numerical station protection system...

Numerical Station Protection System Busbar Protection with integrated Breaker Failure, Line and Transformer Protection

REB500 / REB500sys

1MRB520308-Ben

Issued: December 2008Changed since October 2007

Data subject to change without notice

Main features • Low-impedance busbar protection• Stub and T-zone protection• High functional reliability due to two inde-

pendent measurement criteria:

- stabilized differential current algorithm

- directional current comparison algorithm

• Phase-by-phase measurement

• Reduced CT performance requirements

• High through-fault stability even in case of CT saturation

• Full solid-state busbar replica

• No switching of CT circuits

• Only one hardware version for

- 1 and 5 A rated currents

- all auxiliary supply voltages between 48 V DC and 250 V DC

- nominal frequencies of 50, 60 and 16.7 Hz

• Short tripping times independent of the plant’s size or configuration

• Centralized layout: Installation of hardware in one or several cubicles

• Distributed layout: Bay units distributed and, in the case of location close to the feeders, with short connections to CTs, iso-lators, circuit breakers, etc.

• Connections between bay units and central unit by fiber-optic cables

- maximum permissible length 1200 m

- for distributed and centralized layout

• fiber-optic connections mean interference-proof data transfer even close to HV power cables

• Replacement of existing busbar protection schemes can be accomplished without re-strictions (centralized layout) in the case of substation extensions e.g. by a mixture of centralized and distributed layout

• Easily extensible

• User-friendly, PC-based human machine interface (HMI)

• Fully numerical signal processing

• Comprehensive self-supervision

• Binary logic and timer in the bay unit

• Integrated event recording

• Integrated disturbance recording for power system currents

• A minimum of spare parts needed due to standardization and a low number of vary-ing units

• Communication facilities for substation monitoring and control systems via IEC 61850-8-1, IEC 60870-5-103 and LON

REB500sys - Station protection with distributed architecture


ABB Switzerland LtdPower Systems

REB500 / REB500sys1MRB520308-Ben

Page 2

Main features (cont’d) Options• Breaker failure protection (also separately

operable without busbar protection)

• End fault protection

• Definite time overcurrent protection

• Breaker pole discrepancy

• Current and voltage release criteria

• Disturbance recording for power system voltages

• Separate I0 measurement 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 units and/or bay units

Additional main features

REB500sys combines the well-proven numer-ical busbar and breaker failure protection REB500 of ABB with Main 2 or back-up pro-tection for line or transformer feeders. The Main 2 / Group 1 or back-up protection is based on the well-proven protection function library of ABB line and transformer protection for 50, 60 and 16.7 Hz.

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

current protection• Directional overcurrent definite and inverse

time protection• Inverse time earth fault overcurrent protec-

tion• Definite time over- and undervoltage pro-

tection• Three-phase current and three-phase volt-

age plausibility

Main 2 / back-up bay protection: Line protection• High-speed distance protection• Directional sensitive earth fault protection

for grounded systems against high resis-tive faults in solidly grounded networks

• Directional sensitive earth fault protection for ungrounded or compensated systems

• Autoreclosure for - single-pole / three-pole reclosure- up to four reclosure sequences

• Synchrocheck with - measurement of amplitudes, phase

angles and frequency of two voltage vectors

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

Group 1 / back-up bay protection: Transformer 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• Peak value over- and undervoltage protec-

tion• Overfluxing protection• Rate of change frequency protection• Frequency protection• Independent T-Zone protection with trans-

former differential protection

• Power protection

Application REB500The numerical busbar protection REB500 is designed for the high-speed, selective protec-tion of MV, HV and EHV busbar installations at a nominal frequency of 50, 60 and 16.7 Hz.

The structure of both hardware and software is 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 to quadruple busbars with transfer buses, ring busbars and 1½ breaker schemes to be pro-tected.

In 1½ breaker schemes the busbars and the entire diameters, including Stub/T-Zone can be protected. An integrated tripping scheme allows 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 REB500 detects all phase and earth faults in solidly grounded and resistive-grounded power sys-tems and phase faults in ungrounded systems and systems with Petersen coils.



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The main CTs supplying the currents to the busbar protection have to fulfil only modest performance requirements (see page 18). The protection operates discriminatively for all faults inside the zone of protection and remains reliably stable for all faults outside the zone of protection.

REB500sysThe REB500sys is foreseen in MV, HV and EHV substations with nominal frequencies of 50 Hz resp. 60 Hz to protect the busbars and their feeders. The bay protection functions included in REB500sys are used as Main 2 / Group 1 - or back-up protection.

The system REB500sys is foreseen for all single or double busbar configurations (Line variants L-V1 to L-V5 and Transformer vari-ant T-V1 to T-V4). In 1½ breaker configura-tions, variant L-V5 can be used for the bay level functions autoreclosure and synchro-check. 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 ungrounded and compensated power systems as well as feeder faults in solidly, low resistive-grounded, compensated and ungrounded power systems.

The protection operates selectively for all faults inside the zone of protection and remains reliably stable for all faults outside the zone of protection.

REB500sys is perfectly suited for retrofit concepts and stepwise upgrades. The bay unit is used as a stand-alone unit for bay protec-tion functions (e.g. line protection, autoreclo-sure and synchrocheck or 2- and 3 winding transformer protection or autonomous T-zone protection). The central unit can be added at a later stage for full busbar and breaker failure protection functionality.

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

• Two main protection schemes per bay and one busbar protection. With REB500sys the protection concept can be simplified. Due to the higher inte-gration of functionality one of the main protection equipment can be eliminated.

• One main protection and one back-up protection scheme per bay, no busbar protection. With REB500sys a higher availability of the energy delivery can be reached, due to the implementation of busbar and breaker failure protection schemes where it hasn't been possible in the past because of eco-nomical reasons.

Nine 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 overcurrent and directional earth fault protection

- 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 and synchrocheck.

Transformer protection- Transformer Variant 1 (T-V1)

2- or 3 winding transformer differential protection, thermal overload, current func-tions; applicable also as autonomous T-zone protection.

- Transformer Variant 2 (T-V2) 2-winding transformer differential protec-tion, thermal overload, current functions, overfluxing protection, neutral overcurrent (EF).

- Transformer Variant 3 (T-V3) Distance protection for transformer back-up or 2- winding transformer differential pro-tection, thermal overload, current func-tions, voltage functions, frequency func-tions, power function, overfluxing protec-tion.

- Transformer Variant 4 (T-V4) Transformer oriented functions/ back-up functions -> thermal overload, current func-tions, voltage functions, frequency func-tions, power function, overfluxing protection.



Page 4


Application (cont´d)Application (cont´d)

Fig. 1



Page 5


Table 1 Overview of the functionalities REB500 / REB500sys

Main functionality IE

EE

Pro

tecti

on

fu

ncti

on

IE

C61850

Sta

nd

ard

Op

tio

n

Lin

e V

ari

an

t 1

(L-V

1)

Lin

e V

ari

an

t 2

(L-V

2)

Lin

e V

ari

an

t 3

(L-V

3)

Lin

e V

ari

an

t 4

(L-V

4)

Lin

e V

ari

an

t 5

(L-V

5)

Tra

nsfo

rmer

Vari

an

t 1

(T-V

1)

Tra

nsfo

rmer

Vari

an

t 2

(T-V

2)

Tra

nsfo

rmer

Vari

an

t 3

(T-V

3)

Tra

nsfo

rmer

Vari

an

t 4

(T-V

4)

Bay U

nit

Hard

ware

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

Current plausibility check - - -

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 s 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 - -

WEB - Server - -

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 PTUV/PTOV

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. sensitive EF prot. for ungrounded or compensated

systems32N 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 PTUC/PTOC

Peak value over- and undervoltage protection 59 OVINST PTUV/PTOV

Definite time overfluxing protection 24 U/fDT PVPH

Inverse time overfluxing protection 24 U/fINV PVPH

Rate-of-change frequency protection 81 df/dt PVRC

Frequency protection 81 Freq PTOF/PTUF

Power protection 32 P PDUP/PDOP

* for special applications only

500BU03: bay unit

500B

U03 f

or

50 H

z,

60 H

z500B

U03 f

or

50 H

z,

60 H

z,

16.7

Hz

Fu

ncti

on

ali

tyR

EB

500 /

RE

B500sys

RE

B500




Page 6

Mode of installation

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. 24) are installed 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 fiber cables. The cen-tral processing unit is normally in a centrally located cubicle or in the central relay room.

Fig. 2 Distributed installation

Centralized installation19" mounting plates with up to three bay units each, and the central processing unit are mounted according to the size of the busbar system in one or more cubicles (see Fig. 23). A centralized installation is the ideal solution

for upgrading existing stations, since very little 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 distributed installationBasically, the only difference between a dis-tributed and a centralized scheme is the mounting location of the bay units and there-fore it is possible to mix the two philosophies.



Page 7


System design 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 the associated data acquisition, pre-processing, control functions and bay level protection functions. It also provides the electrical insu-lation between the primary system and the internal electronics of the protection.

The input transformer module contains four input CTs for measuring phase and neutral currents with terminals for 1 A and 5 A. Additional interposing CTs are not required, because any differences between the CT ratios are compensated by appropriately con-figuring the software of the respective bay units.

Optional input transformer module also con-tains five input voltage transformers for the measurement of the three-phase voltages and two busbar voltages and recording of voltage disturbances or 6 current transformers for transformer differential protection. (see Fig. 12).

In the analog input and processing module, the analog current and voltage signals are converted to numerical signals at a sampling rate 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 intervals from the bay units to the central processing unit via the process bus.

Every bay unit has 20 binary inputs and 16 relay outputs. The binary I/O module detects and processes the positions of isolators and couplers, blocking signals, starting signals, external resetting signals, etc. The binary input channels operate according to a pat-ented pulse modulation principle in a nominal range of 48 to 250 V DC. The PC-based HMI program provides settings for the threshold voltage of the binary inputs. All the binary output 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 output channels to be assigned to the various func-tions. A time stamp is attached to all the data such as currents, voltages, binary inputs, events and diagnostic information acquired by a bay unit.

Where more binary and analog inputs are needed, several bay units can be combined to form a feeder/bus coupler bay (e.g. a bus cou-pler bay with CTs on both sides of the bus-tie breaker 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

CPUModule

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 Unit (500BU03)

Local HMI

DC



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System design (cont´d)System design (cont´d) In the event that the central unit is out of operation or the optical fiber communication is disrupted an alarm is generated, the bay unit will continue to operate, and all local and bay protection as well as the recorders (event and disturbance) will remain fully functional (stand-alone operation).

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

• Without local HMI: ideal solution if con-venient access to all information via the central unit or by an existing substation automation system is sufficient.

• With local HMI and 20 programmable LEDs (Fig. 5): ideal solution for distrib-uted and kiosk mounting (AIS), since all information is available in the bay.

For the latter option it is possible to have the HMI either built in or connected via a flexible cable to a fixed mounting position (see Fig. 28).

In the event of a failure, a bay unit can be eas-ily replaced. The replacement of a bay unit can be handled in a simple way. During sys-tem start-up the new bay unit requests its address, this can be entered directly via its local HMI. The necessary setting values and configuration data are then downloaded auto-matically.

Additional plug-and-play functionalityBay units can be added to an existing REB500 system in a simple way.

Fig. 5 Built-in HMI directly on the bay unit 500BU03.

Central unit (500CU03)The hardware structure is based on standard racks and only a few different module types for the central unit (see Fig. 4).

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

A parallel bus on a front-plate motherboard establishes the interconnections between the modules in a rack. The modules are inserted from the rear.

The central unit is the system manager, i.e. it configures the system, contains the busbar replica, assigns bays within the system, man-ages the sets of operating parameters, acts as process 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 process data provided by the bay units.

The process data are transferred to the central processor via a star coupler module. Up to 10 bay units can be connected to the first central processor and 10 to the others. Central pro-cessors and star coupler modules are added for protection systems that include more than 10 bay units. In the case of more than 30 bay units, additional casings are required for accommodating 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 minimize module 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/IP port for very fast HMI500 connection within the local area network.

Fig. 6 Central unit



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Functionality Busbar protection The protection algorithms are based on two well-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 relationship between the feeder currents (phase com-parison)

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

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

Fig. 7 Tripping characteristic of the stabilized differential current algorithm.

In Fig. 7, the differential current is

and the restraint current

where N is the number of feeders. The fol-lowing two conditions have to be accom-plished for the detection of an internal fault:

where kst stabilizing factorkst max stabilization factor limit.

A typical value is kst max = 0.80IK min differential current pick-up value

The above calculations and evaluations are performed by the central unit. The second measuring principle determines the direction of energy flow and involves comparing the phases of the currents of all the feeders connected to a busbar section.

The fundamental frequency current phasors ϕ1..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 least one current is approximately 180° out of phase with the others.

The algorithm detects an internal fault when the difference between the phase angles of all the feeder currents lies within the tripping angle of the phase comparator (see Fig. 8).

( | | )Σ Ι

0Restraint current

( | | )Σ Ι0

IKmin

k = 1

Ksetting =kst maxTri

pping

area

Differentialcurrent

Restraintarea

(1)∑=

=N

1n LnDiff II

(2)∑=

=N

1n LnRestII

(3)maxstRest

Diffst kI

Ik >=

(4)minKDiff II >

(5)( )( )⎥⎦

⎤⎢⎣

⎡=ϕ

LnIReLnIImarctann



Page 10


Functionality (cont´d)Functionality (cont´d)

Fig. 8 Characteristic of the phase comparator for determining energy direction.

The task of processing the algorithms is shared 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 then filters the resulting data according to a Fou-rier function. The analog data filtered in this way are then transferred at regular intervals to the central processing unit running the busbar protection algorithms.

Depending on the phase-angle of the fault, the tripping time varies at Idiff/Ikmin ≥5 bet-ween 20 and 30 ms including the auxiliary tripping relay.

Optionally, the tripping signal can be inter-locked by a current or voltage release criteria in the bay unit that enables tripping only when a current above a certain minimum is flowing, respectively the voltage is below a certain value.

Breaker failure protectionThe breaker failure functions in the bay units monitor the phase currents independently of the busbar protection. They have two timers with individual settings.

Operation of the breaker failure function is enabled either:

• internally by the busbar protection algo-rithm (and, if configured, also by the inter-nal line protection, overcurrent or pole discrepancy protection features) of the bay level

• externally via a binary input, e.g. by the line 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-alone mode in the bay unit.

If the fault still persists at the end of the sec-ond time delay, the breaker failure function uses the busbar replica to trip all the other feeders supplying the same section of busbar via their bay units.

A remote tripping signal can be configured in the software to be transmitted after the first or second timer.

Phase-segregated measurements in each bay unit cope with evolving faults.

End fault protectionIn order to protect the “dead zone” between an open circuit-breaker and the associated CTs, a signal derived from the breaker posi-tion and the close command is applied.

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

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

Overcurrent functionA definite time overcurrent back-up protec-tion scheme can be integrated in each bay unit. (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.

Current release criteriaThe current release criteria is only performed in the bay unit. It is effective for a busbar pro-tection trip and for an intertripping signal (including end fault and breaker failure) and prevents those feeders from being tripped that are conducting currents lower than the setting of the current release criteria.

Voltage release criteriaThe voltage criterion is measured in the bay unit. The function can be configured as release criterion per zone through internal

Phase-shift

Δϕ

74°

0° ϕ12 = 36°

ϕ12 = 144°

Restraint area

Case 1 2

Δϕ max = 74°

Tripping area

Busbar

Operating characteristic

Re

Im

I1

I2

Im

ReI1

I2

180°

Case 1: External fault Δϕ = 144°

Case 2: Internal fault Δϕ = 36°



Page 11


linking in the central unit. This necessitates the 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 transformers must be installed). For details see Table 22.

Check zone criterionThe check zone algorithm can be used as a release criterion for the zone-discriminating low-impedance busbar protection system. It is based on a stabilized differential current measurement, which only acquires the feeder currents of the complete busbar. The isolator / breaker positions are not relevant for this cri-terion.

Neutral current detection I0 Earth fault currents in impedance-grounded systems may be too low for the stabilized dif-ferential current and phase comparison func-tions to detect. A function for detecting the neutral current is therefore also available, but only for single phase-to-earth faults.

Pole discrepancyA pole discrepancy protection algorithm supervises 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 send an 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. A time stamp with a resolution of 1ms is attach-ed to every binary event. Events are divided into the three following groups:

• system events• protection events• test events

The events are stored locally in the bay unit or 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 (see Table 14).

A disturbance record can be triggered by either the leading or lagging edges of all binary signals or by events generated by the internal protection algorithms. Up to 10 gen-eral-purpose binary inputs may be configured to enable external signals to trigger a distur-bance record. In addition, there is a binary input in the central and the bay unit for start-ing the disturbance recorders of all bay units.

The number of analog channels that can be recorded, the sampling rate and the recording period are given in Table 14. A lower sam-pling rate enables a longer period to be recorded.

The total recording period can be divided into a maximum of 15 recording intervals per bay unit.

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

The function can be configured to record the pre-disturbance and post-disturbance states of the signals.

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

This function is performed in a stand-alone mode in the bay unit (see page 7).

Note:Stored disturbance data can be transferred via the central unit to other computer systems for evaluation by programs such as PSM505 [4]. Files are transferred in the COMTRADE for-mat.

After retrieving the disturbance recorder data, it is possible to display them graphically with PSM505 directly.

Communication interfaceWhere the busbar protection has to communi-cate with a station automation (SAS), a com-munication module is added to the central unit. The module supports the interbay bus protocols IEC 61850-8-1, IEC 60870-5-103 and LON.



Page 12


Functionality (cont´d)Functionality (cont´d) The IEC 61850-8-1 interbay bus transfers via either optical or electrical connection:

• differential current of each protection zone• monitoring information from REB500

central unit and bay units• binary events (signals, trips and diagnos-

tic)• trip reset command• disturbance recording data (via MMS file

transfer 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 optical connection:

• differential currents of each protection zone

• binary events (signals, trips and diagnos-tic)

• trip reset command• disturbance recording data (via HMI500)• time synchronization

The IEC 60870-5-103 interbay bus transfers via 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) which runs on a PC connected to either a bay unit or the cen-tral processing unit includes a test generator.

During commissioning and system mainte-nance, the test generator function enables the user to:• activate binary input and output signals• monitor system response.• test the trip circuit up to and including the

circuit-breaker • test the reclosure cycles• establish and perform test sequences with

virtual currents and voltages for the bay protection of the REB500sys

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

Isolator supervisionThe isolator replica is a software feature with-out any mechanical switching elements. The software replica logic determines dynami-cally the boundaries of the protected busbar zones (protection zones). The system moni-tors any inconsistencies of the binary input circuits connected to the isolator auxiliary contacts and generates an alarm after a set time delay.

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

• blocked• zone-selective blocked• remain in operation

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 the behavior of the busbar protection:

• blocked• zone-selective blocked• remain in operation

Trip redirectionA binary input channel can be provided to which the external signal monitoring the cir-

Table 2 N/O contact:“Isolator CLOSED”

N/Ccontact: “Isolator OPEN”

Isolator position

open open Last position stored (for busbar protection) + delayed isolator alarm, + switching prohibited signal

open closed OPEN

closed open CLOSED

closed closed CLOSED + delayed isolator alarm, + switching prohibited signal



Page 13


cuit-breaker air pressure is connected. Trip-ping is not possible without active signal. When it is inactive, a trip generated by the respective bay unit is automatically redirected to the station at the opposite end of the line and also to the intertripping logic to trip all the circuit-breakers connected to the same section of busbar.

The trip redirection can also be configured with a current criterion (current release crite-ria).

Human machine interface (HMI)The busbar protection is configured and maintained with the aid of human machine interfaces at three levels.

Local HMIThe local display interface installed in the central unit and in the bay units comprises:• a four-line LCD with 16 characters each

for displaying system data and error mes-sages

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

• in addition 20 freely programmable LEDs for 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 (within the busbar protection function)

• starting and tripping signals of protection functions

External HMI (HMI500)More comprehensive and convenient control is provided by the external HMI software run-ning on a PC connected to an optical interface on the front of either the central unit or a bay unit. The optical interface is completely immune to electrical interference. The PC software facilitates configuration of the entire busbar protection, the set-ting of parameters and full functional checking and testing. The HMI500 can also be operated via the LON Bus on MicroSCADA for example, thus eliminating a separate serial connection to the central unit.

The HMI runs under MS WINDOWS NT, WINDOWS 98, WINDOWS 2000 and WIN-DOWS XP. The HMI500 is equipped with a comfortable on-line help function. A data base comparison function enables a detailed comparison between two configuration files (e.g. between the PC and the central unit or between two files on the PC).

Remote HMIA second serial interface at the rear of the central unit provides facility for connecting a PC remotely via either an optical fiber, TCP/IP or modem link. The operation and function of HMI500 is the same whether the PC is connected locally or remotely.

Additional functionalities

Bay level functionsThese functions are based on the well estab-lished and well-proven functions built in the ABB line and transformer protection. The bay level functions contain all the relevant additional functions, which are normally requested of a line and transformer protection scheme.

The line protection functions (L-V1 - L-V5) are used as Main 2 or back-up for lines as well as for transformer bays. The transformer protection functions (T-V1 - V4) are used as Group 2 or back-up bay protection for trans-former bays or as an independent T-Zone pro-tection.



Page 14


Additional functional-ities (cont´d)Additional functional-ities (cont´d)

High-speed distance protection• Overcurrent and underimpedance starters

with polygonal characteristic• Five distance zones (polygon for forwards

and reverse measurement)• Load-compensated measurement• Definite time overcurrent back-up protec-

tion (short-zone protection)• System logic

- switch-onto-fault- overreach zone

• Voltage transformer circuit supervision• Power swing blocking function• HF teleprotection. The carrier-aided

schemes include:- permissive underreaching transfer trip-

ping- permissive overreaching transfer trip-

ping- blocking scheme with echo and tran-

sient blocking functions• Load-compensated measurement

- fixed reactance slope- reactance slope dependent on load value

and direction (ZHV



Page 15


needed. This can be achieved by configuring the rate-of-change frequency function several times.

Definite time overfluxing protectionThis function is primarily intended to protect the iron cores of transformers against exces-sive flux. The function works with a definite time delay. The magnetic flux is not mea-sured directly. Instead the voltage/frequency-ratio, which is proportional to the flux is monitored.

Inverse time overfluxing protectionThis function is primarily intended to protect the iron cores of transformer against exces-sive flux. The function works with an inverse time delay. The inverse curve ca be set by a table of 10 values and the times t-min and t-max. The magnetic flux is not measured di-rectly. Instead the voltage/frequency-ratio, which is proportional to the flux is monitored.

Power functionThis function provides single, or three phase measurement of the real or apparent power. The function can be configured for monitor-ing reverse, active or reactive power (power direction setting). Phase angle errors of the CT/VT inputs can be compensated by setting. The operating mode can be configured either to underpower or to overpower protection.

Logics and delay/integratorThese functions allow the user the engineer-ing of some easily programmable logical functions and are available as standard also in the REB500 functionality.

Directional sensitive earth fault protection for grounded systemsA sensitive directional ground fault function based on the measurement of neutral current and voltage is provided for the detection of high-resistance ground faults in solidly or low-resistance grounded systems. The scheme operates either in a permissive or blocking mode and can be used in conjunc-tion with an inverse time earth fault overcur-rent function. In both cases the neutral current and 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 an indepen-dent channel.

Directional sensitive earth fault protection for ungrounded or compensated systemsThe sensitive earth fault protection function for ungrounded systems and compensated systems with Petersen coils can be set for either forwards or reverse measurement. The characteristic angle is set to ±90° (U0 · I0 · sin ϕ) in ungrounded systems and to 0° or 180° (U0 · I0 · cos ϕ) for systems with Petersen coils. The neutral current is always used for measurement in the case of systems with Petersen coils, but in ungrounded sys-tems its use is determined by the value of the capacitive current and measurement is per-formed by a measuring CT to achieve the required sensitivity. To perform this function the BU03 with 3I, 1MT and 5U is required.

Definite time over- and undercurrent pro-tection This function is used as Main 2 or as back-up function respectively for line, 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 current increases and it can therefore achieve shorter operating times for fault locations closer to the source. Four different characteristics according to British Standard 142 designated normal inverse, very inverse, extremely inverse and long time inverse but with an extended setting range are provided. The function can be configured for single phase measurement or a combined three-phase mea-surement with detection of the highest phase current.

Inverse time earth fault overcurrent protec-tion The inverse time earth fault overcurrent func-tion monitors the neutral current of the sys-tem. Four different characteristics according to British Standard 142 designated normal inverse, very inverse, extremely inverse and long time inverse but with an extended set-ting range are provided.

Directional overcurrent definite / inverse time protection The directional overcurrent definite time function is available either with inverse time or definite time overcurrent characteristic. This function comprises a voltage memory for faults close to the relay location. The function response after the memory time has elapsed can be selected (trip or block).




Page 16

Additional functional-ities (cont’d)

Definite time over- and undervoltage pro-tection This function works with a definite time delay with either single or three-phase mea-surement.

Three-phase current plausibilityThis function is used for checking the sum and the phase sequence of the three-phase currents.

Three-phase voltage plausibilityThis function is used for checking the sum and the phase sequence of the three-phase voltages.

Additional features

Self-supervision All the system functions are continuously monitored to ensure the maximum reliability and availability of the protection. In the event of a failure, incorrect response or inconsis-tency, the corresponding action is taken to establish a safe status, an alarm is given and an event is registered for subsequent diagnos-tic analysis.

Important items of hardware (e.g. auxiliary supplies, A/D converters and main and pro-gram memories) are subjected to various tests when 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 process bus is also continuously supervised.

The processing of tripping commands is one of the most important functions from the reli-ability and dependability point of view. Accordingly, every output channel comprises two redundant commands, which have to be enabled at regular intervals by a watchdog. If the watchdog condition is not satisfied, the channels are blocked.

Extension of the systemThe system functions are determined by soft-ware, configured using the software configu-ration tool.

The system can be completely engineered in advance to correspond to the final state of the station. The software modules for new bays or features can be activated using the HMI500 when the primary plant is installed or the features 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 signal outputs):• Latches until manually reset• Resets automatically after a delay

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

Redundant power supplies (Option)Two power supply modules can be fitted in a redundant arrangement, e.g. to facilitate maintenance of station batteries. This is an option for the central unit as well as for the bay unit.

Time synchronizationThe absolute time accuracy with respect to an external time reference depends on the method 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 control system): 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 to the central unit is possible: accuracy typi-cally ±1 ms

The system time may also be synchronized by a minute pulse applied to a binary input on the central unit.



Page 17


Requirements Optical fiber cablesA distributed busbar protection layout re-quires optical fiber cables and connectors with the following characteristics:• 2 optical fiber cores per bay unit• glass fibers with gradient index • diameter of core and sheath 62.5,

respectively 125 μm• maximum permissible attenuation ≤5 dB• FST connector (for 62.5 μm optical fibers)• rodent protected and longitudinally water-

proof if in cable ducts

Please observe the permissible bending radius when laying the cables.

The following attenuation figures are typical values which may be used to determine an approximate attenuation balance for each bay:

Fig. 9 Attenuation

Isolator auxiliary contactAuxiliary 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.

One potentially-free N/O and N/C contact are required on each isolator. The N/O contact signals that the isolator is “CLOSED” and the N/C contact that the isolator is “OPEN”. Dur-ing the closing movement, the N/O contact

must close before the isolator main contact gap 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 signals ‘no longer closed’ beforehand, then the N/C contact may not signal “OPEN” before the flashover point has been exceeded.

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

Optical equipment Typical 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

Openend position

must be closed

Close isolator

Auxiliary contacts:„CLOSED“normally open

Open isolator

Flashover gap

may be closed

must be open

Isolator

Closeend position

„OPEN“normally closed




Page 18

Circuit-breaker replicaWhen the circuit-breaker replica is read in the feeder or the bus-tie breaker, the circuit-breaker CLOSE command must also be con-nected.

Main current transformerThe algorithms and stabilization features used make the busbar protection largely insensitive to CT saturation phenomena. Main CTs types TPS (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 needed for the busbar protection makes it possible for it 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-phase systems are determined by the maximum fault 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 the CT manufacturer. Taking account of the bur-den and the CT losses, the effective accuracy limit factor n' becomes:

where:n = rated accuracy limit factor PN = rated CT power PE = CT losses PB = burden at rated current

In the case of schemes with phase-by-phase measurement, n' must satisfy the following two relationships:

where:IKmax = max. primary through-fault currentI1N = rated primary CT current

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

(2) n' ≥10 for TN ≤120 ms, or n' ≥20 for 120 ms



Page 19


Technical data Table 3 General dataTemperature range:

- operation- storage and transport

-10°C...+ 55°C- 40°C...+ 85°C

EN 60255-6 (1994), IEC 60255-6 (1988)EN 60255-6 (1994), IEC 60255-6 (1988)

Climate tests- Cold- Dry heat- Damp heat (long-time)

-25°C / 16 h+70°C / 16 h-25° to 70°C, 1°/min, 2 cycles+40°C; 93% rel. hum. / 4 days

EN 60068-2-1 (1993), IEC 68-2-1 (1990),EN 60068-2-2 (1993), IEC 68-2-2 (1974),EN 60068-2-14 (2000), IEC 60068-2-14 (2000), IEC 68-2-3 (1984)

Thermal withstand of insulating materials EN 60950 (1995) Sec. 5.1

Clearance and creepage distances EN 60255-5 (2001), IEC 60255-5 (2000), EN 60950 (1995), IEC 60950 (1995)

Insulation resistance tests 0.5 kV / >100 MOhm EN 60255 (2001), IEC 60255-5 (2000), VDE 0411

Dielectric tests 2 kV AC or 3 kV DC / 1 min1 kV AC or 1.4 kV DC / 1 min (across open contacts)

EN 60255 (2001), IEC 60255-5 Cl.C (2000), EN 60950 (1995), IEC 60950 (1995),BS 142-1966, ANSI/IEEE C37.90-1989

Impulse test 1.2/50 μs/0.5 Joule 5 kV AC

EN 60255-5 (2001), IEC 60255-5 (2000)

Table 4 Electromagnetic compatibility (EMC)Immunity

1 MHz burst disturbance tests

1.0/2.5 kV, 1 MHz 400 Hz rep. freq.

IEC 60255-22-1, Cl. 3 (1988), ANSI/IEEE C37.90.1-1989

Immunity Industrial environment EN 50263 (1996)

Electrostatic discharge test (ESD)

- air discharge- contact discharge

8 kV6 kV

EN 61000-4-2, Cl. 3 (1996), IEC 61000-4-2 (2001)

Fast transient test (burst) 2/4 kV EN 61000-4-4, Cl. 4 (1995), IEC 61000-4-4 (1995)

Power frequency magnetic field immunity test (50/60 Hz)- continuous field- short duration

30 A/m300 A/m

EN 61000-4-8, Cl. 4 (1993), IEC 61000-4-8 (1993)

Radio frequency interference test (RFI)

0.15 - 80 MHz, 80% ampli-tude modulated 10 V, Cl. 380 - 1000 MHz, 80% ampli-tude modulated10 V/m, Cl. 3900 MHz, pulse modulated10 V/m, Cl. 3

EN 61000-4-6 (1996), IEC 61000-4-6 (1996),EN 61000-4-3 (1996), IEC 61000-4-3 (1995),

Emission Industrial environmentTest procedure

EN 55022 (1998), CISPR 22 (1990)



Page 20


Technical data (cont´d)Technical data (cont´d) 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 classesBay unit 19" central unit Cubicle (see Table 12)

IP40 IP20 IP40-50

Table 7 Analog inputs (Bay unit)Currents

4 /6/8/9 input channels

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

Thermal ratings:continuous

for 10 sfor 1 s

1 half-cycle

4 x IN

30 x IN100 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 A ≤0.10 VA at IN = 5 A

Voltages (optional)

1/3/5 input channels

U1/U1, U2, U3/U1, U2, U3, U4, U5

500BU03

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

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 UNCommon data

Rated frequency (fN) 50 Hz, 60 Hz, 16.7 Hz adjustable via HMI500



Page 21


Table 9 Auxiliary supply

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

General

Operating time 3 ms (typical)

Max. operating voltage ≤250 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 < 50 V DC ≤ 1.5 A U < 120 V DC ≤ 0.3 A U < 250 V DC ≤ 0.1 AU < 50 V DC ≤ 5 AU < 120 V DC ≤ 1 AU < 250 V DC ≤ 0.3 A

Signalling contacts CR01...CR07, 500BU03

Signalling contacts CR05, CR06 - 500CU03

Breaking current U < 50 V DC ≤ 0.5 A U < 120V DC ≤ 0.1 A U < 250V DC ≤ 0.04 A

Binary inputs

Number of inputs per bay unit 20 optocouplers 9 groups with common terminal

Number of inputs for central unit 12 optocouplers per binary I/O module (max. 2) 3 groups with common terminal

Voltage range (Uoc) 48 to 250 V DCPick-up setting via HMI500

Pick-up current ≥10 mA

Operating time 50 ms; IEC 60255-11 (1979), VDE 0435, Part 303

Frontplate signal green "standby" LED

Switch ON/OFF

Redundancy of power supply optional in bay and in central unit



Page 22


Technical data (cont´d)Technical data (cont´d) Table 10 Optical interfaces

Table 12 Cubicle design

Number of cores 2 fiber cores per bay unit

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

Max. permissible attenuation ≤5 dB (see Fig. 9)

Max. length approx. 1200 m

Connector Type FST for 62.5 μm optical fiber cables

Table 11 Mechanical designMounting

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



Page 23


Recording facilitiesTable 13 Event recorder

Table 14 Disturbance recorder

Table 15 Interbay bus protocols

Event recorder Bay unit Central unit

System eventsProtection eventsTest events

100 total 1000 total

Analog channel Recording period Sample 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 ± 1 ms - Two independent time servers 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)

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 events Generic mode: Support of all binary events - Trip reset command - Disturbance recording data

Address setting of station address 0...254

Sub address setting, common address of ADSU

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



Page 24


Technical data (cont´d)Technical data (cont´d) 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 Ikmin in 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/Ikmin ≥5 incl. tripping relays; for fN = 50, 60 Hz30 to 40 ms at Idiff/Ikmin ≥5 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



Page 25


Table 19 Overcurrent protection (51) Characteristic definite time

Measurement:

Setting range 0.1 to 20 x IN in steps of 0.1 x INSetting 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 criterion (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 HMI500

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



Page 26


Technical data (cont´d)Technical data (cont´d) Table 24 Delay/integrator

Table 25 Logic

Bay level functions 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 INDelay 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)



Page 27


Settings:

Number of phases 1 or 3

Base current IB 0.04 to 2.5 IN in steps of 0.01 INPick-up current Istart 1 to 4 IB in steps of 0.01 IBMin. time setting tmin 0 to 10 s in steps of 0.1 s

k1 setting 0.01 to 200 s in steps of 0.01 s

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

E 5.0±4% (1 - I/80 IB)

Reset ratio 95%

Table 28 Definite time over- and undervoltage 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 UN in steps of 0.01 UNDelay 0.02 to 60 s in steps of 0.01 s

Accuracy of the pick-up setting (at fN) ±2% or ±0.005 UNReset ratio (U ≥ 0.1 UN)

overvoltageundervoltage

>96% (for max. function)



Page 28


Technical data (cont´d)Technical data (cont´d) Table 30 Directional overcurrent definite time protection (67)• Directional overcurrent protection with detection of power flow direction• Back-up protection• 4 independent parameter sets

• Three-phase measurement• Suppression of DC and HF components• Definite time characteristic• Voltage memory for near faults• Selectable response when power direction no longer valid (trip or block)

Settings:

Current 0.02 to 20 IN in steps of 0.01 INAngle -180° to +180° in steps of 15°

Delay 0.02 to 60 s in steps of 0.01 s

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 0.9…1.05 fN• Sinusoidal voltage including 3., 5., 7. and 9. harmonic

Accuracy of pick-up valueReset ratioAccuracy of angle measurement (at 0.97…1.03 fN)

±5%95%±5°

• Voltage input range • Voltage memory range• Accuracy of angle measurement at voltage memory• Frequency dependence of angle measurement at

voltage memory• Response time without delay

0.005 to 2 UN



Page 29


Accuracies:Measuring accuracies are defined by:• Frequency range 0.9…1.05 fNAccuracy of pick-up value Reset ratioAccuracy of angle measurement (at 0.97…1.03 fN)

±5%95%±5°

• Voltage input range • Voltage memory range• Accuracy of angle measurement at voltage memory• Frequency dependence of angle measurement at

voltage memory• Response 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 current 0.05 to 1.00 IN in steps of 0.05 INAmplitude 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 voltage 0.05 to 1.2 UN in steps of 0.05 UNAmplitude compensation for summation VT -2.00 to +2.00 in steps of 0.01




Page 30


Technical data (cont´d)Technical data (cont´d)

Remark: Distance protection operating times on next page

Table 34 Directional sensitive 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 IN in steps of 0.01 INVoltage pick-up setting 0.003 to 1 UN in steps of 0.001 UNCharacteristic 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 backward• All 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 Ω/ph in steps of 0.01 Ω/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 Ω/ph in steps of 0.1 Ω/ph

Overcurrent starters 0.5 to 10 IN in steps of 0.01 INMin. operating current 0.1 to 2 IN in steps of 0.01 INBack-up overcurrent 0 to 10 IN in steps of 0.01 INNeutral current criterion 0.1 to 2 IN in steps of 0.01 INNeutral voltage criterion 0 to 2 UN in steps of 0.01 UNLow-voltage criterion for detecting, for exam-ple, a weak infeed

0 to 2 UN in steps of 0.01 UN

VT supervisionNPS/neutral voltage criterionNPS/neutral current criterion

0.01 to 0.5 UN in steps of 0.01 UN 0.01 to 0.5 IN in 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 >0.1±2° for U/UN >0.1

±5%±10%±10%

Operating times of the distance protection function (including tripping relay)

minimumtypical(see also isochrones)

20 ms25 ms

Typical reset time 25 ms

VT-MCB auxiliary contact requirementsOperation time



Page 31


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)

Z F/Z

L

Z F/Z

L

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

Z F/Z

L

Z F/Z

L

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

Z F/Z

L

Z F/Z

L

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

18ms17ms



Page 32


Technical data (cont´d)Technical data (cont´d) 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 none 1P fault - 1P reclosure 1P fault - 3P reclosure 1P/3P fault - 3P reclosure1P/3P fault - 1P/3P reclosure

2nd to 4th reclosure none two reclosure cycles three reclosure cycles four reclosure cycles

Single 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 synchronism

Single phase measurement. The differences between the amplitudes, phase-angles and frequencies of two voltage vectors are determined.

• Voltage supervisionSingle or three-phase measurement Evaluation of instantaneous values and therefore wider frequency range Determination 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 UN in steps of 0.05 UNMax. 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 steps of 0.05 UNMax. voltage 0.1 to 1 UN in steps of 0.05 UNSupervision 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 differencePhase differenceFrequency difference

for 0.9 to 1.1 fN±5% UN±5°±0.05 Hz



Page 33


Table 38 Transformer differential protection (87T)• For two- and three-winding transformers• Three-phase function• Current-adaptive characteristic• High stability for external faults and current transformer saturation• No auxiliary transformers necessary because of vector group and CT ratio compensation• Inrush restraint using 2nd harmonic

Settings:

g-setting 0.1 to 0.5 IN in steps of 0.05 INv-setting 0.25 or 0.5 or 0.7

b-setting 1.25 to 2.5 in steps of 0.25 INMax. trip time (protected transformer loaded)- for IΔ >2 IN- for IΔ ≤2 IN

≤30 ms≤50 ms

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

Reset conditions IΔ



Page 34


Technical data (cont´d)Technical data (cont´d) Table 40 Peak value over- and undervoltage protection (50)• 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)

90% (for max. function)



Page 35


Table 43 Rate of change frequency protection df/dt (81)• Maximum or minimum function (over- and underfrequency)• Minimum voltage blocking

Settings:

df/dt -10 to +10 Hz/s in steps of 0.1 Hz/s

Frequency 0 to 55 Hz in steps of 0.01 Hz at fN = 50 Hz50 to 65 Hz in steps of 0.01 Hz at fN = 60 Hz


Minimum voltage blocking 0.2 to 0.8 UN in steps of 0.1 UNAccuracy of df/dt (at 0.9 to 1.05 fN) ±0.1 Hz/s

Accuracy of frequency (at 0.9 to 1.05 fN) ±30 mHz

Reset ratio 95% for max. function105% for min. function

Table 44 Definite time overfluxing protection (24)• Single-phase measurement• Minimum voltage blocking

Settings:

Pick up value 0.2 to 2 UN/fN in steps of 0.01 UN/fNDelay 0.1 to 60 s in steps of 0.01 s

Frequency range 0.5 to 1.2 fNAccuracy (at fN) ±3% or ±0.01 UN/fNReset ratio >98% (max.),



Page 36


Technical data (cont´d)Technical data (cont´d) Table 46 Power protection (32)• Measurement of real or apparent power• Protection function based on real or apparent power measurement• Reverse power protection• Over- and underpower• Single or three-phase measurement• Suppression of DC components and harmonics in current and voltage• Compensation of phase errors in main and input CTs and VTs

Settings:

Power pick-up -0.1 to 1.2 SN in steps of 0.005 PN

Characteristic angle -180° to +180° in steps of 5°


Power factor comp. (Phi) -5° to +5° in steps of 0.1°

Rated power PN 0.5 to 2.5 UN × IN in steps of 0.001 UN × INReset ratio 30% to 170% in steps of 1% of power pick-up

Accuracy of the pick-up setting ±10% of setting or 2% UN × IN(for protection CTs)±3% of setting or 0.5% UN × IN(for core-balance CTs)

Max. operating time without intentional delay 70 ms



Page 37


Connection diagrams

Inputs / outputs central unit

Fig. 11 Central unit module; Connection of power supply, binary inputs and outputs

Binary inputs Binary outputs

500BIO01

500PSM03

aux

Alarm

Warning

123

4

5

6

2

1

Binary inputs Binary outputs

500BIO01

Optional I/O board

Optional redundant power supply

500PSM03

aux

Alarm

Warning

123

4

5

6

1

2

Abbreviations Explanation

OCxx CRxx

optocoupler Tripping relay

Terminal block/ terminals

Explanation Wire gauge/ Type

ABP

Binary inputsBinary outputsPower supply

1.5 mm21.5 mm21.5 mm2



Page 38


Connection diagrams (cont´d)Connection diagrams (cont´d)

Fig. 12 Wiring diagram of bay units 500BU03, types 1-8

Bay unit types Available inputs/outputs

500BU03_4 (4 I, 20/16 I/O, stand-alone)

500BU03_2 (4 I, 5 U, 20/16 I/O, stand-alone)

500BU03_6 (3 I, 1MT, 5 U, 20/16 I/O, stand-alone)

500BU03_1 (4 I, 5 U, 20/16 I/O, stand-alone) red. power supply

500BU03_5 (3 I, 1MT, 5 U, 20/16 I/O, stand-alone)red. power supply

500BU03_4 (4 I, 20/16 I/O, classic-mounting)

500BU03_2 (4 I, 5 U, 20/16 I/O, classic-mounting)

500BU03_6 (3 I, 1MT, 5 U, 20/16 I/O, classic-mounting)

500BU03_1 (4 I, 5 U, 20/16 I/O, classic-mounting) red. power supply

500BU03_5 (3 I, 1MT, 5 U, 20/16 I/O, classic-mounting) red. power supply

500BU03_8 (9 I, 20/16 I/O, stand-alone)

500BU03_7 (9 I, 20/16 I/O, stand-alone) red. power supply

500BU03_8 (9 I, 20/16 I/O, classic-mounting)

500BU03_7 (9 I, 20/16 I/O, classic-mounting) red. power supply

*) 1 Measuring transformer in 500BU03_5 or 500BU03_6

Terminal block/

terminals

Function Wire gauge/

Type

A, B Binary inputs 1.5 mm2

C, D Binary outputs 1.5 mm2

E Rx Tx

Optical connection Receive Transmit

FST plug FST plug

I, J Currents 2.5 mm2

U Voltages 1.5 mm2

P, R Supply 1.5 mm2

Abbreviations Explanation

OCxx CRxx OLxx

Opto-coupler Tripping relay Optical link

I1[1]

I1[5]

I1[0]

I2[1]

I2[5]

I2[0]

I3[1]

I3[5]

I3[0]

I4[1]

I4[5]

I4[0]

+-

R

I

0

DC

HMI

H

1

2

3

4

5

6

7

8

9

10

11

12

+-

P

I

0

B

D

A

C

Tx

Rx

I

Rx Tx

E

U1U1[0]

U2U2[0]

U3

U3[0]

U4U4[0]

U5U5[0]

U

500BU03

I1[1]

I1[5]

I1[0]

I2[1]

I2[5]

I2[0]

I3[1]

I3[5]

I3[0]

I4[1]

I4[5]

I4[0]

+-

R

0

I

DC

HMI

H

1

2

3

4

5

6

7

8

9

10

11

12

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

+-

P

0

I

B

D

A

C

Tx

Rx

Rx Tx

I1[1]

I1[5]

I1[0]

I2[1]

I2[5]

I2[0]

I3[1]

I3[5]

I3[0]

I4[1]

I4[5]

I4[0]

I5[1]

I5[5]

I5[0]

I6[1]

I6[5]

I6[0]

JE

I7[1]

I7[5]

I7[0]

I8[1]

I8[5]

I8[0]

I9[1]

I9[5]

I9[0]

500BU03

I

Binary Inputs

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

OC01

OC02

OC03

OC04

OC05

OC06

OC07

OC08

16

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

OC01

OC02

OC03

OC04

OC05

OC06

OC07

OC08

A

16

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

OC10

OC11

OC12

OC13

OC14

OC15

OC16

17

18OC09

OC17

OC18

OC19

OC20

16

17

18

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

OC10

OC11

OC12

OC13

OC14

OC15

OC16

B

17

18OC09

OC17

OC18

OC19

OC20

16

17

18

Processbus

Binary Outputs1

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

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

OL01

Tx

Rx

E

Current Transformer

1

5

0

Power Supply

1

5

0

I

1

2

3

I1

I2

4

5

6

1

5

0

I3

7

8

9

HMI InterfaceH

+_

1

2

P

Current Transformer

1

5

0

Redundant Power Supply

1

5

0

J

1

2

3

I4

I5

4

5

6

1

5

0

I6

7

8

9

+_

1

2

R

1

5

0

I7

10

11

12

1

5

0

I8

13

14

15

1

5

0

I9

16

17

18

Current Transformer

1

5

0

Power Supply

1

5

0

1

5

0

I

1

2

3

I1

I2

4

5

6

1

5

0

I3

7

8

9

I4

10

11

12

HMI InterfaceH

+_

1

2

P

Voltage Transformer

Redundant Power Supply

U

+_

1

2

R

0

1

2

U1

numerical station protection system...

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