September 2013

Baker Project No.

127829
Task Order 0036

Iraq Transmission System Protection Study

REVISED FINAL

MoE Protection Setting Policy

for

Transmission Protection System

Prepared for:

USACE-Middle East District

Contract No. W912ER-09-D-0002
Task Order 0036

Prepared by

US Army Corps of Engineers

Middle East District
Michael Baker Jr., Inc.
Moon Township, Pennsylvania
 TABLE OF CONTENTS
Iraq MoE Protection Setting Policy
USACE, Middle East District

Page No.
PURPOSE ............................................................................................................................. 1

1 SCOPE ........................................................................................................................... 1

2 REFERENCES ............................................................................................................... 1

3 PROTECTION SETTINGS.............................................................................................. 1

3.1 Feeders ................................................................................................................... 3

3.1.1 Auto-reclose ..................................................................................................... 12

3.1.2 Broken Conductor Protection .......................................................................... 13

3.2 400kV and 132kV Busbars .................................................................................. 14

3.3 Bus Sections and Bus Couplers ......................................................................... 15

3.4 Transformers ...................................................................................................... 16

3.4.1 400/132kV Auto-Transformers ...................................................................... 16

3.4.2 132/33kV and 132/11kV Double -Wound-Transformers ............................... 17

3.4.3 132/33/11kV Three-WindingTransformers ................................................... 18

3.5 Reactors ............................................................................................................... 20

3.5.1 Shunt Reactors ............................................................................................. 20

3.6 Circuit Breaker Fail Protection ........................................................................... 21

3.7 Check and System Synchronising ...................................................................... 21

3.8 400kV Overhead Line Overvoltage Protection .................................................... 22

3.9 Fault Recorders.................................................................................................... 22

APPENDIX A ....................................................................................................................... 24

i
PROTECTION SETTING POLICY FOR THE MOE’S TRANSMISSION SYSTEM

PURPOSE

This Document defines the Iraq Ministry of Electricity’s (MoE's) policy for the setting of main
protection, back-up protection and fault recorders on Iraq’s 400kV and 132kV systems.

This setting policy has been produced to meet the MoE’s specific requirements for the setting
of protection relays on the Iraqi system and is in general accordance with international best
practice.

1 SCOPE

This Setting Policy document details the protection settings required for feeders,
transformers, reactors, busbars and switchgear associated with MoE's 400kV, and 132kV
systems. This document also details the setting policy for the fault recording function whether
it is applied as standalone equipment or integrated within other equipment.

2 REFERENCES

This Policy makes reference to, or should be read in conjunction with, the following
documents:

MoE Application Policy for the Protection of the Iraq Transmission System

ENA-TS 48-3 – Issue 1 1977 - Energy Networks Association – Technical Specification 48-3
Instantaneous High-Impedance Differential Protection

3 PROTECTION SETTINGS

MoE’s policy for protection settings is laid out in the attached tables. For easy reference a
listing of the tables is given below. An explanation of the abbreviations employed in this
Policy can be found in Appendix A.

If the settings given for the overcurrent and earth fault protection in this Policy cannot be
obtained, the next higher available setting shall be used.

The MoE – Planning and Studies Office shall be consulted when the settings given in this
Policy cannot be achieved or are considered inappropriate.

In addition to the setting recommendations given in this Policy, cognisance should be taken
of relevant manufacturer's setting recommendations.

1
 List of Tables

Section Protection Page

3.1 Feeders 4

3.1.1 Auto Reclose 12

3.1.2 Broken Conductor Protection 13

3.2 400kV and 132kV Busbars 14

3.3 Bus Sections and Bus Couplers 15

3.4.1 400/132kV Auto-Transformers 16

132/33kV and 132/11kV Double-

3.4.2 Wound Transformers 17

3.4.3 132/33/11kV Three-Winding 18

Transformers

3.5.1 Shunt Reactors 20

3.6 Circuit Breaker Fail Protection 21

3.7 Check and System Synchronising 21

3.8 400kV Overvoltage Protection 22

3.9 Fault Recorders 22

2
3.1 Feeders

400kV feeder circuits are equipped with two Groups of protection - Group A and Group B.

For 400kV overhead line (OHL) circuits, Group A shall comprise a distance main protection
(PUTT), stub bus protection, three pole and single pole auto-reclosure, a communicating
directional earth fault protection (POTT), a non-directional 3 phase overcurrent back-up
protection, circuit breaker failure protection and an overvoltage protection. Group B shall
comprise a distance main protection (Blocking), stub bus protection, three pole and single
pole auto-reclosure and non-directional 3 phase overcurrent and earth fault back-up
protection.

For 400kV underground cable feeder circuits, Group A shall comprise a current differential
(unit) main protection with an integral distance protection function and non-directional 3
phase overcurrent and earth fault back-up protection. Group B shall also comprise a current
differential (unit) main protection with an integral distance protection function and non-
directional 3 phase overcurrent and earth fault back-up protection.

132kV feeder circuits are equipped with a single main protection and back-up protection.

For 132kV overhead line circuits the main protection shall be a distance protection (PUTT)
and the back-up protection shall be non-directional 3 phase overcurrent and earth fault.

The protection for 132kV underground feeder circuits and 132kV Overhead Line Feeders of 5
km or less shall comprise a current differential (unit) main protection with an integral distance
protection function and non-directional 3 phase overcurrent and earth fault back-up
protection.

3
Protection Setting
The settings shall be determined in accordance with the relevant
manufacturer's instructions to satisfy the following requirements:-

400kV and 132kV Plain Underground Cable Feeders and 400kV and 132kV
Overhead Line Feeders of 5 km or Less (Note 2)

(i) The minimum credible in zone fault current shall produce a multiple of relay
Unit fault setting of at least 1.5.

(ii) The protection shall operate for all types of faults within the protected zone
with a minimum fault resistance (RF) of 100 . The protection shall be set with
sensitivity consistent with security criteria. (Note 1).

(iii) Special care is required to compensate for the underground cable capacitive
current.

The settings shall be determined in accordance with the relevant

manufacturer's instructions to satisfy the following requirements:-

Distance 400kV and 132kV Plain Underground Cable Feeders and 400kV and 132kV
(Note 3 and 4) Overhead Line Feeders of 5 km or Less (Note 2)

Zone 1

(i) Zone 1 disabled (as overhead line circuits are of 5km or less and typically
cable circuits are usually relatively short)

Zone 2

(i) Reach at line angle - 150% of the protected circuit pps impedance.

Zone 2 should not reach through transformers at the remote busbar. If this
cannot be achieved, the Zone 2 reach of the distance protection shall be set to
cover 100% of the protected line and to provide back up protection for as much
of the shortest line out of the remote busbar as is possible without reaching
through the transformer.

(ii) Time delay - 0.4 s.

Zone 3

(i)Zone 3 forward reach at line angle = larger of 160% of protected circuit

pps impedance or (protected circuit pps impedance + 120% of longest
remote outgoing feeder pps impedance)

Zone 3 should not reach into the lower voltage circuits of transformers at
remote busbars. If this cannot be achieved, the Zone 3 reach of the distance
protection shall be set to cover 100% of the protected line and to provide
backup protection for as much of the longest line out of the remote busbar as is
possible without risk of non-discrimination with transformer lower voltage
protection.

4
 (ii) Time delay – 0.8 s.
Distance
(Note 3 and 4) 400kV (Group A) Distance Protection and 132kV Distance Protection on
Plain Overhead Line Feeders Greater than 5km

Zone 1

(i) Reach at line angle - 80% of the protected line pps impedance - PUTT
(ii) Time delay - 0 s.

Zone 2

(i) Single circuit OHL - Reach at line angle - not less than 120% of the
protected circuit pps impedance but not more than 100% of protected line
pps plus 50% of shortest line pps out of remote busbar.

Double Circuit OHLs - To cater for the effects of zero sequence mutual
coupling, ideally a setting of 150% of the protected line pps impedance
should be selected, provided that this does not exceed 100% of protected
line pps impedance plus 50% of shortest line pps impedance out of the
remote busbar. Where this cannot be achieved, advice should be sought
from the MoE Planning and Studies office. Consideration could then be
given to co-ordinating the Zone 2 time delays or of applying a reverse Zone
4 reach with a Zone 2 time delay at the remote end.
In addition to the above, Zone 2 should not reach through transformers at the
remote busbar. If this cannot be achieved, the Zone 2 reach of the distance
protection shall be set to cover 100% of the protected line and to provide back
up protection for as much of the shortest line out of the remote busbar as is
possible without reaching through the transformer.

(ii) Time delay - 0.4s

Zone 3

(i) Zone 3 forward reach at line angle = larger of 160% of protected circuit
pps impedance or (protected circuit pps impedance + 120% of longest
remote outgoing feeder pps impedance)

Zone 3 should not reach into the lower voltage circuits of transformers at
remote busbars. If this cannot be achieved, the Zone 3 reach of the distance
protection shall be set to cover 100% of the protected line and to provide
backup protection for as much of the longest line out of the remote busbar as is
possible without risk of non-discrimination with transformer lower voltage
protection.

(ii) Time delay – 0.8 s.

5
 Distance
(Note 3 and 4) 400kV (Group B) Distance Protection on Plain Overhead Line Feeders
Greater than 5km

Group B distance protection (Blocking Overreaching Scheme)

Zone 1, Zone 2 and Zone 3 settings are the same as for Group A distance
protection

Zone 4 (Blocking Signal Transmitting Zone)

(i) Reverse reach must be greater than the over-reach of the Zone 2 distance
relay at the remote end including a margin to cater for measurement
errors, CT/VT tolerances and inaccuracies in the circuit impedances.

Zone 4 = (1.2 x Zone 2remote end – Z1)/0.8

Where Z1 = positive sequence impedance of the protected circuit.

(ii) Time delay – 0 s.

6
 Distance 132kV Three-ended Overhead Line Feeders with a Teed transformer (e.g.
(Note 3 and 4) Teed mobile substation with associated 132kV Circuit Breaker)

Zone 1

(i) Reach at line angle - 80% of the protected line pps impedance
to the electrically nearer of the remote substations (i.e. the
remote end substation and the Teed transformer) – PUTT (2
ended )
(ii) Time delay - 0 s.

Zone 2

(i) Reach at line angle – 150% of the protected circuit pps (to the
furthest remote end).
(ii) Time delay – 0.4s

Zone 3

(i) Zone 3 forward reach at line angle = 100% of circuit pps

impedance up to Teed transformer plus 50% of the
transformer impedance. Checks shall be made to ensure that
the reach is adequate to cater for the effects of current infeed
from both circuit ends.
(ii) Time delay – 0.8 s.

Note: Where 132/33kV or 132/11kV mobile substations with typical

transformer ratings of 10MVA, 15MVA or 25 MVA are teed–off 132kV
transmission overhead lines, the distance protection at the line ends will not
normally see through the mobile substation transformer for MV faults and
therefore they do not pose a problem to the line end protection in this
respect. However, for 132kV phase to earth faults, the earthed 132kV star
point of each transformer contributes zero sequence current to an earth fault,
this infeed of zero sequence current affects the reach on the distance
protection and for this reason it is suggested that no more than two mobile
substations should be teed-off any 132kV over head transmission line.
Additionally, ratings of 132kV overhead lines range from approximately
50MVA to 275MVA, any mobile substation teed-off a 132kV transmission line
will reduce the transport capacity of the transmission line in proportion to the
rating of the mobile substation transformer, the number of mobile substations
should therefore be limited in order not to severely restrict the transport
capacity of transmission line, again a limit of two mobile substation is
considered to be reasonable.

General
Distance Residual Compensation
Protection
Settings Residual compensation factor shall be set in accordance with the relevant relay
manufacturer’s instructions (Note 5).

Relay Characteristic Angle

Relay characteristic angle - set in accordance with the relevant manufacturer's

instructions to match the line angle of the protected line.

7
 General Quadrilateral Resistive Reach Settings
Distance
Protection Distance protection resistive reach settings of the quadrilateral characteristics
Settings should accommodate the circuit resistance, fault arc resistance and tower
footing resistance (in the case of earth faults) whilst maintaining an adequate
margin with load impedance.
Minimum load impedance can be determined from the following formula:
Z load min = (Vmin/ 3)/Imax
Where: Vmin = minimum phase to phase voltage (say 0.9 x V nominal)
Imax = maximum load current
R load min = cos x Z load min
Where: = maximum load impedance angle (cos = power factor) related to
minimum load conditions
Typically the phase resistive reach should a have a margin of 40% and the earth
resistive reach a margin of 20% with the load minimum resistance.
In addition, relay manufacturers often recommend a limit to the magnitude of
the resistive reach settings in order to achieve specified relay accuracy and
performance, these limits shall not be exceeded.

Voltage Transformer Supervision

Voltage transformer supervision function shall be set to block protection

operation instantly and alarm after a time delay (not less than 3s).

Switch-on-to-fault

(i) Duration of switch-onto-fault function activation after line

energization
0.2 s – 1 s; 0.2s being the preferred setting.

(ii) Recognition of line energization – automatic pole dead logic (i.e. Using
voltage and current level detectors)

Power Swing Blocking

The manufacturer’s recommended settings shall be applied for 400kV and

132kV circuits and arranged to block all zones.

Distance Schemes

A Permissive Under Reach Transfer Trip scheme (PUTT) shall be applied for
the Group A distance protection on 400kV overhead line circuits and for the
distance protection on 132kV overhead line circuits.

A blocked overreach scheme shall be applied for the Group B distance

protection on 400kV overhead line circuits.

8
 General Underground cable circuits which employ a unit protection incorporating a
Distance distance protection function shall operate as a non-communicating plain
Protection distance protection.
Settings

Setting Groups

To cater for the effects of zero sequence mutual coupling, two setting groups
shall be applied for overhead line circuits which are run in parallel for the
majority of their length

(i) Group 1 – normal service - – caters for the following conditions:

Normal system operation - both circuits in operation.
One circuit in operation and the other isolated at one or both
ends.
One circuit in operation and the other isolated at both ends
with only one end earthed.

Settings as above for Group A and Group B 400kV and 132kV Plain
Overhead Line Feeders

(ii) Group 2 – for the case when one of the parallel circuits is in service, but
the other parallel circuit is isolated and earthed at both ends. For this
situation the active setting group of the distance protection on the in-
service circuit should be switched manually or through SCADA from
Setting Group 1 to Setting Group 2 which should be set as follows:

Zone 1:

To cater for the tendency of Zone 1 overreaching for faults beyond the
line end, the following reduced reach settings should be applied:

Zone 1 phase reach = 80% protected line pps impedance

Zone 1 earth reach = 65% of protected line pps impedance

Zone 2, Zone 3 and Zone 4:

Standard settings as for Setting Group 1

Fault Locator

Fault locator shall be activated. See section 3.9 for further information.

Back-up 400kV and 132kV Overhead Line and Underground Cable Circuits
Overcurrent
Back-up 3 phase non-directional overcurrent protection is applied to MoE 400kV
and 132kV feeder circuits.

The overcurrent protection shall be set to 130% of the seasonal maximum

continuous circuit rating with a standard inverse characteristic and a time
9
 multiplier setting which will allow a clearance time of around 1 sec for a remote
end fault with maximum fault infeed at the local end.

The current setting above should also be no more than 75% of the minimum
phase to phase fault current infeed for a remote end fault. If this condition is not
satisfied advice should be sought from the MoE Planning and Studies office.

Back-up 400kV and 132kV Overhead Line and Underground Cable Circuits
Earth fault
Back-up non-directional earth fault protection is applied to MoE 400kV and
132kV feeder circuits.
The earth fault protection shall be set to 20% CT nominal current with a
standard inverse characteristic and a time multiplier setting which will allow a
clearance time of around 1 sec for a remote end earth-fault with maximum fault
infeed at the local end.

The earth fault current setting above should also be no more than 40% on the
minimum earth fault current infeed for a remote end fault. If this condition is not
satisfied advice should be sought from the MoE Planning and Studies office.

Directional 400kV Overhead Line Circuits

Earth Fault
(communicat- An independent communicating, directional earth fault protection is applied to
ing) MoE 400kV overhead line circuits

The directional earth fault protection shall operate in conjunction with a tele-
protection channel to form a directional comparison permissive overreach
scheme with echo feature. The communication aided directional earth fault
protection shall be set to 10% CT nominal current with a 200ms time delay in
order to provide co-ordination with the distance protection function. The Relay
Characteristic angle shall be set in accordance with the relay manufacturer’s
recommendations (depending on the type of DEF relay, the relay characteristic
angle may be negative or positive).

Notes:

1 With load biased types of protection, 100 sensitivity may not be achievable during short duration
overloads; however for load current conditions of less than 1.5 times the relay nominal current, a
sensitivity of at least 100 shall be achieved.

2 All underground cable circuits and overhead line circuits of 5 km or less are to be equipped with
current differential unit protection.

For 400kV underground circuits and 400kV overhead line circuits of 5 km or less, a unit
protection relay with an integral distance protection function shall be provided for each of the
two groups of protection (i.e. Group A and Group B).

For 132kV underground circuits and 132kV overhead line circuits of 5 km or less, a single unit
protection relay with an integral distance protection function shall be provided.

The integral distance protection function in the 400kV Group A and the single 132kV unit protection
relays shall be enabled. The distance protection function shall operate as a plain distance
protection (non-communicating) scheme.

10
3 The Zone 2 and Zone 3 reach settings shall be consistent with loading requirements given in Note
4. Quadrilateral characteristics, where available, shall be used in preference to the shaped or
circular ones. The use of load blinders may be necessary to prevent load encroachment, in which
case the settings shall be determined in accordance with the relevant manufacturer's instructions.
In exceptional circumstances, where load encroachment cannot be avoided, consideration will be
given to reducing maximum line loading.

4 The maximum loading requirements for feeders shall be as follows:

For 400kV and 132kV feeders, the load rating shall be based on seasonal maximum
continuous circuit rating (depends on type of conductor used) at 30 load angle allowing a 30%
load encroachment safety margin i.e. (max continuous rating 0.7) xxx A at 30 load angle.

5 Special care must be taken in setting the residual compensation factor for cable circuits due to the
following: (i) The angle of the zero sequence impedance of cable circuits could be significantly
different from that of the positive sequence impedance, and/or (ii) The required residual
compensation factor could be negative.

11
3.1.1 Auto-reclose

Protection Setting

Auto On 400kV over head line circuits at one and a half circuit breaker configuration
Reclose substations, sequential reclosing of the busbar circuit breaker and tie (middle)
circuit breaker is recommended.
For 400kV over head line circuits where single pole circuits breakers are available,
single pole high speed auto reclosing is applied with the following settings:-
1
Dead time of busbar circuit breaker = 0.8 seconds
2
Dead time of tie (middle) circuit breaker = 1.2 seconds
3
Reclaim time = 30 seconds.

Note 1: These are typical settings, however, in some circumstances e.g. long lines,
may require a longer dead time to ensure that the secondary arc is
extinguished. If necessary power system studies should be performed to
establish the deionisation time for these circumstances.

Note 2: If the busbar circuit breaker fails to reclose, reclosing of the tie
(middle) circuit breaker should be blocked.

Note 3: The reclaim time should be compatible with the circuit breaker open-close
duty cycle.

For 132kV over head line circuits, three pole gang operated circuits breakers are
utilized and three pole high speed auto reclose is applied with the following
settings:-

Dead time = 0.8 second

Reclaim time = 30 seconds. (Note: the reclaim time should be

compatible with the circuit breaker open-close duty cycle).

12
3.1.2 Broken Conductor Protection

Protection Setting
Broken The following settings shall be applied for 400kV and 132kV overhead line circuits:-
Conductor
protection Where the broken conductor protection detection is based on measuring
the ratio of the standing negative phase sequence current to standing
positive phase sequence current the following settings should be applied:

I2/I1 = 200%

Time delay = 60 secs

Note: 60 secs is recommended in order to ensure co-ordination with other

protection devices.

13
3.2 400kV and 132kV Busbars

Protection Setting

Busbar High impedance busbar schemes based on the circulating current differential
principle with high impedance relays:

Settings in accordance with ENA-TS 48-3

Low impedance busbar schemes based on the low impedance biased differential
current principle – the settings shall be determined in accordance with the
manufacturer’s recommendations (Note 2).

Overall fault setting – between 10% and 50% of the fault current available for
faults on the busbars under minimum plant conditions (Note 1).

Differential Current/CT Supervision Alarm

(i) Current - 10% of the full load rating of the busbar (Note 3).
(ii) Time delay - 3 s.

Notes:
1 The fault settings of individual protection zones shall meet the following requirements:

(a) The fault setting of the check zone and the minimum fault setting of the individual
discriminating zones shall be equal to approximately 50% of the full load rating of the
associated busbar.

(b) The maximum fault setting of the individual discriminating zones shall not exceed the full load
rating of the associated busbar.

(c) When two or more sections of busbar are connected together via section disconnectors and
the combined discriminating zone gives rise to a fault setting in excess of the full load current
rating of the associated busbar, the minimum fault setting of the individual discriminating
zones shall be reduced below 50% to achieve a combined fault setting equal to or less than
the full load rating of the associated busbar.

2 The minimum threshold setting shall be set to the lesser of the following:

The continuous rating of the busbars

or
50% of the fault current available for faults on the busbars under minimum plant
conditions.

3 Subject to the setting not exceeding 50% of the anticipated full load current rating of any single
connected circuit. For low impedance protection working on biased differential current, the
differential current alarm shall be set to 10% of busbar rating, and time delay 3s. This is to prevent
a spurious alarm being generated with maximum through load with the worst possible CT error,
bearing in mind that for low impedance busbar protection schemes Class P CTs can be used in
lieu of Class X CTs.

14
3.3 Bus Sections and Bus Couplers

Protection Setting
400kV and 132kV
OC (IDMT)
Overcurrent Current Setting = As near as possible to busbar continuous current rating

Time multiplier setting = to ensure that under maximum fault condition, operation
is not faster than 1 sec.

SI Curve to IEC characteristic

EF (IDMT)
Earth fault 400kV and 132kV

Current Setting = As near as possible to the largest maximum loading of an out

going feeder

Time multiplier setting = to ensure that under maximum fault condition, operation
is not faster than 1 sec.

SI Curve to IEC characteristic

15
3.4 Transformers

3.4.1 400/132kV Auto-Transformers

Protection Setting

Overall
Differential (low
impedance Current – 10% - 60% rated ITX HV WINDING - preferred setting 15%.
biased
differential)

High Impedance
Circulating Settings in accordance with ENA-TS 48-3
Current
Differential

SI Curve to IEC characteristic

400kV 3 (i) Current – 150% transformer HV winding current rating - or as close as
Overcurrent possible
(ii) TM – set to achieve an operating time of 1.0 - 2.0 seconds under
maximum let through conditions.) (Note 1)

400kV Earth Fault SI Curve to IEC characteristic

(in CT residual (i) Current – 20% nominal CT secondary current
connection) (ii) TM – set to achieve an operating time of 2.0 seconds under maximum
let through conditions. (Note 1)

132kV 3 SI Curve to IEC characteristic

Overcurrent (i) Current – 150% transformer LV winding rating - or as close as
possible
(ii) TM - set to achieve an operating time of 0.3 - 0.4 seconds faster than
the HV overcurrent under maximum let through fault condition.

132kV Incomer SI Curve to IEC characteristic

Earth Fault (i) Current – 10 – 30% LV earth fault current
(in CT residual (ii) TM - set to achieve adequate coordination between the LV transformer
connection) incomer and the LV bus section/bus coupler earth fault protection
assuming the same fault current in both the transformer LV Incomer
earth fault protection and the bus section/bus coupler earth fault
protection.

Tertiary 11kV SI Curve to IEC characteristic

Overcurrent (i) Current – 150% transformer tertiary winding rating - or as close as
possible
(ii) TM - set to achieve an operating time of approx 0.3 – 0.4 secs faster
than the downstream 11kV overcurrent protection

(i) Alarm – 85 C or in accordance with the manufacturer’s

Oil recommendations.
Temperature (ii) Trip – 95 C or in accordance with the manufacturer’s
recommendations.

Winding (i) Alarm - 95 C or in accordance with the manufacturer’s

16
 Protection Setting
Temperature recommendations.
(ii) Trip - 105 C or in accordance with the manufacturer’s
recommendations

Notes:-
1 As per IEC 60076-5, the transformer must withstand 2 seconds under maximum let through fault
conditions.

.
3.4.2 132/33kV and 132/11kV Double -Wound-Transformers

Protection Setting

Overall
Differential
(low Current - 10% - 60% transformer HV winding rating - preferred setting 15%.
impedance
biased
differential)

132kV
restricted Low Impedance settings as per manufacturer recommendations
Earth Fault
Protection High Impedance settings in accordance with ENA-TS 48-3

SI Curve to IEC characteristic

132kV 3 (i) Current – 150% transformer HV winding rating - or as close as possible
Overcurrent (ii) TM – set to achieve an operating time of 1.0 -2.0 seconds under maximum
let through conditions. (Note 1)

132kV Earth SI Curve to IEC characteristic

Fault (i) Current – 20% nominal CT secondary current
(in CT (ii) TM – set to achieve an operating time of 2.0 seconds under maximum let
residual through conditions. (Note 1)
connection)

132kV Definite Time characteristic

Neutral (i) Current – Note 2
Standby (ii) Time Delay – 1 - 2 s (Note 1)
Earth Fault

33kV (11kV) SI Curve to IEC characteristic

(i) Current – 150% transformer 33kV (11kV) winding rating - or as close as
Overcurrent possible
(ii) TM - set to to co-ordinate with the 33kV (11kV) bus section/coupler and
outgoing feeder overcurrent protection.

17
 Protection Setting

33kV (11kV) SI Curve to IEC characteristic

Incomer (i) Current – 20% minimum earth fault current
Earth Fault (ii) TM - set to co-ordinate with the 33 kV (11kV) bus section/bus coupler earth
(in CT fault protection.
residual
connection) Due to the location of the earthing transformer, operation of the incomer earth
fault protection is restricted to earth faults in the transformer 33kV (or 11kV)
winding only.

Oil Oil - Alarm - 85 C or in accordance with the manufacturer’s recommendations.

Temperature Oil – Trip - 95 C or in accordance with the manufacturer’s recommendations

Winding (i) Alarm - 95 C or in accordance with the manufacturer’s recommendations.

Temperature (ii) Trip - 105 C or in accordance with the manufacturer’s recommendations.

Notes:-
1 As per IEC 60076-5, the transformer must withstand 2 seconds under maximum let through fault
condition.

2 As the transformer neutral carries earth fault current for any earth fault on the 132kV system, the
maximum transformer neutral current must be calculated for an external earth fault and a current
setting above this value must be selected. This will ensure that the transformer SBEF will not trip
for a feeder earth fault.

3.4.3 132/33/11kV Three-WindingTransformers

Protection Setting

Overall
Differential
(low impedance Current - 10% - 60% transformer HV winding rating - preferred setting 15%.
biased
differential)
132kV restricted
Earth Fault Low Impedance settings as per manufacturer recommendations
Protection
High Impedance settings in accordance with ENA-TS 48-3

SI Curve to IEC characteristic

132kV 3 (i) Current – 150% transformer HV winding rating - or as close as possible
Overcurrent (ii) TM – set to achieve an operating time of 1.0 -2.0 seconds under maximum
let through conditions. (Note 1)

132- kV Earth SI Curve to IEC characteristic

Fault (i) Current – 20% nominal CT secondary current
(in CT residual (ii) TM – set to achieve an operating time of 1.0 - 2.0 seconds under maximum
connection) let through conditions. (Note 1)

18
 Protection Setting

132kV Neutral Definite Time characteristic

Standby Earth (i) Current – Note 2
Fault (ii) Time Delay – 1 - 2 s (Note 1)

33kV (11kV) 3 SI Curve to IEC characteristic

Overcurrent (i) Current – 150% transformer 33kV (11kV) winding rating - or as close as
possible
(ii) TM - set to to co-ordinate with the 33kV (11kV) bus section/coupler.

33kV (11kV) SI Curve to IEC characteristic

Incomer (i) Current – 20% minimum earth fault current
Earth Fault (ii) TM - set to co-ordinate with the 33kV (11kV) bus section/bus coupler earth
(in CT residual fault protection and outgoing feeder earth fault protections.
connection)
Due to the location of the earthing transformer, operation of the incomer earth
protection is restricted to earth faults in the transformer 33kV (or 11kV) winding
only.

Oil Temperature Oil - Alarm - 85 C or in accordance with the manufacturer’s

recommendations.
Oil – Trip - 95 C or in accordance with the manufacturer’s recommendations

Winding (i) Alarm - 95 C or in accordance with the manufacturer’s

Temperature recommendations.
(ii) Trip - 105 C or in accordance with the manufacturer’s
recommendations.

Notes:-

1 As per IEC 60076-5, the transformer must withstand 2 seconds under maximum let through fault
condition.

19
3.5 Reactors

3.5.1 Shunt Reactors

Protection Setting

High Impedance
Circulating
Current Current - 10% - 25% reactor rated current - preferred setting 15% (Note 3)
Overall
Differential
Current – 400% reactor rated current
Time – Instantaneous
High Set
Overcurrent

SI Curve to IEC characteristic

3 (i) Overcurrent setting – 150% reactor rated current

Overcurrent (ii) TM - 0.15
(SI or DT)
(Note 2) or

DT (Definite Time) characteristic

(i) Overcurrent setting – 150% reactor rated current

(ii) Time delay - 1 s

SI Curve to IEC characteristic

(i) Earth Fault setting – 50% reactor rated current

Earth Fault
(ii) TM - 0.15
(SI or DT)
DT (Definite Time) characteristic

(i) Overcurrent setting – 150% reactor rated current

(ii) Time delay - 1 s

Oil and Winding Oil Temp - Alarm - 90 C or in accordance with the manufacturer’s
Temperature recommendations.
(Note 1) Oil Temp – Trip - 100 C or in accordance with the manufacturer’s
recommendations.

Winding Temp – Alarm - 110 C or in accordance with the manufacturer’s

recommendations.
Winding Temp – Trip - 120 C or in accordance with the manufacturer’s
recommendations.

Notes:-
1 To comply with manufacturer’s recommendations, a tolerance of 5 C is acceptable.

2 Definite time is the preferred characteristic

3 Guidance on the setting of high impedance circulating current differential protection schemes
is given in ENA-TS 48-3
20
3.6 Circuit Breaker Fail Protection

Protection Setting
Current Check Setting
Circuit
Breaker 10% of CT rated secondary current
Fail .

CBF Time Delay Setting

In the event of a circuit breaker failing to open within a pre-selected time, the breaker
failure protection (CBF) shall after a 140 ms time delay initiate tripping of all circuit
breakers connected to the same bus bar as the failed circuit breaker and if necessary
shall simultaneously initiate an intertrip of the remote circuit breaker/s associated with
the failed circuit breaker.

3.7 Check and System Synchronising

Check synchronising is used when switching two parts of a system which are weakly tied together
via other paths elsewhere in the system. In this synchronous system there should be no frequency
difference across the breaker but there may be significant differences in phase angle and voltage
magnitude due to differences in circuit lengths and loadings.

System synchronising is used when switching an islanded system in order to re-parallel it to the rest
of the transmission system. In this asynchronous system there may be a frequency difference
across the circuit breaker in addition to phase angle and voltage magnitude differences.

Standard settings for check and system synchronising functions are given below. For the majority
of cases these setting should be adequate, but unusual system configurations or operating
conditions may require that these setting be reviewed.

Protection Setting
The following settings shall be applied for 400kV:-
Check and The phase angle difference setting for check synchronising =
System 35°
Synchronising
The phase angle difference setting for system synchronising =
10°

The frequency difference setting = 0.1% (50 mHz slip frequency)

for check synch. Frequency difference setting for system synch
= 0.25% (125 mHz slip frequency).

The voltage difference = 10%.

The voltage setting for live line = 80%.

The voltage setting for dead line = 20%.

21
 The following settings shall be applied for 132kV:-
The phase angle difference setting for check synchronising =
20°

The phase angle difference setting for system synchronising =

10°

The frequency difference setting = 0.1% (50 mHz slip frequency)

for check synch. Frequency difference setting for system synch
= 0.25% (125 mHz slip frequency).

The voltage difference = 10%.

The voltage setting for live line = 80%.

The voltage setting for dead line = 20%.

3.8 400kV Overhead Line Overvoltage Protection

Protection Setting
Stage 1 Alarm Voltage setting = 1.15 x Vn
400kV OHL Time Delay = 20 secs
Overvoltage
Protection Stage 2 Trip Voltage setting = 1.20 x Vn
Time Delay = 3 secs

3.9 Fault Recorders

Protection Settings

Fault Triggering Settings (Note 1)

Recorder
(i) Phase Current – 150% of nominal current

(ii) Residual Current - 40% of nominal current.

(iii) Voltage – for feeders: V> = 120% Vnom (Note 2)

for busbars: V> =120% Vnom and V< = 80% Vnom

(iv) Frequency: f< = 49.5 Hz, f> = 50.5 Hz, Frequency gradient: ± 0.4 Hz/s.
To avoid triggering in case the feeder is manually switched off, frequency to be
triggered at busbars only.

(i) Sampling rate: 6 kHz for Voltage and Current (Note 3)

(ii) Sampling rate: 10Hz for frequency (slow scan - if applicable).

22
 Recording Duration:

(i) Pre-triggering duration: 150 ms minimum.

(ii) Fault duration: 200 to 3000 ms
(iii) Post fault duration: 200 ms.

Clock:

(i) Time – GMT + 4.

(ii) Clock synchronization: 1 per hour minimum.

Channel Labeling

The analogue and event channels shall be labeled with their appropriate name.
e.g. Red phase current – IR, Group A Main Protection Trip Relay - FMP TR.

Fault Locator (Notes 4, 5, 6 & 7)

Fault locator shall be activated for feeder circuits.

Notes:-
1 If nuisance triggering is experienced then the triggering levels should be adjusted accordingly
for affected circuits.

2 Feeder under-voltage triggering is to be disabled to avoid triggering in case the feeder is

manually switched OFF.

3 Where the fault recording function is integrated within a protection relay, this setting may be
fixed by the protection equipment and so may not be able to be set differently for fault
recording.

4 The required distance to fault setting information (line impedance per km and line length)
should be recorded with the equipment’s other setting information as part of the settings
schedule.

5 Where more than one equipment type on a feeder bay, has a fault location facility, (e.g.
distance relay and bay controller with integrated fault recorder), then all equipment shall be
set and enabled to provide confirmatory evidence of a fault location.

6 The fault locator need not be set for circuits of short route length Typically, these will be
circuits that are so short that a distance relay could not be deployed e.g. the distance relay
does not have the settings capability for such a short distance (say < 5km) or no 3 phase VTs
exist on a cable circuit.

7 For current Differential schemes, fault location with measurements from both ends of the
line should be activated.

23
 Appendix A - List of Abbreviations

APPENDIX A

LIST OF ABBREVIATIONS

MoE Protection Setting Policy Sept. 2013

 Appendix A - List of Abbreviations

pps - positive phase sequence.

nps - negative phase sequence.

Z1 - positive sequence impedance of one circuit of a double-circuit line in which the other
circuit is open circuited at each end.

Z0 - zero sequence impedance of one circuit of a double-circuit line in which the other
circuit is open circuited at each end.

RF - fault resistance.

HSOC - high set overcurrent relay.

OC - instantaneous overcurrent relay.

OCI - IDMT overcurrent relay.

DT - definite time overcurrent relay.

SI – Standard Inverse 30 times Definite Time Curve (overcurrent or earth fault protection)

TM - time multiplier for overcurrent or earth fault protection function.

- three phase.

GMT - Greenwich Mean Time.

PUTT – Permissive Under-reach Transfer Trip

POTT – Permissive Over-reach Transfer Trip

VT – Voltage Transformer

CT – Current Transformer

SBEF – Standby Earth Fault

DEF - Directional Earth Fault

MoE Protection Setting Policy Sept. 2013