Substation Automation Products
Distributed busbar protection REB500пЂ including line and transformer protection
Product Guide
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Main features
• Low-impedance busbar protection
• Stub and T-zone protection
• High functional reliability due to two independent 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 пЂ 48 V DC and 250 V DC
- nominal frequencies of 50, 60 and пЂ 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, isolators, 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 interferenceproof data transfer even close to HV power
cables
• Replacement of existing busbar protection
schemes can be accomplished without restrictions (centralized layout) in the case of
substation extensions e.g. by a mixture of
centralized and distributed layout
• Easily extensible
Additional
main features
Page 2
REB500sys combines the well-proven numerical busbar and breaker failure protection
REB500 of ABB with Main 2 or back-up protection 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.
• 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 varying units
• Communication facilities for substation
monitoring and control systems via пЂ IEC 61850-8-1, IEC 60870-5-103 and LON
• IEC 62439 standard redundant station bus
communication
• IEC 61850-9-2 LE process bus communication
• Cyber security to support
- User Access Management
- User Activity Logging
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 impedancegrounded networks
• Communication with substation monitoring
and control system (IEC 61850-8-1 /пЂ IEC 60870-5-103 / LON)
• Internal user-friendly human machine interface with display
• Redundant power supply for central units
and/or bay units
Main 2 / back-up bay protection
• Definite and inverse time over- and undercurrent protection
• Directional overcurrent definite and inverse
time protection
• Inverse time earth fault overcurrent protection
• Definite time over- and undervoltage protection
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
• Three-phase current and three-phase voltage plausibility
- checks for dead line, dead bus, dead
line and bus
Main 2 / back-up bay protection: пЂ Line protection
• High-speed distance protection
• Directional sensitive earth fault protection
for grounded systems against high resistive 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
Group 1 / back-up bay protection: пЂ Transformer protection
• High-speed transformer differential protection for 2- and 3-winding and auto-transformers
• Thermal overload
• Peak value over- and undercurrent protection
• Peak value over- and undervoltage protection
• Overfluxing protection
• Rate of change frequency protection
• Frequency protection
• Independent T-Zone protection with transformer differential protection
• Power protection
Application
REB500
REB500sys
The numerical busbar protection REB500 is
designed for the high-speed, selective protection of MV, HV and EHV busbar installations
at a nominal frequency of 50, 60 and 16.7 Hz.
The REB500sys is foreseen in MV, HV and
EHV substations with nominal frequencies of
16.7, 50 Hz or 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 structure of both hardware and software
is modular enabling the protection to be easily
configured to suit the layout of the primary
system.
The flexibility of the system enables all configurations of busbars from single busbars to
quadruple busbars with transfer buses, ring
busbars and 1ВЅ breaker schemes to be protected.
In 1ВЅ 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 wiring.
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 systems and phase faults in ungrounded systems
and systems with Petersen coils.
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.
The system REB500sys is foreseen for all single or double busbar configurations (Line variants L-V1 to L-V7 and Transformer variant TV1 to T-V4). In 1ВЅ breaker configurations,
variant L-V5 can be used for the bay level
functions 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 solidly and low resistive-grounded power systems, 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 protection
functions (e.g. line protection, autoreclosure
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.
Page 3
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Application (contВґd)
Depending on the network voltage level and
the protection philosophy the following protection concepts are generally applied:
- Line variant 5 (L-V5)пЂ as line variant L-V1 plus autoreclosure and
synchrocheck.
• Two main protection schemes per bay
and one busbar protection.пЂ With REB500sys the protection concept
can be simplified. Due to the higher integration 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.пЂ 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 economical reasons.
- Line variant 6 (L-V6) for 16.7 HzпЂ non-directional overcurrent, distance protection, autoreclosure.
Nine standard options are defined for Main 2/
Group 1 or back-up bay level functions:
Line protection
- Line variant 1 (L-V1)пЂ directional, non-directional overcurrent and
directional earth fault protection
- Line variant 2 (L-V2)пЂ as line variant L-V1 plus distance prot.
- Line variant 3 (L-V3)пЂ as line variant L-V2 plus autoreclosure
- Line variant 4 (L-V4)пЂ as line variant L-V3 plus synchrocheck
Fig. 1
Page 4
- Line variant 7 (L-V7) for 16.7 HzпЂ as line variant L-V6 plus directional earth
fault protection for grounded systems
Transformer protection
- Transformer variant 1 (T-V1)пЂ 2- or 3 winding transformer differential protection, thermal overload, current functions;
applicable also as autonomous T-zone protection.
- Transformer variant 2 (T-V2)пЂ 2-winding transformer differential protection, thermal overload, current functions,
overfluxing protection, neutral overcurrent
(EF).
- Transformer variant 3 (T-V3)пЂ Distance protection for transformer back-up
or 2-winding transformer differential protection, thermal overload, current functions,
voltage functions, frequency functions,
power function, overfluxing protection.
- Transformer variant 4 (T-V4)пЂ Transformer oriented functions/ back-up
functions -> thermal overload, current functions, voltage functions, frequency functions, power function, overfluxing protection.
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
PDIS
RREC
RSYN
PDIF
PDIF
PTTR
PTUC/PTOC
PTUV/PTOV
PVPH
PVPH
PVRC
PTOF/PTUF
PDUP/PDOP
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z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
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z z
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z
z
Transformer Variant 4 (T-V4) 50/60 Hz
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Transformer Variant 3 (T-V3) 50/60 Hz
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z
z
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z
z
z
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Transformer Variant 2 (T-V2) 50/60 Hz
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z
z
z
z
z
z
z
z
z
Transformer Variant 1 (T-V1) 50/60 Hz
Line Variant 7 (L-V7) 16.7 Hz
OCDT
OCINV
OVDT
I0INV
DIROCDT
DIROCINV
CHKI3PH
CHKU3PH
Line Variant 6 (L-V6) 16.7 Hz
IEC61850
-
Line Variant 5 (L-V5) 50/60Hz
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-
51
51
59/27
51N
67
67
46
47
67N
z
z
Line Variant 4 (L-V4) 50/60Hz
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Com
ER
DR
DR
z
Line Variant 3 (L-V3) 50/60Hz
DIREFISOL PSDE
DIST
AR
SYNC
DIFTRA
DIFTRA
TH
OCINST
OVINST
U/fDT
U/fINV
df/dt
Freq
P
-
BBP CZ
OCDT
PDIF
PDIF
RBRF
PTOC
PTOC
PTOC
PTOV/PTUV
PDIF
PTOC
RDRE
RDRE
Option
32N
21
79
25
87T
87T
49
50
59
24
24
81
81
32
BBP
I0
BFP
EFP
PDF
Standard
z
z
z
z
z
z
z
z
z
z
Protection function
PTOC
PTOC
PTUV/PTOV
PTOC
PTOC
PTOC
PTOC
PTUV
DIREFGND PDEF
87B
87BN
50BF
51/62EF
51/62PD
51
59/27
87CZ
51
94RD
95DR
95DR
Line Variant 2 (L-V2) 50/60Hz
Busbar protection
Busbar protection with neutral current
Breaker failure protection inlcluding neutral current detection
End-fault protection
Breaker pole discrepancy
Overcurrent check feature
Voltage check feature
Check zone
Current plausibility check
Overcurrent protection (def. time)
Trip command re-direction
Software matrix for inputs / outputs / trip matrix
Event recording up to 1000 events
Disturbance recorder (4 x I)
Disturbance recorder (4 x I, 5 x U) up to 10 s at 2400 Hz
Communication interface IEC 61850-8-1/
LON / IEC 60870-5-103
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
Inverse time overcurrent protection
Definite time over- and undervoltage protection
Inverse time earth fault overcurrent protection
Directional overcurrent definite time protection
Directional overcurrent inverse time protection
Three phase current plausibility
Three phase voltage plausibility
Test sequenzer
Direct. sensitive EF prot. for grounded systems
Direct. sensitive EF prot. for ungrounded or compensated
systems
Distance protection
Autoreclosure
Synchrocheck
Transformer differential protection 2 winding
Transformer differential protection 3 winding
Thermal overload
Peak value over- and undercurrent protection
Peak value over- and undervoltage protection
Definite time overfluxing protection
Inverse time overfluxing protection
Rate-of-change frequency protection
Frequency protection
Power protection
IEEE
Main functionality
Line Variant 1 (L-V1) 50/60Hz
Table 1 Overview of the functionalities REB500 / REB500sys
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Page 5
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Mode of пЂ installation
There are three versions of installing the numerical busbar protection REB500 and the numerical station protection REB500sys:
Distributed installation
In this case, the bay units (see Fig. 24) are
installed in casings or cubicles in the individual switchgear bays distributed around the
Fig. 2
Distributed installation
Centralized installation
19" 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
Fig. 3
Centralized installation
Combined centralized and distributed
installation
Basically, the only difference between a distributed and a centralized scheme is the
mounting location of the bay units and therefore it is possible to mix the two philosophies.
Page 6
station and are connected to the central processing unit by optical fiber cables. The central processing unit is normally in a centrally
located cubicle or in the central relay room.
for upgrading existing stations, since veryпЂ little additional wiring is required and compared with older kinds of busbar protection,
much more functionality can be packed into
the same space.
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
System design
Bay unit (500BU03)
The bay unit (see Fig. 4) is the interface
between the protection and the primary system process comprising the main CTs, isolators and circuit-breaker and performs the
associated data acquisition, pre-processing,
control functions and bay level protection
functions. It also provides the electrical insulation 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 configuring the software of the respective bay
units.
Optional input transformer module also contains 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 пЂ 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
numerically preprocessed and filtered accordingly. Zero-sequence voltage and zero-current
signals 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 patented 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 operating
relays and can be used for either signaling or
tripping purposes (see contact data in Table
8).
A software logic enables the input and output
channels to be assigned to the various functions. 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 coupler bay with CTs on both sides of the bus-tie
breaker requires two bay units).
The bay unit is provided with local intelligence
and performs local protection (e.g. breaker
failure, end fault, breaker pole discrepancy),
bay protection (Main 2 or back-up bay protections) as well as the event and disturbance
recording.
Central Unit (500CU03)
Bay Unit (500BU03)
DC
DC
Optical
Interface
DC
DC
Local HMI
Process-bus
SAS/SMS
Interface
Real-time
Clock
RS 232
Interface
Local HMI
CPU
Uhr
M odul
I nt
e r
f ace
I nt
e rf ace
M odul
Central
c es s
- bu s
tp u t
CPU
Module
M odul
Kopp ler
DSP
DP
U
nit
Ko pp ler
E/ A
(500
CU03
)
DC
D
C
Lo
ca
l
Mod ul
E/ A
Re a l -ti m e
Cl o c k
S A S/ SM S
In t e rfa c e
RS
23 2
I n te rf a c e
HM
I
CIM
CP U
M o d u le
C IM
CP U
M odule
Mem
St
a rc o u p le r
Bi n a ry
I/ O
CP U
M odule
St
ar
c o u p le r
Binary in/output
registers
A/D
CPU
Module
CPU
Module
Filter
Filter
Starcoupler
Binary
I/O
Star
coupler
Electrical
insulation
Fig. 4
Block diagram of a bay unit and a central unit
Page 7
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
System design (contВґd)
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 convenient 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 distributed 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 (seeпЂ Fig. 28).
In the event of a failure, a bay unit can be easily replaced. The replacement of a bay unit
can be handled in a simple way. During system 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 automatically.
Additional plug-and-play functionality
Bay units can be added to an existing
REB500 system in a simple way.
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, complexity and functionality of the busbar system.
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, manages the sets of operating parameters, acts as
process bus controller, assures synchronization of the system and controls communication with the station control system.
The variables for the busbar protection function 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
processors 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 processors and star coupler modules
required.
All modules of the central unit have a plugand-play functionality in order to minimize
module configuration.
One or two binary I/O modules can be connected 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. 5
Bay unit
Fig. 6
Page 8
Central unit
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Functionality
Busbar protection
The protection algorithms are based on two
well-proven measuring principles which have
been applied successfully in earlier ABB lowimpedance busbar protection systems:
where N is the number of feeders. The following two conditions have to be accomplished
for the detection of an internal fault:
k st пЂЅ
• a stabilized differential current measurement
• the determination of the phase relationship
between the feeder currents (phase comparison)
The algorithms process complex current vectors which are obtained by Fourier analysis
and only contain the fundamental frequency
component. Any DC component and harmonics 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).
k=1
Differential
current
( |пЃ“ пЃ‰ | )
in
ip p
Tr a
e
r
a
K setting =
kst max
Restraint
area
IK m in
0
0
Fig. 7
g
Restraint current
(пЃ“|пЃ‰|)
Tripping characteristic of the stabilized пЂ differential current algorithm.
N
 ILn
nпЂЅ1
IDiff пЂѕ IK min
whereпЂ kst
kst max
IK min
(3)
(4)
stabilizing factor
stabilization factor limit. пЂ A typical value is kst max = 0.80
differential current pick-up value
The above calculations and evaluations are
performed by the central unit.
пЂ 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
пЃЄ1..n (5) are compared. In the case of an internal fault, all of the feeder currents have almost the same phase angle, while in normal
operation or during an external fault at least
one current is approximately 180В° out of
phase with the others.
пѓ© ImпЂЁI пЂ© пѓ№
пЃЄn пЂЅ arctanпѓЄ Ln пѓє
пѓ«ReпЂЁILn пЂ©пѓ»
(5)
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).
In Fig. 7, the differential current is
IDiff пЂЅ
IDiff
пЂѕ k st max
IRest
(1)
and the restraint current
IRest пЂЅ
N
 ILn
nпЂЅ1
(2)
Page 9
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Functionality (contВґd)
Case 1: External fault пЃ„пЃЄпЂ = 144В°
Im
Busbar
пЃЄпЂ±пЂІпЂ = 144В°
I2
Re
I1
Operating characteristic
Case 2: Internal fault пЃ„пЃЄ = 36В°
180В°
Im
Phase-shift
Restraint area
пЃ„пЃЄ
74В°
пЃ„пЃЄ
max
= 74В°
Tripping area
0В°
Case
Fig. 8
1
2
I1
This first timer operates in a stand-alone
mode in the bay unit.
If the fault still persists at the end of the second 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.
Re
I2
пЃЄпЂ±пЂІпЂ = 36В°
Characteristic of the phase comparator for
determining energy direction
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.
The task of processing the algorithms is
shared between the bay units and the central
processing unit. Each of the bay units continuously monitors the currents of its own fee-der,
preprocesses them accordingly and then filters the resulting data according to a Fourier
function. The analog data filtered in this way
are then transferred at regular intervals to the
central processing unit running the busbar
protection algorithms.
End fault protection
In order to protect the “dead zone” between
an open circuit-breaker and the associated
CTs, a signal derived from the breaker position and the close command is applied.
Depending on the phase-angle of the fault,
the tripping time varies at Idiff/IkminпЂ п‚і5 between 20 and 30 ms including the auxiliary
tripping relay.
This function is performed in a stand-alone
mode in the bay unit.
Optionally, the tripping signal can be interlocked 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 protection
The breaker failure functions in the bay units
monitor both phase currents and neutral current 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 algorithm (and, if configured, also by the internal 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 second
Page 10
tripping coil on the circuit-breaker and a
remote tripping signal transmitted to the station at the opposite end of the line.
The end fault protection is enabled a certain
time after the circuit-breaker has been opened. In the event of a short circuit in the dead
zone the nearest circuit-breakers are tripped.
Overcurrent function
A definite time overcurrent back-up protection
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 criteria
The current release criteria is only performed
in the bay unit. It is effective for a busbar protection 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 criteria
The voltage criterion is measured in the bay
unit. The function can be configured as
release criterion per zone through internal
linking in the central unit. This necessitates
the existence of one set of voltage transformers per zone in one of the bay units. Tripping
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
is only possible if the voltage falls short of
(U<) or exceeds (U0>) the set value.
Additionally this release criterion can be configured for each feeder (voltage transformers
must be installed). For details see Table 22.
Check zone criterion
The 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 criterion.
Neutral current detection I0
Earth fault currents in impedance-grounded
systems may be too low for the stabilized differential current and phase comparison functions to detect. A function for detecting the
neutral current is therefore also available, but
only for single phase-to-earth faults.
Pole discrepancy
A pole discrepancy protection algorithm
supervises that all three poles of a circuitbreakers open within a given time.
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 general-purpose binary inputs may be configured
to enable external signals to trigger a disturbance record. In addition, there is a binary
input in the central and the bay unit for starting
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 sampling
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 recorded data is retained or overwritten by the
next disturbance (FIFO = First In, First Out).
This function monitors the discrepancy between the three-phase currents of the circuitbreaker.
This function is performed in a stand-alone
mode in the bay unit (see page 7).
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).
Note:
Stored disturbance data can be transferred via
the central unit to other computer systems for
evaluation by programs such as PSM505 [3].
Files are transferred in the COMTRADE format.
This function is also performed in a standalone mode in the bay unit.
Event recording
The events are recorded in each bay unit. A
time stamp with a resolution of 1ms is attached to every binary event. Events are divided
into the three following groups:
After retrieving the disturbance recorder data,
it is possible to display them graphically with
PSM505 directly.
• test events
Communication interface
Where the busbar protection has to communicate with a station automation system (SAS),
a communication module is added to the central unit. The module supports the interbay
bus protocols IEC 61850-8-1, IEC 60870-5103 and LON.
The events are stored locally in the bay unit or
in the central unit.
The IEC 61850-8-1 interbay bus transfers via
either optical or electrical connection:
Disturbance recording
This function registers the currents and the
binary inputs and outputs in each bay. Voltages can also be optionally registered (see
Table 14).
• differential current of each protection zone
• system events
• protection events
• monitoring information from REB500 central unit and bay units
• binary events (signals, trips and diagnostic)
• trip reset command
Page 11
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Functionality (contВґd)
• disturbance recording data (via MMS file
transfer protocol)
• time synchronization with Simple Network
Time Protocol (SNTP)
• two independent time servers are supported. Server 2 as backup time
The LON interbay bus transfers via optical
connection:
(protection zones). The system monitors 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 protection:
• blocked
• differential currents of each protection zone
• zone-selective blocked
• binary events (signals, trips and diagnostic)
• remain in operation
• trip reset command
• disturbance recording data (via HMI500)
Table 2
• time synchronization
N/O
contact:
“Isolator
CLOSED”
N/C
contact:пЂ вЂњIsolator
OPEN”
open
open
open
closed
OPEN
closed
open
CLOSED
closed
closed
CLOSEDпЂ + delayed isolator
alarm, + switching prohibited signal
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 generator
The HMI program (HMI500) which runs on a
PC connected to either a bay unit or the central processing unit includes a test generator.
During commissioning and system maintenance, the test generator function enables the
user to:
• activate binary input and output signals
• monitor system response.
• blocked
• test the reclosure cycles
• remain in operation
The test sequencer enables easy testing of
the bay protection without the need to decommission 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 supervision
The isolator replica is a software feature without any mechanical switching elements. The
software replica logic determines dynamically
the boundaries of the protected busbar zones
Page 12
Last position stored
(for busbar protection)пЂ + delayed isolator
alarm, + switching prohibited signal
Differential current supervision
The differential current is permanently supervised. Any differential current triggers a timedelayed alarm. In the event of a differential
current alarm, it is possible to select the
behavior of the busbar protection:
• test the trip circuit up to and including the
circuit-breaker
• establish and perform test sequences with
virtual currents and voltages for the bay
protection of the REB500sys
Isolator position
• zone-selective blocked
Trip redirection
A binary input channel can be provided to
which the external signal monitoring the circuit-breaker air pressure is connected. Tripping 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 criteria).
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Human machine interface (HMI)
The busbar protection is configured and maintained with the aid of human machine interfaces at three levels.
Local HMI
The 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 messages
• 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 busbar protection)
• system status, alarms
• switchgear and isolator positions (within
the busbar protection function)
• starting and tripping signals of protection
functions
Additional
functionalities
Bay level functions
These functions are based on the well established 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.
External HMI (HMI500)
More comprehensive and convenient control
is provided by the external HMI software running 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 WINDOWS
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 HMI
A 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.
The line protection functions (L-V1 - L-V7) are
used as Main 2 or back-up for lines as well as
for transformer bays. The transformer protection functions (T-V1 - T-V4) are used as Group
2 or back-up bay protection for transformer
bays or as an independent T-Zone protection.
Page 13
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Additional functionalities (contВґd)
High-speed distance protection
• Overcurrent or underimpedance starters
with polygonal characteristic
• Five distance zones (polygon for forwards
and reverse measurement)
• Load-compensated measurement
• Definite time overcurrent back-up protection (short-zone protection)
Transformer differential protection
• For two- and three-winding transformers
• System logic
• Auto transformers
- switch-onto-fault
• Three-phase function
- overreach zone
• Current-adaptive characteristic
• Voltage transformer circuit supervision
• Power swing blocking function
• HF teleprotection. The carrier-aided
schemes include:
• High stability for external faults and current
transformer saturation
• No auxiliary transformers necessary
because of vector group and CT ratio compensation
- permissive underreaching transfer tripping
• Inrush restraint using 2nd harmonic
- permissive overreaching transfer tripping
The transformer differential protection function
can also be used as an autonomous T-zone
protection in a 1ВЅ breaker scheme.
- blocking scheme with echo and transient blocking functions
• Load-compensated measurement
- fixed reactance slope
- reactance slope dependent on load
value and direction (ZHV<)
• Parallel line compensation
• Phase-selective tripping for single and
three-pole autoreclosure
• Four independent, user-selectable setting
groups.
In the supervision mode the active and reactive power with the respective energy direction
is displayed by the HMI500.
Autoreclosure
The autoreclosure function permits up to four
three-phase autoreclosure cycles. The first
cycle can be single phase or three-phase.
If the REB500sys autoreclosure function is
employed, it can be used as a back-up for the
autoreclosure realized externally (separate
equipment or in the Main 1 protection).
When the autoreclosure function is realized
outside of REB500sys, all input and output
signals required by the external autoreclosure
equipment are available in order to guarantee
correct functionality.
Page 14
Synchrocheck
The synchrocheck function determines the difference between the amplitudes, phase
angles and frequencies of two voltage vectors. The synchrocheck function also contains
checks for dead line and dead bus.
Thermal overload
This function protects the insulation against
thermal stress. This protection function is normally equipped with two independently set
levels and is used when oil overtemperature
detectors are not installed.
Peak value over- and undercurrent protection
These functions are used for current monitoring with instantaneous response and where
insensitivity to frequency is required.
Peak value over- and undervoltage protection
This function is used for voltage monitoring
with instantaneous response and where insensitivity to frequency is required.
Frequency function
The function is used either as an over-/ underfrequency protection, or for load-shedding in
the event of an overload. Several stages of
the frequency protection are often needed.
This can be achieved by configuring the frequency function several times.
Rate of change frequency protection df/dt
This function is used for the static, dynamic
and adaptive load-shedding in power utilities
and industrial distribution systems. The function supervises the rate-of-change df/dt of one
voltage input channel. Several stages of the
rate-of-change frequency protection are often
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
needed. This can be achieved by configuring
the rate-of-change frequency function several
times.
Definite time overfluxing protection
This function is primarily intended to protect
the iron cores of transformers against excessive flux. The function works with a definite
time delay. The magnetic flux is not measured
directly. Instead the voltage/frequency-ratio,
which is proportional to the flux is monitored.
Inverse time overfluxing protection
This function is primarily intended to protect
the iron cores of transformer against excessive 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 tmax. The magnetic flux is not measured directly. Instead the voltage/frequency-ratio,
which is proportional to the flux is monitored.
Power function
This function provides single, or three phase
measurement of the real or apparent power.
The function can be configured for monitoring
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/integrator
These functions allow the user the engineering of some easily programmable logical functions and are available as standard also in the
REB500 functionality.
Directional sensitive earth fault protection
for grounded systems
A 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 lowresistance grounded systems. The scheme
operates either in a permissive or blocking
mode and can be used in conjunction with an
inverse time earth fault overcurrent 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 distance protection
scheme or with an independent channel.
Directional sensitive earth fault protection
for ungrounded or compensated systems
The 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 В±90В° пЂ (U0 В· I0 В· sin пЃЄ) in ungrounded systems and to
0В° or 180В° (U0 В· I0 В· cos пЃЄ) for systems with
Petersen coils. The neutral current is always
used for measurement in the case of systems
with Petersen coils, but in ungrounded systems its use is determined by the value of the
capacitive current and measurement is performed 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 protection
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 protection
The operating time of the inverse time overcurrent 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 measurement with
detection of the highest phase current.
Inverse time earth fault overcurrent protection
The inverse time earth fault overcurrent function monitors the neutral current of the system. 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.
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).
Definite time over- and undervoltage protection
This function works with a definite time delay
with either single or three-phase measurement.
Page 15
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Additional functionalities (cont’d)
Three-phase current plausibility
This function is used for checking the sum and
the phase sequence of the three-phase currents.
Three-phase voltage plausibility
This function is used for checking the sum and
the phase sequence of the three-phase voltages.
AdditionalпЂ 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 inconsistency, the corresponding action is taken to
establish a safe status, an alarm is given and
an event is registered for subsequent diagnostic analysis.
Resetting the trip commands/-signals
The following resetting modes can be selected for each binary output (tripping or signal
outputs):
Important items of hardware (e.g. auxiliary
supplies, A/D converters and main and program memories) are subjected to various
tests when the system is switched on and also
during operation. A watchdog continuously
monitors the integrity of the software functions
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 reliability 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 system
The system functions are determined by software, configured using the software configuration 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 failure, end fault protection or bay level пЂ back-up / Main 2 functions can be easily activated at any time without extra hardware.
Page 16
• Latches until manually reset
• Resets automatically after a delay
Inspection/maintenance
A binary input is provided that excludes a bay
unit from evaluation by the protection system.
It is used while performing maintenance
respectively inspection activities on the primary 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 synchronization
The absolute time accuracy with respect to an
external time reference depends on the
method of synchronization used:
• no external time synchronization:пЂ accuracy approx. 1 min. per month
• periodic time telegram with minute pulse
(radio or satellite clock or station control
system): accuracy typically В±10 ms
• periodic time telegram as above with second pulse: accuracy typically ±1 ms
• a direct connection of a GPS or DCF77 to
the central unit is possible: accuracy typically В±1 ms
• Furthermore, the time synchronization can
be done, if available, via the interbay bus
IEC103, LON or SNTP (in case IEC618508-1 is used)
The system time may also be synchronized by
a minute pulse applied to a binary input on the
central unit.
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Requirements
Optical fiber cables
A distributed busbar protection layout requires optical fiber cables and connectors with
the following characteristics:
• 2 optical fiber cores per bay unit
• glass fibers with gradient index
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:
• diameter of core and sheath 62.5, пЂ respectively 125 пЃ­m
Optical equipment
TypicalпЂ attenuation
• maximum permissible attenuation 5 dB
for gradient index (840 nm)
3.5 dB/km
• FST connector (for 62.5 m optical fibers)
per connector
0.7 dB
• rodent protected and longitudinally waterproof if in cable ducts
per cable joint
0.2 dB
Central unit
1200 m
1m
FST-connector
Bay unit
1m
FST-connector
п‚ЈпЂµпЂ dB
Fig. 9
Attenuation
Isolator auxiliary contact
Auxiliary contacts on the isolators are connected to binary inputs on the bay units and
control the status of the busbar replica in the
numerical busbar protection.
must close before the isolator main contact
gap reaches its flashover point.
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”. During the closing movement, the N/O contact
Conversely, during the opening movement,
the N/O contact must not open before the isolator 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.
Close
end position
Open
end position
Close isolator
Open isolator
Isolator
Auxiliary contacts:
Flashover gap
„CLOSED“
normally open
„OPEN“
normally closed
must be closed
may be closed
must be open
Fig. 10
Switching sequence of the auxiliary contacts that control the busbar replica
Page 17
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Requirements (contВґd)
Circuit-breaker replica
When the circuit-breaker replica is read in the
feeder or the bus-tie breaker, the circuitbreaker CLOSE command must also be connected.
Main current transformer
The 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 protection
devices.
I1N =
rated primary CT current
Taking the DC time constant of the feeder into
account, the effective n' becomes:
(2)
n' п‚і10пЂ for TN п‚Ј120 ms, or
n' п‚і20пЂ for 120 ms <TN п‚Ј300 ms.
where:
TN = DC time constant
Example: IKmax = 30000 A
I1N = 1000 A
TN п‚Ј 120 ms
Current transformer requirements for stability during external faults (Busbar protection)
The minimum CT requirements for 3-phase
systems are determined by the maximum fault
current.
Applying relationships (1) and (2):
The effective accuracy limit factor (n') must be
checked to ensure the stability of the busbar
protection during external faults.
Selected:
The rated accuracy limit factor is given by the
CT manufacturer. Taking account of the burden and the CT losses, the effective accuracy
limit factor n' becomes:
n' пЂЅ n пѓ—
where:
n
=
PN =
PE =
PB =
PN пЂ« PE
PB пЂ« PE
rated accuracy limit factor
rated CT power
CT losses
burden at rated current
In the case of schemes with phase-by-phase
measurement, n' must satisfy the following
two relationships:
(1)
Page 18
where:
IKmax = max. primary through-fault current
1 пѓ— I Kmax
nп‚ў п‚і -----------------5 пѓ— I 1N
(1)
(2)
30000
n п‚ў ---------------- = 6
5000
n' п‚іпЂ 10
n' п‚іпЂ 10
The current transformer requirements for
REB500sys for Line and Transformer protection are described in a separate publication
[1].
Pick-up for internal faults
In the case of internal busbar faults, CT saturation is less likely, because each CT only
conducts the current of its own feeder.
Should nevertheless CT saturation be possible, it is important to check that the minimum
fault current exceeds the setting for Ikmin.
Note:
For systems that measure I0, the REB500
questionnaire 1MRB520371-Ken should be
filled in and submitted to ABB, so that the CT
requirements can be checked in order to
ensure proper I0 measurement.
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data
Table 3 General data
Temperature range:
- operation
- storage and
transport
Climate tests
- Cold
- Dry heat
- Change of temperature
- Damp heat пЂ (long-time)
-10В°C...+ 55В°C
- 40В°C...+ 85В°C
-25В°C / 16 h
+70В°C / 16 h
-25В° to 70В°C, 1В°/min, 2 cycles
IEC 60255-1 (2009), EN60255-1 (2010)
IEC 60255-27 (2005), EN 60255-27 (2006)
IEC 60255-1 (2009), EN60255-1 (2010)
IEC 60255-27 (2005), EN 60255-27 (2006)
EN 60068-2-1 (2008), IEC 60068-2-1 (2007),
EN 60068-2-2 (1993), IEC 60068-2-2 (2007),
EN 60068-2-14 (2010), IEC 60068-2-14 (2009)
EN 60068-2-78 (2002), IEC 60068-2-78 (2001)
+40В°C; 93% rel. hum. / 10
days
Thermal withstand of insulating materials
EN 60950 (1995) Sec. 5.1
Clearance and creepage distances
EN 60255-5 (2001), IEC 60255-5 (2000),пЂ EN 60950 (1995), IEC 60950 (1995)
Insulation resistance tests
0.5 kV / >100 MOhm
EN 60255-5 (2001), IEC 60255-5 (2000),
VDE 0411
Dielectric tests
2 kV AC or 3 kV DC / 1 min
1 kV AC or 1.4 kV DC / 1 min
(across open contacts)
EN 60255-5 (2001), IEC 60255-5 Cl.C (2000)
1.2/50 пЃ­s/0.5 JouleпЂ 5 kV AC
EN 60255-5 (2001), IEC 60255-5 (2000)
Impulse test
EN 60950 (1995), IEC 60950 (1995)
BS 142-1966, ANSI/IEEE C37.90-1989
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 (2007),
ANSI/IEEE C37.90.1-1989
Immunity
Industrial environment
EN 50263 (2000)
Electrostatic discharge test
(ESD)
- air discharge
- contact discharge
Class 3
EN 61000-4-2 (2009),пЂ IEC 61000-4-2 (2008)
EN 60255-22-2 (2009), пЂ IEC 60255-22-2 (2008)
Fast transient test (burst)
Class 4
2/4 kV
EN 61000-4-4 (2005), пЂ IEC 61000-4-4 (2004)
EN 60255-22-4 (2009), пЂ IEC 60255-22-4 (2008)
Power frequency magneticпЂ field immunity test (50/60 Hz)
- continuous field
- short duration
Class 4
EN 61000-4-8 (2009), пЂ IEC 61000-4-8 (2009)
8 kV
6 kV
30 A/m
300 A/m
Radio frequency interference пЂ Class 3
test (RFI)
0.15 - 80 MHz, 80% amplitude modulated 10 V
80 - 1000 MHz, 80% amplitude modulated 10 V/m
900 MHz, pulse modulated 10 V/m
EN 61000-4-6 (2009), IEC 61000-4-6
(2008)
Emission
- Conducted RFI
- Radiated RFI
Industrial environment
Test procedure
EN 55022 (1998), CISPR 22 (1990)
Surge
Class 3
1kV / 2kV
EN 60255-21-3 (1995), IEC 60255-21-3
(1993),
IEEE 344; 2004
EN 61000-4-3 (2011), IEC 61000-4-3
(2002)
Page 19
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Table 5 Mechanical tests
Vibration and shock
Vibration
- reponse test
- endurance test
Shock and bump
- shock
- bump
Seismic (SSE)
10 to 150 Hz / 0.5 gn
10 to 150 Hz / 1 gn
EN 60255-21-1 (1996), пЂ IEC 60255-21-1 (1988)
EN 60068-2-6 (2008) IEC 60068-2-6 (2007)
IEEE 344; 2004
Class 1
A = 15 gn; D = 11 ms pulse/
axis = 3
A = 10 gn; D = 16 ms pulse/
axis = 1000
EN 60255-21-2 (1996), пЂ IEC 60255-21-2 (1988)
EN 60068-2-27 (2010), пЂ IEC 60068-2-27 (2008)
IEEE 344; 2004
1 to 35 Hz, 1/2 gn
EN 60255-21-3 (1995), пЂ IEC 60255-21-3 (1993),
IEEE 344; 2004
Table 6 Enclosure protection classes
Bay unit
19" central unit
Cubicle (see Table 12)
IP40
IP20
IP40-50
Hardware modules
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, пЂ adjustable CT ratio via HMI500
Thermal ratings:
continuous
4 x IN
for 10 s
for 1 s
30 x IN
100 x IN
1 half-cycle
250 x IN (50/60 Hz) (peak)
Burden per phase
EN 60255-6 (1994),
IEC 60255-6 (1988), пЂ VDE 0435, part 303
EN 60255-6 (1994),
IEC 60255-6 (1988),пЂ VDE 0435, Part 303
п‚Ј0.02 VA at IN = 1 A пЂ п‚Ј0.10 VA at IN = 5 A
Voltages (optional)
1/
3/
5 input channels
U1/
U1, U2, U3/
U1, U2, U3, U4, U5
Rated voltage (UN)
100 V, 50/60 Hz, 16.7 Hz
200 V, 50/60 Hz
500BU03
VT ratio adjustable via HMI500
Thermal ratings:
continuous
2 x UN
for 10 s
3 x UN
Burden per phase
п‚Ј0.3 VA at UN
Common data
Rated frequency (fN)
50 Hz, 60 Hz, 16.7 Hz пЂ adjustable via HMI500
Page 20
EN 60255-6 (1994),
IEC 60255-6 (1988),
VDE 0435, part 303
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Table 8 Binary inputs/outputs (Bay unit, Central unit)
Binary outputs
General
Operating time
3 ms (typical)
Max. operating voltage
п‚Ј250 V AC/DC
Max. continuous rating
п‚Ј8 A
Max. make and carry for 0.5 s
п‚Ј30 A
Max. making power at 110 V DC
п‚Ј3300 W
Binary output reset response, programmable 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 п‚ЈпЂ 1.5 AпЂ U < 120 V DC п‚ЈпЂ 0.3 AпЂ U < 250 V DC п‚ЈпЂ 0.1 A
U < 50 V DC п‚ЈпЂ 5 A
U < 120 V DC п‚ЈпЂ 1 A
U < 250 V DC п‚ЈпЂ 0.3 A
Signalling contacts CR01...CR07, 500BU03
Signalling contacts CR05, CR06 - 500CU03
Breaking current
U < 50 V DC п‚ЈпЂ 0.5 AпЂ U < 120V DC п‚ЈпЂ 0.1 AпЂ U < 250V DC п‚ЈпЂ 0.04 A
Binary inputs
Number of inputs per bay unit
20 optocouplers пЂ 9 groups with common terminal
Number of inputs for central unit
12 optocouplers per binary I/O module (max. 2)пЂ 3 groups with common terminal
Voltage range (Uoc)
48 to 250 V DC
Pick-up setting via HMI500
Pick-up current
п‚і10 mA
Operating time
<1 ms
Table 9 Auxiliary supply
Module type
Bay unit
Central unit
Input voltage range (Uaux) В±25%
48 to 250 V DC
48 to 250 V DC
Fuse
no fuse
10 A slow
Load
11 W
100 W
Common data
Max. input voltage interruption during
which output voltage maintained
>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 21
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Table 10 Optical interfaces
Number of cores
2 fiber cores per bay unit
Core/sheath diameter
62.5/125 пЃ­m (multi-mode)
Max. permissible attenuation
п‚Ј5 dB (see Fig. 9)
Max. length
approx. 1200 m
Connector
Type FST for 62.5 пЃ­m optical fiber cables
Table 11 Mechanical design
Mounting
Bay unit
flush mounting on frames or in cubicles
HMI integrated or separately mounted
Central unit
flush mounting on frames or in cubicles
Table 12 Cubicle design
Cubicle
Standard type RESP97 (for details see 1MRB520159-Ken)
Dimensions w x d x h
800 x 800 x 2200 mm (single cubicle)пЂ 1600 x 800 x 2200 mm (double cubicle)пЂ 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
CTs
Phoenix URTK/S
0.5 - 10 mm2
0.5 - 6 mm2
VTs
Phoenix URTK/S
0.5 - 10 mm2
0.5 - 6 mm2
2
0.2 - 6 mm2
Connection data
Solid
Strand
Power supply
Phoenix UK 6 N
0.2 - 10 mm
Tripping
Phoenix UK 10-TWIN
0.5 - 16 mm2
Binary I/Os
Phoenix UKD 4-MTK-P/P
0.2 - 4
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
Recording facilities
Table 13 Event recorder
Page 22
Event recorder
Bay unit
Central unit
System events
Protection events
Test events
100 total
1000 total
0.5 - 10 mm2
0.2 - 2.5 mm2
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Table 14
Disturbance recorder
Analog channel
Recording periodпЂ Sample rate selectable
4 currents
or
9 currents
4 currents
and
5 voltages
802 Hz (16.7 Hz)
2400 Hz (50 Hz)
2880 Hz (60 Hz)
Standard
X
X*)
1.5 s
3s
6s
Option 1
X
X
6s
12 s
24 s
Option 2
X
X
10 s
20 s
40 s
Options
401 Hz (16.7 Hz)
1200 Hz (50 Hz)
1440 Hz (60 Hz)
600 Hz (50 Hz)
720 Hz (60 Hz)
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
Table 15 Interbay bus protocols
IEC 61850-8-1
IEC 61850-8-1 interbay bus supports
- Time synchronization via SNTP: typical accuracy В± 1 msпЂ - Two independent time servers are supported. Server 2 as
backup timeпЂ - Optical or electrical connectionпЂ - Differential current of each protection zoneпЂ - Monitoring information from REB500 central unit and bay unitпЂ - Binary events (signals, trips and diagnostic)пЂ - Trip reset commandпЂ - Single connection point to REB500 central unitпЂ - Disturbance recorder access via MMS file transfer protocolпЂ - Export of ICD - file, based on Substation Configuration
Language SCL
LON
LON interbay bus supports
- Time synchronization: typical accuracy В±1 msпЂ - Optical connectionпЂ - Differential currents of each protection zoneпЂ - Binary events (signals, trips and diagnostic)пЂ - Trip reset commandsпЂ - Single connection point to REB500 central unitпЂ - Disturbance recorder data (via HMI500)
IEC 60870-5-103
IEC 60870-5-103 interbay bus supports
- Time synchronization: typical accuracy В±5 msпЂ - Optical or electrical connectionпЂ - Subset of binary events as specified in IECпЂ Private range: Support of all binary eventsпЂ Generic mode: Support of all binary eventsпЂ - Trip reset commandпЂ - 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 23
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Software modules
Station level functions
(Applicable for nominal frequencies of 50, 60 and 16.7 Hz)
Table 16 Busbar protection (87B)пЂ Min. fault current pick-up setting (Ikmin)
Neutral current detection
500 to 6000 A in steps of 100 A
100 to 6000 A
Stabilizing factor (k)
0.7 to 0.9 in steps of 0.05
Differential current alarms
current setting
time delay setting
5 to 50% x Ikmin in steps of 5%
2 to 50 s in steps of 1 s
Isolator alarm
time delay
0.5 to 90 s
Typical tripping time
20 to 30 ms at Idiff/Ikmin п‚і5 incl. tripping relays; for fN = 50, 60 Hz
30 to 40 ms at Idiff/Ikmin п‚і5 incl. tripping relays; for fN = 16.7 Hz
CT ratio per feeder
50 to 10 000/1 A, пЂ 50 to 10 000/5 A, adjustable via HMI
Reset time
30 to 96 ms (at 1.2 <Ik/Ikmin <20); for fN = 50, 60 Hz
45 to 159 ms (at 1.2 <Ik/Ikmin <20);for fN = 16.7 Hz
Table 17 Breaker failure protection (50BF)
Measurement:
Setting range
0.1 to 2 x IN in steps of 0.1 x IN
Accuracy
В±5%
Timers:
Setting range for timers
t1:
t2:
10 to 5000 ms in steps of 10 ms
0 to 5000 ms in steps of 10 ms
Accuracy
В±5%
Remote trip pulse
100 to 2000 ms in steps of 10 ms
Reset ratio
typically 80%
Table 18 End-fault protection (51/62EF)
Timer setting range
100 to 10,000 ms in steps of 100 ms
Current setting range
0.1 to 2 x IN in steps of 0.1 IN
Reset ratio
95%
Reset time
17 to 63 ms (at 1.2 <I/Isetting <20); for fN = 50, 60 Hz
Table 19 Overcurrent protection (51)
Characteristic
definite time
Measurement:
Page 24
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 <I/Isetting <20); for fN = 50, 60 Hz
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Table 20 Breaker pole discrepancy protection (51/62PD)
Setting range
Time delay
Discrepancy factor
0.1 IN to 2.0 IN in steps of 0.1 IN, default 0.2 IN
100 ms to 10000 ms in steps of 100 ms, default 1500 ms
0.01* Imax to 0.99 * Imax in steps of 0.01 * Imax, default 0.6 * Imax
For feeders with single phase tripping and autoreclosure, the time setting for the breaker pole discrepancy
protection must be greater than the reclosure time. The discrepancy factor is the maximum permissible
difference between the amplitudes of two phases.
Table 21 Current release criteria (51)
Setting range (per feeder)
0.1 IN to 4.0 IN in steps of 0.1 IN, default 0.7 IN
If the current release criteria is not activated, the tripping command (“21110_TRIP”) is given independent
of current (standard setting).
The current release criteria only allows the trip of a circuit breaker if the feeder current value is above the
setting value of the enabling current. This value can be individually selected for each bay.
Table 22 Voltage release criteria (27/59)
U< Setting range (per feeder)
U0> Setting range (per feeder)
0.2 UN to 1.0 UN in steps of 0.05 UN, default 0.7 UN
0.1 UN to 1.0 UN in steps of 0.05 UN, default 0.2 UN
If the voltage release criteria is not activated the tripping command (“21110_TRIP”) is given independent
of voltage (standard setting).
The voltage release criteria is used as an additional criterion for busbar protection (as well as for the other
station protection functions) and operates per zone. It can be used as U< or U0> 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,пЂ 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-independent.
Table 24 Delay/integrator
п‚·пЂ For delaying pick-up or reset or for integrating 1 binary signalпЂ п‚·пЂ Provision for inverting the input
п‚·пЂ 4 independent parameter sets
Settings:
Pick-up or reset time
0 to 300 s in steps of 0.01 s
Integration
yes/no
Page 25
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Table 25 Logic
п‚·пЂ Logic for 4 binary inputs with the following 3 configurations:
1. OR gate
2. AND gate
3. Bistable flip-flop with 2 set and 2 reset inputs (both OR gates), resetting takes priority
п‚· 4 independent parameter sets.
All configurations have an additional blocking input.
Provision for inverting all inputs.
Bay level functions for Back-up/Main 2 REB500sys
Table 26 Definite time over- and undercurrent protection (51)
п‚·пЂ Over- and undercurrent detection
п‚·пЂ Single or three-phase measurement with detection of the highest, respectively lowest phase current
п‚·пЂ 2nd harmonic restraint for high inrush currents
п‚·пЂ 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)
В±5%
Reset ratio
overcurrent
undercurrent
>94% (for max. function)пЂ <106% (for min. function)
Max. operating time without intentional delay
60 ms
Inrush restraint
pick-up setting
reset ratio
optional
0.1 I2h/I1h
0.8
Table 27 Inverse time overcurrent protection (51)
п‚·пЂ Single or three-phase measurement with detection of the highest phase currentпЂ п‚·пЂ 4 independent parameter sets
t = k1 / ((I/IB)C - 1)
Inverse time characteristic
(acc. to B.S. 142, IEC 60255-3 with extended
setting range)
normal inverse
very inverseпЂ extremely inverseпЂ long time inverse
c = 0.02
c=1
c=2
c=1
or RXIDG characteristic
t = 5.8 - 1.35 В· In (I/IB)
Settings:
Page 26
Number of phases
1 or 3
Base current IB
0.04 to 2.5 IN in 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
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 60255-3
RXIDG characteristic
E 5.0
В±4% (1 - I/80 IB)
Reset ratio
95%
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Table 28 Definite time over- and undervoltage protection (59/27)
п‚·пЂ Over- and undervoltage detectionпЂ п‚·пЂ Single or three-phase measurement with detection of the highest, respectively lowest phase voltage
п‚·пЂ 4 independent parameter sets
Settings:
Pick-up voltage
0.01 to 2.0 UN in steps of 0.01 UN
Delay
0.02 to 60 s in steps of 0.01 s
Accuracy of the pick-up setting (at fN)
В±2% or В±0.005 UN
Reset ratio (U п‚іпЂ 0.1 UN)
overvoltage
undervoltage
>96% (for max. function)пЂ <104% (for min. function)
Max. operating time without intentional delay
60 ms
Table 29 Inverse time earth fault overcurrent protection (51N)
п‚·пЂ Neutral current measurement (derived externally or internally)пЂ п‚·пЂ 4 independent parameter sets
t = k1 / ((I/IB)C - 1)
Inverse time characteristic
(acc. to B.S. 142, IEC 60255-3 with extended setting
range)
normal inverse
very inverseпЂ extremely inverseпЂ long time inverse
c = 0.02
c=1
c=2
c=1
or RXIDG characteristic
t = 5.8 - 1.35 В· In (I/IB)
Settings:
Number of phases
1 or 3
Base current IB
0.04 to 2.5 IN in 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
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 60255-3
RXIDG characteristic
E 5.0
В±4% (1 - I/80 IB)
Reset ratio
95%
Table 30 Directional overcurrent definite time protection (67)
п‚·пЂ Directional overcurrent protection with detection of power flow direction
п‚·пЂ Back-up protection
п‚·пЂ 4 independent parameter sets
п‚·пЂ Three-phase measurement
п‚· Suppression of DC and HF components
п‚· Definite time characteristic
п‚·пЂ Voltage memory for near faults
п‚·пЂ Selectable response when power direction no longer valid (trip or block)
Settings:
Current
0.02 to 20 IN in steps of 0.01 IN
Angle
-180В° to +180В° in steps of 15В°
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
Page 27
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
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
п‚· Sinusoidal voltage including 3., 5., 7. and 9. harmonic
Accuracy of pick-up value
Reset ratio
Accuracy of angle measurement (at 0.97…1.03 fN)
В±5%
95%
В±5В°
п‚· Voltage input range
п‚· Voltage memory range
п‚· Accuracy of angle measurement at voltage memory
п‚· Frequency dependence of angle measurement at
voltage memory
п‚· Response time without delay
0.005 to 2 UN
<0.005 UN
В±20В°
В±0.5В°/Hz
60 ms
Table 31 Directional overcurrent inverse time protection (67)
п‚·пЂ Directional overcurrent protection with detection of power flow direction
п‚·пЂ Back-up for distance protection
п‚·пЂ 4 independent parameter sets
п‚· Three-phase measurement
п‚· Suppression of DC and HF components
п‚· Inverse time characteristic
п‚· Voltage memory for near faults
п‚·пЂ Selectable response when power direction no longer valid (trip or block)
Settings:
Current
1 to 4 IN in steps of 0.01 IN
Angle
-180В° to +180В° in steps of 15В°
Inverse time characteristic
(acc. to B.S. 142, IEC 60255-3 with extended setting
range)
normal inverse
very inverseпЂ extremely inverseпЂ long time inverse
t = k1 / ((I/IB)C - 1)
c = 0.02
c=1
c=2
c=1
t-min
0 to 20 in steps of 0.01
IB-value
0.04 to 2.5 IN in steps of 0.01 IN
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
Page 28
Accuracy of pick-up value
Reset ratio
Accuracy of angle measurement (at 0.97…1.03 fN)
В±5%
95%
В±5В°
п‚· Voltage input range
п‚· Voltage memory range
п‚· Accuracy of angle measurement at voltage memory
п‚· Frequency dependence of angle measurement at
voltage memory
п‚· Response time without delay
0.005 to 2 UN
<0.005 UN
В±20В°
В±0.5В°/Hz
60 ms
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Table 32 Directional sensitive EF protection for ungrounded or compensated systems
(32N)
Determination of real or apparent power from neutral current and voltage
Settings:
Pick-up power SN
0.005 to 0.1 SN in steps of 0.001 SN
Reference value of the power SN
0.5 to 2.5 UN В· IN in steps of 0.001 UN В· IN
Characteristic angle
-180В° to +180В° in steps of 0.01В°
Phase error compensation of current input
-5В° to +5В° in steps of 0.01В°
Delay
0.05 to 60 s in steps of 0.01 s
Reset ratio
30 to 95% in steps of 1%
Accuracy of the pick-up setting
В±10% of setting or 2% UN В· IN (for protection CTs)пЂ В±3% of setting or 0.5% UN В· IN (for measuring CTs)
Max. operating time without intentional delay
70 ms
The directional sensitive EF protection for ungrounded or compensated systems requires the BU03 type
with 3I + 1MT + 5U
Table 33 Three-phase current plausibility / Three-phase voltage plausibility (46/47)
A plausibility check function is provided for the three-phase current and three-phase voltage input which
performs the following:
п‚·пЂ Determination of the sum and phase sequence of the 3 phase currents or voltages
п‚·пЂ 4 independent parameter sets
Accuracy of the pick-up setting at rated frequency
В±2% IN in the range 0.2 to 1.2 INпЂ В±2% UN in the range 0.2 to 1.2 UN
Reset ratio
п‚і90% whole range
>95% (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 IN
Amplitude compensation for summation CT
-2.00 to +2.00 in steps of 0.01
Delay
0.1 to 60 s in steps of 0.1 s
Voltage plausibility settings:
Pick-up differential for sum of internal summation voltage
0.05 to 1.2 UN in steps of 0.05 UN
Amplitude compensation for summation VT
-2.00 to +2.00 in steps of 0.01
Delay
0.1 to 60 s in steps of 0.1 s
Table 34 Directional sensitive earth fault protection for grounded systems (67N)
п‚·пЂ Detection of high-resistance earth faultsпЂ п‚·пЂ Current enabling setting 3I0пЂ п‚·пЂ Direction determined on basis of neutral variables (derived externally or internally)пЂ п‚·пЂ Permissive or blocking directional comparison schemeпЂ п‚·пЂ Echo logic for weak infeedsпЂ п‚·пЂ Logic for change of energy direction
п‚·пЂ 4 independent parameter sets
Settings:
Current pick-up setting
0.1 to 1.0 IN in steps of 0.01 IN
Voltage pick-up setting
0.003 to 1 UN in steps of 0.001 UN
Characteristic angle
-90В° to +90В° in steps of 5В°
Delay
0 to 1 s in steps of 0.001 s
Accuracy of the current pick-up setting
В±10% of setting
Page 29
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Table 35 Distance protection (21)
п‚·пЂ Five measuring stages with polygonal impedance characteristic forward and backward
п‚·пЂ All values of settings referred to the secondaries, every zone can be set independently of the others
п‚·пЂ 4 independent parameter sets
Impedance measurement
-300 to 300 пЃ—/ph in steps of 0.01 пЃ—/ph
Zero-sequence current compensation
0 to 8 in steps of 0.01,пЂ -180В° to +90В° in steps of 1В°
Mutual impedance for parallel circuit lines
0 to 8 in steps of 0.01,
-90В° to +90В° in steps of 1В°
Time step setting range
0 to 10 s in steps of 0.01 s
Underimpedance starters
-999 to 999 пЃ—/ph in steps of 0.1 пЃ—/ph
Overcurrent starters
0.5 to 10 IN in steps of 0.01 IN
Min. operating current
0.1 to 2 IN in 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 IN in steps of 0.01 IN
Neutral voltage criterion
0 to 2 UN in steps of 0.01 UN
Low-voltage criterion for detecting, for example, a weak infeed
0 to 2 UN in steps of 0.01 UN
VT supervision
NPS/neutral voltage criterion
NPS/neutral current criterion
пЂ 0.01 to 0.5 UN in steps of 0.01 UNпЂ 0.01 to 0.5 IN in steps of 0.01 IN
Accuracy (applicable for current time constants between 40 and 150 ms)
amplitude error
phase error
Supplementary error for
- frequency fluctuations of +10%
- 10% third harmonic
- 10% fifth harmonic
Operating times of the distance protection
function (including tripping relay)
minimum
typical
(see also isochrones)
В±5% for U/UN >0.1
В±2В° for U/UN >0.1
В±5%
В±10%
В±10%
20 ms
25 ms
Typical reset time
25 ms
VT-MCB auxiliary contact requirements
Operation time
<15 ms
Remark: Distance protection operating times on next page
Page 30
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Distance protection operating timesпЂ Isochrones
Single phase fault (max)
1
1
0.8
0.8
0.6
0.6
ZF/ZL
ZF/ZL
Single phase fault (min)
0.4
18ms
0.2
31ms
0.4
29ms
0.2
17ms
18ms
0
0
0.1
1
10
100
0.1
1000
1
10
1
1
0.8
0.8
19ms
0.6
0.4
32ms
0.6
0.4
0.2
17ms
18ms
29ms
0
0
0.1
1
10
100
0.1
1000
1
10
Three phase fault (min)
1
1
0.8
0.6
0.6
ZF/ZL
0.8
0.4
17ms
1000
Three phase fault (max)
20ms
0.2
100
SIR (ZS/ZL)
SIR (ZS/ZL)
ZF/ZL
1000
Two phase fault (max)
ZF/ZL
ZF/ZL
Two phase fault (min)
0.2
100
SIR (ZS/ZL)
SIR (ZS/ZL)
33ms
0.4
0.2
18ms
0
29ms
0
0.1
1
10
100
1000
SIR (ZS/ZL)
Abbreviations:
0.1
1
10
100
1000
SIR (ZS/ZL)
ZS = source impedance
ZF = fault impedance
ZL = zone 1 impedance setting
Page 31
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Table 36 Autoreclosure (79)
п‚·пЂ Single and three-phase autoreclosure
п‚·пЂ Operation in conjunction with distance, overcurrent and synchrocheck functions and also with external
protection and synchrocheck relays
п‚·пЂ Logic for 1st and 2nd main protections, duplex and master/follower schemes
п‚·пЂ Up to four fast or slow reclosure shots
п‚·пЂ Detection of evolving faults
п‚·пЂ 4 independent parameter sets
Settings:
1st reclosure
noneпЂ 1P fault - 1P reclosureпЂ 1P fault - 3P reclosureпЂ 1P/3P fault - 3P reclosure
1P/3P fault - 1P/3P reclosure
2nd to 4th reclosure
noneпЂ two reclosure cyclesпЂ three reclosure cyclesпЂ 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)
п‚·пЂ Determination of synchronism
Single phase measurement. The differences between the amplitudes, phase-angles and frequencies
of two voltage vectors are determined.
п‚·пЂ Voltage supervision
Single or three-phase measurementпЂ Evaluation of instantaneous values and therefore wider frequency rangeпЂ Determination of maximum and minimum values in the case of three-phase inputs
п‚·пЂ Phase selection for voltage inputs
п‚·пЂ Provision for switching to a different voltage input (double busbar systems)пЂ п‚·пЂ Remote selection of operating mode
п‚·пЂ 4 independent parameter sets
Settings:
Max. voltage difference
Page 32
0.05 to 0.4 UN in steps of 0.05 UN
Max. phase difference
5 to 80В° in steps of 5В°
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 UN
Max. voltage
0.1 to 1 UN in steps of 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
Accuracy
Voltage difference
Phase difference
Frequency difference
for 0.9 to 1.1 fN
В±5% UN
В±5В°
В±0.05 Hz
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Table 38 Transformer differential protection (87T)
п‚· For two- and three-winding transformers
п‚· Three-phase function
п‚· Current-adaptive characteristic
п‚· High stability for external faults and current transformer saturation
п‚· No auxiliary transformers necessary because of vector group and CT ratio compensation
п‚· Inrush restraint using 2nd harmonic
Settings:
g-setting
0.1 to 0.5 IN in 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 IпЃ„ >2 IN
- for IпЃ„пЂ п‚Ј2 IN
п‚Ј30 ms
п‚Ј50 ms
Accuracy of pick-up value
В±5% IN (at fN)
Reset conditions
IпЃ„ <0.8 g-setting
Accuracy of pick-up value
В±5% IN (at fN)
Reset conditions
IпЃ„ <0.8 g-setting
Differential protection definitions:
Differential protection characteristic
IпЃ„ = пѓЄI1+ I2 + I3 пѓЄ
пѓ¬пѓЇ I' пѓ—I' пѓ— cosпЃЎ
IH пЂЅ пѓ­ 1 2
пѓЇпѓ®0
IпЃ„
IN
3
2
for cos пЃЎпЂ п‚іпЂ пЂ°пЂ for cos пЃЎпЂ пЂјпЂ пЂ°пЂ пЂ пЂ пЂ пЂ пЂ пЂ пЂ I'1 = MAX (I1, I2, I3)
I'2 = I1 + I2 + I3 - I'1
пЃЎпЂ = пѓђ(I'1;- I'2)
Operation for
I'1
<b
IN
or
I'2
<b
IN
Operation
1
v
g
Restraint
1
I1
b
2
IH
IN
3
Protected
unit
I2
I3
HEST 965 007 C
Table 39 Thermal overload (49)
п‚· Thermal image for the 1st order model
п‚· Single or three-phase measurement with detection of maximum phase value
Settings:
Base current IB
0.5 to 2.5 IN in steps of 0.01 IN
Alarm stage
50 to 200% пЃЉTN in steps of 1% пЃЉN
Tripping stage
50 to 200% пЃЉN in steps of 1% пЃЉN
Thermal time constant
2 to 500 min in steps of 0.1 min
Accuracy of the thermal image
В±5% пЃЉN (at fN)
Page 33
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Table 40 Peak value over- and undercurrent protection (50)
п‚· Maximum or minimum function (over- and undercurrent)
п‚·пЂ Single or three-phase measurements
п‚·пЂ Wide frequency range (0.04 to 1.2 fN)
п‚·пЂ 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)
В±5% or В±0.02 IN
Reset ratio
>90% (for max. function)
<110% (for min. function)
Max. trip time with no delay (at fN)
п‚Ј30пЂ ms (for max. function)
п‚Ј60пЂ ms (for min. function)
Table 41 Peak value over- and undervoltage protection (59)
п‚· Maximum or minimum function (over- and undervoltage)
п‚·пЂ Single or three-phase measurements
п‚·пЂ Peak value evaluation
Settings:
Voltage
0.01 to 2 UN in steps of 0.01 UN
Delay
0 to 60 s in steps of 0.01 s
Limiting fmin
25 to 50 Hz in steps of 1 Hz
Accuracy of pick-up value (at 0.08 to 1.1 fN)
В±3% or В±0.005 UN
Reset ratio
>90% (for max. function)
<110% (for min. function)
Max. trip time with no delay (at fN)
п‚Ј30пЂ ms (for max. function)
п‚Ј60пЂ ms (for min. function)
Table 42 Frequency function (81)
п‚· Maximum or minimum function (over- and underfrequency)
п‚·пЂ Minimum voltage blocking
Settings:
Frequency
Page 34
40 to 65 Hz in steps of 0.01 Hz
Delay
0.1 to 60 s in steps of 0.01 s
Minimum voltage blocking
0.2 to 0.8 UN in steps of 0.1 UN
Accuracy of pick-up value
В±30 mHz at UN and fN
Reset ratio
100%
Starting time
<130 ms
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Table 43 Rate of change frequency protection df/dt (81)
п‚· Maximum or minimum function (over- and underfrequency)
п‚·пЂ 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 Hz
50 to 65 Hz in steps of 0.01 Hz at fN = 60 Hz
Delay
0.1 to 60 s in steps of 0.01 s
Minimum voltage blocking
0.2 to 0.8 UN in steps of 0.1 UN
Accuracy of df/dt (at 0.9 to 1.05 fN)
В±0.1 Hz/s
Accuracy of frequency (at 0.9 to 1.05 fN)
В±30 mHz
Reset ratio
95% for max. function
105% for min. function
Table 44 Definite time overfluxing protection (24)
п‚· Single-phase measurement
п‚·пЂ Minimum voltage blocking
Settings:
Pick up value
0.2 to 2 UN/fN in steps of 0.01 UN/fN
Delay
0.1 to 60 s in steps of 0.01 s
Frequency range
0.5 to 1.2 fN
Accuracy (at fN)
В±3% or В±0.01 UN/fN
Reset ratio
>98% (max.), <102% (min.)
Starting time
п‚Ј120 ms
Table 45 Inverse time overfluxing protection (24)
п‚· Single-phase measurement
п‚· Inverse time delay according to IEEE Guide C37.91-1985
п‚· Setting made by help of table settings
Settings:
Table settings
U/f values: (1.05; 1.10 to 1.50) UN/fN
Start value U/f
1.05 to 1.20 UN/fN in steps of 0.01 UN/fN
tmin
0.01 to 2 min in steps of 0.01 min
tmax
5 to 100 min in steps of 0.1 min
Reference voltage UB-value
0.8 to 1.2 UN in steps of 0.01 UN
Accuracy of pick-up value
0.8 to 1.2 UN in steps of 0.01 UN
Frequency range
0.5 to 1.2 fN
Reset ratio
100%
Starting time
<120 ms
Page 35
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Technical data (contВґd)
Table 46
Power protection (32)
п‚· Measurement of real or apparent power
п‚· Protection function based on real or apparent power measurement
п‚· Reverse power protection
п‚· Over- and underpower
п‚· Single or three-phase measurement
п‚· Suppression of DC components and harmonics in current and voltage
п‚· Compensation of phase errors in main and input CTs and VTs
Settings:
Page 36
Power pick-up
-0.1 to 1.2 SN in steps of 0.005 PN
Characteristic angle
-180В° to +180В° in steps of 5В°
Delay
0.05 to 60 s in steps of 0.01 s
Power factor comp. (Phi)
-5В° to +5В° in steps of 0.1В°
Rated power PN
0.5 to 2.5 UN Г— IN in steps of 0.001 UN Г— IN
Reset ratio
30% to 170% in steps of 1% of power pick-up
Accuracy of the pick-up setting
В±10% of setting or 2% UN Г— IN
(for protection CTs)
В±3% of setting or 0.5% UN Г— IN
(for core-balance CTs)
Max. operating time without intentional delay
70 ms
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Connection пЂ diagrams
Inputs / outputs central unit
Optional I/O board
Binary inputs
Binary inputs
Binary outputs
Binary outputs
500BIO01
500BIO01
Optional redundant power supply
1
2
Alarm
1
2
3
Warning
4
5
6
aux
1
2
3
Warning
4
5
6
1
2
aux
500PSM03
500PSM03
Fig. 11
Alarm
Central unit module; Connection of power supply, binary inputs and outputs
Abbreviations
Explanation
OCxx
CRxx
optocoupler
Tripping relay
Terminal
block/
terminals
Explanation
Wire gauge/
Type
A
B
P
Binary inputs
Binary outputs
Power supply
1.5 mm2
1.5 mm2
1.5 mm2
Page 37
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Connection diagrams
(contВґd)
Bay unit types
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
E
Terminal block/
terminals
A, B
C, D
E
Rx
Tx
I, J
U
P, R
Function
Rx
Wire gauge/
Type
1.5 mm2
1.5 mm2
Binary inputs
Binary outputs
Optical connection
Receive
Transmit
Currents
Voltages
Supply
Tx
Rx
C
FST plug
FST plug
2.5 mm2
1.5 mm2
1.5 mm2
B
D
E
I
J
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Tx
A
Available inputs/outputs
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
1
2
3
4
5
6
7
8
9
10
11
12
I4[1]
I4[5]
I4[0]
I5[1]
I5[5]
I5[0]
I6[1]
I6[5]
I6[0]
I7[1]
I7[5]
I7[0]
z
z
z
z
z
z
z
z
z
z
I
U
1
2
3
4
5
6
7
8
9
10
11
12
Tx
I1[1]
U1
U1[0]
A
I1[5]
Rx
I1[0]
Tx
I2[1]
U2
U2[0]
Rx
I2[5]
U3
U3[0]
C
I2[0]
I3[1]
U4
U4[0]
I3[5]
I3[0]
U5
U5[0]
Explanation
Opto-coupler
Tripping relay
Optical link
I9[5]
H
HMI
DC
I
0
I
0
Processbus
J
Tx E
3
Current Transformer
I
1
Current Transformer
2
I4
U
5
OC03
Binary Outputs
1
6
OC04
7
CR01
C
9
11
13
14
CR04
CR05
2
7
CR06
OC10
CR07
1
2
CR08
OC14
CR09
13
7
CR11
OC17
CR12
CR13
OC18
8
OC19
0
14
H
16
Page 38
HMI Interface
I9
0
18
CR14
13
CR15
14
CR16
15
Redundant Power Supply
R
1
2
Redundant Power Supply
Power Supply
R
P
+
_
1
+
_
2
OC20
*) 1 Measuring transformer in 500BU03_5 or 500BU03_6
Fig. 12
H
HMI Interface
5
17
10
12
15
U5
I8
15
9
11
14
5
14
1
6
OC16
*)
4
CR10
13
D
0
3
5
12
I4
0
12
11
12
15
13
OC12
OC13
5
11
0
1
OC15
18
U4
I7
0
14
9
17
1
5
11
OC11
8
16
I3
10
10
10
12
10
11
5
9
8
9
8
0
0
1
11
13
5
6
U3
I3
0
9
OC09
3
4
8
10
18
1
5
I6
0
9
7
7
7
5
8
8
OC08
16
B
I2
1
1
7
7
OC07
15
17
1
6
CR03
5
6
5
6
5
0
0
0
6
U2
I2
5
OC06
12
1
4
4
5
5
0
4
CR02
I1
0
1
I5
5
3
2
4
5
OC05
10
1
5
Current Transformer
2
0
0
3
4
2
3
8
I
1
U1
I1
2
0
3
5
Voltage Transformer
1
1
Rx
4
P
+
-
1
1
1
5
OL01
I
0
R
+
-
P
+
-
500BU03
2
OC02
I4[5]
I4[5]
I4[0]
I4[0]
H
D
I9[0]
500BU03
OC01
I3[0]
I3[0]
I4[1]
I4[1]
B
I9[1]
R
+
-
Binary Inputs
I3[1]
I3[1]
I3[5]
I3[5]
I8[0]
DC
1
I2[5]
I2[5]
I2[0]
I2[0]
I8[5]
I
0
A
I1[0]
I1[0]
I2[1]
I2[1]
I8[1]
HMI
Abbreviations
OCxx
CRxx
OLxx
I1[1]
I1[1]
I1[5]
I1[5]
Wiring diagram of bay units 500BU03, types 1-8
1
2
Power Supply
P
+
_
1
2
+
_
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Bay unit types
500BU03_10 (8 I, 1U, 20/16 I/O, stand-alone)
z
500BU03_12 (6 I, 3 U, 20/16 I/O, stand-alone)
500BU03_ 9 (8 I, 1U, 20/16 I/O, stand-alone) red. power supply
z
500BU03_11 (6 I, 3 U, 20/16 I/O, stand-alone) red. power supply
500BU03_10 (8 I, 1U, 20/16 I/O, classic-mounting)
z
500BU03_12 (6 I, 3 U, 20/16 I/O, classic-mounting)
500BU03_ 9 (8 I, 1U, 20/16 I/O, classic-mounting) red. power supply
z
500BU03_11(6 I, 3 U, 20/16 I/O, classic-mounting) red. power supply
Terminal block/
terminals
Function
Wire gauge/
Type
A, B
C, D
E
Rx
Tx
I
J
Binary inputs
Binary outputs
Optical connection
Receive
Transmit
Currents
Currents and
voltages
Supply
1.5 mm
2
1.5 mm
P, R
E
J
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
Tx
A
Rx
2
Tx
Rx
C
FST plug
FST plug
2
2.5 mm
1.5 mm
2
B
Abbreviations
Explanation
OCxx
CRxx
OLxx
Opto-coupler
Tripping relay
Optical link
D
1
2
3
4
5
6
7
8
9
10
11
12
I4[1]
I4[5]
I4[0]
I5[1]
I5[5]
I5[0]
I6[1]
I6[5]
I6[0]
U1
U1[0]
Available inputs/outputs
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
z
I
E
I1[1]
Tx
I1[5]
J
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
A
Rx
I1[0]
Tx
I2[1]
Rx
I2[5]
C
I2[0]
I3[1]
I3[5]
I3[0]
U2
U2[0]
B
U3
U3[0]
H
D
I
1
2
3
4
5
6
7
8
9
10
11
12
I4[1]
I4[5]
I4[0]
I5[1]
I5[5]
I5[0]
I6[1]
I6[5]
I6[0]
I7[1]
I7[5]
I7[0]
Binary Inputs
1
Processbus
OC02
OC03
Binary Outputs
1
OC04
7
CR01
8
9
OC05
CR02
10
14
U1[0]
H
CR07
1
4
5
I5
5
I2
0
0
6
6
1
5
5
8
I3
8
0
9
7
7
5
I6
1
1
7
5
I6
8
I3
0
0
9
9
9
Voltage Transformer
1
10
10
12
5
11
U1
0
12
15
1
13
OC12
1
13
D
5
U2
2
14
0
CR08
OC13
OC14
CR09
3
CR10
7
CR11
OC16
OC17
13
CR12
CR13
OC18
8
H
16
Voltage Transformer
HMI Interface
H
HMI Interface
16
U3
U1
0
17
0
17
9
10
12
15
OC19
15
Redundant Power Supply
R
1
CR14
13
CR15
14
CR16
15
2
R
P
+
_
1
+
_
2
Power Supply
Redundant Power Supply
Power Supply
11
14
I8
0
14
4
5
12
I7
0
11
14
6
Fig. 13
0
5
5
OC11
OC15
18
I1
2
3
1
I2
0
1
8
11
9
17
I4
4
5
7
8
13
CR06
OC10
8
16
5
5
10
11
5
2
1
5
Current Transformer
I
1
0
6
10
OC09
5
7
P
+
-
1
3
4
I5
0
3
6
I3[0]
OC08
18
4
I1
0
0
CR05
2
6
9
CR04
1
4
7
15
B
5
5
Current Transformer
J
1
2
1
5
6
CR03
I3[5]
I
0
1
3
4
OC07
16
17
C
3
OC06
12
13
I4
0
2
Current Transformer
I
1
3
6
I3[1]
I8[0]
R
+
-
1
2
Rx
5
11
Current Transformer
5
OL01
4
I2[0]
U1
I
0
P
+
-
1
2
3
I2[5]
500BU03
J
Tx E
I2[1]
DC
I
0
1
OC01
I1[0]
HMI
500BU03
A
I1[5]
I8[5]
DC
R
+
-
I1[1]
I8[1]
HMI
I
0
z
z
z
z
z
z
z
z
1
2
P
+
_
1
+
_
2
OC20
Wiring diagram of bay units 500BU03, types 9-12
Page 39
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Bay unit 500BU03 connection diagrams
A detailed description of each variant is given in the application description [2].
Protection functions
Measurement value
Voltage plausibility check
Current plausibility check
Inverse time earth fault overcurrent protection
Direct. sensitive EF prot. for ungr. or comp. systems
Direct. sensitive EF prot. for grounded systems
Synchrocheck
Definite time over and undervoltage protection
Directional overcurrent inverse time protection
Directional overcurrent definite time protection
Inverse time overcurrent protection
Definite time over and undercurrent protection
Bay level
Disturbance recorder
Voltage check
Pole discrepancy protection
Analog inputs
End fault protection
Station level
Busbar protection
500BU03
Distance protection
Bay unit
Breaker failure protection
Connection diagrams
(contВґd)
Currents
1
1
2 5
I1
zzzz
zz„„zz
z
„„
Phase current L1
(Line)
I2
zzzz
zz„„zz
z
„„
Phase current L2
(Line)
I3
zzzz
zz„„zz
z
„„
Phase current L3
(Line)
3 0
4 1
5 5
6 0
7 1
8 5
9 0
10 1
11 5
12 0
I4 ВЃ
z
Derived
internally
Neutral current Lo (Y)
(Line)
В†
Neutral current derrived
internally Io=6 I L1+I L2+I L3
z
z
U1
zzz
„„z
В„
Phase voltage L1
(Line)
U2
zzz
„„z
В„
Phase voltage L2
(Line)
U3
zzz
„„z
В„
Phase voltage L3
(Line)
U4
z
В„
U5
z
В„
Voltages
1
2 0
4
5 0
7
8 0
10
11 0
В„
13
14 0
Derived
internally
z
z
В„
ВЃ
В†
Fig. 14
Page 40
Phase voltage L2
(Bus 1)
1ph -> L2-E
Phase voltage L2
(Bus 2)
1ph -> L2-E
z
Neutral voltage derrived
internally Uo=6 U L1+U L2+U L3
Current transformer/voltage transformer fixed assignment
Recommended setting/ respectively free for selection (configured via software HMI500-REBWIN)
Only for busbar protection Io-measurement (optional function)
Bay unit types with measuring CT (torroid CT) on input I4
Bay unit connection diagram 500BU03, 4I, 5U
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Protection functions
Three phase current plausibility
Definite time over and undercurrent protection
Inverse time earth fault overcurrent protection
Measurement value
Inverse time overcurrent protection
Peak value over and undercurrent protection
Thermal overload
Bay level
Disturbance recorder
Pole discrepancy protection
End-fault protection
Analog inputs
Breaker-failure protection
Station level
Busbar protection
500BU03
Transformer differential protection
Bay unit
Currents
1 1
I
2 5
I1
z z z z z „‹ „ „ „ „ „
Phase current L1
A-side
I2
z z z z z „‹ „ „ „ „ „
Phase current L2
A-side
I3
z z z z z „‹ „ „ „ „ „
Phase current L3
A-side
ВЃ
Neutral current derrived
internally Io=6 I L1+I L2+I L3
3 0
4 1
5 5
6 0
7 1
8 5
9 0
Derived
internally
Currents
1 1
J
2 5
I4
z „‹
В„ В„ В„ В„
Phase current L1
B-side
I5
z „‹
В„ В„ В„ В„
Phase current L2
B-side
I6
z „‹
В„ В„ В„ В„
Phase current L3
B-side
3 0
4 1
5 5
6 0
7 1
8 5
9 0
Neutral current derrived
internally Io=6 I L1+I L2+I L3
Derived
internally
Currents
10 1
J
11 5
I7
z „‹
В„ В„ В„ В„
Phase current L1
C-side (if existing)
I8
z „‹
В„ В„ В„ В„
Phase current L2
C-side (if existing)
I9
z „‹
В„ В„ В„ В„
Phase current L3
C-side (if existing)
12 0
13 1
14 5
15 0
16 1
17 5
18 0
Neutral voltage derrived
internally Uo=6 U L1+U L2+U L3
Derived
internally
z
В„
ВЃ
В‹
A-side
B-side
C-side
Fig. 15
Current transformer, fixed assignment
Recommended setting/ respectively free for selection (configured via software HMI500-REBWIN)
Only for busbar protection Io-measurement (optional function)
Configured either on A-side, or on B-side or on C-side respectively
Transformer primary side
Transformer secondary side
Transformer tertiary side
Bay unit connection diagram 500BU03, 9I
Page 41
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Protection functions
Measurement value
Power
Frequency
Rate of change frequency protection
Inverse time overfluxing protection
Definite time overfluxing protection
Peak value over and undervoltage protection
Peak value over and undercurrent protection
Thermal overload
Transformer differential protection
Three phase voltage plausibility
Three phase current plausibility
Inverse time earth fault overcurrent protection
Direct. sensitive EF prot. for grounded systems
Definite time over and undervoltage protection
Directional overcurrent inverse time protection
Directional overcurrent definite time protection
Inverse time overcurrent protection
Definite time over and undercurrent protection
Bay level
Disturbance recorder
Pole discrepancy protection
Analog inputs
End fault protection
Station level
Busbar protection
500BU03
Distance protection
Bay Unit
Breaker failure protection
Connection diagrams
(contВґd)
Currents
1 1
I
2 5
I1
z z z z z ‹„ „‹‹
‹„„
„‹„
В‹
Phase current L1
A-side
I2
z z z z z ‹„ „‹‹
‹„„
„‹„
В‹
Phase current L2
A-side
I3
z z z z z ‹„ „‹‹
‹„„
„‹„
В‹
Phase current L3
A-side
ВЃ
В‹
3 0
4 1
5 5
6 0
7 1
8 5
9 0
Derrived
internally
В‹
Neutral current derrived
internally Io=6 I L1+I L2+I L3
Currents
1 1
J
2 5
I4
z z z z z ‹„ „‹‹
‹„„
„‹„
В‹
Phase current L1
B-side
I5
z z z z z ‹„ „‹‹
‹„„
„‹„
В‹
Phase current L2
B-side
I6
z z z z z ‹„ „‹‹
‹„„
„‹„
В‹
Phase current L3
B-side
3 0
4 1
5 5
6 0
7 1
8 5
9 0
Derrived
internally
Neutral current derrived
internally Io=6 I L1+I L2+I L3
В‹
В‹
U1
z z
z z В„ z
В„
„„„„„ „
Phase voltage L1
A-side or B-side
U2
z z
z z В„ z
В„
„„„„„ „
Phase voltage L2
A-side or B-side
U3
z z
z z В„ z
В„
„„„„„ „
Phase voltage L3
A-side or B-side
z
z
Voltages
10
J
11 0
13
14 0
16
17 0
Derrived
internally
z
В„
ВЃ
В‹
Current transformer/voltage transformer fixed assignment
Recommended setting/ respectively free for selection (configured via software HMI500-REBWIN)
Only for busbar protection Io-measurement (optional function)
Configured either on A-side, or on B-side respectively
A-side Transformer primary side
B-side Transformer secondary side
Fig. 16
Page 42
Neutral voltage derrived
internally Uo=6 U L1+U L2+U L3
Bay unit connection diagram 500BU03, 6I, 3U
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Protection functions
Inverse time overfluxing protection
Definite time overfluxing protection
Peak value over and undercurrent protection
Thermal overload
Transformer differential protection
Measurement value
Three phase current plausibility
Inverse time earth fault overcurrent protection
Inverse time overcurrent protection
Bay level
Disturbance recorder
Pole discrepancy protection
End fault protection
Analog inputs
Breaker failure protection
Station level
Busbar protection
500BU03
Definite time over and undercurrent protection
Bay Unit
Currents
1 1
I
2 5
I1
z z z z z „ „ „ „ „‹„
Phase current L1
A-side
I2
z z z z z „ „ „ „ „‹„
Phase current L2
A-side
I3
z z z z z „ „ „ „ „‹„
Phase current L3
A-side
ВЃ
Neutral current derrived
internally Io=6 I L1+I L2+I L3
3 0
4 1
5 5
6 0
7 1
8 5
9 0
Derrived
internally
Currents
1 1
J
2 5
3 0
4 1
5 5
6 0
7 1
8 5
I4
z „ „ „ „ „‹„
Phase current L1
B-side
I5
z „ „ „ „ „‹„
Phase current L2
B-side
I6
z „ „ „ „ „‹„
Phase current L3
B-side
9 0
Neutral current derrived
internally Io=6 I L1+I L2+I L3
Derrived
internally
Currents
10 1
J
11 5
12 0
13 1
14 5
I7
z В„ В„
Current Lx
(e.g. Lo)
I8
z В„ В„
Current Lx
(e.g.Lo)
U1
z
15 0
Voltages
16
J
17 0
z
В„
ВЃ
В‹
A-side
B-side
Fig. 17
z z
Voltage Lx
(e.g. Phase L1-L2 ->
Overfluxing protection )
Current transformer/voltage transformer fixed assignment
Recommended setting/ respectively free for selection (configured via software HMI500-REBWIN)
Only for busbar protection Io-measurement (optional function)
Configured either on A-side, or on B-side respectively
Transformer primary side
Transformer secondary side
Bay unit connection diagram 500BU03, 8I, 1U
Page 43
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Connection diagrams
(contВґd)
REB500: Typical assignment of the in/outputs
Binary inputs
Accept bus image alarm
1
External reset
2
Binary outputs
1
OC01
2
OC02
Block of all protection functions
3
Block output relays
4
OC03
CR01
3
Protection blocked / Output relays blocked
CR02
4
Test generator active
CR03
5
Isolator alarm
OC04
6
5
6
Block busbar protection
CR04
7
7
OC05
Block breaker failure protection
8
OC06
Switch inhibited
8
CR05
9
10 System alarm
9
OC07
11
10
OC08
11
12 In service
CR06
12
13
14
13
OC09
15
14
OC10
15
OC11
16
CR07
16 Differential current alarm
CR08
17 Busbar protection tripped
CR09
18 Breaker failure protection tripped
OC12
17
18
Fig. 18
REB500: Typical assignment of the in/outputs of a central unit for busbar and breaker failure protection
Binary Inputs
1
Start BFP protection 1 L1
Start BFP protection 1 L2
2
3
OC01
A
Binary outputs
1
C
CR01
OC02
rt BFP protection 1 L1L2L3
5
6
7
4
CR02
OC03
9
11
t BFP protection 2 L1L2L3
13
14
15
Block close command
7
CR03
8
OC05
9
OC06
10
CR04
12
Start BFP protection 2 L3
5
6
OC04
8
Start BFP protection 2 L1
10
Start BFP protection 2 L2
In Service
3
4
Start BFP protection 1 L3
2
CR05
OC07
11
Remote Trip, channel 1
12
13
CR06
OC08
CR07
14
Remote Trip, channel 2
15
16
17
OC09
1
D
18
2
1
2
3
4
OC10
OC11
OC12
B
CR08
CR09
CR10
Bus 1 Isolator Q1 off
Bus 1 Isolator Q1 on
Bus 2 Isolator Q2 off
7
8
9
Bus 2 Isolator Q2 on
12
13
14
5
7
OC13
CR11
8
OC14
CR12
9
OC15
CR13
10
Trip Phase L1, trip coil 1
Trip Phase L2, trip coil 1
Trip Phase L3, trip coil 1
11
10
11
4
6
5
6
3
12
OC16
CR14
13
OC17
CR15
14
OC18
CR16
15
Trip Phase L1, trip coil 2
Trip Phase L2, trip coil 2
Trip Phase L3, trip coil 2
15
16
17
18
Fig. 19
Page 44
OC19
OC20
REB500: Typical assignment of the in/outputs for a double busbar with busbar and breaker failure
protection of a bay unit
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
REB500sys: Typical assignment of the in-/outputs
Binary Inputs
Variant L-V4
1
Start BFP protection 1 L1
Start BFP protection 1 L2
2
3
OC01
Binary outputs
Variant L-V4
A
1
C
CR01
OC02
2
In Service
3
4
4
Start BFP protection 1 L3
Start BFP protection 1 L1L2L3
5
6
7
OC03
CR02
OC04
Carrier Receive, Distance Prot.
10
Carrier Receive, DEF Prot.
11
7
CR03
OC05
OC06
Bus 1 VT MCB Fail
14
15
CR05
OC07
Line VT MCB Fail
CB All Poles Closed for DEF Prot.
OCO Ready for AR Release
17
CR06
CR07
2
3
4
OC10
OC11
B
Bus 1 Isolator Q1 off
Bus 1 Isolator Q1 on
Bus 2 Isolator Q2 off
7
8
9
Bus 2 Isolator Q2 on
12
Breaker Q0 off
13
Breaker Q0 on
14
CR09
CR10
Prepare 3 Pole Trip,from Main1
Main 1 Healthy/In Service Mode (Blk. AR)
Fig. 20
17
18
15
Remote Trip, channel 2
Carrier Send, DEF Prot.
3
4
5
Start L1L2L3 to AR in Main 1
Trip CB 3-Pole to AR in Main 1
Trip CB to AR in Main 1
6
OC13
7
OC14
CR11
8
OC15
CR12
9
CR13
10
Trip Phase L1, trip coil 1
Trip Phase L2, trip coil 1
Trip Phase L3, trip coil 1
11
OC16
12
OC17
OC18
15
16
14
2
CR08
OC12
10
11
Remote Trip, channel 1
Carrier Send, Distance Prot.
1
D
5
6
12
OC09
18
1
11
13
OC08
16
Breaker Q0 Close Command
AR Close Command
10
CR04
Bus 2 VT MCB Fail
8
9
12
13
Block close command
6
8
9
5
CR14
13
CR15
14
CR16
15
Trip Phase L1, trip coil 2
Trip Phase L2, trip coil 2
Trip Phase L3, trip coil 2
OC19
OC20
REB500sys: Typical assignment of the in-/outputs of line variant L-V4 for 500BU03пЂ (See [2] Application description)
Page 45
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Connection diagrams
(contВґd)
Binary inputs
Transformer
Variant 1
Start BFP phase L1L2L3
from prot. group 2 TRIP
External start BFP
from mechanic prot. TRIP
1
2
3
OC01
A
Binary outputs
Transformer
Variant 1
C
1
CR01
OC02
2
In service
3
4
Start BFP phase L1L2L3
from back-up prot. TRIP
Spare
5
6
7
4
OC03
CR02
OC04
Mechanic protection TRIP 1
10
Mechanic protection alarm 1
Mechanic protection TRIP 2
11
7
Mechanic protection alarm 2
CR03
OC05
Transf. prot. trip L1L2L3 group 1
Tripping relay (94-1)
10 trip CB A/B/C–side *)
CR04
13
CR05
15
OC07
17
Block transformer
1
diff. protection
CR06
Transformer diff. inrush input
Transformer diff. high-set
CR07
OC09
18
2
3
4
OC10
B
A-side bus 1 isolator Q1 open
A-side bus 1 isolator Q1 closed
A-side bus 2 isolator Q2 open
7
8
9
11
12
A-side breaker Q0 open
13
A-side breaker Q0 closed
14
OC12
CR08
CR09
CR10
OC13
OC15
16
17
Spare
18
3
Remote trip 1 to B-side
4
Remote Trip 1 to C-side *)
5
Transf. prot. trip Г† start BFP
on B-side
6
OC14
7
CR11
CR12
CR13
8
Trip phase L1
9
Trip phase L2
Trip breaker
Q0 coil 1 A-side
10 Trip phase L3
OC16
11
OC17
OC18
15
Spare
15 Transf. prot. trip L1L2L3 group 2
Tripping relay (94-2)
trip CB A/B/C–side *)
1
D
10
A-side bus 2 isolator Q2 closed
14 Remote trip 2 to B-side
2
OC11
5
6
11 Transf. prot. trip Г† start BFP
on C-side *)
12
13
OC08
16
A-side breaker Q0
manual close command
8
9
OC06
12
14
Block close command
breaker Q0 A-side
6
8
9
5
OC19
12
CR14
13 Trip phase L1
CR15
14 Trip phase L2
CR16
15 Trip phase L3
Trip breaker
Q0 coil 3 A-side
OC20
Legend:
A-side Г† Transformer primary side
B-side Г† Transformer secondary side
C-side Г† Transformer tertiary side *)
*) Г† C-side, if existing
Fig. 21
Page 46
REB500sys: Typical assignment of the in-/outputs of transformer variant T-V1 for 500BU03пЂ (See [2] application description)
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Dimensioned
drawings (in mm)
Bay unit 500BU03
2
Cross section: max. 2.5 mm
2
Space for wiring
max. 4.0 mm
Achtung
Caution
Attention
Atencion
Fig. 22
Cross section: max. 2.5 mm
Bay unit casing for flush mounting, enclosure protection class IP 40 (without local HMI)
2
Space for wiring
max. 4.0 mm2
Fig. 23
Centralized version based on a 19'' mounting plate with up to three bay units. пЂ Optionally with local HMI.
Page 47
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Bay unit 500BU03
2
Cross section max. 2.5 mm
2
max. 4.0 mm
6U=265.8
223
200В±0.5
25
267+0.1
204В±0.5
Space for wiring
189
approx. 100
276
Dimensioned drawings (in mm) (contВґd)
210
Panel cutout
Fig. 24
Dimensional drawing of the bay unit with local HMI, classical mountingпЂ protection type IP40
Central unit
6U=265.8
57.1
76.2
57.1
482.6
443
approx. 235
Rear view
30
212
approx. 70
465.6
Fig. 25
Page 48
Dimensional drawing of the central unit, protection type IP20
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Cubicle mounting
Fig. 26
Front view of REB500 (example only)
Fig. 27
Hinged frame and rear wall
Example with 9 bay units
The cubicles are equipped with gratings for the fixation of incoming cables. For space reasons
there are no cable ducts.
Table 47 Maximum number of units per cubicle (central version)
Unit
Current transformer per bay
Voltage transformer per bay
Quantity of 500BU03
4
5
8
6
1
3
9
-
Cross-section
ext. cable
Quantity of
system cables
per bay
2.5 mm2 - 6 mm2
1
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 per
cubicle with central unit
9*
Max. number of bays per
cubicle without central unit
12*
* number of bays per cubicleпЂ (2200 x 800 x 800 mm)пЂ based on the min. cross-section and an
average quantity of cables
Page 49
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Cubicle mounting
(cont’d)
Table 48 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 version
Bay 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 feeders
plus communication interface)
Central unit with redundant power supply
10.0 kg
Basic version
Fig. 28
Sample пЂ specification
Basic version with HMI
Possible arrangement of the bay unit with HMI
Combined numerical bay and station protection with extensive self-monitoring and analog/digital conversion of all input quantities.
The architecture shall be decentralized, with
bay units and a central unit.
It shall be suitable for the protection of single
and double busbar as well as for the protection (Main 2 or back-up) of incoming and outgoing bays, lines, cables or transformer bays.
The hardware shall allow functions to be activated from a software library:
Page 50
Classic version
• Busbar protection scheme based on lowimpedance principle and at least two independent tripping criteria
• End fault protection
• Breaker failure protection
• Breaker pole discrepancy
• Additional criteria for the busbar protection
as overcurrent or voltage release
• Over-/undercurrent and over-/undervoltage back-up bay function (overcurrent
directional or non-directional)
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
• Distance protection function with all relevant additional features, such as switch-onto-fault, teleprotection schemes, voltage
supervision, power swing blocking
No auxiliary CTs are necessary and the system contains internal check of the voltage and
current circuits. The adaptation of the CTratio is done by software.
• Earth fault directional function based on
zero components with separate communication scheme or using the same channel
as the distance protection
A modern human machine interface shall
allow the allocation of input and output signals.
• Directional sensitive earth fault protection
for ungrounded or compensated systems
• Autoreclosure function, single/three pole
and multi-shot
• Synchrocheck function with the different
operation modes (dead line and /or dead
bus check)
• Thermal overload protection
• Peak value over-/undervoltage function
• Transformer differential protection for the
protection of two or three-winding transformers and autotransformers
Ordering
Communication via computer or via interface
to monitoring or control systems allows the
actual configuration of the whole busbar to be
displayed.
Event and disturbance recording shall be
included, collection of data in the bay units,
comprehensive recording available for the
whole station in the central unit.
The proposed system shall be easily extensible, in case of extensions in the substation.
Ordering
When sending your enquiry please provide
the short version of the questionnaire on page
55 in this data sheet together with a single-line
diagram of the station. This will enable us to
submit a tender that corresponds more accurately to your needs.
Page 51
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Ordering (cont’d)
Ordering code
REB500-CU03-V76 -S
-P
-B
-CA
-CB
Equipped for
10 bay units
20 bay units
30 bay units
40 bay units, incl. 2nd rack
50 bay units, incl. 2nd rack
60 bay units, incl. 2nd rack
10
20
30
40
50
60
Red. Power Supply
No
Yes, for 1-30 bay units
Yes, for 1-60 bay units
0
1
2
2nd Binary Input Module
No (12 inputs / 9 outputs)
Yes (24 inputs /18 outputs)
0
1
Communication Interface A
No
LON
IEC 103
IEC 61850-8-1
0
1
2
3
Communication Interface B
No
LON
IEC 103
IEC 61850-8-1
Page 52
0
1
2
3
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Short questionnaire
mandatory ordering information
Accessories
HMI software
HMI500 Ver. 7.50/7.60 Operator
Quantity
1MRB260027R0076
HMI500 Ver. 7.50/7.60 Configurator *
Quantity
1MRB260027R0176
* HMI500 Configurator is including software license for 4 users
(authorization by serial number).
Please note license is only provided for trained customers!
Central unit module
500CIM06
Communication card IEC 103 ,IEC 61850
Quantity
1MRB150077R0111
500CIM06
Communication card IEC 103 ,IEC 61850 , LON
Quantity
1MRB150077R0112
500CPU05
Processor unit complete
Quantity
1MRB150081R0001
500BIO01
Binary I/O card
Quantity
1MRB150005R0001
500PSM03
Power supply 100 W
Quantity
1MRB150038R0001
500SCM01
Star coupler module
Quantity
1MRB150004R0001
Operating instructions REB500/REB500sys in English
Quantity
1MRB520292-Uen
2 core FO-cable *5.00 m, indoor, ready made incl. 4 connectors
Quantity
HESP417456R0005
2 core FO-cable *10.00 m, indoor, ready made incl. 4 connectors
Quantity
HESP417456R0010
2 core FO-cable *20.00 m, indoor, ready made incl. 4 connectors
Quantity
HESP417456R0020
2 core FO-cable *100.00 m, indoor, ready made incl. 4 connectors Quantity
HESP417456R0100
Manuals
Fiber optic cables
Page 53
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Ordering (cont’d)
LHMI
-A
500HMI03 * 0.5REB500-BU03-V7-C
m, local HMI with 0.5 m cable
-P
500HMI03 * 3 m, local HMI with 3 m cable
-F
-BB Quantity
-IO -R
Quantity
-OC
-BFP -EFP
1MRB150073R0052
-PD
-DR
-L
-T
1MRB150073R0302
Line protection
No
Line variant 1 (L-V1)
Miscellaneous
Line variant 2 (L-V2)
500OCC02 Converter cable (serial) HMI-PC
Line variant 3 (L-V3)
500OCC03 Converter cable (USB) HMI-PC
Line variant 4 (L-V4)
Line variant 5 (L-V5)
Line variant 6 (L-V6)
Mounting parts
Line variant 7 (L-V7)
Cover plate 4R
Transformer protection Cover plate 8R
Mounting plate 19"
No
4R (4 divisions)
Quantity
0
1
2
1MRB380084R0001
3
1MRB380084R0003
4
5
6
7
1MRB400164 R0004
8R (8 divisions)
Quantity
1MRB400164 R0008
Quantity
1MRB400299 P0101
0
Quantity
Quantity
Transformer variant 1 (T-V1)
Transformer variant 2 (T-V2)
Transformer variant 3 (T-V3)
Transformer variant 4 (T-V4)
1
2
3
4
Mounting plate 19", 7U, max. 3 500BU03, пЂ no display cut-out
Mounting plate 19"
Quantity
1MRB400299 P0103
HMI Cover plate for mounting on unused dis- Quantity
play cut-outs
1MRB400304 R0101
Quantity
1MRB400130 P0101
Mounting plate 19", 7U, max. 3 500BU03,
with display cut-out
HMI Cover plate
Mounting plate 19"
Mounting plate 19", 7U, 1 x 500BU03 classic
cut out
Page 54
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Short questionnaire
1. Client
Client
Station
Client's reference
Client's representive, date
2. ABB (filled in by ABB)
Tender No.:
Order No.:
Sales Engineer
Project Manager
3. Binding Single line diagram
Diagram No.
Date
System Voltage [kV]
Neutral Grounding
Solidly grounded
Isolated
Compensated
Low resistance gr.
Rev. Index
Rev. Date
Remark :
This attachment is
absolutely essential !
(must show location and configuration
of spare bays)
4. HV System
Frequency [Hz]
Switchgear
1-1/2 Breaker
Ring bus
Transfer bus
Circuit Breaker type
AIS
5. Trip circuits
Busbar configuration
Single
Double
Triple
Quadruple
GIS
Single pole
Three pole
Tripping method
One trip coil
Distributed CU loose delivered
6. Type of installation
Two trip coils
Centralized CU and BU loose delivered
BU loose delivered
Distributed CU mounted in cubicle
Centralized CU and BU mounted in cubicles
BU mounted in cubicles
mandatory ordering information
Accessories
HMI software
HMI500 Ver. 7.60 Operator
Quantity
1MRB260027R0076
HMI500 Ver. 7.60 Configurator *
Quantity
1MRB260027R0176
* HMI500 Configurator is including software license for 4 usersпЂ (authorization by serial number). пЂ Please note license is only provided for trained customers!
Central unit module
500CIM06
Communication card IEC 103 ,IEC 61850
Quantity
1MRB150077R0111
500CIM06
Communication card IEC 103 ,IEC 61850 , LON
Quantity
1MRB150077R0112
500CPU05
Processor unit complete
Quantity
1MRB150081R0001
500BIO01
Binary I/O card
Quantity
1MRB150005R0001
500PSM03
Power supply 100 W
Quantity
1MRB150038R0001
500SCM01
Star coupler module
Quantity
1MRB150004R0001
Operating instructions REB500/REB500sys in English
Quantity
1MRB520292-Uen
2 core FO-cable *5.00 m, indoor, ready made incl. 4 connectors
Quantity
HESP417456R0005
2 core FO-cable *10.00 m, indoor, ready made incl. 4 connectors
Quantity
HESP417456R0010
2 core FO-cable *20.00 m, indoor, ready made incl. 4 connectors
Quantity
HESP417456R0020
2 core FO-cable *100.00 m, indoor, ready made incl. 4 connectors Quantity
HESP417456R0100
Manuals
Fiber optic cables
Page 55
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Ordering (cont’d)
LHMI
500HMI03 * 0.5 m, local HMI with 0.5 m cable
Quantity
1MRB150073R0052
500HMI03 * 3 m, local HMI with 3 m cable
Quantity
1MRB150073R0302
Miscellaneous
500OCC02 Converter cable (serial) HMI-PC
Quantity
1MRB380084R0001
500OCC03 Converter cable (USB) HMI-PC
Quantity
1MRB380084R0003
Mounting parts
Cover plate 4R
4R (4 divisions)
Quantity
1MRB400164 R0004
Cover plate 8R
8R (8 divisions)
Quantity
1MRB400164 R0008
Quantity
1MRB400299 P0101
Quantity
1MRB400299 P0103
HMI Cover plate for mounting on unused dis- Quantity
play cut-outs
1MRB400304 R0101
Quantity
1MRB400130 P0101
Mounting plate 19"
Mounting plate 19", 7U, max. 3 500BU03, пЂ no display cut-out
Mounting plate 19"
Mounting plate 19", 7U, max. 3 500BU03,
with display cut-out
HMI Cover plate
Mounting plate 19"
Mounting plate 19", 7U, 1 x 500BU03 classic
cut out
Page 56
Substation Automation Products
Distributed busbar protection REB500
including line and transformer protection
Mounting parts
Mounting plate 19"
Quantity
1MRB400130 P0102
Mounting plate 19", 7U, 2 x 500BU03 classic
cut out
Other relevant
publications
[1] CT requirements for REB500 / REB500sys
1KHL020347-AEN
[2] Application description REB500sys
1MRB520295-Aen
[3] Data sheet PSM505
1MRB520376-Ben
Operating instructions REB500 / REB500sys
1MRB520292-Uen
Data sheet RESP07
1KHA005034-BEN
Reference list REB500
1MRB520009-Ren
Ordering questionnaire REB500
1MRB520371-Ken
Page 57
ABB Switzerland Ltd
Power Systems
Bruggerstrasse 72
CH-5400 Baden
Tel.
+41 58 585 77 44
Fax
+41 58 585 55 77пЂ E-mail: substation.automation@ch.abb.com
www.abb.com/substationautomation
ABB AB
Substation Automation Products
SE-721 59 Västerås
Tel.
+46 21 34 20 00
Fax
+46 21 32 42 23пЂ E-mail: sa-t.supportline@se.abb.com
1MRB520308-Ben В© Copyright 2011 ABB. All rights reserved.
Contact us

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