Patent Application
20220178976
The present disclosure pertains to estimating and tracking a frequency of an alternating current in an electric power system. More particularly, but not exclusively, the present disclosure pertains to line-mounted current sensors that estimate and track the frequency of an alternating current to generate a sampled representation of the alternating current that may be used to monitor, automate, and/or protect the electric power system.
Non-limiting and non-exhaustive embodiments of the disclosure are described, including various embodiments of the disclosure with reference to the figures, in which:
Electric power systems are used to generate, transmit, and distribute electric power to loads, and serve as an important part of critical infrastructure. Electric power systems and equipment may be monitored and protected by a variety of types of equipment. Protection relays may analyze the parameters of an electric power system to implement protective functions. The primary protective relays may communicate with various other supervisory devices such as automation systems, monitoring systems, supervisory (SCADA) systems, and other intelligent electronic devices (IEDs). IEDs may collect data from various devices within an electric power system and monitor, control, automate, and/or protect such devices.
Protective relays typically use voltage measurements to estimate system frequency and track frequency changes because voltages usually exhibit less waveform distortions (e.g., harmonic distortions) than currents; however, voltage measurements may not be available to some types of equipment (e.g., line sensors) or in some applications. When voltage signals are unavailable, the distortions in current signals may make frequency estimation and tracking more challenging.
The inventors of the present disclosure have recognized that the systems and methods disclosed herein may allow for improved tracking of an electric system by tracking system frequency using current measurements. In various embodiments, line sensors consistent with the present disclosure analyze zero crossing of a current signal to estimate periods and track the period changes. The estimated periods and period changes may be used to determine a data sampling period so that a specified number of samples per cycle can be obtained by a current sensor. The sampled data can then be used to compute a variety of quantities and for a wide range of applications such as fault current magnitude, fault direction, and high impedance fault detection, etc. The sampled data may be provided to a variety of equipment used to automate, monitor, and protect the power system, such as protective relays, IEDs, control systems, etc.
As used herein, an IED may refer to any microprocessor-based device that monitors, controls, automates, and/or protects monitored equipment within a system. Such devices may include, for example, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, remote terminal units, automation controllers, bay controllers, meters, recloser controls, communications processors, computing platforms, programmable logic controllers (PLCs), programmable automation controllers, input and output modules, and the like. The term IED may be used to describe an individual IED or a system comprising multiple IEDs. Further, IEDs may include sensors (e.g., voltage transformers, current transformers, contact sensors, status sensors, light sensors, tension sensors, etc.) that provide information about the electric power system.
The embodiments of the disclosure will be best understood by reference to the drawings. It will be readily understood that the components of the disclosed embodiments, as generally described and illustrated in the figures herein, could be arranged and designed in a wide variety of different configurations. Thus, the following detailed description of the embodiments of the systems and methods of the disclosure is not intended to limit the scope of the disclosure, as claimed, but is merely representative of possible embodiments of the disclosure. In addition, the steps of a method do not necessarily need to be executed in any specific order, or even sequentially, nor do the steps need to be executed only once, unless otherwise specified.
In some cases, well-known features, structures, or operations are not shown or described in detail. Furthermore, the described features, structures, or operations may be combined in any suitable manner in one or more embodiments. It will also be readily understood that the components of the embodiments, as generally described and illustrated in the figures herein, could be arranged and designed in a wide variety of different configurations. For example, throughout this specification, any reference to “one embodiment,” “an embodiment,” or “the embodiment” means that a particular feature, structure, or characteristic described in connection with that embodiment is included in at least one embodiment. Thus, the quoted phrases, or variations thereof, as recited throughout this specification are not necessarily all referring to the same embodiment.
Several aspects of the embodiments disclosed herein may be implemented as software modules or components. As used herein, a software module or component may include any type of computer instruction or computer-executable code located within a memory device that is operable in conjunction with appropriate hardware to implement the programmed instructions. A software module or component may, for instance, comprise one or more physical or logical blocks of computer instructions, which may be organized as a routine, program, object, component, data structure, etc., that performs one or more tasks or implements particular abstract data types.
In certain embodiments, a particular software module or component may comprise disparate instructions stored in different locations of a memory device, which together implement the described functionality of the module. A module or component may comprise a single instruction or many instructions and may be distributed over several different code segments, among different programs, and across several memory devices. Some embodiments may be practiced in a distributed computing environment where tasks are performed by a remote processing device linked through a communications network. In a distributed computing environment, software modules or components may be located in local and/or remote memory storage devices. In addition, data being tied or rendered together in a database record may be resident in the same memory device, or across several memory devices, and may be linked together in fields of a record in a database across a network.
Embodiments may be provided as a computer program product including a non-transitory machine-readable medium having stored thereon instructions that may be used to program a computer or other electronic device to perform processes described herein. The non-transitory machine-readable medium may include, but is not limited to, hard drives, floppy diskettes, optical disks, CD-ROMs, DVD-ROMs, ROMs, RAMs, EPROMs, EEPROMs, magnetic or optical cards, solid-state memory devices, or other types of media/machine-readable media suitable for storing electronic instructions. In some embodiments, the computer or another electronic device may include a processing device such as a microprocessor, microcontroller, logic circuitry, or the like. The processing device may further include one or more special-purpose processing devices such as an application-specific interface circuit (ASIC), PAL, PLA, PLD, field-programmable gate array (FPGA), or any other customizable or programmable device.
Substation 119 may include a generator 114, which may be a distributed generator, and which may be connected to bus 126 through step-up transformer 117. Bus 126 may be connected to a distribution bus 132 via a step-down transformer 130. Various distribution lines 136 and 134 may be connected to distribution bus 132. Load 140 may be fed from distribution line 136. Further, step-down transformer 144 in communication with distribution bus 132 via distribution line 136 may be used to step down a voltage for consumption by load 140.
Distribution line 134 may lead to substation 151 and deliver electric power to bus 148. Bus 148 may also receive electric power from distributed generator 116 via transformer 150. Distribution line 158 may deliver electric power from bus 148 to load 138 and may include further step-down transformer 142. Circuit breaker 160 may be used to selectively connect bus 148 to distribution line 134. IED 108 may be used to monitor and/or control circuit breaker 160 as well as distribution line 158.
Electric power delivery system 100 may be monitored, controlled, automated, and/or protected using IEDs, such as IEDs 104, 106, 108, 115, and 170, and a central monitoring system 172. In general, IEDs in an electric power generation and transmission system may be used for protection, control, automation, and/or monitoring of equipment in the system. For example, IEDs may be used to monitor equipment of many types, including electric transmission lines, electric distribution lines, current transformers, busses, switches, circuit breakers, reclosers, transformers, autotransformers, tap changers, voltage regulators, capacitor banks, generators, motors, pumps, compressors, valves, and a variety of other types of monitored equipment.
Central monitoring system 172 may comprise one or more of a variety of types of systems. For example, central monitoring system 172 may include a supervisory control and data acquisition (SCADA) system and/or a wide area control and situational awareness (WACSA) system. A central IED 170 may be in communication with IEDs 104, 106, 108, and 115. IEDs 104, 106, 108, and 115 may be remote from the central IED 170 and may communicate over various media such as a direct communication from IED 106 or over a wide-area communications network 162. According to various embodiments, certain IEDs may be in direct communication with other IEDs (e.g., IED 104 is in direct communication with central IED 170) or may be in communication via a communication network 162 (e.g., IED 108 is in communication with central IED 170 via communication network 162).
A common time signal 168 may be used to time-align measurements for comparison and/or synchronize action across system 100. Utilizing a common or universal time source may allow for the generation of time-synchronized data, such as synchrophasors. In various embodiments, the common time source may comprise a time signal from a GNSS system 190. IED 104 may include a receiver 192 configured to receive the time signal 168 from the GNSS system 190. In various embodiments, IED 106 may be configured to distribute the time signal 168 to other components in system 100, such as IEDs 104, 108, 115, and 170.
A voltage transformer 174 may be in communication with a merging unit (MU) 176. MU 176 may provide information from voltage transformer 174 to IED 115 in a format useable by IED 115. MU 176 may be placed near to voltage transformer 174 and may digitize discrete input/output (I/O) signals and analog data, such as voltage measurements. These data may then be streamed to IED 115. In various embodiments, MU 176 may be located outside of a substation enclosure or control house, thus increasing safety by removing high-energy cables from areas where personnel typically work. In various embodiments, MU 176 may be embodied as an SEL-2240 available from Schweitzer Engineering Laboratories of Pullman, Wash.
A variety of sensors, such as line sensor 180, may be distributed throughout system 100 to provide information regarding electrical conditions used for automation, monitoring, and protection. Line sensor 180 may track the frequency of alternating current through transmission line 158 to determine a data sampling period and obtain a specified number of samples per cycle. The sampled data may be provided to IED 108 or another device for use in a variety of applications, such as determining a fault current magnitude, determining a fault direction, and detecting a high impedance fault, etc.
A data sampling 302 block may obtain a specified number of samples per cycle (e.g., 8, 16, 32, 64 samples per cycle). Data sampling 302 block may be initialized with an estimated frequency equal to an electric power system's fundamental frequency (e.g., 50 Hz, 60 Hz), and may then use the techniques discussed below to determine the actual frequency of the system. In some embodiments, the data sampling frequency remains constant within a cycle and changes from cycle to cycle.
The current waveform input may be passed to a cosine filter 304 block. Cosine filter 304 block may remove distortions (e.g., DC components, harmonic distortions, etc.) of the alternating current signal without affecting the fundamental frequency of the signal. The elimination of such distortions may reduce or eliminate spurious zero crossings that may be used in generating an estimate of the frequency. Various numbers of taps may be used by cosine filter 304 block (e.g., 8, 16, 32, or 64 taps). Although a cosine filter is illustrated in
A period estimation 306 block may generate an estimate of the period of the current based on the sampled and filtered data. In various embodiments, period estimation 306 block may estimate the period using zero crossings of the signal and linear interpolation. Period estimation 306 block may use either rising or falling zero crossings. One advantage of using zero crossings is that the system does not require a high-precision time source to accurately determine the frequency using the techniques disclosed herein.
A frequency discrimination 308 block may selectively discard sudden changes in frequency. In various embodiments, frequency discrimination 308 block may compare a change in the frequency to a threshold. If the change is less than the threshold, the estimated period may be used in a subsequent iteration, but if the change exceeds the threshold, frequency discrimination 308 block may discard the estimated period and instead use a prior frequency value as illustrated by arrow 316.
A filter 310 block may smooth the output of the period according to specific response criteria. Frequency in an electric power system changes smoothly due to a variety of factors (e.g., spinning inertia associated with various types of generation). Filter 310 block may ensure that the changes reflect constraints on frequency changes in physical systems. In some embodiments, filter 310 block is implemented using an infinite impulse response filter or a finite impulse response filter. In other embodiments, filter 310 block is implemented using an Olympic Filter, which rejects the largest and smallest measurements and averages the remaining measurements.
A frequency 312 block may convert the period of the current waveform to a frequency measurement using the reciprocal relationship between period and frequency. The frequency may be an output used by other systems to monitor, automate, and/or protect an electric power system.
The frequency may also be used in a feedback loop by in data flow 300. In the illustrated embodiment, the frequency is filtered by filter 314 block before being fed back into data sampling 302 block. Filter 314 block may smooth adjustments of the sampling rate used by data sampling 302 block. In some embodiments, the filtering performed by cosine filter 304 block, filter 310 block, and filter 314 block may be accomplished using a filter subsystem or filter module.
Frequency discrimination may increase the accuracy of frequency tracking by eliminating distortions. Distortions may be severe as a result of saturation. Saturation may occur as a result of a fault that causes a sudden change in current. In such a scenario, a frequency determined just prior to the fault may be used. Various parameters associated with a fault, such as magnitude estimation, may be estimated based on a frequency determined before the fault.
A sampling interval, Dn, may be established and used for each cycle. Each sampling interval is identified in
For example, where the estimated frequency is 60, and the number of samples per cycle is 32, the sampling interval is 5.20
For each period, a time interval, Tn, may be determined between a first rising zero crossing and a subsequent rising zero crossing. The time intervals for the four cycles (i.e., T1, T2, T3, and T4) are shown in
Additional points 512, 514 associated with a second zero crossing may also be identified, with point 512 being below zero and point 514 being above zero. A time interval 516 between point 516 and the zero crossing, which is designated with a “Y” may be determined, along with a time interval 518 between the zero crossing and point 514. Time interval 518 may be designated where D1 is the sampling rate in the current period.
The time intervals determined using interpolation may be used to estimate the period in some embodiments. In such embodiments, the period may be calculated using Eq. 2, where N is the number of samples per period.
Period=(N−1)*D1+D0−t2+D1−t1 Eq. 2
The period determined using Eq. 2 may yield a better estimate than simply relying on the product of the sampling interval and the number of samples per period (i.e., Tn=Dn*N), as discussed above. The period determined using Eq. 2 may also be used to determine a frequency using the reciprocal relationship between period and frequency.
At 604, the current waveform may be sampled at an estimated frequency to generate a sampled current waveform. During an initial period, the estimated frequency may equal the nominal frequency of an electric power system (e.g., 60 Hz, 50 Hz). After an initial period, the estimated frequency may be updated at a specified interval (e.g., once per half-cycle, once per cycle, once every two cycles, etc.). The sampled current waveform may be used for various functions, such as determining a fault current magnitude, a determining fault direction, and detecting a high impedance fault, etc.
At 606, the sampled current waveform may be filtered to generate a filtered and sampled current waveform. The filter may smooth out distortions of the current signal and eliminate the spurious zero crossings. Various embodiments consistent with the present disclosure may use cosine filters or other techniques to achieve similar results.
At 608, a period of the filtered and sampled current waveform may be determined. In various embodiments, the period is determined using zero crossings of the waveform, as illustrated and described in connection with
At 610, it may be determined whether the period determined at 608 satisfies a threshold. If the change is less than the threshold, the estimated period may be used in a subsequent iteration. If the change exceeds the threshold, the period may be discarded and a previously determined period may be used at 612.
At 614, a period estimate may be up updated, using either the period determined at 608 or using a previously determined period. In some embodiments, the period estimate may be used to set a schedule for transitioning between a power-saving mode and an active mode to save power. In such embodiments, an interrupt may be set based on the sampling interval to ensure that a system implementing method 600 is active at the time a measurement is to be made. The sampling interval may be periodically adjusted, and an appropriate schedule of interrupts may be set to wake the system from a power-saving mode in time for each measurement.
At 616, a frequency may be determined based on the period estimate. The frequency may be determined using the reciprocal relationship between period and frequency. In some embodiments, filtering may also be performed to smooth fluctuations in frequency. Such smoothing may reflect physical constraints of electric power systems that resist rapid changes in frequency.
At 618, a frequency estimate may be updated and method 600 may repeat using the updated frequency estimate. Method 600 may repeat at various intervals (e.g., twice per cycle, once per cycle, once every two cycles, etc.).
Line-mounted current sensor 720 is mounted to conductor 754, which is suspended between pylons 750, 752. Only a single line-mounted wireless current sensor 720 is illustrated. In other embodiments, multiple line-mounted current sensors may be used, or IED 730 may assume that the current on other phases are the same magnitude as the first current but shifted in phase (i.e., shifted by 120 degrees in a three-phase system).
Line-mounted current sensor 720 and IED 730 each contain various subsystems represented by functional blocks. The functional blocks in line-mounted current sensor 720 may communicate using data bus 724, and the functional blocks in IED 730 may communicate using data bus 748.
A communication subsystem 712 may be configured to communicate information, such as sampled current measurements obtained by line-mounted current sensor 720, to IED 730. Wireless communication subsystem 712 may utilize various technologies to enable wireless communication. Such communication may include radio frequency communications and may employ analog or digital modulation techniques and protocols. Wireless communication subsystem 712 may enable transmission of data from line-mounted current sensor 720 related to electrical parameters associated with conductor 754. In some embodiments, communication subsystem 712 may enable bi-directional communication between line-mounted current sensor 720 and IED 730, while in other embodiments, communication may be unidirectional.
A current sensor 714 may obtain a current waveform representing current flowing through conductor 754. Current sensor 714 may be embodied as a current transformer, a Rogowski coil, a hall effect sensor, a flux gate sensor, a magneto-resistive current sensor, or other current-sensing device. The measurements obtained by current sensor 714 may be subject to substantial distortion, including the types of distortions illustrated in
A power harvesting subsystem 722 may harvest power from conductor 754. In some embodiments, power harvesting subsystem 722 may utilize a current transformer to harvest energy from conductor 754. In various embodiments, the current transformer used to harvest power from conductor 754 may also provide a signal that is analyzed and used to obtain electrical parameter measurements from conductor 754. Power harvesting subsystem 722 may further incorporate a power storage device that may be used to transmit information when current is not flowing through conductor 754 and power cannot be harvested. A power storage device may be embodied as a battery, a supercapacitor, and the like. Line-mounted current sensor 720 may reduce the need for ongoing maintenance associated with devices powered with batteries.
A data sampling subsystem 718 may be configured to obtain data samples from a current waveform representing current flowing through conductor 754. Data sampling subsystem 718 may obtain a specified number of samples per cycle (e.g., 8, 16, 32, 64 samples per cycle). Data sampling subsystem 718 may be initialized with an estimated frequency equal to an electric power system's fundamental frequency (e.g., 50 Hz, 60 Hz.), and may then use the techniques discussed below to determine the actual frequency of the system. In some embodiments, the data sampling frequency remains constant within a cycle and changes from cycle to cycle. In other embodiments, the sampling frequency may be changed with more frequency (e.g., every half cycle) or less frequency (e.g., every two cycles).
A period and frequency subsystem 728 may generate an estimate of an alternating current period and frequency. In various embodiments, period and frequency subsystem 728 may estimate the period using zero crossings of the current signal. In some embodiments, the time of the zero crossings may be estimated using linear interpolation. Period and frequency subsystem 728 may determine a frequency using a period based on the reciprocal relationship between period and frequency. Period and frequency subsystem 728 may also implement frequency discrimination, which is illustrated as block 308 in
A filter subsystem 726 may filter the current waveform generated by current sensor 714 and/or the estimates of period and frequency generated by the period and frequency subsystem 728. Filter subsystem 726 may implement various types of filters (e.g., cosine filters, Olympic filters, FIR filters, IIR filters, etc.). In various embodiments, filter subsystem 726 may implement cosine filter 304, filter 310, and filter 314 illustrated in
A memory 716 may include computer system readable media in the form of volatile memory, such as random access memory (RAM) and/or cache memory. The memory 716 may further include other removable/non-removable, volatile/non-volatile computer system storage media. In various embodiments, the memory 716 may include at least one program product having a set of program modules that are configured to carry out the functions described herein.
A processing subsystem 710 may be configured to process information received from the data sampling subsystem 718, the wireless communication subsystem 712, and the memory 716. Processing subsystem 710 may operate using any number of processing rates and architectures. Processing subsystem 710 may be configured to perform various algorithms and calculations described herein. Processing subsystem 710 may be embodied as a general-purpose integrated circuit, an application-specific integrated circuit, a field-programmable gate array, and/or any other suitable programmable logic device.
Turning now to the functional blocks associated with IED 730, a monitored equipment subsystem 732 may be in communication with monitored equipment that is operable to control an aspect or a portion of an electric power system. The monitored equipment subsystem 732 may be configured to issue commands to and/or receive status information from monitored equipment. In certain embodiments, monitored equipment subsystem 732 may be in communication with, for example, a circuit breaker and may issue commands to the circuit breaker to selectively connect or disconnect portions of the electric power system.
Memory 746 may include computer system readable media in the form of volatile memory, such as random access memory (RAM) and/or cache memory. The memory 746 may further include other removable/non-removable, volatile/non-volatile computer system storage media. In various embodiments, the memory 746 may include at least one program product having a set of program modules.
Processing subsystem 736 may be configured to perform various algorithms and calculations described herein. In various embodiments, processing subsystem 736 may be embodied as a general-purpose integrated circuit, an application-specific integrated circuit, a field-programmable gate array, and/or any other suitable programmable logic device.
Wireless communication subsystem 738 may receive information from and/or send information to line-mounted current sensor 720. Wireless communication subsystem 738 may be compatible with the wireless communication subsystem 712, utilizing the same communication technology and communication protocol(s). In various embodiments, IED 730 may also comprise other communication interfaces (e.g., a wired communication interface) to communicate with other devices, such as other IEDs, a SCADA system, etc.
A control action subsystem 742 may implement control actions based on information received from line-mounted current sensor 720 and other electrical parameters associated with an AC signal on conductor 754. In some embodiments, control action subsystem 742 may control a circuit breaker, which may be selectively activated and deactivated based on electrical conditions. Control action subsystem 742 may issue commands to selectively connect and disconnect portions of an electric power system using monitored equipment subsystem 732.
While specific embodiments and applications of the disclosure have been illustrated and described, it is to be understood that the disclosure is not limited to the precise configurations and components disclosed herein. Accordingly, many changes may be made to the details of the above-described embodiments without departing from the underlying principles of this disclosure. The scope of the present invention should, therefore, be determined only by the following claims.
