Substation Automation Products. Distributed busbar protection REB500 including line and transformer protection Product Guide

Transcription

1 Distributed busbar protection REB Product Guide

2 Distributed busbar protection REB 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 - and A rated currents - all auxiliary supply voltages between V DC and V DC - nominal frequencies of, and. 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 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 --, IEC -- and LON IEC 9 standard redundant station bus communication IEC -9- LE process bus communication Cyber security to support - User Access Management - User Activity Logging Options Breaker failure protection (also separately operable without busbar protection) End fault protection Definite time overcurrent protection Breaker pole discrepancy Current and voltage release criteria Disturbance recording for power system voltages Separate I measurement for impedancegrounded networks Communication with substation monitoring and control system (IEC -- / IEC -- / LON) Internal user-friendly human machine interface with display Redundant power supply for central units and/or bay units Additional main features REBsys combines the well-proven numerical busbar and breaker failure protection REB of ABB with Main or back-up protection for line or transformer feeders. The Main / Group or back-up protection is based on the well-proven protection function library of ABB line and transformer protection for, and. Hz. Main / 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 Page

3 Distributed busbar protection REB Application Three-phase current and three-phase voltage plausibility Main / 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 REB The numerical busbar protection REB is designed for the high-speed, selective protection of MV, HV and EHV busbar installations at a nominal frequency of, and. 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 ½ breaker schemes to be protected. In ½ 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 feeders (bay units) and a total of busbar zones. The numerical busbar protection REB detects all phase and earth faults in solidly grounded and resistive-grounded power systems and phase faults in ungrounded systems and systems with Petersen coils. The main CTs supplying the currents to the busbar protection have to fulfil only modest performance requirements (see page ). The protection operates discriminatively for all faults inside the zone of protection and remains reliably stable for all faults outside the zone of protection. - checks for dead line, dead bus, dead line and bus Group / back-up bay protection: Transformer protection High-speed transformer differential protection for - and -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 REBsys The REBsys is foreseen in MV, HV and EHV substations with nominal frequencies of., Hz or Hz to protect the busbars and their feeders. The bay protection functions included in REBsys are used as Main / Group - or back-up protection. The system REBsys is foreseen for all single or double busbar configurations (Line variants L-V to L-V and Transformer variant T- V to T-V). In ½ breaker configurations, variant L-V can be used for the bay level functions autoreclosure and synchrocheck. The capacity is sufficient for up to feeders (bay units) and a total of busbar zones. The REBsys detects all bus faults in solidly and low resistive-grounded power systems, all kind of phase faults in ungrounded and compensated power systems as well as feeder faults in solidly, low resistive-grounded, compensated and ungrounded power systems. The protection operates selectively for all faults inside the zone of protection and remains reliably stable for all faults outside the zone of protection. REBsys 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 - and winding transformer protection or autonomous T-zone protection). The central unit can be added at a later stage for full busbar and breaker failure protection functionality. Page

4 Distributed busbar protection REB Application (cont d) 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 REBsys 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 REBsys 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 / Group or back-up bay level functions: Line protection - Line variant (L-V) directional, non-directional overcurrent and directional earth fault protection - Line variant (L-V) as line variant L-V plus distance prot. - Line variant (L-V) as line variant L-V plus autoreclosure - Line variant (L-V) as line variant L-V plus synchrocheck - Line variant (L-V) as line variant L-V plus autoreclosure and synchrocheck. - Line variant (L-V) for. Hz non-directional overcurrent, distance protection, autoreclosure. - Line variant (L-V) for. Hz as line variant L-V plus directional earth fault protection for grounded systems Transformer protection - Transformer variant (T-V) - or winding transformer differential protection, thermal overload, current functions; applicable also as autonomous T-zone protection. - Transformer variant (T-V) -winding transformer differential protection, thermal overload, current functions, overfluxing protection, neutral overcurrent (EF). - Transformer variant (T-V) Distance protection for transformer back-up or -winding transformer differential protection, thermal overload, current functions, voltage functions, frequency functions, power function, overfluxing protection. - Transformer variant (T-V) Transformer oriented functions/ back-up functions -> thermal overload, current functions, voltage functions, frequency functions, power function, overfluxing protection. Fig. Page

5 Distributed busbar protection REB Table Overview of the functionalities REB / REBsys IEEE Main functionality Busbar protection B BBP PDIF Busbar protection with neutral current BN I PDIF Breaker failure protection inlcluding neutral current detection BF BFP RBRF End-fault protection /EF EFP PTOC Breaker pole discrepancy /PD PDF PTOC Overcurrent check feature PTOC Voltage check feature 9/ PTOV/PTUV Check zone CZ BBP CZ PDIF Current plausibility check Overcurrent protection (def. time) OCDT PTOC Trip command re-direction 9RD - Software matrix for inputs / outputs / trip matrix - - Event recording up to events - ER - Disturbance recorder ( x I) 9DR DR RDRE Disturbance recorder ( x I, x U) up to s at Hz 9DR DR RDRE Communication interface IEC --/ LON / IEC -- - Com - Time synchronization - - Redundant power supply for central- and/or bay units - - Isolator supervision - - Differential current supervision - - Comprehensive self-supervision - - Dynamic Busbar replica with display of currents - - WEB - Server - - Testgenerator for commissioning & maintenance - - Remote-HMI - - Delay / Integrator function - - Binary logic and Flip-Flop functions - - Definite time over- and undercurrent protection OCDT PTOC Inverse time overcurrent protection OCINV PTOC Definite time over- and undervoltage protection 9/ OVDT PTUV/PTOV Inverse time earth fault overcurrent protection N IINV PTOC Directional overcurrent definite time protection DIROCDT PTOC Directional overcurrent inverse time protection DIROCINV PTOC Three phase current plausibility CHKIPH PTOC Three phase voltage plausibility CHKUPH PTUV Test sequenzer - - Direct. sensitive EF prot. for grounded systems N DIREFGND PDEF Direct. sensitive EF prot. for ungrounded or compensated systems N DIREFISOL PSDE Distance protection DIST PDIS Autoreclosure 9 AR RREC Synchrocheck SYNC RSYN Transformer differential protection winding T DIFTRA PDIF Transformer differential protection winding T DIFTRA PDIF Thermal overload 9 TH PTTR Peak value over- and undercurrent protection OCINST PTUC/PTOC Peak value over- and undervoltage protection 9 OVINST PTUV/PTOV Definite time overfluxing protection U/fDT PVPH Inverse time overfluxing protection U/fINV PVPH Rate-of-change frequency protection df/dt PVRC Frequency protection Freq PTOF/PTUF Power protection P PDUP/PDOP Protection function IEC Standard Option Line Variant (L-V) /Hz Line Variant (L-V) /Hz Line Variant (L-V) /Hz Line Variant (L-V) /Hz Line Variant (L-V) /Hz Line Variant (L-V). Hz Line Variant (L-V). Hz Transformer Variant (T-V) / Hz Transformer Variant (T-V) / Hz Transformer Variant (T-V) / Hz Transformer Variant (T-V) / Hz Page

6 Distributed busbar protection REB Mode of installation There are three versions of installing the numerical busbar protection REB and the numerical station protection REBsys: Distributed installation In this case, the bay units (see Fig. ) 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 central processing unit is normally in a centrally located cubicle or in the central relay room. Fig. Distributed installation Centralized installation 9" mounting plates with up to three bay units each, and the central processing unit are mounted according to the size of the busbar system in one or more cubicles (see Fig. ). A centralized installation is the ideal solution for upgrading existing stations, since very little additional wiring is required and compared with older kinds of busbar protection, much more functionality can be packed into the same space. Fig. Centralized installation Combined centralized and distributed installation Basically, the only difference between a distributed and a centralized scheme is the mounting location of the bay units and therefore it is possible to mix the two philosophies. Page

7 Modul cess-bus tput Uhr Central Unit (CU) DC Real-time Clock DC Local HMI CIM Modul Modul Interface Koppler E/A Koppler E/A CPU Module CPU Module Binary I/O SAS/SMS Interface Star coupler Interface Modul RS Interface CPU Module Substation Automation Products Distributed busbar protection REB System design Bay unit (BU) The bay unit (see Fig. ) is the interface between the protection and the primary system process comprising the main CTs, isolators and circuit-breaker and performs the associated data acquisition, pre-processing, control functions and bay level protection functions. It also provides the electrical insulation between the primary system and the internal electronics of the protection. The input transformer module contains four input CTs for measuring phase and neutral currents with terminals for A and A. Additional interposing CTs are not required, because any differences between the CT ratios are compensated by appropriately configuring the software of the respective bay units. Optional input transformer module also contains five input voltage transformers for the measurement of the three-phase voltages and two busbar voltages and recording of voltage disturbances or current transformers for transformer differential protection. (see Fig. ). In the analog input and processing module, the analog current and voltage signals are converted to numerical signals at a sampling rate of samples per period and then numerically preprocessed and filtered accordingly. Zero-sequence voltage and zero-current signals are also calculated internally. The Process data are transferred at regular intervals from the bay units to the central processing unit via the process bus. Every bay unit has binary inputs and relay outputs. The binary I/O module detects and processes the positions of isolators and couplers, blocking signals, starting signals, external resetting signals, etc. The binary input channels operate according to a patented pulse modulation principle in a nominal range of to V DC. The PC-based HMI program provides settings for the threshold voltage of the binary inputs. All the binary output channels are equipped with fast operating relays and can be used for either signaling or tripping purposes (see contact data in Table ). A software logic enables the input and output channels to be assigned to the various functions. A time stamp is attached to all the data such as currents, voltages, binary inputs, events and diagnostic information acquired by a bay unit. Where more binary and analog inputs are needed, several bay units can be combined to form a feeder/bus coupler bay (e.g. a bus coupler bay with CTs on both sides of the bus-tie breaker requires two bay units). The bay unit is provided with local intelligence and performs local protection (e.g. breaker failure, end fault, breaker pole discrepancy), bay protection (Main or back-up bay protections) as well as the event and disturbance recording. Bay Unit (BU) Central Unit (CU) Local HMI Optical Interface CPU DC DC Process-bus Local HMI DC DC Real-time Clock CPU Module SAS/SMS Interface RS Interface DSP DP Mem CIM A/D Filter Binary in/output registers Filter CPU Module CPU Module Starcoupler Starcoupler Binary I/O Star coupler Electrical insulation Fig. Block diagram of a bay unit and a central unit Page

8 Distributed busbar protection REB System design (cont d) In the event that the central unit is out of operation or the optical fiber communication is disrupted an alarm is generated, the bay unit will continue to operate, and all local and bay protection as well as the recorders (event and disturbance) will remain fully functional (stand-alone operation). The hardware structure is based on a closed, monolithic casing and presented in two mounting solutions: Without local HMI: ideal solution if convenient access to all information via the central unit or by an existing substation automation system is sufficient. With local HMI and programmable LEDs (Fig. ): ideal solution for distributed and kiosk mounting (AIS), since all information is available in the bay. For the latter option it is possible to have the HMI either built in or connected via a flexible cable to a fixed mounting position (see Fig. ). In the event of a failure, a bay unit can be easily replaced. The replacement of a bay unit can be handled in a simple way. During system start-up the new bay unit requests its address, this can be entered directly via its local HMI. The necessary setting values and configuration data are then downloaded automatically. Additional plug-and-play functionality Bay units can be added to an existing REB system in a simple way. Central unit (CU) The hardware structure is based on standard racks and only a few different module types for the central unit (see Fig. ). The modules actually installed in a particular protection scheme depend on the size, complexity and functionality of the busbar system. A parallel bus on a front-plate motherboard establishes the interconnections between the modules in a rack. The modules are inserted from the rear. The central unit is the system manager, i.e. it configures the system, contains the busbar replica, assigns bays within the system, manages the sets of operating parameters, acts as process bus controller, assures synchronization of the system and controls communication with the station control system. The variables for the busbar protection function are derived dynamically from the process data provided by the bay units. The process data are transferred to the central processor via a star coupler module. Up to bay units can be connected to the first central processor and to the others. Central processors and star coupler modules are added for protection systems that include more than bay units. In the case of more than bay units, additional casings are required for accommodating the additional central processors and star coupler modules required. All modules of the central unit have a plugand-play functionality in order to minimize module configuration. One or two binary I/O modules can be connected to a central processing unit. The central unit comprises a local HMI with programmable LEDs (Fig. ), a TCP/IP port for very fast HMI connection within the local area network. Fig. Bay unit Fig. Central unit Page

9 Distributed busbar protection REB 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. Any DC component and harmonics are suppressed. The first measuring principle uses a stabilized differential current algorithm. The currents are evaluated individually for each of the phases and each section of busbar (protection zone). Differential current ( ) IKmin Restraint area Tripping area k= K setting = k st max where N is the number of feeders. The following two conditions have to be accomplished for the detection of an internal fault: where k st k st max I K min k st I I Diff Rest k IDiff I K min stmax () () stabilizing factor stabilization factor limit. A typical value is k st max =. differential current pick-up value The above calculations and evaluations are performed by the central unit. The second measuring principle determines the direction of energy flow and involves comparing the phases of the currents of all the feeders connected to a busbar section. The fundamental frequency current phasors..n () are compared. In the case of an internal fault, all of the feeder currents have almost the same phase angle, while in normal operation or during an external fault at least one current is approximately out of phase with the others. Fig. Restraint current ( ) Tripping characteristic of the stabilized differential current algorithm. Im I n arctan Re I Ln Ln () In Fig., the differential current is I Diff I Ln N n () 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. ). and the restraint current I Rest I Ln N n () Page 9

10 Distributed busbar protection REB Functionality (cont d) Busbar Case : External fault = Im = I I Re tripping coil on the circuit-breaker and a remote tripping signal transmitted to the station at the opposite end of the line. This first timer operates in a stand-alone mode in the bay unit. Operating characteristic Case : Internal fault = Im Phase-shift Restraint area max = Tripping area I I Re = Case If the fault still persists at the end of the second time delay, the breaker failure function uses the busbar replica to trip all the other feeders supplying the same section of busbar via their bay units. A remote tripping signal can be configured in the software to be transmitted after the first or second timer. Fig. Characteristic of the phase comparator for determining energy direction Phase-segregated measurements in each bay unit cope with evolving faults. The task of processing the algorithms is shared between the bay units and the central processing unit. Each of the bay units continuously monitors the currents of its own fee-der, preprocesses them accordingly and then filters the resulting data according to a Fourier function. The analog data filtered in this way are then transferred at regular intervals to the central processing unit running the busbar protection algorithms. Depending on the phase-angle of the fault, the tripping time varies at I diff /I kmin between and ms including the auxiliary tripping relay. Optionally, the tripping signal can be interlocked by a current or voltage release criteria in the bay unit that enables tripping only when a current above a certain minimum is flowing, respectively the voltage is below a certain value. Breaker failure protection The breaker failure functions in the bay units monitor both phase currents and neutral current independently of the busbar protection. They have two timers with individual settings. Operation of the breaker failure function is enabled either: internally by the busbar protection algorithm (and, if configured, also by the internal line protection, overcurrent or pole discrepancy protection features) of the bay level externally via a binary input, e.g. by the line protection, transformer protection etc. After the delay of the first timer has expired, a tripping command can be applied to a second End fault protection In order to protect the dead zone between an open circuit-breaker and the associated CTs, a signal derived from the breaker position and the close command is applied. The end fault protection is enabled a certain time after the circuit-breaker has been opened. In the event of a short circuit in the dead zone the nearest circuit-breakers are tripped. This function is performed in a stand-alone mode in the bay unit. Overcurrent function A definite time overcurrent back-up protection scheme can be integrated in each bay unit. (The operation of the function, if para-meterized, may start the local breaker failure protection scheme). This function is performed in a stand-alone mode in the bay unit. Current release criteria The current release criteria is only performed in the bay unit. It is effective for a busbar protection trip and for an intertripping signal (including end fault and breaker failure) and prevents those feeders from being tripped that are conducting currents lower than the setting of the current release criteria. Voltage release criteria The voltage criterion is measured in the bay unit. The function can be configured as release criterion per zone through internal linking in the central unit. This necessitates the existence of one set of voltage transformers per zone in one of the bay units. Tripping Page

11 Distributed busbar protection REB is only possible if the voltage falls short of (U<) or exceeds (U >) the set value. Additionally this release criterion can be configured for each feeder (voltage transformers must be installed). For details see Table. Check zone criterion The check zone algorithm can be used as a release criterion for the zone-discriminating low-impedance busbar protection system. It is based on a stabilized differential current measurement, which only acquires the feeder currents of the complete busbar. The isolator / breaker positions are not relevant for this criterion. Neutral current detection I Earth fault currents in impedance-grounded systems may be too low for the stabilized differential current and phase comparison functions to detect. A function for detecting the neutral current is therefore also available, but only for single phase-to-earth faults. Pole discrepancy A pole discrepancy protection algorithm supervises that all three poles of a circuitbreakers open within a given time. This function monitors the discrepancy between the three-phase currents of the circuitbreaker. When it picks up, the function does not send an intertripping signal to the central unit, but, if configured, it starts the local breaker failure protection (BFP logic ). This function is also performed in a standalone mode in the bay unit. Event recording The events are recorded in each bay unit. A time stamp with a resolution of ms is attached to every binary event. Events are divided into the three following groups: system events protection events test events The events are stored locally in the bay unit or in the central unit. Disturbance recording This function registers the currents and the binary inputs and outputs in each bay. Voltages can also be optionally registered (see Table ). A disturbance record can be triggered by either the leading or lagging edges of all binary signals or by events generated by the internal protection algorithms. Up to general-purpose binary inputs may be configured to enable external signals to trigger a disturbance record. In addition, there is a binary input in the central and the bay unit for starting the disturbance recorders of all bay units. The number of analog channels that can be recorded, the sampling rate and the recording period are given in Table. A lower sampling rate enables a longer period to be recorded. The total recording period can be divided into a maximum of recording intervals per bay unit. Each bay unit can record a maximum of binary signals, of which can be configured as trigger signals. The function can be configured to record the pre-disturbance and post-disturbance states of the signals. The user can also determine whether the recorded data is retained or overwritten by the next disturbance (FIFO = First In, First Out). This function is performed in a stand-alone mode in the bay unit (see page ). Note: Stored disturbance data can be transferred via the central unit to other computer systems for evaluation by programs such as PSM []. Files are transferred in the COMTRADE format. After retrieving the disturbance recorder data, it is possible to display them graphically with PSM directly. Communication interface Where the busbar protection has to communicate with a station automation system (SAS), a communication module is added to the central unit. The module supports the interbay bus protocols IEC --, IEC -- and LON. The IEC -- interbay bus transfers via either optical or electrical connection: differential current of each protection zone monitoring information from REB central unit and bay units binary events (signals, trips and diagnostic) trip reset command Page

12 Distributed busbar protection REB Functionality (cont d) disturbance recording data (via MMS file transfer protocol) time synchronization with Simple Network Time Protocol (SNTP) two independent time servers are supported. Server as backup time The LON interbay bus transfers via optical connection: differential currents of each protection zone binary events (signals, trips and diagnostic) trip reset command disturbance recording data (via HMI) time synchronization The IEC -- interbay bus transfers via either optical or electrical connection: time synchronization selected events listed in the public part all binary events assigned to a private part all binary events in the generic part trip reset command Test generator The HMI program (HMI) which runs on a PC connected to either a bay unit or the central processing unit includes a test generator. During commissioning and system maintenance, the test generator function enables the user to: activate binary input and output signals monitor system response. 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 REBsys The test sequencer enables easy testing of the bay protection without the need to decommission the busbar protection. Up to seven se-quences per test stage can be started. The sequences can be saved and reactivated for future tests. Isolator supervision The isolator replica is a software feature without any mechanical switching elements. The software replica logic determines dynamically the boundaries of the protected busbar zones (protection zones). The system monitors any inconsistencies of the binary input circuits connected to the isolator auxiliary contacts and generates an alarm after a set time delay. In the event of an isolator alarm, it is possible to select the behavior of the busbar protection: blocked zone-selective blocked remain in operation Table N/O contact: Isolator CLOSED N/C contact: Isolator OPEN Isolator position open open Last position stored (for busbar protection) + delayed isolator alarm, + switching prohibited signal open closed OPEN closed open CLOSED closed closed CLOSED + delayed isolator alarm, + switching prohibited signal Differential current supervision The differential current is permanently supervised. Any differential current triggers a timedelayed alarm. In the event of a differential current alarm, it is possible to select the behavior of the busbar protection: blocked zone-selective blocked remain in operation Trip redirection A binary input channel can be provided to which the external signal monitoring the circuit-breaker air pressure is connected. Tripping is not possible without active signal. When it is inactive, a trip generated by the respective bay unit is automatically redirected to the station at the opposite end of the line and also to the intertripping logic to trip all the circuit-breakers connected to the same section of busbar. The trip redirection can also be configured with a current criterion (current release criteria). Page

13 Distributed busbar protection REB Human machine interface (HMI) The busbar protection is configured and maintained with the aid of human machine interfaces at three levels. Local HMI The local display interface installed in the central unit and in the bay units comprises: a four-line LCD with characters each for displaying system data and error messages keys for entering and display as well as LEDs for the display of trips, alarms and normal operation. in addition freely programmable LEDs for user-specific displays on the bay unit BU and central unit CU. The following information can be displayed: measured input currents and voltages measured differential currents (for the busbar protection) system status, alarms switchgear and isolator positions (within the busbar protection function) starting and tripping signals of protection functions External HMI (HMI) More comprehensive and convenient control is provided by the external HMI software running on a PC connected to an optical interface on the front of either the central unit or a bay unit. The optical interface is completely immune to electrical interference. The PC software facilitates configuration of the entire busbar protection, the set-ting of parameters and full functional checking and testing. The HMI can also be operated via the LON Bus on MicroSCADA for example, thus eliminating a separate serial connection to the central unit. The HMI runs under MS WINDOWS NT, WIN- DOWS 9, WINDOWS and WINDOWS XP. The HMI is equipped with a comfortable on-line help function. A data base comparison function enables a detailed comparison between two configuration files (e.g. between the PC and the central unit or between two files on the PC). Remote HMI A second serial interface at the rear of the central unit provides facility for connecting a PC remotely via either an optical fiber, TCP/IP or modem link. The operation and function of HMI is the same whether the PC is connected locally or remotely. Additional functionalities Bay level functions These functions are based on the well established and well-proven functions built in the ABB line and transformer protection. The bay level functions contain all the relevant additional functions, which are normally requested of a line and transformer protection scheme. The line protection functions (L-V - L-V) are used as Main or back-up for lines as well as for transformer bays. The transformer protection functions (T-V - T-V) are used as Group or back-up bay protection for transformer bays or as an independent T-Zone protection. Page

14 Distributed busbar protection REB Additional functionalities (cont d) High-speed distance protection Overcurrent or underimpedance starters with polygonal characteristic Five distance zones (polygon for forwards and reverse measurement) Load-compensated measurement Definite time overcurrent back-up protection (short-zone protection) System logic - switch-onto-fault - overreach zone Voltage transformer circuit supervision Power swing blocking function HF teleprotection. The carrier-aided schemes include: - permissive underreaching transfer tripping - permissive overreaching transfer tripping - blocking scheme with echo and transient blocking functions Load-compensated measurement - fixed reactance slope - reactance slope dependent on load value and direction (Z HV <) Parallel line compensation Phase-selective tripping for single and three-pole autoreclosure Four independent, user-selectable setting groups. In the supervision mode the active and reactive power with the respective energy direction is displayed by the HMI. Autoreclosure The autoreclosure function permits up to four three-phase autoreclosure cycles. The first cycle can be single phase or three-phase. If the REBsys autoreclosure function is employed, it can be used as a back-up for the autoreclosure realized externally (separate equipment or in the Main protection). When the autoreclosure function is realized outside of REBsys, all input and output signals required by the external autoreclosure equipment are available in order to guarantee correct functionality. Synchrocheck The synchrocheck function determines the difference between the amplitudes, phase angles and frequencies of two voltage vectors. The synchrocheck function also contains checks for dead line and dead bus. Transformer differential protection For two- 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 nd harmonic The transformer differential protection function can also be used as an autonomous T-zone protection in a ½ breaker scheme. Thermal overload This function protects the insulation against thermal stress. This protection function is normally equipped with two independently set levels and is used when oil overtemperature detectors are not installed. Peak value over- and undercurrent protection These functions are used for current monitoring with instantaneous response and where insensitivity to frequency is required. Peak value over- and undervoltage protection This function is used for voltage monitoring with instantaneous response and where insensitivity to frequency is required. Frequency function The function is used either as an over-/ underfrequency protection, or for load-shedding in the event of an overload. Several stages of the frequency protection are often needed. This can be achieved by configuring the frequency function several times. Rate of change frequency protection df/dt This function is used for the static, dynamic and adaptive load-shedding in power utilities and industrial distribution systems. The function supervises the rate-of-change df/dt of one voltage input channel. Several stages of the rate-of-change frequency protection are often Page

15 Distributed busbar protection REB needed. This can be achieved by configuring the rate-of-change frequency function several times. Definite time overfluxing protection This function is primarily intended to protect the iron cores of transformers against excessive flux. The function works with a definite time delay. The magnetic flux is not measured directly. Instead the voltage/frequency-ratio, which is proportional to the flux is monitored. Inverse time overfluxing protection This function is primarily intended to protect the iron cores of transformer against excessive flux. The function works with an inverse time delay. The inverse curve ca be set by a table of values and the times t-min and t- max. The magnetic flux is not measured directly. Instead the voltage/frequency-ratio, which is proportional to the flux is monitored. Power function This function provides single, or three phase measurement of the real or apparent power. The function can be configured for monitoring reverse, active or reactive power (power direction setting). Phase angle errors of the CT/VT inputs can be compensated by setting. The operating mode can be configured either to underpower or to overpower protection. Logics and delay/integrator These functions allow the user the engineering of some easily programmable logical functions and are available as standard also in the REB functionality. Directional sensitive earth fault protection for grounded systems A sensitive directional ground fault function based on the measurement of neutral current and voltage is provided for the detection of high-resistance ground faults in solidly or lowresistance grounded systems. The scheme operates either in a permissive or blocking mode and can be used in conjunction with an inverse time earth fault overcurrent function. In both cases the neutral current and voltage can be derived either externally or internally. This function works either with the same communication channel as the distance protection scheme or with an independent channel. Directional sensitive earth fault protection for ungrounded or compensated systems The sensitive earth fault protection function for ungrounded systems and compensated systems with Petersen coils can be set for either forwards or reverse measurement. The characteristic angle is set to ±9 (U I sin ) in ungrounded systems and to or (U I cos ) for systems with Petersen coils. The neutral current is always used for measurement in the case of systems with Petersen coils, but in ungrounded systems its use is determined by the value of the capacitive current and measurement is performed by a measuring CT to achieve the required sensitivity. To perform this function the BU with I, MT and U is required. Definite time over- and undercurrent protection This function is used as Main or as back-up function respectively for line, transformer or bus-tie bays. This function can be activated in the phase- and/or the neutral current circuit. Inverse time overcurrent protection The operating time of the inverse time overcurrent function reduces as the fault current increases and it can therefore achieve shorter operating times for fault locations closer to the source. Four different characteristics according to British Standard designated normal inverse, very inverse, extremely inverse and long time inverse but with an extended setting range are provided. The function can be configured for single phase measurement or a combined three-phase measurement with detection of the highest phase current. Inverse time earth fault overcurrent protection The inverse time earth fault overcurrent function monitors the neutral current of the system. Four different characteristics according to British Standard designated normal inverse, very inverse, extremely inverse and long time inverse but with an extended setting range are provided. Directional overcurrent definite / inverse time protection The directional overcurrent definite time function is available either with inverse time or definite time overcurrent characteristic. This function comprises a voltage memory for faults close to the relay location. The function response after the memory time has elapsed can be selected (trip or block). Definite time over- and undervoltage protection This function works with a definite time delay with either single or three-phase measurement. Page

16 Distributed busbar protection REB Additional functionalities (cont d) Three-phase current plausibility This function is used for checking the sum and the phase sequence of the three-phase currents. Three-phase voltage plausibility This function is used for checking the sum and the phase sequence of the three-phase voltages. Additional features Self-supervision All the system functions are continuously monitored to ensure the maximum reliability and availability of the protection. In the event of a failure, incorrect response or inconsistency, the corresponding action is taken to establish a safe status, an alarm is given and an event is registered for subsequent diagnostic analysis. Important items of hardware (e.g. auxiliary supplies, A/D converters and main and program memories) are subjected to various tests when the system is switched on and also during operation. A watchdog continuously monitors the integrity of the software functions and the exchange of data via the process bus is also continuously supervised. The processing of tripping commands is one of the most important functions from the reliability and dependability point of view. Accordingly, every output channel comprises two redundant commands, which have to be enabled at regular intervals by a watchdog. If the watchdog condition is not satisfied, the channels are blocked. Extension of the system The system functions are determined by software, configured using the software configuration tool. The system can be completely engineered in advance to correspond to the final state of the station. The software modules for new bays or features can be activated using the HMI when the primary plant is installed or the features are needed. Additional system functions, e.g. breaker failure, end fault protection or bay level back-up / Main functions can be easily activated at any time without extra hardware. Resetting the trip commands/-signals 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. It is used while performing maintenance respectively inspection activities on the primary equipment. Redundant power supplies (Option) Two power supply modules can be fitted in a redundant arrangement, e.g. to facilitate maintenance of station batteries. This is an option for the central unit as well as for the bay unit. Time synchronization The absolute time accuracy with respect to an external time reference depends on the method of synchronization used: no external time synchronization: accuracy approx. min. per month periodic time telegram with minute pulse (radio or satellite clock or station control system): accuracy typically ± ms periodic time telegram as above with second pulse: accuracy typically ± ms a direct connection of a GPS or DCF to the central unit is possible: accuracy typically ± ms Furthermore, the time synchronization can be done, if available, via the interbay bus IEC, LON or SNTP (in case IEC- - is used) The system time may also be synchronized by a minute pulse applied to a binary input on the central unit. Page

17 Distributed busbar protection REB Requirements Optical fiber cables A distributed busbar protection layout requires optical fiber cables and connectors with the following characteristics: optical fiber cores per bay unit glass fibers with gradient index diameter of core and sheath., respectively m maximum permissible attenuation db FST connector (for. m optical fibers) rodent protected and longitudinally waterproof if in cable ducts Please observe the permissible bending radius when laying the cables. The following attenuation figures are typical values which may be used to determine an approximate attenuation balance for each bay: Optical equipment for gradient index ( nm) per connector per cable joint Typical attenuation. db/km. db. db Central unit m m m Bay unit FST-connector FST-connector db Fig. 9 Attenuation Isolator auxiliary contact Auxiliary contacts on the isolators are connected to binary inputs on the bay units and control the status of the busbar replica in the numerical busbar protection. One potentially-free N/O and N/C contact are required on each isolator. The N/O contact signals that the isolator is CLOSED and the N/C contact that the isolator is OPEN. During the closing movement, the N/O contact Open end position must close before the isolator main contact gap reaches its flashover point. Conversely, during the opening movement, the N/O contact must not open before the isolator main contact gap exceeds its flashover point. If this is not the case, i.e. the contact signals no longer closed beforehand, then the N/C contact may not signal OPEN before the flashover point has been exceeded. Close end position Close isolator Isolator Open isolator Auxiliary contacts: CLOSED normally open Flashover gap OPEN normally closed Fig. must be closed may be closed must be open Switching sequence of the auxiliary contacts that control the busbar replica Page

18 Distributed busbar protection REB Requirements (cont d) Circuit-breaker replica When the circuit-breaker replica is read in the feeder or the bus-tie breaker, the circuitbreaker CLOSE command must also be connected. Main current transformer The algorithms and stabilization features used make the busbar protection largely insensitive to CT saturation phenomena. Main CTs types TPS (B.S. class x), TPX, TPY, P.. or P.. are permissible. TPX, TPY and TPZ CTs may be mixed within one substation in phase-fault schemes. The relatively low CT performance needed for the busbar protection makes it possible for it to share protection cores with other protection devices. Current transformer requirements for stability during external faults (Busbar protection) The minimum CT requirements for -phase systems are determined by the maximum fault current. 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. Taking account of the burden and the CT losses, the effective accuracy limit factor n' becomes: P n' n P where: n = rated accuracy limit factor P N = rated CT power P E = CT losses P B = burden at rated current N B P P In the case of schemes with phase-by-phase measurement, n' must satisfy the following two relationships: E E where: I Kmax = max. primary through-fault current I N = rated primary CT current Taking the DC time constant of the feeder into account, the effective n' becomes: () n' for T N ms, or n' for ms <T N ms. where: T N = Example: DC time constant I Kmax = A I N = A T N ms Applying relationships () and (): () () n' Selected: n = n' The current transformer requirements for REBsys for Line and Transformer protection are described in a separate publication []. Pick-up for internal faults In the case of internal busbar faults, CT saturation is less likely, because each CT only conducts the current of its own feeder. Should nevertheless CT saturation be possible, it is important to check that the minimum fault current exceeds the setting for I kmin. Note: For systems that measure I, the REB questionnaire MRB-Ken should be filled in and submitted to ABB, so that the CT requirements can be checked in order to ensure proper I measurement. () I n Kmax I N Page

19 Distributed busbar protection REB Technical data Table General data Temperature range: - operation - storage and transport Climate tests - Cold - Dry heat - Change of temperature - Damp heat (long-time) - C...+ C - C...+ C - C / h + C / h - to C, /min, cycles + C; 9% rel. hum. / days IEC - (9), EN- () IEC - (), EN - () IEC - (9), EN- () IEC - (), EN - () EN -- (), IEC -- (), EN -- (99), IEC -- (), EN -- (), IEC -- (9) EN -- (), IEC -- () Thermal withstand of insulating materials EN 9 (99) Sec.. Clearance and creepage distances EN - (), IEC - (), EN 9 (99), IEC 9 (99) Insulation resistance tests. kv / > MOhm EN - (), IEC - (), VDE Dielectric tests kv AC or kv DC / min kv AC or. kv DC / min (across open contacts) EN - (), IEC - Cl.C () EN 9 (99), IEC 9 (99) BS -9, ANSI/IEEE C.9-99 Impulse test./ s/. Joule kv AC EN - (), IEC - () Table Electromagnetic compatibility (EMC) Immunity MHz burst disturbance tests./. kv, MHz Hz rep. freq. IEC --, Cl. (), ANSI/IEEE C Immunity Industrial environment EN () Electrostatic discharge test (ESD) - air discharge - contact discharge Class kv kv Fast transient test (burst) Class / kv Power frequency magnetic field immunity test (/ Hz) - continuous field - short duration Radio frequency interference test (RFI) Emission - Conducted RFI - Radiated RFI Class A/m A/m Surge Class kv / kv Class. - MHz, % amplitude modulated V - MHz, % amplitude modulated V/m 9 MHz, pulse modulated V/m Industrial environment Test procedure EN -- (9), IEC -- () EN -- (9), IEC -- () EN -- (), IEC -- () EN -- (9), IEC -- () EN -- (9), IEC -- (9) EN -- (9), IEC -- () EN -- (), IEC -- () EN (99), CISPR (99) EN -- (99), IEC -- (99), IEEE ; Page 9

20 Distributed busbar protection REB Technical data (cont d) Table Mechanical tests Vibration and shock Vibration - reponse test - endurance test Shock and bump - shock - bump to Hz /. gn to Hz / gn Class A = gn; D = ms pulse/ axis = A = gn; D = ms pulse/ axis = EN -- (99), IEC -- (9) EN -- () IEC -- () IEEE ; EN -- (99), IEC -- (9) EN -- (), IEC -- () IEEE ; Seismic (SSE) to Hz, / gn EN -- (99), IEC -- (99), IEEE ; Table Enclosure protection classes Bay unit 9" central unit Cubicle (see Table ) IP IP IP- Hardware modules Table Analog inputs (Bay unit) Currents / / / 9 input channels Rated current (I N ) Thermal ratings: continuous for s for s half-cycle Burden per phase Voltages (optional) / / input channels Rated voltage (U N ) Thermal ratings: continuous for s Burden per phase Common data Rated frequency (f N ) I, I, I, I/ I, I, I, I, I, I/ I, I, I, I, I, I, I, I/ I, I, I, I, I, I, I, I, I9 A or A by choice of terminals, adjustable CT ratio via HMI x I N x I N x I N x I N (/ Hz) (peak). VA at I N = A. VA at I N = A U/ U, U, U/ U, U, U, U, U V, / Hz,. Hz V, / Hz VT ratio adjustable via HMI x U N x U N. VA at U N Hz, Hz,. Hz adjustable via HMI EN - (99), IEC - (9), VDE, part EN - (99), IEC - (9), VDE, Part BU EN - (99), IEC - (9), VDE, part Page

21 Distributed busbar protection REB Table Binary inputs/outputs (Bay unit, Central unit) Binary outputs General Operating time ms (typical) Max. operating voltage V AC/DC Max. continuous rating A Max. make and carry for. s A Max. making power at V DC W Binary output reset response, programmable per output - automatic reset (delay... s) - latched Heavy-duty N/O contacts CR...CR, BU Heavy-duty N/O contacts CR...CR, CR...CR9 - CU Breaking current for (L/R = ms) contact contacts in series U < V DC. A U < V DC. A U < V DC. A U < V DC A U < V DC A U < V DC. A Signalling contacts CR...CR, BU Signalling contacts CR, CR - CU Breaking current U < V DC. A U < V DC. A U < V DC. A Binary inputs Number of inputs per bay unit optocouplers 9 groups with common terminal Number of inputs for central unit optocouplers per binary I/O module (max. ) groups with common terminal Voltage range (U oc ) to V DC Pick-up setting via HMI Pick-up current ma Operating time < ms Table 9 Auxiliary supply Module type Bay unit Central unit Input voltage range (U aux ) ±% to V DC to V DC Fuse no fuse A slow Load W W Common data Max. input voltage interruption during > ms; IEC - (99), VDE, Part which output voltage maintained Frontplate signal Switch Redundancy of power supply green "standby" LED ON/OFF optional in bay and in central unit Page

22 Distributed busbar protection REB Technical data (cont d) Table Optical interfaces Number of cores fiber cores per bay unit Core/sheath diameter./ m (multi-mode) Max. permissible attenuation db (see Fig. 9) Max. length approx. m Connector Type FST for. m optical fiber cables Table 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 Cubicle design Cubicle Standard type RESP9 (for details see MRB9-Ken) Dimensions w x d x h x x mm (single cubicle) x x mm (double cubicle) x x mm (triple cubicle) *) *) largest shipping unit Total weight (with all units inserted) approx. - kg per cubicle Terminals Terminal type Connection data Solid Strand CTs Phoenix URTK/S. - mm. - mm VTs Phoenix URTK/S. - mm. - mm Power supply Phoenix UK N. - mm. - mm Tripping Phoenix UK -TWIN. - mm. - mm Binary I/Os Phoenix UKD -MTK-P/P. - mm. -. mm Internal wiring gauges CTs. mm stranded VTs. mm stranded Power supply. mm stranded Binary I/Os. mm stranded Recording facilities Table Event recorder Event recorder Bay unit Central unit System events Protection events total total Test events Page

23 Distributed busbar protection REB Table Options Disturbance recorder Analog channel currents or 9 currents currents and voltages Recording period Sample rate selectable Hz (. Hz) Hz ( Hz) Hz ( Hz) Hz (. Hz) Hz ( Hz) Hz ( Hz) Hz ( Hz) Hz ( Hz) Standard X X*). s s s Option X X s s s Option X X s s s Number of disturbance records = total recording time / set recording period (max.) Independent settings for pre-fault and post-fault period (min. setting ms). Format: COMTRADE 9 and COMTRADE 99 *) in Standard, voltage channels are recorded, if existing Table Interbay bus protocols IEC -- IEC -- interbay bus supports LON LON interbay bus supports IEC -- IEC -- interbay bus supports Address setting of station address... Sub address setting, common address of ADSU - Time synchronization via SNTP: typical accuracy ± ms - Two independent time servers are supported. Server as backup time - Optical or electrical connection - Differential current of each protection zone - Monitoring information from REB central unit and bay unit - Binary events (signals, trips and diagnostic) - Trip reset command - Single connection point to REB central unit - Disturbance recorder access via MMS file transfer protocol - Export of ICD - file, based on Substation Configuration Language SCL - Time synchronization: typical accuracy ± ms - Optical connection - Differential currents of each protection zone - Binary events (signals, trips and diagnostic) - Trip reset commands - Single connection point to REB central unit - Disturbance recorder data (via HMI) - Time synchronization: typical accuracy ± ms - Optical or electrical connection - Subset of binary events as specified in IEC Private range: Support of all binary events Generic mode: Support of all binary events - Trip reset command - Disturbance recording data... (CAA) CAA per bay unit freely selectable Page

24 Distributed busbar protection REB Technical data (cont d) Software modules Station level functions (Applicable for nominal frequencies of, and. Hz) Table Busbar protection (B) Min. fault current pick-up setting (I kmin ) Neutral current detection to A in steps of A to A Stabilizing factor (k). to.9 in steps of. Differential current alarms current setting time delay setting Isolator alarm time delay Typical tripping time CT ratio per feeder Reset time to % x I kmin in steps of % to s in steps of s. to 9 s to ms at I diff /I kmin incl. tripping relays; for f N =, Hz to ms at I diff /I kmin incl. tripping relays; for f N =. Hz to / A, to / A, adjustable via HMI to 9 ms (at. <I k /I kmin <); for f N =, Hz to 9 ms (at. <I k /I kmin <);for f N =. Hz Table Breaker failure protection (BF) Measurement: Setting range. to x I N in steps of. x I N Accuracy ±% Timers: Setting range for timers t: t: to ms in steps of ms to ms in steps of ms Accuracy ±% Remote trip pulse to ms in steps of ms Reset ratio typically % Table End-fault protection (/EF) Timer setting range to, ms in steps of ms Current setting range. to x I N in steps of. I N Reset ratio 9% Reset time to ms (at. <I/I setting <); for f N =, Hz Table 9 Overcurrent protection () Characteristic definite time Measurement: Setting range. to x I N in steps of. x I N Setting range time delay ms to s in steps of ms Reset ratio typically 9% Reset time to ms (at. <I/I setting <); for f N =, Hz Page

25 Distributed busbar protection REB Table Breaker pole discrepancy protection (/PD) Setting range Time delay Discrepancy factor. I N to. I N in steps of. I N, default. I N ms to ms in steps of ms, default ms.* I max to.99 * I max in steps of. * I max, default. * I max For feeders with single phase tripping and autoreclosure, the time setting for the breaker pole discrepancy protection must be greater than the reclosure time. The discrepancy factor is the maximum permissible difference between the amplitudes of two phases. Table Current release criteria () Setting range (per feeder). I N to. I N in steps of. I N, default. I N If the current release criteria is not activated, the tripping command ( _TRIP ) is given independent of current (standard setting). The current release criteria only allows the trip of a circuit breaker if the feeder current value is above the setting value of the enabling current. This value can be individually selected for each bay. Table Voltage release criteria (/9) U< Setting range (per feeder) U > Setting range (per feeder). U N to. U N in steps of. U N, default. U N. U N to. U N in steps of. U N, default. U N If the voltage release criteria is not activated the tripping command ( _TRIP ) is given independent of voltage (standard setting). The voltage release criteria is used as an additional criterion for busbar protection (as well as for the other station protection functions) and operates per zone. It can be used as U< or U > or in combination. Table Check zone criterion (CZ) Min. fault current pick-up setting (I kmin ) to A in steps of A Stabilizing factor (k). to.9 in steps of. CT ratio per feeder Feeder to / A, to / A, adjustable via HMI The check zone is used as an additional release criterion for busbar protection and operates zone-independent. Table Delay/integrator For delaying pick-up or reset or for integrating binary signal Provision for inverting the input independent parameter sets Settings: Pick-up or reset time to s in steps of. s Integration yes/no Page

26 Distributed busbar protection REB Technical data (cont d) Table Logic Logic for binary inputs with the following configurations:. OR gate. AND gate. Bistable flip-flop with set and reset inputs (both OR gates), resetting takes priority independent parameter sets. All configurations have an additional blocking input. Provision for inverting all inputs. Bay level functions for Back-up/Main REBsys Table Definite time over- and undercurrent protection () Over- and undercurrent detection Single or three-phase measurement with detection of the highest, respectively lowest phase current nd harmonic restraint for high inrush currents independent parameter sets Settings: Pick-up current. to I N in steps of. I N Delay. to s in steps of. s Accuracy of the pick-up setting (at f N ) ±% Reset ratio overcurrent undercurrent Max. operating time without intentional delay Inrush restraint pick-up setting reset ratio >9% (for max. function) <% (for min. function) ms optional. I h /I h. Table Inverse time overcurrent protection () Single or three-phase measurement with detection of the highest phase current independent parameter sets Inverse time characteristic (acc. to B.S., IEC - with extended setting range) normal inverse very inverse extremely inverse long time inverse t = k / ((I/I B ) C - ) c =. c = c = c = or RXIDG characteristic t =. -. In (I/I B ) Settings: Number of phases or Base current I B. to. I N in steps of. I N Pick-up current I start to I B in steps of. I B Min. time setting t min to s in steps of. s k setting. to s in steps of. s Accuracy classes for the operating time according to B.S., IEC - RXIDG characteristic E. ±% ( - I/ I B ) Reset ratio 9% Page

27 Distributed busbar protection REB Table Definite time over- and undervoltage protection (9/) Over- and undervoltage detection Single or three-phase measurement with detection of the highest, respectively lowest phase voltage independent parameter sets Settings: Pick-up voltage. to. U N in steps of. U N Delay. to s in steps of. s Accuracy of the pick-up setting (at f N ) ±% or ±. U N Reset ratio (U. U N ) overvoltage undervoltage Max. operating time without intentional delay >9% (for max. function) <% (for min. function) ms Table 9 Inverse time earth fault overcurrent protection (N) Neutral current measurement (derived externally or internally) independent parameter sets Inverse time characteristic (acc. to B.S., IEC - with extended setting range) normal inverse very inverse extremely inverse long time inverse t = k / ((I/I B ) C - ) c =. c = c = c = or RXIDG characteristic t =. -. In (I/I B ) Settings: Number of phases or Base current I B. to. I N in steps of. I N Pick-up current I start to I B in steps of. I B Min. time setting t min to s in steps of. s k setting. to s in steps of. s Accuracy classes for the operating time according to B.S., IEC - RXIDG characteristic E. ±% ( - I/ I B ) Reset ratio 9% Table Directional overcurrent definite time protection () Directional overcurrent protection with detection of power flow direction Back-up protection 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. to I N in steps of. I N Angle - to + in steps of Delay. to s in steps of. s Wait time. to s in steps of. s Page

28 Distributed busbar protection REB Technical data (cont d) Memory duration. to s in steps of. s Accuracies: Measuring accuracies are defined by: Frequency range.9. f N Sinusoidal voltage including.,.,. and 9. harmonic Accuracy of pick-up value Reset ratio Accuracy of angle measurement (at.9. f N ) 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 ±% 9% ±. to U N <. U N ± ±. /Hz ms Table Directional overcurrent inverse time protection () Directional overcurrent protection with detection of power flow direction Back-up for distance protection 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 to I N in steps of. I N Angle - to + in steps of Inverse time characteristic (acc. to B.S., IEC - with extended setting range) normal inverse very inverse extremely inverse long time inverse t = k / ((I/I B ) C - ) c =. c = c = c = t-min to in steps of. IB-value. to. I N in steps of. I N Wait time. to s in steps of. s Memory duration. to s in steps of. s Accuracies: Measuring accuracies are defined by: Frequency range.9. f N Accuracy of pick-up value Reset ratio Accuracy of angle measurement (at.9. f N ) 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 ±% 9% ±. to U N <. U N ± ±. /Hz ms Page

29 Distributed busbar protection REB Table Directional sensitive EF protection for ungrounded or compensated systems (N) Determination of real or apparent power from neutral current and voltage Settings: Pick-up power SN. to. SN in steps of. SN Reference value of the power SN. to. U N I N in steps of. U N I N Characteristic angle - to + in steps of. Phase error compensation of current input - to + in steps of. Delay. to s in steps of. s Reset ratio to 9% in steps of % Accuracy of the pick-up setting ±% of setting or % U N I N (for protection CTs) ±% of setting or.% U N I N (for measuring CTs) Max. operating time without intentional delay ms The directional sensitive EF protection for ungrounded or compensated systems requires the BU type with I + MT + U Table Three-phase current plausibility / Three-phase voltage plausibility (/) 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 phase currents or voltages independent parameter sets Accuracy of the pick-up setting at rated frequency ±% I N in the range. to. I N ±% U N in the range. to. U N Reset ratio 9% whole range >9% (at U >. U N or I >. I N ) Current plausibility settings: Pick-up differential for sum of internal summation current. to. I N in steps of. I N Amplitude compensation for summation CT -. to +. in steps of. Delay. to s in steps of. s Voltage plausibility settings: Pick-up differential for sum of internal summation voltage. to. U N in steps of. U N Amplitude compensation for summation VT -. to +. in steps of. Delay. to s in steps of. s Table Directional sensitive earth fault protection for grounded systems (N) Detection of high-resistance earth faults Current enabling setting I 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 independent parameter sets Settings: Current pick-up setting. to. I N in steps of. I N Voltage pick-up setting. to U N in steps of. U N Characteristic angle -9 to +9 in steps of Delay to s in steps of. s Accuracy of the current pick-up setting ±% of setting Page 9

30 Distributed busbar protection REB Technical data (cont d) Table Distance protection () Five measuring stages with polygonal impedance characteristic forward and backward All values of settings referred to the secondaries, every zone can be set independently of the others independent parameter sets Impedance measurement - to /ph in steps of. /ph Zero-sequence current compensation to in steps of., - to +9 in steps of Mutual impedance for parallel circuit lines to in steps of., -9 to +9 in steps of Time step setting range to s in steps of. s Underimpedance starters -999 to 999 /ph in steps of. /ph Overcurrent starters. to I N in steps of. I N Min. operating current. to I N in steps of. I N Back-up overcurrent to I N in steps of. I N Neutral current criterion. to I N in steps of. I N Neutral voltage criterion to U N in steps of. U N Low-voltage criterion for detecting, for example, to U N in steps of. U N a weak infeed VT supervision NPS/neutral voltage criterion NPS/neutral current criterion Accuracy (applicable for current time constants between and ms) amplitude error phase error Supplementary error for - frequency fluctuations of +% - % third harmonic - % 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. to. U N in steps of. U N. to. I N in steps of. I N ±% for U/U N >. ± for U/U N >. ±% ±% ±% ms ms ms < ms Remark: Distance protection operating times on next page Page

31 Distributed busbar protection REB Distance protection operating times Isochrones Single phase fault (min) Single phase fault (max).. ms Z F /Z L.. Z F /Z L... ms ms ms. SIR (Z S /Z L ). 9ms. SIR (Z S /Z L ) Two phase fault (min) Two phase fault (max) Z F /Z L... 9ms Z F /Z L... ms. ms ms.. 9ms. SIR (Z S /Z L ) SIR (Z S /Z L ) Three phase fault (min) Three phase fault (max) ms.. ms Z F /Z L.. Z F /Z L.... ms ms 9ms.. SIR (Z S /Z L ) SIR (Z S /Z L ) Abbreviations: Z S = source impedance Z F = fault impedance Z L = zone impedance setting Page

32 Distributed busbar protection REB Technical data (cont d) Table Autoreclosure (9) Single and three-phase autoreclosure Operation in conjunction with distance, overcurrent and synchrocheck functions and also with external protection and synchrocheck relays Logic for st and nd main protections, duplex and master/follower schemes Up to four fast or slow reclosure shots Detection of evolving faults independent parameter sets Settings: st reclosure none P fault - P reclosure P fault - P reclosure P/P fault - P reclosure P/P fault - P/P reclosure nd to th reclosure none two reclosure cycles three reclosure cycles four reclosure cycles Single phase dead time. to s Three-phase dead time. to s Dead time extension by ext. signal. to s Dead times for nd, rd and th reclosures. to s Fault duration time. to s Reclaim time. to s Blocking time. to s Single and three-phase discrimination times. to s All settings in steps of. s Table Synchrocheck () Determination of synchronism Single phase measurement. The differences between the amplitudes, 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 independent parameter sets Settings: Max. voltage difference. to. U N in steps of. U N Max. phase difference to in steps of Max. frequency difference. to. Hz in steps of. Hz Min. voltage. to U N in steps of. U N Max. voltage. to U N in steps of. U N Supervision time. to s in steps of. s Resetting time to s in steps of. s Accuracy Voltage difference Phase difference Frequency difference for.9 to. f N ±% U N ± ±. Hz Page

33 Distributed busbar protection REB Table Transformer differential protection (T) For two- and three-winding transformers Three-phase function Current-adaptive characteristic High stability for external faults and current transformer saturation No auxiliary transformers necessary because of vector group and CT ratio compensation Inrush restraint using nd harmonic Settings: g-setting. to. I N in steps of. I N v-setting. or. or. b-setting. to. in steps of. I N Max. trip time (protected transformer loaded) - for I > I N ms - for I I N ms Accuracy of pick-up value ±% I N (at f N ) Reset conditions I <. g-setting Accuracy of pick-up value ±% I N (at f N ) Reset conditions I <. g-setting Differential protection definitions: Differential protection characteristic I = I + I + I I I N I H I' I' cos for cos for cos I' = MAX (I, I, I ) I' = I + I + I - I' = (I' ;- I' ) v g Operation Operation for I' < b I N or I' < b I N Restraint b I H I N Protected I I unit I HEST 9 C Table 9 Thermal overload (9) Thermal image for the st order model Single or three-phase measurement with detection of maximum phase value Settings: Base current I B. to. I N in steps of. I N Alarm stage to % T N in steps of % N Tripping stage to % N in steps of % N Thermal time constant to min in steps of. min Accuracy of the thermal image ±% N (at f N ) Page

34 Distributed busbar protection REB Technical data (cont d) Table Peak value over- and undercurrent protection () Maximum or minimum function (over- and undercurrent) Single or three-phase measurements Wide frequency range (. to. f N ) Peak value evaluation Settings: Current. to I N in steps of. I N Delay to s in steps of.s Accuracy of pick-up value (at. to. f N ) ±% or ±. I N Reset ratio >9% (for max. function) <% (for min. function) Max. trip time with no delay (at f N ) ms (for max. function) ms (for min. function) Table Peak value over- and undervoltage protection (9) Maximum or minimum function (over- and undervoltage) Single or three-phase measurements Peak value evaluation Settings: Voltage. to U N in steps of. U N Delay to s in steps of. s Limiting f min to Hz in steps of Hz Accuracy of pick-up value (at. to. f N ) ±% or ±. U N Reset ratio >9% (for max. function) <% (for min. function) Max. trip time with no delay (at f N ) ms (for max. function) ms (for min. function) Table Frequency function () Maximum or minimum function (over- and underfrequency) Minimum voltage blocking Settings: Frequency to Hz in steps of. Hz Delay. to s in steps of. s Minimum voltage blocking. to. U N in steps of. U N Accuracy of pick-up value ± mhz at U N and f N Reset ratio % Starting time < ms Page

35 Distributed busbar protection REB Table Rate of change frequency protection df/dt () Maximum or minimum function (over- and underfrequency) Minimum voltage blocking Settings: df/dt - to + Hz/s in steps of. Hz/s Frequency to Hz in steps of. Hz at f N = Hz to Hz in steps of. Hz at f N = Hz Delay. to s in steps of. s Minimum voltage blocking. to. U N in steps of. U N Accuracy of df/dt (at.9 to. f N ) ±. Hz/s Accuracy of frequency (at.9 to. f N ) ± mhz Reset ratio 9% for max. function % for min. function Table Definite time overfluxing protection () Single-phase measurement Minimum voltage blocking Settings: Pick up value. to U N /f N in steps of. U N /f N Delay. to s in steps of. s Frequency range. to. f N Accuracy (at f N ) ±% or ±. U N /f N Reset ratio >9% (max.), <% (min.) Starting time ms Table Inverse time overfluxing protection () Single-phase measurement Inverse time delay according to IEEE Guide C.9-9 Setting made by help of table settings Settings: Table settings U/f values: (.;. to.) U N /f N Start value U/f. to. U N /f N in steps of. U N /f N t min. to min in steps of. min t max to min in steps of. min Reference voltage U B -value. to. U N in steps of. U N Accuracy of pick-up value. to. U N in steps of. U N Frequency range. to. f N Reset ratio % Starting time < ms Page

36 Distributed busbar protection REB Technical data (cont d) Table Power protection () Measurement of real or apparent power Protection function based on real or apparent power measurement Reverse power protection Over- and underpower Single or three-phase measurement Suppression of DC components and harmonics in current and voltage Compensation of phase errors in main and input CTs and VTs Settings: Power pick-up -. to. S N in steps of. PN Characteristic angle - to + in steps of Delay. to s in steps of. s Power factor comp. (Phi) - to + in steps of. Rated power PN. to. U N I N in steps of. U N I N Reset ratio % to % in steps of % of power pick-up Accuracy of the pick-up setting ±% of setting or % U N I N (for protection CTs) ±% of setting or.% U N I N (for core-balance CTs) Max. operating time without intentional delay ms Page

37 Distributed busbar protection REB Connection diagrams Inputs / outputs central unit Optional I/O board Binary inputs Binary outputs Binary inputs Binary outputs BIO BIO Optional redundant power supply aux Alarm Warning aux Alarm Warning PSM PSM Fig. Central unit module; Connection of power supply, binary inputs and outputs Abbreviations OCxx CRxx Explanation optocoupler Tripping relay Terminal block/ terminals A B P Explanation Binary inputs Binary outputs Power supply Wire gauge/ Type. mm. mm. mm Page

38 Distributed busbar protection REB Connection diagrams (cont d) Bay unit types Available inputs/outputs BU_ ( I, / I/O, stand-alone) BU_ ( I, U, / I/O, stand-alone) BU_ ( I, MT, U, / I/O, stand-alone) BU_ ( I, U, / I/O, stand-alone) red. power supply BU_ ( I, MT, U, / I/O, stand-alone)red. power supply BU_ ( I, / I/O, classic-mounting) BU_ ( I, U, / I/O, classic-mounting) BU_ ( I, MT, U, / I/O, classic-mounting) BU_ ( I, U, / I/O, classic-mounting) red. power supply BU_ ( I, MT, U, / I/O, classic-mounting) red. power supply BU_ (9 I, / I/O, stand-alone) BU_ (9 I, / I/O, stand-alone) red. power supply BU_ (9 I, / I/O, classic-mounting) BU_ (9 I, / I/O, classic-mounting) red. power supply Terminal block/ terminals Function Wire gauge/ Type A, B Binary inputs. mm C, D Binary outputs. mm E Rx Tx Optical connection Receive Transmit FST plug FST plug I, J Currents. mm U Voltages. mm P, R Supply. mm A Rx B E Tx Tx Rx C D J I[] I[] I[] I[] I[] I[] I[] I[] 9 I[] I[] I[] I[] I[] I[] I[] I9[] I9[] I9[] H I I[] I[] I[] I[] I[] I[] I[] I[] 9 I[] A Rx B E Tx Tx Rx C D U U[] U U[] U U[] U U[] U U[] U H I I[] I[] I[] I[] I[] I[] I[] I[] I[] I[] I[] I[] I[] I[] I[] I[] 9 I[] I[] I[] I[] I[] I[] I[] I[] HMI HMI Abbreviations OCxx CRxx OLxx Explanation Opto-coupler Tripping relay Optical link I R + - DC I P + - I R + - DC I P + - BU BU A 9 Binary Inputs OC OC OC OC OC Processbus OL Binary Outputs CR Tx E Rx C J Current Transformer I I I Current Transformer I I U Voltage Transformer U U I Current Transformer I I OC CR B 9 OC OC OC9 OC OC OC OC OC OC OC OC OC OC9 OC CR CR CR CR CR CR CR9 CR CR CR CR CR CR CR 9 D 9 9 R I Redundant Power Supply + _ I I I9 9 H P + _ Power Supply I HMI Interface R Redundant Power Supply + _ U U U 9 H P I I HMI Interface Power Supply + _ *) *) Measuring transformer in BU_ or BU_ Fig. Wiring diagram of bay units BU, types - Page

39 Distributed busbar protection REB Bay unit types Available inputs/outputs BU_ ( I, U, / I/O, stand-alone) BU_ ( I, U, / I/O, stand-alone) BU_ 9 ( I, U, / I/O, stand-alone) red. power supply BU_ ( I, U, / I/O, stand-alone) red. power supply BU_ ( I, U, / I/O, classic-mounting) BU_ ( I, U, / I/O, classic-mounting) BU_ 9 ( I, U, / I/O, classic-mounting) red. power supply BU_( I, U, / I/O, classic-mounting) red. power supply Terminal block/ terminals Function Wire gauge/ Type A, B Binary inputs. mm C, D Binary outputs. mm E Rx Tx Optical connection Receive Transmit FST plug FST plug I Currents. mm J Currents and voltages P, R Supply. mm Abbreviations OCxx CRxx OLxx Explanation Opto-coupler Tripping relay Optical link A B Rx E Tx Tx Rx C D J I[] I[] I[] I[] I[] I[] I[] I[] 9 I[] U U[] U U[] U U[] H DC I[] I[] I[] I[] I[] I[] I[] I[] 9 I[] HMI I A B Rx E Tx Tx Rx C D J I[] I[] I[] I[] I[] I[] I[] I[] 9 I[] I[] I[] I[] I[] I[] I[] U U[] H DC I[] I[] I[] I[] I[] I[] I[] I[] 9 I[] HMI I I I I I R + - P + - R + - P + - BU BU A 9 Binary Inputs OC OC OC OC OC Processbus OL Binary Outputs CR Tx E Rx C J Current Transformer I I I Current Transformer I I J Current Transformer I I I Current Transformer I I B 9 OC OC OC OC9 OC OC OC OC OC OC OC OC OC OC9 OC CR CR CR CR CR CR CR CR9 CR CR CR CR CR CR CR 9 D 9 9 R I Redundant Power Supply + _ Voltage Transformer U U U 9 H P + _ Power Supply I HMI Interface 9 R Redundant Power Supply + _ I I I Voltage Transformer U 9 H P + _ Power Supply I HMI Interface Fig. Wiring diagram of bay units BU, types 9- Page 9

40 Distributed busbar protection REB Connection diagrams (cont d) Bay unit BU connection diagrams A detailed description of each variant is given in the application description []. Bay unit Protection functions BU Station level Bay level Measurement value Analog inputs Busbar protection Breaker failure protection End fault protection Pole discrepancy protection Voltage check Disturbance recorder Distance protection Definite time over and undercurrent protection Inverse time overcurrent protection Directional overcurrent definite time protection Directional overcurrent inverse time protection Definite time over and undervoltage protection Synchrocheck Direct. sensitive EF prot. for grounded systems Direct. sensitive EF prot. for ungr. or comp. systems Inverse time earth fault overcurrent protection Current plausibility check Voltage plausibility check Currents 9 I I I I Phase current L (Line) Phase current L (Line) Phase current L (Line) Neutral current Lo (Y) (Line) Derived internally Neutral current derrived internally Io= IL+IL+IL Voltages U U U U U Phase voltage L (Line) Phase voltage L (Line) Phase voltage L (Line) Phase voltage L (Bus ) ph -> L-E Phase voltage L (Bus ) ph -> L-E Derived internally Neutral voltage derrived internally Uo= UL+UL+UL Current transformer/voltage transformer fixed assignment Recommended setting/ respectively free for selection (configured via software HMI-REBWIN) Only for busbar protection Io-measurement (optional function) Bay unit types with measuring CT (torroid CT) on input I Fig. Bay unit connection diagram BU, I, U Page

41 Distributed busbar protection REB Bay unit Protection functions BU Station level Bay level Measurement value Analog inputs Busbar protection Breaker-failure protection End-fault protection Pole discrepancy protection Disturbance recorder Transformer differential protection Thermal overload Peak value over and undercurrent protection Inverse time overcurrent protection Inverse time earth fault overcurrent protection Definite time over and undercurrent protection Three phase current plausibility Currents I 9 I I I Phase current L A-side Phase current L A-side Phase current L A-side Derived internally Neutral current derrived internally Io= I L +I L +I L Currents J 9 Derived internally Currents J Derived internally I I I I I I9 Phase current L B-side Phase current L B-side Phase current L B-side Neutral current derrived internally Io= I L +I L +I L Phase current L C-side (if existing) Phase current L C-side (if existing) Phase current L C-side (if existing) Neutral voltage derrived internally Uo= U L +U L +U L A-side B-side C-side Current transformer, fixed assignment Recommended setting/ respectively free for selection (configured via software HMI-REBWIN) Only for busbar protection Io-measurement (optional function) Configured either on A-side, or on B-side or on C-side respectively Transformer primary side Transformer secondary side Transformer tertiary side Fig. Bay unit connection diagram BU, 9I Page

42 Distributed busbar protection REB Connection diagrams (cont d) Bay Unit Protection functions BU Station level Bay level Measurement value Analog inputs Busbar protection Breaker failure protection End fault protection Pole discrepancy protection Disturbance recorder Distance protection Definite time over and undercurrent protection Inverse time overcurrent protection Directional overcurrent definite time protection Directional overcurrent inverse time protection Definite time over and undervoltage protection Direct. sensitive EF prot. for grounded systems Inverse time earth fault overcurrent protection Three phase current plausibility Three phase voltage plausibility Transformer differential protection 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 Power Currents I 9 Derrived internally Currents J 9 I I I I I I Phase current L A-side Phase current L A-side Phase current L A-side Neutral current derrived internally Io= I L +I L +I L Phase current L B-side Phase current L B-side Phase current L B-side Derrived internally Neutral current derrived internally Io= I L +I L +I L Voltages J U U U Phase voltage L A-side or B-side Phase voltage L A-side or B-side Phase voltage L A-side or B-side Derrived internally Neutral voltage derrived internally Uo= U L +U L +U L Current transformer/voltage transformer fixed assignment Recommended setting/ respectively free for selection (configured via software HMI-REBWIN) Only for busbar protection Io-measurement (optional function) Configured either on A-side, or on B-side respectively A-side B-side Transformer primary side Transformer secondary side Fig. Bay unit connection diagram BU, I, U Page

43 Distributed busbar protection REB Bay Unit Protection functions BU Station level Bay level Measurement value Analog inputs Busbar protection Breaker failure protection End fault protection Pole discrepancy protection Disturbance recorder Definite time over and undercurrent protection Inverse time overcurrent protection Inverse time earth fault overcurrent protection Three phase current plausibility Transformer differential protection Thermal overload Peak value over and undercurrent protection Definite time overfluxing protection Inverse time overfluxing protection Currents I 9 I I I Phase current L A-side Phase current L A-side Phase current L A-side Derrived internally Neutral current derrived internally Io= I L +I L +I L Currents J 9 I I I Phase current L B-side Phase current L B-side Phase current L B-side Derrived internally Neutral current derrived internally Io= I L +I L +I L Currents J I I Current Lx (e.g. Lo) Current Lx (e.g.lo) Voltages J U Voltage Lx (e.g. Phase L-L -> Overfluxing protection ) Current transformer/voltage transformer fixed assignment Recommended setting/ respectively free for selection (configured via software HMI-REBWIN) Only for busbar protection Io-measurement (optional function) Configured either on A-side, or on B-side respectively A-side Transformer primary side B-side Transformer secondary side Fig. Bay unit connection diagram BU, I, U Page

44 Distributed busbar protection REB Connection diagrams (cont d) REB: Typical assignment of the in/outputs Binary inputs Binary outputs Accept bus image alarm OC External reset Block of all protection functions OC OC CR CR Protection blocked / Output relays blocked Test generator active Block output relays OC CR Isolator alarm Block busbar protection OC CR Switch inhibited Block breaker failure protection 9 OC CR 9 System alarm OC OC CR In service OC9 OC CR Differential current alarm OC CR Busbar protection tripped CR9 Breaker failure protection tripped OC Fig. REB: Typical assignment of the in/outputs of a central unit for busbar and breaker failure protection Binary Inputs Binary outputs Start BFP protection L Start BFP protection L OC OC A C CR In Service Start BFP protection L rt BFP protection LLL OC OC CR Block close command 9 Start BFP protection L Start BFP protection L Start BFP protection L t BFP protection LLL OC OC OC OC CR CR CR CR CR 9 Remote Trip, channel Remote Trip, channel OC9 OC OC OC B D CR CR9 CR Bus Isolator Q off Bus Isolator Q on Bus Isolator Q off 9 OC OC OC CR CR CR Trip Phase L, trip coil 9 Trip Phase L, trip coil Trip Phase L, trip coil Bus Isolator Q on OC OC OC CR CR CR Trip Phase L, trip coil Trip Phase L, trip coil Trip Phase L, trip coil OC9 OC Fig. 9 REB: Typical assignment of the in/outputs for a double busbar with busbar and breaker failure protection of a bay unit Page

45 Distributed busbar protection REB REBsys: Typical assignment of the in-/outputs Binary Inputs Variant L-V Binary outputs Variant L-V Start BFP protection L Start BFP protection L Start BFP protection L Start BFP protection LLL OC OC OC OC A C CR CR In Service Block close command Carrier Receive, Distance Prot. Carrier Receive, DEF Prot. Bus VT MCB Fail Bus VT MCB Fail 9 OC OC OC OC CR CR CR CR CR 9 AR Close Command Remote Trip, channel Carrier Send, Distance Prot. Remote Trip, channel Carrier Send, DEF Prot. Breaker Q Close Command Line VT MCB Fail CB All Poles Closed for DEF Prot. OCO Ready for AR Release OC9 OC OC OC B D CR CR9 CR Start LLL to AR in Main Trip CB -Pole to AR in Main Trip CB to AR in Main Bus Isolator Q off Bus Isolator Q on Bus Isolator Q off 9 OC OC OC CR CR CR 9 Trip Phase L, trip coil Trip Phase L, trip coil Trip Phase L, trip coil Bus Isolator Q on Breaker Q off Breaker Q on OC OC OC CR CR CR Trip Phase L, trip coil Trip Phase L, trip coil Trip Phase L, trip coil Prepare Pole Trip,from Main Main Healthy/In Service Mode (Blk. AR) OC9 OC Fig. REBsys: Typical assignment of the in-/outputs of line variant L-V for BU (See [] Application description) Page

46 Distributed busbar protection REB Connection diagrams (cont d) Binary inputs Transformer Variant Binary outputs Transformer Variant Start BFP phase LLL from prot. group TRIP External start BFP from mechanic prot. TRIP Start BFP phase LLL from back-up prot. TRIP Spare OC OC OC OC A C CR CR In service Block close command breaker Q A-side Mechanic protection TRIP Mechanic protection alarm Mechanic protection TRIP Mechanic protection alarm A-side breaker Q manual close command 9 OC OC OC OC OC9 CR CR CR CR CR 9 Transf. prot. trip LLL group Tripping relay (9-) trip CB A/B/C side *) Transf. prot. trip start BFP on C-side *) Remote trip to B-side Transf. prot. trip LLL group Tripping relay (9-) trip CB A/B/C side *) Block transformer diff. protection Transformer diff. inrush input Transformer diff. high-set A-side bus isolator Q open OC OC OC OC B D CR CR9 CR Remote trip to B-side Remote Trip to C-side *) Transf. prot. trip start BFP on B-side A-side bus isolator Q closed A-side bus isolator Q open A-side bus isolator Q closed A-side breaker Q open A-side breaker Q closed Spare Spare 9 OC OC OC OC OC OC9 OC CR CR CR CR CR CR 9 Trip phase L Trip phase L Trip phase L Trip phase L Trip phase L Trip phase L Trip breaker Q coil A-side Trip breaker Q coil A-side Legend: A-side Transformer primary side B-side Transformer secondary side C-side Transformer tertiary side *) *) C-side, if existing Fig. REBsys: Typical assignment of the in-/outputs of transformer variant T-V for BU (See [] application description) Page

47 Space for wiring Substation Automation Products Distributed busbar protection REB Dimensioned drawings (in mm) Bay unit BU Cross section: max.. mm max.. mm Achtung Caution Attention Atencion Fig. Bay unit casing for flush mounting, enclosure protection class IP (without local HMI) Cross section: max.. mm max.. mm Space for wiring Fig. Centralized version based on a 9'' mounting plate with up to three bay units. Optionally with local HMI. Page

48 ±. +. Substation Automation Products Distributed busbar protection REB Dimensioned drawings (in mm) (cont d) Bay unit BU Cross section max.. mm max.. mm approx. Space for wiring 9 U=. ±. Fig. Panel cutout Dimensional drawing of the bay unit with local HMI, classical mounting protection type IP Central unit. approx. Rear view... U=.. approx. Fig. Dimensional drawing of the central unit, protection type IP Page

49 Substation Automation Products Distributed busbar protection REB Cubicle mounting Fig. Front view of REB (example only) Fig. Hinged frame and rear wall Example with 9 bay units The cubicles are equipped with gratings for the fixation of incoming cables. For space reasons there are no cable ducts. Table Maximum number of units per cubicle (central version) Unit Current transformer per bay Voltage transformer per bay Quantity of BU 9 - Cross-section ext. cable Quantity of system cables per bay. mm - mm. mm - mm Binary inputs per bay. mm -. mm - Binary outputs per bay. mm -. mm - Max. number of bays per cubicle with central unit 9* Max. number of bays per cubicle without central unit * * number of bays per cubicle ( x x mm) based on the min. cross-section and an average quantity of cables Page 9

50 Distributed busbar protection REB Cubicle mounting (cont d) Table Unit weights Unit Bay unit l, classic (incl. HMI) Bay unit l, U, red. power supply, classic (incl. HMI) Bay unit l, MT, U, red. power supply, classic (incl. HMI) Bay unit l, basic version Bay unit l, U, red. power supply, basic version Bay unit l, MT, U, red. power supply, basic version Bay unit 9I, red. power supply, classic (incl. HMI) Bay unit 9I, red. power supply, basic version Central unit Central unit with redundant power supply Weight. kg. kg.9 kg. kg. kg. kg 9. kg (Average weight => here feeders plus communication interface). kg Basic version Basic version with HMI Classic version Fig. 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. The architecture shall be decentralized, with bay units and a central unit. It shall be suitable for the protection of single and double busbar as well as for the protection (Main or back-up) of incoming and outgoing bays, lines, cables or transformer bays. The hardware shall allow functions to be activated from a software library: Busbar protection scheme based on lowimpedance principle and at least two independent tripping criteria End fault protection Breaker failure protection Breaker pole discrepancy Additional criteria for the busbar protection as overcurrent or voltage release Over-/undercurrent and over-/undervoltage back-up bay function (overcurrent directional or non-directional) Page

51 Distributed busbar protection REB Distance protection function with all relevant additional features, such as switch-onto-fault, teleprotection schemes, voltage supervision, 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, 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 adaptation of the CTratio is done by software. A modern human machine interface shall allow the allocation of input and output signals. Communication via computer or via interface to monitoring or control systems allows the actual configuration of the whole busbar to be displayed. Event and disturbance recording shall be included, collection of data in the bay units, comprehensive recording available for the whole station in the central unit. The proposed system shall be easily extensible, in case of extensions in the substation. Ordering Ordering When sending your enquiry please provide the short version of the questionnaire on page in this data sheet together with a single-line diagram of the station. This will enable us to submit a tender that corresponds more accurately to your needs. Page

52 Distributed busbar protection REB Ordering (cont d) Ordering code REB-CU-V -S -P -B -CA -CB Equipped for bay units bay units bay units bay units, incl. nd rack bay units, incl. nd rack bay units, incl. nd rack Red. Power Supply No Yes, for - bay units Yes, for - bay units nd Binary Input Module No ( inputs / 9 outputs) Yes ( inputs / outputs) Communication Interface A No LON IEC IEC -- Communication Interface B No LON IEC IEC -- Page

53 Distributed busbar protection REB Short questionnaire mandatory ordering information Accessories HMI software HMI Ver../. Operator Quantity MRBR HMI Ver../. Configurator * Quantity MRBR * HMI Configurator is including software license for users (authorization by serial number). Please note license is only provided for trained customers! Central unit module CIM Communication card IEC,IEC Quantity MRBR CIM Communication card IEC,IEC, LON Quantity MRBR CPU Processor unit complete Quantity MRBR BIO Binary I/O card Quantity MRBR PSM Power supply W Quantity MRBR SCM Star coupler module Quantity MRBR Manuals Operating instructions REB/REBsys in English Quantity MRB9-Uen Fiber optic cables core FO-cable *. m, indoor, ready made incl. connectors Quantity HESPR core FO-cable *. m, indoor, ready made incl. connectors Quantity HESPR core FO-cable *. m, indoor, ready made incl. connectors Quantity HESPR core FO-cable *. m, indoor, ready made incl. connectors Quantity HESPR Page