power system protection - siemens power engineering guide

Siemens Power Engineering Guide · Transmission & Distribution6/8

Introduction

Siemens is one of the world’s leading sup-pliers of protective equipment for powersystems.Thousands of our relays ensure first-classperformance in transmission and distribu-tion networks of all voltage levels, all overthe world, in countries of tropical heat orarctic frost.For many years, Siemens has also signifi-cantly influenced the development of pro-tection technology.■ In 1976, the first minicomputer (process

computer) based protection system wascommissioned: A total of 10 systemsfor 110/20 kV substations were suppliedand are still operating satisfactorily today.

■ Since 1985 we have been the first tomanufacture a range of fully numericalrelays with standardized communicationinterfaces.Today, Siemens offers a complete pro-gram of protective relays for all applica-tions including numerical busbar protec-tion.To date (1996), more than 50,000 numer-ical protection relays from Siemens areproviding successful service, as stand-alone devices in traditional systems oras components of coordinated protec-tion and substation control.Meanwhile, a second-generation inno-vative series has been launched, incor-porating the many years of operationalexperience with thousands of relays,together with users’ requirements,(power authority reommendations).

State of the art

Mechanical and solid-state (static) relayshave been almost completely phased outof our production because numerical relaysare now preferred by the users due totheir decisive advantages:■ Compact design and lower cost due to

integration of many functions into onerelay

■ High availability even with less mainte-nance due to integral self-monitoring

■ No drift (aging) of measuring characteris-tics due to fully numerical processing

■ High measuring accuracy due to digitalfiltering and optimized measuring algo-rithms

■ Many integrated add-on functions,for example, for load-monitoring andevent/fault recording

■ Easy and secure read-out of informationvia serial interfaces with a PC, locally orremotely

■ Possibility to communicate with higher-level control systems

Fig. 12: Numerical relay range of Siemens

Power System Protection

Siemens Power Engineering Guide · Transmission & Distribution 6/9

Modern protection management

All the functions, for example, of a line pro-tection scheme can be incorporated in oneunit:■ Distance protection with associated

add-on and monitoring functions■ Universal teleprotection interface■ Autoreclose and synchronism check

Protection-related information, can becalled up on-line or off-line such as:■ Distance to fault■ Fault currents and voltages■ Relay operation data (fault detector pick-

up, operating times etc.)■ Set values■ Line load data (kV, A, MW, kVAr)To fulfill vital protection redundancy require-ments, only those functions which are in-terdependent and directly associated witheach other are integrated in the same unit.For back-up protection, one or more addi-tional units have to be provided.

Supervisory control

2167NFL792585SMERFRBM

Distance protectionDirectional ground-fault protectionDistance-to-fault locatorAutoreclosureSynchro-checkCarrier interface (teleprotection)Self-monitoringEvent recordingFault recordingBreaker monitor

Breaker monitor

Relay monitor

Fault record

01.10.93

Fault report

BM

Serial link to station – or personal computer

SM ER FR2579FL67N21

to remote line end kA,kV,Hz,MW,MVAr,MVA,

85

Load monitor

All relays can stand fully alone. Thus thetraditional protection concept of separatemain and alternate protection as well asthe external connection to the switchyardremain unchanged.

”One feeder, one relay“ concept

Analog protection schemes have been en-gineered and assembled from individualrelays. Interwiring between these relaysand scheme testing has been carried outmanually in the workshop.Data sharing now allows for the integrationof several protection and protection relatedtasks into one single numerical relay. Onlya few external devices may be required forcompletion of the total scheme. This hassignificantly lowered the costs of engineer-ing, assembly, panel wiring, testing andcommissioning. Scheme failure probabilityhas also been lowered.Engineering has moved from schematicdiagrams towards a parameter definitionprocedure. The documentation is providedby the relay itself. Free allocation of LEDoperation indicators and output contactsprovides more application design flexibility.

Metering included

For many applications, the protective-cur-rent transformer accuracy is sufficient foroperational metering. The additional meter-ing c.t. was more for protection of metersunder system fault conditions. Due to thelow thermal withstand ability of the me-ters, they could not be connected to theprotection c.t.. Consequently, additionalmetering c.t.s and meters are now onlynecessary where high accuracy is required,e.g. for revenue metering.

Fig. 13: Numerical relays, increased information availability



On-line remote data exchange

A powerful serial data link provides forinterrogation of digitized measured valuesand other information, stored in the pro-tection units, for printout and furtherprocessing at the substation or systemcontrol level.In the opposite direction, settings may bealtered or test routines initiated from a re-mote control center.For greater distances, especially in outdoorswitchyards, fiber-optic cables are prefera-bly used. This technique has the advantagethat it is totally unaffected by electromag-netic interference.

Off-line dialog with numerical relays

A simple built-in operator panel whichrequires no special software knowledge orcodeword tables is used for parameterinput and readout.This allows operator dialog with the protec-tion relay. Answers appear largely in plain-text on the display of the operator panel.Dialog is divided into three main phases:■ Input, alternation and readout of settings■ Testing the functions of the protection

device and■ Readout of relay operation data for the

three last system faults and the autore-close counter.

Modern system protectionmanagement

A more versatile notebook computer maybe used for upgraded protection manage-ment.The relays may be set in 2 steps. First, allrelay settings are prepared in the officewith the aid of a PC and stored on a floppyor the hard disk. At site, the settings canthen be transferred from a portable PC intothe relay. The relay confirms the settingsand thus provides an unquestionablerecord.Vice versa, after a system fault, the relaymemory can be uploaded to a PC andcomprehensive fault analysis can then takeplace in the engineer’s office.

Protection Laptop

RecordingPersonal computer

Assigning

Recording andconfirmation

System level to remote control

Substationlevel

Modem(option)

Bay level

Dataconcentrator

ERTU

Control

Coordinatedprotection & control

RTU

Relay

Fig. 14: PC-aided setting procedure

Fig. 15: Communication options



Parameter

Line data

O/C Phase settings

O/C Earth settings

Fault Recording

Breaker Fall

1000

1100

1200

1500

2800

3900

DParameter

Line data

O/C Phase settings

O/C Earth settings

Fault Recording

Breaker Fall

1000

1100

1200

1500

2800

3900

CParameter

Line data

O/C Phase settings

O/C Earth settings

Fault Recording

Breaker Fall

1000

1100

1200

1500

2800

3900

BParameter

Line data

O/C Phase settings

O/C Ground settings

Fault recording

Breaker fail

1000

1100

1200

1500

2800

3900

A

Relay data management

Analog-distribution-type relays have some20–30 setpoints. If we consider a powersystem with about 500 relays, then thenumber adds up to 10,000 settings. Thisrequired considerable expenditure in set-ting the relays and filing retrieval setpoints.A personal computer-aided man-machinedialog and archiving program assists therelay engineer in data filing and retrieval.The program files all settings systemati-cally in substation-feeder-relay order.

Corrective rather than preventivemaintenance

Numerical relays monitor their own hard-ware and software. Exhaustive self-moni-toring and failure diagnostic routines arenot restricted to the protective relay inself,but are methodically carried through fromcurrent transformer circuits to tripping re-lay coils.Equipment failures and faults in the c.t. cir-cuits are immediately reported and the pro-tective relay blocked.Thus the service personnel is now able tocorrect the failure upon occurrence, result-ing in a significantly upgraded availability ofthe protection system.

Adaptive relaying

Numerical relays now offer secure, con-venient and comprehensive matching tochanging conditions. Matching may be initi-ated either by the relay’s own intelligenceor from the outside world via contacts orserial telegrams. Modern numerical relayscontain a number of parameter sets thatcan be pretested during commissioning ofthe scheme (Fig. 17). One set is normallyoperative. Transfer to the other sets can becontrolled via binary inputs or serial datalink. There are a number of applications forwhich multiple setting groups can upgradethe scheme performance, e.g.a) for use as a voltage-dependent control

of o/c relay pick-up values to overcomealternator fault current decrement to be-low normal load current when the AVRis not in automatic operation.

b) for maintaining short operation timeswith lower fault currents, e.g. automaticchange of settings if one supply trans-former is taken out of service.

c) for “switch-onto-fault” protection to pro-vide shorter time settings when energiz-ing a circuit after maintenance.The normal settings can be restoredautomatically after a time delay.

Fig. 16: System-wide setting and relay operation library

Fig. 17: Alternate parameter groups

10 000setpoints

systemca. 500relays

200setpoints

sub

bay

20setpoints

bay

4flags

OH-Line

1200flagsp. a.

system

Relay operationsSetpoints

1

1

1

300 faults p. a.ca. 6,000 km OHL(fault rate:5 p. a. and 100 km)

d) for autoreclose programs, i.e. instanta-neous operation for first trip and delayedoperation after unsuccessful reclosure.

e) for cold load pick-up problems wherehigh starting currents may cause relayoperation.

f) for ”ring open“ or ”ring closed“ oper-ation.



Mode of operation

Numerical protection relays operate on thebasis of numerical measuring principles.The analog measured values of current andvoltage are decoupled galvanically from theplant secondary circuits via input transduc-ers (Fig. 18). After analog filtering, thesampling and the analog-to-digital conver-sion take place. The sampling rate is, de-pending on the different protection princi-ples, between 12 and 20 samples perperiod. With certain devices (e.g. generatorprotection) a continuous adjustment of thesampling rate takes place depending onthe actual system frequency.The protection principle is based on a cy-clic calculation algorithm, utilizing the sam-pled current and voltage analog measuredvalues. The fault detections determined bythis process must be established in severalsequential calculations before protectionreactions can follow.A trip command is transferred to the com-mand relay by the processor, utilizing adual channel control.The numerical protection concept offers avariety of advantages, especially with re-gard to higher security, reliability and userfriendliness, such as:

Meas. inputs

Current inputs(100 x /N, 1 s)

Voltage inputs(140 Vcontinuous)

A/Dconverter

Processorsystem

Input filter V24Serialinterface

PC interfaceLSA interface

Memory:RAMEEPROMEPROM

Input/outputports

Input/outputunits

Binaryinputs

Alarmrelay

Commandrelay

LEDdisplays0001

01010011

Amplifier

Input/output contactsdigital10 Vanalog

100 V/1 A, 5 Aanalog

O. F.

■ High measurement accuracy:The high ultilization of adaptive algo-rithms produce accurate results evenduring, problematic conditions

■ Good long-term stability:Due to the digital mode of operation,drift phenomena at components due toageing do not lead to changes in accura-cy of measurement or time delays

■ Security against over- and underfunctionWith this concept the danger of an unde-tected error in the device causing protec-tion failure in the case of a network faultis clearly reduced when compared to con-ventional protection technology. Cyclicaland preventive maintenance services havetherefore become largely obsolete.The integrated self-monitoring system(Fig. 19) encompasses the following areas:– Analog inputs– Microprocessor system– Command relays.

Setting of protection relays

Numerical protection devices are able tohandle a number of additional protectionrelated functions, for which additional de-vices were required in the past.

A compact numerical protection device canreplace a number of complicated conven-tional single devices.Protection functions, configurations andmarshalling data are selected by parametersetting. Functions can be activated or de-activated by configuration.By marshalling internal logic alarms (whichare produced by certain device functionson the software side) to light-emittingdiodes or to alarm relays, an allocationbetween these can be made (Fig. 20).The same also applies to the input con-tacts.A flexible application according to thespecific requirements of the plant configu-ration is possible thanks to the extensivemarshalling and configuration options.All set values are stored in E2PROMS.In this way the settings cannot be lost asa result of supply failure.The setting values are accessed via 4-digitaddresses.Each parameter can be accessed and al-tered via the integrated operator panel oran externally connected operator terminal.

Fig. 18: Block diagram of numerical protection



The display appears on an alphanumericLCD display with 2 lines with 16 charactersper line. A code word prevents uninten-tional changes of setting values.Some relays allow for the storage of4 different sets of protection settings. Viabinary inputs or via the operator panel aparticular set of setting values can be acti-vated (switching of settings groups).

Fault analysis

The evaluation of faults is simplified by nu-merical protection technology. In the eventof a fault in the network, all events as wellas the analog traces of the measured volt-ages and currents are recorded.The following types of memory are avail-able:■ 1 operational event memory

Alarms that are not directly assigned toa fault in the network (e.g. monitoringalarms, alternation of a set value, block-ing of the automatic reclose function).

■ 3 fault-event historiesAlarms that occurred during the last3 faults on the network (e.g. type offault detection, trip commands, fault lo-cation, autoreclose commands). A re-close cycle with one or more reclosuresis treated as one fault history. Each newfault in the network overrides the oldestfault history.

■ A memory for the fault recordings forvoltage and current. Up to 8 fault record-ings are stored. The fault recordingmemory is organized as a ring buffer, i.e.a new fault entry overrides the oldestfault record.

■ 1 earth-fault event memory (optional forisolated or resonant grounded networks)Event record of the sensitive earth faultdetector (e.g. faulted phase, real compo-nent of residual current).

The time tag attached to the fault-recordevents is a relative time from fault detec-tion with a resolution of 1 ms. In the caseof devices with integrated, battery back-upclock the operational events as well as thefault detection are assigned the internalclock time and date stamp.The memory for operational events andfault record events is protected against fail-ure of auxiliary supply with battery back-upsupply.The integrated operator interface or a PCsupported by the programming tool DIGSIis used to retrieve fault reports as well asfor the input of settings and marshalling.

Plausibility check of input quantitiese.g. iL1 + iL2 + iL3 = iE

uL1 + uL2 + uL3 = uE

Check of analog-to-digital conversionby comparison withconverted reference quantities

A

D

Hardware and software monitoring ofthe microprocessor system incl. memory,e.g. by watchdog and

cyclic memory checks

Micro-processorsystem

Monitoring of the tripping relaysoperated via dual channels

Relay

Tripping check or test reclosure by localor remote operation (not automatic)

Logical signal

LED1

LED2

LED3

LED4

LED5

LED6

LED7

. . .LED No.

Start L1

Start L2

Start L3

Start E

Trip

Autoreclosure

.

.

.


Fig. 20: Marshalling matrix, LED control as an example

Fig. 19: Self-monitoring system


A further source of information is the indi-cation via LEDs and alarm relays, as wasthe case with traditional relays. The LEDscan be selected on an individual basis toprovide the indication stored or unstored,depending on what information they repre-sent. In the case of devices with internalbattery back-up, the LED indications arerestored following an auxiliary power sup-ply failure. The alarm relays in these de-vices provide N0-type contacts, some ofthem changeover contacts.

Operation of numerical protectiondevices

The DIGSI operation software enables con-venient and transparent operation of thenumerical protection devices using a PC.The new DIGSI V3 version operates underWINDOWS and can therefore make useof all advantages of this internationally ac-cepted user interface.DIGSI V3 uses protocol-secured data ex-change between PC and protection device.This data exchange also meets the stand-ard recommendations for the interface be-tween protection equipment and stationcontrol equipment (IEC 870-5-103).

Application

DIGSI V3 is a WINDOWS PC program,with which numeric protection relays canbe conveniently operated under menuguidance using the serial interface of a PC(see Fig. 21). The PC can thus be directlyconnected with the protection device via aV24 (RS232) interface cable. The isolatedconnection version using optoelectricalconverter and fiber-optic cable is recom-mended, particularly if the protection de-vice is in operation in the substation.

Hardware and software platform

■ PC 386 SX or above, with at least4 Mbytes RAM

■ DIGSI V3 requires about 10 Mbytesharddisk space

■ Additional hard-disk space per installedprotection device 2 to 3 Mbytes

■ One free serial interface to the protec-tion device (COM 1 to COM 4)

■ One floppy disk drive 3.5", high densitywith 1.44 Mbytes (required for installa-tion)

■ MS DOS 5.0 or higher■ WINDOWS version 3.1 or higher


Fig. 21: Operation of the protection relays using PC and DIGSI V3 software program

Fig. 22: Parameterization using DIGSI V3



Operation features

The DIGSI V3 user interface is structuredin accordance with the SAA/CUA standardused for WINDOWS programs (see Fig. 22).The selection of a system, a feeder and aprotection device is implemented in DIGSIV3, using system, bay and protection unitaddresses. Consistent use of this principle,which will be supported in future both inprotection devices and DIGSI file manage-ment, prevents incorrect allocation of pro-tection units within a system.DIGSI V3 supports the complete parame-terization and marshalling functionality ofthe numeric Siemens protection relays.Parameterization and routing of a protec-tion device can be done in file mode.All advanced storage media for manage-ment and archiving of this data (e.g. mem-ory cards, exchangeable hard disks, opto-disks, etc.) are provided. Device files of aprotection unit created in the office can betransferred subsequently with protocol-security into the protection unit. Data con-sistency is ensured, for example, by auto-matic comparison of data stored on a fileand in the device.DIGSI V3 permits the readout of operation-al and fault events from a protection de-vice which are stored with a 1 millisecondrealtime resolution. This enables effectiveand rapid fault analysis, which contributesto optimization of protection in networkoperation. Archiving and printout are con-veniently supported. The polling procedureis defined as a standard.Likewise, measured load values of a pro-tection device can be read out on-line andrecorded. Integration of extensive testfunctions facilitate the PC-guided commis-sioning and testing of a protection device.

Printer, plotter, networks

DIGSI V3 uses the full WINDOWS inter-face functionality. All common printers andplotters for which WINDOWS drivers areavailable can be used with DIGSI V3. Theuser is therefore not faced with any restric-tions when purchasing printers or plottersas long as WINDOWS drivers are available.Even transmission of information via faxfrom DIGSI V3 can be implemented.Linking into the PC network and remoteaccess to DIGSI V3 via communication net-works (e.g. ISDN) are part of the frame-work as supported by the WINDOWS op-erating system.

Evaluation of the fault recording

Readout of the fault record from the pro-tection device by DIGSI V3 is done byfault-proof scanning procedures in accord-ance with the standard recommendationfor transmission of fault records.A fault record can also be read out repeat-edly. In addition to analog values, such asvoltage and current, binary tracks can alsobe transferred and presented.DIGSI V3 is supplied together with theDIGRA (Digsi Graphic) program, whichprovides the customer with full graphicaloperating and evaluation functionality likethat of the digital fault recorders (Oscil-lostores) from Siemens (see Fig. 23).Real-time presentation of analog distur-bance records, overlaying and zooming ofcurves, visualization of binary tracks (e.g.trip command, reclose command, etc.) arealso part of the extensive graphical func-tionality as are setting of measurementcursors, spectrum analysis and R/X deriva-tion.

Fig. 23: Display and evaluation of a fault record using DIGSI V3

Data security, data interfaces

DIGSI V3 is a closed system as far as pro-tection parameter security is concerned.The security of the stored data of the oper-ating PC is ensured by checksums. Thismeans that it is only possible to changedata with DIGSI V3, which subsequentlycalculates a checksum for the changeddata and stores it with the data. Changesin the data and thus in safety-related pro-tection data are thus reliably detected.DIGSI V3 is, however, also an open sys-tem. The data export function supports ex-port of parameterization and marshallingdata in standard ASCII format. This permitssimple access to these data by other pro-grams, such as test programs without en-dangering the security of data within theDIGSI program system.With the import and export of fault recordsin IEEE standard format COMTRADE(ANSI) a high performance data interfaceis produced which supports import andexport of fault records into the DIGSI V3partner program DIGRA.This enables the export of fault recordsfrom Siemens protection units to custom-er-specific programs via the COMTRADEformat.



Remote relay interrogation

The numerical relay range 7**5 of Siemenscan also be operated from a remotely lo-cated PC via modem-telephone connec-tion.Up to 254 relays can be addressed viaone modem connection if the star coupler7XV53 is used as a communication node(Fig. 24).The relays are connected to the star cou-pler via optical fiber links.Every protection device which belongs toa DIGSI V3 substation structure has aunique address.The attached relays are always listening,but only the addressed one answers to theoperator command which comes from thecentral PC.If the relay which is located in a stationis to be operated from a remote office,then a device file is opened in DIGSI (V3.2or higher) and protection dialog is chosenvia modem. After password input, DIGSIestablishes a connection to the protectiondevice after receiving a call-back from thesystem.In this way secure and timesaving remotesetting and readout of data are possible.Diagnostics and control of test routines arealso possible without the need for visitingthe substation.

Housing and terminal system

The protection devices and the corre-sponding supplementary devices are avail-able mainly in 7XP20 housings (Fig. 26).The dimension drawings are to be foundon 6/24 and following pages. Installing ofthe modules in a cubicle without the hous-ing is not permissible.The width of the housing conforms to the19" system with the divisions 1/6, 1/3, 1/2or 1/1 of a 19" rack. The termination mod-ule is located at the rear of devices forpanel flush mounting or cubicle mounting(Fig. 26 left). Each termination may bemade via a screw terminal or crimp con-tact. The termination modules used eachcontain:■ 4 termination points for measured volt-

ages, binary inputs or relay outputs(max. 1.5 mm2) or

■ 2 termination points for measured cur-rents (screw termination max. 4 mm,crimp contact max. 2.5 mm2) or

■ 2 FSMA plugs for fiber-optic termination.For mounting of devices into cubicles, the8MC cubicle system is recommended. It isdescribed in Siemens Catalog NV21.

7XV53

7**57**5

7SJ60 7SJ60 7SJ60

RS485 Bus

opt.

RS485

DIGSI V3

DIGSI V3PC, remotely located

Modem

Office

Substation

AnalogISDN

Modem,optionally withcall-back function

Star coupler

Signal converter

PC,centrally locatedin the substation(option)

Fig. 24: Remote relay communication

The standard cubicle has the followingdimensions:2200 mm x 900 mm x 600 mm (HxWxD).These cubicles are provided with a 44 Uhigh mounting rack (standard height unitU = 44.45 mm). It can swivel as much as180° in a swing frame.The rack provides for a mounting width of19", allowing, for example, 2 devices witha width of 1/2 x 19" to be mounted. Thedevices in the 7XP20 housing are securedto rails by screws. Module racks are notrequired.To withdraw crimp contact terminations,the following tool is recommended:extraction tool No. 135900 (from Messrs.Weidmüller, Paderbornstrasse 157,D-32760 Detmold).In the housing version for surface mount-ing, the terminations are wired up on ter-minal strips on the top and bottom side ofthe device (max. terminated wire crosssection 7 mm2). For this purpose two-tierterminal blocks are used to attain the re-quired number of terminals (Fig. 26 right).

According to IEC 529 the degree of protec-tion is indicated by the identifying IP, fol-lowed by a number for the degree of pro-tection. The first digit indicates theprotection against accidental contact andingress of solid foreign bodies, the seconddigit indicates the protection against water.7XP20 housings are protected against ac-cess to dangerous parts with a wire, dustand dripping water (IP 51).



Fig. 25: Numerical protection relays in 7XP20 standard housings

Fig. 26 left: Connection method for panel flash mounting including fiber-optic interfaces; right: Connection method for panel surface mounting

1/6 1/3 1/2 1/1 of 19" width


ANSINo.*

14

21

21N

24

25

27

27/59/81

32

32F

32R

37

40

46

47

48

49

49R

49S

50

50N

51G

Aut

orec

lose

+Sy

nchr

oche

ckSy

nchr

oniz

ing

Bre

aker

failu

re

Volta

ge, F

requ

ency

7VE5

1

7SV5

12

* ANSI/IEEE C 37.2: IEEE Standard Electrical Power System Device Function Numbers

7RW

600

7SJ6

07S

J511

7SJ5

127S

J55

7SJ5

31

7SJ5

517S

J60

Ove

rcur

rent

Mot

or p

rote

ctio

n

Diff

eren

tial

7VH

807U

T512

7UT5

137S

S50/

517V

H83

7UM

511

7UM

512

7UM

515

7UM

516

7VK5

12

Gen

erat

or p

rote

ctio

n

7SA

511

7SA

513

7SD

247S

D50

27S

D50

37S

D51

17S

D51

2Fi

ber-

optic

cur

rent

com

pari

son

–

–

–

–

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Description

Protection functions

Zero speed and underspeed dev.

Distance protection, phase

Distance protection, ground

Overfluxing

Synchronism check

Synchronizing

Undervoltage

U/f protection

Directional power

Forward power

Reverse power

Undercurrent or underpower

Field failure

Load unbalance, negative phasesequence overcurrent

Phase sequence voltage

Incomplete sequence, lockedrotor, failure to accelerate

Thermal overload

Rotor thermal protection

Stator thermal protection

Instantaneous overcurrent

Instantaneous ground faultovercurrent

Ground overcurrent relay

Pilo

t wir

e di

ffere

ntia

l

Dis

tanc

e

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Fig. 27a



Fig. 27b

Aut

orec

lose

+Sy

nchr

oche

ckSy

nchr

oniz

ing

Bre

aker

failu

re

Volta

ge, F

requ

ency

7VE5

1

7SV5

12

* ANSI/IEEE C 37.2: IEEE Standard Electrical Power System Device Function Numbers

7RW

600

7SJ6

07S

J511

7SJ5

127S

J55

7SJ5

31

7SJ5

517S

J60

Ove

rcur

rent

Mot

or p

rote

ctio

n

Diff

eren

tial

7VH

807U

T512

7UT5

137S

S50/

517V

H83

7UM

511

7UM

512

7UM

515

7UM

516

7VK5

12

Gen

erat

or p

rote

ctio

n

7SA

511

7SA

513

7SD

247S

D50

27S

D50

37S

D51

17S

D51

2Fi

ber-

optic

cur

rent

com

pari

son

ANSINo.*

Pilo

t wir

e di

ffere

ntia

l

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tanc

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■

Stator ground-fault overcurrent

Overcurrent with time delay

Ground-fault overcurrentwith time delay

Overvoltage

Residual voltage ground-faultprotection

Rotor ground fault

Directional overcurrent

Directional ground-faultovercurrent

Stator ground-fault, directionalovercurrent

Out-of-step protection

Autoreclose

Frequency relay

Carrier interface

Lockout relay, start inhibit

Differential protection, generator

Differential protection, transf.

Differential protection, bus-bar

Differential protection, motor

Differential protection, line

Restricted earth-fault protection

Voltage and power directional rel.

Breaker failure

51GN

51

51N�59

59N

64R

67

67N

67G

68/78

79

81

85

86

87G

87T

87B

87M

87L

87N

92

BF

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Description

Protection functions

Type

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21

21N

67N

79

25

85

68

78

49

50 50N

51N51

49

46

50 50N

51N51

BF

67

67N

79

51N

48

79

*

**

* only with 7SJ512

47


Protection relays

Siemens manufactures a complete seriesof numerical relays for all kinds of protec-tion application.The series is briefly portrayed on the fol-lowing pages.

7SJ60

Universal overcurrentand overload protection

■ Phase-segregated measurement andindication (Input 3 ph, IE calculated)

■ All instantaneous, i.d.m.t. and d.t.characteristics can be set individuallyfor phase and ground faults

■ Selectable setting groups■ Integral autoreclose function (option)■ Thermal overload, unbalanced load

and locked rotor protection■ Suitable for busbar protection with

reverse interlocking■ With load monitoring, event and fault

memory

7SJ511

Universal overcurrent protection

■ Phase-segregated measurement andindication (3 ph and E)

■ I.d.m.t and d.t. characteristics can be setindividually for phase and ground faults

■ Suitable for busbar protection withreverse interlocking

■ With integral breaker failureprotection

■ With load monitoring, event and faultmemory

7SJ512

Digital overcurrent-time protectionwith additional functions

the same features as 7SJ511, plus:■ Autoreclose■ Sensitive directional ground-fault protec-

tion for isolated, resonant or high-resist-ance grounded networks

■ Directional module when used asdirectional overcurrent relay (optional)

■ Selectable setting groups■ Inrush stabilization

7SA511

Subtransmission line protectionwith distance-to-fault locator

Universal distance relay for all networks,with many additional functions, amongstothers■ Universal carrier interface (permissive

and blocking procedures programmable)■ Power swing blocking or tripping■ Selectable setting groups■ Sensitive directional ground-fault deter-

mination for isolated and compensatednetworks

■ Ground-fault protection for earthed net-works

■ Single and three-pole autoreclose■ Synchrocheck■ Free marshalling of optocoupler inputs

and relay outputs■ Line load monitoring, event and fault

recording■ Thermal overload protection

Fig. 28: 7SJ60 Fig. 29: 7SJ511/512

Fig. 30: 7SA511


21 25

5921N

67N

85

87L

49

6051

BF 79

79BF

68

87L

49

5051

BF

78


7SA513

Transmission line protectionwith distance-to-fault locator

■ Fast distance protection, with operatingtimes less than one cycle (20 ms at50 Hz), with a package of extra functionswhich cover all the demands of extra-high-voltage applications

■ Universal carrier interface (permissiveand blocking procedures programmable)

■ Power swing blocking or tripping■ Parallel line compensation■ Load compensation that ensures high

accuracy even for high-resistance faultsand double-end infeed

■ High-resistance ground-fault protection■ Back-up ground-fault protection■ Overvoltage protection■ Single- and three-pole autoreclose■ Synchrocheck option■ Breaker failure protection■ Free marshalling of a comprehensive

range of optocoupler inputs and relayoutputs

■ Selectable setting groups■ Line load monitoring, event and fault

recording■ High-performance measurement using

digital signal processors■ Flash EPROM memories

7SD511

Current-comparison protectionfor overhead lines and cables

■ With phase-segregated measurement■ For serial data transmission

(19.2 kbits/sec)– with integrated optical transmitter/

receiver for direct fiber-optic link upto approx. 15 km distance

– or with the additional digital signaltransmission device 7VR5012 up to150 km fiber-optic length

– or through a 64 kbit/s channel of avail-able multipurpose PCM devices, viafiber-optic or microwave link

■ Integral overload and breaker failureprotection

■ Emergency operation as overcurrentback-up protection on failure of data link

■ Automatic measurement and correctionof signal transmission time, i.e. channel-swapping is permissible

■ Line load monitoring, event and faultrecording

Fig. 31: 7SA513

Fig. 32: 7SD511 Fig. 33: 7SD512

7SD512

Current-comparison protectionfor overhead lines and cables

with functions as 7SD511, but additionallywith autoreclose function for single- andthree-pole fast and delayed autoreclosure.


87 T 49 50/51

87BB BF

87T

49

87REF50G

50/51

**

* 87REF or 50G


7UT512

Differential protection for machinesand power transformers

with additional functions, such as:■ Numerical matching to transformer ratio

and connection group (no matchingtransformers necessary)

■ Thermal overload protection■ Back-up overcurrent protection■ Measured-value indication for com-

missioning (no separate instrumentsnecessary)

■ Load monitor, event and fault recording

7UT513

Differential protectionfor three-winding transformers

with the same functions as 7UT512, plus:■ Sensitive restricted ground-fault

protection■ Sensitive d.t. or i.d.m.t. ground-fault –

o/c-protection

7SS5

Numerical busbar protection

■ With absolutely secure 2-out-of-2 meas-urement and additional check zone, eachprocessed on separate microprocessorhardware

■ With fast operating time (< 15 ms)■ Extreme stability against c.t. saturation■ Completely self-monitoring, including c.t.

circuits, isolator positions and run time■ With integrated circuit-breaker failure

protection■ With commissioning-friendly aids (indica-

tion of all feeder, operating and stabiliz-ing currents)

■ With event and fault recording■ Designed for single and multiple bus-

bars, up to 8 busbar sections and 32 bays

7UM511/12/15/16

Multifunctional devicesfor machine protection

■ With 10 protection functions on average,with flexible combination to completeprotection systems from the smallest tothe largest motor generator units

■ With improved measurement methodsbased on Fourier filters and the evalua-tion of symmetrical components (fullynumeric, frequency compensated)

■ With load monitoring, event and faultrecording

Fig. 34: 7UT512 Fig. 35: 7UT513

Fig. 36: 7SS5

Fig. 37: Protection operation with the PC operatorprogram DIGSI

See separate reference list for machineprotection.Order No. E50001-U321-A39-X-7600


51

64

67N

87L

49

27

37

46

49R

50

46

51N

BF

49LR

37

51N

59

50G 86

48

49

51

51G

50

51

27

50 7950N 49 59


7VE51

Paralleling device

for synchronization of generators andnetworks■ Absolutely secure against faulty switch-

ing due to duplicate measurement withdifferent procedures

■ With numerical measurand filtering thatensures exact synchronization even innetworks suffering transients

■ With synchrocheck option■ Available in two versions: 7VE511 with-

out, 7VE512 with voltage and frequencybalancing

Combined bay protection and controlunit 7SJ531

Line protection

■ Non directional time overcurrent■ Directional time overcurrent■ IEC/ANSI and user definable TOC curves■ Overload protection■ Sensitive directional ground fault■ Negative sequence overcurrent■ Under/Overvoltage■ Breaker failure■ Autoreclosure■ Fault locator

Motor protection

■ Thermal overload■ Locked rotor■ Start inhibit■ Undercurrent

Control functions

■ Measured-value acquisition■ Signal and command indications■ P, Q, cos ϕ and meter-reading calculation■ Measured-value recording■ Event logging■ Switching statistics■ Feeder control diagram with load indica-

tion■ Switchgear interlocking

7SJ551

Universal motor protectionand overcurrent relay

■ Thermal overload protection– separate thermal replica for stator

and rotor based on true RMS currentmeasurement

– up to 2 heating time constants for thestator thermal replica

– separate cooling time constants forstator and rotor thermal replica

– ambient temperature biasing of ther-mal replica

■ Connection of up to 8 RTD sensors■ Multi-curve overcurrent and ground-fault

protection:– four selectable i.d.m.t. and d.t. curves

for phase faults, two for ground-faults– customized curves instead of standard

curves can be programmed to offeroptimal flexibility for both phase andground elements

■ Real-Time Clock: last 3 events are storedwith real-time stamps of alarm and tripdata

7SD502

■ Pilot-wire differential protection forlines and cables (2 pilot wires)

■ Up to about 25 km telephone-type pilotlength

■ With integrated overcurrent back-upand overload protection

■ Also applicable to 3-terminal lines(2 devices at each end)

Fig. 38: 7SJ531 Fig. 39: 7SJ551

Fig. 40: 7SD502/503

7SD503

■ Pilot-wire differential protection for linesand cables (3 pilot wires)

■ Up to about 15 km pilot length■ With integrated overcurrent back-up

and overload protection■ Also applicable to 3-terminal lines

(2 devices at each end)


Front view

Case 7XP2030-2 for relays 7SD511, 7SJ511/12, 7SJ531, 7UT512, 7VE51

145

150

17230 29.5

266244

231.5

1.5

10

Opticalfibreinterface

131.57.310513.2 5.4

ø 5or

M4 255.8

146

245

ø 6

Side view Panel cutout

225

220 17230 29.5

266

1,5

231.5

10

Optical fiber interface180

ø 5or

M4

206.513.67.3

245 255.8

221

ø 6

5.4

Front view

Case 7XP2040-2 for relays 7SA511, 7UT513, 7SD512, 7UM5**, 7VE512, 7SD502/503

Side view Panel cutout

56.5±0.370

75

Back view

244266

Side view

Case 7XP20 for relays 7SJ600, 7RW600

37 172 29.5

245 +1 255 ±0.3

71+2

ø 5or

M4

7.3

ø 6

Panel cutout

Fig. 41

Fig. 42

Fig. 43


All dimensions in mm.

Cutout and drilling dimensions


7XR9672 Core-balance current transformer (zero sequence c.t.)

14

K

102

200

120

2

55

120

14.5 x 6.5 K

L

k l96 104

M6

7XR9600 Core-balance current transformer (zero sequence c.t.)

170

143

81

94

8012

Diam.6.4

54

Diam.149

Fig. 44

Fig. 45


Fig. 46

70172 29.530

26624

75

Case 7XP2020-2

3056.3

13.27.3

ø 5or

M4

5.4

71

ø 6

255.8245

Front view Side view Back view Panel cutout



Case for relay 7SJ551

105 17230

266

29.5

115

244 255.9

86.4100

Front view Side view Back view

Case 7XP2060-2 for relay 7SA513

266

445

450

13.2

7.3

245

405

431.5

5.4

255.8

446

ø 6

ø 5 or M4

2661.5

10

30 172 29.5

Front view

Optical fiberinterface

Side view

Panel cutout


Fig. 47

Fig. 48



Typical protection schemes


Fig. 49

from both ends6

5

4

3

2

1

10

9

8

7

11

13

12

17

16

15

14

20

19

18

Circuitnumber

Radial feeder circuit

Ring main circuit

Distribution feeder with reclosers

Parallel feeder circuit

Cable or short overhead line with infeedfrom both ends

Overhead lines or longer cables with infeed

Cables andoverhead lines

Applicationgroup

Circuit equipmentprotected

Transformers Small transformer infeed

Large or important transformer infeed

Dual infeed with single transformer

Parallel incoming transformer feeder

Parallel incoming transformer feeder with bus tie

Motors Small- and medium-sized motors

Large HV motors

Generators Smallest generator < 500 kW

Small generator, around 1 MW

Large generator > 1 MW

Generator-transformer unit

Busbars Busbar protection by o/c relays withreverse interlocking

High-impedance differential busbar protection

Low-impedance differential busbar protection

6/28

6/28

6/29

6/29

6/30

6/30

Page

6/31

6/31

6/32

6/32

6/33

6/33

6/34

6/34

6/35

6/35

6/36

6/37

6/38

6/38



1. Radial feeder circuit

Notes:

1) Autoreclosure 79 only with O.H. lines.2) Negative sequence o/c protection 46 as

sensitive back-up protection against un-symmetrical faults.

General hints:

– The relay at the far end (D) gets theshortest operating time.Relays further upstream have to betime-graded against the next down-stream relay in steps of about 0.3 sec-onds.

– Inverse-time curves can be selected ac-cording to the following criteria:

– Definite time:source impedance large compared tothe line impedance, i.e. small currentvariation between near and far endfaults

– Inverse time:Longer lines, where the fault current ismuch less at the end of the line than atthe local end.

– Very or extremely inverse time:Lines, where the line impedance is largecompared to the source impedance(high difference for close-in and remotefaults), or lines, where coordination withfuses or reclosers is necessary.Steeper characteristics provide alsohigher stability on service restoration(cold load pick-up and transformer inrush currents)

2. Ring main circuit

General hints:

– Operating time of overcurrent relays tobe coordinated with downstream fusesof load transformers.(Preferably very inverse time characteris-tic with about 0.2 s grading-time delay

– Thermal overload protection for thecables (option)

– Negative sequence o/c protection 46 assensitive protection against unsymmetri-cal faults (option)

51N51 46 79

51N51 46

51N51 46

Infeed

Furtherfeeders

I>, t IE>, t I2>, t ARC

2) 1)

I>, t IE>, t I2>, t

A

B

C

Load

Load Load

D I>, t IE>, t I2>, t

7SJ60

7SJ60

7SJ60

Transformerprotection,see Fig. 56

51N51 46 49

I>, t IE>, t I2>, t52

5252

51N51 46 49

I>, t IE>, t I2>, t ϑ>52

Infeed

7SJ60

Transformerprotection,see Fig. 56

7SJ60

ϑ>

Fig. 50

Fig. 51



3. Distribution feeder withreclosers

General hints:

– The feeder relay operating characteris-tics, delay times and autoreclosurecycles must be carefully coordinatedwith downstream reclosers, sectionaliz-ers and fuses.The instantaneous zone 50/50N is nor-mally set to reach out to the first mainfeeder sectionalizing point. It shall en-sure fast clearing of close-in faults andprevent blowing of fuses in this area(“fuse saving”). Fast autoreclosure isiniciated in this case.Further time delayed tripping and reclo-sure steps (normally 2 or 3) have to begraded against the recloser.

– The o/c relay should automaticallyswitch over to less sensitive characteris-tics after longer breaker interruptiontimes to enable overriding of subse-quent cold load pick-up and transformerinrush currents.

52

50/51

50N/51N

46

79

52

7SJ60

Infeed

I>>,I>, t

IE>>,IE>, t

I2>, t

Auto-reclose

Recloser

Sectionalizers

Fuses

Furtherfeeders

52

51N51 49 46 7SJ60

7SJ51267N67 51 51N

52

52

52

52

52

52

52

52

Infeed

Protectionsame asline or cable 1

I>, t IE>, t I2>, tϑ>

Load

O.H. line orcable 1

O.H. line orcable 2

Load

Fig. 52

Fig. 53

4. Parallel feeder circuit

General hints:

– This circuit is preferably used for theinterruptionfree supply of important con-sumers without significant back-feed.

– The directional o/c protection 67/67Ntrips instantaneously for faults on theprotected line. This allows the savingof one time-grading interval for the o/c-relays at the infeed.

– The o/c relay functions 51/51N haveeach to be time-graded against theupstream located relays.


5. Cables or short overhead lines withinfeed from both sides

Notes:

1) Autoreclosure only with overhead lines2) Overload protection only with cables3) Differential protection options:

– Type 7SD511/12 with direct fiber-opticconnection up to about 20 km or via a64 kbit/s channel of a general purposePCM connection (optical fiber, micro-wave)

– Type 7SD502 with 2-wire pilot cablesup to about 20 km

– Type 7SD503 with 3-wire pilot cablesup to about 10 km.

2)

3)

2)

3)

1)

7SA511

52

52

52

85 79

52

52

52

52

52 52 52 52

21/21N

79

67N

67N21/21N

85

7SA511

Load

Infeed

Sameprotectionfor parallel line,if applicable

Line orcable

Backfeed

7SD5**

5252

52

51N/51N 87L

79

49

1)

2)

52

51N/51N

87L

79

49

1)

2)7SD5**

3)

52

52

52

52 52 52 52

Load

Infeed

Sameprotectionfor parallel line,if applicable

Line orcable

Backfeed

7SJ60

7SJ60


Fig. 54

Fig. 55

6. Overhead lines or longer cables withinfeed from both sides

Notes:

1) Teleprotection logic 85 for transfer tripor blocking schemes. Signal transmis-sion via pilot wire, power-line carrier,microwave or optical fiber (to be pro-vided seperately). The teleprotectionsupplement is only necessary if fastfault clearance on 100% line length isrequired, i.e. second zone tripping(about 0.3 s delay) cannot be acceptedfor far end faults.

2) Directional ground-fault protection 67Nwith inverse-time delay against high-resistance faults

3) Single- or multishot autoreclosure 79only with overhead lines.


7. Small transformer infeed

General hints:

– Ground-faults on the secondary side aredetected by current relay 51G which,however, has to be time graded againstdownstream feeder protection relays.The restricted ground-fault relay 87N canoptionally be provided to achieve fastclearance of ground-faults in the trans-former secondary winding.Relay 7VH80 is high-impedance typeand requires class X c.t.s with equaltransformation ratio.

– Primary breaker and relay may be re-placed by fuses.

5150 51N 49 46 7SJ60

52

52

7UT513

51G 7SJ60

87N

51N51

87T

52

52

63

I>> I>, t IE> ϑ> I2>, t

Load

HV infeed High voltage, e.g. 115 kV

2)

1)

I>, t IE>, t

7SJ60

Load

Load bus, e.g. 13.8 kV


Fig. 56

Fig. 57

8. Large or important transformerinfeed

Notes:

1) Three winding transformer relaytype 7UT513 may be replaced by two-winding type 7UT512 plus high-imped-ance-type restricted ground-fault relay7VH80. However, class X c.t. coreswould additionally be necessary in thiscase. (See small transformer protection)

2) 51G may additionally be provided,in particular for the protection of theneutral resistance, if provided.

3) Relays 7UT512/513 provide numericalratio and vector group adaption.Matching transformers as used withtraditional relays are therefore no moreapplicable.

5150 50N 49

7SJ60

52

52

46

63

87N

51G

7SJ60

RN

52

HV infeed

I>> I>, t IE> ϑ>

Load

Optional resistor orreactor

I2>, t

I>>

IE>7VH80

o/c-relay

Distribution bus

Fuse

Load


9. Dual-infeed with single transformer

Notes:

1) Line c.t.s are to be connected to sepa-rate stabilizing inputs of the differentialrelay 87T in order to guarantee stabilityin case of line through-fault currents.

2) Relay 7UT513 provides numerical ratioand vector group adaption. Matchingtransformers, as used with traditionalrelays, are therefore no longer applica-ble.

52 52

46

51 51N50

49

63

7SJ60

7SJ60

52

52 52 52

7UT51387T87N

Protection line 1same as line 2

Load

I>> IE>

Protection line 221/21N or 87L + 51 + optionally 67/67N

I>> I>, t IE>, t

ϑ>I2>

7SJ60

Loadbus

51G

51N51


Fig. 58

Fig. 59

10. Parallel incoming transformerfeeders

Note:

1) The directional functions 67 and 67Ndo not apply for cases where the trans-formers are equipped with transformerdifferential relays 87T.

5150 51N 49 46

52

52

51G

52

52

52 52

63

51N51

52

67 67N

I>, t IE>, t IE>

7SJ512

I>> I>, t IE>, t ϑ> I2>, t

Load

HV infeed 1

7SJ60

Load

HV infeed 27SJ60

Protection

same asinfeed 1

I>

1)

Load

Loadbus

IE>, t


49CR

52

4951N50 7SJ60

49CR

52

50 7SJ531 or7SJ551

51G 67G

M

M

Lockedrotor

I>> Lockedrotor

IE> ϑ>

46

I>>

IE>

ϑ> I2>

4649

I<

37

2)7XR961)60/1A

I2>

11. Parallel incoming transformerfeeders with bus tie

Note:

1) Overcurrent relays 51, 51N each con-nected as a partial differential scheme.This provides a simple and fast busbarprotection and saves one time-gradingstep.

5150 51N 49 46

52

52

51G

51 51N

52

52

5151N

52

I>> I>, t IE>, t ϑ> I2>, t

Load

Infeed 1

7SJ60

Load

I>, t IE>, t I>, tIE>, t

7SJ60 7SJ60

Infeed 27SJ60

Protectionsame asinfeed 1


Fig. 60

Fig. 61b

Fig. 61a

12. Small- and medium-sized motors< about 1 MW

a) With effective or low-resistancegrounded infeed (IE ≥ I N Motor)

General hint:

– Applicable to low-voltage motors andhigh-voltage motors with low-resistancegrounded infeed (IE ≥ IN Motor).

b) With high-resistance grounded infeed(IE ≤ IN Motor)

Notes:

1) Window-type zero sequence c.t.2) Sensitive directional ground-fault protec-

tion 67N only applicable with infeedfrom isolated or Peterson-coil groundednetwork.


13. Large HV motors > about 1 MW

Notes:

1) Window-type zero sequence c.t.2) Sensitive directional ground-fault protec-

tion 67N only applicable with infeedfrom isolated or Peterson-coil groundednetwork.

3) This function is only needed for motorswhere the run-up time is longer than thesafe stall time tE.

According to IEC 79-7, the tE-time is thetime needed to heat up a.c. windings,when carrying the starting current IA,from the temperature reached in ratedservice and at maximum ambient tem-perature to the limiting temperature.A separate speed switch is used tosupervise actual starting of the motor.The motor breaker is tripped if the motordoes not reach speed in the preset time.The speed switch is part of the motordelivery itself.

4) Pt100, Ni100, Ni1205) 49T only available with relay type 75J551

49CR

52

50

7UT512

51G 67G

7SJ531 or7SJ551

49T

Speedswitch M

87M

37

Lockedrotor

I>>

IE>

ϑ> I2>

4649

U<

27

2)7XR961)60/1A

Start-upsuper-visior

I< Optional

RTD's 4)optional

3)

3)


7SJ60G

46 495151N

I>, IE>, t

LV

I2> ϑ>

G146 4951

51N7SJ60

RN =VN

√3 • (0.5 to 1) • Irated

I>, IE>, t I2> ϑ>

MV

Generator 2

Fig. 62

Fig. 63b: With resistance grounded neutral

14. Smallest generators < 500 kW

Fig. 63a: With solidly grounded neutral


52

7UM511

G

51

51G

64R

PI>, t

IE>, t

I2>

4632

L.O.F

40

1)

Field

15. Small generator, typically 1 MW

Note:

1) Two c.t.s in V-connection also sufficient.


52

7UM511

G

51G

64R

P

87

87G

51

27

81

59

51 32 46 40 49

7SJ60

MV

I

RE Field<

I>, t

2)

IG

O/Cv.c.

I2> L.O.F. ϑ>

1)

1)

U<

U>

f>

IE>, t

Field

3)

Fig. 64

Fig. 65

16. Large generator > 1 MW

Notes:

1) Functions 81 und 59 only requiredwhere prime mover can assume excessspeed and voltage regulator may permitrise of output voltage above upper limit.

2) Differential relaying options:– 7UT512: Low-impedance differential

protection 87– 7UT513: Low-impedance differen-

tial 87 with integral restricted ground-fault protection 87G

– 7VH83: High-impedance differentialprotection 87 (requires class X c.t.s)

3) 7SJ60 used as voltage-controlled o/cprotection.Function 27 of 7UM511 is used toswitch over to a second, more sensitivesetting group.


87U

87TU

Unittrans.

63

71 Oil low

Transf. fault press

51TN

Transf. neut. OC

Unit diff.51

Unit aux.back-up

78

40

32

59Over volt

Loss ofsync.

Loss offield

Over freq.

Volt/Hz

51TN

Unitaux.

Trans.diff.

87T

Trans.neut.OC

81N

24

49S

87G

StatorO.L.

Gen.diff.

G

2146

Neg.seq.

Sys.back-up

59GN

Gen.neut. OV

51GN

64R64R2

E

Fieldgrd.

Fieldgrd.

63

71Transf.fault press

Oil low

Reversepower

2)

1)

52

A


17. Generator-transformer unit

Notes:

1) 100% stator ground-fault protectionbased on 20 Hz voltage injection

2) Sensitive field ground-fault protectionbased on 1 Hz voltage injection

3) Only used functions shown, furtherintegrated functions available in each re-lay type (see ”Relay Selection Guide“,Fig. 27).

Fig. 66

46 59 81N 49 64R40

32 21 7859GN

51GN

64R2

241) 2)

87G and optionally

87U

5151N

87T2

optionally3

87TU

7UM511

7UM516

7UM515

7UT512

7UT513

7SJ60

Relaytype

Functions 3) Numberof relaysrequired

1

1

1

1

3



18. Busbar protection by O/C relayswith reverse interlocking

General hint:

Applicable to distribution busbars withoutsubstantial (< 0.25 x IN) backfeed from theoutgoing feeders

Fig. 67

52

52

5050N

5151N

52

5050N

5151N

5050N

5151N

52

5050N

5151N

7SJ60

7SJ60

7SJ60 7SJ60

t0 = 50 ms

I> I>, t I> I>, t

I>, t0 I>, t

I> I>, t

Infeed

reverse interlocking



19. High impedance busbarprotection

General hints:

– Normally used with single busbarand 1 1/2 breaker schemes

– Requires separate class X current trans-former cores. All c.t.s must have thesame transformation ratio

Fig. 68

87BB

87S.V.

5151N

Transformerprotection

7VH83

52 52

G

Feederprotection

Feederprotection

52

G

Feederprotection

86Alarm

Load

Fig. 69

20. Low-impedance busbar protection

General hints:

– Preferably used for multiple busbarschemes where an isolator replica isnecessary

– The numerical busbar protection 7SS5provides additional breaker failure pro-tection

– C.t. transformation ratios can be differ-ent, e.g. 600/1 A in the feeders and2000/1 at the bus tie

– The protection system and the isolatorreplica is continuously self-monitored bythe 7SS5

– Feeder protection can be connected tothe same c.t. core.

5050N

Back-feed

7SS5

52

Infeed

Transformer protecton

52 52

Feederprotection

52

Bus tieprotection

BF

86

87BB

Load

Feederprotection

Isolatorreplica


Nominal power[MVA]

Time constant[s]

0.5 . . . 1.0

0.16 . . . 0.2

1.0 . . . 10

0.2 . . . 1.2

>10

1.2 . . . 720

Rated transformer power [MVA]

Time constant of inrush current

12.0

11.0

10.0

9.0

8.0

7.0

6.0

5.0

4.0

3.0

2.0

1.0

102 100 400

Peak value of inrush current

IRush^

IN^


Protection coordination

Relay operating characteristics and theirsetting must be carefully coordinated inorder to achieve selectivity. The aim is ba-sically to switch-off only the faulted com-ponent and to leave the rest of the powersystem in service in order to minimize sup-ply interruptions and to guarantee stability.

Sensivity

Protection should be as sensitive as possi-ble to detect faults at the lowest possiblecurrent level.At the same time, however, it shouldremain stable under all permissible load,overload and through-fault conditions.

Phase-fault relays

The pick-up values of phase o/c relays arenormally set 30% above the maximumload current, provided that sufficient short-circuit current is available.This practice is recommmended in particu-lar for mechanical relays with reset ratiosof 0.8 to 0.85.Numerical relays have high reset ratiosnear 0.95 and allow therefore about 10%lower setting.Feeders with high transformer and/ormotor load require special consideration.

Transformer feeders

The energizing of transformers causesinrush currents that may last for seconds,depending on their size (Fig. 70).Selection of the pick-up current and as-signed time delay have to be coordinatedso that the rush current decreases belowthe relay o/c reset value before the setoperating time has elapsed.The rush current typically contains onlyabout 50% fundamental frequency compo-nent.Numerical relays that filter out harmonicsand the DC component of the rush currentcan therefore be set more sensitive. Theinrush-current peak values of Fig. 70 willbe nearly reduced to one half in this case.

Ground-fault relays

Residual-current relays enable a muchmore sensitive setting, as load currents donot have to be considered (except 4-wirecircuits with single-phase load). In solidlyand low-resistance grounded systems asetting of 10 to 20% rated load current isgenerally applied.

High-resistance grounding requires muchmore sensitive setting in the order ofsome amperes primary.The ground-fault current of motors andgenerators, for example, should be limitedto values below 10 A in order to avoid ironburning.Residual-current relays in the star pointconnection of c.t.s can in this case not beused, in particular with rated c.t. primarycurrents higher than 200 A. The pick-upvalue of the zero-sequence relay wouldin this case be in the order of the errorcurrents of the c.t.s.A special zero-sequence c.t. is thereforeused in this case as earth current sensor.The window type current transformer7XR96 is designed for a ratio of 60/1 A.The detection of 6 A primary would thenrequire a relay pick-up setting of 0.1 Asecondary.

An even more sensitive setting is appliedin isolated or Peterson-coil grounded net-works where very low earth currents occurwith single-phase-to-ground faults.Settings of 20 mA and less may then berequired depending on the minimumground-fault current.Sensitive directional ground-fault relays(integrated in the relays 7SJ512, 7SJ55and 7SA511) allow settings as low a 5 mA.

Fig. 70: Transformer inrush currents, typical data



Differential relays (87)

Transformer differential relays are normallyset to pick-up values between 20 and 30%rated current. The higher value has to bechosen when the transformer is fitted witha tap changer.Restricted ground-fault relays and high-re-sistance motor/generator differential relaysare, as a rule, set to about 10% ratedcurrent.

Instantaneous o/c protection (50)

This is typically applied on the final supplyload or on any protective device with suffi-cient circuit impedance between itself andthe next downstream protective device.The setting at transformers, for example,must be chosen about 20 to 30% higherthan the maximum through-fault current.

Motor feeders

The energizing of motors causes a startingcurrent of initially 5 to 6 times rated cur-rent (locked rotor current).A typical time-current curve for an induc-tion motor is shown in Fig. 71.In the first 100 ms, a fast decaying assy-metrical inrush current appears additionally.With conventional relays it was currentpractice to set the instantaneous o/c stepfor short circuit protection 20 to 30%above the locked-rotor current with a shorttime delay of 50 to 100 ms to override theasymetrical inrush periode.Numerical relays are able to filter out theasymmetrical current component very fastso that the setting of an additional timedelay is no longer applicable.The overload protection characteristicshould follow the thermal motor character-istic as closely as possible. The adaption isto be made by setting of the pick-up valueand the thermal time constant, using thedata supplied by the motor manufacturer.Further, the locked-rotor protection timerhas to be set according to the characteris-tic motor value.

Time grading of o/c relays (51)

The selectivity of overcurrent protectionis based on time grading of the relay oper-ating characteristics. The relay closer tothe infeed (upstream relay) is time-delayedagainst the relay further away from the in-feed (downstream relay).This is shown in Fig. 73 by the example ofdefinite time o/c relays.The overshoot times takes into accountthe fact that the measuring relay continuesto operate due to its inertia, even whenthe fault current is interrupted. This may

Fig. 71: Typical motor current-time characteristics

be is high for mechanical relays (about0.1 s) and neglectable for numerical relays(20 ms).

Inverse time relays (51)

For the time grading of inverse-time relays,the same rules apply in principle as for thedefinite time relays. The time grading isfirst calculated for the maximum fault leveland then checked for lower current levels(Fig. 72).

If the same characteristic is used for allrelays, or when the upstream relay hasa steeper characteristic (e.g. very overnormal inverse), then selectivity is auto-matically fulfilled at lower currents.

0 1 2 3 4 5 6 7 8 9

Time in seconds

10

High set instantaneous o/c step

Motor thermal limit curve

Permissible locked rotor time

Motor starting current

Locked rotor current

Overload protection characteristic

10000

1000

100

10

1

.1

.01

.001

Current in multplies of full-load amps

Time

0.2–0.4 seconds

51

5151

Maximum feeder fault levelCurrent

Main

Feeder

Fig. 72: Coordination of inverse-time relays



* also called overtravel orcoasting time

Example 1

tTG = 0.10 + 0.15 + 0.15 = 0.40 s

Example 2

Mechanical relays: tOS = 0.15 sOil circuit breaker t52F = 0.10 sSafety margin for measuring errors,etc.: tM = 0.15

Numerical relays: tOS = 0.02 sVacuum breaker: t52F = 0.08 sSafety margin: tM = 0.10 s

tTG = 0.08 + 0.02 + 0.10 = 0.20 s

t51M– t51F = t52F + tOS + tM

Time grading tTG

52M

52F 52F

Operating time

0.2–0.4Time grading

51

5151

M

FF

Interruption offault current

Faultdetection

Faultinception

Circuit-breaker

Set time delay Interruption time

Overshoot*

Margin tM

t51M

t51F t52FI>

I>tOS

Fig. 73: Time grading of overcurrent-time relays


Calculation example

The feeder configuration of Fig. 74 and theassigned load and short-circuit currents aregiven.Numerical o/c relays 7SJ60 with normalinverse-time characteristic are applied.The relay operating times dependent oncurrent can be taken from the diagram orderived from the formula given in Fig. 75.The IP /IN settings shown in Fig. 74 havebeen chosen to get pick-up values safelyabove maximum load current.This current setting shall be lowest forthe relay farthest downstream. The relaysfurther upstream shall each have equal orhigher current setting.The time multiplier settings can now becalculated as follows:

Station C:

■ For coordination with the fuses, weconsider the fault in location F1.The short-circuit current related to13.8 kV is 523 A.This results in 7.47 for I /IP at the o/crelay in location C.

■ With this value and TP = 0.05we derive from Fig. 75an operating time of tA = 0.17 s

This setting was selected for the o/c relayto get a safe grading time over the fuse onthe transformer low-voltage side.The setting values for the relay at station Care therefore:■ Current tap: IP /IN = 0.7■ Time multipler: TP = 0.05

Station B:

The relay in B has a back-up function forthe relay in C.The maximum through-fault current of1.395 A becomes effective for a fault inlocation F2.For the relay in C, we obtain an operatingtime of 0.11 s (I /IP = 19.9).We assume that no special requirementsfor short operating times exist and cantherefore choose an average time gradinginterval of 0.3 s. The operating time of therelay in B can then be calculated:■ tB = 0.11 + 0.3 = 0.41 s■ Value of IP /IN = 1395 A = 6.34

(see Fig. 74). 220 A■ With the operating time 0.41 s

and IP/IN = 6.34,we can now derive TP = 0.11from Fig. 75.


Fig. 74

The setting values for the relay at station Bare herewith■ Current tap: IP /IN = 1.1■ Time multiplier TP = 0.11Given these settings, we can also checkthe operating time of the relay in B for aclose-in fault in F3:The short-circuit current increases in thiscase to 2690 A (see Fig. 74). The corre-sponding I/IP value is 12.23.■ With this value and the set value of

TP = 0.11we obtain again derive from Fig. 75an operating time of 0.3 s.

Station A:

■ We add the time grading interval of0.3 s and find the desired operating timetA = 0.3 + 0.3 = 0.6 s.

Following the same procedure as for therelay in station B we obtain the followingvalues for the relay in station A:■ Current tap: IP /IN = 1.0■ Time multiplier: TP = 0.17■ For the close-in fault at location F4 we

obtain an operating time of 0.48 s.

Fig. 75: Normal inverse time characteristic ofrelay 7SJ60

Example: Time grading of inverse-time relays for a radial feeder

– – – – –

*) Iscc.max. = Maximum short-circuit current** Ip/IN = Relay current multiplier setting*** Iprim = Primary setting current corresponding to Ip/IN

A

B

C

D

Station

300

170

50

Max. Load[A]

I scc. max.*[A]

4500

2690

1395

523

400/5

200/5

100/5

I p/I N **CT ratio I prim***[A]

1.0

1.1

0.7

400

220

70

11.25

12.23

19.93

Fuse:160 A

515151

A F4 F3 F2

13.8 kVLoad

L.V.

7SJ607SJ607SJ60

I /I p =I scc. max.

I prim

F1

Load

Load

B C D13.8 kV/0.4 kV

1.0 MVA5.0%

I/Ip [A]

Tp [s]

Normal inverse

.

3.2

1.6

0.8

0.4

0.2

0.1

0.05

t [s]

1

2

345

10

20

304050

100

0.14

(I/Ip)0.02 – 1Tp [s]t =

82 10 2064�0.05

0.1

0.2

0.30.40.50



I A>,t

I C>,t

I B>,t

t [s

]

t [m

in]

210 5

2

5

.01

.001

2

5

.1

2

5

1

2

5

10

2

5

100�

2100 5 21000 5

I max

= 4

500

A

I scc

= 2

690

A

I scc

= 1

395

A

I –

0.4

kVm

ax=

16.

000

kA

fuse 13.8/0.4 KV1.0 MVA5.0%

VDE 160

Bus-C

Bus-B

7SJ600

7SJ600

7SJ600

Ip = 0.10 – 4.00 xInTp = 0.05 – 3.2 sI>>= 0.1 – 25. xIn

Ip = 1.0 xInTp = 0.17 sI>>= ∞

Ip = 0.10 – 4.00 xInTp = 0.05 – 3.2 sI>>= 0.1 – 25. xIn

Ip = 1.1 xInTp = 0.11 sI>>= ∞

Ip = 0.10 – 4.00 xInTp = 0.05 – 3.2 sI>>= 0.1 – 25. xIn

Ip = 0.7 xInTp = 0.05 sI>>= ∞

IN

400/5 A

200/5 A

100/5 A

A

TR

fuse

I [A]

10 4

2 51000 10 4 10 52 5 2

13.80 kV 0.40 kV

1

HRC fuse 160 A

Setting range Setting

I>>I>, t

I>>I>, t

I>>I>, t

52

52

52

The normal way

To prove the selectivity over the wholerange of possible short-circuit currents, it isnormal practice to draw the set operatingcurves in a common diagram with doublelog scales. These diagrams can be manual-ly calculated and drawn point by point orconstructed by using templates.Today computer programs are also availa-ble for this purpose. Fig. 76 shows the re-lay coordination diagram for the exampleselected, as calculated by the Siemensprogram CUSS (computer-aided protectivegrading).

Fig. 76: O/c time grading diagram

Note:

To simplify calculations, only inverse-timecharacteristics have been used for this ex-ample. About 0.1 s shorter operating timescould have been reached for high-currentfaults by additionally applying the instanta-neous zones I>> of the 7SJ60 relays.



Coordination of o/c relays with fusesand low-voltage trip devices

The procedure is similar to the above de-scribed grading of o/c relays. Usually atime interval between 0.1 and 0.2 secondsis sufficient for a safe time coordination.Very and extremely inverse characteristicsare often more suitable than normal in-verse curves in this case. Fig. 77 showstypical examples.Simple consumer-utility interrupts use apower fuse on the primary side of the sup-ply transformers (Fig. 77a).In this case, the operating characteristic ofthe o/c relay at the infeed has to be coordi-nated with the fuse curve.Very inverse characteristics may be usedwith expulsion-type fuses (fuse cutouts)while extremly inverse versions adapt bet-ter to current limiting fuses.In any case, the final decision should bemade by plotting the curves in the log-logcoordination diagram.Electronic trip devices of LV breakers havelong-delay, short-delay and instantaneouszones.Numerical o/c relays with one inverse timeand two definite-time zones can be closelyadapted (Fig. 77b).

Fig. 77: Coordination of an o/c relay with an MV fuse and a low-voltage breaker trip device

Time

Current

Time

Current

0.2 seconds

Maximum fault level at MV bus

Secondarybreaker

o/c relay

0.2 seconds

Maximum fault available at HV bus

Fuse

Inverse relay

I>>

I2>, t2

I1>, t1

a)

b)

LV bus

MV

an

51

Fuse

MV bus

an

5051

LV bus

otherconsumers


XPrimary Minimum =

= XRelay Min xVTratio

CTratio

[Ohm]

Imin =XPrim.Min

X’Line [Ohm/km]

[Ohm][km]


Coordination of distance relays

The reach setting of distance times musttake into account the limited relay accuracyincluding transient overreach (5% accord-ing to IEC 255-6), the c.t. error (1% forclass 5P and 3% for class 10P) and a secu-rity margin of about 5%. Further, the lineparameters are normally only calculated,not measured. This is a further source oferrors.A setting of 80–85% is therefore commonpractice: being 80% used for mechanicalrelays while 85% can be used for themore accurate numerical relays.

Fig. 78: Grading of distance zones

Fig. 79: Operating characteristic of Siemens distance relays 7SA511 and 7SA513

Where measured line or cable impedancesare available, the reach setting may also beextended to 90%. The second and thirdzones have to keep a safety margin ofabout 15 to 20% to the correspondingzones of the following lines. The shortestfollowing line has always to be considered(Fig. 78).As a general rule, the second zone shouldat least reach 20% over the next station toensure back-up for busbar faults, and thethird zone should cover the largest follow-ing line as back-up for the line protection.

Grading of zone times

The first zone normally operates unde-layed. For the grading of the time intervalsof the second and third zones, the samerules as for o/c relays apply (see Fig. 73).For the quadrilateral characteristics (relays7SA511 and 7SA513) only the reactancevalues ( X values) have to be consideredfor the reach setting. The setting of theR values should cover the line resistanceand possible arc or fault resistances. Thearc resistance can be roughly estimatedas follows:

X1A

X2A

X3A

R3AR2AR1A

X

RA

B

C

D

■ Typical settings of the ratio R/X are:– Short lines and cables (≤ 10 km):

R/X = 2 to 10– Medium line lengths < 25 km: R/X = 2– Longer lines 25 to 50 km: R/X = 1

Shortest feeder protectable bydistance relays

The shortest feeder that can be protectedby underreach distance zones without theneed for signaling links depends on theshortest settable relay reactance.

IArc = arc length in mIscc Min = minimum short-circuit current

Iscc Min

RArc =IArc x 2kV/m

Fig. 80

Fig. 81

B

t1

ZLA-B~

t2

t3Z3A

A C DZLB-C ZLC-D

Z2A

Z1A

Z2B

Z1B Z1C

Load LoadLoad

Z1A = 0.85 • ZLA-B

Z2A = 0.85 • (ZLA-B+Z1B)

Z3A = 0.85 • (ZLA-B+Z2B)

Operatingtime

The shortest setting of the numericalSiemens relays is 0.05 ohms for 1 Arelays, corresponding to 0.01 ohms for5 A relays.This allows distance protection of distribu-tion cables down to the range of some500 meters.

power system protection - siemens power engineering guide

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