1MRB520308-BEN B en Numerical Station Protection System REB500-REB500sys

Numerical Station Protection SystemBusbar Protection with integrated Breaker Failure, Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 1 Issued: December 2008 Changed since October 2007 Data subject to change without notice REB500sys - Station protection with distributed architecture 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 48 V DC and 250 V DC - nominal frequencies of 50, 60 and 16.7 Hz • Short tripping times independent of the plant’s size or configuration • Centralized layout: Installation of hardware in one or several cubicles • Distributed layout: Bay units distributed and, in the case of location close to the feeders, with short connections to CTs, 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 • 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 IEC 61850-8-1, IEC 60870-5-103 and LON ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure, Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 2 Main features (cont’d) Options • Breaker failure protection (also separately operable without busbar protection) • End fault protection • Definite time overcurrent protection • Breaker pole discrepancy • Current and voltage release criteria • Disturbance recording for power system voltages • Separate I0 measurement for impedancegrounded networks • Communication with substation monitoring and control system (IEC 61850-8-1 / IEC 60870-5-103 / LON) • Internal user-friendly human machine interface with display • Redundant power supply for central units and/or bay units Additional main features 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. 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 • Three-phase current and three-phase voltage plausibility Main 2 / back-up bay protection: 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 - checks for dead line, dead bus, dead line and bus Group 1 / back-up bay protection: 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 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 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 1½ breaker schemes to be protected. In 1½ breaker schemes the busbars and the entire diameters, including Stub/T-Zone can be protected. An integrated tripping scheme allows to save external logics as well as 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. ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure, Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 3 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. REB500sys The REB500sys is foreseen in MV, HV and EHV substations with nominal frequencies of 50 Hz resp. 60 Hz to protect the busbars and their feeders. The bay protection functions included in REB500sys are used as Main 2 / Group 1 - or back-up protection. The system REB500sys is foreseen for all single or double busbar configurations (Line variants L-V1 to L-V5 and Transformer variant T-V1 to T-V4). In 1½ 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 resistivegrounded, 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. Depending on the network voltage level and the protection philosophy the following protection concepts are generally applied: • Two main protection schemes per bay and one busbar protection. With REB500sys the protection concept can be simplified. Due to the higher 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. 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. Nine standard options are defined for Main 2/ Group 1 or back-up bay level functions: Line protection - Line variant 1 (L-V1) directional, non-directional overcurrent and directional earth fault protection - Line variant 2 (L-V2) as Line variant L-V1 plus distance prot. - Line variant 3 (L-V3) as Line variant L-V2 plus autoreclosure - Line variant 4 (L-V4) as Line variant L-V3 plus synchrocheck - Line variant 5 (L-V5) as Line variant L-V1 plus autoreclosure and synchrocheck. Transformer protection - Transformer Variant 1 (T-V1) 2- or 3 winding transformer differential protection, thermal overload, current functions; applicable also as autonomous T-zone protection. - Transformer Variant 2 (T-V2) 2-winding transformer differential protection, thermal overload, current functions, overfluxing protection, neutral overcurrent (EF). - Transformer Variant 3 (T-V3) Distance protection for transformer back-up or 2- winding transformer differential protection, thermal overload, current functions, voltage functions, frequency functions, power function, overfluxing protection. - Transformer Variant 4 (T-V4) Transformer oriented functions/ back-up functions -> thermal overload, current functions, voltage functions, frequency functions, power function, overfluxing protection. ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure, Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 4 Application (cont´d) Fig. 1 ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure, Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 5 Table 1 Overview of the functionalities REB500 / REB500sys Transformer Variant 1 (T-V1) Transformer Variant 2 (T-V2) Transformer Variant 3 (T-V3) Transformer Variant 4 (T-V4) Line Variant 1 (L-V1) Line Variant 2 (L-V2) Line Variant 3 (L-V3) Line Variant 4 (L-V4) Line Variant 5 (L-V5) Protection function Bay Unit Hardware 500BU03 for 50 Hz, 60 Hz, 16.7 Hz IEC61850 Standard Main functionality Busbar protection Measurement of neutral current / detection I0 Breaker failure protection 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 IEC61850-8-1/ LON / IEC60870-5-103 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 * for special applications only 500BU03: bay unit 51 51 59/27 51N 67 67 46 47 67N 32N 21 79 25 87T 87T 49 50 59 24 24 81 81 32 Com - REB500 REB500 / REB500sys 87B 87BN 50BF 51/62EF 51/62PD 51 59/27 87CZ 51 94RD 95DR 95DR BBP I0 BFP EFP PDF BBP CZ OCDT ER DR DR PDIF PDIF RBRF PTOC PTOC PTOC PTOV/PTUV PDIF PTOC RDRE RDRE DIREFISOL PSDE DIST AR SYNC DIFTRA DIFTRA TH OCINST OVINST U/fDT U/fINV df/dt Freq P PDIS RREC RSYN PDIF PDIF PTTR PTUC/PTOC PTUV/PTOV PVPH PVPH PVRC PTOF/PTUF PDUP/PDOP 500BU03 for 50 Hz, 60 Hz OCDT OCINV OVDT I0INV DIROCDT DIROCINV CHKI3PH CHKU3PH PTOC PTOC PTUV/PTOV PTOC PTOC PTOC PTOC PTUV DIREFGND PDEF Option IEEE Functionality The central processing unit is normally in a centrally located cubicle or in the central relay room. and the central processing unit are mounted according to the size of the busbar system in one or more cubicles (see Fig. 2 Distributed installation Centralized installation 19" mounting plates with up to three bay units each. 23). much more functionality can be packed into the same space. 24) are installed in casings or cubicles in the individual switchgear bays distributed around the station and are connected to the central processing unit by optical fiber cables. 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.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 6 Mode of installation There are three versions of installing the numerical busbar protection REB500 and the numerical station protection REB500sys: Distributed installation In this case. Fig. 3 Centralized installation Combined centralized and distributed installation Basically. the bay units (see Fig. Fig. since very little additional wiring is required and compared with older kinds of busbar protection. A centralized installation is the ideal solution for upgrading existing stations. . Where more binary and analog inputs are needed. etc. The binary I/O module detects and processes the positions of isolators and couplers. 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). In the analog input and processing module. voltages. several bay units can be combined to form a feeder/bus coupler bay (e. 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. 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. external resetting signals.g. a bus coupler bay with CTs on both sides of the bus-tie breaker requires two bay units). (see Fig. 4) is the interface between the protection and the primary system process comprising the main CTs. The binary input channels operate according to a patented pulse modulation principle in a nominal range of 48 to 250 V DC. A software logic enables the input and output channels to be assigned to the various functions. end fault. Zero-sequence voltage and zero-current signals are also calculated internally. starting signals. The PC-based HMI program provides settings for the threshold voltage of the binary inputs. because any differences between the CT ratios are compensated by appropriately configuring the software of the respective bay units.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. blocking signals. A time stamp is attached to all the data such as currents. breaker failure. 4 Block diagram of a bay unit and a central unit . Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 7 System design Bay unit (500BU03) The bay unit (see Fig. The Pro- cess data are transferred at regular intervals from the bay units to the central processing unit via the process bus. The bay unit is provided with local intelligence and performs local protection (e. The input transformer module contains four input CTs for measuring phase and neutral currents with terminals for 1 A and 5 A.g. bay protection (Main 2 or back-up bay protections) as well as the event and disturbance recording. 12). events and diagnostic information acquired by a bay unit. pre-processing. Additional interposing CTs are not required. binary inputs. breaker pole discrepancy). Every bay unit has 20 binary inputs and 16 relay outputs. isolators and circuit-breaker and performs the associated data acquisition. Bay Unit (500BU03) Optical Interface Local HMI Central Unit (500CU03) DC DC DC DC Real-time Clock SAS/SMS Interface RS 232 Interface Process-bus CPU Local HMI CPU Module DSP DP Mem Binary in/output registers CIM A/D CPU Module CPU Module Filter Filter Starcoupler Binary I/O Star coupler Electrical insulation Fig. It also provides the electrical insulation between the primary system and the internal electronics of the protection. control functions and bay level protection functions. additional casings are required for accommodating the additional central processors and star coupler modules required. it configures the system. 6). The hardware structure is based on a closed. 5): ideal solution for distributed and kiosk mounting (AIS). The replacement of a bay unit can be handled in a simple way. The necessary setting values and configuration data are then downloaded automatically. a bay unit can be easily replaced. Fig. 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. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 8 System design (cont´d) In the event that the central unit is out of operation or the optical fiber communication is disrupted an alarm is generated. acts as process bus controller. Fig. and all local and bay protection as well as the recorders (event and disturbance) will remain fully functional (stand-alone operation). The modules are inserted from the rear. this can be entered directly via its local HMI. complexity and functionality of the busbar system. a TCP/IP port for very fast HMI500 connection within the local area network. assigns bays within the system. i. contains the busbar replica.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. The modules actually installed in a particular protection scheme depend on the size. The variables for the busbar protection function are derived dynamically from the process data provided by the bay units. The central unit comprises a local HMI with 20 programmable LEDs (Fig. Additional plug-and-play functionality Central unit (500CU03) The hardware structure is based on standard racks and only a few different module types for the central unit (see Fig. since all information is available in the bay. 4). 5 Built-in HMI directly on the bay unit 500BU03. Up to 10 bay units can be connected to the first central processor and 10 to the others. the bay unit will continue to operate. All modules of the central unit have a plugand-play functionality in order to minimize module configuration. In the case of more than 30 bay units. Bay units can be added to an existing REB500 system in a simple way. The process data are transferred to the central processor via a star coupler module. A parallel bus on a front-plate motherboard establishes the interconnections between the modules in a rack. During system start-up the new bay unit requests its address. manages the sets of operating parameters. For the latter option it is possible to have the HMI either built in or connected via a flexible cable to a fixed mounting position (see Fig. The central unit is the system manager. 6 Central unit . Central processors and star coupler modules are added for protection systems that include more than 10 bay units. In the event of a failure. One or two binary I/O modules can be connected to a central processing unit. • With local HMI and 20 programmable LEDs (Fig. 28). assures synchronization of the system and controls communication with the station control system.e. ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. In Fig. The first measuring principle uses a stabilized differential current algorithm. In the case of an internal fault.. The following two conditions have to be accomplished for the detection of an internal fault: k st = IDiff > k st max IRest (3) IDiff > IK min where kst kst max IK min (4) stabilizing factor stabilization factor limit. Differential current ( |Σ Ι | ) ing ipp Tr a are Ksetting = kst max IKmin 0 0 Restraint area Restraint current (Σ|Ι|) ⎡ Im ILn ⎤ ϕ = arctan ⎢ ⎥ n ⎣ Re ILn ⎦ ( ) ( ) (5) Fig. 8). Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 9 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: • 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. The currents are evaluated individually for each of the phases and each section of busbar (protection zone). A typical value is kst max = 0. 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. (1) IDiff = N ∑ ILn n=1 and the restraint current IRest = N ∑ ILn n=1 (2) . k=1 where N is the number of feeders. while in normal operation or during an external fault at least one current is approximately 180° out of phase with the others. 7 Tripping characteristic of the stabilized differential current algorithm. the differential current is 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. Any DC component and harmonics are suppressed. 7.80 differential current pick-up value The above calculations and evaluations are performed by the central unit. The fundamental frequency current phasors ϕ1. all of the feeder currents have almost the same phase angle.n (5) are compared. if parameterized. Optionally. Operation of the breaker failure function is enabled either: • internally by the busbar protection algorithm (and. A remote tripping signal can be configured in the software to be transmitted after the first or second timer. (The operation of the function. 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. Depending on the phase-angle of the fault. overcurrent or pole discrepancy protection features) of the bay level • externally via a binary input. Overcurrent function A definite time overcurrent back-up protection scheme can be integrated in each bay unit. a tripping command can be applied to a second tripping coil on the circuit-breaker and a remote tripping signal transmitted to the station at the opposite end of the line. may start the local breaker failure protection scheme). preprocesses them accordingly and then filters the resulting data according to a Fourier function. The function can be configured as release criterion per zone through internal . 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.g. 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 Operating characteristic 180° Case 2: Internal fault Δϕ = 36° Im Phase-shift Δϕ 74° Restraint area Δϕ max = 74° Tripping area I1 I2 Re 0° Case 1 2 ϕ12 = 36° Fig. The end fault protection is enabled a certain time after the circuit-breaker has been opened.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 10 Functionality (cont´d) Case 1: External fault Δϕ = 144° Im Busbar ϕ12 = 144° I2 I1 Re After the delay of the first timer has expired. Breaker failure protection In order to protect the “dead zone” between an open circuit-breaker and the associated CTs. Phase-segregated measurements in each bay unit cope with evolving faults. The current release criteria is only performed in the bay unit. 8 Characteristic of the phase comparator for determining energy direction. also by the internal line protection. if configured. by the line protection. Each of the bay units continuously monitors the currents of its own feeder. the tripping time varies at Idiff/Ikmin ≥5 between 20 and 30 ms including the auxiliary tripping relay. the breaker failure function uses the busbar replica to trip all the other feeders supplying the same section of busbar via their bay units. The task of processing the algorithms is shared between the bay units and the central processing unit. respectively the voltage is below a certain value. They have two timers with individual settings. Voltage release criteria The voltage criterion is measured in the bay unit. If the fault still persists at the end of the second time delay. Current release criteria The breaker failure functions in the bay units monitor the phase currents independently of the busbar protection. In the event of a short circuit in the dead zone the nearest circuit-breakers are tripped. This first timer operates in a stand-alone mode in the bay unit. This function is performed in a stand-alone mode in the bay unit. e. This function is performed in a stand-alone mode in the bay unit. a signal derived from the breaker position and the close command is applied. transformer protection etc. a communication module is added to the central unit. The total recording period can be divided into a maximum of 15 recording intervals per bay unit. A lower sampling rate enables a longer period to be recorded. Up to 10 general-purpose binary inputs may be configured to enable external signals to trigger a disturbance record. the function does not send an intertripping signal to the central unit. First Out). In addition. A time stamp with a resolution of 1ms is attached to every binary event. IEC 60870-5-103 and LON. This function is also performed in a standalone mode in the bay unit. Note: Stored disturbance data can be transferred via the central unit to other computer systems for evaluation by programs such as PSM505 [4]. Files are transferred in the COMTRADE format. Communication interface The check zone algorithm can be used as a release criterion for the zone-discriminating low-impedance busbar protection system. Pole discrepancy A pole discrepancy protection algorithm supervises that all three poles of a circuitbreakers open within a given time. Where the busbar protection has to communicate with a station automation (SAS). The module supports the interbay bus protocols IEC 61850-8-1. Events are divided into the three following groups: • system events • protection events • test events The events are stored locally in the bay unit or in the central unit. This function monitors the discrepancy between the three-phase currents of the circuitbreaker. 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. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 11 linking in the central unit. Tripping is only possible if the voltage falls short of (U<) or exceeds (U0>) the set value. . For details see Table 22. which only acquires the feeder currents of the complete busbar. This function is performed in a stand-alone mode in the bay unit (see page 7). 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. When it picks up. This necessitates the existence of one set of voltage transformers per zone in one of the bay units. Event recording The events are recorded in each bay unit. After retrieving the disturbance recorder data. it starts the local breaker failure protection (BFP logic 3). Voltages can also be optionally registered (see Table 14). The number of analog channels that can be recorded. 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. The user can also determine whether the recorded data is retained or overwritten by the next disturbance (FIFO = First In. if configured. Each bay unit can record a maximum of 32 binary signals. but only for single phase-to-earth faults. there is a binary input in the central and the bay unit for starting the disturbance recorders of all bay units. The isolator / breaker positions are not relevant for this criterion. Additionally this release criterion can be configured for each feeder (voltage transformers must be installed). Check zone criterion Disturbance recording This function registers the currents and the binary inputs and outputs in each bay. It is based on a stabilized differential current measurement. the sampling rate and the recording period are given in Table 14. but. it is possible to display them graphically with PSM505 directly. A function for detecting the neutral current is therefore also available.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. + switching prohibited signal OPEN CLOSED CLOSED + delayed isolator alarm. it is possible to select the behavior of the busbar protection: • blocked • zone-selective blocked • remain in operation Table 2 N/O contact: “Isolator CLOSED” N/C contact: “Isolator OPEN” Isolator position open open Last position stored (for busbar protection) + delayed isolator alarm. Any differential current triggers a time-delayed alarm. In the event of an isolator alarm. Server 2 as backup time The LON interbay bus transfers via optical connection: • differential currents of each protection zone • binary events (signals. + switching prohibited signal open closed closed closed open closed The HMI program (HMI500) which runs on a PC connected to either a bay unit or the central processing unit includes a test generator. trips and diagnostic) • trip reset command • disturbance recording data (via MMS file transfer protocol) • time synchronization with Simple Network Time Protocol (SNTP) • two independent time servers are supported. In the event of a differential current alarm. Up to seven sequences per test stage can be started. The software replica logic determines dynamically the boundaries of the protected busbar zones (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.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. The sequences can be saved and reactivated for future tests. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 12 Functionality (cont´d) The IEC 61850-8-1 interbay bus transfers via either optical or electrical connection: • differential current of each protection zone • monitoring information from REB500 central unit and bay units • binary events (signals. it is possible to select the behavior of the busbar protection: • blocked • zone-selective blocked • remain in operation Trip redirection A binary input channel can be provided to which the external signal monitoring the cir- . trips and diagnostic) • trip reset command • disturbance recording data (via HMI500) • time synchronization The IEC 60870-5-103 interbay bus transfers via either optical or electrical connection: • time synchronization • selected events listed in the public part • all binary events assigned to a private part • all binary events in the generic part • trip reset command Test generator The test sequencer enables easy testing of the bay protection without the need to decommission the busbar protection. the test generator function enables the user to: • activate binary input and output signals • monitor system response. • test the trip circuit up to and including the circuit-breaker • test the reclosure cycles • establish and perform test sequences with virtual currents and voltages for the bay protection of the REB500sys Differential current supervision The differential current is permanently supervised. During commissioning and system maintenance. Isolator supervision The isolator replica is a software feature without any mechanical switching elements. the set-ting of parameters and full functional checking and testing. • in addition 20 freely programmable LEDs for user-specific displays on the bay unit 500BU03 and central unit 500CU03. which are normally requested of a line and transformer protection scheme. The transformer protection functions (T-V1 . The operation and function of HMI500 is the same whether the PC is connected locally or remotely. The bay level functions contain all the relevant additional functions. 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. Human machine interface (HMI) • switchgear and isolator positions (within the busbar protection function) • starting and tripping signals of protection functions External HMI (HMI500) The busbar protection is configured and maintained with the aid of human machine interfaces at three levels. 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.V4) are used as Group 2 or back-up bay protection for transformer bays or as an independent T-Zone protection.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. When it is inactive. 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. The HMI500 is equipped with a comfortable on-line help function. The PC software facilitates configuration of the entire busbar protection. 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. A data base comparison function enables a detailed comparison between two configuration files (e. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 13 cuit-breaker air pressure is connected. alarms 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 following information can be displayed: • measured input currents and voltages • measured differential currents (for the busbar protection) • system status. WINDOWS 2000 and WINDOWS XP. thus eliminating a separate serial connection to the central unit.L-V5) are used as Main 2 or back-up for lines as well as for transformer bays. Tripping is not possible without active signal. . The optical interface is completely immune to electrical interference. The HMI500 can also be operated via the LON Bus on MicroSCADA for example. WINDOWS 98.g. alarms and normal operation. The trip redirection can also be configured with a current criterion (current release criteria). TCP/ IP or modem link. The line protection functions (L-V1 . between the PC and the central unit or between two files on the PC). The HMI runs under MS WINDOWS NT. and undervoltage protection This function is used for voltage monitoring with instantaneous response and where insensitivity to frequency is required. dynamic and adaptive load-shedding in power utilities and industrial distribution systems. The synchrocheck function also contains checks for dead line and dead bus. user-selectable setting groups. Autoreclosure The synchrocheck function determines the difference between the amplitudes. Peak value over. Rate of change frequency protection df/dt This function is used for the static.permissive overreaching transfer tripping . This protection function is normally equipped with two independently set levels and is used when oil overtemperature detectors are not installed.and undercurrent protection These functions are used for current monitoring with instantaneous response and where insensitivity to frequency is required. Frequency function The autoreclosure function permits up to four three-phase autoreclosure cycles. In the supervision mode the active and reactive power with the respective energy direction is displayed by the HMI500. If the REB500sys autoreclosure function is employed.and three-winding transformers • Auto transformers • Three-phase function • Current-adaptive characteristic • High stability for external faults and current transformer saturation • No auxiliary transformers necessary because of vector group and CT ratio compensation • Inrush restraint using 2nd harmonic The transformer differential protection function can also be used as an autonomous Tzone protection in a 1½ breaker scheme. phase angles and frequencies of two voltage vectors. This can be achieved by configuring the frequency function several times. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 14 Additional functionalities (cont´d) High-speed distance protection Synchrocheck • Overcurrent and 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) • System logic .overreach zone • Voltage transformer circuit supervision • Power swing blocking function • HF teleprotection. Transformer differential protection • For two. The carrier-aided schemes include: .fixed reactance slope .permissive underreaching transfer tripping . When the autoreclosure function is realized outside of REB500sys. Peak value over. Thermal overload This function protects the insulation against thermal stress.reactance slope dependent on load value and direction (ZHV<) • Parallel line compensation • Phase-selective tripping for single and three-pole autoreclosure • Four independent.blocking scheme with echo and transient blocking functions • Load-compensated measurement . The function supervises the rate-of-change df/dt of one voltage input channel. The first cycle can be single phase or three-phase. Several stages of the frequency protection are often needed. or for load-shedding in the event of an overload. all input and output signals required by the external autoreclosure equipment are available in order to guarantee correct functionality. it can be used as a back-up for the autoreclosure realized externally (separate equipment or in the Main 1 protection). Several stages of the rate-of-change frequency protection are often .switch-onto-fault .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. The function is used either as an over-/ underfrequency protection. Inverse time overfluxing protection This function is primarily intended to protect the iron cores of transformer against excessive flux. To perform this function the BU03 with 3I. Four different characteristics according to British Standard 142 designated normal inverse. The function can be configured for single phase measurement or a combined three-phase measurement with detection of the highest phase current. or three phase measurement of the real or apparent power. The inverse curve ca be set by a table of 10 values and the times t-min and tmax. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 15 needed. Definite time overfluxing protection Directional sensitive earth fault protection for ungrounded or compensated systems This function is primarily intended to protect the iron cores of transformers against excessive flux. In both cases the neutral current and voltage can be derived either externally or internally. active or reactive power (power direction setting).and undercurrent protection This function is used as Main 2 or as back-up function respectively for line. extremely inverse and long time inverse but with an extended setting range are provided. Power function The sensitive earth fault protection function for ungrounded systems and compensated systems with Petersen coils can be set for either forwards or reverse measurement. Definite time over. This function works either with the same communication channel as the distance protection scheme or with an independent channel. 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. 1MT and 5U is required. Inverse time earth fault overcurrent protection 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 low-resistance grounded systems. 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. The function works with an inverse time delay. Phase angle errors of the CT/VT inputs can be compensated by setting. The inverse time earth fault overcurrent function monitors the neutral current of the system. This function can be activated in the phase. The characteristic angle is set to ±90° (U0 · I0 · sin ϕ) in ungrounded systems and to 0° or 180° (U0 · I0 · cos ϕ) for systems with Petersen coils. This function comprises a voltage memory for faults close to the relay location. very inverse. Instead the voltage/frequency-ratio. Inverse time overcurrent protection This function provides single. Four different characteristics according to British Standard 142 designated normal inverse. The scheme operates either in a permissive or blocking mode and can be used in conjunction with an inverse time earth fault overcurrent function. Directional overcurrent definite / inverse time protection The directional overcurrent definite time function is available either with inverse time or definite time overcurrent characteristic.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. which is proportional to the flux is monitored.and/or the neutral current circuit. transformer or bus-tie bays. very inverse. The neutral current is always used for measurement in the case of systems with Petersen coils. The magnetic flux is not measured directly. Instead the voltage/frequencyratio. The operating mode can be configured either to underpower or to overpower protection. This can be achieved by configuring the rate-of-change frequency function several times. The magnetic flux is not measured directly. The function response after the memory time has elapsed can be selected (trip or block). The function can be configured for monitoring reverse. Directional sensitive earth fault protection for grounded systems 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. which is proportional to the flux is monitored. The function works with a definite time delay. extremely inverse and long time inverse but with an extended setting range are provided. . every output channel comprises two redundant commands. end fault protection or bay level back-up / Main 2 functions can be easily activated at any time without extra hardware.g. 1 min.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 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. configured using the software configuration tool. This function is used for checking the sum and the phase sequence of the three-phase currents.and undervoltage protection Three-phase current plausibility This function works with a definite time delay with either single or three-phase measurement. incorrect response or inconsistency. The processing of tripping commands is one of the most important functions from the reliability and dependability point of view. . auxiliary supplies. Extension of the system The following resetting modes can be selected for each binary output (tripping or signal outputs): • 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. to facilitate maintenance of station batteries. per month • periodic time telegram with minute pulse (radio or satellite clock or station control system): accuracy typically ±10 ms • periodic time telegram as above with second pulse: accuracy typically ±1 ms • a direct connection of a GPS or DCF77 to the central unit is possible: accuracy typically ±1 ms The system time may also be synchronized by a minute pulse applied to a binary input on the central unit. which have to be enabled at regular intervals by a watchdog. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 16 Additional functionalities (cont’d) Definite time over. Three-phase voltage plausibility This function is used for checking the sum and the phase sequence of the three-phase voltages. The system functions are determined by software. Additional features Self-supervision Resetting the trip commands/-signals All the system functions are continuously monitored to ensure the maximum reliability and availability of the protection. A watchdog continuously monitors the integrity of the software functions and the exchange of data via the process bus is also continuously supervised.g. e. This is an option for the central unit as well as for the bay unit. If the watchdog condition is not satisfied. the corresponding action is taken to establish a safe status.g. breaker failure. the channels are blocked. Time synchronization The absolute time accuracy with respect to an external time reference depends on the method of synchronization used: • no external time synchronization: accuracy approx. In the event of a failure. Accordingly. It is used while performing maintenance respectively inspection activities on the primary equipment. The system can be completely engineered in advance to correspond to the final state of the station. Additional system functions. A/D converters and main and program memories) are subjected to various tests when the system is switched on and also during operation. Redundant power supplies (Option) Two power supply modules can be fitted in a redundant arrangement. an alarm is given and an event is registered for subsequent diagnostic analysis. e. Important items of hardware (e. 5 μm optical fibers) • rodent protected and longitudinally waterproof if in cable ducts Please observe the permissible bending radius when laying the cables. i. during the opening movement. One potentially-free N/O and N/C contact are required on each isolator.e. During the closing movement. If this is not the case. the N/O contact Open end position must close before the isolator main contact gap reaches its flashover point. The following attenuation figures are typical values which may be used to determine an approximate attenuation balance for each bay: Optical equipment Typical attenuation for gradient index (840 nm) per connector per cable joint 3. 10 Switching sequence of the auxiliary contacts that control the busbar replica . the N/O contact must not open before the isolator main contact gap exceeds its flashover point.5 dB/km 0.2 dB Central unit 1m 1200 m 1m Bay unit FST-connector ≤5 dB FST-connector Fig.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. The N/O contact signals that the isolator is “CLOSED” and the N/C contact that the isolator is “OPEN”.5. Conversely.7 dB 0. the contact signals ‘no longer closed’ beforehand. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 17 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 • diameter of core and sheath 62. respectively 125 μm • maximum permissible attenuation ≤5 dB • FST connector (for 62. 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. Close end position Close isolator Open isolator Isolator Auxiliary contacts: „CLOSED“ normally open „OPEN“ normally closed must be closed may be closed must be open Flashover gap Fig. then the N/C contact may not signal “OPEN” before the flashover point has been exceeded. the circuitbreaker CLOSE command must also be connected. The effective accuracy limit factor (n') must be checked to ensure the stability of the busbar protection during external faults. The rated accuracy limit factor is given by the CT manufacturer. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 18 Circuit-breaker replica When the circuit-breaker replica is read in the feeder or the bus-tie breaker. the effective accuracy limit factor n' becomes: 30000 n′ ≥ --------------. or 10P. Pick-up for internal faults P + PE n' = n ⋅ N PB + PE where: n = PN = PE = PB = rated accuracy limit factor rated CT power CT losses burden at rated current In the case of internal busbar faults. Main current transformer where: IKmax = max. class x). n' must satisfy the following two relationships: (1) 1 ⋅ I Kmax n′ ≥ ------------------5 ⋅ I 1N . The algorithms and stabilization features used make the busbar protection largely insensitive to CT saturation phenomena. Taking account of the burden and the CT losses.S. Should nevertheless CT saturation be possible. CT saturation is less likely. it is important to check that the minimum fault current exceeds the setting for Ikmin. because each CT only conducts the current of its own feeder. Current transformer requirements for stability during external faults (Busbar protection) where: TN = DC time constant Example: IKmax = 30000 A I1N = 1000 A TN = ≤120 ms Applying relationships (1) and (2): (1) (2) Selected: The minimum CT requirements for 3-phase systems are determined by the maximum fault current. TPX.= 6 5000 n' ≥10 n' ≥10 The current transformer requirements for REB500sys for Line and Transformer protection are described in a separate publication [2]. In the case of schemes with phase-by-phase measurement. the effective n' becomes: (2) n' ≥10 for TN ≤120 ms.. are permissible. TPY and TPZ CTs may be mixed within one substation in phase-fault schemes. TPX.. TPY. so that the CT requirements can be checked in order to ensure proper I0 measurement.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Note: For systems that measure I0. Main CTs types TPS (B. The relatively low CT performance needed for the busbar protection makes it possible for it to share protection cores with other protection devices. the REB500 questionnaire 1MRB520371-Ken should be filled in and submitted to ABB. or n' ≥20 for 120 ms <TN ≤300 ms. primary through-fault current I1N = rated primary CT current Taking the DC time constant of the feeder into account. 5P. 93% rel.+ 55°C . IEC 60255-6 (1988) EN 60255-6 (1994). EN 60068-2-14 (2000). IEC 60255-5 (2000) Thermal withstand of insulating materials Clearance and creepage distances Insulation resistance tests Dielectric tests 0. IEC 60255-6 (1988) -25°C / 16 h +70°C / 16 h -25° to 70°C. EN 60950 (1995). EN 60950 (1995). 80% amplitude modulated 10 V. / 4 days EN 60068-2-1 (1993). VDE 0411 EN 60255 (2001). IEC 68-2-2 (1974).15 . IEC 68-2-1 (1990). 4 (1993). IEC 68-2-3 (1984) EN 60950 (1995) Sec.5 Joule 5 kV AC Impulse test Table 4 Electromagnetic compatibility (EMC) Immunity 1 MHz burst disturbance tests Immunity Electrostatic discharge test (ESD) .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.Dry heat . Cl.40°C. IEC 61000-4-2 (2001) EN 61000-4-4..C (2000). IEC 60950 (1995).5 kV. IEC 60068-2-14 (2000).4 kV DC / 1 min (across open contacts) 1. IEC 60950 (1995) EN 60255 (2001). 3 80 ..air discharge . Cl.2/50 μs/0. BS 142-1966. ANSI/IEEE C37. 5. Cl. IEC 60255-5 (2000).operation . Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 19 Technical data Table 3 General data Temperature range: . IEC 60255-5 (2000).Damp heat (long-time) -10°C. 1°/min.5 kV / >100 MOhm 2 kV AC or 3 kV DC / 1 min 1 kV AC or 1. 1 MHz 400 Hz rep.storage and transport Climate tests . 2 cycles +40°C. 3 Industrial environment Test procedure EN 61000-4-8.0/2. IEC 61000-4-6 (1996). Industrial environment IEC 60255-22-1.. IEC 61000-4-8 (1993) EN 61000-4-6 (1996).continuous field .80 MHz. 3 900 MHz.contact discharge Fast transient test (burst) Power frequency magnetic field immunity test (50/60 Hz) . IEC 61000-4-4 (1995) 30 A/m 300 A/m 0. ANSI/IEEE C37..90.+ 85°C EN 60255-6 (1994). Cl.90-1989 EN 60255-5 (2001). 3 (1996). Cl.1 EN 60255-5 (2001). Cl. EN 60068-2-2 (1993). IEC 60255-5 Cl. EN 61000-4-3 (1996).Cold . 4 (1995).1000 MHz. Emission EN 55022 (1998). CISPR 22 (1990) . freq. IEC 61000-4-3 (1995). hum. Cl. pulse modulated 10 V/m. 3 (1988). 80% amplitude modulated 10 V/m.1-1989 EN 50263 (1996) 8 kV 6 kV 2/4 kV EN 61000-4-2.short duration Radio frequency interference test (RFI) 1. IEC 60255-21-2 (1988). U4.02 VA at IN = 1 A ≤0. Part 303 for 10 s for 1 s 30 x IN 100 x IN 1 half-cycle Burden per phase Voltages (optional) 250 x IN (50/60 Hz) (peak) ≤0. IEC 60068-2-27 (1987) EN 60255-21-2 (1996). IEC 60255-6 (1988). VDE 0435. IEC 60255-21-2 (1988). I6. I5. I7.1. 16. I3. IEEE 344-1987 EN 60255-21-2 (1996). 2 gn Cl. 16. I5. D = 11 ms. D = 16 ms. adjustable CT ratio via HMI500 4 x IN EN 60255-6 (1994). I3. I6/ I1.1.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. IEC 60255-6 (1988). IEC 60068-2-29 (1987) 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 Rated current (IN) Thermal ratings: continuous I1. part 303 Rated frequency (fN) 50 Hz. I4. U3. I4. IEEE 344-1987 EN 60255-21-1 (1996). I5. 60 Hz. VDE 0435. IEC 60255-21-1 (1988). I7. I4/ I1. U2. I2. I4. IEC 60255-21-3 (1995). I6. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 20 Technical data (cont´d) Table 5 Mechanical tests Vibration and shock Resonance investigation Permanent strength Seismic Shock test Bump test 2 to 150 Hz / 0. I2. U3/ U1.7 Hz adjustable via HMI500 . I2. IEC 60255-21-1 (1988) EN 60255-21-3 (1995). I8. I3. pulse/axis = 3 Cl. I3. I2. U5 100 V. U2. part 303 EN 60255-6 (1994). pulse/axis = 1000 EN 60255-21-1 (1996). I8/ I1. I9 1 A or 5 A by choice of terminals. IEC 60255-6 (1988).7 Hz 200 V.10 VA at IN = 5 A 1/ 3/ 5 input channels Rated voltage (UN) U1/ U1. VDE 0435. 50/60 Hz. A = 15 gn. 50/60 Hz VT ratio adjustable via HMI500 500BU03 Thermal ratings: continuous for 10 s Burden per phase Common data 2 x UN 3 x UN ≤0.5 gn 10 to 150 Hz / 1 gn 2 to 33 Hz. A = 10 gn.3 VA at UN EN 60255-6 (1994). CR16..1 A U < 250V DC ≤ 0. 500BU03 Signalling contacts CR05. operating voltage Max...3 A U < 250 V DC ≤ 0. Central unit) Binary outputs General Operating time Max.5 s Max.latched . continuous rating Max.04 A Binary inputs Number of inputs per bay unit Number of inputs for central unit Voltage range (Uoc) Pick-up current Operating time 20 optocouplers 9 groups with common terminal 12 optocouplers per binary I/O module (max.CR04. input voltage interruption during which output voltage maintained Frontplate signal Switch Redundancy of power supply >50 ms. IEC 60255-11 (1979). Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 21 Table 8 Binary inputs/outputs (Bay unit.automatic reset (delay 0. Part 303 green "standby" LED ON/OFF optional in bay and in central unit . CR07. make and carry for 0.60 s) Heavy-duty N/O contacts CR08.. CR06 . 2) 3 groups with common terminal 48 to 250 V DC Pick-up setting via HMI500 ≥10 mA <1 ms Table 9 Auxiliary supply Module type Bay unit Central unit Input voltage range (Uaux) ±25% Fuse Load Common data 48 to 250 V DC no fuse 11 W 48 to 250 V DC 10 A slow 100 W Max.CR07. programmable per output 3 ms (typical) ≤250 V AC/DC ≤8 A ≤30 A ≤3300 W .500CU03 Breaking current U < 50 V DC ≤ 0.5 A U < 120V DC ≤ 0.. making power at 110 V DC Binary output reset response.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.CR09 ..1 A U < 50 V DC ≤ 5 A U < 120 V DC ≤ 1 A U < 250 V DC ≤ 0.500CU03 Breaking current for (L/R = 40 ms) 1 contact U < 50 V DC ≤ 1.3 A 2 contacts in series Signalling contacts CR01... VDE 0435.. 500BU03 Heavy-duty N/O contacts CR01.5 A U < 120 V DC ≤ 0.. 10 mm2 0.10 mm2 0.5 .5 .5 . 9) approx.2.2 . 400-600 kg per cubicle Terminal type Connection data Solid Strand CTs VTs Power supply Tripping Binary I/Os Internal wiring gauges Phoenix URTK/S Phoenix URTK/S Phoenix UK 6 N Phoenix UK 10-TWIN Phoenix UKD 4-MTK-P/P 2.10 mm2 0.5 mm2 stranded 1.5 .5 mm2 0.5 mm2 stranded 1.2 .6 mm2 0.10 mm2 2 0.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 22 Technical data (cont´d) Table 10 Optical interfaces Number of cores Core/sheath diameter Max.5 μm optical fiber cables Table 11 Mechanical design Mounting Bay unit Central unit flush mounting on frames or in cubicles HMI integrated or separately mounted flush mounting on frames or in cubicles Table 12 Cubicle design Cubicle Standard type RESP97 (for details see 1MRB520159-Ken) 800 x 800 x 2200 mm (single cubicle) 1600 x 800 x 2200 mm (double cubicle) 2400 x 800 x 2200 mm (triple cubicle) *) Dimensions w x d x h *) largest shipping unit Total weight (with all units inserted) Terminals approx.5 .2 .5 .5 mm2 stranded 1.2 .5 mm2 stranded 0.4 mm CTs VTs Power supply Binary I/Os . length Connector 2 fiber cores per bay unit 62.6 mm2 0. permissible attenuation Max.5/125 μm (multi-mode) ≤5 dB (see Fig. 1200 m Type FST for 62.6 mm2 0.16 mm2 0. 15) Independent settings for pre-fault and post-fault period (min.Single connection point to REB500 central unit .Disturbance recording data 0..7 Hz) 2400 Hz (50 Hz) 2880 Hz (60 Hz) 1. voltage channels are recorded.Optical or electrical connection .Subset of binary events as specified in IEC Private range: Support of all binary events Generic mode: Support of all binary events .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.file. setting 200 ms). Server 2 as backup time .Time synchronization via SNTP: typical accuracy ± 1 ms .Trip reset command .Single connection point to REB500 central unit .Differential current of each protection zone .Export of ICD .5 s 6s 10 s 401 Hz (16. common address of ADSU .Two independent time servers are supported.Monitoring information from REB500 central unit and bay unit . trips and diagnostic) . if existing Table 15 Interbay bus protocols IEC 61850-8-1 IBB protocol IEC 61850-8-1 interbay bus supports .Trip reset command .Disturbance recorder data (via HMI500) IEC 60870-5-103 IBB protocol IEC 60870-5-103 interbay bus supports .Optical or electrical connection .Differential currents of each protection zone .. based on Substation Configuration Language SCL LON IBB protocol LON interbay bus supports .Time synchronization: typical accuracy ±1 ms ..7 Hz) 1200 Hz (50 Hz) 1440 Hz (60 Hz) 3s 12 s 20 s 600 Hz (50 Hz) 720 Hz (60 Hz) 6s 24 s 40 s Options 4 currents or 9 currents X X X 4 currents and 5 voltages X*) X X Standard Option 1 Option 2 Number of disturbance records = total recording time / set recording period (max.. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 23 Recording facilities Table 13 Event recorder Event recorder System events Protection events Test events Bay unit 100 total Central unit 1000 total Table 14 Disturbance recorder Analog channel Recording period Sample rate selectable 802 Hz (16.Disturbance recorder access via MMS file transfer protocol .Trip reset commands .255 (CAA) CAA per bay unit freely selectable Address setting of station address Sub address setting.Optical connection . Format: COMTRADE 91 and COMTRADE 99 *) in Standard.254 0.Time synchronization: typical accuracy ±5 ms .Binary events (signals.Binary events (signals. trips and diagnostic) . Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 24 Technical data (cont´d) Software modules Station level functions (Applicable for nominal frequencies of 50. for fN = 50.9 in steps of 0. tripping relays.7 Hz Table 17 Breaker failure protection (50BF) Measurement: Setting range Accuracy Timers: Setting range for timers t1: t2: Accuracy Remote trip pulse Reset ratio 10 to 5000 ms in steps of 10 ms 0 to 5000 ms in steps of 10 ms 0.1 to 2 x IN in steps of 0. for fN = 16.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. for fN = 50. 60 and 16.for fN = 16.2 <I/Isetting <20). 60 Hz 30 to 40 ms at Idiff/Ikmin ≥5 incl.7 Hz 50 to 10 000/1 A.1 to 2 x IN in steps of 0.2 <Ik/Ikmin <20).7 to 0. fault current pick-up setting (Ikmin) Neutral current detection Stabilizing factor (k) Differential current alarms current setting time delay setting Isolator alarm time delay Typical tripping time CT ratio per feeder Reset time 500 to 6000 A in steps of 100 A 100 to 6000 A 0. tripping relays. 60 Hz 45 to 159 ms (at 1.7 Hz) Table 16 Busbar protection (87B) Min.000 ms in steps of 100 ms 0.1 x IN ±5% ±5% 100 to 2000 ms in steps of 10 ms typically 80% Table 18 End-fault protection (51/62EF) Timer setting range Current setting range Reset ratio Reset time 100 to 10. 50 to 10 000/5 A.2 <Ik/Ikmin <20).5 to 90 s 20 to 30 ms at Idiff/Ikmin ≥5 incl. adjustable via HMI 30 to 96 ms (at 1. for fN = 50.1 IN 95% 17 to 63 ms (at 1. 60 Hz .05 5 to 50% x Ikmin in steps of 5% 2 to 50 s in steps of 1 s 0. 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. default 1500 ms 0.1 IN. Table 23 Check zone criterion (87CZ) Min. default 0. for fN = 50.2 UN to 1. 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. . fault current pick-up setting (Ikmin) Stabilizing factor (k) CT ratio per feeder 500 to 6000 A in steps of 100 A 0. the tripping command (“21110_TRIP”) is given independent of current (standard setting).05 Feeder 50 to 10 000/1 A.05 UN.0 UN in steps of 0.6 * Imax For feeders with single phase tripping and autoreclosure.0 IN in steps of 0.99 * Imax in steps of 0. 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.1 to 20 x IN in steps of 0.05 UN. 50 to 10 000/5 A.1 IN to 4.1 UN to 1.01* Imax to 0. Table 22 Voltage release criteria (27/59) U< Setting range (per feeder) U0> Setting range (per feeder) 0. default 0. It can be used as U< or U0> or in combination.1 IN. adjustable via HMI500 The check zone is used as an additional release criterion for busbar protection and operates zone-independent.7 UN 0.0 UN in steps of 0.01 * Imax.1 x IN 10 ms to 20 s in steps of 10 ms typically 95% 20 to 60 ms (at 1.2 IN 100 ms to 10000 ms in steps of 100 ms. default 0.2 <I/Isetting <20).0 IN in steps of 0. This value can be individually selected for each bay.1 IN to 2. Table 21 Current release criteria (51) Setting range (per feeder) 0.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 25 Table 19 Overcurrent protection (51) Characteristic Measurement: Setting range Setting range time delay Reset ratio Reset time 0.7 IN If the current release criteria is not activated. default 0. 60 Hz definite time Table 20 Breaker pole discrepancy protection (51/62PD) Setting range Time delay Discrepancy factor 0. default 0.2 UN If the voltage release criteria is not activated the tripping command (“21110_TRIP”) is given independent of voltage (standard setting).0 to 0.90 in steps of 0. 35 · In (I/IB) . AND gate 3.1.01 s yes/no Table 25 Logic • Logic for 4 binary inputs with the following 3 configurations: 1. IEC 60255-3 with extended setting range) normal inverse very inverse extremely inverse long time inverse or RXIDG characteristic t = k1 / ((I/IB)C .1 I2h/I1h 0. Bay level functions for Back-up/Main 2 REB500sys (Applicable for nominal frequencies of 50.01 s ±5% >94% (for max.1) c = 0.and undercurrent protection (51) • Over.and undercurrent detection • Single or three-phase measurement with detection of the highest. function) <106% (for min.01 IN 0. respectively lowest phase current • 2nd harmonic restraint for high inrush currents • 4 independent parameter sets Settings: Pick-up current Delay Accuracy of the pick-up setting (at fN) Reset ratio overcurrent undercurrent Max. OR gate 2. Bistable flip-flop with 2 set and 2 reset inputs (both OR gates). Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 26 Technical data (cont´d) Table 24 Delay/integrator • For delaying pick-up or reset or for integrating 1 binary signal • Provision for inverting the input • 4 independent parameter sets Settings: Pick-up or reset time Integration 0 to 300 s in steps of 0.8 . 142. resetting takes priority • 4 independent parameter sets. function) 60 ms optional 0. to B.S.8 Table 27 Inverse time overcurrent protection (51) • Single or three-phase measurement with detection of the highest phase current • 4 independent parameter sets Inverse time characteristic (acc.2 to 20 IN in steps of 0. operating time without intentional delay Inrush restraint pick-up setting reset ratio 0.02 to 60 s in steps of 0. Provision for inverting all inputs.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. All configurations have an additional blocking input. 60 Hz) Table 26 Definite time over.02 c=1 c=2 c=1 t = 5. IEC 60255-3 with extended setting range) normal inverse very inverse extremely inverse long time inverse or RXIDG characteristic Settings: Number of phases Base current IB Pick-up current Istart Min. 142.02 c=1 c=2 c=1 t = 5.01 s E 5.0 ±4% (1 .01 to 2.01 IB 0 to 10 s in steps of 0.S.I/80 IB) 95% . function) <104% (for min.01 s E 5. to B.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.1 s 0.35 · In (I/IB) 1 or 3 0.1.01 IN 1 to 4 IB in steps of 0. time setting tmin k1 setting Accuracy classes for the operating time according to B.5 IN in steps of 0.01 to 200 s in steps of 0.04 to 2.01 IB 0 to 10 s in steps of 0.8 .1 s 0.5 IN in steps of 0.and undervoltage protection (59/27) • Over.1) c = 0.0 ±4% (1 . 142. time setting tmin k1 setting Accuracy classes for the operating time according to B.1 UN) overvoltage undervoltage Max.S. IEC 60255-3 RXIDG characteristic Reset ratio t = k1 / ((I/IB)C .02 to 60 s in steps of 0.and undervoltage detection • Single or three-phase measurement with detection of the highest. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 27 Settings: Number of phases Base current IB Pick-up current Istart Min.01 UN 0.005 UN >96% (for max.I/80 IB) 95% Table 28 Definite time over. operating time without intentional delay 0. IEC 60255-3 RXIDG characteristic Reset ratio 1 or 3 0. 142.01 to 200 s in steps of 0. respectively lowest phase voltage • 4 independent parameter sets Settings: Pick-up voltage Delay Accuracy of the pick-up setting (at fN) Reset ratio (U ≥ 0.0 UN in steps of 0.01 IN 1 to 4 IB in steps of 0.01 s ±2% or ±0.04 to 2.S. function) 60 ms Table 29 Inverse time earth fault overcurrent protection (51N) • Neutral current measurement (derived externally or internally) • 4 independent parameter sets Inverse time characteristic (acc. 02 to 60 s in steps of 0.97…1.5°/Hz 60 ms Table 31 Directional overcurrent inverse time protection (67) • Directional overcurrent protection with detection of power flow direction • Back-up for distance protection • 4 independent parameter sets • Three-phase measurement • Suppression of DC and HF components • Inverse time characteristic • Voltage memory for near faults • Selectable response when power direction no longer valid (trip or block) Settings: Current Angle Inverse time characteristic (acc.01 IN 0.02 to 20 IN in steps of 0.1) c = 0.01 IN -180° to +180° in steps of 15° 0. IEC 60255-3 with extended setting range) normal inverse very inverse extremely inverse long time inverse t-min IB-value Wait time Memory duration 1 to 4 IN in steps of 0.2 to 60 s in steps of 0.04 to 2.2 to 60 s in steps of 0.01 IN -180° to +180° in steps of 15° t = k1 / ((I/IB)C . harmonic Accuracy of pick-up value Reset ratio Accuracy of angle measurement (at 0. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 28 Technical data (cont´d) Table 30 Directional overcurrent definite time protection (67) • Directional overcurrent protection with detection of power flow direction • Back-up protection • 4 independent parameter sets • Three-phase measurement • Suppression of DC and HF components • Definite time characteristic • Voltage memory for near faults • Selectable response when power direction no longer valid (trip or block) Settings: Current Angle Delay Wait time Memory duration Accuracies: Measuring accuracies are defined by: • Frequency range 0.5 IN in steps of 0. and 9.005 to 2 UN <0.01 s 0. 7.01 s 0.9…1.01 s 0..02 c=1 c=2 c=1 0 to 20 in steps of 0..ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. to B.02 to 20 s in steps of 0. 5.05 fN • Sinusoidal voltage including 3.03 fN) • Voltage input range • Voltage memory range • Accuracy of angle measurement at voltage memory • Frequency dependence of angle measurement at voltage memory • Response time without delay 0.01 s ±5% 95% ±5° 0. 142.01 0.01 s .02 to 20 s in steps of 0.005 UN ±20° ±0.S. 5°/Hz 60 ms 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 Reference value of the power SN Characteristic angle Phase error compensation of current input Delay Reset ratio Accuracy of the pick-up setting Max.2 UN in steps of 0.01 0.05 IN -2.005 UN ±20° ±0.97…1.1 s 0.1 SN in steps of 0.05 to 60 s in steps of 0.2 UN ≥90% whole range >95% (at U > 0.005 to 0.05 UN -2.1 UN or I > 0.01 s 30 to 95% in steps of 1% ±10% of setting or 2% UN · IN (for protection CTs) ±3% of setting or 0.00 to +2.005 to 2 UN <0.1 to 60 s in steps of 0.2 IN ±2% UN in the range 0.1 s ±2% IN in the range 0.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.00 in steps of 0.05 fN Accuracy of pick-up value Reset ratio Accuracy of angle measurement (at 0.01° 0.00 to +2.00 IN in steps of 0.5 UN · IN in steps of 0.00 in steps of 0.2 to 1.01° -5° to +5° in steps of 0.2 to 1.01 0.03 fN) • Voltage input range • Voltage memory range • Accuracy of angle measurement at voltage memory • Frequency dependence of angle measurement at voltage memory • Response time without delay ±5% 95% ±5° 0.001 SN 0.1 IN) .05 to 1.001 UN · IN -180° to +180° in steps of 0. operating time without intentional delay 0.1 to 60 s in steps of 0. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 29 Accuracies: Measuring accuracies are defined by: • Frequency range 0.9…1.05 to 1.5 to 2.5% UN · IN (for measuring CTs) 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: • Determination of the sum and phase sequence of the 3 phase currents or voltages • 4 independent parameter sets Accuracy of the pick-up setting at rated frequency Reset ratio Current plausibility settings: Pick-up differential for sum of internal summation current Amplitude compensation for summation CT Delay Voltage plausibility settings: Pick-up differential for sum of internal summation voltage Amplitude compensation for summation VT Delay 0. 01.01 IN 0.01 s -999 to 999 Ω/ph in steps of 0.5 to 10 IN in steps of 0.frequency fluctuations of +10% . operating current Back-up overcurrent Neutral current criterion Neutral voltage criterion Low-voltage criterion for detecting.01 UN 0. every zone can be set independently of the others • 4 independent parameter sets Impedance measurement Zero-sequence current compensation Mutual impedance for parallel circuit lines Time step setting range Underimpedance starters Overcurrent starters Min.01 IN 0 to 10 IN in steps of 0.01 IN 0.01 UN 0 to 2 UN in steps of 0.0 IN in steps of 0.01. -90° to +90° in steps of 1° 0 to 10 s in steps of 0.01 to 0. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 30 Technical data (cont´d) Table 34 Directional sensitive earth fault protection for grounded systems (67N) • Detection of high-resistance earth faults • Current enabling setting 3I0 • Direction determined on basis of neutral variables (derived externally or internally) • Permissive or blocking directional comparison scheme • Echo logic for weak infeeds • Logic for change of energy direction • 4 independent parameter sets Settings: Current pick-up setting Voltage pick-up setting Characteristic angle Delay Accuracy of the current pick-up setting 0.1 ±2° for U/UN >0.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. a weak infeed VT supervision NPS/neutral voltage criterion NPS/neutral current criterion Accuracy (applicable for current time constants between 40 and 150 ms) amplitude error phase error Supplementary error for .1 to 2 IN in steps of 0.003 to 1 UN in steps of 0.5 IN in steps of 0.001 s ±10% of setting Table 35 Distance protection (21) • Five measuring stages with polygonal impedance characteristic forward and backward • All values of settings referred to the secondaries.1 to 1.01 IN 0 to 2 UN in steps of 0.10% fifth harmonic Operating times of the distance protection function (including tripping relay) minimum typical (see also isochrones) Typical reset time VT-MCB auxiliary contact requirements Operation time -300 to 300 Ω/ph in steps of 0.1 ±5% ±10% ±10% 20 ms 25 ms 25 ms <15 ms Remark: Distance protection operating times on next page .1 Ω/ph 0.01 IN 0.5 UN in steps of 0.01 UN 0. for example.001 UN -90° to +90° in steps of 5° 0 to 1 s in steps of 0.10% third harmonic .01 to 0.1 to 2 IN in steps of 0. -180° to +90° in steps of 1° 0 to 8 in steps of 0.01 IN ±5% for U/UN >0.01 Ω/ph 0 to 8 in steps of 0. 6 0.6 0.8 ZF/ZL 32ms 0.2 0 0.6 0.2 0 0.8 ZF/ZL ZF/ZL 0. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 31 Distance protection operating times Isochrones Single phase fault (min) 1 0.2 29ms 0 100 1000 0.4 0.1 1 10 SIR (ZS/ZL) 100 1000 Three phase fault (min) 1 0.1 1 10 SIR (ZS/ZL) 100 1000 18ms 17ms 18ms Single phase fault (max) 1 0.4 0.2 0 0.1 1 10 SIR (ZS/ZL) 100 1000 Abbreviations: ZS = source impedance ZF = fault impedance ZL = zone 1 impedance setting .4 0.4 0.1 1 10 SIR (ZS/ZL) 100 1000 29ms 31ms Two phase fault (min) 1 0.4 0.1 1 10 SIR (ZS/ZL) 17ms 18ms 0.6 0.8 ZF/ZL 19ms Two phase fault (max) 1 0.2 29ms 33ms 0.1 1 10 SIR (ZS/ZL) 17ms 18ms 0 100 1000 0.2 0 0.8 0.6 0.8 ZF/ZL ZF/ZL 20ms Three phase fault (max) 1 0.4 0.8 0.6 0.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 05 UN 0.05 to 300 s 0.05 to 300 s 0. voltage Supervision time Resetting time Accuracy Voltage difference Phase difference Frequency difference 0.05 Hz 0.05 to 300 s 0.1 fN ±5% UN ±5° ±0.05 s for 0.05 Hz .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.05 s 0 to 1 s in steps of 0. signal Dead times for 2nd.05 UN 5 to 80° in steps of 5° 0.1P reclosure 1P fault .05 to 300 s 0.05 to 300 s 0.05 to 300 s 0. phase difference Max. The differences between the amplitudes.01 s 2nd to 4th reclosure Single phase dead time Three-phase dead time Dead time extension by ext. duplex and master/follower schemes • Up to four fast or slow reclosure shots • Detection of evolving faults • 4 independent parameter sets Settings: 1st reclosure none 1P fault .1P/3P reclosure none two reclosure cycles three reclosure cycles four reclosure cycles 0.05 UN 0.05 to 0. frequency difference Min. phase-angles and frequencies of two voltage vectors are determined. • Voltage supervision Single or three-phase measurement Evaluation of instantaneous values and therefore wider frequency range Determination of maximum and minimum values in the case of three-phase inputs • Phase selection for voltage inputs • Provision for switching to a different voltage input (double busbar systems) • Remote selection of operating mode • 4 independent parameter sets Settings: Max.3P reclosure 1P/3P fault . Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 32 Technical data (cont´d) Table 36 Autoreclosure (79) • Single and three-phase autoreclosure • Operation in conjunction with distance. voltage Max.4 UN in steps of 0.9 to 1.6 to 1 UN in steps of 0. overcurrent and synchrocheck functions and also with external protection and synchrocheck relays • Logic for 1st and 2nd main protections.4 Hz in steps of 0.1 to 300 s All settings in steps of 0.1 to 1 UN in steps of 0.3P reclosure 1P/3P fault .05 to 300 s 0.05 to 0.05 to 5 s in steps of 0. voltage difference Max. 3rd and 4th reclosures Fault duration time Reclaim time Blocking time Single and three-phase discrimination times Table 37 Synchrocheck (25) • Determination of synchronism Single phase measurement. 5 IN in steps of 0.8 g-setting Differential protection characteristic IΔ IN IΔ = ⎢I1+ I2 + I3 ⎢ ⎧ I' ⋅I' ⋅ cosα ⎪ IH = ⎨ 1 2 ⎪0 ⎩ for cos α ≥ 0 for cos α < 0 3 Operation for I'1 <b IN or I'2 <b IN Operation 2 1 I'1 = MAX (I1.for IΔ ≤2 IN Accuracy of pick-up value Reset conditions Accuracy of pick-up value Reset conditions Differential protection definitions: 0.I'2) v g 1 b 2 Restraint 3 IH IN I1 Protected unit I2 I3 HEST 965 007 C Table 39 Thermal overload (49) • Thermal image for the 1st order model • Single or three-phase measurement with detection of maximum phase value Settings: Base current IB Alarm stage Tripping stage Thermal time constant Accuracy of the thermal image 0.1 min ±5% ϑN (at fN) ..5 or 0.01 IN 50 to 200% ϑTN in steps of 1% ϑN 50 to 200% ϑN in steps of 1% ϑN 2 to 500 min in steps of 0. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 33 Table 38 Transformer differential protection (87T) • For two.7 1.5 to 2.8 g-setting ±5% IN (at fN) IΔ <0.5 IN in steps of 0.25 to 2.05 IN 0.for IΔ >2 IN .1 to 0. I3) I'2 = I1 + I2 + I3 . I2. trip time (protected transformer loaded) .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.and three-winding transformers • Three-phase function • Current-adaptive characteristic • High stability for external faults and current transformer saturation • No auxiliary transformers necessary because of vector group and CT ratio compensation • Inrush restraint using 2nd harmonic Settings: g-setting v-setting b-setting Max.25 or 0.25 IN ≤30 ms ≤50 ms ±5% IN (at fN) IΔ <0.5 in steps of 0.I'1 α = ∠(I'1. 01 to 2 UN in steps of 0.04 to 1.01 Hz 0. function) ≤30 ms (for max. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 34 Technical data (cont´d) Table 40 Peak value over.1 UN ±30 mHz at UN and fN 100% <130 ms .02 IN >90% (for max. function) <110% (for min.1 to 20 IN in steps of 0.08 to 1.and undervoltage) • Single or three-phase measurements • Peak value evaluation Settings: Voltage Delay Limiting fmin Accuracy of pick-up value (at 0. trip time with no delay (at fN) 0.2 to 0.and underfrequency) • Minimum voltage blocking Settings: Frequency Delay Minimum voltage blocking Accuracy of pick-up value Reset ratio Starting time 40 to 65 Hz in steps of 0.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. function) Table 41 Peak value over.01 s 0.8 UN in steps of 0.1 IN 0 to 60 s in steps of 0.2 fN) • Peak value evaluation Settings: Current Delay Accuracy of pick-up value (at 0.01 UN 0 to 60 s in steps of 0.005 UN >90% (for max.1 to 60 s in steps of 0.08 to 1.1 fN) Reset ratio Max. function) ≤60 ms (for min. function) <110% (for min. function) ≤60 ms (for min.01s ±5% or ±0.1 fN) Reset ratio Max.and undervoltage protection (59) • Maximum or minimum function (over.01 s 25 to 50 Hz in steps of 1 Hz ±3% or ±0. function) Table 42 Frequency function (81) • Maximum or minimum function (over. function) ≤30 ms (for max. trip time with no delay (at fN) 0.and undercurrent) • Single or three-phase measurements • Wide frequency range (0.and undervoltage protection (50) • Maximum or minimum function (over. 01 UN/fN 0.05 to 1.2 UN in steps of 0.01 Hz at fN = 60 Hz 0.2 UN in steps of 0.05 fN) Reset ratio -10 to +10 Hz/s in steps of 0. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 35 Table 43 Rate of change frequency protection df/dt (81) • Maximum or minimum function (over. 1.1 min 0.91-1985 • Setting made by help of table settings Settings: Table settings Start value U/f tmin tmax Reference voltage UB-value Accuracy of pick-up value Frequency range Reset ratio Starting time U/f values: (1.20 UN/fN in steps of 0.2 fN 100% <120 ms .01 to 2 min in steps of 0.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure.5 to 1.01 UN 0.2 to 2 UN/fN in steps of 0.50) UN/fN 1.05.01 UN 0.and underfrequency) • Minimum voltage blocking Settings: df/dt Frequency Delay Minimum voltage blocking Accuracy of df/dt (at 0.5 to 1. <102% (min.05 fN) Accuracy of frequency (at 0.1 Hz/s ±30 mHz 95% for max.01 Hz at fN = 50 Hz 50 to 65 Hz in steps of 0.1 to 60 s in steps of 0.9 to 1.) ≤120 ms Table 45 Inverse time overfluxing protection (24) • Single-phase measurement • Inverse time delay according to IEEE Guide C37.8 to 1.9 to 1.01 s 0.1 UN ±0.2 fN ±3% or ±0.01 min 5 to 100 min in steps of 0.2 to 0.1 Hz/s 0 to 55 Hz in steps of 0.8 to 1.1 to 60 s in steps of 0.). function Table 44 Definite time overfluxing protection (24) • Single-phase measurement • Minimum voltage blocking Settings: Pick up value Delay Frequency range Accuracy (at fN) Reset ratio Starting time 0.10 to 1.01 UN/fN >98% (max.01 UN/fN 0.01 s 0. function 105% for min.8 UN in steps of 0. ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. (Phi) Rated power PN Reset ratio Accuracy of the pick-up setting -0.2 SN in steps of 0.001 UN × IN 30% to 170% in steps of 1% of power pick-up ±10% of setting or 2% UN × IN (for protection CTs) ±3% of setting or 0.5% UN × IN (for core-balance CTs) 70 ms Max.5 to 2. operating time without intentional delay .and underpower • Single or three-phase measurement • Suppression of DC components and harmonics in current and voltage • Compensation of phase errors in main and input CTs and VTs Settings: Power pick-up Characteristic angle Delay Power factor comp.01 s -5° to +5° in steps of 0.1 to 1.005 PN -180° to +180° in steps of 5° 0. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 36 Technical data (cont´d) Table 46 Power protection (32) • Measurement of real or apparent power • Protection function based on real or apparent power measurement • Reverse power protection • Over.5 UN × IN in steps of 0.05 to 60 s in steps of 0.1° 0. 5 mm2 .5 mm2 1. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 37 Connection diagrams Inputs / outputs central unit Optional I/O board Binary inputs Binary outputs Binary inputs Binary outputs 500BIO01 500BIO01 Optional redundant power supply 1 2 3 4 5 6 1 2 3 4 5 6 1 2 aux Alarm 1 2 aux Alarm Warning Warning 500PSM03 500PSM03 Fig. 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. Connection of power supply.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 11 Central unit module. 5 mm2 FST plug FST plug 2. classic-mounting) 500BU03_1 (4 I. 20/16 I/O. 5 U. 5 U.5 mm2 B D 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 I4[1] I4[5] I4[0] I5[1] I5[5] I5[0] I6[1] I6[5] I6[0] I7[1] I7[5] I7[0] I8[1] I8[5] I8[0] I9[1] I9[5] H I9[0] HMI 1 2 3 4 5 6 7 8 9 10 11 12 I1[1] I1[5] I1[0] I2[1] I2[5] I2[0] I3[1] I3[5] I3[0] 1 2 3 4 5 6 7 8 9 10 11 12 I1[1] I1[1] I1[5] I1[5] I1[0] I1[0] I2[1] I2[1] I2[5] I2[5] I2[0] I2[0] I3[1] I3[1] I3[5] I3[5] I3[0] I3[0] I4[1] I4[1] I4[5] I4[5] I4[0] I4[0] B D H HMI Abbreviations OCxx CRxx OLxx Explanation Opto-coupler Tripping relay Optical link DC DC I 0 R + - I 0 P + - I 0 R + - I 0 P + - 500BU03 500BU03 Binary Inputs Processbus Tx E OL01 Rx A J 1 Current Transformer 1 I 1 Current Transformer 1 U 1 Voltage Transformer I 1 Current Transformer 1 1 2 OC01 OC02 5 3 4 5 OC03 6 OC04 7 8 9 OC05 10 11 12 13 14 15 OC06 2 0 I4 5 2 0 I1 0 U1 2 5 2 0 I1 3 3 1 1 3 1 Binary Outputs 1 CR01 2 3 4 CR02 5 6 7 CR03 8 9 C 4 5 4 5 4 4 U2 0 5 5 0 I5 5 0 I2 5 5 0 I2 6 1 6 1 6 1 7 5 7 5 7 7 U3 0 5 8 0 I6 8 0 I3 8 8 0 I3 OC07 9 1 9 9 1 OC08 10 CR04 11 12 13 CR06 OC10 OC11 CR07 14 15 1 16 CR05 17 18 OC09 10 5 10 10 U4 0 5 11 0 I7 11 11 0 I4 *) B 1 2 3 4 5 6 7 8 12 12 13 OC12 1 2 CR08 OC13 OC14 OC15 CR09 CR10 5 6 7 CR11 OC16 OC17 CR12 CR13 8 9 10 11 12 OC19 OC20 CR16 15 CR14 CR15 13 14 3 4 1 13 5 D 14 0 I8 0 U5 14 15 16 5 H I9 0 HMI Interface H HMI Interface 9 10 11 12 13 OC18 14 15 16 17 18 17 18 Redundant Power Supply Power Supply Redundant Power Supply Power Supply R 1 2 + _ P 1 2 + _ R 1 2 + _ P 1 2 + _ *) 1 Measuring transformer in 500BU03_5 or 500BU03_6 Fig. 20/16 I/O. power supply 500BU03_8 (9 I. B C. classic-mounting) red.5 mm2 1. 20/16 I/O. 1MT. classic-mounting) 500BU03_7 (9 I. 20/16 I/O.5 mm2 1.5 mm2 1. stand-alone) red. power supply 500BU03_5 (3 I. stand-alone) 500BU03_2 (4 I. stand-alone)red. 5 U. 5 U. classic-mounting) red. power supply Available inputs/outputs E Tx A Rx Tx Rx C J I E Tx A Rx Tx Rx C U1 U1[0] U2 U2[0] U3 U3[0] U4 U4[0] U5 U5[0] U I Terminal block/ terminals A. 5 U. 5 U. 1MT. 20/16 I/O. 5 U.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 20/16 I/O. power supply 500BU03_5 (3 I. 20/16 I/O. stand-alone) 500BU03_1 (4 I. 20/16 I/O. classic-mounting) 500BU03_6 (3 I. stand-alone) 500BU03_6 (3 I. 12 Wiring diagram of bay units 500BU03. D E Rx Tx I. 1MT. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 38 Connection diagrams (cont´d) Bay unit types 500BU03_4 (4 I. power supply 500BU03_4 (4 I. 20/16 I/O. classic-mounting) red. 1MT. stand-alone) red. 20/16 I/O. 20/16 I/O. stand-alone) 500BU03_7 (9 I. 20/16 I/O. 5 U. classic-mounting) 500BU03_2 (4 I. 20/16 I/O. 20/16 I/O. power supply 500BU03_8 (9 I. R Function Binary inputs Binary outputs Optical connection Receive Transmit Currents Voltages Supply Wire gauge/ Type 1. types 1-8 . J U P. power supply Available inputs/outputs Terminal block/ terminals A. stand-alone) red. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 39 Bay unit types 500BU03_10 (8 I. 1U. 3 U.5 mm2 2 E Tx A Rx Tx Rx C J I E Tx A Rx Tx Rx C J I B Abbreviations OCxx CRxx OLxx Explanation Opto-coupler Tripping relay Optical link D 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 I4[1] I4[5] I4[0] I5[1] I5[5] I5[0] I6[1] I6[5] I6[0] U1 U1[0] 1 2 3 4 5 6 7 8 9 10 11 12 I1[1] I1[5] I1[0] I2[1] I2[5] I2[0] I3[1] I3[5] I3[0] U2 U2[0] U3 U3[0] H HMI B D 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 I4[1] I4[5] I4[0] I5[1] I5[5] I5[0] I6[1] I6[5] I6[0] I7[1] I7[5] I7[0] I8[1] I8[5] I8[0] U1 U1[0] H 1 2 3 4 5 6 7 8 9 10 11 12 I1[1] I1[5] I1[0] I2[1] I2[5] I2[0] I3[1] I3[5] I3[0] HMI DC DC I 0 R + - I 0 P + - I 0 R + - I 0 P + - 500BU03 500BU03 Binary Inputs Processbus Tx E OL01 Rx A J 1 Current Transformer 1 I 1 Current Transformer 1 J 1 Voltage Transformer 1 I 1 Current Transformer 1 1 2 OC01 OC02 5 3 4 5 OC03 6 OC04 7 8 9 OC05 10 11 12 13 14 15 OC06 2 0 I4 5 2 0 I1 5 5 2 0 I4 2 0 I1 3 3 1 1 3 1 3 1 Binary Outputs 1 CR01 2 3 4 CR02 5 6 7 CR03 8 9 C 4 5 4 5 4 4 5 5 0 I5 5 0 I2 5 5 0 I5 5 0 I2 6 1 6 1 6 1 6 1 7 5 7 5 7 5 7 5 8 0 I6 8 0 I3 8 0 I6 8 0 I3 OC07 9 9 9 1 9 OC08 10 CR04 11 12 13 CR06 OC10 OC11 CR07 0 16 CR05 17 18 OC09 10 U1 11 10 5 11 0 I7 B 1 2 3 4 5 6 7 8 14 15 12 1 13 OC12 1 2 0 13 D U2 14 14 15 5 I8 0 CR08 OC13 OC14 OC15 CR09 CR10 3 4 5 6 7 16 U3 0 H HMI Interface 16 U1 0 H HMI Interface 9 10 11 12 OC17 13 OC18 14 15 16 17 18 OC19 OC20 CR16 CR14 CR15 CR11 OC16 CR12 CR13 8 9 10 11 12 13 14 15 17 17 Redundant Power Supply Power Supply Redundant Power Supply Power Supply R 1 2 + _ P 1 2 + _ R 1 2 + _ P 1 2 + _ Fig. stand-alone) red.5 mm2 FST plug FST plug 2. 3 U.5 mm2 1. 1U. 3 U. 1U. 20/16 I/O. classic-mounting) red. 20/16 I/O. power supply 500BU03_11 (6 I. D E Rx Tx I J P. 20/16 I/O. power supply 500BU03_11(6 I.5 mm 1. 1U.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 13 Wiring diagram of bay units 500BU03. stand-alone) 500BU03_ 9 (8 I. 20/16 I/O. R Function Binary inputs Binary outputs Optical connection Receive Transmit Currents Currents and voltages Supply Wire gauge/ Type 1. power supply 500BU03_10 (8 I. stand-alone) 500BU03_12 (6 I. 3 U. 20/16 I/O. 20/16 I/O. classic-mounting) 500BU03_ 9 (8 I. types 9-12 . 20/16 I/O. classic-mounting) red. B C. classic-mounting) 500BU03_12 (6 I. 20/16 I/O. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 40 Connection diagrams (cont´d) Bay unit 500BU03 connection diagrams A detailed description of each variant is given in the application description [3]. or comp.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 4I. for grounded systems Directional overcurrent definite time protection Directional overcurrent inverse time protection Measurement value Definite time over and undervoltage protection Inverse time earth fault overcurrent protection Definite time over and undercurrent protection Inverse time overcurrent protection Pole discrepancy protection Currents 1 1 2 5 3 0 4 1 5 5 6 0 7 1 8 5 9 0 10 1 11 5 12 0 Voltage plausibility check Current plausibility check Breaker failure protection Disturbance recorder End fault protection Distance protection Busbar protection Synchrocheck Voltage check Analog inputs I1 Phase current L1 (Line) Phase current L2 (Line) Phase current L3 (Line) Neutral current Lo (Y) (Line) Neutral current derrived internally Io=Σ IL1+IL2+IL3 I2 I3 I4 Derived internally Voltages 1 U1 2 0 4 Phase voltage L1 (Line) Phase voltage L2 (Line) Phase voltage L3 (Line) Phase voltage L2 (Bus 1) 1ph -> L2-E Phase voltage L2 (Bus 2) 1ph -> L2-E Neutral voltage derrived internally Uo=Σ UL1+UL2+UL3 U2 5 0 7 U3 8 0 10 U4 11 0 13 U5 14 0 Derived internally 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 Fig. 14 Bay unit connection diagram 500BU03. 5U . sensitive EF prot. for ungr. system Direct. sensitive EF prot. Bay unit 500BU03 Protection functions Station level Bay level Direct. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 41 Bay unit 500BU03 Protection functions Station level Bay level Inverse time earth fault overcurrent protection Definite time over and undercurrent protectio Peak value over and undercurrent protection Measurement value Inverse time overcurrent protection Transformer differential protection Currents 1 1 I 2 5 3 0 4 1 5 5 6 0 7 1 8 5 9 0 Three phase current plausibility Pole discrepancy protection Breaker-failure protection Disturbance recorder End-fault protection Busbar protection Thermal overload Analog inputs I1 Phase current L1 A-side Phase current L2 A-side Phase current L3 A-side Neutral current derrived internally Io=Σ IL1+IL2+IL3 I2 I3 Derived internally Currents 1 1 J 2 5 3 0 4 1 5 5 6 0 7 1 8 5 9 0 I4 Phase current L1 B-side Phase current L2 B-side Phase current L3 B-side Neutral current derrived internally Io=Σ IL1+IL2+IL3 I5 I6 Derived internally Currents 10 1 J 11 5 12 0 13 1 14 5 15 0 16 1 17 5 18 0 I7 Phase current L1 C-side (if existing) Phase current L2 C-side (if existing) Phase current L3 C-side (if existing) Neutral voltage derrived internally Uo=Σ UL1+UL2+UL3 I8 I9 Derived internally Current transformer. or on B-side or on C-side respectively A-side Transformer primary side B-side Transformer secondary side C-side Transformer tertiary side Fig. 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. 15 Bay unit connection diagram 500BU03. 9I .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 3U .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. sensitive EF prot. 6I. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 42 Connection diagrams (cont´d) Bay Unit 500BU03 Protection functions Station level Bay level Directional overcurrent definite time protection Directional overcurrent inverse time protection Definite time over and undervoltage protection Definite time over and undercurrent protection Direct. 16 Bay unit connection diagram 500BU03. or on B-side respectively A-side Transformer primary side B-side Transformer secondary side Fig. for grounded system Inverse time earth fault overcurrent protection Peak value over and undervoltage protection Peak value over and undercurrent protection Measurement value Rate of change frequency protection Definite time overfluxing protection Inverse time overcurrent protection Inverse time overfluxing protection Transformer differential protection Three phase voltage plausibility Three phase current plausibility Pole discrepancy protection Breaker failure protection Disturbance recorder End fault protection Distance protection Busbar protection Thermal overload Analog inputs Frequency Currents 1 1 I 2 5 3 0 4 1 5 5 6 0 7 1 8 5 9 0 Power Phase current L1 A-side Phase current L2 A-side Phase current L3 A-side Neutral current derrived internally Io=Σ IL1+IL2+IL3 Phase current L1 B-side Phase current L2 B-side Phase current L3 B-side Neutral current derrived internally Io=Σ IL1+IL2+IL3 Phase voltage L1 A-side or B-side Phase voltage L2 A-side or B-side Phase voltage L3 A-side or B-side Neutral voltage derrived internally Uo=Σ UL1+UL2+UL3 I1 I2 I3 Derrived internally Currents 1 1 J 2 5 3 0 4 1 5 5 6 0 7 1 8 5 9 0 I4 I5 I6 Derrived internally Voltages 10 J U1 11 0 13 U2 14 0 16 U3 17 0 Derrived internally 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. 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. Lo) Current Lx (e.g. 17 Bay unit connection diagram 500BU03. 1U .g.g.Lo) I8 Voltages 16 J U1 17 0 Voltage Lx (e. 8I. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 43 Bay Unit 500BU03 Protection functions Station level Bay level Definite time over and undercurrent protection Inverse time earth fault overcurrent protection Peak value over and undercurrent protection Measurement value Definite time overfluxing protection Inverse time overcurrent protection Currents 1 1 I 2 5 3 0 4 1 5 5 6 0 7 1 8 5 9 0 Inverse time overfluxing protection Transformer differential protection Three phase current plausibility Pole discrepancy protection Breaker failure protection Disturbance recorder End fault protection Busbar protection Thermal overload Analog inputs I1 Phase current L1 A-side Phase current L2 A-side Phase current L3 A-side Neutral current derrived internally Io=Σ IL1+IL2+IL3 I2 I3 Derrived internally Currents 1 1 J 2 5 3 0 4 1 5 5 6 0 7 1 8 5 9 0 I4 Phase current L1 B-side Phase current L2 B-side Phase current L3 B-side Neutral current derrived internally Io=Σ IL1+IL2+IL3 I5 I6 Derrived internally Currents 10 1 J 11 5 12 0 13 1 14 5 15 0 I7 Current Lx (e. or on B-side respectively A-side Transformer primary side B-side Transformer secondary side Fig.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. trip coil 1 Trip Phase L3.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 44 Connection diagrams (cont´d) REB500: Typical assignment of the in/outputs Binary inputs Accept bus image alarm External reset Block of all protection functions Block output relays 1 OC01 Binary outputs 1 2 2 OC02 CR01 3 OC03 3 4 5 6 Protection blocked / Output relays blocked Test generator active Isolator alarm Switch inhibited CR02 CR03 4 OC04 5 6 Block busbar protection Block breaker failure protection CR04 7 OC05 7 8 8 OC06 CR05 9 10 System alarm 9 OC07 11 10 OC08 11 12 CR06 12 In service 13 13 OC09 14 15 14 OC10 CR07 CR08 CR09 16 Differential current alarm 17 Busbar protection tripped 18 Breaker failure protection tripped 15 OC11 16 OC12 17 18 Fig. trip coil 1 Bus 2 Isolator Q2 on OC16 OC17 OC18 12 13 14 15 16 17 18 CR14 CR15 CR16 13 14 15 Trip Phase L1. trip coil 2 Trip Phase L3. trip coil 2 OC19 OC20 Fig. trip coil 1 Trip Phase L2. 18 REB500: Typical assignment of the in/outputs of a central unit for busbar and breaker failure protection Binary Inputs 1 Binary outputs C CR01 1 2 3 4 Start BFP protection 1 L1 Start BFP protection 1 L2 OC01 OC02 A 2 3 4 In Service Start BFP protection 1 L3 rt BFP protection 1 L1L2L3 5 6 7 8 OC03 OC04 CR02 5 6 7 Block close command CR03 OC05 OC06 8 9 10 Start BFP protection 2 L1 10 Start BFP protection 2 L2 11 12 9 CR04 CR05 OC07 OC08 11 12 13 Remote Trip. channel 2 OC09 D B CR08 CR09 CR10 1 2 OC10 OC11 OC12 3 4 5 6 7 Bus 1 Isolator Q1 off Bus 1 Isolator Q1 on Bus 2 Isolator Q2 off 7 8 9 10 11 OC13 OC14 OC15 CR11 CR12 CR13 8 9 10 11 12 Trip Phase L1. channel 1 Start BFP protection 2 L3 t BFP protection 2 L1L2L3 13 14 15 16 17 18 1 2 3 4 5 6 CR06 CR07 14 15 Remote Trip. 19 REB500: Typical assignment of the in/outputs for a double busbar with busbar and breaker failure protection of a bay unit . trip coil 2 Trip Phase L2. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 45 REB500sys: Typical assignment of the in-/outputs Binary Inputs Variant L-V4 1 Binary outputs Variant L-V4 A Start BFP protection 1 L1 Start BFP protection 1 L2 OC01 OC02 2 3 4 C CR01 1 2 3 4 In Service Start BFP protection 1 L3 Start BFP protection 1 L1L2L3 5 6 7 8 OC03 OC04 CR02 5 6 7 Block close command Carrier Receive. 20 REB500sys: Typical assignment of the in-/outputs of line variant L-V4 for 500BU03 (See [3] Application description) . AR) 16 17 18 OC19 OC20 Fig. DEF Prot. Remote Trip.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. DEF Prot. trip coil 2 Trip Phase L2.from Main1 Main 1 Healthy/In Service Mode (Blk. 11 12 9 CR03 OC05 OC06 8 9 10 AR Close Command CR04 13 14 15 16 11 12 13 CR05 OC07 OC08 Bus 1 VT MCB Fail Bus 2 VT MCB Fail Remote Trip. 10 Carrier Receive. channel 1 Carrier Send. channel 2 Carrier Send. trip coil 2 Trip Phase L3. trip coil 1 Bus 2 Isolator Q2 on 12 OC16 12 OC17 OC18 Breaker Q0 off 13 CR14 CR15 CR16 13 14 15 Breaker Q0 on 14 15 Trip Phase L1. trip coil 2 Prepare 3 Pole Trip. CR06 CR07 14 15 Breaker Q0 Close Command Line VT MCB Fail CB All Poles Closed for DEF Prot. Distance Prot. trip coil 1 Trip Phase L2. OCO Ready for AR Release 17 18 1 2 3 4 5 6 OC09 OC10 OC11 OC12 B D CR08 CR09 CR10 1 2 3 4 5 6 Start L1L2L3 to AR in Main 1 Trip CB 3-Pole to AR in Main 1 Trip CB to AR in Main 1 Bus 1 Isolator Q1 off Bus 1 Isolator Q1 on Bus 2 Isolator Q2 off 7 8 9 10 11 OC13 OC14 OC15 7 CR11 CR12 CR13 8 9 10 11 Trip Phase L1. Distance Prot. trip coil 1 Trip Phase L3. if existing Fig. TRIP Spare 5 6 7 8 Mechanic protection TRIP 1 Mechanic protection alarm 1 9 10 11 12 Mechanic protection TRIP 2 Mechanic protection alarm 2 13 14 15 16 A-side breaker Q0 manual close command Block transformer diff. high-set 17 18 1 2 3 4 5 A-side bus 1 isolator Q1 open A-side bus 1 isolator Q1 closed A-side bus 2 isolator Q2 open 6 7 8 9 10 A-side bus 2 isolator Q2 closed A-side breaker Q0 open 13 A-side breaker Q0 closed 14 15 16 Spare 17 Spare 18 OC19 OC20 11 12 OC13 OC14 OC15 OC10 OC11 OC12 OC09 OC07 OC08 OC01 OC02 Binary outputs Transformer Variant 1 C CR01 1 2 In service 3 4 A OC03 OC04 CR02 5 6 7 Block close command breaker Q0 A-side CR03 OC05 OC06 CR04 CR05 8 Transf. prot. inrush input Transformer diff. group 2 TRIP External start BFP from mechanic prot. trip L1L2L3 group 2 Tripping relay (94-2) trip CB A/B/C–side *) 1 2 B D CR08 CR09 CR10 3 4 5 6 7 Remote trip 1 to B-side Remote Trip 1 to C-side *) Transf. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 46 Connection diagrams (cont´d) Binary inputs Transformer Variant 1 Start BFP phase L1L2L3 from prot. 21 REB500sys: Typical assignment of the in-/outputs of transformer variant T-V1 for 500BU03 (See [3] application description) . prot. protection Transformer diff. TRIP 1 2 3 4 Start BFP phase L1L2L3 from back-up prot. trip on B-side start BFP CR11 CR12 CR13 8 9 Trip phase L1 Trip phase L2 Trip breaker Q0 coil 1 A-side 10 Trip phase L3 11 OC16 OC17 OC18 CR14 CR15 CR16 12 13 Trip phase L1 14 Trip phase L2 15 Trip phase L3 Trip breaker Q0 coil 3 A-side Legend: A-side B-side C-side *) Transformer primary side Transformer secondary side Transformer tertiary side *) C-side. trip L1L2L3 group 1 Tripping relay (94-1) 10 trip CB A/B/C–side *) 9 11 Transf. prot. prot. trip on C-side *) 12 13 start BFP CR06 CR07 14 Remote trip 2 to B-side 15 Transf.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 0 mm Space for wiring Achtung Caution Attention Atencion Fig. 2.5 mm 2 max. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 47 Dimensioned drawings (in mm) Bay unit 500BU03 Cross section: max. 4. enclosure protection class IP 40 (without local HMI) Cross section: max. 22 Bay unit casing for flush mounting. 23 Centralized version based on a 19'' mounting plate with up to three bay units. Optionally with local HMI.0 mm2 Fig.5 mm 2 2 max. 2. 4. Space for wiring .ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 48 Dimensioned drawings (in mm) (cont´d) Bay unit 500BU03 223 Cross section max.5 267 +0. 235 212 443 Fig.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 100 Space for wiring 0 204 ±.5 25 210 Panel cutout Fig. 25 Dimensional drawing of the central unit.8 76.2 200 ±0.1 465. 4.6 approx.8 276 . 24 Dimensional drawing of the bay unit with local HMI. protection type IP20 30 57.1 0 189 6U=265.6 57.1 6U=265. classical mounting protection type IP40 Central unit 482.5 mm2 max.0 mm2 approx. 70 Rear view approx. 2. 5 mm2 . cross-section and an average quantity of cables .5 mm .6 mm2 1.5 mm2 * number of bays per cubicle (2200 x 800 x 800 mm) based on the min.5 mm2 . Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 49 Cubicle mounting Fig. number of bays per cubicle without central unit 4 5 8 1 20 16 9* 12* 6 3 9 - 2. Table 47 Maximum number of units per cubicle (central version) Unit Quantity of 500BU03 Cross-section ext.6 mm2 1. cable Quantity of system cables per bay Current transformer per bay Voltage transformer per bay Binary inputs per bay Binary outputs per bay Max.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. 27 Hinged frame and rear wall Example with 9 bay units The cubicles are equipped with gratings for the fixation of incoming cables. number of bays per cubicle with central unit Max. 26 Front view of REB500 (example only) Fig. For space reasons there are no cable ducts.5 mm2 .2.5 mm 2 2 1 1 1-3 1-3 1.2. 5U. 5U. 5U. red. power supply. red. power supply.5 kg 9. HMI) Bay unit 9I. 1MT. red.9 kg 5. basic version Bay unit 9I. cables or transformer bays. HMI) Bay unit 4l. 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. classic (incl. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 50 Cubicle mounting (cont’d) Table 48 Unit weights Unit Weight Bay unit 4l. power supply. red.7 kg 5. basic version Central unit Central unit with redundant power supply 5. power supply. 28 Basic version with HMI Classic version Possible arrangement of the bay unit with HMI Sample specification Combined numerical bay and station protection with extensive self-monitoring and analog/digital conversion of all input quantities. classic (incl. 5U.0 kg 6.0 kg Basic version Fig. red.0 kg (Average weight => here 11 feeders plus communication interface) 10. classic (incl. red. basic version Bay unit 4l. The hardware shall allow functions to be activated from a software library: • 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 .1 kg 6. classic (incl. basic version Bay unit 3l.2 kg 3. with bay units and a central unit. HMI) Bay unit 4l. The architecture shall be decentralized. power supply. HMI) Bay unit 3l. power supply.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. lines. 1MT. power swing blocking • Earth fault directional function based on zero components with separate communication scheme or using the same channel as the distance protection • Directional sensitive earth fault protection for ungrounded or compensated systems • Autoreclosure function. comprehensive recording available for the whole station in the central unit. 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 No auxiliary CTs are necessary and the system contains internal check of the voltage and current circuits. The proposed system shall be easily extensible. such as switchon-to-fault. This will enable us to submit a tender that corresponds more accurately to your needs. collection of data in the bay units. voltage supervision. Communication via computer or via interface to monitoring or control systems allows the actual configuration of the whole busbar to be displayed.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Ordering Ordering When sending your enquiry please provide the short version of the questionnaire on page 55 in this data sheet together with a singleline diagram of the station. Event and disturbance recording shall be included. . A modern human machine interface shall allow the allocation of input and output signals. The adaptation of the CTratio is done by software. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 51 • Over-/undercurrent and over-/undervoltage back-up bay function (overcurrent directional or non-directional) • Distance protection function with all relevant additional features. teleprotection schemes. in case of extensions in the substation. 2nd rack 50 bay units.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. incl. incl. 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 IEC103 IEC61850 0 1 2 3 Communication Interface B No LON IEC103 IEC61850 0 1 2 3 . Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 52 Ordering (cont’d) Ordering code REB500-CU03-V75 -S -P -B -CA -CB Equipped for 10 bay units 20 bay units 30 bay units 40 bay units. incl. 2nd rack 10 20 30 40 50 60 Red. for 1-30 bay units Yes. Power Supply No Yes. 2nd rack 60 bay units. ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 53 REB500-BU03-V75-C Case Classic (incl.7 Hz 1 2 Busbar Protection No Yes 0 1 Neutral Current IO No Yes 0 1 Release Criterion No Yes 0 1 Overcurrent Protection No Yes 0 1 Breaker Failure Protection No Yes 0 1 End Fault Protection No Yes 0 1 Pole Discrepancy No Yes 0 1 Disturbance Recorder Standard (1.4 kHz) Advanced (10 s @ 2. LHMI) Stand alone (no LHMI) 1 2 -A -P -F -BB -IO -R -OC -BFP -EFP -PD -DR -L -T Analog Input Module 4 CTs 4 CTs and 5 VTs 9 CTs 6 CTs and 3 VTs 40 45 90 63 Red.4 kHz) 0 2 .5 s @ 2. Power Supply No Yes 0 1 Power Frequency 50 Hz or 60 Hz 16. ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 54 Ordering (cont’d) REB500-BU03-V75-C -A -P -F -BB -IO -R -OC -BFP -EFP -PD -DR -L -T Line Protection No Line Variant 1 (L-V1) Line Variant 2 (L-V2) Line Variant 3 (L-V3) Line Variant 4 (L-V4) Line Variant 5 (L-V5) 0 1 2 3 4 5 Transformer Protection No Transformer Variant 1 (T-V1) Transformer Variant 2 (T-V2) Transformer Variant 3 (T-V3) Transformer Variant 4 (T-V4) 0 1 2 3 4 . 4 connectors Quantity LHMI 500HMI03 * 0.00 m. 4 connectors Quantity Quantity Quantity HESP417456R0005 HESP417456R0010 HESP417456R0020 HESP417456R0100 2 core FO-cable *100. 4 connectors 2 core FO-cable *20. Trip circuits Tripping method GIS Circuit Breaker type Single pole One trip coil Two trip coils Centralized CU and BU loose delivered Three pole 6. Please note license is only provided for trained customers! Manuals Quantity Quantity 1MRB260027R0075 1MRB260027R0175 Operating Instructions REB500/REB500sys in English Fiber optic cables Quantity 1MRB520292-Uen 2 core FO-cable *5. indoor. ready made incl. 4 connectors 2 core FO-cable *10. Date Rev. Client Client Station Client's reference Client's representive. 7.: Sales Engineer Project Manager 3. ABB (filled in by ABB) Tender No. indoor.5 m cable for REB500/BU03 500HMI03 * 3 m.5 m. Busbar configuration Single Double Triple Quadruple Switchgear AIS 5. local HMI with 0. indoor. indoor.50 Configurator * * HMI500 Configurator is including software license for 4 users (authorization by serial number). Index Rev. ready made incl.: Order No. date 2. local HMI with 3 m cable for REB500/BU03 Miscellaneous Quantity Quantity 1MRB150073R0052 1MRB150073R0302 500OCC02 Converter cable (serial) HMI_PC 500OCC03 Converter cable (USB) HMI_PC Quantity Quantity 1MRB380084R0001 1MRB380084R0003 . Type of installation Distributed CU loose delivered BU loose delivered Distributed CU mounted in cubicle BU mounted in cubicles Centralized CU and BU mounted in cubicles mandatory ordering information Accessories HMI software HMI500 Ver. Date Remark : This attachment is absolutely essential ! 1-1/2 Breaker Ring bus Transfer bus 4. 7.00 m. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 55 Short questionnaire 1. ready made incl.ABB Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. HV System System Voltage [kV] Frequency [Hz] Neutral Grounding Solidly grounded Isolated Compensated Low resistance gr. Binding Single line diagram (must show location and configuration of spare bays) Diagram No.50 Operator HMI500 Ver.00 m.00 m. ready made incl. com www. Line and Transformer Protection REB500 / REB500sys 1MRB520308-Ben Page 56 Other relevant publications [2] CT requirements for REB500 / REB500sys [3] Application description REB500sys [4] Data sheet PSM505 Operating instructions REB500 / REB500sys Cubicle specification RESP97 Data sheet RESP97 Reference list REB500 Ordering questionnaire REB500 1KHL020347-AEN 1MRB520295-Aen 1MRB520376-Ben 1MRB520292-Uen 1MRB520159-Ken 1MRB520115-Ben 1MRB520009-Ren 1MRB520371-Ken ABB Switzerland Ltd Power Systems Brown-Boveri-Strasse 72 CH-5400 Baden/Switzerland [email protected] Switzerland Ltd Power Systems Numerical Station Protection System Busbar Protection with integrated Breaker Failure. +41 58 585 77 44 Fax +41 58 585 55 77 E-mail: substation.com/substationautomation Printed in Switzerland (0901-0000-0) .abb.