EP2684105A1 - Commande répartie de la puissance réactive dynamique - Google Patents

Commande répartie de la puissance réactive dynamique

Info

Publication number
EP2684105A1
EP2684105A1 EP12754274.4A EP12754274A EP2684105A1 EP 2684105 A1 EP2684105 A1 EP 2684105A1 EP 12754274 A EP12754274 A EP 12754274A EP 2684105 A1 EP2684105 A1 EP 2684105A1
Authority
EP
European Patent Office
Prior art keywords
reactive power
utility grid
voltage
controller
mean square
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Withdrawn
Application number
EP12754274.4A
Other languages
German (de)
English (en)
Inventor
Johan ENSLIN
Ruba Akram AMARIN
Adje F. MENSAH
Ehab H. SHOUBAKI
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Petra Solar Inc
Original Assignee
Petra Solar Inc
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Petra Solar Inc filed Critical Petra Solar Inc
Publication of EP2684105A1 publication Critical patent/EP2684105A1/fr
Withdrawn legal-status Critical Current

Links

Classifications

    • 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
    • H02J3/12—Circuit arrangements for ac mains or ac distribution networks for adjusting voltage in ac networks by changing a characteristic of the network load
    • H02J3/16—Circuit arrangements for ac mains or ac distribution networks for adjusting voltage in ac networks by changing a characteristic of the network load by adjustment of reactive power
    • 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
    • H02J13/00—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network
    • H02J13/00002—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by monitoring
    • 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
    • H02J13/00—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network
    • H02J13/00006—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment
    • H02J13/00016—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment using a wired telecommunication network or a data transmission bus
    • H02J13/00017—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network characterised by information or instructions transport means between the monitoring, controlling or managing units and monitored, controlled or operated power network element or electrical equipment using a wired telecommunication network or a data transmission bus using optical fiber
    • 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
    • H02J13/00—Circuit arrangements for providing remote indication of network conditions, e.g. an instantaneous record of the open or closed condition of each circuitbreaker in the network; Circuit arrangements for providing remote control of switching means in a power distribution network, e.g. switching in and out of current consumers by using a pulse code signal carried by the network
    • H02J13/00032—Systems characterised by the controlled or operated power network elements or equipment, the power network elements or equipment not otherwise provided for
    • H02J13/00034—Systems characterised by the controlled or operated power network elements or equipment, the power network elements or equipment not otherwise provided for the elements or equipment being or involving an electric power substation
    • 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
    • H02J3/18—Arrangements for adjusting, eliminating or compensating reactive power in networks
    • H02J3/1821—Arrangements for adjusting, eliminating or compensating reactive power in networks using shunt compensators
    • H02J3/1835—Arrangements for adjusting, eliminating or compensating reactive power in networks using shunt compensators with stepless control
    • 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
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E40/00—Technologies for an efficient electrical power generation, transmission or distribution
    • Y02E40/30—Reactive power compensation
    • 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
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E40/00—Technologies for an efficient electrical power generation, transmission or distribution
    • Y02E40/70—Smart grids as climate change mitigation technology in the energy generation sector
    • 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
    • Y02E—REDUCTION OF GREENHOUSE GAS [GHG] EMISSIONS, RELATED TO ENERGY GENERATION, TRANSMISSION OR DISTRIBUTION
    • Y02E60/00—Enabling technologies; Technologies with a potential or indirect contribution to GHG emissions mitigation
    • 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
    • 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
    • Y04S10/22—Flexible AC transmission systems [FACTS] or power factor or reactive power compensating or correcting units
    • 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
    • Y04S10/30—State monitoring, e.g. fault, temperature monitoring, insulator monitoring, corona discharge

Definitions

  • a large amount of today's electric power is generated by large- scale, centralized power plants using fossil fuels, hydropower or nuclear power, and is transported over long distances to end-users. Power flows from the centralized power plants through distribution networks to consumers.
  • the electric power from the centralized power plants to end-users is generally delivered in form of alternating current (AC), where both current and voltages are sinusoidal, also referred to as AC systems.
  • AC systems power is measured as the rate of flow of energy past a given point. If the end-user's load is purely resistive, only real power is transferred, as both the voltage and the current are in phase. If the end-user's load is purely reactive (capacitor and inductor), the voltage and the current are 90 degrees out of phase and there is no net transfer of energy to the load.
  • Typical end-user loads have resistance, inductance, and capacitance, so both real and reactive power flow to the end-user loads.
  • the inductive and capacitive properties of the end-user loads cause the currents to change phase with respect to voltage: capacitance tending the current to lead the voltage in phase, and inductance to lag it.
  • the AC system with higher phase difference between the current and the voltage will have higher circulating currents, hence higher loses.
  • the higher circulating currents require higher rated equipment (conductors, transformers, etc.) or can cause damage to the equipment due to overcurrent.
  • VAR support The VAR support in the electric power system is provided using VAR compensators. These VAR compensators are generally located in a distribution substation or on feeders closer to the distribution substation. These VAR compensators offer minimal or no protection to transformers or other equipment's located near the loads. Moreover, the present day VAR compensators are stand-alone.
  • the systems may include a voltage sensor for sensing an instantaneous value of the grid voltage.
  • the systems may further include a reactive power compensator and a controller to operate the reactive power compensator.
  • the controller may be configured to determine an amount of reactive power to be provided to the electric system based on the sensed grid voltage and a droop profile.
  • the controller may further be configured to operate switches of the reactive power compensator to add/remove capacitors to the electric power system and/or set firing angle of one or more inductors.
  • FIG. 1 shows an environment in which various embodiments of the present invention can be practiced
  • FIG. 2 shows a power distribution system with fast dynamic distributed VAR compensators, in accordance with an embodiment of the present invention
  • FIG. 3 shows the dynamic distributed VAR compensator of FIG. 2, in accordance with an embodiment of the present invention
  • FIG. 4 is a block diagram of elements of a controller for the VAR compensator of FIG. 3, in accordance with an embodiment of the present invention
  • FIG. 5 is a droop profile for a distributed VAR compensator, in accordance with an embodiment of the present invention.
  • FIG. 6 is an architecture for data acquisition, monitoring, and control, of fast dynamic distributed VAR compensators, in accordance with an embodiment of the present invention.
  • FIG. 7 is a diagram depicting modes of operation for a VAR compensator, in accordance with an embodiment of the present invention.
  • Embodiments of the present invention may provide systems and methods for controlling reactive power in an electric power distribution system by providing a fast dynamic distributed VAR compensator.
  • the reactive power may be controlled by absorbing or delivering reactive power in the power distribution system through the distributed VAR compensator.
  • the systems may include a voltage sensor for sensing an instantaneous value of the grid voltage.
  • the systems may further include a reactive power compensator and a controller to operate the reactive power compensator.
  • the controller may be configured to determine an amount of reactive power to be provided to the electric system based on the sensed grid voltage and a droop profile.
  • the controller may further be configured to operate switches of the reactive power compensator to add/remove capacitors to the electric power system and/or set firing angle of one or more inductors, based on the determined amount of reactive power.
  • FIG. 1 is an environment in which various embodiments of the present invention can be practiced.
  • FIG. 1 is shown to include a generation station 102, one or more transmission units 104a, 104b, and 104c (collectively referred to as transmission units 104), one or more distribution units 106a and 106b (collectively referred to as distribution units 106), a micro grid 108, one or more loads 1 10a and 1 10b
  • loads 110 (collectively referred to as loads 110), and a power distribution system 112.
  • micro grid 108 further includes one or more Power Electronic Interfaces (PEIs) 114a, 1 14b, and 114c (collectively referred to as PEIs 314), one or more DG resources 1 16a, 1 16b, and 1 16c (collectively referred to as DG resources 116), and one or more DG units 118a, 118b, and 118c (collectively referred to as DG units 118).
  • PEIs Power Electronic Interfaces
  • DG resources 116 one or more DG resources 1 16a, 1 16b, and 1 16c
  • DG units 118a, 118b, and 118c collectively referred to as DG units 118.
  • the generation station 102 may depend on traditional and renewable sources that may include, but are not limited to, fossil fuels, nuclear, hydro, wind, photovoltaic, and geo-thermal.
  • the generation station 102 may generate a large-scale power to be distributed to the loads 110 via the power distribution system 112.
  • the distribution network is described in more details with respect to FIG. 2.
  • the power generated by the generation station 102 may be provided to the transmission units 104 to further transmit the power to the distribution units 106.
  • the power generated from the generation station 102 is feed into transmission units 104.
  • the transmission units 104 may use high voltage (110KV or above) to reduce the energy loss in transmission.
  • the distribution units 106 may be the final stage in the delivery of power to the end-users and may use step down transformers to reduce voltages from the high values.
  • the end-users are also referred to as customer premise in this disclosure.
  • FIG. 2 is a diagram of a power distribution system 200 with fast dynamic distributed VAR compensator.
  • the power distribution system 200 may include a distribution substation 202, one or more distribution feeders 204a and 204b (collectively referred to as feeders 204), one or more secondary distribution transformers 206a and 206b (collectively referred to as secondary distribution transformers 206), one or more customer premises 208a and 208b (collectively referred to as customer premises 208), one or more capacitor banks 210, one or more fast dynamic distributed VAR compensators 212a and 212b (collectively referred to as VAR compensators 212).
  • the power distribution system 200 of FIG.2 may further include a communication system 214 and a data center 216.
  • the distribution substation 202 may transfer power received from a transmission system to the feeders 204.
  • the substation 202 may include one or more primary transformers 218 to change voltage levels between high transmission voltages (1 10KV or above) and lower distribution voltages (2.3KV to 35KV).
  • the substation 202 may further include switching, protection, and control equipment 220.
  • the primary transformers 218 may have a primary winding and a secondary winding (not shown the FIG. 2).
  • the transmission system may be connected to the primary windings and the feeders 204 may be connected to the secondary windings of the primary transformers 218.
  • the output of the distribution substation 202 may be feeders 204.
  • the feeders 204 may run along streets overhead (or underground, in some cases).
  • the feeders 204 may be used to deliver power from the distribution substation 202 to the customer premises 208. Only large customer premises may be fed directly from the distribution voltages. Most customer premises may be fed via secondary distribution transformers 206.
  • the secondary distribution transformers 206 may be configured to change the voltage level from the feeders 204 to a voltage level (relatively low level) requested by the customer premises 208.
  • the secondary distribution transformers 206 may be pole mounted or set on the ground and may be located near customer premises 208. Although only one customer premise is shown to be connected to a secondary distribution transformer in FG. 2, more than one customer premises may be connected to a single secondary distribution transformer. In one example embodiment, part of the power distribution system 200 beyond the secondary distribution transformer 206 may also be referred to as secondary voltage network.
  • the secondary voltage network may be provided with one more VAR compensators 212.
  • the VAR compensators 212 may be connected between the secondary distribution transformers 206 and the customer premises 208, preferably nearer to the secondary distribution transformers 206.
  • the VAR compensators 212 may be configured to provide fast dynamic distributed reactive power compensation on the secondary voltage network.
  • the VAR compensators 212 are described in more detail with respect to FIG. 3 in this disclosure.
  • one or more capacitor banks 222 may be connected to the feeders 204 to provide voltage control on the feeders 204.
  • the capacitor banks 222 may also include a capacitor controller 224 to connect/disconnect one or more capacitors to the feeders 204.
  • the capacitor controller 224, the VAR compensator 212, and the control equipment 220 may be connected to the data center 216 through the communication system 214.
  • the communication system 214 may be a ZigBee protocol based communication system, a wide area network (WAN), a mesh network, the internet or another standard communication system.
  • the capacitor controller 224, the VAR compensator 212, and the control equipment 220 may also communicate with each other using the communication system 214.
  • the data center 216 may be located at a central monitoring system.
  • the power distribution system 200 may include a central monitoring system (not shown in FIG. 2).
  • the central monitoring system may be configured to communicate with elements of the power distribution system 200 using the communication system 214 or a separate communication system.
  • the central monitoring system may be configured to communicate with the elements of the power distribution system 200 using two way communication systems.
  • the two way communication may include, receiving data from the elements regarding status of the power distribution system, and in response to the received status data, sending commands to configurable elements.
  • the commands may include set of action to be performed by the element receiving the command.
  • the data center 214 may be located at the central monitoring system and is used to store the received data from the elements of the power distribution system.
  • the central monitoring system may include standard power distribution system management tools like Distribution Management System (DMS), Supervisory Control and Data Acquisition (SCADA) system, Outage Management System (OMS), Fault Detection Isolation and Restoration (FDIR) system, Crew Management System (CMS),
  • DMS Distribution Management System
  • SCADA Supervisory Control and Data Acquisition
  • OMS Outage Management System
  • FDIR Fault Detection Isolation and Restoration
  • CMS Crew Management System
  • MDMS Metrology Data Management System
  • a typical power distribution system may include more than two VAR compensators distributed over a large geographical area.
  • the number of VAR compensators may be based on number of customer premises, types of customer loads, amount of customer loads, and distance of the customer premise from the distribution substation.
  • one VAR compensator per secondary distribution transformer may be provided to control reactive power in the power distribution system.
  • An example specification of a VAR compensator is provided in Appendix 1 of this specification.
  • FIG. 3 shows elements of the VAR compensator 212, in accordance with an embodiment of the present invention.
  • the VAR compensator 212 may include a voltage sensor 302, a controller 304, a reactive power compensator 306, a ruse 308, an electromagnetic interference (EMI) reactor 310, and a communication module 312.
  • EMI electromagnetic interference
  • the voltage sensor 302 may be connected to the feeders 204.
  • the voltage sensor 302 may be configured to sense an instantaneous value of the feeder voltage, also referred to as grid voltage (V gr id).
  • the sensed instantaneous value of the feeder voltage may be sent to the controller 304.
  • the controller 304 may be configured to operate switches in the reactive power compensator 306 to provide VAR support to the feeders 204 based on the sensed grid voltage.
  • the controller 304 and its functioning are described in more detail with respect to FIG. 4 of this disclosure.
  • the reactive power compensator 306 may be connected to the feeders 204 through the fuse 308 and the EMI reactor 310.
  • the fuse 308 may be configured to interrupt excessive current to prevent overheating or damage of the reactive power compensator 306.
  • the EMI reactor 308 may be configured to attenuate conducted radio frequencies disturbances between the feeders 204 and the reactive power compensator 306.
  • the reactive power compensator 306 may include a lead VAR unit 314 and one or more VAR units 316a, 316b, and 316c (collectively referred to as VAR units 316).
  • the lead VAR unit 314 and the VAR unites 316 are connected to the feeders 204 in parallel.
  • the reactive power compensator 306 may further include a Metal Oxide Varistor (MOV) 318.
  • the Metal Oxide Varistor (MOV) 318 may be connected in parallel to the lead VAR unit 314 and the VAR units 316.
  • the MOV 318 may be configured to protect sensitive components of the reactive power compensator 306 against excessive transient voltages.
  • the MOV 318 may conduct significantly increased current when voltage across the lead VAR unit 314 and the VAR units 316 is high.
  • the MOV 318 may remain non-conductive as a shunt-mode device during normal operations when the voltage across the VAR units remains below a clamping voltage.
  • the MOV 318 may be triggered, and may shunt the current created by the increased voltage away from the VAR units.
  • the clamping voltage may be determined by the utilities.
  • the lead VAR unit 314 may include a reactor 320, a Triode for Alternating Current (TRIAC) or solid-state AC switch 322, and a driver 324.
  • the reactor 320 may be connected to the feeders 204 through the TRIAC 322.
  • the driver 324 may be configured to operate the TRIAC 322.
  • the VAR unit 316a may include a TRIAC 324a, a driver 326a, a reactor 328a and one or more capacitors 330a and 330b (collectively referred to as capacitors 330).
  • the one or more capacitors 330 may be connected to the reactor 328 in series.
  • the one or more capacitors 330a and 330b may be connected together either in series or in parallel or in combination of series and parallel.
  • the reactor 328 may be connected to the feeders 204 through the TRIAC 324.
  • the VAR units 316b and 316c may also include components similar to the VAR unit 316a.
  • the components of the VAR units 316b and 316c may be connected in similar fashion to those of the VAR unit 316a.
  • the VAR units 316b may include a TRIAC 324b, a driver 326b, a reactor 328b and one or more capacitors 330c and 330d.
  • the VAR unit 316c may include TRIAC 324c, a driver 326c, a reactor 328c and one or more capacitors 330e and 33 Of.
  • the TRIACs 322 and 324 may be electronic components that can conduct current in either direction when switched ON.
  • the TRIACs 322 and 324 may be switched ON by applying either a positive or a negative current to its gate electrodes.
  • the gate current, also referred to as gating signal may be provided by the drivers 324 and 326.
  • the TRIACs 322 and 324 may continue to conduct until the current flowing through it drops below a predetermined threshold value.
  • the predetermined threshold value may also be referred to as holding current.
  • the drivers 324 and 326 may be operated by the controller 304.
  • FIG. 4 is block diagram of the controller 304 of FIG. 3, in accordance with an embodiment of the present invention.
  • the controller 304 may include an Analog-to-Digital converter (ADC) 402, a Phase Locked Loop (PLL) 404, a Root Mean Square (RMS) estimator 406, an error estimator 408, a droop profile 410, and a modulator 412.
  • ADC Analog-to-Digital converter
  • PLL Phase Locked Loop
  • RMS Root Mean Square
  • the controller 304 may further include a supervisory state machine 414, a digital communication bus 416 and a timer 418.
  • the ADC 402 may be configured to receive the sensed instantaneous value of the grid voltage from the voltage sensor 302.
  • the ADC 402 may provide digital versions of physical signals representing the grid voltage and each individual capacitor banks.
  • the output from the ADC 402 may be sent to PLL 404 and the RMS estimator 406.
  • the PLL 404 may generate an output signal related to the phase of the input signal.
  • the PLL 404 may provide a reference in phase with the grid voltage.
  • the PLL 404 may also provide an estimated frequency of the grid voltage to the RMS estimator 406 as a corrective factor.
  • the RMS estimator 406 may use the output from the ADC 402, to compute a RMS value of the grid voltage (Vg rid ).
  • the RMS value is a statistical measure of magnitude of varying quantity, e.g. sinusoids.
  • the RMS value of the grid voltage can be computed as:
  • Vpeak is peak value of the grid voltage (V gr jd).
  • the output from the RMS estimator 406 may be used as input for the error estimator 408.
  • the error estimator 408 may compare the RMS value of the grid voltage (V gr id) received from the RMS estimator 406 with a reference RMS voltage.
  • the error estimator 408 may further estimate a difference between the RMS value of the grid voltage computed by the RMS estimator 406 and the reference RMS voltage.
  • the reference RMS voltage may be provided by the central monitoring system and stored locally in the RMS estimator 406. In one example embodiment, the reference RMS voltage may be dynamically modified based on an operating condition of the power distribution system 200.
  • the estimated difference between the RMS value of the grid voltage computed by the RMS estimator 406 and the reference RMS voltage may be used as input for the droop profile module 410.
  • the droop profile module 410 may include a droop profile as depicted in FIG. 5. The droop profile is discussed in more detail with respect to FIG.5 of this disclosure.
  • the droop profile module 410 may estimate a desired amount of reactive power to be absorbed/delivered in the feeders 204 based on the estimated difference.
  • the droop profile module may estimate the desired amount by either using a locally stored droop profile or using a droop profile located at a central monitoring system.
  • the output from the droop profile module 410 may be used as an input for the modulator 412.
  • the modulator 412 may translate the output from the droop profile module 410 into a control signal that
  • the output from the modulator 410 may be used as inputs for the drivers 324 and 326.
  • the supervisory state machine 414 may be configured to coordinate interaction between closed loop droop control and external command interface exposed through a communication conduit.
  • the supervisory state machine 414 may also carry configuration parameters such as various operating schedules and relative to voltage, or any other quantities described above.
  • the timer 418 may provide a reference timing signals to all other components within the controller.
  • the reference timing signals may be used by the components to synchronize internal clock or time stamp the data sensed from the utility grid.
  • the digital communication bus 416 is configured to establish communication between the controller 304 and communication system 214.
  • the reactor 324 may be variably switched into the circuit and so provide a continuously variable reactive power injection (or absorption) to the power distribution system 200.
  • coarse voltage control is provided by the capacitors 330; the TRIAC controlled reactor is to provide smooth control. Smoother control and more flexibility can be provided with the TRIAC controlled capacitor switching.
  • FIG. 5 depicts an example of a droop profile, in accordance with an embodiment of the present invention.
  • the droop profile may include a one to one mapping between an estimated error in RMS value of the grid voltage and a desired amount of reactive power to be absorbed or delivered in the feeders 204. Whenever, the estimated error in RMS value of the grid voltage falls between two consecutive values provided in the mapping, the desired reactive power may be calculated by performing an interpolation using the points below and above of the estimated error in RMS value of the grid voltage.
  • mapping between the estimated error in RMS value of the grid voltage and the desired amount of reactive power is depicted in form of a graph in FIG. 5, the mapping may be depicted in form of a table or any other mapping technique.
  • the mapping between the estimated error in RMS value of the grid voltage and the desired amount of reactive power may be stored on the droop profile and updated dynamically.
  • the mapping may be updated by a central monitoring system or an administrator.
  • the updated mapping may be sent over the communication system 214.
  • the mapping between the estimated error in RMS value of the grid voltage and the desired amount of reactive power may be updated locally based on operating conditions of the feeders 204.
  • FIG. 6 is architecture for data acquisition, monitoring, and control for fast dynamic distributed VAR compensator, in accordance with yet another embodiment of the present invention.
  • the VAR compensators may be connected to the secondary voltage network of the power distribution system.
  • the VAR compensator may be provided with a power generation source connected to the power distribution system.
  • the VAR compensator may be provided along with a solar Photovoltaic (PV) system.
  • the VAR compensator may be provided as a standalone element connected to the power distribution system.
  • the VAR compensator may be configured to communicate over a communication system to a central monitoring system.
  • the communication system may be a wireless communication system or a wired communication system.
  • the communication system may enable the VAR compensator to interact with other VAR compensators or another power
  • the central monitoring system may use the communication system to monitor and control each individual VAR compensators.
  • the communication system may allow management of a VAR compensators geographically dispersed over a large area from a centralized location.
  • the communication system may be a smart grid communication system which is employed by utilities to manage the power distribution system.
  • the integration of the VAR compensators with the smart grid system will enable monitoring and reporting of operation and health of the VAR compensator to the central monitoring system.
  • the monitoring and reporting may include recording reactive power generated by the VAR compensator.
  • the monitoring and reporting may further include sending a maintenance and repair alerts to a utility control center.
  • the integration of VAR compensator with smart grid may enable the VAR compensators to be controlled remotely.
  • the VAR compensator can be remotely configured by command over the communication system. The resulting state of the VAR compensator may be viewed in the central monitoring system.
  • the integration of VAR compensator with smart grid may provide utilities with grid reliability tools, in which the central monitoring system constantly monitor and provide real time status updates on critical parameters such as voltage and VAR thereby enabling automatic power outage detection and faster repair response time.
  • FIG. 7 depicts voltage different mode of operation of the VAR compensator, in accordance with an embodiment of the present invention.
  • the VAR compensator may be operated in two different modes.
  • the VAR compensator may work based on a droop profile stored locally.
  • the VAR compensator based on a grid voltage and the droop profile can absorb/deliver reactive power in the power distribution system.
  • the VAR compensator operations are controlled by a central monitoring system.
  • the central monitoring system may send commands over the communication system.
  • the fast dynamic distributed VAR compensator may regulate voltage on secondary service taps on distribution feeders to within required limits.
  • the voltage regulation may allow the utilities to extend operation lifetime of secondary distribution transformer by compensating for emergent and growing load profiles along the feeder.
  • the distributed VAR compensator may minimize loses in secondary distribution transformers by improving power factor along the feeder.
  • the distributed VAR compensator may curtail voltage rise due to increasing number of distributed generation such as photovoltaic (PV) cells. The ability to curtail voltage rise may allow for additional PV cells on feeders.
  • PV photovoltaic
  • the fast dynamic distributed VAR compensator may be capable of delivering both leading and lagging reactive power to the power distribution system.
  • the reactive power generation in the VAR compensator may provide smooth and continuous voltage output when operating (e.g. supporting minimum voltage or correcting power factor) on the power distribution system.
  • the VAR compensator may be designed to minimize harmonics and noise generated on the line due to component selection and controlled switching.
  • Controlling reactive power in a power distribution system may reduce loses in the power distribution system and transmission system. Moreover, controlling reactive power allows reduction of transformer loses, capacity relieve and peak saving through volt VAR optimization. Controlling reactive power may allow defer transformer upgrade and replacement, thereby increasing efficiency. Moreover controlling reactive power increases the power factor on the feeder thereby mitigating power quality impacts of other photovoltaic (PV) generation or non-linear loads.
  • PV photovoltaic
  • the distribution helps in avoiding reliance on a centralized VAR compensation that requires big reactive elements, and generates line frequency harmonics. Further, avoiding reliance on the centralized VAR support eliminates the possibility of a single point of failure.
  • the fast dynamic distributed VAR compensators, using separate VAR units, by providing VAR support at the point of load increases the overall performance of the utility grid, and decreases the loses and voltage fluctuations for the customers.
  • Embodiments of the invention may be practiced in an electrical circuit comprising discrete electronic elements, packaged or integrated electronic chips containing logic gates, a circuit utilizing a microprocessor, or on a single chip containing electronic elements or microprocessors. Embodiments of the invention may also be practiced using other technologies capable of performing logical operations such as, for example, AND, OR, and NOT, including but not limited to mechanical, optical, fluidic, and quantum technologies. In addition, embodiments of the invention may be practiced within a general purpose computer or in any other circuits or systems.
  • Embodiments of the invention may be implemented as a computer process (method), a computing system, or as an article of manufacture, such as a computer program product or computer readable media.
  • the computer program product may be a computer storage media readable by a computer system and encoding a computer program of instructions for executing a computer process.
  • the computer program product may also be a propagated signal on a carrier readable by a computing system and encoding a computer program of instructions for executing a computer process.
  • the present invention may be embodied in hardware and/or in software (including firmware, resident software, micro-code, etc.).
  • embodiments of the present invention may take the form of a computer program product on a computer-usable or computer-readable storage medium having computer-usable or computer-readable program code embodied in the medium for use by or in connection with an instruction execution system.
  • a computer-usable or computer-readable medium may be any medium that can contain, store, communicate, propagate, or transport the program for use by or in connection with the instruction execution system, apparatus, or device.
  • the computer-usable or computer-readable medium may be, for example but not limited to, an electronic, magnetic, optical, electromagnetic, infrared, or semiconductor system, apparatus, device, or propagation medium. More specific computer-readable medium examples (a non-exhaustive list), the computer- readable medium may include the following: an electrical connection having one or more wires, a portable computer diskette, a random access memory (RAM), a readonly memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), an optical fiber, and a portable compact disc read-only memory (CD-ROM).
  • RAM random access memory
  • ROM readonly memory
  • EPROM or Flash memory erasable programmable read-only memory
  • CD-ROM portable compact disc read-only memory
  • the computer-usable or computer-readable medium could even be paper or another suitable medium upon which the program is printed, as the program can be electronically captured, via, for instance, optical scanning of the paper or other medium, then compiled, interpreted, or otherwise processed in a suitable manner, if necessary, and then stored in a computer memory.

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  • Engineering & Computer Science (AREA)
  • Power Engineering (AREA)
  • Computer Networks & Wireless Communication (AREA)
  • Supply And Distribution Of Alternating Current (AREA)
  • Control Of Electrical Variables (AREA)

Abstract

Cette invention concerne un système et un procédé de commande de la puissance réactive dynamique dans un réseau électrique par mise en œuvre d'un compensateur statique réparti. Le compensateur statique peut comprendre un capteur de tension pour détecter une valeur instantanée d'une tension de réseau. Le compensateur statique peut en outre comprendre un compensateur de puissance réactive et un contrôleur conçu pour actionner le compensateur de puissance réactive. Le contrôleur peut de plus être conçu pour déterminer une quantité de puissance réactive à transmettre au réseau électrique en fonction de la tension de réseau détectée et d'un profil de statisme de tension.
EP12754274.4A 2011-03-09 2012-03-09 Commande répartie de la puissance réactive dynamique Withdrawn EP2684105A1 (fr)

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US201161450742P 2011-03-09 2011-03-09
PCT/US2012/028436 WO2012122454A1 (fr) 2011-03-09 2012-03-09 Commande répartie de la puissance réactive dynamique

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WO2012122454A1 (fr) 2012-09-13

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