Protection

Contents PageGeneral overview ........................ 6/2

Application hints ......................... 6/4

Power System Protection

Introduction ................................... 6/8

Relay selection guide ................ 6/22

Relay portraits ............................ 6/25

Typical protection schemes ..... 6/42

Protection coordination ............ 6/62

6

Contents PageLocal and Remote Control

Introduction ................................. 6/71

SINAUT LSAOverview ...................................... 6/74

SINAUT LSASubstation automationdistributed structure .................. 6/78

SINAUT LSASubstation automationcentralized structure(Enhanced RTU) .......................... 6/91

SINAUT LSACompact remoteterminal units .............................. 6/93

SICAM Overview ........................ 6/96

SICAM RTU Remote terminalunits (RTUs) ................................. 6/97

SICAM SASSubstation automation ............ 6/108

SICAM PCCSubstation automation ............ 6/118

Device dimensions .................. 6/125

Power Quality

Introduction ............................... 6/131

Measuring and recording ...... 6/132

Compensation systemsIntroduction ............................... 6/146

Passive compensationsystems ...................................... 6/147

Active compensationsystems ...................................... 6/154

Protection andSubstation ControlProtection andSubstation Control

Siemens Power Engineering Guide · Transmission and Distribution · 4th Edition6/2

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Automation

Engineering,Para-meterizing

SIPROTEC-IEDs:– Relays– Bay control units– Transducers– etc.

Moni-toringandcontrol

SICAM WinCC

PROFIBUS

GPS

System control centersIEC 60870-5-101

SICAM plusTools

IEC 60870-5-103O.F.

WireRS485

Fig. 2a: Protection and control in HV GIS switchgear Fig. 2b: Protection and control in bay dedicatedkiosks of an EHV switchyard

General overview

Three trends have emerged in the sphereof substation secondary equipment: intelli-gent electronic devices (IEDs), open com-munication and operation with a PC.Numerical relays and cumputerized substa-tion control are now state-of-the-art.The multitude of conventional, individualdevices prevalent in the past as well ascomprehensive parallel wiring are beingreplaced by a small number of multifunc-tional devices with serial connections.

One design for all applications

In this respect, Siemens offers a uniform,universal technology for the entire func-tional scope of secondary equipment, bothin the construction and connection of thedevices and in their operation and commu-nication. This results in uniformity of de-sign, coordinated interfaces and the sameoperating concept being establishedthroughout, whether in power system andgenerator protection, in measurement andrecording systems, in substation controland protection or in telecontrol.All devices are highly compact and im-mune to interference, and are thereforealso suitable for direct installation inswitchgear cells. Furthermore, all devicesand systems are largely self-monitoring,which means that previously costly mainte-nance can be reduced considerably.

“Complete technology from one partner“

The Protection and Substation Control Sys-tems Division of the Siemens Power Trans-mission and Distribution Group suppliesdevices and systems for:■ Power System Protection■ Substation Control■ Remote Control (RTUs)■ Measurement and Recording■ Monitoring and Conditioning of Power

QualityThis covers all of the measurement, con-trol, automation and protection functionsfor substations*.Furthermore, our activities cover:■ Consulting■ Planning■ Design■ Commissioning and ServiceThis uniform technology ”all from onesource“ saves the user time and money inthe planning, assembly and operation ofhis substations.

Fig. 1: The digital substation control system SICAM implements all of the control, measurement and automationfunctions of a substation. Protection relays are connected serially

Fig. 3: For the user, “complete technology from one source” has many advantages*An exception is revenue metering. Meters are separate products of our Metering Division.

Protection and Substation ControlGeneral Overview

by means of SCADA-like operation controland high-performance, uniformly operable PC tools

Rationalization of operation

by means of integration of many functionsinto one unit and compact equipment design

Savings in terms of spaceand costs

by means of uniform design,coordinated interfaces and universally identical EMC

Simplified planning andoperational reliability

Efficient parameterizationand operation

by means of PC tools with uniform operatorinterface

High levels of reliabilityand availability

by means of type-tested system technology, completeself-monitoring and the use of proven technology– 20 years of practical experience with digital protection,

more than 150,000 devices in operation (1999)– 15 years of practical experience with substation

automation (SINAUT LSA and SICAM), over1500 substations in operation (1999)

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System Protection

Siemens offers a complete spectrum ofmultifunctional, numerical relays for allapplications in the field of network andmachine protection.Uniform design and electromagnetic-inter-ference-free construction in metal housingswith conventional connection terminals inaccordance with public utility requirementsassure simple system design and usagejust as with conventional relays.Numerical measurement techniques en-sure precise operation and necessitate lessmaintenance thanks to their continuousself-monitoring capability.

The integration of additional protectionand other functions, such as real-timeoperational measurements, event and faultrecording, all in one unit economizes onspace, design and wiring costs.Setting and programming of the devicescan be performed through the integral,plaintext, menu-guided operator display orby using the comfortable PC program DIG-SI for Windows*.Open serial interfaces, IEC 870-5-103-com-pliant, allow free communication with high-er level control systems, including thosefrom other manufacturers. Connection to aProfibus substation LAN is optionally possible.

Thus the on-line measurements and faultdata registered in the protective relayscan be used for local and remote controlor can be transmitted via telephone mo-dem connections to the workplace of theservice engineer.Siemens supplies individual devices aswell as complete protection systems infactory finished cubicles. For complex ap-plications, for example, in the field of extra-high-voltage transmission, type and designtest facilities are available together with anextensive and comprehensive networkmodel using the most modern simulationand evaluation techniques.

Line protectionpilot protection relays7SD5

SIMEAS TMeasuringtransducers

SIMEAS Q, M, NPower qualityrecorders

SIPCONPower conditioners

Substation automationSICAM/SINAUT LSA

Power qualitySIMEAS/SIPCON

ProtectionSIPROTEC

SINAUT LSASubstation automationsystems, centralized anddecentralized

SICAM SASSubstation automationsystems, LAN-based(Profibus)

SINAUT LSACompact unit6MB552Minicompact unit6MB553

Remote terminal units

SICAM RTUEnhanced RTU6MD2010

Feeder protectionovercurrent/overload relays7SJ5 and 7SJ6

Line protectiondistance relays7SA5

Busbar protection7SS5 and 7VH8

Generator/motor protection7UM5

Transformer protection7UT5

Protection and substation automation

SIMEAS RFault recorders(Oscillostores)

SICAM PCCEnergy automationbased on PC and LAN(Profibus)

Fig. 4: Siemens Protection and Substation Control comprises these systems and product ranges

* Windows is a registered product of Microsoft



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Substation control

The digital substation control systemsSICAM and SINAUT LSA provide all con-trol, measurement and automation func-tions (e.g. transformer tap changing) re-quired by a switching station. They operatewith distributed intelligence. Commu-nication between feeder-located devicesand central unit is made via interference-free fiber optic connections.Devices are extremely compact and can bebuilt directly into medium and high-voltageswitchgear.To input data, set and program the system,the unique PC programs SICAM PlusToolsand LSA-TOOLS are available. Parametersand values are input at the central unit anddownloaded to the field devices, thus en-suring error-free and consistent data trans-fer.The operator interface is menu-guided,with SCADA comparable functions, that is,with a level of convenience which was pre-viously only available in a network controlcenter. Optional telecontrol functions canbe added to allow coupling of the systemto one or more network control centers.In contrast to conventional controls, digitaltechnology saves enormously on spaceand wiring. SICAM and LSA systems aresubjected to full factory tests and are deliv-ered in fully functional condition.

Remote control

Siemens remote control equipment6MB55* and 6MD2010 fulfills all the clas-sic functions of remote measurement andcontrol. Furthermore, because of the pow-erful microprocessors with 32-bit technolo-gy, they provide comprehensive data pre-processing, automation functions and bulkstorage of operational and fault informa-tion.In the classic case, connections to theswitchgear are made through coupling re-lays and transducers. This method allowsan economically favorable solution whenmodernizing or renewing the secondarysystems in older installations. Alternatively,especially for new installations, direct con-nection is also possible. Digital protectiondevices can be connected by serial linksthrough fiber-optic conductors.In addition, the functions ”operating andmonitoring“ can be provided by the con-nection of a PC, thus raising the telecontrolunit to the level of a central station controlsystem. Using the facility of nodal func-tions, it is also possible to build regionalcontrol points so that several substationscan be controlled from one location.

Switchgear interlocking

The digital interlocking system 8TK is usedfor important substations in particular withmultiple busbar arrangements. It preventsfalse switching and provides an additionallocal bay control function which allows fail-safe switching, even when the substationcontrol system is not available. Thereforethe safety of operating personnel andequipment is considerabely enhanced.The 8TK system can be used as a stand-alone interlocked control, or as back-upsystem together with the digital 6MB sub-station control.

Power Quality(Measurement, recording and powercompensation)

The SIMEAS product range offers equip-ment for the superversion of power supplyquality (harmonic content, distortion factor,peak loads, power factor, etc.), fault re-corders (Oscillostore), data logging printersand measurement transducers.Stored data can be transmitted manually orautomatically to PC evaluation systemswhere it can be analyzed by intelligent pro-grams. Expert systems are also appliedhere. This leads to rapid fault analysis andvaluable indicators for the improvement ofnetwork reliability.For local bulk data storage and transmis-sion, the central processor DAKON canbe installed at substation level. Data trans-mission circuits for analog telephone ordigital ISDN networks are incorporated asstandard. Connection to local or wide-areanetworks (LAN, WAN) is equally possible.We also have the SIMEAS T series of com-pact and powerful measurement transduc-ers with analog and digital outputs.The SIPCON Power Conditioner solvesnumerous system problems. It compen-sates (for example) unbalanced loads orsystem voltage dips and suppressessystem harmonics. It performs these func-tions so that sensitive loads are assured ofsuitable voltage quality at all times. In addi-tion, the system ist also capable of elimi-nating the perturbation produced by irregu-lar loads. The use of SIPCON can enableenergy suppliers worldwide to provide theend consumer with distinctive quality ofsupply.

Advantages for the user

The concept of ”Complete technologyfrom one partner“ offers the user manyadvantages:■ High-level security for his systems

and operational rationalization possibili-ties– powerful system solutions with the

most modern technology– compliance with international standards

■ Integration in the overall systemSIPROTEC-SICAM-SIMATIC

■ Space and cost savings– integration of many functions into one

unit and compact equipment packaging■ Simple planning and secure operation

– unified design, matched interfacesand EMI security throughout

■ Rationalized programming and handling– menu-guided PC Tools and unified

keypads and displays■ Fast, flexible mounting, reduced wiring■ Simple, fast commissioning■ Effective spare part stocking, high

flexibility■ High-level operational security and avail-

ability– continuous self-monitoring and proven

technology:– 20 years digital relay experience (more

than 150,000 units in operation)– 10 years of SINAUT LSA and SICAM

substation control (more than 1500systems in operation)

■ Rapid problem solving– comprehensive advice and fast re-

sponse from local sales andworkshop facilities worldwide.

Application hints

All named devices and systems for pro-tection, metering and control are designedto be used in the harsh environment ofelectrical substations, power plants andthe various industrial application areas.When the devices were developed, specialemphasis was placed on EMI. The devicesare in accordance with IEC 60 255 stand-ards. Detailed information is contained inthe device manuals.Reliable operation of the devices is notaffected by the usual interference fromthe switchgear, even when the device ismounted directly in a low-voltage compart-ment of a medium-voltage cubicle.



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It must, however, be ensured that the coilsof auxiliary relays located on the samepanel, or in the same cubicle, are fittedwith suitable spike quenching elements(e.g. free-wheeling diodes).When used in conjunction with switchgearfor 100 kV or above, all external connectioncables should be fitted with a screengrounded at both ends and capable of car-rying currents. That means that the crosssection of the screen should be at least4 mm2 for a single cable and 2.5 mm2 formultiple cables in one cable duct.All equipment proposed in this guideis built-up either in closed housings(type 7XP20) or cubicles with protectiondegree IP 51 according to IEC 60 529:■ Protected against access to dangerous

parts with a wire■ Sealed against dust■ Protected against dripping water

Climatic conditions:

■ Permissible temperature duringservice–5 °C to +55 °Cpermissible temperature during storage–25 °C to +55 °Cpermissible temperature during transport–25 °C to +70 °CStorage and transport with standardworks packaging

■ Permissible humidityMean value per year ≤ 75% relative hu-midity; on 30 days per year 95% relativehumidity; Condensation not permissible

We recommend that units be installedsuch that they are not subjected to directsunlight, nor to large temperature fluctua-tions which may give rise to condensation.

Mechanical stress

Vibration and shock during operation

■ Standards:IEC 60255-21 and IEC 60068-2

■ Vibration– sinusoidalIEC 60255-21-1, class 1– 10 Hz to 60 Hz:

± 0.035 mm amplitude;IEC 60068-2-6– 60 Hz to 150 Hz:

0.5 g accelerationsweep rate 10 octaves/min20 cycles in 3 orthogonal axes

Vibration and shock during transport

■ Standards:IEC 60255-21and IEC 60068-2

■ Vibration– sinusoidalIEC 60255-21-1, class 2– 5 Hz to 8 Hz:

± 7.5 mm amplitude;IEC 60068-2-6– 8 Hz to 150 Hz: 2 g acceleration

sweep rate 1 octave/min20 cycles in 3 orthogonal axes

■ ShockIEC 60255-21-2, class 1IEC 60068-2-27

Insulation tests

■ Standards:IEC 60255-5– High-voltage test (routine test)

2 kV (rms), 50 Hz– Impulse voltage test (type test)

all circuits, class III5 kV (peak); 1.2/50 µs; 0.5 J; 3 positiveand 3 negative shots at intervals of 5 s

Fig. 5: Installation of the numerical protection in thedoor of the low-voltage section of medium-voltage cell

Electromagnetic compatibility

EC Conformity declaration (CE mark):

All Siemens protection and control prod-ucts recommended in this guide complywith the EMC Directive 99/336/EEC of theCouncil of the European Community andfurther relevant IEC 255 standards on elec-tromagnetic compatibility.All products carry the CE mark.

EMC tests; immunity (type tests)

■ Standards:IEC 60255-22 (product standard)EN 50082-2 (generic standard)

■ High frequencyIEC 60255-22-1 class III– 2.5 kV (peak);

1 MHz; τ = 15 µs;400 shots/s;duration 2 s

■ Electrostatic dischargeIEC 60255-22-2 class IIIand EN 61000-4-2 class III– 4 kV contact discharge;

8 kV air discharge;both polarities;150 pF; Ri = 330 Ohm

■ Radio-frequency electromagnetic field,nonmodulated;IEC 60255-22-3 (report) class III– 10 V/m; 27 MHz to 500 MHz

■ Radio-frequency electromagnetic field,amplitude-modulated;ENV 50140, class III– 10 V/m; 80 MHz to 1000 MHz, 80%;

1 kHz; AM■ Radio-frequency electromagnetic field,

pulse-modulated;ENV 50140/ENV 50204, class III– 10 V/m; 900 MHz;

repetition frequency 200 Hz;duty cycle 50%

■ Fast transientsIEC 60255-22-4 and EN 61000-4-4,class III– 2 kV; 5/50 ns; 5 kHz;

burst length 15 ms; repetition rate300 ms; both polarities;Ri = 50 Ohm; duration 1 min

■ Conducted disturbances induced byradio-frequency fields HF,amplitude-modulatedENV 50141, class III– 10 V; 150 kHz to 80 MHz;

80%; 1kHz; AM■ Power-frequency magnetic field

EN 61000-4-8, class IV– 30 A/m continuous;

300 A/m for 3 s; 50 Hz

Protection and Substation ControlApplication Hints


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C.t. designaccording to ANSI/IEEE C 57.13

Class C of this standard defines the c.t. byits secondary terminal voltage at 20 timesnominal current, for which the ratio errorshall not exceed 10%. Standard classesare C100, C200, C400 and C800 for 5 Anominal secondary current.This terminal voltage can be approximatelycalculated from the IEC data as follows:

EMC tests; emission (type tests)

■ Standard:EN 50081-2 (generic standard)

■ Interference field strength CISPR 11,EN 55011, class A– 30 MHz to 1000 MHz

■ Conducted interference voltage,aux. voltage CISPR 22, EN 55022,class B– 150 kHz to 30 MHz

Instrument transformers

Instrument transformers must complywith the applicable IEC recommendationsIEC 60044, formerly IEC 60185 (c.t.) and186 (p.t.), ANSI/IEEE C57.13 or other com-parable standards.

Potential transformers

Potential transformers (p.t.) in single- ordouble-pole design for all primary voltageshave single or dual secondary windings of100, 110 or 120 V/ 3, with output ratingsbetween 10 and 300 VA, and accuraciesof 0.2, 0.5 or 1% to suit the particularapplication. Primary BIL values are select-ed to match those of the associatedswitchgear.

Current transformers

Current transformers (c.t.) are usually ofthe single-ratio type with wound or bar-type primaries of adequate thermal rating.Single, dual or triple secondary windings of1 or 5 A are standard.1 A rating however should be preferred,particularly in HV and EHV stations, to re-duce the burden of the connecting leads.Output power (rated burden in VA), accura-cy and saturation characteristics (accuracylimiting factor) of the cores and secondarywindings must meet the particular applica-tion.The c.t. classification code of IEC is usedin the following:

Measuring cores

They are normally specified with 0.5% or1.0% accuracy (class 0.5 M or 1.0 M), andan accuracy limiting factor of 5 or 10.The required output power (rated burden)must be higher than the actually connect-ed burden. Typical values are 5, 10, 15 VA.Higher values are normally not necessarywhen only electronic meters and recordersare connected.A typical specification could be: 0.5 M 10,15 VA.

The required c.t. accuracy-limiting factorKALF can be determined by calculation,as shown in Fig. 6.The overdimensioning factor KOF dependson the type of relay and the primary d.c.time constant. For the normal case, withshort-circuit time constants lower than100 ms, the necessary value for K*ALF canbe taken from the table in Fig. 9.The recommended values are based onextensive type tests.

C.t. design according to BS 3938

In this case the c.t. is defined by the knee-point voltage UKN and the internal second-ary resistance Ri.The design values according to IEC 60 185can be approximately transferred into theBS standard definition by the followingformula:

Fig. 6: C.t. dimensioning formulae

Cores for revenue metering

In this case, class 0.2 M is normallyrequired.

Protection cores:

The size of the protection core dependsmainly on the maximum short-circuit cur-rent and the total burden (internal c.t. bur-den, plus burden of connecting leads, plusrelay burden).Further, an overdimensioning factor has tobe considered to cover the influence of thed.c. component in the short-circuit current.In general, an accuracy of 1% (class 5 P) isspecified. The accuracy limiting factor KALFshould normally be designed so thatat least the maximum short-circuit currentcan be transmitted without saturation(d.c. component not considered).This results, as a rule, in rated accuracylimiting factors of 10 or 20 dependent onthe rated burden of the c.t. in relation tothe connected burden. A typical specifica-tion for protection cores for distributionfeeders is 5P10, 15 VA or 5P20, 10 VA.The requirements for protective currenttransformers for transient performance arespecified in IEC 60044-6. The recom-mended calculation procedure for satura-tion-free design, however, leads to veryhigh c.t. dimensions.In many practical cases, the c.t.s cannotbe designed to avoid saturation under allcircumstances because of cost and spacereasons, particularly with metal-enclosedswitchgear.The Siemens relays are therefore designedto tolerate c.t. saturation to a large extent.The numerical relays proposed in thisguide are particularly stable in this casedue to their integral saturation detectionfunction.

KALF : Rated c.t. accuracy limiting factorK*ALF : Effective c.t. accuracy

limiting factorRBN : Rated burden resistanceRBC : Connected burdenRi : Internal c.t. burden (resistance

of the c.t. secondary winding)

Iscc.max. = Maximum short-circuit currentIN = Rated primary c.t. currentKOF = Overdimensioning factor

RBC + Ri

RBN + Ri

KALF> K*ALF

Iscc.max.K*ALF>

IN

KOF

with:

Fig. 7: BS c.t. definition

Fig. 8: ANSI c.t. definition

Example:IEC 185 : 600/1, 15 VA, 5P10, Ri = 4 Ohm

(RNC + Ri) • I2N • KALFUKN =

1.3

BS : UKN = (15 + 4) • 1 • 10 = 146 V1.3

Ri = 4 Ohm

I2N = Nominal secondary current

Example:IEC 185 : 600/5, 25 VA, 5P20,

20Vs.t. max = 20 x 5 A x RBN •

KALF

with:

RBN = PBN

INsec

2and I

Nsec = 5 A, we get

Vs.t. max = PBN • KALF

5

Vs.t. max = 25 • 20 =5

ANSI C57.13:

= 100, i.e. class C100



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Relay burden

The c.t. burdens of the numerical relays ofSiemens are below 0.1 VA and can there-fore be neglected for a practical estimation.Exceptions are the busbar protection 7SS50(1.5 VA) and the pilot wire relays 7SD502,7SD600 (4 VA) and 7SD503 (3 VA + 9 VA per100 Ohm pilot wire resistance).Intermediate c.t.s are normally no longerapplicable as the ratio adaption for busbarand transformer protection is numericallyperformed in the relay.Analog static relays in gereral also haveburdens below about 1 VA.Mechanical relays, however, have a muchhigher burden, up to the order of 10 VA.This has to be considered when older re-lays are connected to the same c.t. circuit.In any case, the relevant relay manualsshould always be consulted for the actualburden values.

Fig. 9: Required effective accuracy limiting factor K*ALF

Fig. 10 Fig. 11

Burden of the connection leads

The resistance of the current loop fromthe c.t. to the relay has to be considered:


Relay type Minimum K*ALF

o/c protection7SJ511, 512, 551,7SJ60, 61, 62, 63

, at least 20IHigh set point

IN

Transformerdifferential protection7UT51

Line differential(fiber-optic) protection7SD511/512

and

Iscc. max. (close-in fault)

IN

aDistance protection7SA511, 7SA513,7SA522

Iscc. max. (line-end fault)

IN

10

Iscc. max. (outflowing current for ext. fault)

IN

Numerical busbarprotection (low impe-dance type) 7SS5

Line differential(pilot wire) protection7SD502/503/600

=

=

=

=

andIscc. max. (internal fault)

IN

=[K*ALF

. UN . IN](High voltage)

[K*ALF . UN

. IN](Low voltage)

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2

1

2<2


IN

[K*ALF . IN](line-end 1)1

3<3=


IN

K*ALF (line-end 1)

K*ALF (line-end 2)

3

4<=

4

3

<

<

<

[K*ALF . IN](line-end 2)

TN < 50 ms:

a = 2

TN < 100 ms:

a = 3 for 7SA511

a = 2 for 7SA513

and 7SA522

AR l =

2 ρ lOhm

l = single conductor lengthfrom the c.t. to the relay in m.

Specific resistance:

ρ = 0.0179 (copper wires)

A = conductor cross sectionin mm2

Ohm mm2

m

Example: Stability-verification of thenumerical busbar protection 7SS50

1 A2RBN =

15 VA= 15 Ohm;

1 A2RRelay =

1.5 VA= 1.5 Ohm

15 + 4KALF >

1.8 + 425 = 7.6

600/15 P 10,15 VA,Ri = 4 Ohm

50=Iscc.max.

IN

30,000

600=

7SS5

I scc.max. = 30 kA

l = 50 mA = 6 mm2

Result:

The rated KALF-factor (10) is higherthan the calculated value (7.6).Therefore, the stability criterium isfulfilled.

Rl6

=2 0.0179 50

0.3 Ohm=

RBC = Rl + RRelay =

= 0.3 + 1.5 = 1.8 Ohm

Given case:

2K*ALF >

150 = 25

According to Fig. 9:


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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 on 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 (1999), more than 150,000 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, the innovative SIPROTEC 4series has been launched, incorporatingthe many years of operational experi-ence with thousands of relays, togetherwith users’ requirements (power author-ity recommendations).

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

■ Local operation keypad and display de-signed to modern ergonomic criteria

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

■ Possibility to communicate with higher-level control systems using standardizedprotocols (open communication)

Fig. 12: Numerical relay ranges of Siemens

Power System ProtectionIntroduction

SIPROTEC 3 SIPROTEC 4


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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

52

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.

Measuring included

For many applications, the protective-currenttransformer accuracy is sufficient for oper-ational measuring. The additional mea-suring c.t. was more for protection ofmeasuring instruments under system faultconditions. Due to the low thermal with-stand ability of the measuring instruments,they could not be connected to the protec-tion c.t.. Consequently, additional measur-ing c.t.s and measuring instruments arenow only necessary where high accuracyis required, e.g. for revenue metering.

Fig. 13: Numerical relays, increased information availability



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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 PC may beused for upgraded protection manage-ment.The MS Windows-compatible relay opera-tion program DIGSI is available for enteringand readout of setpoints and archiving ofprotection data.The relays may be set in 2 steps. First, allrelay settings are prepared in the officewith the aid of a local PC and stored on afloppy or the hard disk. At site, the set-tings can then be downloaded from a PCinto the relay. The relay confirms the set-tings and 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.Alternatively, the total relay dialog can beguided from any remote location through amodem-telephone connection (Fig. 15).

Protection Laptop

RecordingPersonal computer

Assigning

Recording andconfirmation

DIGSI

DIGSI

System level to remote control

Substationlevel

Modem(option)

Bay level

Dataconcentrator

ERTU

Control

Coordinatedprotection & control

RTU

Relay

52

Fig. 14: PC-aided setting procedure

Fig. 15: Communication options



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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. Thisrequires considerable expenditure in set-ting the relays and filing retrieval setpoints.A personal computer-aided man-machinedialog and archiving program, e.g. DIGSI,assists the relay engineer in data filing andretrieval. The program files all settingssystematically in substation-feeder-relayorder.

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 itself,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 are now ableto correct the failure upon occurrence, re-sulting in a significantly upgraded availabilityof the 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 pickup 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

200setpoints

sub

bay

20setpoints

bay

4flags

OH-Line

1200flagsp. a.

system

Relay operationsSetpoints

1

1

1

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

systemapprox.500relays

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“ operation.



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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)

Meas.inputs

Currentinputs(100 x /N,1 s)

Voltageinputs(140 Vcontin-uous)

A/Dconverter

Processorsystem

Input filter V.24SerialInterfaces

PC interfaceLSA interface

Memory:RAMEEPROMEPROM

Input/outputports

Input/outputunits

Binaryinputs

Alarmrelay

Com-mandrelay

LEDdis-plays0001

01010011

Amplifier

Input/outputcontacts

digital10 Vanalog

100 V/1 A,5 A analog

FO

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:■ 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 event 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.

Fig. 18: Block diagram of numerical protection

Fig. 19: Self-monitoring system

Power System ProtectionRelay Design and Operation


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Implemented Functions

SIOPROTEC relays are available with avariety of protective functions. See relaycharts (page 6/20 and following).The high processing power of modern nu-merical devices allow further integration ofnon-protective add-on functions.

The question as to whether separate orcombined relays should be used for pro-tection and control cannot be uniformly an-swered. In transmission type substations,separation into independent hardware unitsis still preferred, whereas on the distribu-tion level a trend towards higher functionintegration can be observed. Here, com-bined feeder relays for protection, monitor-ing and control are on the march (Fig. 20).

Most of the relays of this guide are stand-alone protection relays. The exception inthe SIPROTEC 3 series is the distributionfeeder relay 7SJ531 that also integratescontrol functions. Per feeder, only one re-lay package ist needed in this case leadingto a considerable reduction in space undwiring.

With the new SIPROTEC 4 series (types7SJ61, 62 and 63), Siemens supports bothstand-alone and combined solutions on thebasis of a single hardware and softwareplatform. The user can decide within widelimits on the configuration of the controland protection functions in the feeder,without compromising the reliability of theprotection functions (Fig. 21).

Fig. 21: SIPROTEC 4 relays 7SJ61/62/63, implemented function

The following solutions are available withinone relay family:■ Separate control and protection relays■ Protection relays including remote con-

trol of the feeder breaker via the serialcommunication link


27

47

Auto reclosing

Local/Remote controlCommands/Feedback indications

Motorcontrol(only 7SJ63)

Communica-tions moduleRS23/485fiber opticIEC 60870-5-103PROFIBUS FMS

Faultrecording

21FL

6467

5150 51N50N 4946

51N60N

79M

Inrushrestrain 50BF

14

Breakerfailureprotection Locked

rotor

Motor protection (option)Starting time

Startinhibit

Directional ground-fault detection (option)

Rotating fieldmonitoring

Directional (option)

Metering values

Metered powervalues pulses

Calculated

V, Watts,Vars f.p.f.

I2 limit values

Vf (option)

Fault locator

PLC logic52

74TC 86

Trip circuitsupervision Lockout

&

Busbar

HMI

7SJ61/62/63

7SJ62/63

4837 66/86

67N67

810/U 59

■ Combined feeder relays for protection,monitoring and control

Mixed use of the different relay types isreadily possible on account of the uniformoperation and communication procedures.

Fig. 20: Switchgear with numerical relay (7SJ62)and traditional control

Switchgear with combined protectionand control relay (7SJ63)


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Integration of relays in the substationautomation

Basically, Siemens numerical relaysare all equipped with an interface to IEC60870-5-103 for open communication withsubstation control systems either fromSiemens (SINAUT LSA or SICAM, seepage 6/71 ff) or of any other supplier.The relays of the newer SIPROTEC 4series, however, are even more flexibleand equipped with communication options.SIPROTEC 4 relays may also be connectedto the SINAUT LSA system or to a systemof another supplier via IEC 60870-5-103.But, SICAM 4 relays were originally de-signed as components of the new SICAMsubstation automation system, and theircommon use offers the most technical andcost benefits.SIPROTEC 4 protection and SICAM stationcontrol, which is based on SIMATIC, are ofuniform design, and communication is basedon the Profibus standard.SIPROTEC 4 relays can in this case beconnected to the Profibus substation LANof the SICAM system via one serial inter-face. Through a second serial interface,e.g. IEC 60 870-5-103, the relay can sepa-rately communicate with a remote PC via amodem-telephone line (Fig. 22).

Local relay operation

All operator actions can be executed andinformation displayed on an integrated userinterface.Many advantages are already to be foundon the clear and user-friendly front panel:■ Positioning and grouping of the keys

supports the natural operating process(ergonomic design)

■ Large non-reflective back-lit display■ Programmable (freely assignable) LEDs

for important messages■ Arrows arrangement of the keys for

easy navigation in the function tree■ Operator-friendly input of the setting val-

ues via the numeric keys or with a PCby using the operating program DIGSI 4

■ Command input protected by key lock(6MD63/7SJ63 only) or password

■ Four programmable keys for frequentlyused functions >at the press of a but-ton<


Fig. 22: SIPROTEC 4 relays, communication options

DIGSI 4

SICAMSAS

DIGSI 4

Telephoneconnection

PROFIBUS FMS

Modem IEC 60870-5-103

IEC 60870-5-103

DIGSI 4

Fig. 24: Front view of the combined protection,monitoring and control relay 7SJ63

Fig. 23: Front view of the protection relay 7SJ62

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4 567

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4

6

7

1 Large illuminated display2 Cursor keys3 LED with reset key

4 Control (7SJ61/62 uses function keys)5 Key switches

6 Freely programmablefunction keys

7 Numerical keypad


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DIGSI 4 the PC program for operatingSIPROTEC 4 relays

For the user, DIGSI is synonymous withconvenient, user-friendly parameterizingand operation of digital protection relays.DIGSI 4 is a logical innovation for operationof protection and bay control units of theSIPROTEC 4 family.The PC operating program DIGSI 4 is thehuman-machine interface between theuser and the SIPROTEC 4 units. It featuresmodern, intuitive operating procedures.With DIGSI 4, the SIPROTEC 4 units ca beconfigured and queried.■ The interface provides you only with

what is really necessary, irrespective ofwhich unit you are currently configuring.

■ Contextual menus for every situationprovide you with made-to-measure func-tionality – searching through menuhierarchies is a thing of the past.

■ Explorer – operation on the MS Win-dows 95® Standard – shows the optionsin logically structured form.

■ Even with marshalling, you have theoverall picture – a matrix shows you at aglance, for example, which LEDs arelinked to which protection controlfunction(s). It just takes a click with themouse to establish these links by afingertip.

■ Thus, you can also use the PC to link upwith the relay via star coupler or channelswitch, as well via the PROFIBUS® of asubstation control system. The integrat-ed administrating system ensures clearaddressing of the feeders and relays of asubstation.

■ Access authorization by means of pass-words protects the individual functions,such as for example parameterizing,commissioning and control, from unau-thorized access.

■ When configuring the operator environ-ment and interfaces, we have attachedimportance to continuity with the SICAMautomation system. This means that youcan readily use DIGSI on the station con-trol level in conjunction with SICAM.Thus, the way is open to the SIMATICautomation world.

Fig. 26: Function range


Fig. 27: Range of operational measured values

Fig. 25: Substation manager for managing of substation and device data


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DIGSI 4 matrix

The DIGSI 4 matrix allows the user to seethe overall view of the relay configurationat a glance. For example, you can displayall the LEDs that are linked to binary inputsor show external signals that are connect-ed to the relay. And with one click ofthe button, connections can be switched(Fig. 28).

Display editor

A display editor is available to design thedisplay on SIPROTEC 4 units. The prede-fined symbol sets can be expanded to suitthe user. The drawing of a one-line dia-gram is extremely simple. Load monitoringvalues (analog values) can be placed whererequired (Fig. 29).

Commissioning

Special attention has been paid to commis-sioning. All binary inputs and outputs canbe read and set directly. This can simplifythe wire checking process significantly forthe user.

CFC: Planning instead of programminglogic

With the help of the graphical CFC (Contin-uous Function Chart)Tool, you can config-ure interlocks and switching sequencessimply by drawing the logic sequences; nospecial knowledge of software is required.Logical elements such as AND, OR andtime elements are available (Fig. 30) .

Hardware and software platform

■ Pentium 133 MHz or above, with atleast 32 Mbytes RAM

■ DIGSI requires about 200 Mbytes hard-disk space

■ Additional hard-disk space per installedprotection device 2 Mbytes

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

■ One CD ROM drive (required for in-stallation)

■ WINDOWS 95/98 or NT 4

Fig. 30: CFC logic with module library

Fig. 29: Display Editor

Fig. 28: DIGSI 4 allocation matrix


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Fig. 31: Operation of the protection relays using PC and DIGSI 3 software program

Fig. 32: Parameterization using DIGSI 3


Operation of SIPROTEC 3 Relays

Most of the Siemens numerical relays be-long to the series SIPROTEC 3. (Only thedistribution protection relays 7SJ61/62,the combined protection and control relay7SJ63 and the line protection 7SA522 arepresently available in the version SIPRO-TEC 4).Both relay series are widely compatible andcan be used together in protection and con-trol systems. SIPROTEC 3 relays howeverare not applicable with PROFIBUS but onlywith the IEC 60870-5-103 communicationstandard.The operation of SIPROTEC 3 and 4 relaysis very similar. Some novel features of thePC operating program DIGSI 4 like the CFCfunction and the graphical setting matrixare however not contained in DIGSI 3.

Operation of SIPROTEC 3 relays via inte-gral key pad and LCD display:

Each parameter can be accessed and al-tered via the integrated operator panel or aPC connected to the front side serial com-munication interface.The setting values can be accessed directlyvia 4-digit addresses or by paging throughthe menu. The display appears on an alpha-numeric LCD display with 2 lines with16 characters per line.Also the rear side IEC 60870-5-103 com-patible serial interface can be used for therelay dialog with a PC, when not occupiedfor the connection to a substation automa-tion system. This rear side interface is inparticular used for remote relay communi-cation with a PC (see page 6/19).Most relays allow for the storage of severalsetting groups (in general 4) which can beactivated via binary relay input, serial inter-face or operator panel.Binary inputs, alarm contact outputs, indi-cating LEDs and command output relayscan be freely assigned to the internal relayfunctions.

DIGSI 3 the PC program for operatingSIPROTEC 3 relays

For setting of SIPROTEC 3 relays, theDIGSI 3 version is applicable. (Figs. 31 and32). It is a WINDOWS-based program thatallows comfortable user-guided relay set-ting, load monitoring and readout of storedfault reports, including oscillographic faultrecords. It is also a valuable tool for com-missioning as it allows an online overviewdisplay of all measuring values.DIGSI comes with the program DIGRA forgraphic display and evaluation of oscillo-graphic fault records (see next page).For remote relay communication, the pro-gram WINDIMOD is offered (option).The DIGSI 3 program requires the follow-ing hardware and software platform:

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

■ 10 Mbytes hard-disc space for DIGSI 3■ 2 to 3 Mbytes additional hard-disc space

per installed protection device■ One free serial interface to the protec-

tion device (COM 1 to COM 4)■ One floppy disc drive 3.5", high density

with 1.44 Mbytes or CD ROM drive forprogram installation

■ WINDOWS version 3.1 or higherThese requirements relate to the casewhen DIGSI 3 is used as stand-alone ver-sion. When used together with DIGSI 4,the requirements for DIGSI 4 apply. In thiscase DIGSI 3 and DIGSI 4 run under thecommon DIGSI 4 substation manager.


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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).

■ 5 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.

Evaluation of the fault recording

Readout of the fault record from the pro-tection device by DIGSI is done by fault-proof scanning procedures in accordancewith the standard recommendation fortransmission 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 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. 33).Real-time presentation of analog distur-bance records, overlaying and zooming ofcurves and visualization of binary tracks(e.g. trip command, reclose command, etc.)are also part of the extensive graphicalfunctionality, as are setting of measurementcursors, spectrum analysis and fault resist-ance derivation.

Fig. 33: Display and evaluation of a fault record using DIGSI

Data security, data interfaces

DIGSI is a closed system as far as protec-tion parameter security is concerned. Thesecurity of the stored data of the operatingPC is ensured by checksums. This meansthat it is only possible to change data withDIGSI, which subsequently calculates achecksum for the changed data and storesit with the data. Changes in the data andthus in safety-related protection data arereliably detected.DIGSI is, however, also an open system.The data export function supports exportof parameterization and marshalling data instandard ASCII format. This permits simpleaccess to these data by other programs,such as test programs, without endanger-ing the security of data within the DIGSIprogram system.With the import and export of fault recordsin IEEE standard format COMTRADE (ANSI),a high-performance data interface is pro-duced which supports import and export offault records into the DIGSI partner programDIGRA.This enables the export of fault recordsfrom Siemens protection units to custom-er-specific programs via the COMTRADEformat.



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Remote relay interrogation

The numerical relay range of Siemens canalso be operated from a remotely locatedPC via modem-telephone connection.Up to 254 relays can be addressed viaone modem connection if the star coupler7XV53 is used as a communication node(Fig. 34).The relays are connected to the star cou-pler via optical fiber links.Every protection device which belongs toa DIGSI substation structure has a uniqueaddress.The attached relays are always listening,but only the addressed one answers theoperator command which comes from thecentral PC.If the relay located in a station is to be op-erated from a remote office, then a devicefile is opened in DIGSI and protection dia-log is chosen via modem.After password input, DIGSI establishes aconnection to the protection device afterreceiving a call-back from the system.In this way secure and timesaving remotesetting and readout of data are possible.Diagnostics and control of test routines arealso possible without the need to visit thesubstation.

Housing and terminal system

The protection devices and the corre-sponding supplementary devices are avail-able mainly in 7XP20 housings (Figs. 35 to42). The dimension drawings are to befound on 6/36 and the following pages.Installing of the modules in a cubicle with-out the housing 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.For electrical connection, screwed termi-nals of the SIPROTEC 3 relay series andalso parallel crimp contacts are provided.For field wiring, the use of the screwedterminals is recommended; snap-in con-nection requires special tools.To withdraw crimp contact terminations ofthe SIPROTEC 3 relay series the followingtool is recommended:Extraction tool No. 135900 (from Weid-müller, Paderbornstrasse 157, D-32760Detmold).

7XV53

7**67**57SJ60 7RW60 7SD60

RS485 Bus

opt.

RS485

DIGSI

DIGSIPC, remotely located

Modem

Office

Substation

AnalogISDN

Modem,optionally withcall-back function

Star coupler

Signal converter

PC,centrally locatedin the substation(option)

Fig. 34: Remote relay communication

The heavy-duty current plug connectorsprovide automatic shorting of the c.t. cir-cuits whenever the modules are with-drawn. This does not release from the careto be taken when c.t. secondary circuitsare concerned.In the housing version for surface mount-ing, the terminations are wired up on ter-minal strips on the top and bottom of thedevice. For this purpose two-tier terminalblocks are used to attain the required num-ber of terminals (Fig. 36 right).According to IEC 60529 the degree of pro-tection is indicated by the identifying IP,followed by a number for the degree ofprotection. The first digit indicates the pro-tection against accidental contact and in-gress of solid foreign bodies, the seconddigit indicates the protection against water.7XP20 housings are protected against ac-cess to dangerous parts by wire, dust anddripping water (IP 51).


For mounting of devices into cubicles, the8MC cubicle system is recommended. It isdescribed in Siemens Catalog NV21.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 (see Fig. 65b on page 6/33).


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SIPROTEC 3 Relay Series

SIPROTEC 3 relays come in 1/6 to 1/1 of19" wide cases with a standard height of243 mm.Their size is compatible with SIPROTEC 4relays. Therefore, exchange is always pos-sible.Versions for flush and surface mountingare available.

Fig. 36: SIPROTEC 3 relays left: Connection methodfor panel flush mounting including fiber-optic inter-faces;

Fig. 36 Right: Connection method for panel surfacemounting

1/3 1/2 of 19" width

Fig. 35a/b: Numerical protection relays of the SIPROTEC 3 series in 7XP20 standard housing

1/1 of 19" width

Terminations:

Surface mounted version:

Screw terminals (max. wire cross sec-tion 7 mm2) for all wired terminations atthe top and bottom of the housing

2 FMS plugs for fiber optic terminationof the serial communication link at thebottom of the housing

4 termination points for measured volt-ages, binary inputs or relay outputs(max. 1.5 mm2) or

Flush-mounted version:Each termination may be made via screwterminal or crimp contact. The terminationmodules used each contain:

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

2 FSMA plugs for the fiber optic termina-tion of the serial communication link

Fig. 35c


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SIPROTEC 4 Relay Series

SIPROTEC 4 relays come in 1/6 to 1/1 of19" wide cases with a standard height of243 mm.Their size is compatible with SIPROTEC 3relays. Therefore, compatible exchange isalways possible.All wires (cables) are connected at the rearside of the relay via ring tongue terminals.A special relay version with loose cable-connected operator panel (Fig. 42) is alsoavailable. It allows for example installationof the relay itself in the low-voltage com-partment and of the operator panel sepa-rately in the door of the switchgear.In this version voltage terminals are of theplug-in type. Current terminals are againscrew-type.

Fig. 38: 1/6 of 19" Fig. 39: 1/3 of 19"

Fig. 40: 1/2 of 19" Fig. 41: SIPROTEC 4 relay case versions

Fig. 42: SIPROTEC 4 combined protection, control and monitoring relay 7SJ63 with separate operator panel


Fig. 37

Connectionring cable lugs

Wmax = 12mmd1 = 5mm

Wire size 2.7 – 4 mm2

(AWG 13–11)

Directconnection

Solid conductor, flexiblelead, connector sleeve

Wire size 2.7 – 4 mm2

(AWG 13–11)

2-pin or 3-pinconnectorsWire size

0.5 – 1.0mm2

0.75 – 1.5mm2

1.0 – 2.5mm2

Special relay version (Fig. 42)with plug-in terminals:Current terminals:Screw type as above

Connectionring cable lugs

Wmax = 10mmd1 = 4 mm

Wire size 1.0 – 2.6 mm2

(AWG 17–13)Directconnection

Solid conductor, flexiblelead, connector sleeve

Wire size 0.5 – 2.5 mm2

(AWG 20–13)

Voltage terminals:

Terminations:

Voltage terminals:

Standard relay version withscrew terminals:Current terminals:

W

d1


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ANSINo.*

14

21

21N

24

25

27

27/59/81

32

32F

32R

37

40

46

47

48

49

49R

49S

50

50N

51G

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

7SJ5

117S

J512

7SJ5

317S

J60

7SJ6

17S

J62

7SJ6

3

Ove

rcur

rent

7SA

511

7SA

513

7SA

522

7SD

600

7SD

502

7SD

503

7SD

511

7SD

512

Fibe

r-op

tic c

urre

ntco

mpa

riso

n

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Description

Protection functions

Zero speed and underspeed dev.

Distance protection, phase

Distance protection, ground

Overfluxing

Synchronism check

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

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t wir

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Type

Relay Selection Guide

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eren

tial

7VH

807U

T512

7UT5

137S

S50/

527V

H83

7UM

511

7UM

512

7UM

515

7UM

516

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51M

otor

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ion

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Fig. 43a

Power System ProtectionRelay Selection Guide


1

2

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9

10

Fig. 43b



7SJ5

51

Ove

rcur

rent

Mot

or p

rote

ctio

n

Diff

eren

tial

7VH

807U

T512

7UT5

137S

S50/

527V

H83

7UM

511

7UM

512

7UM

515

7UM

516

Gen

erat

or p

rote

ctio

n

Fibe

r-op

tic c

urre

ntco

mpa

riso

n

ANSINo.*

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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

50BF

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Description


Type

7SA

511

7SA

513

7SA

522

7SD

600

7SD

502

7SD

503

7SD

511

7SD

512

7SJ5

117S

J512

7SJ5

57S

J531

7SJ6

07S

J61

7SJ6

27S

J63

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1

2

3

4

5

6

7

8

9

10


Fig. 43c

ANSINo.*

24

25

27

27/59/81

50BF

59

79

81


7RW

600

Volta

ge, F

requ

ency

7VK5

12

Bre

aker

failu

re

–

–

–

–

–

–

–

–

–

■

■

–

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Description


Overfluxing

Synchronism check

Synchronizing

Undervoltage

U/f protection

Breaker failure

Overvoltage

Autoreclose

Frequency relay

Sync

hron

izin

g

Aut

orec

lose

+Sy

nchr

onis

m c

heck

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Type

Relay Selection Guide

7VE5

1

7SV5

12

7SV6

00

–

■

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1

2

3

4

5

6

7

8

9

10

50 50N

51N51

49

46

50 50N

51N51

BF

67

67N

79

48

79

*

**

* only with 7SJ512

Relay portraits

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

7SJ600

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

7SJ602*

Universal overcurrentand overload protection

Functions as 7SJ600, however additionally:■ Fourth current input transformer for con-

nection to an independent ground cur-rent source (e.g. core-balance CT)

■ Optical data interface as alternative tothe wired RS485 version (located at therelay bottom)

■ Serial PC interface at the relay front

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

■ Inrush stabilization

7SJ512

Digital overcurrent-time protectionwith additional functions

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

Fig. 44: 7SJ600/7SJ602 Fig. 45: 7SJ511/512

*) Commencement of delivery planned for end of 1999

Power System ProtectionRelay Portraits


1

2

3

4

5

6

7

8

9

10

51

67 81o/u

27

37

46

49R

50

27

51N

76N

74TC

59

51N

59

50G 86

48

49

51

51G

56 50BF50N 79 86

7SJ61

7SJ62 additionally:

FL 4946 47

7SJ61

Universal overcurrentand overload protection withcontrol functions

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

■ All instantaneous, i.d.m.t. and d.t. char-acteristics can be set individually forphase and ground faults

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

locked rotor protection■ Suitable for busbar protection with

reserve interlocking■ With load monitoring, event and fault

memory■ With integral breaker failure protection■ With trip circuit supervision

Control functions:

■ Measured-value acquisition (current)■ Limit values of current■ Control of 1 C.B.■ Switchgear interlocking isolator/C.B.

7SJ62

Digital overcurrent and overload protectionwith additional functionsFeatures as 7SJ61, plus:

■ Sensitive directional ground-fault protec-tion for isolated, resonant or high-resistance grounded networks

■ Directional overcurrent protection■ Selectable setting groups■ Over and undervoltage protection■ Over and underfrequency protection■ Distance to fault locator (option)

Control functions:

■ Measured-value acquisition (voltage)■ P, Q, cos ϕ and meter-reading calculation■ Measured-value recording■ Limit values of I, V, P, Q, f, cos ϕ

7SJ551

Universal motor protectionand overcurrent relay

■ Thermal overload pretection– 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 ofthermal replica

■ Connection of up to 8 RTD sensorsground elements

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

Fig. 46: 7SJ61/7SJ62 Fig. 47: 7SJ551



1

2

3

4

5

6

7

8

9

1051

64

67N

46

51N

BF

49LR

37

27

50 7950N 49 59

5

49

79

33

67N

37

51N

67

46

21FL

14

51

81u/o

50N

66/86

86

27

49LR

50

50BF

48

74TC

59

Combined feeder protection and controlrelay 7SJ63

Line protection

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

Motor protection

■ Thermal overload■ Locked rotor■ Start inhibit■ Undercurrent

Control functions

■ Control up to 5 C.B.■ Switchgear interlocking isolator/C.B.■ Key-operated switching authority■ Feeder control diagram■ Status indication of feeder devices at

graphic display■ Measured-value acquisition■ Signal and command indications■ P, Q, cos ϕ and meter-reading calculation■ Measured-value recording■ Event logging■ Switching statistics■ Switchgear interlocking■ 2 measuring transducer inputs

Combined feeder protection and controlrelay 7SJ531

Line protection

■ Nondirectional 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

indication■ Switchgear interlocking

I/O Capability

Fig. 49: 7SJ63

Fig. 50: 7SJ531


Fig. 48

11

8+Life

0

3

1/2 of 19"

24/20

11+Life

4(2)

5

1/1 of 19"

37/33

14+Life

8(4)

5

1/1 of 19"

Binaryinputs

Contactoutputs

Motorcontroloutputs

Control ofswitchingdevices

Cases

7SJ631 7SJ632/3 7SJ635/6


1

2

3

4

5

6

7

8

9

10

21

21N

67N

79

25

85

68

78

49

51N

47

21 67N

8521N

78

49

7SA511

Line protection withdistance-to-fault locator

Universal distance relay for all networks,with many additional functions, including■ Universal carrier interface (PUTT, POTT,

Blocking, Unblocking)■ Power swing blocking or tripping■ Selectable setting groups■ Sensitive directional ground-fault deter-

mining for isolated and compensatednetworks

■ High-resistance ground-fault protectionfor grounded networks

■ Single and three-pole autoreclose■ Synchrocheck■ Thermal overload protection for cables■ Free marshalling of optocoupler inputs

and relay outputs■ Line load monitoring, event and fault re-

cording■ Selectable setting groups

Fig. 51: 7SA5117SA510

Line protection with distance-to-fault locator

(Reduced version of 7SA511)Universal distance protection, suitable forall networks, with additional functions,including■ Universal carrier interface (PUTT, POTT,

Blocking, Unblocking)■ Power swing blocking and/or tripping■ Selectable setting groups■ Sensitive directional ground-fault deter-

mining for isolated and compensatednetworks

■ High-resistance ground-fault protectionfor grounded networks

■ Thermal overload protection for cables■ Free marshalling of optocoupler inputs

and relay outputs■ Line load monitoring, event and fault

recording■ Three-pole autoreclose

Fig. 52: 7SA510



1

2

3

4

5

6

7

8

9

10

21 21N

7968

50N51N

85

67N

59

FL

85N

2579 50BF*

21 25

5921N

67N

85

7950BF

68 78

FL50N51N

85N

7SA522

Full scheme distance protectionwith add-on functions

■ Quadrilateral or MHO characteristic■ Sub-cycle operating time■ Universal teleprotection interface (PUTT,

POTT, Blocking, Unblocking)■ Weak infeed protection■ Power swing blocking/tripping■ High-resistance ground-fault protection

(time delayed or as directional compari-son scheme)

■ Overvoltage protection■ Switch-onto-fault protection■ Stub bus O/C protection■ Single and three-pole multi-shot auto-

reclosure*)■ Synchro-check*)■ Breaker failure protection*)■ Trip circuit supervision■ Fault locator w./w.o. parallel line com-

pensation■ Oscillographic fault recording■ Voltage phase sequence

7SA513

Transmission line protectionwith distance-to-fault locator

■ Full scheme distance protection, withoperating times less than one cycle(20 ms at 50 Hz), with a package ofextra functions which cover all the de-mands of extra-high-voltage applications

■ Suitable for series-compensated lines■ Universal carrier interface (permissive

and 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■ Backup 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

Fig. 53: 7SA522

Fig. 54: 7SA513


*) available with Version 4.1 (Commencement of delivery planned for Oct. 1999)


1

2

3

4

5

6

7

8

9

10

87L

49

5051

BF 79

87L

49

5051

BF

Fig. 55: 7SD511 Fig. 56: 7SD512

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 overcurrentbackup 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

7SD512

Current-comparison protectionfor overhead lines and cables

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

7SD502

■ Pilot-wire differential protection for linesand cables (2 pilot wires)

■ Up to about 25 km telephone-type pilotwire length

■ With integrated overcurrent back-up andoverload protection

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

7SD503

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

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

overload protection■ Also applicable to 3-terminal lines

(2 devices at each end)

Fig. 57: 7SD502/503


87L

49

50

51


1

2

3

4

5

6

7

8

9

10

87T

49

87REF50G

50/51

**

* 87REF or 50G

87T 49 50/51

7SD600

Pilot wire differential protection for linesand cables (2 pilot wires)

■ Up to about 10 km telephone-type pilotwire length

■ Connection to an external current sum-mation transformer

■ Pilot wire supervision (option)■ Remote trip command■ External current summation transformer

4AM4930 to be ordered separately

Fig. 58: 7SD600

Fig. 59: 7UT512 Fig. 60: 7UT513


87 L

7UT512

Differential protection for machines andpower transformers

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

and connection group (no matchingtransformers necessary)

■ Thermal overload protection■ Backup overcurrent protection■ Measured-value indication for commis-

sioning (no separate instruments neces-sary)

■ 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


1

2

3

4

5

6

7

8

9

10

87BB BF

7SS50

Numerical busbar andbreaker failure protection

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

■ Mixed current measurement■ 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 32bays

7SS52

Distributed numerical busbarand breaker failure protection

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

■ Phase-segregated measurement■ 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 2-stage circuit-breaker

failure protection

Fig. 63: 7VH83

Fig. 64: 7VH80

Fig. 61: 7SS50 Fig. 62: 7SS52


■ 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 12 busbar sections and 48bays

7VH80

High impedance differential relay

■ Single-phase type■ Robust solid-state design

87

87

■ Inrush stabilized through filtering■ Fast operation: 15 ms (l > 5 x setting)■ Optionally, external voltage limiters

(varistor)

7VH83

High impedance differential relay

■ Three-phase type■ Robust solid-state design■ Integral buswire supervision■ Integral c.t. shorting relay■ Inrush stabilized through filtering■ Fast operation: 21 ms (l > 5 x setting)■ Optionally, external voltage limiters

(varistors)

1 2 3 48

Bay units

Central unit

Optic fibers


1

2

3

4

5

6

7

8

9

10

Fig. 65b: Numerical protection of a generating unit(example). Cubicle design.

7UM511/12/15/16

Multifunctional devicesfor machine protection

■ With 10 protection functions on average,with flexible combination to form com-plete protection systems, from thesmallest to the largest motor generatorunits (see Fig. 66)

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

■ With load monitoring, event and faultrecording

See also separate reference list formachine protection.Order No. E50001-U321-A39-X-7600

7VE51

Paralleling device

for synchronization of generators andnetworks■ Absolutely secure against spurious

switching due to duplicate measurementwith different 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


7UT512

7UM511

7UM512

7UT513

7VE51

7SJ511

G

3281u 59 40 497UM511

517SJ511

87T7UT513

257VE51 Synchronizing

59N 64R 467UM512

87G7UT512

Fig. 65a: Numerical protection of a generating unit(example). Single-line diagram.


1

2

3

4

5

6

7

8

9

10


1) for special applications2) IE> sensitive stage,suitable for rotor or statorearth fault protection3) altogether 4 frequency stages,to be used as either f> or f<4) altogether 4 frequency stages,to be used as either f> or f<5) tank protection6) evaluation of displacement voltage7) 1 stage

ANSINo.*

51

51, 37

49

46

87

59

27

59GN

53GN

81o

81u

3Z

40

64R

24

21

78

87N


■

■ 2)

■

■

■

■

■

■

■

■ 6)

■ 3)

■ 3)

■

■

■

■

■ 2)

4

2

Function

Overcurrent

Overcurrent/Undercurrent

Thermal overload

Load unbalance

Differential protection

Overvoltage

Undervoltage

U< with frequency evaluation

Direct voltage

Stator

ground fault protection <90%

Stator

ground fault protection 100%

Interturn fault protection

Overfrequency

Underfrequency

Reverse power

Forward power1)

Underexcitation (field failure)

protection

Rotor

ground fault protection

Overexcitation

protection

Impedance protection

Out-of-step protection

Restricted ground fault prot.

Trip control inputs

Trip circuit monitoring

Relay

Numerical generator protectionProtection functions

7UM

511

I>, t(+U<)

IE>, t

I>>, t

I ><, t

I2t

I2ln>, t

(I2lln)2 t

∆lG>

∆lT>

∆lg>

U>, t

U>>, t

U>, t

t = f(U<)

U(f)<, t

U=><, t

UE >,t

UE + lE>,t

RE <,t

UW >,t

f>

f<

(–P)>, t

(+P)>, t

ϑ>, t

ϑ1 + Ue>, t

RE<, t(fN)

RE<, t(1Hz)

IE>, t(fN)

U/f >, t

(U/f)2 t

Z<, t

ϑ (Z) >, n

∆lE

t, trip

7UM

512

■

■

■

■

■

■

■

■

■

■

■ 4)

■ 4)

■ 7)

■ 7)

■

4

2

7UM

515

■

■

■

■

■

■

■ 3)

■ 3)

■

■

■

4

2

7UM

516

■

■

■

■

■

■

■

4

2

Fig. 66


1

2

3

4

5

6

7

8

9

10

59 27 59N 81

24

7VK512

Autoreclose and check-synchronism relay

Highly flexible autoreclose relay with orwithout check-synchronism function.Available functions include:■ Single or/and three-pole auto-reclosure■ Up to 10 autoreclose shots■ Independently settable dead times and

reclaim time■ Sequential fault recognition■ Check-synchronism or dead line/dead

bus charging■ Selectable setting groups■ Event and fault recording (voltage inputs)

7SV512

Breaker failure protection relay

■ Variable and failsafe breaker failure pro-tection (2-out-of-4 current check,2-channel logic and trip circuits)

■ Phase selective for single and three-poleautoreclosure

■ Reset time < 10 ms (sinusoidal current) < 20 ms worst case

■ “No current“ condition control using thebreaker auxiliary contacts

■ Integral end fault protection■ Selectable setting groups■ Event and fault recording

7SV600

Breaker failure protection relay

■ Phase selective for single and three-poleautoreclosure

■ Reset time < 10 ms (Sinusoidal current) < 20 ms worst case

■ “No current“ condition control using thebreaker auxiliary contacts

■ Selectable setting groups■ Event and fault recording■ Lockout of trip command

7RW600

Voltage and Frequency Relay

■ Intelligent protection and monitoringdevice

■ Two separate voltage measuring inputs■ Applicable as two independent single-

phase units or one multiphase unit(positive sequence voltage)

■ High-set and low-set voltage supervisionU>>, U>, U<

■ 4-step frequency supervision f><■ 4-step rate of change of frequency

supervision df/dt>■ All voltage, frequency and df/dt steps

with separate definite time delay setting■ Overfluxing (overexcitation) protection

U/f (t) as thermal model,U/f >> (DT delay)

■ Voltage and frequency indication■ Fault recording

(momentary or RMS values)■ RS485 serial interface for connection of

a PC or coordination with controlsystems

Fig. 67: 7RW600


Fig. 68: 7SV600

50BF


1

2

3

4

5

6

7

8

9

10

Front view

Case 7XP2030-2 for relays 7SD511, 7SJ511/12, 7SJ531, 7UT512, 7VE51, 7SV512, 7SK512

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, 7SD600, 7SV600

37 172 29.5

245 +1 255 ±0.3

71+2

ø 5or

M4

7.3

ø 6

Panel cutout

Fig. 69

Fig. 70

Fig. 71

All dimensions in mm.

Power System ProtectionRelay Dimensions


1

2

3

4

5

6

7

8

9

10

Fig. 72

Fig. 73

Fig. 74

70172 29.530

266244

75

Case 7XP2020-2 for relay 7VH83

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


172 29.530

133111.0

75

Case 7XP2010-2 for relay 7VH80, 7TR93

3056.3

20.57.3

ø 5or M4

5.4

71

ø 6

122.5112

70

Front view Side view Back view Panel cutout


1

2

3

4

5

6

7

8

9

10

Case for 7SJ61, 62

Case for 7SJ631/632/633

Panel cutoutRear view 1

Sideview

341.33

146/5.74

105/4.13131.5/5.17

ø6/0.24diameter

ø5 or M4/0.2 diameter

150/5.90145/5.70

244/

9.61

RS232-port

SUB-DConnector

FO2

0.07

29.51.16

172/6.77

Mounting plate

244/

9.61

RS232-port

SUB-DConnector

FO2

0.07

29.51.16

172/6.77

Mounting plate

Sideview

225/8.85220/8.66

221/8.70

180/7.08206.5/8.12

ø5 or M4/0.2 diameter

ø6/0.24diameter

Panel cutoutRear view 1

266/10.47

266/10.47

255.8/10.07245/9.65

255.8/10.07245/9.64

Fig. 75


Fig. 76b

Fig. 76a


13.2

7.3

245

405

431.5

5.4

255.8

446

ø 6

ø 5 or M4

Panel cutout

266

445

450

Front view

2661.5

10

30 172 29.5

Optical fiberinterface

Side view

Case 7XP2060-2 for relay 7SA513


1

2

3

4

5

6

7

8

9

10

Side view Rear view Side view

Case for 7SJ631/632/633Special version with detached operator panel

225/8.85220/8.66 Mounting

plate

Connection cable68 poles to basicunit length 2.5 m/8 ft.,2.4 in

29.51.16

27.11.06

20.07

266/

10.4

7

RS232-port

Mounting plate

FO

202.5/7.97 291.14

301.18

266/10.47 312/12.28 244/9.61

Detached operator panel


Fig. 77: 7SJ63, 1/2 surface mounting case (only with detached panel, see Fig. 42, page 6/21)


Case for 7SJ635/636:Special version with detached operator panel Rear view

Side view

Mounting plate

SUB-DConnector

FO

202.5/7.97 291.14

301.18

266/10.47 312/12.28 244/9.61

450/17.71

445/17.51

Fig. 78: 7SJ63, 1/1 surface mounting case (only with detached panel, see Fig. 42, page 6/21)


1

2

3

4

5

6

7

8

9

10

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. 79

Fig. 80



1

2

3

4

5

6

7

8

9

10


Fig. 81

4AM4930 Current summation transformer for relay 7SD600

90

92

121

62

110

75

64

110

G H I K L M Y

A B C D E F Z

G H I K L M Y

64

63.563.5 100


1

2

3

4

5

6

7

8

9

10

6

5

4

3

2

1

10

9

8

7

11

13

12

20

16

15

14

19

18

17

21

22

23

24

25

26

27

28

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 infeedfrom both ends

Subtransmission line

Transmission line with reactor

Transmission line or cable(with wide band communication)

Transmission line, breaker-and-a-half terminal

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

Three-winding transformer

Autotransformer

Large autotransformer bank

Motors Small and medium-sized motors

Large HV motors

Generators Smallest generator < 500 kW

Small generator, around 1 MW

Large generator > 1 MW

Large generator >1 MW feeding into a networkwith isolated neutral

Generator-transformer unit

Busbars Busbar protection by o/c relays withreverse interlocking

High-impedance differential busbar protection

Low-impedance differential busbar protection

6/43

6/43

6/44

6/44

6/45

6/45

6/46

6/48

6/49

6/49

Page

6/51

6/51

6/52

6/52

6/53

6/53

6/54

6/54

6/55

6/55

6/56

6/56

6/57

6/57

6/59

6/60

6/61

6/61

Circuitnumber

Power System ProtectionTypical Protection Schemes

Fig. 82


1

2

3

4

5

6

7

8

9

10


1. Radial feeder circuit

Notes:

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

sensitive backup 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 0.3seconds.

– Inverse-time curves can be selectedaccording 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)

Fig. 83

Fig. 84

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. 94

51N51 46 49

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

5252

51N51 46 49

I>, t IE>, t I2>, t ϑ>52ϑ>

Infeed

7SJ60

Transformerprotection,see Fig. 97

7SJ60


1

2

3

4

5

6

7

8

9

10


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 has to en-sure fast clearing of close-in faults andprevent blowing of fuses in this area(“fuse saving”). Fast autoreclosure isinitiated 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.

Fig. 85

Fig. 86

4. Parallel feeder circuit

General hints:

– This circuit is preferably used for theinterruption-free supply of importantconsumers without significant backfeed.

– 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 therelays located upstream.

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

7SJ6267N67 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


1

2

3

4

5

6

7

8

9

10

5. Cables or short overhead lines withinfeed from both ends

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 7SD600 with 2-wire pilot cablesup to about 10 km

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

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

4) Functions 49 and 79 only with relays7SD5**. 7SD600 is a cost-effective solu-tion where only the function 87L isrequired (external current summationtransformer 4AM4930 to be orderedseparately)


Fig. 87

Fig. 88

6. Overhead lines or longer cables withinfeed from both ends

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 separately). 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

4) Reduced version 7SA510 may be usedwhere no, or only 3-pole autoreclosureis required.

5252

52

51N/51N 87L

79

49

1)

2)

52

51N/51N

87L

79

49

1)

2)

3)

52

52

52

52 52 52 52

4)

4)

7SD600 or7SD5**

7SD600 or7SD5**

Load

Infeed

Sameprotectionfor parallel line,if applicable

Line orcable

Backfeed

7SJ60

7SJ60

2)

3)

2)

3)

1)

4)

4)

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


1

2

3

4

5

6

7

8

9

10


7. Subtransmission line

Note:

1) Connection to open delta winding ifavailable. Relays 7SA511 and 7SJ512can, however, also be set to calculatethe zero-sequence voltage internally.

General hints:

– Distance teleprotection is proposed asmain, and time graded directional O/C asbackup protection.

– The 67N function of 7SA511 providesadditional high-resistance ground faultprotection. It can be used in a directionalcomparison scheme in parallel with the21/21N-function, but only in POTT mode.If the distance protection scheme ope-rates in PUTT mode, 67N is only availa-ble as time-delayed function.

– Recommended schemes:PUTT on medium and long lines withphase shift carrier or other secure com-munication channel.POTT on short lines.BLOCKING with On/Off carrier (all linelengths).

Fig. 89

7SJ62

Signal transmissionequipment

2121N7925

67N6878

BF

85

5151N

6767N

SR

CH To remoteline end

1)

7SA511


1

2

3

4

5

6

7

8

9

10


Application criteria for frequently used teleprotection schemes

■ Dependable chan-nel (only with ex-ternal faults)

■ Amplitude modu-lated ON/OFFpower line carrier(same frequencycan be used at allterminals)

Permissive under-reaching transferredtripping (PUTT)

Permissive over-reaching transferredtripping (POTT)

Blocking Unblocking

Applicable only with■ Frequency shift

power line carrier

All kinds of line(Preferred USpractice)

■ Short lines in particu-lar when high fault re-sistance coverage isrequired

■ Multi-terminal andtapped lines with in-termediate infeed ef-fects

Line con-figuration:

Signal trans-mission:

Secure and dependable channel:■ Frequency shift power line carrier (phase-to-

phase HF coupling to the protected line, betterHF coupling to a parallel running line to avoidsending through the fault)

■ Microwave, in particular digital (PCM)■ Fiber optic cables

Preferredapplication

■ No distance zoneoverreaching pro-blems, when appliedwith CCVTs on shortlines

■ Applicable to extremeshort lines below theminimum zone settinglimit

■ No problems with theimpact of parallel linecoupling.

■ Simple method■ Tripping of underrea-

ching zone does notdepend on the chan-nel (release signalfrom the remote lineend not necessary).

■ No distance zone ortime coordination be-tween line ends ne-cessary, i.e. this modecan easily be usedwith different relaytypes.

■ Parallel, teed andtapped lines maycause underreachproblems. Carefulconsideration of zero-sequence couplingand intermediate in-feed effects is neces-sary.

■ Not applicable withweak infeed termi-nals.

Except that a weakinfeed supplementis not necessary

No continuous on-line supervision ofthe channel possi-ble!

Advantages:

Drawbacks:

same asfor POTT

same asfor POTT

same asfor POTT

Fig. 90

Same as for POTT,however, loss of re-mote end signaldoes not completelyblock the protectionscheme. Tripping isin this case releasedwith a short timedelay of about20 ms (unblockinglogic).

EHV linesNormally used withmedium and long lines

(7SA511/513 relays al-low use also with shortlines due to their inde-pendent X and R settingof all distance zones).

■ Distance zone andtime coordination withremote line end relaysnecessary

■ Tripping depends onreceipt of remote endsignal (additional inde-pendent underrea-ching zone of 7SA511/513 relays avoids thisproblem).

■ Weak infeed supple-ment necessary


1

2

3

4

5

6

7

8

9

10


8. Transmission line with reactor

Note:

1) 51G only applicable with grounded reac-tor neutral.

2) If phase CTs at the low-voltage reactorside are not available, the high-voltagephase CTs and the CT in the neutral canbe connected to a restricted ground faultprotection using one 7VH80 high-imped-ance relay.

General hints:

– Distance relays are proposed as main 1and main 2 protection. Duplicated 7SA513is recommended for long (>100 km) andheavily loaded lines or series-compensat-ed lines and in all cases where extremeshort operating times are required dueto system stability problems.7SA513 as main 1 and 7SA511 as main2 can be used in the normal case.

– Operating time of the 7SA513 relay is inthe range of 15 to 25 ms dependent onthe particular fault condition, while theoperating time of the 7SA511 is 25 to35 ms respectively.These tripping times are valid for faultsin the underreaching distance zone(80 to 85% of the line length). Remoteend faults must be cleared by the super-imposed teleprotection scheme. Itsoverall operating time depends on thesignal transmission time of the channel(typically 15 to 20 ms for frequency shiftaudio-tone PLC or Microwave channels,and lower than 10 ms for ON/OFF PLCor digital PCM signalling via opticalfibres).Teleprotection schemes based on7SA513 and 7SA511 have therefore ope-rating times in the order of 40 ms and50 ms each. With state-of-the-art two-cycle circuit breakers, fault clearingtimes well below 100 ms (4 to 5 cycles)can normally be achived.

– Dissimilar carrier schemes are recom-mended for main 1 and main 2 protec-tion, for example PUTT, and POTT orBlocking/Unblocking

– Both 7SA513 and 7SA511 can practiseselective single-pole and/or three-poletripping and autoreclosure.The ground current directional compari-son protection 67N of the 7SA513 relayuses phase selectors based on symmet-rical components. Thus, single pole au-toreclosure can also be practised withhigh-resistance faults.The 67N function of the 7SA511 relayshould be used as time delayed direc-tional O/C backup in this case.

– The 67N functions are provided as high-impendance fault protection. 67N of the7SA513 relay is normally used with anadditional channel as separate carrierscheme. Use of a common channel withdistance protection is only possible inthe POTT mode. The 67N function in the7SA511 is blocked when function 21/21N picks up. It can therefore only beused in parallel with the distance direc-tional comparison scheme POTT usingone common channel. Alternatively, it canbe used as time-delayed backup protec-tion.

Fig. 91

67N79

25

To remoteline end

BF6879

CC

TC1 TC2

7SA51385

25

CVT

7SA522 or7SA511

2121N59

2121N

6879

797SJ600

7VH8387R

SR

Direct TripChannel

52R52L

SR

Channel2

SR

Trip52L

Reactor

7SJ600

5151N

5050N

2)

Channel3

85

67N

BF, 59BF

BF

51G


1

2

3

4

5

6

7

8

9

10


10. Transmission line, breaker-and-a-halfterminal

Notes:

1) When the line is switched off and theline isolator is open, high through-fault-currents in the diameter may cause mal-operation of the distance relay due tounequal CT errors (saturation).Normal practice is therefore to block thedistance protection (21/21N) and the di-rectional ground fault protection (67N)under this condition via an auxiliary con-tact of the line isolator. Instead, a stand-by overcurrent function (50/50N, 51/51N)is released to protect the remaining stubbetween the breakers (“stub“protection).

2) Overvoltage protection only with7SA513

General hints:

– The protection functions of one diame-ter of a breaker-and-a-half arrangementare shown.

– The currents of two CTs have each to besummed up to get the relevant linecurrent as input for main 1 and 2 lineprotection.

To remoteline end

CC

TC1 TC2

79 97L

52L

SR

Channel1

79

6879

59

BF

BF

2121N

67N

25

7SA522 or7SA511

SR

PCMFOWire

Direct connection with dedicatedfibers up to about 20 km

85

X.21

1)

7SD512

optial fiber

Fig. 92

9. Transmission line or cable(with wide band communication)

Note:

1) Overvoltage protection only with7SA513

General hints:

– Digital PCM coded communication (withn x 64 kBit/s channels) between lineends is now getting more and more fre-quently available, either directly by opti-cal or microwave point-to-point links, orvia a general purpose digital communica-tion network.In both cases, the unit-type current com-parison protection 7SD511/12 can beapplied. It provides absolute phase and-zone selectivity by phase-segregatedmeasurement, and is not affected bypower swing or parallel line zero-se-quence coupling effects. It is further acurrent-only protection that does notneed VT connection. For this reason, theadverse effects of CVT transients arenot applicable.This makes it in particular suitable fordouble and multicircuit lines where com-plex fault situations can occur.Pilot wire protection can only be appliedto short lines or cables due to the inher-ent limitation of the applied measuringprinciple. The 7SD511/12 can be appliedto lines up to about 20 km in direct re-lay-to-relay connection via dedicated op-tical fiber cores (see also application 5),and also to much longer distances up toabout 100 km by using separate PCMdevices for optical fiber or microwavetransmission.The 7SD511/512 then uses only a smallpart (64 kBit/s) of the total transmissioncapacity being in the order of Mbits/s.

– The unit protection 7SD511 can be com-bined with the distance relay 7SA513 or7SA511 to form a redundant protectionsystem with dissimilar measuring princi-ples complementing each other. Thisprovides the highest degree of availabili-ty. Also, separate signal transmissionways should be used for main 1 andmain 2 protection, e.g. optical fiber ormicro-wave, and power line carrier(PLC).1. The criteria for selection of 7SA513 or

7SA511 are the same as discussed inapplication 8.The current comparison protectionhas a typical operating time of 25 msfor faults on 100% line length includ-ing signalling time.


1

2

3

4

5

6

7

8

9

10


– The location of the CTs on both sides ofthe circuit-breakers is typical for substa-tions with dead-tank breakers. Live-tankbreakers may have CTs only on one sideto reduce cost. A Fault between circuitbreakers and CT (end fault) may thenstill be fed from one side even when thebreaker has opened. Consequently, finalfault clearing by cascaded tripping has tobe accepted in this case.The 7SV512 relay provides the neces-sary end fault protection function andtrips the breakers of the remaining in-feeding circuits.

– For the selection of the main 1 and main2 line protection schemes, the com-ments of application examples 8 and 9apply.

– Autoreclosure (79) and synchrocheckfunction (25) are each assigned directlyto the circuit breakers and controlled bymain 1 and 2 line protection in parallel.In case of a line fault, both adjacentbreakers have to be tripped by the lineprotection. The sequence of automaticreclosure of both breakers or, alterna-tively, the automatic reclosure of only

one breaker and the manual closure ofthe other breaker, may be made selecta-ble by a control switch.

– A coordinated scheme of control circuitsis necessary to ensure selective tripping,interlocking and reclosing of the twobreakers of one line (or transformerfeeder).

– The voltages for synchrochecking haveto be selected according to the breakerand isolator positions by a voltage repli-ca circuit.

Fig. 93

79

7VK512UBB1

25UBB1

UL1 or UL2or UBB2

52

87BB1

7SS5. or7VH83

79

7VK512

25UL1 or UBB1

UL2 or UBB2

52

79

7VK512

25

UL2 orUL1 or UBB1

UBB2

52

BFUBB2

BF

BF

87BB2

7SS5. or7VH83

85

5050N 5951

51N

7SA522 or7SA51121

21N 67N

Line 1

1) 1) 2)

87L 7SD511/12

Line 2

UL2

BB1

BB2

Main 1

Main 2

Protection of Line 2(or transformer,if applicable)

UL1

7SV512 or7SV600

7SV512 or7SV600

7SV512 or7SV600


1

2

3

4

5

6

7

8

9

10


11. 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 of the high-impedancetype and requires class X CTs with equaltransformation ratio.

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

12. 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 CT 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 longerapplicable.

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

5150 51N 49 46

52

52

7UT513

51G 7SJ60

87N

51N51

87T

52

52

63

7SJ60 or7SJ61

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. 95

Fig. 94


1

2

3

4

5

6

7

8

9

10

13. Dual-infeed with single transformer

Notes:

1) Line CTs are to be connected to sepa-rate stabilizing inputs of the differentialrelay 87T in order to assure stability incase 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.

14. 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.


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 or7SJ61

Loadbus

51G

51N51

5150 51N 49 46

52

52

51G

52

52

52 52

63

51N51

52

67 67N

I>, t IE>, t IE>

7SJ62

I>> I>, t IE>, t ϑ> I2>, t

Load

HV infeed 1

7SJ60

Load

HV infeed 27SJ60 or

7SJ61

Protection

same asinfeed 1

I>

1)

Load

Loadbus

IE>, t

Fig. 97

Fig. 96


1

2

3

4

5

6

7

8

9

10

15. Parallel incoming transformerfeeders with bus tie

Note:

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


16. Three-winding transformer

Notes:

1) The zero-sequence current must beblocked from entering the differentialrelay by a delta winding in the CT con-nection on the transformer sides withgrounded winding neutral. This is to avoidfalse operation with external groundfaults (numerical relays provide this func-tion by calculation). About 30% sensitivi-ty, however, is then lost in case of inter-nal faults.Optionally, the zero-sequence currentcan be regained by introducing the wind-ing neutral current in the differential re-lay (87T). Relay type 7UT513 providestwo current inputs for this purpose.By using this feature, the ground faultsensitivity can be upgraded again to itsoriginal value.

2) Restricted ground fault protection (87T)is optional. It provides back-up protec-tion for ground faults and increasedground fault sensitivity (about 10%IN,compared to about 20 to 30%IN of thetransformer differential relay).Separate class X CT-cores with equaltransmission ratio are additionally re-quired for this protection.

General hint:

– In this example, the transformer feedstwo different distribution networks withcogeneration. Restraining differential re-lay inputs are therefore provided at eachtransformer side.If both distribution networks only con-sume load and no through-feed is possi-ble from one MV network to the other,parallel connection of the CTs of the twoMV transformer windings is admissibleallowing the use of a two-winding differ-ential relay (7UT512).

HV Infeed

51 51N 51N51

7SJ60

87N 7VH80

7SJ60 7SJ60

63

87T 7UT513

87N 7VH80

M.V.

52

52 52 52 52M.V.

51G 51G 7SJ60

1)

51

I>, t

49

ϑ>

46

I2>, t

50

I>>7SJ60 or7SJ61

Load

I>, t IE>, t IE>,tI>, t

Backfeed Load Backfeed

Fig. 98

Fig. 99

5150 51N 49 46

52

52

51G

51 51N

52

52

5151N

52

63 63

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


1

2

3

4

5

6

7

8

9

1063

52

7UT513

52

51

50BF

7SJ60

59N

7RW60

87TL

49

87TH7VH83

51G

7SJ60

EHV

50BF

50BF

52

7SV600 7SV60021 68

78 7SA513

52

52

50BF

50BF

7SV600

7SV600

21

21N

6878

7SA511

HV

21N

51N 50BF 46 50

51

63

52

7UT513

52

51

50BF

7SJ60

59N

7RW60

52

87T 49

7SJ60

51N

50BF

46

5051

87N 7VH80

7SJ60 or7SJ61

2)

1)

1)

1)


17. Autotransformer

Notes:

1) 87N high-impedance protection requiresspecial class X current transformer coreswith equal transmission ratio.

2) The 7SJ60 relay can alternatively beconnected in series with the 7UT513 re-lay to save this CT core.

General hint:

– Two different protection schemes areprovided:87T is chosen as low-impedance three-winding version (7UT513). 87N is a sin-gle-phase high-impedance relay (7VH80)connected as restricted ground fault pro-tection. (In this example, it is assumedthat the phaseends of the transformerwinding are not accessible on the neu-tral side, i.e. there exists a CT only in theneutral grounding connection.)

18. Large autotransformer bank

General hints:

– The transformer bank is connected in a11/2 breaker arrangement.Duplicated differential protection is pro-posed:Main 1: Low-impedance differential pro-tection 87TL (7UT513) connected to thetransformer bushing CTs.Main 2: High-impedance overall differen-tial protection 87TH (7VH83). Separateclass X cores and equal CT ratios are re-quired for this type of protection.

– Back-up protection is provided by dis-tance relays (7SA513 and 7SA511), each“looking“ with an instantaneous firstzone about 80% into the transformerand with a time-delayed zone beyondthe transformer.

– The tertiary winding is assumed to feeda small station supply network with iso-lated neutral.

Fig. 100

Fig. 101


1

2

3

4

5

6

7

8

9

10

49CR

52

4951N50 7SJ60

M

49CR

52

50 7SJ62 or7SJ551

51G 67G

M

Lockedrotor

I>>

IE>

ϑ> I2>

4649

I<

37

2)7XR961)60/1A

3)

I>> Lockedrotor

IE> ϑ>

46

I2>


Fig. 102a

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

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

General hint:

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

49CR

52

50

7UT512

51G 67G

7SJ62 or7SJ551

49T

Speedswitch M

87M

37

Lockedrotor

I>>

IE>

ϑ> I2>

4649

U<

27

2)7XR961)60/1A

Startupsuper-visior

I<Optional

RTD's 4)optional

3)

3)

5) 6)

Fig. 102b

Fig. 103

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

Notes:

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

tion 67N only applicable with infeedfrom isolated or Peterson-coil-groundednetwork.(For dimensioning of the sensitive direc-tional ground fault protection, see alsoapplication circuit No. 24)

3) If 67G ist not applicable, relay 7SJ602can be applied.

20. Large HV motors > about 1 MW

Notes:

1) Window-type zero sequence CT.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 runup time is longer than thesafe stall time tE.

According to IEC 79-7, the tE-time is thetime needed to heat up AC 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 7SJ56) High impedance relay 7VH83 may be

used instead of 7UT12 if separateclass x CTs. are provided at the terminaland star-point side of the motor winding.


1

2

3

4

5

6

7

8

9

10

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

1)

Fig. 104b: With resistance grounded neutral

21. Smallest generators < 500 kW

Fig. 104a: With solidly grounded neutral

22. Small generator, typically 1 MW

Note:

1) Two CTs in V connection also sufficient.

Fig. 105


52

7UM511

G

51

51G

64R

PI>, t

IE>, t

I2>

4632

L.O.F

40

1)

Field

Note:

1) If a window-type zero-sequence CT isprovided for sensitive ground fault pro-tection, relay 7SJ602 with separateground current input can be used(similar to Fig. 102b of application exam-ple 19b).


1

2

3

4

5

6

7

8

9

10

Three-phase-CTs inresidual (Holmgreen)connection

Three-phase-CTs inresidual (Holmgreen)connection with specialfactory calibration tominimum residual falsecurrent (≤ 2 mA)

2 mA 5 mA 8 mA12 mA

1A CT: ca. 50 mA5A CT: ca. 200 mA

2 – 3‰ of secondaryrated CT current In SEC:

10 – 15 mA with 5A CTs

In general not suitable forsensitive earth faultprotection

1A CTs are notrecommented inthis case

Core-balance c.t. 60/1 A:1 single CT2 parallel CTs3 parallel CTs4 parallel CTs

Relay ground current inputconnected to:

Minimum relay setting: Comments:

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)

rise of output voltage above upper limit.2) Differential relaying options:

– 7UT512: Low-impedance differentialprotection 87

– 7UT513: Low-impedance differen-tial 87 with integral restricted ground-fault protection 87G

– 7VH83: High-impedance differentialprotection 87 (requires class X CTs)

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


24. Large generator > 1 MW feeding intoa network with isolated neutral

General hints:

– The setting range of the directionalground fault protection 67G in the7UM511 relay is 2 – 100 mA.Dependent on the current transformeraccuracy, a certain minimum setting isrequired to avoid false operation on loador transient rush currents:

23. Smallest generators > 1 MW

Notes:

1) Functions 81 und 59 only requiredwhere prime mover can assume excessspeed and voltage regulator may permit

Fig. 106

Fig. 107


1

2

3

4

5

6

7

8

9

10


Notes:

1) The standard core-balance CT 7XR96has a transformation ratio of 60/1 A.

2) Instead of an open delta winding at theterminal VT, a single-phase VT at themachine neutral could be used as zero-sequence polarizing voltage.

3) The grounding transformer is designedfor a short-time rating of 20 seconds. Toprevent overloading, the load resistor isautomatically switched off by a time-de-layed zero-sequence voltage relay (59G+ 62) and a contactor (52).

4) During the startup time of the generatorwith open breaker, the grounding sourceis not available. To ensure ground faultprotection during this time interval, anauxilliary contact of the breaker can beused to change over the directionalground fault relay function (67G) to azero-sequence voltage detection func-tion (59G) via a contact converter input.

Fig. 108

– In practice, efforts are generally made toprotect about 90% of the machine wind-ing, measured from the machine termi-nals. The full ground current for a termi-nal fault must then be ten times thesetting value which corresponds to thefault current of a fault at 10% distancefrom the machine neutral.For the most sensitive setting of 2 mA,we need therefore 20 mA secondaryground current, corresponding to (60/1) x20 mA = 1.2 A primary.This current may be delivered by thenetwork ground capacitances if enoughcables are contained. In this case, thedirectional ground fault protection (67G)has to be set to reactive power mea-surement (U x I x sin w).If sufficient capacitive ground current isnot available, a grounding transformerwith resistive zero-sequence load can beinstalled as ground current source at thestation busbar. The 67G function has inthis case to be set to active (wattmetric)power measurement (U x I x cosw).The smallest standard grounding trans-former TGAG 3541 has a 20 s short timerating of PG = 27 kVA.

In a 5kV network, it would deliver:

IG 20s = ––––––- = –––––––––––– = 9.4 A

corresponding to a relay input current of9.4 A x 1/60 = 156 mA. This would pro-vide a 90% protection range with a set-ting of about 15 mA, allowing the use of4 parallel connected core balance CTs.The resistance at the 500V open-deltawinding of the grounding transformerwould then have to be designed forRG = USEC

2 / PG = 500 V2 / 27,000 VA =9.26 Ohm (27 KW, 20 s).For a 5 MVA machine and 600/5 A CTswith special calibration for minimum re-sidual false current, we would get a sec-ondary current of IG SEC = 9.4 A /(600/5) =78 mA.With a relay setting of 12 mA, the pro-tection range would in this case be100 (1- ––) = 85%.

A 3 x PG

U N

A 3 x 27,000VA

5000V

1278

87

52

7UT512

Small grid with isolated neutral

1)

REF<

I2>I>, t

IE U< U> f

Uo >

4)

P L.O.F

7UM512

Single-phase VT

2)

7XR9660/1A

GField

64F

51 46 32

27

40

59 81

59G

67G

52

RB

GroundingtransformerUN

3100

3 3500

V

3)

62

59G


1

2

3

4

5

6

7

8

9

10

25. 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. 43).


87U

87TU

Unittrans.

63

71 Oil low

Transf. fault press

51TN

Transf. neut. OC

Unit diff.51

Unit aux.backup

78

40

32

59Overvolt.

Loss ofsync.

Loss offield

Overfreq.

Volt/Hz

51TN

Unitaux.

Trans.diff.

87T

Trans.neut.OC

81N

24

49S

87G

StatorO.L.

Gen.diff.

G

2146

Neg.seq.

Sys.backup

59GN

Gen.neut. OV

51GN

64R64R2

E

Fieldgrd.

Fieldgrd.

63

71Transf.fault press

Oil low

Reversepower

2)

1)

52

A

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

3Fig. 109


1

2

3

4

5

6

7

8

9

10


26. Busbar protection by O/C relayswith reverse interlocking

General hint:

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

Fig. 110

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


1

2

3

4

5

6

7

8

9

10


Fig. 111

87BB

87S.V.

5151N

Transformerprotection

7VH83

52 52

G

Feederprotection

Feederprotection

52

G

Feederprotection

86Alarm

Load

1)

5050N

Back-feed

7SS5

52

Infeed

Transformer protection

52 52

Feederprotection

52

Bus tieprotection

BF

86

87BB

Load

Feederprotection

Isolatorreplica

Fig. 112

27. High impedance busbarprotection

General hints:

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

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

Note:

1) A varistor is normally applied accrossthe relay input terminals to limit the volt-age to a value safety below the insula-tion voltage of the secondary circuits(see page 6/70).

28. Low-impedance busbar protection

General hints:

– Preferably used for multiple bus-barschemes where an isolator replica isnecessary

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

– CT 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 are continuously self-monitoredby the 7SS5

– Feeder protection can be connected tothe same CT core.


1

2

3

4

5

6

7

8

9

10

Power System ProtectionProtection Coordination

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 CTs can in this case not beused, in particular with rated CT primarycurrents higher than 200 A. The pickupvalue of the zero-sequence relay wouldin this case be in the order of the errorcurrents of the CTs.A special zero-sequence CT is thereforeused in this case as ground 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 pickup setting of 0.1 Asecondary.

Fig. 113: Transformer inrush currents, typical data

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^

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

An even more sensitive setting is appliedin isolated or Peterson-coil-grounded net-works where very low ground 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 as 5 mA.

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 assure 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. 113).Selection of the pickup 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. 113 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.


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2

3

4

5

6

7

8

9

10


Fig. 114: Typical motor current-time characteristics

be high for mechanical relays (about 0.1 s)and negligible 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. 115).

Fig. 115: Coordination of inverse-time relays

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

Differential relays (87)

Transformer differential relays are normallyset to pickup values between 20 and 30%rated current. The higher value has to bechosen when the transformer is fittedwith a tap changer.Restricted ground-fault relays and high-resistance motor/generator differential re-lays are, 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 inductionmotor is shown in Fig. 114.In the first 100 ms, a fast decaying assy-metrical inrush current appears additional-ly. 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 short-time delay of 50 to 100 ms to override theasymmetrical inrush period.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 pickup valueand the thermal time constant, using thedata supplied by the motor manufacturer.Further, the locked-rotor protection timerhas to be set according to the characteristicmotor 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 theinfeed (downstream relay).This is shown in Fig. 116 by the exampleof definite time o/c relays.The overshoot times takes into accountthe fact that the measuring relay contin-ues to operate due to its inertia, evenwhen the fault current is interrupted. Thismay

If the same characteristic is used for all re-lays, or when the upstream relay has asteeper characteristic (e.g. very much overnormal inverse), then selectivity is automati-cally fulfilled at lower currents.


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9

10


Fig. 116: Time grading of overcurrent-time relays

* also called overtravel or coasting 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


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Calculation example

The feeder configuration of Fig. 117 andthe assigned load and short-circuit currentsare given.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. 118.The IP /IN settings shown in Fig. 117 havebeen chosen to get pickup 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. 118an 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

220 Asee Fig. 117.

■ With the operating time 0.41 sand IP /IN = 6.34,we can now derive TP = 0.11from Fig. 118.


Fig. 117

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. 117). The corre-sponding I/IP value is 12.23.■ With this value and the set value of

TP = 0.11we obtain again from Fig. 118an 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. 118: 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]

Iscc. max.*[A]

4500

2690

1395

523

400/5

200/5

100/5

Ip/IN **CT ratio Iprim***[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. 75.

7SJ607SJ607SJ60

I /Ip =Iscc. max.

Iprim

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 20640.05

0.1

0.2

0.30.40.50


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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. 119 shows the re-lay coordination diagram for the exampleselected, as calculated by the Siemensprogram CUSS (computer-aided protectivegrading).

Fig. 119: 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.

IA>,t

IC>,t

IB>,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 –

0.4

kVm

ax=

16.

000

kAI s

cc

= 1

395

AI s

cc

= 2

690

AI m

ax =

450

0 A

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


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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. 120 showstypical examples.Simple consumer-utility interrupts use apower fuse on the primary side of the sup-ply transformers (Fig. 120a).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. 120b).

Fig. 120: 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


1

2

3

4

5

6

7

8

9

10


Fig. 121: Grading of distance zones

Fig. 122: 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. 121).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. 116).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:

Fig. 123

Fig. 124

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.

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

X1A

X2A

X3A

R3AR2AR1A

X

RA

B

C

D

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

Iscc Min

RArc =IArc x 2kV/m

XPrimary Minimum =

= XRelay Min xVTratio

CTratio

[Ohm]

Imin =XPrim.Min

X’Line [Ohm/km]

[Ohm][km]

■ 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.

Coordination of distance relays

The reach setting of distance times musttake into account the limited relay accuracyincluding transient overreach (5% accord-ing to IEC 60255-6), the CT 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; 80% is used for mechanical relayswhile 85% can be used for the more accu-rate numerical relays.


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10


Breaker failure protection setting

Most digital relays of this guide provide theBF protection as an integral function. Theinitiation of the BF protection by the inter-nal protection functions then takes placevia software logic. However, the BF protec-tion function may also be initiated fromoutside via binary inputs by an alternateprotection. In this case the operating timeof intermediate relays (BFI time) may haveto be considered. Finally, the tripping ofthe infeeding breakers needs auxiliary re-lays which add a small time delay (BFT) tothe overall fault clearing time.This is in particular the case with 1-and-1/2-breaker or ring bus arrangementswhere a separate breaker failure relay(7SV600 or 7SV512) is used per breaker(see application example 10).The deciding criterion of BF protectiontime coordination is the reset time of thecurrent detector (50BF) which must not beexceeded under any condition of currentinterruption. The reset times specified inthe Siemens digital relay manuals are validfor the worst-case condition: interruptionof a fully offset short-circuit current andlow current pick-up setting (0.1 to 0.2times rated CT current).The reset time is 1 cycle for EHV relays(7SA513, 7SV512) and 1.5 to 2 cycles fordistribution type relays (7SJ***).Fig. 126 shows the time chart for a typicalbreaker failure protection scheme. Thestated times in parentheses apply fortransmission system protection and thetimes in square brackets for distributionsystem protection.

Fig. 125

Fig. 126

Normal interrupting time

Fault incidence

Protect. Breaker inter.

time(1~)[2~]

time(2~)[4~]

Currentdetector(50 BF)reset time

(1~)[2~]

Margin

(2,5~)[2,5~]

BFI BF timer (F) (62BF)

0,5~

BFT

0,5~

Adjacentbreakerint. time

(2~)[4~]

Total breaker failure interrupting time

(5~)[8~]

(9~) [15~]

BFI =breaker failureinitiation time(intermediaterelays, if any)BFT =breaker failuretripping time(auxilary relays,if any)

62BF

OR

50BF

P1

P2

Breaker failure protection,logic circuit

P1 P2: primary protection

: alternate protection

AND


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9

10

VRmax = 2 2VKN (VF –VKN) > 2kV

with VF = (RCT + 2·RL + RR)IFmax Through

N

Voltage limitation by a varistoris required if:

Given: n = 8 feedersN = 600/1 AVKN = 500 VRCT = 4 OhmImR = 30 mA (at relay setpoint)RL = 3 Ohm (max.)IRset = 20 mARR = 10 kOhmIVar = 50 mA (at relay setpoint)

Sensitivity:

IFmin = N·(IRset + Ivar + n·ImR)

IFmin = ·(0.02 + 0.05 + 8·0.03)

IFmin = 186 A (31% IN)

6001

Stability:

IFmaxThrough < N· ·IRset

IFmax Through < · ·0.02

IFmax Through < 17 kA (28·IN)

6001

10,0003 + 4

RRRL + RCT

Calculation example:

Fig. 127

Fig. 128

Fig. 129

Fig. 130

VKN =CT knee point voltageVR =RR·IRset

VKN ≥ 2·VR

ImR

V

VKN

VR

Im

RCT

RL

RCT

RL

RCT

RL

RCT

RL

RRVaristor87B

1 2 3 n


High-impedance differentialprotection: Verification of design

The following designdata must be established:

CT data

The CTs must all have the same ratio andshould be of low leakage flux design ac-cording to Class TPS of IEC 44-6 (Class Xof BS 3938). The excitation characteristicand the secondary winding resistance areto be provided by the manufacturer.The knee-point voltage of the CT is requiredto be designed at least for two times therelay pick-up voltage to assure dependableoperation with internal faults.

Differential relay

The differential relay must be a high-impedance relay designed as sensitivecurrent relay (7VH80/83: 20 mA) withseries resistor. If the series resistor isintegrated in the relay, the setting valuesmay be directly calibrated in volts, as withthe relays 7VH80/83 (6 to 60 V or 24 to240 V).

Sensitivity

For the relay to operate in case of an inter-nal fault, the primary current must reach aminimum value to supply the set relaypickup current (IR-set), the varistor leakagecurrent (Ivar) and the magnetizing currentsof all parallel-connected CTs (n·ImR).Low relay voltage setting and CTs with lowmagnetizing demand therefore increasethe protection sensitivity.

Fig. 131

Stability with external faults

This check is made by assuming an exter-nal fault with maximum through-faultcurrent and full saturation of the CT in thefaulted feeder. The saturated CT ist thenonly effective with its secondary windingresistance RCT, and the appearing relay volt-age VR corresponds to the voltage drop ofthe infeeding currents (through-faultcurrent) at RCT and RL. The current at therelay must under this condition safely staybelow the relay pickup value.In practice, the wiring resistances RL maynot be equal. In this case, the worstcondition with the highest relay voltage(corresponding to the highest relay current)must be sought by considering all possibleexternal feeder faults.

Setting

The setting is always a trade-off betweensensitivity and stability. A higher voltagesetting leads to enhanced through-faultstability, but, also to higher CT magnetizingand varistor leakage currents resulting con-sequently in a higher primary pickup cur-rent.A higher voltage setting also requires ahigher knee-point voltage of the CTs andtherefore greater size of the CTs.A sensitivity of 10 to 20% IN is normal formotor and transformer differential protec-tion, or for restricted ground-fault protection.With busbar protection a pickup value≥ 50 % IN is normally applied.An increased pickup value can be achie-ved by connecting a resistor in parallel tothe relay.

Varistor

Voltage limitation by a varistor is needed ifpeak voltages near or above the insulationvoltage (2 kV) are to be expected. A limita-tion to 1500 V rms is then recommended.This can be checked for the maximum in-ternal fault current by applying the formulashown for VR-max.A restricted ground-fault protection maynormally not require a varistor, but, a bus-bar protection in general does.The electrical varistor characteristic can beexpressed as V=K·IB. K and B are the varis-tor constants.

RelaysettingV rms

K

≤125125–240

B Varistortype

450900

0.250.25

600A/S1/S256600A/S1/S1088

Sensitivity:

Stability:

IFmin = N·(IRset + Ivar + n·ImR)

IFThrough max < N· ·IRset

RRRL + RCT

N = CT ratioIRset = Set relay pickup currentIVar = Varistor spill currentImR = CT magnetizing current at

relay pickup voltage


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10

Local and Remote ControlIntroduction

State-of-the-art

Modern protection and substation controluses microprocessor technology and serialcommunication to upgrade substation op-eration, to enhance reliability and to reduceoverall life cycle cost.The traditional conglomeration of often to-tally different devices such as relays, me-ters, switchboards and RTUs is replaced bya few multifunctional, intelligent devicesof uniform design. And, instead of exten-sive parallel wiring (centralized solution,Fig. 132), only a few serial links are used(decentralized solution, Fig. 133).Control of the substation takes place withmenu-guided procedures at a central VDUworkplace.

Fig. 132: Central structure of traditional protection and control

F F

Traditional protection and substation control

Remote terminal unit

To network control center

Alarm annunciationand local control

Marshalling rack

Approx. 20 to40 cores per bay

Mimic displayPushbuttonsPosition indicatorsInterposing relaysLocal/remote switch

Control

Indication lampsMeasuring instrumentsTransducersTerminal blocksMiniature circuit breakers

Monitoring

e.g.Overcurrent relaysGround-fault relaysReclosing relaysAuxiliary relays

Protection

6/72 Siemens Power Engineering Guide · Transmission and Distribution · 4th Edition

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2

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4

5

6

7

8

9

10

Fig. 133: Decentralized structure of modern protection and control


* The compact central control unit can be located in a separate cubicle ordirectly in the low-voltage compartment of the switchgear

Coordinated protection and substation control system

Printer

PC

Control center

Compact centralcontrol unitincluding RTU functions

Shown withopen door

**

Combined protectionand control relay

Low-voltage compartmentof the medium-voltage

switchgear

Protectionrelay

ControlI/O unit

*

Profibus Substation LAN


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7

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9

10


Substation control andprotection system

For numerical substation control and pro-tection system applications, two differentsystems are available:■ SINAUT LSA■ SICAMBy virtue of their different functions andspecific advantages, the two systems cov-er different applications. This means that itis possible to configure an optimum sys-tem for every application.SINAUT LSA is typically used primarily formedium-voltage and high-voltage applica-tions in power supply utilities.The principal use for SICAM products iscurrently in medium-voltage applicationsfor power suppliers and industry.Other features in which they differ aresummarized in Fig. 134.

SINAUT LSA substation control system

Since 1986, SINAUT LSA systems haveproved themselves in practice in over 1500substations. The SINAUT LSA substationautomation system was the first digitalsystem to have integrated all the followingfunctions in a single equipment family:■ Telecontrol■ Local Control■ Monitoring■ Automation and■ ProtectionSINAUT LSA has significantly extended thescope of performance and functionality ofconventional secondary equipment. It isdesign and operation-friendly to a very con-siderable extent.SINAUT LSA is a system matched to re-quirements – from the hardware to the PCtools – and is tailored in optimum form tothe function of numerical substation con-trol and protection systems.Fig. 134 shows the principal applicationaspects of the SINAUT LSA substationcontrol and protection system in compari-son with the SICAM systems.

SICAM Substation Automation System

Units of the SICAM family have been inservice since 1996. The SICAM system isbased on SIMATIC*) and PC standardmodules. SICAM possesses an open com-munication system with standardized inter-faces. Thus, SICAM is a flexible systemcapable of uncomplicated further develop-ment.

The SICAM family offers of the followingoptions:■ SICAM SAS, the substation automation

system with the following features:– Principal function:

substation automation– Decentralized and centralized process

connection– Local control and monitoring with ar-

chive function– Communication with the System

Control Center■ SICAM RTU, the telecontrol system with

central process connection and the fol-lowing features:– Principal function: information commu-

nication

– Central process connection– PLC functions– Communication with Control Center

■ SICAM PCC, the PC-based SubstationControl System with the following fea-tures:– Principal function: local substation su-

pervision and control– Decentralized process connection– LAN/WAN communication with

IEC 60870-6 TASE.2– Flexible communication– Linkage to Office® products.

Fig. 134: Table shows the principal application aspects of the SICAM and SINAUT LSA system families.

+++ Ideally suitable++ Very suitable+ Suitable

(1) Linkage as telecontrol remote stationIED – Intelligent Electronic Device

Telecontrol data concentrator(connection of telecontrol remotestations)

SINAUT LSACentral anddecentralconnection SAS RTU PCC

Telecontrol communication viaWAN with TCP/IP

Telecontrol communication usingstandard protocols IEC 870-5-101,DNP3.0, SINAUT 8FW

Supplementing of project-specifictelecontrol protocols

+++

Supply of existing telecontrolprotocols

IED link using IEC 870-5-103

IED link using DNP3.0

Expansion of existing SICAMsubstations

Incorporation in SIMATICautomation solutions

Linkage of PROFIBUS DP-IEDs

Addition of project-specific IEDprotocols

Uncomplicated, low-cost design

SICAM

++

+ ++++

+++ +++ +++

+ ++ +++++

+++ + ++

+++ ++

+++ +++

+++ ++++++

+++ ++++

+++ ++++

+ ++++

+ ++ ++++++

+++

Expansion of existingSINAUT LSA substations

++(1) ++(1)+++

+

Principal application aspects of SINAUT LSA and SICAM

*)Siemens PLCs and Industrial Automation Systems.For detailed information see: Catalog ST 70,Siemens Components for Totally Integrated Automation.


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Local and Remote ControlSINAUT LSA – Overview

Technical proceedings

The first coordinated protection and sub-station control system SINAUT LSA wascommissioned in 1986 and continuouslyfurther developed over subsequent years.It now features the following main charac-teristics:■ Coordinated system structure■ Optical communication network

(star configuration)■ High processing power

(32-bit µP technology)■ Standardized serial interfaces and com-

munication protocols■ Uniform design of all components■ Complete range of protection and con-

trol functions■ Comprehensive user-software support

packages.Currently (1999) over 1500 systems are insuccessful operation on all voltage levelsup to 400 kV.

System structureand scope of functions

The SINAUT LSA system performs super-visory local control, switchgear interlock-ing, bay and station protection, synchro-nizing, transformer tap-changer control,switching sequence programs, event andfault recording, telecontrol, etc.It consists of the independent subsystems(Fig. 135):■ Supervisory control 6MB5**■ Protection 7S***Normally, switchgear interlocking is inte-grated as a software program in the super-visory control system. Local bay control isimplemented in the bay-dedicated I/O con-trol units 6MB524.For complex substations with multiple bus-bars, however, the interlocking functioncan also be provided as an independentbackup system (System 8TK).Communication and data exchange be-tween components is performed via serialdata links. Optical-fiber connections arepreferred to ensure EMI compatibility.The communication structure of the con-trol system is designed as a hierarchicalstar configuration. It operates in the pollingprocedure with a fixed assignment of themaster function to the central unit. Thedata transmission mode is asynchronous,half-duplex, protected with a hammingdistance d = 4, and complies with theIEC Standard 60870-5.Each subsystem can operate fully in stand-alone mode even in the event of loss ofcommunication.

Data sharing between protection and con-trol via the so-called informative interfaceaccording to IEC 60870-5-103 is restrictedto noncritical measuring or event recordingfunctions. The protection units, for exam-ple, deliver r.m.s. values of currents, volt-ages, power, instantaneous values for os-cillographic fault recording and time-taggedoperating events for fault reporting.Besides the high data transmission securi-ty, the system also provides self-monitor-ing of individual components.The distributed structure also makes theSINAUT LSA system attractive for refur-bishment programs or extensions, whereconventional secondary equipment has tobe integrated.It is general practice to provide protectionof HV and EHV substations as separate,self-contained relays that can communi-cate with the control system, but functionotherwise completely independently.At lower voltage levels, however, higherintegrated solutions are accepted for costreasons.For distribution-type substations combinedprotection and control feeder units (e.g.7SJ63) are available which integrate allnecessary functions of one feeder, includ-

ing: local feeder control, overcurrent andoverload protection, breaker-failure protec-tion and metering.

Supervisory control

The substation is monitored and controlledfrom the operator‘s desk (Fig. 136). TheVDU shows overview diagrams and com-plete details of the switchgear includingmeasurands on a color display. All eventand alarm annunciations are selectable inthe form of lists. The control procedure ismenu-guided and uses mouse and keyboard.The operation is therefore extremely user-friendly.

Automatic functions

Apart from the switchgear interlocking pro-vided, a series of automatic functions en-sure effective and secure system operation.Automatic switching sequences, such aschanging of busbars, can be user-pro-grammed and started locally or remotely.Furthermore, the synchronizing functionhas been integrated into the system soft-ware and is available as an option.

VDU

Event Logger

Modem

”Master Unit“ (i. e. 6MB55)

Stationlevel

Time signal

Bay Protection 7SBay Control Unit6 MB 524 includinginterlocking

Switchyard

Baylevel

1…

ParallelSerial

…n

LSAPROCESS

Operator’sdesk

Modem

EngineeringAnalysis

System Control Center

Fig. 135: Distributed structure of coordinated protection and control system SINAUT LSA


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The synchronizing function runs on the rel-evant 6MB524 bay control units. The per-formance of these functions correspondsto modern digital stand-alone units. Theadvantages of the integrated solution,however, are:■ External auxiliary relay circuits for the

selection of measurands are no longerapplicable.

■ Adaptive parameter setting becomespossible from local or remote controllevels.

High processing powerThe processing power of the central con-trol unit has been enormously increasedby the introduction of the 32-bit µP tech-nology. This permits, on the one hand, amore compact design and provides, on theother hand, sufficient processing reservefor the future introduction of additionalfunctions.

Static memoriesA decisive step in the direction of userfriendliness has been made with the imple-mentation of large nonvolatile Flash EPROMmemories. The system parameters can beloaded via a serial port at the front panel ofthe central unit. Bay level parameters areautomatically downloaded.

Analog value processingThe further processing of raw measureddata, such as the calculation of maximum,minimum or effective values, with as-signed real time, is contained as standardfunction.A Flash EPROM mass storage can option-ally be provided to record measured values,fault events or fault oscillograms.The storedinformation can be read out locally or re-motely by a telephone modem connection.Further data evaluation (harmonic analysis,etc.) is then possible by means of a specialPC program (LSA PROCESS).

Compact designA real reduction in space and cost hasbeen achieved by the creation of compactI/O and central units. The processing hard-ware is enclosed in metallic cases withEMI-proof terminals and optical serial inter-faces. All units are type tested accordingto the latest IEC standards.In this way, the complete control and pro-tection equipment can be directly integrat-ed into the MV or HV switchgear(Fig. 137, 138).

Switchgear interlockingand local control

With the introduction of the bay controlunit 6MB524, the switchgear interlockingand the local control function have beenintegrated completely into the SINAUTLSA station control system. That meansthat there is no technical need for an addi-tional switchgear interlocking like the 8TKsystem, because the SINAUT LSA systemhas the same reliability according to thetesting of interlocking conditions. However,the 8TK system is still available for the casethat an interlocking system with seperatehardware and software is required.

Fig. 137: Switchgear-integrated controland protection

Fig. 138: View of a low-voltage compartment

The interlocking function ensures fail-safeswitching and personal safety down to thelowest control level, i.e. directly at theswitchpanel, even when supervisory con-trol is not available.The bay control unit 6MB524 uses code-words to protect the switchgear from un-authorized operation. With these code-words, the authorization for local switch-ing and unlocked local switching can bereached. The bay-to-bay interlocking condi-tions are checked in the SINAUT LSA cen-tral unit. Each 6MB524 bay control unit hasan optical fiber link to this central unit.

Fig. 136: Digital substation control, operator desk. Control of a 400 kV substation (double control unit)


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Numerical protection

A complete range of fully digital (numeri-cal) relays is available (see chapter PowerSystem Protection 6/8 and followingpages).They all have a uniform design compatiblewith the control units (Fig. 139). This ap-plies to the hardware as well as to the soft-ware structure and the operating proce-dures. Metallic standard cases, IEC 60255-tested, with EMI-secure terminals, ensurean uncomplicated application comparableto mechanical relays. The LCD display andsetting keypad are integrated. Additionallya RS232 port is provided on the front panelfor the connection of a PC as an HMI.The rear terminal block contains an optical-fiber interface for the data communicationwith the SINAUT LSA control system.The relays are normally linked directly tothe relevant I/O control unit at the baylevel. Connection to the central controlsystem unit is, however, also possible.The numerical relays are multifunctionaland contain, for example, all the necessaryprotection functions for a line feeder ortransformer. At higher voltage levels, addi-tional, main or back-up relays are applied.The new relay generation has extendedmemory capacity for fault recording (5 sec-onds, 1 ms resolution) and nonvolatilememory for important fault information.The serial link between protection and con-trol uses standard protocols in accordancewith IEC 60870-5-103.In this way, supplier compatibility andinterchangeability of protection devices isachieved.

Communication with control centres

The SINAUT LSA system uses protocolsthat comply with IEC Standard 60870-5. Inmany cases an adaption to existing propri-etary protocols is necessary, when the sys-tem control center has been supplied byanother manufacturer.For this purpose, an extensive protocol li-brary has been developed (approx. 100protocol variants). Further protocols can beprovided on demand.

Fig. 140: Enhanced remote terminal unit 6MB55, application options

Fig. 139: Numerical protection, standard design

Enhanced remote terminal units

For substations with existing remote ter-minal units, an enhancement towards thedecentralized SINAUT LSA performancelevel is feasible.The telecontrol system 6MB55 replacesoutdated remote terminal units (Fig. 140).Conventional RTUs are connected to theswitchgear via interposing relays andmeasuring transducers with a marshallingrack as a common interface.The centralized version SINAUT LSA canbe directly connected to this interface. Thetotally parallel wiring can be left in its origi-nal state.In this manner, it is possible to enhancethe RTU function and to include substationmonitoring and control with the sameperformance level as the decentralizedSINAUT LSA system.Upgrading of existing substations can thusbe achieved with a minimum of cost andeffort.

VF Modem

Telephone networkRemote control

VF Modem

Marshalling rackPrinter Operator

terminal

Interposing relays,transducers

Existingswitchyard Extended switchyard

ERTU

Modem

Systemcontrolcenter

Substationlevel

Bay level

Managementterminal


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Downloading of parametersduring startup

LSATOOLSparameterization station

Documentation

Loading ofparameters

Network control center

Master unit

PC inputs

Input/outputunits


Engineering system LSATOOLS

In parallel with the upgrading of the centralunit hardware, a novel parameterizing anddocumentation system LSATOOLS hasbeen developed. It uses modern graphicalpresentation management methods,including pull-down menus and multiwin-dowing.LSATOOLS enables the complete configu-ration, parameterization and documentationof the system to be carried out on a PCworkstation. It ensures that a consistentdatabase for the project is maintained fromdesign to commissioning (Fig. 141).The system parameters, generated byLSATOOLS, can be serially loaded into theFlash EPROM memory of the central controlunit and will then be automatically down-loaded to the bay level devices(Fig. 142).Care has been taken to ensure that chang-es and expansions are possible withoutrequiring a complete retest of the system.Because of the object-oriented structure ofLSATOOLS, it is easily possible for the sys-tem engineer to add new bays with allnecessary information.

Fig. 141: Engineering system LSATOOLS

Fig. 142: PC-aided parameterization of SINAUT LSA with LSATOOLS and downloading of parameters

Parameter data Documentation

Engineering system

Parameterizing Documentation


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Local and Remote ControlSINAUT LSA – Distributed Structure

Central control unit 6MB51

Busbar andbreaker failureprotection 7SS5

Stationlevel

Serial interface

Station control centerHigher-levelcontrol system

Central evaluationstation (PC)

Telecontrol channel

Normal time

Telephone channel

1 n

Baylevel

Bay control unit6MB524

Protection relays7S/7U

Substation

Parallel interface

In the SINAUT LSA substation control sys-tem the functions can be distributed be-tween station and bay control levels.The input/output devices have thefollowing tasks on the bay control level:■ Signal acquisition■ Acquisition of measured values and

metering data■ Monitoring the execution of control

commands, e.g. for– Control of switchgear– Transformer tap changing– Setting of Peterson coilsData processing, such as– Limit monitoring of measured values,

including initiation of responses tolimit violations

– Calculation of derived operationalmeasured values (e.g. P, Q, cos ϕ )and/or operational parameters (for ex-ample r.m.s. values, slave pointer)from the logged instantaneous valuesfor current and voltage

– Deciding how much information totransmit to the control master unit ineach polling cycle

– Generation of group signals and deriv-ing of signals internally, e.g. fromself-monitoring

■ Switchgear-related automation tasks– Switching sequences in response to

switching commands or to processevents

– Synchronization■ Local control and operation

(only bay control unit 6MB524):– Display of actual bay status (single

line diagram)– Local control of circuit-breaker and

disconnectors– Display of measurement values and

event recording■ Transmission of data from numerical pro-

tection relays to the control master unit■ Local display of status and measured

values.

Input/output devices

A complete range of devices is available tomeet the particular demands concerningprocess signal capacity and functionality(see Fig. 149). All units are built up in mod-ern 7XP20 housings and can be directlyinstalled in the low-voltage compartmentsof the switchgear or in separate cubicles.The smallest device 6MB525 is designedas a low-cost version and contains onlycontrol functions. It is provided with anRS485-wired serial interface and is normal-ly used for simple distribution-type sub-

Fig. 143: SINAUT LSA protection and substation control system system

stations together with overcurrent/overloadrelays 7SJ60 and digital measuring trans-ducers 7KG60. (see application example,Fig. 165).All further bay control devices contain anoptic serial interface for connection to thecentral control unit, and an RS232 serialinterface on the front side for connectionof an operating PC. Further, integral dis-plays for measuring values and LEDs forstatus indication are provided.

Minicompact device 6MB525

It contains signal inputs and command out-puts for substation control. Analog measur-ing inputs, where needed, have to be pro-vided by additional measuring transducers,type 7KG60. Alternatively, the measuring

functions of the numerical protection re-lays can be used. These can also providelocal indication of measuring values.The local bay control is intended to be per-formed by the existing, switchgear-integratedmechanical control.

Compact devices 6MB522/523

They provide a higher number of signalinputs and outputs, and contain additionalmeasuring functions. One measuring valueor other preprocessed information can bedisplayed on the 2-row, 16-character alpha-numeric display.If local control is required, the bay controlunit 6MB524 is the right choice.


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Bay control unit 6MB524

This bay control device can be delivered infive versions, depending on the peripheralrequirements.It provides all control and measuring func-tions needed for switchgear bays up to theEHV level.Switching status, measuring values andalarms are indicated on a large graphic dis-play. Measuring instruments can thereforebe widely dispensed with.Bay control is, in this case, performed bythe integrated keypad. The synchronizingfunction is included in the software.

Combined protectionand control device 7SJ531

This fully integrated device provides all pro-tection, control and measuring functionsfor simple line/cable, motor or transformerfeeders. Protection includes overcurrent,overload and ground-fault protection, aswell as breaker-failure protection, auto-reclosure and motor supervision functions(see page 6/27).Only one unit is needed per feeder. Space,assembly and wiring costs can thereforebe considerably reduced.Measured value display and local bay con-trol is performed in the same way as withthe bay control unit 6MB524 with a largedisplay and a keypad.

Combined protection and control devices7SJ61, 7SJ62, 7SJ63 and bay control unit6MD63 (SIPROTEC 4 series)

These new SIPROTEC 4 devices have beenavailable since December 1998. With alarge graphical display and ergonomicallydesigned keypad, they offer new possibili-ties for bay control and protection. Via theIEC 60870-5-103 interface, connection tothe substation control system SINAUT LSAis handled. The protection devices includeovercurrent, over/undervoltage and motorprotection functions (see page 6/27).The smaller 7SJ61 and 7SJ62 devices aredelivered with an alphanumerical displaywith 4 lines of text for displaying of meas-urement values, alarms, metering valuesand status of switching devices.The 7SJ63 and 6MD63 units include alarge illuminated graphic display for a clearlyvisible single-line diagram of the switchgear,alarm lists, measured and metered valuesas well as status messages. With the inte-grated key switches, the user authorizationis regulated.For complete description of the newSIPROTEC 4 devices, refer to the protectionchapter (page 6/8).

Fig. 144: MinicompactI/O device 6MB525

Fig. 145: Compact I/O device6MD62

Fig. 147: Compact I/O unit withlocal (bay) control 6MB5240-0

Fig. 148: Combined protection andcontrol device 7SJ531

Fig. 146: Combined protection and control device7SJ63


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101) Local (bay) control has to be provided separately if desired. In distribution-

type substations, mechanical local control of the switchgear may be sufficient.2) Control of switching devices: 11/2 -pole; 2-pole control possible3) Second figure is number of heavy duty relays

Compact1)

Minicompact1) 6MB525 2 – 6 – – – Double commands and alarmsconfigurable also as ”single“

Type Components

6MB5236MB522-06MB522-16MB522-2

Design CommandsDouble Single

Signal inputsDouble Single

Analog inputsDirectconnectionto transformer

Connection tomeasuretransducer

1366

–122

3366

55

1010

1 x I2 x U, 1 x I3 x U, 3 x I4 x U, 2 x I

–2–2

For simple switchgear cubicleswith one switching device

with P, Q calculation

6MB5240-0-1-2-3-4

468

2012

11253

812164024

–––––

2 x U, 1 x I3 x U, 3 x I3 x U, 3 x I9 x U, 6 x I6 x U, 3 x I

12252

High-end bay control forHV and EHVDouble commands and alarmsalso usable as ”single“

Compact withlocal (bay) controland large display

7SJ531 1 – – – 3 x U, 3 x I Double commands and alarmsalso usable as ”single“

Combined controland protectiondevice withlocal (bay) control

6MD6316MD632

6MD633

6MD634

6MD635

6MD636

6MD637

–1

1

–

–

–

1

512

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18

16

16

1–

–

–

1

1

1

4 x I, 3 x U4 x I, 3 x U

4 x I, 3 x U

–

4 x I, 3 x U

4 x I, 3 x U

–

Bay control units in newdesign, optimized for medium-voltage switchgear with11/2-pole control(max. 7 switching devices).2-pole control also possible(max. 4 switching devices).

Double commands and alarmsalso usable as ”single“

Compact with localbay control(SIPROTEC 4 designwith large graphicdisplay) 2)

––

2

–

–

2

–

7SJ6107SJ6127SJ6217SJ6227SJ6317SJ632

7SJ633

7SJ635

7SJ636

––––45 + 43)

5 + 43)

7 + 83)

7 + 83)

4687–1

1

–

–

––––5

12

10

18

16

4 x I4 x I4 x I, 3 x U4 x I, 3 x U4 x I, 3 x U4 x I, 3 x U

4 x I, 3 x U

4 x I, 3 x U

4 x I, 3 x U

Combined control and protec-tion devices. 7SJ61 and 7SJ62with 4 line text display, 7SJ63with graphic display. Optimizedfor 11/2-pole control(max. 7 switching devices).2-pole switching is also poss-ible (max. 4 switching devices).


Combined controland protectiondevice with localbay control(SIPROTEC 4design with largegraphic display) 2)

––––––

2

–

2

3117

111–

–

1

1

45 + 43)

5 + 43)

3 + 43)

7 + 83)

7 + 83)

4 + 83)


Fig. 149: Standardized input/output devices with serial interfaces


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The 6MB51 control master unit

This unit lies at the heart of the 6MB sub-station control system and, with its 32-bit80486 processor, satisfies the most de-manding requirements.It is a compact unit inside the standardhousing used in Siemens substation sec-ondary equipment.The 6MB51 control master unit managesthe input/output devices, controls the inter-action between the control centers in thesubstation and the higher control levels,processes information for the entire stationand archives data in accordance with theparameterized requirements of the user.Specifically, the control master unit coordi-nates communication■ to the higher network control levels■ to the substation control center■ to an analysis center located either in

the station or connected remotely viaa telephone line using a modem

■ to the input/output devices and/or thenumerical protection units (bay controlunits)

■ to lower-level stations.This is for the purpose of controlling andmonitoring activities at the substation andnetwork control levels as well as providingdata for use by engineers.Other tasks of the control master unit are■ Event logging with a time resolution of

1 or 10 ms■ Archiving of events, variations in meas-

ured values and fault records on mass-storage units

■ Time synchronization using radio clock(GPS, DCF77 or Rugby) or using a signalfrom a higher-level control station

■ Automation tasks affecting more thanone bay:– Parallel control of transformers– Synchronizing

(measured value selection)– Switching sequences– Busbar voltage simulation– Switchgear interlocking

■ Parameter management to meet therelevant requirements specification

■ Self-monitoring and system monitoring.

System monitoring primarily involves eval-uating the self-monitoring results of thedevices and serial interfaces which arecoordinated by the control master unit.In particular, in important EHV substations,some users require redundancy of the con-trol master unit. In these cases, two con-trol master units are connected to eachother via a serial interface. System moni-toring then consists of mutual error recog-nition and, if necessary, automatic transferof control of the process to the redundantcontrol master unit.

The SINAUT LSA station control center

The standard equipment of the station con-trol center includes■ The PC with color monitor and LSAVIEW

software package for displaying– Station overview– Detailed pictures– Event and alarm lists– Alarm information

■ A printer for the output reportsThe operator can access the required infor-mation or initiate the desired operationquickly and safely with just a few keystrokes.

Fig. 151: SINAUT LSA PC station control center with function keyboard

Fig. 150: Compact control master unit 6MB513 for amaximum of 32 serial interfaces to bay control units.Extended version 6MB514 for 64 serial interfaces tobay control units (double width) additionally available


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Local and Remote ControlSINAUT LSA – Local Control Functions

Local control functions

Tasks of local control

The Siemens SINAUT LSA station controlsystem performs at first all tasks for con-ventional local control:■ Local control of and checkback indica-

tions from the switching devices■ Acquisition, display and registration of

analog values■ Acquisition, display and registration of

alarms and fault indications in real time■ Measurement data acquisition and pro-

cessing■ Fault recording■ Transformer open-loop and closed-loop

control■ Synchronizing/parallelingUnlike the previous conventional technolo-gy with completely centralized processingof these tasks and complicated parallelwiring and marshalling of process data, thenew microprocessor-controlled technologybenefits from the distribution of tasks tothe central control master unit and the dis-tributed input/output units, and from theserial data exchange in telegrams betweenthese units.

Tasks of the input/output unit

The input/output unit performs the follow-ing bay-related tasks:■ Fast distributed acquisition of process

data such as indications, analog valuesand switching device positions and theirpreprocessing and buffering

■ Command output and monitoring■ Assignment of the time for each event

(time tag)■ Isolation from the switchyard via heavy-

duty relay contacts■ Run-time monitoring■ Limit value supervision■ Paralleling/synchronizing■ Local control and monitoringAnalog values can be input to the bay con-trol unit both via analog value transducersand by direct connection to CTs and VTs.The required r.m.s. values for current andvoltage are digitized and calculated as wellas active and reactive power. The advan-tage is that separate measuring cores andanalog value transducers for operationalmeasurement are eliminated.

Control master unit

The process data acquired in the input/out-put unit are scanned cyclically by the con-trol master unit. The control master unitperforms further information processingof all data called from the feeders for sta-tion tasks ”local control and telecontrol“with the associated event logging and faultrecording and therefore replaces the com-plicated conventional marshalling distribu-tor racks. Marshalling is implemented un-der microprocessor control in the controlmaster unit.

Serial protection interface

All protection indications and fault record-ing data acquired for fault analysis in pro-tection relays are called by the controlmaster unit via the serial interface.These include instantaneous values forfault current and voltage of all phases andground, sampled with a resolution of 1 ms,as well as distance-to-fault location.

Serial data exchange

The serial data exchange between the baycomponents and the control master unithas important economic advantages. Thisis especially true when one considers thepreparation and forwarding of the informa-tion via serial data link to the control centercommunication module which is a compo-nent of the control master unit. This mod-ule is a single, system-compatible micro-processor module on which both thetelecontrol tasks and telegram adaptationto telegram structures of existing remotetransmission systems are implemented.This makes the station control independentof the telecontrol technology and the asso-ciated telegram structure used in the net-work control center at a higher level of thehierarchy.

Station control center

The peripheral devices for operating andvisualization (station control center) arealso connected to the control master unit.The following devices are part of the sta-tion control center:■ A color VDU with a function keyboard

or mouse for display, control, event andalarm indication,

■ A printer for on-line logging (event list),■ Mass storage.

Switchyard overview diagram

A switchyard single-line diagram can beconfigured to show an overview of thesubstation. This diagram is used to givethe operator a quick overview of the entireswitchyard status and shows, for example,which feeders are connected or discon-nected. Current and other analog valuescan also be displayed.Information about raised or cleared opera-tional and alarm indications is also dis-played along the top edge of the screen.It is not possible to perform control actionsfrom the switchyard overview. If the opera-tor wants to switch a device, he has toselect a detailed diagram, say ”110 kVdetailed diagram“. If the appropriate func-tion key is pressed, the 110 kV detaileddiagram (Fig. 153) appears. This displayshows the switching state of all switchingdevices of the feeders.

Function field control

In the menu of the function fields, it is pos-sible, for example, to select between con-trol switching devices and tap changing.The control diagram shows details of sta-tion components and allows control anddefining of display properties or functions(e.g. change in color/flashing). Further-more, the popup diagram window can beopened from here, where switching opera-tions with control elements are performed.The configured switching operation worksas follows:■ Selecting the switch: A click with the

left mouse button on the switch symbolopens the popup window for commandoutput

■ Output of the command. On clicking theoperate button in the popup window thecommand is output

The color of the switch symbol dependson the state. If the command is found tobe safe after a check has been made forviolations of interlock conditions, theswitching device in question is operated.In the case where a mouse is available,the appropriate device is selected by theusual mouse operation.Once the switching command has beenexecuted and a checkback signal has beenreceived, the blinking symbol changes tothe new actual state on the VDU.In this way, switching operations can beperformed very simply and absolutely with-out error. If commands violate the interlockconditions or if the switch position is notadopted by a switching device, for exam-ple, because of a drive fault, the relevantfault indications or notes are displayed onthe screen.


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Event list

All events are logged in chronological or-der. The event list can be displayed on theVDU whenever called or printed out ona printer or stored on a mass-storage me-dium. Fig. 153 shows a section of thisevent list as it appears on the VDU.The event list can also be incorporated inthe detailed displays. The bay-relatedevents can therefore also be shown in thedetailed displays.

Example event list (Fig. 154)

The date can be seen in the left-hand areaand the events are shown in order of prior-ity. Switching commands and fault indi-cations are displayed with a precision of upto 1 ms and events with high priority andprotection indications after a fault-detec-tion are shown with millisecond resolution.A command that is accepted by the controlsystem is also displayed. This can be seenby the index ”+“ of the command (OP),otherwise ”OP–“ would appear.If the switchgear device itself does notexecute the command, ”FB–“ (checkbacknegative) indicates this. ”FB+“ resultsafter successful command execution. Thetexts chosen are suggestions and can beparameterized differently.The event list shows that a protectionfault-detection (general start GS) has oc-curred with all the associated details. Thereal time is shown in the left-hand columnand the relative time with millisecond pre-cision in the right-hand column, permittingclear and fast fault analysis. The fault loca-tion, 17 km in this case, is also displayed.The lower section of the event list showsexamples of raised (RAI) and cleared (CLE)alarm indications, such as ”voltage trans-former miniature-circuit-breaker tripped“.This fault has been remedied as can beseen from the corresponding cleared indi-cation. The letter S in the top line, calledthe indication bar, indicates that a fault indi-cation has been received that is stored ina separate ”warning list“.

Example alarm list (Fig. 155)

When the alarm list is selected, it is dis-played on the VDU. In this danger alarmconcept a distinction is made betweencleared and raised and between acknowl-edged and unacknowledged indications.Raised indications are shown in red,cleared indications are green (similar tothe fast/slow blinking lamp principle).The letter Q is placed in front of an indica-tion that has not yet been acknowledged.Indications that are raised and cleared andacknowledged are displayed in white inthe list.

This system with representation in thealarm list therefore supersedes dangeralarm equipment with two-frequency blink-ing lamps traditionally used with conven-tional equipment.As stated above, all events can also becontinuously logged in chronological orderon the associated printer, too. The appear-ance of this event list is identical to that onthe VDU. The alarm list can also be incor-porated in the detailed displays. The bay-related alarms can therefore also beshown in the detailed displays.

Mass storage

It is also possible to store historic faultdata, i.e. fault recording data and events onmass-storage medium.It can accept data from the control masterunits and stores it on Flash EPROMs. Thisstatic memory is completely maintenance-free when compared to floppy or hard discsystems. 8Mbyte of recorded data can bestored. The locally or remotely readablememory permits evaluation of the data us-ing a PC. This personal computer can beset up separately from the control equip-ment, e.g. in an office. Communicationthen takes place via a telephone-modemconnection.In addition to fault recording data, opera-tional data, such as load-monitoring values(current, voltage, power, etc.) and eventscan be stored.

Local bay control (Fig.152a, Fig. 152b)

With the 6MB524 bay control units, localcontrol and monitoring directly in the bay ispossible. The large graphic display canshow customer-specific single-line dia-grams. A convenient menu-guided opera-

tion leads the user to the display of meas-urands, metering values, alarm lists andstatus messages. The keypad design with6 colors supports the operator for quickand secure operation. User authorization ishandled via password, for example un-locked switching.The new SIPROTEC4 devices also allowlocal bay control. At the 7SJ63 and 6MD63devices, a large graphic display and an er-gonomic keypad assist the operator in con-trol of the switching devices and read outmessages, measurements and meteringvalues. In the 7SJ61 and 7SJ62 protectionunits, the user interface consists of a 4-linetext display. These smaller units also makeit possible to control the feeder circuit-breaker.All SIPROTEC4 devices are parameterizedwith the operating program DIGSI4.

Fig. 152a: Compact I/O unit with local (bay) control, extended version 6MB5240-3

Fig. 152b: 6MD63 bay control unit


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Fig. 156: 6MB substation control system, example: fault recording

Example fault recording (Fig. 156)

After a fault, the millisecond-precision val-ues for the phase currents and voltagesand the ground current and ground voltageare buffered in the feeder protection.These values are called from the numericalfeeder protection by the control masterunit and can be output as curves with theprogram LSAPROCESS (Fig. 156).The time marking 0 indicates the time offault detection, i.e. the relay general start(GS). Approx. 5 ms before the generalstart, a three-phase fault to ground oc-curred, which can be seen by the rise inphase currents and the ground current.

12 ms after the general start, the circuitbreaker was tripped (OFF) and after further80 ms, the fault was cleared.After approx. 120 ms the protection reset.Voltage recovery after disconnection wasrecorded up to 600 ms after the generalstart.This format permits quick and clear analy-sis of a fault. The correct operation of theprotection and the circuit breaker can beseen in the fault recording (Fig. 156).The high-voltage feeder protection present-ly includes a time range of at least 5 sec-onds for the fault recording.

Fig. 153: SINAUT LSA substation control, example: overview picture

The important point is that this fault re-cording is possible in all feeders that areequipped with the microprocessor-control-led protection having a serial interfaceaccording to IEC 60870-5-103.

Fig. 154: SINAUT LSA substation control, example: event list

Fig. 155: SINAUT LSA substation control, example: alarm list


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FPRBCU

FPRBCU

FPRBCU

FPRBCU

CCU withCCC and MS

VDU

Key:

CCUCCCMS

VDUFPRBCU

Modem

Bay 1 2 n Bus coupler

Relaykiosks

To the networkcontrol center

To the operationsand maintenanceoffice

Controlbuilding

Parallel

Serial

Central control unitControl center couplingMass storage

Visual display unitFeeder protection relaysBay control unit

Local and Remote ControlSINAUT LSA – Application Examples

Application examples

The flexible use of the components of theCoordinated Protection and SubstationControl System SINAUT LSA is demon-strated in the following for some typicalapplication examples.

Application in high-voltage substationswith relay kiosks

Fig. 157 shows the arrangement of thelocal components. Each two bays (line ortransformer) are assigned to one kiosk.Each bay has at least one input/output unitfor control (bay control unit) and one pro-tection unit. In extra-high voltage, the pro-tection is normally doubled (main and back-up protection).Local control is performed at the bay units(6MB524) using the integrated graphic dis-play and keypad.Switchgear interlocking is included in thebay control units and in the central controlunit.The protection relays are serially connect-ed to the bay control unit by optical-fiberlinks.

Fig. 157: Application example of outdoor HV or EHV substations with relay kiosks


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In extremely important substations, mainlyextra-high voltage, there exists a doublingphilosophy. In these substations, the feed-er protection, the DC supply, the operatingcoils and the telecontrol interface are dou-bled. In such cases, the station control sys-tem with its serial connections, and themaster unit with the control center cou-pling can also be doubled.Both master units are brought up-to-datein signal direction. The operation manage-ment can be switched over between thetwo master units (Fig. 158).

Control systemmaster unit 1with massstorage 1

Control systemmaster unit 2with massstorage 2

• • • • • • • • • • • •

Network control center

• • • • • • • • • • • • • • • • • • • • • • • •

• • • • • • • • • •

Serial

Switchover andmonitoring*

Localcontrollevel

Printer

Control/annunciation

Controlcentercoupling

Control/annunciation

Controlcentercoupling

Baycontrol level

Protec-tion relay

BayControlunit

Protec-tion relay

BayControlunit

Switchgear

Parallel

Printer

*only principle shown

Feeder 1 Feeder n

Fig. 158: System concept with double central control


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Fig. 159: Typical example of indoor substations with switchgear interlocking system

Fig. 160: Protection and substation control system SINAUT LSA for a distribution-type substation

Key:

CCU

VDU

FPRBCU

VDU

BCUFPRBCUCCU

Modem

To the net-work controlcenter

To the office

Parallel Serial

Central control unit with controlcenter coupling and mass storageMonitor

Feeder protection relaysBay control unit

Control room Switchgear room

BCU

FPR

BCU

FPR

BCU

Controlandpro-tectioncubicles

Switchgear Buscoupler

BCU

bay 1 bay 2 …

Network controlcenter

Operation place

Feeder protection unit(e.g. 7UT51 transformer protection)

Feeder I/O contol unit (e.g. 6MB524)

Combined control andprotection feeder unit 7SJ53

Miniature I/O unit 6MB525

Feeder protection(e.g. 7SD5 line differential protection)

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2

3

45

Central controlunit with optical-fiber link

VDU with keyboard Printer

1 2 3 4 5

Protection and substation control SINAUT LSA with input/output units and numericalprotection installed in low-voltage compartments of the switchgear

Application in indoor high-voltagesubstations

The following example (Fig. 159) shows anindoor high-voltage substation. All decen-tralized control system components, suchas bay control unit and feeder protectionare also grouped per bay and installedclose to the switchgear. They are connect-ed to the central control unit in the sameway as described in the outdoor versionvia fiber-optic cables.

Application in medium-voltagesubstations

The same basic arrangement is also appli-cable to medium-voltage (distribution-type)substations (Fig. 160 and 161).The feeder protection and the compact in-put/output units are, however, preferablyinstalled in the low-voltage compartmentof the feeders (Fig. 160) to save costs.There is now a trend to apply combinedcontrol and protection units. The relay7SJ63, for example, provides protectionand measurement, and has integratedgraphic display and keypad for bay control.Thus, only one device is needed per cable,motor or O H line feeder.


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Fig. 162: Principle wiring diagram of the medium-voltage feeder components

Fig. 162 shows an example for the mostsimple wiring of the feeder units.The voltages between the bay control unitand the protection can be paralleled at thebay control unit because the plug-in mod-ules have a double connection facility.The current is connected in series be-tween the devices. The current input atthe bay control unit is dimensioned for100xIN, 1 s (protection dimensioning).The plug-in modules have a short-circuitingfacility to avoid opening of CT circuits.The accuracy of the operational measure-ments depends on the protection charac-teristics. Normally, it is approx. 2% of IN.If more exact values are required, a sepa-rate measuring core must be provided.The serial interface of the protection isconnected to the bay control unit.The protection data is transferred to thecontrol central unit via the connection be-tween the bay control unit and the centralunit. Thus, only one serial connection to thecentral unit is required per feeder.

To the office

Parallel Serial

Key:

VDU

To the network control center

Buscoupler

BCUFPR BCU FPR CCU BCUFPR

Central control unitwith mass storage andcontrol center couplingMonitor

Feeder protectionrelayBay Control Unit

For o/c feeder ormotor protection alsoavailable as one com-bined unit (e.g. 7SJ63)

Control room Switchgear room

Switchgear

CCU

VDU

FPR

BCU

Modem

Bay Control Unit 1) Numerical 1)

For o/c feeder protection or motor protectionalso available as combined controland protection unit 7SJ63

Switching status

6MB52 ProtectionPlug-in module

CB ON/OFF 2)

Short-circuitingfacility

Protectioncore

U

I

2)closeoropen

closeortrip

1)

2) Only one circuit shown

Serial data connection

2)

Fig. 161: Application example of medium-voltage switchgear


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10

5 feeders

Typical distribution-type substation

115 kV

13.8 kV

115 kV

13.8 kV

5 feeders


System configuration

The system arrangement depends on thetype of substation, the number of feedersand the required control and protectionfunctions. The basic equipment can bechosen according to the following criteria:

Central control master unithas to be chosen according to thenumber of bay control units to be seriallyconnected:■ 6MB513 for a maximum of 32 serial

interfaces■ 6MB514 for a maximum of 64 serial

interfacesAt the most 9 more serial interfaces areavailable for connection of data channels toload dispatch centers, local substation con-trol PCs, printers, etc.

Substation control centerIt normally consists of a PC with keyboardand a mouse, color monitor, LSAVIEW soft-ware and a printer for the output of reports.For exact time synchronization of 1 milli-second accuracy, a GPS or DCF77 receiverwith antenna may be used.

Bay control unitsNormally, a separate bay control unit is as-signed to every substation bay. The typehas to be selected according to the follow-ing requirements:■ Number of command outputs:

that means the sum of circuit breakers,isolators and other equipment to be cen-trally or remotely controlled. The stateddouble commands are normally providedfor double-pole (”+“ and ”–“) control oftrip or closing coils.Each double-pole command can be sep-arated into two single-pole commandswhere stated (Fig. 149, page 6/80).

■ Number of digital signal inputs:as the sum of alarms, breaker and iso-lator positions, tap changer positions,binary coded meter values, etc, to beacquired, processed or monitored.Position monitoring requires doublesignal inputs while single inputs aresufficient for normal alarms.

■ Number of analog inputs:depends on the number of voltages,currents and other analog values(e.g. temperatures) to be monitored.Currents (rated 1 A or 5 A ) or voltages(normally rated 100 to 110 V) can bedirectly connected to the bay controlunits. No transducers are required.Numerical protection relays also acquireand process currents and voltages.

Fig. 163: Typical distribution-type substation Fig. 164: Typical I/O signal requirements for a trans-former bay

They can also be used for load monitor-ing and indication (accuracy about 2% ofrated value). In this way, the number ofanalog inputs of the bay control unitscan be reduced. This is often practisedin distribution-type substations.

The device selection is discussed in thefollowing example.

Example:Substation control configuration

Fig. 163 shows the arrangement of atypical distribution-type substation withtwo incoming transformers, 10 outgoingfeeders and a bus tie.The required inputs and outputs at baylevel are listed in Fig. 164 for the incomingtransformer feeders and in Fig. 165 for theoutgoing line feeders, the bus tie and theVT bay.Each bay control unit is connected to thecentral control unit via fiber-optic cables(graded index fibers).The o/c relays 7SJ60, the minicompactI/O units 6MB5250 and the measuringtransducers 7KG60 each have RS 485communication interfaces and are connect-ed to a bus of a twisted pair of wires.An RS485 converter to fiber-optic is there-fore additionally provided to adapt the seri-al wire link to the fiber-optic inputs of thecentral unit.Recommendations for the selection ofthe protection relays are given in the sec-tion System Protection (6/8 and followingpages).The selection of the combined control/pro-tection units 7SJ531 or 7SJ63 is recom-mended when local control at bay level isto be provided by the bay control unit. Thelow-cost solution 7SJ60 + 6MB5250should be selected where switchgear inte-grated mechanical local control is acceptable.

Control

Isolator HV sideCircuit-breaker HV sideIsolator MV sideCircuit-breaker MV sideTap changer, higher, lowerEmergency trip

SSIDSIDCOSCO

Single signal inputDouble signal inputDouble commandSingle command

2 x DCO2 x DCO2 x DCO2 x DCO2 x SCO1 x SCO

M

I

V

50/51

87T

M

M

HV

RTD's

6MB5240-2 7SJ61 7UT512

To the centralcontrol unitOF

OFOF

M

MV

63

Incoming transformer bays

Data acqusition

1 x DSI1 x DSI1 x DSI1 x DSI8 x DSI

1 x SSI1 x SSI3 x V, 3 x J, 8 xϑ

Isolator HV sideCircuit-breaker HV sideIsolator MV sideCircuit-breaker MV sideTransformertap-changer positionsAlarm Buchholz 1Alarm Buchholz 2Measuring values


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10

51

M

51

M

51

M

51

M

51

To load dispatchcenter

Centralcontrolunit

To transformerfeeders

7KG60 6MB5250

7SJ60 6MB5250

6MB5250

7SJ60 7SJ531or 7SJ63

7SJ531or 7SJ63

6MB513

RS485/O F

RS485

1 x DSI

1 x DSI

1 x DSI

5 x SSI

Isolator

Grounding switch

Circuit-breaker

5 alarms

Load currents are taken from the protection relays

Bus tie

1 x DSI

9 x SSI

Circuit-breaker

9 alarms

Control

2 x DCO Circuit-breaker

Per feeder

1 x DSI

1 x DSI

1 x DSI

5 x SSI

Isolator

Grounding switch

Circuit-breaker

5 alarms

Measuring values(3 x V, 3 x I) from protection

2 x DCO Circuit-breaker 2 x DCO Circuit-breaker

OFOF

OF

Per feederVoltage transformer-bay

1 x 7KG60

GPS

VDU Printer(option)

Massstorage

7SJ60


Fig. 165: Typical I/O signal requirements for feeders of a distribution-type substation


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Local and Remote ControlSINAUT LSA – Centralized (RTU) Structure

Enhanced remoteterminal units 6MB551

The 6MB55 telecontrol system is based onthe same hardware and software modulesas the 6MB51 substation control system.The functions of the inupt/output deviceshave been taken away from the bays andrelocated to the central unit at station con-trol level. The result is the 6MB551 en-hanced remote terminal unit (ERTU).Special plug-in modules for control andacquisition of process signals are usedinstead of the bay dedicated input/outputdevices:■ Digital input (32 DI)■ Analog input (32 AI grouped,

16 AI isolated)■ Command output (32 CO) and■ Command enablingThese modules communicate with thecentral modules in the same frame via theinternal standard LSA bus. The bus can beextended to further frames by parallel in-terfaces.The 6MB551 station control unit thereforehas the basic structure of a remote termi-nal unit but offers all the functions of the6MB51 substation control system such as:

Communication

■ to the higher network control levels■ to an analysis center located either in

the station or connected remotely viaa telephone line using a modem

■ to the bay control unit and/or the numer-ical protection units (bay control units)

■ to lower-level stations (node function).This is for the purpose of controlling andmonitoring activities at the substation andnetwork control levels as well as providingdata for system planning and analysis.

Enhanced terminal unit 6MB551

Station protection7SS5

… …

Bay Control Unit6MB52*

Extension to substation

Serial interface

Station control center (option)Systemcontrol center

Central evaluationstation (PC)

Remote controlchannel

Radio time(option)

Telephone channel

1 n

Protection relay7S/7U

Parallel interface

Marshalling rackTransducers andinterposing relays

(option) (option)

Substation

Fig. 166: Protection and substation control system LSA 678 for a distribution-type substation


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Local and Remote ControlSINAUT LSA – Centralized (RTU) Structure

Other tasks of the enhanced RTU are■ Event logging with a time resolution of

1 or 10 ms■ Archiving of events, variations in meas-

ured values and fault records on massstorage units

■ Time synchronization using radio clock(GPS, DCF77 or Rugby) or using a signalfrom a higher-level control station

■ Automation tasks affecting more thanone bay:– Parallel control of transformers– Synchronizing

(measured value selection)– Switching sequences– Busbar voltage simulation– Switchgear interlocking

■ Parameter management to meet therelevant requirements specification

■ Self-monitoring and system monitoring.■ Up to 96 serial fiber-optic interfaces to

distributed bay control units■ Up to 5 expansion frames.Configuration including signal I/O modulescan be parameterized as desired.Up to 121 signal I/O modules can be used(21 per frame minus one in the baseframefor each expansion frame, i.e. totally6 x 21 – 5 = 121).The 6MB551 station control unit cantherefore be expanded from having simpletelecontrol data processing functions toassuming the complex functionality of asubstation control system.The same applies to the process signalcapacity. In one unit, more than 4 000 datapoints can be addressed and, by means ofserial interfacing of subsystems, this figurecan be increased even further.The 6MB551 station control unit simplifiesthe incorporation of extensions to the sub-station by using the decentralized 6MB52*bay control units for the additional substa-tion bays.

Fig. 167: 6MB551 enhanced remote terminal unit, in-stalled in an 8MC standard cubicle with baseframeand expansion frame

These distributed input/output devicescan then be connected via serial interfaceto the telecontrol equipment. Additionalparameterization takes care of their actualintegration in the operational hierarchy.The 6MB551 RTU system is also availableas standard cubicle version SINAUT LSACOMPACT 6MB5540. The modules andthe bus system have been kept; the rackdesign and the connection technology,however, have been cost-optimized (fixedrack only and plug connectors).This version is limited to a baseframeplus one extension frame with altogether33 I/O modules, and a maximum of 5 seri-al interfaces for telecontrol connectionwithout communication to bay controlunits or numerical protection units.


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MinicompactRTU*

Compact RTU

* Further 3 minicompact RTUs can be serially connected in cascadefor extension (maximum distance 100 m)With switching-current checkPotential-free

6MB552-0A6MB552-0B6MB552-0C6MB552-0D

Type Serial portsto controlcenters

6MB5530-0A6MB5530-0B6MB5530-0C

Design Singlecommands

Alarminputs

Analoginputs

888

Remote ter-minal unit withcable shieldcommunication(RTC)

Serial portsto bay units

6MB5530-1A6MB5530-1C

88

321)/8321)/8321)/8

8

82432

832

7240

104136

–8–

––

32162)

––

1Option 2

1

1additionalgateway

7

–

–

2)

1)

Local and Remote ControlSINAUT LSA – Remote Terminal Units

Remote terminal units (RTUs)

The following range of intelligent RTUs aredesigned for high-performance data acqui-sition, data processing and remote controlof substations. The compact versions6MB552/553 of SINAUT LSA are intendedfor use in smaller substations.

Fig. 171: 6MB5530-1 remote terminal unit (RTC) withcable-shield communication

Fig. 172: Remote terminal units, process signal volumes

Fig. 168: 6MB552 compact RTU for medium processsignal capacity

Fig. 169: SINAUT LSA COMPACT 6MB5540 remoteterminal unit installed in a cubicle

Fig. 170: 6MB5530-0 minicompact RTU for smallprocess signal capacity


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RTU interfaces

The described RTUs are connected to theswitchgear via interposing relays and meas-uring transducers (± 2.5 to ± 20 mA DC)(Fig. 173). Serial connection of numericalprotection relays and control I/O units ispossible with the compact RTU type6MB552.The communication protocols for the serialconnection to system control centers canbe IEC standard 870-5-101 or the Siemensproprietary protocols 8FW.For the communication with protectionrelays, the IEC standard 870-5-103 is im-plemented.Besides these standard protocols, morethan 100 legacy protocols including deriva-tives are implemented for remote controllinks up to system control centers anddown to remote substations (see tableoverleaf).

Fig. 173: RTU interfaces

Fig. 174: VF coupler with ferrite core 35 mm

Modem

Modem

Point to point con. 1)

Line connection 1)

1)

1)

Interposing relays, transducers

……

Modem

Controlcenter

1…

Bay level

Extended switchgear

2) 2) 2)

Optical fiber

Protectionrelays andI/O units

1) Telecontrol channel2) Only with compact RTU 6MB552

Telecontrol channel

M

MM

MRTU M

MMMM

Substationlevel

RTU RTU RTU

RTU M

M

M

RTU

M

RTU

Loop configuration

Marshalling rack

Existing switchgear

Controlcenter

…n

M = Modem


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7

8

9

10


Higher telecontrol level

Distribution station

ModemChannel 1 Channel 2

Mini RTU6MB5530-1 (RTC)

Substation



Power cable (typically 5 km)

Signalloop

Signalloop

VF couplers VF couplers VF couplers

VF couplers VF couplersVF couplers

Power cable (typically 5 km)

Modem(optional)

Multiplexer(optional)Modem

Channel 1 Channel 2

Communicationcontrol unit

6MB5530-1 (CCU)

1st station of branch 8

1st station of branch 1

VF couplers


Distribution station


16th station of branch 1

Substation



16th station of branch 8

VF couplers

1 2 3 4 5 6 7 8

…

…

…… Branch 2

Branch 1

Fig. 175: Remote control network based on remote terminal units with cable-shield communication

List of implemented legacy protocols:■ ADLP 180■ ANSI X3.28■ CETT 20■ CETT 50■ DNP3.0■ DUST 3964R

(SINAUT 8-FW-data structure)■ EFD 300■ EFD 400■ F4F■ FW 535■ FW 537■ Geadat 90■ Geadat 81GT■ GI74■ Granit■ Harris 5000■ IDS■ IEC 60870-5-101

■ IEC 870-5-BAG■ IEC 870-5-VEAG■ Indactic 21■ Indactic 23■ Indactic 33■ Indactic ZM20■ LMU■ Modbus■ Netcon 8830■ RP570■ SAT 1703■ SEAB 1F■ SINAUT 8-FW■ SINAUT HSL■ SINAUT ST1■ Telegyr 709E■ Telegyr 809■ Tracec 130■ Ursatron 8000■ Wisp+

Cable-shield communication

The minicompact RTU can be deliveredin a special version for communication viacable shield (Type 6MB5530-1).It does not need a separate signaling link.The coded voice frequency (9.4 and9.9 kHz) is coupled to the cable shield witha special ferrite core (35 mm or 100 mmwindow diameter) as shown in Fig. 174.The special modem for cable-shield com-munication is integrated in the RTU.Fig. 175 shows as an example the struc-ture of a remote control network formonitoring and control of a local supplynetwork.


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Local and Remote ControlSICAM – Overview

SICAM is an equipment family consistingof products for digital power automation.The system is continuous, from the sys-tem control center, through the informationtechnology, to the bay protection and con-trol units.The SICAM System is based on SIMATIC*)

and PC standard modules. SICAM is thusan open system with standardized inter-faces, readily lending itself to further de-velopment.The SICAM family consists of the follow-ing individual systems (see Fig. 176):■ SICAM RTU, the telecontrol system with

the following features– Principal function: information transfer– Central process connection– PLC functions– Communication with control center

■ SICAM SAS, the decentralized automa-tion system– Principal function: substation automa-

tion– Decentralized and centralized process

connection– Local operation and monitoring with

archiving functions– Communication with the control

center■ SICAM PCC, the PC-based Station Con-

trol System with the following features– Principal function:

Substation supervision and control– Decentralized process connection– LAN/WAN communication with

IEC 60870-6 TASE.2– Flexible communication– Linkage to Office® products

Fig. 176: The SICAM family

IEC 60 870-5-103

SICAM RTU

SICAM SAS

SICAM PCC

Othernetworks

IEC 60870-5-101SINAUT 8-FWPROFIBUSIndustrial Ethernet

PROFIBUS

SICAMWinCC

IEC 60870-5-101

SIPROTEC 4Protection andcontrol devices

Processcontrol unit

OtherIEDs

SIPROTEC 3Protection relays

PROFIBUS

Corporate infor-mation system

PROFIBUS

SIPROTEC 4Protection andcontrol devices

Other IEDs

IEC 60870-5-103

WANe.g. ICCP

SystemControl center

Switchgear

System Control center

...

Protection relays

IEC 60870-5-103

Interposing relays, transducers

Marshalling rack

SIMEASQ or T Trans-ducers

...IEDs(Relays, etc.)

*) Siemens PLCs and Industrial AutomationSystems (see Catalog ST70)


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Local and Remote ControlSICAM RTU – Design

SICAM RTU 6MD201Enhanced Remote Terminal Unit

Overview

The SICAM RTU Remote Terminal Unit isbased on the SIMATIC S7-400, a powerfulPLC version of the Siemens product rangefor industrial automation. The SIMATIC S7-400 has been supplemented by the addi-tion of modules and functions so as to pro-vide a flexible, efficient remote terminalunit. Based on worldwide used SIMATICS7-400, it is possible to add project-specif-ic automation functions to the existing tel-econtrol functions.The SIMATIC S7-400 System has been ex-panded to include the following properties:■ All-round isolation of all connections with

2.5 kV electric strength■ Heavy duty output contacts (10 A,

150 VDC, 240 AC) on external relay mo-dule (type LR with up to 16 commandrelays)

System control center

Communication

Central processconnection

SICAMRTU

Fig. 178: SICAM RTU remote terminal unit

■ CT and VT graded measuring value ac-quisition via serially connected numericaltransducers SIMEAS Q or T(see page 6/132)

■ Acquisition of short-time event signalswith 1 ms resolution and real-timestamping

■ Preprocessing of information acquired(e.g. double indications, metered values)

■ Fail-safe process control (e.g., 1-out-of-ncheck, switching current check)

■ Secure long-distance data transmissionusing the IEC 60870-5-101 or SINAUT8-FW protocol

■ Remote diagnostic capabilityThe open and uniform system structure isillustrated in Fig. 177, showing the essen-tial modules.A variety of SICAM equipment family prod-ucts are available depending on the differ-ent requirements and applications.The individual system modules are de-scribed in detail in the sections below.

Fig.177: SICAM system structure

SICAM: Open system structure

SIPROTEC

SICAM

Database

SICAM WinCC

DIGSI

SICAM plusTOOLS

Bay control devices

Communication

SCADA

CPU

Central I/O

Protective devices

Datarecording

Software Communi-cation


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10


Fig. 179: SICAM mounting rack

System architecture

The SICAM RTU is a modular system. It issuitable for substation sizes from approxi-mately 300 up to 2048 data points.The SICAM RTU consists of the:■ SICAM S7-400 basic rack with its exten-

sion facilities and■ Any S7-400 CPU (412 to 477, with/with-

out PROFIBUS connection). As standardCPU, the CPU 412 or CPU 413 is used.

To supplement the SIMATIC S7-400 mod-ules, telecontrol-specific modules havebeen developed in order to fulfill the re-quired properties and functions, such asfor example electric insulation strength andtime resolution.These are the following modules:■ Power supply

– Voltage range from 19 V–72 V DC– 88 V–288 V AC/DC

■ Process input and output modules– Digital input DI (32 inputs) for status

indications, counting pulses, bit pat-terns and transformer tap settings• voltage ranges:24–60 V DC110–125 V DC

– Analog input AI (32 analog inputsgrouped, 16 AIR (analog inputs iso-lated) for currents (0.5 mA–24 mA)and voltages (0.5 V–10 V)

– Command output (32 CO) forcommands and digital setpoints• voltage range: 24–125 V DC

– Command release (8 DI, 8 DO) forlocal inputs and outputs and monitor-ing of command output circuits• voltage ranges:24–60 V DC110–125 V DC

■ Communication module– Telecontrol processor TP1 for commu-

nication with the system control cen-ter with protocols IEC 60870-5-101and SINAUT 8-FW and as time signalreceivers for DCF77 or GPS reception.

The Power Supply and the I/O modulescan also be used in SICAM SAS.


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Construction

The SICAM RTU is based on the SIMATICS7-400. The construction of the SICAMRTU is therefore, as is the case withSIMATIC, highly compact, straightforwardand simple to operate:■ All connections are accessible from the

front. Therefore, no swivel frame is nec-essary.

■ The modules are enclosed and thereforeextremely rugged.

■ Plugging and unplugging of modules ispossible while in operation; thereforemaintenance work can be carried out ina minimum of time (reduced MTTR).

■ Direct process connection is effected bymeans of self-coding front plug connec-tors of screw-in or crimp design.

■ During configuration, no module slotrules have to be observed; the SICAMRTU permits free module fitting.

■ No forms of setting are necessary onthe modules; replacement can be carriedout in a minimum of time.

Dependent on configuration level and cus-tomer requirements, there are two housingvariants:■ a floor-mounting cabinet and■ a wall-mounting cabinet.Both housing variants are optimized for theSICAM RTU; they are of flexible modularconstruction. Thus, for example, provisionis made for installation of accessories toprovide a cost-effective rack system.

Fig. 180a: SICAM RTU wall-mounting cabinet

Fig. 180b: SICAM RTU floor-mounting cabinet


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SICAM Modules

SICAM RTU modules have been developedto be SIMATIC-compatible and can there-fore be used in a standard SIMATIC S7-400,for example for the following applications:■ Acquisition of status indications with a

resolution of 1 ms and an accuracy of± 2 ms

■ Time synchronization of the SIMATICCPU to within an accuracy of ± 2 ms

■ An analog input module with 32 channelswith current or voltage inputs

■ Use of modules with 2.5 kV electric insu-lation strength in order to save interpos-ing relays

The modules are used for example in hydro-power plants for acquisition of fault eventsvia digital input with a resolution of 1 msand relaying them to a power station sys-tem, for example via an Industrial Ethernet.The other application is the use of the com-munication module TP1 in a SIMATIC NET -IEC 60870-5-101 gateway. Fig. 182 showsan example of a PROFIBUS gateway.

Fig. 181: SICAM module

Fig. 182: Gateway: PROFIBUS – IEC 60870-5-101

SICAM RTU

Switchgear

IEC 60870-5-101SINAUT 8-FWPROFIBUSIndustrial Ethernet

IEDs

Profibus

Gateway


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Local and Remote ControlSICAM RTU – Functions

SICAM RTU functions

SICAM RTU possesses telecontrol func-tions, such as:■ Alarm acquisition and processing, includ-

ing:– Single point information– Double point information– Bit patterns– Transformer taps– Metering pulses

■ Measured value acquisition and process-ing, including:– parameterizable current inputs in

ranges from0.5 mA–24 mA

– parameterizable voltage inputs inranges from 0.5 V–10 V

■ Fail-safe command output, including:– Single commands– Double commands– Bit pattern outputs– Transformer tap change control– Pulse commands– Continuous commands

■ Telecontrol communication with a maxi-mum of two system control centerswith different telecontrol messages,with the standardized IEC 60870-5-101and/or with the worldwide provenSINAUT 8-FW protocol.

In addition to the standard RTU functions,the SICAM RTU provides additional func-tions, such as:■ Efficient operation mode control with 15

priorities and various send lists,such as:– Spontaneous lists with/without time– Scan lists for measured values, me-

tered values or status indications– Cyclic lists– Time-controlled lists

With the aid of this mode control system,it is possible to optimize the data flow be-tween remote terminal unit and systemcontrol center.

■ Time synchronization via DCF or GPS re-ceiver on the TP1 module.The SIMATIC CPU is synchronized towithin an accuracy of 1 ms.

■ Serial interface to a maximum of twocontrol centers.In addition to selection of the telecontrolprotocols IEC 60870-5-101 and SINAUT8-FW, the scope of status indications,measured values and commands percontrol center per interface can be con-figured, with separate telecontrol proto-cols, different process data, differentmessage addresses and different modes.

■ Can be extended up to 4096 informationpoints

■ Comprehensive remote diagnostic facili-ties locally or in remote form with the aidof the SIMATIC TeleService.

■ Output of analog setpoints via theS7-400 AO module (1500 kV insulated)

■ SICAM RTU is maintenance-free andrequires no fan cooling

■ The variety of available module typeswith wide-range inputs is kept to a mini-mum; the value ranges are parameterizble.

Fig. 183: plusTOOLS for SICAM RTU, hardware configuration

Engineering

The SICAM RTU is designed such that alltelecontrol functions are parameterizable.Comprehensive Help texts assist the oper-ator during configuration. The followingconfiguration steps are carried out with theaid of the intuitive-operation program plus-TOOLS for SICAM RTU:■ Creation of hardware configuration,

SIMATIC modules and SICAM modules■ Setting of module parameters on the

SIMATIC modules and SICAM modules■ Assignment of process data to the mes-

sage addresses■ Assignment of message addresses to

the message lists in the mode controlsystem, stipulation of send priorities.

■ Checking of all parameters for plausibil-ity.

■ Loading of parameters into a non-volatileflash EPROM of the CPU.

Fig. 183 shows as an example the maskfor hardware configuration.

1. Select a module from the Hardware Catalog and2. Drag it to the desired module location –

automatic plausibility checking and addressing


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Local and Remote ControlSICAM RTU – Functions

Fig. 184a: Operator Panel

Fig. 184b: Operator Panel mounted in a cubicle door

Automation functions

The SICAM RTU is based on the SIMATICS7-400. Therefore, all modules of theSIMATIC S7-400 System can be used in aSICAM RTU: For example, a CPU 413-DPwith PROFIBUS connection or the com-munication processor CP 441, e.g. for con-nection of a Modbus device.If additional functions are to be introducedproject-specifically by S7 PLC means,these can be integrated with the aid of theinternal API Interface (Application ProgramInterface). Thus, for example, the data re-ceived via the CP 441 can be processedinternally and sent via the TP1 to the sys-tem control center.The following functions can for examplebe implemented:■ Initiate functions by commands from

the system control center■ Derive commands as a function of

measured value changes (e.g. loadshedding when a frequency drop hasbeen measured)

■ Connection of an operator panel to theserial system interface (Fig. 184a/b)

■ Connection of decentralized peripheralsvia the PROFIBUS DP


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Local and Remote ControlSICAM MRTU/microRTU

SICAM MRTU 6MD202/6MD203Small Remote Terminal Unit

Overview

Supplementary to the SICAM RTU, thefollowing small remote terminal units areavailable for low-level upgrades:■ SICAM microRTU 6MD203 up to

50 process inputs/outputs■ SICAM miniRTU 6MD202 up to

300 process inputs/outputsThe two remote terminal units are basedon the SIMATIC S7-200.Supplementary to the SIMATIC modules, a“SICAM TCM” communication module hasbeen developed for the SICAM miniRTU.The TCM module is installed in a S7-214housing.The SICAM micro and miniRTUs providesmall remote terminal units which handlethe process data and communicate bymeans of an assured IEC 60870-5-101 tel-econtrol protocol with the system controlcenter. The SICAM miniRTU makes it pos-sible to supplement project-specific func-tions.Both units possess the following advantag-es of the SIMATIC S7-200 System in termsof construction:■ Compact design■ Quick mounting by snapping onto a hat

rail■ Low power consumption■ Extensive range of expansion modules

– Digital inputs– Relay outputs– Electronic outputs– Analog inputs– Analog outputs

■ Connection of expansion modules bymeans of plug-in system

■ Connection of process signals by meansof screw terminals

■ Automatic recognition of upgrade level

Fig. 185: SICAM microRTU

SICAM microRTU 6MD203

For the SICAM microRTU, it is possible touse an S7-214 or an S8-216 CPU. The PPIinterface is used for loading the programsand the parameters and also for communi-cation with the system control center.The standardized transmission protocol IEC60870-5-101 has been implemented. Un-balanced mode has been chosen as trafficmode because small remote terminal unitsare generally operated in partyline (that isto say polling) mode.The SICAM microRTU performs the follow-ing functions:■ Acquisition and processing of a maxi-

mum of 24 single point items of infor-mation

■ Acquisition and processing of meteringpulses (maximum 20 Hz) for a maximumof 4 metered values

■ Acquisition of a maximum of 12 meas-ured values

■ Command output as pulse or persistentcommand for a maximum of 14 digitaloutputs

■ Transmission of data (priority-controlled)spontaneously or on demand in half du-plex mode

■ Transmission rate: 300–9600 bit/secParameterizing takes place with STEP7MicroWIN. All parameters are preset; theyonly have to be adapted slightly. The pa-rameters are loaded locally from the PC.For transmission, there is a gradable V.23hat-rail-mounted modem with an RS-485interface. The transmission rate is 1200bit/sec.


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Local and Remote ControlSICAM miniRTU

Functions

The SICAM miniRTU performs the follow-ing functions or incorporates the followingfeatures:■ Acquisition and processing of single

point and double point information.Transmission with or without time inmessage.

■ Acquisition and processing of meteringpulses (maximum 20 Hz). Re-storing bymeans of internal timer or by means ofmessage from the system control center.Transmission with or without time inmessage.

Fig. 186: SICAM miniRTU with TCM and S7-214 CPU

SICAM miniRTU 6MD2020

Overview

The SICAM miniRTU differs from a SICAMmicroRTU in the following respects:■ Volume of data: 300 instead of 50 infor-

mation points■ Clock control: messages with time

stamp are possible■ An integrated V.21 modem is available■ Project-specific additions can be intro-

duced via the API interfaceThe SICAM miniRTU is a small, efficientmodular remote terminal unit with a widerange of functions. The SICAM miniRTUcan be upgraded from a configuration levelof 14 digital inputs up to a medium-sizedterminal with a maximum of 300 processpoints.For the SICAM miniRTU, it is possible touse the S7-200 CPUs 27-214 or S7-216. Inaddition, the TCM (telecontrol module)communication module is required. TheTCM incorporates an RS-232 interface forcommunication with the system controlcenter; this implements the entire mes-sage interchange. The standard transmis-sion protocol is implemented: IEC 60870-5-101, unbalanced mode. IEC 60870-5-101balanced mode and SINAUT 8-FW point-to-point traffic are in preparation.Fig. 186 illustrates a minimum configura-tion level of a SICAM miniRTU with anS7-214 CPU. Fig. 187 shows in diagram-matic form a maximum configuration levelwith 3 S7-200 CPUs.

■ Acquisition and processing of measuredvalues, threshold processing, thresholdmatchable by means of message.Transmission with or without time inmessage.

■ Command output as pulse commandswith 1-out-of-n monitoring and commandrelease. Persistent command output ispossible.

■ Analog setpoint output.■ Bit-by-bit assignment of process infor-

mation to processing functions■ Clock control with synchronization by

message from system control center

Fig. 187: SICAM miniRTU with TCM and three S7-214 CPUs

2-wire, partyline traffic, transmission on demand

IEC 60870-5-101unbalanced mode


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To control centerPoint-to-point traffic

SINAUT LSAdata concentrator

2-wire, polling mode


Communication

Communication with the system controlcenter is carried out by the SICAM miniRTUwith the TCM communicaton module.A gradable V.21 modem is already integrat-ed in the TCM, so that the SICAM miniRTUcan be used directly.Other communication characteristics are:■ Transmission speed of 300–9600 bit/

sec. adjustable■ Mode control with 15 priorities which

can be freely assigned■ Different send lists for:

– Spontaneous mode– Polling mode– Cyclic mode

Linkage of small remote transmission unitsgenerally takes place by means of trans-mission on demand. The lines with the re-mote transmission units are compressedwith the aid of a data concentrator and arerelayed to the system control center.Fig. 188 shows an example of configura-tion.Rail-mounted modems with RS-232 inter-face are available for transmission with anexternal modem:■ Gradable V.23 modem with 1200 bit/sec

transmission speed■ Dedicated line modem – V.32 modem –

with a transmission speed of 9600 bit/sec.

Fig. 188: SICAM miniRTU, typical configuration

Project-specific expansion options

In the SICAM miniRTU, an API interface(Application Program Interface) is availa-ble. Project-specific programs can thus beupgraded. Access by the API interface tocommunication is supported by the sys-tem. That is to say, the information fromthe control center can be processed in theuser program; information derived in theuser program can be remotely controlled.Examples of this are:■ Formation of group alarms,■ Transmitting internally formed meas-

ured values or metered values to thecontrol center,

■ Initiating functions by means of com-mands from the control center,

■ Influencing of alarm processing,for example filtering, relaying via API,

■ Activating PROFIBUS link on an S7-215.


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SICAM RTU

SICAMmicroRTU

1) Processing of double point information and double commands is also possible. The table is intended solely to represent the numberof connection points.

2) Maximum values; note combination options!

RTU Type Serial portsto CC

6MD201

Design Singlecommands 1)

Analoginputs

Analogoutputs

typical up to 2048maximum: 4096

SICAMminiRTU

2

Single pointinformation 1)

6MD202 192 2) 192 2) 36 2) 12 2) 1

6MD203 24 16 12 4 1


Engineering

Parameterizing is effected with the plus-TOOLS program for miniRTU. The programcan be run on Windows 95, 98 or NT 4.Parameterizing takes place operator-guidedby means of menus. Extensive help textsfacilitate operation. Figs. 190 and 191 illus-trate as examples the mask for hardwareconfiguration and the mask for assignmentof message addresses.The parameters are checked for plausibilityprior to loading. They are loaded in non-volatile form from the PC into the flashEPROM of the TCM. All parameters of aSICAM miniRTU can be read locally withthe PC. For this purpose, the parameterset of the station to be read out does nothave to be present on the PC. Modificationand reloading is possible.

Fig. 190: plusTOOLS, generation of hardware configuration Fig. 191: plusTOOLS, parameterizing of communication

Fig. 189: Remote terminal units, process signal volumes


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Local and Remote ControlSICAM SAS – Overview

SICAM SAS Overview

In order to assure security of supply, thesubstation automation system must be ca-pable in normal operation of real-time ac-quisition and evaluation of a large volumeof individual items of information.In the event of a fault, additional informa-tion is required to assist rapid fault diagno-sis. Graphic display functions, logs andcurve evaluations are aids suitable for thispurpose. The SICAM SAS substation con-trol and protection system provides a sys-tem solution for efficient implementationof these functions.SICAM SAS is designed as an open-typesystem which, based on internationalstandards, provides simple interfaces forintegration of additional bay control units ornew transmission protocols, as well as in-terfaces for implementation of project-spe-cific automation functions.

Field of application

SICAM SAS is used in power transmissionand distribution for automation of medium-voltage and high-voltage substations.It is used wherever:■ Distributed processes are to be moni-

tored and controlled.■ Functions previously available on a high-

er control level are being decentralizedand implemented locally.

■ High standards of electric insulationstrength and electromagnetic compatibil-ity are demanded.

■ A real-time capability system is required.■ Reliability is very important.■ Communication with other control sys-

tems must be possible.

Fig.192: SICAM SAS components: SICAM SC Substation Controller,SIPROTEC 4 relays and 6MB525 bay control units

Functions

SAS assumes the following functions in asubstation:■ Monitoring■ Data exchange with and operation of se-

rially connected protection devices andother IEDs

■ Local and remote control with interlock■ Teleindication■ Automation■ Local processing and display■ Archiving and logging


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Local and Remote ControlSICAM SAS – Structure

System architecture

The typical configuration of a SICAM SASconsists of:■ SICAM SC Substation Controller■ Connection to higher-level system con-

trol centers■ Connection to bay level■ Bay control units, protection relays or

combined control and protection bayunits.

■ Configuration PC with SICAM plusTOOLS■ Operation and monitoring with SICAM

WinCCThe modular construction of the systempermits a wide range of combination op-tions within the scope of the system limits.In the SICAM SC substation controller, theSICAM I/O modules can be used for alter-native central connection of process inputsand outputs (see description of the SICAMRTU).

Fig. 193: Typical configuration of a SICAM SAS

System control center(s) or telecontrol node(s)

IEC 60870-5-101SINAUT 8-FW

SICAM SCSubstationController

SIMATIC NET

SICAM plusTOOLSConfiguration

SICAM WinCCOperator control,monitoring,and archiving

SIPROTEC 4 protectionand control devices

6MB525 baycontrol unitsand 7**6relays

SIPROTEC 3protection relays

GPS

PROFIBUS FMS wireRS485 O.F. O.F.

IEC 60870-5-103


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Local and Remote ControlSICAM SAS – SC Substation Controller

SICAM SC Substation Controller

The SICAM SC is an open-type, modularconstruction telecontrol and substationcontroller. The specific functions of a tele-control system are combined with those ofa programmable automation system (PLC).Standard functions of the automation sys-tem and control and protection-specificapplications, such as real-time processing,fail-safe command output or telecontrolfunctions, combine to form a rugged,future-oriented hardware system.The basis of the SICAM SC is formed bythe SIMATIC M7-400 family of systems. Inorder to meet the increased requirementsof telecontrol and substation control tech-nology for electric insulation strength, younow have at your disposal a wide range ofmodules and devices to supplement theSIMATIC standard modules. The communi-cation processors of the system supportthe IEC 60870-5-101, SINAUT 8FW,IEC 60870-5-103, PROFIBUS FMS, PROFI-BUS DP and Industrial Ethernet communi-cation protocols.

Hardware

The hardware of the SICAM SubstationController is based on the standard mod-ules of the SIMATIC S7/M7-400 automa-tion system and on additional moduleswhich have been developed for the specialrequirements of control and protection.The following modules form the basic com-plement of the SICAM SC:■ Power Supply■ SIMATIC M7-400 CPU

(Pentium processor)■ MCP (Modular Communication

Processor)The MCP module is the function modulewhich supports the communication func-tions, such as telecontrol connection tohigher-level system control centers, e.g.with the IEC 60870-5-101 protocol, andserial connection of bay control units bymeans of the IEC 60870-5-103 protocol. Inaddition, it is in SICAM SAS the time mas-ter, to which can be connected time signalreceivers for DCF77 or GPS.Additionally available for the MCP are theXC2 (eXtension Copper 2 interfaces) andXF6 (eXtension Fiber optic 6 interfaces)extension modules for additional communi-cation interfaces to higher-level systemcontrol centers and bay control units (IEC 60870-5-103).In addition, the following modules can beused for supplementary functions in theSICAM SC:■ For central process connection:

SICAM I/O modules (see description ofthe SICAM RTU) and SIMATIC 400Standard I/O modules (see Siemens Cat-alog ST 70)

■ For connection of bay control units viaProfibus DP and FMS:SIMATIC 400 communication processormodules

■ For connection to SICAM WinCC:SIMATIC 400 modules for Profibus FMSand Industrial Ethernet

Construction

Like the SICAM RTU, the SICAM SC isbased on the SIMATIC 400. Consequently,the statements on construction of theSICAM RTU are also applicable to theSICAM SC.

Software

The bases of the run-time system (SICAMRTC for SAS) in the SICAM SC are to befound both on the M7-CPU and on theMCP module real-time operating systemsfor event-controlled program execution.Among other things, this assures an es-sential requirement for control applications:State change of information may not belost or remain unnoticed in critical situa-tions (→ alarm surge).


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System security

SICAM SAS fulfills to a very considerableextent the reliability and security require-ments imposed on a substation controland protection system. In the case of allelectronic devices incorporated in theSAS SICAM System, special attention hasbeen paid to electromagnetic compatibility.

Interruption of power supply

The SICAM SAS System is designed to bemaintenance-free, that is to say no backupbatteries are required for restart aftermains failure.

Safety functions

Hardware self-test: On startup and cyclical-ly in the background.General check: At start of the transfer timesystem and creep mode in background.

Communication

Errors in data transmission due to electro-magnetic effects, earth potential differenc-es, ageing of components and other sourc-es of interference and noise on the trans-mission channels are reliably detected.The safety measures of the protocols pro-vide protection from:■ Bit and message errors■ Information loss■ Unwanted information■ Separation or interference of assembled

items of information

Priority-controlled message initialization

Messages initiated by events are initializedquickly (priority-controlled).

Failure indication

The failure status is derived in case of:■ Contact chatter■ Signalling-circuit voltage failure■ Module out of orderA telecontrol malfunction group alarm canbe parameterized from individual pieces ofinformation, for example:■ MCB trip■ Voice-frequency telegraphy error■ Channel error■ No signalling-circuit voltage■ Module out of order■ Buffer overflow

System capacity

The maximum configuration of theSICAM SC substation controller consistsof:■ 1 baseframe with 7 to 11 free module

locations, dependent on choice of MCPcommunication link and

■ Maximum of 6 expansion racks,each with 14 free module locations

Thus, you have available a maximum of95 free module locations which you canequip for example with 95 I/O modules ora further 4 MCP(4) communication assem-blies and 75 I/O modules. For connectionof bay control units via PROFIBUS FMS, upto 4 CP443-5 base communication proces-sors can be plugged into the baseframe.Each CP443-5 requires one module loca-tion. For connection of PROFIBUS DP de-vices, an interface module is used which isplugged into a module shaft of the CPUmodule. Connection to Industrial Ethernetcan be implemented via the CP443-1 com-munication processor and will then requireone module location. Alternatively, you canalso however use the CP1401 interfacemodule which is plugged into a moduleshaft of the CPU module.Under these conditions, it is possible to im-plement up to a maximum of 3040 itemsof information to a SICAM SC via central-ized process connection. With the use ofbay control units – linked to the SICAM SCvia MCP communication assemblies orPROFIBUS – it is possible for up to 10,000items of information to be managed, fordecentralized process connection.

Interfaces

The variability and expansion capability ofa substation control and protection systemdepends primarily on its outward interfac-es. SICAM SAS supports internationalstandards, such as PROFIBUS, theIEC 60870 5-101 telecontrol protocol orthe IEC 60870-5-103 relay communicationprotocol and thus assures optimum flexibili-ty of substation planning.The SICAM communication modules of theSICAM SC are equipped with serial inter-faces (parameterizable as RS232 or asRS422/485) and with optical fiber links.They are combined, according to applica-tion, to form MCP communication assem-blies which consist of the MCP communi-cation processor and XC2 and/or XF expan-sion modules.

Measured value capturing

■ Live zero monitoring (4–20 mA)

Command output

Safe command output, i.e.■ Destination monitoring (1-out-of-n)■ Switching current check■ Interference voltage monitoring■ Determination of the coil resistanceThe SICAM SC system provides the follow-ing five operating modes, thus allowing theuser to take into account different safetyrequirements for process output:■ 1-pole command output■ 11/2-pole command output■ 2-pole command output■ 11/2-pole command output with separate

command release through CR module■ 2-pole command output with separate

command release through CR moduleBy combining the CO module with theCR module, a single error (in case of 11/2-pole command output) in the commandoutput circuit results in the command notbeing executed.Through the test and monitoring measuresprovided by the CR module, which make itpossible to distribute the command outputcircuit to two independent modules, highrequirements are met.


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– IEC 60870-5-103protection relays andbay unitsModule MCP (XC2, XF6)

IED-communication

– IEC 60870-5-103SINAUT 8FWModule MCP (XC2, XF6)

– PROFIBUS FMSConnection to SIPROTECModule CP443-5

– PROFIBUS DPDP-“devices“Module IF964

– Industrial Ethernet– PPROFIBUS FMS

Connection to SICAMWinCCModule CP443-1or -5

Substation bus

Field bus

Telecommunication


Telecontrol interfaces

Via the serial interfaces of the MCP com-munication processor and the XC2 expan-sion modules, one can connect the SICAMSC to a maximum of three higher-level sys-tem control centers.The telecontrol interfaces are operatedwith the IEC 60870-5-101 or SINAUT 8FWtransmission protocols and are parameter-izable as RS232, RS422/RS485 or opticalfiber interfaces.

Bay control unit interfaces

For connection of decentralized items ofinformation via bay control interfaces, vari-ous options are available:■ A maximum of 4 CP 443-5 base mod-

ules for connection of bay control unitswith PROFIBUS FMS interface. Onecan connect a maximum of 48 devices(SIPROTEC 4, 6MB525) per module; thetotal number in the design may nothowever exceed 96 devices.

■ One IF964-DP interface module for con-nection of a maximum of 20 SU200 baycontrol units and/or SIMEAS measuringtransducers via PROFIBUS DP. For allother bay control units with PROFIBUSDP interface, the upper limit of 127 de-vices will apply.

■ A maximum of 4 MCP(4) communicationassemblies, each consisting of one MCPcommunication processor and 4 XF6 ex-pansion modules with optical fiber inter-faces for a maximum of 96 bay controlunits (IEC 60870-5-103).

■ A maximum of 1 MCP (1) communica-tion assembly (consisting of 1 MCPcommunication processor and 1 XC2 ex-pansion module) and 1 MCP communi-cation assembly (consisting of 1 MCPcommunication processor) for a maxi-mum of 186 bay control units via a maxi-mum of 6 RS485 lines (IEC 60870-5-103).

Combinations of the above examples arepossible, but the quantity of 10,000 infor-mation points should not be exceeded.

MPI interface

On the CPU module is located 1 MPI inter-face (token ring multipoint-capability busstructure) for design, parameterizing, diag-nostics.

Time signal reception

The MCP communication processor pos-sesses an interface for receipt of an exter-nal time signal. Time synchronization iseffected by means of DCF77 or GPS.

Fig. 194: SICAM SC communication interfaces

Design tools

Design of the SICAM SC is carried out withSICAM plusTOOLS which is based on theSIMATIC basic modules: STEP7, SIMATICCFC and Borland C/C++.

Process visualization

For visualization and control of the process,SICAM WinCC is used; this is based onSIMATIC WinCC.

Expandability

SICAM has been designed for a new gen-eration of devices and function modules forthe automation of substations in powersupply.SICAM integrates complementary andcompatible product lines and is the logicalcontinuation of proven, available modules.By virtue of its open system concept,SICAM SAS is adaptable to the growingdemands of the future. System expansionand further development are readily possible.

Bay control units

In the design and parameterizing of sub-device connections, SICAM plusTOOLSaccesses databases which describe theinterface complement of the devices.Creation of a new protection unit type withIEC 60870-5-103 transmission protocol ismade possible by the parameterizer inSICAM plusTOOLS.

Protocols

Telecontrol and field bus protocols will infuture be incorporated in modular fashionby means of an expansion interface.

SIMATIC modules

Within SICAM SAS, it is possible to usethe SIMATIC Standard I/O modules (seeSiemens Catalog ST70, Siemens Compo-nents for Totally Integrated Automation.)


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Local and Remote ControlSICAM SAS – Bay Control Units

Bay control units

Serial connection of distributed bay controlunits allows access to extensive detailedinformation about your switchgear in thesubstation control and protection system.For this purpose, SICAM SAS offers baycontrol units with differing scope of infor-mation and function. The range extends,according to requirements, from pure baycontrol units and protection relays on theone hand, to combined devices on the oth-er hand which provide the bay protectionand control functions in a single unit.SICAM SAS supports bay control unitswith IEC 60870-5-103, PROFIBUS FMSand PROFIBUS DP interface.

6MB525 Mini Bay Unit

(see description of SINAUT LSA)This low-end unit with its limited range ofinformation is preferably used in single-busbar substations. It can be connectedvia RS485 with IEC 60870-5-103 or viaPROFIBUS FMS to the SICAM SC.

7SJ531 CombinedBay Control and Protection Unit

(see description of SINAUT LSA and Pow-er System Protection)The 7SJ531 possesses, in addition to pro-tection functions, the facility for controllinga switching device (also remotely). It canbe integrated in the SICAM SAS withIEC 60870-5-103 via optical fiber link.

Type ComponentsDesign CommandsDouble Single

Signal inputsDouble Single

Analog inputsDirectconnectionto transformer

Connectionto measuretransducer

6MD6316MD632

6MD633

6MD634

6MD635

6MD636

6MD637

45 + 4 2)

5 + 4 2)

3 + 4 2)

7 + 8 2)

7 + 8 2)

4 + 8 2)

–1

1

–

–

–

1

Bay control units in newdesign, optimized for mediumvoltage switchgear with11/2-pole control (max. 7switching devices). 2-polecontrol is also possible (withmax. 4 switching devices).


Compact baycontrol unit(SIPROTEC 4design with largegraphic display) 1)

512

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1–

–

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4 x I, 3 x U4 x I, 3 x U

4 x I, 3 x U

–

4 x I, 3 x U

4 x I, 3 x U

–

––

2

–

–

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–

Combined controland protectiondevice with localbay control 1)

7SJ6107SJ6127SJ6217SJ6227SJ6317SJ632

7SJ633

7SJ635

7SJ636

––––45 + 4 2)

5 + 4 2)

7 + 8 2)

7 + 8 2)

Combined control and protectiondevices. 7SJ61 and 7SJ62 with4 line text display, 7SJ63 withgraphic display. Optimized for11/2 pole control (max.7switching devices). 2-polecontrol is also possible(with max. 4 switching devices).


4687–1

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––––5

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3117

111–

–

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4 x I4 x I4 x I, 3 x U4 x I, 3 x U4 x I, 3 x U4 x I, 3 x U

4 x I, 3 x U

4 x I, 3 x U

4 x I, 3 x U

––––––

2

–

2

1) 11/2-pole control; 2-pole control possible2) Second figure is number of heavy duty relays

Fig. 195: Survey of bay units


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Local and Remote ControlSICAM SAS – Bay Control Units

SIPROTEC 4

(see description of Power SystemProtection)The 7SJ63 and the 6MD63 are designedfor larger volumes of information and thusare also suitable for use in duplicate-busbarsubstations.SIPROTEC 4 units are preferably connect-ed to the SICAM SAS via PROFIBUS FMS.Connection via IEC 60870-5-103 with re-duced functionality (compared to the useof PROFIBUS FM) is also possible.The SIPROTEC 4 7SJ61 and 7SJ62 relayscan also be used via Profibus FMS andIEC 60870-5-103 in SICAM SAS. Thesetwo units support control of the feeder cir-cuit-breaker.

Protective relays (V3 type)

By means of IEC 60870-5-103, allSIPROTEC 3 protective relays (see PowerSystem Protection, page 6/8), and also pro-tection relays of other manufacturers supp-orting IEC 60870-5-103 can be connectedto the SICAM SC substation controller.

Other bay control units

In addition, the following can be connectedto the SICAM SC:■ SIMEAS T transducer via

IEC 60870-5-103■ SIMEAS Q Power Quality via

PROFIBUS DP■ Maschinenfabrik Reinhausen transform-

er tap voltage controllers (for exampleVC100, MK30E) via IEC 60870-5-103

■ Eberle transformer tap voltage controller(RegD) via IEC 60870-5-103

■ SU200 bay control unit for high-voltageuse via PROFIBUS DP

■ Decentralized peripherals via PROFIBUSDP (for example ET200)

Fig.196: SICAM SAS, connection of SIPROTEC 4 bay control units via PROFIBUS FMS and optical fiber

PROFIBUS FMS

System control center or telecontrol node

IEC 80870-5-101SINAUT 8-FW

SICAM SCSubstationController

MPI

SIMATIC plusTOOLSConfiguration

SICAM WinCCOperator controland monitoring,archiving

Fiber opticcables

GPS

OLM(Optical Link Module)

Fiber opticcables

SIPROTEC 4 devices via PROFIBUS FMS


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SICAM WinCC

In the SICAM SAS substation automationsystem, SICAM WinCC is the human-ma-chine interface HMI between the user andthe computer-assisted monitoring and con-trol system.For efficient system management, numer-ous single information items must be dis-played quickly and clearly.The state of the substation must be dis-played and logged correctly at all times.Important indications, along with measuredand metered values of past time periodsmust be archived in such a way that theyare available for specific evaluation in theform of curves or tables at any time.The SICAM WinCC human-machine inter-face meets these requirements for efficientsystem management and also provides theuser with numerous options for individualdesign of the system user interface andnumerous open interfaces for implement-ing operation-specific functions. The win-dowing technique of SICAM WinCC makesit easier to work with. In designing thegraphic displays, the user has every degreeof freedom and also has the support of apool of predefined substation automationsymbols such as switchgear, transformersor bay devices.SICAM WinCC consists of the WinCCprocess visualization system and SICAMsoftware components.■ WinCC

WinCC offers standard function modulesfor graphical display, for messaging, ar-chiving and reporting. Its powerful proc-ess interface, fast display refresh andreliable data archiving function assurehigh availability.S7-PMC serves as a basis for a chrono-logical messaging and archiving of data.

■ SICAM componentsThey consist of:– SICAM symbol library,– SICAM message management

expansion,– SICAM wizards,– SICAM processing functions and– SICAM Valpro, (Measured/ Metered

Value Processing Unit)

SICAM symbol library

The SICAM symbol library contains switch-gear, bay devices, transformers and otherobject templates for bay representationswhich are typical for substation control and

Local and Remote ControlSICAM SAS – Human-Machine Interface

Fig. 197: Overview diagram in Graphics Designer

Fig. 198: Selecting a circuit-breaker from the symbol library

protection systems. One can use them fordesigning detail images. The symbols areselected from the library and placed in adetail image using the Drag & Drop func-tion. The symbols are dynamized. Thus, forexample, there are several different viewsof a circuit-breaker which visualize the ON,OFF or fault position switching states.


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SICAM message managementexpansion

The SICAM message management expan-sion ensures a chronological messagingand archiving of data. On the basis ofS7-PMC, the SICAM Format DLL evaluatesthe data and assigns the correspondingmessages to them. Based on this, a milli-second resolution of all events is given andfor every event not only the state of indica-tion itself is available, but also additionalinformation without the need for additionalparameterizing effort.For message assignment, the format DLLrecurs to the WinCC text libary. You canadapt the texts contained in the text libraryto meet your project-specific requirements.

SICAM wizards

The SICAM wizards assist the user in cre-ating a new WinCC project. The followingtasks are carried out with help of the wiz-ards:■ Creating SICAM structure types:

The Create SICAM tag structure typeswizard helps the user to generate thestructure types for structured tags whichare necessary in a SICAM system.Structure types are needed for importingtags from SICAM plusTOOLS.

■ Taking over tags from SICAM plusTOOLS:The Import SICAM tags wizard helps toimport tags from SICAM plusTOOLSinto SICAM WinCC.This function allows the user to visualizeinformation, i.e. to represent it in proc-ess diagrams, configured and parameter-ized with SICAM plusTOOLS.

■ Creating the SICAM message manage-ment:The SICAM message management wiz-ard helps the user to generate a mes-sage management system under WinCCwhich meets the specific requirementsof a substation automation system.In addition to a message archive, theSICAM message management includesthe following templates: event list, alarmlist and protection message list.Each of these lists always contains mes-sage blocks, message window tem-plates, message line formats, messageclasses, message sequence reports, lay-outs and texts.

Local and Remote ControlSICAM SAS – Human-Machine Interface

■ Taking over messages from SICAMplusTOOLS:The Import SICAM messages wizardhelps the user to import messages fromSICAM plusTOOLS into WinCC.This function allows the user to reportinformation in the message managementsystem which was configured and param-eterized with SICAM plusTOOLS. Thisfunction allows the user to visualizeinformation from SICAM plusTOOLSunder WinCC, i.e. to use it in processdiagrams.

■ Creating the SICAM archiving system:The Create SICAM archives wizard helpsgeneration of an archiving system underWinCC. The SICAM WinCC archivingsystem consists of:– a sequence archive for measured

values and– a sequence archive for metered

values.One can import metered values und meas-ured values from SICAM plusTOOLS intothis archiving system.■ Integrating the SICAM symbol library:

The Import SICAM libary wizard helpsthe user to load the SICAM symbol li-brary into the current project. One canuse the symbol library for designing indi-vidual detail images.

Fig.199: SICAM WinCC event list


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SICAM Valpro

Curve and tabular display of archivedmeasured values and metered values iscarried out by means of the SICAM Valproprogram. Valpro provides the facility for us-ing archived values for various evaluationpurposes, without altering them in the ar-chive. The user decides at the time of eval-uation (in a dialog) which values should bedisplayed in which raster. In addition to thevariables to be displayed, he specifies thetime range, the color and if necessary themathematical function to be carried out.One can have totals, averages, maximums,minimums or the power factor formed anddisplayed. The calculation interval can beindividually specified. Stored presets canbe altered at any time.

Engineering System SICAM plus TOOLS

With SICAM plusTOOLS, a versatile andpowerful system solution is available,which supports the user efficiently in con-figuring and parameterizing the SICAMSAS (SICAM Substation Automation Sys-tem). SICAM plusTOOLS is based onWindows 95 and Windows NT. Thus theuser moves within a familiar system envi-ronment and can recur to the well-known,convenient functionality of the Windowstechnique.SICAM plusTOOLS allows a flexible proce-dure when configuring and parameterizinga station, while providing consequent userguidance at the same time.Plausibility checks allow only operationsand combinations which are permissible inthe respective context.■ Permissible input variables are displayed

in drop-down lists or scroll boxes.■ The Drag & Drop function makes it easy

to group, separate or move data.■ Context-sensitive help texts explain the

text boxes and the permissible input var-iables.

■ Copy functions on different levels opti-mize the configuration procedure.

■ Help texts which are organized accord-ing to topics explain the configuration.

The SICAM plusTOOLS SoftwarePackage

The SICAM plusTOOLS configuration sys-tem is divided into individual, function-spe-cific applications.

Local and Remote ControlSICAM SAS – Engineering Tools

SIMATIC Manager

The SIMATIC Manager is the platform ofSICAM plusTOOLS. With the help of theSIMATIC Manager, the user defines andmanages the project and calls the individ-ual applications.The project structure is created automati-cally in the course of the configuration pro-cedure. The data areas are organized inseparate containers.In the navigation window of the SIMATICManager, the project structure is repre-sented similar to a Windows 95 directorytree. Each container corresponds to afolder on the respective hierarchical level.

Hardware Configuration

The Hardware (HW) Configuration applica-tion serves for configuring the modulesand their parameters. The configuration isrepresented as a table on the screen. Theuser chooses the components from aHardware Catalog and places them intothe hardware configuration window usingDrag & Drop or double-clicks. The tabs forparameterizing the modules are alreadyfilled with the default values, which can bemodified by the user.

Fig. 200: Example of curve evaluation using Valpro

Fig. 201: Hardware Configuration of a demo station


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Local and Remote ControlSICAM SAS – Engineering Tools

COM IED

The COM IED application (Communicationto Intelligent Electronic Devices) serves forconfiguring the connection of bay devicesin control and monitoring direction.The bay devices are imported into COMIED with their maximum information vol-ume from an IED Catalog using Drag &Drop. The information volume can be re-duced later. If SIPROTEC 4 bay units withProfibus FMS communication are used,then the information parameterized withDIGSI 4 will be taken over automatically.

COM TC

The COM TC application manages all pa-rameters which are related to the informa-tion exchange with higher-level controlcenters. The telegrams are configured sep-arately for control and monitoring direction.For the transmission of the telegrams inmonitoring direction, these are assigned topriority-specific and type-specific lists. Thelist types are provided in a Telecontrol ListCatalog and are copied into COM TC usingDrag & Drop.

Fig. 204: CFC with Component Library

Fig. 202: MCP Parameterizing

CFC

In the SICAM SAS System, automationfunctions, such as:■ Bay-related and cross-bay interlocks■ Switching sequences (busbar changes,

etc.)■ Status indication and command deriva-

tives (group indications, load shedding,etc.)

■ Measured value and metered valueprocessing (limit value processing, com-parative functions, etc.)

are projected graphically with the CFC(Continuous Function Chart).The scope of supply of SICAM plusTOOLSincludes a comprehensive library of SICAMSAS components. The designer makes hisselection from this library, positions the se-lected component by Drag and Drop on hisworksheet and interconnects the compo-nents required for its function to one an-other and to the process signals.

Fig. 203: COM IED and bay units catalog

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Siemens Power Engineering Guide · Transmission and Distribution · 4th Edition

(Legacy)IEDs

(LAN-Enabled IEDs)

SubstationLAN “A”

Router

SubstationLAN “B”

SICAMPCC

SICAMSubstationController

Legacy Protocol(e.g., DNP, IEC 870-5)Link To Control Center

ICCP(ISO/IEC 870-6TASE.2)Link To ControlCenter(Optional)

■ One or more legacy IEDs, connected tothe PCC in a star configuration.

■ One or more RTUs.■ ICCP communications to a Control Center

(optional).■ Siemens’ SICAM WinCC Human Machine

Interface (HMI) (optional component ofSICAM PCC).

Introduction

Changing requirements

The ongoing deregulation of the powersupply industry has been creating a com-petitive environment with new challengesfor the utilities:■ The liberalized production, transmission

and distribution of electrical power callfor more flexible operation of the powersystem resulting in more complex con-trol, metering and accounting procedures.

■ The deregulated system structure re-quires the extension of load and qualityof supply monitoring, as well as eventand disturbance recording, to control thebusiness processes and to care for liabil-ity cases.

■ Operation data that has traditionallybeen used only within a given utilitymust now be shared by a number ofplayers in various locations, such as utili-ties, independent power producers, sys-tem operators and metering or billingcompanies. More effective data acquisi-tion, archiving and communication istherefore needed.

■ Competition requires that costs have tobe reduced wherever possible. The opti-mization of processes has consequentlybeen given high priority. System automa-tion and in particular distribution automa-tion including automatic meter readingand customer load control can thereforebe observed as the future trend.

The SICAM PCC meets these require-ments by integrating modern PC-technolo-gy and open communication.

Some Typical Configurations

PC-Based Substation Automation

Fig. 203 illustrates a typical configurationemploying the SICAM PCC. The compo-nents of such a configuration include:■ SICAM PCC.■ Substation LAN.■ One or more LAN Enabled Intelligent

Electronic Devices (IEDs).

Fig. 205: Sample Substation with SICAM PCC

Local and Remote ControlSICAM PCC – System Design

SICAM PCC

LAN-Enabled IEDs (Legacy) IEDs

Substation LAN

Router

ICCP (ISO/IEC 870-6 TASE.2)Link To Control Center(Optional)

Fig. 206: Sample Substation with SICAM PCC and SICAM SC

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A PLC can be added

This, of course, is not the only way in whichthe SICAM PCC may be used in a substa-tion configuration. Fig. 206 illustrates aslightly more complex substation configu-ration which includes both the SICAM PCCand the SICAM Substation Controller (SC)1).The SICAM Substation Controller is anadvanced Programmable Logic Controller(PLC) (see 6/109 and following pages).

Open-ness

A product is not ”open“ just because itsmanufacturer decides to publish the speci-fications of a proprietary communicationsprotocol. A product is really open if it sup-ports standard and de facto industry stand-ard communications.There was a time, not so very long ago,when vendors of substation and controlcenter equipment offered only proprietarysolutions. The designer and maintainer ofsubstations was forced to choose among anumber of options, many – in fact almostall-of which would force the designer touse a proprietary communications protocol.After the choice, either the future optionsbecame very limited or one was forced todeal with the problem of installing protocolgateways. With SICAM, those days areover. SICAM, and specifically the SICAMPCC, are designed with ”open-ness“ as aprimary design consideration. Siemens’goal in designing this product line is to pro-vide the tools and features which enablethe user to design and upgrade the substa-tions the way he wants.The sample configuration diagrams shownare not meant to illustrate all the possibleconfigurations using the PCC and othercomponents of the SICAM product line.Rather, they show that the components ofthe SICAM product line are designed sothat users may take a ”building block” ap-proach to designing or upgrading their sub-stations.

Fig. 207: DSI with RDBMS

PCC At A Glance

Platform

The SICAM PCC executes on Intel-basedhardware running the Microsoft WindowsNT operating system (Version 4.0 andabove). Siemens chose this platform be-cause it offers an effective combination oflow hardware and software cost, ease ofuse, scalability, flexibility, and easy accessto support.

Distributed Architecture & Database

The SICAM PCC uses a high-performancedata distribution subsystem for distributionof real-time data among system compo-nents. The data distribution subsystempermits distribution of applications acrossmultiple computers to address perform-ance, physical connectivity and redundan-cy requirements. This means that if a con-figuration contains more devices than canphysically be connected to a single compu-ter, one can distribute the system acrossmultiple computers. Or, if the applicationsrequire more processing power than canbe provided by a single computer, one cansolve the problem by adding additionalcomputers to the system and distributingthe processing load.In designing the PCC, the data distributionsubsystem was combined with a standardthird-party RDBMS. The PCC architectureuses the RDBMS to do what an RDBMSdoes best – organize and store data.

The architecture uses the data distributionsubsystem to augment the RDBMS tomeet those data distribution performancerequirements which the RDBMS cannotaddress.The presence of both the data distributionsubsystem and the RDBMS is largelytransparent to the average user. However,for designers and programmers who wishto interface to the PCC infrastructure,Siemens publishes full details of the Appli-cations Programming Interface (API) pro-vided by the data distribution system, in-cluding all details of the RDBMS datamodel used by SICAM PCC.DSI (Distributed System Infrastructure) is asimple data distribution switch which oper-ates in conjunction with a standard RDBMS.While DSI does have some characteristicsof a database, it lacks certain others, so itis not referred to as a database.DSI allows distributed applications to sharedata in a consistent, efficient (i.e. high-per-formance) manner.There are three basic components whichmake up DSI:■ A central application called the DSI cen-

tral server.■ A collection of interface functions which

make up the DSI API.■ A data model which describes the

RDBMS tables used to store the configu-ration and status information used by DSIand applications which interface to DSI.

1) In PCC version 2.0, WinCC is required for configura-tions in which there is communication between PCC andthe SICAM Substation Controller.

User InterfaceFor Configuration

ODBC

ConfigurationData

Configuration Data

Status Data

Configuration Data

Status DataDSI CentralServer

ODBC

Real-TimeData

“DSI”Application

ODBC

DSIAPI

RDBMS

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Interfacing to Other Systems

The PCC is designed to be an effective in-tegration platform by including support forboth modern and legacy communicationsprotocols.The SICAM PCC does several things tosimplify the task of interfacing to othersystems:■ The interface to PCC’s data distribution

subsystem is fully externalized and doc-umented. All interfaces are available foruse by customers or third parties in de-veloping software (including gateways)to interface to the PCC. Siemens pro-vides a Software Development Kit whichcan automatically generate the basis fora working application, as well as theuser interface windows to configure it.PCC’s DB Gateway feature allows youto use familiar RDBMS tools and tech-niques to exchange data with the PCC.DB Gateway provides a bidirectionalmechanism which may be used to insertdata into the real-time data distributionsystem via the RDBMS. That is, one canwrite an object into the RDBMS using,for example, SQL statements. DB Gate-way will retrieve that object from theRDBMS and enter it into the real-timedata distribution stream for distributionto other components of the system.Similarly, one can configure DB Gatewayto accept data objects from the real-timedata distribution stream and write theminto the RDBMS. The user can then readthem using RDBMS tools and techniques.All of this can be done with almost noknowledge of the internals of the PCCarchitecture – all one needs to know iswhich RDBMS table to read and/orwhich to write.Fig. 208 illustrates the position of DeviceMaster in the architecture. In this picture,it is easy to visualize a protocol modulewhich is isolated from other systemcomponents while at the same time hasfull access to all system services required.

■ Version 2.0 of PCC makes available aset of ActiveX controls which can beembedded into an ActiveX containerapplication. This feature is included as a“proof of concept“ feature to explorethe scope of the ability to embed a real-time value from PCC’s data distributionsubsystem into a “web” document.

”Enterprise” Protocols

Siemens is the acknowledged leader indelivering ICCP solutions. The PCC’s full-featured ICCP implementation allows com-munication with any system which sup-ports this popular protocol. PCC’s ICCPcurrently supports Conformance Blocks1, 2, 5, and 8.Whenever a power system disturbanceoccurs or even during normal operations,it is very useful to be able to collect a logof changes in one or more data objects.Many modern field devices (e.g. relays,meters, etc.) allow collection of this typeof data within the device itself. However,many others do not. PCC’s Sequence ofEvents Logger option allows collection andstorage to the RDBMS of any data objectsprocessed by PCC’s data distribution sub-system. Data may be collected either peri-odically or ”on event“. Since data arestored into the RDBMS, they may be re-trieved for analysis using standard RDBMStools and techniques.

”Legacy“ Protocols

Perhaps the largest problem the user willtackle in attempting to upgrade and auto-mate existing substations arises from thelarge number of communications protocolsused by existing equipment in those sub-stations. Many of these devices simply willnot talk to each other. Many of them willnot talk to the control center. Even if a com-pletely new substation is built, one mayface this problem because the choice ofdevices may be limited by the suite of pro-tocols which are supported by the existingSCADA or EMS system.A primary design consideration in the PCCis the ability to support legacy1) protocols.The ability to support these protocols hasbeen enhanced by a PCC feature calledDevice Master. It allows Siemens (andthird parties) to develop protocol modulesin much less time than would be requiredfor a traditional system. This means thatmore protocols can be made availablemore quickly and at reduced cost.

Fig. 208: Device Master

DSI CentralServer

ConfigurationData

DSI API

RDBMS

Device Master

Device Master API

Protocol Module

Real-TimeData

ODBC


1} ”Legacy“, when used to refer to communicationsprotocols, is an euphemism for ”old and proprietary”.

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Data Conditioning

The SICAM PCC includes the feature DataNormalization (or simply Normalization)which provides a simplified method bywhich normalize procedures may be as-sociated with data objects. These normal-ize procedures perform transformations ondata objects as they enter and leave PCC’sdata distribution subsystem. The types oftransformation which may be performedinclude (but are not limited to): jitter sup-pression, deadband calculations, lineartransformation, and curve-based transfor-mation. In addition, custom procedures canbe developed and added to the system toperform any type of calculation and datatransformation. Up to 16 normalization pro-cedures may be concatenated and appliedto a single data object. PCC’s user inter-face provides a simple, intuitive way tocreate custom normalization proceduresand associate normalization procedureswith individual data objects or groups ofdata objects.


Human-Machine Interface.

Frequently, it is desirable for personnelworking in a substation to have access toHMI displays. If an HMI is available in thesubstation, costs can be reduced by elimi-nating or reducing the size of local controlpanels and the wiring associated with them.Additionally, well-designed HMI displayscan reduce the risk of error by presentingdata and controls in a logical schematic rep-resentation – interlocks can be included toprevent certain operations or to ”remind”personnel to follow certain procedures.If an HMI is used in a substation automa-tion and integration system like the PCC,it is important to ensure that the HMI inte-grates well into the system. The HMI mustbe integrated in such a way that it doesnot become a performance ”bottleneck”.The HMI must not be the ”center” of thesubstation automation architecture. NoHMI offers a sufficient level of data distri-bution performance to allow it to be usedas the “center” of the architecture. Anoth-er strong consideration in integrating anHMI is to ensure that whoever has the jobof configuring the system is not requiredto enter data a number of times. Nor shouldthe HMI require the user to become a com-puter programmer.The PCC’s optional HMI Gateway providesa pathway through which data are ex-changed between PCC’s data distributionsubsystem and the HMI. Point and clickmethods are used to select data objectswhich are to be exchanged with the HMI.If one adds, for example, a new meter tothe substation and one wants to placesome data from that meter on an HMIone-line display, only a few mouse clicksare required to perform the task. Typingthe name of a data object is at no time re-quired. Definition of data objects may beperformed either via PCC’s user interfaceor from within the HMI.The recommended HMI is the WinCCproduct from Siemens. While WinCC is asuperior product, it is recognized thatsome customers have ”standardized” onanother product. The Siemens HMI Gate-way however is designed to simplify cus-tomization to meet these requirements.

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User Interface

The user interface used to configure andoperate the PCC is very much influencedby de facto industry standards. Specifically,the user interface has a ”look and feel”established by Microsoft’s Windows 95.The great popularity of Windows 95 madethis an easy decision. The choice of a Win-dows 95 ”look and feel” means that theuser interface is familiar to anyone who hasused Windows 95 software. The PCC de-velopment team has worked with Siemenshuman factors engineers to make the userinterface as intuitive as possible.The PCC’s user interface is divided intotwo parts:■ User Interface for Configuration, also

called the PCC Configuration Manager.■ User Interface for Operation, also called

the PCC Operations Manager.

User Interface for Configuration

The PCC user interface is started just likeany other Windows 95 or Windows NT 4.0program:1. Click on the Start button of the taskbar.2. Select Programs from the menu which

appears.3. Select the SICAM PCC folder from the

menu which then appears.4. Double-click on SICAM PCC.Now a window appears like shown inFig. 209.It looks like the Windows Explorer ofWindows 95 and Windows NT 4.0. Onthe left is a navigation window. At the topis a menu bar and a tool bar. The naviga-tion window can be undocked and thenresized or moved around on your screen.

The navigation window has four elements:■ A Systems folder: By opening this fold-

er, one sees an icon for each computerin the PCC configuration.

■ An Interfaces folder: By opening thisfolder, one sees the interfaces which areconfigured on the PCC.

■ A Normalization folder: By opening thisfolder, one is able to create custom nor-malize procedures.

■ A Tools icon: By opening this, one seesa number of tools which may be used inconfiguration mode.

Fig. 210 illustrates the PCC main window(configuration mode) with several foldersopen. In this case, the system is a distrib-uted configuration with two computers.

Local and Remote ControlSICAM PCC – User Interface

Fig. 209: PCC Main Configuration Window

Fig. 210: PCC Configuration Window – Distributed System

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When the user wishes to work with an in-terface or device, it is done by double-click-ing on the device he wishes to work with.For example, Fig. 211 shows the PCC userinterface after double-clicking on Meter1(a relay which speaks the DNP 3.0 proto-col). As one can see in this illustration, anew window has appeared on the right-hand side of the PCC main window. In thiscase, the new window contains a tabbeddisplay which may be used to select andrename data objects from Meter1.

If a mistake is made…

The user can change interface and deviceparameters by double-clicking on the ap-propriate folders and / or icons. For exam-ple, by a double-click on the icon for a de-vice, windows appear which are almostidentical to those used to initially configurethe device. By working with these win-dows, one can make any necessary chang-es to the PCC configuration.

User Interface for Operation

The user interface for operation is verymuch like what has already been shown.One can switch between two modes byclicking on toolbar buttons:

selects configuration mode.

selects operational mode.

The user interface in operational modelooks like the illustration in Fig. 212.Navigation in operational mode is just likeconfiguration mode. The items displayedon the navigation tree are very similar.■ Operations Manager: By double-clicking

on this, the Operations Manager is openedwhich allows the user to view and con-trol the status of the software and de-vices which make up the PCC system.

■ Event Log: This is a tool which opensthe Windows NT event log viewer. It isused to examine messages which PCCsoftware places in the event log.

■ SCADA Value Viewer: This is a toolwhich allows the user to examine datawhich is being distributed by PCC’s datadistribution subsystem. Using this tool,one can verify that changes which occurin a device are being correctly communi-cated throughout the system.

Local and Remote ControlSICAM PCC – User Interface

Fig. 211: Working with an Existing Device

Fig. 212: User Interface (Operation Mode)

■ Generic Value Viewer: This is a toolwhich allows the user to view details ofcomplex data types used within PCC.Like the SCADA Value Viewer, it canalso be used to view data being distrib-uted by PCC’s data distribution subsys-tem. It can also be used to introducemanual changes in data for debugging,testing, and checkout.

The PCC’s Operations Manager displaysare built automatically during system con-figuration. The configuration mode to add anew interface or device will appear on theOperations Manager display the next timethe Operations Manager is started.For those who want to customize their dis-play, the PCC user interface provides aninteractive tool for customizing colors andtext on status indicators.

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…

…

CU/RS 485

CU/RS 485

…

SICAMPCC

FO-ETHERNET ICCP

Distributed SICAM PCC Substation control system

CU/RS 485(IEC 970-5-103)

SICAM PCCWin CC

2 incoming feeders

8 outgoing feeders

2 incoming feeders

8 outgoing feeders

Substation 1Substation 2

Application example for Sicam PCC

The example shows the application ofSICAM PCC to a large industrial powersupply system with distributed substa-tions. (Fig. 213)Remote substation 1 has been built com-pletely new. In the existing substation 2only the secondary equipment has beenrefurbished. Control of both substationstakes place at the operator workstation insubstation 2. The operator workstation insubstation 2 is only used in special casesfor local control (maintenance, emergencycontrol).

Substation 1:

Consists of two half-bars, each with 2 in-coming cable bays and 8 outgoing feederbays.The incoming feeder bays are all equippedwith a bay control unit 6MD63 for com-mand output, data acquisition and local baycontrol. In addition, cable differential pro-tection 7SD600 and overcurrent protectionrelays 7SJ600 are also provided.The outgoing feeders each have a com-bined protection and control relay 7SJ63,providing overcurrent protection and bay-related measuring, data acquisition andcontrol functions.The SICAM PCC station serves in this sub-station predominantly as data concentratorand communication node for the distribut-ed bay units. The connection of the bayunits is established by a copper-based mul-ti-drop link (RS 485 bus) according to theIEC 870-5-103 standard.

Substation 2:

Combined protection and control relays7SJ63 are used in this substation in allfeeder bays. Connection to the substationcontrol system SICAM PCC is again estab-lished with the wired RS485-bus as in sub-station 1.The SICAM PCC, located in the controlroom of this substation, is designed as afull server and uses WinCC as operatingand monitoring tool. The data concentratorSICAM PCC of substation 1 is connectedto this common SICAM PCC control sta-tion in substation 2 via an optical fiber net-work using the network-capable protocolIEC 60870-6 TASE.2.

Fig. 213: System Configuration

Local and Remote ControlSICAM PCC – Application Example

This configuration provides numerous facil-ities for expansion. Thus, for example, itis possible to expand bays in each of theremote stations and to link the devices onthe bay level necessary for protection andcontrol via Profibus or IEC 60 870-5-103 tothe existing PCC. Additional devices canalso be connected to the control roomPCC. For expansion of a complete remotestation, it is possible for example to usea further Device Interface Processor asSICAM PCC, to which in turn devices onthe bay level are connected. For expansionof the operating and monitoring function,it is possible, instead of the Single-UserWinCC System, to use for example aWinCC Client Server System with severaloperator terminals. This system offers re-dundancy as an option.

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482.6

84 TE = 426.72

7

57.1

5

133.

3557

.15

37.4

FPI

RK

AE

AR

SV

BA

BA

3 U

m =

266

.87

……

11

456.1

471.

2

90

45

217182


6MB5540

Rear view

One screw terminal block at top, one at bottom,per transducer module (two of each per module BF)

Front view

Connectionboard

Subrack

Side view

6MB5515


482.684 E = 426.72

465.111

7

57.1

5

133.

3557

.15

37.4

FP/L

PII

RK

RK

SC

AE

AR

DE

DE

BA

BA

BF SV

6 U

= 2

66.7

…

182251

30

Rear viewFront view Side view

Local and Remote ControlDevice Dimensions

Fig. 214: Enhanced RTU 6MB551

Fig. 215: SINAULT LSA COMPACT 6MB5540, basic frame

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6MB5130

Side view Rear view Panel cutout

17229.5

266

37 39

277.5

244

2257.313.2 220 13.2

7.3

5.4

ø 6

ø 5 or M4

255.8

206.5

180

221

245


6MB5140


7.3

5.4

ø 6

ø 5

255.8

431.5405

446

245

13.2

266

17229.5 37 39

277.5

4507.313.2 445


Fig. 216: Compact central control unit 6MB513

Fig. 217: Compact central control unit 6MB514

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6MB523 Front view Side view Panel cutout

244

231.5

30 29.5145

160

7.3

5.4

ø 6ø 5

255.8

105

245

131.5

146All dimensions in mm.

6MB522 Side view Rear view Panel cutout

FSMAoptical-fiberconnector

7.3

5.4

ø 6

ø 5 or M4

255.8

180

245

206.5

221

220

225

244

30 29.5

231.5277

266

4


6MB524-0, 1, 2 Side view Rear view Panel cutout

255.8±0.3

Terminalblocks

7.35.4

ø 6

ø 5 or M4

206.5±0.3

180±0.5

221+2

245+1

13.2225220

F E CD B A

1234

5678

Optical-fibersocketsAll dimensions in mm.

3017229.5

266

9

244

Terminalblocks


Fig. 218: Compact input/output device 6MB522

Fig. 220: Compact I/0 unit with local (bay) control 6MB524-0,1,2

Fig. 219: Compact input/output device 6MB523

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6MB5240-3, -4

17229.5

266

30 7.3

5.4

ø 6ø 5


431±0.3

405±0.5

446+2

244 245+1

13.2450

445

F E CD B A

1234

5678

255.8±0.3H GK JML

Optical-fibersockets

Terminalblock


9

Terminalblock

17229.5

266

37

244

Terminalblock

7570 7.3

ø 6

ø 5or

M4

71+2

56.5±0.3

245+1 255.8±0.3

6MB525

Side view Panel cutoutRear view


Fig. 221: Compact I/0 unit with local (bay) control, extended version 6MB5240-3

Fig. 222: Minicompact I/0 device 6MB525

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1) applicable to 6MD631/632/633/634/6371) applicable to 6MD635/636

Case for 6MD63

Side view

Mounting plate

FO

202.5/7.9729

1.1430

1.18

312/12.28 244/9.61266/10.47

SUB-DConnector

Rear view

225/8.85220/8.66

1/2 case1)

450/17.71445/17.51

Rear view

1M case

Connection cable68 poles to basicunit length 2.5 m/8 ft., 2.4 in

Side view

Mountingplate

29.51.16

27.11.06

20.07

RS232-port

266/10.47

246.2/9.69

Detachedoperator panel

Panel cutout

Case for 6MD631/632/633/634/637

Side view

SUB-DConnector

FO

172/6.77 341.33

266/10.47 244/9.61

29.51.16

Mounting plate

20.07

RS232-port

225/8.85220/8.66

Rear view

ø 6/0.24 diameter

ø 5 or M4/0.2 diameter

255.8/10.07

221/8.70

206.5/8.12

245/9.64

180/7.08


Fig. 223: 6MD63 in 1/2 flush-mounting case for surface mounting with detachable operator panel

Fig. 224: 6MD63 in 1/2 and 1/1 surface mounting case (only with detached operator panel, see Fig. 42, page 6/21)

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6MB552

17229.5

266

39

225

244

7.3

5.4

ø 6

ø 5 or M4


220

8

1) 2)

13.2206.5 ±0.3

180 ±0.5

255.8 ±0.3

221+2

245+1

Bus cover

BNC socket forantenna

Optical-fiber socketFSMA for connectionof bay units



6MB5530-0 and -1

Front view Side view Rear view

300

22515

400

1.5

35

45

Cable bushing

200

20

20 18

20

20 10

25

A

A

8

8.2

Section A-A

Wall mount


Fig. 225: Compact RTU 6MB552 in 7XP20 housing

Fig. 226: Minicompact RTU 6MB5530


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Introduction

For more than 100 years, electrical energyhas been a product, measured, for exam-ple, in kilowatt-hours, and its value wasdetermined by the amount of energy sup-plied. In addition, the time of day could beconsidered in the price calculation (cheapnight current, expensive peak time tariffs)and agreements could be made on themaximum and minimum power consump-tion within defined periods. The latest de-velopment shows an increased tendencyto include the aspect of voltage quality intothe purchase orders and cost calculations.Previously, the term “quality” was associ-ated mainly with the reliable availability ofenergy and the prevention of major devia-tions from the rated voltage. Over the lastfew years, however, the term of voltagequality has gained a completely new sig-nificance. On the one hand, devices havebecome more and more sensitive and de-pend on the adherence to certain limit val-ues in voltage, frequency and waveshape;on the other hand, these quantities are in-creasingly affected by extreme load varia-tions (e.g. in steelworks) and non-linearconsumers (electronic devices, fluorescentlamps).

Power Quality standards

The specific characteristics of supply volt-age have been defined in standards whichare used to determine the level of qualitywith reference to■ frequency■ voltage level■ waveshape■ symmetry of the three phase voltages.These characteristics are permanently in-fluenced by accidental changes resultingfrom load variations, disturbances fromother machines and by the occurrence ofinsulation faults. In contrast to usual com-modity trade, the quality of voltage de-pends not only on the individual supplierbut, to an even larger degree, on the cus-tomers.

The IEC series 1000 and the standardsIEEE 519 and EN 50160 describe the com-patibility level required by equipment con-nected to the network, as well as the lim-its of emissions from these devices. Thisrequires the use of suitable measuring in-struments in order to verify compliancewith the limits defined for the individualcharacteristics as laid down in the relevantstandards.If these limit values are exceeded, the pol-luter may be requested to provide for cor-rective action.

Competitive advantage thoughpower quality

In addition to the requirements stated instandards, the liberalization of the energymarkets forces the utilities to make them-selves stand out against their competitors,to offer energy at lower prices and to takecost-saving measures. These demands re-sult in the following consequences for thesupplier:■ The energy tariffs will have to reflect the

quality supplied.■ Customers polluting the network with

negative effects on power quality willhave to expect higher power rates –“polluter-must-pay” principle.

■ Cost saving through network planningand distribution is different from today’spractice in network systems, which isoriented towards the customers withthe highest power requirements.

The significant aspect for the customer isthat non-satisfying quality and availability ofpower supply may cause production lossesresulting in high costs or leading to poorproduct quality.Examples are in particular■ Semiconductor industry■ Paper industry■ Automotive industry (welding processes)■ Industries with high energy requirementsSiemens offers a wide range of productsincluding different types of recording equip-ment, as well as systems for active qualityimprovement.

Power QualityMeasuring, Recording, Compensation


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Power QualityMeasuring and Recording

The SIMEAS T MeasuringTransducer

SIMEAS T is a new generation of measur-ing transducers for quantities present inelectrical power supply systems. The com-pact housings are mounted to a standardrail with the help of a snap-on mechanism.Depending on the specific application, thedevices are available with or without auxil-iary power supply or can be provided witha multi-purpose measuring transducer whichcan be configured according to individualrequirements.

Applications

■ Electrical isolation and conditioningof electrical measurands for furtherprocessing.

■ Industrial plants, power plants andsubstations.

■ Easy-to-instal, space-saving device.Fig. 227: Measuring transducer 7KG60, block diagram

Fig. 229: Measuring transducer 7KG60, dimensions

Digital output

Analog output 1

Analog output 2

Analog output 3

Serial interface

UH

IL1

IL2

IL3

UL2

UL3

UL1

N

Block diagram

RS 232RS 485

AC

75

90

Front view

Side view

Connection terminals

All dimensions in mm

90105

Fig. 228: Measuring transducer 7KG60


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Functions

Conversion of the measured values intoanalog or digital values suitable for systemsin the fields of automatic control, energyoptimization and operational control.

Special features

■ Minimum dimensions,■ Short delivery time, standard types

delivered ex-warehouse,■ Complies with all relevant standards,■ High-capacity output signals,■ Electrical isolation at high test voltage,■ Suitable to extend the beginning and end

of the measuring range,■ Design variants for true r.m.s measure-

ment.Additional features of the multi-purposemeasuring transducers:■ Acquisition of up to 16 measurands,■ Connection to any type of single-phase

or three-phase systems, 16 2/3, 50,60 Hz,

■ 3 electrically isolated outputs, ±10 V and± 20 mA,

■ 1 binary output,■ Type of network, measurand, measuring

range, etc. can be freely programmed,■ V.28 or RS 485 serial interface for con-

figuration and output of the measuredvalues.

Measurands

■ AC voltage,■ AC current,■ Extension of the measuring range is

possible.Additional features of the multi-purposemeasuring transducer:■ AC voltage and current,■ Active, reactive and apparent power,

power factor, phase angle,■ System frequency,■ Energy pulses,■ Limit-value monitoring.

Special features of the parameterizablemulti-purpose measuring transducer

Input quantities

■ 3 voltage inputs for 0 –346 V, up to 600 Vline-to-line voltage in the three-phasesystem,

■ 3 current inputs for 0–10 A.

Outputs

■ 3 isolated outputs for ± 20 mA or ±10 Vand smaller values,

■ 1 contact, definable for error or limit indi-cation or as energy pulse,

■ 1 serial interface type RS 232C (V.28) or,as an option, type RS 485 for connectionto a personal computer for configurationand data transmission.

Types of connection

■ Single-phase,■ Three-wire three-phase current with

constant/balanced load,■ Three-wire three-phase current with

any load,■ Four-wire three-phase current with

constant/balanced load,■ Four-wire three-phase current with

any load,■ Connected either directly or via external

transformer.

Measured and calculated quantities

■ R.m.s. values of the line-to-line and starvoltages,

■ R.m.s. value of the zero sequence voltage,■ R.m.s. value of the line-to-line currents,■ R.m.s. value of the zero sequence current,■ Active and reactive power of the single

phases and the sum thereof,■ Power factors of the single phases and

the sum thereof,■ Total apparent power,■ Active energy, incoming supply at the

single phases and the sum thereof(pulses),

■ Active energy, exported supply at thesingle phases and the sum thereof(pulses),

■ Reactive energy, inductive, at the singlephases and the sum thereof (pulses),

■ Reactive energy, capacitive, at the singlephases and the sum thereof (pulses),Line frequency.

Alarm contact

■ Violation of the min./max. limits forvoltage, current, active power, reactivepower, frequency,

■ Violation of the min. limit for powerfactor,

■ Functional error.

Serial interface

Standard-type RS 232 C (V.28) interface forconnection to a personal computer for con-figuration, calibration and transfer of themeasured values; an RS 485-type serial in-terface is available with an additional busfunction according to IEC 60 870-5-103.

Auxiliary power

Two versions: 24 to 60 V DC and 110 to250 V DC, as well as 100 to 230 V AC.

Characteristic line with breakpoint

The start and end periods of the analogoutputs can be extended according to re-quirements. This enables enlarging of thedisplay of the operating range of voltages,while the less interesting overcurrentrange can be compressed.

Configuration and adjustment

With the help of a personal computer con-nected to the serial interface, the type ofnetwork, the measurands and the outputsignals can be configured to suit the indi-vidual situation. The SIMEAS PAR softwareprogram enables easy adjustment of thedevices to different requirements. Sinceonly one type needs to be kept on stock,the user can benefit from the advantagesof reduced storage costs and easier projectplanning and ordering procedures. The soft-ware also supports and facilitates the ad-justment of the transducers.

Data output with SIMEAS T PAR

SIMEAS T PAR can also be used to contin-uously collect the data of 12 measurandsfrom the transducer and to display themboth graphically and numerically on thescreen. These data can then be saved orprinted.

Bus operation with IEC protocol

The transducer is suitable for the acquisi-tion of up to 43 measurands and for themonitoring of up to 39 measurands. Withthree analog outputs and one contact out-put only part of these data can be trans-ferred. With the help of the RS 485 serialinterface which uses the IEC 60870-5-103protocol, however, any number of meas-ured data can be transmitted to a centralunit (e.g. LSA or PC). As this protocol re-stricts the number of data units to 9 or 16measuring points, the function parametersfor file transfer can be assigned in such away as to bypass this restriction and toload any desired number of data.


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SIMEAS T PAR parameterizationsoftware

Description

By means of the SIMEAS T PAR software,SIMEAS T transducers with an RS232 oran RS485 interface can be parameterizedor calibrated swiftly and easily. Measuredquantities can be displayed on the PC on-line via a graphical meter or can be record-ed and stored over a period of up to oneweek.SIMEAS T PAR was designed for installa-tion on a commercially available PC or lap-top with the MS-DOS operating system. Itis operated via the MS-Windows V3.1 orWindows 95 graphical user interface by PCmouse and keyboard. Operating instructionscan be created by printing the ”Help“ file.Communication with the transducer is a-chieved by means of a cable (optionallyavailable) connected via the interface thatis available on every PC or laptop. For unitsfeaturing an RS232 interface, use the con-necting cable 7KG6051-8BA or, for unitsfeaturing an RS485 interface, use the con-verter 7KG6051-8EB/EC. Three mutuallyindependent program sections can becalled up.

Parameterization

Parameterization serves to set the trans-ducer to the required measured quantities,measuring ranges and output signals etc.Users are able to parameterize the trans-ducer themselves in only a few steps.Entry of the data in the windows providedis clear and simple, supported with ”Help“windows.Parameterization is also possible withoutthe transducer. After storage of the dataunder a separate name, the transducerscan be adjusted with the ”Send file“ com-mand. They can also be reparameterizedonline during operation.

Features

■ Extremely simple and straightforwardoperation

■ Storage of parameterization data undera user-defined name even without thetransducer

■ Parameters are sent to transducers evenafter installation on the site

■ When ”Receive“ is selected, the trans-ducer‘s parameters are read into the”Parameterization window“, can bemodified and can be sent back by select-ing ”Send“

■ Entered data is subjected to an exten-sive plausibility check and a messageand ”Help“ are displayed in the event ofinvalid inputs

■ A parameterization list with the specificconnection diagram of the transducercan be printed

■ A self-adhesive data plate can be printedand affixed to the transducer, including apossibility of entering three lines of textcontaining the name and location etc.

■ When units featuring an RS485 interfaceare chosen, an additional window isavailable for entry of the bus parameters

Calibration

As the transducer features neither settingpotentiometers nor other hardware con-trols, it is calibrated easily by means of theSIMEAS T PARA software, by selection ofthe ”Calibrate“ function.Generally, all the transducers are alreadycalibrated and factory-set when delivered.Recalibration of the transducers is normallyonly necessary after repairs or in the eventof readjustment.It goes without saying that the windowsand graphical characteristics displayed inthe ”Calibrate“ program can be operatedwith ease.Here also, the test setup and explanationsof how to operate the programm are pro-vided in ”Help“ windows.

Features

■ Sealed for life design■ Calibration without tools or special

devices■ No test field environment is neededCurrent inputs, voltage inputs and the indi-vidual analog outputs can be calibrated in-dependently of one another.

Fig. 230: Parameterization of the basic parameters

Fig. 232: Parameterization of an analog output

Fig. 231: Parameterization of the binary output

Fig. 233: Calibrating an analog output


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Reading out data

With graphical instruments, all measuredquantities calculated in the transducer andpower quantities can be displayed onlineon a PC or laptop, and either in analogform or digitally.To improve the resolution of the graphics,users can freely choose the number of in-struments on the screen and can freely as-sign the measured quantity and measuringrange.These are selected and assigned independ-ently of the unit’s analog outputs.Displayed measured values can be stored,printed or recorded for the EVAL evaluationsoftware.

Features

■ Online measurements in the systemwith high accuracy

■ The meters for the 3 analog outputswith the appropiate measuring range ap-pear automatically when the programpart is called up

■ Easy addition or modification of meterswith measured quantity and measuringrange

■ Selection of measured quantities inde-pendently of the analog outputs

■ Storage of the layout under a file name■ Printing of the instantaneous values of

the displayed measured quantities■ Recording and storage of measured val-

ues for the EVAL evaluation software

SIMEAS EVAL evaluation software

Description

With a PC or a notebook with the SIMEAS TPAR software installed on it, up to 25 meas-ured quantities can be displayed and re-corded online with the SIMEAS T digitaltransducer. A maximum of one week canbe recorded. Every second, one completeset of measured values is recorded withtime information. The complete recordingcan then be saved under a chosen name.Using the SIMEAS EVAL evaluation soft-ware, the stored values can then be edit-ed, evaluated and printed in the form ofa graphic or a table (Figs. 236 to 238).

Fig. 234: Measured value display with 3 measuredquantities

Fig. 235: Measured value display with 6 measuredquantities

Fig. 236: SIMEAS EVAL, overview recorded values

Fig. 237: After setting cursors in the overview, the affiliated measurements and times are displayed in the table



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Fig. 238: When a cursor is moved by the mouse,the measured values and times in the table are adapted automatically

SIMEAS EVAL is a typical Windows pro-gram, i.e. it is completely Windows-orient-ed and all functions can be operated withthe mouse or keyboard.SIMEAS EVAL is installed together withSIMEAS T PAR and is started by doubleclicking on the EVAL icon. A window con-taining the series of measurements record-ed by SIMEAS T PAR is displayed for se-lection.

Features

■ Automatic diagram marking■ Graphic or tabular representation■ Sampling frequency: 1 s■ A measured value from the table can

be dragged to the graphic by simplyright-clicking it

■ Add your own text to graphics■ Select measured quantities and the

measuring range■ Easy zooming with automatic adaption

of the diagram captions on the X and Yaxes

■ Up to 8 cursors can be set or movedanywhere

■ Tabular online display of the chosencursor positions with values and times

■ Characteristics can be placed over oneanother for improved analysis

■ The sequence of displayed measuredquantities can be selected and modified

■ The complete recording or editedgraphic can be printed, including a possi-bility of selecting the number of curveson each sheet

■ The table can be printed with measuredvalues and times pertaining to the cursorpositions.

Information for SIMEAS T ProjectPlanning

The transducer is suitable for low-voltageapplications, 400 V three-phase and 230 Vsingle-phase voltages, (max. measuring600 L-L) and currents of 1, 5, 10 A (max.measurement 12 Ar.m.s), either directly orvia current transformers, as well as forconnection to voltage transformers of

1000√—3, 110√

—3, 200√

—3. The devices can

be pre-configured at the factory accordingto customer requirements or configurationcan be performed by the customer himself.The latter possibility facilitates and consid-erably reduces the customer’s expense forstorage and spare parts service. All usualvariants of connection (two, three or four-wire systems, constant/balanced or any/unbalanced load 16 2/3, 50, 60 Hz) can beconfigured according to individual require-ments.Please note that two different types areavailable which differ in their types of inter-face: V.28 (RS 232C) and RS 458. The stand-ard interface (V.28) is used for configuration.It enables loading of the measured valuesto a personal computer, whereby only onetransducer can be connected to a com-puter. Both versions are operated withthe SIMEAS PAR software. The RS 485enables connection to a bus, i.e. up to31 transducers can be connected to a cen-tral device (e.g. PC) simultaneously. Datatransmission is based on IEC 60 870-5-103protocol.The type of power supply is to be speci-fied when ordering, either 24..60 V DC or100..230 V AC/DC. Please note that analogoutput 1 and the serial interface use thesame potential and can be operated simul-taneously only under certain conditions.


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162.2 (6.39")

86 (3.39")

96 (3.78")

96 (3.78")

SIMEAS P

SIMEAS P

Side view

Front view

Fig. 239: Power Meter SIMEAS P, views and dimensions

Power Meter SIMEAS P

The SIMEAS P power meter is suitable forpanel mounting. The digital multi-functiondisplay can replace any measuring devicesusually required for a three-phase feeder.Furthermore, it offers a variety of addition-al functions. The optional equipment with aPROFIBUS enables centralized access tothe measured values.

Application

All systems used for the generation anddistribution of electrical power. The devicecan be easily installed for stationary use.

Functions

Measuring instrument for all relevantmeasurands of a feeder. Combination ofseveral measuring instruments in one unit.

Special features

Dimensions for panel mounting accordingto DIN (front frame 96 x 96 mm). IntegratedPROFIBUS as optional equipment. Dataoutput is effected via the Profibus.

Measuring inputs

■ 3 voltage inputs up to 347 V (L-E), 600 V(L-L),

■ 3 current inputs for 5 A rated current,measuring range up to 10 A with anoverload of 25%.

Communication

■ LCD display with background illumina-tion,

■ Simultaneous display of four measuringvalues,

■ Parameter assignment by using the keyson the front panel,

■ 1 serial interface type RS 485 for con-nection to the Profibus (option).


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Auxiliary power

Two versions: 24 to 60 V DC and 85 to240 V AC/DC.


■ R.m.s. values of the line-to-ground orline-to-line voltages and the mean value,

■ R.m.s. values of the line-to-line currentsand the mean value,

■ Line frequency,■ Power factor (incl. sign),■ Active, reactive and apparent power,

separately for each phase and as awhole, imported supply,

■ Total harmonic distortion (THD) for volt-age and currents, separately for eachphase, up to the 15th harmonic order,

■ Unbalanced voltage and current,Active and reactive power (import,export), total sum, difference,

■ Apparent power, total sum,■ Minimum and maximum values of most

quantities.

Basic Function

Display of the measured quantities andtransfer to the Profibus.

Information for Project Planning

The SIMEAS P can be delivered in differ-ent designs varying with regard to themeasuring voltage, auxiliary voltage, linefrequency and type of terminals. It is alwaysdesigned for four-wire connection at anyload. The measuring voltages are:■ 120 V, 277 V, 347 V L-N for screw

clamps, up to max. 277 V for self-clamping contacts.

■ The basic rated current value is 5 A;fully controlled it is 10 A.

Two variants are to be considered forthe auxiliary voltage: standard versionand 85–240 V AC/DC and, as an option20–60 V DC.The standard version of the device can beused only for the display of the differentmeasurands. Communication with a cen-tralized system is possible only in connec-tion with the Profibus which can be or-dered as optional equipment.

Fig. 240: Power Meter SIMEAS P, back panel diagram

N – L + G Captured-wireterminals

Barrier-typeterminals(ring or spadeconnectors)

Thumbscrew

Chassis groundAWG 14(2.5 mm)

PROFIBUSDEPWR

VVVV

Fuses 2 Amp

Power supply connections,phase voltage and currentconnections, and fuse,CT and PT details dependon the configuration of thepower system.

Phase voltage andpower supply connections:AWG 12 to AWG 14(2.5 mm to 4.0 mm)

SHORTING BLOCK or TEST BLOCK

SIMEAS P


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Communication

■ 2 optorelays as signaling output, availa-ble either for– device in operation,– energy pulse,– signaling the direction of energy flow (import, export),– value below min. limit for cos ϕ,– pulse indicating a voltage dip,

■ 3 LEDs indicating the operating statusand PROFIBUS activity,

■ 1 RS 485 serial interface for connectionto the PROFIBUS.

Auxiliary power

Two versions: 24 to 60 V DC and 110 to250 V DC, as well as 100 to 230 V AC.


■ R.m.s. values of the line-to-ground orline-to-line voltages,

■ R.m.s. values of the line-to-line currents,■ Line frequency (from the first voltage

input),■ Active, reactive and apparent power,

separately for each phase and as awhole,

■ Harmonics for voltages and currents upto the 40th order,

■ Total harmonic distortion (THD), voltagesand currents of each phase,

■ Unbalanced voltage and current in thethree-phase system,

■ Flicker irritability factor.

Averaging intervals

■ Voltages and currents from 10 ms to60 min.,

■ Other quantities from 1s to 60 min.

The SIMEAS Q Quality Recorder

SIMEAS Q is a measuring and recordingdevice which enables monitoring of allcharacteristics related to the voltage quali-ty in three-phase systems according tothe specifications defined in the standardsEN 50160 and IEC 61000. It is mounted ona standard rail with the help of a snap-onmechanism.

Application

Medium and low-voltage systems.The device requires only little space andcan be easily installed for stationary use.

Functions

Instrument for network quality measure-ment. All relevant measurands and operandsare continuously recorded at freely defina-ble intervals or, if a limit value is violated,the values are averaged. This enables theregistration of all characteristics of voltagequality according to the relevant standards.The measured values can be automaticallytransferred to a central computer systemat freely definable intervals via a standard-ized PROFIBUS DP interface and at atransmission rate of up to 1.5 Mbit/s.

Special features

■ Cost-effective solution.■ Comprehensive measuring functions

which can also be used in the field ofautomatic control engineering.

■ Minimum dimensions.■ Integrated PROFIBUS DP.■ The integrated clock can be synchro-

nized via the PROFIBUS. Configurationand data output via PROFIBUS DP.

Measuring inputs

3 voltage inputs, 0 – 280 V,3 current inputs, 0 – 6 A.

Fig. 241: The SIMEAS Q quality recorder

Front view

Side view

Connection terminals

Terminal block

All dimensions in mm

SIMEAS Q7KG-8000-8AB/BB

PROFIBUS-DPPROFIBUS-DP Aux. Volt.

1 2 3 4 5 6 7 8 9 10

Input: Current AC Input: Volt. AC

20 21 22 23 24 25

UL1 UL2 UL3IL3IL3IL2IL2IL1IL1 ULN

90105

75

90

SIMEAS Q7KG-8000-8AB/BB

PROFIBUS-DPPROFIBUS-DP 20 21 22 23 24 25

RUN BF DIA

1 2 3 4 5 6 7 8 9 10

Fig. 242: The SIMEAS Q quality recorder,dimension drawings


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Operating modes

■ Continuous measurement with definableaveraging intervals,

■ Event-controlled measurement withdefinable averaging intervals.

Storage capacity

Up to 20,000 measured and calculated val-ues. Parameters for the measuring pointscan be freely defined. The PROFIBUS DPenables quick loading of the measured val-ues, so that the apparently small storagecapacity is absolutely sufficient. Assuminga usual parameter setting with regard tothe measuring points and averaging inter-vals for quality monitoring, the storagecapacity will last for seven days in caseof a PROFIBUS failure.

Basic Functions

In the course of continuous measurement,the selected measuring data are stored inthe memory or transferred directly via thePROFIBUS. The averaging interval can beselected separately for the different meas-urands.In the event-controlled mode of operation,the data will be stored only if a limit valuehas been violated within an averaging inter-val.Apart from the mean values, the maximumand minimum values within an averaginginterval can be stored, with the exceptionof flicker irritability factors and the valuesfrom energy measurement.Parameter assignment and adjustment ofthe device are performed via the Profibusinterface.

Information for SIMEAS Q ProjectPlanning

Up to 400 V (L-L), the device is connecteddirectly, or, if higher voltages are applied,via a external transformer. The rated cur-rent values are 1 and 5 A (max. 6 A canbe measured) without switchover. Commu-nication with the device is effected viaPROFIBUS DP or, as an option, via modem(telephone network).Auxiliary voltage is available in two vari-ants: 24 to 60 V DC and 110 to 250 V DCor 100 to 230 V AC.

Fig. 243: SIMEAS Q connection terminals

L

Connection terminals SIMEAS Q7 8 9 10

k l

K L

k l

K L

1 2 3 4

k l

K L

5 6

L1L2L3N

U

u

U U

u u

X X X


k l

K L

1 2 3 4

k l

K

5 6

L1L2L3

VV UU

u uv v


k l

K L

k l

K L

1 2 3 4

k l

K L

5 6

L1L2L3N

1 2 3 4 5 6 7 8 9 10Connection terminals SIMEAS Q

k l

K LL1N

4-wire – 3-phase with any load (low voltage network)

3-wires – 3-phase with any load

4-wire – 3-phase with any load (high voltage network)

Single phase – alternating current



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Fig. 244: SIMEAS N Quality Recorder

The SIMEAS N Quality Recorder

SIMEAS N is a measuring and recordingdevice which is used to monitor all charac-teristics referring to the voltage quality inthree-phase systems in compliance withthe requirements stated in the EN 50160and IEC 1000 Standards.

Application

Medium and low-voltage systems, laborato-ries, test bays. Portable device for mobile use.

Functions

Device for network quality measurement.The measurands and operands are continu-ously recorded over definable intervals; incase of limit violations, the values will beaveraged. This enables the recording of allcharacteristics relevant to voltage quality.In addition, this multi-purpose device canbe used for general measurement tasks inthe field of AC power engineering.

Special features

Comprehensive measuring functions. A lock-able cover protects the terminals againstaccidental contact. The operator access canbe password-protected. Clamp-on probeswith an error correction function facilitateconnection. A back-up battery stores themeasured data in case of voltage failure.The integrated battery-backed real-time clockwill be usable until the year 2097.Output of the measured values via inte-grated thermal printer, floppy disk or serialinterface.

Measuring inputs

■ 4 voltage inputs, 0–460 V,■ 3 of these inputs with additional transient

acquisition ±2650 Vpeak at a samplingrate of 2 MHz,

■ 4 voltage/current inputs, voltage0–460 V/clamp-on probe or transducer.

Communication

■ 1 input for trigger signal,■ 1 contact as alarm output,■ 1 integrated thermal printer,■ 1 3.5" floppy disk drive, 1.44 MB for

parameters and data storage,■ 1 serial interface type RS 232C (V.24) for

connection to a personal computer forconfiguration and data transmission.


■ R.m.s. values of voltages, AC, AC+DC,DC,

■ Peak voltage values during transientmeasurement,

■ R.m.s values of currents, AC, AC+DC,DC (depending on transducer or clamp-on probes),

■ Voltage dips and voltage cutoffs,■ Overvoltages,■ System frequency,■ Active, reactive and apparent power,

1- to 3 phases,■ Phase angle,■ Harmonics of voltages and currents up

to the 50th order,■ Total harmonic distortion (THD), voltages

and currents, unweighted or weightedinductively or capacitively,

■ Unbalanced voltage and current in thethree-phase system.

Connection types

■ Single phase,■ Four-wire three-phase current.

Measurands and operands,available as an option

■ Direction of harmonics,■ Flicker measurement,■ Digital storage oscilloscope.

Operating modes

■ Continuous measurement with displayat one-second intervals,

■ Continuous measurement with data stor-age,

■ Event-controlled measurement with datastorage.

Storage capacity

Up to 500,000 measured and calculatedvalues; various options for defining themeasuring points.

Function

Continuous measurement without storageroughly corresponds to the function of amultimeter. The selected values to bemeasured are continuously displayed andthe whole screen content including thegraphic illustrations can be printed on theintegrated thermal printer by key command.This operating mode is used to check cor-rect connection of the device and is suitablefor general measurement tasks. Monitoringof the network quality is effected by contin-uously calculating and storing the mean val-ues of the measured quantities. In the stor-age mode, the averaging interval can beconfigured individually from one period ofthe system voltage up to several months.Two types of storage modes can be select-ed, either linear mode (stops when thememory is full) or overwrite mode (the old-est data will be overwritten by the new in-formation).With the help of the OSCOP Q program, themeasuring data can be transmitted toa personal computer for detailed analysis.


The basic version of the device is fullycapable of simultaneous acquisition of up to55 measurands.The voltage range of 400 V +15% is suita-ble for connection to 400 V three-phase sys-tems. Clamp-on probes (10, 100 and 1000A) for current measurement are available.The connection of a transducer is possible,if a resistor provides a voltage drop of 1 Vnominal value.The device can also be delivered for high-speed processing which enables simultane-ous acquisition of up to 186 different meas-urands.Optional functions which can be added at alater date by software installation:■ Power measurement of individual har-

monics and their direction in order toidentify the cause.

■ Extension of the device functions for useas an additional three-channel digital oscil-loscope.

■ Flicker measurement according toIEC 60 868.


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Fig. 247: Fault record

Fig. 246: … and to monitor transmission lines

Fig. 245: SIMEAS R Systemsare used in power plants …

Recording Equipment

The SIMEAS R Fault and Digital Recorder

Application

■ Stand-alone stationary recorder for extra-high, high and medium-voltage systems.

■ Component of secondary equipment ofpower stations and substations or indus-trial plants.

Functions

Fault recorder, digital recorder, frequency/power fault recorder, power quality record-er, event recorder.All functions can be performed simultane-ously and are combined in one unit with noneed for additional devices to carry out thedifferent tasks.

Special features

■ The modular design enables the realiza-tion of different variants starting fromsystems with 8 analog and 16 binary in-puts up to the acquisition of data fromany number of analog and binary chan-nels.

■ Clock with time synchronization usingGPS or DCF77.

■ Data output via postscript printer, re-mote data transmission with a modemvia the telephone line, connection toLAN and WAN.

Fault Recording (DFR)

This function is used for the continuousmonitoring of the AC voltages and cur-rents, binary signals and direct voltages orcurrents with a high time resolution. If afault event, e.g. a short-circuit, occurs, thespecific fault will be registered includingits history. The recorded data are then ar-chived and can either be printed directly inthe form of graphics or be transferred to adiagnosis system which can, for example,be used to identify the fault location.

Fault detection is effected with the help oftrigger functions. With analog quantitiesthis refers to■ exceeding the limit values for voltage,

current and unbalanced load (positiveand negative phase sequence system).

■ falling below the limit values for voltage,current and unbalanced load (positiveand negative phase sequence system).

■ limit values for sudden changes in up ordownward direction.

Monitoring of the binary signals includes■ signal status (high, low)■ status changes


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Logical triggers

Logical triggers can be defined by combin-ing any types of trigger event (analog orbinary). They are used to avoid undesiredrecording by increasing the selectivity ofthe trigger function. The device can distin-guish between different causes of a fault,e.g. between a voltage dip caused by ashort-circuit (low voltage, high current)which needs to be recorded, and the dis-connection of a feeder (voltage low, cur-rent low) which does not need to be re-corded.

Sequential control

An intelligent logic operation is used tomake sure that each record refers to theactual duration of the fault event. This is toprevent continuous violation of a limit value(e.g. undervoltage) from causing perma-nent recording and blocking of the device.

Analog measurands

16-bit resolution for voltages and DC quan-tities and 2 x 16-bit resolution for AC volt-ages.The sampling frequency is 256 times theperiod length, i.e. 12.8 kHz at 50 Hz and15.36 kHz at 60 Hz for each channel.A new current transformer concept ena-bles a measuring range between 0.5 mAand 400 Ar.m.s. with tolerances of <0.2%at <7 Ar.m.s. and <1% at >7 Ar.m.s. Further-more, direct current is registered in therange above 7 A; this enables a true imageof the transient DC component in theshort-circuit current.

Binary signals

The sampling frequency at the binary in-puts is 2 kHz.

Data compression

For best utilization of the memory spaceand for high-speed remote transmissionthe data can be compressed to as little as2% of their original size.

Fault diagnosis

Performed with the OSCOP P softwarepackage.

Digital Recording (DR)

This function is used for the continuousregistration of the mean values of themeasurands at intervals which can be free-ly defined (min. interval is one period). Themain function of this device is the continu-ous recording of quantities at the feedersand to make these values available for theanalysis of the network quality.

In single-phase and three-phase systems,the following measurands are recorded:■ R.m.s. values of voltages and currents■ Active power, phase-segregated and

overall■ Reactive power, phase-segregated and

overall (displacement or total reactivepower)

■ Power factor, phase-segregated andoverall

■ Frequency■ Positive and negative sequence voltage

and current■ Weighted and unweighted total harmon-

ic distortion (THD)■ 5 th to 50 th harmonics (depending on

the averaging time)■ DC signals, e.g. from transducersDepending on the individual network con-figuration, a three or four-wire connectionis used.

Frequency/Power Recording (FPR)

This function uses the same principle as afault recorder. It continuously monitors thegradient of the frequency and/or power ofone or more three-phase feeders. If majordeviations are detected, e.g. caused by theoutage of a power plant or when great loadsare applied, the profile of the measurandswill be recorded including their history. Therecorder is also used for the registration ofpower swings.

Measurands

■ Frequency of one of the voltages,(limit of error ±1 mHz)

■ Active power, reactive power(reactive displacement power),(limit of error ≤ 0.2%)

■ Power factor

Averaging interval

A value between 1 and 250 periods of thenetwork frequency can be selected.

History

Depends on the averaging interval;10 s times the averaging periods.

Automatic power analysis

With the help of the OSCOP software pack-age (see The OSCOP P) a power analysisof a station can be created automatically.

Fig. 248: SIMEAS R for 8 analog and 16 binary inputs,1/2 19'' design

Sequence of Event (SOE) Recording

Each status change occurring at the binaryinputs is registered with a resolution of0.5 ms and is then provided with a timestamp indicating the time information fromthe year down to the millisecond.200 status changes per second can bestored for each group of 32 inputs. Themass memory of the device can be config-ured according to requirements (a 5 MBmemory, for example, enables the storageof approx. 120,000 status changes). Mod-ules for signal voltages between 24 and250 V are available.The time-synchronous output enablesthe combined representation with analogcurves, e.g. of alarm and command signalstogether with the course of relay voltagesand currents. With the help of the OSCOP Pprogram, the event signals can howeveralso be displayed in the form of a text listin chronological order. The use of a sepa-rate sequence of event recorder will nolonger be required.


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The individual diagrams can, of course, beadjusted to individual requirements withthe help of variable scaling and zoom func-tions. Records from different devices canbe combined in one diagram. The differentquantities measured can be immediatelycalculated by marking a specific point in adiagram with the cursor (impedance, reac-tance, active and reactive power, harmon-ics, peak value, r.m.s. value, symmetry, etc.).Additional diagnosis modules can be usedto perform an automatic analysis of faultevents and to identify the fault location.The program also supports server/clientstructures.

Configuration Evaluation

WANISDNX.25

Telephone

OfficeLAN

ContainerizedData Base

Spontaneousprint

Spontaneousprint

RMS values+ diagnostic

Data compression

Diagnostic system

Decentralized Data Base

Remote control, automatic mode

StationsLAN

SIMEAS R8 analog/16 binary inputs

Evaluation

Configuration

Printer

DAKON

Load Dispatch Center

Station Level

Bay Level

Office

The OSCOP P Evaluation Program

The OSCOP P software package is suitablefor use in personal computers provided withthe operating systems MS WINDOWS 95/98or WINDOWS NT. It is used for remotetransmission, evaluation and archiving (da-tabase system) of the data received froma SIMEAS R or OSCILLOSTORE and fromdigital protection devices. The programincludes a parameterization function forremote configuration of SIMEAS R andOSCILLOSTORE units.The program enables fully-automated datatransmission of all recorded events fromthe acquisition units to one or more evalua-tion stations via dedicated line, switchedline or a network; the received data canthen be immediately displayed on a moni-tor and/or printed (Fig. 249).The OSCOP P program is provided witha very convenient graphical evaluation pro-gram for the creation of a time diagramwith the curve profiles, diagrams of ther.m.s. values or vector diagrams (Fig. 252).

Fig. 249: Example of a distributed recording system realized with SIMEAS R recorders and data central unit DAKON

Information for Project Planningwith SIMEAS R

The secondary components of high ormedium-voltage systems can either beaccommodated in a central relay room orin the feeder dedicated low-voltage com-partments of switchgear panels. For thisreason, the SIMEAS R system has beendesigned in such a way as to allow bothcentralized or decentralized installation.The acquisition unit can be delivered intwo different widths, either 1/2 19" or 19"(full width). The first version is favorableif measurands of only one feeder are to beconsidered (8 analog and 16 binary signals).This often applies to high-voltage plantswhere each feeder is provided with an ex-tra relay kiosk for the secondary equipment.In all other cases, the full-width version of19" is more economical, since it enables theprocessing of up to 32 analog and 64 bina-ry signals. The modular structure with avariety of interface modules (DAUs) providesa maximum of flexibility. The number ofDAUs which can be integrated in the ac-quisition system is unlimited.


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MeasurandsDAU Type

4 AC voltages,4 AC currents,16 binary signals

8 AC voltages,16 binary signals

8 AC currents,16 binary signals

8 DC currents or16 binary signals

16 binary signals

Use of the interface modules

VCDAU

VDAU

CDAU

DDAU

BDAU

Application

Monitoring of voltages and currents ofthree-phase feeders or transformers includingthe signals from protective equipment.All recorder functions can be run simultaneously.

Monitoring of busbar voltages

Monitoring of feeder and transformer currentsor currents at the infeeds and couplings of busbars

For monitoring of quantities received frommeasuring transducers and telecontrol units,20 mA or 1 and 10 V.

Event recording of alarm signals, disconnectorstatus signals, circuit-breaker monitoring


Fig. 251: Use of the data acquisition units

Fig. 252: OSCOP P Program, evaluation of a fault record

Fig. 250: Rear view of a SIMEAS R unit with terminalsfor the signals and interfaces for data transmission

With the help of a DAKON, several devicescan be interlinked and automatically con-trolled. In addition, digital protection devic-es of different make can be connected tothe DAKON.The voltage inputs are designed for directconnection to low-voltage networks or tolow-voltage transformers. Current inputsare suitable for direct connection to currenttransformers (IN = 1 or 5 A). All inputscomply with the relevant requirements forprotection devices acc. to IEC 60 255.The binary inputs are connected to floatingcontacts.Data transmission is preferably effectedvia telephone network or WAN (Wide AreaNetwork). If more than one SIMEAS R isinstalled, we recommend the use of aDAKON (data concentrator). The DAKONcreates connection with the OSCOP Pevaluation program, e.g. via the telephonenetwork. Moreover, the DAKON automati-cally collects all information registered bythe devices connected and stores thesedata on a decentralized basis, e.g. in thesubstation. The DAKON performs a greatvariety of different functions, e.g. it sup-ports the automatic fax transmission ofthe data. A database management systemdistributes the recorded data to differentstations either automatically or on specialcommand.


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Compensation – Introduction Power Quality

Compensations Systems

Many consumers of electrical energy (trans-formers, engines, fluorescent lamps) maycause a number of different problems:reactive displacement power, non-linearloads (rectifiers, transformers), resulting indistorted waveshapes. Harmonics are gen-erated and, finally, an unbalanced load atthe three phases leads to increased appar-ent power and thus to increased powerconsumption. This is accompanied by high-er conduction losses, which require theinstallation of lines and operating equipmentsuitable for higher capacities and at highercosts than actually necessary. The cost forpower rates in relation to the apparent pow-er and distortion should also be considered.In many cases it is favorable to performcompensation of the undesired components.Siemens offers two different systems forthe compensation of reactive power and ofharmonics – SIPCON T and SIPCON DVR/DSTATCOM – both suitable for three-phaseLV systems up to a rated voltage of 690 V.The latter system is available in designsalso capable of compensating short-termvoltage dips and surges, as well as loadunbalances.■ SIPCON T

Passive systems using switchedcapacitors or capacitors with permanentwiring.

■ SIPCON DVR / DSTATCOMActive systems using IGBT convertersfor quick and continuous operation.

The use of SIPCON can enable energysuppliers worldwide to provide the endconsumer with distinctive quality of supply.As it is now possible with this technologyto supply ”Premium Energy“, an energysupplier can formulate differing tariffs forhis product – electrical energy – so that hewill stand out from his competitors.

30.00

25.00

20.00

15.00

10.00

5.00

0.0010 ms

to 100 ms100 ms

to 500 ms 500 ms

to 1 s1 s

to 3 s20 s

to 60 s3 s

to 20 s

interruption 10060 to 100

30 to 6010 to 30

Duration of voltage dips

Magnitudeof voltagedip [%]

Frequency ofvoltage dips [%]

Fig. 253: Frequency and duration of voltage dips

Fig. 254: Active compensation system(Power Conditioner DSTATCOM)

For industry, especially in the case of com-plex manufacturing processes (such as forexample in the semiconductor industry)”Premium Energy“ is an absolute necessity.SIPCON is capable of effectively suppress-ing system perturbation, such as for exam-ple harmonics. Here as well, tariff changesare to be expected worldwide in the fu-ture. Investigations in Europe have shownthat the increase in harmonics is imposinga particular strain on systems. Such har-monics occur through the operation of vari-able speed drives, of rectifiers – for exam-ple in electroplating – and of inductionfurnaces or wind power plants. In privatehouses, the principal loads are single-phase, such as TV sets and personal com-puters. With the aid of selective recordingof weaknesses in the electrical system andsubsequent use of the SIPCON PowerConditioner, it will be possible to improvesystem loading and to significantly rational-ize the high capital investment necessaryfor system expansion.


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MMM

Group correction

M M

MMM

M

Centralized correction

Controller

Fig. 256: Group correction

Fig. 257: Centralized correction

Fig. 255: Individual correction

M

Individual correction

Power QualityPassive Compensation – Power Factor Correction

The SIPCON T Passive Filtersand Compensation Systems

All consumers based on an electromagnet-ic operation principle (e.g. motors, trans-formers, fluorescent lamps with series re-actors) require a lagging reactive power.This leads to an increase in the amount ofapparent power and consequently in current.The supply of reactive power from the mainsleads to additional load applied to the oper-ating equipment which, as a result, needsto be configured for higher capacities thanactually required. The higher current is ac-companied by an increased power loss.However, the required reactive power canalso be generated close to the consumerwith the help of capacitors which preventthe above mentioned disadvantages. Whenselecting the capacity it is general practiceto calculate with a power factor of 0.9 orhigher.Compensation can be effected according tothree different principles: individual correc-tion, group correction and centralized cor-rection.

Individual Correction

This type of compensation is reasonablefor consumers with high capacities,constant load and long operating times.(Fig. 255).■ The capacitor is installed close to the op-

erating equipment. The lower currentflows already in the line from the busbarto the consumer.

■ The capacitor and the consumer areturned on and off together; an additionalswitch is not required.

When selecting the type of capacitorsplease note that in the case of inductionmotors, the reactive power supplied by thecapacitor must not exceed approx. 90% ofthe motor reactive power in idle operation.Otherwise, disconnection might cause self-excitation by the resonance frequency,since the motor and the capacitor form aresonant circuit. This effect may lead tohigh overvoltages at the terminals and af-fect the insulation of the operating equip-ment. As a general rule, the following val-ues should be considered for the capacitor:■ Approx. 35% of the motor power

at ≥ 40 kW,■ Approx. 40% of the motor power from

20 to 39 kW,■ Approx. 50% of the motor power

at < 20 kW.

Under unfavorable conditions, adherenceto this rule may lead to a power factorsmaller than 0.9. In this case, centralizedcorrection should be performed additionally.

Group Correction

A group of consumers, e.g. motors or fluo-rescent lamps, operated by one commonswitch, can be compensated with one sin-gle capacitor (Fig. 256).

Centralized Correction

The solution for correcting the power fac-tor for a great number of small consumerswith varying power consumption is a cen-tralized compensation principle (Fig. 257)using switched capacitor modules and acontroller. The low losses of the capacitorsallows them to be integrated directly in theswitchboards or distributors.A programmable controller is used to mon-itor the power factor and to switch the ca-pacitors according to the reactive-powerflow.The devices for group correction differ intheir power and in their number of switch-ing steps. For example, a unit with 250 kVAcan be switched in steps of 50 kVA.We recommend the use of units suitablefor switching between five and twelvesteps.


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Fig. 258: SIMEAS C Power Factor Controller

Active power Pa 550 kWPower factor cos ϕ1 0.6Apparent power S1 920 kVACurrent I1 1330 A

cos ϕ1

S1

=P

a

Two examples

Uncompensated system, rated voltage 400 V

Compensated system, rated voltage 400 V

√3 • UI1

=S

1

√3 • 400 V=

920 kVA= 1330 A

0.6=

550 kW= 920 kVA

Power factor cos ϕ2 0.9Capacitor power QC 470 kvarApparent power S2 610 kVACurrent I2 880 A

cos ϕ2

S2

=P

a

√3 • UI2

=S

2

√3 • 400 V=

610 kVA= 880 A

=550 kW

= 610 kVA

QC

= Pa

(tan ϕ1– tan ϕ

2)

The correction of the power factor fromcos ϕ1 = 0.6 to cos ϕ2 = 0.9, results in a34% reduction in apparent power trans-mitted. Line losses can be reduced by56%.

S1

S1

– S

2 = 0.34

I12

I12 –

I22

= 0.56

1

2

0.9

Q2

ϕ1ϕ2

QC

Q1

S1

S2

P

Fig. 259: Effect of compensation

Fig. 260: Examples of power factor control

Power QualityPassive Compensation – Power Factor Control

The SIMEAS C Power FactorController

The centralized correction principle is ef-fected with the help of a controller. Thisunit is designed for panel mounting (frontframe dimensions 144 x 144 mm accord-ing to DIN) in the door of the compensa-tion equipment. It is connected to L1, L2and L3 of the mains voltage; the current istaken from a current transformer in L1 rated1 A or 5 A.All capacitor modules connected areswitched stepwise in such a way as toenable best approximation to the setpointvalue of the power factor. Defined waitingperiods prevent excessive switching opera-tions and ensure that the capacitor will bedischarged properly before the next con-nection. Two setpoints (cos ϕ1 and cos ϕ2)can be specified separately to enable dif-ferent modes for day and night time.Each capacitor module is operated by con-tactors which are controlled by means ofsix contacts. A further contact is used forerror indication. One input for a floatingcontact is used to select one of the twosetpoints for the power factor. Apart fromthe control function, the device also offersa great amount of information on the sta-tus of the supply system. It shows:■ Setpoint cos ϕ1,■ Setpoint cos ϕ2 (e.g. night operation),■ Line current,■ Voltages,■ Active power in kW,■ Apparent power in kVA,■ Actual reactive power in kvar,■ Deviation of the reactive power from

the setpoint value,■ Reactive power of the activated

capacitors,■ Harmonics of voltage U5,■ Harmonics of voltage U7,■ Harmonics of voltage U11,■ Harmonics of current U5,■ Harmonics of current U7,■ Harmonics of current U11.A fiber-optic interface is accessible at therear of the device. On request, a cablesuitable for the conversion of optical puls-es into RS 232C (V.2) signals can be sup-plied. This cable enables connection to apersonal computer which can be used toprogram the controller and to read out pa-rameters, as well as the measured values.


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Ripple controlfrequencies

< 250 Hz

> 250 Hz

> 350 Hz

Reactor/capacitorratio p

14%

≥ 7%

≥ 5%QC

= Pa·(tan ϕ1– tan ϕ2)

Er = reactive energy (kvarh)Ea = active energy (kWh)t = operating time in hours over

the accounting periodtan ϕ2= calculated from the setpoint

value for cos ϕ2

tQ

C=

Er– (Ea • tan ϕ2)

Fig. 261

Fig. 262

Fig. 263: Types of compensation for different ripplecontrol frequencies

Power QualityPassive Compensation – Power Factor Control

Selecting the Capacitor Power

When defining the capacitor power for asystem, the active power P and the powerfactor cos ϕ1 of the system have to beconsidered. In order to upgrade cos ϕ1 tocos ϕ2, the following applies to the powerQC of the capacitor:

The diagram in Fig. 259 shows how theapparent power S1 – caused by activepower Pa and reactive power Q1 – is re-duced to the value S2 by the capacitorpower QC. When taking into account thatthe current is proportional to the apparentpower, whereby the loss caused by thecurrent increases by the power of two, thesaving is remarkable. This result is possiblysupported by a lower energy tariff to bepaid.With systems in the planning stage we canassume that the reactive load is causedmainly by induction motors. These motorsoperate with an average power factor of≥ 0.7. Increasing the power factor to 0.9requires a capacitor power of approx. 50%of the active power.In present industrial plants, the requiredcapacitor power can be determined on thebasis of the energy bill, provided the plantis equipped with an active and reactive en-ergy meter.

If no reactive energy meters are installed,the required data can be determined withthe help of a reactive power recorder.

Correction of the Power Factor inNetworks with Harmonics

Consumers with non-linear resistors, i.e.with non-sinusoidal power consumption,cause a distorted voltage waveshape.However, all waveshapes are made up ofsine curves the frequencies of which areinteger multiples of the system frequency– the harmonics. When using capacitorsfor power factor correction, the capacity ofthese capacitors and the inductivity of thenetwork (supplying transformer) form a se-ries resonant circuit.The two impedances of the resonance fre-quency are the same and cancel each oth-er out; the relatively low active resistance,however, causes current peaks which maypossibly lead to the tripping of protectiondevices. This may occur if the resonancefrequency equals or is close to the fre-quency of a present harmonic.This effect can be corrected by the use ofcapacitor units equipped with an inductor.These inductors are designed in such away that the resonance frequency in com-bination with the network inductivity fallsbelow the fifth harmonic. With all higherharmonics, the capacitor unit is then induc-tive which excludes the generation of reso-nances.We recommend use of these inductor-ca-pacitor units in all cases where more than20% of the power is caused by harmonics-generating equipment.

Compensation in Networks withRipple Control

Ripple control is effected by superimpos-ing the network voltage with signals of afrequency between 160 and 1350 Hz.Since the capacitor conductance is rising ina linear manner in relation to the frequen-cy, these signals can be practically short-circuited. For this reason, the influence ofthe compensation measures should beconsidered and, if inadmissible, it shouldbe corrected. VDEW (German Utility Board)has issued a recommendation on this sub-ject, where the impedance factor α hasbeen defined as the ratio of the networkimpedance to that of the compensationequipment at the frequency of the ripplecontrol signal.The practical consequence is that in net-works without harmonics and with ripplecontrol frequencies of less than 250 Hz,capacitors without inductors can be usedto correct the power factor at a capacity ofup to 35% of the apparent transformerpower. In this case, follow-up measure-ments can be omitted.

Only in cases with a higher capacitor pow-er should the power supply companies beconsulted for an agreement on the use ofaudio frequency hold-offs. With frequen-cies greater than 250 Hz, capacitor powerswithout audio frequency hold-off are ad-missible only up to 10 kvar. If the capacitorpower exceeds this value, audio frequencyhold-offs are to be integrated. This refersmainly to parallel resonant circuits whichare connected to the capacitors in seriesand which show a high impedance in theirresonance frequency.In networks where harmonics are clearlypresent, inductor-capacitor units should beused for compensation in any case. Thespecific type of compensation equipmentis to be selected with consideration of theripple control frequency. Fig. 263 showssome guide values for this procedure.

Compensation of Harmonics

The continuous progress in power semi-conductor technology has resulted in anincreased use of controlled rectifiers andfrequency converters, e.g. for variable-speed drives. The common and character-istic feature of these devices is their non-sinusoidal power consumption. This leadsto distortion of the network voltage, i.e. itcontains harmonics. This distortion is thenforced upon other consumers connectedto the same network and will also have aneffect on higher voltage levels. This disad-vantage may lead to operational failuresand cause a higher apparent power in thenetwork. In order to keep to the limit val-ues as specified in the EN 50160 standard,filtering may become necessary.


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M

M

ν = 5 ν = 7 ν =11…

Drive Low-voltage

Transformer

Primary distribution network

Filter

Active power

Reactive power

ν = 6 · k ± 1, k = 1, 2, 3, …

Iν = 1ν

· I1

Fig. 264: Three-phase bridge circuit

Fig. 265: Correction of the power factor with the help of filters

Fig. 266

Fig. 267

Power QualityPassive Compensation – Harmonics Filter

The following example shows the harmon-ics present in a typical three-phase, fully-controlled, bridge-circuit rectifier (Fig. 264).

The amplitude of the currents decreasesinversely to the increase of the ordernumber, ideally, in a linear manner in rela-tion to the frequency:

Actually, the values are often slightly high-er, since the DC current is not completelysmoothed. Harmonics of the fifth, seventh,eleventh and thirteenth order may showamplitudes which need to be reduced;harmonics of a higher order can usuallybe neglected.The effect of harmonic currents on thesystem can be reduced considerably by theuse of filters. This is effected by generat-ing a series resonant circuit from a capaci-tor and an inductor which is then adjustedexactly to the corresponding frequency foreach harmonic to be absorbed. The twoimpedances cancel each other out, so thatthe remaining ohmic resistance is reducedto a negligible amount, compared to thenetwork impedance. The harmonic currentsare absorbed to a large extent; the restremains present in the supply network.This results in a lower voltage distortionand a considerable increase in voltagequality.Referring to the fundamental component,the filters form a capacitive load. This sup-ports the general reactive power compen-sation. This measure enables the corre-sponding equipment to be designed forlower capacities (Fig. 265).


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Help for Selection

Siemens offers capacitors with and with-out reactors, suitable for single-phase andthree-phase systems for reactive powersbetween 5 and 100 kvar and for nominalvoltages between 230 and 690 V. Thesecapacitors are suitable for the compensa-tion of constant reactive power.

Type Series 4RB

MKK Power Capacitors for fixed compen-sation without reactors, ratings 5 to 25 kvar.The three-phase capacitors can be directlyconnected at the load. Discharge resistor4RX92 are to be connected in parallel.

Type Series 4RD

MKK power capacitors for fixed compen-sation without reactors, mounted in a pro-tective housing or on a plate. Ratings 5 to100 kvar. Discharge resistors included.

Type Series 4RY

Complete small systems without reactorsfor the automatic stepwise control of thepower factor with and without integratedaudio frequency hold-off in different hous-ings and at different ratings. The units areequipped with a BLR-CC controller suitablefor 8 switching steps. Without audio fre-quency hold-off, the capacity ranges from10 to 100 kvar, with hold-off from 12 to50 kvar. The nominal voltage for both ver-sions is 400 V, the frequency is 50 Hz.Larger, fully-equipped systems withoutreactors are delivered in cabinets. Theratings of these systems range from 37.5up to 500 kvar for nominal values between230 V and 690 V and frequencies between50 and 60 Hz. With these systems theSIMEAS C controller for operation in sixswitching steps is used. This controlleroptimizes the switching sequence for con-stant use of the capacitors. For voltagesof 400 V, systems with ratings between75 and 300 kvar and with an integratedaudio frequency hold-off are available.

Type Series 4RY56

Capacitor modules without reactors be-tween 20 and 100 kvar for installation inracks of 600 or 800 mm in width.

Type Series 4RF56

Reactor-capacitor modules from 5 to100 kvar for installation in racks of 600 or800 mm in width.

Type Series 4RF6

Fixed reactor-capacitor units for stationarycompensation in networks with a non-line-ar load percentage of more than 20% re-lated to the supply transformer apparentpower rating. Voltages between 400 and690 V, rating from 5 to 50 kvar. Reactor/capacitor ratios: 5.67%, 7% or 14%.

Type Series 4RF14

Passive, adjusted filter circuits for the ab-sorption of harmonics. Voltages from 400to 690 V, rating from 29 to 195 kvar. In thecourse of project planning, the customerwill be requested to specify the currents ofthe generated harmonics, the harmoniccontent in the higher-level network and theshort-circuit reactance at the connectingpoint.

Type Series 4RF1

Fully-equipped compensation systems withreactor suitable for 400 to 690 V, with acapacitor rating up to 800 kvar and withadditional reactors for a total rating up to1000 kvar. The controller function is real-ized by SIMEAS C.

Type Series 4RF3

Fully-equipped compensation systems withreactors suitable for 400 to 525 V (and alsofor other voltages on request) for ratingsbetween 200 and 400 kvar. Special feature:audio frequency blocking and simultaneousfiltering of harmonics. The controller func-tion is realized by SIMEAS C.

Version

4RF16

4RF17

4RF18

4RF19

Reactor/capacitorratio

5.67%

7%

8%

14%

Fig. 268

Fig. 269: 4RY56 Capacitor module 100 kvar, switchableas 2 x 50 kvar module for cable connection

Fig. 270: 4RY19 power factor correction unit in sheet-steel wall cabinet, 50 kvar

Fig. 271: 4RF1 power factor correction unit250 kvar (5 x 50 kvar) in a cabinet 2275 x 625 mm

Power QualityPassive Compensation – Selection Guide

For technical data of SIPCON T Passive Filters and Com-pensation Systems see Power Quality Catalog SR 10.6


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Equipment forpower factorcorrection,type 4RF17,reactors (7%).Filtering of 5thharmonic upapprox. 30%

Capacitor type4RB, stationarycompensationequipm. type4RD. Equipmentfor power factorcorrection with-out reactors,type 4RY.

Special audiofrequency hold-off on request orcompensationunit with reactor(7%).

Capacitors andcompensationunits without4RY. Audio fre-quency hold-offon the supplyside.

Ripple control inthe network?

Audio frequency> 250 Hz

U5 < 3%U7 < 2%present in thenetwork?

Percentage ofnon-linear load inthe network< 20% of Sr*)

Must resonanceswith the higher-level network beavoided?

Ripple control inthe network?

Audio frequency> 250 Hz? 1

2

*) Sr is the apparent power of the upstream infeeding system (transformer)

Go toflowchart 2

No

No

No

No

No

No

Yes

Yes

Yes

Yes

Yes

Yes

Fig. 272: Flowchart 1: Power factor correction for low, non-linear load

Flowcharts

The flowcharts can be used as a referencewhen selecting the suitable compensationequipment with regard to the individualpreconditions of the specific network.



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*) Sr is the apparent power of the upstream infeeding system (transformer)

Avoiding resonanceswith higher level network

Partial filtering of self-generated harmonics

Ripple controlpresent in the network?

Audio frequency> 350 Hz?

Audio frequency< 250 Hz?

Filtering a large amountof self-generatedharmonics.

Ripple control presentin the netwok?

Compensationequipment forpower factorcorrection, type4RF16, withreactors (5.67%).Filtering of self-generated 5thharmonic up toapprox. 50%.

4RF34 or 4RF36special reactorconnected powerfactor correctionunit, or powerfactor correctionunit, type 4RF19,with reactors(14%).

Requires specialversion, availableon request.

Passive, tunedfilter circuittype 4RF14 re-quired, availableon request.

Improving thepower factor

Percentage ofnon-linear loadin the network≥ 20% of Sr *)

No

No Yes

Yes

YesNo

No NoYes

Yes

Fig. 273: Flowchart 2: Power factor correction for large non-linear load



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SIPCON-DVR/SIPCON-DSTATCOMActive Filter and CompensationSystems

A great number of industrial processesbased on the supply of electrical energyrequire a high degree of reliability in powersupply, including the constancy of the volt-age applied and the waveshape. A short-time voltage failure or voltage dip may cau-se the destruction of a component presentlybeing processed in an NC machine or of awhole production lot in the semiconductor,chemical or steel industry. In the automo-tive and semiconductor industries, for ex-ample, the cost incurred by these lossesmay quickly accumulate to millions of dollars.In return, some production processes cau-se unacceptable perturbations in the supplynetwork resulting from voltage dips (rollingmills), flickers and asymmetries (steel mills).Correction is possible with the help ofactive compensation systems. These sys-tems are capable of absorbing harmonicsand of compensating voltage dips, reactivepower, imbalance in the three-phase sys-tem and flicker problems. Their characteris-tic features go far beyond the capabilitiesof passive systems (e.g. SIPCON T) andoffer great advantages when comparedwith other applications. The function princi-ple is based on a pulse-width modulated,three-phase bridge-circuit rectifier, as usedfor example in variable-speed drives. Theswitching elements – IGBTs (insulated gatebipolar transistors) – are controlled by meansof pulses of a certain length and phase an-gle. These pulses initiate charging and dis-charging of a capacitor, used as an energystore, at periodical intervals in order to achie-ve the desired effect of influencing the cur-rent flow direction. The control function isperformed by means of a microprocessor-based, programmable control unit.

Advantages of ActiveCompensation Equipment

■ No capacitance, in order to exclude thegeneration of undesired resonances.

■ Reactive power and harmonics aretreated independently of each other; thecompensation of harmonics has no ef-fect on the power factor and vice versa.

■ The audio frequency ripple control levelsremain unaffected.

■ Stepless control avoids sudden changesand enables compensation at any de-gree of accuracy.

■ Most rapid reaction to load changes witha minimum delay.

■ No overvoltages caused by switchingoperations.

■ The equipment protects itself againstoverload.

■ The functions will not be affected byageing of the power capacitors.

■ The user can re-configure the system atany time; this greatly enhances flexibility,even if the specific tasks have changed.

Net-work Load

IGBTConverter

Intermediate-circuit capacitor

Net-work Load

Fig. 275: DVR

Fig. 274: DSTATCOM

There are two systems available, the DVR(Dynamic Voltage Restorer) and the DSTAT-COM (Distributed Static Compensator)which differ in their specific design and ap-plication. DSTATCOM is designed for paral-lel and the DVR for serial connection.The DSTATCOM is connected to the net-work between the incoming supply lineand the consumer or a group of consum-ers as shown in Fig. 274. The compensa-tion unit functions as a current source andsink. Correction includes all network char-acteristics related to the reactive power.The DSTATCOM is used to compensateload reactions on the network.Connection of the DVR requires some moreeffort, since the system is to be loopedinto the line (Fig. 275) in series connection.In this connection, the DVR can influencethe line current flow which enables a com-plete compensation of voltage dips asoccurring, for example, in the event ofshort-circuits in the network. The DVR im-proves the voltage quality of the supplysystem.

Power QualityActive Compensation


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Function Principle

The DSTATCOM unit measures the currentapplied to the supply side and injects a cor-rective current which compensates loadperturbations in the supply system or re-duces them to the admissible amount.Since no capacitors are used for correc-tion, the risk of resonances, as with pas-sive systems, can be neglected. Inductorsare not required.The signals from the audio frequency rip-ple control systems are not affected. Theuse of audio frequency hold-offs can beomitted.The DSTATCOM is available in two controlvariants: control variant 1 for standard op-eration and variant 2 for flicker mode.

HarmonicsReactive power

ImbalanceFlickers

LoadNet-work

LoadNet-work

LCL filter

PWMIGBT converter

Intermediate-circuit capacitor

DSTATCOM

Fig. 276: Load perturbations are compensated

Fig. 277: Basic diagram of the DSTATCOM

The DSTATCOM CompensationEquipment

The DSTATCOM is used to compensatereactive power, harmonics, unbalancedload and flickers caused by a consumer.The current supplied from the network ismeasured and modified by injecting correc-tive current in such a way as to preventviolation of the limit values defined for re-active power and for specific harmonicsflowing to the supply system; flicker prob-lems can also be reduced. The power re-quired for this compensation is derivedfrom the intermediate-circuit capacitorwhich is simultaneously re-charged withline current. This line current is also usedto correct the network current. Apart fromthe comparatively low losses, no activepower flow occurs. The DSTATCOM reduc-es or fully compensates perturbations onthe network caused by the consumer.

Fig. 277 shows the basic diagram of thesystem. The IGBT rectifier bridge is con-nected to the network via an LCL filter.The impedance of the inductivity causesthe pulse-width modulated voltage to im-press a current into the network and ab-sorb components of higher frequency.With the help of capacitors, the filter effectwill be improved. DC voltage is applied tothe intermediate-circuit capacitor which isadjusted according to its specific function.The current is measured on the networkside with the result that the correctingfunctions improve the network current andreduce the load reactions on the system.



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Fig. 278: Example: SIPCON DSTATCOM LV

Fig. 279: Steinmetz compensator

Application of Variant 1

This is the standard design used to fulfillthe tasks as described below. All functionscan be performed simultaneously; they arecarried out completely independently anddo not affect each other, as occurs whenusing solutions with passive components(capacitors).DSTATCOM protects itself against overloadby limiting the current. The individual taskscan be allocated to different priority levels.In case of overload, the tasks with the low-est priority will then be skipped and the de-vice will use its full capacity for the othertasks. The control functions with the high-est priority level will be the last ones re-maining active.In this operating mode the DSTATCOMshows excellent dynamic behavior. Withinonly a few network periods, the systemwill reach the setpoint value. Operating var-iant 1 is used for:■ Absorption of Harmonics

A maximum of 4 harmonics up to the13th order, e.g. 5, 7, 11 and 13, are com-pensated. The remaining residual currentcan be adjusted. This option avoids ex-cessive system load, since the increas-ing effect of correction causes a declinein the internal resistance for the corre-sponding frequency. In return, the load-caused current will considerably increaseand with it the losses, which might re-sult in a system overload. Therefore, it isreasonable to correct the harmonics onlyup to the limit specified by the supplier.

■ Reactive Power CompensationReactive power compensation, i.e. cor-rection of the power factor, is possiblefor both inductive and capacitive loads.The continuous control principle avoidsswitching peaks and deviations whichmight occur when switching from onestep to the next.

■ Correction of Unbalanced LoadLoads in single and two-phase connec-tion cause voltage imbalance in thethree-phase system which may alsohave negative effects on other consum-ers. Especially three-phase motors maythen be exposed to overheat.An active load can be symmetrized bymeans of a Steinmetz compensator.While this compensator can correct onlyconstant loads, the SIPCOM is capableof adjusting its correction dynamically tothe load, even if this load is changingquickly.

Three-phasesystem

L1

L2

L3

Activeload

Applications of Variant 2

Variable loads require an even quicker reac-tion than can be realized with variant 1.Therefore, variant 2 has been optimized insuch a way as to enable reactive powercompensation and load balancing withinthe shortest time. Possible applications ofthis variant are:■ Reduction of flickers

Heavy load surges as occurring, for ex-ample, in welding machines, presses orduring the startup of drives, may causevoltage line drops. Fluorescent lampsreact to these voltage drops with varia-tions in their brightness, called flickers.The reactive components of the loadcurrent have usually a greater effect inthis case. The DSTATCOM can be oper-ated in the flicker mode which providesan optimized reaction within the shortesttime in order to reduce these voltagevariations to a large extent. The delaytime of the system is only 1/60 of theperiod length and control is completedwithin one network period.

■ Correction of unbalanced load conditionsThe DSTATCOM is suitable to fully cor-rect unbalanced loads of the three phas-es. Until now, this was achieved withthe help of stepwise controlled inductorsand capacitors, but now correction canbe performed continuously and veryprecisely. The quick reaction of theDSTATCOM in the flicker mode enablescontrol within only one network period.Consumers in single or two-phase con-nection, such as welding devices, willno longer affect symmetry.



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The whole nominal current of the DSTATCOM can beused for the filtering of harmonics.Reactive power compensation and load balancing canalso be performed.This function should be used if the device is mainly usedfor the filtering of harmonics

Only 50% of the DSTATCOM nominal current is usedfor the filtering of harmonics.The remaining current can be used for reactive powercompensation and load balancing.

Instead of harmonics filtering, the whole nominal currentis used to perform highly dynamic reactive powercompensation and load balancing.Compared with other control variants, the dynamicbehavior is many times better.

100% use for the filteringof harmonics

50% use for the filteringof harmonics

Flicker mode

Requirednominal current

The required nominal current for the DSTATCOM iscalculated as the geometrical sum of the required partialcurrents according to the following formula:

Control rangeDSTATCOM

Net-work

Load

SIPCONDSTATCOM

Permanentcompensation

Control rangeof a DSTATCOMwith permanentcompensation

2 x capacitive

capacitive

inductive

Fig. 280: Application modes of DSTATCOM

Fig. 281: Displaced control range


When selecting a DSTATCOM, three as-pects should be considered:1. The nominal voltage.

Nominal voltages of 400 V, 525 V, 690 Vand for medium-voltage applications upto 20 kV.

2. The supply current ISN required by theDSTATCOM.

3. The type of application.Application can be broken down intothree types of different tasks (Fig. 280).

I1 = Reactive component ofthe fundamental current component

I5…I13 = Current harmonics

ISN

= √ I12+ I

52+ I

72+ I

112+ I

132


SIPCON can be used for the generation ofeither capacitive or inductive reactive cur-rent. Since the latter can usually be neglect-ed as regards reactive power compensa-tion, the working point of the DSTATCOMcan be displaced by means of fixed com-pensation with the help of traditional com-pensation (SIPCON T). The power of theDSTATCOM can thus be almost doubled.(Fig. 281).


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LoadNet-work

IGBT converter LCL filter

The DVR Compensation Equipment

The DVR unit is used to correct interferinginfluences from the supply network on theconsumer. Short-time and even longer volt-age dips, harmonics and unbalanced loadmay cause considerable damage to sensi-tive consumers. The DVR has been de-signed for the compensation of such faultsin order to improve the quality in powersupply and to prevent production loss anddamage.

Function Principle

The DVR is used as a voltage sourcewhich is integrated in the feeder line be-tween the supply system and the consum-er in series connection. The voltage ap-plied to the consumer is measured and if itdeviates from the ideal values, the missingcomponents will be injected, so that theconsumer voltage remains constant. Apartfrom the prevention of voltage dips, theDVR is also used to correct overvoltagesand unsymmetries. The highly dynamicsystem is capable of realizing the full com-pensation of voltage dips within a period of2 to 3 milliseconds.

Voltage dipsVoltage overshootsHarmonicsImbalance

LoadNet-work

Fig. 282: Improving the quality in power supply Fig. 283: Block diagram – DVR



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In contrast to the principle of SIPCONDSTATCOM, which corrects the reactivepower only for the parallel-connected load,the whole load current flows through theDVR system. Therefore, all preconditionsand marginal conditions are to be consid-ered to enable correct configuration. Basi-cally, the following points should be takeninto account:■ Fault characteristics:

What kind of network faults are to becorrected (single, two or three-phase)and up to which residual voltage valueand fault duration shall correction be-come effective.

■ Load:Nominal value of the apparent power,type of load, e.g. what types of drive,resistance load, etc. are to be suppliedwith the help of the DVR.

■ Corrective behavior:What degree of accuracy is to be ob-served for the voltage on the load side.

It will often be sufficient if the DVR sup-plies only part of the nominal load. To en-sure correct project planning, a Siemensexpert should be consulted.

The signals from audio frequency ripplecontrol systems are not affected. An audiofrequency hold-off is not required.

Application

The DVR is basically used to improve thequality of the voltage supplied by the pow-er supply system.■ Correction of voltage variations

Remote short-circuits in the supply net-work occasionally result in voltage dipsof different strength and of a duration ofonly few tenths of a second. In weaknetworks it may also occur that the usu-al voltage limits cannot be held over along period of time or that sensitive con-sumers require smaller tolerances thanoffered by the power supply company.With the DVR, single, two and three-phase voltage dips up to a certain inten-sity can be compensated independentlyof their duration. Additional power is tak-en from the rectifier part from the net-work, even if the voltage is too low; thispower is then supplied to the seriestransformer on the load side via the con-verter. The value of the nominal powerof the DVR is reciprocal to the voltagesto be corrected. Statistics show thatmost of the short-time voltage dips havea residual voltage of at least 70 to 80%.The power to be generated by the DVRmust be sufficient to compensate themissing part.

■ Compensation of unbalanced loadThe DVR can be used to inject a positivephase-sequence voltage which enablesthe compensation of imbalance in thesupply voltage in order to avoid exces-sive temperatures of three-phase ma-chines.

■ Absorption of harmonicsThe quick-action control of the DVR ena-bles elimination of harmonics by correct-ing distortions of the voltage waveshape.Since the system can be configured fordifferent tasks, it can also be used toprocess harmonics of the fifth, seventh,eleventh and thirteenth order, either sep-arately or as a whole.

Further information:

www.powerquality.de



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Protection

Documents

operation control

protection functions

protection relays

digital protection

edition protection

generator protection

protection coordination

remote control introduction