Catalogo Rele Siemens Ingles

2005Applications forSIPROTEC Protection Relays

Contents

Line Protection in Distributions Systems Page

Protection of Combined Cable and Overhead Lines 3

Redundant Supply with Bus Coupler 7

Coordination of Inverse-Time Overcurrent Relayswith Fuses 11

Medium-Voltage Protection with Auto-Reclosureand Control 21

Differential Protection of Cables up to 12 km viaPilot Wires (Relay Type: 7SD600) 31

Differential Protection of Cables via Fiber Optics(Relay Type: 7SD610) 37

Thermal Overload Protection of Cables 47

Disconnecting Facility with Flexible ProtectionFunction 53

Earth-Fault Protection in Systems with IsolatedStar Point 59

Earth-Fault Protection in a Resonant-Earthed System 63

Earth-Fault Protection in a Low-Resistance-Earthed System 67

Coping with Single-Phase Load Diversity UsingAdaptive Relay Settings 69

Line Protection in Transmission Systems400 kV Overhead Transmission Line Protection 73

Directional Phase Overcurrent Protection ANSI 67with 7SA522 and 7SA6 117

Distance Protection with Parallel Compensation 121

Protection of Long Lines with SIPROTEC 7SD5 135

Transformer ProtectionProtection of a Three-Winding Transformer 143

Protection of a Transformer with Tap Changer 153

Protection of an Autotransformer 159

Motor ProtectionProtection of a Motor up to 200 kW 169

Generator ProtectionProtection of a Medium-Sized Generator up to 5 MW 179

System Solutions for Protecting Medium and LargePower Station Units 187

Protection of Medium-Sized and Large Generatorswith SIPROTEC 7UM6 193

Unit Protection System for Pumped-Storage PowerStations 207

Busbar ProtectionApplication of Low-Impedance 7SS601 BusbarDifferential Protection 213

Basic Busbar Protection by Reverse Interlocking 223

Applications forSIPROTEC Protection Relays2005

© Siemens AG 2005

Siemens PTD EA · Applications for SIPROTEC Protection Relays · 2005 3

Line Protection in Distribution Systems

1. Distance protection with auto-reclosure onmixed lines

On mixed lines with cables and overhead lines thedistance zone signals can be used with a distanceprotection relay 7SA6 to distinguish to a certainextent between cable and overhead line faults.Mixed lines mean that part of the protected line isdesigned – within the same grading zone – as acable section and the other part of that line as anoverhead line section. The auto-reclosure functionis only useful on the overhead section of the line.The section of the line to be protected must beselected accordingly in the grading. The auto-rec-losure function can be blocked (in the event of afault in the cable section) by interconnection bymeans of the user-programmable logic functions(CFC) in the DIGSI parameterization and config-uration tool.

2. System configurationAccording to the system configuration in the dis-tance zones Z1, Z2, Z3 and Z5 with their line im-pedances (impedances of the line as R and X va-lues, resistance values and reactance values) theline sections are graded as usual in the distanceprotection relay SIPROTEC 7SA6. Zone Z1Bserves above all for the automatic reclosing func-tion and for switching functions (e.g. “manualclose”). Zone Z4 is used to measure and select thecable or overhead line part of the line to be pro-tected.

Zone Z1B can also be used for fast disconnectionof the line to be protected when closing onto afault, in addition to application in conjunctionwith the auto-reclosure function. The protectionmust trip fast if, when closing onto the line to beprotected, the feeder at the remote end is e.g. stillearthed. The 7SA6 also provides the “high-current– instantaneous tripping” function for this protec -tion as an alternative. Both applications are de-scribed here.

Protection of CombinedCable and Overhead Lines

The application is described on the basis of a line<A-B> with two SIPROTEC 7SA6 distance pro-tection relays.

A solution for the protection relay at location “A”is described in the following. Here the line sec-tions of the mixed line are selected with the dis-tance zones Z1B and Z4.

The protection relay at location “B” can be set forauto-reclosure on mixed lines either

by the distance zone Z1B and the high-currentinstantaneous tripping or

alternatively with grading of zones Z1B and Z4.

Fig. 1 SIPROTEC 7SA6 distance protection

LSP2

318.

eps

Fig. 2 Protection of combined cable and overhead lines


Siemens PTD EA · Applications for SIPROTEC Protection Relays · 20054

3. Settings in the configuration with DIGSIFirst the following settings must be made in theconfiguration matrix in the parameter set for the7SA6, for configuration in DIGSI.

Configuration matrix (group: “Auto-reclosure” or“General distance protection”

a) FNo. 2703 – “>Block auto-reclose function”configured to “Source CFC”

b) FNo. 3747 – “Distance pickup Z1B, loop L1E”configured to “Target CFC”

c) FNo. 3748 – “Distance pickup Z1B, loop L2E”configured to “Target CFC”

d) FNo. 3749 – “Distance pickup Z1B, loop L3E”configured to “Target CFC”

e) FNo. 3750 – “Distance pickup Z1B, loop L12”configured to “Target CFC”

f) FNo. 3751 – “Distance pickup Z1B, loop L23”configured to “Target CFC”

g) FNo. 3752 – “Distance pickup Z1B, loop L31”configured to “Target CFC”

h) FNo. 3759 – “Distance pickup Z4”configured to “Target CFC”

Parameterization: (parameter group A, distanceprotection – polygon, zone 4)Parameter 1335 “T4 DELAY”

The tripping time for zone 4 (parameter 1335 =T4) must be set to infinite (T4 = ∞) because thiszone is only used for selecting the cable or over-head line part of the line. Zone 4 should only sig-nal a pickup in this application. Tripping in thiszone is irrelevant. This function is particularly im-portant for the single-pole auto-reclosure func-tion because the tripping then takes placeexclusively via zone Z1B.

4. Creating the logic flowchartsAll that need now be done is to create, link andtranslate the appropriate logic diagrams in theCFC in DIGSI. The “fast” PLC task (PLC0) is usedas a run level in the CFC.

The individual logic functions and the effect onthe protected zone are described below.

Appropriate allocations must be performed (withthe execution of an auto-reclosure function) forthe described line <A – B> in both distance pro-tection relays, to detect the zone of the overheadline.

4.1 Control of auto-reclosure in the 7SA6 forprotection relay A

7SA6 – protection relay A:

The setting values of zone Z4 correspond to thegrading with the R and X values of the cable sec-tion. Zone Z1B is designed as usual for about120 % of the line length. Since no auto-reclosureis to be performed in the cable section, the over-head line section is selected in zone Z1B by a CFCplan. With the result of the CFC plan (FNo. 2703:“>AR block.”) auto-reclosure can be blocked inthe event of a fault in the cable section (zone Z4)(see Fig. 4).

Fig. 3 Control of the auto-reclosure for protection relay A

Fig. 4 CFC plan for protection relay A

LSP2

689e

n.ti

f

>AR block(FNo. 2703)



4.2 Control of auto-reclosure in the 7SA6 forprotection relay B

4.2.1 Version 1

7SA6 – protection relay B:

The setting values of zone Z1B correspond to thegrading with the R and X values of the overheadline on which the auto-reclosure function is to beperformed. The instantaneous “high-current trip-ping” function is used in 7SA6 for instantaneoustripping when closing onto a fault, to completelyprotect the <A – B> line.

The task of the instantaneous high-current ele-ment (instantaneous high-current switch-onto-fault) is to perform tripping immediately andwithout delay when a feeder is closed onto ahigh-current short-circuit. It serves primarily asfast-acting protection when connecting anearthed feeder, but can also become effective(settable) with every closing – including auto-reclosure. The connection of the line is reportedto the protection by the “detection of the circuit-breaker position” (parameter 1134).

In order to make use of the instantaneous high-current tripping, the function must have been en-abled in the relay scope configuration. The valueof the short-circuit current which leads to pickupof the instantaneous tripping function is set as‘I>>>’ value (parameter 2404). The value must behigh enough to avoid the protection tripping(whatever the circumstances) in the event of a lineoverload or current increase – e.g. as a result of abrief interruption on a parallel line.

At least 2.5 times the rated current of the line isrecommended as a pickup value for the instanta-neous high-current tripping.

4.2.2 Version 2

7SA6 – protection relay B:

The setting values of zone Z4 correspond to thegrading with the R and X values of the overheadline. Zone Z1B is designed as usual for about 120 %of the line length. Since no auto-reclosure is to beperformed in the cable section, the overhead linesection is selected in zone Z1B with a CFC plan.With the result of the CFC plan (FNo. 2703: “>ARblock.”) automatic reclosing is blocked in theevent of a fault in the cable section. This meansthat an auto-reclosure is only performed in thecase of pickup of the protection in zones Z1B andZ4 (see Fig. 7).

5. Summary:By division into two distance protection zones(Z1B and Z4), selection of the cable and overheadline sections for double-end feeding in the eventof a fault is substantially simplified. In the practi-cal application the auto-reclosure function canonly be performed restricted to the overhead line.A fault in the cable section leads immediately to afinal TRIP command.

As shown, special requirements (such as selectionof the faulty line section) can be implementedeasily and at low cost with the CFC logic in theSIPROTEC distance protection.

Fig. 5 Distance protection with zone Z1B and the instan-taneous high-current tripping

Fig. 6 Distance protection with grading of the zones Z1Band Z4

Fig. 7 CFC plan for protection relay B

>AR block(FNo. 2703)

LSP2

690e

n.ti

f





Automatic switchover of incoming supply withSIPROTEC 7SJ62

1. IntroductionLiberalized energy markets are demanding new so-lutions for the operation of electrical systems. Thispublication describes an application in which theavailability of power supply of a switchgear or plantcan be improved considerably by switching overfrom a faulty to a redundant incoming supply. Theinfluence of external system faults is minimized de-cisively by fast disconnection of faulty system partsand switchover from a faulty to a trouble-free in-feed. These automation tasks can be accomplishedtoday with modern SIPROTEC protection relayswithout the need for further equipment.

2. Influential variables of system availability“Power Quality” covers all the properties of anelectrical power supply. Power quality can be fur-ther subdivided into “voltage quality and systemreliability” as shown in Fig. 2. The latter is closelylinked with an “adequate” power supply and thesecurity of the supply. Only the system reliabilityis looked at in detail below.

Redundant Supply withBus Coupler

The reliability of an electrical system is deter-mined by a number of factors. These include thereliability of every single item of equipment, thekind and method of connection of the equipment,i.e. the system topology, the properties of the pro-tection relays, the remote control equipment, thedimensioning of the equipment, the method ofoperation including troubleshooting, and the sys-tem load capacity. The most frequently appliedqualitative criterion in power system planning is(n-1), with which a system can be checked forsufficient redundancy.

It requires that the system must be able to survivefailure of any item of equipment without imper-missible restriction of its function. The (n-1) cri-terion is a pragmatic and easy-to-handle basis fordecision but has the disadvantage that the supplyreliability cannot be quantified. Frequency, dura-tion and scope of interruptions in the supply arenot measured, with the result that it is not possible(for example) to distinguish between different(n-1)-safe system variants in terms of reliability.Quantitative methods of system reliability analysisallow further evaluation of planning and operat-ing variants supplementary to the qualitativemethods. The supply quality is quantified by suit-able parameters and thus enables a comparativeassessment of different (n-1) reliable planning andoperation variants (for example). This allows aspecific estimate of the costs and benefits of indi-vidual solutions in system planning and opera-tion.

Fig. 1 SIVACON 400 V, with 7SJ62-protected and controlled circuit-breakers

LSP2

587.

tif

Fig. 2 Subdivision of Power Quality

PowerQuality

SystemReliability

VoltageQuality



Switchover with redundant incoming feedersmeans investment. However, by considering thebehavior in case of outages of equipment, the sys-tem topology, the protection concepts, the systemcapacity utilization (supply and loads) and themethod of operation, even more reliable and safesystem operation can be ensured. The aim is over-all system reliability, expressed in terms of a highdegree of supply availability for special customerswith sensitive processes. Closer analyses by way ofthe load cycle of individual feeders or transformerstations – as well as permanent rationalizationmeasures in operation of the power systems – alsocall for a higher degree of automation in all powersystem sections.

2.1 Transient voltage sags and outagesThe most frequent cause of system faults and in-ternal voltage sags or outages (total failures) is alightning strike. As Fig. 3 shows, the system faultmay be in the transmission system or in the distri-bution system.Usually there is no total blackout but the remain-ing residual voltage is greater than 70 %.

The economic damage caused by sags or outages isimmense (Fig. 4). The following Fig. 5 showscomputer loads can fail already when the systemamplitude deviates from its rating for less thanone period. This so-called ITI/CBEMA curve isused worldwide as a reference for the sensitivity ofother load types too, because the appropriatemanufacturer data are often unavailable. The dif-ficulty in protecting a highly automated factory islargely attributable to the large number of loadsand the degree of networking of these loads.

3. Functional principle and aim of automaticswitchover

A traditional method for a utility to solve itspower quality problems is information from cus-tomers about supply limitations suffered. Withthe multifunction protection relays presented be-low it is possible to find solutions for protectingwhole areas from outages by means of protectionrelays with integrated automatic functions.

Automatic switchover is suitable for disconnec-ting an endangered supply and quickly bringing ina redundant, secure supply with the aid of an al-ternative incoming feeder. A fault is detected byan undervoltage detection function. Using a direc-tional overcurrent detection function, it can bedecided whether the fault is external or internal.In the event of an external fault, switchover to thealternative incoming feeder takes place. However,if the fault is internal there is no switchover, withthe intention that the fault can be cleared by avail-able circuit-breakers.

Switchover to the alternative incoming feeder orthe coupling of separated networks only takesplace instantaneously when both separated net-works are synchronized. Otherwise it waits untilsynchro- nicity between the two separated net-works is established or the voltage has dropped tosuch an extent that safe connection is possible.However this is only on condition that the two in-coming feeders are not impaired in their voltagequality by the same system fault, such thatswitchover provides no protection against loadshedding.

Fig. 3 Possible locations of system faults

Fig. 4 Typical failure costs per voltage sags



In the case of rapid system decoupling (openingthe circuit-breaker in the faulty incoming feeder)it can be assumed that the fault current has ahigher displacement than in normal switching.This should be taken into account in the choice ofcircuit-breakers. The system configuration andthe specific requirements regarding switching timemust therefore be analyzed before choosing thesuitable rapid switchover.

The following typical applications are particularlyconceivable:

1. Switchover from one redundant incomingfeeder to the next to protect loads from volt-age outages

2. System decoupling in the event of a fault onthe load side and therefore prevention of thefault from affecting other loads.

3.1 Practical principleThe SIPROTEC relays attend to full protection ofthe incoming feeders by means of directionalovercurrent-time protection.

Configuration instructions for protection of theincoming feeders are not dealt with in detail here.

Automatic switchover is implemented by at leasttwo autarchic SIPROTEC 4 relays (e.g. 7SJ62)which can be adapted individually to the designand basic conditions applying in a customer speci-fication, in combination with the existingswitchgear.

The following switchover possibilities can bedistinguished here:

Overlap switchoverBoth circuit-breakers are actuated almostsimultaneously

Rapid switchoverCircuit-breaker 1 is opened and circuit-breaker 2closed as long as the voltage is below ∆U – motorrundown behavior is taken into account

Slow switchoverMotors must have run down, or else be switchedback on as from a certain residual voltage, thereason being high start-up current of the motorgroups; this possibility should be rare.

3.2 DescriptionThe desired configuration can be selected as “nor -mal operation” with the preselector switch S100.The selected circuit-breaker remains defined as“normally OPEN”. This open circuit-breaker isconsidered as a backup in the event of a faultwhich can then supply the faulty, disconnectedbusbar section with energy again. Each circuit-breaker operates autarchically and is controlled byone single multifunction relay.

The relays are interconnected by binary signalcommunication between the binary inputs andoutputs. In this way every relay can communicatewith the other two relays and exchange informa-tion about circuit-breaker position and protectionfunctions.

Fig. 5 ITI/CBEMA curve

Fig. 6 Bay layout



Therefore it is possible to create self-controllingautomatism also allowing manual control fromthe outside. When connecting, the synchro-checkcan be performed by the multifunction relays(7SJ64) themselves or by a separate synchro-checkdevice.

a) In the event of undervoltage and breakerfailure from subordinate feeders or from theparallel incoming supply, the circuit-breakersare tripped individually by any protectivepickup.

b) If the protection has picked up due to a faultoutside the switchgear or plant, or the supplyvoltage drops although there is no short-circuit/earth fault, the parallel incomingfeeder is granted release (release of infeed B)to close.

c) If the disconnector is closed in the trouble-free incoming feeder and the parallel supply isreleased (2 releases), the circuit-breaker isclosed, either at synchronicity or if there is novoltage on the busbar. Disconnection of thefaulty incoming feeder and switch-in of thesubstitute incoming feeder can be coordi-nated by the timer T1 (overlap time).

By setting the post-fault time with timer T2,the maximum permissible time interval isspecified which may pass between connectionand the last satisfied synchronization condi-tion.

d) If the circuit-breaker in the faulty incomingfeeder has not opened properly, the circuit-breaker in the substitute incoming feeder willbe reclosed by the breaker failure protection.

This configuration was installed in the plant of apetrochemical industry customer and has beenoperating reliably since 2002.

The principle has proven so reliable that it is usedin all the busbars there, from the 400 V switchgearthrough 6.6 kV right up to the 33 kV level.

4. SummaryMultifunction relays which also assume controland protection duties for the switchgear or plantare highly attractive due to their greater flexibility.There is considerable interest in solutions for pro-tection against outages that would otherwise bringwhole factories to a standstill. Therefore this solu-tion has the potential for use in both the low andthe medium-voltage sector.

Automatic switchover based exclusively onSIPROTEC 4 relays represents an attractive alter-native to existing products in terms of both invest-ment volume and engineering effort. The neces-sary functions are available. The integrated logiccan be used to great advantage for the parameteri-zation (by means of a CFC logic editor) of auto-matic switchover in the relays.

Fig. 7 Logic example for input field A

Fig. 8 Air-insulated switchgear 8BK, 6.6 kV, with7SJ63-protected and controlled circuit-breakers

LSP2

586.

tif



1. IntroductionThe duty of protection equipment is to allowoverload currents that occur during operation,yet to prevent impermissible loading of lines andequipment. To avoid damages in the case of short-circuits the relevant equipment must be tripped inthe shortest possible time. On the other hand onlyas few feeders or loads as possible should be dis-connected from supply.The protection relays available in the power sys-tem must recognize the fault, perform trippingthemselves or give trip commands for the relevantswitching device.The protection relays must be set to ensure selec-tive tripping. Absolute selectivity is not always as-sured. “Selectivity” means that the series-connec-ted protection relay nearest the fault first trips thefaulted line. Other protection relays (further up-stream) recognize the fault but trip only after a de-lay (backup protection).

In the following the use of HV HRC fuses(high-voltage-high-rupturing capacity) and in-verse-time overcurrent-time protection relays(as well as their interaction) will be described.See Fig. 1.

2. Protective equipment2.1 HV HRC fusesThe high-voltage-high-rupturing capacity fuse is aprotective device suited for non-recurring shut-down in medium-voltage switchgear, in which thecurrent is interrupted by the melting of a fusibleelement embedded in sand.

HV HRC fuses are used for short-circuit protec-tion in medium-voltage switchgear up to 20 kV.Used upstream of transformers, capacitors andcable feeders, they protect equipment and systemcomponents from the dynamic and thermal ef-fects of high short-circuit currents by shuttingthem down as they arise.

Coordination of Inverse-Time Overcurrent Relayswith Fuses

However, they are not used as overload protectionbecause they can only trip reliably as from theirminimum breaking current. For most HV HRCfuse links the lowest breaking current isImin = 2.5 to 3 x IN.

With currents between IN and Imin HV HRC fusescannot operate.

When choosing HV HRC fuse-links, stressing ofthe fuse from earth-fault current or residual cur-rent must be considered.

HV HRC fuse-links are installed with high-voltagefuse-bases in the switchgear. They can also be in-stalled in the built-on units of the switch discon-nectors provided. By combining switch discon-nector and HV HRC fuse, the IN to Imin currentwhich is critical to the fuse can also be reliablybroken. The switch is tripped by the fuse's strikerand disconnects the overload current in the threephases. Some typical breaking characteristics areshown in Fig. 2.

Fig. 1 Block diagram



2.2 Inverse-time overcurrent protectionOvercurrent protection is the main function of the7SJ6 product range. It can be activated separatelyfor phase and earth-fault currents.The I>> high-set overcurrent stage and the I>overcurrent stage always work with definite trip-ping time.In the Ip inverse-time overcurrent stage, the trip-ping time depends on the magnitude of theshort-circuit current.

Fig. 3 shows the basic characteristics of definiteand inverse-time overcurrent protection.

For inverse-time overcurrent functions (Ip stages)various tripping characteristics can be set.

Normal inverse (NI) Very inverse (VI) Extremely inverse (EI) Long time inverse (LI)

All characteristics are described by the formulaebelow. At the same time, there are also distinc-tions as follows:

IEC/BS ANSI

NI tI I

T=−

⋅0 14

10 02

.

( / ) .p

p tI I

D=−

+

⋅8 9341

10 17966

2 0938

.

( / ).

.p

VI tI I

T=−

⋅13 5

1

.

( / )p

p tI I

D=−

+

⋅3 922

10 0982

2

.

( / ). )

p

EI tI I

T=−

⋅80

12( / )p

p tI I

D=−

+

⋅5 64

10 02434

2

.

( / ).

p

LI tI I

T=−

⋅120

1( / )p

p tI I

D=−

+

⋅5 6143

12 18592

.

( / ).

p

t = Tripping timeTp = Setting value of the time multiplierI = Fault currentIp = Setting value of the current

Table 1 IEC/BS and ANSI

The general IEC/BS characteristic is shown inFig. 4 and that of ANSI in Fig. 5

Breakingcharacteristicsof HV HRC fuses

Fig. 3Definite andinverse-timecharacteristics



3. Network circuit and protection conceptThe topology of a distribution system should be assimple and clear as possible and ensure a reliablesupply.

Individual transformer stations are supplied byring cables. An example of a ring cable system isshown in Fig. 6.In order that a fault does not cause the whole ringwith all stations to fail, an “open” operatingmethod is the standard. In this example, trans-formers are protected on the low voltage (LV)side with HV HRC fuses and the ring cable itselfwith an overcurrent-time relay.

3.1 Calculating the relevant system currentsThe full load current and short-circuit strength arethe selection criteria for the cable to be used. Thetransformer rated currents must not deviate toomuch from the rated currents of the cables used.The maximum and minimum short-circuit cur-rents (3, 2, 1 phase) appearing in this power sys-tem section must be calculated before the para-meters of the relays can be set. LV-side short-circuit currents must also be taken into accounthere. It is advisable to use programs such asSIGRADE (Siemens Grading Program) to calcu-late the short-circuit currents.For further information please visit us at:www.siemens.com/systemplanning

Fig. 4 IEC/BS characteristics Fig. 5 ANSI characteristics

4. Selection and setting of protective componentsThe HV HRC fuses are selected using tables thattake into account transformer power (Sn), short-circuit voltage (Usc) and rated voltage on the HV side.Using the short-circuit currents detected, a proposalcan be worked out for selective protection setting ofthe inverse-time overcurrent functions:

Ip must be set above the permissible rated current ofthe cable (around 1.5 x IN cable)

I>> should not trip in the case of a fault on the low-voltage side

In the case of a max. short-circuit current in the MVsystem, there must be an interval of at least 100 msbetween the tripping characteristic of the HV HRCfuse and the inverse-time characteristic. The timemultiplier Tp must be set to get this safe gradingtime.

It must be borne in mind that the value of the timemultiplier Tp (in 7SJ6 from 0.05 to 3.2 seconds) doesnot correspond to the genuine tripping time of thecharacteristic. Rather, the inverse-time characteristiccan be shifted in parallel in the time axis by this value.



5. Proof of selective trippingAs mentioned earlier, selectivity means only theprotection relay closest to the faulty system sec-tion trips. Protection equipment connected (up-stream) in series must register the fault but onlytrip after a delay period. Typically, proof of selec-tive tripping is shown in a current-time-diagramwith double logarithm scale. Programs likeSIGRADE are also used for this.For the power system sections in question, typicalor critical time grading diagrams are selected.

Each protection relay has its own name, which de-scribes the installation location. The same powersystem and protective elements shown in morethan one time grading diagram have the samename.

The color of the name in the time grading path(left side of the diagram) matches the color of theset characteristic (in the time grading diagram onthe right) in the current-time-diagram. On the leftside, in addition to the single-line circuit diagram(time-grading path) for each protection relay, thetype name, the setting range and the set values aregiven.

In addition to the characteristics of the protectionrelay, the current-time-diagram shows the short-circuit current ranges plotted with minimum andmaximum values as bandwidth (values from theshort-circuit calculation). These short-circuit

current bands always end on the voltage currentscale. The right-hand characteristic in a band isthe maximum short-circuit current (3 phase), cal-culated (here in green) from the incoming ele-ments (generators, transformers, etc). The left-hand characteristic shows the minimum short-cir-cuit current (1 or 2 phase) which is calculated onthe basis of the impedances of the elements in thepower system up to the location of the fault.

Band 1 (Transf. D Pr) shows the bandwidth of the20 kV power system;band 2 (Transf. D Sec) shows that of the 0.4 kVpower system.The above-mentioned bands are contained in thetime-grading diagrams (Figs. 7 to 11).

6. Grading of overcurrent-time relay andHV HRC fuse

As an example of the power system shown inFig. 6, in 3 time sequence diagrams the most usualcharacteristics (NI, VI, EI) of the inverse-timeovercurrent protection are shown with the corre-sponding HV HRC fuses characteristic. The over-current-time relay 1, HV HRC fuse D and trans-former D are selected from the circuit diagram.

Fig. 6 Example of a 20 kV ring distribution system



Fig. 7 Time-gradingdiagram, inverse-time NI

Setting range Setting

Ip = 0.1 – 4 ATp = 0.05 – 3.2 s

Ip = 1.8 ATp = 0.05 s

Ip_mi = 2.3 kAIs_mi = 15.8 kA

Ip_ma = 7.8 kAIs_ma = 18.2 kA

Overcurrent-time relay with “Normal Inverse” (NI) setting

Band 2 Band 1



Fig. 8 Time-gradingdiagram, inverse-time VI


Ip = 0.1 – 4 ATp = 0.05 – 3.2 s

Ip = 1.8 ATp = 0.15 s



Overcurrent-time relay with “Very Inverse” (VI) setting

Band 2 Band 1



Fig. 9 Time-gradingdiagram, inverse-time EI


Ip = 0.1 – 4 ATp = 0.05 – 3.2 s

Ip = 1.8 ATp = 0.45 s



Overcurrent-time relay with “Extremely Inverse” (EI) setting

Band 2 Band 1



Fig. 10Time-grading diagram,very inverse, withsetting like normalinverse


Ip = 0.1 – 4 ATp = 0.05 – 3.2 s

Ip = 1.8 ATp = 0.05 s



Overcurrent-time relay with VI setting,with same setting as NI

Band 2 Band 1



Fig. 11Time-grading diagram,extremely inverse, withsetting like normal in-verse

Setting

Ip = 0.1 – 4 ATp = 0.05 – 3.2 s

Ip = 1.8 ATp = 0.05 s



Overcurrent-time relay with EI setting,with same setting as NI

Band 2 Band 1

Setting range



For the transformer considered (20/0.4 kV,Sn = 0.8 MVA, Uk = 6.1 %), a 63 A HV HRC fuseis selected according to the above-mentioned se-lection tables.

In order to maintain selectivity, the target triptime is approx. 100 ms for the overcurrent-timerelay setting in the various characteristics withmaximum short-circuit current on the 20 kV side.Under the same short-circuit conditions theHV HRC fuse trips in approx. 1 ms.

By setting the Ip appropriately, the maximum faulton the LV side does not lead to pickup of the over-current-time relay. As can be seen in Fig. 10 thecharacteristic begins on the right, next to the max-imum short-circuit current (brown, vertical lines).The following setting values should be used toachieve a safe grading time of 100 ms between alltypes of o/c inverse-time characteristics (NI, VI,EI) and the characteristic of the fuse.

Fig. Ip x IN Tp (s) Characteristics

7 1.8 0.05 Normal inverse (NI)

8 1.8 0.15 Very inverse (VI)

9 1.8 0.45 Extremely inverse (EI)

Table 2

When comparing the three figures it is clear thatthe area between the HV HRC and inverse-timecharacteristics is smallest for the setting NI.Therefore the NI setting must be preferred in thisexample.

In order to explain the difference in the character-istics more clearly, two diagrams are shown withthe characteristics VI and EI with the same settingvalues as NI.

Very inverse (VI) Extremely inverse (EI)

Ip = 1.8 Ip = 1.8

Tp = 0.05 Tp = 0.05

See Fig. 10 See Fig. 11

Table 3

ConclusionThe steeper the slope of the characteristic thelower the tripping time with maximum faultcurrent. The safe grading time from the HVHRC characteristic becomes smaller. The coor-dination shown here of the protection devices isonly part of the power system and must beadapted to the concept of the overall power sys-tem with all protection relays.

Note:In this example there was no setting of I>>, be-cause the inverse-time characteristics themselvestrip in the ≤ 0.2 s range in the event of the maxi-mum or minimum 20 kV side fault.

7. SummaryThis application example demonstrates the engi-neering effort necessary to achieve a selective timegrading.

Real power systems are more complex and equip-ped with various protection relays. Whatever thecircumstances, it is necessary to know the operat-ing mode of the power system (parallel, generator,meshing, spur lines etc) as well as to calculate therated and short-circuit currents. It is worth the ef-fort for the protection engineer because the objec-tive is to lose only the faulty part of the power sys-tem.

SIGRADE software effectively supports gradingcalculations. Power system planning and timegrading calculation is also offered by Siemens.

8. ReferencesGünther Seip: Elektrische Installationstechnik

Siemens: Manual for Totally Integrated Power

Catalog HG12: HV HRC Fuses

SIGRADE Software V3.2

Manual 7SJ61: Multifunctional Protective Relaywith Bay Controller 7SJ61



1. IntroductionAn important protection criterion in medium-voltage applications is overcurrent-time protec-tion. Hardware redundancy can be dispensed within favor of lower-cost solutions, thanks to numer-ical technology and the high reliability of theSIPROTEC 4 protection relays. The SIPROTEC 4protection relays also allow functions which gobeyond the basic scope of protection:

Unbalanced load (negative-sequence) pro-tection, motor protection functions, circuit-breaker failure protection,...

Other voltage-dependent protection functionssuch as voltage protection, directionalovercurrent protection

Auto-reclosure Control, including interlocking Integration in a control system

This enables all the requirements in the feeder tobe met with a single relay. Scalable, flexible hard-ware allows simple adaptation to any application.

2. Protection concept2.1 Overcurrent-time protectionThe task of overcurrent-time protection is to detectthe feeder currents, in order to initiate tripping bythe circuit-breaker in the event of overcurrent. Se-lectivity is achieved here by current grading or timegrading. The phase currents IL1, IL2 and IL3 and theearth current IE serve as measuring variables here.(Non-directional) overcurrent-time protection isused in medium-voltage power systems withsingle-end infeed or as backup protection inhigh-voltage applications.

Medium-Voltage Protectionwith Auto-Reclosure andControl

Fig. 1 SIPROTEC medium-voltage protection

Fig. 2 Block diagram

R_H

A25

-328

.tif



2.1.1 Grading and selectivityThe aim of every protective setting is to achieveselectivity, i.e. the protection relay closest to thefault location trips the CB; all the others detect thefault but do not switch off or at least only after adelay. This ensures backup protection if “regular”protection fails.

There are basically two criteria for achieving selec-tivity:

TimeHere a protection relay initiates tripping imme-diately or with an adjustable delay time. Sincethe power system fault is usually detected by anumber of protection relays in the powersystem, the protection relay with the shortestdelay time initiates tripping. The delay times inthe individual protection relays are defined suchthat the short-circuit is cleared by the protec-tion relay closest to the fault.

This type of grading is normally used for cable andoverhead power line systems.

CurrentAnother grading criterion may be the magni-tude of the short-circuit current itself. Since thesize of the short-circuit current cannot be deter-mined exactly in pure line or cable systems, thismethod is used for grading of transformers. Thetransformer limits the short-circuit current re-sulting in different magnitudes of short-circuitcurrent on the high and low-voltage side.This behavior is utilized to achieve selectivity intripping, as is attained in time grading.

The flexibility of SIPROTEC 4 overcurrent-timeprotection relays allows a mixture of these two cri-teria and therefore helps to achieve optimum sup-ply security.

2.1.2 Definite-time overcurrent protectionDefinite-time overcurrent protection is the maincharacteristic used in Europe (except in countrieswith a British influence). Delay times are assignedto several current pickup thresholds.

I>> pickup value (high short-circuit current)t>> (short delay time)

I> pickup value (low short-circuit current),t> (delay time)

2.1.3 Inverse-time overcurrent protectionThe inverse-time characteristic is widely used incountries with a British and American influence.Here the delay time is dependent on the currentdetected.

Inverse-time overcurrent protection characteristicsaccording to IEC 60255

IEC 60255-3 defines four characteristics whichdiffer in their slope.

InverseVery InverseExtremely InverseLong Inverse

The calculation formulae and the correspondingcharacteristics are shown below by way of com-parison.

Inverse

Very inverse

Extremely inverse

Long inverse

Fig. 22-stage definite-timeovercurrent characteristic(I>>, I>)

( )t T=

−⋅014

10 02

..

I Ip

p

( )t T=−

⋅135

1

.

I Ipp

( )t T=

−⋅80

1I Ip

2 p

( )t T=−

⋅120

1I Ipp

Fig. 3 Comparison of inverse-time overcurrentprotection characteristics



The corresponding characteristic is selected de-pendent on the overall grading coordinationchart. However, the inverse characteristic is suffi-cient for most applications.

Inverse-time overcurrent protection characteristicsaccording to ANSI/IEEE

Characteristics are also defined by ANSI/IEEEsimilar to those according to IEC 60255. Forfurther details about these, see the applicationexample on “Coordination of Inverse-TimeOvercurrent Relays with Fuses”. The ANSI char -acteristics are also available as standard in allSIPROTEC 4 overcurrent-time protection relays.

2.1.4 User-defined characteristicsNumerical protection relays like SIPROTEC 4 alsoallow the user to freely define characteristics, andtherefore enable maximum flexibility. This meansease of adaptation to existing protection concepts,e.g. when renewing the protection, even for specialapplications.

2.1.5 Combined characteristicsSIPROTEC 4 overcurrent-time protection allowsthe advantages of definite and inverse-timeovercurrent protection to be combined. On theone hand, with the high-set current stage I>>, thetripping time with high short-circuit currents canbe reduced in comparison with inverse-timeovercurrent protection characteristics, and on theother hand the grading can be adapted optimallyto the characteristic of the HV HRC fuses with in-verse-time overcurrent protection characteristic.

2.1.6 SensitivityThe earth current can be measured or calculatedin addition to the phase currents. Independentprotection stages for phase-to-earth faults are alsoavailable in the SIPROTEC 4. As a result, sensitiv-ity below the rated current is achieved for such afault.

2.2 Auto-reclosureAuto-reclosure is only used on overhead lines, be-cause the chances of success are relatively slight inthe event of faults in a cable network. About 85%of reclosures are successful on overhead lines,which contributes greatly to a reduction in powersystem downtimes.

Important parameters for reclosure are:

Dead timeLockout (blocking) timeSingle or three-poleSingle or multishot

Normally only one single three-pole reclosure isperformed for medium-voltage applications. Deadtimes between 0.3 and 0.6 s usually suffice for ade-quate de-ionization of the flashover distance andthus a successful reclosure.

The lockout times (time up to next reclosure) arechosen so that protection relays affected by thepower system fault have reliably reset. In the pastthis led to relatively long lockout times (approxi-mately 30 s) due to the dropout time of mechani-cal protection relays. This is not necessary in nu-merical protection relays. Shorter lockout timescan therefore reduce the number of final discon-nections (unsuccessful reclosures), for exampleduring thunderstorms.

In the past separate relays were used forprotection and automatic reclosure. The initiationfor this was given by parallel wiring with the pro-tection relay. In SIPROTEC 4 relays the auto-reclosure function can be integrated in the protec-tion relay; there is no need for any additional relayand wiring.

2.3 ControlThere is a noticeable worldwide trend towardsautomation, even in medium-voltage power sys-tems. SIPROTEC 4 protection relays provide theconditions for controlling the feeder both locallyand remotely by telecontrol/station control andprotection systems. This is supported by the ap-propriate control elements on the relay and vari-ous serial interfaces. See Chapter 4 for furtherinformation.

3. SettingsThe determining of the most important settingparameters is explained in this chapter by meansof a typical application.

3.1 Overcurrent-time protectionThe setting of the overcurrent stages is defined bythe grading coordination chart of the overall net-work. Current grading is possible for the “trans -former” protection object; only time grading canusually be applied for overhead lines/cables.

3.1.1 High-set current stage I>>The high-set current stage I>> is set under the ad-dress 1202 and the corresponding delay T I>> un-der 1203. It is normally used for current grading athigh impedances such as are encountered in trans-formers, motors or generators. Setting is such thatit picks up for short-circuits reaching into this im-pedance range.



Example:Transformer in the infeed of a busbar with the fol-lowing data:

Rated apparent power SNT = 4 MVAShort-circuit voltage Uk = 10 %Primary rated voltage UN1 = 33 kVSecondary rated voltage UN2 = 11 kVVector group Dy 5Neutral earthedShort-circuit poweron 33 kV side 250 MVA

The following short-circuit currents can be calcu-lated from these data:

3-pole, high-voltage side short-circuitI"SC3 = 4389 A

3-pole, low-voltage side short-circuitI"SC3, 11 = 2100 A

on the high-voltage side flowI"SC3,33 = 700 A

rated current of the transformer HVINT, 33 = 70 A (high-voltage side)

rated current of the transformer LVINT, 11 = 211 A (low-voltage side)

current transformer (high-voltage side)INW, 33 = 100 A / 1 A

current transformer (low-voltage side)INW, 11 = 300 A / 1 A

Due to the setting value of the high-set currentstage I>>

I>>/IN >1

U

I

k Transfo

N Transfo

N CT

⋅I

the following setting on the protection relay:

The high-set current stage I> must be set higherthan the maximum short-circuit current detectedon the high-voltage side in the event of a fault onthe low-voltage side. In order to attain a sufficientnoise ratio even at fluctuating short-circuit power,a setting of

I>>/IN = 10, i.e. I>> = 1000 A

is selected.

Increased inrush current surges are disarmed bythe delay times (parameter 1203 T I>>) providedtheir fundamental component exceeds the settingvalue. The set time is a purely additional time de-lay which does not include the operating time.

3.1.2 Overcurrent stage I>The maximum operating current occurring is sig-nificant for the setting of the overcurrent stage I>.Pickup by overload must be ruled out because therelay works as a short-circuit protection with cor-respondingly short operating times in this modeand not as overload protection. It is therefore setfor lines at about 20 % and for transformers andmotors at about 40 % above the maximum (over)load to be expected. The delay to be set (parame-ter 1205 TI>) is given by the grading coordinationchart created for the power system.

The set time is a purely additional time delaywhich does not include the operating time (mea-suring time). The delay can be set to ∞. The stagethen does not trip after pickup but the pickup issignaled. If the I> stage is not needed at all, thepickup threshold I> is set to ∞. Then there isneither pickup indication nor tripping.

According to the above example this gives a calcu-lated setting value of

I I> = ⋅ = ⋅ ⋅14 14 70. .NT, 33 NW, 33A =100 A =1.0 I

3.1.3 Inverse-time overcurrent protection stages Ip

It must be taken into account when selecting aninverse-time overcurrent characteristic that a fac-tor of approximately 1.1 is already incorporatedbetween the pickup value and the setting value.This means that pickup only takes place when acurrent 1.1 times the setting value flows. The cur-rent value is set under address 1207 Ip. The maxi-mum operating current occurring is significantfor the setting.

Fig. 4 DIGSI parameter sheet, definite-time overcurrent protectionphase

LSP2

682.

tif



Pickup by overload must be ruled out because therelay works as a short-circuit protection with ap-propriately short command times in this modeand not as overload protection. The correspond-ing time multiplier is accessible under address1208 T Ip (51 TIME DIAL) when selecting an IECcharacteristic, and under address 1209 51 TIMEDIAL when selecting an ANSI characteristic. Thismust be coordinated with the grading coordina-tion chart of the power system.

The time multiplier can be set to ∞. Then the stagedoes not trip after pickup but the pickup is sig-naled. If the Ip stage is not needed at all, address1201 DMT/IDMT PHASE = DTM only (FCT50/51) is selected in the configuration of the pro-tection functions.

3.1.4 Earth current stagesIE>> (earth)The high-set current stage IE>> is set under ad-dress 1302 (50 N-2 PICKUP) and the correspond-ing delay T IE>> under 1030 (50 N-2 DELAY).Similar considerations apply for the setting, aspreviously described, for the phase currents.

IE> (earth) or IEp

The minimum occuring earth fault current ismainly decisive for the setting of the overcurrentstage IE> or IEp. If great inrush currents are to beexpected when using the protection relay ontransformers or motors, an inrush restraint can beused in 7SJ62/63/64 for the overcurrent stage IE>or IEp. This is switched on or off for both phaseand earth current together under address 2201INRUSH REST.

The time delay to be set (parameter 1305 T IE>/50 N-1 DELAY or 1308 T /IEp/51N TIME DIAL) isgiven by the grading coordination chart createdfor the power system, whereby a separate gradingcoordination chart with shorter delay times is of-ten possible for earth currents in the earthedpower system.

3.2 Auto-reclosureThe integrated auto-reclosure function can beused for performing reclosures on overhead lines.This can be initiated by every overcurrent stageand other protection functions. External initiationvia binary inputs is also possible. In this way thereclosing function can be adapted individually tothe respective application without external wiring.

A description for setting the most importantreclosure parameters follows:

7105 Time restraint:

The blocking time TIME RESTRAINT (address7105) is the time span following successful rec-losure after which the power system fault is con-sidered cleared. Generally, a few seconds areenough. In regions with frequent thunderstorms ashort lockout time is recommendable, to reducethe danger of final disconnection due to lightningstrikes in rapid succession or cable flashover. Thedefault selection is 3 s.

Fig. 5 DIGSI parameter sheet, inverse time overcurrent protection phase

DIGSI parameter sheet, definite time overcurrent earth protection

LSP2

683.

tif

LSP2

684.

tif



7117 Action time

The action time checks the time between thepickup of a relay and the trip command of a pro-tection function parameterized as a starter, inready (but not yet running) auto-reclosure.If a trip command is received from a protectionfunction parameterized as a starter within the ac-tion time, auto-reclosure is initiated. If this time isoutside the parameterized value of T-ACTION(address 7117), auto-reclosure is blocked dynami-cally. With inverse-time characteristics the releasetime is determined essentially by the fault locationand the fault resistance. With the help of the ac-tion time, no reclosure is performed in the eventof very remote or high-resistance faults with along tripping time.Presetting of ∞ always initiates a reclosure.

7135 Number of reclosure attempts, earth7136 Number of reclosure attempts, phaseThe number of reclosures can be set separately forthe programs “Phase” (address 7136, NUMBER RCPHASE/# OF RCL. PH) and “Earth” (address 7135NUMBER RC EARTH/# OF RCL. GND). The pre-setting for both parameters is 1 (one); one reclosurecycle is therefore executed.

The “configuration sheet” defines which of theprotection stages starts the reclosure. For each ofthe stages it can be decided whether this stagestarts the reclosure, does not start it or blocks itout.

7127 Dead time 1: ph7128 Dead time 1: G

The parameters 7127 and 7128 define the lengthof the dead times of the 1st cycle. The time definedby the parameter is started upon opening thecircuit-breaker (if auxiliary contacts are allocated)or upon reset after the trip command.

The dead time before the 1st reclosure for thereclosure program “Phase” (phase-to-phase fault)is set in address 7127 DEADTIME 1:PH; for thereclosure program “Earth” (single phase-to-earthfault) it is set in address 7128 DEADTIME 1:G.The duration of the dead time should relate to thetype of application. For longer lines the timeshould be long enough for the short-circuit arc toextinguish and de-ionize the ambient air, to allowsuccessful reclosure (usually 0.9 s to 1.5 s). Thestability of the power system has priority in thecase of lines fed from several ends. Since the dis-connected line cannot develop any synchronizingforces, often only a short dead time is permissible.Normal values are between 0.3 s and 0.6 s. Longerdead periods are usually allowed in radial systems.The default is 0.5 s.

DIGSI parameter sheet, auto-reclosure (general)

Fig. 8 DIGSI parameter sheet, auto-reclosure configuration

Fig. 9 DIGSI parameter sheet, auto-reclosure (1st reclosure cycle)

LSP2

561e

n.ti

f

LSP2

686.

tif

LSP2

687.

tif



4. Further functionsAs already described in Chapter 2, a number ofadditional functions can be configured in theSIPROTEC 4 relays. Apart from further protec-tion functions, these also include control tasks forthe feeder. All SIPROTEC 4 relays (e.g. 7SJ61 and7SJ62) have 4 freely assignable function keys F1 toF4 which simplify frequently required operations.These function keys can take the user directly tothe display window for measured values, or tofault event logs for example. If the relay is also tobe used for feeder control, these keys can be usedfor controlling the circuit-breaker. The key F1then selects the ON command for example, key F2the OFF command and key F3 executes the se-lected command (two-stage command output).

The 7SJ63 also has a graphic display on which theindividual feeder mimic diagram can be shown.Separate ON/OFF control buttons ensure safe andreliable local control. An integrated, freely pro-grammable interlock logic prevents switchingerrors.

The switching authority (local/remote) can bechanged and the interlock check overridden bytwo key-operated switches.

Fig. 10 Front view 7SJ61 or 7SJ62

Fig. 11 Front view 7SJ63

Fig. 12 Example of interlock logic

Fig. 13 Front view, key-operated switch withcustomer-specific feeder mimic diagram

LSP2

299.

eps

LSP2

316.

eps

LSP2

565.

tif

LSP2

564.

tif



5. Connection examples5.1 Current and voltage transformersConnection of the protection relays to theswitchgear depends on the number of switchingobjects (circuit-breakers, disconnectors) and cur-rent and voltage transformers. Normally at leastthree current transformers are available per feederwhich are connected to the protection relay as fol-lows.

In some systems, also the earth current is mea-sured by a core-balance current transformer. Thiscan be connected to the protection relay sepa-rately. A core-balance current transformer achie-ves greater accuracy (sensitivity) for low earthcurrents.

If voltages are also available (from the feeder oras a busbar measurement), these can be connectedon 7SJ62/63/64 and then also enable voltage-dependent protection functions (directional over-current protection, voltage protection, frequencyprotection, ...).

5.2 Input/output peripheryIn addition to the current transformers (and ifrequired to the voltage transformers too), at leastthe TRIP command has to be wired to the circuit-breaker. The standard allocation supports this bypractice-oriented preassignment.

Preassignment of the inputs and outputs in the7SJ610:

Binary inputs

BI1 Block definite/inverse timeovercurrent protection

BI2 LED resetBI3 Display lighting on

Binary outputs (command relays)

BO1 TRIP commandBO2 Reclosure commandBO3 Reclosure commandBO4 MV monitoring

Fig. 14 Transformer connection to three current trans-formers

Fig. 15 Transformer connection to three current trans-formers and core-balance CT

Important: The cable shield must be earthed on the cable side!

Note: Reversing the current polarity (address 0201) also reversesthe polarity of the current input IE

Fig. 16 Transformer connection to three current and three voltagetransformers



LEDs

LED1 TRIP commandLED2 PICKUP L1LED3 PICKUP L2LED4 PICKUP L3LED5 PICKUP ELED6 MV monitoringLED7 Not used

The assignment can be changed and the pro-tection parameters set conveniently with theDIGSI 4 operating program. The parameteri-zation data can then be saved and copiedconveniently as a basis for further feeders.

6. SummarySIPROTEC 4 protection relays are suitable for al-most any application due to their modular hard-ware structure and the flexible scope of functions.A suitable relay with the necessary scope can beselected in line with requirements. Factory para-meterization is oriented to typical applicationsand can often be adopted with only small modifi-cations. In the parameter setting with DIGSI, allunnecessary parameters are hidden so that clarityis much improved.

The retrofitting of serial interfaces for subsequentintegration into a substation control and protec-tion system is also possible locally, which reducesdowntimes to a minimum. The functional scopecan also be changed later by “downloading” a neworder number.

Fig. 17 Configuration matrix

LSP2

688.

tif





1. IntroductionLine differential protection systems make it possi-ble to protect cables or overhead lines selectivelyand as fast as possible in the event of a short-circuit. The application domain of the SIPROTEC7SD600 described here is predominantly in themedium-voltage sector if either the tripping timesof graded overcurrent-time protection relays be-come too great, or if distance protection relays areno longer able to guarantee the desired selectivity.

2. Protection conceptThe 7SD600 digital differential protection relayprovides short-circuit protection for cables andoverhead lines in power supply systems, inde-pendent of the system star-point configuration. Itworks according to the conventional 2-conductorsprinciple. Here, the phase currents at the two line-ends are – with the help of summation currenttransformers – added up to one summation cur-rent. These are then transformed by voltage divid-ers into proportional voltages, which are fed withreversed polarity to two pilot wires. The resultantvoltage difference finally produces a current,which represents the determinant tripping magni-tude for both relays. Because of its rigorous localselectivity (the protection range is limited by cur-rent transformers at both ends of the line), differ-ential protection is generally applied as aninstantaneous main protection since no otherprotection can disconnect the line more quicklyand selectively.

2.1 Differential protection (ANSI 87L)2.1.1 Principle and current transformer

connectionThe differential protection function of the 7SD600recognizes short-circuits in the protection rangeby comparing the summation currents detected atboth ends of the line. In order to do this, the sec-ondary phase currents from the primary currenttransformers are fed with variable weighting(number of windings) into the summation cur-rent transformer which combines them to pro-duce a summation current.

Differential Protection ofCables up to 12 km viaPilot Wires(Relay Type: 7SD600)

This also assumes, that current transformers withidentical primary values are used at both ends,otherwise the variable windings ratio must beequalized by an appropriate arrangement of thematching transformer and/or summation currenttransformer.

Fig. 1 SIPROTEC 7SD600 line differential protection relay

Fig. 2 Principal circuit diagram of line differentialprotection 7SD600

LSP2

001.

eps



2.1.2 Summation current transformersThe 4AM4930 summation current transformer isinstalled as standard in the normal circuit.

This summation current transformer has differentprimary windings with several tapping points al-lowing phase current and connection type (for ex-ample two-phase) mixing ratios to be varied. Thisway, increased sensitivities (e.g. of the earth cur-rent) or preferences in the case of double earthfault can be neatly ensured.

Fault W W / 3 I1 for IM = 20 mA

L1-L2-L3 (sym.) 3 1.0 1 x IN

L1-L2 2 1.15 0.87 x IN

L2-L3 1 0.58 1.73 x IN

L3-L1 1 0.58 1.73 x IN

L1-E 5 2.89 0.35 x IN

L2-E 3 1.73 0.58 x IN

L3-E 4 2.31 0.43 x IN

Table 1 Fault types and winding valencies W in caseof normal connection L1 - L3 - E

The selected summation current transformer con-nection must be implemented identically at bothends of the line to avoid false tripping.

2.1.3 Differential currentWith normal summation current transformerconnection and symmetrical current flow (ratedquantity), 20 mA flow to the summation currenttransformer on the secondary side. This summa-tion current is now measured in the local 7SD600,and also fed as voltage drop to two pilot wires viaan internal resistor of the protection relay. At theremote end the summation current is formed inthe same manner and also fed as voltage drop toboth pilot wires, but this time with reversed pola-rity.

In healthy state, the reverse polarity voltagesshould neutralize each other out. However, underfault condition there is in the case of differentsummation currents a resulting voltage which willdrive a current (proportional to the theoreticaldifferential current) along both wires. This cur-rent is then measured by the protection relay andserves as a tripping parameter.

2.1.4 Transformers in the protected zoneThe 7SD600 optionally also analyses the summa-tion currents for a component of 100 Hz. Thismakes it possible to expand the protection rangebeyond a transformer. Additional external match-ing transformers must nevertheless ensure, thatthe transformation ratio of the currents and theirphases is compensated analagously to the trans-former.

2.1.5 Restraint currentIn order to stabilize the differential protection sys-tem against overfunction (unwanted operation) inthe event of external faults, the “differential cur -rent” tripping parameter is standardized to a sta -bilization parameter. The latter is the sum of themagnitudes of the currents detected at both endsof the protection range. This stabilization meansthat in the event of large currents flowing throughand of measurement errors resulting from trans-former faults or transformer saturation, the trip-ping parameter must likewise be high.

Measuring the local summation current trans-former secondary currents and the current flow-ing through the pilot wires ensures, that each ofthe two protection relays can calculate both thedifferential and stabilizing currents and react ac-cording to the tripping characteristic.

Fig. 3 4AM4930 summation current transformer normalconnection

Fig. 4 Function diagram



2.1.6 Tripping characteristicThe 7SD600 tripping characteristic consists ofthree sections. In the area of small currents a fixedtripping threshold settable as parameter must beexceeded in order to ensure response. Both theother tripping characteristic branches have set de-faults. Current-proportional transformer faultsrise as the current magnitude increases. This istaken into account in the tripping diagram with asection of a straight line through the origin with a1/3 gradient (slope). In the case of even greater cur-rents the tripping limit is determined by a furtherstraight line, which intersects the stabilization axisat 2.5 · INLine and has a gradient of 2/3. This branchtakes account of incipient current transformer sat-uration.

IDiff = |I1 + I2|IRestraint = |I1| + |I2|I1 = Current at local line end, positive flowing into lineI2 = Current at remote end, positive flowing into lineIN Line = Line rated current

In order that differential protection remains stablein the case of external faults with strong currents,the 7SD600 offers additional stabilization with re-gard to possible transformer saturation. Here, onthe basis of the stabilization and differential cur-rent trend, the protection recognizes that an exter-nal fault initially occurred before the build-up ofthe differential current as a result of transformersaturation. When the current values enter the ad-ditional stabilization (restraint) range, the differ-ential protection is blocked for a maximum of1 second in order to give the transformer time tocome out of saturation. However, if during thistime steady state prevails in the tripping range fortwo network periods, blocking is neutralized andthe protection makes the decision to trip.

2.1.7 Pilot wiresSymmetrical telecommunication wire pairs (typi-cally 73 Ω/km loop resistance and 60 nF/km ca-pacity) with a wire/wire asymmetry (at 800 Hz) ofless than 10-3 are suitable. The loop resistance maynot exceed 1200 Ω. Furthermore, the longitudinalvoltage component induced in the pilot wires bythe short-circuits (to earth) must be taken into ac-count. The induced direct axis voltage componentcan be calculated according to the following for-mula:

U ll f M I= ⋅ ⋅ ⋅ ⋅ ⋅2 1 2π k1 r r

whereUl = Induced direct axis voltage componentƒ = Rated frequency [Hz]M = Mutual inductance between power cable and

pilot wires [mH/km]Ik1 = Maximum single-pole short-circuit current [kA]l = Length of the parallel distance between power

cable and pilot wires [km]r1 = Reduction factor of the power cable

(in case of overhead lines r1 = 1)r2 = Reduction factor of the pilot wire cable

The calculated induced voltage needs only be halftaken into account since it builds up on the insu-lated pilot wires at both ends. If this exceeds 60 %of the permitted test voltage, additional measures(isolating transformers) are necessary. Isolation(barrier) transformers are available for isolationup to 5 kV and 20 kV respectively. The center tapon the side facing the protection relay must beearthed for anti-touch protection reasons, but thepilot wire connection must not be earthed or pro-vided with surge arresters.

2.2 Backup protection functions (ANSI 50)As is usual with modern, numerical protection re-lays, the 7SD600 also offers further integrated pro-tection and additional functions. The user mustnevertheless be aware of the lack of hardware re-dundancy when deploying these functions. Forthis reason, at least a further separate short-circuitprotection relay, for instance a 7SJ602, should beinstalled.

Fig. 5 Restraint characteristic of the differential pro-tection drawn with a default of IDiff> = 1.0 · IN Line

Fig. 6 Connection of isolating transformers 7XR9515 (5 kV) or 7XR9513 (20 kV)



2.2.1 Overcurrent-time protection (ANSI 51)The 7SD600 includes overcurrent-time protectionalongside differential protection as an emergencyfunction, i.e. for cases where the main function isno longer available. Parameterization makes itpossible to set whether the emergency definite-time overcurrent protection should generally beactivated when differential protection is ineffec-tive, or only if the wire monitoring responds. Thisemergency definite-time overcurrent protectionworks with the local summation current and fea-tures one single stage. The current threshold is setabove the maximum symmetrical load current.Since in general no time grading is possible if fullselectivity is to be retained, a compromise betweenselectivity and speed of protection has to befound. In any case the tripping time should be de-layed by at least one grading, in order to wait tosee whether this high current is caused by faultson adjoining power system sections and otherprotection relays selectively trip upon this fault.

2.2.2 Additional functionsPilot-wire monitoring

The ohmic resistance of the pilot-wire loop isneeded for correct calculation of the summationcurrent at the remote end of the protection range.This current is comfortably determined with thehelp of DIGSI during commissioning and enteredinto the protection relay parameters. Because nodifferential voltage and thus no differential cur-rent occur in flowing currents during normal op-eration, monitoring of the pilot-wire connectionis strongly advised. Audio frequency signals aremodulated onto the connection line.

Intertripping, remote tripping

In the event of protective tripping at the local end,an intertrip signal can be sent to the remote end(using the same transmission equipment) in orderto isolate the faulted line. The remote tripping sys-tem, in which a signal coupled via binary input isinterpreted as a shutoff command for the circuit-breaker on the remote end, works according to thesame pattern. Here too an audio frequency signalis transmitted to the partner relay, as with inter-tripping.

3. SettingsThe parameter settings of both relays of the differ-ential protection system differ in only a fewpoints. This is the reason why only the 7SD600settings of one line end are explained initially.

The differences are explicitly listed towards theend of this chapter.

The 7SD600 is notable for its few setting parame-ters, which allow it to be configured quickly andeasily. Pilot-wire monitoring is the only functionthat can be activated (or deactivated) under“Scope of the device”, provided the relay has beenordered with this option. This must be activated.

3.1 System /line dataThe parameters defined by the primary equipmentare set under the “system/line data” heading (seeFig. 7). These include network frequency, currenttransformer ratio and minimum circuit-breakeractivation time in the event of protective tripping.In order to better match the differential protec-tion characteristic, the protection parameters arereferred to the line rated current; this must be in-put at this point and must imperatively be thesame in both relays. As already described above,the resistance of the pilot-wire connection is re-quired for correct calculation of the current valueat the remote end. This can be calculated eitherfrom the pilot-wire connection data sheets or canbe measured within the context of commissioningby the relay itself in accordance with the instruc-tions in the manual. This value must subsequentlybe entered here. Finally, the lock-out function canbe switched either on or off at this point. The acti-vated lock-out function requires an acknowledge-ment of the TRIP command via the acknowledge-ment button on the relay or by the setting of abinary input, e.g. by using an external switch.

3.2 Line differential protection3.2.1 Line differential protectionAs with all protection functions, the differentialprotection can be switched either on or off at thispoint in order to simplify function-selective test-ing. Additionally, there is the option to set theseparameters to “indication only”, so that for exam -ple at the time of commissioning all indicationsfor this protection function are logged, but notripping occurs. The differential protection func-tion must of course be switched on for normaloperation. Regarding the differential protectionfunction, only the tripping threshold IDIFF> mustbe set (referred to the line rated current).

Fig. 7 Settings for “Power system data”

LSP2

746.

tif



Referred to the summation current, this valuemust thus lie below the minimum short-circuitcurrent but above the inrush current and thetransformer faults of the primary and summationcurrent transformers, taking the weighting factorsfor the various fault types into account. The presetvalue of 1.0 ⋅ I /IN,Line has proved over many yearsto be a stable empirical figure. Taking account of aweighting factor of more than 2 for single-polefaults, this corresponds to barely five times an ac-cepted charging current of 10 % referred to IN,Line.

Should 5 times the charging current be above thisvalue, IDIFF> must be increased.This charging current is calculated according tothe equation:

IC = 3.63 · 10-6 · UN · fN · CB’ · s

IC = Charging current to be ascertained in A primaryUN = System rated voltage in kVfN = System rated frequency in HzCB’ = Operating capacity of the line in nF/kms = Line length in km

3.2.2 Blocking with second harmonicA transformer may also be situated within the7SD600 protection range. However, in this casethe transformer ratio must be recreated with ex-ternal matching transformers, so that the currentmagnitude and phase angle of the summationcurrent transformer inputs correspond on bothsides of the transformer. For this application it isnecessary to stabilize the differential protection inrelation to the transformer inrush. Because notransformer is located within the protection range,blocking of the differential protection is deacti-vated by means of the second harmonic. Conse-quently, the tripping threshold set values for boththe second harmonic and the maximum differen-tial current (which is blocked by this function) areirrelevant.

3.2.3 TRIP delayIn certain applications (e.g. reverse interlocking),it can be necessary to delay the differential protec-tion somewhat. This delay can be set at this point.

3.2.4 Local current thresholdA local current threshold (which must be ex-ceeded) can be set as a further tripping conditionat the local end. With the preset value 0 ⋅ IN, Line

the protection relays trip at both ends if the differ-ential protection responds. The local currentthreshold can be raised if, for example, in the caseof single-side infeed, the remote end (from whichno current is feeding onto the fault) should not betripped.

3.2.5 Intertrip functionNormally, tripping is effected at both stations as aresult of current comparison. Tripping at one endonly can occur when an overcurrent release isused or with short-circuit currents only slightlyabove the tripping value. Circuit-breaker inter-tripping can be parameterized in the unit with in-tegral pilot-wire monitor, so that definite trippingat both ends of the line is assured.

3.2.6 Differential protection blocking(spill current)

This differential current monitoring functionreacts to a permanently low differential current,which can be produced by phase failure at thesummation current transformer (e.g. due to wirebreak) and blocks the differential protection func-tion. The threshold (parameter 1550) is set slightlyover the capacitive losses of the pilot wires, whichat a power system frequency of 50 Hz can beestimated according to

Ispill (%) = 0.025 ⋅ IN, Line ⋅ lLine (km)

With a line length of 12 km, this gives a value of0.3 ⋅ IN, line for the spill current. In order to preventspurious tripping, the parameter is set at0.4 ⋅ IN, line. In accordance with the default (preset)value, monitoring is delayed by 5 seconds.

3.3 Pilot wire monitoringPilot wire monitoring is extremely important formonitoring the capability of the differential pro-tection system. Since in fault-free operation, par-ticularly where operating currents are low, noappreciable differential current occurs (due totransformer and measurement inaccuracies), wirebreak or short-circuit would not be noticed,which would lead to protection malfunction. Thusthe pilot-wire function will be activated and thereaction of the protection will be defined. When aconnection fault is recognized, the differentialprotection can be blocked or the fault can simplybe reported – after an adjustable delay time.

Fig. 8 Setting the differential protection function

LSP2

658e

n.ti

f



In order to begin the communication betweenboth relays in a defined manner, the station iden-tification must be set differently. One 7SD600 isparametrized as master, the other as slave.

3.4 Overcurrent-time protectionEmergency overcurrent-time protection can beactivated either in the event of a recognized pilot-wire fault or generally when the differential pro-tection is deactivated. The local summation cur-rent must likewise be used as a measuring quantityand the setting must be referred to the line ratedcurrent. Here too, when setting the current thres-hold, the weighting factors for the various faulttypes must also be taken into consideration. Thecurrent thresholds are set – as far as possible – be-tween maximum operating current and minimumshort-circuit current. The associated delay time isadjusted to the network grading plan as closely aspossible, in order to maximize selectivity.

3.5 Remote tripping/Transfer tripA signal injected via binary input (e.g. from thecircuit-breaker failure protection) can be trans-mitted as an audio-frequency signal to the remoteend through the pilot wires in order to effect trip-ping of the circuit-breaker there. Thus reliabletransmission is ensured even when pulses are veryshort. The transmission duration can be pro-longed. The protection relay at the remote endmust be appropriately set for the reception of aremote tripping signal, i.e. the “transfer trip”function must be switched on.

To avoid an overfunction, tripping can be delayed.Hence, a transient signal will not lead to a misin-terpretation. In order to ensure reliable trippingeven when a short signal is received, the transfertrip signal can also be delayed until the circuit-breaker opens. The preset values are intended toensure remote tripping.

3.6 Relay at the remote endThe parameter settings of the second 7SD600,which is installed at the remote line end, are to thegreatest possible extent identical to the relay de-scribed here. The identical summation currenttransformer connection and the same set value forthe line rated current are essential. All further pa-rameters can normally be taken over by the localrelay; however, under the key term “pilot-wiremonitoring”, the station identification of “mas -ter” has to be changed to "slave” so that this pa -rameter is set differently in both relays.

4. SummaryUndelayed and at the same time rigorously selec-tive protection of cables and lines reduces theconsequences of unavoidable power system dis-turbances. For one this means protection of theequipment, and secondly a contribution to a max-imized level of supply security.

A differential protection system consisting of twoSIPROTEC 7SD600 relays and the associatedsummation current transformers offers compre-hensive protection of cables and overhead lines.Extensive additional functions allow trouble-freeconnection of the relays and integration into com-plex power system protection grading.

The default settings of the relay are selected insuch a way, that the user only has to configure theknown cable and primary transformer data. Manyof the preset values can be taken over with noproblem and thus substantially reduce effort in-volved in parameterization and setting.

Fig. 9 Settings of the pilot-wire monitoring for the localrelay (master)

Fig. 11 Settings of the pilot-wire monitoring for the relay at theremote end (slave)

LSP2

660e

n.ti

fLS

P265

9en

.tif

Fig. 10 Settings of the pilot-wire monitoring“Emergency overcurrent-time protection”

LSP2

692.

tif



20 kV single-core cross-linked polyethylene ca-ble N2XS(F)2Y 1x120RM/16

Resonant-earthed system Fiber-optic link ANSI 87L differential protection ANSI 50/51 definite-time overcurrent-time

protection as backup protection ANSI 50HS instantaneous high-current

switch-onto-fault protection ANSI 49 thermal overload protection

1. IntroductionThe ever higher load imposed on primary equip-ment requires it to be protected in a selectivemanner and fast fault clearing in case of a short-circuit, in order to minimize possible consequen-tial damage resulting from faults. For overheadlines and cables this requirement is met by linedifferential protection relays.

A full example of how to set SIPROTEC 4 7SD610protection relays for a power cable in the distribu-tion network is described, in addition to notes ondesign.

2. Protection conceptThe 7SD610 numerical differential protection re-lay is a modern short-circuit protection relay forcables and overhead lines in power supply system.Due to rigorous local selectivity – the protectedzone is limited at both ends of the line section –power system topology and voltage levels play norole. Furthermore, the star-point conditioning ofthe current network is of no significance as cur-rent comparison takes place per phase and thusvariable weightings for different faults – as theyoccurred in the conventional summation currenttransformer differential protection process – arenowadays unimportant. Due to its selectivity, thedifferential protection is generally set as an unde-layed, instantaneous main protection since noother protection can disconnect the line morequickly and selectively.

2.1 Differential protection (ANSI 87L)The differential protection function of the 7SD610detects short-circuits using phase-selective com-parison of the current values measured by sepa-rate relays at both ends of the line in the zone tobe protected, including weak current or high-re-sistance short-circuits.

Differential Protection ofCables via Fiber Optics(Relay Type: 7SD610)

Each 7SD610 compares locally measured currentvalues with those from the remote end and de-cides independently whether there is a system dis-turbance or not. A communication link betweenboth relays is required to exchange the measuredvalues. The relays are designed for a fiber-opticlink, which is the preferred method. System-testedcommunication converters for other transmissionmedia (copper conductors, ISDN line, digitalcommunication networks with X21 or G703.1)are nevertheless also available.

Fig. 2 Differential protection for a line

LSP2

638.

tif




The differential protection function implementedin the 7SD610 uses two algorithms in order tomeet the demands of speed and sensitivity. Thecharge comparison process integrates the meas-ured currents and compares the charge values atboth ends over a short time interval. This simpleprocess makes it possible to detect high-currentfaults as quickly as possible.

This crude algorithm is complemented by a sub-stantially more sensitive vector comparison pro-cess. In this process, the current vectors per phaseof both relays are compared with each other ateach sampling time point. In particular, the errorsfor each measured value during the process areconsidered. This includes the current measuredvalue error based on the stored transformer data.The error consideration also takes into accountboth the signal transmission time of the mea-sured-value telegram from the partner relay andthe cable charge current. Finally, each protectionrelay can decide whether its own (directly mea-sured) current value corresponds to the measuredvalue received by telegram from the remote endvia the functional interface, including all magni-tude and phase errors. If this is not the case, a fur-ther (fault) current must be responsible for thedifference and the 7SD610 decides on tripping.

Converted to the conventional characteristic, thismeans that the restraint current is not simplyformed as the sum of the magnitudes of the cur-rents measured at both ends, but as the sum of theerrors described above plus the minimum trippingthreshold IDIFF>, which are converted into a singlecurrent component. Protective tripping occurs atthe moment when the differential current is grea-ter than the adaptively formed restraint current.

In order to ensure reliable operation of the differ-ential protection system, the current transformersdeployed must comply with the followingrequirements:

1st condition:When the maximum short-circuit current isflowing through, current transformers may notbe saturated in steady state.

nI

Kd max

N prim

'≥I

2nd condition:The operating overcurrent factor n' must be atleast 30 or a saturation-free time t'AL of min ¼period is ensuredn' ≥ 30 or t'AL ≥ ¼ period

3rd condition:Maximum mutual ratio of the current trans-former primary rated currents at the ends of theobject to be protectedI

Iprim

prim min

max ≤ 8

2.2 Backup protection functionsAs usual with modern, numerical protectionrelays, the 7SD610 also offers a range of furtherprotection and additional functions, which makeit flexibly customizable for almost all uses. Theuser must nevertheless be aware of the lack ofhardware redundancy when deploying these func-tions. For this reason at least one additional, sepa-rate short-circuit protection relay should beinstalled. Depending on voltage level and/or im-portance of the line, this can be a separate distanceprotection (7SA6) or a definite-time overcurrent-time protection relay (7SJ6).

The overcurrent-time protection included in the7SD610 should therefore only be used as backupprotection against external faults in the powersystem outside the differential protection zone.

2.2.1 Overcurrent-time protection (ANSI 50/51)Parameterization makes it possible to specifywhether the three-stage overcurrent-time protec-tion included in the 7SD610 should be workingpermanently as an independent protection func-tion (backup), or whether it should only be acti-vated as an emergency function in case of mal-function in the communication link.

As mentioned above, if the backup function is used,the concept of hardware redundancy must not beneglected. Consequently, the backup definite-timeovercurrent-time protection function is recom-mended primarily for protection outside the differ-ential protection area, such as e.g. protection of anincoming feeder panel in a substation.

Fig. 3 Differential protection tripping characteristic



Two of the three stages (I> and I>> stage) areconfigured as incoming feeder protection in thiscase. It has only been possible to authorize and setthe I>>> stage in such a way, that it trips high-current faults quickly in this exceptional situation,losing the selectivity. If the overcurrent-time pro-tection is used as an emergency function, all stagescan be set in terms of tripping threshold and delaytime for this exceptional case, in line with selectiv-ity and speed.

2.2.2 Instantaneous high-current switch-onto-fault protection (ANSI 50HS)

This function is meant to disconnect immediatelyin the event of single-end switching onto a high-current short-circuit.The measured values of each phase, filtered to thefundamental component, are compared with theset threshold.If the measured value exceeds twice the threshold,protective tripping occurs immediately. For thisfunction, the circuit-breaker position of the re-mote end must be known.

A further stage of this protection function workswithout data on the status of the circuit-breaker atthe remote end, but can only be used if currentgrading above the object to be protected is possible.

2.2.3 Thermal overload protection (ANSI 49)The thermal overload protection prevents over-loading of the object. In the case of the 7SD610,this function is used specifically for a transformersituated within the protected zone, but is also ap-propriate for power cables that are working to fullcapacity.

The 7SD610 uses a thermal model to calculate(from the measured phase currents and from theset parameters that characterize the object to beprotected) the temperature of the equipment. Ifthis temperature exceeds an adjustable threshold,the 7SD610 issues a warning message, and if a sec-ond, higher threshold is exceeded, the protectiontrips.

2.3 Additional functionsThe additional functions listed in the followingare not used in the example given and are there-fore only mentioned for the sake of completeness.

Automatic reclosure makes it possible toquench arc short-circuits on overhead lines by abrief interruption of the current flow, i.e. notnecessarily immediately and fully disconnectingthe line.

The breaker failure protection in the 7SD610has two stages. If a TRIP command issued by aprotection relay does not lead to the fault cur-rent being shut off, the 7SD610 can initially re-peat the TRIP command before, at the secondstage, the higher-level protection is informed ofthis malfunction by parallel wiring and trips thecircuit-breaker allocated to it.

The 7SD610 supports three-pole and sin-gle-pole circuit-breaker activation, requiredparticularly frequently on the high-voltage level,thanks to its phase-selective operation.

Transformers and shunt reactors in the differ-ential protected zone are also governed by inte-grated functions.

By means of a connected binary input, a TRIPcommand can be generated by the 7SD610 viaan external coupling.

The digital communication link of the R2Rinterface makes it possible to transfer 4 remotecommands and 24 remote messages from onerelay to the other and process them individuallyin that relay.

Because the 7SD610 also has voltage inputs, theline-to-earth voltages of the three phases and,where applicable, the shift voltage can be con-nected to the relay. This does not affect theprotection function, but makes it possible to de-tect the measured voltages and to calculate withthe current measured values the derived electri-cal magnitudes such as active power, reactivepower, apparent power, cos ϕ (power factor)and frequency.

3. Setting example:As an example, the settings of the 7SD610 relaysare described, such as are intended to protect a20 kV single-core XLPE cable of type N2XS(F)2Y1x120RM/16 with a length of 9.5 km. The cablerated current is 317 A, on side 1 a new 400 A/1 A,10P10, 5 VA current transformer is used, and anexisting 300 A/5 A, 10P20, 30 VA current trans-former is located at the remote end. The maxi-mum short-circuit current flowing through is12.7 kA.



3.1 Checking the transformersInitial checks must be made to ascertain whetheror not the transformer requirements are met. Thequotient of the primary side transformer ratedcurrents evidently amounts to 400 : 300; a valuesmaller than 8 is thus achieved.

The operational overcurrent factor is calculatedfrom the formula

n n N i

i

''

= ⋅ ++

P P

P P

Equation 1

n’ = Operational accuracy limiting factorn = Rated overcurrent factorPN = Rated burden of the current transformers [VA]Pi = Inherent burden of the current transformers [VA]P’ = Actual connected burden [VA]

The current transformer’s own inherent load iscalculated from

Pi = Ri · IN,CT2

Equation 2

If Ri (the transformer’s secondary winding innerresistance) is unknown, the estimation ofPi = 20 % ⋅ PN is a good approximation. To arriveat the actually connected burdens, all burdensconnected to the transformer core must be added.In this example, it is assumed that only the bur-dens of the protection relay (0.05 VA for relayrated current of 1 A, 0.3 VA for relay rated cur-rent of 5 A) and the incoming feeder cable loadare concerned.

The latter is calculated from the formula

Pl

aLine

Cu Line

Line

= ⋅ ⋅2 ρ

Equation 3

PLine = Incoming feeder cable load [VA]ρCu = Specific resistance of Cu [ 0.0175 Ω mm²/m]lLine = Secondary-side, single line length [m]aLine = Line cross-section [mm²]

It is clear from equation 2, that with a second-ary-side transformer rated current of 5 A, an in-coming feeder cable load 25 times higher appearsthan for 1 A.

For our example, a 5 m incoming feeder cable(single distance, therefore factor 2) with a cross-section of 4 mm² is assumed. From this we cal-culate an incoming feeder cable load for bothtransformers of 0.045 VA (transformer 1) and1.116 VA (transformer 2).

The overcurrent factors for both transformers arenow calculated from these values. According toequation 1 for transformer 1 we have

n’ = 44.6

and for transformer 2

n’ = 97.1.

These values must now be greater than or equalto the required overcurrent factors in order to beable to transmit the maximum through-flowingshort-circuit current at a level of 12.7 kA in asaturation-free manner.

The following are required for transformer 1

n’ > 12700 A/400 A = 31.75

and for transformer 2

n’ > 12700 A/300 A = 42.33.

In both cases this is clearly achieved, as is the thirdcondition n’ > 30. Consequently, the transformersavailable are suitable for use in this differentialprotection system.

3.2 Local relay settingsThe parameter settings of both the differentialprotection relays usually differ only in a fewpoints. This is why only the settings mentioned atthe beginning of this application example of a7SD610 are explained initially. The settings to bechanged of the second relay are explicitly listedtowards the end of this chapter. Initially, usingthe DIGSI 4 software for configuration, the 7SD6relay with Order No. 7SD6101-4BA39-0BA0+M2Cis applied and opened in the current project.

3.2.1 Functional scopeIn the next step the parameters, beginning withthe “functional scope”, are set. At this point, wedetermine which of the functions provided by theprotection relay should be used. The other func-tions are set at “not available” and are conse -quently concealed for the remainder of the relayparameterization. For our example, we have se-lected differential protection as the main protec-tion function together with overcurrent-timeprotection, instantaneous high-current switch-onto-fault protection and overload protection.

Fig. 4 “Functional scope” menu item settings

LSP2

661.

tif



3.2.2 Power system dataIn the section called “power system data 1”, theparameters defined by the primary equipment areset. These are in particular the current transfor-mer transformation ratio (400 A/1 A), the posi-tion of its star (neutral) point (assumed to be“on the line side”) as well as the rated frequency(50 Hz) of the power supply system.

On the next card the minimum and maximumcircuit-breaker trigger times are input in order toensure the execution of switching commands.

Next, three parameters must be set. These charac-terize the current transformer in terms of its char-acteristic progression and also define differentialprotection sensitivity.

Broadly, due to transformer faults, the influenceof current-proportional measuring accuracy canbe divided into two areas, which are separated onthe current scale by the quotients n’/n. These per-centage error values are dependent on the trans-former class and can be taken from the Table 1below. The footnote demonstrates that the quo-tient n’/n should be set at a maximum of 1.50,which corresponds to a “defensive” setting thatprematurely migrates to the higher error influenceand thereby increases the self-restraint.

The preset values were defined under the same as-pect. They refer to a transformer in the “10P” classand also lie “on the safe side” for the quotients.These preset values can be left for all currenttransformer types. Under certain circumstances,some of the potentially very high differential pro-tection sensitivity may be lost.

For our example this means, that the presettingfor both error values are suitable; the quotient canbe increased to the set value of 1.50, since in thiscase n’/n = 4.46 is clearly over the recommendedmaximum value of 1.50.

Fig. 5 “Power system data/Transformer data” menu itemsettings

Fig. 6 Current transformer fault approximation

Transformerclass

Standard Error at rated current Error at ratedovercurrentfactor

Setting recommendations

Transformation Angle Address 251 Address 253 Address 254

5P IEC 60044-1 1.0 % ± 60 min ≤ 5 % ≤ 1.501) 3.0 % 10.0 %

10P 3.0 % – ≤ 10 % ≤ 1.501) 5.0 % 15.0 %

TPX IEC 60044-1 0.5 % ± 30 min ε ≤ 10 % ≤ 1.501) 1.0 % 15.0 %

TPY 1.0 % ± 30 min ε ≤ 10 % ≤ 1.501) 3.0 % 15.0 %

TPZ 1.0 % ± 180 min± 18 min

ε ≤ 10 %(only I ∼)

≤ 1.501) 6.0 % 20.0 %

TPS IEC 60044-1BS: Class X

≤ 1.501) 3.0 % 10.0 %

C100 toC800

ANSI ≤ 1.501) 5.0 % 15.0 %

Table 1 Current transformer data setting recommendations

1) If n'/n ≤ 1.50, then setting = calculated value;if n'/n > 1.50, then setting = 1.50.

LSP2

662.

tif



When parameter set switchover is deactivated,only the “parameter set A” is available for the fur -ther settings. Under “power system data 2”, onlythe rated operating current of the line (317 A), aswell as correct line state recognition and connec-tion recognition details, are set. At this point therated operating current of the object to be pro-tected (i.e. the power cable) in particular can devi-ate from the transformer rated current. The ratedoperating current must be set identically for both7SD610 relays, since this value is the basis for thecurrent comparison at both ends.

3.2.3 Differential protection settingsThe differential protection is parameterized andset in a few steps as the main 7SD610 protectionfunction. As in the case of all protection functionsincluded in the scope, the differential protectioncan once again be switched either on or off at thispoint in order to simplify function-selectivechecking. The differential protection functionmust be switched on as a matter of course fornormal operating status.

Concerning the differential protection function,only five parameters need be set in the examplegiven. In particular, two discrete pickup thresh-olds (IDIFF> and IDIFF>>) of the differential pro-tection function are set. Both these values deter-mine the pickup thresholds of both protection al-gorithms (described above) of the differential pro-tection function.

1233 IDIFF>>: Pickup value

The IDIFF>> value defines the charge comparisontripping threshold, which decides on tripping veryquickly in the event of high-current faults. Thisvalue is usually set at rated operating current. Inthe case of a resonant-earthed power system, thesetting must not be below the non-compensatedearth-fault current. Otherwise the starting oscilla-tion on occurrence of an earth fault could lead to(unwanted) tripping. Consequently, the Petersencoil rated current provides a good guide for set-ting the IDIFF>> threshold if this lies above therated line current.

1210 IDIFF>: Pickup value

The IDIFF> stage corresponds to the trippingthreshold of the actual current comparison pro-tection and is set at approximately 2.5 times thecharge current. This charge current is calculatedaccording to the equation:

IC = 3.63 · 10-6 · UN · fN · CB’ · s

IC Primary charge current to be calculated [A]UN Power system rated current [kV]fN Power system rated frequency [Hz]CB’ Line operating capacity [nF/km]s Line length [km]

The data for the single-core oil-filled cable to beprotected are: CB’ = 235 nF/km, s = 9.5 km

At a rated voltage of 20 kV and a power systemfrequency of 50 Hz, a charge current of 8.1 A iscalculated from the above equation. Conse-quently, a set value of 20.3 A (primary) arises forIDIFF> or, in the case of a current transformer ratioof 400 A/1 A, a secondary value of 0.05 A. Thisfigure is below the minimum threshold setting of0.10 A (secondary). The “safe side” was once againsought with the preset value of 0.30 A. This figureresults from the assumption of three times thecharge current at a level of 10 %, referred to ratedcurrent. In the case of transformers with compa-rable response qualities and which – in the eventof external faults – transmit the maximumthrough-flowing current while remaining unsatu-rated, this threshold can also be lowered to as littleas 0.10 A. With various transformer types (e.g.iron-core and linear), the preset value remainsunchanged, in order to ensure protection stabilityagainst transients in the event of external faults.

In this case, on comparable transformers withgood response (n’ high), a setting of 0.10 A or –with a safety margin – of 0.20 A is possible. If2.5 times the charge current is greater than 0.30 A,the higher value must clearly be set.

When comparing the apparently very sensitivepreset value of 0.30 A with customary differentialprotection settings (IN), the different failure typeweighting prevailing in the latter must be takeninto account. Single-pole faults are often detectedby the summation current transformer circuitwith a sensitivity higher by a factor close to 3,which would also correspond to a IDIFF> thresholdclose to 0.30 A.

Fig. 7 Settings in the menu item “Power system data1-I- CT characteristic”

LSP2

663.

tif



Further differential protection functionparameters (settings)

Three further parameters also exist for finer ad-justment of the differential protection function.

First, there is the possibility to raise the IDIFF>pickup threshold when the line is switched in.This is recommended when long off-load cablesor overhead lines are energized. In order to avoidcausing pickup of the differential protection inthis case, this parameter IDIFF> SWITCH ONshould be set at approximately 3.5 times thecharge current, provided that this value is greaterthan IDIFF>. Tripping of the current comparisonprotection should only be delayed in exceptionalcases and it is therefore advisable to leave the pre-setting for T-IDIFF> unchanged at 0.00 s. In a reso-nant-earthed system however, in the event ofsingle-pole pickup, a delay is recommended in or-der to avoid tripping due to the earth-fault igni-tion process. A delay of 0.04 seconds has provedsuitable.

Because it is not necessary to take a transformerinto account in the range of the differential pro-tection system, the transient rush restraint may re-main deactivated. All further parameter settings ofthis small card are consequently irrelevant.

3.2.4 Setting the communicationBoth 7SD610 relays communicate via a fiber-optic link laid parallel to the power cable. With asection length of 9.5 km, a fiber-optic cable with9/125 µm mono-mode fibers is used. This com-munication link also requires a few parametersettings, which means that the presettings in the“R2R interface” section can generally be left un-changed.

As already mentioned, data (i.e. predominantlythe current measured values) is transmitted be-tween the two relays by telegram. Individual erro-neous or missing telegrams pose no problem sincethey are counted for statistics purposes, but areotherwise ignored. However, if such an error sta-tus remains over long time periods and an initialtime threshold is exceeded, a link malfunction isreported. At a second, higher threshold, this is rec-ognized as a link failure (outage). It is also possi-ble to set the length of time for which transmittedremote signals should retain their “old” statuswhen a link malfunction is recognized.

In the "CT 1” card file, the R2R interface is acti-vated and the type of communication connection,in this case “fiber-optic cable direct”, is selected.Further parameters can be left at the presettings.

Fig. 8 Settings in the menu item “Settings group A –Differential protection – Diff protection”

LSP2

664.

tif



Under the concept of "differential protection to-pology” the relays must now be assigned the iden -tification number “n”. This differential protectionsystem consists of two 7SD610 relays. One of thetwo relays must be set as “relay 1”, the other as“relay 2”. The difference lies in that the absolutechronology management of the system conformsto relay 1. Relay 2 adjusts itself accordingly andconsequently the time data of both relays is alwayscomparable. Since both the relays could also belinked to each other via a digital communicationnetwork in which more than one differential pro-tection system is communicating, each relay canin addition have a relay identification number as-signed to it. This may only be used once in thecommunication network. Both these addressesmust be set identically in both relays. In our ex-ample of a direct fiber-optic link, no adaptation ofthe identification numbers is necessary.

3.2.5 Backup protection functions3.2.5.1 Instantaneous high-current

switch-onto-fault protectionThis function is only operative if the cir-cuit-breaker at the remote end is open and the lo-cal 7SD610 is informed of this via the communi-cation link. Assuming that the function is acti-vated in both relays, the data relating to the cir-cuit-breaker position must also be detected bythe local 7SD610. For this purpose the data items00379 “>CB 3p Closed” and 00380 “>CB 3p Open”in the allocation matrix in the “power system data 2”data group must be combined with the associatedbinary inputs. The pickup threshold for the I>>>stage should be set at the approximate charge cur-rent of the line. This value offers a sufficient safetymargin since the protection algorithm comparesthe instantaneous values with double the set root-mean-square (r.m.s.)value. The stage I>>>>,which is independent of the circuit- breaker, is leftdeactivated (set value “ ∞”) as no current gradingis possible via the object to be protected.

3.2.5.2 Overcurrent-time protectionSince further short-circuit protection is generallyprovided in addition to the differential protection– for reasons of hardware redundancy in an inde -pendent relay – the integrated definite-timeovercurrent-time protection is only activated ifthere is a communication link failure (outage).The current thresholds are set – as far as possible –between maximum operating current and mini-mum short-circuit current. The associated delaytime is adjusted to the power system grading planin the best possible way, in order to maximize se-lectivity. In the example here – without knowingthe minimum short-circuit current – the recom -mended setting is 20 % above the maximum per-mitted continuous current for the cable (407 A),i.e. 488 A or 1.22 A secondary.

If current-dependent grading via the object to beprotected is possible, a high-current stage withimmediate disconnection can also be set. In thiscase it must be ensured that the threshold does notpickup in the event of fault current flowingthrough.

If the definite-time overcurrent-time protectionintegrated into the 7SD610 is set as a permanentlyactive backup protection function, overcurrentand high current stages can be used for regulardefinite-time overcurrent-time protection dutiesoutside the differential protection area. In theevent of a communication link outage, the I>>>stage can be used in the sense described above asan emergency definite-time overcurrent stage.

3.2.5.3 Thermal overload protectionThermal overload protection prevents overload ofthe object to be protected, in this case the 20 kVcable. Because the cause of the overload normallylies outside the object to be protected, the over-load current is a through-flowing current. The re-lay calculates the temperature rise in accordancewith a thermal single-body model according to thedifferential equation:

d

d th th N

Θ Θt

I

k I+ ⋅ = ⋅

⋅

1 12

τ τ

For each phase, the protection function calculatesa thermal replica of the object to be protectedfrom the square of the phase current. The unfil-tered measured value is used so that harmonicsare also taken into account in the thermal consid-eration. Whether the overload function should infact disconnect when the tripping limit is reached,or whether reaching this threshold should only bereported, must initially be set.

Fig. 9 Settings in the menu item “Settings group A –differential topology”

LSP2

666.

tif



The basic current for overload detection is thethermally continuous permitted current of the ob-ject to be protected (compare cable data). This canbe referred to the protection relay rated currentvia the setting factor k:

kN

= I

Imax

Consequently, at a maximum permitted continu-ous current of 407 A and a primary transformerrated current of 400 A, a value for k of 1.02 results.

The temperature rise time constant τth must alsobe taken from the manufacturer’s data. It must beborne in mind that this must be set in minutes,whereas often a maximum permitted 1 secondcurrent is specified, and the same applies to ourcable. In this case the 1 second current is 17.2 kA.The conversion formula is

τth

min

permissible 1 second current

permissible= ⋅1

60 continuous current

2

τth is 29.8 minutes in this case.

Before reaching the tripping threshold, a thermaland/or current alarm stage can be set. Theseshould typically be set somewhere below the trip-ping threshold in order to give the operating staffsufficient time to reduce the equipment load. Forthe thermal alarm stage it is recommended thatthe preset value of 90 % be left unchanged. Thecurrent alarm stage is set somewhere below themaximum continuous permitted operating cur-rent. 95 % of this figure is selected here, i.e. 387 Aprimary. Referred to the transformer rated cur-rent, this gives approximately 0.97 A secondary.Finally, it is also possible to set the method used tocalculate the temperature rise. This is calculatedseparately for each phase. There is a choice as towhether the maximum of the three excess temper-atures (preset), the arithmetic mean of these three,or the temperature rise calculated from the maxi-mum phase current should be significant for com-parison with the tripping thresholds. In this case,the preset value remains unchanged, provided noother algorithm must be preferred.

3.3 Settings of the relay at the remote endThe settings of the local relay just parameterizedcan mostly be used as a basis for parameter assign-ment on the relay at the remote end. The record issimply duplicated by copying and pasting. Thiscreates a new relay file, the only difference inwhich is the VD address. This ensures that the re-cord copied belongs to another relay, even thoughthat relay was until now identical.

In the “Settings group A – differential protectiontopology” section, the parameter 1710 must be setto “relay 2”. In the absence of this setting, therecannot be any communication between the tworelays.

The transformer data and the transformer charac-teristic in the “Power system data 1” section mustbe adapted. Whether intertripping should be op-erable from both ends should also be checked.Otherwise, this must also be changed.

The settings in the “Power system data 2” (differ-ential protection function, R2R interfaces, instan-taneous switch-onto-fault and overload) are iden-tical for both relays and need not be changed. Thedefinite-time overcurrent-time function settingsare dependent on power system topology andmust therefore be checked. If the relays are con-nected to a substation control system or RTU, therespective relay addresses must be checked.

Fig. 10 Settings in the menu item “Settings group A –thermal overload protection”

Fig. 11 Settings for the relay at the remote end in the“Settings group A – differential topology” section

LSP2

667.

tif

LSP2

668.

tif



4. Connection exampleGenerally, connection of three phase currenttransformers to the 7SD610 in Holmgreen circuitis recommended in accordance with Fig. 12. Thisallows the differential protection to work with thethree directly measured phase currents. For otherprotection functions (e.g. definite-timeovercurrent-time protection), an earth currentsummated from the three phase currents is avail-able. If there are higher demands for the accuracyof the earth current, a core-balance current trans-former can also be connected to the 7SD610 IE in-put (Fig. 13). In this case the modified transfor-mation ratio for this input must be entered via pa-rameter 221 in “Power system data 1 –transformer data”.

5. SummaryThe instantaneous and at the same time selectiveprotection of cables and lines reduces the conse-quences of unavoidable power system disturban-ces. For one this means protection of equipment,secondly it contributes to maximizing supplysecurity.

A differential protection system consisting of twoSIPROTEC 7SD610 relays provides comprehen-sive safeguarding of cables and overhead lines.Built-in emergency and backup protection func-tions – as well as extensive additional facilities –allow problem-free connection of the relay andintegration in complex power system protectiongrading schemes, without the need for anyadditional equipment.

The preset values on the relay are selected in sucha way that the user only has to set the known cableand primary transformer data. Many of the presetvalues can be taken over without difficulty, there-by reducing the effort involved in parameteriza-tion and setting.

Fig. 12 Current transformer connection to three primary current transformers andneutral point current (normal connection)

Fig. 13 Current transformer connection to three primary current transformersand separate earthing transformer (core-balance current transformer)

Important: The cable shielding must be earthed on the cable side.

Note: Changing over the current polarity (address 0201) also causesa polarity reversal of the current input I4.



1. IntroductionFailure of underground cables can be costly andtime consuming to repair. Protection systems aredesigned to protect cables from the high currentlevels present under fault conditions. However,the temperature rise due to extended overloadconditions is just as likely to cause cable failure. Asthe trend in power system operations is to utilizeequipment as close to operating limits as possible,the importance of protecting equipment againstthermal overloads becomes more critical.

Thermal overload protection calculates the tem-perature of the conductor based on specific con-ductor data and the current present in the circuit,and is used to protect conductors from damagedue to extended overloads. In this application ex-ample thermal overload protection of under-ground cables only is described.

Thermal overload protection is normally used inan alarm mode to notify system operators of thepotential for cable damage. However, thermaloverload protection can be used to trip a circuit-breaker as well. In either case, the presence ofthermal overload can be detected and removedbefore cable failure occurs.

2. Thermal overload protectionThermal overload protection with total memorycalculates a real time estimate of the temperaturerise of the cable, Θ, expressed in terms of the max-imum temperature rise, ∆Θmax. This calculation isbased on the magnitude of currents flowing to theload, and the maximum continuous current ratingof the conductor. The calculation uses the solu-tion to the first order thermal differential equa-tion:

τd

d

Θ Θt

I+ = 2

with = Θ ∆Θ∆Θ

=max

Thermal OverloadProtection of Cables

∆Θ = temperature rise above ambient temperature∆Θmax = maximum rated temperature rise correspond-

ing to maximum currentτ = thermal time constant for heating of the

conductorI = measured r.m.s. current based on the maximum

rated overload current of the protected conduc-tors: Imeas/Imax.

The solution to the thermal differential equationis:

Θ Θ ∆Θop amb max= + −

−

1 et

τ

The initial value is Θamb, the ambient temperatureof the cable, and the steady state value is

Θamb +∆Θ, where ∆Θ is determined by the magni-

tude of I. The initial value, Θamb, is assumed to bethat temperature on which the cable ratings arebased. The steady state value is achieved when thetemperature has reached its final value due to theheating effects of I. At this point, the value of

τdΘ/dt in Equation 1 is zero. Therefore, at steady

state, ∆Θ = ∆Θmax I2, where I = Imeas/Imax. Thetransition between the initial value and the steadystate value is governed by the exponential expres-

sion,1 −−

et

τ . τ is a constant of the cable to be pro-tected.

Fig. 1

LSP2

299-

eps

BU

IS08

5.ep

s



Fig. 2 shows the operating temperature of the ca-ble as a function of time and overload. With noload, the conductor is at its ambient temperature.If an overload equivalent to the maximum ratedcurrent is added at some time, the temperature of

the cable will approach Θmax following the expo-nential

1 −−

et

τ .

The conductor temperature due to a current over-load, starting from no-load conditions, has thesame characteristic as shown in Fig. 2, with Θmax

becoming Θop, and IMAX becoming ILoad. However,when the conductor already has some load pres-ent, the characteristic of the operating tempera-ture changes. The conductor will heat up the cableto some steady state temperature. When an over-load is added, the final temperature of the cable iscalculated as if the cable was at normal operatingtemperature. However, the starting point of thesecond (overload) characteristic will coincide withthe steady state temperature of the normal load.This is illustrated in Fig. 3.

3. Calculation of settingsThere are two required settings for thermal over-load protection, the k factor, and the thermal timeconstant τ. τ is specific to the properties of the ca-ble. The k factor relates the maximum continuouscurrent rating of the cable to the relay.

3.1 Maximum continuous current of cableThe maximum continuous current rating of thecable is used in determining the k factor setting,and may be used in determining the setting for τ.This current depends on the cross-section, insu-lating material, cable design, and conductor con-figuration. Cable manufacturers may specify themaximum continuous current rating of their ca-ble. If the rating is not available, it is possible to

estimate a maximum continuous current based onconductor ampacity information. The ampacity ofconductors is specified based on circuit configura-tions, conductor temperature, and ambient tem-perature. Also specified is the maximum operatingtemperature of the conductor, and correction fac-tors for various conductor operating temperaturesand ambient earth temperatures.

To determine the maximum continuous currentrating of a cable, use the ampacity at the emer-gency overload operating temperature, and notthat of the maximum conductor operating tem-perature. According to ICEA specifications, [1]emergency overloads are permitted for only a totalof 100 hours per 12 month period, only for nomore than five such periods in the life of the cable.Therefore, it is desirable to trip or alarm for anysituation when the thermal overload reaches thislevel. To determine the maximum continuouscurrent, remember that the conductor configura-tion and ambient temperature effect the currentrating.

Example:

Circuit voltage: 12.47 kVCable size: 500 MCM shielded

copper cableConductor temperature: 90 °CAmbient temperature: 20 °CConfiguration: 3 circuits duct bank

From conductor tables, the ampacity for 90 °Ccopper conductor at 20° ambient temperaturewith 3 circuits in duct bank is 360 amps. Theemergency overload operating temperature for90 °C-cable is 130 °C. From Table 1, at 20 °C am -bient temperature, the ampacity rating factor is1.18.

Therefore,360 A x 1.18 = 424.8 A maximum continuous cur-rent

Fig. 2 Temperature vs. time for an overload of Imax



3.2 Calculating the k factorThe k factor relates the operating current to therelay to permit overload detection. The k factor isdefined as the ratio of the maximum continuouscurrent Imax to the rated relay current IN:

Example:

kN

= I

Imax

Circuit voltage 12.47 kVCable size 500 MCM shielded

copper cableConductor temperature 90 °CAmbient temperature 20 °CConfiguration 3 circuits in duct bankMaximum continuouscurrent (Imax) 424.8 A primaryCurrent transformerratio 800/5Rated relay current (IN) 5 A secondary

k = =

424 8

800 55

0 53

.

( / ) .

3.3 Thermal time constantThe thermal time constant τ is a measure of thespeed at which the cable heats up or cools down asload increases or decreases, and is the time re-quired to reach 63 per cent of the final tempera-ture rise with a constant power loss. The thermaltime constant is the determining factor for calcu-lating the operating temperature as a percent ofthe maximum permissible overload temperature,as shown in Equation 2. τ may be available fromthe cable manufacturer. If no specification for τ isavailable, it may be estimated from the permissibleshort-circuit rated current of the cable, and themaximum continuous current rating. It is com-mon to use the 1 second rated current as the per-missible short-circuit current. τ is calculated bythe following equation:

τ(min)=1

60second⋅

I

I1

2

max

If the short-circuit current at an interval otherthan one second is used, the equation is multipliedby this interval. For example, if the 0.5 second rat-ing is used:

τ(min)=0.5

60second⋅

I

I0 5

2

.

max

Example for calculating the thermal constant τ:

Circuit voltage 12.47 kVCable size 500 MCM shielded copper cableConductortemperature 90 °CAmbienttemperature 20 °CConfiguration 3 circuits in duct bankMaximum continuoscurrent (Imax) 424.8 A primaryMaximum currentoür 1 second 35,975 A primary

τ(min)=1

60min⋅ =35 975

424 8119 5

2,

..

Conductorsize

Ampacity Max. continu-ous current

Short-timewithstandcapability (1 sec)

τ(minutes)

1/0 160 189 7 585 27

2/0 185 218 9 570 32

3/0 205 242 12 065 41

4/0 230 271 15 214 52

250 MCM 255 301 17 975 59

350 MCM 305 360 25 165 81

500 MCM 360 425 35 950 119

750 MCM 430 507 53 925 188

1000 MCM 485 572 71 900 263

Table 1 Shielded copper conductor, 5001 - 35000 volts, 90 °C,three-conductor cable, three circuits in duct bank

Fig. 3 Temperature vs. time with an existing overload



Short-circuit rated current for copper

I

At

T

T

⋅ = ⋅ +

+

2

2

1

0 0297234

234. log

I = Short-circuit current - Amperes [A]A = Conductor area - circular mils

(0,001" diameter; convert to mm2 wherenecessary)

t = time of short-circuit, secondsT1 = Operating temperature 90 °CT2 = Maximum short-circuit temperature 250 °C

Short-circuit current for aluminium

I

At

T

T

⋅ = ⋅ +

+

2

2

1

0 0125234

234. log

Table 1 lists calculated values of τ for commonconductors and configurations. Below Table 2 arethe formulas to calculate the short-circuit ratingof conductors

3.4 Analysis of relay settingsCombining the examples in Sections 3.1, 3.2, and3.3, the cable information leads to the followingrelay settings:

k factor: 0.53

τ: 119.5 minutes

The operating temperature at a given moment intime can be calculated using Equation 2.

Θamb = the conductor operating temperature = 90 °C.∆Θmax = the maximum overload temperatureminus the initial operating temperature =130 °C - 90 °C = 40 °C.

As shown in Section 2 above, to determine thesteady state temperature, the exponential term canbe replaced by I2, where I = Imeas/Imax. Based onthese settings, and a load current of 400 A,

Θ Θ ∆Θop ambmeas= +

= °+ °

max

max .

I

I

2

90 40400

424 8

= °

2

125 C

Thus, for a load of 400 A, the conductor will heatup to 125 °C.

4. Implementing thermal overload protectionThermal overload protection in SIPROTEC relayscalculates the temperature for all three phases in-dependently, and uses the highest of the three cal-culated temperatures for tripping levels. Besidesthe k factor and the thermal time constant, thereare two other settings for thermal overload pro-tection. As seen in Figure 3, these are the “thermalalarm stage” and the “current overload alarmstage”.

4.1 Thermal alarm stageThe thermal alarm stage sends an alarm signal be-fore the relay trips for a thermal overload condi-tion. The thermal alarm stage is also the dropoutlevel for the thermal overload protection trip sig-nal. Therefore, the calculated temperature mustdrop below this level for the protection trip to re-set. This stage is set in percent of the maximumtemperature. A setting of 90 % will meet mostoperating conditions.

Conductortemperature

Ambient earth temperature

°C 10 °C 15 °C 20 °C 25 °C 30 °C

75 0.99 0.95 0.91 0.87 0.82

85 1.04 1.02 0.97 0.93 0.89

90 1.07 1.04 1.00 0.96 0.93

100 1.12 1.09 1.05 1.02 0.98

105 1.14 1.11 1.08 1.05 1.01

110 1.16 1.13 1.10 1.07 1.04

125 1.22 1.19 1.16 1.14 1.11

130 1.24 1.21 1.18 1.16 1.13

140 1.27 1.24 1.22 1.19 1.17

Table 2Correction factors for various ambient earth temperatures

Fig. 4 Thermal overload protection settings

LSP2

588.

tif



Fig. 5 Logic diagram of the overload protection



4.2 Current overload alarm stageThe current overload alarm stage sends an alarmwhen the load current exceeds the value of the set-ting. This setting should be set equal to, or slightlyless than, the maximum continuous current ratingof the cable.

4.3 Thermal overload protection as an alarm ortripping functionThermal overload protection may be configuredto either “ON” (tripping) or “Alarm only” foroverload conditions, and is normally set to“Alarm only”. Configuring thermal overload pro -tection to “ON” makes this a tripping function,meaning it asserts the 0511 Relay TRIP function.The factory default configuration of the relay hasthe 0511 Relay TRIP function set to close a contactthat trips the circuit-breaker.

“Alarm only” means thermal overload protectiondoes not assert the 0511 relay trip function. Ther-mal overload protection may still be programmedto operate a binary output for tripping purposes.this configuration allows the thermal overloadfunction to be used to warn operators of potentialcable failure due to overloads.

4.4 Adjusting settings for differences in ambienttemperatureThe ambient temperature of the earth has a signif-icant effect on the maximum continuous currentrating of the cable. In most applications, it is bestto assume one ambient earth temperature to per-form relay setting calculations. However, in someareas, there may be large seasonal differences inambient earth temperature. Using multiple set-tings groups allows the relay to adapt the thermaloverload protection settings to large changes inthe seasonal temperature.

Changing the settings group can be accomplishedvia binary input, remote command, or functionkey, all of which require operator intervention toaccomplish the change. Another possibility is tohave the relay change settings groups based onsystem conditions. Wiring the output of a temper-ature sensor into an optional transducer input onthe 7SJ63 relay will permit the changing of settingsgroups when the earth temperature passes athreshold for a specified period of time.

5. SummaryThe failure of underground cables due to heatingcaused by long term overload conditions is easilyprevented by using thermal overload protection.Based on information provided by cable manufac-turers, circuit configuration, and operating condi-tions, it is simple to determine settings for thermaloverload protection. Thermal overload protectionis normally used to alarm for overload conditions,to allow system operators to make informed deci-sions on how to handle an overload to prevent ca-ble damage. A thermal overload alarm, whencombined with a SCADA system, can be used totrack the amount of time the cable is exposed tooverload, allowing for estimates of the remaininglife of the cable.

6. ReferencesInsulated Cable Engineers Association StandardP32-382-1994, “Short Circuit Characteristics ofInsulated Cable”, 1994, South Yarmouth, MA.

“Engineering Handbook”, The Okonite Com-pany, 1999, Ramsey, NJ.

H. Pender and W. Del Mar, “Electrical Engineer’sHandbook”, 4th Edition, Wiley & Sons, NewYork, NY.



1. IntroductionThe flexible protection functions allow sin-gle-stage or multi-stage directional protection tobe implemented. Each directional stage may beoperated on one phase or on three phases. Thestages may use optionally forward active power,reverse active power, forward reactive power orreverse reactive power as a measuring variable.Pickup of the protection stages can take placewhen the threshold value is exceeded or under-shot. Possible applications for directional powerprotection are listed in Table 1.

A practical application example for reverse-powerprotection using the flexible protection function isdescribed below.

2. System example2.1 Functions for the disconnecting facilityFig. 2 shows the example of an industrialswitchgear with autonomous supply from the il-lustrated generator. All the lines and the busbarshown are in three-phase layout (except the earthconnections and the connection for voltage mea-surement on the generator). The two feeders 1 and2 supply the customer loads. In the standard case,the industrial customer receives power from theutility. The generator runs only in synchronousoperation without feeding in power. If the utilitycan no longer maintain the required supply qual-ity, the switchgear should be disconnected fromthe utility power system and the generator shouldassume autonomous supply. In the exampleshown, the switchgear is disconnected from theutility power system when the frequency leaves therated range (e.g. 1-2 % of the rated frequency), thevoltage drops below or exceeds a given value orthe generator feeds active power back into theutility power system. Some of these criteria arecombined depending on the user’s philosophy.This would be implemented using CFC.

Here, reverse-power protection with the flexibleprotection functions is explained. Recommenda-tions are given for frequency and voltage protec-tion in the Chapter 4 on setting instructions.

Disconnecting Facilitywith Flexible ProtectionFunction

Fig. 1 Protection for industrial plants

Direction Evaluation

Overshoot Undershoot

P Forward Monitoring of forward powerlimits of equipment (trans-formers, lines)

Detection of motors running atno load

P Reverse − Protection of a local indus-trial power system againstfeeding energy back into theutility power system

− Detection of reverse energysupply from motors

Table 1 Application overview, reverse-power protection

LSP2

650.

tif



2.2 System dataA 110 kV line connects the switchgear to the util-ity power system on the high-voltage side. The cir-cuit-breaker CB1 belongs to the utility powersystem. The switch disconnector decouples theswitchgear from the utility power system if neces-sary. The transformer with a ratio of 10:1 trans-forms the voltage level to 11 kV. On the low-voltage side the transformer, the generator and thetwo feeders are connected by a busbar. The cir-cuit-breakers CB2 to CB5 disconnect loads andequipment from the busbar.

3. Protection functionalityThe SIPROTEC protection relay 7SJ64 discon-nects the switchgear from the utility power systemif the generator feeds energy back into the powersystem (protection function P reverse >). Thisfunctionality is achieved by using flexible protec-tion. Disconnection also takes place in the event offrequency or voltage fluctuations in the utilitypower system (protection functions f<, f>, U<,U>, Idir>., IEdir>/ 81, 27, 59, 67, 67N).

The protection receive the measured values via athree-phase current and voltage transformer setand a single-phase connection to the generatorvoltage transformer (for synchronization). Thecircuit-breaker CB2 is activated in the case of adisconnection.

The transformer is protected by differential pro-tection and inverse or definite-time overcurrent-time protection functions for the phase currents.In the event of a fault, the circuit-breaker CB1 onthe utility side is tripped by a remote link. Circuit-breaker CB2 is tripped additionally.

Overcurrent-time protection functions protectfeeders 1 and 2 against short-circuits and overloadcaused by the connected loads. Both the phasecurrents and the zero currents of the feeders canbe protected by inverse and definite-time over-current-time stages. The circuit-breakers CB4 andCB5 are tripped in the event of a fault.

The busbar could be equipped additionally withthe differential protection 7UT635. The currenttransformers required for this are already shownin Fig. 2.

Fig. 2 Example of a switchgear with autonomousgenerator supply

Switchgear data

Rated power of generator SN, Gen = 38.1 MVA

Rated power of transformer SN, Transfo. = 40 MVA

Rated voltage of high-voltage side UN = 110 kV

Rated voltage of busbar side UN = 11 kV

Primary rated current of the currenttransformers on the busbar side

IN, prim = 2000 A

Secondary rated current of the currenttransformers on the busbar side

IN, sec = 1 A

Primary rated voltage of the voltage trans-formers on the busbar side

UN, prim = 11 kV

Secondary rated voltage of the voltagetransformers on the busbar side

UN, sec = 100 kV

Table 2 Switchgear data for the application example



3.1 Synchronization when connecting thegenerator

In most cases the electricity customer is responsi-ble for restoring the switchgear or substation tonormal operation after shutdown. The SIPROTEC7SJ64 tests whether synchronous conditions aresatisfied. After successful synchronization, thegenerator is connected to the busbar. The voltagesrequired for synchronization are measured at thetransformer and at the generator. The voltage atthe transformer is measured in all three-phase be-cause this is also necessary for determining the di-rection. The generator feeds the phase-to-phasevoltage U31 to the device input U4 via a voltagetransformer in a star-delta connection (see Fig. 3).

3.2 Connection diagramFig. 3 shows the connection of the relay for re-verse-power protection and synchronization. Thepower flow in positive or forward direction takesplace from the high-voltage side busbar (notshown) via the transformer to the low-voltage sidebusbar.

3.3 Reverse-power protection with flexibleprotection functions

The reverse-power protection evaluates the activepower from the symmetrical fundamental compo-nents of the voltages and currents. Evaluation ofthe positive-sequence systems makes the reverse-power determination independent of the asymme-tries in the currents and voltages and reflects thereal load on the drive side. The calculated activepower value corresponds to the total active power.In the connection shown in the example the po-wer in the direction of the busbar from the relay ismeasured as positive.

3.4 Function logicThe logic diagram in Fig. 4 shows the functionlogic of the reverse-power protection.

The reverse-power protection picks up when theconfigured pickup threshold is exceeded. If thepickup condition persists during the equally para-meterizable pickup delay, the pickup message“P reverse pickup.” is emitted.

This starts the trip command delay. If pickup doesnot drop out while the trip command delay is run-ning, the trip message “P reverse TRIP” and thetime-out indication “P reverse timeout” are gen -erated (latter not illustrated). The picked-up ele-ment drops out when the value falls below thedropout threshold. The blocking input “>P re -verse block” blocks the entire function; i.e. pickup,trip command and running times are reset.

After the blocking has been released, the reversepower must exceed the pickup threshold and bothtimes must run out before the protection trips.

Fig. 3 Connection diagram for a 7SJ642 as reverse-power protection(flush-mounted housing)

Fig. 4 Logic diagram of the reverse-power determination with flexible protectionfunction



4. Setting instructions4.1 Reverse-power protectionThe pickup value of the reverse-power protectionis set at 10 % of the generator rated output. In thisexample the setting value is parameterized as sec-ondary power in Watts. The primary and secon-dary power have the relation:

P PU

U

I

Isec prim

N, sec

N, prim

N, sec

N, prim

= ⋅ ⋅

With the indicated data, the pickup values can becalculated – taking account of Pprim = 3.81 MW(10 % of 38.1 MW) on the primary level – as

Psec MW100 V

11000 V

A

AW= ⋅ ⋅ =381

1

200017 3. .

on the secondary level. The dropout ratio isparameterized to 0.9. This gives a secondary drop-out threshold of Psec, dropout = 15.6 W. If the pickupthreshold is reduced to a value close to the lowersetting limit of 0.5 W, the dropout ratio shouldlikewise be reduced to approximately 0.7.

The reverse-power protection requires no shorttrip times as protection against undesirable feed-back. In this example it is useful to delay pickupand dropout by about 0.5 s and tripping by about1 s. Delaying the pickup minimizes the number ofopened fault logs when the reverse power fluctu-ates around the threshold value. If the reverse-power protection is used to make it possible todisconnect the switchgear from the utility powersupply system quickly in the event of faults in thelatter, it is advisable to select a higher pickup value(e.g. 50 % of the rated power) and shorter delaytimes.

4.2 Frequency protection f<, f>The relay 7SJ64 contains 4 frequency stages. Onestage is parameterized as f> and set to 50.5 Hz; itoperates without time delay. This stage detects thefrequency increase caused by a short-circuit in theutility. The other 3 frequency stages should beparameterized as f< stages to serve as load shedd-ing criteria for isolated operation of the industrialpower supply system.

Suggested settings:

f1< = 49.5 Hz t1 = 0.2 sf2< = 49 Hz t2 = 0.1 sf3< = 48 Hz t3 = 0.2 s

On reaching stage f3<, the generator should be op-erated in isolated mode to safeguard autonomousauxiliary supply coverage.

4.3 Undervoltage protection U< (ANSI 27)The voltage dip in the event of a short-circuit inthe system is detected with the U< criterion. TheU< criterion should always be linked with thefault current direction, to open the coupler circuit-breaker only in the event of a fault in the utilitysystem. The voltage level should be set to 0.5 x UN.

4.4 Parameterization of reverse-powerprotection with DIGSI

A relay 7SJ64x (e.g. 7SJ642) is created and openedfirst in the DIGSI Manager. A flexible protectionfunction 01 is configured for the given example inthe scope of functions (Fig. 5).

Select “Additional functions” in the “Parameters”menu to view the flexible functions (Fig. 6)

Fig. 5 Configuration of a flexible protection function

LSP2

652e

n.ti

f

Fig. 6 The flexible function is visible in the functionselection

LSP2

653e

n.ti

f



First the function must be activated under “Set -tings → General”, and “3-phase” operating modemust be selected (Fig. 7).

Select “Active power reverse” or “Overshoot” inthe menu items “Measured quantity” and “Mea -surement method”. If the “Display additional set -tings” box is activated in the “Settings” menuitem, the threshold value, pickup delay and TRIPcommand delay can be configured (Fig. 8). Sincethe power direction cannot be determined in theevent of a measuring voltage failure, protectionblocking is useful in this case.

4.5 Configuration for reverse-power protection inDIGSI

The names of the messages can be edited in DIGSIand adapted accordingly for this example. Thenames of the parameters are fixed.The DIGSI configuration matrix initially showsthe following indications (after selecting “Indica -tions and commands only” and “No filter”:Fig. 9).

It is possible to edit short text and long texts tosuit the application by clicking the texts (Fig. 10).

Configuring of the indications is performed in thesame way as for the configuring of the indicationsof other protection functions.

5. SummaryWith the flexible protection functions, it is easy toimplement measuring criteria not available asstandard, such as power direction. This measuringcriterion is a fully fledged protection function andcan therefore be integrated as an equivalent crite-rion in a disconnecting facility. The synchroniza-tion function of the SIPROTEC 7SJ64 can be usedto advantage here, to synchronize the industrialpower supply system to the utility power supplysystem.

Fig. 7 Selection of three-phase operation

LSP2

654e

n.ti

f

Fig. 8 Setting options of the flexible function

LSP2

655e

n.ti

f

Fig. 9 Indications prior to editing

Fig. 10 Indications after editing

LSP2

656e

n.ti

fLS

P265

7de.

tif





1. General earth-fault informationIn a system with isolated star point an earth faultis not a short-circuit, but an abnormal operatingstate. It must be signalled and corrected as quicklyas possible. The way in which the earth fault isidentified depends on the configuration of the sys-tem. In a radial system, sensitive earth-fault direc-tion detection with sine ϕ measurement is themethod; in a meshed system the transient earth-fault relay is preferred. In the case of an earth faultwith no resistance, e.g. in phase L3, the voltageUL3-E drops to zero and the voltages UL2-E andUL1-E increase to the 3-fold value. A displace-ment voltage UE-N appears. This is also referred toa zero-sequence voltage (U0). In normal operationit has the value of the phase-to-earth voltage. Apurely capacitive earth-fault current flows at thefault location. This can create very unstable arcs.In general, isolated systems operate up to a capaci-tive earth-fault current of 50 A. The UE-N is evalu-ated for signalling the earth fault.

The U0 voltage can be calculated from the phasevoltages or it can be detected via the voltage trans-former open delta winding (e–n delta). This wind -ing generally has a greater ratio in the region offactor 3. In the case of an earth fault, the measu-ring-circuit voltage is thus approximately 100 V. Avoltage relay for earth-fault detection is set at 25 V– 30 V, and a time delay of 5 s is appropriate. Thisfunctionality is included in line protection relays7SJ5.., 7SJ6.., 7SA5.. and 7SA6 depending on theconfiguration chosen. If the relays are equippedwith three transformer inputs a phase-selectiveearth-fault alarm can also be provided. U ≤ 40 Vserves as the criterion for recognizing the defectivephase and U ≥ 75 V for the fault-free phases.

Earth-Fault Protection inSystems with IsolatedStar Point

Fig. 1 Transient earth-fault relay 7SN60

Fig. 2 Isolated system

LSP2

367.

eps

Earth fault = no short-circuit

Operation continues during singleearth fault

Earth fault must be signaled andcorrected as quickly as possible

Earth-fault location with watt-metric earth-fault directionmeasurement or transient earth-fault relay

Fig. 3 Voltages in normal operation



Two methods can be used to measure the earthcurrent.

The Holmgreen circuit adds the three phase cur-rents (by means of appropriate connection of thecurrent transformers) and thus provides the earthcurrent. However, because each transformer hasalways an error of measurement, this method formeasuring the earth current is only suitable in sys-tems with higher earth-fault currents (> 40 A) and

a not excessively high ratio of the transformers(<150/1 or 150/5). The second method, measure-ment with a core-balance current transformer, canbe used for smaller earth currents. It deliversbetter values for sensitive earth-fault detection. Itis important to ensure that the transformer is as-sembled with precision. In the case of cut-stripwound transformers it is essential that the coresurfaces lie directly on top of each other. It is alsocritically important that the earthing connectionof the cable screen earthing is led back through thetransformer so that the sum of the phase currentscan actually be measured (see Fig. 6 and 7).

2. Sensitive earth-fault direction detectionwith sine measurement

Earth-fault direction measurement is only appli-cable in the radial system. If it is used in a meshedsystem, meaningful results can only be expectedafter switching over to radial lines.

Fig. 4 Voltages for earth fault in phase L3

Fig. 6 Connection of currents

3 0 1 2 3⋅ = + +I I I IL L L

Core balance currenttransformer

Fig. 7 Core-balance current transformer

Fig. 8 Radial system

Fig. 5 Voltage transformer with open delta winding

Earthing connectionmust be led back

Radial system

Energy direction



Capacitive currents

Overhead line 20 kV ∼ 0.05 A/km

110 kV ∼ 0.30 A/km

Cable 10 kV ∼ 1.5 A/km

20 kV ∼ 3.0 A/km

110 kV ∼ 20.0 A/km

The system capacitive current can be estimated byusing the table or values given in cable manuals.

Example to determine IE

Current30 km 10 kV cable, 1.5 A/kmIE = 1.5 A / km · 30 km = 45 A

Holmgreen-circuit, ratio of themain current transformer 200/1Earth current at the protection relay 225 mASetting IE> 150 mA

In the case of an earth fault only the healthy partsof the system continue to provide an earth-faultcurrent; therefore the pickup value must always belower than the maximum earth-fault current. Inan exact calculation the value of the longest linesection plus a safety margin must be subtractedfrom the maximum.

Voltage settings:

Attention must be paid to the voltage settings asfollows:

Displacement voltage: value in the case of earthfault: 100 V/ 3

Measured voltage at the open delta winding(e-n winding): value in the case of earth fault:100 V

Threefold zero-sequence voltage 3U0: value inthe case of earth fault: 100 V· 3.

For connection to the e-n winding, a pickup valueof Ue-n> = 25 V is usual. For setting tripping val-ues for the (calculated) displacement voltage,25 V/ 3 is recommended. The proposed operat-ing value for 3U0 is 25 V· 3.

Earth-fault report time delay: t = 5 s

Voltage setting for phase-selective earth-fault de-tection:Affected phase U ≤ 40 VHealthy phases U ≥ 75 V

Type of measurementSine phi

Earth-fault detectionSignal only (disconnection following an earthfault is not usual)

Fig. 9 shows an example of how the indication ofearth-fault direction detection could look in a spe-cific case. It is important to note that not all the un-affected circuits (or in the worst case scenario noneof them) indicate backward. If the partial currentbeing delivered to the earth-fault location is lowerthan the limit value set, no direction indication oc-curs. However, because of the voltage ratios, theearth fault is recognized by all relays and the generalearth-fault signal is given. For remote reporting themessage “earth fault” must be transmitted oncefrom the galvanically connected system. From theindividual feeders it is advisable only to transmitthe message “earth fault forward”. If the feeder with“earth-fault forward” message is disconnected, theearth-fault message will be cleared.

If the line affected by the earth fault is an openring with several sectioning points, it is possible toidentify the earth-faulted section by moving theisolating point.

Example in Fig. 10:Normally the isolating point is situated at C.An earth fault has occurred and relay 8 has re-ported “forward”. If the isolating point is nowmoved from C to A, which can be done (by loaddisconnection) with no interruption to supply, therelay 7 indicates “forward”. The section A – C isthus affected by the earth fault. If the isolatingpoint is now moved to B, the relay 8 once againindicates “forward”. Thus section A – B is clearlyaffected by the earth fault.

Fig. 9 Earth fault in radial system

Fig. 10 Searching for the earth fault in a ring system

Normal connection 1. Moving the isolating point 2. Moving the isolating point

Earth-fault direction detection

Forward

Backward



3. Earth-fault direction detection withthe transient earth-fault relay 7SN60

If the system is meshed, no clear direction indica-tion can be obtained from the sine ϕ measurement.The current direction in the case of an earth faultcannot be definitely detected. Good locating resultsare achieved using transient earth-fault relays.These relay work with the charge-reversal process,which occurs with the earth fault. The capacity ofthe phase affected by the earth fault is discharged toearth and the healthy phases are charged up to thehigher voltage value.

This charge-reversal produces a large current,amounting to a multiplication (threefold orfourfold) of the capacitive current. The transientearth-fault relays are thus always connected to theHolmgreen circuit.

It is important to be aware that the charge-reversalprocess only occurs when the earth fault appears,i.e. just once. Repeat measurements followingswitching therefore have no meaning and lead toconfusion.In order to identify the circuit affected by theearth fault in a meshed system, an indication isrequired from both ends of the line. Both relaysmust indicate in a “forward direction”. It is there-fore advisable to transfer the signals from thetransient earth-fault relay onto an image of thesystem. It is then possible to decide quickly wherethe earth fault is located.

In Fig. 11, the fault is located in the middle linefrom ST 4 to ST 3, since here both relays are indi-cating “forward”.

4. SummaryOperation can be continued when an earth faultoccurs in a power system with an isolated starpoint. The fault can be located as described above.The operator should quickly separate the faultlocation from the system. Thus a double fault(which – as a short-circuit – would cause a supplyinterruption) can be avoided.

Fig. 11 Transient earth-fault relay indications

Fig. 13 Transients in an earth fault

Fig. 12 Transient earth-fault relay connection

ForwardBackward



1. General earth-fault informationIn a resonant-earthed power system an earth faultis not a short-circuit, but an abnormal operatingstate. It must be signalled and corrected as quicklyas possible. The way in which the earth fault isidentified depends on the configuration of thenetwork. In a radial system, sensitive earth-faultdirection measurement with sine ϕ measurementis used; in a meshed system the transient earth-fault measurement is preferred.

In the case of an earth fault with no resistance, e.g.in phase L3, the voltage UL3-E drops to zero andthe voltages UL2-E and UL1-E increase to the

3-fold value. A displacement voltage UE-N accu-mulates. This is also referred to as zero-sequencevoltage (U0). Under normal operating conditionsit has the value of the phase-to-earth voltage.

The capacitive earth-fault current at the fault loca-tion is compensated by the inductive current fromthe Petersen coil so that the active current at thefault location is very small. A residual resistivecurrent remains and is determined by the ohmicpart of the coil. It is in the order of magnitude of3 % of the capacitive coil current. The UE-N volt-age is evaluated for signalling the earth fault.

The U0 voltage can be calculated from the phasevoltages or it can be detected via the voltage trans-former open delta winding (e–n delta). This wind -ing generally has a greater ratio in the region offactor 3. In the case of an earth fault, the mea-suring-circuit voltage is thus approximately100 V. A voltage relay for earth-fault detection isset at 25 – 30 V, and a time delay of 5 s is appro -priate. This functionality is included in line pro-tection relays 7SJ5.., 7SJ6.., 7SA5.. and 7SA6depending on the configuration chosen. If the re-lays are equipped with three transformer inputs aphase-selective earth-fault alarm can also be pro-duced. U ≤ 40 V serves as the criterion for recog-nizing the defective phase and U ≥ 75 V for thefault-free phase.

Earth-Fault Protection in aResonant-Earthed System

Fig. 1 Transient earth-fault relay 7SN60

Fig. 2 Resonant-earthed system

LSP2

367.

eps

Earth fault = No short-circuit

Operation continues

Earth fault must be signaled andcorrected as quickly as possible

Earth-fault location withwatt-metric earth-fault directionmeasurement or transientearth-fault relay

Fig. 3 Voltages in normal operation



Two methods can be used to measure the flowingearth current.

The Holmgreen-circuit adds the three phase cur-rents (by means of appropriate connection of thecurrent transformers) and thus provides the earthcurrent. However, because each transformer has afault, this measurement method is not suitable forthe small residual resistive currents in a resonant-

earthed system. The second method, the core-balance current transformer is available for suchcases. This delivers definitely better values forearth-fault detection. It is important to ensurethat it is assembled with precision. In the case ofcut-strip wound transformers it is essential thatthe core surfaces lie directly on top of each other.It is also critically important that the cable screenearthing is led back through the transformer sothat the sum of the phase currents can actually bemeasured.

2. Watt-metric earth-fault direction detectionwith cos measurement.

Watt-metric earth-fault direction measurement isonly appropriate in the radial system. If it is usedin a meshed system, meaningful results can onlybe expected after switching over to radial lines.

Fig. 4 Voltages for earth fault L3

Fig. 6 Connection of currents

Holmgreen circuit

Core balance currenttransformer

Fig. 7 Core-balance current transformer

Fig. 8 Radial system

Fig. 5 Voltage transformer with open delta winding

3 0 1 2 3⋅ = + +I I I IL L L

Earthing connectionmust be led back

Radial system

Energy direction



Capacitive currents

Overhead line 20 kV ∼ 0.05 A/km

110 kV ∼ 0.30 A/km

Cable 10 kV ∼ 1.5 A/km

20 kV ∼ 3.0 A/km

110 kV ∼ 20.0 A/km

The network’s capacitive current can be estimatedby using the table or values given in cable manuals.Alternatively, the value can be read from the coil.

Example:

Current

Petersen coil with a rated current of 200 A,momentarily adjusted to 180 A.We can assume a capacitive earth-fault current of180 A. If we estimate the residual resistive propor-tion at 3 %, 5.40 A is the result. This is trans-formed by the core-balance current transformer at60:1, and 90 mA consequently arrive at the protec-tion relay. The pickup value should then be set atapproximately 50 mA. In the case of an earth faultonly the healthy parts of the system continue toprovide an earth-fault current; therefore thepickup value must always be lower than the maxi-mum earth-fault current.

Voltage settings:

Attention must be paid to the voltage settings asfollows:

Displacement voltage: value in the case of earthfault: 100 V/ 3

Measured voltage at the open delta winding(e-n winding): value in the case of earth fault:100 V

Threefold zero-sequence voltage 3U0: value inthe case of earth fault: 100 V· 3.

For connection to the e-n winding, a pickup valueof Ue-n> = 25 V is usual. For setting trippingvalues for the (calculated) displacement voltage,25 V/ 3 is recommended. The proposed pickupvalue for 3U0 is 25 V · 3.

Earth-fault report time delay: t = 5 s

Voltage setting for phase-selective earth-fault de-tection:Affected phase U ≤ 40 VHealthy phases U ≥ 75 V

Type of measurement

Cos phi

Earth-fault detection

Signal only (disconnection following anearth fault is not usual)

Fig. 9 shows an example of how watt-metric indi-cation of the earth-fault direction detection couldlook in a specific case. It is important to note that

not all the unaffected circuits (or in the worst casescenario none of them) indicate backward. If theactive component of the partial current being de-livered to the earth-fault location is lower than thelimit value set, no direction indication occurs.However, because of the voltage ratios, the earthfault is recognized by all relays and the generalearth-fault signal is given. For remote reportingthe message “earth fault” must be transmittedonce from the galvanically connected system.From the individual feeders it is advisable only totransmit the message “earth fault forward”. If thefeeder with “earth-fault forward” message is dis-connected, the earth-fault message will be cleared.

If the line affected by the earth fault is an openring with several sectioning points, it is possible toidentify the earth faulted section by moving theisolating point.

Fig. 9 Earth fault in radial network

Fig. 10 Searching for the earth fault in a ring system

Earth-fault direction detection

Forward

Normal connection 1. Moving the isolating point 2. Moving the isolating point



Example in Fig. 10:

Normally the isolating point is situated at C.An earth fault has occurred and relay 8 has re-ported “forward”. If the isolating point is nowmoved from C to A, which can be done (by loaddisconnection switches) with no interruption tosupply, the relay 7 indicates “forward”. The sec -tion A – C is thus affected by the earth fault. If theisolating point is now moved to B, the relay 8 onceagain indicates “forward”. Thus section A – B isclearly affected by the earth fault.

3. Earth-fault direction detection withthe transient earth-fault relay 7SN60

If the system is meshed, no clear direction indica-tion can be obtained with watt-metric relays. Thecurrent direction in the case of an earth fault can-not be definitely detected. Good locating resultsare achieved using transiente earth-fault relays.These relays work with the charge-reversalprocess, which occurs with the earth fault. Thecapacity of the phase affected by the earth fault isdischarged to earth and the healthy phases arecharged up to the higher voltage value. Thischarge-reversal produces a large current, amount-ing to a multiplication (threefold or fourfold)of the capacitive current. The transient earth-fault relays are thus always connected to theHolmgreen-circuit. It is important to be awarethat the charge-reversal process only occurs whenthe earth fault appears, i.e. just once. Repeat mea-surements following switching therefore have nomeaning and lead to confusion.In order to identify the circuit affected by theearth fault in a meshed system, an indication isrequired from both ends of the line. Both relaysmust indicate in a “forward direction”. It is there -fore advisable to transfer the signals from thetransient earth-fault relay onto an image of thesystem. It is then possible to decide quickly wherethe earth fault is located.

In Fig. 11, the fault is located in the middle linefrom ST 4 to ST 3, since here both relays are indi-cating “forward”.

4. SummaryOperation can be continued when an earth faultoccurs in a resonant-earthed power system. Thefault can be located as described above. The oper-ator should quickly separate the fault locationfrom the system. Thus a double fault (which – as ashort-circuit – would cause a supply interruption)can be avoided.

Fig. 11 Transient earth-fault relay indications

Fig. 13 Transients in an earth fault

Fig. 12 Transient earth-fault relay connection

ForwardBackward



1. General earth-fault informationIn a low-resistance-earthed power system theearth fault is a short-circuit and must therefore betripped by the short-circuit protection. In mostcases, in an impedance-earthed network (predom-inantly medium voltage) the earth-fault current islimited to a maximum of 2000 A. The minimumshort-circuit current occuring in the case of faultsat a greater distance is the standard pickup valuefor earth-fault protection (IE>). It must be en-sured that any earth fault is safely tripped. Ifshort-circuit calculations for the power system arecarried out, it is useful to have the minimumshort-circuit currents calculated as well as themaximum ones. These values less a safety marginthen form the basis of the IE> set value. The pick-up value for the earth fault is lower than that forphase failure, and in unfavorable cases can actual-ly be below the rated current.

When distance protection relays (7SA5.., 7SA6.)are used, the pickup value IE> merely acts torelease the phase-to-earth measuring systems. Thesame setting considerations nevertheless apply.

2. Earth fault in an overhead line systemSince an earth fault is by far the most frequentfault in medium-voltage overhead line systems,measures for its quick correction are welcome.The most frequently used method is auto-reclosure (AR). On the medium-voltage levelauto-reclosure is always triple-pole, and in thecase of high-voltage single-pole. Single-poleauto-reclosing circuit-breakers are therefore aprecondition here. If an earth fault occurs on theoverhead line, the protection relays concerned willpick up.

Following a TRIP command, there is a dead time(500 ms for medium voltage, 1 s for single-poleAR at high voltage), after this the line is recon-nected. If the earth fault is corrected, operationcontinues. If not, final disconnection takes placewithin the set time. Approximately 70 % of earthfaults are corrected in this way without any majorinterruption to operation.

Earth-Fault Protection ina Low-Resistance-EarthedSystem

Fig. 1 SIPROTEC relay with earth-fault protection

Fig. 2 Low-resistance-earthed system

Earth fault = short-circuit

Disconnected by the short-circuitprotection

Earth-fault detection is more sen-sitive than phase current detection

LSP2

318.

.ep

s

Fig. 3 Earth short-circuit in an overhead line system



Overcurrent-time protection relays 7SJ5.., 7SJ6..can be ordered with this functional option, as canthe distance protection relays 7SA5.., 7SA6..

Settings for medium voltage:Auto-reclosure Triple-poleDead time 500 msAction time 300 ms

Settings for high voltage (≥ 110 kV):Auto-reclosure Single-poleDead time 1 sAction time 300 ms

3. Earth fault in a cable systemAuto-reclosure is not appropriate for a cablesystem. In such cases, final disconnection isunavoidable since an earth fault does not correctitself. Selective grading avoids unnecessarytripping in such cases.

4. Locating faultsIt is possible to locate earth faults with the 7SJ6..definite time overcurrent-time relay as well aswith the distance protection relays 7SA5.., 7SA6...The precise setting of the line’s X layer is required.This can be taken from the appropriate tables inthe cable manual. In contrast, the setting of theZE/ZL factor is more difficult. Only measurementscan reveal the true facts here. The relays measurethe impedance loop as far as the fault location.If the above-mentioned set values are correct, anaccuracy of 3 % of the given fault distance can beexpected. In practice, the set values can be opti-mized on the basis of an exact empirical analysisof faults that have occurred.

5. SummaryIn a low-resistance-earthed system an earth fault isalways a short-circuit.The sensitivity of the pickup value for the earth-fault protection has to be set adequately to reliablytrip upon each earth fault.SIPROTEC line protection relays are availablewith the earth-fault protection function as anoption.In an overhead system about 70 % of the earthfaults are successfully eliminated by AR withoutsignificant system interruptions.



1. IntroductionSetting ground overcurrent elements on the typi-cal distribution circuit is a straightforward task.The ground element setting must be sensitiveenough to operate for the coordination point withthe lowest ground (earth) fault current. However,for circuits with large single-phase load diversity, alarge zero-sequence current (or 3I0), will be seenin the neutral due to this imbalance. The groundelement pickup setting must also be high enoughthat the relay does not trip for this level of zero-se-quence current. The amount of 3I0 present willchange for different system conditions, such assummer peak versus winter peak.

Typical relaying practices for a circuit that haslarge single-phase load diversity involve makingsome tradeoffs on the reliability of the protectionsystem. Generally, sensitivity (and therefore de-pendability) is lowered so the relay allows themaximum expected zero-sequence current in theneutral (maintaining security).

This application note introduces the idea of adap-tive relay settings to provide better groundovercurrent protection for circuits with large sin-gle-phase load diversity. The normal settings ofthe relay use a ground element with maximumsensitivity for fault conditions. As system condi-tions change and the load diversity increases, therelay adapts by decreasing the sensitivity of theground pickup, preventing a false operation by al-lowing more 3I0 to flow. Adaptive relay settingsprovide a cost-effective method of improving theprotection of distribution feeders, by automati-cally maintaining both dependability and securityas system conditions change.

2. Current practicesFor circuits with large single-phase load diversity,there are three philosophies used for settingground relay elements:

1. Disable the ground element: This allows themaximum amount of 3I0 present during loaddiversity. However, the method provides mini-mum protection. Only the phase elements willoperate for a ground fault, and, due to load al-lowance requirements, they may not have thesensitivity to see all phase-to-ground faults. Thismethod greatly lowers the dependability of theprotection system to maintain security.

Coping with Single-PhaseLoad Diversity UsingAdaptive Relay Settings

2. Lower the ground element sensitivity to allowthe maximum amount of 3I0 expected. Thismaintains some ground protection for all sys-tem conditions and doesn’t require constantcorrection of the relay settings. However, thesensitivity of the ground relay is not ideal, espe-cially when load diversity is small. Like disablingthe ground element, this method also lowers thedependability of the protection relay to main-tain security, but not as radically.



3. Change the ground element sensitivity for spe-cific system conditions. This method is usedwhen load diversity increases greatly for a longperiod of time, such as seasonal load peaks.Protection is maximized as much as feasible,but relay settings must be changed several timesa year. This method only lowers the depend-ability of the protection system when absolutelyrequired, and maintains security.

All three of these methods are in common use.From a pure protection standpoint, changing theground pickup settings for system conditions isthe best method. This method provides the bestsystem reliability, by only lowering dependabilitywhen required. The drawback is the cost in-volved. With electro-mechanical relays, fieldchanges of settings are required. Numerical relaysgenerally require remote control, auxiliary relays,and operator action to change settings groups.

3. New application conceptAdaptive relay settings allow a protection relay toautomatically, and independently, change settingsas the system operating conditions change. TheSiemens SIPROTEC 4 overcurrent relays (7SJ61,7SJ62, and 7SJ63), using the PLC programmingcapability in the Continuous Function Chart(CFC), can adapt relay settings automatically. Forthis application, a relay will adapt the ground ele-ment sensitivity as the amount of zero-sequencecurrent changes due to increasing single-phaseload diversity.

To adapt the ground element settings, the relay isprogrammed to change settings groups as themeasured zero-sequence current changes overtime. As the amount of 3I0 increases, and remainsabove a pre-determined threshold value, the relaychanges settings groups from one with maximumground element sensitivity, to one that providesless sensitivity for higher phase diversity.

When the amount of 3I0 decreases, and remainsbelow the predetermined threshold, the relay re-turns to the normal settings group. This concept isillustrated in Fig. 1.

Definition of the elements shown in Fig. 1:

Settings Group AThe “normal” settings group. The ground ele -ment pickup setting is set with maximum sensi-tivity to operate for a fault at the circuit reachpoint, while allowing the amount of 3I0 presentduring normal single-phase load diversity con-ditions.

Settings Group BThe alternate settings group. The ground ele-ment is set to allow the amount of 3I0 presentduring the maximum single-phase load diver-sity condition.

3I0 Current ThresholdThe level of zero-sequence current that indi-cates a change in single-phase load diversity ofthe circuit. The value of this threshold must belarge enough to indicate that the load diversityis actually changing, but less than the pickupsetting of the ground element for SettingsGroup A.

Threshold TimerThis time delay is used to ensure a larger loaddiversity exists, and that the diversity is not atransient condition. The increase in sin-gle-phase load diversity, as indicated by theamount of 3I0, must the load diversity settingsgroup. The timer must be set long enough toensure the load diversity has increased to newlevel, and has not just temporarily increased dueto a the addition of a large, transient, singlephase current draw condition. The timer mustalso be set so the relay can differentiate betweenfault conditions and changes in single-phaseload diversity.

Reset TimerThis is the time necessary to indicate a decreasein the single-phase load diversity. The single-phase load diversity, as indicated by the amountof 3I0, must stay below the 3I0 Current Thresh-old for this length of time to return the relay tothe original settings group. This timer must beset long enough to ensure the single-phase loaddiversity has actually returned to normal condi-tion.

Fig. 1 Adapting ground element settings



4. Application examplesThe load information shown in Table 1 is for acircuit with a summer peak. As shown, there is asignificant increase in the load and the amount of3I0 during the summer. It is desirable to use peakdemand values for load information, or when pos-sible, historical data for the amount of zero-se-quence current. For this example, the minimumfault current that the ground element must oper-ate for is 1.5 Asec.

Winter Summer

Phase A Load 1.25 Asec 2.38 Asec

Phase B Load 1.54 Asec 1.62 Asec

Phase C Load 1.35 Asec 1.42 Asec

3I0 Current 0.26 Asec 0.87 Asec

Table 1 Typical circuit load

Table 2 lists possible relay settings for the circuitload information from Table 1. The ground ele-ment pickup setting in Settings Group A is set toprovide a desired reach sensitivity to the mini-mum ground reach point, while allowing somepercentage of the normal amount of 3I0. For de-pendability, to ensure the ground element tripsfor all faults in the zone of protection, minimumreach is set in the range of 2/1 to 3/1. For security,the ground pickup should allow 120 % to 150 %of the normal amount of 3I0.

The ground element pickup setting for SettingsGroup B is set to maintain security by allowingsome percentage of the expected amount of 3I0.A typical setting range is 120 % to 150 %. This set-ting is balanced against the desire to maintainsome dependability by having some reach sensi-tivity to the minimum ground reach point.

The 3I0 Current Threshold is set at a level highenough to indicate a change in the single-phaseload diversity, but still below the ground elementpickup setting for Settings Group A. The 3I0 Cur-rent Threshold level, and the Threshold Timer,must also account for the rate of change of thezero-sequence current. If the threshold is toohigh, or the timer too long, the zero-sequence cur-rent may increase over the ground element pickupsetting before a settings change occurs. Once theground element is in pickup, no settings groupchange is possible, and the ground element willeventually trip.

The Reset Timer is set at a time long enough toensure that the single-phase load diversity hasactually decreased, to prevent the relay from“bouncing” between settings groups.

Element Setting Calculations

Setting Group AGround element pickup

0.5 Asec Reach = 1.5/0.5 = 3.0Allowance = 0.5/0.26 = 192 %

Ground element time dial 1.0

Setting Group BGround element pickup

1.1 Asec Reach = 1.5/1.1 = 1.36Allowance = 1.1/0.87 = 126 %

Ground element time dial 1.0

3I0 current threshold 0.45 Asec

Threshold timer 30 min

Reset timer 15 min

Table 2 Example relay settings

5. Implementation of adaptive relay settingsin a SIPROTEC 4 relay

Implementation of the adaptive relay setting logic,using the SIPROTEC 4 7SJ61, 7SJ62, and 7SJ63 re-lays, is in the Continuous Function Chart (CFC)portion of the relay. This is a graphical program-mable logic controller programming tool that per-mits the use of standard and advanced logic andcontrol capabilities. Using the CFC, the logic ofFig. 2 is implemented in the relay.

The zero-sequence current measured by the relayis compared to the 3I0 Current Threshold in the“Measurement” plan of the CFC. The output ofthis comparison is used in the “Slow PLC” plan tostart either the Threshold Timer or the ResetTimer. If the output of the comparison is logical 1,the Threshold Timer is started. Otherwise, the Re-set Timer is started. When the Threshold Timerexpires, a SR flip-flop is used to latch the “>SetGroup Bit0” command. Asserting the “>SetGroup Bit0” command changes the settings groupfrom A to B. When the Reset Timer expires, theSR flip-flop is reset, deasserting the “>Set GroupBit0” command, and changing the settings groupfrom B to A.

Fig. 2 Adaptive ground element logic



6. SummaryAdaptive relay settings provide a method formatching the reliability of the protection systemto the actual system conditions. When looking atthis example of single-phase load diversity, theprotection engineer has typically had to give upsome of the dependability of the protection sys-tem to maintain the security of the protection sys-tem. Adaptive relay settings give the relay theability to maximize the dependability of the pro-tection system, while not effecting security at all.

The idea of adaptive relay settings is a very power-ful concept that can be extended to many applica-tions. One possible application is to automaticallychange relay settings for temporary increases incircuit demand, such as during switching opera-tions.

7. ReferencesWilliam D. Stevenson, Jr. Elements of PowerSystem Analysis, 4th Ed., McGraw-Hill BookCompany, New York, NY; 1982

Turan Gonen, Electric Power Distribution SystemEngineering, McGraw-Hill Book Company,New York, NY; 1986

DIGSI CFC Instruction Manual, Siemens PowerTransmission and Distribution,Inc., Raleigh, NC; 1999

SIPROTEC Time-Overcurrent, Overload, AndMotor Protective Relay with Bay Controller 7SJ61V4.0/4.1 Instruction Manual, Siemens PowerTransmission and Distribution,Inc., Raleigh, NC; 1999


Line Protection in Transmission Systems

1. IntroductionThis application example will guide the readerthrough all the steps required to set the distanceprotection functions for a typical transmissionline. Standard supplements such as teleprotection,power swing, switch onto fault, directional earth-fault protection, etc. are also covered.

2. Key functions applied: Distance protection (ANSI 21):

Quadrilateral characteristic Teleprotection for ANSI 21:

POTT Earth fault O/C (ANSI 67N):

IEC curves, directional Teleprotection for ANSI 67N:

Directional comparison Power swing blocking Weak infeed:

Echo and trip Overcurrent protection:

Emergency mode Auto-reclose:

1 and 3-pole, 1 cycle Synchronism check:

Sync. and async. closing Fault locator:

Single-end measurement

3. Single line diagram and power systemdata

The required time graded distance protectionzones are:

400 kV OverheadTransmission LineProtection

Fig. 2 Single line diagram of protected feeder

Zone number Function Reach Time delay

Zone 1 Fast underreach protection for Line 1 80 % Line 1 0 s

Zone 2 Forward time delay backup, overreach 20 % less than Z1 reach on Line 3 1 time step

Zone 3 Reverse time delay backup 50 % Z-Line 1 2 time steps

Zone 4 Not applied – –

Zone 5 Non-directional 120 % Line 2 3 time steps

Table 1 Notes on setting the distance protection zones

Fig. 1 Universal protection for OHL

LSP2

589.

tif



Parameter Value

System data Nominal system voltage phase-phase 400 kV

Power system frequency 50 Hz

Maximum positive sequence source impedance 10 + j100

Maximum zero sequence source impedance 25 + j200

Minimum positive sequence source impedance 1 + j10

Minimum zero sequence source impedance 2.5 + j20

Maximum ratio: Remote infeed / local infeed (I2/I1) 3

Instrument transformers Voltage transformer ratio (LINE) 380 kV / 100 V

Voltage transformer ratio (BUS) 400 kV / 110 V

Current transformer ratio 1000 A / 1 A

Current transformer data 5P20 20 VA Pi = 3 VA

CT secondary connection cable 2.5 mm2 50 m

CT ratio / VT ratio for impedance conversion 0.2632

Line data Line 1 – length 80 km

Maximum load current 250 % of full load

Minimum operating voltage 85 % nominal voltage

Sign convention for power flow Export = negative

Full load apparent power (S) 600 MVA

Line 1 – positive seq. impedance per km Z1 0.025 + j0.21 Ω/km

Line 1 – zero seq. impedance per km Z0 0.13 + j0.81 Ω/km

Line 2 – total positive seq. impedance 3.5 + j39.5 Ω

Line 2 – total zero seq. impedance 6.8 + j148 Ω

Line 3 – total positive seq. impedance 1.5 + j17.5 Ω

Line 3 – total zero seq. impedance 7.5 + j86.5 Ω

Maximum fault resistance, Ph - E 250 Ω

Power data Average tower footing resistance 15 Ω

Earth wire 60 mm2 steel

Distance: Conductor to tower/ground (midspan) 3 m

Distance: Conductor to conductor (phase-phase) 5 m

Circuit-breaker Trip operating time 60 ms

Close operating time 70 ms

Table 2 Power system and line parameters

Based on the source and line impedance, the fol-lowing minimum fault current levels can be calcu-lated for faults on Line 1:

IU

Zfault

source

tot3=

⋅with Usource = 400 kV

If fault resistance is neglected then for 3-phasefaults:

Ztot = sum of positive sequence source and lineimpedance (as only current magnitudes are beingcalculated, only the magnitude of the impedanceis relevant)

|Ztot| = |(10 + 80 ⋅ 0.025) + j(100 + 80 ⋅ 0.21)|

|Ztot| = |12 + j116.8|

|Ztot| = 117.4

The minimum three-phase fault current is there-fore:

I 3400

3 117 4ph min

kV=⋅ .

I 3 1967ph min A=



If fault resistance is neglected then for single-phase faults:

Ztot = 1/3 (sum of positive, negative and zero se-quence source and line impedance)

The minimum single-phase fault current withoutfault resistance is therefore:

I1400

167 31380ph min

kV

3A=

⋅=

.

If fault resistance is included then for single-phasefaults:

Ztot_R = Ztot + RF

|Ztot_R| = |RF + Ztot|

|Ztot| = |250 + 19.8 + j166.1|

|Ztot| = 316.8

The minimum single-phase fault current withhigh resistance is therefore:

I1400

3 316 8729ph min_ R

kVA=

⋅=

.

4. Selection of device configuration(functional scope)

After selection and opening of the device in theDIGSI Manager, the first step when applying thesettings is entering the functional scope of the de-vice. A sample screen shot showing the selectionfor this example is given below:

The available functions displayed depend on theordering code of the device (MLFB). The selectionmade here will affect the setting options duringthe later stages. Careful consideration is therefore

required to make sure that allthe required functions are se-lected and that the functionsthat are not required in thisparticular application are dis-abled. This will ensure thatonly relevant settingalternatives appear later on.

103 Setting Group Change Option:Only enable this function, if more than onesetting group is required. In this exampleonly one setting group is used; therefore thisfunction is disabled.

110 Trip mode:On OHL applications, single-pole tripping ispossible if the circuit-breaker is capable ofthis. The advantage is that during a single-pole dead time the OHL can still transportsome power and reduce the risk of systeminstability. In this example both one andthree-pole tripping is used so the setting is1-/3-pole.

112 Phase Distance:As distance protection for phase faults is re-quired, Quadrilateral must be selected. Insome cases (depending on the ordering code)a MHO characteristic can also be selected.

113 Earth Distance:Here the earth fault distance protection char-acteristic is selected as for 112 above. There-fore set Quadrilateral.

120 Power Swing detection:If power swing conditions can occur in thevicinity of the applied relay, the power swingdetection must be enabled. It is required forblocking of the distance protection duringpower swings. At 380 kV it is common prac-tice to Enable the power swing detection.

121 Teleprotection for Distance prot.:To achieve fast tripping for all faults on thecircuit a teleprotection scheme must be ap-plied.

| || [( . ) ( . )] ( .

Zj

tot = ⋅ + ⋅ + + ⋅ + + ⋅2 10 80 0 025 100 80 0 21 25 80 013 200 80 0 81

3

) ( . )|+ + ⋅j

|Ztot| = |19.8 + j166.1|

|Ztot| = 167.3

Fig. 3 Selected scope of functions

LSP2

590.

tif



Parameter PUTT POTT Blocking Unblocking

Short line Not suitable as theZone 1 operation is es-sential and Zone 1 set-ting in X and Rdirection must besmall on short lines

Suitable as the Z1b set-ting may be substan-tially larger than theline impedance so thatsignal transmission issecure for all faults onthe line

Suitable as reversereach setting is inde-pendent of line length

Suitable as the Z1b set-ting may be substan-tially larger than theline impedance so thatsignal transmission issecure for all faults onthe line

Weak infeed Not suitable as theZone 1 operation is es-sential at both ends for100 % line coverage

Suitable as the strongend detects all linefaults with overreach-ing Z1b. The weakinfeed end then echosthe received signal

Partially suitable as thereverse fault is also de-tected at the weakinfeed end but no tripat weak infeed end

Suitable as the strongend detects all linefaults with overreach-ing Z1b. The weakinfeed end then echosthe received signal

Amplitude modulatedpower line carrier

Not suitable as the sig-nal must be transmit-ted through the faultlocation which attenu-ates the signal


Suitable as the signal isonly sent when the lineis not faulted


Frequency or phasemodulated power linecarrier

Suitable as the signalcan be transmittedthrough the fault loca-tion


Suitable as the signalcan be transmitted un-der all conditions


Communication inde-pendent of power line

Suitable Suitable Suitable Suitable

Table 3 Selection of teleprotection scheme

In this case the selection is POTT

122 DTT Direct Transfer Trip:If external inputs must be connected to initi-ate tripping via binary input, this functionshould be activated. The trip will then auto-matically be accompanied by the minimumtrip command duration (trip circuit seal in)and event and fault recordings. In this exam-ple this function is not required and there-fore Disabled.

124 Instantaneous High Speed SOTFOvercurrent:When closing onto bolted faults extremelylarge currents arise that must be switched offas fast as possible. A special overcurrent pro-tection stage is provided for this purpose. Inthis example it will not be used and is there-fore Disabled.

125 Weak Infeed:When weak infeed conditions exist (perma-nently or temporarily) at one or both ends,the weak infeed function must be Enabled.Refer also to Table 3.

126 Backup overcurrent:When the distance protection is in service, itprovides adequate backup protection for re-mote failures. The overcurrent protection inthe distance relay is usually only appliedwhen the distance function is blocked due to,for example, failure of the measured voltagecircuit (VT-fuse fail). This will be done inthis example, so the function must be acti-vated. The selection of the response curve

standard is Time Overcurrent Curve IEC inthis application.

131 Earth Fault overcurrent:For high resistance earth faults it is advisableto not only depend on the distance protectionas this would demand very large reach settingsin the R direction. The directional (and non-directional) earth-fault protection is very sen-sitive to high resistance earth faults and istherefore activated in this example. Here TimeOvercurrent Curve IEC is selected.

132 Teleprotection for Earth fault Overcurr.:To accelerate the tripping of the earth-faultprotection (activated under 131 above) ateleprotection scheme can be applied. In thisexample a Directional Comparison Pickupscheme will be applied.

133 Auto-Reclose Function:Most faults on overhead lines are of a tran-sient nature so that the line can be energisedsuccessfully after fault clearance. For thispurpose an automatic reclosure function canbe implemented to minimise the line outageby reclosing with a set or flexible dead time.In this application 1 AR-cycle will be applied.



134 Auto-Reclose control mode:If, as in this example, single and three-poletripping is used, the auto-reclose function istriggered by the trip command. If the trip isdue to a backup protection operation (e.g.Zone 2) then reclosure is normally not de-sired. By application of an action time whichmonitors the time between fault detectionand trip, reclosure can be prevented for timedelayed tripping (longer than set actiontime). In this example the auto-recloser willbe triggered with Trip and Action time mon-itoring.

135 Synchronism and Voltage Check:Before closing a circuit-breaker it is advisableto check that the system conditions on bothsides of the circuit-breaker are suitable forbeing connected. For this purpose the Syn-chronism and Voltage Check function is En-abled in this example.

138 Fault Locator:Following fault clearance an inspection of thefault location may be needed to check thatthere is no permanent damage or risk of fur-ther faults at the fault location. Particularlyon longer lines it is very helpful to have anindication of the fault location to allow fasteraccess by the inspection team. For this pur-pose the fault locator is Enabled in this ex-ample.

140 Trip Circuit Supervision:The monitoring done by the relay can be ex-tended to include the trip circuit and tripcoils. For this purpose a small current is cir-culated in the monitored circuits and routedvia binary inputs to indicate a failure. In thisexample this function is not used and there-fore set to Disabled.

5. Masking I/O (configuration matrix)The configuration matrix is used to route and al-locate the information flow in the device. All theassignments of binary inputs and outputs, as wellas LED’s, sequence of event records, user definedlogic, controls etc. are made in the matrix.

6. User defined logic CFCIf any special logic is required in the application,the CFC task can be used for this purpose.

7. Settings for power system data 17.1 Instrument transformersUnder this heading power system parameters areapplied. Place a ‘Tick’ in the box ‘Display addi-tional settings’ to include ‘advanced’ settings (des-ignated by A, e.g. 0214A) in the displayed list.

The ‘advanced’ settings can in most cases be lefton the default setting value.

201 CT Starpoint:In this application the CTs are connected asshown below in Figure 5. The polarity of theCT connection must be selected correctly toensure correct response by the protection.For this purpose the position of the starpoint

connection is indicated: In this example itmust be set towards line.

203 Rated Primary Voltage:The VT ratio must be set correctly to ensureaccurate measured value output. It is alsopossible to set the protection parameters inprimary quantities. For correct conversionfrom primary to secondary the VT and CTdata must be set correctly. In this applicationthe VT primary voltage is 380 kV.

204 Rated Secondary Voltage (ph-ph):Set to 100 V as per VT data.

205 CT Rated Primary Current:Set to 1000 A as per CT data.

Fig. 4 Configuration of CT and VT circuits

Fig. 5 Relay connections

LSP2

591.

tif

19"



206 CT Rated Secondary Current:Set to 1 A as per CT data. Note that this set-ting must correspond to the jumper settingson the measurement module (printed circuitboard). If this is not the case, the relay willblock and issue an alarm. Refer to devicemanual for instructions on changing jumpersettings.

210 U4 voltage transformer is:The 4th voltage measuring input may be usedfor a number of different functions. In thisexample it is connected to measure busbarvoltage for synchronising check (set Usynctransformer) as shown in Figure 6.

211 Matching ratio Phase-VT to Open-delta-VT:If in setting 210 the 4th voltage measuring in-put is selected to measure the open-deltavoltage (3 U0) then this setting must be usedto configure the transformation ratio differ-ence between the phase VT and the open-delta VT. As sync. check is applied this set-ting has no relevance.

212 VT connection for sync. voltage:If the setting 210 for the 4th voltage measur-ing input is selected to measure the voltagefor sync. check this setting must be applied todefine which voltage is used for sync. check.In this example, the voltage connected to U4

is the phase-phase voltage L3-L1 as shown inFigure 6.

214A Angle adjustment Usync-Uline:If there is a phase angle difference betweenthe voltage Usync and Uline, for example dueto a power transformer with phase shiftingvector group connected between the meas-uring points, then this phase shift must beset here. In this example the busbar is con-nected directly to the line so that there is0° phase shift.

215 Matching ratio Uline-Usync:If the transformation ratio of the VT forline voltage and sync. voltage measurementis not the same, then the difference must beset here. In this application:

Ratio correction

prim Line

sec Line

prim BUS

sec

=

U

UU

U BUS

= =

380

01400

011

105.

.

.

The required setting is therefore 1.05.

220 I4 current transformer is:The 4th current measurement may be usedfor a number of different functions. In thiscase it is used to measure the Neutral Cur-rent (of the protected line) by means of aHolmgreen connection. See Figure 5.

221 Matching ratio I4/Iph for CT’s:If the CT connected to I4 has a different ra-tio, for example a core balance CT, to theratio of the CT measuring the phase cur-rents of the protected circuit, this differ-ence must be set here. In this applicationthe ratio is the same so the setting must be1.00.

7.2 Power system data

207 System Starpoint is:The condition of the system starpointearthing must be set here. If the systemstarpoint is not effectively earthed, isolatedor resonant earthed, then the distance pro-tection response to simple earth faults willbe stabilised to prevent operation on tran-sient earth fault currents. In this exampleSolid Earthed applies.

Fig. 6 VT connections

Fig. 7 Power system data

LSP2

592.

tif



230 Rated Frequency:Set the rated system frequency to 50 Hz or60 Hz.

235 Phase Sequence:The phase sequence of the system is usuallypositive, L1 L2 L3. If the system has nega-tive phase sequence this can be set here. Inthis example the phase sequence is positive(L1 L2 L3).

236 Distance measurement unit:The distance measurement unit for thefault locator and certain line parameterscan either be in km or in miles. In this ex-ample km is used.

237 Setting format for zero seq. comp.:The distance protection includes a zerosequence compensation so that the samereach settings apply to phase and earthfaults. The zero sequence compensationcan either be set as RE/RL and XE/XL pa-rameters (standard format used by Siemensin the past) or as the complex ratio KO bymeans of a magnitude and angle setting. Inthis example the setting will be applied asZero seq. comp. factors RE/RL and XE/XL.

7.3 Breaker

239 Closing (operating) time of CB:This setting is only relevant if synchrocheck with asynchronous switching is con-figured. Under asynchronous closing, thesync. check function will determine the in-stant for issuing the close command so thatthe primary CB contacts close when theswitched voltages are in phase. For thispurpose the time that expires after applica-tion of the close command to the close coiluntil the primary contacts of the CB makemust be set here. From Table 2 the re-quired setting is 0.07 s.

240A Minimum TRIP Command Duration:The trip command to the circuit-breakermust have a minimum duration to ensurethat the CB responds and to prevent pre-mature interruption of the current in thetrip coil which may cause damage to thetrip contact which is not rated to interruptsuch a large inductive current.

When primary current flow is detected(measured current > pole open current:Parameter 1130) then the trip command issealed in by the current flow and will onlyreset once the current flow is interrupted(refer to Figure 9). When the trip com-mand is issued and no current flow is de-tected, the minimum trip command dura-tion set here will apply. It must be setlonger than the maximum time taken forthe CB auxiliary contacts to open and in-terrupt the current in the trip coil follow-ing the start of the trip command. The re-set conditions for the trip command can beset with parameter “1135 RESET of TripCommand”. From Table 2 the given circuit-breaker operating time is seen to be 60 ms.A safety margin of 50 ms is sensible so thata setting of 0.11 s is applied.

241A Maximum Close Command Duration:The close command must also have a mini-mum duration to ensure that the circuit-breaker can respond and that the auxiliarycontacts can interrupt the current flowthrough the close coil. If, following a closecommand, a trip is issued due to switch onto fault, the close command is reset imme-diately by the new trip command. Theclose command maximum durationshould be set at least as long as the maxi-mum time required by the CB auxiliarycontact to interrupt the close coil currentafter start of the close command. From Ta-ble 2 the given circuit-breaker operatingtime is seen to be 70 ms. A safety margin of50 ms is sensible so that a setting of 0.12 sis applied.

242 Dead Time for CB test-autoreclosure:One of the test features in DIGSI is the CBtest-autoreclosure. For this test the circuit-breaker is tripped and reclosed under nor-mal load conditions. A successful testproves that the trip and close circuits andthe CB are in a fully functional state. As thetest causes a disruption to the power flow(either single phase or three phase), thedead time should be as short as possible.While a normal dead time must allow forthe time required by the fault arc to dissi-pate (typically 0.5 s for three-pole trip and1s for single-pole trip), the test cycle mustonly allow for the circuit-breaker mecha-nism to open and close. Here a dead timeof 0.10 s is usually sufficient.

Fig. 8 Breaker parameters

LSP2

593.

tif



8. Settings for Setting Group AThe setting blocks that are available in SettingGroup A depend on the selections made duringthe selection of the device configuration (Heading4). If the setting group changeover had been acti-vated, a total of 4 setting groups would have beenavailable.

9. Settings for Power System Data 2Further power system data, in addition to PowerSystem Data 1, is set here. As these parameters areinside Setting Group A, they can be modified be-tween the setting groups if setting group change-over is activated.

9.1 Power system1103 Measurement: Full Scale Voltage (100 %):

For the indication and processing of meas-ured values it is important to set the fullscale value on the primary side. This doesnot have to correspond to the VT rated pri-mary voltage. When the primary value cor-responds to this setting the percentagemeasured value will be 100 %. Other per-centage measured values that also dependon voltage, such as for example power (P)will also have the full scale indication de-pendant on this setting. In Table 2 the sys-tem rated voltage is given and therefore setat 400 kV.

Fig. 9 Trip command seal in

Fig. 10 Setting blocks available in Setting Group A forthis application

Fig. 11 Power system settings in Power System Data 2

LSP2

594.

tif

LSP2

595.

tif



1104 Measurement: Full Scale Current (100%):For the indication and processing of mea-sured values it is important to set the fullscale value on the primary side. This doesnot have to correspond to the CT rated pri-mary current. When the primary value cor-responds to this setting the percentagemeasured value will be 100 %. Other per-centage measured values that also dependon current, such as for example power (P)will also have the full scale indication de-pendant on this setting. In Table 2 therated apparent power of the line is stated at600 MVA:

Full scale currentRated MVA

3 Full scale voltage

Fu

=⋅

ll scale current A=⋅

=600

3 400866

The measurement: Full scale current(100 %) is therefore set to 866 A.

1105 Line Angle:The line angle setting is calculated from thepositive sequence line impedance data. Inthis example:

Z1 = 0.025 + j0.21

Line angle arctanX

RL

L

=

Line angle = 83°

1211 Angle of inclination, distance charact.:This is usually set the same as the line an-gle. In this manner the resistance coveragefor all faults along the line is the same(Fig. 12). Therefore set for this applicationthe angle of inclination of the distancecharacteristic equal to the line angle whichis 83° .

1107 P,Q operational measured values sign:The measured values P and Q are desig-nated as positive when the power flow isinto the protected object. If the oppositesign is required, this setting must bechanged so that the sign of P and Q will bereversed. In Table 2 the sign convention forpower flow states that exported power(flowing into the line) is designated as neg-ative. The setting here must therefore bereversed.

1110 x’-Line Reactance per length unit:The line reactance per length unit (in thisexample per km) is required for the faultlocator output in km (miles) and percent.In Table 2 this is given as 0.21 Ω/km pri-mary. The setting can therefore be appliedas primary value 0.2100 /km, or it can beconverted to a secondary value:

x'CT ratio

VT ratiox'secondary primary= ⋅ =

1000

1380

01.

⋅

=

0 21

0 0553

.

.x'secondary

The setting in secondary impedance is0.0553 /km.

1111 Line Length:The line length setting in km (miles) is re-quired for the fault locator output. FromTable 2 set 80.0 km.

1116 Zero seq. comp. factor RE/RL for Z1:The zero sequence compensation setting isapplied so that the distance protectionmeasures the distance to fault of all faulttypes based on the set positive sequencereach. The setting is applied as RE/RL andXE/XL setting; here RE/RL for Zone 1 withthe data for Line 1 from Table 2.

R

R

R

RE

L

= ⋅ −

= ⋅ −

=1

31

1

3

013

0 0251 140

1

.

..

Apply setting RE/RL for Z1 equal to 1.40.

Fig. 12 Polygon and line angle



1117 Zero seq. comp. factor XE/XL for Z1:The same consideration as for parameter1116 above applies:

X

X

X

XE

L

= ⋅ −

= ⋅ −

=1

31

1

3

0 81

0 211 0 950

1

.

..

Apply setting XE/XL for Z1 equal to 0.95.

1118 Zero seq. comp. factor RE/RL for Z1B…Z5:As the overreaching zones cover the pro-tected line as well as adjacent circuits, thezero sequence compensating factor musttake the impedance parameters of the pro-tected line as well as the adjacent lines intoaccount. The Zone 2 reach has to beco-ordinated with the protection on theshortest adjacent feeder (Line 3) so that theZone 2 reach will be used to determine thissetting. The other zone reaches are largelyinfluenced by other system conditions suchas parallel and intermediate infeeds:

If the Zone 2 reach is set to 80 % of the to-tal impedance up to the Zone 1 reach onLine 3 (shortest adjacent line) then the to-tal positive sequence impedance at theZone 2 reach limit is:

X X X

XLine1 Line32 0 8 0 8

2 0 8 80 0 21 0 8 171

1

= ⋅ + ⋅= ⋅ ⋅ + ⋅

. ( . )

. ( . . . ) .5 24 64=

R RX X

XR

R

Line1Line1

Line3

Line322

2 80 0 02524

1

1

= + − ⋅

= ⋅ +

( )

.. .

.. .

64 80 0 21

17 515 2 672

− ⋅ ⋅ =

The corresponding zero sequence imped-ance is calculated as follows:

X XX X

X

X

Line1Line1

Line3

Line32 02

0

2 80 0 812

0

0

= + − ⋅

= ⋅ +

( )

.

X

4 64 80 0 21

17 586 5

2 10340

. .

..

.

− ⋅ ⋅

=X

R RX X

XR

R

Line1Line1

Line3

Line32 02

0

2 80 0132

0

0

= + − ⋅

= ⋅ +

( )

.4 64 80 0 21

17 57 5

2 13760

. .

..

.

− ⋅ ⋅

=R

This is graphically shown for the X valuesin Figure 13. A similar drawing can also bemade for the R values. Always use the Zone2 setting in the X direction as a reference.Now apply the derived values, X21, R21,X20 and R20 to the following equation:

R

R

R

RE

L

= ⋅ −

= ⋅ −

=1

31

1

3

1376

2 6721 1 380

1

.

..

Apply setting RE/RL for Z1B...Z5 equal to1.38.

1119 Zero seq. comp. factor XE/XL for Z1B…Z5:This is the XE/XL setting corresponding tothe RE/RL setting 1118 above. Thereforeapply the derived values, X21, R21, X20 andR20 to the following equation:

X

X

X

XE

L

= ⋅ −

= ⋅ −

=1

31

1

3

1034

24 641 1070

1

.

..

Apply setting XE/XL for Z1B...Z5 equal to1.07.

Fig. 13 Positive and zero sequence line impedanceprofile



9.2 Line status1130A Pole Open Current Threshold:

For a number of functions in the relay theswitching state of the circuit-breaker is animportant logical information input. Thiscan be derived via auxiliary contacts or bymeasuring the current flow in the circuit.With this parameter the current thresholdis set to determine the pole open conditionof the circuit-breaker. If the phase currentmeasured by the relay is below this thresh-old this condition for pole open detectionis true.

This setting should be as sensitive as possi-ble (setting equal to or lower than thesmallest current pick-up threshold of aprotection function). Stray induced cur-rents during a true open pole conditionmay however not cause incorrect pick-up.

In this example no special conditions haveto be considered, so the default setting of0.10 A is maintained.

1131A Pole Open Voltage Threshold:As was described for the pole open currentabove (1130A), the pole open voltage set-ting determines the threshold below whichthe voltage condition for pole open is true.

As single-pole tripping will be applied hereand the voltage transformers are located onthe line side of the circuit-breaker, the set-ting should be large enough to ensure thatthe voltage induced on the open phase isbelow this setting. Apply a setting that is atleast 20 % below the minimum operatingphase to earth voltage.

In this example the minimum operatingvoltage is 85 % of nominal voltage:

Setting< 0.8 ⋅ 0.85 ⋅ 400 kV/380 kV ⋅ 100/ 3 < 41

Therefore apply a setting of 40 V.

1132A Seal-in Time after ALL closures:When the feeder is energised the switch onto fault (SOTF) protection functions areactivated. The line closure detection condi-tions are set with parameter 1135 below.This seal-in time setting applies to all lineclosure detections other than the manualclose binary input condition. This directdetection of circuit-breaker closing re-sponds almost at the same instant as theprimary circuit-breaker contact closing. Afairly short seal in time can therefore be sethere to allow for pick-up of the desiredprotection functions.

In this application only the distance pro-tection will be used for switch on to faultso that a setting of 0.05 s is sufficient.

1134 Recognition of Line Closure with:As stated above (1132A) the recognition ofline closure is important for the switch onto fault protection functions. If the manualclose binary input is assigned in the matrix,it will be one of the line closure detectioncriteria. If other circuit-breaker closingconditions such as auto-reclose or remoteclosing are applied then it is advisable toapply additional criteria for line closure de-tection. In the table below the prerequisitesfor application of the individual conditionsare marked with X.

In this example, the manual close binaryinput and CB aux contacts are not allo-cated in the Matrix, so the conditions Volt-age and Current flow must be used for lineclosure detection. As the voltage trans-formers are on the line side, the settingCurrent or Voltage or Manual Close BI isapplied. Note that the inclusion of ManualClose is of no consequence because the bi-nary input is not allocated in the Matrix.

Line status settings in Power System Data 2

1134 Recognition ofLine Closure with:

Manual Close BI al-located in Matrix

CB aux allocated inMatrix

VT on line sideof CB

Manual Close BI X

Voltage X

Current flow Always valid Always valid Always valid

CB aux X

Table 4 Prerequisites for application of individual conditions in Parameter 1134LS

P259

6.ti

f



1135 RESET of Trip Command:The trip command duration must alwaysbe long enough to allow the circuit-breakerauxiliary contacts to interrupt the currentflowing through the trip coil. The most re-liable method for sealing in the trip com-mand is the detection of current flow in theprimary circuit through the CB. The auxil-iary contact status may be used as an addi-tional condition. This is helpful when tripcommands are issued in the absence of pri-mary current flow, e.g. during testing or byprotection functions that do not respondto current flow such as voltage or fre-quency protection. In this example, theauxiliary contacts are not allocated in theMatrix so that the trip command is resetwith Pole Open Current Threshold only.

1140A CT Saturation Threshold:CT saturation is normally detected bymonitoring of harmonic content in themeasured current. This is not possible forprotection response below 1 cycle as atleast one cycle of recorded fault current isrequired to determine the harmonic con-tent. Below one cycle the CT saturationcondition is therefore set when the currentexceeds this threshold. The following cal-culation gives an approximation of thiscurrent threshold:

CT Sutaration Threshold N= ⋅nI

'

5

with

n nP P

P P'

'= ⋅ +

+=N i

i

actual overcurrent factor

P’ = the actual burden connected to thesecondary CT relay burden + CTsecondary connection cable burden

In this example only the 7SA relay isconnected to the CT, so that the relay bur-den is 0.05 VA per phase. Due to theHolmgreen connection, the maximumburden for earth currents is therefore twice0.05 VA =0.1 VA.

The CT secondary cable connection bur-den is calculated as follows:

Rl

acable

cable CU

cable

= ⋅ ⋅2 ρ

lcable = 50 mρCU = 0.0179 Ωmm2/macable = 2.5 mm2

therefore:

R

R

cable

cable 0.72

= ⋅ ⋅

=

2 50 0 0179

2 5

.

.Ω

at 1 A nominal secondary current, this re-lates to:

P' = Rcable ⋅ IN CT2 +Prelay

P' = 0.72 ⋅ 12 + 0.1P' = 0.82 VA

From Table 2, the CT data is 5P20 20 VA,therefore:

n'.

= ⋅ ++

=2020 3

0 82 3120

with this value, the setting can then be cal-culated:

CT Sutaration Threshold A = 24 A= ⋅120

51

The applied setting in this case is therefore24.0 A.

1150A Seal-in Time after MANUAL closures:This setting is only applicable when themanual close binary input is allocated inthe Matrix (refer to setting 1134 above).The time applied here should allow for thecircuit-breaker response and any addi-tional delays such as sync. check releasewhich can occur between the initiation ofthe binary input and closure of the CB pri-mary contacts. In this example, the manualclose binary input is not allocated so thissetting is of no consequence and thereforeleft on the default value of 0.30 s.

1151 Manual CLOSE COMMAND generation:If the manual close binary input is allo-cated, it may be used to generate a closecommand to the circuit-breaker in the re-lay. Alternatively the input may be usedonly to inform the relay that a manualclose has been issued externally to the cir-cuit-breaker. If the relay has to generate aclose command following the initiation,this can be done with or without sync.check if the internal sync. check function isavailable. In this example the manual closebinary input is not allocated so this settingshould be set to NO.



1152 MANUAL Closure Impulse afterCONTROL:If the internal control functions are used,either via front keypad or system interface,the issued control-CLOSE command to thecircuit-breaker can be used to activate theprotection functions in the same manneras the manual-close binary input would.The setting options provided consist of allthe configured controls in the device. Inthis example, the internal control functionsare not used, so this setting is left on thedefault value: <none>

9.3 Trip 1/3-poleAs 1 and 3-pole tripping is applied in thisexample, the following settings must be applied:

1155 3 pole coupling:When single-pole tripping is applied therelay must select the faulted phase and tripsingle pole selectively. In the event of 2 si-multaneous faults, e.g. inter-circuit faulton double circuit line, the relay detects twofaulted phases, but only one of the two isinside a tripping zone. To ensure single-pole tripping under these conditions, set3-pole coupling to with Trip.

1156A Trip type with 2phase faults:Phase to phase faults without ground, canbe cleared by single-pole tripping. On cir-cuits where such faults occur frequently,e.g. conductor clashing due to conductorgalloping with ice and wind conditions,single-pole tripping for 2-phase faults canimprove availability of the circuit. The set-ting at both line ends must be the same. Ifsingle-pole tripping is selected, either theleading or lagging phase will then be trip-ped at both line ends. In this example 2-phase faults will be tripped 3-pole.

10. Distance protection, general settings –Setting Group A

10.1 General

1201 Distance protection is:If the distance protection must be switchedoff in this setting group, it can be done sowith this setting.In this example, only one setting group isused and the distance protection functionis required so this setting is left on the de-fault value which is ON.

1202 Phase Current threshold for dist. meas.:Although the distance protection respondsto the impedance of the faulted loop, alower limit must apply for the current flowbefore the distance protection responds. Ifthe system conditions can not ensure thatthis minimum current flows during all in-ternal short-circuit faults, special weakinfeed measures may be required (seechapter 14). It is common practice to applya very sensitive setting here so that theback-up functionality of the distance pro-tection for remote faults on other circuitsis effective. The default setting of 10 % istherefore commonly applied.In this application, no special conditionsexist, so the default setting of 0.10 A is ap-plied.

1211 Angle of inclination, distance charact.:This setting was already discussed and ap-plied in chapter 9.1 “Power system”, whereits association with the line angle was de-scribed. It is set to 83° .

1208 Series compensated line:On feeders in the vicinity of series capaci-tors, special measures are required for di-rection measurement.This application is without series capaci-tors on the protected or adjacent feeders,so the setting applied is NO.

Fig. 15 Trip 1/3-pole settings in Power System Data 2

Fig. 16 General settings for distance protection

LSP2

597.

tif

LSP2

598.

tif



1232 Instantaneous trip after SwitchOnToFault:When the protected circuit is switched off,a permanent fault (e.g. working earth orbroken conductor on ground) may bepresent. After switching on the circuit,such faults must be cleared as fast as possi-ble. It is common practice to activatenon-selective stages with fast tripping forswitch on to fault conditions. In the dis-tance protection a number of alternativesexists:

It is recommended to use the distance pro-tection for SOTF conditions. In many casesthe setting “with pickup (non-directional)”would result in a reach that operates due toheavy load inrush, e.g. when large machinesand transformers are connected to thefeeder so that the energising current ismore than twice the full load current. Inthese cases the Zone Z1B can be applied asits reach is typically only between approx.120 % and 200 % of the protected feeder.Of special interest is the application ofZone Z1B undirectional. If the local busbarcan be energised from the remote end viathe protected feeder, then SOTF conditionsfor busbar faults can be provided by appli-cation of this setting. Note that the line clo-sure detection should not be with thevoltage condition in this case, as the liveline voltage prior to energising the busbarwould prevent the SOTF release.In this example, the local bus will not beenergised via the feeder so the setting withZone Z1B is applied.

1241 R load, minimum Load Impedance (ph-e):The settings 1241 to 1244 determine the“load encroachment area” for the distancerelay setting characteristic. The distancezone settings must exclude the load area inthe impedance plane so that operation isonly possible under fault conditions. For

this purpose, the smallest load impedanceand the largest load impedance angle mustbe determined (refer to Fig. 17).

The load encroachment area is set forphase to earth loops (parameter 1241 and1242) and for phase to phase loops (para-meter 1243 and 1244) separately. Normallyload conditions will not cause earth faultdetection as no zero sequence current ispresent in the load. In the event of single-pole tripping of adjacent circuits, an earth-fault detection and increased load currentflow may be present at the same time. Forsuch contingencies, the load encroachmentmust also be set for earth-fault characteris-tics.

RI

load minoperation min

load max

=⋅

U

3

From Table 1, the minimum operatingvoltage is 85 % of nominal system voltage,and the maximum load current is 250 % ofthe full load apparent power.

U operation min kV kV= ⋅ =0 85 400 340.

I load max

MVA

kVA= ⋅

⋅=2 5

600

3 4002170.

By substituting these values in the aboveequation:

Rload min

kV=⋅

=340

3 217090 5. Ω

To convert this to a secondary value, mul-tiply it with the factor 0.2632 (Table 2) toobtain the setting 23.8 . As worst caseconditions are assumed, a safety factor isnot required. If the parameters for calcula-tion are less conservative, a safety factor,e.g. 10 to 20 % may be included in the cal-culation.

1242 PHI load, maximum Load Angle (ph-e):To determine the largest angle that the loadimpedance may assume, the largest anglebetween operating voltage and load currentmust be determined. As load current ide-ally is in phase with the voltage, the differ-ence is indicated with the power factorcos ϕ. The largest angle of the load impe-dance is therefore given by the worst,smallest power factor. From Table 2 theworst power factor under full load condi-tions is 0.9:

ϕ load max minarc power factor− = cos( )

ϕ load max arc− = = °cos( . )0 9 26

Setting Distance protection during SOTF

Inactive No special measures

With pickup (non-directional) All distance zones are released forinstantaneous tripping

With Zone Z1B The Zone Z1B is released for in-stantaneous tripping and will oper-ate with its set direction if a polaris-ing voltage is available

Zone Z1B undirectional The Zone Z1B is released for in-stantaneous tripping and will oper-ate as a non-directional zone.(MHO characteristic as forward andreverse zone)

Table 5 Setting alternatives for SOTF with distanceprotection



The power factor under full load condi-tions should be used for this calculation, asunder lightly loaded conditions the VARflow may dominate, but under these condi-tions the load impedance is not close to theset impedance reach. In this case the settingfor PHI load, maximum Load Angle (ph-e)is 26° .

1243 R load, minimum Load Impedance(ph-ph):No distinction is made in this example be-tween the maximum load during phase toearth pickup (adjacent circuit single-poleopen) and phase to phase pickup, e.g. whenparallel circuit is three-pole tripped. There-fore the same setting as for 1241 is appliedhere, being 23.8 .

1244 PHI load, maximum Load Angle (ph-ph):Again the same setting as for the phase toearth loop is applied here, being 26° .

1317A Single pole trip for faults in Z2:For special applications, single-pole trip-ping by Zone 2 can be applied. However,time delayed protection stages are usuallyapplied with 3-pole tripping.In this example, 3-pole tripping in Zone 2is desired so the default setting of NO is leftunchanged.

1357 Z1B enabled before 1st AR (int. or ext.):In this example a teleprotection scheme(POTT) is applied. The controlled ZoneZ1B operation is therefore subject to thesignals from the teleprotection scheme.In an application where no teleprotectionscheme is applied or in the case of a recep-tion failure of the teleprotection scheme,the Zone Z1B can also be controlled by theauto-reclose function.

This achieves fast tripping for all faults onthe feeder although some non-selectivetrips can also occur. This is tolerated insuch a scheme because following all fasttrips there is an automatic reclosure. In thisexample, the Z1B will only be controlled bythe teleprotection, the setting NO is there-fore applied.

10.2 Earth faults

1203 3I0 threshold for neutral current pickup:The distance protection must identify thefaulted loop to ensure correct response. Ifan earth-fault is present, this is detected bythe earth-fault detection. Only in this casewill the three earth loop measurements bereleased subject to further phase selectioncriteria. The earth current pickup is themost important parameter for the earth-fault detection. Its threshold must be setbelow the smallest earth current expectedfor faults on the protected feeder. As thedistance protection is also set to operate asbackup protection for remote externalfaults, this setting is set far more sensitivethan required for internal faults. In chapter3 the minimum single-phase fault currentfor internal faults neglecting fault resis-tance was calculated to be 1380 A.To allow for fault resistance and reach intoadjacent feeders for back-up, the settingapplied here should be substantially lowerthan this calculated value. In this example,the default value of 0.10 A secondary(100 A primary) is maintained.

Fig. 17 Load encroachment characteristic

Fig. 18 Earth-fault settings for distance protection

LSP2

599.

tif



1204 3U0 threshold zero seq. voltage pickup:A further criteria for earth-fault detectionis the zero sequence voltage. In an earthedsystem, zero sequence voltage is alwayspresent during earth faults and it decreasesas the distance between the measuringpoint and the fault location increases. Thisthreshold setting is therefore also used forearth-fault detection as shown in the logicdiagram, Fig. 19. When the zero sequencesource impedance is large, the zero se-quence current component in the faultcurrent may become small. In such anevent, the zero sequence voltage will how-ever be relatively large due to the small zerosequence current flowing through the largezero sequence source impedance.For secure earth-fault detection the defaultsetting of 5 V is maintained. If system un-balance during unfaulted conditions causeslarger zero sequence voltages then this set-ting should be increased to avoid earth-fault detection under these circumstances.

1207A 3I0> pickup stabilisation (3I0>/Iph max):In the event of large phase currents, thesystem unbalance (e.g. non-transposedlines) and CT errors (e.g. saturation) cancause zero sequence current to flow via themeasuring circuit of the relay although noearth fault is present. To avoid earth-faultdetection under these conditions, the zerosequence current pickup is stabilised bythis set factor.Unless extreme system unbalance or excep-tionally large CT errors are expected, thedefault setting of 10 % i.e. 0.10 can bemaintained, as is done for this example.

1209A Criterion for earth fault recognition:For the settings 1203 and 1204 above, andin Fig. 19, the method and logic of theearth-fault detection were explained. Withthis setting the user has the means to influ-ence the earth-fault detection logic. Inearthed systems it is recommended to usethe very reliable OR combination of zerosequence current and voltage for the earth-fault detection. As mentioned before, thesetwo criteria supplement each other so thatsmall zero sequence current is often associ-ated with large zero sequence voltage atweak infeeds and the other way around atstrong infeeds. The AND setting is only forexceptional conditions when, for example,the zero sequence voltage or current ontheir own are not a reliable indicator forearth faults.In this example, the default setting OR ismaintained for the reasons stated above.

Fig. 19 Earth-fault detection logic

Fig. 20 Stabilised zero sequence pickup threshold



1221A Loop selection with 2Ph-E faults:If some fault resistance (arc voltage) ispresent, then the measured fault loop im-pedances are affected by this additionalvoltage drop in the short-circuit loop. Inthe case of 2Ph-E faults this is most severeas the current in the fault resistance stemsfrom 3 different short-circuit loops. Theo-retical analysis and simulations show thefollowing distribution of the measuredloop impedances for a 2Ph-E fault:The influence of load (remote infeed andload angle) can increase or decrease the ro-tation of the measured fault resistances.The leading phase to earth loop will how-ever always tend to produce an overreach.For this reason, the default setting of blockleading Ph-E loop will be used in this ex-ample. If the application is on a double cir-cuit line where simultaneous earth faultson both lines can occur, the setting onlyphase-earth loops or all loops should beused to avoid blocking of the internal faultloop by this setting. Of course additionalgrading margin must be applied for Zone 1in this case to avoid an overreach during anexternal 2Ph-E fault.

10.3 Time delays1210 Condition for zone timer start:

During internal faults, all time delayedzones pickup unless there is substantialfault resistance and very strong remoteinfeed.Although the fault in Fig. 23 is an internalfault it is measured only by Zone Z4 due tothe fault resistance and strong remote in-feed. If all zone timers are started by thedistance pickup, the fault will be cleared bythe relay with the set Zone 2 time afterfault inception because the measured im-pedance moves into Zone 2 as soon as theremote, strong infeed trips the breaker onthe right hand side.From the timing diagram in Fig. 24 the in-fluence of this setting can be seen. If thezone timers are started with distancepickup, the trip signal is issued with Zone 2time delay (250 ms) after fault inception(distance pickup) although the Zone 2 onlypicks up some time later when the remoteend has opened the circuit-breaker on theright hand side. The timing of the trip sig-nals is therefore as if the fault had been in-side the Zone 2 all along. For external faultback-up tripping similar operation byhigher zones is achieved. This mode of op-eration will be applied in this example, sothe setting with distance pickup is applied.

Fig. 21 Impedance distribution for 2ph-E fault with fault resistance

Fig. 22 Time delay setting for the distance zones

Fig. 23 Influence of fault resistance and remote infeed on measured impedance

LSP2

600.

tif



If co-ordination with other distance orovercurrent protection is required, the set-ting “with zone pickup” can be applied.For the scenario described in Fig. 23 and 24this will however result in additional timedelay (∆t in Fig. 24). During external faultswith backup protection operation this timedelay may become very long, often a fulltime grading step so that reach and timegrading must be applied more conserva-tively.

1305 T1-1phase, delay for single phase faults:The Zone 1 is usually operated as fast trip-ping (instantaneous) underreach zone. Forthe fastest tripping all Zone 1 times are setto 0.00 s. For special applications, the triptime of single-phase faults may be set hereto differ from that for multi-phase faultswhich is set below with parameter 1306.

1306 T1 multi-ph, delay for multi phase faults:Also here the zone 1 is usually operated asfast tripping (instantaneous) underreachzone. For the fastest tripping all Zone 1times are set to 0.00 s. Refer also to setting1305 above.

1315 T2-1phase, delay for single phase faults:For the Zone 2 and higher zones the co-or-dination time must be calculated. Thistime must ensure that time graded trippingremains selective.In Fig. 25 the parameters that need to beconsidered for the time grading margin areshown. The values entered apply for thisexample and correspond to the worst caseconditions. The required time gradingmargin is therefore 250 ms. The Zone 2 isgraded with the Zone 1 at the remote feed-ers so that a single time grading step is re-quired (refer to Table 1). Set this time forsingle-phase faults to 0.25 s. For special ap-plications, the trip time of single-phasefaults may be set here to differ from thatfor multi-phase faults which is set belowwith parameter 1316.

1316 T2 multi-ph, delay for multi phase faults:As the Zone 2 will only trip three-pole inthis example, and no special considerationis given to single-phase faults, this time isset the same as 1315 above to 0.25 s.

1325 T3 delay:From Table 1, the required time delay forthis stage is two time steps = 0.50 s.

1335 T4 delay:From Table 1, this stage is not required sothe time delay can be set to infinity, s.

1345 T5 delay:From Table 1, the required time delay forthis stage is three time steps = 0.75 s.

1355 T1B-1phase, delay for single ph. faults:The zone Z1B will be used for theteleprotection in a POTT scheme. For thisapplication no time delay is required so thesetting here is 0.00 s. For special applica-tions, the trip time of single-phase faultsmay be set here to differ from that formulti-phase faults which is set below withparameter 1356.

Fig. 24 Timing diagram for fault in Fig. 23

Fig. 25 Time chart to determine time step for gradedprotection



1356 T1B-multi-ph, delay for multi ph. faults:As stated above the Zone Z1B will be usedfor the teleprotection in a POTT scheme.For this application no time delay is re-quired so the setting here is 0.00 s.

11. Distance zones (quadrilateral) – SettingGroup A

11.1 Zone Z11301 Operating mode Z1:

In the case of quadrilateral distance pro-tection zones, the user may select the oper-ating mode for each zone as either “for -ward”, “reverse”, “non-directional” or“inactive”. When the zone is “inactive”, itdoes not produce any pickup signals ortrip. The other options can be seen in theadjacent diagram where Z1, Z1B, Z2 andZ4 are set in the forward direction. Z3 is setin the reverse direction and Z5 is set non-directional. In this example, Zone 1 mustbe set in the forward direction.

1302 R(Z1), Resistance for ph-ph faults:As the distance protection is applied withpolygonal (quadrilateral) tripping charac-teristics, the zone limits are entered as re-sistance (R) and reactance (X) settings. Aseparate resistance reach setting is availablefor ph-ph measured loops and ph-e meas-ured loops. This setting is for the ph-phloops. With setting “1211 Angle of inclina-tion, distance charact.” the polygonR-reach is inclined such that it is parallel tothe line impedance (refer to Figure 12).The resistance settings of the individualzones therefore only have to cover the faultresistance at the fault location. For theZone 1 setting only arc faults will be con-sidered. For this purpose the arc resistancewill be calculated with the following equa-tion:

RU

Iarc

arc

F

=

The arc voltage (Uarc) will be calculated us-ing the following rule of thumb which pro-vides a very conservative estimate (theestimated Rarc is larger than the actualvalue):

U larc arcV= ⋅2500 whereby larc is thelength of the arc.

The length of the arc is greater than thespacing between the conductors (ph-ph),because the arc is blown into a curve due tothermal and magnetic forces. For estima-tion purposes it is assumed that larc is twicethe conductor spacing.

To obtain the largest value of Rarc , which isrequired for the setting, the smallest valueof fault current must be used (calculated inChapter 3):

Rarc

V m

A= ⋅ ⋅ =2500 2 5

196712 7. Ω

By addition of a 20 % safety margin andconversion to secondary impedance (factorfrom Table 2) the following minimum set-ting is calculated (division by 2 because Rarc

appears in the loop measurement while thesetting is done as phase impedance or posi-tive sequence impedance):

R Z( ). . .

. ( )11 2 12 7 0 2632

22 01= ⋅ ⋅ = Ω sec.

This calculated value corresponds to thesmallest setting required to obtain the de-sired arc resistance coverage. Dependingon the X(Z1) reach calculated (see nextpage), this setting may be increased to ob-tain the desired Zone 1 polygon symmetry.

Fig. 26 Distance zone settings (Zone 1)

Fig. 27 Quadrilateral zone diagram

LSP2

601.

tif



Therefore, looking ahead at the setting re-sult for “1303 X(Z1), Reactance” below, wesee that 3.537 Ohm are applied. For over-head line protection applications, the fol-lowing rule of thumb may be used for theR(Z1) setting:

0.8 ⋅ X(Z1) < R(Z1) < 2.5 ⋅ X(Z1)

In this example the lower limit applies, sothe setting for R(Z1) is:

R(Z1) = 0.8 ⋅ 3.537 = 2.830 Ω (sec.)

This setting is then applied, 2.830 .

1303 X(Z1), Reactance:The reactance reach is calculated based onthe distance reach that this zone must pro-vide. In Table 1 the reach of Zone 1 is spec-ified as 80 % of Line 1. Therefore:

X(Z1) = 0.8 ⋅ XLine 1

X(Z1) = 0.8 ⋅ 80 ⋅ 0.021 = 13.44 Ω (prim.)

This is converted to a secondary value bymultiplying with the conversion factor inTable 2:

X(Z1) = 13.44 ⋅ 0.2632 = 3.537 Ω (s)


1304 RE(Z1), Resistance for ph-e faults:The phase to earth fault resistance reach iscalculated along the same lines as the “1302R(Z1)” setting for ph-ph faults. For theearth fault however, not only the arc volt-age must be considered, but also the towerfooting resistance. From the graph in Fig-ure 29 it is apparent that although the indi-vidual tower footing resistance is 15 Ω(Table 2) the resultant value due to theparallel connection of multiple tower foot-ing resistances is less than 1.5 Ω.

From Fig. 28 it can be seen that the remoteinfeed (I2) will introduce an additionalvoltage drop across the “effective towerfooting resistance” which will be measuredin the fault loop by the relay (this effect isalso shown in Figure 23).

To compensate for this influence, the max-imum value (for practical purposes) of theratio of I2/I1 is required. This is given inTable 2 as the value 3. The maximumtower footing resistance that is measuredby the relay in the fault loop is therefore:

RI

ITF effective tower footing R= +

⋅12

1

RTF = (1 + 3) ⋅ 1.5 = 6 Ω (prim.)

The arc voltage for the earth faults is calcu-lated as follows using the conductor totower/ground spacing given in Table 2:

Uarc = 2500 V ⋅ larc

Uarc = 2500 V ⋅ 2 ⋅ 3 m = 15 kV

To obtain the largest value of Rarc , which isrequired for the setting, the smallest valueof fault current must be used (calculated inChapter 3):

Rarc

kV= =15

138010 9

ΩΩ.

The total resistance that must be coveredduring earth faults is the sum of Rarc andRTF . A safety factor of 20 % is included andthe result is converted to secondary values(division by factor (1 + RE/RL), becauseRarc and RTF appear in the loop measure-ment while the setting is done as phase im-pedance or positive sequence impedance):

RE Z sec.( ). ( . ) .

( . ). ( )1

1 2 10 9 6 0 2632

1 142 22= ⋅ + ⋅

+= Ω

This calculated value corresponds to thesmallest setting required to obtain the de-sired resistance coverage. Depending onthe X(Z1) reach calculated above, this set-ting may be increased to obtain desiredZone 1 polygon symmetry. The setting re-sult for “1303 X(Z1), Reactance” is3.537 Ω. For overhead line protection ap-plications, the following rule of thumb maybe used for the RE(Z1) setting; note thatthe lower limit is the same as for ph-phfaults – this ensures fast Zone 1 tripping,while the upper limit is based on the loopreach – this avoids overreach:Fig. 28 Combination of arc voltage and tower footing

resistance



0 8 1 11

12 5 1. ( ) ( ) . ( )⋅ < <

+

+⋅ ⋅X Z RE Z

XE

XLRE

RL

X Z

In this example the lower limit applies, sothe setting for RE(Z1) is:

RE Z sec.( ) . . . ( )1 0 8 3537 2 83= ⋅ = Ω


Fig. 29 Effective tower footing resistance



1305 T1-1phase, delay for single phase faults:The Zone 1 is required to trip as fast aspossible, therefore this time is set to 0.00 s.

1306 T1 multi-ph, delay for multi phase faults:The Zone 1 is required to trip as fast aspossible, therefore this time is set to 0.00 s.

1307 Zone Reduction Angle (load compensa-tion):The Zone 1 may under no circumstancesoperate for external faults as this wouldmean a loss of selectivity. The influence ofremote infeed in conjunction with fault re-sistance must be considered in this regard.From the voltage and current phasors inFig. 30 the influence of the transmissionangle (TA), i.e. angle between the voltagesVA and VB, on the measured fault resis-tance can be seen. In the impedance planethe phasor I2/I1 RF is rotated downwards bythe transmission angle. The risk of the ex-ternal fault encroaching into Zone 1 isshown. To prevent this, the Zone 1 X set-ting characteristic is tilted downwards bythe “Alpha angle”. A detailed calculation ofthe “Alpha angle” is complicated andheavily dependant on changing systemconditions. A worst practical case is there-fore selected to fix the “Alpha angle” set-ting. For this purpose the largesttransmission angle that can occur in thesystem during normal overload conditionsmust be applied to the following set ofcurves.

From Table 2 the maximum “Transmis -sion Angle “ for this application is given as35° . If this is checked in Figure 31 togetherwith the R1/X1 setting value of 0.8 (seeabove 2.830/3.537 = 0.8), then the required“Alpha Angle” setting is less than 15° (byusing the TA = 40 curve). A setting of 15°is therefore applied.

Fig. 30 Transmission angle for Alpha angle setting

Fig. 31 Curves for selection of Alpha angle setting



11.2 Zone Z1B

1351 Operating mode Z1B (overreach zone):The Zone Z1B will be used for theteleprotection scheme POTT in this appli-cation. For this the Zone Z1B must be ap-plied as forward overreach zone.

1352 R(Z1B), Resistance for ph-ph faults:As was the case for the Zone 1 settings, thissetting must cover all internal arc faults.The minimum setting therefore equals theR(Z1) setting, 2.830 Ω. However, addi-tional reach is set for the Z1B compared toZ1, because this is an overreach zone whileZ1 is set to underreach. The amount of ad-ditional R reach mainly depends on the ra-tio of R reach to X reach setting. For theZone Z1B the following limit is recom-mended:

X(Z1B) < R(Z1) < 4 ⋅ X(Z1)

Looking ahead at the applied setting for“1353 X(Z1B), Reactance” which is 6.633Ohm, it is apparent that the lower limit willapply. The setting of R(Z1B) therefore alsois 6.633 .

1353 X(Z1B), Reactance:The Zone Z1B must be set to overreachLine 1. The minimum setting is 120 % ofthe line reactance. In practice, however, asetting of 150 % or greater is applied unlessthe line in question is extremely long.

The risk of underreach due to the effectsshown in Figs. 21, 23 and 30 are thenavoided. For this application, mediumlength line, a reach of 150 % is selected:

X(Z1B) = 1.5 ⋅ XLine 1

X(Z1B) = 1.5 ⋅ 80 ⋅ 0.21 = 25.2 Ω (prim.)

The applied setting therefore is:

X(Z1B) = 25.2 Ω(prim.) ⋅ 0.2632

X(Z1B) = 6.633 Ω(sec.)

6.633 .

1354 RE(Z1B), Resistance for ph-e faults:As was the case for the Zone 1 settings, thissetting must cover all internal arc faults.The minimum setting therefore equals theRE(Z1) setting, 2.83 Ohm. As describedfor setting “1352 R(Z1B)” additional reachis usually applied and the following rule ofthumb is used for the RE(Z1B) setting:

1

1

1

14

+

+⋅ < <

+

+⋅ ⋅

XE

XLRE

RL

X(Z1B RE(Z1B

XE

XLRE

RL

X(Z1B) ) )

In this example the lower limit applies, sothe setting for RE(Z1B) is:

RE Z B(1 1.07)

(1 1.38)sec.( ) . . ( )1 6 633 5 769= +

+⋅ = Ω


1355 T1B-1phase, delay for single ph. faults:In this POTT scheme both single andmulti-phase faults must be tripped withoutadditional delay. The setting 0.00 s is there-fore applied.

1356 T1B-multi-ph, delay for multi ph. faults:In this POTT scheme both single andmulti-phase faults must be tripped withoutadditional delay. The setting 0.00 s is there-fore applied.

1357 Z1B enabled before 1st AR (int. or ext.):This setting was already applied in Chapter10.1 and is repeated here with the otherZ1B settings. The setting is NO.

Fig. 32 Settings for Zone Z1B

LSP2

602.

tif



11.3 Zone Z2

1311 Operating mode Z2:The Zone Z2 is used as the first overreach-ing time graded zone. It must therefore beapplied in the forward direction.

1312 R(Z2), Resistance for ph-ph faults:Resistance coverage for all arc faults up tothe set reach (refer to Table 1) must be ap-plied. As this zone is applied with over-reach, an additional safety margin is in-cluded, based on a minimum setting equiv-alent to the X(Z2) setting and arc resis-tance setting for internal faults, R(Z1)setting. Looking ahead, X(Z2) is set to6.485 . Therefore:

R Rmin( ) ( )Z2X(Z2)

X (s)Z

Line1

= ⋅ 1

R(.

. .. . ( )Z2) sec.min =

⋅ ⋅⋅ =6 485

80 0 21 0 26322 83 415 Ω

The setting of R(Z2) therefore is 4.150 .

1313 X(Z2), Reactance:According to the grading requirement inTable 1:

X Z X XCTratio

VTratioLine1 Line3( ) . ( . )2 0 8 0 8= ⋅ + ⋅ ⋅

X Z

X Z sec

( ) . ( . . . ) .

( ) . (

2 0 8 80 0 21 0 8 17 5 0 2632

2 6 485

= ⋅ + ⋅ ⋅= Ω .)

The applied setting therefore is 6.485 .

1314 RE(Z2), Resistance for ph-e faults:Similar to the R(Z2) setting, the minimumrequired reach for this setting is based onthe RE(Z1) setting which covers all internalfault resistance and the X(Z2) settingwhich determines the amount of over-reach. Alternatively, the RE(Z2) reach canbe calculated from the R(Z2) reach withthe following equation:

R RE ZX(Z

X sec.E Z

Line

( ))

( )( ) .2

21 1 2

1

= ⋅ ⋅

RE(Z2) sec.)=⋅ ⋅

⋅ ⋅ =6 485

80 0 21 0 26322 83 1 2 4 98

.

. .. . . (Ω


1315 T2-1phase, delay for single phase faults:This setting was already applied in Chapter10.3 and is shown here again with all theZone 2 settings. The setting 0.25 s is ap-plied.

1356 T2-multi-ph, delay for multi phase faults:This setting was already applied in Chapter10.3 and is shown here again with all theZone 2 settings. The setting 0.25 s is ap-plied.

1317A Single pole trip for faults in Z2:This setting was already applied in Chapter10.1 and is shown here again with all theZone 2 settings. The setting NO is applied.

11.4 Zone Z3

1321 Operating mode Z3:Zone Z3 is used as reverse time delayedback-up stage (refer to Table 1). It musttherefore be set in the reverse direction.

1322 R(Z3), Resistance for ph-ph faults:Resistance coverage settings for backupprotection with distance protection zonesis defined by a lower limit and upper limit.The lower limit is the minimum fault resis-tance (arc resistance) that must be covered,and the upper limit is based on the corre-sponding X reach setting. Note that forhigh resistance faults (not arc faults), theother infeeds to the reverse fault cause se-vere underreach.As no detailed values are available, it is safeto assume that the required arc resistancecoverage is the same as that calculated forfaults on Line 1. Therefore the setting forR(Z1), 2.830 Ω, defines the lower limit.The upper limit is given by reach symmetryconstraints and states that R(Z3)<6 timesX(Z3). Looking ahead, X(Z3) is set to2.211 Ω, so the upper limit is 13.266 Ω.A setting halfway between these limits is asafe compromise:

Fig. 33 Settings for Zone Z2


LSP2

603.

tif

LSP2

604.

tif



RR

( )( ) ( )

ZZ X Z

31 6 3

2= + ⋅

R( ). .

. ( )Z sec.32 83 6 2 211

28 048= + ⋅ = Ω


1323 X(Z3), Reactance:According to the grading requirement inTable 1:

X Z3 XCTratio

VTratio( ) .= ⋅ ⋅0 5 1Line

X Z3 sec.( ) . . . . ( )= ⋅ ⋅ ⋅ =0 5 80 0 211 0 2632 2 211 Ω


1324 RE(Z3), Resistance for ph-e faults:Similar to the R(Z3) setting, the upper andlower limits are defined by minimum re-quired reach and symmetry. In this appli-cation set the RE(Z3) reach the same asR(Z3) to 8.048 .

1325 T3 delay:This setting was already applied in Chapter10.3 and is shown here again with all theZone 3 settings. The setting 0.50 s is ap-plied.

11.5 Zone Z4

1331 Operating mode Z4:Zone Z4 is not applied (refer to Table 1). Itmust therefore be set as inactive direction.

Further settings in this block are of no con-sequence and therefore not discussed here.

11.6 Zone Z5

1341 Operating mode Z5:Zone Z5 is used as non-directional finalbackup stage (refer to Table 1). It musttherefore be set as non-directional zone.

1342 R(Z5), Resistance for ph-ph faults:Resistance coverage settings for backupprotection with distance protection zonesis defined by a lower limit and upper limit.The lower limit is the minimum fault resis-tance (arc resistance) that must be covered,and the upper limit is based on the corre-sponding X reach setting. Note that forhigh resistance faults (not arc faults), theother infeeds to the reverse fault cause se-vere underreach.As no detailed values are available, the re-quired arc resistance coverage is calculatedfor the arc voltage (5 m) and 50 % of nom-inal current or 500 A primary.

R( )/

ZV m m

A

CTratio

VTratiomin5

2500 2 5

500= ⋅ ⋅ ⋅

R( ) . . ( )Z sec.min52500 2 5

5000 2632 1316= ⋅ ⋅ ⋅ = Ω

This setting would ensure detection inZone 5, if the arc voltage, as calculated inChapter 11.1, is for 5 m conductor spacingand the fault current is at least 500 A. Theupper limit is given by reach symmetryconstraints and states that R(Z5)< 6 timesX(Z5) + or X(Z5) –. Looking ahead, X(Z5)is set to 17.782 Ω, so the upper limit is106.69 Ω. This is far into the load area (re-fer to parameter 1241, calculated in Chap-ter 10.1). A setting of double the minimumis a safe compromise:

R(Z5) = R(Z5)min ⋅ 2

R(Z5) = 13.16 Ω ⋅ 2 = 26.32 Ω



Fig. 36 Settings for Zone Z5LS

P260

5.ti

f

LSP2

606.

tif



1343 X(Z5)+, Reactance for Forward direction:According to the grading requirement inTable 1:

X Z X XCTratio

VTratioLine1 Line2( ) . ( )5 1 2= ⋅ + ⋅

X Z( ) . ( . . ) .5 1 2 80 0 21 39 5 0 2632= ⋅ ⋅ + ⋅

X(Z5) = 17.782 Ω (sec.)


1344 RE(Z5), Resistance for ph-e faults:Similar to the R(Z5) setting, the upper andlower limits are defined by minimum re-quired reach and symmetry. In this appli-cation set RE(Z5) reach to the same asR(Z5). The applied setting therefore is26.32 .

1345 T5 delay:This setting was already applied in Chapter10.3 and is shown here again with all theZone 5 settings. The setting 0.75 s is ap-plied.

1346 X(Z5)-, Reactance for Reverse direction:For non-directional Zone Z5 the followingsymmetry requirement can be applied, ifno other conditions are specified:

0.5 ⋅ X(Z5)+ < X(Z5)- < 2 ⋅ X(Z5)+

In this case the lower limit will apply sothat:

X (Z5)- = 0.5 ⋅ X (Z5)+X (Z5)- = 0.5 ⋅ 17.782X (Z5)- = 8.891 Ω(sec.)


12. Power swing – Setting Group A

2002 Power Swing Operating mode:In the event of a power swing, tripping bythe distance protection due to the meas-urement of the “swing impedance” must beprevented. The setting all zones blocked istherefore applied.

2006 Power swing trip:When the power swing is severe and an outof step condition is reached, selectivepower swing tripping should be applied inthe system to obtain stable islanded subsys-tems. This relay is not positioned on suchan interconnection so out of step trippingis not required, therefore setting is NO.

2007 Trip delay after Power Swing Blocking:If during a power swing, which is detectedby the relay, an external switching opera-tion takes place, a jump of the measured“swing impedance” takes place. This jumpcan reset the power swing detection. Toprevent tripping, if this impedance is insidethe protected zones, a delay time of 0.08 sis set to allow the power swing measure-ment to securely pick up again.

13. Teleprotection for distance protection –Setting Group A

2101 Teleprotection for Distance prot. is:In this application the teleprotection isON.

2102 Type of Line:The line is a two terminal line.

2103A Time for send signal prolongation:In the event of sequential operation at thetwo line ends or very slow operation at oneend, the end that trips first may reset andstop transmitting the send signal before theslow end is ready to operate. The send sig-nal prolongation time ensures that the tripsignal only resets once the remote end hashad sufficient time to pickup.

Fig. 37 Power swing settings

Fig. 38 Teleprotection for distance protection settings

LSP2

607.

tif

LSP2

608.

tif



In Figure 39 the delayed pickup of the re-mote end, after opening of the local cir-cuit-breaker, must be considered to ensurethat the send signal is not reset too soon.Channel timing is neglected as it adds on tothe safety margin. The times indicated inthe drawing apply in this example so that asetting of 0.05 s is applied.

2109A Transient Block.: Duration external flt:The transient blocking, also referred to ascurrent reversal guard, is required with thePOTT scheme, if parallel circuits are pre-sent. During clearance of a fault on theparallel circuit, the fault current may re-verse on the protected circuit. To avoidoperation of the POTT scheme under theseconditions, the transient blocking times areapplied. To ensure that transient blockingis only activated by external faults, it onlystarts following reverse fault detection forthis time which is set to 80 % of the fastestfault clearance on the parallel circuit (in-cluding CB operation).

The setting 0.04 s is applied.

2110A Transient Block.: Blk. T. after ext. flt:Following clearance of the external fault,the transient blocking condition must bemaintained until both line ends securelydetect the new fault condition. For thispurpose the relay pickup time (re-orienta-tion) and channel delay time must be con-sidered.

Tb T T= ⋅ +1 2. ( )channel_ delay relay_re-orientation

Tb = + =1 2 20 20 48. ( )ms ms ms

The setting 0.05 s is applied.

14. Weak infeed (trip and/or echo) –Setting Group A

2501 Weak Infeed function is:When the POTT teleprotection scheme isused, the weak infeed function can be ap-plied for fast fault clearance at both lineends even if one line end has very weak orno infeed. The weak infeed function mustbe activated at the line end where a weakinfeed can occur. If a strong infeed is as-sured at all times, this function can beswitched off. The function may also beused to only send an echo back to thestrong infeed, so that it can trip with thePOTT scheme, or to trip at the weak infeed

end in addition to sending the echo. In thisapplication both Echo and Trip will beused.

2502A Trip /Echo Delay after carrier receipt:As the communication channel may pro-duce a spurious signal (unwanted recep-tion), a small delay is included for securitypurposes. Only if the receive signal is pres-ent for this time will the weak infeed func-tion respond. In the event of 3-pole opencondition of the circuit-breaker, this timedelay is bypassed and the echo is sent im-mediately. The default setting of 0.04 s isappropriate for this application.

2503A Trip Extention / Echo Impulse time:To ensure that the echo signal can be se-curely transmitted, it must have a definedminimum length. On the other hand, apermanent echo signal is not desired.Therefore the echo is sent as a pulse withthis set length. If tripping is also applied,then this time also defines the length of theinternal trip signal (refer also to parameter240 A in Chapter 7.3). The default settingof 0.05 s is appropriate for this application.

Fig. 39 Time chart to send signal prolongation time

Tw T T T= ⋅ + −0 8. ( circuit_ breaker relay_ parallel_ Line relay_ protected_ Line)

Tw = ⋅ + − =0 8 60 40. ( )ms 10 ms 20 ms ms

Fig. 40 Weak infeed settings

LSP2

609.

tif



2504A Echo Block Time:If weak infeed echo is applied at both lineends, then it must be avoided that a re-ceived echo signal is again sent as echo in acontinuous stream of echo signals. For thispurpose, this blocking time is set to pre-vent a new weak infeed operation before itexpires. A secure setting of this timer is thetime required for a signal to be transmittedfrom one end to the other and back again(twice the channel delay time) plus a safetymargin of 10 ms. In this application, aworst channel delay time of 20 ms is as-sumed so that a setting of 0.05 s is appro-priate.

2505 Undervoltage (ph-e):The weak infeed trip signal (phase selec-tive) is supervised by this undervoltagethreshold. At the weak infeed end thesource impedance is very large so that verysmall voltages are measured during faultson the protected circuit. If this threshold isset well below the minimum operationalph-e voltage then weak infeed tripping issecure and phase selective. Simulations andpractical experience have shown that a set-ting of 50 % nominal ph-e voltage providesgood results. The default setting of 25 V istherefore applied.

2509 Echo Logic: Dis and EF on common chan-nel:If the distance protection and directionalearth-fault protection are both appliedwith teleprotection (Distance with POTTand EF with directional comparison) thesignals can be routed via one commonchannel or via two separate channels in thecommunication system. The weak infeedand echo logic must be set accordingly toensure correct response. In this applica-tion, two separate channels are used so thesetting is NO.

15. Backup overcurrent – Setting Group A15.1 General

2601 Operating mode:The distance protection is more selectiveand more sensitive than the overcurrentprotection. The overcurrent protection istherefore only required when the distanceprotection is blocked due to failure of thevoltage measuring circuit (emergencymode). Therefore the operating mode is setto ON: only active with loss of VT sec. cir.

2680 Trip time delay after SOTF:Following line closure detection the“Switch On To Fault” function is activated(refer to parameters 1132A and 1134 inChapter 9.2). The backup overcurrent sta-ges may also be used for SOTF tripping.This timer sets the time delay for SOTF tripwith a backup overcurrent. In this applica-tion SOTF with backup overcurrent is notapplied so the setting of this timer is notrelevant; leave the default value of 0.00 s.

15.2 I>> stage

2610 Iph>> Pickup:This high set stage is required to trip withsingle time step grading. It should there-fore have a reach equivalent to the Zone 2setting. The setting should therefore beequal to the maximum 3-phase fault cur-rent for a fault at the Zone 2 reach setting.

Based on the source and line impedances,the following maximum fault current levelcan be calculated for faults at the Zone 2reach limit:

IU

faultsource

totZ=

⋅3with Usource = 400 kV

Ztot = sum of minimum positive sequencesource and line impedance up to Zone 2reach (as only current magnitudes are be-ing calculated, only the magnitude of theimpedance is relevant)

Fig. 41 General settings, backup overcurrent

Fig. 42 I>> stage settings, backup overcurrent

LSP2

610.

tif

LSP2

611.

tif



The maximum three-phase fault current atthe Zone 2 reach limit therefore is:

I 3400

3 34 86636ph Z2

kVAmax

.=

⋅=

As a secondary value, the setting applied forI>> is therefore 6.64 A.

2611 T Iph>> Time delay:This high set stage is required to trip withsingle time step grading. Therefore set 0.25 swhich is one time step (refer to Fig. 25).

2612 3I0>> Pickup:This high set stage is required to trip earthfaults with single time step grading. Itshould therefore have a reach equivalent tothe Zone 2 setting. The setting should there-fore be equal to the maximum single-phasefault current for a fault at the Zone 2 reachsetting.

Based on the source and line impedances,the following maximum fault current levelcan be calculated for faults at the Zone 2reach limit:

IU

faultsource

totZ=

⋅3with Usource = 400 kV

Ztot = 1/3 of the sum of minimum positive,negative and zero sequence source and lineimpedance up to Zone 2 reach (as only cur-rent magnitudes are being calculated, onlythe magnitude of the impedance is relevant)

For the 3-phase fault level used in setting2610, the total positive sequence impedancewas calculated. As the negative sequenceimpedance equals the positive sequencevalue, the Ztot for this setting can be calcu-lated as follows:

| | |( . ( . ))Z j(Xtot source_ min ine1 Line2 s= + ⋅ + ⋅ +R R RL0 8 0 8 ource_ min Line1 Line2X X+ ⋅ + ⋅0 8 0 8. ( . ))|

| | |( . ( . . . )) . ( .Z j(tot = + ⋅ ⋅ + + + + ⋅ ⋅1 0 8 80 0 025 0 8 15 10 0 8 80 0 21 0 8 17 5+ ⋅. . ))|

| | . .Z jtot = +356 34 64

| | .Z tot = 34 8

|Z |Z

tottot source_ min Line1=

⋅ + + ⋅ +| ( . ( ._2 0 0 8 0 0 82610 R R ⋅ + + ⋅ + ⋅R s0 0 0 8 0 0 8 0Line2 ource_ min Line1 Line2j(X X X)) . ( . ))|

3

|Z |j(

tot = + + ⋅ ⋅ + ⋅ + +|( . . . ( . . . )) .712 2 5 0 8 80 013 0 8 7 5 69 28 20 0 8 80 0 81 0 8 86 5

3

+ ⋅ ⋅ + ⋅. ( . . . ))|

|Z tot| = |7.58 + j65.49|

|Z tot| = 65.9



The maximum single-phase fault current atthe Zone 2 reach limit therefore is:

I 3400

3 65 93504ph Z2

kVAmax

.=

⋅=

As a secondary value, the setting appliedfor 3I0>> is therefore 3.50 A.

2613 T 3I0>> Time delay:This high set stage is required to trip withsingle time step grading. Therefore set 0.25 swhich is one time step (refer to Fig. 25).

2614 Instantaneous trip via Teleprot./BI:The backup overcurrent is only activewhen the distance protection is blockeddue to failure of the secondary VT circuit(refer to setting 2601 in Chapter 15.1). Ifunder these conditions a teleprotection sig-nal is received from the remote end, thetripping of the overcurrent protection maybe accelerated. This may be safely appliedfor this stage, because its reach is less thanthe set Z1B. Therefore apply the settingYES. Note that for this function to work,the binary input function “7110 >O/CInstTRIP” must be assigned in parallel tothe teleprotection receive binary input ofthe distance protection.

2615 Instantaneous trip after SwitchOnToFault:This function is not applied (refer to set-ting 2680 in Chapter 15.1). Therefore NOis set.

15.3 I> stage

2620 Iph> Pickup:This stage is required to trip with time de-lay equal to Zone 5. It may not pick up dueto load (permissible overload). The per-missible overload is twice the full load,therefore:

Iph PickupRated MVA

Full scale voltage> ≥ ⋅

⋅2

3

Iph Pickup A> ≥ ⋅⋅

=2 600

3 4001732

As a secondary value, the setting appliedfor I> is therefore 1.74 A.

2621 T Iph> Time delay:This stage is required to trip with the sametime delay as Zone 5, three time gradingsteps. Therefore set 0.75 s which is threetime steps (refer to Fig. 25).

2622 3I0> Pickup:This stage is required to trip with time de-lay equal to Zone 5. It should detect earthfaults with similar sensitivity as Zone 5.Therefore, with the weakest infeed accord-ing to Table 2, an earth fault at the X reachlimit of Zone 5 will have the following cur-rent magnitude:

3

3 1

IU

0 Z5_ minnom_ sec

source_ max Z5_ settX XXE

XL

=⋅ + ⋅ +( )

3100

3 100 0 2632 17 782 1 1 38I0 Z5_ min =

⋅ ⋅ + ⋅ +( . . ) ( . )

3 0 55I0 Z5_ min A= .

As a secondary value, the setting appliedfor 3I0> is therefore 0.55 A.

2623 T 3I0>> Time delay:This high set stage is required to trip withthree time grading steps. Therefore set0.75 s which is three time steps (refer toFig. 25).

2624 Instantaneous trip via via Teleprot./BI:The I>> stage is applied for this purpose,refer to setting 2614 in Chapter 15.2.Therefore set NO for this stage.


Fig. 43 I> stage settings, backup overcurrent

LSP2

612.

tif



15.4 Inverse stage

2640 Ip> Pickup:The co-ordination of inverse time gradedprotection can be applied effectively to ob-tain reasonably fast and sensitive selectiveprotection. In this application, the inversestage is not used, so the setting here is in-finity, A.

2642 T Ip Time Dial:As the setting of 2640 above is infinity (∞),this setting is not relevant and left on thedefault value of 0.50 s.

2646 T Ip Additional Time Delay:This stage may also be used as a furtherdefinite time delay stage by using this set-ting. As the setting of 2640 above is infinity(∞), this setting is not relevant and left onthe default value of 0.00 s.

2650 3I0p Pickup:The co-ordination of inverse time gradedprotection can be applied effectively to ob-tain reasonably fast and sensitive selectiveprotection. In this application, the inversestage is not used, so the setting here is in-finity, A.

2652 T 3I0p Time Dial:As the setting of 2650 above is infinity (∞),this setting is not relevant and left on thedefault value of 0.50 s.

2656 T 3I0p Additional Time Delay:This stage may also be used as a furtherdefinite time delay stage by using this set-ting. As the setting of 2650 above is infinity(∞), this setting is not relevant and left onthe default value of 0.00 s.

2660 IEC Curve:During the device configuration (Chapter4) the standard of the curves was selectedwith parameter 0126 to be IEC. Here thechoice is made from the various IECcurves. As the stage is not applied in thisapplication the setting is not relevant andleft on the default value of Normal inverse.

2670 Instantaneous trip via Teleprot./BI:The I>> stage is applied for this purpose,refer to setting 2614 in Chapter 15.2.Therefore set NO for this stage.


15.5 I STUB stage

2630 Iph> STUB Pickup:This stage may be used as a normal definitetime delay stage. In addition to this, it pro-vides for blocking or release via binary in-put. For certain applications (e.g.1 ½ CB) aSTUB exists when the line isolator is open.By releasing this overcurrent stage via thementioned binary inputs, a fast selectivefault clearance for faults on the STUB canbe obtained. In this application, no suchSTUB protection is required, so this stageis disabled by applying an infinite pickupvalue with the setting A.

2631 T Iph STUB Time delay:As the setting of 2630 above is infinity (∞),this setting is not relevant and left on thedefault value of 0.30 s.

2632 3I0> STUB Pickup:This stage may be used as a normal definitetime delay stage. In addition to this, it pro-vides for blocking or release via binary in-put. For certain applications (e.g.1 ½ CB) aSTUB exists when the line isolator is open.By releasing this overcurrent stage via thementioned binary inputs, a fast selectivefault clearance for faults on the STUB canbe obtained. In this application, no suchSTUB protection is required, so this stageis disabled by applying an infinite pickupvalue with the setting A.

2633 T 3I0 STUB Time delay:As the setting of 2632 above is infinity (∞),this setting is not relevant and left on thedefault value of 2.00 s.

Fig. 44 Inverse stage settings, backup overcurrent

Fig. 45 I STUB stage settings, backup overcurrent

LSP2

613.

tif

LSP2

614.

tif



2634 Instantaneous trip via Teleprot./BI:The I>> stage is applied for this purpose,refer to setting 2614 in Chapter 15.2.Therefore set NO for this stage.


16. Measurement supervision – SettingGroup A

16.1 Balance / Summation

2901 Measurement Supervision:Only in exceptional cases will the measure-ment supervision not be activated. There-fore this setting should always be ON.

The advanced settings 2902A to 2909A can beused to modify the parameters of the monitoringfunctions. Generally, they can all be left on theirdefault values.

16.2 Measured voltage failure

2910 Fuse Failure Monitor:Only in exceptional cases will the fuse fail-ure monitor not be activated. Thereforethis setting should always be ON.

For the voltage failure detection, the default pa-rameters can be applied for the advanced settings.

2915 Voltage Failure Supervision:In the event of energising the primary cir-cuit with the voltage transformer second-ary circuit out of service, an alarm “168Fail U absent” will be issued and the emer -gency mode activated. This monitoringtask can be controlled with this parameter2915. As no auxiliary contacts of the cir-cuit-breaker are allocated, it is only con-trolled with current supervision.

16.3 VT mcb

2921 VT mcb operating time:If an auxiliary contact of the mcb is utilised(allocated in the matrix), the operatingtime of this contact must be entered here.Note that such an input is not required inpractice as the relay detects all VT failures,including the operation of the mcb viameasurement. This set time will delay alldistance protection fault detection so itshould in general not be used. In this appli-cation, it is also not required and thereforeleft on the default setting of 0 ms.

17. Earth-fault overcurrent – Setting Group A17.1 General

3101 Earth Fault overcurrent function is:For the clearance of high resistance earthfaults this function provides better sensitiv-ity than the distance protection. As high re-sistance earth faults are expected in thisapplication, this function is activated bysetting it ON.

3102 Block E/F for Distance protection:As the distance protection is more selective(defined zone reach) than the earth-faultprotection and has superior phase selectionit is set to block the E/F protection withevery pickup.

Fig. 46 Balance/Summation settings, measurementsupervision

Fig. 47 Measured voltage fail settings, measurementsupervision

Fig. 48 VT mcb settings, measurement supervision

Fig. 49 General settings, earth fault overcurrent

LSP2

615.

tif

LSP2

616.

tif

LSP2

617.

tif

LSP2

618.

tif



3174 Block E/F for Distance Protection Pickup:As fast single-pole tripping is only donewith Zone 1 and Zone 1B with the distanceprotection, the earth-fault protection isonly blocked when the distance protectionpicks up in Zone Z1/Z1B.

3103 Block E/F for 1pole Dead time:During 1-pole dead times, load current canflow via the zero sequence path. To preventincorrect operation of the earth-fault pro-tection as a result of this it should beblocked. Therefore set YES.

3104A Stabilisation Slope with Iphase:When large currents flow during faultswithout ground, CT errors (saturation)will cause current flow via the residualpath. The earth-fault protection, having avery sensitive pickup threshold for high re-sistance faults, could pick up due to thisCT error current. To prevent this, a stabi-lising characteristic is provided to increasethe threshold when the phase currents arelarge. The characteristic is shown below inFigure 50. The default setting of 10 % issuitable for most applications.

3105 3I0-Min threshold for Teleprot. schemes:For directional comparison protection, inparticular for the weak infeed echo func-tion, a teleprotection send or echo blockcondition must be more sensitive than theteleprotection trip condition. This thresh-old determines the minimum earth currentfor teleprotection send and is set to 80 % ofthe most sensitive teleprotection trip stage.Set

3 0 8 30 0I TP I_ .= ⋅ >>

3 0 8 0 580I TP_ . .= ⋅

3 0 460I TP_ .= A

Therefore apply the setting of 0.46 A.

3109 Single pole trip with earth flt. prot.:The distance protection is set to cover allarc faults on the line. High resistance faultsusually are due to mechanical defects (bro-ken conductors or obstructions in the line)so that an automatic reclosure is not sensi-ble. Therefore, set earth fault only forthree-pole tripping by application of NO.

3170 2nd harmonic for inrush restraint:When energising the line, connected trans-formers and load may cause an inrush cur-rent with zero sequence component. Thisrush current can be identified by its 2ndharmonic content. In this application in-rush blocking is not required and not ap-plied in the individual stages. The setting isof no consequence, so leave the defaultvalue of 15 %.

3171 Max. Current, overriding inrush restraint:If very large fault currents flow, CT errorsmay also cause some 2nd harmonic. There-fore the rush blocking is disabled whencurrent is above this threshold. As statedfor parameter 3170 above, the inrush re-straint is not applied in this example. Thissetting is of no consequence, so leave thedefault value of 7.50 A.

3172 Instantaneous mode after SwitchOnToFault:The earth-fault protection may be acti-vated with a set time delay (parameter3173) in the case of line energising (SOTF).In this application, only the distance pro-tection function is used for SOTF so thatthis setting is of no consequence, so leavethe default value of with pickup and direc-tion.

3173 Trip time delay after SOTF:As stated for parameter 3172 above, thistimer defines the delay of the SOTF trip byearth-fault protection. As it is not applied,the default value of 0.00 s is left unchanged.

Fig. 50 Stabilisation of 3I0 pickup threshold



17.2 3I0>>>

3110 Operating mode:A total of 4 stages are available, one ofwhich may be applied as inverse stage. Inthis application only three stages will beused, the 3I0>>> stage for fast (single timestep) directional operation and the 3I0>>stage for time delayed directional opera-tion and fast directional comparison aswell as the 3I0> stage for non-directionalbackup operation. This stage must there-fore be set to Forward.

3111 3I0>>> Pickup:This stage must operate with the same sen-sitivity as the backup (emergency)overcurrent stage 3I0>> (refer to setting2612). Therefore apply the setting 3.50 Ahere. Note that this stage is only activewhen distance protection is not picked up,and it is directional (no reverse fault opera-tion) whereas the backup O/C stage onlyoperates in the emergency mode when dis-tance protection is not available.

3112 T 3I0>>> Time delay:This stage must operate with single timestep delay. Therefore set 0.25 s here.

3113 Instantaneous trip via Teleprot./BI:The stage 3I0>> will operate withteleprotection, so the setting here is NO .

3114 Instantaneous trip after SwitchOnToFault:As stated above, only the distance protec-tion operates with SOTF, so set NO here.

3115 Inrush Blocking:As stated above, inrush blocking is not ap-plied, so set NO here.

17.3 3I0>>

3120 Operating mode:In this application only three stages will beused, the 3I0>>> stage for fast (single timestep) directional operation and the 3I0>>stage for time delayed directional opera-tion and fast directional comparison aswell as the 3I0> stage for non-directionalbackup operation. This stage must there-fore be set to Forward.

3121 3I0>> Pickup:This stage must operate for all internalhigh resistance faults, use a 20 % margin.

3 0 80I I>> = ⋅Pickup 1ph min_ R.

3 0 8 729 5830I >> = ⋅ =Pickup A.

In secondary values therefore set 0.58 A.

3122 T 3I0>> Time delay:This stage must operate with two time stepdelays. Therefore set 0.50 s here.

3123 Instantaneous trip via Teleprot./BI:The stage 3I0>> will operate withteleprotection, so the setting here is YES .



Fig. 51 3I0>>> stage settings, earth fault overcurrent

Fig. 52 3I0>> stage settings, earth fault overcurrent

LSP2

619.

eps

LSP2

620.

tif



17.4 3I0>

3130 Operating mode:In this application only three stages will beused, the 3I0>>> stage for fast (single timestep) directional operation and the 3I0>>stage for time delayed directional opera-tion and fast directional comparison aswell as the 3I0> stage for non-directionalbackup operation. This stage must there-fore be set to Non-Directional.

3131 3I0> Pickup:This stage must operate for all internalhigh resistance faults, the same as 3I0>>,but non-directional and with longer timedelay. In secondary values therefore set0.58 A.

3132 T 3I0> Time delay:This stage must operate with four time stepdelays. Therefore set 1.00 s here.

3133 Instantaneous trip via Teleprot./BI:The stage 3I0>> will operate withteleprotection, so the setting here is NO.



17.5 3I0 Inverse time

3140 Operating mode:This stage is not required so it is set toInactive.

Because this stage is inactive, the settings 3141 to3151 are of no consequence and left on their de-fault values.

17.6 Direction

3160 Polarization:Because both applied stages of the earth-fault overcurrent protection are directional(forward), the choice of polarising signalmust be carefully considered. If both nega-tive and zero sequence infeed are present atthe relay location polarisation with U0 +IY or U2 provides excellent results. Theearth current from a star connected andearthed transformer winding is only in-cluded, when the 4th current input of therelay is connected as such. In this applica-tion, this current input measures the resid-ual current of the protected line, (parame-ter 220 in Chapter 7.1). Therefore only thezero sequence or negative sequence voltageare used as polarising signal with this set-ting. The choice is automatic (the larger ofthe two values is chosen individually dur-ing each fault).

Fig. 53 3I0> stage settings, earth fault overcurrent

Fig. 54 3I0 Inverse time stage settings, earth fault overcurrent

Fig. 55 Direction settings, earth fault overcurrent

LSP2

621.

tif

LSP2

622.

tif

LSP2

623.

tif



3162A ALPHA, lower angle for forward direction:The default direction limits have been opti-mised for high resistance faults and are leftunchanged at 338° here.

3163A BETA, upper angle for forward direction:The default direction limits have been opti-mised for high resistance faults and are leftunchanged at 122° here.

3164 Min. zero seq. voltage 3U0 for polarizing:The zero sequence voltage is one of the val-ues for directional polarising. Under highresistance fault conditions, this value maybecome very small. For the setting it is cal-culated using the minimum single-phasefault current under high resistance faultconditions and the smallest zero sequencesource impedance (this includes a safetymargin as these two conditions will not co-incide):

3I I Z0 min 1 ph min_ R 0 source_ min= ⋅

3 729 20 14 58I0 min kV= ⋅ = .

As secondary value this is:

3 3100

380U U0 min_ sec 0 min

V

kV= ⋅

3 14 58100

38038U 0 min_ sec kV

V

kVV= ⋅ =. .

Therefore apply the setting 3.8 V.

3166 Min. neg. seq. polarizing voltage 3U2:Although a similar calculation as done for3164 would return a smaller value (50 %),this is not applied, as an automatic selec-tion of the larger of the two voltages wasset (parameter 3160). The setting appliedhere therefore is the same as that for thezero sequence voltage. Therefore apply thesetting 3.8 V.

3167 Min. neg. seq. polarizing current 3I2:Apply here the minimum negative se-quence current flowing for high resistancefaults with a 20 % margin.

3 0 8I I2 min 1 ph min_ R= ⋅.

3 0 8 729 583 2I2 min A= ⋅ =. .

Therefore apply the setting 0.58 A.

3168 Compensation angle PHI comp. for Sr:This setting is only relevant for directiondecisions based on zero sequence power. Inthis application it is of no consequence andleft on default value of 255° .

3169 Forward direction power threshold:This setting is only relevant for directiondecisions based on zero sequence power. Inthis application it is of no consequence andleft on default value of 0.3 VA.

18. Teleprotection for earth faultovercurrent – Setting Group A

3201 Teleprotection for Earth Fault O/C:In this application the teleprotection is re-quired and applied as “Directional Com -parison Pickup”, refer to parameter 132 inChapter 4. This function is therefore acti-vated by setting it ON.

3202 Line Configuration:The line is a two terminal line.

3203A Time for send signal prolongation:As the same type of communication withthe same channel delay time is used for dis-tance teleprotection and earth-fault tele-protection, the same setting considerationas for parameter 2103A in Chapter 13 ap-plies here. Therefore in this example a set-ting of 0.05 s is applied.

3209A Transient Block.: Duration external flt.:As the same type of communication withthe same channel delay time is used for dis-tance teleprotection and earth-fault tele-protection, the same setting considerationas for parameter 2109A in Chapter 13 ap-plies here. Therefore in this example a set-ting of 0.04 s is applied.

3210A Transient Block.: Blk. T. after ext. flt.:As the same type of communication withthe same channel delay time is used for dis-tance teleprotection and earth-fault tele-protection, the same setting considerationas for parameter 2110A in Chapter 13 ap-plies here. Therefore in this example a set-ting of 0.05 s is applied.

Fig. 56 Teleprotection for earth fault overcurrentsettings

LSP2

624.

tif



19. Automatic reclosure – Setting Group A19.1 General

3401 Auto-Reclose function:In this application the automatic reclosurefunction is required and applied with “1Cycle” and “with Trip and Action Time”,refer to parameters 133 and 134 in Chap-ter 4. This function is therefore activatedby setting it ON.

3402 CB ready interrogation at 1st trip:Before a reclosure is attempted the circuit-breaker status must be checked. This canbe done before the reclose cycle is started(prior/at time of initiation) or before thereclose command is issued. In this applica-tion the breaker status is checked beforethe close command is issued by the reclo-ser, so this setting must be NO.

3403 Reclaim time after successful AR cycle:If the reclose is successful, the reclosermust return to the normal state which ex-isted prior to the first fault. The time sethere is started by each reclose commandand must take the system conditions intoaccount (also the circuit-breaker recoverytime may be considered). Here a setting of3.00 s is applied.

3404 AR blocking duration after manual close:If the manual close binary input is as-signed, then the AR should be blocked for aset time after manual close to prevent ARwhen switching onto a fault. In this appli-cation the manual close binary input is notassigned, SOTF is recognised by currentflow and AR is not initiated in this case.This setting is not relevant here as themanual close binary input is not assigned,the default setting of 1.00 s is left un-changed.

3406 Evolving fault recognition:If during the single-pole dead time a fur-ther fault is detected (evolving fault), theAR function can respond to this in a de-fined manner. The detection of evolvingfault in this application will be done by de-tection of a further (new) trip commandinitiation to the AR function. Therefore setwith Trip.

3407 Evolving fault (during the dead time):The response to the evolving fault duringthe single-pole dead time is set here. In thisapplication it is set to starts 3pole AR-cycle.

3408 AR start-signal monitoring time:If the AR start signal (protection trip) doesnot reset after a reasonable time (breakeroperating time plus protection reset time),then a problem with either the circuit-breaker (breaker failure) or the protectionexists and the reclose cycle must not bestarted. Here the maximum time for theinitiate signal is set. If it takes longer, theAR cycle is not started and a final trip con-dition is set. Apply a setting of twice thebreaker operating time plus protection re-set time, i.e. 0.20 s.

3409 Circuit Breaker (CB) Supervision Time:As the CB ready status will be checkedprior to issue of the close command, a timelimit must be applied during which thisready status must be reached. If it takeslonger, a final trip status is set andreclosure does not take place. This timelimit is set here to be 3.00 s.

3410 Send delay for remote close command:The AR function can be applied to send aclose command to the remote end via com-munication channels. This is not appliedhere, so the time is left on the default set-ting of infinity, s.

3411A Maximum dead time extension:The AR function can be applied to wait forrelease by sync. check or CB status beforerelease of close command. Here, the maxi-mum extension of the dead time in thecourse of waiting for release conditions isset. In practice, a limitation to less than 1minute is practical. In this application 10 swill be used.

Fig. 57 General settings, automatic reclosureLS

P262

5.ti

f



19.2 1st auto reclose cycle

3450 Start of AR allowed in this cycle:As this is the only AR cycle that is applied,starting must be allowed in this cycle, so setthis parameter to YES.

3451 Action time:As indicated with parameter 134 in Chap-ter 4, the action time is used to differentiatebetween faults cleared without delay by themain protection and backup protectionoperation for external faults. The actiontime must be set below the calculated coor-dination time step (0.25 s) and must belonger than the slowest operation withteleprotection (60 ms). A time of 0.20 s isapplied.

3456 Dead time after 1pole trip:The dead time must allow for the arc gasesto dissipate. During single-pole trip thistime is longer, because the arc is still sup-plied by capacitive coupled current fromthe healthy phases after the circuit-breakeris open single pole. In practice a time of1.00 s has proven to provide good results.

3457 Dead time after 3pole trip:The dead time must allow for the arc gasesto dissipate. During three-pole trip thistime is short. In practice a time of 0.50 shas proven to provide good results.

3458 Dead time after evolving fault:As set in parameters 3407 and 3408 above,a three-pole dead time will be started in thecase of evolving fault. Here the same timeas in parameter 3457 can be used becausethis time is started with the three-pole tripissued due to the fault evolving from singleto three phase. Therefore set 0.50 s.

3459 CB ready interrogation before reclosing:As stated above, the CB status will bechecked before issue of close command.Therefore set YES.

3460 Request for synchro-check after 3pole AR:The sync. check condition must be checkedbefore issue of close command. Thereforeset YES.

19.3 3pTRIP / dead line charge / reduced deadtime

3430 3pole TRIP by AR:If the AR function is initiated by single-pole trip signals, it may in the course of asingle-pole AR cycle detect that the condi-tions for single-pole reclosure are no lon-ger valid (e.g. because of further single-pole trip during the dead time or auxiliarycontact status from the breaker indicatingmultiple pole open, etc.). In such an event,the AR function may issue a three-pole tripbefore proceeding with a three-pole AR cy-cle or setting the final trip condition. Thissetting determines whether the AR func-tion will issue such a three-pole trip. In thisapplication no external initiate signals areapplied so this setting is set to NO, becausethe internal protection functions can man-age their own three-pole coupling of thetrip signal when required.

3431 Dead Line Check or Reduced Dead Time:Special reclose programs can be applied toprevent repetitive reclose onto fault and tominimise dead times. In this applicationthese programs are not used, so set With-out.

The settings 3438, 3440 and 3441 are of no conse-quence, because 3431 is set to “Without”.Leave these settings on their default values.

Fig. 58 1st AR cycle settings, automatic reclosure

Fig. 59 3-pole Trip/DLC/RDT settings, automatic reclosure

LSP2

626.

tif LS

P262

7.ti

f



19.4 Start autoreclose

3420 AR with distance protection:The distance protection will trip single poleand three pole and start the autoreclos-ure, so set YES here.

3422 AR with weak infeed tripping:The weak infeed tripping will trip singlepole and three pole and start the autoreclos-ure, so set YES here.

3423 AR with earth fault overcurrent prot.:The earth-fault overcurrent protection willtrip three pole and not start the autoreclos-ure, so set NO here.

3425 AR with back-up overcurrent:The backup overcurrent protection willtrip and start the autoreclosure, so set YEShere. Note that due to the action time (pa-rameter 3451 in Chapter 19.2) only the ac-celerated trip with teleprotection will resultin reclosure.

20. Synchronism and voltage check –Setting Group A

20.1. General

3501 Synchronism and Voltage Check function:In this application the synchro check isused, so this function must be selected ON.

3502 Voltage threshold dead line/bus:If the measured line/bus voltage is belowthis set threshold, the line/bus is consid-ered to be switched off (dead). In this ap-plication the L3-L1 phase to phase voltageis used for synchronism check, so that thevoltage thresholds must be based on phaseto phase voltage. In general, a setting of10 % can be applied, when the voltage isbelow 10 %, the line/bus is definitely dead.

Where parallel lines can couple in largervoltages onto the dead line, a higher settingmay be appropriate. In this case, no paral-lel lines exist, so the setting of 10 % will beused:

Udead = 0.1 ⋅ UN

Udead = 0.1 ⋅ 110 = 11 V

The value for UN in this case (110 V) isbased on the busbar voltage transformers(phase to phase), as this results in the larger(more conservative) setting. Apply the set-ting of 11 V.

3503 Voltage threshold live line/bus:If the measured line/bus voltage is abovethis set threshold, the line/bus is consid-ered to be switched on (live). In this appli-cation the L3-L1 phase to phase voltage isused for synchronism check, so that thevoltage thresholds must be based on phaseto phase voltage. The setting must be below(20 % safety clearance) the minimum an-ticipated operating voltage (in this example85 % of the nominal voltage):

Ulive = 0.8 ⋅ 0.85 ⋅ UN

U live

kV

kVV= ⋅ ⋅ ⋅ =0 8 0 85

400

380100 716. . .

The value for UN in this case (400/380 ⋅110 V)is based on the line voltage transformers(phase to phase), as this results in the lower(more conservative) setting. Apply the set-ting of 71 V.

3504 Maximum permissable voltage:If the measured line or bus voltage is abovethis setting, it is considered to be a toolarge operating voltage for release of a closecommand. This setting must be above thehighest expected operating voltage that isstill acceptable for release of the close com-mand. In general, a setting of 110 % of thenormal operating voltage is recommended.On long lines, the local line voltage fedfrom the remote end may rise to a highervalue due to the Ferranti effect (normallycompensated by shunt reactors on theline). In this case, a higher setting may berequired. In this example we will use a110 % setting:

Umax = 1.10 ⋅ UN

Umax = 1.10 ⋅ 110 = 121 V

The value for UN in this case (110 V) isbased on the busbar voltage transformers(phase to phase), as this results in the larger(more conservative) setting. Apply the set-ting of 121 V.

Fig. 60 Settings for starting the AR, Automatic reclosure

LSP2

628.

tif

Fig. 61 General settings for synchronism and voltagecheck

LSP2

638.

tif



3507 Maximum duration of synchronism check:If the synchronism check conditions arenot obtained within this set time, the sync.check is terminated without release orclose. The person that issues the sync.check request (operator close commandinitiation) expects a response from theswitchgear within a reasonable time. Thistime should be set to the maximum timesuch operating personnel would accept towait for a response. Typically, a setting of60.00 s is an acceptable delay.

3508 Synchronous condition stability timer:When the set synchro check conditions aremet, the release can be delayed by this set-ting to ensure that this condition is notonly a transient condition. In general, thisadditional stability check is not required,so that this setting can be set to 0.00 s.

3509 Synchronizable circuit breaker:The integrated control functions may alsotrigger the sync. check measurement. Forthis purpose the appropriate switchgearitem can be selected in this setting. In thisapplication example, the integrated controlfunctions are not used, so that the setting<none> is applied.

20.2. Settings for operation with auto-reclosureThe following group of settings is relevant forclose commands that originate from theauto-reclose function. This can be the internal AR,which is directly coupled with the internal sync.check, or an external AR device that couples thetrigger signal via binary input to the sync. checkfunction.

3510 Operating mode with AR:If the close release must be possible underasynchronous conditions (line and bus fre-quency are not the same), then the circuit-breaker closing time must be consideredfor timing of the close command. Refer tosetting 239 in Chapter 7.3. In this exampleclosing under asynchronous conditionsmust be possible, so apply the setting: withconsideration of CB closing time.

3511 Maximum voltage difference:In this setting the maximum voltage mag-nitude difference is set. If the magnitudesof the line and bus voltage differ by morethan this setting, the sync. check functionwill not release reclosure. As sync. check isdone with phase to phase voltage in thiscase, the setting must be based on ph-phvoltage. Use the difference between themaximum and minimum operating volt-age to obtain the worst case result:

UDiff max = (UN max - UN min)

U Diff max

kV

kV= − ⋅ ⋅

121400

380100 0 85.

UDiff max = 31.5 V

A setting of 31.5 V is under normal cir-cumstances too large, as switching withsuch a large delta would cause a severetransient in the system. Unless special cir-cumstances exist, such as very long lineswith Ferranti voltage rise or very weak in-terconnections without voltage compensa-tion (e.g. tap changers), an upper limit ofapproximately 20 % of the nominal voltageshould be applied:

UDiff max = 0.2 ⋅ UN

UDiff max = 0.2 ⋅ 110 = 22 V

Therefore, apply a setting of 22 V.

3512 Maximum frequency difference:If the frequency difference between lineand bus voltage is less than this setting, thesync. check conditions for async. switchingcan be used. The sync. conditions forswitching apply, if the frequency differenceis less than 0.01 Hz. Switching with largefrequency difference will cause severe tran-sients to the system. In common practice,an upper limit of 0.10 Hz is suitable.

Fig. 62 Sync. check settings for auto-reclose trigger

LSP3

639.

tif



3513 Maximum angle difference:Under synchronous switching conditions(f diff < 0.01 Hz) the angle difference be-tween the bus and line voltage is alsochecked. This angle under synchronousconditions is stable and mainly due to thetransmission angle of the system. In thisexample, a maximum angle of 40° will beapplied.

3515A Live bus / live line and Sync before AR:In this application, the auto-reclose func-tion may initiate closing when bus and linevoltage are live; therefore set YES. Theabove sync. check conditions will then bemonitored before closing is released.

3516 Live bus / dead line check before AR:In this application, the auto-reclose func-tion may initiate closing to energise a deadline; therefore set YES.

3517 Dead bus / live line check before AR:In this application, the auto-reclose func-tion may not initiate closing to energise adead bus; therefore set NO.

3518 Dead bus / dead line check before AR:In this application, the auto-reclose func-tion may not initiate closing to connect adead bus to a dead line; therefore set NO.

3519 Override of any check before AR:The sync. check override is only used dur-ing testing or commissioning. Thereforeset NO.

20.3 Settings for operation with manual closeand control

The following group of settings is relevant forclose commands that originate from the manualclose binary input or internal control function.

3530 Operating mode with Man.Cl:If the close release must be possible underasynchronous conditions (line and bus fre-quency are not the same), then the circuit-breaker closing time must be consideredfor timing of the close command. Refer tosetting 239 in Chapter 7.3. In this exampleclosing under asynchronous conditionsmust be possible, so apply the setting: withconsideration of CB closing time.

3531 Maximum voltage difference:The same consideration as for the AR clos-ing in parameter 3511 applies. Therefore,apply a setting of 22 V.

3532 Maximum frequency difference:The same consideration as for the AR clos-ing in parameter 3512 applies. Therefore,apply a setting of 0.10 Hz.

3533 Maximum angle difference:The same consideration as for the AR clos-ing in parameter 3513 applies. Therefore,apply a setting of 40° .

3535A Live bus / live line and Sync before MC:In this application, the manual close mayinitiate closing when bus and line voltageare live; therefore set YES. The above sync.check conditions will then be monitoredbefore closing is released.

3536 Live bus / dead line check before Man.Cl.:It is common practice to allow all closingmodes for manual close, so apply the set-ting YES.

3537 Dead bus / live line check before Man.Cl.:Refer to setting 3536; therefore set YES.

3538 Dead bus / dead line check before Man.Cl.:Refer to setting 3536; therefore set YES.

3539 Override of any check before Man.Cl.:The sync. check override is only used dur-ing testing or commissioning. Thereforeset NO.

Fig. 63 Sync. check settings for manual close andcontrol input trigger

LSP2

640.

tif



21. Fault locator – Setting Group A

3802 Start fault locator with:The fault locator can only provide mean-ingful data for faults on the protected lineunless the downstream feeders are in apure radial configuration without interme-diate infeed. In this application, there isinfeed at the remote bus, so that the faultlocator data is only desired when the pro-tection trips for internal faults. Thereforeapply the setting with TRIP.

3806 Load Compensation:The result of the single ended fault locationcomputation may be inaccurate due to theinfluence of load angle and fault resistance.This was described in conjunction with theparameter 1307 in Chapter 11.1. For singlephase to ground faults and for phase tophase faults without ground a load com-pensated measurement can be applied toachieve better results. This function doesnot work under all conditions, and a faultlocation output that closely resembles theprotection operation is desired in this ap-plication, so the load compensation isswitched off by setting NO here.

22. Oscillographic fault records

0402A Waveform Capture:In this application a recording must besaved during internal and external faults,even if the relay does not trip. Thereforeapply the setting Save with Pickup to savethe recording every time the relay detects afault (picks up).With settings 0403A to 0415, the lengthand configuration of the oscillographic re-cord can be set to match the user require-ments.

23. General device settings

0610 Fault Display on LED / LCD:The LED and LCD image/text can be up-dated following pickup or latched withtrip. In this application the last pickup willbe indicated: Display Targets on everyPickup.

0640 Start image Default Display:The LCD display during default conditions(no fault detection or trip) can be selectedfrom a number of standard variants. Here,variant 1 is selected with the setting image 1.

24. Time synchronization & time formatsettings

Time synchronization settings can be ap-plied here. Various sources for synchro-nizing the internal clock exist as shown inFigure 67.

Fig. 64 Fault locator settings

Fig. 65 Settings for the oscillographic fault recording

Fig. 66 General device settings

LSP2

629.

tif

LSP2

630.

tif

LSP2

631.

tif

Fig. 67 Time synchronization and time format settings

LSP2

632.

tif



25. Interface settings25.1 Serial port on PC settings

The PC serial port configuration is shown here.No settings are required in this case.

25.2 VD address settings

These addresses can be left on default values.

25.3 Operator interface settings

The settings here apply to the system interface, ifthis is used.

26. Password settings

Various password access levels can be applied asshown in Figure 71.

27. Language settings

The language settings shown depend on the lan-guages that are installed with the DIGSI devicedriver on the PC.

Fig. 68 Settings for serial port on PC

Fig. 69 Settings for VD address

Fig. 70 Settings for operator interface

Fig. 71 Settings for password access

Fig. 72 Settings for language in the device

LSP2

633.

tif

LSP2

634.

tif

LSP2

635.

tif

LSP2

636.

tif

LSP2

637.

tif



28. SummarySIPROTEC 7SA6 protection relays comprise thefunctions required for overall protection of a linefeeder and can thus be used universally. The diver-sity of parameterization options enables the relayto be adapted easily and clearly to the respectiveapplication using the DIGSI 4 operating program.

Many of the default settings can easily be acceptedand thus facilitate the work for parameterizationand setting. Already when ordering, economicsolutions for all voltage levels can be realized byselection of the scope of functions.



1. IntroductionThe implementation of a directional overcurrentstage (ANSI 67) in the distance protection relays7SA522 and 7SA6 is possible via a simple couplingof the distance protection directional stage (in thiscase Zone 5) with one of the overcurrent stages (inthis example stage I>) in the relay.The distance protection and the directionalovercurrent protection use the same measuredsignals, phase current and phase voltage, but theimpedance measurement achieves both highersensitivity and higher selectivity.This document illustrates how easily the ANSI 67function can be implemented in the 7SA522 and7SA6 by using the CFC logic.

2. General parameters for implementation ofdirectional overcurrent (ANSI 67)

The settings of the relay can be applied as requiredby the application as usual. For the ANSI 67 func-tion at least the functions 0112 Phase Distance,0113 Earth Distance and 0126 Backup Overcur-rent must be activated in the relay configuration(Fig. 2):

Setting parameterof 67

Designation ExampleValue(secondary1 A)

Pick-up threshold I67> pick-up 2.5 A

Time delay Time 67 0.5 s

Table 1 Parameters for directional overcurrent I67

Setting block: Relay configurationThe distance protection must be enabled (quadri-lateral or MHO) for phase faults: Parameter 0112.Backup overcurrent must be enabled (timeovercurrent IEC or ANSI): Parameter 0126

Directional PhaseOvercurrent ProtectionANSI 67 with 7SA522 and7SA6

Fig. 1 SIPROTEC line protection 7SA522 and 7SA6

LSP2

310.

eps

Fig. 2 Setting of functional scope

LSP2

748.

if



Matrix: Masking I/O (configuration matrix)Assign the signal “3719 Distance forward” in the“Distance General” block to destination CFC.

Select that stage in the backup overcurrent thatmust be directional (ANSI 67). For this stage as-sign the corresponding blocking input signal tosource CFC. Therefore either:

7104 >Block O/C I>> or7105 >Block O/C I> (used in this example) or7106 >Block O/C Ip

Multiple assignment is also possible.

3. Special setting for the distance protectionThe distance protection sensitivity must be greaterthan or equal to that of the required directionalovercurrent protection. This does not present anyproblems, as the directional overcurrent protec-tion will be set less sensitive than the maximumload current while the distance protection is setmore sensitive than the smallest fault current.

In the relevant setting group (e.g. Setting GroupA) the following distance protection settings mustbe checked:

1201 Distance protection is ON1202 Phase current threshold for distance meas-urement ≤ I67> pick-up (Table 1)

To calculate the minimum reach setting of the dis-tance protection, the overcurrent characteristic isshown in the impedance plane below in Fig. 6:

From Fig. 6 it is apparent, that the largest circle ra-dius must be determined to set the minimum im-pedance reach so that a direction decision is avai-lable when the overcurrent stage picks up. Themaximum circle radius is obtained when themeasured fault voltage together with fault currentat pick-up threshold occurs. If the maximum op-erating voltage (unfaulted) is used, a large safetyfactor is already incorporated as the fault voltagewill always be less than this.

Circle radiusU

I pi k p_

( )

max=⋅ > −

operating

c u3 67

In this example the rated secondary VT voltage is100 V. The maximum operating voltage is 110%of rated, so the following circle radius can becalculated:

Circle radius_.

.= ⋅

⋅100 11

3 2 5

Circle radius_ .= 25 4 Ω

The setting 1243 R load, minimum load imped-ance (ph-ph) must be greater than the calculatedcircle radius. In practice, this is no problem be-cause this setting is calculated with a similar equa-tion using the maximum load current instead ofthe overcurrent pick-up (I67> pick-up) whichmust be greater than the maximum load current.Therefore, this setting when applied is by naturegreater than the circle radius calculated here.

Fig. 3 Masking of dist. signals in configuration matrix

Fig. 4 Masking of overcurrent signals in configurationmatrix

Fig. 5 Distance protection function general setting

Fig. 6 Pick-up characteristic of overcurrent protectionin impedance plane

LSP2

750.

tif

LSP2

749.

tif

LSP2

751.

tif



At least one of the set distance protection zoneswith forward or non-directional reach must havea reach greater than the circle radius. In this ex-ample the Zone 5 has the largest reach, and it is setnon-directional. In this case the following must bechecked:

1341 Operating mode Zone 5 isnon-directional

1342 R(Z5) resistance for ph-ph faults ≥Circle radius (25.4 Ω)

1343 X+(Z5) reactance for forward direction ≥Circle radius (25.4 Ω)

If none of the applied zones has a sufficiently largereach, a special zone must be selected for this pur-pose. This zone must then be set as non-direc-tional (for MHO set forward) with an X and Rreach equal to the calculated circle radius (25. 4 Ωin this example). The time delay of this zone canbe set to infinity (∞) to avoid tripping by the dis-tance protection in this zone if required.

4. Setting the backup overcurrent stagefor ANSI 67

The backup overcurrent must be operated asbackup protection so that it is always active:

2601 Operating mode ON: always active

In the backup overcurrent proctection the follow-ing settings must be applied to the stage that is in-tended for the ANSI 67 function. In this examplestage I> will be used:

2620 Iph> pick-up valueset equal to required I67> pick-up (in this example2.5 A)

2621 T Iph> time delayset equal to the desired 67 time delay (in this ex-ample 0.5 s)

2622 3I0> pick-up valuedisabled by setting to infinity (∞)

5. Setting up the CFC logicIn the CFC logic, the absence of a forward detec-tion by the distance protection (in this caseZone 5) will be used to block the backup over-current stage (in this example stage I<).

In the fast PLC, insert a negator and route the sig-nal “Dis forward” to its input. Route the negatoroutput to the relevant blocking input to thebackup overcurrent stage.

6. Testing the ANSI 67 functionTo test the directional overcurrent, a forward anda reverse fault condition were simulated with theOmicron® state sequencer. For both faults, thefault current level was set to 10 % above pick-upof the ANSI 67 function, 2.75 A. The angle be-tween current and voltage for the forward faultwas 0° and for the reverse fault 180°.

The fault recordings and trip log for these twocases are shown on the following page:

Zone settings of non-directional zone

Fig. 8 Settings for backup overcurrent function (I> in this example)

Fig. 9 Input signal allocation in the CFC logic

LSP2

753.

tif

LSP2

752.

tif

LSP2

754.

tif



The trip log (Fig. 10) shows the trip signal by thebackup O/C I> stage after 510 ms.

7. SummaryThe implementation of a directional overcurrentstage (ANSI 67) in the distance protection relays7SA522 and 7SA6 is possible via a simple couplingof the distance protection directional release withone of the overcurrent stages in the relay.If one of the other backup overcurrent stages is re-quired as an emergency protection in the eventthat the distance protection is blocked due to fuse

failure, a similar logic may be implementedwhereby the blocking signal is derived from theFuse Fail alarm (170).

Fig. 10 Trip log for forward fault

LSP2

755.

tif

Fig. 11 Trip log of reverse fault

LSP2

756.

tif



Environmental and cost consciousness are forcingutilities to install more and more parallel lines.The close arrangement of the transmission linesleads to a higher fault rate and to influencing ofthe measuring results. The considerable influenceexerted by parallel lines on the measuring results(of up to 30 % in distance protection) and the re-medial actions are considered in this applicationexample.

1. Explanation of the term parallel line1.1 Parallel lines with common positive and

negative-sequence systems

The two parallel lines have the same infeed at bothline ends.

In this arrangement where both systems are con-nected with the same infeed, it is possible (for dis-tance protection) to compensate the influence ofthe parallel line.

In this arrangement of parallel lines the effect canonly be compensated on one side.

Distance Protection withParallel Compensation

1.2 Parallel lines with common positive-sequenceand independent zero-sequence system

This arrangement of parallel lines does not influ-ence the distance measurement.

Fig. 3 Parallel lines over the Bosporus

Fig. 1 Parallel lines with same infeed at both line ends

Fig. 2 Parallel line with only one common infeedFig. 4 Parallel line with common infeed at a common tower

LSP2

567.

tif



1.3 Parallel lines with isolated positive and zero-sequence systems

This is the most unfavorable arrangement for dis-tance protection. Compensation of the inductivecoupling of the circuits is not possible.

This arrangement causes a complicated fault volt-age and current distribution due to the inductivecoupling.

2. General

When overhead lines follow parallel paths, a mu-tual, inductive coupling of the current paths ex-ists. In the case of transposed lines, this effect inthe positive and negative sequence system may beneglected for all practical purposes (mutual reac-tance less than 5 % of the self-impedance). Thisimplies that during load conditions, and for allshort-circuits without earth, the lines may be con-sidered as independent.

During earth-faults, the phase currents do not addup to zero, but rather a summation current corre-sponding to the earth-current results. For thissummated current, a fictitious summation con-ductor placed at the geometrical centre of the

phase-conductors models the three-phase system.Two lines in parallel are modelled by two parallelsingle conductors with an earth return path, forwhich the mutual reactance must be calculated. Inthe case of lines with earth-wires, an additionalcoupling results, which must be considered in thecalculations. The coupling impedance can be cal-culated as follows:

Z f j f lD km

M n

ab

'= ⋅ ⋅ + ⋅ ⋅

π µ4

ϑ0µ0

Ω

µ π044 10= ⋅ ⋅

− Ω s

km

ϑ ρ= 658f

ϑ = Depth of penetration in groundf = Frequency in Hzρ = Specific resistance in Ω / mDab = Spacing in meters between the two conductors

For a typical value of the specific earth resistanceof ρ = 100 Ω/m, a system frequency of 50 Hz,a conductor spacing of 20 m and an earth-fault ofIa = 1000 A, the following result is arrived at.

ZM j 0.24 km' .= +0 05 Ω /

Then the induced voltage in the parallel conduc-tor can be calculated with Ub = ZM ⋅ Ia, and 250 Vper km is obtained.On a 100 km parallel line, this would give an in-duced voltage in the conductor of 25 kV.

3. Calculation of the measuring error of thedistance protection caused by a parallelline in the event of an earth fault

Fig. 5 Parallel lines with separate infeed

Fig. 6 Inductive coupling of parallel lines

Fig. 7 Tower diagrams



Earth resistance100 Ω/ m

Positive impedance (Ω / km) 0.032 + j 0.254Zero impedance (Ω / km) 0.139 + j 0.906Coupling impedance (Ω / km) 0.107 + j 0.488

R1 = 0.032 Ω / kmX1 = 0.254 Ω /kmR0 = 0.139 Ω / kmX0 = 0.906 Ω / kmR0M = 0.107 Ω / kmX0M = 0.488 Ω / km

Z

Z

Z Z

ZE

L

= −⋅

=0 1

130 86.

Z

Z

Z Z

ZM

L

= −⋅

=0 1

130 65.

Phase current :ILA = IA1+IA2+IA0 ILB = IB1+IB2+IB0

Earth current:IEA= 3 IA0 IEB = 3 IB0

K0 = ( ZLo- ZL1 ) / 3 ZL1

K0M = Z0M / 3 ZL1

IC0 / IA0 = x / 2-x

For measured impedance ZA for the distance relayZ1 is

Zx

lZ

x

lZ

Z

Z

x

l xZ

Z

1

2

1= ⋅ + ⋅ ⋅

⋅−

+L L

0M

L

E

L

3

The measured impedance ZB for the distance relayZ2 is

Z l x Z

xZ

L2 2= ⋅ − ⋅ +⋅

⋅( )

0M

L

E

L

3 Z

1+Z

Z

By placing the values in the equations we can cal-culate the measuring errors for this double-circuitline with single-end infeed.The results are shown in the diagram below:

Fig. 8 Parallel line with an infeed without parallel linecompensation

Measuring error

Fig. 9 Double-circuit line with single-end infeed

Measuring error

Fig. 10 Distance measuring error on a double-circuit line withsingle-end infeed



The greatest measuring deviation (35 %) occurs inthe event of a fault at the end of the line, becausethe coupled length up to the fault position is atmaximum.

This example shows that the zone reach needs tobe reduced to 70 % to avoid overreaching in theevent of earth faults.

3.1 Result The fault is proportional to K0M = Z0M / 3 ZL1

The fault increases with the ratio of the earthcurrent of the parallel line IEP to the earth-faultcurrent of the relay

The relay has an underreach when the earth-fault current of the parallel line and the earthcurrent of the relay are in phase (same direc-tion)

The relay has an overreach when the earth-faultcurrent of the parallel line and the earth currentof the relay have opposite phase (opposite direc-tion).

The measuring error of the relay on the faulty linewith two-end infeed is shown in the above dia-gram. It can be seen that the fault becomes nega-tive in the case of faults in the first 50 % of the lineunder the same infeed conditions. This is exactlythe reach where the earth current on the parallelline flows in the opposite direction.

The following figures show that the parallel lineinfluence changes strongly with the switching stateof the parallel line. The reason is the differentearth-current distribution.

ZU

I k I k Iph E

ph E

ph E E E EM Ep

−−

−

=+ ⋅ + ⋅

with kZ

ZEM

0M

1L

=⋅3

∆Ζ = ⋅k

kEM

E

L1+

Z 24 % von ZL

Fault at the line end (Fig. 12):Infeed sources for positive-sequence and zero-sequence system at the line end

∆Ζ = − ⋅k

kEM

E

L1+

Z 24 % von ZL

Fault at the line end (Fig. 13):One switch open, star-point earthing and relay atopposite ends.

Fig. 11 Earth fault on a double-circuit line with two-endinfeed

Fig. 12 Fault at the line end

Fig. 13 Fault at the line end with open circuit-breaker



∆Z =k

3

1+ ZEM

E

L0M

0

L

⋅ ⋅ = ⋅kZ

ZZ 40 % of ZL

Fault at line end (Fig. 14):

∆Z = -ZL

EM0M

0L

E

⋅⋅

+

kZ

Z

k1 -10 % of ZL

Fault at line end (Fig. 15):

4. Parallel line compensationIn order for the distance protection to be able tooperate with parallel line compensation, it is as-sumed that it receives IEP of the parallel line as ameasuring variable.

ZU

I k IA

A

ph E E

=+ ⋅

=+ ⋅ +

⋅⋅

+ ⋅

Z IZ

IZ

I

k I

E1

0L ph

L

1L

EM

1L

Ep

ph E E

Z 3 Z

I

As can bee seen from the equation the fault im-pedance is measured correctly when we add the

termZ

ZI0

13M

L

EP⋅⋅ in the denominator. With the

normal setting kE = ZE/ZL the denominator is thenreduced against the bracketed expression in thecounter and Z1L is produced as measured result.

The distance protection has another measuringinput to which the earth current of the parallelline is connected. The addition is numeric. Itshould be noted that the relay on the healthy linesees the fault at too short a distance due to cou-pling of the earth current of the parallel line. Ifzone 1 of the line without a fault is set to 85 %, thedistance protection would lead to an overreachthrough the fed parallel fault. The distance protec-tion would still see faults on the parallel line at upto 55 % line length in zone 1.

Fig. 14 Infeed sources of the positive and zero-sequence systems at oppositeline ends

Fig. 15 Parallel line disconnected and earthed at both ends

Fig. 16 Connection of the parallel line compensation



Example:

Z ZE

L

M

LZ 3 Z=

⋅=

0 86 0 650. / .

ZL = line impedance

The so-called earth-current balance is used to pre-vent this overfunction. It compares the earth cur-rents of both line systems and blocks the parallelline compensation when the earth current of theparallel line exceeds the earth current of the ownline by a settable factor.

I l x

x

x

lx

l

E

E2

1 22

I= ⋅ − =

−

At a setting of x/l of 85 %, the parallel line com-pensation is effective for faults on the own lineand for a further 15 % into the parallel line. Thisresults in a factor of IE1 / IE2 = 1.35 as a standardvalue for the earth-current balance.

Setting instructions for the parallel line compen-sation

The compensation is only possible where bothlines end in the same station.

In the distance protection the compensation isonly used where no sufficient backup zone ispossible without compensation (When the dou-ble-circuit line is followed by short lines).

Fig. 17 Distance measurement with parallel linecompensation

Fig. 18 Effect of the parallel line compensation

Fig. 19Example of adouble-circuit linestation

S"SC = 10 000 MVA

Z

Z0

1

1=

ZVA1 = 16 ΩPN = 1000 MVAS"SC = 2500 MVAZ

Z0

1

1=

ZVB1 = 64 Ω

S"SC = 20 000 MVA

Z

Z0

1

1=

ZVC1 = 8 Ω



5. Calculation examplesThe procedure for setting a normal single-circuitline is explained in the available manuals. Specialapplications are dealt with here.

5.1 Double-circuit line in earthed system

The coupling in the zero-sequence system requiresdetailed consideration of the zone setting for earthfaults.

5.2 General procedureIt is recommended to first determine the gradingof the distance zones for phase faults without tak-ing into account the parallel line coupling. In thesecond step the zone reaches are then checked forearth faults and a suitable earth-current compen-sation factor selected.The use of parallel line compensation must beconsidered so that an adequate remote backupprotection can be ensured in the event of earthfaults.

5.3 Grading of the distance zones forphase-to-phase short-circuits

The zones must be set according to the basic rulesof grading plans. For the backup zones, the para-bolic course of the impedance dependent on thefault location is important.When double-circuit lines are connected in seriesthere are also different reaches of the backupzones dependent on the switching state and theinfeed at the opposite end.Theoretically speaking, this results in relativelyhigh effort for creating the grading plan of dou-ble-circuit lines.The procedure is usually simpler in practice.Half the impedance of the following parallel linecan be used for practical grading of the secondzone (double-circuit line follows single-circuitline). This gives:

Z GF Z Z2A A B B C= ⋅ + ⋅⋅ ⋅2 0 5( . )

In the third zone, the grading should be per-formed according to the backup protection strat-egy. A selective grading for all switching statesleads to relatively short third stages which hardlyget any longer than the corresponding secondstage. In the high and extra-high voltage system,an attempt will be made for the third stage tocover the following double-circuit line in normalparallel line mode. In this case the following stepsetting is derived:

( )Z Z Z3A A B B C= ⋅ +⋅ ⋅11.

In the pickup zone the following lines should be inthe protected zone in the worst switching state(single line follows parallel line). The followingsetting should be set for this:

( )Z Z Z+ − −= ⋅ + ⋅AA A B B C11 2.

As a rule infeeds are available in the intermediatestations of the double-circuit line which have tobe taken into account in the grading of the backupzones. This is demonstrated by the following ex-ample (see Fig. 19):

Double-circuit line.Setting of the distance zones for phase-to-phaseshort-circuits

Given:100 kV double-circuit lineLine data:Configuration according tol1 and l2 = 150 km, l3 and l4 = 80 kmZ1L'= 0.0185 + j 0.3559 Ω/kmZ0L'= 0.2539 + j 1.1108 Ω/kmZ0M'= 0.2354 + j 0.6759 Ω/kmPnat. = 518 MW per lineCurrent transformer: 2000/1 AVoltage transformer: 400/0.1 kV

Task:Calculation of the zone setting for relay D1.

Solution:Only X values are used in the short-circuit calcula-tions, for the sake of simplicity:XL1 = XL2 = 0.3559 Ω/km · 150 km = 53.4 ΩXL3 = XL4 = 0.3559 Ω/km · 80 km = 28.5 ΩWe generally apply a grading factor (GF) of 85 %.The zone reaches are calculated as follows:X1 = 0.85 · 53.4 ΩFor selective grading of the 2nd stage it is assumedthat the parallel line L2 is open but that always atleast half the short-circuit power is available fromthe intermediate infeed in B. Grading takes placeselectively to the end of the 1st zone of the distancerelays of the following lines 3 and 4. That meanswe can use about half the line impedance. Thisgives a simplified equivalent circuit. For a three-pole fault in C we calculate the short-circuit cur-rents drawn in the figure.



Under consideration of the intermediate infeed ef-fect we get

X2 53428 5

21

119

2190 85

64 120

= + ⋅ +

⋅ =

=

.. .

..

%Ω XL 1

According to the above recommendation we getfor zone 3

X X3 L= + ⋅ = =( . . ) . . %534 28 5 11 901 169 1Ω

and for the pickup zone:

X A+ = + ⋅ ⋅ = =( . . ) .534 2 28 5 11 121 Ω 226 % L1X

we adapt the reach of the zones in R direction tothe impedance of the natural power:

ZU

PNat.

Nat.

N 2

= = =400

518309

2

Ω

We assume that a new line has to transmit doublethe power temporarily and allow an additionalsafety margin of 30 %. This gives the maximum Rreach of pickup as:

RA1 0 7309

2108= ⋅ =. Ω

We further select ϕA = 50° andRA2 = 2 · RA1 = 208 Ω

An R/X ratio of 1 offers adequate compensationfor fault resistance for the distance zones.

5.4 Zone reach during earth faultsThe earth-current compensation factor kE is de-cisive in the Ph-E measuring systems. For single-circuit lines this is set to the corresponding ZF/ZL

value. The protection then measures the same im-pedance for Ph-Ph and earth faults.On double-circuit lines the zero-sequence systemcoupling produces a measuring error for earthfaults. The measurement can be corrected with theparallel line compensation. This function is con-tained optionally in the relays 7SA. Only the earthcurrent of the parallel line needs to be connectedto the relay and the coupling impedance set. Theearth-current balance may be left at the standardvalue x/l = 85 %. The earth-current factor must beadapted to the single-circuit line in this case.

5.5 Setting of the kE factor (operation withoutparallel line compensation)

In the event that the parallel line compensation isnot used, a kE factor must be found which ensuresadequate protection for the possible operatingstates of the double-circuit line (see Table 1).

Fig. 20 Protection setting in double-circuit lines: Systemdata for the calculation example



a) This equation applies forx

l≤1

Forx

l>1 it applies that:

GF k kX

X1 1( )

'

'+ + ⋅XER XEM

0M

0L

XEL1+ k

b) kX

XXEL

EL

L Line

=

'

'1

c) kX

XXEM

M

0L Line

=⋅

'

'0

3

Adapting the setting to a particular operating statecauses an overreach or underreach in the respec-tive other states. GF1 in % is the selected gradingfactor for the 1st zone (reach for phase-to-phasefaults). x/l in % then specifies how far the zone 1(Ph- E loop) reaches in the event of earth faults,referred to the line length.

Determining of the relay setting value kER is dem-onstrated by the example of double-circuit lineoperation. For a fault at the distance x/l, the volt-age at the relay location is:

Ux

lZ I

x

lZ I

x

l

ZIM

Ph E L Ph E E EP⋅ = ⋅ + ⋅ + ⋅0

3

Whereby with single-end infeed:

I I

x

lx

l

IPh E EP Eand= =−

⋅I2

For the measurement on the Ph-E loop the resultis

ZU

I k I

x

l

Z Z

x

lx

lkP

Ph EPh E

h ER E

L E0M

ER

Z

3

−⋅=

+ ⋅= ⋅

+ + ⋅−

+

2

1

kER is the complex earth-current compensationfactor set at the relay.X and R are calculated separately for the numeri-cal relays 7SA. Simplified equations apply for thisif phases and earth currents have the same phaserelation.

This results in:

Initially, only the X value measured is of interestfor the reach.

With kX

Xk

XLXE

E

L

XEMM

L

and3

= =⋅

0

Xthis gives:

Xx

lX

k k

x

lx

lk

Ph E L

XEL XEM

XER

− = ⋅

+ + ⋅−

+

12

1

The Ph-E measuring system and the Ph-Ph mea-suring system have the same impedance pickupvalue (common setting value Z1).Therefore: ZPh-E = ZPh-Ph = Z1 = GF1 · ZL, applies,whereby GF1 is the grading factor of the first zone.The following equation is finally arrived at for theearth-current compensation factor which must beset at the relay:

k

k k

x

lx

lGF

x

lXER

XEL XEM

=

+ + ⋅−

⋅ −

12

11

We can vary the reach of the Ph-E measuring sys-tems of a given zone reach for phase faults (GF1 in% of ZL) by adjusting the kXER factor.We can also solve the previous equation accordingto x/l and then arrive at the reach for a given kXER

setting.

In the same way we derive the equations specifiedin Table 1 for the cases “parallel line open” and“parallel line open and earthed at both ends”.

x

l

GF k k k k=

⋅ + + + − − + − ⋅[ ( ) ( )] [..] ( ) (1 1 2 1 8 12XER XEL XEL XEM 1 1+ ⋅

⋅ −k F

kXER

XEL XEM

G

2 (1+

)

)k

XU

X

XI

Ph EPh E SC

PhE

L R

E

sin−

−= ⋅

+

⋅

ϕ

I

= ⋅ ⋅

+⋅

⋅−

+

x

lX

X

Xx

lx

lX

X

L

E

L

M

L

E

L R

1+3

X

X0

2

1

RU

R

RI

Ph EPh E SC

PhE

L R

E

−−= ⋅

+

⋅

cosϕ

I

= ⋅ ⋅

+ +⋅

⋅−

+

x

lR

R R

R

x

lx

lR

R

L

E

L

M

L

E

L

13 2

1

0

R



The choice of the setting of kXER requires a com-promise which takes all three cases of operationinto account (Table 1)1). At a grading factor ofGF1 = 85 %, adaptation to the single-circuit lineusually offers an acceptable solution. The two-enddisconnection of a line with earthing at both endsonly occurs in maintenance work, so the briefoverreach of 8 % is only rarely effective becauseoverreaching is usually reduced by intermediateinfeeds.

In operation with single-pole auto-reclosure, theoverreach would only lead to excessive auto-reclosure and not to final disconnection, providedthat a transient short-circuit is concerned (about90 % of faults).

Alternatively, the reach can be reduced slightly forearth faults by setting a lower kXER factor. If it werereduced from kXER = 0.71 to kXER = 0.5, overreachwould just about be avoided in this example. Thereach with both lines in service would then onlybe 64 %, taking into consideration that the paral-lel line coupling only takes full effect in the worstcase of single-end infeed. In the normal case oftwo-end infeed the earth current on the parallelline is much lower in the event of faults close tothe middle of the line, and the zone reach corre-sponds almost to the single-circuit line. In addi-tion, the parallel line coupling at the other end of

the line always has the opposite direction, i.e. thezone reach is increased. Reliable fast disconnec-tion can always be ensured by intertripping. How-ever, in reducing the kXER factor it must be takeninto account that the reach of the backup zones isalso reduced accordingly in the event of earthfaults. Zone reach reduction (e.g. GF1 = 0.8)should therefore also be considered instead ofonly reduction of the kXER factor.

5.6 Setting the overreach zoneZone Z1B should be set to 120 – 130 % Z L. Thisreach would also apply for earth faults in the caseof operation with parallel line compensation.

1) The numeric values in Table 1 were calculated with theline layers of the previous example. For the sake of sim-plicity the complex factors kEL = 0.71 - j0.18 andkEM = 0.64 - j0.18 were only taken into account withtheir real components, which correspond to the valueskXEL = XE/XL and kXEm = XM/(3 · XL) in the first approxi-mation. This gives sufficient accuracy for the extrahigh-voltage system.

Reach x/l at Ph-E short-circuits

x

lF

k= ⋅ +G

1+XER

XEL

11

k

x

l= See equation on

previous page

x

l

k F

k kX

a= + ⋅

+ − ⋅

( )'

)1 1

1

XER

XEL XEM0M

0L

G

X

kXER-setting with:

x

l= 0 85.

GF1 = 0.85

kXEL = 0.71

b) kXEM = 0.64

c) X'0M = 0.72 Ω/km

X'0L = 1.11 Ω/km

X'1L = 0.356 Ω/km

kk x

lER

EL

GF1= + ⋅ − =1

1 0 71 0 5. ( . )

85 %(75 %)

71 %(64 %)

108 %(98 %)

kk k

x l

x lF

XER

XEL XEM

G=

+ + ⋅− −

12

11

/

/

kXER = 1.18

108 % 85 % 132 %

k

k kx

lXER

XEL XEM0M

0L

'

'

G 1=

+ + ⋅⋅ − =

1

1 0 31

X

X

F.

65 % 56 % 85 %

Distance measurement in the event of earth faults: Reach (in X direction) dependent on the relay setting

kX

XXER

E

L Relay

=

and the switching state



Adapting the setting to an operating state causesan overreach or underreach in the respective otherstates. GF1 in % is the selected grading factor forthe 1st zone (reach for Ph-Ph faults). x/l in % thenspecifies how far zone 1 (Ph-E loop) reaches in theevent of earth faults, referred to the line length.

Determining of the relay setting value kER is dem-onstrated by the example of double-circuit lineoperation:

The voltage at the relay location for a fault at thedistance x/l is:

Ux

lZ I

x

lZ I

X

l

ZILPh E Ph E E

MEP− = ⋅ + ⋅ + ⋅0

3

with single-end infeed:

I I I

x

lx

l

IPh E EP Eand= =−

⋅2

for the measurement of the Ph-E loop the follow-ing is derived:

ZU

I k I

x

l

Z ZZ

x

lx

lk

Ph EPh E

Ph ER E

L EM

ER

3

−−=

+ ⋅= ⋅

+ + ⋅−

+

0

2

1

whereby kER is the complex earth current compen-sation factor set on the relay. X and R are calcu-lated separately in the numerical relays 7SA.Simplified equations apply for this when phasesand earth currents have the same phase angle.This results in

Only the measured value is initially for the reach:

With kX

Xk

X

XXEL

E

L

XEMM

L

and= =⋅

0

3this gives:

Xx

lX

k k

x

lx

lk

Ph E L

XEL XEM

XER

− = ⋅

+ + ⋅−

+

12

1

The Ph-E measuring system and the Ph-Ph mea-suring system have the same impedance pickupvalue (common setting value Z1).Therefore: ZPh-E = ZPh-Ph = Z1 = GF1 · ZL, applies,whereby GF1 is the grading factor of the first zone:

The following equation finally results for theearth-current compensation factor which must beset in the relay:

k

k k

x

lx

lGF

x

l

XEL XEM

XER =

+ + ⋅−

⋅ −

12

11

Without parallel line compensation the 120 %reach must be dimensioned for the case of parallelline operation under consideration of the previ-ously defined kXER factor.

GF

k k

x

lx

l x

l=

+ + ⋅−

⋅

12

XEL XEM

XER1+ k

For a fault at the end of the line (x/l = 100 %) anda safety margin of 20 %, the following equationfor the overreach zone is produced:

X B GF X

k k

kX

1120

1001

11 2

100= ⋅ ⋅

= + ++

⋅ ⋅

%

%

.

L

XEL XEM

XER

L

The selected kXER = 0.71 producesX1B = 165 % XL.Without parallel line compensation, theoverreach zone must therefore be set veryhigh, so that a safety margin of 20 % is en-sured in double-circuit line operation.

5.7 Reach of the backup zones for earthfaults

We observe the behavior of the distancemeasurement with and without parallel linecompensation.

XU

IX

XI

Ph EPh E SC

PhE

L R

E

−−= ⋅

+

⋅

sinϕ = ⋅ ⋅

+ +⋅

⋅−

+

x

lX

X

X

X

X

x

lx

lX

X

L

E

L

M

L

E

L R

13 2

1

0

RU

IR

RI

x

lR

R

R

Ph EPh E SC

PhE

L R

E

L

E

L

−−= ⋅

+

⋅

= ⋅ ⋅

+ +

cosϕ

1R

R

x

lx

lR

R

0

3 2

1

M

L

E

L R

⋅⋅

−

+



5.8 Distance measurement without parallel linecompensation

For the simple case that the parallel line is fol-lowed by a single-circuit line (Fig. 21, line 4 dis-connected), the measured impedance can bedetermined as follows:

Voltage at the relay location:

U Z I Z IZ

I

x

lZ I

x

l

Ph E L Ph E1 EM

E

L2 Ph3

3−

−= ⋅ + ⋅ + ⋅

+ ⋅ +

1 1 10 1 2

2

2 2

Z IE2 E3⋅

With IPh1 = IE1 = IE2 = ISC and IPh3 = IE3 = 2 · ISC

we get for the relay reactance:

XU

I k I

k k

k

Ph EPh E SC

Ph XER E1

XEL XEM1 2

−−

−

= ⋅+ ⋅

=

+ ++

sinϕ

1

11

1 XER

L1XEL3

XER

L2⋅ + ⋅ ⋅ ++

⋅Xx

l

k

kX2

1

12

If we set x/l = 0 we arrive at the measuredreactance in the event of a fault at the oppositestation. For the calculated example this gives thevalue

X XPh E L− = + + = ⋅1 0 71 0 64

0 711 37 1

. .

..

This shows that in the case at hand the backupzones only reach beyond the next station whenthey are set greater than 137 % ZL1. This does notapply for the 2nd zone at the selected setting.

At the grading (120 %) selected on the basis of thephase-to-phase short-circuits, the 2nd zone wouldonly reach up to 91 % ZL1 in the parallel line statein the event of an earth fault.

This problem is particularly pronounced when thedownstream line, according to which the secondzone has to be graded, is substantially shorter thanthe protected line, and when only a short interme-diate infeed is present.

Fig. 21 Distance measurement on double-circuit lines: Fault on a following line



With IPh1 = IE1 = IE2 = ISC and

IPh3 = IE3 = 22

−

⋅x

lISC and IE4 =

x

l2

⋅ ISC

we get:

Resolution according to x/l2 produces again theequation for the reaches of the zones:

with

For zone 3 (169 % XL1) we get x/l2 = 33 %, i.e. onlyslightly more than for the single-circuit line. For thepickup zone (226 % XL1) the expression under theroot is negative because the zone only reaches tojust past the next substation.The limit (root = 0) is at 223 % XL1.

5.9 Distance measurement with parallel linecompensation

With parallel line compensation, faults on theown line are measured in the correct distance.For faults beyond the next substation the zonesare extended by the factor:

kk k

k= + +

+1

1XER XEMR

XER

according to the compensation factors set at therelay.The term 1 + kXER must be replaced in the equa-tions on pages 12 and 13 by 1 + kXER + kXEMR.

This gives us a reach of up to 71 % ZL2 for the 2nd

zone, i.e. the zone reaches up to just before theend of the first zone of the following line which isset to 85 % ZL2.

U Z I ZZ

Ix

lZ I

x

lPh E L1 Ph1 E E1

ME L2 Ph3

3−

−= ⋅ + ⋅ + ⋅ + ⋅ +10 1 2

2

2 2

I Z Ix

l

ZIE2 E3

0M3 4E4⋅ + ⋅−

2 3

Xk k

kX

x

l

x

lPh E

XEL1 XEM1 2

XER

L1−−= + +

+⋅ +

−

⋅ +

1

1

2 12 2

( kx

lk

kX

XEL2 XEM3 4

XER

L2

) +

⋅

+⋅

−2

2

1

x

l

k k k k

2

22 1 4 1 4 1=

+ − + − + − ⋅⋅

−( ) ( ) ( )XEL2 XEL2 XEL2 XEM3 4

2 (

∆1+ XEL2 XEM3 4k − −k )

∆ = ⋅ + ⋅ − + +

−X

Xk

X

Xk kL1

L2

XERZone

L1

XEL1 XEM1 2( ) ( )1 1



Taking account of the intermediate infeed in sta-tion B, there will be a further reduction of the 2nd

stage so that the safety margin is increased.The 3rd zone (169 %ZL1) just reaches with parallelline compensation and the pickup zone (226 %ZL1) comfortably reaches over the next station butone ( C ) (A fault in C would correspond to 162 %ZL1). For the final definition of the setting, the in-termediate infeed again has to be taken into ac-count.

6. SummaryThe zone setting can be estimated for the double-circuit lines based on the arithmetic proceduresand the derived equations shown here. In practicethe intermediate infeeds must be taken into ac-count, so that the second zone can be gradedsafely past the next station (whilst retaining the se-lectivity and reliably detecting busbar faults).

If the line lengths do not differ, an acceptablecompromise for the relay setting can usually befound without parallel line compensation. Forshort following lines, parallel compensation musthowever be taken into account.

Computer programs are nowadays available forthe relatively complex testing of the backup zonesand the pickup.



1. IntroductionThe protection of long transmission lines waspreviously the domain of distance protection.Modern available information transmission tech-nology – with the ability to reliably exchange com -parison signals over substantial distances – makesdifferential protection interesting for use on longtransmission lines. High sensitivity and strict se-lectivity are further aspects that speak in favor ofdifferential protection. The SIPROTEC 7SD5 relayprovides, in addition to differential protection,comprehensive backup protection and additionalfunctions for the complete protection of transmis-sion lines.

2. Protection conceptThis application example describes largely differ-ential protection of two-end lines. In addition tothis use, modern SIPROTEC differential protec-tion relays can meet the following requirements:

Protection of multi-branch configurations Transformer in the protected zone Matching to various transmission media such as

fiber optics or digital communication networks

For protection of a two-end line, we recommendto activate the following functions:

ANSI 87 L Differential protectionANSI 67 N Directional overcurrent protectionANSI 79 Auto-reclosureANSI 50 BF Breaker failure protectionANSI 59/27 Undervoltage and overvoltage

protectionANSI 25 Synchro-check and voltage check

Protection of Long Lineswith SIPROTEC 7SD5


LSP2

173f

.ep

s

LSP2

314_

afp

.ep

s

Fig. 2 Settings for functional scope

LSP2

747.

tif



2.1 Differential protectionDifferential protection is based on current com-parison. It makes use of the fact, that e.g. a linesection L (Fig. 5) carries always the same current Iat its two ends in fault-free operation. This cur-rent flows into one side of the considered zoneand leaves it again on the other side. A differencein current is a clear indication of a fault withinthis line section. If the actual current transforma-tion ratios are the same, the secondary windings ofthe current transformers CT1 and CT2 at the lineends can be connected to form a closed electriccircuit with a secondary current I; a measuringelement M which is connected to the electrical ba-lance point remains at zero current in fault-freeoperation.

When a fault occurs in the zone limited by thetransformers, a current i1 + i2 which is propor-tional to the fault currents I1 + I2 flowing in fromboth sides is fed to the measuring element. As aresult, the simple circuit shown in Fig. 5 ensures areliable tripping of the protection if the fault cur-rent flowing into the protected zone during a faultis high enough for the measuring element M topick up.

Fig. 3 Function scope of the SIPROTEC 7SD5

Fig. 4 Differential protection for a line with two ends (single-phase system)

Fig. 5 Basic principle of the differential protection for a line with two ends

*

*

* Option



2.2 Charging current compensationCharging current compensation is an additionalfunction for differential protection. It allows animprovement in the sensitivity, achieved by thecharging current (caused by the capacitances inthe overhead line or cable and flowing through thedistributed capacitance in steady state) beingcompensated. As a result of the capacitances of thephase conductors (to earth and mutually), charg-ing currents flow – even in fault-free conditions –and cause a difference in the currents at the endsof the protected zone. Particularly on cables andlong lines the capacitive charging currents canreach considerable levels. If the feeder-side trans-former voltages are connected to the relays, theinfluence of the capacitive charging currents canbe largely arithmetically compensated. It is pos-sible here to activate charging current compensa-tion, which determines the actual charging cur-rent. Where there are two line ends, each relayattends to half the charging current compensa-tion; where there are M relays, each covers an Mth

fraction. Fig. 6 shows a single-phase system, forthe sake of simplicity.

In fault-free operation, steady-state charging cur-rents can be considered as practically constant, asthey are determined only by the voltage and theline capacitances. Without charging current com-pensation, they must therefore be taken into ac-count when setting the sensitivity of the differ-ential protection. With charging current compen-sation, there is no need to consider them at thispoint. With charging current compensation, thesteady-state magnetization currents across shuntreactances (quadrature-axis reactances) are alsotaken into account.

2.3 Directional overcurrent protection (ANSI 67 N)The zero-sequence current is used as measuredquantity. According to its definition equation it isobtained from the sum of three phase currents,i.e. 3I0 = IL1 + IL2 + IL3.The direction determination is carried out withthe measured current IE (= –3 I0), which is com-pared to a reference voltage UP.

The voltage required for direction determinationUP may be derived of the starpoint current IY of anearthed transformer (source transformer), provid-ed that the transformer is available. Moreover,both the zero-sequence voltage 3U0 and the star-point current IY of a transformer can be used formeasurement. The reference magnitude UP then isthe sum of the zero-sequence voltage 3U0 anda value which is proportional to reference currentIY. This value is about 20 V for rated current(Fig. 7).

The directional polarization using the transformerstarpoint current is independent of voltage trans-formers and therefore also functions reliably dur-ing a fault in the voltage transformer secondarycircuit. It is, however, a requirement that not all,but at least a substantial amount of the earth-faultcurrent flows via the transformer, the starpointcurrent of which is measured.

For the determination of direction, a minimumcurrent 3I0 and a minimum displacement voltage,which can be set as 3U0>, are required. If the dis-placement voltage is too small, the direction canonly be determined if it is polarized with thetransformer starpoint current and this exceeds aminimum value corresponding to the setting IY>.The direction determination with 3U0 is inhibitedif a “trip of the voltage transformer mcb” is repor-ted via binary input.

Fig. 6 Charging current compensation for a line with two ends(single-phase system)

Fig. 7 Directional characteristic of the earth-faultprotection



2.4 Auto-reclosure function (ANSI 79)The 85 % of the arc faults on overhead lines areextinguished automatically after being tripped bythe protection. This means that the line can bereclosed. Auto-reclosure is only permitted onoverhead lines because the option of automaticextinguishing of an arc fault only exists there. Itshould not be used in any other case. If the protec-ted object consists of a combination of overheadlines and other equipment (e.g. overhead line di-rectly connected to a transformer or a combinati-on of overhead line/cable), it must be ensured thatreclosure can only be performed in the event of afault on the overhead line. If the circuit-breakerpoles can be operated individually, a single-phaseauto-reclosure is usually initiated for single-phasefaults and a three-pole auto-reclosure for multiplephase faults in the system with earthed systemstarpoint. If the earth fault still exists after auto-reclosure (arc has not disappeared, there is a me-tallic fault), then the protection functions will re-trip the circuit-breaker. In some systems severalreclosing attempts are performed.In a model with single-pole tripping, the 7SD5allows phase-selective, single-pole tripping. Asingle and three-pole, single and multiple-shotauto-reclosure function is integrated, dependingon the version.

The 7SD5 can also operate in conjunction with anexternal auto-reclosure device. In this case, thesignal exchange between 7SD5 and the externalreclosure device must be effected via binary inputsand outputs. It is also possible to initiate the inte-grated auto-reclose function by an external pro-tection device (e.g. a backup protection). The useof two 7SD5 with auto-reclosure function or theuse of one 7SD5 with an auto-reclosure functionand a second protection with its own auto-reclosure function is also possible.

Reclosure is performed by an auto-reclosurefunction (AR). An example of the normal timesequence of a double reclosure is shown in Fig. 8.The integrated auto-reclosure cycle allows up to8 reclose attempts. The first four reclose cyclesmay operate with different parameters (action anddead times, single/three-pole). The parameters ofthe fourth cycle also apply for the fifth cycle andonwards.

Fig. 8 Timing diagram of a double-shot reclosure with action time (2nd reclosure successful)



2.5 Breaker failure protection (ANSI 50BF)The breaker failure protection provides rapid ba-ckup fault clearance, in the event that the circuit-breaker fails to respond to a trip command from aprotection function of the local circuit-breaker.Whenever, e.g., a protection relay of a feeder issu-es a trip command to the circuit-breaker, this isrepeated to the breaker failure protection. A timerin the breaker failure protection is started. The ti-mer runs as long as a trip command is present andcurrent continues to flow through the breaker po-les.

2.6 Undervoltage and overvoltage protection(ANSI 27/59)

Voltage protection has the function of protectingelectrical equipment against undervoltage andovervoltage. Both operational states are unfavor-able as overvoltage may cause, for example, insu-lation problems or undervoltage may causestability problems.The overvoltage protection in the 7SD5 detects thephase voltages UL1-E, UL2-E and UL3-E, the phase-to-phase voltages UL1-L2, UL2-L3 and UL3-L1, as wellas the displacement voltage 3U0. Instead of thedisplacement voltage any other voltage that isconnected to the fourth voltage input U4 of therelay can be detected. Furthermore, the relay cal-culates the positive-sequence voltage and the ne-gative-sequence voltage, so that the symmetricalcomponents are also monitored. Here, compoun-ding is also possible which calculates the voltage atthe remote line end.

The undervoltage protection can also use thephase voltages UL1-E, UL2-E and UL3-E, the phase-to-phase voltages UL1-L2, UL2-L3 and UL3-L1, aswell as the positive-sequence system voltage.

2.7 Synchro-check and voltage check (ANSI 25)The synchro-check and voltage check functionsensure, when switching a line onto a busbar, thatthe stability of the system is not endangered. Thevoltage of the feeder to be energized is comparedto that of the busbar to check conformances interms of magnitude, phase angle and frequencywithin certain tolerances. Optionally, deenergiza-tion of the feeder can be checked before it is con-nected to an energized busbar (or vice versa).

The synchro-check can either be conducted onlyfor auto-reclosure, only for manual closure (thisincludes also closing via control command) or forboth cases. Different close permission (release)criteria can also be programmed for automaticand manual closure. Synchronism check is alsopossible without external matching transformersif a power transformer is located between themeasuring points. Closing is released for synchro-nous or asynchronous system conditions.

In the latter case, the relay determines the time forissuing the close command such that the voltagesare identical the instant the circuit-breaker polesmake contact.

The synchronism and voltage check function usesthe feeder voltage – designated with ULine – andthe busbar voltage – designated with UBus – forcomparison purposes. The latter may be anyphase-to-earth or phase-to-phase voltage.

If a power transformer is located between thefeeder voltage transformers and the busbar voltagetransformers (Fig. 10), its vector group can becompensated for by the 7SD5 relay, so that no ex-ternal matching transformers are necessary.

The synchronism check function in the 7SD5 usu-ally operates in conjunction with the integratedautomatic reclose, manual close, and the controlfunctions of the relay. It is also possible to employan external automatic reclosing system. In such acase, signal exchange between the devices is ac-complished via binary inputs and outputs.

When closing via the integrated control function,the configured interlocking conditions may haveto be verified before checking the conditions forsynchronism. After the synchronism check grantsthe release, the interlocking conditions are notchecked a second time.

Fig. 9 Synchronism check on closing



Communications media

The exchange of signals between the line differen-tial protection relays becomes particularly compli-cated due to the geographic coverage of the relaysover medium and long distances. At the mini-mum, two substations find themselves using re-lays of the same system that exchange data over arelay-to-relay (R2R) communication channel.

The communication is enabled via pilot wire ordirect optical fiber connections or via communi-cation networks. Which kind of FO media is used,depends on the distance and on the communicati-on media available (Table 1). For shorter distancesa direct connection via optical fibers having atransmission rate of 512 kBit/s is possible. A trans-mission via modem and communication networkscan also be realized.

It is very important to note, however, that thetripping times of the different protection relaysdepend on the transmission quality and are pro-longed in case of a reduced transmission qualityand/or an increased transmission time. Fig. 11shows some examples for communication con-nections. In case of a direct connection the dista-nce depends on the type of the optical fiber.Table 1 lists the options available. The modules inthe relays are replaceable. If an external communi-cation converter is used, the relay must be equip-ped with an FO5 module in order to achievecorrect operation. The relay and the external com-munication converter are linked via optical fibers.The converter itself allows connections to com-munication networks, two-wire copper lines orISDN (Fig. 12).

To span larger distances with fiber-optic cables, itis presently recommended to use external repeat-ers. Optical modules for distances of up to 100 kmare being developed and will be available in 2005.

A further option is the connection via communi-cation network (no limitation of distance).

Fig. 10 Synchronism check across a transformer

Fig. 11 Optional communication media



1) For direct connection over short distances, asuitable optical attenuator should be used to avoidmalfunctions and damage to the relay.

Module in therelay

Connectortype

FO type Opticalwavelength

Perm. pathattenuation

Distance,typical

FO5 ST Multi-mode62.5/125 µm

820 nm 8 dB 1.5 km(0.95 miles)

FO6 ST Multi-mode62.5/125 µm

820 nm 16 dB 3.5 km(2.2 miles)

FO7 ST Mono-mode9/125 µm

1300 nm 7 dB 10 km(6.25 miles)

FO8 FC Mono-mode9/125 µm

1300 nm 18 dB 35 km(22 miles)

FO171) LC Mono-mode9/125 µm

1300 nm 13 dB 24 km(14.9 miles)


1300 nm 29 dB 60 km(37.5 miles)


1550 nm 29 dB 100 km(62.5 miles)

Table 1 Communication via direct FO connection



3. SummaryOptimal protection of transmission lines withSIPROTEC 7SD5 relays means high selectivity infault clearing; any available parallel duplicate lineremains reliably in operation. Very short releasetimes ensure the stability of the transmissionsystem in the event of a fault, and consequentlycontribute significantly to maximizing the levelof supply security.

The SIPROTEC 7SD5 relay provides comprehen-sive main and backup protection of transmissionlines in a single relay. Thanks to its flexible com-munication capabilities, the SIPROTEC 7SD5can be easily matched to the existing communi-cation infrastructure.

Fig.12 Examples for communication links


Transformer Protection

Three-winding transformer110 kV/25 kV/10 kVYyn0d525 kV-side: Solidly earthed

Protection functionsANSI 87 T - Differential protectionANSI 87 N - Earth-fault differential protectionANSI 50/51 - Definite-time overcurrent-time

protection as backupANSI 49 - Thermal overload protectionANSI 46 - Load unbalance protection

(negative-sequence protection)ANSI 24 - Overexcitation protection

1. IntroductionTransformers are valuable equipment which makea major contribution to the supply security of apower system. Optimum design of the transfor-mer protection ensures that any faults that mayoccur are cleared quickly and possible consequen-tial damage is minimized.In addition to design notes, a complete setting ex-ample with SIPROTEC protection relays for athree-winding transformer in the transmissionsystem is described.

2. Protection conceptThe range of high-voltage transformers comprisessmall distribution system transformers (from100 kVA) up to large transformers of several hun-dred MVA. Differential protection offers fast, sel-ective short-circuit protection, alone or as a sup-plement to Buchholz protection. It is part of thestandard equipment in larger units from about5 MVA.

2.1 Differential protectionTransformer differential protection contains anumber of additional functions (matching totransformation ratio and vector group, restraintagainst inrush currents and overexcitation).Therefore it requires some fundamental consider-ation for configuration and selection of the settingvalues.

The additional functions integrated per relay areadvantageous. However, backup protection func-tions have to be arranged in separate hardware(other relay) for redundancy reasons. Thereforethe overcurrent-time protection contained in the

differential protection relay 7UT613 can only beused as backup protection against external faultsin the connected power system. The backup pro-tection for the transformer itself must be providedas a separate overcurrent relay (e.g. 7SJ602). TheBuchholz protection as fast short-circuit protec-tion is delivered with the transformer.

Designations in accordance with ANSI (AmericanNational Standard) are used for the individualfunctions. The differential protection thereforehas the ANSI No. 87 for example.The 7UT613 differential protection relay is pro-vided as independent, fast-acting short-circuitprotection in addition to the Buchholz protection.

Protection of a Three-Winding Transformer

Fig. 1 SIPROTEC Transformer protection relay

LSP2

309.

eps

Fig. 2 Protection of a three-winding transformer



2.2 Earth-fault differential protectionEarth-fault differential protection detects earth-faults in transformers in which the star (neutral)point has low resistance or is solidly earthed. It en-ables fast, selective disconnection in the event ofan earth fault in the winding. The protection isbased on a comparison of the star-point currentISP with the phase currents of the main winding.

The pickup sensitivity should be ≤ 10 % of thecurrent in the event of terminal earth fault (90 %protected zone). The single-phase auxiliary mea-suring input with connection IZ1 of 7UT613should be used for this and assigned to the corre-sponding main winding by setting. The earth cur-rent of this input is then compared with the phasecurrents of the main winding.

2.3 Backup protection functionsThe integrated overcurrent-time protection(ANSI 51) in 7UT613 serves as backup protectionfor faults in the system to which power is sup-plied. Separate overcurrent protection on thelow-voltage (LV) side is therefore unnecessary.The 7SJ602 relay can be used as backup protectionagainst short-circuits in the transformer and asadditional backup protection against faults on theLV side. The high-set, fast tripping stage I>>(ANSI 50) must be set above the through-faultcurrent, so that it does not pick up in case of faultson the low-voltage (LV) side.

The delayed trip (ANSI 51) must be of higher pri-ority than the overcurrent protection in 7UT613.

Owing to the different ratings, windings S2 and S3are assigned a separate overload protection (inte-grated in 7UT613). The delta winding (often onlyused for own internal supply) has its own overcur-rent-time protection (ANSI 51, integrated in7UT613) against phase faults.At low ratings of the tertiary winding and accord-ingly adapted transformer ratio, it should bechecked whether an external matching trans-former may be required.

2.4 Integration of Buchholz protectionThe Buchholz protection of the transformerevaluates the gas pressure of the transformer tankand therefore detects internal transformer faultsquickly and sensitively. The following consider-ations are necessary for integration:

The trip command of the Buchholz protectionshould act on the circuit-breaker directly andindependently of the differential protection

The trip command of the Buchholz protectionshould be recorded in the fault log/fault recordof the differential protection

Coupling the trip command via a binary input ofthe differential protection provides informativedata for evaluation in the case of a fault.

Fig. 3 Connection of an earth-fault differentialprotection relay

Fig. 4 Scheme for Buchholz protection



3. Settings3.1 Setting instructions for differential protectionThe differential protection as a main function ofthe 7UT613 is parameterized and set in a fewsteps:

Parameterize “three-phase transformer” pro-tected object

Assign the measuring locations on the mainprotected object

Example:

Sides:S1 HV side of the main protected object

(transformer)

S2 LV side of the main protected object(transformer)

S3 Side of the tertiary winding of the main protectedobject (transformer)

Measuring locations assigned 3-phase:M1 Measuring location assigned to the main protected

object for side 1

M2 Measuring location assigned to the main protectedobject for side 2

M3 Measuring location assigned to the main protectedobject for side 3

When defining the sides, the assignments maderegarding the measuring locations (Fig. 5) at themain protected object must be observed. Side 1 isalways the reference winding and therefore hascurrent phase position 0° and no vector groupcode. This is usually the HV winding of the trans-former. The object data refer to specifications forevery side of the protected object as fixed in theassignment definition.

The relay requires the following data for the pri-mary winding (side S1):

The primary rated voltage UN in kV(line-to-line)

The rated apparent power The conditioning of the star point The transformer vector group

Generally, the currents measured on the second-ary side of the current transformers with a currentflowing through them are not equal. They are de-termined by the transformation ratio and the vec-tor group of the transformer to be protected, andby the rated currents of the current transformers.The currents therefore have to be matched first tomake them comparable.

This matching takes place arithmetically in the7UT613. External matching equipment is there-fore normally not necessary. The digitized cur-rents are converted to the respective transformerrated currents. To do this, the transformer’s ratingdata, i.e. rated apparent power, rated voltage andthe primary rated currents of the current trans-formers, are entered in the protection relay.

Fig. 6 shows an example of magnitude matching.The primary rated currents of the two sides(windings) S1 (378 A) and S2 (1663 A) are calcu-lated from the rated apparent power of the trans-former (72 MVA) and the rated voltages of thewindings (110 kV and 25 kV). Since the currenttransformer's rated currents deviate from ratedcurrents of these sides, the secondary currents aremultiplied by the factors k1 and k2.

Fig. 5 Assigning of measurement locations

Fig. 6 Magnitude matching

IMVA

ANSidekV

1

73

3 110378=

⋅=

I = IN Obj N Side

k1

400

378= A

A

IN Side2

MVA

3 kVA=

⋅=72

251663

I = IN Obj N Side

k2

2000

1663= A

A

IN Side3

MVA

3 kVA=

⋅=16

10924

IN Obj

MVA

3 kVA=

⋅=72

104157

k3

A

A= 1000

4157



The third winding (S3) on the other hand is onlydimensioned for 16 MVA (e.g. as auxiliary supplywinding). The rated current of this winding (=side of the protected object) is therefore 924 A.For the differential protection, however, compara-ble currents must be used for the calculation.Therefore, the protected object rated power of72 MVA must also be used as a basis for the thirdwinding. This results in a rated current (here: cur-rent under rated conditions of the protected ob-ject, i.e. at 72 MVA) of 4157 A. This is the refer-ence variable for the currents of the third winding.

The currents are therefore multiplied by factor k3.The relay does perform this matching on the basisof the set rated values. Together with the vectorgroup which also has to be entered, it is able toperform the current comparison according tofixed arithmetic rules. This is explained by thefollowing example for the vector group Y(N)d5(with earthed star-point):

Fig. 7 shows the windings and below them thephasor diagrams of symmetrical currents. Thematrix equation in a general form is:

( ) ( ) ( )I k k Im n= ⋅ ⋅

The phase currents on the left-hand (star-point)side are equal to the winding currents (The mag-nitude matching of the absolute value is not takeninto account in the figure).

Since there is no point earthed within the pro-tected zone, no considerable zero-sequence cur-rent (residual current) can be produced within theprotected zone in case of an earth fault outside theprotected zone. This is also valid if the systemstar-point is earthed anywhere else in the system.In case of an earth fault within the protected zone,a zero-sequence current may occur at a measuringlocation if the system star-point is earthed any-where else or another earth fault is present in the

system (double earth fault in a non-earthed sys-tem). Thus, zero-sequence currents are of no con-cern for the stability of the differential protectionas they cannot occur in case of external faults. Inthe case of internal faults, on the other hand, thezero-sequence currents (because they come fromthe outside) are absorbed almost totally by thesensitivity. A very high sensitivity in the event ofearth faults in the protected zone can be achievedwith overcurrent-time protection for zero-sequence current and/or the single-phase overcur-rent-time protection, which can also be used ashigh impedance differential protection. The dif-ferential protection function must be activated byparameterization. The differential protection relay7UT613 is delivered in inactive-circuit state. Thisis because the protection may not be operatedwithout at least having set the vector groups andmatching values correctly first. The relay may re-act unpredictably without these settings.

Setting of the characteristic of the differential pro-tection is based on the following considerations:

The presetting of 0.2 x IN referred to the ratedcurrent of the transformer can be taken as apickup value for the differential current as a rule.

The slope 1 together with base point 1 take intoaccount current-proportional error currentswhich may be caused by transformation errors ofthe CTs. The slope (gradient) of this section ofthe characteristic is set to 25 %.

The add-on restraint increases the stability ofthe differential protection in the very highshort-circuit current range in the event of exter-nal faults; it is based on the setting value EXF-restraint (address 1261) and has the slope 1 (ad-dress 1241).

The slope 2 together with base point 2 lead tohigher stabilization in the higher current rangeat which current transformer saturation can oc-cur. The slope of this section of the characteris-tic is set to 50 %.

Fig. 7 Phasor diagram for vector group matching

Fig. 8 Tripping characteristics of the differential protection



3.1.1 Notes on add-on restraintIn systems with very high through-flowing cur-rents, a dynamic add-on restraint (stabilization)becomes effective for external faults. Note, thatthe restraint current is the arithmetic sum of thecurrents flowing into the protected object, i.e. istwice the through-flowing current. The add-on re-straint does not affect the I>> stage.

The maximum duration of add-on restraint afterdetecting an external fault is set in multiples of aperiod (AC cycle). The recommended settingvalue is 15 periods (preset). The add-on restraintis disabled automatically – even before the set timeperiod expires – as soon as the relay has detectedthat the operation point IDiff/IRest is located steadily(i.e. for at least one period) within the trippingzone. The add-on restraint operates separately foreach phase. Hence, blocking can be extended to allthree phases thanks to the available vector-group(so called “crossblock” function). The recommen-ded setting value for the crossblock function is 15periods (preset).

3.1.2 Notes on setting the inrush blockingAn inrush current with a high proportion of 2nd

harmonics is generated when switching on thetransformer, which can lead to false tripping ofthe differential protection. The default for theharmonic restraint with 2nd harmonics of 15 %can be retained without change. A lower value canbe set for greater stabilization in exceptional casesunder unfavorable energizing conditions resultingfrom the design of the transformer.

The inrush restraint can be extended by the“crossblock” function. This means, that all threephases of the IDiff> stage are blocked when theharmonic component is exceeded in only onephase. A setting value of 3 periods, effective for thetime of mutual blocking after exceeding the differ-ential current threshold, is recommended (de-fault).

3.1.3 Notes on setting the overexcitation blockingStationary overexcitation in transformers is char-acterized by odd harmonics. The third or fifthharmonic is suitable for stabilization. Since thethird harmonic is often eliminated in transform-ers (e.g. in a delta winding), the 5th harmonic ismostly used. The proportion of 5th harmonicswhich leads to blocking of the differential protec-tion is set at 30 % (default). It is usually not neces-sary to set the crossblock function in this case.

3.2 Earth-fault differential protectionThe earth-fault differential protection detects –selectively and with high sensitivity – earth faultsin transformers with earthed star-point. The pre-requisite is that a current transformer is installedin the star-point connection, i.e. between the starpoint and the earthing electrode. This star-pointtransformer and the phase current transformerdefine the limits of the protected zone.

No current ISt flows in the star-point connectionin normal operation. The sum of the phase cur-rents

3I0 = IL1 + IL2 + IL3 is almost zero.

In the event of an earth fault in the protected zone(Fig. 9) a star-point current ISt will flow; depend-ing on the earthing conditions of the system, anearth current can also feed the fault position viathe phase current transformer (dotted arrow),which, however, is more or less in phase with thestar-point current. The currents flowing into theprotected object are defined positive.

Fig. 9 Currents in case of an earth fault inside thetransformer



In the event of an external earth fault a zero-sequence current also flows through the phase cur-rent transformers. This current has the same mag-nitude as the star-point current on the primaryside and is phase-opposed to it. Therefore, both themagnitude of the currents and their relative phasepositions are evaluated for stabilization. This pro-duces the following tripping characteristic for theearth differential protection:

In the above examples it was assumed that 3I0” and3I0’ are phase-opposed in the event of an externalearth fault, which is correct as far as the primaryvariables are concerned. However, current trans-former saturation can simulate a phase shift be-tween the star-point current and the sum of thephase currents, which weakens the restraint value.The restraint is zero at ϕ(3I0”; 3 I0’) = 90°. This cor -responds to the conventional method of directiondetection by use of the vectorial sum and differ-ence comparison.

The following phasor diagram shows the restraintvalue in the event of an external fault:

The earth-fault differential protection functionmust be activated by parameterization. The7UT613 earth-fault differential protection relay isdelivered in inactive-circuit state. This is becausethe protection relay may not be operated withoutat least having set the allocation and polarity ofthe current transformers correctly first. The relaymay react unpredictably without these settings.

The setting of the I-EDS> value is decisive for thesensitivity of the protection. This value is theearth-fault current which flows through the star-point connection of the transformer. Anotherearth current flowing in from the system is notabsorbed by the pickup sensitivity. The currentvalue refers to the rated operating current of theside of the transformer to be protected. The pre-set pickup value of 0.15 I/InS is normally appro-priate.

3.3 Backup protection functions3.3.1 Overcurrent-time protectionThe definite-time overcurrent-time protection ofthe 7UT613 serves as backup for the short-circuitprotection of the downstream system sectionswhen faults cannot be cleared in time there,meaning that the protected object is in danger.

The overcurrent-time protection can be assignedto one of the three voltage sides of the trans-former. Correct allocation between the measur-ing inputs of the relay and the measuring loca-tions (current transformer sets) of the powerplant must also be observed. The stage I>> to-gether with stage I> or stage IP produces a two-stage characteristic. If the overcurrent-time pro-tection acts on the feed side of the transformer,stage I>> is set so that it picks up for short-cir-cuits extending into the protected object, but notfor a short-circuit current flowing through it.

Fig. 10 Tripping charac-teristic for earthdifferential pro-tection

Fig. 11 Phasor diagram ofrestraint (stabiliza-tion) value



Calculation example:

Transformer Y(N)d572 MVA25 kV/10 kVuSC = 12 %Current transformer 2000 A/1 A on the 25-kV-sideThe overcurrent-time protection acts on the25 kV side (= feed side).The maximum possible three-phase short-circuitcurrent on the 10 kV side with rigid voltage on the25 kV side would be:

IU

IU

S3polemax

SC Transf.

N Transf.

SC Transf.

N= ⋅ = ⋅1 1 Transf.

N3

MVA

3 kVA

⋅=

⋅⋅

=

U

1

012

72

2513856 4

..

With a safety factor of 20 % this gives the primarysetting:

I>> = 1.2 x 13856.4 A = 16628 A

With parameterization in secondary variables thecurrents in amperes are converted to the second-ary side of the current transformers.

Secondary setting value:

I >> = ⋅166281

A

2000 AA = 8,314 A

i.e. at short-circuit currents above 16628 A (pri-mary) or 8,314 A (secondary), there is definitely ashort-circuit in the transformer area. This can becleared immediately by the overcurrent-time pro-tection. Increased inrush currents are disarmed bythe delay times of the I>> stage if their fundamen-tal exceeds the setting value. The inrush restraintdoes not affect the stages I>>.

Stage I> represents the backup protection for thesubordinate busbar. It is set higher than the sumof the rated outgoing currents. Pickup by overloadmust be ruled out because the relay operates withcorrespondingly short command times asshort-circuit protection in this mode and not asoverload protection. This value must be convertedto the HV side of the transformer. The delay timedepends on the grading time in the outgoing lines.It should be set 300 ms more than the highestgrading time on the LV side. Moreover, the inrushrestraint for the I> stage must be parameterizedeffectively in this case, so that false pickup of theI> stage (resulting from the inrush of the trans-former) is prevented.

3.3.2 Load unbalance protection (negative-sequence protection)

The load unbalance protection (phase-balancecurrent protection or negative-sequence protec-tion) can be used in the transformer as sensitiveprotection function on the feed side for weak-current single and two-pole faults. LV side, single-pole faults can also be detected which cause nozero-sequence current on the HV side (e.g. in vec-tor group DYN).

The load unbalance protection of the HV winding(110 kV in the example) can detect the followingfault currents on the LV side (25 kV in theexample):

If I2 > = 0.1 A is set for the HV side, a faultcurrent of

I F1

kV

25 kV

A

AA = 528 A= ⋅ ⋅ ⋅3

110 400

101.

can be detected for a single-phase fault and of

IF2

kV

25 kV

A

1 AA = 305 A= ⋅ ⋅ ⋅3

100 40001.

for a two-phase fault on the LV side. This corre-sponds to 26 % or respectively 15 % of the trans-former’s rated current. Since this is a LV sideshort-circuit, the delay time must be coordinatedwith the times of the subordinate protection relays.The definite-time characteristic is two-stage.

Stage I2> can be used for warning. A trip com-mand can be given at the end of the delay time ofstage I2>>.

Fig. 12 Tripping characteristic of load unbalance protection



3.3.3 Overload protectionThe thermal overload protection prevents over-load of the transformer to be protected. Twomethods of overload detection are available in the7UT6:

Overload protection with thermal replicaaccording to IEC 60255-8,

Hot-spot calculation with determining of therelative ageing rate according to IEC 60354.

One of these two methods can be selected. Thefirst is notable for easy handling and a low num-ber of setting values; the second requires someknowledge of the protected object, its ambientcontext and its cooling, and needs the input of thecoolant temperature via a connected thermobox.The second method is used when the transformeris operated at the limit of its performance and therelative ageing rate is to be monitored by the hot-spot calculation.Overload protection with thermal replica (to acton the HV side) is chosen for this applicationexample. Since the cause of the overload is nor-mally outside the protected object, the overloadcurrent is a through-flowing current. The relaycalculates the temperature rise according to athermal single-body model by means of the ther-mal differential equation

d

d th th N Obj

Θ Θ = 1t

I

I+ ⋅ ⋅

1

2

τ τ

The protection function therefore represents athermal replica of the object to be protected(overload protection with memory function).Both the history of an overload and the heat trans-mitted to the ambient area are taken into account.Pickup of the overload protection is output as amessage.

Notes on the settingIn transformers, the rated current of the windingto be protected, which the relay calculates fromthe set rated apparent power and the rated voltage,is significant. The rated current of the side of themain protected object assigned to the overloadprotection is used as the basic current for detect-ing the overload. The setting factor k is deter-mined by the ratio of the thermally permissiblecontinuous current to this rated current:

kI

I= max

N Obj

The permissible continuous current is at the sametime the current at which the e-function of theovertemperature has its asymptote. The pre-setting of 1.15 can be accepted for the HV wind-ing.

Time constant τ in thermal replica:The heating time constant th for the thermal rep-lica must be specified by the transformer manu-facturer. It must be ensured that the time constantis set in minutes. There are often other specifica-tions from which the time constant can be deter-mined:

Example:t6 time: This is the time in seconds for which 6times the rated current of the transformer windingmay flow.

τth

min= ⋅0 6 6. t

If the transformer winding has a 6 time of 12 s

τth

min= ⋅ =0 6 12 7 2. .s

the time constant must be set to 7.2 min.

3.3.4 Overexcitation protectionThe overexcitation protection serves to detect in-creased induction in generators and transformers,especially in power station unit transformers. Anincrease in the induction above the rated valuequickly leads to saturation of the iron core andhigh eddy current losses which in turn lead to im-permissible heating up of the iron.

Use of the overexcitation protection assumes thatmeasuring voltages are connected to the relay. Theoverexcitation protection measures the voltage/frequency quotient U/f, which is proportional tothe induction B at given dimensions of the ironcore. If the quotient U/f is set in relation to voltageand frequency under rated conditions of the pro-tected object UNObj/fN, a direct measure is ob-tained of the induction related to the inductionunder rated conditions B/BNObj. All constant vari-ables cancel each other:

B

B

U

U U f

U fN Obj

N Obj

N

N Obj N

= =f

f

/

/

The relative relation makes all conversions unnec-essary. All values can be specified directly relatedto the permissible induction. The rated variablesof the protected object have already been enteredin the 7UT613 relay with the object and trans-former data when setting the differential protec-tion.



Setting instructions

The limit value of permanently permissible induc-tion in relation to the rated induction (B/BN)specified by the protected object manufacturerforms the basis for setting the limit value. Thisvalue is at the same time a warning stage and theminimum value for the thermal characteristic(see Fig. 13).

An alarm is output after the relevant set delay time(about 10 s) of the overexcitation stage U/f has ex-pired. Major overexcitation endangers the pro-tected object already after a short time. The high-set tripping stage U/f>> is therefore set to a maxi-mum of 1 s.

The thermal characteristic should simulate theheating, i.e. temperature rise, of the iron core re-sulting from overexcitation. The heating charac-teristic is approximated by entering 8 delay timesfor 8 given induction values B/BNObj (referred to insimplified form as U/f). Intermediate values areobtained by linear interpolation. If no data areavailable from the protected object manufacturer,the preset standard characteristic is used.

4. Further functions4.1 Integration into substation control systemThe protection can be connected to a substationcontrol system via the system interface and oper-ated in parallel by PC via the service interface to astar coupler for separate remote communication.

Via the interface,

Messages Alarms Measured values

are transmitted from the transformer differentialprotection to the substation control system. Mes-sages are available for every one of the activatedprotection functions, which can be either trans-mitted to the substation control system in thecourse of plant equipment parameterization, orallocated to the LEDs or alarm contacts in theprotection relay. This configuration is made clearand easy by the DIGSI matrix.

Service interface

The 7UT613 has a separate service interface whichcan be read out by telecommunication via a mo-dem. The user is informed in the office quicklyand in detail about the transformer fault. The dataare then analyzed in the office by DIGSI. If thisremote fault clearing is insufficient, the fault dataprovide hints for an efficient service mission.

Fig. 13 Tripping characteristic of the overexcitation protection

Fig. 14 Integration into substation control system



5. Connection diagram 6. SummaryOptimum protection of the transformer withSIPROTEC relays means security of investmentfor valuable operating equipment and thereforemakes a contribution to maximum supply secu-rity.

From a technical point of view, the SIPROTEC7UT613 relay offers extensive short-circuit pro-tection for both the main and the backup protec-tion of transformers in one single relay. Extensivemeasuring functions allow trouble-free connec-tion of the relay without the need for additionalequipment, and enable monitoring of the trans-former in operation in terms of its electrical andthermal parameters. The relay’s presettings arechosen so that the user need only parameterizethe known data of the main and primary trans-formers. Many of the default settings can simplybe accepted as they are, and therefore makeparameterization and setting easier.

Fig. 15 Connection diagram of 7UT613



1. IntroductionTransformers are among the most important andcost-intensive equipment in electrical power sys-tems, meaning that faults which occur in thesecomponents not only entail an interruption in theelectrical power supply over wide areas but alsocause considerable losses in financial terms. A con-tinuous fault-free power supply must therefore beensured, over the course of years if possible. Faultsand signs of potential failures of the transformersmust therefore be detected in time in order to takesuitable measures for troubleshooting.

For this reason transformers are equipped withvarious monitoring and protection relays depend-ing on their type and size. The electrical protec-tion should be highlighted particularly in additionto the mechanical protection.

Fuses and definite-time overcurrent-time relaysare sufficient in smaller distribution transformersfor both technical and economic reasons. Fusesand definite-time overcurrent-time relays repre-sent time-delayed protection measures. Time-de-layed protection tripping relays are unacceptablefor larger transformers in distribution, transmis-sion and power generation applications and mustbe disconnected immediately to avoid system in-stability and cost-intensive shutdowns.

Transformer faults can generally be divided intofive categories:

Interturn and terminal fault Winding fault Fault on the transformer tank and auxiliary

devices Fault on the transformer tap changer Abnormal operating conditions (temperature,

humidity, dirt) External fault

This application example gives an insight into theprotection of regulated power transformers withtap changer function.

Protection of a Trans-former with Tap Changer

2. Protection conceptDepending on the type and size of the transform-ers, Buchholz protection, overload protection andovercurrent time protection are used as fast, selec-tive short-circuit protection in addition to theclassic differential protection (as from approxi-mately 1 MVA and higher). These are only men-tioned briefly here because they are described indetail in other application examples.

2.1 Differential protection as main protectionDifferential protection represents the main pro-tection function for the transformer and is fea-tured in the SIPROTEC relays 7UT6* (addr. 1201)and 7UM62* (addr. 2001). It also comprises anumber of additional functions (matching totransformation ratio and vector group, restraintagainst inrush currents). Therefore false differen-tial currents caused by transformation errors ofthe current transformers are to be expected inpractice. In regulated transformers an additionalerror current is to be expected caused by adjust-ment of the tap changer.

The additional functions integrated in the relaysare influenced by the use of a transformer with tapchanger and the resulting correction values. Thisis explained in chapter 4 by a calculation example.

Fig. 1 SIPROTEC 7UT6 transformer protection

LSP2

171.

eps



Backup protection such as overcurrent timeprotection are provided in separate relays (e.g.7SJ602, 7SJ45/46). The overcurrent-time protec-tion and/or overload protection contained in thedifferential protection relays serve merely asbackup protection against external faults in theconnected power system.

2.2 Earth-fault differential protectionIn transformer windings with star-point earthingvia an impedance (earth-current limiting), theearth-current differential protection (7UT6* addr.1301) is an ideal supplement to the phase protec-tion to enhance the response sensitivity in theearth fault.

In this method the measured star-point currentI0* in the transformer star-point is compared withthe calculated summation current I0** of thephase currents.

2.3 Buchholz protectionThe Buchholz protection is coupled into the relay(alarm, tank and trip message) as an external pro-tection (7UT6*, 7UM62* addr. 8601, 8701) and isused for liquid-cooled transformers and reactorswith expansion tank. The Buchholz relay respondsto faults which cause the forming of gas in thetank (winding fault, interturn fault, loss of insulat-ing fluid, accumulation of air).

3. Integration of the transformer tap changerin differential protection

3.1 Purpose of a transformer tap changerVoltage regulation on transformers with load tapchangers is an important topic for power supplycompanies. In accordance with DIN/IEC standardsit is necessary to keep the 230 V/400 V voltage inthe public low-voltage system constant, at least inthe range ± 10 %. To keep the voltage constant inthis bandwidth, a transformer tap changer is con-trolled by a transformer voltage regulator (e.g.Maschinenfabrik Rheinhausen TAPCON®230/240). The voltage regulator constantly com-pares the actual value Uact (output voltage at thetransformer) and a fixed or load-dependentsetpoint Usetp.

The voltage regulator supplies the setting variablefor the transformer’s load tap changer dependenton the deviation of the actual value from thesetpoint. The load tap changer switches when thegiven bandwidth (Usetp +/- B%) is dropped belowor exceeded. The voltage at the transformer is thuskept constant. Fluctuations within the permissiblebandwidth have no influence on the control be-havior or the switching process.

Fig. 2 False differential current in the event of load andcontinuity faults and matched relay characteristic

Fig. 3 Protection of a two-winding transformer

Fig. 4 Earth-fault differential protection

87T Transformer differentialprotection

51 Assigned to W2 asprotection for busbarfaults and backup pro-tection for feeders

50/51 Backup protection forthe transformer

49 Overload protectionBu Buchholz protection

Relay characteristic

∆IGF = Total error current

∆IWF = CT error current∆IAF = Matching error current

∆IWF = CT magnetizationcurrent



The parameters of the voltage regulator can beadapted optimally to the behavior of the systemvoltage so that a balanced control behavior isachieved at a low number of cycles of the load tapchanger.

3.2 Correcting “false” differential currentsMost calculations of differential and restraint cur-rents are made without taking the tap changer po-sition into account. In practice, however, mostpower transformers are equipped with a tapchanger. Two types are distinguished: Off-load tap changer On-load tap changer

Whilst most transformers are equipped foroff-load tap changing, on-load tap changing isused for voltage regulation in power systems. Theprotection parameterization must take the differ-ent tap changer positions into consideration toavoid the possibility of false tripping (especiallywith extreme positions).

Correct operation of the differential protection re-quires that the differential currents on the primaryand secondary side correspond to real conditionsunder normal load and fault conditions. The pri-mary and secondary side current transformers donot pick up the real transformer ratio. Today’sprotection relays such as those in the SIPROTECseries compensate these faults with calculated cor-rection factors based on the parameterized power

system data. Former relay generations requiredseparate matching transformers for (e.g.) vectorgroup adaptation.

If the winding is regulated, not the actual ratedvoltage is used as UN for the stabilized side, but thevoltage corresponding to the mean current of theregulated range.

UU U

UU U

Nmin

max min

min

= ⋅ ⋅+

=+

22

1 1max

max

U

with Umax, Umin as limits for the regulated range.

Example:

Transformer Ynd535 MVA110 kV/20 kVY side regulated ± 20%

For the regulated winding (110 kV) this results in

Maximum voltage Umax = 132 kVMinimum voltage Umin = 88 kV

Voltage to be set

U N -PRI SIDE

kV kV

kV1

21

132

1

88

105 6=+

= .

Fig. 5 Voltage regulation of a regulated transformer using a TAPCON® system



Parameters in relevant SIPROTEC relays

7UT612 addr. 2407UT613/63* addr. 3117UM62 addr. 240

4. Calculation exampleInfluence of tap positions on differentialand restraint currents

A two-winding transformer with a tap changerange of –15 % to + 5 % is used for the followingexample. The tap changer is integrated in the pri-mary winding for voltage regulation.

Transformer YNd5(irrelevant for the calculation)72 MVA110 kV/25 kVY side regulated -15 %/+5 %CT1 = 400 (1 A)CT2 = 2000 (5 A)

4.1 Calculations of the voltage, object ratedcurrents and correction factors to be set

The voltage to be set is calculated using the for-mula in chapter 3.2 and parameterized asUN WIND.S1 in the SIPROTEC relays 7UT6*,7UM62*.

For the regulated winding (110 kV) this gives acalculatedmaximum voltage Umax = 115.5 kVminimum voltage Umin = 93.5 kV

Voltage to be set

UU U

U UU U

Nmin

min

min

kV

1 22

1 1

2115 5 93

= ⋅ ⋅+

=+

= ⋅ ⋅

max

max

max

. .

. ..

5

115 5 935103 3

kV

kV kVkV

+=

Object rated current of the regulated side

IS

UN

N

N

MVA

kVA1

13

72

3 103 3402 3=

⋅=

⋅=

..

corresponds on the CT1 secondary side to

II

CTN

N1NObj

402.3 AA1

1 400100575= = = ≅. I

(referred to S1)

Object rated current of the unregulated side(remains constant)

IS

UN2

N

N2

MVA

kVA=

⋅=

⋅=

3

72

3 251663


II

CTN2

N2NObj

AA= = = ≅

2

1663

20000 8315. I

(referred to S2)

4.2 Calculations of the differential/restraintcurrents in the tap changer extreme positions

4.2.1 Tap position +5 %Object current in maximum tap position

IS

UN

N MVA

kVA1 5

3

72

3 115 5359 9( %)

max ..+ =

⋅=

⋅=


II

CTN

N1(+5%)NOb

359.9AA 0.89461 5

1 4000 8997( %) .+ = = = ≅ ⋅ I j

Differential current in maximum tap position

I I I I I IDiff N NObj NObj NObj NO= − = ⋅ − = ⋅+1 5 0 8946 01054( %) . . bj

Restraint current in maximum tap position

I I I I IRestraint N1 NObj NObj NObj= + = ⋅ + =+( %) . .5 0 8946 18946 ⋅ INObj

4.2.2 Tap position -15 %Object current in minimum tap position

IS

UN

N

min

MVA

kVA1 15

3

72

3 935444 6( %)

..− =

⋅=

⋅=


II

CTN

N1(-15%)N

AA I1 15

1

444 6

40011115 11051( %)

.. .− = = = ≅ ⋅ Obj

Differential current in maximum tap position

I I I I I IDiff N N2 NObj NObj NOb= − = ⋅ − = ⋅−1 15 11051 01051( %) . . j

Restraint current in maximum tap position

I I I I I IRestraint N N2 NObj NObj= + = ⋅ + = ⋅+1 5 1051 21051( %) . . NObj

Fig. 6

IN SIDE 1

MVA

3 kVA=

⋅=72

110378 IN SIDE 2

MVA

3 kVA=

⋅=72

251663



At the voltage to be set according to chapter 3.2the same differential current portion of the objectrated current is measured respectively in the ex-treme positions The calculated voltage UN1 tobe set corresponds to the middle position of thetransformer tap changer.

4.3 Difference between operating current andrestraint current

I Iop Restraintm= ⋅

Presetting m = 0.25Iop = 0.25 ⋅ IRestraint

At maximum tap position + 5 % it follows that

I I Iop NObj NObj= ⋅ ⋅ = ⋅0 25 18496 0 4624. . .

At minimum tap position - 15 % it follows that

I I Iop NObj NObj= ⋅ ⋅ = ⋅0 25 21051 0 5263. . .

From the calculations it can also be derived that,under rated conditions and at the tap changer ex-treme positions, the operating currents are not inthe tripping area (due to the characteristic).Therefore the slope (gradient) of the trip charac-teristic (7UT6* addr. 1241, 7UM62* addr. 2041)need not be adapted to conditions (presettingm = 0.25).

5. Parameterization notesDirect coupling of the transformer tap changerinto the protection algorithm is available as fromV4.6 for 7UT63* relays (approx. available as ofmid-2005). By reading in the tap positions (withthe codings BCD, binary, 1 from n table), thetransformation ratio can be adapted depending onthe position, and the faulty differential currentscompensated as a result. This improves both thesensitivity and the stability of the differential pro-tection.

The matching is currently performed by correc-tion of the primary voltage according to theformula in chapter 3.2 and parameterization bymeans of the appropriate addresses or DIGSI.

6. Integration of tap positions in DIGSITransformer taps can be indicated either by theDIGSI PC or the graphic display of the SIPROTECrelay. The transformer taps are signaled via binaryinputs on the relay. The binary inputs are assignedaccording to the coding type and number of trans-former taps (see Fig. 9).

In order to display the transformer taps, the trans-former tap message type must first be entered inthe configuration matrix.

Fig. 8 Tripping characteristic of the differential protection in 7UT6* and 7UM62*

Fig. 7 7UT613/63* parameterization in transformersystem data

Fig. 9 Schematic diagram – Reading in of tap position by DIGSI orgraphic display

LSP2

669.

tif



The transformer tap message is entered in theconfiguration matrix and activated by configura-tion of the binary inputs.

Detailed settings must be made under the objectproperties of the transformer tap message.

Number of bits: necessary for coding; numberdepends on the selected coding

Display offset: the value by which the size of thedisplayed value is to be shifted in positive ornegative direction in relation to the magnitudeof the actual value

Moving contact: if the moving contact option isactivated, the tap position is not recognized asvalid and accepted until the moving contact sig-nals that it has reached the taps (always thehighest ranking contact)

7. SummaryIn most differential protection relays the influenceof the transformer tap changer is mainly takeninto account with the corrected input of the pri-mary voltage (determined in the middle positionof the tap changer).

Owing to the demand for stabilized voltages andregulation by tap changers, the probabilities oftripping faults in the extreme positions of the tapchanger can be limited in future by matching ofthe transformation ratio. This requirement is metby inclusion of the tap position in the protectionrelay and consideration of the protection algo-rithm in the SIPROTEC 7UT63* relays.

Fig. 10 Activating the transformer tap message in theinformation catalog

Fig. 11 Entry of the transformer tap message in theDIGSI configuration matrix

Fig. 12 Object properties, transformer tap message

LSP2

670.

tif

LSP2

575.

tif

LSP2

671.

tif



1. IntroductionTransformers are valuable equipment which makea major contribution to the supply security of thepower system. Optimum design of the transform-er protection ensures that any faults that may oc-cur are found quickly, so that consequentialdamage is minimized. A special variant is theso-called autotransformer in which, unlike in thefull transformer, the voltage and current transfor-mation is not performed by two independentwindings but uses part of the winding from bothsides, allowing a much more compact design.The spectrum of autotransformers ranges fromsmall distribution system transformers (from1000 kVA) to large transformers of several hun-dred MVA. Their use becomes more interesting,the less the ratio between the high-voltage (HV)side and low-voltage (LV) side deviates from 1,i.e. the less energy is transmitted via the magneticcoupling which leads to a saving in iron material.In addition to the design notes, a complete settingexample with SIPROTEC protection relays for atriple-wound autotransformer in the transmissionsystem is described.

2. Protection conceptDifferential protection offers fast, selective short-circuit protection, alone or as a supplement to theBuchholz protection. In larger units from about5 MVA it is part of the standard equipment. In ad-dition to the main protection function which reli-ably clears a short-circuit within the protected ob-ject, a fully-fledged protection concept contains anumber of additional functions which take care ofother problems such as overload, overexcitation,etc. All the necessary functions are already con-tained in the SIPROTEC 4 relays. Backup protec-tion functions are a useful addition.

Fig. 2 shows an example of a full protectionconcept for an autotransformer.

Protection of anAutotransformer

Fig. 1 SIPROTEC 7UT6 transformer protection

Fig. 2 Protection of an autotransformer

7UT613

7UT612



For this example a differential protectionANSI 87T (3-windings version) must be selected(7UT613), so that the delta stabilizing windingcan be included in the protected zone (differentalternatives for connection are explained in detailin chapter 3). If this is missing, an autotransfor-mer can also be fully protected with the 7UT612.The integrated overload protection ANSI 49 isadapted to the load and protects the transformerfrom overheating and premature aging. The over-excitation protection ANSI 24 prevents impermis-sible heating of the iron.To increase the earth-fault sensitivity, an addition-al high-impedance earth-fault differentialprotection ANSI 87TE is often used in English-influenced regions. The single-phase relay7VH600 is on the parallel circuit of the outgoingside transformers and of the star-point transform-er. The seven transformers (3 side 1, 3 side 2,1 star point) must be provided additionally, how-ever, and be designed according to class TPS(IEC 60 044-6). A pickup value of 10 % In is usual-ly achieved. Additionally or alternatively, an over-current relay Ie>t ANSI 50N can be provided inthe star-point link. However, this must be in timecoordination with the subordinate overcurrent re-lay.The delta winding which, in addition to its stabi-lizing (restraint) function, is also often used forautonomous supply, gets its own overcurrent-time protection ANSI 50, 50N for external phasefaults. The voltage relay 7RW600 (ANSI 59N) onthe open delta winding of the voltage transformermeasures the displacement voltage 3U0 withwhich an earth fault in the tertiary winding or inthe connected distribution system is indicated.An overcurrent-time protection ANSI 50, 50N isarranged on the HV and LV sides, each with ainstantaneous tripping stage I>> and delayedstage I> (against phase and earth-faults). Integrat-ed overcurrent-time protection can also configur-ed optionally in 7UT613 on one of the two sides.For every outgoing circuit the breaker failure pro-tection ANSI 50 BF must be activated in the rele-vant protection relay.

The individual elements shown in an overview aredescribed step by step as follows.

3. Structure of an autotransformer

Autotransformers only have the vector groupYNyn0; i.e. there is no phase shift of the currentsand voltages between the primary and secondarysides. The common star point is always earthed.Therefore both sides are always electrically con-nected. The distribution of the star-point currenton both sides depends on several factors, e.g. win-ding distribution and presence of a tertiary win-ding.

4. Implementation with SIPROTEC4.1 Differential protectionTransformer differential protection contains anumber of additional functions (matching totransformation ratio and vector group, stabilizati-on (restraint) against inrush currents and over-excitation) and therefore requires some funda-mental consideration for configuration andselection of the setting values. The additionalfunctions integrated per relay can be used to ad-vantage. However, it must be considered that ba-ckup protection functions must be arranged inseparate hardware (further relay) for reasons ofhardware redundancy. This means that the over-current-time protection in the differential protec-tion 7UT612/ 613 can only be used as backupprotection against external faults in the connectedpower system. The backup protection for thetransformer itself must be provided as a separateovercurrent relay (e.g. 7SJ602). The Buchholzprotection as fast short-circuit protection is supp-lied with the transformer.

Fig. 3 Structure and transmission ratios of atwo-winding autotransformer

NW W= +I II

IIW

U

UN

N1

2

1

2

1= =;I

I

I1L1

U1L1

I1L2

U1L2

I1L3

U1L3

I2L1

U2L1

I2L2

U2L2

I2L3

U2L3

WI WII



Designations according to ANSI (American Na-tional Standard) are used for the individualfunctions. The differential protection thereforehas ANSI No. 87, for example. The differentialprotection is provided as a definite-time fastshort-circuit protection in addition to the Buch-holz protection.The differential protection for an autotransformercan be implemented in 2 different ways dependingon the available current transformers.

1. Differential protection over the whole trans-former bank (protection to be used 7UT612(2 windings) / 7UT613 (3 windings):In this case, as shown in Fig. 4, three phase currenttransformers are used for each side. The star-pointtransformer is insignificant for the differentialprotection but can be used for backup overcur-rent-time protection. It can be set on both sidesdepending on further use by other protectionfunctions.

2. Current comparison per autotransformerwindingUse of phase current transformers upstream of thestar-point junction (earth-current winding). Fig. 5shows, that the supply lines to the star (neutral)point all have a phase current transformer. In thiscase, the autotransformer can be treated as a nodeobject with three terminals.

Both connection types are basically different andare treated separately in chapter 5.

4.2 Earth-fault differential protectionThe earth-fault differential protection cannot beused in the autotransformer.

4.3 Backup protection functionsThe integrated overcurrent-time protection(ANSI 51) in the 7UT613 serves as backup protec-tion for faults in the supplied system. Separateovercurrent protection on the LV side is thereforeunnecessary. The 7JS600 relay on the HV side canbe used as backup protection against short-circuitsin the transformer and as additional backup protec-tion against LV side faults. The high-set, fast trip-ping stage I>> (ANSI 50) must be set above theshort-circuit current flowing through it, so that itdoes not pick up in the event of faults on the LVside. The delayed tripping (ANSI 51) must be gra-ded with the overcurrent protection in the 7UT613.

The windings S1 and S2 can be protected with theintegrated overload protection.

Fig. 4 Topology of a transformer bank consisting of 3 single-phase autotransformerswith a stabilizing winding designed as a tertiary winding

Fig. 5 Topology of a transformer bank consisting of 3 single-phase autotransformers;topology definitions for one current comparison protection per phase, i.e. thereis phase-selective current measurement at M3 before the star-point junction

Sides:S1 HV side of the autotransformer

winding on the main protectedobject

S2 LV side of the autotransformerwinding (tapping) on the mainprotected object

S3 Side of the tertiary winding(stabilizing winding) on the mainprotected object

3-phase measuring locations, assigned:M1 Measuring location for side 1

assigned to the main protectedobject

M2 Measuring location for side 2assigned to the main protectedobject


Additional measuring locations 1-phase,assigned (summation current of thetransformer set):Z3 Measuring location for side 1 and

side 2 assigned to the mainprotected object

Sides:S1 HV side of the autotransformer

winding on the main protectedobject

S2 LV side of the autotransformerwinding (tapping) on the mainprotected object

S3 Star-point side of the autotrans-former on the main protectedobject

3-phase measuring locations, assigned:M1 Measuring location for side 1

assigned to the main protectedobject



Additional measuring locations 1-phase,assigned (summation current of thetransformer set)Z3 Measuring location for side 1 and

side 2 assigned to the mainprotected object

Phase L1 Phase L2 Phase L2

Phase L1 Phase L2 Phase L2



The delta winding – which is often only used forown, internal supply – has its own overcurrent-time protection (ANSI 51) against phase faultsand because of its reduced rated power it requiresa separate overload protection. Both can be reali-zed with a 7SJ600 as shown in Fig. 2, for example.

4.4 Integration of Buchholz protectionThe Buchholz protection of the transformer eval-uates the gas pressure of the transformer tank andtherefore detects internal faults in the transformerquickly and sensitively. The following should beconsidered for the integration:

The trip command of the Buchholz protectionshould act on the circuit-breaker directly andindependently of the differential protection

The trip command of the Buchholz protectionshould be recorded in the fault event log / faultrecord of the differential protection

Coupling the trip command via the binary inputof the differential protection provides informativedata for evaluation in the event of a fault.

5. Settings5.1 Setting instructions for differential protection

over the whole transformer bankThe differential protection as a main protectionfunction of the 7UT612/613 is parameterized andset in a few steps:

Parameterize protected object “autotransformer” Assign the measuring locations on the main

protected object

The topology in the autotransformer is defined asfollows:Side 1 is the first of the autotransformer windings;the HV side is usually chosen here.Side 2 is the second of the autotransformerwindings; the LV side is usually chosen here.

This may be followed by further tappings. If thereis a delta stabilizing winding, this should be as-signed last.

Fig. 7 Topology of an autotransformer with a stabilizingwinding designed as a tertiary winding

Fig. 6 Integration in the Buchholz protection

Sides:S1 HV side of the main protected object (autotransformer)S2 LV side of the main protected object (autotransformer)S3 Side of the tertiary winding (stabilizing winding) of the

main protected object (autotransformer)3-phase measuring locations, assigned:M1 Measuring location for side 1 assigned to the main

protected objectM2 Measuring location for side 1 assigned to the main



protected object

Mainprotectionobject



The relay requires the following data of the pro-tected object:

The primary rated voltage UN in kV(line-to-line)

The secondary rated voltage UN in kV(line-to-line)

The rated apparent power which is the same forboth sides in the autotransformer.

The “autotransformer” setting in the configura-tion automatically defines that no vector groupshift is performed (phase angle 0° between HVand LV side) and the zero current elimination isperformed on both sides.

In transformers, the currents measured on thesecondary side of the current transformer whencurrent flows through are not generally equal, butare determined by the ratio of the transformer tobe protected and the rated currents of the currenttransformers. To make the currents comparablethey therefore have to be matched first. This takesplace arithmetically in the 7UT613. Externalmatching equipment is therefore normally super-fluous (frequent exception: tertiary winding withlow rated apparent power). The digitized currentsare converted to the respective transformer ratedcurrents. To do this, the transformer rating data,i.e. rated apparent power, rated voltages and theprimary rated currents of the current transform-ers, are entered in the protection relay.

Fig. 8 shows an example for magnitude matching.The primary rated currents of the two sides S1(288.7 A) and S2 (525 A) are calculated fromthe rated apparent power of the transformer(200 MVA) and the rated voltages of the windings(400 kV and 220 kV). Since the current transfor-mer rated currents deviate from these transformerrated currents, the secondary currents are multi-plied by the factors k1 and k2. The third winding(S3) on the other hand is only dimensioned for12 MVA (e.g. as an auxiliary supply winding). Therated current of this winding (= side of the pro-tected object) is therefore 346 A. For the differen-tial protection, however, comparable currentsaccording to the ratio of the individual sides of thetransformer must be used for the calculation.Therefore the rated power of the protected objectof 200 MVA must likewise be taken as basis for thethird winding. This gives a theoretical rated cur-rent (here = current under rated conditions of theprotected object, i.e. at 200 MVA) of 5773.5 A.This is the reference variable for the currents ofthe third winding. The currents are thereforemultiplied by factor k3. The relay performs thismagnitude matching based on the set rated values.

The technical data of the 7UT612/613 show a per-missible ratio of 0.25 < k < 4 specified for phasecurrents. This means that in the case of thewinding 3, k3 has an impermissibly small ratio.A matching transformer must be provided here toreach the permissible range. It should be dimen-sioned so that the matching factor reaches justabove the minimum figure of 0.25. In this case itcould therefore be assumed:

n > 0.25 / (400A / 5773.5A) = 3.6, e.g. n=4.

Together with the autotransformer informationthe protection relay is now able to perform a cur-rent comparison. The principle is explained in thefollowing example (see Figs. 9 and 10):

Fig. 8 Example of an autotransformer for magnitudematching

UN= 400 kV kA

A1

300288 7

104= =.

,

SN = 200 MVAUN = 20 kVSN = 12 MVA

UN = 220 kV

kA

A3 = =400

577350 07

.,

kA

A2

600524 9

114= =.

,

IS

UNT

N

NNCT1

MVA

kVA A1

3

200

3 400288 7 300=

⋅=

⋅= → =. I

INT2 NCT2MVA

kVA A=

⋅= → =200

3 220524 9 600. I

INT3 NCT3MVA

kVA A=

⋅= → =12

3 20346 400I

IN obj1 = INT1 = 288.7 A

IN obj2 = INT2 = 524.9 A

IN obj3 =200

3 2057735

MVA

kVA

⋅= .

Fig. 9 Calculation of the differential current in the autotransformer for an external fault



Vector group: Autotransformer (YNyn0) ü = 3/2(Transformation ratio)

Side 2: w2 = 2N Side 1: w1 = N

Fig. 10 Calculation of the differential current in the event of an internal fault

Vector group: Autotransformer (YNyn0) ü = 3/2(Transformation ratio)

Side 2: w2 = 2N Side 1: w1 = N

Both sides are converted to a “virtual” side, basedon which the current comparison is made. In caseof vector group 0 (as is always the case with theautotransformer) this is done by a standard ma-trix. The matrices used are given by the standardmatrix by subtracting the zero current from themeasurement (corresponds to 1/3 of the sum ofall three phase currents). This is necessary, becau-se it is not possible to divide the star-pointcurrent on both sides of the protected object.

5.2 Setting instructions for differential protectionin current comparison per autotransformerwinding

If current transformers are available for eachphase on the supply lines to the star point (earthwinding), one node protection per phase can beimplemented. Current transformation ratios andtheir tap changes have no effect, because the threeentry points of the current are measured here andform the end points of the Kirchoff node.Such a current comparison is more sensitive forearth-faults than normal differential protection(see Fig. 11). This is of interest, because thesefaults have the highest probability in transformerbanks. Any stabilizing winding or tertiary windingmust not be integrated in the protection in thisapplication, even if it is connected externally andequipped with current transformers, because thisdoes not belong to the protected (phase-selective)node.

Fig. 11 Increasing the sensitivity by usingphase-selective earth windings

W = 1 = W1 + W2

WkV

kV2

275

4000 6875= = .

W1 = W - W2 = 1 - 0.6875 = 0.3125

Side 2: Side 1:

I

I

I

I2

2

2

1

3

2

1

1

1

2

1

1

1

2

A

B

C

= ⋅ −−

−

−

−−

⋅2

2

2

2

2 0

2 0

2

2

2

1

2

3

1

L

L

L

L F

L2

L3

A

B

C

I

I

I I

I

I

I

I

I

= −==

= ⋅− ⋅ +

++

+++

1

3

2 0

0

0

0

0

0

I

I

I

F

F

F

I

I

I

I1

1

1

1

3

2

1

1

1

2

1

1

1

2

A

B

C

= ⋅ −−

−

−

−−

⋅1

1

1

1 2 3

1 0

1 0

1

2

3

1

L

L

L

L F F

L2

L3

ü

I

I

I I I

I

I

I

= ⋅ ⋅ ===

/

1

1

1

1

3

2

1

1

0

0

0

0

0

0

A

B

C

F

F

F

I

I

I

I

I

= ⋅⋅

−−

+−+

++−

= −−

1

3

2I

I

I

F

F

F

IDiff

IDiff

IDiff

I

I

I

A

B

C

F

F

F

= −

−

2

3

3

3

+

−

=

2

3

3

3

0

0

0

I

I

I

F

F

F

No trip

Side 2: Side 1:

I

I

I

I2

2

2

1

3

2

1

1

1

2

1

1

1

2

A

B

C

= ⋅ −−

−

−

−−

⋅2

2

2

2 0

2 0

2 0

2

2

2

1

2

3

1

L

L

L

L

L2

L3

A

B

C

I

I

I

I

I

I

I

I

===

= ⋅

1

3

0

0

0

I

I

I

I1

1

1

1

3

2

1

1

1

2

1

1

1

2

A

B

C

= ⋅ −−

−

−

−−

⋅1

1

1

1 2 3

1 0

1 0

1

2

3

1

L

L

L

L F F

L2

L2

ü

I

I

I I I

I

I

I

= ⋅ ⋅ ===

/

1

1

1

1

3

2

1

1

0

0

0

0

0

0

A

B

C

F

F

F

I

I

I

I

I

= ⋅⋅

−−

+−+

++−

= −−

1

3

2I

I

I

F

F

F

IDiff

IDiff

IDiff

I

I

I

A

B

C

F

F

F

= −

−

2

3

3

3

+

= −

−

0

0

0

2

3

3

3

I

I

I

F

F

F

Trip

Differential current in the2-winding differential protectionacc. to Chap. 5.1

IDiff = I1 (I2 = 0)

Differential current in the3-winding differential protection(incl. earth winding) acc. toChap. 5.2

IDiff = I1 + I3 = I1 + 1.909 ⋅ I1

= 2.909 ⋅ I1

Example:Fault in winding W2 at 50 %

WF = 0.5 W2 = 0.34375

I1 (W1 + WF) = I3 (W2- WF)

I3 = I1

W W

W W1 F

2 F

+−

= ⋅1 909 1. I



The topology is determined as follows:The two autotransformer windings becomeS1 and S2 (tapping).The earth winding must in this case be set asside 3. If there is a further tapping, the earth wind-ing is specified as side 4. As soon as one of thesides is defined as earth winding, the protectionautomatically places node differential protectionacross all autotransformer windings involved.

The differential protection function must beactivated by parameterization. The differentialprotection relay 7UT613 is delivered in inactive-circuit state. This is because the protection maynot be operated without at least having set thevector groups and matching values correctly first.The relay may react unpredictably without thesesettings.

Setting of the characteristic of the differential pro-tection is based on the following considerations:

The presetting for IDiff > of 0.2 x IN referred tothe rated current of the transformer can be ta-ken as a pickup value for the differential currentas a rule.

The slope 1 together with base point 1 take intoaccount current-proportional false currentswhich may be caused by transformation errorsof the CTs. The slope of this section of the cha-racteristic is set to 25 %.

The add-on restraint increases the stability ofthe differential protection in the very highshort-circuit current range in the event of exter-nal faults; it is based on the setting valueEXF-Restraint (address 1261) and has the slope 1(address 1241).

The slope 2 together with base point 2 lead tohigher stabilization in the higher current rangeat which current transformer saturation can oc-cur. The slope of this characteristic section is setto 50 %.

The IDiff >> stage works without restraint (stabi-lization) and is designed for high internal faultcurrents on the primary side of the transformerwith a high degree of saturation. It should be setto at least 20 % above the max. through flowingfault current or the max. inrush currents, respec-tively.

Notes on add-on restraint

In systems with very high traversing currents, adynamic add-on restraint becomes effective forexternal faults. Presetting 4.0 can, as a rule, be ta-ken over without change. The value is referred tothe rated current of the protected object.Note that the restraint current is the arithmeticsum of the currents flowing into the protected ob-ject, i.e. is double the traversing current. The

add-on restraint does not affect the I>> stage.The maximum duration of add-on restraint afterdetecting an external fault is set in multiples of aperiod (AC cycle). The recommended settingvalue is 15 periods (preset). The add-on restraintis automatically disabled before the set time peri-od expires as soon as the relay has detected thatthe operation point IDiff/IRestraint is located steadily(i.e. for at least one period) within the trippingzone near to the fault characteristic. The add-onrestraint operates separately for each phase butcan be extended to blocking all phases dependingon the used vector group (crossblock function).The recommended setting value for the crossblockfunction is 15 periods (preset).

Notes on setting the inrush blocking

An inrush current with a high proportion of 2nd

harmonics is generated when switching the trans-former on, which can lead to false tripping of thedifferential protection. The preset value for the in-rush restraint with 2nd harmonics of 15 % can beaccepted unchanged. A lower value can be set forgreater restraint in exceptional cases under un-favorable energizing conditions resulting from thedesign of the transformer.

The inrush restraint can be extended by the cross-block function. This means, that all three phasesof the IDiff > stage are blocked when the harmoniccomponent is exceeded in only one phase. A set-ting value of 3 periods, effective for the time ofmutual blocking after exceeding the differentialcurrent threshold, is recommended (preset).

Fig. 12 Differential protection tripping characteristics



Notes on setting the overexcitation blocking

Stationary overexcitation in transformers is char-acterized by odd harmonics. The third or fifthharmonic is suitable for restraint. Since the thirdharmonic is often eliminated in transformers (e.g.in a delta winding), the 5th harmonic is mostlyused. The proportion of 5th harmonics which leadsto blocking of the differential protection is set at30 % (preset). It is not usually necessary to set thecrossblock function in this case.

5.3 Backup protection functions5.3.1 Overcurrent time protectionThe definite-time overcurrent-time protection ofthe 7UT612/613 serves as backup for the short-circuit protection of the downstream power sys-tem sections when faults cannot be cleared in timethere, meaning that the protected object is in dan-ger.The overcurrent-time protection can be assignedto one of the three voltage sides of the transform-er. Correct allocation between the measuring in-puts of the relay and the measuring locations (cur-rent transformer sets) of the power plant mustalso be observed. The stage I>> together with sta-ge I> or stage IP produces a two-stage characteris-tic. If the overcurrent-time protection acts on thefeed side of the transformer, stage I>> is set sothat it picks up for short-circuits extending intothe protected object, but not for a short-circuitcurrent flowing through it.

Calculation example:

Autotransformer YNyn050 MVA66 kV/33 kVuSC = 12 %Current transformer 500 A/1 A on the 66 kV sideThe overcurrent-time protection acts on the66 kV side (= feed side).The maximum possible three-phase short-circuitcurrent on the 33 kV side with rigid voltage on the66 kV side would be:

Iu

Iu

SN3

1 1pole

SC TransfoN Transfo

SC Transfo

Tmax = ⋅ = ⋅ ransfo

N3U

= ⋅⋅

=1

012

35

3 663645

.

MVA

kVA

With a safety factor of 20 % this gives the primarysetting:

I>> = 1.2 x 3645 A = 4374 A

With parameterization in secondary values thecurrents in amperes are converted to the secon-dary side of the current transformers.

Secondary setting value:

I A>> = ⋅ =4375

5008 75

A

AA.

i.e. at short-circuit currents above 4374 A (prima-ry) or 8.8 A (secondary), there is definitely a faultin the transformer area, which can be eliminatedimmediately by the overcurrent time protection.Increased inrush currents must be considered aswell. The inrush restraint does not affect the stageI>>.

Stage I> represents the backup protection for thedownstream busbar. It is set higher than the sumof the rated outgoing currents. Pickup by over-load must be ruled out because the relay operateswith correspondingly short command times asshort-circuit protection in this mode and not asoverload protection. This value must be convertedto the higher-voltage side of the transformer. Thedelay time depends on the grading time in theoutgoing lines. It should be set e.g. 200 ms morethan the greatest grading time on the LV side.Moreover, the inrush restraint for the I> stagemust be parameterized effectively in this case, sothat false pickup of the I> stage (resulting fromthe inrush of the transformer) is prevented.

5.3.2 Overload protectionThe thermal overload protection prevents over-loading of the transformer to be protected. Twomethods of overload detection are possible in the7UT6:

Overload protection with thermal replica accor-ding to IEC 60255-8,

Hot-spot calculation with determining of therelative ageing rate according to IEC 60354

One of these two methods can be selected. Thefirst is notable for easy handling and a low num-ber of setting values; the second requires someknowledge of the protected object, its ambientcontext and its cooling, and needs the input of thecoolant temperature via a connected thermobox.The second method is used when the transformeris operated at the limit of its performance and therelative ageing rate is to be monitored by thehot-spot calculation.

Overload protection with thermal replica (to act onthe HV side) is chosen for this application. Sincethe cause of the overload is normally outside theprotected object, the overload current is a traver-sing current. The relay calculates the temperaturerise according to a thermal single-body model bymeans of the thermal differential equation



d

dt th th N Obj

Θ Θ+ ⋅ = ⋅⋅

1 1

2

τ τI

k I

The protection function therefore represents athermal replica of the object to be protected(overload protection with memory function).Both the history of an overload and the heat trans-mitted to the ambient area are taken into account.Pickup of the overload protection is output as amessage.

Notes on the setting

In transformers, the rated current of the windingto be protected, which the relay calculates fromthe set rated apparent power and the rated voltage,is significant. The rated current of the side of themain protected object assigned to the overloadprotection is used as the basic current for detec-ting the overload. The setting factor k is deter-mined by the ratio of the thermally permissiblecontinuous current to this rated current:

kI

I= max

N Obj

The permissible continuous current is at the sametime the current at which the e-function of theovertemperature has its asymptote. The presettingof 1.15 can be accepted for the HV winding.

Time constant τ in thermal replica:

The heating time constant τth for the thermal rep-lica must be specified by the transformer manu-facturer. It must be ensured that the time constantis set in minutes. There are often other specifica-tions from which the time constant can be deter-mined:

Example:t6 time: This is the time in seconds for which6 times the rated current of the transformer wind-ing may flow.

τth

min= ⋅0 6 6. t

If the transformer winding has a t6 time of 12 s

τth

mins= ⋅ =0 6 12 7 2. .

the time constant τ must be set to 7.2 min.

5.3.3 Overexcitation protectionThe overexcitation protection serves to detect in-creased induction in generators and transformers,especially in power station unit transformers. Anincrease in the induction above the rated valuequickly leads to saturation of the iron core andhigh eddy current losses which in turn lead to im-permissible heating up of the iron.Use of the overexcitation protection assumes thatmeasuring voltages are connected to the relay. Theoverexcitation protection measures the voltage/frequency quotient U/f, which is proportional tothe induction B at given dimensions of the ironcore. If the quotient U/f is set in relation to voltageand frequency under rated conditions of the pro-tected object UN Obj/fN, a direct measure is obtain-ed of the induction related to the induction underrated conditions B/BN OBj. All constantvariables cancel each other:

B

B

U f

U fN Obj

N Obj

N

N Obj N

= =

U

U

f

f

/

/

The relative relation makes all conversions unnec-essary. All values can be specified directly relatedto the permissible induction. The rated variablesof the protected object have already been enteredin the 7UT613 relay with the object and trans-former data when setting the differential protec-tion.


The limit value of permanently permissible induc-tion in relation to the rated induction (B/BN)specified by the protected object manufacturerforms the basis for setting the limit value. Thisvalue is at the same time a warning stage and theminimum value for the thermal characteristic(see Fig. 13)

Fig. 13Tripping characteristic of theoverexcitation protection



An alarm is output after of the relevant set delaytime (about 10 s) of the overexcitation stage U/fhas expired. Major overexcitation endangers theprotected object already after a short time. Thehigh-set, fast tripping stage U/f>> is therefore setto a maximum of 1 s.

The thermal characteristic should simulate theheating, i.e. temperature rise, of the iron core re-sulting from overexcitation. The heating charac-teristic is approximated by entering 8 delay timesfor 8 given induction values B/BNObj (referred to insimplified form as U/f). Intermediate values areobtained by linear interpolation. If no data areavailable from the protected object manufacturer,the preset standard characteristic is used.

6. Further functions6.1 Integration in substation control and

protectionThe protection can be connected to a substationcontrol system via the system interface and oper-ated in parallel by PC via the service interface to astar coupler for separate remote communication.

Via the interface,

Messages Alarms Measured values

are transmitted from the transformer differentialprotection to the substation control system. Mes-sages are available for every one of the activatedprotection functions, which can be either trans-mitted to the substation control system in thecourse of plant equipment parameterization, orconfigured to the LEDs or message contacts in theprotection relay. Configuration is made clear andeasy by the DIGSI matrix.

Service interface

The 7UT613 has a separate service interface whichcan be read out by telecommunication via a mo-dem. The user is informed in the office quicklyand in detail about the transformer fault. The dataare then analyzed in the office by DIGSI. If this re-mote fault clearance is insufficient, the fault dataprovide hints for an efficient service mission.

7. SummaryOptimum protection of the transformer withSIPROTEC relays means security of investment forvaluable operating equipment and therefore makesa contribution to maximum supply security.

From a technical point of view, the 7UT612 or7UT613 relay offers extensive short-circuit protec-tion for both the main and the backup protectionof transformers in one single relay. FurtherSIPROTEC relays supplement the main protecti-on and enhance the reliability of the protectionscheme by way of hardware redundancy.

Extensive measuring functions allow trouble-freeconnection of the relay without the need for addi-tional equipment, and enable monitoring of thetransformer in operation in terms of its electricaland thermal parameters. The relay’s presettingsare chosen so that the user need only parameterizethe known data of the main and primary trans-formers. Many of the default settings can simplybe accepted as they are, and therefore make para-meterization and setting easier.

Fig. 14 Integration in substation control and protection


Motor Protection

1. IntroductionDrive motors often play a decisive role in thefunctioning of a production process. Motor dam-age and breakdowns not infrequently lead also toconsequential damage and production shutdowns,the cost of which significantly exceeds the cost ofrepairing the motor. Optimum design of the mo-tor protection ensures that damage followingthermal overload is prevented, meaning that thereis no reduction to the normal service life. Second-ary faults are minimized in the event of short-circuits, earth faults and winding faults.

The spectrum extends from small low-voltagemotors with an output of a few kW to high-voltage motors with outputs measured in MW.Protection system design must be based on therating of the motor, the importance of the drivefor the technological process, the operating condi-tions and the requirements of the motor manufac-turer.

The setting of a SIPROTEC protection relay formotor protection is described below taking ahigh-voltage motor (10 kV) as the example.

2. The tasks of motor protectionMotors have some striking features in their oper-ating conditions. These are important for under-standing the various possible causes of failure andmust be taken into account when designing pro-tection systems.

2.1 Protection of the stator against thermaloverload

The power drawn by the motor from the supplysystem during operation is supplied to the shaft asmechanical power for the production machine.The power lost to the winding during this energyconversion is the decisive factor for the arisingmotor temperatures. The loss of heat is propor-tional to the square of the current. The motorheating time characteristic is determined by itsheat storage capability and heat transfer proper-ties, and characterized by the thermal time con-stant [τ]. Electrical machines are at particular riskfrom long-term overload. Thermal overloading ofthe motor leads to damage to the insulation andtherefore to secondary faults or to a reduction inthe total service life of the motor.

Such overloading cannot and should not be de-tected by short-circuit protection since any poten-tial delay must be very short on these occasions.Overload protection prevents thermal overloadingof the motor to be protected. The 7SJ602 relay de-tects stresses either before overload occurs (over-load protection with complete memory = thermalreplica) or only after exceeding a preset start-upcurrent (overload protection without memoryfunction).

Overload protection without memoryIf overload protection without memory is cho-sen, the tripping time is calculated according toa simple formula. Pre-stressing is not taken intoaccount because currents are only recorded ifthey are greater than 1.1 times the set value.

tI I

t=−

⋅35

12( / )B

6IB for I > 1.1 IB

t Tripping timeI Overload currentIB Set thresholdt6IB Set time factor

(t6-time = tripping time when applying 6 timesthe actual set value IB)

Protection of aMotor up to 200 kW

Fig. 1 SIPROTEC 7SJ602 multifunction protection

LSP2

731.

tif

Motor Protection


Overload protection with memoryThe relay calculates the temperature rise in ac-cordance with a thermal homogenous-bodymodel and a thermal differential equation. Inthis way the previous load, with all load cycles,can be recorded and evaluated correctly by therelay. Such a thermal replica can be optimallyadapted to the overload capacity of the pro-tected equipment.

2.2 Protection of the rotor from thermal overloadAmong the many causes of excessive temperaturescaused by currents in motors is an unacceptablylong start-up time or, in limit cases, blocking ofthe rotor. Such conditions are caused by an exces-sive mechanical load torque, such as can occur inoverfilled mills and breakers or overloaded centri-fuges, etc.

Start-up time monitoringThe protection relay has start-time monitoring,which represents a meaningful addition to over-load protection for electrical machines. The triptime depends on the current. This enables evenextended start-up times to be correctly evalu-ated when the start-up current is reduced be-cause of voltage sags when the engine is started.The start-up time monitoring begins when a setcurrent level is exceeded. The trip time dependson the actual measured start-up current. If thepermissible locked rotor time is shorter than thestart-up time, the rotational speed (motor sta-tionary or rotating) must also be requested via abinary input.

Restart inhibitRestart inhibit prevents the motor restarting if,during this start-up, the permissible rotor heat-ing is expected to be exceeded.The rotor temperature of a motor generally lieswell below its permitted temperature limit bothduring normal operation and with increasedload currents. On the other hand, duringstart-up, with the associated high start-up cur-rents, the rotor is at a higher risk of thermaldamage than the stator because of its smallerthermal time constant. The motor must be pre-vented from switching on if the permissible ro-tor heating is expected to be exceeded duringthis start-up. This is the task of the restart in-hibit. Because the rotor current is not directlymeasurable, stator currents must be relied uponfrom which the rotor temperature is indirectlycalculated. It is therefore assumed that the ther-mal limit values for the rotor winding in thedata provided by the motor manufacturer forthe rated start-up current equal the maximumpermitted start-up time and the number of the

permitted start-ups from cold (nc) and operat-ing temperature (nW) conditions. The relay cal-culates from this the value of the thermal rotorreplica and gives a blocking command until thethermal replica of the rotor reaches a value be-low the restart limit and therefore permits a newstart-up. As long as a blocking command pre-vails, switching on by the relay’s integratedswitch control is prevented. In this case, it is notnecessary to allocate the restart inhibit’s block-ing command to a command relay or an exter-nal link with the switch control. If however themotor can be switched on from another posi-tion, an output relay must be allocated to theblocking command and its contact looped intothe starting circuit.

2.3 Negative-sequence protectionIn protection of the motor, negative sequence(unbalanced load) protection assumes particularimportance. Unbalanced loads produce a reversefield in motors which drives the rotor at twice thefrequency. Eddy currents are induced on the sur-face of the rotor, leading to local temperature risesin the rotor. If the motor is protected by fuses, aphase voltage failure is a frequent fault in practice.During this breakdown, the line-to-line voltage isfed to the stator winding by the remaining work-ing phases. Depending on the load, a more or lesscircular rotating field is maintained by the motor,so that it can develop sufficient torque with in-creased current input. There is also the risk ofthermal overload if the system voltage is unbal-anced. Even small voltage unbalances can lead tolarge negative sequence currents because of thesmall negative sequence reactance.


Motor Protection

The 7SJ602’s negative-sequence protection filtersthe fundamental out of the fed phase currents andbreaks it down into balanced components (nega-tive phase-sequence system I2 and positive phase-sequence system I1). The “negative phase-sequencesystem/rated current (I2/IN)” relationship is as -sessed to detect the unbalanced load. The nega-tive-sequence protection is set up in two stages.After reaching a first, adjustable threshold I2> atime stage TI2>is started; after reaching a second,adjustable threshold I2>> the time stage TI2>> isstarted. After one of the operating times haspassed a tripping command is set up. The thresh-old comparison can only be made if the largest ofthe three phase currents is at least 10 % of therated current.

2.4 Earth-fault protectionWhen designing earth-fault protection it is impor-tant to know how the star point of the power sup-ply system is connected. This must also be takeninto account when selecting protection relay hard-ware. Two versions of the 7SJ602 are available,differing in the design of the transformer inputs.

7SJ6021../7SJ6025.. for low-resistance earthedpower systems

The relay has a fourth input transformer with“normal” sensitivity for recording the earth cur -rent. This can be connected to the star point leadwire of the current transformer unit or to a sepa-rate core-balance current transformer.

7SJ6022../7SJ6026.. for resonant-earthed, isolatedor high-resistance earthed power systems

The relay has two phase current transformers, asensitive earth current input and a voltage input,e.g. to record Uen Voltage.Fig. 2 Characteristics of the negative sequence protec-

tion

Fig. 3 Connection of 4 CTs with measurement of the earth current

Fig. 4 Connection of 3 CTs and 1 VT with measurement of the earth current and onephase voltage


Motor Protection

Earth-fault protection detects earth faults in thestator winding of three-phase machines. Becausemotors are usually connected directly by a busbarto a power supply system (directly connected to abusbar) it is important to recognize whether theearth fault is in the machine feeder or on anotherfeeder of the busbar.

With earthed systems, this can usually be clearlyrecognized from the magnitude of the earth cur-rent. When a fault occurs in the machine, the fullearth-fault current driven by the power supplysystem flows via the protection measuring point.The machine must be isolated from the powersupply system as quickly as possible to preventmore damage. When there is a power systemearth-fault the recorded earth current is essentiallydetermined by the machine capabilities andtherefore considerably smaller. There must be notripping.

In compensated, isolated and low-resistanceearthed systems, a design with sensitive earth-cur-rent input and sensitive earth-fault detectionshould be chosen. The high-resistance earth-faultdetection then replaces the earth-current stage ofthe overcurrent-time protection. Because of itshigh sensitivity it is not suitable for detecting earthfaults with large earth currents (more than around1.6 ⋅ IN on the terminals for sensitive earth-cur-rent connection).Overcurrent-time protection for earth currentsmust be used here.Should the magnitude of the earth current be suf-ficient to determine the earth fault, no voltage in-put is needed. The 7SJ602 has a two-stage current/time characteristic which works with earth-cur-rent values. They are appropriate where the mag-nitude of the earth current enables the location ofthe earth fault to be defined. This can, for exam-ple, happen with machines on low-resistanceearthed systems (with earth-current limiting).

With machines directly connected to a busbar toisolated power systems, it is essential that the ca-pacity of the upstream power system delivers asufficiently large earth current but that the earthcurrent at the relay location is comparably smallin the case of earth faults on the power systemside. The magnitude of the earth current is used toreach a decision on the position of the faultlocation.

If this is not the case an additional earth-currentproduction device must be installed on thebusbar. This produces a defined earth currentduring an earth fault. The connected displacementvoltage is then used to make a direction decision.Should a load device (earth-current productiondevice) be installed, it should only be used when

dimensioning the setting in order to be independ-ent of the circuit state in the power supply system.With machines in compensated power supplysystems a load device and measurement of the dis-placement voltage are always recommended sothat a safe earth-fault decision can be made.

2.5 Short-circuit protectionThe task of the short-circuit protection when ashort-circuit occurs is both to prevent increaseddamage to the motor (destruction of the ironcore, etc.) by quickly switching off the motor andto minimize the effect on the power supply systemwith its connected loads (voltage unbalance, volt-age sags, etc.).

The overcurrent-time protection in the 7SJ602can take the form both of definite-time overcur-rent-time protection and of inverse-time over-current-time protection. For the latter, a range ofcharacteristics defined in IEC 60255---3 or inANSI standards is available. A high-current stageI>>, which always works with definite trippingtime, can be superimposed on the selected over-current characteristics. An instantaneous trippingstage I>>> can also be superimposed on the phasebranches. In this way the tripping characteristicscan be optimally adapted to the motor's start-upcharacteristics.

In order to be able to switch off during high cur-rent faults in the machine, the 7SJ602 has a specialinstantaneous tripping stage. The I>>> stage mustbe set safely above the motor’s inrush current, sothat switching on the motor does not lead to trip-ping. Experience has shown that the inrush cur-rents can be around 1.5 to 1.6 times the start-upcurrent.

The I>> stage should be set above the motor start-up current to prevent tripping. With the time de-lay TI>> the period of the inrush current must betaken into account. Because the inrush currentlasts only a few ms, the TI>> can be selected ataround 50 ms.


Motor Protection

In the overcurrent-time protection function aninverse-time characteristic must be chosen sincethis can be better adapted to the motor’s opera-tional performance.

The inverse-time short-circuit protection Ip> pro-tects the motor from short-circuits during opera-tion in transient condition (after ramping up).The higher the short-circuit current the quickerthe tripping. The extreme inverse characteristicmust be selected as tripping characteristic.

3. AdjustmentsCalculation examples are oriented towards the fol-lowing motor data:

Motor/system dataCurrent transformer phaseINPRIM/INSEC 100 A / 1 ACurrent transformer earth(60/1) IEE/IPH 0.6 (core-

balance CT)Voltage transformer 10 kV / 100 VMotor rated current INM 74 AMax. permissible unbalanced load 10 %Permissible unbalanced load period 15 sPermissible continuous thermalcurrent IMax 1.1 ⋅ INM

Thermal stator time constant τth 40 minStandstill transient factor kτ 5Start-up current IA 5 ⋅ INM

Data of the system and equipment to be protectedis input. Some data which particularly involvesmotor protection functions is worthy of mentionhere.

For some protection functions it is important torecognize whether the circuit-breaker is closed oropen. As a criterion for this overshooting or un-dershooting a current threshold is applied. The set

value applies for all three phases. If the set currentvalue in one phase is exceeded, the circuit-breakeris considered closed. In machines the value se-lected must be smaller than the machine’s mini-mum no-load current.

Motor data is generally related to the rated motorcurrent. A matching factor must be communi-cated in the system data to the 7SJ602 so that thesettings for motor protection functions can beprovided directly as a reference quantity.

Example:

Current transformer 100 A / 1 ARated motor current INM = 74 A

Ratio of rated motor current to rated trans-former currentIm = INM/INTRANSF = 0.74 [from transformerdata]The motor’s start-up current is likewise presetin the 7SJ602's system data.The start-up current is specified as a value re-lated to the rated motor current (INM).It depends on the size and nature of the motorand in a normal load-free start-up is approxi-mately 5 ⋅ INM.

Motor start-up current referred to rated motorcurrentIa = 5 [from motor data sheet]In the 7SJ602, the motor’s start-up time is pre-set in the system data. After this time the start-up current must be safely undershot.

Motor start-up timetSTART-UP = 4.3 [from motor data sheet]

3.1 Overload protectionFor overload protection the load must be takeninto account before the overload occurs; i.e. theoverload function must be used with full memory.

The relay calculates the temperature rise in accor-dance with a thermal homogenous-body modeland a thermal differential equation:

d

dtI

Θ Θ+ ⋅ = ⋅1 1 2

τ ττη th

Θ Present temperature rise referred to the finaltemperature with maximum permissible linecurrent k · IN

τth Thermal time constant for heating of the objectto be protected

I Present effective current referred to the maximumpermissible current Imax =k · IN

Fig. 5 Current characteristic of motor start-up

Ip> Short-circuit protection, inverse-time stageI>> Short-circuit protection, definite-time stageI>>> High-set instantaneous tripping stage,

definite-time stage


Motor Protection

The following parameters must be set:

Set value of the k factor = Imax/INTransf

Imax = maximum permissible continuousthermal current = 1.1 ⋅ INM = 81.4 Ak = 0.82

Set value of the thermal time constant τth inminutes

th = 40 min [from motor data sheet]

For motors the t6 time, i.e. the permissible timefor the six-fold permissible continuous current, isoften specified instead of the time constant.As a result the τth is calculated as follows:

Set value τth min ss

[ ] .= ⋅ = ⋅

tt

6

6

6036 0 6

Transient factor kτ between time constant(during standstill) and running of the motork = 5 according to motor data

Alarm temperature rise as a percentage of theoperating temperature rise ΘALARM/ΘTRIP

ALARM = 90 % [preset]

The 7SJ602 also provides the option to connect anexternal thermobox to the relay. This affords anopportunity to connect the coolant temperatureor ambient temperature of the protected objectinto the relay using the serial interface and includeit in the overload calculation.

3.2 Start-up time monitoringThe start-up time monitoring interprets over-shooting the current value Ia> as a motor start-up.Consequently this value must be chosen so that itis safely exceeded during motor start-up in all loadand voltage conditions by the actual start-up cur-rent but is not reached during permissible, short-term overload. It must also be configured abovethe maximum load current. The set value is re-lated to the rated motor current. Half the value ofthe rated start-up current is customary. If thestart-up current is 5 ⋅ rated motor current (INM),Ia> is set at 2.5 ⋅ rated motor current.The tripping time is calculated quadraticallyaccording to the magnitude of the current:

t tI

Ia

TRIP START -UP= ⋅

2

with I > Ia>

tTRIP Actual tripping time for flowing current ItSTART-UP Max. start-up timeI Actual flowing current (measured quantity)Ia Rated motor start-up current

The following parameters must be set:

Start-up current threshold Ia> for start-up timemonitoring, referred to rated motor current INM

with Ia = 5 ⋅ INM motor data entered with systemdataIa> = 0.5 Ia = 2.5 INM

Should the start-up time exceed the tripping timeof the overcurrent time protection, said protec-tion is blocked during start-up after 70 ms.

Blocking the I> / Ip stages during start-upNO

If the permissible locked rotor time is less than thestart-up time, the rotational speed (engine standsor rotates) must be additionally requested via a bi-nary input.

3.3 Restart inhibitRotor temperature simulation plays a decisive rolein the restart limit. The parameters required forthis such as start-up current, rated motor currentand maximum permissible start-up time are con-figured with the system data.

The following parameters must also be set inaddition during restart inhibit:

Temperature equalization time of the rotorAs the thermal time constant of the rotor isconsiderably smaller than that for the stator, avalue of 1 min. at most (preset) is practicablefor the temperature equalization time of the ro-tor.tEQUAL = 1min [empirical value]

Number of maximum permissible warmstart-upsnW = 2 [empirical value]

If no specifications are available from the motordata sheet, empirical value 2 is set.

Difference between the number of maximumpermissible cold start-ups and the maximumnumber of permissible warm start-upsnc – n W= 1 [empirical value]

If no specifications are available from the mo-tor data sheet, empirical value 1 is set.

Factor for the thermal cooling-down time of therotor when the machine is at standstill.The reduced cooling (when the motor is atstandstill) in motors with self-ventilation istaken into account by the factor kτSTI (related tothe time constant during no-load operation).Undershooting the current threshold set in thesystem data as LS I> is considered as criterionfor the motor’s standstill.


Motor Protection

1 is set in forced-ventilated motors.kτSTI = 5 [empirical value]

If no specifications are available from the motordata sheet, empirical value 5 is set.

Factor for the thermal cooling-down time of therotor when the machine is running.This factor takes into account the differentcooling-down of a loaded, running motor com-pared to that of a motor which is switched off. Itis effective as soon as the current exceeds LS I>(set in system data).With kτoperation = 1 heating and cooling-downtime constants are equal under normal operat-ing conditions.kτBET = 2 [empirical value]If no specifications are available from the motordata sheet, empirical value 2 is set.

Minimum lock-out timeThe minimum lock-out time tLOCK relates to themotor manufacturer's specifications or operat-ing conditions. It must be greater than the timeof temperature equalization tEQUAL .

tLOCK = 6 min [assumption]

3.4 Negative-sequence protectionIn electrical machines, negative-sequence (unbal-anced load) protection is of particular impor-tance.

The definite-time characteristic is set up in twostages. When a first, adjustable I2> threshold isreached, a pick-up signal is given and a time stageT I2> started. When a second stage I2>> isreached, another signal is transmitted and thetime stage T I2>> started. After one of the delayshas elapsed, a tripping command is given. TheI2>> stage is well suited to faults in the secondarytransformer circuit with lower sensitivity and veryshort tripping time, for example.

The preset values for pick-up and time delay aremostly sufficient. If the machine manufacturer hasstated values concerning continuous permissibleunbalanced load and the duration of loadabilityas a function of the magnitude of the unbalancedload, these should have priority.

The percentage values are related to the trans-former’s rated current.

Pick-up value of stage I2> (related to ratedtransformer current IN)I2> = 10 % [from motor data sheet]

Tripping delay of stage I2>TI2 = 15 s [from motor data sheet]

Pick-up value of stage I2>>I2>> = 50 % [preset]

Tripping delay of stage I2>>TI2>> = 1 s [preset]

3.5 Earth-fault protectionEarth-fault protection detects earth faults in thestator winding of three-phase machines. The de-sign of the earth-fault protection depends on howthe star point of the power supply system is con-nected. The star point of the motor must alwaysbe set up isolated as follows. The 7SJ602 is suitableboth for power systems with earthed star pointand for power systems with isolated, compensatedor low-resistance earthed star point. Two hard-ware variants cover all these system configura-tions. These must be taken into account whenordering.

The following depicts the earth-fault protectionsetting for a motor feeder in a 10 kV isolated sys-tem.

As this is an isolated system the variant must bechosen with sensitive earth-fault detection.

Fig. 6 Application example motor protection

10 kV cable 3 x 1 x 170 mm2

ICE = 1.8 A / kml = 0.1 km


Motor Protection

In our example it is assumed that the supplying10 kV power system has a corresponding size and,during an earth fault, a capacitive earth-fault cur-rent ICE of approximately 20 A flows to the faultlocation. Information about the magnitude of thecapacitive earth-fault current must be requestedfrom the power system operator. Of course, themotor feeder also delivers an earth-fault current.The motor feeder must be connected via a 100 mlong 10 kV cable. The motor feeder earth-faultcurrent is calculated as follows:

ICEcable = I'CE ⋅ l

I'CE = 1.8 A/km (from the cable data sheet)l = 0.1 km

ICEcable ≈ 0.20A

The following earth-fault current distribution isthe result.

From the current distribution it is clear, that thefault can be unambiguously located from themagnitude of the earth-fault current.

In the event of an earth fault on the busbar, onlythe 7SJ602 in the incoming feeder bay may pickup. If the fault location is in the motor feeder, the7SJ602 must pick up both in the incoming feederbay and in the motor outgoing feeder. In this ex-ample, therefore, a statement of the situation canonly be made via the magnitude of the earthcurrent.

The following setting recommendation for themotor outgoing feeder has been produced as apickup threshold: For safety reasons ICEtotal mustnot be assumed since, for example, this may be re-duced as a result of power system disconnections.As a base IEE> ≈ 0.5 ⋅ ICE can be chosen.

Should an earth fault not lead to tripping, the IEE>function can also be adjusted only to signals. If nosecond pickup threshold is needed, IEE>> can bedeactivated.

If the earth current is insufficient for fault loca-tion, an earth-fault direction determination isconfigured. In this case a voltage input (Uen) isobligatory.

With sensitive earth-fault direction determinationit is not the magnitude of the current that countsbut rather the component of the current verticalto a settable directional characteristic (symmetryaxis). A precondition for direction determinationis exceeding of the displacement voltage stage UE

and a likewise parameterizable current compo-nent that determines the direction (active [cos ϕ]or reactive component [sin ϕ]).

In electrical machines directly connected tobusbar on the isolated power system, cos ϕ and acorrection angle of around +45° can be set for themeasuring mode, because the earth-fault currentoften consists of a superimposition of the capaci-tive earth-fault current from the power systemand the resistive current of a load resistor.

3.6 Short-circuit protectionShort-circuit protection is the main protectionfunction of the 7SJ602. It has in all three stages forphase currents, and two for the earth current. Theovercurrent stage (I>) can if need be work withdefinite or inverse command time. High-currenttripping (I>>) and instantaneous tripping (I>>>)always work with a definite command time.

For a motor’s short-circuit protection, it must beensured that the set value I>>> is lower than thesmallest (2-pole) short-circuit current and greaterthan the highest start-up current. Because themaximum inrush current is usually below1.6 × the rated start-up current, even under unfa -vorable circumstances, the following setting con-ditions apply for the short-circuit stage I>>>.

1.6 x IStart-up < I>>> < Ik2pole

As safety distance, the setting value should be se-lected approx. 30 % above the expected start-upcurrent.

I>>> = 2.0 · IA = 2.0 · 5 · INM = 2.0 · 5 · 74/100 · IN

≈ 7.4 ⋅ IN

Pickup value of the instantaneous release stageI>>> = 7.4 ⋅ IN

Fig. 7 Earth-fault current distribution depending on thefault location


Motor Protection

The setting of I>> is aligned to the motor start-upcurrent. A safety factor of around 1.5 must be setin order that correct start-up does not lead to trip-ping.

1.5 ⋅ IStart-up < (I>>) < (I>>>)

I>> should be set above the motor start-up cur-rent so that it is not tripped by it.

I>> = 1.5 · IA = 1.5 · 5 · INM = 1.5 · 5 · 74/100 · IN

≈ 5.5 IN

Pick-up value of the high-current stageI>> = 5.5 ⋅ IN

The time delay for the high-current stage shouldbe delayed until the maximum inrush current hassafely decayed. The values in the motor data sheetmust always have priority over the assumptionsand empirical values used in these applications.

Tripping delay for the high-current stageTI>> = 50 ms

In the overcurrent protection function an inverse-time characteristic must be chosen since this canbe better adapted to the motor’s operationalperformance.

The inverse-time short-circuit protection Ip pro-tects the motor from short-circuits during normaloperation (after start-up). The higher the short-circuit current the quicker the tripping. The ex-treme inverse-time characteristic must be selectedfor tripping.

The maximum normal current is essential for set-ting the overcurrent stage Ip. Pickup by overloadmust be ruled out, because with this mode therelay works with correspondingly short commandtimes as a short-circuit protection, not as an over-load protection.

Ip = 1.5 ⋅ INM/1.1 = 1.5/1.1 ⋅ 74/100 ⋅ IN ≈ 1.0 IN

Time multiplier for phase currentsTp = 1.5 s

Set value of the overcurrent stage Ip for thephase currentsIp = 1.0 IN

4. SummaryIn this example for setting, it is evident that aSIPROTEC relay can provide comprehensive pro-tection of a motor, and that thereby (in additionto actual protection of the equipment) protectionof the remaining power supply system is alsoavailable.

From a protection point of view, the relay offersextensive protection functions for low power classmotors in addition to short-circuit protection. Be-cause all protective functions are available in onerelay, connection and testing costs are minimized.

The relay presettings are selected so that the usercan apply many parameters, even if they are notwell known. Motor sheet data is mainly used toselect the required values, thus making settingeasier.


Motor Protection

1. IntroductionSmall-scale stations are making a significant con-tribution to power generation. Hydropower plantscurrently still account for the largest share of sys-tem infeed. The most significant increase in thenumber of generating plants has been in windenergy.Electrical protection is essential for the reliableoperation of such equipment.The scope of protection must be in proportion tothe overall costs and importance of the plant. Thescope and choice of protection functions are influ-enced by plant type, generator design and addi-tional equipment, output level and power systemconnection. The following table gives an overviewof the protection functions used depending ongenerator output.


Generator Protection

Protection of a Medium-Sized Generator up to 5 MW

Fig. 1 SIPROTEC 7UM generator, motor and transformerprotection

For hydropower generators For diesel generators and turbogenerators

Up to300kVA

300 to700kVA

700 to1500kVA

> 1500

kVA

up to300kVA

300 to700kVA

700 to1500kVA

> 1500

kVA

Thermal and short-time delayedtrip and shunt release for U~on generator circuit-breaker

x – – – x – – –

Only shunt releases for U~ ongenerator circuit-breaker

– x x x – x x x

Rise-in-voltage protection x x x x – – x x

Reverse-power protection – – – – x x x x

Overcurrent-time protection – x x x – x x x

Differential protection – – – x – – – x

Rotor earth-fault protection – – – x – – – x

Is DC auxiliary voltage forprotection required?

– x x x – x x x

Table 1 Protection functions for small-scale power stations

LSP2

171-

afp

en.e

ps



2. Protection conceptIn small-scale power stations, the basic circuits forbusbar and unit connection (as shown in Fig. 1)can be assumed.

In unit connection, the generator is linked to thehigher voltage level busbar via a transformer. Inthe case of several parallel units, the generators areelectrically isolated by the transformers.

In busbar connection, several generators feedonto a common busbar. Subsequently, the nexthigher voltage level is fed via a transformer. Thegenerators are galvanically connected.

Owing to the low overall plant costs, the busbarconnection is frequently chosen for small-scalepower stations. This application is therefore con-sidered in greater detail in the following.

Table 2 shows the protection functions suitablefor small-scale power stations in accordance withtoday’s state-of-the-art. Fault type, cause and theprotection function to be deployed are indicated,together with general notes on particular featuresof the protection function.

Fig. 2 Plant basic circuit

Fault type Cause Protection function Remarks

Overload Sab>Sproduced

Controller errorMaloperation

Thermal overloadprotection (I2t)

Evaluation of currentr.m.s. value with pre-vious load recording

Short-circuit(2 or3 phase)

Deterioration of insula-tion

Winding displacement

Overvoltages

Manufacturing defects

Overcurrent-timeprotection (I>)

Differential protection(∆I)

Time delay must becoordinated withsystem protection

Earth fault(Stator)

Same cause as for short-circuit

Stator earth-fault pro-tection U0> in unitconnectionEarth-fault directionin busbar connection(/UE, IE)

The protected zone(approximately80 %) is determinedby plant conditions(see discussion in text)

Earth fault(Rotor)

Deterioration of insula-tion

Winding displacement

Brush abrasion on theslipring surface

Material fatigue

Rotor earth-fault pro-tection with systemfrequency signal cou-pling in rotor circuit

Used as from 5 MW,if sliprings available;below 5 MW optional

Reverse-power

Drive failure

Shutdown

Reverse-powerprotection (-P)

Only necessary forsteam and diesel drivesystems

Speedirregularities

Leaking stream valves

Sudden changes in activepower

Overload

Frequency protection(f> or f<)

As from 5 MW f> andf<

Below 5 MW so faronly f>; f< is likewiserecommended if avail-able

Overvoltage Controller error ormanual maloperation

Overvoltage protec-tion (U>)

Evaluation of phase-to-phase voltage

Unpermissibleunder-excitation

Fault in exciter circuit

Operation in underex-cited state (high reactivepower demand insystem)

Maloperation,controller error

Underexcitationprotection (e.g. -Q, orZ)

Used as from 5 MW

Below 5 MW so farnot usual;recommended if func-tion available

Asymmetricload

Unequal loading of con-ductor

Negative-sequence(or load unbalance)protection (I2>)

Used from 5 MW;Below 5 MW so farnot usual; recom-mended if possible, Table 2 Fault type, protection functions

Busbar connectionUnit connection



3. ApplicationsTable 1 shows, that even with small generators of< 5MW, relays must be used with a number ofprotection functions. Numerical protection relaysare the current state-of-the-art.The SIPROTEC range provides a good choice.As shown in Table 3, 7SJ relays are well suited forsimple protection functions for small generators.

The decisive advantage of the 7UM6* generatorprotection relay is the automatic adjustment ofthe sampling frequency. To ensure that the pro-tection and measurement functions deliver cor-rect results over a wide frequency range, the actualfrequency is continuously measured and the mea-surement processing sampling frequency continu-ously tracked. This ensures the measuring accura-cy in the frequency range from 11 Hz to 69 Hz.This relay offers a wide range of additional protec-tion functions. If differential protection is re-quired and the appropriate transformer sets areavailable, a 7UM62 is recommended. As differen-tial protection is applied usually for generatorsabove 5 MW, the example shown opposite refersto a 7UM61 relay for a 5 MW generator in busbarconnection.

4. SettingsIn the following sections, the individual protec-tion and additional functions (see Table 3) areexplained. Notes on the setting values are alsogiven. The calculation examples are oriented to-wards the reference plant shown in Fig. 3. For thetripping concept, it is assumed that the protectiondirectly actuates the tripping (circuit-breaker,de-excitation, turbine valve closing or dieselcut-off).

4.1 Thermal overload protection (ANSI 49)Overload protection prevents thermal overload ofthe stator windings on the machine to be protec-ted. The relay calculates the temperature rise inaccordance with a thermal single-body model bymeans of the thermal differential equation andtakes account of both previous overload historyand emission of heat into the ambient area.

After an initial, adjustable threshold has beenreached, an alarm signal is emitted for the purposeof enabling a load reduction in good time, forexample.The second temperature threshold disconnectsthe machine from the system. For example,ambient or coolant temperatures can be input viathe PROFIBUS-DP interface.

Low ambient or coolant temperatures mean thatthe generator can be loaded with more current;high temperatures signify that the loadability isless.

ExampleGenerator and transformer with the followingdata:

Permissible continuous currentImax prim = 1.15 • IN, generator

Rated generator current IN, generator = 483 A Current transformer 500 A/1 A

Protection functions ANSI 7SJ60 7SJ61 7SJ62 7SJ63/64 7UM61

Rotor overload protection 49 X X X X X

Earth-fault protectiondirectional / non directional

64G50G67G

XXX

XXXX

XXX

XXX

Overcurrent-time protection 5051

X X X X X

Negative-sequence protection 46 X X X X X

Rotor earth-fault protection 64R X1) X1) X1) X1)

Reverse-power protection 32 X2) X

Overcurrent protection 59 X X X

Underexcitation protection 40 X

Frequency protection 81 X X X

Temperature monitoring(by an external monitoringbox called thermo-box)

38 X X X X

Breaker failure protection 50BF X X X X X

Programmable logic X X X X

Control functions X X X X X

Flexible serial interface 1 2 2 2/3 2

1) via IEE measuring input if earth-fault direction function is not used.2) in 7SJ63 with CFC, in 7SJ64 with flexible functions.

Table 3 Protection relays – selection matrix

Fig. 3 Busbar connection with core-balance CT



Set value k-factor = 1.15 483A/500A = 1.11

Note:Taking the k factor at the usual figure of 1.1, ap-plying the generator rated current (with the pri-mary transformer current matched) produces atemperature rise of Θ/ ΘK = 1 / 1.12 = 0.83 of thetripping temperature. The alarm stage should thusbe set between end temperature at rated current(83 % in this case) and tripping temperature(100 %).

With an assumed load current of I = 1.5 IN (relay)and a preload of Ipre = 0, the following trippingtimes are derived for various ambient temperatures

ΘK= 40 ºC t = 463 sΘK= 80 ºC t = 366 sΘK= 0 ºC t = 637 s

4.2 Definite-time overcurrent-time protection(I>, I>>) (ANSI 50/51)

GeneralOvercurrent-time is the form of short-circuit pro-tection for extra-low or low voltage generators. Inorder that internal faults are always responded to,the generator protection is connected to thecurrent transformer set located in the star pointconnection of the generator. In the case of genera-tors whose excitation voltage is taken from themachine terminals, in the event of nearby faults(i.e. in the generator or the unit transformer re-gion) the short-circuit current decays very quicklysince there is no longer any excitation current, andwithin a few seconds falls below the overcurrent-time protection pickup value. In these casesundervoltage seal-in is used.

4.3 Definite-time overcurrent-time protection(I>) with undervoltage seal-in (ANSI 51V)

Setting example:Pickup value 1.4 ⋅ INGenerator

Tripping delay 3 sUndervoltage seal-in 0.8 UNGenerator

Seal-in time of U < 4 sDropout ratio 0.95

4.4 Earth-fault protectionIn addition to short-circuit protection, which asdescribed above is provided in a familiar fashionvia overcurrent (or differential) protection, earth-fault protection is of particular significance forsmall-scale machines.

4.4.1 PrincipleA particular feature of electric machines with iso-lated star point is that the displacement voltagedecreases linearly as the fault location moves inthe direction of the generator star-point (Fig. 4).The earth-fault current, the magnitude of which isdetermined by the earth capacitances in additionto the displacement voltage, thus also decreases.In the event of faults close to the star point, thedisplacement voltage and earth current become sosmall that they can no longer be reliably mea-sured.

A protected zone of 80 – 90 % is consequentlyspoken of.

In unit connection (Fig. 2a), the protected zonediscussed above is additionally determined by thedisturbance signal injection from the upstreamsystem. If an earth fault occurs in the system, adisplacement voltage is identifiable via the cou-pling capacitance of the unit transformer. Themagnitude of the interference voltage is deter-mined by the coupling capacitance, the genera-tor-side earth capacitance (stator, incoming line)and the difference between rated system voltageand rated generator voltage.

In busbar connection, the displacement voltagecan only be used for earth-fault indication due tothe galvanical connection of the generators. Theearth-fault direction protection makes selectivetripping possible. The protected zone is deter-mined by the earth current, which is measured bya core-balance current transformer (60 A/1 A). Asshown in Fig. 2b the sum of the component earthcurrents flows through the generator affected bythe fault. The cable network connected to thegenerators is decisive for the fault current magni-tude.

Fig. 4Displacement voltageas a function of the faultlocation in the statorwinding



Example:

In the case of 10 kV cables (lead sheath, polymer-insulated) the capacitive earth-fault current liesbetween 1.2 to 3.5 A/km. If with a full displace-ment voltage we assume an earth current ofmax. 3 A and aim for a protected zone of 80 %,approximately 0.6 A flows on the primary side.This current (secondary approximately 10 mA)can be handled reliably by the protection.

If the capacitive current is not sufficient wherehigher power levels are concerned, it is worth in-vesting in an earthing transformer on the busbaror in disconnectable load resistors on the genera-tor star point. The earth-current increases as aresult of the resistive current.

4.4.2 NoteIn industry, busbar systems are designed with highor low resitive switchable star-point resistors. Forearth-fault detection, the star-point current andthe summation current are measured by the core-balance current transformer and fed into the pro-tection relay as a current difference (see Fig. 4).The earth-current component coming from thestar-point resistor, as well as any from the system,contribute to the total earth-current. In order torule out overfunction as a result of transformerfaults, the displacement voltage serves for tripping.The protection then decides on generator earth-fault if both of the following criteria apply:

Displacement voltage is greater than settingvalue U0>,

Earth-fault current difference DIE greater thansetting value 3 I0>, magnitude.

Fig. 5 Earth-fault protection by differentiation with core-balance current transformers

SES = Stator earth-fault protection



The pickup value should be at least twice the oper-ational asymmetries. A value of 10% of the fulldisplacement voltage is normal.

4.5 Sensitive earth-fault detection (ANSI 50/51 GN)/rotor earth-fault protection (ANSI 64R)

Sensitive earth-current protection is used for de-tecting earth faults in isolated or high-resistanceearthed systems. This protection function can alsoserve to detect rotor winding earth-faults if therotor circuit is artificially displaced with a system-frequency voltage to earth (UV ≈ 42 V by means of7XR61 coupling device). In this case the maxi-mum flowing earth current is limited by the mag-nitude of the selected URE voltage and by thecapacitive coupling to the rotor circuit. Monitor-ing of the measuring circuit is provided (for thisapplication) as rotor earth-fault protection via thesensitive earth-current measuring input. It is re-garded as closed if the earth current (which alsoflows with healthy insulation) resulting from theearth capacitance of the rotor circuit exceeds aparametrizable minimum value IEE<. Should theearth-current fall below this value, a failure signalis issued after a short delay time (2 s).

A typical pickup value is approximately 2 mA. Ifthis value is set at 0, the monitoring stage is ineffec-tive. This can become necessary if the earth capaci-tances are too low. The setting of the earth-faultpickup IEE> is selected in such a way that the insula-tion (earth) resistances RE can be detected in therange from about 3 kΩ to 5 kΩ: The value setshould in this case be at least twice as high as theinterference current owing to the earth capacitancesof the rotor circuit. The tripping delaysT IEE> and T IEE>> do not include operating times.

4.6 Reverse-power protection (ANSI 32R)Reverse-power protection serves to protect a tur-bine generator unit if, in the event of drive powerfailure, the synchronous generator runs as a mo-tor and drives the turbine and is thereby drawingthe required motoring energy out of the system.This state will endanger the turbine blades andmust be interrupted without delay by opening thenetwork circuit-breaker. For the generator thereexists the additional danger that in the event of re-sidual steam leakage (defective seal valves) afteropening of the circuit-breaker, the turbine genera-tor unit can be run up to overspeed. For this rea-son disconnection from the power system shouldonly take place after detection of active power in-put into the machine. The value of the consumedactive power is determined by the friction losses tobe overcome and, depending on the system, isapproximately:

Steam turbines: PReverse/SN ≈ 1 % to 3% Gas turbines: PReverse/SN ≈ 3 % to 3% Diesel drives: PReverse/SN > 5 %

However, it is advisible to measure the reversepower with the protection itself in the primarytest. About 0.5 times of the measured motoringenergy is chosen as a setting value. The motoringenergy value can be found at the “percentage op -erational measured-values”.

4.7 Frequency protection (ANSI 81)Frequency protection detects overfrequencies andunderfrequencies of the generator. If the fre-quency lies outside the permitted range, the ap-propriate switching operations are initiated, suchas separating the generator from the system. De-crease of frequency is caused by an increase activepower demand the system or by malfunctions inthe frequency or speed control. Frequency de-crease protection is also used on generators that(temporarily) feed a separate island system, sincein such a case the reverse-power protection can-not work if the drive power fails. The generatorcan be disconnected from the system by the fre-quency decrease protection. Frequency increase iscaused for example by load shedding (separateisland system) or malfunctions in the frequencycontrol. In such cases there is a danger of self-exci-tation of generators which feed long, no-loadlines. The frequency values are generally set in ac-cordance with the specifications of the system orpower station operator. Frequency decrease pro-tection has the task of securing power for the sta-tion-service equipment by disconnecting it fromthe system in good time. The turbo regulator thenadjusts the machine set to rated speed so that thestation-service power can continue to be suppliedat rated frequency. A frequency increase can occurfor example in the event of load shedding or speedcontrol malfunction (e.g. in a separate island sys-tem). The frequency increase protection is thusused for example as overspeed protection.

Stage Cause Setting values

atfN = 50 Hz

atfN = 60 Hz

Delay

f1 Disconnectionfrom system

48.00 Hz 58.00 Hz 1 s

f2 Shutdown 47.00 Hz 57.00 Hz 6 s

f3 Alarm 49.50 Hz 59.50 Hz 20 s

f4 Alarm ortripping

52.00 Hz 62.00 Hz 10 s

Setting example



4.8 Overvoltage protection (ANSI 59)Overvoltage protection serves to protect the elec-tric machine and the connected system compo-nents from impermissible voltage increases,thereby protecting the insulation from damage.Voltage increases result for example from incor-rect operation in manual control of the excitationsystem, from malfunction of the automatic volt-age regulator or from (full) shedding of a genera-tor load, separation of a generator from the sys-tem or in separate island operation. Setting of thelimit values and delay times of the overvoltageprotection depends on the speed with which thevoltage regulator can control voltage changes. Theprotection may not intervene in the control pro-cess when it is operating trouble-free. The two-stage characteristic must therefore always beabove the voltage time characteristic of the controlprocess. The long-time stage should intervene inthe event of steady-state overvoltages. It is set toapproximately 110 % to 115 % of UN and, de-pending on the regulator speed, at 1.5 s to 5 s.

4.9 Underexcitation protection (ANSI 40)Underexcitation protection (loss-of-field) protectsa synchronous machine from loss of synchronismin the event of malfunction of excitation or con-trol and from local rotor overheating.In order to detect underexcitation, the relay pro-cesses all three phase currents and all three volt-ages as stator circuit criteria as well as the signal ofan external excitation voltage monitor as rotorcircuit criterion (Fig. 6).

The tripping characteristics of the underexcitationprotection are composed of straight lines in thediagram, each defined by its conductance section1/xd (= coordinate admittance distance) and itsangle of inclination α (Fig. 7).

The straight lines (1/xd Char. 1) / α 1 (characteristic1) and (1/xd Char. 2) / α 2 (characteristic 2) formthe static underexcitation limit. (1/xd Char.1) cor-responds to the reciprocal value of the referencesynchronous direct reactance

1 1

x x 3d d

N

N

= ⋅⋅

U

I

If the synchronous machine voltage regulator in-cludes underexcitation limitation, the static char-acteristics are set such that intervention by theunderexcitation limitation is enabled before thecharacteristic 1 is reached. The generator perfor-mance diagram can be used as a basis for setting.If the axis sizes are divided by the rated apparentpower, the generator diagram is obtained in “perunit” form (corresponding to a “per unit” repre -sentation of the admittance diagram). Multiplying1/xd by a safety factor of approximately 1.05 pro-duces the setting value.

For α 1 the angle of the voltage regulator under-excitation limitation is selected, or the inclinationangle from the restraint characteristic of the ma-chine can be read. α 1 is normally between 60° to80°. For low active power levels, the machinemanufacturer normally specifies a minimum exci-tation. Here the characteristic 1 is cut off fromcharacteristic 2 when the active power is low. α 2is set to 90 °. With characteristic 3, the protectioncan be matched to the dynamic stability limits ofthe machine. If no more precise details are avail-able, a value roughly between the synchronous di-rect-axis reactance xd and the transient reactancexd is selected; it should however be greater than 1.

Fig. 6 Admittance diagram of turbo generators

Fig. 7 Underexcitation protection characteristics in theadmittance plane



For the angle α 3, 80 ° to 110 ° is normally se -lected, in order to ensure that only dynamic insta-bility can lead to tripping with characteristic 3. Ifthe static limit curve (consisting of characteristics1 and 2) is exceeded, initially the voltage regulatormust be given the opportunity to increase the ex-citation; for this reason an alarm signal is delayed“long time” (at least 10 s). If the relay is neverthe -less “informed” of excitation voltage failure (by anexternal excitation voltage monitor via binaryinput), disconnection can take place with a shortdelay time.

Note:Selecting very short delay times can lead todynamic transients (possibly overfunctions).It is therefore advisable not to set the times below0.05 s.

4.10 Negative-sequence protection (ANSI 46)Negative-sequence (or unbalanced load) protec-tion is used to detect asymmetrical loading ofthree-phase induction machines. Asymmetricalloads create a reverse field, which affects the rotorswith double the frequency. Eddy currents are in-duced on the surface of the rotor, leading to localoverheating in the rotor end zones and slot wedges.Furthermore, interruptions, faults or incorrectlyinter-changed connections to the current trans-formers can also be detected with this protectionfunction. Additionally, single and two-phase faultswith fault currents lower than the maximum loadcurrents can be identified.

Setting example:Setting value I2 permissible = 11 % ⋅ (483 A/500 A) =10.6 %Factor k = 18.7 sT cooling = 1650 s

5. CommunicationThe SIPROTEC 7UM6 relays fully satisfy the re-quirements of modern communication technol-ogy. They have interfaces that enable integrationinto– superordinate control centers,– convenient parameter assignment and operation

via PC (locally or via modem connection).

PROFIBUS DP, RS485 or optical 820 nmdouble-ring ST connector,

IEC 60870–5–103, DNP3.0; RS485 or optical 820 nm double-ring

ST connector and MODBUS; RS485 or optical 820 nm

double-ring ST connector

7UM6 supports the widely used, internationallystandardized open communication standards.

6. SummaryBased on the recommendations for protectionfunctions [1] it has been described how, despitethe cost aspects that have to be taken into accountin small-scale power generating plants, modernrelays can be used to create technically effectiveyet uncomplicated concepts.

In contrast to traditional individual relays,state-of-the-art multifunctional numerical protec-tion equipment now provides a wider scope offunctions. Self-monitoring contributes to avoid-ance of underfunctions (failure to detect relay fail-ure). A generator can be adequately protectedwith a single relay. For more detailed informationon selecting functions and settings, the 7UM61manual is recommended, chapter 2.1 of which hasbeen provided as an application handbook.

7. ReferencesHerrmann, H.-J.:"Digitale Schutztechnik" (Digital ProtectionTechnology).Basic principles, software, examples ofimplementation.VDE-Verlag GmbH, Berlin 1997, ISBN3-8007-1850-2.

Herrmann, H.-J.: "Elektrischer Schutz vonKleinkraftwerken"(Electrical Protection of Small Power Stations)."Elektrizitätswirtschaft Jg."(Electricity Industry Year) 97 (1998) Issue 24

Siemens AG; PTD:SIPROTEC 7UM61 V4.1 MultifunctionalMachine Protection Manual

Characteristic 1 and 2steady-state stability

Instantaneous Excitation signalExc < Exc

Characteristic 1 and 2steady-state stability

Long time-delayT Char. 1 = T Char. 2 ≈ 10 s

TrippingsExc < Char. 1 TRIP /Err < Char. 2 TRIP

Characteristic 1 and 2Excitation voltage failure

Short time-delayT SHORT Uex < ≈ 1.5 s

TrippingExc < UPU < TRIP

Characteristic 3Dynamic stability

Short time-delayT Char. 3 ≈ 0,5 s

TrippingExc < Char. 3 TRIP

Setting of underexcitation protection



1. IntroductionElectrical protection is essential for reliable opera-tion and high availability in power stations. Elec-trical protection equipment cannot prevent faultsfrom occurring in the power station unit itself, butcan limit the damage and thereby shorten thestation's downtime.

Protection equipment will not be discussed in de-tail here. Detailed reports on protection functionsand measurement procedures can be found in“Protection of a Medium-Sized Generator up to5 MW” and “Protection of Medium-Sized andLarge Generators with SIPROTEC 7UM6.

The subject of this publication is the design ofprotection systems with regard to reliability, avail-ability and operational safety. Various equipmenttechnologies (and how these affect the design andoperation of a protection system) are compared.

2. Safety and availability of the protectionsystem

Protection equipment serves to detect faults orimpermissible operating conditions in power sup-ply systems and to shut them down when suchconditions occur. When the station is operatingtrouble-free, conventional protection equipmentdoes not indicate whether it is functioning cor-rectly or not. The operator must therefore checkto make sure that the protection relays are work-ing, using recurrent function tests. This confirma-tion of correct operation only applies for the du-ration of the function test. For the time betweensuch periodic function tests, no dependable state-ment about the condition of the protection relayscan be made. Maintenance and testing is discussedin more detail in Chapter 4 of this applicationexample.

System Solutions forProtecting Medium andLarge Power Station Units

Possible failures in electromechanical protectionrelay can go unnoticed and the relay then almostalways fails to function properly. Availability ofthe protection system is no longer ensured. Forthis reason the protection equipment for large-scale plants – including of course large powerstation units – is duplicated. The statistical proba -bility that both protection relays will fail at thesame time is so slight that the availability of a re-dundant protection system can be considered assufficient (see Fig. 2).

Fig. 1 SIPROTEC Generator protection for power stations



In the use of analog electronic protection relays anadditional aspect comes into play. A fault on anelectromechanical protection relay almost alwayscauses relay failure. A relay fault in an analog sta-tic protection relay can cause either underfunctionor overfunction, with approximately the sameprobability. Underfunction can, as with electro-mechanical protection systems, be mastered by re-dundant design. The danger of overfunction canbe prevented in a limited sense by dual-channeldesign of the measuring circuits (see Fig. 3).

If a high level of safety and availability is to be at-tained with analog technology, the 2-out-of-3principle can be applied. Three identical or equiv-alent protection systems must be linked with eachother externally so that two tripping signals fromdifferent systems are always connected in series.This way a very high level of safety fromoverfunction and underfunction can be achieved.

In a study in the 1970s the safety and reliability ofdifferent analog protection system configurationswere statistically researched (see Table 1).

System design Underfunction Overfunction

1-out-of-1 5 years 5 years

1-out-of-2 600 years 2,5 years

2-out-of-2 2,5 years 21,750 years

2-out-of-3 200 years 7,250 years

Table 1 Overview system design

The MTBF (Mean Time Between Failures) wascalculated for different system configurations. The2-out-of-3 system in analog design offers thehighest reliability against overfunction and under-function. However, a 2-out-of-3 system is techni-cally very complex and cost-intensive and for thisreason only used in a few nuclear power plants.

A notable characteristic of numerical protectionrelays are continuous self-monitoring of hardwareand software. Reliability against overfunction andunderfunction is inherently provided (see Fig. 4).Any relay failure causes blocking of individualprotection functions or of the entire relay. Thisprovides an effective measure againstoverfunction of the protection relays and therebyof the protection system as a whole. Relay failureis signaled at the same time. This feature meansthat defective protection relays can be immedi-ately replaced and the statistical availability of theprotection system is enhanced.

In power stations that either have a relativelylow-output or are of comparatively minor signifi-cance for secure power supplies, the requirementfor a redundant protection system can conse-quently be re-assessed. If brief shutdown of theplant is acceptable, the investment costs can be re-duced by dispensing with redundancy. “Brief ”here means a period of one or two days until thereplacement equipment is installed and put intooperation.

In most power stations, however, shutdown dueto defective protection relays is not acceptable noris continued operation without complete protec-tion. Consequently, a redundant protection sys-tem must be considered in medium and largepower station units. From a technical point ofview, complete redundancy of the protectionfunctions enables continuous operation of theunit for a short time until defective protection re-lays are replaced.

Safety, availability

Electromechanical protection

Cause of fault Relay failure Transient effects

Result Underfunction Overfunction

Countermeasure Redundancy None

Fig. 2 Safety design for electromechanical protection


Analog-static protection


Result Underfunction Overfunction Overfunction

Countermeasure Redundancy Dual-channelelectroniccircuit design

Measuringrepetition(limited)

2-out-of-3

Fig. 3 Safety design for analog-static protection



For the sake of completeness, the influence oftransient phenomena on the behavior of protec-tion relays (Figs. 2, 3 and 4) must be mentioned.Electromechanical protection relays offered, apartfrom their time-lag characteristics, practically noeffective compensation for transient influences.With analog technology, disturbing transientmeasured variables can be eliminated to a certainextent by multiple measurements. Only numericaltechnology enables reliable control of transientdisturbances through consistent digital filteringand repeat measurements.

Producing complete redundancy does not require100% duplication of all protection relays. Redun-dancy can also be achieved by two different mea-surement procedures for one and the same fault.For example a redundant protection concept canbe realized against short-circuits by combiningcurrent differential protection and impedanceprotection in mutually independent relays. Forsome protection functions, differing measurementprinciples are even desirable. Duplicate differen-tial protection provides two fast and selectiveprotection against short-circuits in the machine.Impedance protection as the second stage ofshort-circuit protection includes at the same timebackup protection against power system faults(see Figs. 5 and 6).

A few special features must be noted in the redun-dant design of protection functions whose princi-ple is based on supplying an external voltage(100% stator earth-fault protection with 20 Hz in-jection and rotor earth-fault protection). Theauxiliary devices cannot be operated in duplicateon the generator. It is, however, possible and ap-propriate to operate the protection functionsthemselves in redundancy. Here, the measuringinputs of both protection relays are fed in parallelfrom the same 20 Hz or 1 Hz frequency generator.If a very high level of statistical availability isaimed for, the auxiliary devices can be installed induplicate with one changeover switch in the pro-tection cabinet. If any auxiliary devices fails, theparallel relay is activated by the changeoverswitch.


Numerical protection


Result Underfunction Overfunction Overfunction

Countermeasure Self-monitoringwithfailure alarm +redundancy

Self-monitoringwithrelay blocking

Measuringrepetition(consequent)

Fig. 4 Safety design for numerical protection

Fig. 5 Diverse redundancy: Backup protection against system faults

Fig. 6 Mirrored redundancy: No backup protection against system faults



3. Indication processing and communicationNumerical protection relays offer the operatorconsiderably more scope for status and faultindications than do conventional relays. In the in-terests of more reliable operation and control ofthe power station, it is the planning engineer's re-sponsibility, from the abundance of available in-formation, to provide (to operating personnel)precisely those indications and measured valuesthat are needed for each task. Rather than suc-cumbing to the temptation to make all availableinformation accessible at each workstation, theplanning engineer is responsible for working outan intelligent indication signalling concept.

This means that each member of staff receives theinformation needed to make quick and reliabledecisions about technical operation and control ofthe power station. Fig. 7 provides a concept forsuch an information network. Group indicationsfrom the protection system are provided in the

power station control room. These indications en-able a quick overview of the operating state of thepower station unit in terms of electrical faults orimpermissible operating states. The recommendedspontaneous indications for the control room are:

Tripping on faults Protection faulty Negative-sequence (unbalanced load) alarm Stator earth-fault alarm Rotor earth-fault alarm Underexcitation alarm

In addition to these spontaneous indications,measured values from the protection relays can

also be requested via the bus connection as neces-sary. An information network with connected PCis available for detailed fault analysis after trippingon faults has occurred. Via this means of commu-nication, the protection expert can read out all theavailable information from the protection relays.Using the message lists and the transient fault re-cords the expert can draw up an exact profile ofthe fault that led to the power station unit beingshut down. Alternatively, this detailed informa-tion can be read out on the front of the protectionrelays.

4. Maintenance and testingContinuous self-monitoring of numerical protec-tion relays creates new opportunities for opera-tion and testing. While it was essential to monitorthe state of conventional protection relays bymeans of periodic function tests, numerical pro-tection relays do most of this work themselves.

The self-monitoring installed in each numericalprotection relay continuously checks that thehardware and software are working correctly. Thisproduces a series of consequences for mainten-ance and testing of a numerical protection system.

Fig. 7 Integration of protection relays into power station control and protection system



Protection relays can be regularly checked by feed-ing in fault currents and voltage over a longer pe-riod of time. Such overall testing should be carriedout in the context of regular power station main-tenance. Since this check does not take place dur-ing operation of the power station, special testswitches or plugs are not necessary. Current andvoltage is fed in via the cabinet terminals. In viewof the multi-functional protection relay conceptfor generators it is practically impossible to testindividual protection functions without interven-ing in the relay parameterization. This is also notnecessary because all protection functions of arelay are handled on the same hardware. The con-ventional approach involving protection charac-teristics with measurement of tolerances is notprovided in numerical protection. Thanks to digi-tal measured-value processing, the ageing or tem-perature drift of analog components is nowadayspractically unknown. The function test is thuslimited to a sensitivity check of the protectionrelay as a whole.

During power station operation the self-monitor-ing performs continuous testing of the numericalprotection relays. As well as monitoring the pro-gram flow using Watchdog, the correct conditionof the hardware components is continuallychecked. This takes place for example using write/read cycles for the memory and with the process-ing of reference parameters for the analog/digitalconverter. The protection relay also monitors ex-ternal connections, where possible. One exampleof many is monitoring of the measuring voltagebalance (Figs. 8 and 9).

As a reaction to an identified fault, a defectiveprotection relay produces either just an indicationor blocks itself partly or wholly to prevent over-function. Taking into account the recognizedfault, the protection relay reacts in a graded wayaccording to the seriousness of the fault (Fig. 10).

Fig. 8 Voltage balance monitoring

Tasks: – Detection of a wire breakage in the voltage circuit- Detection of device-internal faults in the voltage circuit

Operating condition:U

Umin SYM.FAK.Umax

< und U kmax ≥ ⋅ SYM.UGREN

Fig. 9 Voltage balance monitoring



During normal power station operation, numeri-cal protection relays make it possible to check thecomplete measured-value acquisition circuit byreading out status measured-values. Measuredvalues can be indicated on the equipment displaywithout adversely affecting the protection func-tions. A comparison of these measured valueswith other measuring devices or protection relaysrepresents an inspection and test sequence whichwould be unthinkable in conventional technologywithout additional equipment. This test stepincludes the following power station and devicecomponents:

Current and voltage transformer Transformer supply cables Cubicle wiring for the measuring circuits Input measuring transmitter for the protection

relays Analog/digital converter Measured-value memory

This inspection and test sequence is of minimalduration and can be carried out at any time, with-out intervening in the protection processing of therelay.

5. SummaryThe development of numerical technology forprotection relays brought about considerable ben-efits in terms of enhanced performance, reliabilityand availability of the protection system. Thesebenefits upgrade the availability of the power sup-ply system. Quantity and quality of informationretrieved from the numerical protection relayshave reached such a high level that operation andmaintenance of the power station can be per-formed much safer and with less efforts. The in-crease in functionality in the numerical protectionrelays requires a well-designed protection and in-formation system, making the best of the manydifferent opportunities.

Possible reactions of a monitoring function

Minor faults

Serious faults

Fig. 10 Design of monitoring functions

Transmitting an indication Blocking individual protection functions. Only functions relating to the

fault are blocked Withdrawal from service of all protection functions.

The relay remains operable and indications can still be read out. Restarting the equipment. A maximum of 2 restarts are possible.

After the 3rd restart the relay switches to monitor mode. Switch to monitor mode. This usually means a hardware fault.

The cause can be determined by evaluating a fault buffer



Protection of Medium-Sized and Large Generatorswith SIPROTEC 7UM6

Fig. 2 Block diagram of generator protection

Fig. 1 SIPROTEC generator protection

1. IntroductionMedium-sized and large generators make a majorcontribution to power generation. They carry thebasic load and ensure the stability of an energysystem.

The task of electrical protection in these systems isto detect deviations from the normal conditionand to react according to the protection conceptand the setting. Based on experience with largerpower station units, cost-effective protection con-cepts can also be implemented with SIPROTECrelays for medium-sized generators.

The scope of protection must be in reasonable re-lation to the total system costs and the importanceof the system.

2. Basic connectionsIn medium-sized and large power stations thegenerators are operated exclusively in unitconnection.

In the unit connection the generator is linked tothe busbar of the higher voltage level via a trans-former. In the case of several parallel units, thegenerators are electrically isolated by the trans-formers. A circuit-breaker can be connected be-tween the generator and the transformer(see Figs. 2 and 3).



3. Protection conceptComponents of the protection concept are:

The redundancy concept The tripping concept Protection function scope

3.1 Redundancy conceptThe redundancy concept is crucial in the design ofprotection systems. Many concepts are based onthe n-1 principle. That means that the failure of acomponent is under control and does not lead to atotal system failure. However, this principle is notalways applied consistently. In smaller systemsthere is a compromise between redundancy andcosts. The following strategies are common inpractice for medium-sized and large generators.

Partial redundancy (see Fig. 4)

At least 2 protection relays are used here. The pro-tection relays/functions are selected so that thesystem can continue to operate when a relay fails.However, certain restrictions have to be accepted.This system design is seldom used in high-powergenerators. The protection is connected to thesame transformers for example.

Full redundancy (see Fig. 5)

In this system design the redundancy concept isapplied consistently throughout by duplicating allthe essential components. As shown in Fig. 5, theredundancy begins with separate transformers ortransformer cores, continues through the protec-tion relays, and the TRIP signal is passed throughseparate DC voltage paths to switchgear with 2circuit-breaker coils (see Fig. 5). In the protectionrelays the protection functions can be duplicatedon the one hand; on the other hand additionalprotection functions with different measuringprinciples are desired. Typical examples areearth-fault and short-circuit protection.

The displacement voltage measurement coversabout 90 % of the protected zone in the event ofan earth fault. The totally different method –injecting an external voltage (20 Hz) into thestator circuit – ensures 100 % protection.

The same can be implemented for the short-circuit protection. The main protection is the fastand selective current differential protection. Sup-plementary to this, impedance protection is used,with which the backup protection for the powersystem protection can be achieved by appropriategrading.

Fig. 3 Redundant protection concept for large generators



3.2 Tripping conceptThe special feature of generator protection is thatdifferent switching devices have to be activated de-pending on the fault. The number is basically de-termined by the system/plant concept. As a rule,most of the switching devices need to be actuatedin the larger units. Special trippings are used inhydro-electric power stations.

Fig. 6 shows the basic concepts. On one side thereare the switching devices to be actuated and on theother side the connected protection functions.The tripping program or tripping concept de-pends on the recommendations/experiences andthe operating conditions. There are two opposingphilosophies. The tripping program is determinedindividually by a tripping matrix (a software ma-trix in digital technology) and the switching de-vices are activated directly. The other (American-influenced) variant reduces the tripping to twoprograms, e.g. exclusive shutdown of the gener-ator and shutdown of the power station unit.Lockout relays are used to control the switchingdevices. The protection needs only a few trip con-tacts.

3.3 Protection function scopeNumerous protection functions are necessary forreliable protection of electrical generators. Thescope and the combination are determined byvarious factors such as generator size, operatingprinciple, system design, availability requirements,experiences and philosophies. This automaticallyleads to a multifunctionality which can be con-trolled excellently by numerical technology.

The function matrix is scalable to meet different re-quirements (see Table 1).

The selection simplifies division intoobject and application-related groups.

Fig. 4 Example: Partial redundancy

Fig. 6 Protection tripping by the matrix

Generator circuit-breaker De-excitation switch Turbine valve closing System switch Auxiliaries switch 1 Auxiliaries switch 2 Auxiliaries transfer Spray water system, unit transformer Spray water system, station-service trans-

former Backup Special trippings for hydropower

(e.g. braking)

Fig. 5 Example: Full redundancy



A function selection taking redundancy intoconsideration is shown in Table 2.

Protection group A(System 1, 7UM622)

Protection group B(System 2, 7UM622)

Stator earth-fault 100 % Stator earth-fault 90 %

Differential protection Differential protection (asunit protection)

Impedance Impedance

Rotor earth-fault Negative-sequence

Negative-sequence Underexcitation

Underexcitation Out-of-step

Overvoltage Stator overload

Frequency f >< Overvoltage

Reverse power Frequency f ><

Overexcitation Reverse power

Overexcitation

Table 2 Function selection for a redundancy concept

4. Protection functions and settingThe basic connection (Fig. 2) is considered for thesetting value calculation – with generator datafrom the Table 3. Manufacturer characteristics(e.g. power diagram) are necessary for some pro-tection settings. The physical backgrounds and theformulae for calculation are in the manual. Thesecondary setting values are shown.

Protection functions Generator rated power

5 - 50 MVA 50 - 200 MVA > 200 MVA

Stator earth-fault protection 90 %

Stator earth-fault protection 100 %

Differential protection

Overcurrent-time protection

Impedance protection

Rotor earth-fault protection

Negative-sequence(or load unbalance) protection

Underexcitation protection

Out-of-step protection

Stator overload protection

Rotor overload protection

Overvoltage protection

Frequency protection f >

Frequency protection f <

Reverse-power protection

Undervoltage protection

Overexcitation protection

Available Optional Pumped-storage station (motor protection and phase modifier operation)

Table 1 Recommended protection functions according to generator rated power



Generator data

Rated voltage UN 15.75 kV ± 5 %

Rated apparent power (40 °C cold gas) SN 327 MVA

Circuit-breaker cos ϕ 0.8

Rated active power PN 261.6 MW

Rated current IN 12 kA

Rated frequency fN 50 Hz

Maximum overexcitation (U/f)max % from the manufacturer’s overexcitation characteristic

Permissible overexcitation duration t (U/f)max from the manufacturer’s overexcitation characteristic

Synchronous longitudinal reactance xd

(for drum rotor generators: xd = xq)264.6 %

Transient reactance xd1 29.2 %

Maximum exciter voltage Uexc-min 77 V

Maximum continuous permissible inverse current Imax prim / IN 10 %

Thermal continuous permissible primary current Imax / IN 1.2

Asymmetry factor (I2) K = (I2/IN)2 t 20 s

Current transformer Iprim Isec ü Target

Star-point sideT1, core 1T1, core 3

14 kA14 kA

1 A1 A

14 00014 000

System 1System 2

Busbar sideT2, core 1T2, core 3

14 kA14 kA

1 A1 A

14 00014 000

System 1System 2

110 kV sideT3, core 1 2 000 A 1 A 2 000 System 2

Earthing transformer Uprim Usec ü Target

T4; U0 15.75 kV/ 3 5 V/ 3 54.56 System 1

External voltagetransformer

Uprim Usec ü Target

Generator sideT5, UL1, UL2, UL3 15.75 kV/ 3 100 V/ 3 157.5 System 1, 2

Unit transformer dataVector group Ynd5

Total coupling capacity HV-LV Ck 14.4 nF (4.8 per phase)

Maximum overexcitation (U/f)max 120 %

Permissible overexcitation time t (U/f)max from the manufacturer’s overexcitation characteristic

Permissible overload Imax / IN from the manufacturer’s overexcitation characteristic

Winding Primary Secondary

Rated voltage UN 115 kV 15.75 kV

Rated apparent power SN 318 MVA 318 MVA

Rated current IN 1.596 kA 11.657 kA

Short-circuit voltage uSC 15 %

Control range of the tap changer ± 9 x 1.25 %

Table 3 Data of the power station unit with gas turbine



4.1 Current differential protection(ANSI 87G, 87M, 87T)

The function is the instantaneous short-circuitprotection in generators, motors and transformersand is based on the current differential protectionprinciple (node set). The difference and restraint(stabilization) current is calculated from the phasecurrents. Optimized digital filters safely attenuatedisturbance variables such as aperiodic DC ele-ments and harmonics. The high resolution of themeasuring variables enables small difference cur-rents (10 % of IN) to be picked up, i.e. a very highsensitivity. A settable restraint characteristic al-lows optimum adaptation to the conditions of theprotected object.


An important setting is the position of the starpoints of the current transformer sets on bothsides of the protected object. In addition, the rateddata (SN GEN/MOTOR, UN GEN/MOTOR) of the genera-tor to be protected and the primary and secondaryrated currents of the main current transformersare requested on both sides. The setting valuesrefer to these. In addition, they are used for exam-ple to determine the primary measured values.

As an additional security measure against unwant-ed operation when connecting a previously non-energized protected object, the increased pickupvalue can be switched on when starting up.

The table below shows the setting options ofselected parameters. The settings are relevant forthe generator and not for the unit (protectiongroup A).

4.2 Stator overload protection(ANSI 49)

The overload protection should protect the statorwinding of generators and motors against exces-sively high continuous current overloads. All loadcycles are evaluated by a mathematical model. Thebasis for the calculation is the thermal effect of thecurrent r.m.s. value. The transformation corre-sponds to IEC 60255-8.


The cooling time constant is prolonged automati-cally, dependent on the current. If the ambienttemperature or coolant temperature is fed inthrough a transducer (MU2) or via thePROFIBUS-DP, the model automatically adaptsto the ambient conditions; otherwise a constantambient temperature is assumed.

The following table shows the setting options andthe setting example of important parameters(without taking the ambient or coolant tempera-ture into account).

Parameter Setting options Setting

k-factor 0.1 to 4.0 1.11

Thermal warninglevel

70 to 100 % 95 %

Current warninglevel

0.1 to 4.0 A 1.0 A

kt-time factor atstandstill

1.0 to 10.0 1.0

Limit current forthe thermal replica

0.5 to 8.0 A 3.30 A

Dropout time afteremergency start

10 to 15000 s 100 s

Table 5 Parameter overview for the stator overloadprotection

The setting ranges and presettings (defaults) arespecified for a secondary rated current of IN = 1 A.At a secondary rated current of IN = 5 A, these va-lues must be multiplied by 5. The ratio of the cur-rent transformer must be taken into accountadditionally for settings of primary values.

Parameter Setting options Default *)

Pickup value of the tripstage Idiff>

0.05 to 2.0 I/INObject 0.2 I/INObject

Delay of the trip stageIdiff>

0 to 60.0 s; ∞ 0.00 s

Pickup value of the tripstage Idiff>>

0.05 to 12.0 I/INObject 7 I/INObject

Delay of the trip stageIdiff>>

0 to 60.0 s; ∞ 0.00 s

Slope 1 of the tripcharacteristic

0.1 to 0.5 0.15

Foot of slope 1 of thetrip characteristic

0 to 2.0 I/INObject 0 I/INObject

Slope 2 of the tripcharacteristic

0.25 to 0.95 0.5

Foot for slope 2 of thetrip characteristic

0 to 10.0 I/INObject 2.50 I/INObject

Table 4 Parameter overview for the differentialprotection

*) In this example, most of the default settings can be used.



4.3 Negative-sequence protection (ANSI 46)Asymmetrical current loads of the three phases ofa generator lead to heating up in the rotor due tothe reverse field. The protection detects an unbal-anced load of three-phase generators. It operateson the basis of symmetrical components and eval-uates the negative-sequence component of thephase currents. The thermal processes are takeninto account in the algorithm and lead to aninverse-time characteristic. In addition, the nega-tive-sequence is evaluated by a definite-timewarning and tripping stage which is supplementedby delay elements.

Setting instructionsThermal characteristic

The generator manufacturers specify the permissi-ble negative-sequence with the following formula:

tI

I

permK

2

N

=

2

tperm = Maximum permissible application time ofthe negative-sequence current I2

K = Asymmetry factor (generator constant)

I2/IN = Negative-sequence (ratio of negative-sequence current I2 to rated current IN)

The asymmetry factor is generator-dependent andrepresents the time in seconds for which the gen-erator may be loaded at the maximum with 100 %unbalanced load. The factor is mainly in the rangebetween 5 s and 30 s. On exceeding the permissi-ble load unbalance (value of the continuously per-missible negative-sequence current), simulation ofthe heating of the object to be protected in the re-lay begins. The current-time-area is calculatedcontinuously taking different load cases correctlyinto consideration. If the current-time-area((I2/IN)2· t) reaches the asymmetry factor K, trip-ping takes place with the thermal characteristic.

Table 6 shows the setting options and the settingexample.


Continuously permissibleload unbalance

3.0 to 30.0 % 8.6 %

Delay time of warningstage

0 to 60.0 s; ∞ 10.0 s

Asymmetry factor K 2.0 to 100.0 s; ∞ 11 s

Cooling time of thermalmodel

0 to 50000 s 1500 s

Excitation current I2>> 10 to 100 % 51.4 %

Delay time T I2>> 0 to 60.0 s; ∞ 3.0 s

Table 6 Parameter overview for negative-sequenceprotection

4.4 Underexcitation protection (ANSI 40)The protection prevents damage due to out-of-steps resulting from underexcitation. The complexmaster value is calculated from the generator ter-minal voltage and current. The protection func-tion offers three characteristics for monitoring thestatic and dynamic stability. The exciter voltagecan be fed in through a transducer and a fast re-sponse of the protection can be achieved by timerswitching in the event of a failure. The straightline characteristics allow optimum adaptation ofthe protection to the generator diagram. The set-ting values can be read out directly from the per-unit representation of the diagram. The positive-sequence components of the currents and voltagesare used for calculating the variables, wherebycorrect operation is ensured even under asymme-trical conditions.


The tripping characteristics of the underexcitationprotection are made up of straight lines in themaster value diagram, defined by their reactivepart of the admittance 1/xd and their angle ofinclination α.Table 7 shows the settings for this applicationexample.


Pickup threshold 1/xd characteristic 1 0.25 to 3.0 0.37

Characteristic slope characteristic 1 50 to 120 ° 80 °

Delay time characteristic 1 0 to 60.0 s; ∞ 10.0 s







Table 7 Parameter overview for underexcitation protection




4.5 Reverse-power protection (ANSI 32R)The reverse-power protection monitors the activepower direction and picks up in the event of a me-chanical energy failure, because the drive energy isthen taken out of the system. This function can beused for operational shutdown of the generatorbut also prevents damage to steam turbines. Theposition of the emergency tripping valve is enteredas binary information. This switches between twodelays of the open command. The reverse power iscalculated from the positive phase sequence sys-tems of current and voltage. Asymmetrical systemconditions therefore do not impair the measuringaccuracy.

If reverse power occurs, the turbo set must be dis-connected from the system, because operation ofthe turbines is not permissible without a certainminimum steam throughput (cooling effect), orthe motorized load is too great for the system in agas turbo set.

The trip command is delayed by an adjustabletime to bridge any brief power consumptionduring synchronization or in the event of powerswings due to system faults. In the event of aclosed emergency tripping valve on the otherhand, the unit must be shut down with a short de-lay. By entering the position of the emergencytripping valve through a binary input, the shortdelay becomes effective in the event of emergencytripping. It is also possible to block the tripping bymeans of an external signal.

The value of the consumed active power is deter-mined by the friction losses to be overcome and,depending on the system, is approximately:

Steam turbines: Prev/SN 1 % to 3 % Gas turbines: Prev/SN 3 % to 5 % Diesel drives: Prev/SN > 5 %

However, it is advisable to measure the reversepower with the protection itself in the primarytest. About 0.5 times of the measured motoringenergy, which can be read out under the “percent-age operational measured values”, is chosen as asetting value.

Table 8 shows the setting of selected parameters.


Delay time with emer-gency tripping

0 to 60.0 s; ∞ ∞ s

Delay time withoutemergency tripping

0 to 60.0 s; ∞ 6.00 s

Pickup threshold re-verse power

30.0 to 0.50 % -3.42 %

Pickup seal-in time 0 to 60.0 s; ∞ 1.00 s

Table 8 Parameter overview of reverse-powerprotection

4.6 Impedance protection (ANSI 21)This fast acting short-circuit protection protectsthe generator or unit transformer on the one handand is the backup protection for the system. It hastwo adjustable impedance stages whereby the firststage is additionally switchable by a binary input.The impedance measuring range can be extendedwith open system switch. The overcurrent pickupwith undervoltage seal-in provides reliable pickupand loop selection logic for determining the faultyloop. It also allows correct measurement throughthe transformer.


The maximum load current occurring during op-eration is decisive for setting the overcurrentpickup. Pickup by overload must be ruled out.The pickup value must therefore be set above themaximum expected (over) load current. Recom-mended setting: 1.2 to 1.5 times rated generatorcurrent.

The pickup logic corresponds to that of the defi-nite-time overcurrent protection I>. If the excita-tion is derived from the generator terminals andthe short-circuit current is able to drop below thepickup value due to collapsing voltage, the under-voltage seal-in is activated.The undervoltage seal-in U< is set to a value justbelow the lowest phase-to-phase voltage occurringduring operation, e.g. to U< = 75 % to 80 % of therated voltage. The seal-in time must be greaterthan the maximum fault clearance time in thebackup case. (Recommended: This time + 1 s).



As described in the manual, the protection hasthree characteristics which can be set independ-ently:

Zone (instantaneous zone Z1) with the settingparametersZONE Z1 reactance = reach,ZONE1 T1 = 0 or short delay if necessary.

Overreach zone Z1B, controlled externally by abinary input with the setting parametersOVERR. Z1B reactance = reach,OVERR. T1B T1B = 0 or short delay if necessary.

2nd zone (Zone Z2) with the setting parametersZONE Z2 reactance = reach,ZONE2 T2 T2 should be chosen so high that itis above the grading time of the system protec-tion.

Undirected final stage with the setting parame-ters T END T END must be chosen such thatthe second or third stage of the series-connectedpower system distance protection is overreached.

Since it can be assumed that the impedance pro-tection measures into the generator transformer,it must be ensured that the parameterizationselec- tion sufficiently considers the control rangeof the transformer. For ZONE Z1, a reach ofabout 70 % of the zone to be protected is thereforenormally chosen (i.e. about 70 % of the trans-former reactance) without or with only slight de-lay (i.e. = 0 s to 0.50 s).

For ZONE Z2, the reach could be set to about100 % of the transformer reactance or a systemimpedance additionally. The corresponding timestage ZONE2 T2 must be chosen so that itovergrades the system protection relays of the fol-lowing lines.

The following settings apply for the configurationexample (without activation of the out-of-stepblock):

4.7 Overvoltage protection (ANSI 59)This protection prevents insulation faults as aresult of high voltage. Optionally the maximumphase-to-phase voltages or phase-to-earth volt-ages (in low-voltage generators) can be evaluated.In the phase-to-phase voltages, the measuring re-sult is independent of the zero point displace-ments resulting from earth-faults. The protectionfunction is designed in two stages.

The setting of the limit values and delay times ofthe overvoltage protection depends on the speedat which the voltage regulator can regulate volt-age fluctuations. The protection may not interve-ne in the regulating process of the voltage regula-tor when it is operating trouble-free. The two-stage characteristic must therefore always beabove the voltage time characteristic of the regu-lating process.


The long-time stage U> and T U> should inter-vene in the case of steady-state overvoltages. It isset to about 110 to 115 % UN and to 1.5 to 5 s,depending on the regulator speed. In the event ofa full load disconnection of the generator, thevoltage first rises according to the transient volt-age and is reduced to its rated value by the voltageregulator afterwards. The U>> stage is generallyset as a short-time stage so that the transient pro-cess in full load shutdown does not lead to trip-ping. About 130 % UN – with a delay T U>> ran-ging from zero to 0.5 s – are usual (for example)for U>>.


Pickup value of theovercurrent pickup

0.10 to 20.0 A 1.20 A

Pickup voltage of theundervoltage seal-in

10.0 to 125.0 V 75.0 V

Seal-in time of theundervoltage seal-in

0.1 to 60.0 s 10.0 s

Trip time of the end time stage 0.1 to 60.0 s 3.0 s

Impedance zone Z1 0.05 to 130.0 Ω 7.28 Ω

Trip time zone Z1 0 to 60.0 s; ∞ 0.30 s

Impedance overreach stage Z1B 0.05 to 65.0 Ω 11.44 Ω

Trip time overreach stage Z1B 0 to 60.0 s; ∞ 8.00 s

Impedance zone Z2 0.05 to 65.0 Ω 11.44 Ω

Trip time Z2 0 to 60.0 s; ∞ 8.00 s

Table 9 Parameter overview for the impedance protection



4.8 Frequency protection (ANSI 81)Frequency protection prevents impermissibleloading of the equipment (e.g. turbine) at underand overfrequency, and also serves often as a mo-nitoring and control element. The function is de-signed in four stages, whereby the stages canoperate either as under or overfrequency protecti-on. Each stage can be delayed individually. Thecomplex frequency measuring algorithm also fil-ters out the fundamental harmonic reliably in theevent of distorted voltages and determines fre-quency very accurately. The frequency measure-ment can be blocked by an undervoltage stage.


If the frequency protection is used for the task ofsystem decoupling and load shedding, the settingvalues depend on the concrete system conditions.Usually a grading according to the importance ofthe consumers or consumer groups is aimed at forload shedding. Other applications are to be foundin the power station sector. Basically the frequen-cy values to be set depend on the presettings of thesystem or power station operator.

The following table shows the settings which meetpractical requirements.

Parameter Settingoptions

Setting

Pickup frequency f1 40 to 65 Hz 47.5 Hz

Delay time T f1 0 to 600 s 40 s

Pickup frequency f2 40 to 65 Hz 47 Hz


Pickup frequency f3 40 to 65 Hz 51.50 Hz


Pickup frequency f4 40 to 65 Hz 52 Hz


Minimum voltage 10 to 125 V; 0 65 V

Table 11 Parameter overview for frequency protection

4.9 Overexcitation protection (ANSI 24)Overexcitation protection serves to detect an im-permissibly high induction (proportional to U/f)in generators or transformers which leads tothermal overloading. This danger can occur instart-up processes, in full load disconnections, in“weak” systems and in separate island operation.The inverse-time characteristic is set with the ma-nufacturer data by way of 8 points. A definite-time alarm stage and a short-time stage can beused additionally. Apart from the frequency, themaximum of the three phase-to-phase voltages isused for calculating the quotient U/f. The monito-rable frequency range is between 11 and 69 Hz.


The overexcitation protection contains two-stagedcharacteristics and one thermal characteristic forapproximate simulation of the heating of the pro-tected object due to overexcitation. On exceedingof an initial pickup threshold (alarm stage U/f), atime stage T U/f > is started, at the end of whichan alarm message is output.

The limit value of induction in relation to therated induction (B/BN) specified by the protectedobject manufacturer forms the basis for settingthe limit value U/f >.

The characteristic for a Siemens standard trans-former has been chosen as default. If the protectedobject manufacturer supplies no data, the defaultstandard characteristic is retained. Otherwise, anytripping characteristic can be specified by point-by-point input of parameters by a maximum of7 straight sections.


Pickup voltage U> 30 to 170 V 115 V

Delay time T U> 0 to 60 s; ∞ 3 s

Pickup voltage U>> 30 to 170 V 130 V

Delay time T U>> 0 to 60 s; ∞ 0.50 s

Dropout ratio RV U> 0.90 to 0.99 0.95

Table 10 Parameter overview for the overvoltageprotection




4.10 90 % stator earth-fault protection directio-nal, non-directional (ANSI 59N, 64G, 67G)

In generators operated with an isolated star point,an earth fault is indicated by occurrence of a dis-placement voltage. In unit connection, the displa-cement voltage is a sufficient, selective protectioncriterion. If a generator is connected electrically toa busbar, the direction of the flowing earth-cur-rent must be evaluated additionally for selectiveearth-fault detection. The protection measures thedisplacement voltage on a voltage transformer inthe generator star point, or at the open delta win-ding of a voltage transformer. Optionally thezero-sequence voltage can also be calculated fromthe phase-to-earth voltages. Depending on thesystem design, 90 to 95 % of the stator winding ofa generator can be protected.

When starting, it is possible to switch over tozero-sequence voltage measurement via an exter-nally coupled signal. Various earth-fault protecti-on concepts can be implemented with the func-tion, according to the protection setting.

Setting instructionsFor generators in unit connection, the pickupvalue must be chosen so high that displacementvoltages, which affect the stator circuit throughthe coupling capacitances of the unit transformer,do not lead to pickup. The damping by the loadresistance must also be taken into account here.The setting value is twice the displacement voltagevalue coupled in at full system displacement. Finalspecification of the setting comes during commis-sioning with primary variables according to themanual. Tripping in the event of stator earth-faultis set time-delayed (T SES). The overload capacityof the load equipment must also be taken into ac-count when setting the delay. All set times are ad-ditional delays which do not include the operatingtimes (measuring time, dropout time) of the pro-tection function.

Table 12 shows the setting options for selectedparameters. The settings are selected for this pro-tection configuration.

4.11 Rotor earth-fault protection (ANSI 64R)This protection function can be effected with the7UM62 in three ways. The simplest form is themethod of rotor earth-current measurement (seethe manual: Chapter on sensitive earth-faultprotection, resistance measurement at systemfrequency voltage).

The second form is rotor earth-resistance measu-rement with system frequency voltage couplinginto the rotor circuit (see the manual: Chapter onrotor earth-fault protection). The coupled voltageand the flowing rotor earth-current are detectedby the protection. Taking account of the complexresistance of the coupling device (7XR61), the ro-tor earth resistance is calculated by a mathemati-cal model. This form is often used for medium-sized generators.

The third form is resistance measurement withsquare-wave voltage injection of 1 to 3 Hz. In larg-er generators a higher sensitivity is required. Onthe one hand, disturbances caused by the rotorearth capacitance must be eliminated better, andon the other hand the interference margin to theharmonic (e.g. 6th harmonic) of the exciter devicemust be increased. The injection of a low-frequen-cy square-wave voltage into the rotor circuit hasproven effective here (recommended for this ap-plication). The square-wave voltage injected bythe controller unit 7XT1 leads to polarity reversalof the rotor earth capacitance. Through a shunt inthe 7XT1, the flowing earth-current is detectedand injected into the protection (measuring in-put). In a fault-free case (RE ~ ∞), the rotorearth-current after charging of the earth capaci-tance is nearly zero. In the event of a fault, theearth resistance – including coupling resistance(7XR6004) and the incoming supply voltage – de-termines the steady-state current. Via the secondinput (control input), the transfers, the currentsquare-wave voltage and the polarity reversalfrequency are recorded. Fault resistances up to80 kΩ can be detected with this measuringprinciple.


Pickup voltage U0> 2 to 125 V 10 V

Pickup current 3I0> 2 to 1000 mA 5 mA

Slope angle of thedirectional lines

0 to 360 ° 15 °

Delay time T SES 0 to 60 s; ∞ 0.30 s

Table 12 Parameter overview for the stator earth-faultprotection



Monitoring of the rotor earth circuit for interrup-tion takes place by evaluating the current duringpolarity reversals.

Setting instructions (1 to 3 Hz protection)Since the protection calculates the resistive rotorearth resistance directly from the values of appliedvoltage, series resistance and flowing earth-current,the limit values for the alarm stage (RE WARN) andthe trip stage (RE TRIP) can be set immediately asresistance values. In most cases the preset values(RE WARN = 40 kΩ and RE TRIP = 5 kΩ) are suffi-cient. Depending on the insulation resistance andcoolant, these values can be changed. It is impor-tant to pay attention to an adequate margin be-tween the setting value and the actual insulationresistance. As a result of possible disturbances dueto the exciter device, the setting for the alarm stageis finally determined during the primary tests.The delay is usually set for the alarm stage (T RE

WARN) to about 10 s, and for the trip stage (T RE

TRIP) to a short time of about 1 s.The set times are additional time delays which donot include the operating times (measuring time,dropout time) of the protection function.

4.12 100 % stator earth-fault protection with20 Hz injection (ANSI 64 G (100 %))

The injection of a 20 Hz voltage for detection offaults in the star point or close to the star point ofgenerators has proven a safe and reliable method.Unlike the 3rd harmonic criterion (see page 12,Catalog SIP 6.1), it is independent of the genera-tor properties and the operating method. Mea-surement at system standstill is still possible. Thisprotection function is designed so that it detectsearth-faults both in the whole generator (real100 %) and in all galvanically connected systemcomponents. The protection relay detects the in-jected 20 Hz voltage and the flowing 20 Hz cur-rent. Disturbance variables such as stator earthcapacitances are eliminated, and the ohmic faultresistance is determined by a mathematical model.As a result, high sensitivity is ensured and the use

in generators with high earth capacitances – e.g.large hydroelectric generators – is enabled. Anglefaults due to the earthing or star-point trans-former are detected during commissioning andcorrected in the algorithm. The protection func-tion has a warning and trip stage. In addition, themeasuring circuit is monitored and a failure of the

20 Hz generator detected. Regardless of the earthresistance calculation, the protection function ad-ditionally evaluates the r.m.s. value of the current.Another stage is available for earth-faults in whichthe displacement voltage and thus the fault cur-rent exceed a certain value.

Taking the following parameters into considera-tion, the following settings for the applicationexample apply.

Load resistance on the earthing transformerRL = 4.63 Ω

Transformation ratio, voltage dividerüKl = 200 / 5

Transformation ratio, voltage dividerüdivider = 2 / 5

Transformation ratio, earthing transformerütransf = 15.75: 3 / 0.5 kV


Pickup value of thealarm stage

5 to 80 kΩ 40 kΩ

Pickup value of thetrip stage

1 to 10 kΩ 5 kΩ

Delay time of thealarm stage

0 to 60 s; ∞ 10 s

Delay time of thetrip stage

0 to 60 s; ∞ 1 s

Table 13 Parameter overview for the rotor earth-faultprotection

Parameter Settingoptions

Setting

Pickup value of thealarm stage SES 100 %

20 to 700 Ω 193 Ω

Pickup value of thetrip stage SES 100 %

20 to 700 Ω 48 Ω

Delay time of the alarm stageSES 100 %

0 to 60 s; ∞ 10 s

Delay time of the trip stageSES 100 %

0 to 60 s; ∞ 1 s

Pickup value 100 % I>> 0.02 to 1.5 A 0.27 A

Monitoring threshold for20 Hz voltage

0.3 to 15 V 1 V

Monitoring threshold for20 Hz current

5 to 40 mA 10 mA

Angle correction for I SES 60 ° 0 °

Transition resistance Rps 0 to 700 Ω 0 Ω

Parallel load resistance 20 to 700 Ω; ∞ ∞ Ω

Table 14 Parameter overview for the 100 % stator earth-faultprotection




4.13 Out-of-step protection (ANSI 78)This protection function serves to detect powerswings in the system. If generators feed too longonto a system short-circuit, a compensation pro-cess (active power swings) may take place be-tween the system and the generator after fault dis-connection. If the center of power swings is in thearea of the unit, the “active power surges” lead toimpermissible mechanical stressing of the gener-ator and the whole generator mounting – includ-ing the turbine. Since these are symmetrical proc-esses, the positive-sequence impedance is calculat-ed from the voltage and current positive-sequencecomponents and the impedance curve is evalua-ted. In addition, the symmetry is monitored byevaluating the negative-phase sequence systemcurrent. Two characteristics in the R/X diagramdescribe the range of effect (generator, unit trans-former or system) of the out-of-step protection.The appropriate counters are incremented, de-pending on in which characteristic range the im-pedance vector enters and exits. If the set counterreading is reached, tripping takes place. If no morepower swings occur after a set time, the countersare automatically reset. Every power swing can besignalled by a settable pulse. The extending of thecharacteristic in R direction determines the de-tectable power swing angle. 120 ° are practicable.The characteristic can be tilted at an adjustableangle to adapt to the conditions when the systemis feeding off several parallel generators.


A minimum value of the positive-sequence com-ponents of the currents I1> must be exceeded(overcurrent pickup) to enable the measurement.In addition, a maximum value of the negative-sequence components of the currents I2< may notbe exceeded, due to the symmetry condition. As arule, the setting value I1> is chosen above ratedcurrent – i.e. about 120 % IN – to avoid pickup byoverload. The pickup threshold of the negative-sequence component of the current I2< is set toabout 20 % IN.

The impedances of the protected zone seen fromthe protection relay are decisive for determiningthe setting values. In the direction of the generator(seen from the installation position of the voltagetransformer set), the power swing reactance of thegenerator must be taken into account; it can be setapproximately equal to the transient reactance xd'.This means the transient reactance related to thesecondary side is calculated and set for Zb xd' (seeFig. 7).

The meaning, calculation and setting of the pa-rameters for the trip characteristics are describedin detail in the manual.

The following table shows the setting options andthe calculated settings.

The setting ranges and presettings are specified fora secondary rated current of IN = 1 A.

Fig. 7 Power swing polygon


Pickup value of themeasurement release I1>

20 to 400 % 120 %

Pickup value of themeasurement release I2>

5 to 100 % 20 %

Resistance Za of the polygon(width)

0.2 to 130 Ω 8.25 Ω

Reactance Zb of the polygon(reverse)

0.1 to 130 Ω 19.60 Ω

Reactance Zc of the polygon(forward char. 1)

0.1 to 130 Ω 8.90 Ω

Reactance differencechar. 2 – char. 1

0 to 130 Ω 1.10 Ω

Inclination angle of the polygon 60 to 90 ° 90 °

Number of oscillations bycharacteristic 1

1 to 4 1

Number of oscillations bycharacteristic 2

1 to 8 4

Seal-in time of characteristic 1and characteristic 2

0.2 to 60 s 20 s

Seal-in time of the messageout-of-step, char. 1 andout-of-step char. 2

0.02 to 0.15 s 0.05 s

Table 15 Parameter overview for out-of-step protection



5. Connection diagram 6. CommunicationThe 7UM6 relays fully meet the requirements ofmodern communication technology. They haveinterfaces which allow integration in master con-trol stations, convenient parameterization andoperation by PC (locally or via a modem). The7UM6 supports the widely used internationalopen communication standards

PROFIBUS-DP, RS485 or optical 820 nmdouble-ring ST connector

IEC 60870-5-103, DNP3.0, RS485 or optical 820 nm double-ring

ST connector and MODBUS, RS485 or optical 820 nm

double-ring ST connector

NoteAll SIPROTEC 4 relays also operate with starcoupler. This enables the user to access all infor-mation from the office or en route (for simple ap-plications). With the PROFIBUS-DP protocol,SIPROTEC relays can easily be integrated in PLC-based process control systems (e.g. SIMATICS5/S7). The protocols DNP3.0 and MODBUSASCII/RTU allow integration in numerous instru-mentation and control systems of other manu-facturers.

7. SummaryBeginning with the recommendations for protec-tion functions [1], it has been described that effi-cient concepts can be created with modernSIPROTEC relays in medium-sized generators,despite the need to consider cost factors. The mul-tifunctional, numerical SIPROTEC relays enable agreater functional scope than the previous singlerelays. Self-monitoring substantially improves theavailability of the protection relays.

For further information about the function rangeand setting, the 7UM62 manual is recommended,chapter 2 of which has been compiled as an appli-cation manual.

8. ReferencesHerrmann, H.-J.: “Digitale Schutztechnik”(Digital Protection Technology).Basic principles, software, examples ofimplementation.VDE-Verlag GmbH, Berlin 1997,ISBN 3-8007-1850-2.

Herrmann, H.-J.: “Elektrischer Schutz vonKleinkraftwerken” (Electrical Protection of SmallPower Stations).“Elektrizitätswirtschaft Jg. 97”(Electricity Industry Year 97) (1998) Issue 24

Manual7UM62 Multifunction Generator, Motor andTransformer Protection Relay

Fig. 8 Connection diagram of 7UM6



1. IntroductionIn many power systems, pumped-storage powerstations are used in addition to run-of-river powerstations. These power stations serve primarily tocover load peaks in the power system. In suchpeak load periods the machines operate as genera-tors and feed active power into the grid. In slackperiods, e.g. during the night, the machines oper-ate as motors and pump water into the upper res-ervoir which is then available later as an energysource for peak load supply. In this way, large-scale thermal power units can be continuously runto cover basic load.

Fig. 2 shows a typical redundant protection systemdesign for pumped-storage units with an activepower output greater than 100 MW.

Unit Protection System forPumped-Storage PowerStations

Fig. 1 SIPROTEC 7UM62

Fig. 2 Redundant protection system for pumped-storage power stations

LSP2

171.

eps



If the protection requirements of a pumped-stor-age power station are compared with those of aunit for pure energy generation, certain particularfeatures emerge as well as many parallels. Design-ing a protection system for medium and large-scale power stations is described in another publi-cation. This guide explains the special protectionfunctions and the working of a pumped-storageunit.

Table 1 below describes a typical basic concept fora pumped-storage unit.

The protection system described can be supple-mented by extra protection functions, dependingon technical requirements or country-specific cus-tomary protection concepts. Likewise, the level offunction redundancy can be expanded or reduced.

The advantage of the 7UM6 multifunctional pro-tection relays lies in the ease of configuration.

With the aid of the DIGSI® configuration pro -gram, each of the protection functions containedin the relay can be switched active or inactive.

2. Selected protection functions2.1 Stator earth-fault protectionThe same principle applies for generators inpumped-storage power stations as for other powerstation types: the most frequent electrical fault isan earth fault. Simple stator earth-faults cause nodamage to the generator provided the earthingtransformer and loading resistor have been cor-rectly designed. A second earth fault would, how-ever, result in such high fault currents that thegenerator would be severely damaged. For thisreason a simple stator earth-fault must be detectedat an early stage and at least signalled. In largegenerators simple earth faults nearly always resultin disconnection unless restrictions in the powersystem operation and control exclude this.

The 100 % stator earth-fault with 20 Hz infeed(Fig. 3) complies with the requirements for reli-able detection of a stator earth-fault throughoutthe stator winding up to the star point. Withinfeed of a generator-independent auxiliary volt-age, this protection principle allows so-calledstandstill testing. External supply to the 20 Hzgenerator enables the machine to be tested forpossible stator earth-faults before startup. In nor-mal operation the sensitive signal level indicatesthe start of an earth fault early on. The protectionrelay calculates the resistive component from themeasured earth current. The result is therefore in-dependent of the capacitance of the stator toearth. This advantage is especially effective in largehydroelectric generators which have a high capaci-tance to earth. The insulation value of the earthedstator winding can be shown on the protectionrelay display, providing the operator with valuableinformation about whether the machine can con-tinue to run until the next planned inspectionshutdown.

2.2 Negative-sequence protection (ANSI 46)Various settings are required for phase-se-quence-dependent protection functions if the ma-chine is switched between generator operationand pump operation. An example of such a func-tion is negative-sequence (or unbalanced load)protection, whose pickup criterion is based onmeasuring or calculating the reverse field. Onepossible solution is installing two identical protec-tion relays with respective setting values for gener-ator operation and pump operation. One of thetwo protection relay is always blocked to preventspurious operation.

Protection functions ANSI code Protection Group A Protection Group B

Stator earth-fault protection 90 % 64

Stator earth-fault protection100 %

64 (100 %)

Differential protection 87

Winding fault

Overcurrent-time protection 51

Impedance protection 21

Rotor earth-fault protection 64R

Load unbalance protection 46

Underexcitation protection 40

Out-of-step protection 78

Stator overload protection 49

Rotor overload protection 49E

Overvoltage protection 59

Frequency protection f > 81 (f >)

Frequency protection f < 81 (f <)

Reverse power protection 32

Underpower protection 37

Undervoltage protection 27

Overexcitation protection 24

Table 1 Protection concept for pumped-storage power plants



A more elegant and cost-effevtive solution wouldbe to switch over the parameter sets in the protec-tion relay when changing between the two operat-ing modes. The 7UM6 numerical generator pro-tection relay allows the read-in of two independ-ent parameter sets. When changing between themachine's two operating modes, a control signalto the protection relay digital input activates theother parameter set for protection processing. Fornegative-sequence protection, this means that,from the calculated symmetrical components ofthe measured current, the positive phase-sequencesystem and the negative phase-sequence systemare exchanged for further protection processing.

2.3 Underexcitation protection (ANSI 40)Large pumped-storage units are often used for re-active power compensation, in addition to balanc-ing peak loads in the power system. Consequently,the generator can be run close to its stability limit,depending on reactive-power demand over a longperiod. Slight increases in reactive-power demandcan make the generator fall out of step. Conse-quently, particular emphasis is laid on underexci-tation protection in large pumped-storage powerstations.

Primarily, the excitation system itself detects anovershoot of the stability characteristics of thegenerator and compensates this by readjusting theexcitation voltage. Electrical underexcitation pro-tection comes into action if this automatic read-justment is unsuccessful. The generator movesinto the capacitive working range and finally fallsout of step. This impermissible operating state candamage the generator and create instability in thepower system linked to the power station. Theasynchronously running generator suffers severemechanical stressing of the shaft and bearings,which could result in costly repair work. It alsoproduces electrical oscillations in the power sys-tem which can lead to other generators falling outof step. Asynchronous operation can be caused bydefective excitation equipment or excessive reac-tive-power demand in the connected transmissionnetwork.

In view of the wide range for active and reactivepower in such a pumped-storage unit, particularattention must be paid to setting the underexcita-tion protection characteristic. Simple detection ofreactive-power demand by a circular protectioncharacteristic will not meet these operating re-quirements. A combination of pickup characteris-tics in accordance with Fig. 4 is ideally suited forthe requirements described here.

These protection characteristics form the stabilitycharacteristics of the machine and combine highavailability of the pumped-storage unit withoptimum protection of the machine and the con-nected power system.

The pickup characteristics of the underexcitationprotection are made up of the machine’s steady-state and dynamic stability characteristics. Anovershoot of the steady-state characteristic is aninitial indication that stability is endangered.

Fig. 3 Stator earth-fault protection with generator, 20 Hz

Fig. 4 Characteristic of underexcitation protection



If the excitation equipment is functioning cor-rectly the machine can be returned to synchro-nous operation again by automatically readjustingthe excitation voltage. Only an overshoot of thedynamic restraint characteristic finally makes themachine fall out of step. Both characteristics,sometimes referred to as the stator criterion, arecalculated from machine currents and voltages.The excitation voltage Uexcit (or rotor criterion) isused as an additional measured variable for opti-mum operation and control. The recommendedfunction logic of the underexcitation protection isshown in Table 2 below.

Measurement criterion Protection reaction

Steady-state characteristic Indication (optionaltripping approx. 10 s)

Steady-state characteristic+ Uexcit <

Tripping approx. 0.3 s

Dynamic characteristics Tripping approx. 0.3 s

Uexcit < Indication

Table 2

An overshoot of the steady-state stability charac-teristic without simultaneous excitation voltagedip is only signalled. The operating personnel canmanually intervene to return the machine to sta-ble operation. The cause of underexcitation can liein power factor correction.

Only a simultaneous drop in the excitation voltagebelow a set value causes shutdown of the machinein short time. This is probably due to a fault in theexcitation equipment. It is then only a question oftime before the machine reaches the dynamic sta-bility characteristic and finally falls out of step.Shutting down at an early stage prevents this addi-tional pole slipping and protects both machineand power system.

This logical linking of stator criteria with rotorcriteria enables the pumped-storage unit to con-tinue operation up to its real stability limit. Theexact replica of the machine characteristics en-sures that the unit does not switch off unnecessar-ily within the permissible limit range. On theother hand, this optimum utilization of the oper-ating range involves no danger to the machine orpower system. If the stability of the machine is nolonger guaranteed, it is shut down quickly andsafely.

2.4 Stator overload protectionAn important protection function for pump oper-ation is stator overload protection. In generatormode, the thermal loading on the stator windingis limited by the turbine output if the power sta-tion unit is correctly designed. In pump mode,there may be thermal overload of the machine inmotor mode. A thermal replica with complete me-mory prevents such overloads. Particularly withquick load changes, the thermal replica is moreexact than a direct temperature measurement onthe winding.

The thermal replica calculates the temperature ofthe stator winding from the stator current practi-cally instantaneously (Fig. 5) according to theformula I2t. A direct measurement of the tempera-ture on the insulation of the stator winding fol-lows load changes only after a delay and thereforedoes not always show the current temperature ofthe conductor.

2.5 Rotor monitoringIn large machine units special attention must bepaid to monitoring the rotor circuit, owing to thehigh power per pole. This monitoring includes in-sulation of the rotor winding as well as the ther-mal load on the rotor winding.

To monitor the rotor insulation a specially devel-oped measurement principle is used which largelycompensates for the disturbing influence of therotor capacitance to earth and fluctuations of theexcitation voltage. A reverse polarity square-wavevoltage in a clock pulse from 1 to 3 Hz is appliedbetween rotor circuit and earth (see Fig. 6). Thesteady-state circulating current remaining afterthe capacitive charging current has decayed is ameasure of the insulation resistance of the rotorwinding. The protection relay measures only theresistive component of the earth impedanceregardless of the level of earth capacitance.

Fig. 5 Principle of overload protection

The setting value IB is matchedto the rated motor currentThe rated temperature ΘN isreached at I = IB

The tripping temperature ΘA isreached at I = 1.1 IB



Fig. 6 Principle of rotor earth-fault protection

The differential measurement of the resistive earthcurrent from positive and negative polarity com-pensates on the one hand the disturbance of theexcitation voltage and also stops measurement er-rors owing to operation-related changes in the ex-citation voltage. This sophisticated measuringprocedure measures an insulation resistance(to earth) in the rotor winding up to the order of80 kΩ. Hence, the protection relay detects a rotorearth-fault as it arises. The operator can plan thenecessary maintenance work on the machine forthe long term. Protection-related shutdown of thepumped-storage unit is thereby almost alwaysprevented which considerably enhances the avail-ability of the unit.

As a result of the various operating modes of thepumped-storage unit

Generator mode Generator and VAR compensation mode Pump mode Pump and VAR compensation mode Any electrical brake

the rotor circuit of the excitation system may beexposed to high thermal loads. Overload protec-tion on the high-voltage side of the excitationtransformer measures the current flowing therewhich is in direct relationship to the thermal rotorload. Overload protection works as a thermal re-

plica with complete memory and enables flexibleoperation and control of the unit within the per-missible limits, with simultaneous safe protectionagainst overloads.

2.6 Power system failure in pump operationThe power-shortfall protection function is onlyactivated in pump mode. This happens by way ofthe above-described parameter set changeoverwhen the mode is changed. In the parameter setfor generator mode, the power-shortfall functionis deactivated. This protection function recognisesthe sudden failure of the power system supply(when the machine is in pump mode) by measur-ing the active power in the infeed direction. If afault is detected, the pumped-storage unit isswitched off and the spherical valves are closed.

A second measurement principle for detecting aline side supply failure is underfrequency protec-tion, which is likewise included in the protectionconcept.

The underfrequency protection is not in operationduring run-up and switchover of the system’s var-ious operating states, and is only activated afterthe machine has been synchronized with thepower system. A binary input from the protectionrelay, which requests the position of the systemcircuit-breaker, effects this control.



3. SummaryIn view of their particular status in hydropowerengineering, pumped-storage power stations placespecial demands on the electrical protection sys-tem. Owing to the various operating modes

Generator mode for energy supply Pump mode to feed back energy VAR compensation mode

a protection system is required that automaticallyadapts itself to these changing operating states.The SIPROTEC 7UM6 relays are specifically de-signed to handle these variable operating condi-tions. This applies both to the protectionfunctions comprised in the relays and to the flexi-ble adaptation of the protection system via exter-nal control signals from the power station.


Busbar Protection

1. IntroductionUtilities have to supply power to their customerswith highest reliability and minimum down time.System disturbances, especially short-circuits,cannot always be avoided. They are caused by hu-man error, accidents, nature’s influence such asstorm, lightning, etc...However, damage to primary equipment, such astransformers, switchgear, overhead lines, etc. mustbe limited in order to reduce the repair time and,thus, the downtime.Although busbar faults are rare, they are consid-ered most dangerous for people (staff) and theswitchgear. Hence, fast tripping in case of busbarfaults is essential!This can be achieved primarily by differential pro-tection.

Especially in medium and high-voltage switch-gear, busbar differential protection is often re-garded as an expensive accessory. However, re-sponsible engineers are aware of the risk ofextensive outages, if busbar faults are not clearedfast and selectively.Siemens offers with its 7SS601 low-impedancebusbar differential protection a low-cost solution,particularly suitable for single busbar with orwithout bus sectionalizer or simple double busbarconfigurations.The 7SS601 combines important advantages ofnumerical protection with a cost-effective and aneasy-to-use protection system:

Self-supervision, fault logging and event record-ing, setting with DIGSI required for only a fewparameters.

Highest flexibility with regard to busbar config-uration, number of feeders, different CT-ratios,low CT requirements.

Measured-value acquisition by summation ormatching current transformers (phase-selective)

Fast and selective tripping for all busbar faults. Suitable for all voltage levels, up to 500 kV

The following article describes the basics of low-impedance busbar protection; some of its typicalapplications on a single busbar with bussectionalizer with disconnect switch or bussectionalizer with circuit-breaker).The example is tailored for a solidly earthed net-work.

Application of Low-Impedance7SS601 BusbarDifferential Protection

2. Principle of low-impedance protectionFig. 2 illustrates the basic principle of the low-impedance protection.

Differential protection is based on the Law ofKirchhoff: in a healthy system, the sum of currentsin a node must be zero. This is the ideal case. ButCT errors and measuring errors need to be con-sidered. For that reason, the protection needs tobe stabilized.The differential criteria and the restraint criteriaare defined as follows:

Differential current: IDiff = |I1 + I2 + …. In |Restraint current: IRestraint = |I1| + |I2 |+ ….| In|

Fig. 3 shows, how IDiff and IRestraint are being derived.

It can be seen, that for load or through-flowingcurrents the differential criteria is almost zero,whereas the restraint quantity rises instantly.In case of an internal fault both, the differentialand the restraint quantity rise at the same time.Hence, even within a few milliseconds, the protec-tion relay can decide whether there is an internalor external fault.

Fig. 2 Principle of differential protection

Fig. 1 SIPROTEC 7SS601 centralized numerical busbarprotection relay

LSP2

363.

eps

Busbar Protection


Fig. 3Derivation ofIDiff and IRestraint

Fig. 4 Single busbar with disconnector in bussectionalizer

Fig. 5 Single busbar with circuit-breaker in bussectionalizer

3. Protected objectsFig. 4 and 5 show examples with 10 feeders oneach bus section. However, the number of feedersper bus section is not limited.

3.1 Single busbar with disconnector (DS) in bussectionalizer. In this case, no CTs are used in thebus sectionalizer. See Fig. 4

3.1.1 If the DS is open, both measuring systems(bus differential schemes) work independently. Incase of a busbar fault, only the circuit-breakers(52) connected to the faulty bus will be tripped.

3.1.2 If the DS is closed the busbar must be con-sidered as “one unit”. The preference circuit (pref -erential treatment module) will switch the cur-rents of all feeders to one measuring system only.In case of a busbar fault, all circuit-breakers willbe tripped.

3.2 Single busbar with circuit-breaker and a CT inthe bus sectionalizer. See Fig. 5.

3.2.1 If the circuit-breaker is open, both systemswork independently. In case of a busbar fault, onlythe CBs connected to the faulty bus will be trip-ped.Since the circuit-breaker is open, the CT is not re-quired for measurement and thus shorted.In case of a fault between the circuit-breaker andthe CT in the bus sectionalizer, system 1 will de-tect the fault as “internal” and trip all CBs con -nected to bus 1.

For more than 50 years Siemens has been using thiskind of stabilized differential protection.It was introduced for the first time in the electro-mechanical protection 7SS84, later in the analogstatic protection 7SS10 and is now being employ-ed in the numerical protections 7SS52 and 7SS601.


Busbar Protection

3.2.2 If the circuit-breaker in the bus sectionalizeris closed both systems work independently. In caseof a busbar fault, all circuit-breakers connected tothe faulty busbar will be tripped. The circuit-breaker in the bus sectionalizer will be tripped byboth systems. In case of a fault between the cir-cuit-breaker in the bus sectionalizer and the CT,system 2 will detect this fault as “internal” and tripall circuit-breakers of bus 2 including the circuit-breaker in the bus sectionalizer.System 1 remains stable for the time being.Once the circuit-breaker in the bus sectionalizer hastripped, the CTs are shorted. Now system 1 will de-tect this fault also as “internal” and finally clears thefault by tripping the circuit-breakers of bus 1.

4. Summation current transformers andadaptation of different CT ratios

The advantage of the low-impedance scheme isthat other protection relays may be connected inseries with the summation or matching currenttransformers (Fig. 6). This reduces the overallcosts of the switchgear.As mentioned earlier, the low-impedance schemecan process different CT ratios. Thus, upgradingof existing switchgear with low-impedance busbarprotection is easily possible without changing oradding CT cores!

The standard connection of a summation currenttransformer is shown in Fig. 7.The summation current transformer is used to do a“magnetic” summation of the currents. The result-ing currents depend on the ratio of the windings.The following calculation shows some examples ofhow the currents of the summation current trans-formers are being calculated.

It can be shown that the optimum ratio of the pri-mary windings are 2:1:3. This ensures increasedsensitivity for earth faults.

Example: WP1 = 60 windingsWP2 = 30 windingsWP3 = 90 windingsWS = 500 windings ( fixed )

General equation:

i W i W i iW

Wp P s S s p

P

S

⋅ = ⋅ ⇒ =

For the above example: assume i I= =N A1

Result: summation iL1 + iL2 + iL3 = is

Fig. 6 Serial connection of summation CTs with other relays

Fig. 7 Standard connection of summation current transformer

WP = primary winding of summation current transformerWs = secondary winding of summation current transformer

iW

L 1 1 1 0 3= + = =AW

A150

500AP1 P3

S

W. 0 3. ⋅e j0

iL1 = 0.3 + j0

i L2P3

S

AW

A90

500A= = =1 1 018

W. 018. ⋅e j120

iL2 = -0.09 + j0.156

iW

L3P2 P3

S

AW

A120

500A= + = =1 1 0 24

W.

0 24. ⋅e j240 iL3 = -0.12 - j0.21

is = 0.09 - j0.054 i esj= ⋅ − °0105 30.

current


Busbar Protection

As can be seen the secondary current is

≈ 100 mA, which corresponds to the rated currentof the 7SS601 protection relay.The graphical addition leads to the same result.See Fig. 8.

In order to adapt different CT-ratios, the4AM5120 summation current transformer has 7primary windings, which can be combined bymeans of connecting the windings in series.The 4AM 5120-3DA00-0AN2 summation currenttransformer is suitable for 1A rated current:

As mentioned before, the ratio of the primarywindings should be 2:1:3 in standard applications.Table 1 shows the most commonly used ratios.

NoteAlways be aware of the orientation of the windings !

The examples of Figures 4 and 5 respectively showCT-ratios of 400/1A, 600/1A and 1000/1A.The differential protection can only compare cur-rents, if the basis for comparison is equal, i.e. theCT-ratios must be matched.A simple procedure has to be followed:

The difference in CT-ratios may not exceed 1:10(i.e. 400 / 600 / 1000 is possible, 200 / 800 / 2500is not possible).

The max. possible number of windings of thesummation current transformer shall be used.Thus, accuracy is increased.

The highest CT-ratio is always the reference.

Choose the smallest common integer multipleof the CT-ratios, of which the result of divisionmay not exceed “10”.Example400 / 600 / 1000 smallest multiple:2 → 200 / 300 / 500: Not possible !

400 / 600 / 1000 smallest multiple with result≤ 10 : 100 → 4 / 6 / 10. Possible !

The result of this calculation is used to select theratios of the summation transformer from Table 1( Reference number ).

400 / 1A → 4 → 24-12-36600 / 1A → 6 → 36-18-54

1000 / 1A → 10 → 60-30-90

Fig. 9 Tapping of summation current transformers

Wind-ings

Refer-ence

Phase Connec-tions

Links

6-3-9 1 L1L3N

C, DA, BE, F

12-6-18 2 L1L3N

A, FC, DG, H

B-E

18-9-27 3 L1L3N

G, HE, FA, K B-J

24-12-36 4 L1L3N

J, KA, FL, M

B-E

30-15-45 5 L1L3

N

C, KB, H

E, M

D-JA-G magnetic

subtractionF-L

36-18-54 6 L1L3N

A, KG, HM, O

B-E, F-J

L-N magneticsubtraction

42-21-63 7 L1L3

N

C, MB, K

F, O

D-LA-J magnetic

subtractionE-H, G-N magnetic

subtraction

48-24-72 8 L1L3N

A, MJ, KH, O

B-E; F-L

G-N magneticsubtraction

54-27-81 9 L1L3N

G, MA, KF, O

H-LB-JE-N magnetic

subtraction

60-30-90 10 L1L3N

J, MA, HN, O

K-LB-E, F-G

Table 1 Selected ratios of summation current transformersat IN = 1 A

Fig. 8 Phasor diagram of measurings

Above example


Busbar Protection

Fig. 10 shows that with the above selected ratiosthe secondary currents of the summation currenttransformers are equal. The differential protectioncan now compare all currents.

In case of short-circuits, the sensitivity of the dif-ferential protection varies due to the winding ratio2:1:3 and the resulting secondary currents. Referto Table 2.

Shortcircuits

EffectivewindingsW

W

3

I1 for iM = 100 mA

L1 - L2 - L3 3 1.00 1.00 ⋅ IN

L1 - L2 2 1.15 0.87 ⋅ IN

L2 - L3 1 0.58 1.73 ⋅ IN

L3 - L1 1 0.58 1.73 ⋅ IN

L1 - E 5 2.89 0.35 ⋅ IN

L2 - E 3 1.73 0.58 ⋅ IN

L3 - E 4 2.31 0.43 ⋅ IN

Table 2 Result of secondary current matching

To ensure reliable tripping, the minimum short-circuit currents must be above the lowest pickupvalue of the respective fault type.

Example: Setting of the pickup threshold:

IDiff > 1.20 INO*

* INO is the rated current of the reference ratio (1000/1 A)

1000 / 1 A

3-phase faults 1.20

L1 - L2 1.04

L2 - L3 2.08

L3 - L1 2.08

L1 - E 0.42

L2 - E 0.69

L3 - E 0.52

Table 3 Sensitivity of 7SS60 according to type of fault

Hence, the minimum short-circuit current mustexceed:

1200 A for 3-phase faults2080 A for phase to phase faults

690 A for phase to ground faults

Fig. 10 Adaption of different CT ratios


Busbar Protection

Fig. 11 Block diagram of the 7SS60 with disconnector in bus sectionalizer

5. Components of the 7SS601 centralizednumerical busbar protection

The basic principles are shown in Fig. 11 and 12:4AM5120 summation current transformers, re-straint/command output 7TM70 modules, 7TR71isolator replica/preferential treatment moduleand 7SS601 protection relay are required:

Summation current transformers: one for eachfeeder.

Restraint modules: each module 7TM70 con-tains 5 input transformers with rectifiers and5 tripping relays.

Measuring system(protection relay): one foreach bus section.

7TR71 preferential treatment/isolator replicamodule. For allocation of current and preferen-tial treatment via isolator replica.

7XP20 housing to accommodate 7TM70 and7TR71 modules. One housing can accommo-date up to 4 modules.

Fig. 11 shows the scheme with a disconnector inthe bus sectionalizer. In this case, 7TR71 is used aspreferential treatment module. If the disconnectoris closed the entire bus must be seen as “one unit”.All currents must be measured by one system on-ly. Thus all currents are routed to system 2.The trip circuits of both busses are switched inparallel.Fig. 11 corresponds to the example shown in Fig. 4.


Busbar Protection

Fig. 12 Block diagram of the 7SS60 with circuit-breaker in bus sectionalizer

Fig. 12 shows the scheme with a circuit-breaker inthe bus sectionalizer. In this case, 7TR71 is used as“circuit-breaker position replica” module. If thecircuit-breaker is open, the secondary side of thesummation CT is shorted because no current flowsin the bus section anyway.If the circuit-breaker is closed, the differential andrestraint currents are fed to both measuring sys-tems with opposite direction.In case of a busbar fault, a busbar-selective trippingis possible. The circuit-breaker in the bus sectiona-lizer will be tripped by both measuring systems.

Fig. 12 corresponds to the example shown inFig. 5.


Busbar Protection

Busbar protection for switchgear (20 feeders) asshown in Fig. 11, comprises the following com-ponents:

20 x 4 AM 5120 summation current transfor-mers (10 feeders on each busbar)

4 x 7TM70 restraint modules(4 x 5 inputs = 20 inputs)

2 x 7SS601 protection relays 1 x 7TR71 preferential treatment module 2 x 7XP20 housings

Busbar protection for switchgear (20 feeders + bussectionalizer with circuit-breaker)

21 x 4AM5120 summation current transfor-mers (20 feeders +1 for the sectionalizer)

5 x 7TM70 restraint modules (25 inputs) 2 x 7SS601 protection relays 1 x 7TR71 isolator/CB replica module 2 x 7XP20 housings

The above modules can be accommodated in astandard protection cubicle.Please refer to our documentation (instructionmanual, catalog and circuit diagrams) for moredetails.

6. Setting and design considerationsCTs shall be dimensioned such that all CTs trans-form currents without saturation for at least≥ 4ms.The number of feeders connected in parallel toone protection relay is unlimited.

Please refer to the instruction manual in case ofsystems with transformers of which the star pointis isolated.A lock-out function of the trip command may beactivated in the 7SS601. No external lock-out re-lays are required !

Fig. 13 shows the tripping characteristic of theprotection relay.

The threshold Id > should be set above max. loadcurrent (e.g. 1.2 · ILoad) to avoid tripping by theload current in case of a fault in the CT circuit.If, however, the minimum short-circuit currentsrequire a lower setting, additional trip criteria maybe introduced (e.g. voltage).

On the other hand, to ensure tripping under mini-mum short-circuit conditions, Id> should be set atabout 50 % below minimum short-circuit cur-rents. For instance: Iscmin = 3000 A → 50 % =1500 AId > = 1.2 INO, if the reference ratio is 1000/1 A.

The threshold Id>CTS is the pickup value for CTsupervision.If a CT secondary circuit is open or shorted, a dif-ferential current will appear. The differentialprotection will be blocked and an alarm given.This will avoid unnecessary overfunction in caseof heavy through-flowing currents.

The k-factor changes the slope of the trippingcharacteristic as shown in Fig. 13 and thus deter-mines the stability of the protection.Although a high setting for this factor improvesthe stability with regard to faults outside the pro-tected zone, it reduces the sensivity for the detec-tion of busbar faults. The k-factor shouldtherefore be chosen as low as possible and as highas necessary. If the measuring system (protectionrelay) is to be used for zone-selective protection,which will be the case in most applications, it isadvisable to use the presetting of 0.6 of the k-fac-tor.

Fig. 13 Tripping characteristic


Busbar Protection

7. Comparison of high and low-impedancebusbar protection

Nowadays high impedance protection is stillwidely used, because it is considered “cheap andeasy”.But most users only look at the relay price itself,without considering the additional costs for theswitchgear and other disadvantages of a high-im-pedance schemes:

All CTs must have the same ratio Class X for all CT cores Bus sectionalizers with circuit-breaker must be

equipped with two CTs Separate CT cores for busbar protection Advantages of numerical protection technology

(e.g. fault recording, communication, etc.) notavailable

Check zone needs separate CT cores Isolator replica requires switching of CT sec-

ondaries. Additional check zone obligatory.

8. SummaryThe low-impedance 7SS601 busbar protection is acost-effective solution for medium and high-volt-age switchgear.

Apart from the application described the 7SS601can also be applied

With phase-segregated measurement On switchgear with double busbars.

For a quotation, we would need the following in-formation:

Single-line diagram, showing

– Busbar configuration– Number of feeders, bus sectionalizers with

disconnector/circuit-breaker– Ratio of CTs– Phase-segregated or single phase measurement– Complete cubicles or components only

For more information please contact your localSiemens partner.More details may be obtained from our docu-mentation (instruction manuals, relay catalogSIP2004, CD’s). Circuit diagrams for standardapplications are available on the Internet at:www.siprotec.com


Busbar Protection


Busbar Protection

Busbars have a particular key role in power trans-mission and distribution. They are the central dis-tribution point for many feeders. In the event of afault, the short-circuit current on the busbar isvery high, resulting potentially in mechanical de-struction and the consequent long repair times,which would affect all feeders. On the high andextra-high-voltage level, a fast 7SSx busbar pro-tection relay is used, which, with a tripping timeof <12 ms, limits the damage by busbar faults.Fast busbar protection is also used in all impor-tant medium-voltage switchgear.

For basic medium-voltage switchgear with one in-coming feeder, no special busbar protection isused (for reasons of economy). In such casesbusbar protection is provided by the time-over-current relay of the incoming feeder. As shown inFig. 1, tripping of the time-overcurrent protectionfor the E1 feeder occurs with a grading time of300 ms more than the longest grading time of theA1-A3 feeder protection. The times selected inFig. 1 have been taken as examples. The E1 protec-tion serves as backup protection for each A1-A3feeder protection.A busbar fault is however then only disconnectedafter 0.9 seconds, which would result in damage ofconsiderable magnitude.

In the case of single busbars with one defined in-coming feeder and otherwise only defined outgo-ing feeders, fast busbar protection can be providedwith no major additional effort by means of re-verse interlocking. Such busbar configurations arecommon in medium-voltage systems and in auxil-iary supply networks. The time-overcurrent relaysalready available for feeder protection are used, asshown in Fig. 1. An additional benefit is that allSIPROTEC relays are equipped with at least twodefinite-time current stages, which can be blockedindividually.

The reverse interlocking concept is shown inFig. 2. With the time-overcurrent protection E1 ofthe incoming feeder, a further stage I>> with atime delay of t2 = 50 ms is provided in addition tostage I> with t1. The expiry of time t2 can beblocked via the binary input BI1.

Basic Busbar Protection byReverse Interlocking

Fig. 1 Single busbar with feeder protection

Fig. 2 Single busbar with feeder protection and busbar protection by reverseinterlocking

224

Busbar Protection

The tripping threshold of the stages I> and I>> isset at the same level in accordance with the net-work conditions (approximately 1.5 x Irated). Forthe time-overcurrent relays of outgoing feedersA1-A3, the pick-up signal is allocated to a dedi-cated contact. The pick-up signals of all feedersare connected in parallel and given as a blockingsignal to the binary input BI1 of the relay of theincoming feeder. Wiring is effected by means ofa copper core, looped from panel to panel (seeFig. 2). This means that a pickup in an outgoingfeeder A1-A3 will block the tripping of the I>>stage (t2) of the incoming feeder E1.

Function in the case of a fault in the outgoing feeder:In the case of a fault on the outgoing feeder (see“F1” in Fig. 2), both stages in relay E1 of the in -coming feeder pick up. The relay A1 of the out-going feeder also picks up and issues a blockingsignal via the pick-up signal to binary input BI1 ofthe relay E1 of the incoming feeder. The expiry oft2 is thus blocked. The fault is disconnected fromthe relay A1 of the outgoing feeder. The relay E1of the incoming feeder operates as backup protec-tion with t1.

Function in the case of a fault on the busbar:In the case of a busbar fault (see “F2” in Fig. 2),both stages in relay E1 of the incoming feeder pickup and t1 and t2 are started. From an A1-A3 out-going feeder there can be no infeed onto the fault.Consequently there is no blocking signal. In therelay E1 of the incoming feeder, time t2 expiresand trips the circuit-breaker after 50 ms. Thebusbar fault is thus disconnected within a shorttime and the extent of the fault is limited.

SummaryFor busbars with one incoming feeder and radialoutgoing feeders, i.e. without back-feeding, the re-verse interlocking principle grants an effective andfast busbar protection. Additional hardware is notrequired, because the SIPROTEC devices incorpo-rate this function in their basic versions. Attentionshall be paid to motor feeders, which may feed abusbar fault in the generating mode. They cannotalways be treated as feeders without back-feeding.

Prospects for further applicationsIn the case of ring busbars with two incomingfeeders or single busbars with sectionalizer, a simi-lar reverse interlocking principle can be applied byway of short-circuit direction detection. This casewill be presented in a separate application.

Printed in Germany KGK 01.05 4.0 224 En 101149/6101D6342

Exclusion of liability

We have checked the contents of this manual foragreement with the hardware and software de-scribed. Since deviations cannot be precluded en-tirely, we cannot guarantee that the applicationsdescribed will function correctly in any system.

Copyright

Copyright © Siemens AG 2005. All rights reserved.

The reproduction, transmission or use of thisdocument or its contents is not permitted withoutexpress written authority. Offenders will be liablefor damages. All rights, including rights created bypatent grant or registration of a utility model ordesign, are reserved.

Registered trademarks

SIPROTEC, SINAUT, SICAM and DIGSI areregistered trademarks of Siemens AG. The othernames appearing in this manual may be tradenames the use of which by third parties for theirown purposes may infringe the rights of theowners.

Further application examples can be found on the Internet. Please visit us at: www.siprotec.com

www.siemens.com/ptd Order No.: E50001-K4451-A101-A1-7600

Published by

Siemens Aktiengesellschaft

Power Transmission and DistributionEnergy Automation DivisionPostfach 48 06

90026 NuernbergGermany

Documents

Catalogo Rele Siemens Ingles