17648763-CBIP-Recommondations.pdf

BASIC CONCEPTS
OF PROTECTION OF
IN A 400KV SUBSTATION
( as Per CBIP Recommendations)
P. GOPALA KRISHNA
ADE/400KV/APTRANSCO

NORMS OF PROTECTION FOLLOWED IN UTILITIES
Sr.No VOLTAGE MAIN- 1 PROTECTION MAIN-2 PROTECTION/ BACKUP PROTECTION
1. 11 KV LINES 2 O/L + E/F ( 51 + 51N ) -
2. 33 KV LINES 3 O/L + E/F ( 51 + 51N ) -
3. 66 KV LINES SWITCHED DISTANCE SCHEME OR
NUMERICAL DISTANCE SCHEME (21P+ 21N)
DIRECTIONAL O/L & E/F RELAYS WITH HIGH
SET ( 67 + 67N )
4. 132 KV LINES
5. 220 KV LINES
NON SWITCHED DISTANCE SCHEME OR
NUMERICAL DISTANCE SCHEME (21P + 21N)
SWITCHED DISTANCE SCHEME OR
NUMERICAL DISTANCE SCHEME (21P+ 21N)
6. 400 KV LINES NUMERICAL DISTANCE SCHEME (21P + 21N)
+ in BUILT DEF RELAY(67N)
NUMERICAL DISTANCE SCHEME (21) OR LINE
DIFFERENTIAL SCHEME (87L) WITH 67N
7. 765 KV LINES NUMERICAL DISTANCE SCHEME (21P + 21N)
+ in BUILT DEF RELAY(67N)
NUMERICAL DISTANCE SCHEME (21) OR LINE
DIFFERENTIAL SCHEME (87L) WITH 67N
The DEF 67N is in built to detect high resistance fault which distance relay cannot.
REACH SETTINGS
ZONE-1: 80-85% OF PROTECTED LINE
ZONE-2: 120% = 100% OF MAIN LINE + 50% OF SHORTEST LINE AT OTHER END / 6O% OF T/F
ZONE-3: 200% = 100% OF MAIN LINE + 100% OF LONGEST LINE AT OTHER END / 100% OF T/F
ZONE-4: 100% OF MAIN LINE + (100% OF SHORTEST LINE + 100% OF LONGEST LINE)AT OTHER END.
R-REACH: UP TO LOAD POINT ENCROACHMENT
TIME SETTINGS
ZONE-1: INSTANTENEOUS
ZONE-2: 0.3 SEC FOR SHORT LINES & 0.5 SEC FOR LONG LINES for Discrimination
ZONE-3: 0.6 SEC
ZONE-4: 0.9 SEC

CBIP Guidelines on Protection
400 kV Lines
¾ NEED OF LINE PROTECTION
The line protection relays are required to protect
the line and clear all types of faults on it within the
shortest possible time with reliability, selectivity
and sensitivity.
The line protection relays shall be suitable for
use with capacitive voltage transformers having
passive damping and transient response as per IEC
186

¾ There should be two independent High Speed Main
protection schemes called Main-I and Main-II with
at least one of them being carrier aided non-
switched Three/ Four zone distance protection.
¾ The other protection may be a phase segregated
current differential (this may require digital
communication), phase comparison, directional
comparison type or a carrier aided non-switched
Distance protection.
¾ If Main-I and Main-II are both distance protection
schemes, then they should be preferably of
different types. They need not necessarily of
different make.
¾ Both should be suitable for single and three phase
tripping.
400kV Lines

¾ADDITIONAL PROTECTION
ii) Two stage Over Voltage Protection.
iii) Auto-reclose relay suitable for 1-ph / 3-ph (with
dead line charging and synchro-check facility).
iv) Sensitive IDMT Directional E/F Relay(67N).
According BUSBAR Arrangements
(One & Half Circuit Breaker System)
v) STUB Protection
vi) TEED Protection

¾ There should be at least one carrier aided non-
switched three zone Distance protection scheme.
¾ In addition to this another non-switched /
switched distance scheme or directional over
current and earth fault relays should be provided
as back up.
¾ Main protection should be suitable for single and
three phase tripping.
¾ Auto-reclose relay suitable for 1 ph / 3 ph
reclosure shall be provided.
¾ In case of both line protections being Distance
Protections, IDMT type E / F relay shall also be
provided additionally.
220 kV Lines

(i) If found necessary, at certain locations, out of step tripping
relays shall be provided for islanding the system during
disturbances.
(ii) For short line application distance relays should have shaped
characteristics for ground faults and be used in permissive
over reach mode with weak end infeed logic. Further, if it is a
double circuit line, current reversal should also be available.
(iii)O/V relay for 400 kV lines shall be connected to trip
concerned line breaker, start LBB, block auto reclosure and
send direct trip command.
(iv)The directional earth fault relay recommended along with the
distance relay should be seen as a supplement to it and not as
a back up. It helps to detect very high resistance fault which
distance relay cannot.
(v)HVDC Systems connected to AC networks with low short circuit
levels can influence AC line protections in its vicinity. This
aspect needs to be looked into on case to case basis.
SPECIAL COMMENTS

I. Zone-I: to be set to cover 80-85% of
protected Line length.
II.Zone II: to be set to cover minimum 120%
of length of principle line section.
However, in case of D/C lines 150%
coverage must be provided to take care of,
under reaching due to mutual coupling
effect but, care is to be taken that it does
not reach into next lower voltage level.
SETTING CRITERIA
Reach settings of distance protection

(iii) Zone-III:
For 400kV lines Zone-III to be set to cover120% of
principle section plus adjacent longest section subject
to a reach restriction so that it does not reach into next
lower voltage level.
For 220 kV lines, Zone-III reach may be provided to
cover adjacent longest section if there is no provision of
LBB or all protection are connected to single DC source
at remote end substation.
(iv) Resistive reach should be set to give maximum
coverage subject to check of possibility against load
point encroachment considering minimum expected
voltage and maximum load. Attention has to be
given to any limitations indicated by manufacturer in
respect of resistive setting vis-a-vis reactance setting.

¾ A Zone-II timing of 0.3 second is recommended. If a
long line is followed by a short line, then a higher
setting may be adopted on long line to avoid
indiscriminate tripping through Zone-II operation on
both lines.
¾ Zone-III timer should be set so as to provide
discrimination with the operating time of relays
provided in subsequent sections with which Zone- III
reach of relay being set overlaps.
Time setting of distance protection

¾ Low set voltage may be set at 110% with a typical
time delay of 5 seconds.
¾ A time grading of 1 second may be provided between
relays of different lines at a station.
¾ Longest time delay should be checked with expected
operating time of over fluxing relay of the transformer
to ensure disconnection of line before tripping of
transformer.
¾High set stage may be set at 150% with a time delay
of 100 m second.
O / V Protection
¾ Decisions pertaining to allowing which Zone to trip
and which to block should be taken based on system
studies on case to case basis.
3.4 PSB Function Associated with Distance Relays

i) Four Independent Zones (at least 3).
ii)Seperate Measurement for Ph-Ph & Ph-E faults (Non Switched
scheme).
iii) Capable of 1-Ph & 3-Ph tripping
iv) Directional Characteristics (Mho or quad or any other suitably
shaped) for all zones.
v) Capable of Operation for close-up 3-ph faults & SOTF.
vi) Adjustable characteristic angle to match line angle wherever
applicable.
vii) Accuracy ≤ 5% for Z1 & ≤ 10% for Z2, Z3, Z4 for Set Value of
Reach Measurement.
vii) Accuracy ≤ 5% for Z2, Z3, Z4 for Set Value of Time
Measurement.
viii) Variable residual compensation
ix) Power swing blocking feature shall include.
x) Fuse Failure Protection & Monitor feature shall include.
xi) Week End Infeed Logic(27 WI) feature shall include.
xii) Distance To Fault Locator(21 FL).( % or Km or Miles or R+jx ).
xiii) for Short Line applications it should have suitably shaped
characteristics for ground faults and be used in POTT mode with
WI Logic. Further, if it is a DC Line, current reversal logic should
also be available.
xiii) any other features required by customer
DISTANCE PROTECTION REQUIREMENTS

i) shall be a unit system of protection
ii) Shall be Phase Comparison type.
iii) Shall be suitable for operation with one signally
channel.
iv) Shall be high sensitivity for all types of faults.
v) Shall be capable of 1-Ph & 3-Ph tripping .
vi) Shall have facility for Blocking/Permissive trip
modes.
vi) Shall have a facility for Direct Transfer Tripping.
vii) Shall have comprehensive alarm and test facilities.
vii) shall not affected by Heavy Load Transfer, Power
Swings, CT saturation, CT Phase errors, Propagation
delays, Capacitance current etc., as is typical of unit
protection.
viii) any other features required by customer.
PHASE COMPARISION PROTECTION REQUIREMENTS

i)shall be a unit system of protection
ii)shall be all Digital Multi Microprocessor based, designated for use with
Modern Digital Telecommunication system multiplexer confirming to ITU-
T(CCITT) Specifications and Fibre Optic Medium .
iii) Each Phase Current shall be separately evaluated at both ends for both
Amplitude and Phase.
iv) Shall be suitable of 1-Ph & 3-Ph tripping and Auto-reclosing.
v) The message Transmitted by the relay to other end shall include
information on current, supervision information, CT Saturation detection,
Synchronization of terminals etc.
vi) The Measurement shall be stabilized Phase by Phase for CT Saturation.
vii) The Communication delay shall be continuously measured and
automatically compensated for in the differential Measurement.
viii) Communication telegram shall have error detection and correction
feature.
ix) Suitable Programmable evaluation algorithm will be provided to ensure
proper security and dependability of the message.
x) The Relay shall have Communication port for Remote Monitoring,
Programming and Control.
xi) The Direct inter trip signal shall be transmitted as part of telegram.
xii) any other features required by customer.
PHASE SEGREGATED LINE DIFFERENTIAL PROTECTION

The Relay shall have following features.
i) Have a High drop off to Pick ratio.
ii) Have adjustable setting range for voltage & time.
iii) Have Two stages.
iv) Low set stage shall monitor any one Phase to
Phase Voltage and shall be associated timer.
v) High set stage shall monitor all three Phase to
Phase Voltage and shall be associated timer.
vi) Over Voltage relay for 400KV Lines shall be
connected to trip concerned Line Breaker(s), Start
LBB, Block A/R and send Direct Trip command.
OVER VOLTAGE PROTECTION REQUIREMENTS

GENERAL
¾ The auto-reclosing of power lines has become a
generally accepted practice.
¾ Reports from different parts of the world show that
in certain networks in region subject to a high
lightening intensity only about 5% of the faults are
permanent.
¾ Auto reclosing therefore provides significant
advantages.
¾ Outage times will be short compared to where
station personnel have to re-energize the lines after
a fault.
¾ In interconnected networks auto-reclosing helps in
maintaining system stability

Recommendations for provisions of auto-reclosing
¾ Presently 1 phase high speed auto-reclosure (HSAR)
at 400kV and 220kV level is widely practised including
on lines emanating from Generating Stations and the
same is recommended for adoption.
¾ If 3-phase auto-reclosure is adopted in future the
application of the same on lines emanating from
generating stations should be studied and decision
taken on case to case basis.

¾ FAULTS ARE THREE TYPES
1. TRANSIENT FAULT: These are cleared by the
immediate tripping of Circuit Breakers and do
not reoccur when the line is re-energized.
2. SEMI-PERMANENT FAULTS: These require a time
interval to disappear before a line is charged
again.
3. PERMANENT FAULTS: These are to be located and
repaired before the line is re-energized.
¾ About 80-90% of the faults occurring are transient
in nature. Hence the Automatic Reclosure of
breaker (after tripping on Fault) will result in the
line being successfully re-energized.
¾ ADVANTAGES:
A. Decreasing outage time.
B. Improving Reliability.
C. Improving system stability.
D. Reduce fault damage and Maintenance Time.

1. BASED ON PHASE
A. THREE PHASE AUTO-RECLOSING.
B. SINGLE PHASE AUTO-RECLOSING.
2. BASED ON ATTEMPTS OF RECLOSURE
A. SINGLE SHOT AUTO-RECLOSING.
B. MULTI-SHOT AUTO-RECLOSING.
3. DEPENDING ON SPEED:
A. HIGH-SPEED AUTO-RECLOSING.
B. LOW SPEED OR DELAYED AUTO RECLOSING.
4. CHOICES OF EHV SYSTEM:
A. CHOICE OF ZONE:
This should normally kept in Zone-1. It is a Zone-1 fault
and SLG fault only auto-reclosure is comes in to picture.
In other zones the auto reclosure is blocked.
TYPES OF AUTO-RECLOSING

SETTING CRITERIA
Dead Time
¾ DEAD TIME: The time between the Auto-reclosing
Scheme being energized and the operation of the
contacts which energize the Circuit Breaker closing
circuit.
¾Auto- reclosing requires a dead time which exceeds
the de-ionising time
¾ Time required for the de-ionising of the fault path
depends on:- arcing time, fault duration, wind
conditions, circuit voltage, capacitive coupling to
adjacent conductors, etc.
¾ Single phase dead time of 1.0 sec is recommended for
both 400kV and 220kV system.

Reclaim Time
¾ RECLAIM TIME: The Time Following a successful closing operation measured
from the instant the Auto-Reclosing relay closing contacts make which must
elapse before the Auto-Reclosing relay initiates another reclosing attempt. In
other words, it may be said to be the time between 1st and 2nd Auto-Reclosure.
¾The time during which a new start of the auto-reclosing equipment is blocked.
¾ If reclosing shot has been carried out and the line is energized and a new fault
occurs before the reclaim time has elapsed, the auto-reclosing equipment is
blocked and a signal for definite tripping of the breaker is obtained.
¾ After the reclaim time has elapsed, the auto-reclosing equipment returns to the
starting position and a new reclosing sequence can occur.
¾ The reclaim time must not be set to such a low value that the intended
operating cycle of the breaker is exceeded, when two faults incidents occur close
together.
¾If the breaker is closed manually, the auto reclosing equipment is blocked and
cannot start again until the reclaim time has elapsed.
¾ For the breaker to be used for auto-reclosing, it is essential that it has the
operating mechanism and breaking capacity necessary for it to be able to
perform the auto-reclosing sequences required.

2.3 Circuit Breaker Requirement
¾ According to IEC Publication 56.2, a breaker must be
capable of withstanding the following operating cycle
with full rated breaking current:
O + 0.3 s + CO + 3 min + CO
¾ The recommended operating cycle at 400kV and
220kV is as per the IEC standard.
¾ Reclaim time of 25 sec is recommended.

i) Having 1-Ph and/or 3-ph reclosing facilities.
ii) Have a continuously Variable Single Phase Dead
Time.
iii) Have a continuously Variable Three Phase Dead
Time.
iv) Have a continuously Variable Reclaim Time.
v) Incorporate a facility of selecting 1-Ph / 3-Ph / 1-Ph
& 3-Ph Auto-reclose and Non-auto reclosure modes.
vi) Having a facilities for selecting check synchronising
(SC) or dead Line charging (DLC) features.
vii) Be of high speed single shot type.
viii) Suitable relays for SC and DLC should be included
in the overall auto-reclose scheme.
viii) Should allow sequential reclosing of Breakers in
One and Half Breaker or Double Breaker
Arrangement.
AUTO-RECLOSING RELAY REQUIREMENTS

PROTECTIONS which BLOCK A/R RELAY are
i) Zone 2/3/4 of Distance Protection.
ii) Carrier fail Conditions.
iii) Circuit Breaker problems.
iv) Direct Transfer Trip signal Received.
v) LBB/BFR relay operates.
vi) Line Reactor Protections.
vii) Over Voltage Protection.
viii) Busbar Protection Operated

GENERAL & NEED OF PROTECTION FOR TRANSFORMER
¾ A Power Transformer is a very valuable and vital link
in a Power Transmission system
¾ Fast protection system for transformer is essential to
minimize the damage in case of an internal fault with
suitable back-up protection scheme to take care of
uncleared system faults.
¾ Faults in a Transformer occur due to insulation break-
down, ageing of insulation, overheating due to over-
excitation, oil contamination and leakage or reduced
cooling.
¾ To give an early warning and to minimise the damage
in case of fault it is necessary to equip it with monitors
and protective relays.

Power T/F Protection is usually installed :
A. Internal SCs and E/Fs in the T/F and its connected
circuits.
B. External faults on other circuits. (Back-up
protection)
C. Abnormal service conditions such as overload & over
voltage.
¾ PROTECTION DEVICES INBUILT OR MOUNTED ON
POWER T/F
A. Oil immersed power T/F usually have a gas detector
and oil surge Detector (buchholz alarm & trip devices),
which are excellent for detecting internal faults.
B. Load tap-changer compartments may have a similar
over pressure device.
C. Temperature monitors for oil & winding provide
good O/L Protection.
D. PRD is provided to safe guard the T/F from High
Pressures.

TRANSFORMER DIFFERENTIAL PROTECTION
It is widely used as instantaneous protection for short
circuit faults with in the differential zone. This is
treated as Main-1 Protection for T/F. The most common
type of protection is the current restraint type. Some
type of DIFFERENTIAL RELAYS require interposing CTs
for CT ratio matching and/or phase shift. High
impedance differential protection can be used on auto
T/F or ICT & Reactors. It covers one galvanically
interconnected winding (Winding Differential). But not
a separate tertiary winding. It requires a three phase
set of CTs at the neutral side of winding.
In case of Auto Transformer, 3-ph High
Impedance Differential relay is used as Main-2
Protection in addition to Percentage Biased Differential
Protection is used as Main-1.

RESTRICTED EARTH FAULT PROTECTION
An Alternative to Differential Protection that can be
applied to AT/Fs. A Circulating Current System is
arranged between Equal Ratio CTs in the two Groups of
Line Connections and the Neutral End Connections. The
Line CTs can be connected in Parallel to A Single Element
Relay, Thus providing a Scheme Responsive to E/F Only.
If CTs are fitted in Each Phase at the Neutral End of the
Windings and a Three-Element Relay is used, A
Differential System can be provided, giving Full
Protection against Phase and Earth Faults. This Provides
High-speed Sensitive Protection. It is Unaffected by
Ratio Changes on the T/F due to Tap-changing and is
immune to the Effects of Magnetizing In Rush Current. It
does not respond to Inter-turn Faults. In Addition, This
Scheme does not respond to any Fault in a Tertiary
Winding. Unloaded Delta- connected Tertiary Windings
are often not Protected.

BACK UP PROTECTION
A. OVER CURRENT & EARTH FAULT PROTECTION.
(67P&N, HV & LV)
B. UNDER IMPEDENCE / DISTANCE ( Z<)(21T).
C. NEUTRAL DISPLACEMENT PROTECTION (Un>).
OTHER TYPES OF RELAYS
A. OVER VOLTAGE RELAY (U >).
B. OVER FLUX/ EXCITATION (V/F >)
( INVERSE TIME & DIFENITE TIME).
FOR 400KV/220KV & 765/400KV TRANSFORMERS
BOTH SIDES( i.e HV & LV) OVER FLUX RELAYS ARE
PROVIDED BECAUSE BOTH SIDES HAVING GRID.
C. AT/F NEUTRAL CURRENT RELAY (51N).
D. OVER LOAD RELAY FOR ALARM (51).

CAPACITY OF
TRANSFORMER
HV VOLTAGE HV CURRENT IV VOLTAGE IV CURRENT
315 MVA 400 KV 454.68 A 220 KV 0826.68 A
500 MVA 400 KV 721.71 A 220 KV 1312.20 A
630 MVA 400 KV 909.35 A 220 KV 1653.37 A
NORMALLY ADOPTED
POWER TRANSFORMERS CAPACITIES
BY UTILITIES
IN 400KV / 220KV SYSTEM
CAPACITY OF
TRANSFORMER
HV VOLTAGE HV CURRENT IV VOLTAGE IV CURRENT
630 MVA 765 KV 0475.48 A 400 KV 0909.35 A
750 MVA 765 KV 0566.05 A 400 KV 1082.56 A
1000 MVA 765 KV 0754.73 A 400 KV 1443.42 A
1500 MVA 765 KV 1132.10 A 400 KV 2165.14 A
IN 765KV / 400KV SYSTEM

NORMS OF PROTECTION FOLLOWED BY UTILITIES
FOR POWER TRANSFORMERS & AUTO TRANSFORMERS
3 OL +
1 DIR EL
(51P +
67N)
400 / 132
100, 200
& 250
7
HV & LV
REF 64
220 / 66
31.5, 50 &
100
6
66 / 33
7.5 , 16
& 25
2
BUCHHOLZ
OVER FLUX
OLTC OSR
PRV/PRD
OIL TEMP
WDNG TEMP
132 / 33
16 , 31.5
50 & 80
4
765 / 400
630, 750,
1000 & 1500
10
3 DIR OL
(HIGHSET)
+
1 DIR EL
(HIGHSET)
3 DIR OL
(HIGHSET)
+
1 DIR EL
(HIGHSET)
400 / 220
315, 500
& 630
9
OVER LOAD
ALARM
RELAY +
NEUTRAL
CURRENT E/F
RELAY
87
TH
/
64
REF
ICT
/
AUTO
TFR
220 / 132
100 & 160
8
2
WINDING
TRANSFORMER
(STAR/STAR)
T
Y
P
E
220 / 33
31.5, 50
5
3
OVER
LOAD
+
1
DIRECTIONAL
EARTH
FAULT
RELAY
(
51P
+
67N)
HV
REF
(64)
132 / 11
7.5 , 16 ,
25 & 31.5
3
64REF
IS
1-PH
HIGH
IMPEDANCE
DIFFERENTIAL
RELAY
87TH
IS
3-PH
HIGH
IMPEDANCE
DIFFERENTIAL
RELAY
(PRINCPLE
:
CIRCULATING
CURRENT)
BUCHHOLZ,
OLTC OSR
OIL TEMP
WDNG TEMP
3
OVER
LOAD
+
1
EARTH
FAULT
RELAY
(
51
)
3 OL +
1 EL (51)
NIL
87
TL
DIFFERENTIAL
RELAY
(
LOW
IMPEDANCE
PERCENTAGE
BIASED
PHASE
SEGREGATED
DIFFERENTIAL
RELAY
PRINCIPLE:
MERZ
PRICE)
66 / 11
7.5 & 16
1
LV
HV
PROTECTION
SPECIAL
PROTECTION
ADDITIONAL
PROTECTION
BACK UP
PROTECTION
MAIN-2
MAIN-1
VOLTAGE
RATIO IN
KV
CAPACITY
IN
MVA
S.N
o

DIFFERENTIAL PROTECTION REQUIREMENTS
i) Triple Pole with Individual Indication.
ii) Have Unrestrained instantaneous high-set which
should not operate during in rush.
iii) Have an adjustable or Multi Bias setting
iv) Have second Harmonic or other inrush proof
features and should be stable under normal Over
Fluxing conditions, Magnetizing inrush proof feature
shall not be achieved through any intentional time
delay e.g. use of timers to block relay operation or
using disc operated relays.
v) Have one Bias Winding Per Phase for CT input.
vi) Have an adjustable operating Current.
vii) Have an operating time not grater than 30 msec at
5 times of setting.
viii) The scheme shall have facility for ration and
phase angle correction either through auxiliary
transformer or through in-built Provisions.

REF PROTECTION REQUIREMENTS
i) shall be single Pole.
ii) Have an operating current sensitivity at least 10%
of nominal current.
iii) be tuned with system frequency.
iv) Have a suitable non-linear resistor to limit the peak
voltage during in-zone faults in case of high
impedance type.
v) Shall be high or low impedance Principle type.
vi) Whenever separate Ph-wise CTs are available on
neutral side of T/F, a 3-pole High Impedance Relay
may be provided instead of 1-ph REF.

BACKUP O/C PROTECTION RELAY REQUIREMENTS (HV&LV)
i) Shall be 3-pole type.
ii) Have IDMT characteristic (direction on T/F)
iii) Have a Variable setting range of 50-200% of rated current.
iv) Have a Characteristic angle, 30/45 deg Lead.
v) Shall include high unit having low transient over-reach and
variable setting range of typically 500-2000% of rated current.
vi) include hand reset indicators per phase.
BACKUP E/F PROTECTION RELAY REQUIREMENTS (HV&LV)
ii) Have IDMT characteristic (direction on T/F)
iii) Have a Variable setting range of 20-80% of rated current.
iv) Have a Characteristic angle, 45/60 deg Lag.
v) Shall include high unit having low transient over-reach and
variable setting range of typically 200-800% of rated current.
vi) include hand reset indicators.

OVER LOAD ALARM RELAY REQUIREMENTS
OVER FLUX PROTECTION RELAY REQUIREMENTS (HV&LV)
ii) Shall be of definite time over current type.
iii) Shall have a continuously variable current range of 50-200%
of rated current and continuously variable timer setting range
of 1-10 sec.
iv) Shall have a drop off to pickup ratio of 95% better.
i) Shall be Phase to Phase connected.
ii) Operate on the Principle of Measurement of Voltage to Frequency
ratio.
iii) Have inverse time characteristics compatible with transformer over
fluxing.
iv) Provide on independent alarm with a definite time delay at value of
V/F between 100% to 130% of rated value.
v) Have high resetting ratio of 98% or better.
vi) The T/F, V/F relay has been recommended on both sides of ICTs.

SPECIAL COMMENTS
i) In case of Breaker and Half schemes, the differential Protection
CTs associated with Main and Tie Breakers should be
connected to separate bias windings and these should not be
paralleled in order to avoid false operation due to dissimilar CT
transient response.
ii) The current setting of the Backup O/C relay shall be set above
the expected maximum load current so as to allow possible
overload an account of loss of one of the parallel T/Fs.
iii) Over Load relay shall be set at 110% of rated current with
delay of 5 sec. This shall be connected to give only alarm and
not for tripping.
iv) Whenever separate Ph-wise Bushing CTs are available on
neutral side of T/F, a 3-pole High Impedance Relay may be
provided instead of 1-ph REF.
v) Over-fluxing relay shall be provided on the untapped winding
of the Transformer

TYPES OF REACTORS
¾ A. BASED ON REACTOR CONNECTION
i) SHUNT REACTOR.
ii) SERIES REACTOR.
¾ B. BASED ON REACTOR LOCATION
i) BUS REACTOR
ii) LINE REACTOR
iii)THROUGH CB TO THE TERITIARY WNDG OF ICT
¾ C. BASED ON CONTROL
i) 3-PH OIL IMMERSED REACTOR WITH GAPPED IRON
CORE.
ii) THYRISTOR CONTROLLED REACTOR (STATIC VAR
COMPENSATOR)

NEED OF SHUNT REACTOR
The purpose of the Protection Relaying is to
disconnect the Reactor and limit damage in case of
internal short circuits, Earth faults, inter-turn faults
and over voltage or over load. The reactor forms
certain impedance for rated frequency, and as it is
shunt connected, as over load may be caused by
over voltage or harmonics in voltage and current.
Shunt Reactors are used in EHV systems to limit the
over voltages due to capacitive VAR Generation
(Ferranti effect) in Long transmission Lines.
PURPOSE OF SHUNT REACTOR

PROTECTION DEVICES MOUNTED ON REACTOR
A) Oil immersed Reactor usually have a Gas
detector and Oil surge. Detector (Buchholz Alarm &
Trip devices), which are excellent for detecting
internal faults.
B) Temperature Monitors for Oil & Winding provide
good Over Load Protection.
C)Pressure Relief Device is provided to safe guard
the Reactor from High Pressures.

RECOMMENDED PROTECTIONS FOR REACTOR
1) Reactor Differential Function.
2) Reactor REF Protection.
3) Reactor Backup Protection ( Impedance type or Def
Time O/L&E/F).
4) Protections and Monitors built in to Reactor.

DIFFERENTIAL PROTECTION REQUIREMENTS
i) Shall be Triple Pole Type.
ii) Have an operating current sensitivity at least
10% of nominal current.
iv) Have an operating time not grater than 30 msec
at 5 times of setting.
v) Have a suitable non-linear resistor to limit the
peak voltage during in-zone faults in case of
high impedance type.
vi) Shall be high or low impedance Principle type.

REF PROTECTION REQUIREMENTS
i) shall be single Pole.
ii) Have an operating current sensitivity at least
10% of nominal current.
iv) Have a suitable non-linear resistor to limit the
peak voltage during in-zone faults in case of high
impedance type.
v) Shall be high or low impedance Principle type.

i) Shall be Triple pole type.
ii) Shall be single step Polarized ‘MHO’ or Impedance
Distance relay suitable for Measuring Phase to Ground
and Phase to Phase to faults.
iii)Shall grounds a Characteristic angle between 60-80
deg.
iv)Shall have adjustable definite time delay with
setting range of 0.2 to 2.0 sec.
v) Shall have a suitable range for covering 60% of
Reactor impedance.
OR
i) Shall be single stage Definite Time 3 Pole, Over
Current relay with adjustable current and Time.
ii) Shall be connected for 2 O/C and 1 E/F connection
and shall be non-directional with reset ratio and low
Transient Overreach.
BACKUP PROTECTION REQUIREMENTS

SPECIAL COMMENTS
¾ Connection of restricted earth fault protection on
the neutral side shall be from residually connected
Bushing CTs or from the ground side CT.
¾ The impedance or over current backup protection
may not be able to detect inter-turn fault in the
reactor, for which buchholz may be the only answer,
unless the number of turns involved is very high.
¾ The magnitude and nature of the switching-in currents should
be considered when determining settings of reactor
protections
¾ Typical settings of o/c relays are:
Current Setting- 1.3 x Rated current , Time setting - 1 sec
¾ Typical settings of impedance relays are:
Reach - 60% of Reactor Impedance, Time setting - 1 sec
SETTING CRITERIA

LBB/ BFR PROTECTION COMMENTS
In the event of any CB fails to trip on receipt of
command from Protection relays, all CBs connected to
the Bus section to which the faulty circuit Breaker is
connected are required to be tripped with minimum
possibly delay through LBB Protection.
This Protection also Provides coverage for faults
between CB and CT which are not cleared by other
protections.
GENERAL

RECOMMENDATIONS FOR LBB/BFR PROTECTION
i) In all new 400KV and 220KV Substations as well as
Generating Stations Switch Yard, it must be
provided for each Circuit Breaker.
ii) For existing Switch Yards, it is considered a must at
400KV level and also 220KV Switch Yards having
multiple feed.
iii)In case of radially fed 220KV Substations, Provision
of LBB Protection is desirable but not essential.

LBB/BFR REQUIREMENTS
i) Have Short Operation and Drop off times.
ii) Have 3 Phase Current elements with facility for
Phase wise initiation.
iii)Have current setting range such that these can be set
minimum 200mA for Line and 50mA for generators
(for 1A CT for secondary).
iv) Have one common associated timer with adjustable
setting.
REQUIREMENTS OF CIRCUIT BREAKERS
¾ Operating Time
¾ Breaking Capacity
¾ Stuck Breaker Probability
¾ Operating Sequence / Duty cycle

LBB/BFR OPERATION
¾ The Breaker Failure Protection (LBB/BFR) can
operate single-stage/two-stage.
¾ When used as single-stage protection, the Bus trip
command is given to the adjacent Circuit Breakers if
the protected feeder Breaker fails.
¾ When used as two-stage protection, the first stage
can be used to repeat the trip command to the
relevant feeder Breaker, normally on a different trip
coil, if the initial trip command from the feeder
protection is not successful. The second stage will
result in a Bus trip to the adjacent Breakers, if the
command of the first stage is not successful. (This is
More recommended)

LBB/BFR FLOW CHART
MAIN
PROTECTION
OPERATED
YES
YES
TRIP
MAIN
BREAKER
INITIATE
BFR
WAIT FOR
FAULT
CLEARENCE
AND
FAULT
CLEARED
YES
NO
RESET
BREAKER
FAILURE
SCHEME
TRIP
BACK-UP/
Adjacent
BREAKERS
RETRIP

LBB/BFR SPECIAL COMMENTS
(i) The relay is separate for each breaker and is to be
connected in the secondary circuit of the CTs
associated with that particular breaker.
(ii) For line breakers, direct tripping of remote end
breaker(s) should be arranged on operation of LBB
protection.
For transformer breakers, direct tripping of
breaker(s) on the other side of the transformer
should be arranged on operation of LBB protection
(iii) For lines employing single phase auto reclosing,
the LBB relays should be started on a single phase
basis from the trip relays.

(iv) The CT sec core may be separate core, if available.
Other wise it shall be Clubbed (in series) with Main-1
or Main-2 protection.
(v)It is considered a good practice to have DC circuits
of Gr.A and Gr. B protections and relay independent.
(vi) LBB cannot operate without proper initiation. It is
good practice to provide redundant trip output and
breaker fail input where other forms of redundancy
does not exist.
(vii) Separation should be maintained between
protective relay and CB trip coil DC circuit so that short
circuit or blown fuse in the CB circuit will not prevent
the protective relay from energizing the LBB scheme.

(viii) In addition to other fault sensing relays the LBB
relay should be initiated by Bus bar protection, since
failure of CB to clear a bus fault would result in the loss
of entire station if BFP relay is not initiated
(ix) Tripping logic of the bus bar protection scheme
shall be used for LBB protection also.
(x) For breaker-fail relaying for low energy faults like
buchholz operation, special considerations may have to
be given to ensure proper scheme operation by using
C.B. contact logic in addition to current detectors.

LBB/BFR SETTING CRITERIA
(i) Current level detectors should be set as sensitive as
the main protections
A general setting of 0.2 A is commonly practiced for
Lines and Transformers
(ii)Timer setting should be set considering breaker
interrupting time, current detector reset time and a
margin. Generally a timer setting of 200 ms has been
found to be adequate.

GENERAL
¾ Bus bar protection is provided for high speed sensitive
clearance of bus bar faults by tripping all the circuit breakers
connected to faulty bus.
¾ Recommendations for providing Bus bar protection at different
voltage levels are as follows:
(i) Bus bar protection must be provided in all new 400kV and
220kV substations as well as generating station switchyards.
(ii) For existing substations, provision of Bus bar protection is
considered must at 400kV level and at 220kV level.
In case of radially fed 220kV substations, having more than
one bus it is desirable to have bus bar protection but is not a
must.

TYPES OF BUSBAR PROTECTION SCHEMES
¾ HIGH IMPEDENCE BUSBAR PROTECTION: The Measuring Circuit comprises a High
impedance stabilising Resistor (Metrosil) connected across the circulating current arrangement
of all the CT’s in parallel. The Value of Stabilising Resistor chosen such that the voltage drop
across the relay circuit is insufficient to operate the relay for faults outside the protection zone.
¾ MODERATE/ MEDIUM IMPEDENCE BUSBAR PROTECTION: which is combination of the
normal High-Impedance and Stabilised differential scheme. medium impedance type of Bus
bar protection relays, during internal faults, but low impedance protection during load and
external faults.
¾ LOW IMPEDENCE BUSBAR PROTECTION: A no of Different Measurement principles are
employed in Low Impedance Schemes.
A. CURRENT DIFFERENTIAL PROTECTION: Which is current comparison with current restraint,
biased or percentage differential relaying. The operating current is the Phasor sum of all feeder
currents and the restraint current is the arithmetic sum. A trip command is given when
operating current is greater than its pickup level and the stabilising factor the ratio of operating
current to restraint current.
B. PHASE COMPARISION PROTECTION: The Measuring principle for Phase comparison
protection is based on the assumption that the feeder currents are phase coincident during bus
bar fault. The duration of phase coincidence of all feeder currents is checked for positive and
negative half-cycles. The pickup level is set above the load current.
¾ NUMERICAL BUSBAR PROTECTION: in this two types are available.
A. CENTRALISED ARCHITECTURE.
B. DECENTRLAISED ARCHITECTURE.

SPECIAL COMMENTS
i) DC Supply for Bus bar protection shall be
independent from feeder.
ii) Faults between CB & CT shall be cleared from one
side by opening of CB on Bus bar Protection
Operation.
iii)However clearing of Fault from other side shall be
through breaker failure protection.
iv)3–ph trip relays shall be provided for each CB which
shall also initiate LBB/BFR Protection.
v) in case of existing SS where CTs are different ratios,
biased type differential protection/ Numerical Bus
bar protection is recommended.
vi)Length of secondary leads should be kept as
minimum as possible.
vii)Where lead runs are excessive, an increase in wire
size or use of parallel conductors are meant to
reduce lead resistance.

REQUIREMENTS
i) it shall be 3-ph type and operate selectively for each bus bar section.
ii) it shall operate on differential principle and provide independent zones of
protection for each bus.
iii) it shall provide zone indication.
iv) it shall be stable for through fault conditions up to maximum 40KA fault
level.
v) For applications where bus differential protection sensitivity has to be set
below load current, as may be a case with use of concrete structures, it is
recommended that a separate check zone is provided, other wise separate
check zone is not essential. Check zone, if provided, shall be of High Impedance
type.
vi) it shall incorporate continuous supervision for CT secondary against any
possible open circuits. In case of detection of open circuiting of CT secondary,
after a time delay, the effected zone of protection shall be rendered inoperative
and alarm initiated.
vii) it shall be include DC supply supervision.
viii) include adequate number of high speed tripping relays.
ix) whenever CT switching is involved the scheme shall include necessary CT
switching relays and have provision for CT switching incomplete alarm.
x) it shall be include IN/OUT switching facility for each zone..

¾ C.T wire supervision relays should be set with a sensitivity
such that they can detect C.T secondary open circuit even
in case of least loaded feeder.
¾ Bus bar differential protection should have overall
sensitivity above heaviest loaded feeder current unless a
separate check zone has been provided.
¾ In case where faults currents are expected to be low, the
protection should be sensitive enough to take care of such
expected low fault current.
¾ In case of voltage operated high impedance type
protection, the voltage setting should be above expected
voltage developed across the relay during maximum
through fault current condition.
¾ In case of current operated relays for stability under
through fault condition, external resistance is to be set
such that voltage developed across relay and resistance
combination is below the voltage required for forcing
required relay operating current.
SETTING CRITERIA

¾ It is possible to provide Back-up protection of Bus Bars by
duplicating the dedicated protection.
¾ For Substations of High strategic importance i.e. 1200KV or
765KV or 400KV Systems, the complete Bus bar protection can
be fully duplicated.
¾ Dedicated Protections invariably employ separate DC circuits
and CT cores. They send trip impulses to separate trip coils
and use separate isolator position auxiliary contacts. Cross
tripping of both trip coils is also done.
¾ For substations of 1200KV or 765KV, instead of Providing
Duplicate Bus bar Protection, Providing of Two Different
Manufacturers Numerical Centralised or Distributed
Architecture Bus bar Protection.
DUPLICATION OF BUSBAR PROTECTION

¾ Provides better understanding of the behavior of
Power network after a disturbance.
¾ Gives useful information to improve existing
Equipment and in planning or designing new
installations.
¾ Disturbance recorder shall be microprocessor based
and shall be used to record the graphic form of
instantaneous of values voltage and current in all
three phases, open delta voltage and neutral current,
open or closed positions of relay contacts and
breaker during the system disturbances.
¾ Disturbance recorders are recommended for all the
400kV lines.
¾ At 220kV level also they are recommended for all
interconnecting lines.
¾ It is also recommended that all the disturbance
recorders in the station are synchronized with GPS.
Disturbance Recorder

Fault Locator
¾ Distance to fault locator is recommended to be
provided as a standard for all 400kV and 220kV lines
on both ends.
¾ However for short lines of length up to 20kms, fault
locator can be provided at one end only. Normally in
case of Numerical Relay having inbuilt feature.
Event Logger
¾ The Event Logger is used to record the state of
switchyard equipment and relays and occurrences of
alarms.
¾ The equipment also records events recorded by
disturbance recorder, as also changes in digital
inputs, i.e operation and resetting of relay contact
and switching of primary plant within the substation.

SPECIAL COMMENTS
¾ Start function to disturbance recorder is to be
provided by change in state of one or more of the
events connected and / or by any external triggering
so that recording of events during a fault or system
disturbance can be obtained.
¾ If disturbance recorder function or fault locator
functions are available as integral part of any of main
protection, then separate stand alone units for this
function are not required.
¾ In case of DR being part of main protection, it should
be possible to connect external binary inputs.
¾ Stand alone DR which can cater to more than one
bay / circuit can also be used.

400KV SUBSTATION: MAMIDIPALLY EVENT LOGGER EVENTS INFORMATION
19 MAR 2004 13:00:00
A 13:09:37.090 # 195 400KV SRISAILAM-2 MAIN-2 RAZFE PROT TRIP
A 13:09:37.096 # 188 400KV SRISAILAM-2 MAIN-1 REL100 PROT START’Y’
A 13:09:37.097 # 187 400KV SRISAILAM-2 MAIN-1 REL100 PROT START’R’
A 13:09:37.100 # 181 400KV SRISAILAM-2 MAIN-1 REL100 PROT TRIP
A 13:09:37.104 # 162 400KV SRISAILAM-2 MAIN CB 752 Y-PH OPEN
A 13:09:37.110 # 196 400KV SRISAILAM-2 MAIN-2 RAZFE CARRIER SEND
A 13:09:37.110 # 170 400KV SRISAILAM-2 AT/F-2 TIE CB 852 B-PH OPEN
A 13:09:37.111 # 161 400KV SRISAILAM-2 MAIN CB 752 R-PH OPEN
A 13:09:37.111 # 163 400KV SRISAILAM-2 MAIN CB 752 B-PH OPEN
A 13:09:37.111 # 169 400KV SRISAILAM-2 AT/F-2 TIE CB 852 Y-PH OPEN
A 13:09:37.112 # 168 400KV SRISAILAM-2 AT/F-2 TIE CB 852 R-PH OPEN
A 13:09:37.113 # 182 400KV SRISAILAM-2 MAIN-1 REL100 CARRIER SEND
A 13:09:37.126 # 199 400KV SRISAILAM-2 CARRIER PROT CH-2 RECEIVED
A 13:09:37.140 # 185 400KV SRISAILAM-2 CARRIER PROT CH-1 RECEIVED
N 13:09:37.147 # 195 400KV SRISAILAM-2 MAIN-2 RAZFE PROT TRIP RESET
N 13:09:37.148 # 196 400KV SRISAILAM-2 MAIN-2 RAZFE CARRIER SEND RESET
N 13:09:37.175 # 187 400KV SRISAILAM-2 MAIN-1 REL100 START ‘R’ RESET
N 13:09:37.176 # 181 400KV SRISAILAM-2 MAIN-1 REL100 PROT TRIP RESET
N 13:09:37.176 # 188 400KV SRISAILAM-2 MAIN-1 REL100 START ‘Y’ RESET
N 13:09:37.185 # 182 400KV SRISAILAM-2 MAIN-1 REL100 CARRIER SEND RESET
N 13:09:37.257 # 199 400KV SRISAILAM-2 CARRIER PROT CH-2 RECEIVED RESET
N 13:09:37.279 # 185 400KV SRISAILAM-2 CARRIER PROT CH-1 RECEIVED RESET
19 MAR 2004 14:00:00
N 14:09:48.702 # 163 400KV SRISAILAM-2 MAIN CB 752 B-PH CLOSE
N 14:09:48.704 # 161 400KV SRISAILAM-2 MAIN CB 752 R-PH CLOSE
N 14:09:48.720 # 162 400KV SRISAILAM-2 MAIN CB 752 Y-PH CLOSE
N 14:10:00.903 # 169 400KV SRISAILAM-2 AT/F-2 TIE CB 852 Y-PH CLOSE
N 14:10:00.907 # 168 400KV SRISAILAM-2 AT/F-2 TIE CB 852 R-PH CLOSE
N 14:10:00.907 # 170 400KV SRISAILAM-2 AT/F-2 TIE CB 852 B-PH CLOSE
19 MAR 2004 15:00:00

R PH VOLTAGE
Y PH VOLTAGE
B PH VOLTAGE
OPEN DELTA VOLTAGE
R PH CURRENT
Y PH CURRENT
B PH CURRENT
STAR/NEUTRAL CURRENT
MAIN CB R PH OPEN
MAIN CB Y PH OPEN
MAIN CB B PH OPEN
TIE CB R PH OPEN
TIE CB Y PH OPEN
TIE CB B PH OPEN
MAIN/TIE CB LBB OPTD
DIRECT TRIP CH-1/2 OPTD
BUSBAR PROT OPTD
MAIN-1 PROT OPTD
MAIN-2 PROT OPTD
OVER VOLTAGE STAGE-1/2 OPTD
STUB PROT-1/2 OPTD
MAIN-1 PROT CARRIER RECEIVE
MAIN-2 PROT CARRIER RECEIVE
DF/DT OPTD
EVENT NO
NAME OF FEEDER
DATE & TIME
DISTURBANCE
RECORDER

PREFERRED DISTURBANCE RECORDER
400 KV LINES 400 KV TRANSFORMER
ANALOG CHANNELS
1. R-PH VOLTAGE
2. Y-PH VOLTAGE
3. B-PH VOLTAGE
4. OPEN DELTA VOLTAGE
5. R-PH CURRENT
6. Y-PH CURRENT
7. B-PH CURRENT
8. NEUTRAL/STAR CURRENT
DIGITAL CHANNELS
1. HV MAIN CB R-PH OPEN
2. HV MAIN CB Y-PH OPEN
3. HV MAIN CB B-PH OPEN
4. HV TIE CB R-PH OPEN
5. HV TIE CB Y-PH OPEN
6. HV TIE CB B-PH OPEN
7. 21 MAIN1 REL 521 OPERATED
8. 21 MAIN2 REL 316 OPERATED
9. 87 BUSBAR RELAY OPERATED
10. MAIN CB A/R OPERATED
11. TIE CB A/R OPERATED
12. PSB OPERATED
13. SOTF OPERATED
14. 27 O/V STG-1/2 OPERATED
15. 51 STUB-1/2 OPERATED
16. 87HZ / LZ TEED-1/2 OPERATED
17. MAIN CB LBB OPERATED
18. TIE CB LBB OPERATED
19. DIRECT TRIP CH-1/2 RECEIVED
20. 21M1 / 21M2 CARRIER RECEIVE
21. 86 GR-A/B RELAY OPERATED
22. 67N DEF/TEF RLY OPERATED
23. DF/DT RELAY OPERATED
ANALOG CHANNELS
1. HV R-PH VOLTAGE
2. HV Y-PH VOLTAGE
3. HV B-PH VOLTAGE
4. HV OPEN DELTA VOLTAGE
5. LV R-PH VOLTAGE
6. LV Y-PH VOLTAGE
7. LV B-PH VOLTAGE
8. LV OPEN DELTA VOLTAGE
9. HV R-PH CURRENT
10. HV Y-PH CURRENT
11. HV B-PH CURRENT
12. HV NEUTRAL/STAR CURRENT
13. LV R-PH CURRENT
14. LV Y-PH CURRENT
15. LV B-PH CURRENT
16. LV NEUTRAL/STAR CURRENT
DIGITAL CHANNELS
1. HV MAIN CB R-PH OPEN
2. HV MAIN CB Y-PH OPEN
3. HV MAIN CB B-PH OPEN
4. HV TIE CB R-PH OPEN
5. HV TIE CB Y-PH OPEN
6. HV TIE CB B-PH OPEN
7. LV 220 CB R-PH OPEN
8. LV 220 CB Y-PH OPEN
9. LV 220 CB B-PH OPEN
10 87 LZ DIFF RLY OPERATED
11. HV 67 ABCN OPERATED
12. LV 67 ABCN OPERATED
13. 51 O/L RLY OPERATED
14. 64 REF / 87 HZ RLY OPERATED
15. NDR RLY OPERATED
16. HV 99T OVER FLUX OPTD
17. LV 99T OVER FLUX OPTD
18. HV 400 BUSBAR OPERATED
19. LV 220 BUSBAR OPERATED
20. HV MAIN CB LBB OPERATED
21. HV TIE CB LBB OPERATED
22. LV 220 CB LBB OPERATED
23. HV 86 GR-A/B RELAY OPTD
24. LV 86 GR-A/B RELAY OPTD
25. AT/F 21T UZ RELAY OPERATED
26. OIL TEMP HIGH TRIP
27. WNDG TEMP HV/IV/LV TRIP
28. BUCHHOLZ MAIN/OLTC TRIP
29. PRD 1/ 2 TRIP
30. AT/F NEUTRAL CURRENT TRIP

GENERAL
¾ Some broad guidelines for Engineering of Protection
System are given below and could be refined if felt
necessary by the Utility according to its specific
needs and practices.
¾ Wherever two sets of DC sources are available, to
obtain redundancy and to be able to take protection
out for maintenance, while equipment.
¾ in service, the relays are electrically and physically
segregated into two groups.
¾ Interconnection between these two groups shall not
generally be attempted.
¾ Segregation of protections and trip circuits in two
groups may be considered by giving DC supplies
through separate fuses.

GR-A & GR-B TRIPPINGS
For 400kV stations there shall be two separate Battery Systems
available for Protection, Control & Tripping/ Closing operations.
To obtain Redundancy and to be able to take Protection out for
Maintenance, while equipment is in service, the Relays are
Electrically and Physically segregated in to Two groups.
Grouping is done to the extent possible in such a way that each
group can independently carryout Protective functions with near
equal redundancy. Inter connection of these two groups shall not
be generally be attempted.
Distribution of DC supply shall be done bay wise to feed the
following
1. Protection
2. CB control
3. Isolator / earth switch control
4. Annunciation / indication

a) Protection Function:
For each group of protection, separate DC sources
are recommended.
Example: Group-1: 21L1, 87T1, 67HV, 87R, 87BB1
Group-2: 21L2, 87T2, 67LV, 21R, 87BB2
b) CB Functions
Trip coil 1 & 2 shall be fed from separate sources.
Closing coil can be from either of these two sources.
c) Isolator / Earth switch
These associated with any one circuit shall be fed
from one of the two DC sources.
In the case of One and half (1 & ½) CB arrangement,
the Isolator / Earth switch associated with the tie CB
can be fed from either source 1 or 2.

d) Annunciation & Indication
For each bay, these functions can be fed from either
one of the two sources. Each function shall be fed
however through separate feeds.
e) Monitoring Functions
These shall be grouped in 3 groups
(i) Disturbance Recorders
(ii) Fault Locators
(iii) Event Loggers
All the three groups shall be fed through separate
feeds from either of the two sources.
Now days Numerical IEDs / Protective Relays are
Having above functions are offered as inbuilt. Most of
the Utilities are accepting this.

Cabling
It is recommended that:
(i) Separate cables are used for AC & DC circuit.
(ii) Separate cables are used for DC 1 & DC 2 circuits.
(iii) For different cores of CT & CVT separate cables
shall be used.

GROUP-A & GROUP-B TRIPPINGS
LINE PROTECTION TRANSFORMER
PROTECTION
REACTOR PROTECTION
GROUP-A
MAIN-1 PROTECTION
M1 BUILT IN FUNCTIONS
TEED-1 PROTECTION
OVER VOLTAGE STAGE-1 PROT
DIRECT TRIP CHANNEL-1 RECEIVED
GROUP-B
MAIN-2 PROTCTION
M2 BUILT IN FUNCTIONS
TEED-2 PROTECTION
OVER VOLTAGE STAGE-2 PROT
LBB/BFR RELAY
DIRECT TRIP CHANNEL-2 RECEIVED
GROUP-A
T/F DIFFERENTIAL RELAY
T/F IMP / 21T RELAY
T/F HV BACKUP RELAY
T/F HV OVERFLUX RELAY
OIL TEMP HIGH TRIP
PRESURE RELIEF TRIP
TERITIARY DELTA WNDG NDR PROT
GROUP-B
T/F REF / HIGH Z DIFF RELAY
T/F NEUTRAL CURRENT / 51 O/C RLY
T/F LV BACKUP RELAY
OVER LOAD PROT (ALARM ONLY)
T/F LV OVERFLUX RELAY
BUCHHOLZ TRIP
OLTC BUCHHOLZ TRIP
WINDING TEMP HIGH TRIP
LOW/ HIGH OIL LEVEL TRIP
GROUP-A
REACTOR DIFFERENTIAL RELAY
REACTOR BACKUP / 21R RELAY
OIL TEMP HIGH TRIP
PRESURE RELIEF TRIP
GROUP-B
REACTOR REF RELAY
BUCHHOLZ TRIP
WINDING TEMP HIGH TRIP
LOW/ HIGH OIL LEVEL TRIP
FIRE PROTECTION TRIP

GENERAL
¾ Instrument transformers (CTs and VTs) are used to
obtain measured quantities of current and voltage in
appropriate form for use in Control, Protection and
Measuring equipment such as Energy meters,
indicating instruments, Protective relays, fault
locators, fault recorders, synchronizers.
¾ These are installed in different bays such as Line,
Transformer, Reactor, Bus Coupler, Transfer Bus
Coupler, Bus Sectionalizer Bays and also at the Bus
Bar.
¾ Given below are some examples of different bus
configurations showing suitable location of CTs &
VTs.

¾ The CTs shall be placed near the circuit breakers
(CBs) and on the Line side.
¾ The detection zones of Line Relays and Bus Bar
relays start at the CTs. It is advantageous if these
two points are close to each other.
¾ In the improbable case of a fault between the CT
and CB the Bus Bar protection will detect and clear
the fault.
Double Bus Arrangement
CURRENT TRANSFORMER
CT Polarity
¾ As a practice the P1 terminal of the CT shall be
towards the bus and P2 away from the bus.

Double Main and Transfer Bus Arrangement
¾It is advantageous to locate the CTs on the line side of
the disconnectors for Line and Transformer bays. In
this way the Protective Relay connected to the CT will
remain connected to the line or Transformer when it is
switched over to the Transfer / Auxiliary Bus.
¾A separate CT is required to be provided in the
Transfer bus coupler bay to obtain selective bus
tripping for faults on Transfer bus.
Bus Coupler and Bus Sectionalizer Bays
¾A set of CT is necessary to enable different bus bar
protection zones to be formed.
¾The protection can be arranged to give complete fault
clearing with a short time-delay (LBB time) for faults
between CB and CT.
¾Only one set of CTs is recommended.

Double Main and Bypass CB Arrangement
¾ It is advantageous to locate the CTs on the Line side
of the disconnectors for Line and Transformer bays.
In this way the Protective Relay connected to the CT
will remain connected to the line or Transformer
when the CB is Bi-passed and protection Transferred
to Bus Coupler.
Bus Coupler and Bus Sectionalizer Bays
¾ A set of CT is necessary to enable different Bus bar
protection zones to be formed.
¾ The protection can be arranged to give complete
fault clearing with a short time-delay (LBB time) for
faults between CB and CT.
¾ Only one set of CTs is recommended.

One and Half Breaker System
¾ The CTs are located close to the CBs.
¾ At the central CB ( Tie CB) two CT sets are used.
¾ This arrangement utilizes 4 CTs. However it is also
possible to use a single of CT with the tie CB thus
reducing number of CTs to 3 per diameter.
¾ Alternative way of locating the CTs requires 5 CTs.
The advantages with this arrangement are:
¾ Paralleling of two CTs to the main line protection is
not required. This gives better transient response.
¾ Separate stub protection can be connected. (TEED).
¾ It is recommended that 4 CT arrangement is
continued to be adopted.

Double Bus Double Breaker System
¾ It is usual to locate the CTs on the line side after the
CBs.
¾ The two CTs shall be identical.
¾ To get the line current the secondary current of the
two CTs are summated.

Voltage Transformers
Line CVTs
¾ CVTs are used for metering, protection and
synchronization.
¾ Located at the line entry they also enable indication
of voltage on a line energized from the opposite end.
¾ CVTs can also be used as coupling capacitors for
power line carrier (PLCC) Communication.
¾ They are then to be located at the line side of the line
traps and Line Earthing switches.
¾ For 400kV level it is recommended that each Line
Bay is provided with CVTs all the three phases.
¾ However, depending on utility practice CVTs in one
phase may also be provided in which case
protections will have to be connected to bus VTs.

Bus CVTs
¾ Three phase VTs / CVTs on the busbars provide input
for directional relays and reference voltage for
synchronization.
¾ These VTs will have to be selected by using voltage
selection scheme.
CT / VT Earthing
¾ CT / VT secondary neutrals should be earthed at one
point only.
¾ VT secondary neutral earthing is done at equipment
itself.
¾ It is preferable to earth the CT secondary neutral in
the control / protection cubicle in order to provide
maximum security to the operating personnel.

17648763-CBIP-Recommondations.pdf

17648763-CBIP-Recommondations.pdf

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17648763-CBIP-Recommondations.pdf