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CPRE.2013.6822023_transfers schemes.pdf

Jun 03, 2018



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  • 8/11/2019 CPRE.2013.6822023_transfers schemes.pdf



    J.S. Cramond, P.E.Yale University

    A. Carreras Jr.ABB Inc.

    V.G. Duong, P.E., PMPABB Inc.


    Automatic Bus Transfer Scheme (ABTS) provides many benefits to electric power systemcontrol and automation operations. In a Main-Tie-Main (M-T-M) bus configuration consistingof two independent sources with a normally open tie breaker, the ABTS offers a quick way toautomatically restore a bus that is affected by a loss of its own main source. Automaticretransfer can be done by opening the tie breaker and closing the affected main breaker uponthe return of the source. With advanced technology in microprocessor relays, especiallycoupled with GOOSE application, implementing ABTS can achieve operational speed andreliability and reduced investment cost.

    However there are complicated system protection and coordination issues that could beoverlooked; including:

    Circuit breaker trip and close coil conditions Motor inrush from the affected bus, Transformer and/or main feeder overload from the healthy bus, Sync check for both buses after recovery of the affected main source, Tie breaker switch onto fault, Protection coordination with sub-feeder close-in fault, Breaker failures,

    Main bus protection without bus differential relay.

    This technical paper will present a live project that implements the Automatic BusTransfer Scheme. Discussion focuses on applying relay functions and logic to resolve the abovementioned system protection and coordination issues.


    Traditionally an Automatic Bus Transfer Scheme (ABTS) is applied to a Main-Tie-Main(M-T-M) bus configuration. At Yale University, the Utilities Electrical Engineering Departmenthas implemented one-of-a-kind ABTS (aka Automatic Throw-over Scheme, ATS) on 13.8kVswitchgear buses located in its Sterling Power Plant. The purpose of the ATS installation was toresolve several power system outage incidents on the Universitys Medical Campus whereelectric power is supplied by the Sterling Power Plant and the utility company. This papershares the experience of how power system outages were caused by the utility companyoccurred in the past, and how the unique ATS application at the Sterling Plant would mitigate

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    these issues. The paper also discusses where potential improvement can be observed byimplementing the IEC61850 GOOSE (peer-to-peer) communication, and what additional systemprotections should be considered.


    Yale University owns and operates two power plants, the Central Power Plant and theSterling Power Plant, each with 18MW generating capability at 13.8kV. The remaining balanceof loads including MW and MVAR are supplied by the utility company. The Central Power Plantserves the Universitys central side campus that does not require an ATS scheme; while theSterling Power Plant serves the Medical Campus. The Universitys power plants and electricdistribution system are overseen by the Utilities Engineering Department, who is responsiblefor safe and reliable operations of the electrical system.

    The Sterling Power Plant, which this paper focuses on, consists of two gas turbinegenerators and utility companys four incoming feeders feeding the 13.8kV system. Refer toFigures 1 and 2 for simplified 13.8kV switchgear bus configuration. With two generators alwaysrunning, all four incoming feeders are connected to the buses during HIGH LOAD operatingmode (Figure 1), while only two out of four incoming feeders are connected during LOWLOAD (Figure 2). Note that under HIGH LOAD, both tie breakers are normally open; andunder LOW LOAD the tie breaker between A bus and B bus is normally close with twoincoming feeders feeding either A or B bus.

    Figure 1:Sterling Plant 13.8kV Bus Config. at HIGH LOAD

    Figure 2:Sterling Plant 13.8kV Bus Config. at LOW LOAD

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    At the Sterling Power Plant, besides the required generation unit protection, each13.8kV switchgear bus is protected by a bus overload, with arc flash relay that trips theassociated source circuit breakers only and a bus differential relay that trips all contributingbreakers on the bus. In addition each incoming feeder terminal is currently provided withprotections including over current (51P/N), reverse directional over current (67P/N), undervoltage (27-1&2), over voltage (59G, 59-1&2), reverse power (32U), and over/under frequency(81O, 81U-1&2). Refer to Figure 3 for a typical 13.8kV incoming feeder terminal protectionsingle line diagram. Each breaker has both monitoring trip and close circuits for alarmingpurpose if the monitoring circuit reports an unhealthy state. Sync check control is provided foreach breaker to ensure safe operation of closing the associate breaker.

    Figure 3: Typical Protection Package for a Feeder Terminal at Sterling Power Plant

    The Need for the ATS Scheme

    About four months after the Sterling Plant was commissioned, there were six incidentsin two months that caused the turbines (GT1 and GT2) to trip and resulted in complete poweroutage on the Medical Campus. All of these outages were initiated by fault on the utility sidebut the incoming feeder breakers could not trip fast enough to isolate the fault so that thegenerators would remain on line feeding the fault. As a result, the utility incoming feederbreaker finally tripped and the generators would also trip that left the Medical Campus to be inthe dark.

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    The Utilities Engineering Department needed to come up with a solution that ensuressafe, reliable, and fast operations of a protection package in responding to fault on the utilityincoming feeders such that the generators would not trip due to feeding the fault. Thereforethe current protection system for each terminal is in place, as shown in Figure 3. However, ifone utility incoming feeder breaker on B bus is open for maintenance and an adjacent

    breaker trips due to a fault on the associated feeder, B bus will eventually experience anoutage because GT2 could trip on overload condition. Another scenario is a fault occurs at theutility substation bus. The two incoming feeder breakers will be transfer tripped leading to thesame issue. Therefore an ATS scheme is required to automatically close the tie breaker in atimely manner in order to keep the impacted bus (i.e. B bus) energized. The ATS scheme shallbe designed to properly function for both HIGH LOAD and LOW LOAD conditions.

    Implementing the Scheme

    At Sterling Power Plant, HIGH LOAD condition is about 80% of the time when all fourof the utility incoming feeder breakers are close with the tie breakers open and both of the gas

    turbines are running. In the event of utility bus fault, both incoming feeder breakers usuallytrip within 20 ms of each other. The ATS design is to ensure that the tie breaker between Aand B buses will close after both utility incoming feeder breakers are proven open on oneside of the bus in order to avoid closing onto a fault this is known as Fast Dead Bus Transfer.One more condition for the tie breaker to be closed is sync check across both A and B busesto assure that conditions are constantly within the desired voltage and phase angle ranges.Figures 4 and 5 below show the HIGH LOAD ATS operation.

    Figure 4: HIGH LOAD ATS with Impacted A Bus Figure 5: HIGH LOAD ATS with Impacted B Bus

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    At LOW LOAD condition, the system has only one bus energized by the utility incomingfeeders and the opposite bus is supplied by the normally closed tie breaker and the generators.The same outage situation exists with this bus configuration when a fault occurs on the utilitycompany bus. In this scenario, after two utility incoming feeder breakers are proven open onone bus, ATS would instead close the two other utility incoming feeder breakers one after each

    other on the opposite bus. The same interlocking conditions for close onto fault and sync checkare also confirmed prior to closing these breakers. Figures 6 and 7 illustrate the LOW LOADATS operation.

    Figure 6:LOW LOAD ATS Operation with Impacted A Bus

    Figure 7:LOW LOAD ATS Operation with Impacted B Bus

    Upon the removal of fault on the utility side, the impacted incoming feeder breakers areready to close after the Re-transfer command is initiated (if desired). The breakers wouldthen close automatically only with satisfied sync check condition. This will create a temporaryparallel situation where all four incoming feeder breakers and the tie breaker are closed in avery short moment. The ATS scheme will then automatically: 1) open the tie breaker underHIGH LOAD mode; or 2) open the two previously close incoming feeder breakers one by oneunder LOW LOAD mode. These operations are referred as Close Transition. See Figures 8and 9 for the Close Transition logic.

    Although rare, when the satisfied sync check condition is not met within apredetermined time frame that prevents the breaker from closing, the operator would switchthe ATS scheme into a Manual mode. The operator would manually: 1) open the tie breakerthen close the impacted incoming feeder breakers under HIGH LOAD mode; or 2) open theincoming feeder breakers on one bus then close the other breakers on the opposite bus. These

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    operations are referred as Open Transition that may temporary cause one of the gas turbinesto be over loaded.

    Figure 8:HIGH LOAD ATS Auto Restoration of A Bus

    Figure 9:LOW LOAD ATS Auto Restoration of B Bus

    Benefits of Applying IEC61850 GOOSE Communication

    The above mentioned ATS scheme at Yale University was implemented with hard wiredmethod, which means that numerous physical inputs and outputs are utilized for relay to relaycross-wiring, also coupled with lockout relays for breaker block close purposes. The scheme

    would take many engineering hours for developing DC elementary and wiring diagrams; andtremendous field work for physical wiring installation, testing, and commissioning. When thereis a requirement for system modification, breaker change-out, relay change-out, and/orincoming feeder terminal addition, the same amount of effort needs to be repeated. Furthermore if some part of the interconnecting wire is loosen or broken after the scheme is placed inservice, it is very time consuming and labor intensive to troubleshoot the problem.

    With IEC61850 compliant/capable relays, most of the physical I/O cross-wiring amongrelays can be digitized by utilizing GOOSE communication method. GOOSE stands for GenericObject Oriented Substation Event. Data processing among relays is event based and when achange in GOOSE data occurs, a signal is sent multiple times to the network. Signal exchange

    among relays is based on broadcaster-subscriber mechanism. The broadcaster relay multicastssignal over the local area network to other subscriber relays. The content of GOOSEcommunication allows the subscriber relays to process the receiving signals in order to executethe required actions. These include processing logic for automatic transfer, close transition,open transition, associated timers and sync check, and breaker position interlocking related to

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    the ATS scheme, which can be programmed in the relays. Refer to Figures 8 and 9, the ATSauto restoration logic shown can be easily done with an IEC61850 compliant relay.

    For the ease of discussion and illustration purposes, a typical M-T-M bus configurationwith ATS scheme as shown in Figure 10 will be used for the remaining of this paper. The M-T-MATS scheme consists of two incoming main breakers and a normally open tie breaker, which isusually seen in outdoor distribution substations or in enclosed switchgears, with GOOSEenabled ATS operating principle. In this case the tie breaker relay executes all commandsrelated to the ATS scheme.

    Figure 10: Typical M-T-M Bus Configuration with ATS Scheme

    ICE61850 compliant relays are part of a local area network (LAN) with Ethernetcommunication in a self-healing ring formation. One benefit of the self-healing ring LAN isanytime a piece of communication the ring is broken, the GOOSE data can still be transmittedand received through re-routing on the other direction. This ensures an almost 100%availability of the communication path. Another benefit is the self-check feature in the peer-to-peer communication. The relays involved in the broadcasting/subscribing GOOSE signals arecontinuously verifying their availabilities and the communication path with the Ethernet heart

    beat. Unlike the relays used in the hard wired method, once a relay has a failure or is removedfrom the network, a GOOSE alarm is generated immediately for the owner/operator to take acorrective action.

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    It has been proven that huge number of GOOSE signals can be handled in the LANwithout congesting the communication band width. The latency for a GOOSE signal to thereceiving end is 4 to 10ms. In ATS scheme where GOOSE messages are involved in breakeropening and closing controls, such latency exceeds the requirement of control timing.

    Discussion of Protection Issues and System Conditions Related to the ATS

    This Section discusses the protection aspects associated to the M-T-M ATS scheme.Some protection coordination of the instantaneous over current elements (50P/N) on the mainbreaker relays, i.e. in responding to a terminal fault (close-in fault) on an outgoing feeder, canbe incorporated if IEC61850 peer-to-peer communication exists. The ultimate purpose is toinsure that personnel safety is not compromised and the tie breaker does not switch onto afault.

    On the Sterling Power Plant switchgear, each breaker is equipped with trip coil and closecoil monitoring circuit that reports the unhealthy state of the circuit with an alarm, as well asbeing a condition for the next operation of the breaker. For example, if a close coil monitoralarm condition occurs on the tie breaker, it will not let the tie breaker close under the ATSlogic unless the condition is corrected (Figure 11).

    The Plant has a load shedding control in place, which is conditioned by the underfrequency (81U-1&2) settings. If the system frequency dips below the 81U set point, the 3MWchiller is taken off line. Especially under HIGH LOAD mode, before the tie breaker can closefor automatic bus transfer action, all required load shedding breakers need to be open first.The purpose of load shedding is to ensure adequate supply and demand balance and to preventover-stressing the healthy sources prior to closing the tie breaker. Assume the same outgoing

    feeder breaker, say breaker 52F1-1 in Figure 10, experiences a breaker failure situation,whether it is not open by load shedding command or by tripping on over current in itsprotection zone, then a breaker failure event is declared. This event should be factored in theATS operation on the Tie relay (Figure 11).

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    Figure 11: ATS Logic with Incorporated Loss of Source 1,52TIE Close Circuit Alarm, 52F1-1 Load Shedding, & 52F1-1 CB Failure

    Refer to Figure 10 for the M-T-M bus configuration and Figure 11 for ATS logic. The logicabove illustrates an example of logic incorporating the following conditions:

    Source 1 feeding M1 Bay has an outage due to incoming utility issue, and no overcurrent is picked up by M1 relay

    Outgoing feeder F1-1 on M1 Bay/Switchgear is required to perform load shedding,and breaker F1-1 does not experience breaker failure

    Source 2 feeding M2 Bay is healthy, and no over current is picked by M2 relay Tie relay will execute the ATS command provided all conditions (including 52TIE

    breaker without close circuit monitor alarm) are met Any addition/removal of the conditions for closing the tie breaker can be

    accomplished in the micro-processing, multi-functional, GOOSE enabled relay(another benefit of IEC61850 compliance)

    The next protection issue to be discussed is the coordination of outgoing feeder faultwith the relay for the main incoming source. See Figures 12 and 13 for discussion. Traditionallyin a case that the switchgear or substation bus has only one incoming source, according to

    protection zone guideline the M1 relays instantaneous element is supposed to trip for a mainbus fault and the outgoing feeder relays are supposed to trip for a close-in downstream fault.However, should there be a close-in fault at 52F1-2 terminal, M1 relay should observe the samefault magnitude as if it had occurred on the main bus. Consequently, M1 relay could have anundesired trip. This coordination issue had led to a practice of disabling the instantaneouselement and installing an arc flash relay and/or a bus differential relay. This is the case at theSterling Plant.

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    Figure 12:

    Close-in Fault at 52F1-2 Terminal Figure 13:

    GOOSE Block-trip 52M1 Logic for a Fault at 52F1-2

    One more benefit of GOOSE messaging: the instantaneous element on M1 relay canactually be enabled but applied with a short timer to the M1 50P/N element output (to ensurethe fault is downstream of 52M1 breaker, 67P/N element could be used). If M1 relay senses alarge magnitude fault current and receives a block-trip signal from either outgoing feeder F1-1or F1-2 relay before M1 relays timer expires, then the fault is outside M1 relays protectionzone. Otherwise it is a fault on the main bus, which is further discussed next.

    Bus protection can be achieved without a bus differential protection or an arc flashprotection relay in the scheme. In Figures 14 and 15, even with the tie breaker is closed via ATSscheme, a fault on the M1 main bus is determined by these conditions:

    M1 relay 67P/N picks up Both F1-1 and F1-2 relays 67P/N do not pick up Tie relay 67 elements forward direction is toward M2 bus, Tie relay 67P/N does not

    pick up AND 52TIE breaker is closed

    Bus protection with GOOSE logic can also work for a fault on M2 bus. In this case, Tierelay forward element 67P/N is true. This approach is particularly useful for an existing facilitywhere a mismatch in breaker CTs is so huge, spare CTs are not sufficient, or the switchgear hasno room to accommodate two more bus differential protection relays.

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    Figure 14: Bus Fault on M1 Bus Figure 15: GOOSE Logic Bus Fault on M1 Bus

    Not in the Plants scope but worth discussion is a scenario of a large motor being fed byan outgoing feeder breaker. When the motor is running and the main bus outage occurs due tothe main breaker trip under the loss of main incoming source, with the large motor stoppedcompletely, the motors breaker should be opened first in order for the ATS to close the tiebreaker (similar to load shedding). This will prevent the healthy source on the opposite busfrom over-stressing or even unnecessary tripping because of energizing the large motordirectly. In case a fast transfer is required to keep the large motor running continuously, the tierelay has to have satisfactory sync check across two main buses constantly so the tie relay canbe closed via ATS once the main breaker is open for loss of the incoming source.


    The ATS scheme with automatic load transfer, closed transition, open transition, synccheck condition, and bus fault blocking close characteristics at the Sterling Power Plant hadbeen functionally tested off-line and on-line several times before it was placed in service. Sincethe ATS implementation, the Medical Campus has not been in the dark, proving that thescheme is functioning properly. For a future project with ATS requirement, IEC61850 GOOSEcommunication could be considered due the benefit of labor and material cost reduction,reliable communication network, fast operation, and high scalability. Some special protection,coordination, and control aspects including trip/close circuit monitors, load shedding, breakerfailure, bus blocking, bus protection, and a large running motor load can enhance thedimension of the ATS scheme if GOOSE messaging method is applied to the scheme.

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    Walter A. Elmore (2004). Protective Relaying Theory and Applications , Second Edition, Revised andExpanded. ISBN 0-8247-0972-1, ABB Power T&D Company Inc.

    Antti Hakala-Ranta et al, (2009). Utilizing Possibilities of IEC61850 and GOOSE , CIRED 2009 Paper 0741.

    IMAC050144-MB (2011). Relion Protection and Control, 615 Series ANSI Technical Manual , ABB Inc.Coral Springs, FL.

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    James S. Cramond , P.E., a co-author of this article, graduated from Manhattan College and hasworked in the power engineering field for 40 years. He is a registered professional engineer inN.Y, Connecticut, Pennsylvania, Rode Island, Massachusetts, Alabama, Texas, Puerto Rico and

    South Carolina and has been the engineer of record in most of these states for large projects.After his BEE degree, he worked with consultation engineering companies on process plants,worked at ABB environmental for some 12 years on Flue Gas Desulphurization projects for coalfired utilities, Eaton Corporation for 5 Years in the nuclear controls for projects overseas, as anoutside contractor for Northeast Utilities in Connecticut and for the past 6 years at YaleUniversity. The Yale University responsibility includes all of the Utility projects at both powerplants as well as major Campus construction jobs overseeing the Campus utility electricalsystem.

    Angel Carreras Jr., a co-author of this article, earned a Bachelor of Science in Electrical Engineerfrom Widener University and a Master of Science in Engineering and Engineering Managementfrom the University of Pennsylvania. Mr. Carreras has been with ABB Inc. for 13 years andcurrently holds the position of Northeastern U.S. Regional Technical Manager for theDistribution Automation Protective Relay Division. Before coming to ABB, Mr. Carreras workedfor fifteen years at the Naval Air System Command in remote sensing technology research anddevelopment for the U.S. Navy as a civilian electrical engineer and engineering manager.

    Vincent G. Duong , P.E., PMP, a co-author of this article, currently holds a Regional TechnicalManager position in Distribution Protection and Automation group at ABB. He received hisBSEE degree with Power System Specialization from the University of Alberta in Edmonton,Canada; and both MBA and MS in Operations and Project Management degrees from SouthernNew Hampshire University in Manchester, New Hampshire. Vincent has spent most of hiscareer in distribution and transmission protection and controls engineering, including systemmodeling, study, design, relay settings, and system disturbance analysis. He is also activelyinvolved in customer training and power system protection-coordination instruction. He is anIEEE member, a registered Professional Engineer of New Hampshire, and a ProjectManagement Professional of Project Management Institute (PMI).