WO2013115908A1 - Systems and methods for blackout protection - Google Patents
Systems and methods for blackout protection Download PDFInfo
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- WO2013115908A1 WO2013115908A1 PCT/US2012/068962 US2012068962W WO2013115908A1 WO 2013115908 A1 WO2013115908 A1 WO 2013115908A1 US 2012068962 W US2012068962 W US 2012068962W WO 2013115908 A1 WO2013115908 A1 WO 2013115908A1
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- load
- leds
- information
- generation
- generator
- Prior art date
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Classifications
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- G—PHYSICS
- G05—CONTROLLING; REGULATING
- G05D—SYSTEMS FOR CONTROLLING OR REGULATING NON-ELECTRIC VARIABLES
- G05D17/00—Control of torque; Control of mechanical power
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- H—ELECTRICITY
- H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
- H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
- H02J3/00—Circuit arrangements for ac mains or ac distribution networks
- H02J3/007—Arrangements for selectively connecting the load or loads to one or several among a plurality of power lines or power sources
- H02J3/0073—Arrangements for selectively connecting the load or loads to one or several among a plurality of power lines or power sources for providing alternative feeding paths between load and source when the main path fails, e.g. transformers, busbars
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- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06F—ELECTRIC DIGITAL DATA PROCESSING
- G06F1/00—Details not covered by groups G06F3/00 - G06F13/00 and G06F21/00
- G06F1/26—Power supply means, e.g. regulation thereof
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- H—ELECTRICITY
- H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
- H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
- H02J3/00—Circuit arrangements for ac mains or ac distribution networks
- H02J3/003—Load forecast, e.g. methods or systems for forecasting future load demand
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- H—ELECTRICITY
- H02—GENERATION; CONVERSION OR DISTRIBUTION OF ELECTRIC POWER
- H02J—CIRCUIT ARRANGEMENTS OR SYSTEMS FOR SUPPLYING OR DISTRIBUTING ELECTRIC POWER; SYSTEMS FOR STORING ELECTRIC ENERGY
- H02J3/00—Circuit arrangements for ac mains or ac distribution networks
- H02J3/38—Arrangements for parallely feeding a single network by two or more generators, converters or transformers
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- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02B—CLIMATE CHANGE MITIGATION TECHNOLOGIES RELATED TO BUILDINGS, e.g. HOUSING, HOUSE APPLIANCES OR RELATED END-USER APPLICATIONS
- Y02B70/00—Technologies for an efficient end-user side electric power management and consumption
- Y02B70/30—Systems integrating technologies related to power network operation and communication or information technologies for improving the carbon footprint of the management of residential or tertiary loads, i.e. smart grids as climate change mitigation technology in the buildings sector, including also the last stages of power distribution and the control, monitoring or operating management systems at local level
- Y02B70/3225—Demand response systems, e.g. load shedding, peak shaving
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- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
- Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
- Y04S10/00—Systems supporting electrical power generation, transmission or distribution
- Y04S10/50—Systems or methods supporting the power network operation or management, involving a certain degree of interaction with the load-side end user applications
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
- Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
- Y04S10/00—Systems supporting electrical power generation, transmission or distribution
- Y04S10/50—Systems or methods supporting the power network operation or management, involving a certain degree of interaction with the load-side end user applications
- Y04S10/52—Outage or fault management, e.g. fault detection or location
-
- Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y04—INFORMATION OR COMMUNICATION TECHNOLOGIES HAVING AN IMPACT ON OTHER TECHNOLOGY AREAS
- Y04S—SYSTEMS INTEGRATING TECHNOLOGIES RELATED TO POWER NETWORK OPERATION, COMMUNICATION OR INFORMATION TECHNOLOGIES FOR IMPROVING THE ELECTRICAL POWER GENERATION, TRANSMISSION, DISTRIBUTION, MANAGEMENT OR USAGE, i.e. SMART GRIDS
- Y04S20/00—Management or operation of end-user stationary applications or the last stages of power distribution; Controlling, monitoring or operating thereof
- Y04S20/20—End-user application control systems
- Y04S20/222—Demand response systems, e.g. load shedding, peak shaving
Definitions
- This disclosure relates to systems and methods for controlling and protecting an electric power delivery system and, more particularly, to systems and methods for wide-area under-frequency blackout protection in an electric power delivery system.
- Figure 1 illustrates a simplified diagram of one embodiment of an electric power delivery system that includes intelligent electronic devices.
- Figure 2 illustrates a block diagram of one embodiment of an intelligent electronic device for protection and control of an electric power delivery system
- Figure 3 illustrates another block diagram of one embodiment of an intelligent electronic device for protection and control of an electric power delivery system.
- Figure 4 illustrates one embodiment of a method for protection and control of an electric power delivery system.
- Figure 5 illustrates another embodiment of a method for protection and control of an electric power delivery system that utilizes rotating inertia information from the system.
- 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.
- 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.
- software modules or components may be located in local and/or remote memory storage devices.
- 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 medium suitable for storing electronic instructions.
- the computer or other 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
- Electrical power generation and delivery systems are designed to generate, transmit, and distribute electrical energy to loads.
- Electrical power generation and delivery systems may include equipment, such as electrical generators, electrical motors, power transformers, power transmission and distribution lines, circuit breakers, switches, buses, transmission lines, voltage regulators, capacitor banks, and the like.
- equipment may be monitored, controlled, automated, and/or protected using intelligent electronic devices (lEDs) that receive electric power system information from the equipment, make decisions based on the information, and provide monitoring, control, protection, and/or automation outputs to the equipment.
- lEDs intelligent electronic devices
- an IED may include, for example, remote terminal units, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, automation controllers, bay controllers, meters, recloser controls, communication processors, computing platforms, programmable logic controllers (PLCs), programmable automation controllers, input and output modules, governors, exciters, statcom controllers, SVC controllers, OLTC controllers, and the like.
- PLCs programmable logic controllers
- lEDs may be communicatively connected via a network that includes, for example, multiplexers, routers, hubs, gateways, firewalls, and/or switches to facilitate communications on the networks, each of which may also function as an IED.
- Networking and communication devices may also be integrated into an IED and/or be in communication with an IED.
- an IED may include a single discrete IED or a system of multiple lEDs operating together.
- an IED may be configured to protect the electrical power system equipment from abnormal conditions, such as when the power generation capabilities of the electrical power system cannot adequately supply system loads. Under this unbalanced system condition, power loss or blackouts may occur that negatively affect both providers of electric power and their customers. Consistent with embodiments disclosed herein, an IED may utilize techniques to minimize blackout conditions on a larger portion of the electric power delivery system such as under-frequency (UF) load shedding techniques and over-frequency (OF) generation shedding or run-back techniques.
- UF under-frequency
- OF over-frequency
- Power imbalances in an electrical power delivery system may be associated with a fall (or rise) in the frequency of the electrical power system fundamental voltage. Consistent with embodiments disclosed herein, when a threshold UF (or OF) level is crossed, loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system. By shedding selective loads, shedding generators, or running back generators or other active power producing power system components and rebalancing the system, the negative effects of unbalanced system conditions may be mitigated.
- loads may be disconnected (e.g., shed) from the electrical power system or generators or other active power producing components on the electric power system may be shed or run-back to rebalance the system.
- Figure 1 illustrates a simplified diagram of an electric power generation and delivery system 100 that includes lEDs 102-108 consistent with embodiments disclosed herein. Although illustrated as a one-line diagram for purposes of simplicity, electrical power generation and delivery system 100 may also be configured as a three phase power system. Moreover, embodiments disclosed herein may be utilized by any electric power generation and delivery system and is therefore not limited to the specific system 100 illustrated in Figure 1. Accordingly, embodiments may be integrated, for example, in industrial plant power generation and delivery systems, deep-water vessel power generation and delivery systems, ship power generation and delivery systems, distributed generation power generation and delivery systems, and utility electric power generation and delivery systems.
- the electric power generation and delivery system 100 may include generation, transmission, distribution, and power consumption equipment.
- the system 100 may include one or more generators 1 10 -1 16 that, in some embodiments, may be operated by a utility provider for generation of electrical power for the system 100.
- Generators 1 10 and 1 12 may be coupled to a first transmission bus 1 18 via step up transformers 120 and 122, which are respectively configured to step up the voltages provided to first transmission bus 1 18.
- a transmission line 124 may be coupled between the first transmission bus 1 18 and a second transmission bus 126.
- Another generator 1 14 may be coupled to the second transmission bus 126 via step up transformer 128 which is configured to step up the voltage provided to the second transmission bus 126.
- Generators may refer to any equipment capable of supplying electric power on an electric power delivery system, and may include, for example, rotating synchronous or induction machines or other electronic power producing equipment with an inverter capable of supplying electric power (photovoltaic, wind power, battery, and the like).
- a step down transformer 130 may be coupled between the second
- the transmission bus 126 and a distribution bus 132 configured to step down the voltage provided by the second transmission bus 126 at transmission levels to lower distribution levels at the distribution bus 132.
- One or more feeders 134, 136 may draw power from the distribution bus 132.
- the feeders 134, 136 may distribute electric power to one or more loads 138, 140.
- the electric power delivered to the loads 138, 140 may be further stepped down from distribution levels to load levels via step down transformers 142 and 144, respectively.
- Feeder 134 may feed electric power from the distribution bus 132 to a distributed site 146 (e.g., a refinery, smelter, paper production mill, or the like). Feeder 134 may be coupled to a distribution site bus 148.
- the distribution site 146 may also include a distributed generator 1 16 configured to provide power to the distribution site bus 148 at an appropriate level via transformer 150.
- the distributed generator 1 16 may comprise a turbine configured to produce electric power from the burning of waste, the use of waste heat, or the like.
- the distribution site 146 may further include one or more loads 138. In some embodiments, the power provided to the loads 138 from the distribution site bus 148 may be stepped up or stepped down to an appropriate level via transformer 142.
- the distribution site 146 may be capable of providing sufficient power to loads 138 independently by the distributed generator 1 16, may utilize power from generators 1 10-1 14, or may utilize both the distributed generator 1 16 and one or more of generators 1 10-1 14 to provide electric power to the loads.
- lEDs 102-108 may be configured to control, monitor, protect, and/or automate the electric power system 100.
- an IED may refer to any microprocessor-based device that monitors, controls, automates, and/or protects monitored equipment within an electric power system.
- An IED may include, for example, remote terminal units, differential relays, distance relays, directional relays, feeder relays, overcurrent relays, voltage regulator controls, voltage relays, breaker failure relays, generator relays, motor relays, automation controllers, bay controllers, meters, recloser controls, communications processors, computing platforms,
- lEDs 102-108 may gather status information from one or more pieces of monitored equipment.
- lEDs 102-108 may receive information concerning monitored equipment using sensors, transducers, actuators, and the like.
- Figure 1 illustrates separate lEDs monitoring a signal (e.g., IED 104) and controlling a breaker (e.g., IED 108), these capabilities may be combined into a single IED.
- Figure 1 illustrates various lEDs 102-108 performing various functions for illustrative purposes and does not imply any specific arrangements or functions required of any particular IED.
- lEDs 102-108 may be
- lEDs 102-108 may be configured to monitor and communicate information, such as voltages, currents, equipment status, temperature, frequency, pressure, density, infrared absorption, radio- frequency information, partial pressures, viscosity, speed, rotational velocity, mass, switch status, valve status, valve position, exciter status, magnetic flux conditions, circuit breaker status, tap status, meter readings, and the like. Further, lEDs 102-108 may be configured to communicate calculations, such as phasors (which may or may not be synchronized as synchrophasors), events, fault distances, differentials, impedances, reactances, frequency, and the like. lEDs 102-108 may also
- monitored system data Information of the types listed above, or more generally, information about the status of monitored equipment, may be generally referred to herein as monitored system data.
- lEDs 102-108 may issue control instructions to the monitored equipment in order to control various aspects relating to the monitored equipment.
- an IED e.g., IED 106
- a circuit breaker e.g., breaker 152
- an IED may be in communication with a recloser and capable of controlling reclosing operations.
- an IED may be in communication with a voltage regulator and capable of instructing the voltage regulator to tap up and/or down.
- an IED may be in communication with a synchronous generator exciter to raise or lower field current, voltage, and/or flux conditions.
- an lED may be in communication with a generator speed governor or other electronic devices to modify the position of fuel valves, air louvers, condensing or extraction valves, steam bypass valves, compressor speeds, hydraulic pilot valves.
- Information of the types listed above, or more generally, information or instructions directing an lED or other device to perform a certain action, may be generally referred to as control instructions.
- the distribution site 146 may include an lED 108 for monitoring, controlling, and protecting the equipment of the distributed site 146 (e.g., generator 1 16, transformer 142, etc.).
- IED 108 may receive monitored system data, including current signals via current transformer (CT) 154 and voltage signals via potential transformer (PT 156) from one or more locations (e.g., line 158) in the distribution site 146.
- CT current transformer
- PT 156 potential transformer
- the IED 108 may further be in communication with a breaker 160 coupled between the feeder 134 and the distribution site bus 148.
- the IED 108 may be configurable to cause the breaker 160 to disconnect the distribution site bus 148 from the distribution bus 132, based on monitored system data received via CT 154 and PT 156.
- Feeder 136 may be communicatively coupled with an IED 106 configured to control a breaker 152 between the loads 140 and the distribution bus 132 based on monitored system data.
- the power provided to the loads 140 from the distribution bus 132 may be stepped up or stepped down to an appropriate level via transformer 144.
- monitored system data may be obtained by IED 106 using CTs and/or PTs (not shown).
- IEDs may be configured to monitor, control, and/or protect the electric power generation and delivery system 100.
- IED 104 may provide transformer and generator protection to the step-up transformer 120 and generator 1 10.
- lEDs 104-108 may be in communication with another IED 102, which may be a central controller, synchrophasor vector processor, automation controller, programmable logic controller (PLC), real-time automation controller, Supervisory Control and Data Acquisition (SCADA) system, or the like.
- IED 102 may be a synchrophasor vector processor, as described in U.S. Patent Application Publication No. 2009/0088990, which is
- IED 102 may be a real-time automation controller, such as is described in U.S. Patent Application Publication No. 2009/0254655, which is incorporated herein by reference in its entirety. IED 102 may also be a PLC or any similar device capable of receiving communications from other lEDs and processing the communications therefrom. In certain embodiments,
- lEDs 104-108 may communicate with IED 102 directly or via a
- communications network e.g., network 162.
- the central IED 102 may communicate with other lEDs 104-108 to provide control and monitoring of the other lEDs 104-108 and the power generation and delivery system 100 as a whole.
- lEDs 104-108 may be configured to generate monitored system data in the form of time-synchronized phasors (i.e., synchrophasors) of monitored currents and/or voltages.
- lEDs 104-108 may calculate synchrophasor data using a variety of methods including, for example, the methods described in U.S. Patent No. 6,662,124, U.S. Patent No. 6,845,333, and U.S. Patent No. 7,480,580, which are herein incorporated by reference in their entireties.
- synchrophasor measurements and communications may comply with the IEC C37.1 18 protocol.
- lEDs 102-108 may receive common time signals for synchronizing collected data (e.g., by applying time stamps for the like). Accordingly, lEDs 102-108 may receive common time signals from time references 164-170 respectively.
- the common time signals may be provided using a GPS satellite (e.g., IRIG), a common radio signal such as WWV or WWVB, a network time signal such as IEEE 1588, or the like.
- lEDs 102-108 may be configured to determine a power system operating frequency from monitored system data.
- the operating frequency of the power system may be determined using many methods including, for example, measuring time between zero-crossings of voltage and/or current, measuring positive-sequence phasor rotations, measuring time between period voltage and/or current peaks, and/or the like.
- lEDs 102-108 may be further configured to indicate when an operating frequency falls below a predetermined level.
- an IED may have a number of different UF levels and may indicate when an operating frequency falls below one or more of the UF levels.
- FIG. 2 illustrates a block diagram of an IED 200 for protection and control of an electric power delivery system (e.g., system 100 illustrated in Figure 1 ).
- IED 200 may communicate with one or more lEDs 222 configured to provide indications of UF events (e.g., when system operating frequencies fall below one or more UF levels) to IED 200.
- lEDs 222 may receive monitored system data and, based on the monitored system data, provide indications of UF events such as when measured operating frequencies fall below one or more UF levels to the IED 200.
- lEDs 222 may be programmed with a predetermined UF set point (e.g., level) and be configured to provide time synchronized indications of UF events to the IED 200.
- lEDs 222 may include one or more set points (e.g., levels) and be configured to provide time synchronized indications of UF events (e.g., when one or more of the set points are crossed) to the IED 200.
- lEDs 222 may indicate the UF set point (e.g., level) breached, a time indication of the UF event, the power consumed by a load associated with the IED, and/or synchrophasor data which may include a load angle.
- IED 200 may determine whether specific loads are exhibiting UF events and whether such loads can be disconnected (e.g., shed) to limit and/or avoid UF events and systems disturbances. This functionality may be achieved using one or more functional modules 202-220 included in the IED 200. For example, indications of UF events (e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the lEDs 222, and/or synchrophasor data) detected by lEDs 222 may be provided to a UF level array calculation module included in the IED 200.
- indications of UF events e.g., breached UF set points, time indications of UF events, power consumed by loads associated with the lEDs 222, and/or synchrophasor data
- UF level array calculation module 208 may be configured to order UF events and their associated information based on time stamps indicating when the UF events were received by their associated lEDs 222 (e.g., UF events may be ordered based on their time of occurrence). Information from the UF level array calculation module 208, including one or more ordered UF events may be provided to a coinciding UF level event calculation module 206. The UF level event calculation module 206 may be configured to determine whether the one or more UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on the time stamps associated with the one or more UF events.
- the UF level event calculation module 206 may determine that a particular set of UF events ordered by the UF level array calculation module 208 are associated with a larger system UF event based on their occurrence within a particular time period (e..g, a 10 ms period). Based on the UF events occurring within a particular time period, the UF level array calculation module 208 may determine that the loads associated with the UF events are associated with a power sub-grid experiencing a UF condition and provide this information to a load reduction calculation module 204.
- the IED 200 may also include a user adjustable parameter module 202 that, in some embodiments, includes parameters defining an amount of load to be shed for a particular UF-level.
- the amount of load to be shed may be in the form of a power/frequency value (e.g., MW/Hz).
- Information regarding the amount of load to be shed for a particular UF-level may be provided to the load reduction calculation module 204.
- the load reduction calculation module 204 may also utilize information regarding the UF events provided by the UF level array calculation module 208 and UF level event calculation module 206, including time indications of UF events and indications of UF set points breached. Based on the information received by the load reduction calculation module 204, the load reduction calculation module 204 may determine an amount of load to shed (e.g., the amount of load to shed from the system measured in MW) based on the defined user parameters and the other received UF event information.
- an amount of load to shed e.g., the amount of load to shed from the system measured in MW
- lEDs 222 may be further configured to monitor the power consumed by the loads they are associated with. Information regarding the power consumed by loads associated with the lEDs 222 may be monitored in terms of power (e.g., MW) or other coupled parameters such as current.
- IED 106 may be capable of monitoring the power consumed by loads 140
- IED 108 may be capable of indicating the power presented consumed by the distributed site 146.
- information regarding the power consumed by loads may be provided to a power array calculation module 212 included in the IED 200.
- the power array calculation module 212 may calculate a power consumption value for each load (e.g., by using parameters coupled to power consumption such as current). Further, the power array calculation module 212 may sort and/or order specific loads based on their associated power consumption.
- the user adjustable parameter module 202 may include a parameter that includes a priority indication for loads associated with the lEDs 222.
- the priority indication may include a priority queue indicating the order in which loads should be shed from the system in the event of an UF condition. Accordingly, the priority indication may indicate certain loads (e.g., a hospital) that should stay
- the information generated by the power array calculation module 212 may be provided to a load shedding selection module 210 included in the IED 200 along with the priority indication provided by the user adjustable parameter module 202.
- the load shedding selection module 210 may further receive information related to an amount of load to shed from the load reduction calculation module 204. Based on the received information (e.g., the amount of load to shed, the priority of the loads, and the amount of power consumed by the loads), the load shedding selection module 210 may determine which loads should be shed to reduce the effects of the detected UF event in the system. That is, the load shedding selection module 210 may match the amount of power to shed with the power used by each of the loads, prioritized by the priority information, and determine which loads to shed.
- the IED 200 may include a load shedding control module 214 configured to receive an indication from the load shedding selection module 210 of which loads should be shed and provide a control signal to the lEDs 222 associated with the loads that should be shed directing the lEDs 222 to shed (e.g., disconnect) the relevant loads from the system.
- the load shedding selection module 210 may determine that loads 140 should be shed, and the load shedding control module 214 may direct the IED 106 associated with the loads 140 to trip breaker 152, thereby disconnecting the loads from the system 100.
- Information regarding power sub-grids within a greater grid topology of an electric power delivery system may also be used by the IED 200 to calculate which loads should be shed in view of UF conditions.
- lEDs 222 may provide load angle information (e.g., synchrophasor information) to a phase angle array calculation module 220 included in the IED 200.
- load angle information e.g., synchrophasor information
- equipment ⁇ e.g., loads) associated with a certain power sub-grid of the electric power generation and delivery system may experience similar frequency decay rates when the system experiences an UF condition.
- equipment associated with different power sub-grids may experience different frequency decay rates when the system experiences an UF.
- the probability of both sub-grids experiencing the same frequency decay rate in a system UF condition is low.
- the frequency in one sub-grid may increase while the frequency in the other sub-grid may decrease.
- the frequency decays will likely reach set UF threshold levels at differing times.
- the IED 200 may determine that the loads are associated with a particular power sub-grid.
- IED 200 and its associated modules 202-220 may determine which loads are associated with a particular power sub-grid based on the methods described in U.S. Patent Application Publication No. 2009/0089608 which is herein incorporated by reference in its entirety.
- lEDs 222 may communicate time-synchronized load phase measurements to IED 200 using, for example, the IEC C38.1 18 protocol. Load angles measured by the lEDs 222 may be provided to the phase angle array calculation module 220 that, in some embodiments, may store such information. The phase angle array calculation module 220 may provide the measured load angles to a sub-grid detection module 218. Based on the measured load angles, the sub-grid detection module 218 may determine whether loads associated with the lEDs 222 are associated with particular sub-grids.
- Information regarding which loads are associated with particular sub-grids may be provided to a sub-grid and priority based load selection module 216.
- the sub- grid and priority based load selection module 216 may also receive the parameter that includes a priority indication for loads associated with the lEDs 222 from the user adjustable parameter module 202. Additionally, the sub-grid and priority based load selection module 216 may receive an indication of the amount of load to be shed from the load reduction calculation module 204.
- the sub-grid and priority based load selection module 216 may determine which loads should be shed by the system to reduce the effects of UF conditions. This information may be provided by the sub-grid and priority based load selection module 216 to the load shedding control module 214. The load shedding control module 214 may then use this information in conjunction with the information received from the load shedding selection module 210 to determine which loads should be shed and direct the load shedding control module 214.
- the modules 202-220 included in IED 200 may be implemented in a programmable IED system.
- the functionality of IED 200 may be achieved using a synchrophasor vector process (e.g., the SEL-3378 available from Schweitzer Engineering Laboratories, Inc.) or a real-time automation controller (e.g., the SEL-3530 available from Schweitzer Engineering Laboratories, Inc.).
- FIG. 3 illustrates another block diagram of an IED 300 for protection and control of an electric power delivery system.
- IED 300 may include a processor 302, a random access memory (RAM) 304, a communications interface 306, a user interface 308, and a non-transitory computer-readable storage medium 310.
- the processor 302, RAM 304, communications interface 306, user interface 308, and computer-readable storage medium 310 may be communicatively coupled to each other via a common data bus 312.
- the various components of IED 300 may be implemented using hardware, software, firmware, and/or any combination thereof.
- the user interface 308 may be used by a user to enter user defined settings such as, for example, an amount of load to shed for each event level, load priority information, and the like (e.g., the parameters included in the user adjustable parameter module 202 of Figure 2).
- the user interface 308 may be integrated in the IED 300 or, alternatively, may be a user interface for a laptop or other similar device
- Communications interface 306 may be any interface capable of communicating with lEDs and/or other electric power system equipment communicatively coupled to IED 300.
- communications interface 306 may be a network interface capable of receiving communications from other lEDs over a protocol such as the IEC 61850 or the like.
- communications interface 306 may include a fiber-optic or electrical communications interface for communicating with other lEDs.
- the processor 302 may include one or more general purpose processors, application specific processors, microcontrollers, digital signal processors, FPGAs, or any other customizable or programmable processing device.
- the processor 302 may be configured to execute computer-readable instructions stored on the computer- readable storage medium 310.
- the computer-readable instructions may be computer executable functional modules configured to implement certain systems and methods disclosed herein when executed by the processor.
- the computer-readable instructions may include an UF load shedding module 314 configured to cause the processor to perform the UF load shedding operations and a time alignment module 316 used time-aligning and coordinating various
- the computer-readable instructions may also include any of the functional modules described in reference to Figure 2 to implement the functionality of the IED 300 described therein.
- FIG. 4 illustrates one embodiment of a method 400 for protection and control of an electric power delivery system.
- a central IED may receive system information from a remote lEDs each associated with a load.
- the system information may include information relating to the operating frequencies of the loads, the power consumption of the loads, synchrophasor information, an indication that an operating frequency of a load has reached a predetermined level, and the like.
- the central IED may determine which loads are associated with a particular sub-grid of the electric power delivery system experiencing an UF condition.
- determining which loads are associated with a particular sub-grid of the electric power delivery system is based on the decay rates and/or decay times of operating frequencies of the loads.
- the central IED may determine whether to disconnect one or more loads associated with the sub-grid from the electric power delivery system to mitigate the UF condition, sending a signal to lEDs associated with the one or more loads directing the lEDs to disconnect the loads.
- determining which loads to disconnect from the electric power delivery system may be based on priority information associated with the loads.
- each load in a system may have an associated IED that may be similar or identical lEDs.
- lEDs associated with a load may be configured to monitor a machine rotor angle of a load, an operating frequency, a rate of change of the operating system frequency, and/or power consumption of the load.
- Each generator in the system may also have an associated IED that may be similar or identical lEDs.
- lEDs associated with a generator may be configured to monitor a machine rotor angle, an operational frequency, a rate of change of operation frequency, and power production of the generator.
- island formation may be detected by time-correlation of frequency deviations in operating system frequency information received from lEDs associated with generators and/or loads.
- Frequency deviations may be detected by comparing received operating system frequency information with one or more under frequency and/or over frequency (OF) thresholds. In certain embodiments, these thresholds may be the same for lEDs associated with both loads and generators.
- OF over frequency
- Figure 5 illustrates another embodiment of a method 500 for protection and control of an electric power delivery system that utilizes rotating inertia information from the system.
- the illustrated method 500 may be utilized to determine an amount of load and/or power generator to shed to mitigate a UF or OF condition.
- Rotating inertia information may be expressed in terms of kg m 2 or any other suitable convention including seconds x MVA rating.
- rotating inertia information for one or more loads of the system may be entered by a user into one or more associated lEDs.
- rotating inertia information for one or more generators of the system may be entered by the user into one or more associated lEDs.
- a total spinning inertia associated with one or more detected islands may be calculated.
- the total spinning inertia of a detected island may be denoted as "H".
- the total spinning inertia of a detected island may be calculated by summing together the rotating inertia information for loads and/or generators associated with the detected island.
- the additional mechanical power required by the Pace term can be accomplished by quickly increasing the power output of generators.
- power electronic based generation such as photovoltaic, battery, or other similar power electronic inverter style generation may use such run-up to quickly increase the power output of the generators.
- frequency deviations are above set thresholds (e.g., in an OF condition)
- an amount of mechanical power reduction required from the generators associated with the island may be predicted according to a formula utilizing the operating frequency, the rate of change of the operating frequency, and the total spinning inertia of the detected island (i.e., "H").
- the amount of mechanical power reduction may be measured in Watts.
- An amount of power generation to be shed in the detected island may be calculated based on the predicted amount of mechanical power reduction, a generator priority list, and a measured power production of each generator in the detected island.
- the amount of generator Watts to be reduced may instead be achieved by running back generation instead of tripping generators offline with circuit breakers.
- Certain embodiments of the systems and methods disclosed herein may be implemented using various suitable approaches. For example, in some embodiments, methods utilizing time-synchronized phasors (synchrophasors) may be utilized.
- Machine rotor angle information, operating frequency information, a rate of change of the operating frequency, and power consumption values of generators and/or loads in a detected island may be sent from remote lEDs associated with the generators and/or loads to one or more centralized lEDs operating as central controller(s). Utilizing this information, the one or more centralized lEDs may perform the aforementioned methods to determine which loads and/or generators should be sent trip signals and/or run-back or reject signals.
- determining an amount of load to shed which may be expressed in terms of Pace, may be calculated according to the following:
- Pace 2H system fRoCoF (3)
- J sys tem is the rotating inertia of the system
- J gen e tor_n is the rotating inertia of a particular generator included in the system
- Ji oa d_n is the rotating inertia of a particular load included in the system
- H sys tem is the total spinning inertia of the system
- Pace is the amount of additional mechanical power contribution required or amount of load to be shed
- f is the operating frequency
- RoCoF is the rate of change of the operating frequency.
- the one or more centralized lEDs may be an SEL- 1 102 controller (available from Schweitzer Engineering Laboratories, Inc.) that communicates to one or more remote lEDs such as SEL-751 relays (available from Schweitzer Engineering Laboratories, Inc.) via one or more channels (e.g., one or more C37.1 18 channels).
- SEL-751 relays available from Schweitzer Engineering Laboratories, Inc.
- channels e.g., one or more C37.1 18 channels.
- an illustrative system may include three generators and twelve sheddable loads. Five SEL-751 relays may be associated with the three generators, each having an H of 4 seconds and a 100 MVA rating. Ten SEL-751 's may be associated with the twelve sheddable loads, each having an H of 0.5 seconds and a 30 MVA rating. Each of the generators may produce 100 MW and each of the loads may consume 25 MW.
- An UF event having a 59 Hz UF level and a RoCoF of 2 Hz/sec may occur with two generators and eight loads experiencing UF events within 6 milliseconds of each other.
- Equations 1 -3 a solution for preventing a blackout condition caused by an underfrequency event may be determined.
- J generator for each generator is 800 kg- m 2
- Jioad for each load is 30 kg-m 2
- J sys tem of the island experiencing the UF event is 1 ,840 kg-m 2
- H sys tem of the island is 9.2 seconds
- Pace power deficiency is therefore 60 MW.
- Three of the 25 MW loads may be selected for shedding (i.e., totally 75 MW collectively), ensuring that the island does not experience a blackout condition.
- a solution for preventing a blackout condition caused by an OF event may also be determined. For example, based on the above described illustrated system parameters, J sys tem O the island experiencing an OF event is 2,460 Mkg-m 2 , H syst em of the island experiencing the OF event 12.3 seconds, and Pace power excess is therefore 187 MW. To ensure the island does not experience a blackout condition, one of the 100 MW generators may be shed, while another may be run-back to 87 MW output to account for the 187 MW of excess power.
- one or more remote lEDs associated with loads and/or generators in a system may store operating frequencies and one or more RoCoF thresholds.
- the one or more remote lEDs may generate quantized and/or binary representations of the operating frequencies and a RoCoF based on a comparison with the one or more RoCoF thresholds and transmit this information to one or more centralized lEDs operating as a centralized controller.
- the one or more remote lEDs may further transmit power consumption and generation information from associated loads and/or generators.
- the one or more centralized lEDs may determine an estimated H and Pace for the system utilizing, at least in part, Equations 1 -3. Utilizing the estimated H and Pace, the one or more centralized lEDs may determine which loads and/or generators of the system should be sent trip signals and/or run-back or reject signals.
- An illustrative system implementing embodiments disclosed herein may comprise one or more centralized lEDs that may be an SEL-1 102 controller (available from Schweitzer Engineering Laboratories, Inc.), communicating with one or more remote lEDs such as SEL-751 relays (available from Schweitzer Engineering
- an illustrative system may include three generators and twelve sheddable loads. Five SEL-751 relays may be associated with the three generators, each having an H of 4 seconds and a 100 MVA rating. Ten SEL-751 's may be associated with the twelve sheddable loads, each having an H of 0.5 seconds and a 30 MVA rating. Each of the generators may produce 100 MW and each of the loads may consume 25 MW.
- An UF event having a 59 Hz UF level and a RoCoF of ⁇ 5 Hz/sec may occur with two generators and eight loads experiencing UF events within 6 milliseconds of each other.
- Equations 1 -3 a solution for preventing a blackout condition caused by the underfrequency event may be determined.
- J generator ⁇ each generator is 800 kg-m 2
- J /oad for each load is 30 kg-m 2
- J system of the island experiencing the UF event is 1 ,840 kg-m 2
- H sys tem of the island is 9.2 seconds
- Pace power deficiency may be calculated as 75 MW.
- Three of the 25 MW loads may be selected for shedding (i.e., totally 75 MW collectively), ensuring that the island does not experience a blackout condition.
- a solution for preventing a blackout condition caused by an OF event in the aforementioned system may also be determined.
- an OF event having a 61 Hz UF level and a RoCoF of ⁇ 5 Hz/sec may occur with three generators and two loads experiencing OF events within 3.5 milliseconds of each other.
- J sys tem of the island experiencing the OF event is 2,460 kg-m 2
- Pace power excess is therefore 104 MW.
- one of the 100 MW generators may be shed, while another may be run-back to 96 MW output to account for the 104 MW of excess power.
- the quantized and/or binary representations of the operating frequencies and/or RoCoF may introduce certain errors associated with the binary simplification.
- the binary simplification may introduce an 83 MW error into the calculated excess power Pace.
- the island may survive (i.e., not experience a blackout condition) if the generator can sufficiently cover the 83 MW error introduced by the simplification. If the generator cannot sufficiently cover the error, the OF in the island will accelerate to another OF threshold level.
- the OF event may rise to an operating frequency of 62 Hz and a RoCoF of ⁇ 5 Hz sec.
- J sys tem of the island experiencing the OF event is 1 ,660 kg-m 2
- Pace power excess is therefore 71 MW.
- the generator may be run-back to 71 MW, reducing the error introduced by the binary simplification to 12 MW, thereby preventing a blackout condition.
- load composition factors of each sheddable load may be entered into the one or more remote lEDs associated with system loads and/or the one or more centralized lEDs. This information may be aggregated from loads associated with a detected island to determine a total load composition factor for the island.
- Load compensation factors may be entered based on voltage dependency or frequency dependency or based on standard load categories including, for example, various P/Q modeled loads, PA/ modeled loads, P/f modeled loads or the like.
- Load compensation factors may also be entered as a relative factor of direct connected induction motors, synchronous motors, electronic loads, resistive loads, or the like. Loads may be further categorized by load characteristics of direct connected induction motors and synchronous motors.
- Loads may then calculated by the one or more remote and/or centralized lEDs to determine the totalized load characteristic of each detected island, which may be referred to as "R L .”
- the total RL of a detected island may be calculated by summing together the RL of all loads which are associated to the detected island.
- Interconnected grids such as those associated with large utilities may be associated with boundaries imposed by utility company ownership of transmission and distribution capabilities.
- Islands may form that include interconnected areas of multiple utility companies, each of the areas being independently operated and having localized blackout prevention technologies.
- generator and load information may be provided on one or more centralized lEDs.
- the one or more centralized lEDs may then share total inertia information, load compensation information, and Pace calculations with one or more lEDs associated with particular portions of the grid.
- Localized blackout prevention technologies may use this system-wide information to take localized blackout prevention measures.
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Abstract
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Priority Applications (5)
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BR112014017423A BR112014017423A2 (en) | 2012-01-31 | 2012-12-11 | system and method for managing an electrical distribution system, and intelligent, electronic device |
AU2012368224A AU2012368224B2 (en) | 2012-01-31 | 2012-12-11 | Systems and methods for blackout protection |
CA2860147A CA2860147C (en) | 2012-01-31 | 2012-12-11 | Systems and methods for blackout protection |
ES201490076A ES2520490B2 (en) | 2012-01-31 | 2012-12-11 | Systems and procedures for blackout protection |
MX2014008138A MX2014008138A (en) | 2012-01-31 | 2012-12-11 | Systems and methods for blackout protection. |
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US13/587,068 US8965592B2 (en) | 2010-08-24 | 2012-08-16 | Systems and methods for blackout protection |
US13/587,068 | 2012-08-16 |
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CA (1) | CA2860147C (en) |
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Cited By (8)
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EP3061179A1 (en) * | 2013-12-20 | 2016-08-31 | Siemens Aktiengesellschaft | Power plant |
FR3035277A1 (en) * | 2015-04-16 | 2016-10-21 | Genergies Antilles Guyane | ELECTRICAL SYSTEM CONTROLLED BY POWER SUPPLYING OF ELECTRIC RECEIVERS TO ELECTRICITY PRODUCTION FROM A PHOTOVOLTAIC GENERATOR |
RU180919U1 (en) * | 2017-12-04 | 2018-06-29 | федеральное государственное бюджетное образовательное учреждение высшего образования "Санкт-Петербургский горный университет" | CONTROLLER OF PROTECTION AGAINST FAN SHUT-OFFS WITH THE POSSIBILITY OF HARMONIC COMPENSATION |
RU192770U1 (en) * | 2019-04-09 | 2019-09-30 | федеральное государственное бюджетное образовательное учреждение высшего образования "Санкт-Петербургский горный университет" | CONTROLLER OF PROTECTION AGAINST CIRCUIT BREAKERS WITH THE POSSIBILITY OF COMPENSATION OF HARMONICS AND CORRECTION OF RELAY PROTECTION SETTINGS |
US11218023B2 (en) | 2019-06-10 | 2022-01-04 | Schweitzer Engineering Laboratories, Inc. | Recloser control fast open circuit detection |
US11239659B2 (en) | 2019-06-10 | 2022-02-01 | Schweitzer Engineering Laboratories, Inc. | Microgrid autosynchronizing using remote recloser inputs and outputs |
US11316349B2 (en) | 2019-06-10 | 2022-04-26 | Schweitzer Engineering Laboratories, Inc. | Recloser control with distributed energy resource synchronization |
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US11239659B2 (en) | 2019-06-10 | 2022-02-01 | Schweitzer Engineering Laboratories, Inc. | Microgrid autosynchronizing using remote recloser inputs and outputs |
US11316349B2 (en) | 2019-06-10 | 2022-04-26 | Schweitzer Engineering Laboratories, Inc. | Recloser control with distributed energy resource synchronization |
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Also Published As
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CA2860147A1 (en) | 2013-08-08 |
AU2012368224B2 (en) | 2015-02-26 |
BR112014017423A2 (en) | 2018-06-19 |
MX2014008138A (en) | 2014-08-21 |
AU2012368224A1 (en) | 2014-07-17 |
ES2520490A2 (en) | 2014-11-11 |
ES2520490B2 (en) | 2015-11-27 |
ES2520490R1 (en) | 2015-02-04 |
CA2860147C (en) | 2016-02-23 |
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