ohl siprotec applications

Siemens PTD EA · Applications for SIPROTEC Protection Relays · 2005 73

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

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Siemens PTD EA · Applications for SIPROTEC Protection Relays · 200574

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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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


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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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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

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Fig. 61 General settings for synchronism and voltagecheck

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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

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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

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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

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Fig. 67 Time synchronization and time format settings

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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

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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

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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

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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

Fig. 1 SIPROTEC 7SD5 line differential protection relay

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

ohl siprotec applications

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