embodiment of the calibration method 1800 of the electrical monitoring system according to one embodiment. Method 1800 is merely exemplary and is not limited to the embodiments presented herein. Method 1800 can be used in many different embodiments or examples not specifically described or described herein. In some embodiments, the work, procedures, and / or processes of Method 1800 can be performed in the order presented. In other embodiments, the work, procedures, and / or processes of Method 1800 can be performed in other suitable order. In yet other embodiments, one or more of the operations, procedures, and / or processes of Method 1800 may be combined or omitted.

Method 1800 can be considered as describing a method of calibrating a common detection device. This method may involve determining one or more calibration factors that can be used to calculate the predicted current in the power infrastructure of the structure in Method 2000 of FIG. By using the method described below, the following points: (a) The current sensor 211 (Fig. 2) is so that the signals that can be identified from the mains conductors 193 and 194 are rarely measured, the mains conductors 193 and 194 (. When located away from Figure 1), and (b) all current sensors 211 (Figure 2) are placed very close to the neutral power conductor 195 (Figure 1), from power conductors 193 and 194. The calibration coefficient can be calculated accurately regardless of the position of the detection device 110 (FIG. 1) on panel 196 (FIG. 1), except when placed apart.

Method 1800 in FIG. 18 includes the task 1860 of acquiring and storing one or more first reference measurements. In some embodiments, the detection device 110 (FIG. 2) can be used to obtain a first reference measurement using the current sensor 211 (FIG. 2). These first reference measurements may include the nominal current flowing through at least one of the power conductors 193 or 194 (FIG. 1) by the electrical device eliciting power. In addition, each sensor (eg, sensors 641 and 642 (Figure 6) or sensor 941)₁、941₂、・・・941_NIn (Fig. 9)), the amplitude and phase can be measured. Each amplitude reading L is L_old-NSaved under the name of, each phase power Q is Q_old-NStored under the name of, N is the number of sensors. In some embodiments, the first reference measurement is made for both the first phase branch and the second phase branch.

In some embodiments, work 1860 also includes determining voltage amplitude and phase angle. The use of the voltage phase angle can help in the calculation of the current phase angle. In some embodiments, the voltage sensor 228 of FIG. 2 can be used to determine the phase angle of the voltage.

Subsequently, method 1800 of FIG. 18 includes work 1861 of temporarily connecting a first known calibration load to a first phase branch. In some embodiments, the calibration device 180 (FIGS. 1 and 11) is in the switched loads 1105, 1405, 1505, 1605, or 1705 of FIGS. 11, 14, 15, 16, and 17, respectively. One of the calibration loads can be connected.

Method 1800 of FIG. 18 then includes the task 1862 of acquiring and storing one or more first calibration measurements on the first phase branch. In some embodiments, the detection device 110 (FIG. 2) can be used to obtain a first calibration measurement from the current sensor 211 (FIG. 2). In some embodiments, the known calibration load from the switched loads 1105, 1405, 1505, 1605, or 1705 of FIGS. 11, 14, 15, 16, and 17, respectively, is the first phrase branch (1705). For example, the first calibration measurement is performed while being connected to the line 1) of FIGS. 15 to 17. This first known calibration load is the known current L_cal-1Pull out. These first calibration measurements may include a nominal current flowing through at least one of the power conductors 193 or 194 (FIG. 1) from an appliance that draws power and a first known calibration load.

For example, each sensor (eg, sensors 641 and 642 (Figure 6) or sensor 941).₁、941₂、・・・941_NIn (Fig. 9)), the amplitude and phase angle are measured. Each amplitude reading L is L_new-N-1Etc., and each phase angle reading power Q is Q_new-N-1Etc., where N is the number of sensors.

In some embodiments, work 1862 also includes determining voltage amplitude and phase angle. The use of the voltage phase angle can help in the calculation of the current phase angle. In some embodiments, the voltage sensor 228 of FIG. 2 can be used to determine the phase angle of the voltage.

Method 1800 in FIG. 18 continues work 1863 to disconnect the first known calibration load and temporarily connect the second known calibration load to the second phase branch. In some embodiments, the calibration device 180 (FIGS. 1 and 11) can connect one of the calibration loads at the switched loads 1405, 1505, or 1605 of FIGS. 14, 15, and 16, respectively. .. In some embodiments, the second known calibration load is coupled to a second phase branch (eg, line 2 in FIGS. 15-17).

Subsequently, method 1800 of FIG. 18 includes the task 1864 of acquiring and storing a second calibration measurement on the second phase branch. In some embodiments, the detection device 110 (FIG. 2) can be used to obtain a second calibration measurement from the current sensor 211 (FIG. 2). These second calibration measurements may include a nominal current flowing through at least one of the power conductors 193 or 194 (FIG. 1) from an appliance that draws power and a second known calibration load. In some embodiments, the second calibration measurement is performed with a known calibration load connected to a second phrase branch (eg, line 2 in FIGS. 15-17). This second known calibration load is the known current L_cal-2Pull out.

For example, each sensor (eg, sensors 641 and 642 (Figure 6) or sensor 941).₁、941₂、・・・941_NIn (Fig. 9)), the amplitude and phase angle are measured. Each amplitude reading L is L_new-N-2Saved under the name of, each phase angle power Q is Q_new-N-2Etc., where N is the number of sensors.

In some embodiments, work 1864 also includes determining voltage amplitude and phase angle. The use of the voltage phase angle can help in the calculation of the current phase angle. In some embodiments, the voltage sensor 228 of FIG. 2 can be used to determine the phase angle of the voltage.

Method 1800 of FIG. 18 then includes work 1865 to disconnect the known calibration load (ie, the second calibration load) from the power conductors 193, 194, and / or 195 (FIG. 1).

Method 1800 in FIG. 18 continues the task of acquiring and storing one or more second reference measurements 1866. In some embodiments, the detection device 110 (FIG. 2) can be used to obtain a second reference measurement from the current sensor 211 (FIG. 2). This second reference measurement may include a nominal current flowing through at least one of the power conductors 193 or 194 (FIG. 1) by the appliance drawing power. The purpose of this second reference power is to ensure that the reference load observed in work 1861 did not change during the calibration process. If the measured value in work 1866 is equal to the measured value from 1861 within a predetermined amount, the measured value from work 1866 can be discarded. If the measured value in operation 1866 is out of the prescribed amount, the measured value from 1861 can be discarded. In other embodiments, work 1866 can be omitted.

In some embodiments, work 1866 also includes determining voltage amplitude and phase angle. The use of the voltage phase angle can help in the calculation of the current phase angle. In some embodiments, the voltage sensor 228 of FIG. 2 can be used to determine the phase angle of the voltage.

Subsequently, method 1800 of FIG. 18 includes work 1867 to determine the calibration factor. In some embodiments, Task 1867 solves the calibration coefficient of the detection device 110 (FIG. 1) by fitting one or more sensor calibration equations to the reference and each calibration measurement, and by the detection device 110. Calibration current measurements are obtained on at least one conductor detected. In some embodiments, the calibration calculation module 229 (FIG. 2) can determine the calibration factors as follows.

FIG. 19 shows a flowchart of an example embodiment of operation 1867 for determining the calibration coefficient according to the first embodiment. In some embodiments, work 1867 has a calibration factor Q._M, K₁, K₂, Y₁, And Y₂, Can be broadly included. In other embodiments, other calibration factors can be determined.

With reference to FIG. 19, work 1867 includes procedure 1971 to determine possible calibration factors for the first phase branch. In some embodiments, for each sensor 1 through N (where N is the number of sensors in the current sensor), procedure 1971 is L._old-N, Q_old-N, L_cal-1, L_new-N-1, And Q_new-N-1Using, X_N-1And Q_MN-1May include calculations of X_N-1= [ {L_old-N²+ L_new-N-1²-2 * L_old-N* L_new-N-1* Cos (Q_old-N-Q_new-N-1)}] / L_cal-1and Q_MN-1= Q_new-N-1-Sin^-1[(L_old-N* Sin (Q_old-N-Q_new-N-1)) / (X_N-1* L_cal-1)].

In addition, in some examples, Q_MN-1If&gt; 180 ° Q_MN-1= Q_MN-1-180 ° and X_N-1= X_N-1* (-1).

Task 1867 of FIG. 19 continues procedure 1972 to determine possible calibration factors for the second phase branch. In some embodiments, for each sensor 1-N, procedure 1972 is L._old-N, Q_old-N, L_cal-2, L_new-N-2, And Q_new-N-2Using, X_N-2And Q_MN-2May include calculations of X_N-2= [ {L_old-N²+ L_new-N-2²-2 * L_old-N* L_new-N-2* Cos (Q_old-N-Q_new-N-2)}] / L_cal-2and Q_MN-2= Q_new-N-2-Sin^-1[(L_old-N* Sin (Q_old-N-Q_new-N-2)) / (X_N-2* L_cal-2)].

In addition, in some examples, Q_MN-2If&gt; 180 ° Q_MN-2= Q_MN-2-180 ° and X_N-2= X_N-2* (-1).

Task 1867 of FIG. 19 then includes procedure 1973 to check the validity of the measurements. In procedure 1973, for each of sensors 1-N, within a given tolerance (eg, 0.1%, 1%, 5%, 10%, or 20%), Q_MN-1= Q_MN-2If so, the measured value of the sensor is maintained. Q within the specified tolerance_MN-1 Q_MN-2If so, the phase angle of the sensor is discarded.

Next, task 1867 in Figure 19 is the Q of the sensor that was not discarded in procedure 1973._MN-1Statistical mode Q about_modeIncludes procedure 1974 to determine. In some embodiments, the statistical mode is the most frequently occurring phase angle within a predetermined tolerance for sensors that were not discarded in procedure 1973.

Task 1867 of FIG. 19 continues procedure 1975 to determine the first part of the calibration factor. In some embodiments, procedure 1975 has the highest value X from the remaining sensors._N-1Select the sensor with X and X_N-1= K₁And X_N-2= K₂And Q_MN-1= Q_MKIncludes assigning. This selected sensor is hereinafter referred to as sensor K. Sensor K can be discarded from the list of available sensor candidates for the rest of work 1867.

Subsequently, work 1867 of FIG. 19 includes procedure 1976 to determine the second part of the calibration factor. In some embodiments, procedure 1976 has the highest value X from the remaining sensors._N-2Select the sensor with X and X_N-2= Y₁And X_N-2= Y₂And Q_MN-2= Q_MYIncludes assigning. This selected sensor is hereinafter referred to as sensor Y.

Task 1867 of FIG. 19 then includes procedure 1977 to determine the third part of the calibration factor. In some examples, Q_MIs Q_M= [Q_MY+ Q_MK] / 2 is calculated.

The official example used to determine the calibration factor above is only an example. In other examples, other formulas (eg, linear, non-linear, quadratic, and / or iterative equations) can be used to calculate the same or different calibration factors.

For example, a detection device can be calibrated (and determined for predicted current) using only one sensor. In this embodiment, the sensor is located where the magnetic fields from the mains conductors 193 and 194 (FIG. 1) are symmetrical in the sensor. That is, the magnetic fields from the main power conductors 193 and 194 (Fig. 1) are symmetrical in the sensor. Further, in this embodiment, the sensor Z is in a position where the magnetic field from the main power conductor 195 (FIG. 1) representing the neutral return conductor is small and negligible.

The sensor at this point in which the magnetic field is symmetrical is referred to as sensor Z. In this embodiment, the current measured at sensor Z is L_Z= K_Z* L_predictedbe equivalent to. In the formula, L_ZIs the current measured by sensor Z, K_ZIs a constant, L_predictedIs the integrated predicted current in the first phase branch and the second phase branch.

In this example, the reference current measurement obtained at sensor Z in work 1860 or 1866 is L._Z-baselineIt may be saved as. The first calibration measurement obtained on sensor Z is L_Z-calThe current of the first known calibration load may be ΔP. In this example, K_ZIs K_Z= (L_Z-cal-L_Z-baseline) / ΔP can be calculated.

In other embodiments, other calibration equations that require three or more calibration measurements can be used. In these examples, operations 1861 to 1866 (FIG. 18) may be repeated as many times as necessary, using different calibration loads, to obtain the required number of calibration points.

After the completion of procedure 1977, the task of calculating the calibration factor 1867 is completed.

With reference to FIG. 18 again, method 1800 of FIG. 18 continues task 1868 of preserving the calibration factors. In some embodiments, the calibration coefficients can be stored in memory 226 of the arithmetic unit 120 of FIGS. 1 and 2. In the same or different embodiments, the calibration factors can be stored in the memory of the detection device 110 and / or the calibration device 180 of FIG. In yet another embodiment, the calibration factor can be sent to a remote server for storage and use. After work 1868, method 1800 is completed.

FIG. 20 shows a flowchart of an embodiment of Method 2000 for determining the predicted current of a power conductor. Method 2000 is merely exemplary and is not limited to the embodiments presented herein. Method 2000 can be used in many different embodiments or examples not specifically described or described herein. In some embodiments, the work, procedures, and / or processes of Method 2000 can be performed in the order presented. In other embodiments, the work, procedures, and / or processes of Method 2000 can be performed in any other suitable order. In yet other embodiments, one or more of the operations, procedures, and / or processes of Method 2000 may be combined or omitted.

Method 2000 describes a general method for determining the expected power (and / or current) used for a power conductor. This method involves determining the predicted current in the power infrastructure of the structure using several predetermined calibration factors (see Method 18 in FIG. 18). Using the method described below, the following points: (a) The current sensor 211 (Fig. 2) is placed so far away from the mains conductors 193 and 194 (Fig. 1) that few identifiable signals are measured. And (b) unless all current sensors 211 (Fig. 2) are located very close to the neutral power conductor 195 (Fig. 1) and away from power conductors 193 and 194. , The predicted current can be calculated accurately regardless of the position of the detection device 110 (Fig. 1) on panel 196 (Fig. 1). In some embodiments, Method 2000 has a predicted current L on each branch of the power infrastructure (eg, first and second phase branches)._1-predictedAnd L_2-predictedIt can broadly include calculations (as reported by electrical utilities that power).

In some embodiments, the combination of Method 1800 and Method 2000 in FIG. 18 can produce a method using a power measurement device. Alternatively, method 1800 in FIG. 18, combined with method 2000, can be considered as a method of determining the predicted current (and / or power) of a power conductor. In these embodiments, method 1800 can be performed once to determine the calibration factor and method 2000 determines the predicted current (and / or power) used by the load of the structure at various time points. To do so, it can be repeated before.

With reference to FIG. 20, method 2000 includes work 2061 of making a first set of measurements using a first current sensor. In various embodiments, one of the current sensors 211 (FIG. 2) can be used to make the first set of measurements. In some embodiments, work 2061 may include measurements of amplitude and phase angle at sensor K. The amplitude reading is L_KIt may be saved under the name of, and the phase angle reading power is Q._KIt may be saved under the name of.

In some embodiments, work 2061 also includes determining voltage amplitude and phase angle. The use of the voltage phase angle can help in the calculation of the current phase angle. In some embodiments, the voltage sensor 228 of FIG. 2 can be used to determine the phase angle of the voltage.

Subsequently, method 2000 of FIG. 20 includes work 2062 of making a second set of measurements using a second current sensor. In various embodiments, one of the current sensors 211 (FIG. 2) can be used to make the first set of measurements. In some embodiments, work 2063 may include measurements of current amplitude and phase angle at sensor Y. The amplitude reading is L_YIt may be saved under the name of, and the phase angle reading power is Q._YIt may be saved under the name of.

In some embodiments, work 2062 also includes determining voltage amplitude and phase angle. As mentioned above, 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 embodiments, the voltage sensor 228 of FIG. 2 can be used to determine the phase angle of the voltage.

Method 2000 of FIG. 20 then includes work 2063 to determine the predicted power used in the first phase branch. In some embodiments, work 2063 has a calibration factor Q._M, K₁, K₂, Y₁, And Y₂Amplitude L of the first phase branch using₁And the phase angle Q of the first phrase branch₁May include the decision of L₁= [ {(L)_K/ K₂)²+ (L_Y/ Y₂)²-2 * (L_K/ K₂) * (L_Y/ Y₂) * Cos (Q_K-Q_Y)}] / [(K₁/ K₂)-(Y₁/ Y₂)]] and Q₁= Tan^-1[{(L_K/ K₂) * Sin (Q_K-Q_M)-(L_Y/ Y₂) * Sin (Q_Y-Q_M)} / {(L_K/ K₂) * Cos (Q_K-Q_M)-(L_Y/ Y₂) * Cos (Q_Y-Q_M)}].

In some embodiments, the predicted power P in the first phase branch_1-predictedMay be the power of the first phrase branch as reported by the electrical utility. In some embodiments, the predicted current L at the first phase branch_1-predictedIs P_1-predicted= V * L₁* Cos (Q₁). In the equation, V is the voltage measured in work 2062.

Method 2000 in FIG. 20 continues the task 2064 of determining the predicted power used in the second phase branch. In some embodiments, work 2064 has a calibration factor Q._M, K₁, K₂, Y₁, And Y₂Amplitude L of the second phase branch using₂And the phase angle Q of the second phrase branch₂May include the decision of L₂= [ {(L)_K/ K₁)²+ (L_Y/ Y₁)²-2 * (L_K/ K₁) * (L_Y/ Y₁) * Cos (Q_K-Q_Y)}] / [(K₂/ K₁)-(Y₂/ Y₁)]] and Q₂= Tan^-1[{(L_K/ K₁) * Sin (Q_K-Q_M)-(L_Y/ Y₁) * Sin (Q_Y-Q_M)} / {(L_K/ K₁) * Cos (Q_K-Q_M)-(L_Y/ Y₁) * Cos (Q_Y-Q_M)}].

In some embodiments, the predicted power P in the second phase branch_2-predictedMay be the power of the second phrase branch as reported by the electrical utility. In some embodiments, the predicted current P at the second phase branch_2-predictedIs P_2-predicted= V * L₂* Cos (Q₂). In the equation, V is the voltage measured in work 2062.

In the second embodiment where the detection device uses only one sensor Z, the predicted power P_predictedThe decision is relatively simple. In this embodiment, the sensor Z is located at a position where the magnetic fields from the mains conductors 193 and 194 (FIG. 1) are symmetrical in the sensor Z, and the sensor Z is the magnetic field from the mains conductors 195 (FIG. 1). Is small and in a negligible position. In this embodiment, the power measured at sensor Z is P_predicted= V * L_Z/ K_ZCan be calculated with. In the equation, V is the voltage measured in work 2062 and L_ZIs the current measured by sensor Z at work 2061 and K_ZIs a constant (already determined in work 1867 in FIG. 18).

Method 2000 in FIG. 20 continues work 2065 using and / or reporting the predicted currents of the first and second phase branches. Total predicted power P_predictedIs the sum of the predicted power of the first phrase branch and the predicted power of the second phrase branch: P_predicted= P_2-predicted+ P_1-predictedIs.

In some embodiments, the power used by the load in the structure (ie, P)_predicted) Can be displayed to the user on the user communication device 134 of the arithmetic unit 120 (FIGS. 1 and 2). In other embodiments, the power used (and / or predicted current) can be transmitted to the electrical utility that supplies the power, or can be reported to other entities.

In yet another embodiment, the predicted current can be used to divide the load into individual units based on the stepwise changes and phase angles between the observed currents and voltages. The arithmetic unit 120 can demonstrate its use by determining a stepwise change (increasing or decreasing current) and assigning it to one or more electrical devices in the structure. Further division can be achieved by observing the presence of 120V and 240V appliances from the current data on each phase branch. In addition to the sum of the staircase changes in current, the staircase changes on the individual phase branches further identify the presence of different loads or appliances (ie, similar loads installed in different locations within the building). .. The change in phase angle observed by the internal reactance of the device makes it possible to identify inductive loads (ie, fans, motors, microwave ovens, compressors). Predictive reactance is not required, but rather the observed raw phase angle is sufficient as long as it is a priori related to the device. In some embodiments, the transient change in current consumption of the power infrastructure can be a property of the device's activation characteristics that can characterize residential appliances. This technique involves classifying unknown loads by using template matching against a library of known launch features. This feature space is much less susceptible to overlapping categories of devices and can separate many devices with similar load characteristics. For example, two motors with similar real and reactive power consumption can exhibit very different starting characteristics and can be separated into individual units. This technique may be suitable for electrical devices that consume high current loads, or at least high currents at startup. These tasks can be used to divide the load of the power infrastructure into individual units.

After work 2065, Method 2000 is completed.

FIG. 21 shows an example of the first position of the two current sensors with respect to the main power conductors 193, 194, and 195 (FIG. 1) according to one embodiment. The positions of the two current sensors shown in FIG. 21 were used to test the calibration method 1800 in FIG. 18 and the current determination method 2000 in FIG. The load switches connected to the mains conductors 193, 194, and 195 (Figure 1) were randomly turned on and off. The actual current was monitored using a current monitor, with the load switched on and off at random. After the measurements were made using the two current sensors, the predicted currents were also calculated using the methods 1800 and 2000 in FIGS. 18 and 20. FIG. 22 shows a comparative graph of the predicted currents of the measured currents by the methods of FIGS. 18 and 20. As shown in FIG. 22, the predicted current closely reflects the measured current.

FIG. 23 shows an example of the second position of the two current sensors with respect to the main power conductors 193, 194, and 195 (FIG. 1) according to one embodiment. The positions of the two current sensors shown in FIG. 23 were also used to test the calibration method 1800 in FIG. 18 and the current determination method 2000 in FIG. The load switches connected to the mains conductors 193, 194, and 195 (Figure 1) were randomly turned on and off. The actual current was monitored using a current monitor, with the load switched on and off at random. After making measurements using two current sensors, the predicted current was also calculated using methods 1800 and 2000. FIG. 24 shows a comparative graph of the predicted currents of the measured currents by the methods of FIGS. 18 and 20. As shown in FIG. 24, the predicted current closely reflects the measured current.

Although the invention has been described in the context of specific embodiments, it will be appreciated by those skilled in the art that various modifications can be made without departing from the spirit or scope of the invention. Therefore, the disclosure of embodiments of the present invention is intended to illustrate the scope of the invention, not to limit it. The scope of the present invention shall be limited only to the scope required by the appended claims. For example, work 1860, 1861, 1862, 1863, 1864, 1865, 1866, 1867, and 1868 of FIG. 18, procedures 1971, 1972, 1973, 1974, 1975, 1976, and 1977 of FIG. , 2062, 2063, 2064, and 2065 can consist of many different tasks and procedures, can be done in many different orders with many different modules, and any of the elements in Figure 1. It will be readily apparent to those skilled in the art that they are modifiable and some of the above description of these embodiments does not necessarily represent a complete description of all possible embodiments.

All elements claimed in a particular claim are essential to the embodiments claimed in that particular claim. As a result, the replacement of one or more billing elements results in a rebuild rather than a modification. In addition, benefits, other benefits, and solutions to problems have been described for specific embodiments. However, any one or more of the benefits, benefits, solutions to the problem, and any one or more factors that may give rise to or become more prominent in the benefits, benefits, or solutions, such benefits, benefits, solutions, or. Unless the element is stated in the claims, it is not considered to be an important, necessary or essential feature or element of any one or all claims.

Moreover, the embodiments and limitations disclosed herein are those where the embodiments and / or limitations are not explicitly claimed within the scope of the claims, and (2) under the doctrine of equivalents. If it is an obvious element and / or limited equivalent in the scope, or a potential equivalent, it will not be released to the public under the principle of liberation.

100 power monitoring system 110 detection device 120 arithmetic unit 180 Calibration device 213,225,285 controller 619 Phase indicator 651 Phase detector 955,956 multiplexer