1mrb520308-ben en numerical station protection system reb500-reb500sys

8/11/2019 1MRB520308-BEN en Numerical Station Protection System REB500-REB500sys

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Numerical Station Protection SystemBusbar Protection with integrated BreakerFailure, Line and Transformer Protection

ABB Switzerland LtdPower Technology Systems

REB500 / REB500sys1MRB520308-Ben

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Main featuresREB500 / REB500sys(contd)

Options Breaker failure protection (also separately

operable without busbar protection)

End fault protection Definite time overcurrent protection

Breaker pole discrepancy

Overcurrent and voltage check feature

Disturbance recording for power systemvoltages

Separate I0measurement for impedance-

grounded networks

Communication with substation monitoring

and control system (IEC 61850-8-1 /IEC 60870-5-103 / LON)

Internal user-friendly human machine inter-face with display

Redundant power supply for central unitsand/or bay units.

Addi tional

main features

REB500sys

REB500sys combines the well-proven numer-ical busbar and breaker failure protectionREB500 of ABB with Main 2 or back-up pro-tection for line or transformer feeders. TheMain 2 / Group 1 or back-up protection is

based on the well-proven protection functionlibrary of REL316*4 / RET316*4 from ABB for50 and 60 Hz.

Main 2 / back-up bay protection Definite- and inverse time over and under-

current protection

Directional overcurrent definite- andinverse time protection

Inverse time earth fault overcurrent protec-tion

Definite time over and undervoltage protec-tion

Three-phase current and three-phase volt-age plausibility

Main 2 / back-up bay protection: Line pro-tection High-speed distance protection

Directional sensitive earth fault protectionfor grounded systems against high resis-tive faults in solidly grounded networks

Directional sensitive earth fault protectionfor ungrounded or compensated systems

Autoreclosure for

- single-pole / three-pole reclosure

- up to four reclosure sequences

Synchrocheck with

- measurement of amplitudes, phaseangles and frequency of two voltagevectors

- checks for dead line, dead bus, deadline and bus

Group 1 / back-up bay protection: Trans-former protection

High-speed transformer differential protec-tion for 2- and 3-winding and auto-trans-formers

Thermal overload

Peak value over and undercurrent protec-tion

Independent T-Zone protection with trans-former differential protection

Appl ication

REB500

The numerical busbar protection REB500 isdesigned for the high-speed, selective protec-tion of MV, HV and EHV busbar installationsat a nominal frequency of 50, 60 and 16.7 Hz.

The structure of both hardware and softwareis modular enabling the protection to be eas-ily configured to suit the layout of the pri-mary system.

The flexibility of the system enables all con-figurations of busbars from single busbars toquadruple busbars with transfer buses, ring

busbars and 1 breaker schemes to be pro-tected.

In 1 breaker schemes the busbars and theentire diameters, including Stub/T-Zone can

be protected. An integrated tripping schemeallows to save external logics as well as wir-ing.

The capacity is sufficient for up to 60 feeders(bay units) and a total of 32 busbar zones.

The numerical busbar protection REB500detects all phase and earth faults in solidlygrounded and resistive-grounded power sys-tems and phase faults in ungrounded systemsand systems with Petersen coils.

The main CTs supplying the currents to thebusbar protection have to fulfil only modestperformance requirements (see page16).Theprotection operates discriminatively for allfaults inside the zone of protection and

remains reliably stable for all faults outsidethe zone of protection.


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Appl icat ionREB500sys

The REB500sys is foreseen in MV, HV andEHV substations with nominal frequencies of50 Hz resp. 60 Hz to protect the busbars and

their feeders. The bay protection functionsincluded in REB500sys are used as Main 2 /Group 1 - or back-up protection.

The system REB500sys is foreseen for allsingle or double busbar configurations (Linevariants L-V1 to L-V5 and Transformer vari-ant T-V1). In 1 breaker configurations, vari-ant L-V5 can be used for the bay levelfunctions autoreclosure and synchrocheck.The capacity is sufficient for up to 60 feeders(bay units) and a total of 32 busbar zones.

The REB500sys detects all bus faults in sol-idly and low resistive-grounded power sys-tems, all kind of phase faults in ungroundedand compensated power systems as well asfeeder faults in solidly, low resistive-grounded, compensated and ungrounded

power systems.

The protection operates selectively for allfaults inside the zone of protection andremains reliably stable for all faults outsidethe zone of protection.

REB500sys is perfectly suited for retrofitconcepts and stepwise upgrades. The bay unitis used as a stand-alone unit for bay protec-

tion functions (e.g. line protection, autoreclo-sure and synchrocheck or 2- and 3 windingtransformer protection or autonomous T-zone

protection). The central unit can be added at alater stage for full busbar and breaker failure

protection functionality.

Depending on the network voltage level andthe protection philosophy the following pro-tection concepts are generally applied:

Two main protection schemes per bayand one busbar protection.With REB500sys the protection concept

can be simplified. Due to the higher inte-gration of functionality one of the mainprotection equipment can be eliminated.

One main protection and one back-upprotection scheme per bay, no busbarprotection.With REB500sys a higher availability ofthe energy delivery can be reached, due tothe implementation of busbar and breakerfailure protection schemes where it hasn't

been possible in the past because of eco-nomical reasons.

Six standard options are defined for Main 2 /Group 1 or back-up bay level functions:

Line protection- Line variant 1 (L-V1)

directional, non-directional overcurrentprotection and directional earth fault prot.

- Line variant 2 (L-V2)as Line variant L-V1 plus distance prot.

- Line variant 3 (L-V3)as Line variant L-V2 plus autoreclosure

- Line variant 4 (L-V4)

as Line variant L-V3 plus synchrocheck- Line variant 5 (L-V5)

as Line variant L-V1 plus autoreclosure andsynchrocheck.

Transformer ProtectionTransformer Variant 1 (T-V1) as 2- or 3 wind-ing transformer differential protection, ther-mal overload, current functions; applicablealso as autonomous T-Zone protection.

Fig. 1


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Table 1 Overview of the func tionalities REB500 / REB500sys

Main functionality IEEE

Protectionfunction

IEC61850

Standard

Option

Special*onRequest

LineVariant1

(L-V1)

LineVariant2

(L-V2)

LineVariant3

(L-V3)

LineVariant4

(L-V4)

LineVariant5

(L-V5)

TransformerVariant1

(T-V1)

BayUnitHardware

Busbar protection 87B BBP PDIF Measurement of neutral current / detection I0 87BN I0 PDIF Breaker failure protection 50BF BFP RBRF End-fault protection 51/62EF EFP PTOC Breaker pole discrepancy 51/62PD PDF PTOC Overcurrent check feature 51 PTOC

Voltage check feature 59/27 PTOV/PTUV Check zone 87CZ BBP CZ PDIF Overcurrent protection (def. time) 51 OCDT PTOC Trip command re-direction 94RD - Software Matrix for Inputs / Outputs / Trip matrix - - Event recording up to 1000 events - ER - Disturbance recorder (4 x I) 95DR DR RDRE Disturbance recorder (4 x I, 5 x U) up to 10 sec. at 2400 Hz 95DR DR RDRE Communication interface IEC61850-8-1/ LON / IEC60870-5-103 - Com - Time synchronization - - Redundant power supply for central- and/or bay units - - Isolator supervision - - Differential current supervision - - Comprehensive self-supervision - - Dynamic Busbar replica with display of currents - - Testgenerator for commissioning & maintenance - - Remote-HMI - -

Delay / Integrator function - -

Binary logic and Flip-Flop functions - - Definite time over and undercurrent protection 51 OCDT PTOC Inverse time overcurrent protection 51 OCINV PTOC Definite time over and undervoltage protection 59/27 OVDT PTOV/PTUV Inverse time earth fault overcurrent protection 51N I0INV PTOC Directional overcurrent definite time protection 67 DIROCDT PTOC Directional overcurrent inverse time protection 67 DIROCINV PTOC Three phase current plausibility 46 CHKI3PH PTOC Three phase voltage plausibility 47 CHKU3PH PTUV Test Sequenzer - - Direct. sensitive EF prot. for grounded systems 67N DIREFGND PDEF Direct. sensit ive EF prot. for ungrounded or compensated systems 32N DIREFISOL PSDE Distance protection 21 DIST PDIS Autoreclosure 79 AR RREC Synchrocheck 25 SYNC RSYN Transformer differential protection 2 winding 87T DIFTRA PDIF Transformer differential protection 3 winding 87T DIFTRA PDIF

Thermal overload 49 TH PTTR Peak value over and undercurrent protection 50 OCINST PIOC

* only for special applications500BU03: bay unit

500BU03for50Hz,

60Hz

500BU03for50Hz,

60Hz,

16.7

Hz

Functionality

REB

500/REB500sys

REB500


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Mode ofinstallationREB500 /

REB500sys

There are three versions of installing the numerical busbar protection REB500 and the numeri-cal station protection REB500sys:

Distributed installationIn this case, the bay units (see Fig. 21) areinstalled in casings or cubicles in the indivi-dual switchgear bays distributed around the

station and are connected to the central pro-cessing unit by optical fibre cables. The cen-tral processing unit is normally in a centrallylocated cubicle or in the central relay room.

Fig. 2 Distributed installation

Centralized installation19"mounting plates with up to three bayunits each, and the central processing unit aremounted according to the size of the busbar

system in one or more cubicles (see Fig. 20).A centralized installation is the ideal solution

for upgrading existing stations, since verylittle additional wiring is required and com-

pared with older kinds of busbar protection,much more functionality can be packed into

the same space.

Fig. 3 Centralized installation

Combined centralized and distributedinstallation

Basically, the only difference between a dis-tributed and a centralized scheme is themounting location of the bay units and there-fore it is possible to mix the two philosophies.


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System designREB500 /REB500sys

Bay unit (500BU03)The bay unit (see Fig. 4) is the interface

between the protection and the primary sys-

tem process comprising the main CTs, isola-tors and circuit-breaker and performs theassociated data acquisition, pre-processing,control functions and bay level protectionfunctions. It also provides the electrical insu-lation between the primary system and theinternal electronics of the protection.

The input transformer module contains fourinput CTs for measuring phase and neutralcurrents with terminals for 1 A and 5 A.Additional interposing CTs are not required,

because any differences between the CTratios are compensated by appropriately con-

figuring the software of the respective bayunits.

Optional input transformer module also con-tains five input voltage transformers for themeasurement of the three-phase voltages andtwo busbar voltages and recording of voltagedisturbances or 6 current transformers fortransformer differential protection. (seeFig. 12).

In the analogue input and processing module,the analogue current and voltage signals areconverted to numerical signals at a samplingrate of 48 samples per period and then numer-ically preprocessed and filtered accordingly.Zero-sequence voltage and zero-current sig-nals are also calculated internally. The Pro-

cess data are transferred at regular intervalsfrom the bay units to the central processingunit via the process bus.

Every bay unit has 20 binary inputs and 16relay outputs. The binary I/O module detectsand processes the positions of isolators andcouplers, blocking signals, starting signals,external resetting signals, etc. The binaryinput channels operate according to a pat-ented pulse modulation principle in a nominalrange of 48 to 250 V DC. The PC-based HMI

program provides settings for the thresholdvoltage of the binary inputs. All the binaryoutput channels are equipped with fast oper-ating relays and can be used for either signal-ing or tripping purposes (see contact data in

Table 8).A software logic enables the input and outputchannels to be assigned to the various func-tions. A time stamp is attached to all the datasuch as currents, voltages, binary inputs,events and diagnostic information acquired

by a bay unit.

Where more binary and analogue inputs areneeded, several bay units can be combined toform a feeder/bus coupler bay (e.g. a bus cou-

pler bay with CTs on both sides of the bus-tiebreaker requires two bay units).

The bay unit is provided with local intelli-gence and performs local protection (e.g.

breaker failure, end fault, breaker pole dis-crepancy), bay protection (Main 2 or back-up

bay protections) as well as the event and dis-turbance recording.

Fig. 4 Block diagram of a bay unit and a central unit

CIM

DC

CPUModule

CPUModule

CPU

Module

SAS/SMSInterface

RS 232Interface

Real-timeClock

Star-coupler

BinaryI/O

Starcoupler

Local HMI

Electrical

insulation

Process-bus

Filter

Binary in/outputregisters

A/D

Filter

CPU

Optical

Interface

DC

DC

DSPDP

Mem

Central Unit (500CU03)Bay Uni t (500BU03)

Local HMI

DC


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In the event that the central unit is out ofoperation or the optical fibre communicationis disrupted an alarm is generated, the bay

unit will continue to operate, and all local andbay protection as well as the recorders (eventand disturbance) will remain fully functional(stand-alone operation).

The hardware structure is based on a closed,monolithic casing and presented in twomounting solutions:

Without local HMI: ideal solution if con-venient access to all information via thecentral unit or by an existing substationautomation system is sufficient.

With local HMI and 20 programmable

LEDs (Fig. 5): ideal solution for decentraland kiosk mounting (AIS), since all infor-mation is available in the bay.

For the latter option it is possible to have theHMI either built in or connected via a flexiblecable to a fixed mounting position (seeFig. 25).

In the event of a failure, a bay unit can be eas-ily replaced. The replacement of a bay unitcan be handled in a simple way. During sys-tem start-up the new bay unit requests itsaddress, this can be entered directly via its

local HMI. The necessary setting values andconfiguration data are then downloaded auto-matically.

Addi tional p lug-and-play functionali tyBay units can be added to an existingREB500 system in a simple way.

Fig. 5 Built-in HMI directly on the bay unit500BU03.

Central unit (500CU03)The hardware structure is based on standardracks and only a few different module typesfor the central unit (seeFig. 4).

The modules actually installed in a particularprotection scheme depend on the size, com-plexity and functionality of the busbar sys-tem.

A parallel bus on a front-plate motherboardestablishes the interconnections between themodules in a rack. The modules are insertedfrom the rear.

The central unit is the system manager, i.e. itconfigures the system, contains the busbarreplica, assigns bays within the system, man-

ages the sets of operating parameters, acts asprocess bus controller, assures synchroniza-tion of the system and controls communica-tion with the station control system.

The variables for the busbar protection func-tion are derived dynamically from the processdata provided by the bay units.

The process data are transferred to the centralprocessor via a star coupler module. Up to 10bay units can be connected to the first centralprocessor and 10 to the others. Central pro-cessors and star coupler modules are added

for protection systems that include more than10 bay units. In the case of more than 30 bayunits, additional casings are required foraccommodating the additional central proces-sors and star coupler modules required.

All modules of the central unit have a plug-and-play functionality in order to minimizemodule configuration.

One or two binary I/O modules can be con-nected to a central processing unit.

The central unit comprises a local HMI with

20 programmable LEDs (Fig. 6), a TCP/IPport for very fast HMI500-REBWIN connec-tion within the local area network.

Fig. 6 Central unit


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Functionality ofREB500 /REB500sys

Busbar protectionThe protection algorithms are based on twowell-proven measuring principles which have

been applied successfully in earlier ABB low-impedance busbar protection systems:

a stabilized differential current measure-ment

the determination of the phase relationshipbetween the feeder currents (phase com-parison).

The algorithms process complex current vec-tors which are obtained by Fourier analysisand only contain the fundamental frequencycomponent. Any DC component and harmon-ics are suppressed.

The first measuring principle uses a stabilizeddifferential current algorithm.The currents are evaluated individually foreach of the phases and each section of busbar(protection zone).

Fig. 7 Tripping characteristic of the stabilizeddifferential current algorithm.

In Fig. 7, the differential current is

and the restraint current

where Nis the number of feeders. The fol-lowing two conditions have to be accom-

plished for the detection of an internal fault:

wherekst stabilizing factor

kst max stabilization factor limit.

A typical value is kst max= 0.80

IK min differential current pick-up value

The above calculations and evaluations areperformed by the central unit.

The second measuring principle determinesthe direction of energy flow and involvescomparing the phases of the currents of allthe feeders connected to a busbar section.

The fundamental frequency current phasors1..n (5) are compared. In the case of an in-ternal fault, all of the feeder currents have al-most the same phase angle, while in normal

operation or during an external fault at leastone current is approximately 180 out of

phase with the others.

The algorithm detects an internal fault whenthe difference between the phase angles of allthe feeder currents lies within the trippingangle of the phase comparator (see Fig. 8).

( | | )

0Restraint current

( | | ) 0

IKmin

k = 1

Ksetting =kstmaxTr

ipping

area

Differentialcurrent

Restraintarea

=

= N

n

LnI1

DiffI (1)

=

=N

n

LnI

1

RestI(2)

max

Rest

DiffIstst k

Ik >= (3)

minKDiff II > (4)

( )( )

=

LnIRe

LnIIm

arctann

(5)


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Fig. 8 Characteristic of the phase comparator for

determining energy direction.

The task of processing the algorithms isshared between the bay units and the central

processing unit. Each of the bay units contin-uously monitors the currents of its own fee-der, preprocesses them accordingly and thenfilters the resulting data according to a Fou-rier function. The analogue data filtered inthis way are then transferred at regular inter-vals to the central processing unit running the

busbar protection algorithms.

Depending on the phase-angle of the fault,the tripping time varies at Idiff/Ikmin5 bet-ween 20 and 30 ms including the auxiliarytripping relay.

Optionally, the tripping signal can be inter-locked by a current or voltage check featurein the bay unit that enables tripping onlywhen a current above a certain minimum isflowing, respectively the voltage is below acertain value.

Breaker failure protectionThe breaker failure functions in the bay units

monitor the phase currents independently ofthe busbar protection. They have two timerswith individual settings.

Operation of the breaker failure function isenabled either:

internally by the busbar protection algo-rithm (and, if configured, also by the inter-nal line protection, overcurrent or polediscrepancy protection features) of the baylevel

externally via a binary input, e.g. by theline protection, transformer protection etc.

After the delay of the first timer has expired,a tripping command can be applied to a sec-ond tripping coil on the circuit-breaker and a

remote tripping signal transmitted to the sta-tion at the opposite end of the line.

This first timer operates in a stand-alonemode in the bay unit.

If the fault still persists at the end of the sec-ond time delay, the breaker failure functionuses the busbar replica to trip all the otherfeeders supplying the same section of busbarvia their bay units.

A remote tripping signal can be configured inthe software to be transmitted after the first or

second timer.

Phase-segregated measurements in each bayunit cope with evolving faults.

End fault protection

In order to protect the dead zone betweenan open circuit-breaker and the associatedCTs, a signal derived from the breaker posi-tion and the close command is applied.

The end fault protection is enabled a certaintime after the circuit-breaker has been open-ed. In the event of a short circuit in the deadzone the nearest circuit-breakers are tripped.

This function is performed in a stand-alonemode in the bay unit.

Overcurrent funct ionA definite time overcurrent back-up protec-tion scheme can be integrated in each bayunit. (The operation of the function, if para-meterized, may start the local breaker failure

protection scheme).

This function is performed in a stand-alone

mode in the bay unit.

Overcurrent check feature

The overcurrent check feature is only per-formed in the bay unit. It is effective for a

busbar protection trip and for an intertrippingsignal (including end fault and breaker fail-ure) and prevents those feeders from beingtripped that are conducting currents lowerthan the setting of the overcurrent check fea-ture.

Voltage check featureThe voltage criterion is measured in the bay

unit. The function can be configured asrelease criterion per zone through internal

Phase-shift

74

0 12

= 36

12

= 144

Restraint area

Case 1 2

max = 74

Tripping area

Busbar

Operating characteristic

Re

Im

I1

I2

Im

ReI1

I2

180

Case 1: External fault = 144

Case 2: Internal fault = 36


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Functionality ofREB500 / REB500sys(contd)



linking in the central unit. This necessitatesthe existence of one set of voltage transform-ers per zone in one of the bay units. Tripping

is only possible if the voltage falls short of(U) the set value.

Additionally this release criterion can be con-figured for each feeder (voltage transformersmust be installed). For details see Table 22.

Check zone CriterionThe check zone algorithm can be used as arelease criterion for the zone-discriminatinglow-impedance busbar protection system. Itis based on a stabilized differential currentmeasurement, which only acquires the feedercurrents of the complete busbar. The isolator /

breaker positions are not relevant for this cri-terion.

Neutral current detection I0Earth fault currents in impedance-groundedsystems may be too low for the stabilized dif-ferential current and phase comparison func-tions to detect. A function for detecting theneutral current is therefore also available, butonly for single phase-to-earth faults.

Pole discrepancyA pole discrepancy protection algorithmsupervises that all three poles of a circuit-

breakers open within a given time.

This function monitors the discrepancy bet-ween the three-phase currents of the circuit-

breaker.

When it picks up, the function does not sendan intertripping signal to the central unit, but,if configured, it starts the local breaker failure

protection (BFP logic 3).

This function is also performed in a stand-alone mode in the bay unit.

Event recordingThe events are recorded in each bay unit. Atime stamp with a resolution of 1ms is attach-ed to every binary event. Events are dividedinto the three following groups:

system events

protection events

test events.

The events are stored locally in the bay unitor in the central unit.

Disturbance recordingThis function registers the currents and the

binary inputs and outputs in each bay. Volt-ages can also be optionally registered (seeTable 14).

A disturbance record can be triggered byeither the leading or lagging edges of all

binary signals or by events generated by theinternal protection algorithms. Up to 10 gen-eral-purpose binary inputs may be configuredto enable external signals to trigger a distur-

bance record. In addition, there is a binaryinput in the central and the bay unit for start-ing the disturbance recorders of all bay units.

The number of analogue channels that can be

recorded, the sampling rate and the recordingperiod are given in Table 14. A lower sam-pling rate enables a longer period to berecorded.

The total recording period can be divided intoa maximum of 15 recording intervals per bayunit.

Each bay unit can record a maximum of 32binary signals, 12 of which can be configuredas trigger signals.

The function can be configured to record thepre-disturbance and post-disturbance states ofthe signals.

The user can also determine whether the re-corded data is retained or overwritten by thenext disturbance (FIFO = First In, First Out).

This function is performed in a stand-alonemode in the bay unit (see page6).

Note:

Stored disturbance data can be transferred viathe central unit to other computer systems for

evaluation by programs such as PSM505(E_wineve)[4].Files are transferred in theCOMTRADE format.

After retrieving the disturbance recorder data,it is possible to display them graphically withPSM505 (E_wineve) directly.

Communication interface

Where the busbar protection has to communi-cate with a station control or station monitor-ing system (SAS/SMS), a communicationmodule is added to the central unit. The mod-ule supports the interbay bus protocols IEC61850-8-1, IEC 60870-5-103 and LON.


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The IEC 61850-8-1 interbay bus transfers viaeither optical or electrical connection:

differential current of each protection zone

monitoring information from REB500central unit and bay units

binary events (signals, trips and diagnos-tic)

trip reset command

disturbance recording data (via MMS filetransfer protocol)

time synchronization with Simple Net-work Time Protocol (SNTP)

two independent time servers are sup-ported. Server 2 as backup time.

The LON interbay bus transfers via opticalconnection:

differential currents of each protectionzone

binary events (signals, trips and diagnos-tic)

trip reset command

disturbance recording data (via HMI500-REBWIN)

time synchronization.

The IEC 60870-5-103 interbay bus transfersvia either optical or electrical connection:

time synchronization

selected events listed in the public part

all binary events assigned to a private part

all binary events in the generic part

trip reset command

Test generatorThe HMI program (HMI500-REBWIN)

which runs on a PC connected to either a bayunit or the central processing unit includes atest generator.

During commissioning and system mainte-nance, the test generator function enables theuser to:

activate binary input and output signals

monitor system response.

test the trip circuit up to and including thecircuit-breaker

test the reclosure cycles

establish and perform test sequences withvirtual currents and voltages for the bay

protection of the REB500sys.

The test sequencer enables easy testing of thebay protection without the need to decommis-sion the busbar protection. Up to seven se-quences per test stage can be started. Thesequences can be saved and reactivated forfuture tests.

Isolator supervision

The isolator replica is a software feature with-out any mechanical switching elements. Thesoftware replica logic determines dynami-cally the boundaries of the protected busbarzones (protection zones). The system moni-tors any inconsistencies of the binary inputcircuits connected to the isolator auxiliarycontacts and generates an alarm after a settime delay.

In the event of an isolator alarm, it is possibleto select the behavior of the busbar protec-tion:

blocked

zone-selective blocked

remain in operation.

Table 2

N/O

contact:

Isolator

CLOSED

N/C

contact:

Isolator

OPEN

Isolator position

open open Last position stored+ delayed isolator alarm,

+ switching prohibitedsignal

open closed OPEN

closed open CLOSED

closed closed CLOSED+ delayed isolator alarm,+ switching prohibited

signal


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Differential current supervisionThe differential current is permanently super-vised. Any differential current triggers a

time-delayed alarm. In the event of a differ-ential current alarm, it is possible to select thebehavior of the busbar protection:

blocked

zone-selective blocked

remain in operation.

Trip redirection

A binary input channel can be provided towhich the external signal monitoring the cir-cuit-breaker air pressure is connected. Trip-

ping is not possible without active signal.When it is inactive, a trip generated by therespective bay unit is automatically redirectedto the station at the opposite end of the lineand also to the intertripping logic to trip allthe circuit-breakers connected to the samesection of busbar.

The trip redirection can also be configuredwith a current criterion (overcurrent checkfeature).

Human machine interface (HMI)The busbar protection is configured andmaintained with the aid of human machine

interfaces at three levels.

Local HMIThe local display interface installed in thecentral unit and in the bay units comprises:

a four-line LCD with 16 characters eachfor displaying system data and error mes-sages

keys for entering and display as well as 3LEDs for the display of trips, alarms andnormal operation.

in addition 20 freely programmable LEDsfor user-specific displays on the bay unit

500BU03 and central unit 500CU03.

The following information can be displayed:

measured input currents and voltages

measured differential currents (for the bus-bar protection)

system status, alarms

switchgear and isolator positions (withinthe busbar protection function)

starting and tripping signals of protectionfunctions.

External HMI (HMI500-REBWIN)More comprehensive and convenient controlis provided by the external HMI software run-ning on a PC connected to an optical interfaceon the front of either the central processingunit or a bay unit. The optical interface iscompletely immune to electrical interfer-ence. The PC software facilitates configura-tion of the entire busbar protection, the set-ting of parameters and full functional check-ing and testing. The HMI500-REBWIN canalso be operated via the LON Bus onMicroSCADA for example, thus eliminatinga separate serial connection to the centralunit.

The HMI runs under MS WINDOWS NT,WINDOWS 98, WINDOWS 2000 and WIN-

DOWS XP. The HMI500-REBWIN isequipped with a comfortable on-line helpfunction. A data base comparison functionenables a detailed comparison between twoconfiguration files (e.g. between the PC andthe central unit or between two files on thePC).

Remote HMI

A second serial interface at the rear of thecentral unit provides facility for connecting aPC remotely via either an optical fibre, TCP/IP or modem link. The operation and functionof HMI500-REBWIN is the same whether the

PC is connected locally or remotely.

Addi tional

functionalities

REB500sys

Bay level functionsThese functions are based on the well estab-lished and well-proven functions built in theABB line and protection REL316*4 /RET316*4. The bay level functions containall the relevant additional functions, whichare normally requested of a line and trans-former protection scheme. The line protection

is described in the data sheet REL316*4 [1]and the transformer protection is described inthe data sheet RET316*4[5].

The line protection functions (L-V1 - L-V5)are used as Main 2 or back-up for lines aswell as for transformer bays.


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Additional functional-ities REB500sys(contd)

tion with an inverse time earth fault overcur-rent function. In both cases the neutral currentand voltage can be derived either externally

or internally. This function works either with-the same communication channel as the dis-tance protection scheme or with anindependent channel.

Directional sensitive earth fault protectionfor ungrounded or compensated systemsThe sensitive earth fault protection functionfor ungrounded systems and compensatedsystems with Petersen coils can be set foreither forwards or reverse measurement. Thecharacteristic angle is set to 90(U0 I0 sin ) in ungrounded systems and to0 or 180 (U0 I0 cos ) for systems with

Petersen coils. The neutral current is alwaysused for measurement in the case of systemswith Petersen coils, but in ungrounded sys-tems its use is determined by the value of thecapacitive current and measurement is per-formed by a core-balance CT to achieve therequired sensitivity. To perform this functionthe BU03 with 3I, 1MT and 5U is required.

Definite time over and undercurrent pro-tectionThis function is used as Main 2 or as back-upfunction respectively for lines, transformer or

bus-tie bays. This function can be activated in

the phase- and/or the neutral current circuit.

Inverse time overcurrent protectionThe operating time of the inverse time over-current function reduces as the fault currentincreases and it can therefore achieve shorteroperating times for fault locations closer tothe source. Four different characteristicsaccording to British Standard 142 designatednormal inverse, very inverse, extremely

inverse and long time inverse but with anextended setting range are provided. Thefunction can be configured for single phase

measurement or a combined three-phase mea-surement with detection of the highest phasecurrent.

Inverse time earth fault overcurrent protec-tionThe inverse time earth fault overcurrent func-tion monitors the neutral current of the sys-tem. Four different characteristics accordingto British Standard 142 designated normalinverse, very inverse, extremely inverse andlong time inverse but with an extended set-ting range are provided.

Directional overcurrent definite / inversetime protectionThe Directional overcurrent definite timefunction is available either with inverse timeor definite time overcurrent characteristic.This function comprises a voltage memoryfor faults close to the relay location. Thefunction response after the memory time haselapsed can be selected (trip or block).

Definite time over and undervoltage pro-tectionThis function works with a definite timedelay with either single or three-phase mea-

surement.

Three-phase current p lausibilityThis function is for checking the sum and the

phase sequence of the three-phase currents.

Three-phase voltage plausibilityThis function is used for checking the sumand the phase sequence of the three-phasevoltages.

Addi tional

features ofREB500 /

REB500sys

Self-supervision

All the system functions are continuouslymonitored to ensure the maximum reliabilityand availability of the protection. In the eventof a failure, incorrect response or inconsis-tency, the corresponding action is taken toestablish a safe status, an alarm is given andan event is registered for subsequent diagnos-tic analysis.

Important items of hardware (e.g. auxiliarysupplies, A/D converters and main and pro-gram memories) are subjected to various testswhen the system is switched on and also dur-ing operation. A watchdog continuously

monitors the integrity of the software func-

tions and the exchange of data via the processbus is also continuously supervised.

The processing of tripping commands is oneof the most important functions from the reli-ability and dependability point of view.Accordingly, every output channel comprisestwo redundant commands, which have to beenabled at regular intervals by a watchdog. Ifthe watchdog condition is not satisfied, thechannels are blocked.

Extension of the systemThe system functions are determined by soft-

ware, configured using the software configu-ration tool.


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Page 15


The system can be completely engineered inadvance to correspond to the final state of thestation. The software modules for new bays

or features can be activated using the HMIwhen the primary plant is installed or the fea-tures are needed.

Additional system functions, e.g. breaker fail-ure, end fault protection or bay level

back-up / Main 2 functions can be easily acti-vated at any time without extra hardware.

Resetting the trip commands/-signalsThe following resetting modes can be selec-ted for each binary output (tripping or signaloutputs):

Latches until manually reset

Resets automatically after a delay.

Inspection/maintenanceA binary input is provided that excludes a bayunit from evaluation by the protection sys-tem. It is used while performing maintenancerespectively inspection activities on the pri-mary equipment.

Redundant power supplies (Option)Two power supply modules can be fitted in aredundant arrangement, e.g. to facilitatemaintenance of station batteries. This is anoption for the central unit as well as for the

bay unit.

Time synchronizationThe absolute time accuracy with respect to anexternal time reference depends on themethod of synchronization used:

no external time synchronization:accuracy approx. 1 min. per month

periodic time telegram with minute pulse(radio or satellite clock or station controlsystem): accuracy typically 10 ms

periodic time telegram as above with sec-ond pulse: accuracy typically 1 ms.

a direct connection of a GPS or DCF77 tothe central unit is possible: accuracy typi-cally 1 ms.

The system time may also be synchronizedby a 1 minute pulse applied to a binary inputon the central unit.

Requirements Optical fibre cablesA distributed busbar protection layout re-

quires optical fibre cables and connectorswith the following characteristics:

2 optical fibre cores per bay unit

glass fibres with gradient index

diameter of core and sheath 62.5,respectively 125 m

maximum permissible attenuation 5 dB

FST connector (for 62.5 m optical fibres)

rodent protected and longitudinally water-proof if in cable ducts

Please observe the permissible bending radiuswhen laying the cables.

The following attenuation figures are typicalvalues which may be used to determine anapproximate attenuation balance for each

bay:

Fig. 9 Attenuation

Isolator auxiliary contact

Auxiliary contacts on the isolators are con-nected to binary inputs on the bay units and

control the status of the busbar replica in the

numerical busbar protection.

Optical equipmentTypical

attenuation

for gradient index (840 nm) 3.5 dB/km

per connector 0.7 dB

per cable joint 0.2 dB

Central unit Bay unit1200 m1 m1 m

FST connector

5 dB

FST connector


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Page 16

Requirements (contd)Requirements (contd)


One potentially-free N/O and N/C contact arerequired on each isolator. The N/O contactsignals that the isolator is CLOSED and the

N/C contact that the isolator is OPEN. Dur-ing the closing movement, the N/O contactmust close before the isolator main contactgap reaches its flashover point.

Conversely, during the opening movement,the N/O contact must not open before the iso-lator main contact gap exceeds its flashover

point.If this is not the case, i.e. the contact signalsno longer closed beforehand, then the N/Ccontact may not signal OPEN before theflashover point has been exceeded.

Fig. 10 Switching sequence of the auxiliary contacts that control the busbar replica

Circuit-breaker replicaWhen the circuit-breaker replica is read in thefeeder or the bus-tie breaker, the circuit-

breaker CLOSE command must also be con-nected.

Main current transformerThe algorithms and stabilization features usedmake the busbar protection largely insensitiveto CT saturation phenomena. Main CTs typesTPS (B.S. class x), TPX, TPY, 5P.. or 10P..are permissible.

TPX, TPY and TPZ CTs may be mixed

within one substation in phase-fault schemes.The relatively low CT performance neededfor the busbar protection makes it possible forit to share protection cores with other protec-tion devices.

Current transformer requirements for sta-bility during external faults (Busbar protec-tion)The minimum CT requirements for 3-phasesystems are determined by the maximumfault current.

The effective accuracy limit factor (n') must

be checked to ensure the stability of the bus-bar protection during external faults.

The rated accuracy limit factor is given by theCT manufacturer. Taking account of the bur-den and the CT losses, the effective accuracylimit factor n' becomes:

where:

n = rated accuracy limit factorPN = rated CT powerPE = CT lossesPB = burden at rated current

In the case of schemes with phase-by-phasemeasurement, n' must satisfy the followingtwo relationships:

where:

IKmax = max. primary through-fault current

I1N = rated primary CT current

Taking the DC time constant of the feederinto account, the effective n' becomes:

Close isolator

Flashover gap

must be closed

must be open

may be closed

Isolator

CLOSEDnormally-open

OPENnormally-closed

Closedend-position

Openend-position

Open isolator

Auxiliary contacts :

EB

EN

PP

PPnn'

++

=

n1 IKmax5 I1N

-------------------(1)


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(2) n' 10for TN120 ms, orn' 20for 120 ms


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Table 5 Mechanical tests

Hardware modules

Vibration and shock

Resonance investigation 2 to 150 Hz / 0.5 gn EN 60255-21-1 (1996),

IEC 60255-21-1 (1988), IEEE 344-1987

Permanent strength 10 to 150 Hz / 1 gn EN 60255-21-1 (1996),IEC 60255-21-1 (1988)

Seismic 2 to 33 Hz, 2 gn EN 60255-21-3 (1995),IEC 60255-21-3 (1995), IEEE 344-1987

Shock test Cl.1; A = 15 gn; D = 11 ms;pulse/axis = 3 EN 60255-21-2 (1996), IEC 60255-21-2

(1988), IEC 60068-2-27 (1987)

Bump test Cl.1; A = 10 gn; D = 16 ms;pulse/axis = 1000 EN 60255-21-2 (1996), IEC 60255-21-2

(1988), IEC 60068-2-29 (1987)

Table 6 Enclosure protection classes

Bay unit 19" central unit Cubicle (see Table 12)

IP40 IP20 IP40-50

Table 7 Analogue inpu ts (Bay unit )

Currents

4 /

9 input channels

I1, I2, I3, I4 /

I1, I2, I3, I4, I5, I6, I7, I8, I9

Rated current (IN) 1 A or 5 A by choice of terminals,adjustable CT ratio via HMI500-REBWIN

Thermal ratings:continuous

for 10 sfor 1 s

1 half-cycle

4 x IN

30 xIN100 x IN

250 x IN(50/60 Hz) (peak)

EN 60255-6 (1994),IEC 60255-6 (1988),VDE 0435, part 303

EN 60255-6 (1994),IEC 60255-6 (1988),VDE 0435, Part 303

Burden per phase 0.02 VA at IN = 1 A0.10 VA at IN = 5 A

Voltages (optional)

5 input channels U1, U2, U3, U4, U5 500BU03

Rated voltage (UN) 100 V, 50/60 Hz, 16.7 Hz200 V, 50/60 HzVT ratio adjustable via HMI500-REBWIN

Thermal ratings:continuous

for 10 s

2 x UN

3 x UN

EN 60255-6 (1994),IEC 60255-6 (1988),VDE 0435, part 303

Burden per phase 0.3 VA at UN

Common data

Rated frequency (fN) 50 Hz, 60 Hz 16.7 Hz

adjustable via HMI500-REBWIN


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Technical data (contd)Technical data (contd)


Table 9 Auxil iary supply

Table 8 Binary inputs/outputs (Bay uni t, Central unit )

Binary outputs

General

Operating time 3 ms (typical)

Max. operating voltage 300 V AC/DC

Max. continuous rating 8 A

Max. make and carry for 0.5 s 30 A

Max. making power at 110 V DC 3300 W

Binary output reset response, pro-grammable per output

- latched- automatic reset (delay 0...60 s)

Heavy-duty N/O contacts CR08...CR16, 500BU03

Heavy-duty N/O contacts CR01...CR04, CR07...CR09 - 500CU03

Breaking current for (L/R = 40 ms)1 contact

2 contacts in series

U


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Table 10 Optical interfaces

Table 12 Cubicle design

Number of cores 2 fibre cores per bay unit

Core/sheath diameter 62.5/125m (multi-mode)

Max. permissible attenuation 5 dB (seeFig. 9)

Max. length approx. 1200 m

Connector Type FST for 62.5m optical fibre cables

Table 11 Mechanical design

Mounting

Bay unit flush mounting on frames or in cubiclesHMI integrated or separately mounted

Central unit flush mounting on frames or in cubicles

Cubicle Standard type RESP97 (for details see 1MRB520159-Ken)

Dimensions w x d x h 800 x 800 x 2200 mm (single cubicle)1600 x 800 x 2200 mm (double cubicle)2400 x 800 x 2200 mm (triple cubicle) *)

*) largest shipping unit

Total weight (with all units inserted) approx. 400-600 kg per cubicle

Terminals Terminal type Connection data

Solid Strand

CTs Phoenix URTK/S 0.5 - 10 mm2 0.5 - 6 mm2

VTs Phoenix URTK/S 0.5 - 10 mm2 0.5 - 6 mm2

Power supply Phoenix UK 6 N 0.2 - 10 mm2 0.2 - 6 mm2

Tripping Phoenix UK 10-TWIN 0.5 - 16 mm2 0.5 - 10 mm2

Binary I/Os Phoenix UKD 4-MTK-P/P 0.2 - 4 mm2 0.2 - 2.5 mm2

Internal wiring gauges

CTs 2.5 mm2 stranded

VTs 1.5 mm2 stranded

Power supply 1.5 mm2 stranded

Binary I/Os 1.5 mm2 stranded


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Recording facilities

Table 13 Event recorder

Table 15 Interbay bus protocols

Event recorder Bay unit Central unitSystem eventsProtection eventsTest events

100 total 1000 total

Table 14 Disturbance recorder

Analog channel Recording periodSample rate selectable

Options 4 currentsor9 currents

4 currentsand5 voltages

802 Hz (16.7 Hz)2400 Hz (50 Hz)2880 Hz (60 Hz)

401 Hz (16.7 Hz)1200 Hz (50 Hz)1440 Hz (60 Hz)

600 Hz (50 Hz)720 Hz (60 Hz)

Standard X X*) 1.5 s 3 s 6 s

Option 1 X X 6 s 12 s 24 s

Option 2 X X 10 s 20 s 40 s

Number of disturbance records = total recording time / set recording period (max.15)

Independent settings for pre-fault and post-fault period (min. setting 200 ms).

Format: COMTRADE 91 and COMTRADE 99

*) in Standard, voltage channels are recorded, if existing

IEC 61850-8-1 IBB protocol

IEC 61850-8-1 interbay bus supports: - Time synchronization via SNTP: typical accuracy +/- 1ms- Two independent timeservers are supported. Server 2 as

backup time- Optical or electrical connection- Differential current of each protection zone- Monitoring information from REB500 central unit and bay unit- Binary events (signals, trips and diagnostic)- Trip reset command- Single connection point to REB500 central unit- Disturbance recorder access via MMS file transfer protocol- Export of ICD - file, based on Substation Configuration

Language SCL

LON IBB protocol

LON interbay bus supports - Time synchronization: typical accuracy 1 ms- Optical connection- Differential currents of each protection zone

- Binary events (signals, trips and diagnostic)- Trip reset commands- Single connection point to REB500 central unit- Disturbance recorder data (via HMI500- REBWIN)

IEC 60870-5-103 IBB protocol

IEC 60870-5-103 interbay bus sup-ports

- Time synchronization: typical accuracy 5 ms- Optical or electrical connection- Subset of binary events as specified in IEC

Private range: Support of all binary eventsGeneric mode: Support of all binary events

- Trip reset command- Disturbance recording data

Address setting of station address 0...254

Sub address setting, common addressof ADSU

0...255 (CAA)CAA per bay unit freely selectable


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Page 23


Software modules

Station level functions

(Applicable for nominal frequencies of 50, 60 and 16.7 Hz)

Table 16 Busbar protection (87B)

Min. fault current pick-up setting (Ikmin)Neutral current detection

500 to 6000 A in steps of 100 A100 to 6000 A

Stabilizing factor (k) 0.7 to 0.9 in steps of 0.05

Differential current alarmscurrent settingtime delay setting

5 to 50% x Ikminin steps of 5%2 to 50 s in steps of 1 s

Isolator alarmtime delay 0.5 to 90 s

Typical tripping time 20 to 30 ms at Idiff/Ikmin5 incl. tripping relays; for fN= 50, 60 Hz30 to 40 ms at Idiff/Ikmin5 incl. tripping relays; for fN= 16.7 Hz

CT ratio per feeder 50 to 10 000/1 A,50 to 10 000/5 A, adjustable via HMI

Reset time 30 to 96 ms (at 1.2


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Table 19 Overcurrent protection (51)

Characteristic definite time

Measurement:

Setting range 0.1 to 20 x IN in steps of 0.1 x IN

Setting range time delay 10 ms to 20 s in steps of 10 ms

Reset ratio typically 95%

Reset time 20 to 60 ms (at 1.2 or in combination.

Table 23 Check zone cri terion (87CZ)

Min. fault current pick-up setting (Ikmin) 500 to 6000 A in steps of 100 A

Stabilizing factor (k) 0.0 to 0.90 in steps of 0.05

CT ratio per feeder Feeder 50 to 10 000/1 A,50 to 10 000/5 A, adjustable via HMI

The check zone is used as an additional release criterion for busbar protection and operates zone-inde-pendent.


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Table 24 Delay/integrator

Table 25 Log ic

Bay level funct ions for Back-up/Main 2 REB500sys

(Applicable for nominal frequencies of 50, 60 Hz)

For delaying pick-up or reset or for integrating 1 binary signal Provision for inverting the input

4 independent parameter sets.Settings:

Pick-up or reset time 0 to 300 s in steps of 0.01 s

Integration yes/no

Logic for 4 binary inputs with the following 3 configurations:1. OR gate2. AND gate3. Bistable flip-flop with 2 set and 2 reset inputs (both OR gates), resetting takes priority

4 independent parameter sets.

All configurations have an additional blocking input.Provision for inverting all inputs.

Table 26 Definite time over and undercurrent protection (51)

Over and undercurrent detection Single or three-phase measurement with detection of the highest, respectively lowest phase current

2nd harmonic restraint for high inrush currents. 4 independent parameter sets.

Settings:

Pick-up current 0.2 to 20 IN in steps of 0.01 IN

Delay 0.02 to 60 s in steps of 0.01 s

Accuracy of the pick-up setting (at fN) 5%

Reset ratioovercurrentundercurrent

>94% (for max. function)


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Number of phases 1 or 3

Base current IB 0.04 to 2.5 INin steps of 0.01 IN

Pick-up current Istart

1 to 4 IB

in steps of 0.01 IB

Min. time setting tmin 0 to 10 s in steps of 0.1 s

k1setting 0.01 to 200 s in steps of 0.01 s

Accuracy classes for the operating timeaccording to B.S. 142, IEC 60255-3RXIDG characteristic

E 5.04% (1 - I/80 IB)

Reset ratio 95%

Table 28 Definite time over and undervol tage protection (59/27)

Over and undervoltage detection

Single or three-phase measurement with detection of the highest, respectively lowest phase voltage 4 independent parameter sets.

Settings:

Pick-up voltage 0.01 to 2.0 UNin stepsof 0.01 UN


Accuracy of the pick-up setting (at fN) 2% or 0.005 UN

Reset ratio (U 0.1 UN)overvoltageundervoltage

>96% (for max. function)


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Table 30 Directional overcur rent definite time protection (67)

Directional overcurrent protection with detection of power flow direction Back-up protection

4 independent parameter sets Three-phase measurementSuppression of DC and HF componentsDefinite time characteristic Voltage memory for near faults Selectable response when power direction no longer valid (trip or block)

Settings:

Current 0.02 to 20 INin steps of 0.01 IN

Angle -180 to +180 in steps of 15


Wait time 0.02 to 20 s in steps of 0.01 s

Memory duration 0.2 to 60 s in steps of 0.01 s

Accuracies:Measuring accuracies are defined by:

Frequency range 0.91.05 fNSinusoidal voltage including 3., 5., 7. and 9. harmonic

Accuracy of pick-up valueReset ratio

Accuracy of angle measurement (at 0.971.03 fN)

5%95%5

Voltage input rangeVoltage memory rangeAccuracy of angle measurement at voltage memoryFrequency dependence of angle measurement at

voltage memoryResponse time without delay

0.005 to 2 UN


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Accuracies:Measuring accuracies are defined by:

Frequency range 0.91.05 fN

Accuracy of pick-up valueReset ratio

Accuracy of angle measurement (at 0.971.03 fN)

5%95%5

Voltage input rangeVoltage memory rangeAccuracy of angle measurement at voltage memoryFrequency dependence of angle measurement at

voltage memoryResponse time without delay

0.005 to 2 UN95% (at U >0.1 UN or I >0.1 IN)Current plausibility settings:

Pick-up differential for sum of internal summation cur-rent 0.05 to 1.00 INin stepsof 0.05 IN

Amplitude compensation for summation CT -2.00 to +2.00 in steps of 0.01


Voltage plausibility settings:

Pick-up differential for sum of internal summation volt-age 0.05 to 1.2 UNin steps of 0.05 UN

Amplitude compensation for summation VT -2.00 to +2.00 in steps of 0.01



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Remark: Distance protection operating times on next page

Table 34 Directional sensiti ve earth fault protection for grounded systems (67N)

Detection of high-resistance earth faults Current enabling setting 3I0

Direction determined on basis of neutral variables (derived externally or internally) Permissive or blocking directional comparison scheme Echo logic for weak infeeds Logic for change of energy direction 4 independent parameter sets.

Settings:

Current pick-up setting 0.1 to 1.0 INin steps of 0.01 IN

Voltage pick-up setting 0.003 to 1 UNin steps of 0.001 UN

Characteristic angle -90 to +90 in steps of 5

Delay 0 to 1 s in steps of 0.001 s

Accuracy of the current pick-up setting 10% of setting

Table 35 Distance protection (21)

Five measuring stages with polygonal impedance characteristic forward and backwardAll values of settings referred to the secondaries, every zone can be set independently of the others 4 independent parameter sets.

Impedance measurement -300 to 300 /ph in steps of 0.01 /ph

Zero-sequence current compensation 0 to 8 in steps of 0.01,-180 to +90 in steps of 1

Mutual impedance for parallel circuit lines 0 to 8 in steps of 0.01,-90 to +90 in steps of 1

Time step setting range 0 to 10 s in steps of 0.01 s

Underimpedance starters -999 to 999 /ph in steps of 0.1 /ph

Overcurrent starters 0.5 to 10 IN in steps of 0.01 IN

Min. operating current 0.1 to 2 INin steps of 0.01 IN

Back-up overcurrent 0 to 10 IN in steps of 0.01 IN

Neutral current criterion 0.1 to 2 INin steps of 0.01 IN

Neutral voltage criterion 0 to 2 UNin steps of 0.01 UN

Low-voltage criterion for detecting, for exam-ple, a weak infeed

0 to 2 UNin steps of 0.01 UN

VT supervisionNPS/neutral voltage criterionNPS/neutral current criterion

0.01 to 0.5 UNin steps of 0.01 UN0.01 to 0.5 INin steps of 0.01 IN

Accuracy (applicable for current time con-stants between 40 and 150 ms)

amplitude errorphase errorSupplementary error for- frequency fluctuations of +10%- 10% third harmonic- 10% fifth harmonic

5% for U/UN >0.12 for U/UN >0.1

5%10%10%

Operating times of the distance protectionfunction (including tripping relay)

minimumtypical(see also isochrones)

20 ms25 ms

Typical reset time 25 ms

VT-MCB auxiliary contact requirementsOperation time


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Distance protection operating times

Isochrones

Abbreviations: ZS = source impedanceZF = fault impedanceZL = zone 1 impedance setting

Single phase fault (min)

0

0.2

0.4

0.6

0.8

1

0.1 1 10 100 1000

18ms

Single phase fault (max)

0

0.2

0.4

0.6

0.8

1

0.1 1 10 100 1000

31ms

29ms

SIR (ZS/ZL)

ZF/ZL

ZF/ZL

SIR (ZS/ZL)

18ms17ms

Two phase fault (min)

0

0.2

0.4

0.6

0.8

1

0.1 1 10 100 1000

Two phase fault (max)

0

0.2

0.4

0.6

0.8

1

0.1 1 10 100 1000

29ms

32ms

ZF/ZL

ZF/ZL

SIR (ZS/ZL)SIR (ZS/ZL)

18ms17ms

19ms

Three phase fault (min)

0

0.2

0.4

0.6

0.8

1

0.1 1 10 100 1000

20ms

Three phase fault (max)

0

0.2

0.4

0.6

0.8

1

0.1 1 10 100 1000

29ms

33ms

ZF/ZL

ZF/ZL

SIR (ZS/ZL) SIR (ZS/ZL)

18ms17ms


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Table 36 Autoreclosure (79)

Single and three-phase autoreclosure. Operation in conjunction with distance, overcurrent and synchrocheck functions and also with external

protection and synchrocheck relays. Logic for 1st and 2nd main protections, duplex and master/follower schemes. Up to four fast or slow reclosure shots. Detection of evolving faults 4 independent parameter sets.

Settings:

1st reclosure none1P fault - 1P reclosure1P fault - 3P reclosure1P/3P fault - 3P reclosure1P/3P fault - 1P/3P reclosure

2nd to 4th reclosure nonetwo reclosure cyclesthree reclosure cycles

four reclosure cyclesSingle phase dead time 0.05 to 300 s

Three-phase dead time 0.05 to 300 s

Dead time extension by ext. signal 0.05 to 300 s

Dead times for 2nd, 3rd and 4th reclosures 0.05 to 300 s

Fault duration time 0.05 to 300 s

Reclaim time 0.05 to 300 s

Blocking time 0.05 to 300 s

Single and three-phase discrimination times 0.1 to 300 s

All settings in steps of 0.01 s

Table 37 Synchrocheck (25)

Determination of synchronismSingle phase measurement. The differences between the amplitudes, phase-angles and frequen-cies of two voltage vectors are determined.

Voltage supervisionSingle or three-phase measurementEvaluation of instantaneous values and therefore wider frequency rangeDetermination of maximum and minimum values in the case of three-phase inputs

Phase selection for voltage inputs Provision for switching to a different voltage input (double busbar systems) Remote selection of operating mode

4 independent parameter sets.Settings:

Max. voltage difference 0.05 to 0.4 UNin steps of 0.05 UN

Max. phase difference 5 to 80 in steps of 5

Max. frequency difference 0.05 to 0.4 Hz in steps of 0.05 Hz

Min. voltage 0.6 to 1 UN in stepsof 0.05 UN

Max. voltage 0.1 to 1 UN in stepsof 0.05 UN

Supervision time 0.05 to 5 s in steps of 0.05 s

Resetting time 0 to 1 s in steps of 0.05 s

AccuracyVoltage difference

Phase differenceFrequency difference

for 0.9 to 1.1 fN5% UN

50.05 Hz


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Table 38 Transformer dif ferential protection (87T)

Features:

For two- and three-winding transformers

Three-phase functionCurrent-adaptive characteristicHigh stability for external faults and current transformer saturationNo auxiliary transformers necessary because of vector group and CT ratio compensationInrush restraint using 2nd harmonic

Settings:

g-setting 0.1 to 0.5 INin steps of 0.05 IN

v-setting 0.25 or 0.5 or 0.7

b-setting 1.25 to 2.5 in steps of 0.25 IN

Max. trip time (protected transformer loaded)- for I>2 IN- for I2 IN

30 ms50 ms

Accuracy of pick-up value 5% IN(at fN)

Reset conditions I


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Table 40 Peak value over and undercurrent protect ion (50)

Features:Maximum or minimum function (over- and undercurrent)

Single or three-phase measurements Wide frequency range (0.04 to 1.2 fN) Peak value evaluation

Settings:

Current 0.1 to 20 IN in steps of 0.1 IN

Delay 0 to 60 s in steps of 0.01s

Accuracy of pick-up value (at 0.08 to 1.1 fN) 5% or 0.02 IN

Reset ratio >90% (for max. function)


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Connection diagrams(contd)Connection diagrams(contd)


Bay unit 500BU03 connection diagrams

A detailed description of each variant is given in the application description[3].

Fig. 13 Bay unit connection diagram 500BU03, 4I, 5U

Bay unit Protection functions

500BU03 Stat ion level Bay level Measurement value

Analogueinputs

Busbarprotection

Breakerfailureprotection

Endfaultprotection

Breakerpolediscrepancyprotec

tion

Voltagecheck

Disturbancerecorder

Distanceprotection

Definitetimecurrentprotection

Inversedefiniteminimumt

imeovercurrentprotection

Definitetimedirectionalovercurrentprotection


imedirectionalovercurrentprotection

Definitetimevoltageprotection

Synchrocheck

Direct.sensitiveEFprot.forgroundedsystems

Direct.sensitiveEFprot.forung

r.orcomp.systems


imegroundfaultovercurrentprotection

Currentplausibilitycheck

Voltageplausibilitycheck

Currents

I1

Phase current L1

(Line)

I2

Phase current L2(Line)

I3

Phase current L3

(Line)

I4

Residual current Lo (Y)(Line)

Residual current derived

internally Io= IL1+IL2+IL3

Voltages

U1

Phase voltage L1(Line)

U2

Phase voltage L2

(Line)

U3

Phase voltage L3

(Line)

U4

Phase voltage L2

(Bus 1)

1ph -> L2-E

U5

Phase voltage L2

(Bus 2)

1ph -> L2-E

Residual voltage derived

internally Uo= UL1+UL2+UL3

Current transformer/voltage transformer fixed assignmentRecommended setting (configured via software HMI500-REBWIN)Only for busbar protection Io-measurement (optional function)Bay unit types with metering (core balance) CT on input I4

Derived

internally

Derived

internally

10

12

0

1

5

1

2

3

0

4

5

1

5

6

0

7

5

1

8

9

0

5

1

11

2 0

1

5 0

4

8 0

7

11 0

10

13

14 0


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Page 37


Fig. 14 Bay unit connection diagram 500BU03, 9 I

Bay unit Protection functions

500BU03 Stat ion level Bay level Measurement value

Analogueinputs

Busbarprotection

Bre

aker-failureprotection

End-faultprotection

Bre

aker-polediscrepancyprotection

Dis

turbancerecorder

Tra

nsformerdiffferentialprotection

The

rmaloverload

Pea

kvalueoverandundercurrentprotection

Inversetimeovercurrentprotection

Inversetimeearthfaultovercurrentprotection

Definitetimeoverandundercurrentprotection

Thr

eephasecurrentplausibility

Currents

I1

Phase current L1A-Side

I2

Phase current L2A-Side

I3

Phase current L3

A-Side



Currents

I4

Phase current L1

B-Side

I5

Phase current L2B-Side

I6

Phase current L3B-Side



Currents

I7

Phase current L1C-Side (if existing)

I8


I9




Derivedinternally

A-Sid e

B-Side

C-Side

Transformer primary sideTransformer secondary sideTransformer tertiary side

Derivedinternally

Derivedinternally

Current transformer, fixed assignmentRecommended setting (configured via software HMI500-REBWIN)Only for busbar protection Io-measurement (optional function)Io for earth fault protection

0

1

5

1

2

3

0

4

5

1

5

6

0

7

5

1

8

9

I

0

1

5

1

2

3

0

4

5

1

5

6

0

7

5

1

8

9

J

0

10

5

1

11

12

0

13

5

1

14

15

0

16

5

1

17

18

J


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Page 39


REB500sys: Typical assignment of the in/outputs

Fig. 17 REB500sys: Typical assignment of the in/outputs of line variant L-V4 for 500BU03(See[3]Application description)

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

CR01

CR02

CR03

CR04

CR05

CR06

CR07

CR08

CR09

CR10

CR11

CR12

CR13

CR14

CR15

CR16

C

D

In service

Block close command

AR close command

Remote trip, channel 1

Carrier send, distance prot.

Remote trip, channel 2

Carrier send, DEF prot.

Start L1L2L3 to AR in main 1

Trip CB 3-pole to AR in main 1

Trip CB to AR in main 1

Trip phase L1, trip coil 1






Binary outputsLine Variant 4

1

2

3

4

5

6

7

8

9

10

11

1213

14

15

OC01

OC02

OC03

OC04

OC05

OC06

OC07

OC08

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

OC10

OC11

OC12

OC13

OC14

OC15

OC16

A

B

16

17

18OC09

OC17

OC18

OC19

OC20

16

17

18

Binary inputsLine Variant 4

Bus 1 VT MCB fail

Bus 2 VT MCB fail

Prepare 1-pole trip from main 1

Main 1 healthy/in service mode (Blk. AR)

OCO ready for AR release

Carrier receive, distance prot.

Carrier receive, DEF prot.

CB all poles closed, DEF prot.

Line VT MCB fail

Start BFP Phase L1

Start BFP Phase L2

Start BFP Phase L3Start BFP Phase L1L2L3

Q0 Manual Close Command +AR CLOSE Command CB

Breaker Q0 open

Breaker Q0 closed

Bus 1 Isolator Q1 open

Bus 1 Isolator Q1 closed

Bus 2 Isolator Q2 open

Bus 2 Isolator Q2 closed


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Page 40

Connection diagrams(contd)Connection diagrams(contd)


Fig. 18 REB500sys: Typical assignment of the in/outputs of transformer variant T-V1 for 500BU03(See[3] application description)

Start BFP phase L1L2L3from back-up prot. TRIP

Start BFP phase L1L2L3from prot. group 2 TRIP 1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

OC01

OC02

OC03

OC04

OC05

OC06

OC07

OC08

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

OC10

OC11

OC12

OC13

OC14

OC15

OC16

A

B

16

17

18OC09

OC17

OC18

OC19

OC20

16

17

18

Binary inputs

Transformer

Variant 1

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

CR01

CR02

CR03

CR04

CR05

CR06

CR07

CR08

CR09

CR10

CR11

CR12

CR13

CR14

CR15

CR16

C

D

Binary outputs

Transformer

Variant 1

Block transformerdiff. protection

Transformer diff. inrush input

Transformer diff. high-set

A-side breaker Q0manual close command

A-side breaker Q0 open

A-side breaker Q0 closed

A-side bus 1 isolator Q1 open

A-side bus 1 isolator Q1 closed

A-side bus 2 isolator Q2 open

A-side bus 2 isolator Q2 closed

Mechanic protection TRIP 2

Mechanic protection alarm 2

Spare

Spare

In service

Block close commandbreaker Q0 A-side

Transf. prot. trip start BFPon B-side

Remote Trip 1 to C-side *)

Trip phase L2Trip phase L3

Remote trip 1 to B-side

Mechanic protection TRIP 1

Mechanic protection alarm 1

Spare

External start BFPfrom mechanic prot. TRIP

Legend:

A-side Transformer primary sideB-side Transformer secondary sideC-side Transformer tertiary side *)

*) C-side, if existing

trip breaker

Q0 coil 1 A-side

Trip phase L1

Trip phase L2

Trip phase L3

trip breakerQ0 coil 2 A-side

Trip phase L1

Transf. prot. trip L1L2L3 group 2Tripping relay (94-2)trip CB A/B/Cside *)

Remote trip 2 to B-side

Transf. prot. trip L1L2L3 group 1Tripping relay (94-1)trip CB A/B/Cside *)

Transf. prot. trip start BFPon C-side *)


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Page 41


Dimensioneddrawings (in mm)

Bay uni t 500BU03

Fig. 19 Bay unit casing for flush mounting, enclosure protection class IP 40(without local HMI)

Fig. 20 Centralized version based on a 19'' mounting plate with up to three bay units.Optionally with local HMI.

Caution

Achtung

Atencion

Attention

Cross section: max. 2.5 mm2

max. 4.0 mm2

Spaceforwiring

Cross section: max. 2.5 mm2

max. 4.0 mm2

Spaceforwiring


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Page 42

Dimensioned draw-ings (in mm) (contd)Dimensioned draw-ings (in mm) (contd)


Bay uni t 500BU03

Fig. 21 Dimensional drawing of the bay unit with local HMI, classical mountingProtection type IP40

Central unit

Fig. 22 Dimensional drawing of the central unit, protection type IP20

Cross section max. 2.5 mm

max. 4.0 mm2

Space for wiring

Panel cutout

223

276

app

rox.

100

189

204 ,50

6U=265,8

200

0,

5

267

+

,1

0 0

25

210

Rear viewapprox.

70

212

482.6

6U=265.8

approx.

235

30

443

465.6

6U=265.8

57.1

57.1

76.2


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Page 43


Fig. 23 Front view of REB500 (example only) Fig. 24 Hinged frame and rear wall

Example with 9 bay units

The cubicles are equipped with gratings for the fixation of incoming cables. For space reasonsthere are no cable ducts.

Table 41 Maximum number of units per cubicle (central version)

Unit Quantity of 500BU03Cross-section

ext. cable

Quantity of

system cables

per bay

Current transformer per bay 4 9 2,5 mm2- 6 mm2 1

Voltage transformer per bay 5 - 1,5 mm2- 6 mm2 1

Binary inputs per bay 20 1,5 mm2- 2,5 mm2 1 - 3

Binary outputs per bay 16 1,5 mm2- 2,5 mm2 1 - 3

Max. number of bays percubicle with central unit

9* * number of bays per cubicle(2200 x 800 x 800 mm)based on the min. cross-section and anaverage quantity of cables

Max. number of bays percubicle without central unit

12*


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Page 44

Basic version Basic version Classical mounting

Fig. 25 Possible arrangement of the bay unit with HMI

Table 42 Unit weights

Unit Weight

Bay unit 4l, classic (incl. HMI) 5,1 kg

Bay unit 4l, 5U, red. power supply, classic (incl. HMI)Bay unit 3l, 1MT, 5U, red. power supply, classic (incl. HMI)

6,2 kg

Bay unit 4l, basic version 3,9 kg

Bay unit 4l, 5U, red. power supply, basic versionBay unit 3l, 1MT, 5U, red. power supply, basic version

5.0 kg

Bay unit 9I, red. power supply, classic (incl. HMI) 6.7 kg

Bay unit 9I, red. power supply, basic version 5.5 kg

Central unit 9,0 kg (Average weight => here 11 feedersplus communication interface)

Central unit with redundant power supply 10,0 kg


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Page 45


Samplespecification

Combined numerical bay and station protec-tion with extensive self-monitoring and ana-logue/digital conversion of all input

quantities.

The architecture shall be decentralized, withbay units and a central unit.

It shall be suitable for the protection of singleand double busbar as well as for the protec-tion (Main 2 or back-up) of incoming andoutgoing bays, lines, cables or transformer

bays.

The hardware shall allow functions to be acti-vat

1mrb520308-ben en numerical station protection system reb500-reb500sys

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