FEEDER AND BUS BAR PROTECTION

LENDI INSTITUTE OF ENGINEERING AND TECHNOLOGY
Jonnada, Andhra Pradesh- 535005
Department of Electrical and Electronics Engineering
UNIT -IV
FEEDER AND BUS BAR PROTECTION
Presented by,
Dr. Rohit Babu, Associate Professor

Syllabus
∟Protection of lines
―Over current Protection schemes
―PSM, TMS
―Numerical examples
―Carrier current and three zone distance relay using impedance
relays
―Protection of bus bars by using Differential protection

Overcurrent Protection schemes
1. INTRODUCTION
• A protective relay which operates when the load current exceeds a preset value, is
called an overcurrent relay.
• The value of the preset current above which the relay operates is known as its pick-up
value.
• Overcurrent relays are used for the protection of distribution lines, large motors,
power equipment, industrial systems, etc.
• A scheme which incorporates overcurrent relays for the protection of an element of a
power system, is known as an overcurrent protection scheme or overcurrent
protection.
• An overcurrent protection scheme may include one or more overcurrent relays.

Overcurrent Protection schemes contd.
2. TIME-CURRENT CHARACTERISTICS
Fig. 1 Definite-time and inverse-time characteristics of overcurrent relays
2.1 Definite-time Overcurrent Relay
• A definite-time overcurrent relay operates after
a predetermined time when the current exceeds
its pick-up value.
• The operating time is constant, irrespective of
the magnitude of the current above the pick-up
value.
2.2 Instantaneous Overcurrent Relay
• An instantaneous relay operates in a definite time when the current exceeds its pick-up value.
• There is no intentional time-delay.
• It operates in 0.1s or less.

Fig. 1 Definite-time and inverse-time characteristics of overcurrent relays
2.3 Inverse-time Overcurrent Relay
• An inverse-time overcurrent relay operates
when the current exceeds its pick-up value.
• The operating time depends on the magnitude
of the operating current.
• The operating time decreases as the current
increases.

2.4 Inverse Definite Minimum Time Overcurrent (I.D.M.T) Relay
Fig. 2 I.D.M.T., very inverse-time and extremely inverse-
time characteristics
• This type of a relay gives an inverse-time current
characteristic at lower values of the fault current and
definite-time characteristic at higher values of the fault
current.
• Generally, an inverse-time characteristic is obtained if
the value of the plug setting multiplier is below 10.
• For values of plug setting multiplier between 10 and 20,
the characteristic tends to become a straight line, i.e.
towards the definite time characteristic.

2.5 Very Inverse-time Overcurrent Relay
• A very inverse-time overcurrent realy gives more inverse
characteristic than that of a plain inverse relay or the I.D.M.T.
relay.
• The very inverse characteristic gives better selectivity than the
I.D.M.T. characteristic.
• Its recommended standard time-current characteristic is given
by
13.5
1
t
I



• The general expression for time-current characteristic of overcurrent relays is given by
1
n
K
t
I


• The value of n for very inverse characteristic may lie between 1.02 and 2.
• Very inverse time-current relays are recommended for the cases where there is a substantial
reduction of fault current as the distance from the power source increases.
• They are particularly effective with ground faults because of their steep characteristic.

2.6 Extremely Inverse-time Overcurrent Relay
• When I.D.M.T. and very inverse relays fail in selectivity,
extremely inverse relays are employed. I.D.M.T. relays are not
suitable to be graded with fuses.
• Enclosed fuses have time-current characteristics according to
the law
3.5
I t K

• The time-current characteristic of an extremely inverse relay is
2
I t K

The heating characteristics of machines and other apparatus is
also governed by the above equation.

• A relay should not operate on momentary overloads.
• But it must operate on sustained short circuit current.
• For such a situation, it is difficult to set I.D.M.T. relays.
• An extremely inverse relay is quite suitable for such a situation.
• This relay is used for the protection of alternators against overloads and internal faults.
• It is also used for reclosing distribution circuits after a long outage.
• After long outages, when the circuit breaker is reclosed there is a heavy inrush current which is
comparable to a fault current.
• An I.D.M.T. relay is not able to distinguish between the rapidly decaying inrush current of the load
and the persistent high current of a fault.
• But an extremely inverse relay is able to distinguish between a fault current and inrush current due
to its steep time-current characteristic.

2.7 Special Characteristics
These relays have time-current characteristic
n
I K

with
2
n 
To protect rectifier transformers, a highly inverse characteristic of
8
I t K

is required
Enclosed fuses have a time-current characteristic of
3.5
I t K

A static relay or microprocessor-base relay can be designed to give
3.5
I t K

characteristic, suitable to be graded with fuses.

2.8 Method of Defining Shape of Time-current Characteristics
The general expression for time-current characteristics is given by
1
n
K
t
I


The approximate expression is
n
K
t
I

For definite-time characteristic, the value of n is equal to 0.
According to the British Standard, the following are the important characteristics of overcurrent
relays.
(i) I.D.M.T.: 0.02
0.14
1
t
I



(ii) Very inverse:
13.5
1
t
I


(iii) Extremely inverse:
2
80
1
t
I


A microprocessor-based relay can easily give straight line characteristics of the form
n
K
t
I


2.9 Technique to Realise Various Time-Current Characteristics using Electromechanical Relays
• The magnetic circuit of an overcurrent relay can be designed to saturate above a certain value of
the actuating current.
• If the core is designed to saturate at the pick-up value of the current, the relay gives a definite
time-characteristic.
• If the core is designed to saturate at a later stage, an I.D.M.T. characteristic is obtained.
• If the core saturates at a still later stage, a very inverse characteristic is obtained.
• If the saturation occurs at a very late stage, the relay give an extremely inverse characteristic.

3. CURRENT SETTING
• The current above which an overcurrent relay should operate can be set.
• Suppose that a relay is set at 5 A. It will then operate if the current exceeds 5 A. Below 5 A, the
relay will not operate.
• The plug-setting (current-setting) can either be given directly in amperes or indirectly as
percentages of the rated current.
• An overcurrent relay which is used for phase-to-phase fault protection, can be set at 50% to
200% of the rated current in steps of 25%.
• The usual current rating of this relay is 5 A. So it can be set at 2.5 A, 3.75 A, 5 A, ..., 10 A.
• When a relay is set at 2.5 A, it will operate when current exceeds 2.5 A.
• When the relay is set at 10 A, it will operate when current exceeds 10 A.

• The relay which is used for protection against ground faults (earth-fault relay) has settings 20%
to 80% of the rated current in steps of 10%.
• The current rating of an earth-fault relay is usually 1 A.
Fig. 3 Standard I.D.M.T. characteristic
• The actual r.m.s. current flowing in the relay expressed as a
multiple of the setting current (pickup current) is known as
the plug setting multiplier (PSM).
• Suppose, the rating of a relay is 5 A and it is set at 200%, i.e. at
10 A.
• If the current flowing through the relay is 100 A, then the plug
setting multiplier will be 10.
• The PSM = 4 means 40 A of current is flowing, PSM = 6 means
60 A of current is flowing and so on.

• If the same relay is set at 50%, i.e. at 2.5 A, the PSM = 4 means
10 A; PSM = 6 means 15 A; PSM = 10 means 25 A.
• PSM can be expressed as
Secondary Current
PSM=
Relay Current Setting
Primary Current during fault, i.e. fault Current
=
Relay Current Setting × CT Ratio

4. TIME SETTING
• The term time multiplier setting (TMS) is used for these steps of
time settings.
• The values of TMS are 0.1, 0.2, ..., 0.9, 1.
• Suppose that at a particular value of the current or plug setting
multiplier (PSM), the operating time is 4 s with TMS = 1.
• The operating time for the same current with TMS = 0.5 will be 4
× 0.5 = 2 s.
• The operating time with TMS = 0.2 will be 4 × 0.2 = 0.8 s.
• Figure 4 (a) shows time-current characteristics for different
values of TMS.
• The characteristic at TMS = 1 can also be presented in the form
shown in Fig. 4 (b).
Figure 4 (a)
Fig. 4 (b).

5. OVERCURRENT PROTECTIVE SCHEMES
• Overcurrent protective schemes are widely used for the
protection of distribution lines.
• A radial feeder may be sectionalized and two or more
overcurrent relays may be used, one relay for the
protection of each section of the feeder, as shown in
Fig. 5.
Fig. 5 Time-graded overcurrent protection of a feeder
• For proper selectivity of the relays, one of the following schemes can be employed, depending on
the system conditions.
(i) Time-graded system
(ii) Current-graded system
(iii) A combination of time and current grading

5.1 Time-graded system
Fig. 5 Time-graded overcurrent protection of a feeder
• In this scheme, definite-time overcurrent
relays are used.
• When a definite-time relay operates for a
fault current, it starts a timing unit which
trips the circuit breaker after a preset time,
which is independent of the fault current.
• The operating time of the relays is adjusted in increasing order from the far end of the feeder.
• The difference in the time setting of two adjacent relays is usually kept at 0.5 s.
• This difference is to cover the operating time of the circuit breaker and errors in the relay and CT.
• With fast circuit breakers and modern accurate relays, it may be possible to reduce this time further
to 0.4 s or 0.3 s.

• This scheme is suitable for a system where the impedance (distance) between substations is low.
• It means that the fault current is practically the same if a fault occurs on any section of the feeder.
• This is true for a system in which the source impedance Zg is more than the impedance of the
protected section, Z1.
• If the neutral of the system is grounded through a resistance or an impedance, Zs is high and Zs/(Zs
+ Z1) is not sufficiently lower than unity.
• In this situation, the advantage of inverse-time characteristic cannot be obtained.
• So definite relays can be employed, which are cheaper than I.D.M.T. relays.
• Definite-time relays are popular in Central Europe.

5.2 Current-graded System
• In a current-graded scheme, the relays are set to pick-up
at progressively higher values of current towards the
source.
• The relays employed in this scheme are high set (high
speed) instantaneous overcurrent relays. Fig. 6 Instantaneous overcurrent protection of a feeder
• The operating time is kept the same for all relays used to protect different sections of the feeder.
• The current setting for a relay corresponds to the fault current level for the feeder section to be
protected.
• The magnitude of the fault current cannot be accurately determined as all the circuit parameters may
not be known.
• During a fault, there is a transient conditions and the performance of the relays is not accurate.

• Consequently, to obtain proper
discrimination, relays are set to protect only
a part of the feeder, usually about 80%.
• Since this scheme cannot protect the entire
feeder, this system is not used alone.
• It may be used in conjunction with I.D.M.T.
relays, Fig. 7 Combined instantaneous and I.D.M.T. protection

5.3 Combination of Current and Time-grading
• This scheme is widely used for the protection of distribution lines. I.D.M.T. relays are employed
in this scheme.
• They have the combined features of current and time-grading. I.D.M.T. relays have current as
well as time setting arrangements.
• The current setting of the relay is made according to the fault current level of the particular
section to be protected.
• The relays are set to pickup progressively at higher current levels, towards the source.
• Time setting is also done in a progressively increasing order towards the source.
• The difference in operating times of two adjacent relays is kept 0.5 s.

CARRIER CURRENT PROTECTION
• With the rapid development of power systems and the large amount of interconnection involved,
it has become very essential to have high speed protective schemes.
• Carrier current schemes are quite suitable for EHV and UHV power lines.
• They are faster and superior to distance schemes. Distance protective schemes are non-unit type
schemes.
• They are fast, simple and economical and provide both primary and back-up protection.
• The main disadvantage of conventional time-stepped distance protection is that the circuit
breakers at both ends of the line do not trip simultaneously when a fault occurs at one of the end
zones of the protected line section.
• This may cause instability in the system.

• Where high voltage auto-reclosing is employed, non-simultaneous opening of the circuit breakers
at both ends of the faulted section does not provide sufficient time for the de-ionisation of gases.
• The carrier current protection or any other unit protection does not suffer from these
disadvantages.
• In unit protection, circuit breakers trip simultaneously at both ends. It is capable of providing
high speed protection for the whole length of the protected line section.
• Carrier current schemes are cheaper and more reliable for long lines compared to wire pilot
schemes, even though the terminal equipment is more expensive and more complicated.
• In some cases, the carrier signal may be jointly utilised for telephone communication, supervisory
control, telemetering as well as relaying.

There are two important operating techniques employed for carrier current protection namely the
phase comparison technique and directional comparison technique.
In the phase comparison technique, the phase angle of the current entering one end is compared
with the phase angle of the current leaving the other end of the protected line section.
In the directional comparison technique, the direction of power flow at the two ends of the
protected line section is compared.

1. Phase Comparison Carrier Current Protection
Fig. 8 Schematic diagram of phase comparison carrier current protection
• In this scheme, the phase angle of the
current entering one end of the protected
line section is compared with the current
leaving the other end.
• The line trap is a parallel resonant circuit
tuned to the carrier frequency connected in
series with the line conductor at each end of
the protected line section.
• This keeps carrier signal confined to the protected line section and does not allow the carrier signal to flow into
the neighbouring sections.

Fig. 8 Schematic diagram of phase comparison carrier current protection
• There are carrier transmitter and receivers at both
the end of the protected line.
• The transmitter and receiver are connected to the
power line through a coupling capacitor to
withstand high voltage and grounded through an
inductance.
• The coupling capacitor consists of porcelain-clad,
oil-filled stack of capacitors connected in series.
• It offers very high impedance to power frequency
current but low impedance to carrier frequency
current.
• For the transmission of carrier signal either one phase
conductor with earth return or two phase conductors
can be employed.

Fig. 9 Transmission of carrier signals during internal and external
fault conditions
• The half-cycle blocks of carrier signals are injected into the
transmission line through the coupling capacitor.
• Fault detectors control the carrier signal so that it is started only
during faults.
• The voltage outputs of the summation network at stations A
and B are 180° out of phase during normal conditions.
• This is because the CT connections at the two ends are reversed.
• The carrier signal is transmitted only during positive half cycle
of the network output.

Fig. 9 Transmission of carrier signals during internal and external
fault conditions
• Wave (a) shows the output of the summation network at A.
• Wave (b) shows the carrier signal transmitted by the transmitter
at A.
• Wave (c) shows the output of the summation network at B for
external fault at C.
• Wave (d) shows the carrier signal transmitted by the transmitter
at B.
• For an internal fault, the polarity of the network output voltage
at B is reversed, as shown by the wave (e).
• The carrier signal sent by the transmitter at B is shown by wave
(f).

The ideal phase difference between carrier blocks is 180° for internal faults and zero degree for
external faults. In practice, it is kept 180° ± 30° for internal faults because of
(i) the phase displacement between emfs at the ends of the protected line section.
(ii) through current being added to the fault current at one end and subtracted at the other.
(iii) errors produced by CTs.

The length of transmission line which can be protected by phase comparison scheme is limited by
phase shifts produced by the following factors.
(i) The propagation time, i.e. the time taken by the carrier signal to travel from one end to other
end of the protected line section (up to 0.06° per km).
(ii) The time of response of the band pass fi lter (about 5°).
(iii) The phase shift caused by the transmission line capacitance (up to 10°).

2. Carrier Aided Distance Protection
• A distance scheme is capable of providing back-up protection but it does not provide high-speed protection
for the whole length of the line.
• The circuit breakers do not trip simultaneously at both ends for end-zone faults.
• The most desirable scheme will be one which includes the best features of both, unit protection and distance
protection.
• This can be achieved by interconnecting the distance relays at both ends of the protected section by carrier
signals.
• Such schemes provide instantaneous tripping for the whole length of the line as well as back-up protection.
• The following are the three types of such schemes.

• The following are the three types of such schemes.
(i) Carrier transfer or inter-tripping scheme
(ii) Carrier acceleration scheme
(iii) Carrier blocking scheme
(i) Carrier Transfer or Carrier Inter-tripping Scheme
The following are important types of transfer tripping schemes.
(a) Direct transfer tripping (Under-reaching scheme)
(b) Permissive under-reach transfer tripping scheme
(c) Permissive over-reach transfer tripping scheme

(a) Direct transfer tripping (Under-reaching scheme)
In this scheme, three-stepped distance relays are placed at each of the protected line.
Fig. 10 Stepped time-distance characteristics of relays for direct transfer tripping
(under-reach scheme)
• Consider the protective scheme for line AB.
• The time-distance characteristics of the relays
placed at A and B are shown in Fig. 10.
• When a fault occurs at F3, the I zone high-speed
relay operates at B and trips the circuit breaker.
• But the circuit breaker at A does not trip
instantaneously.

Fig. 11 Direct transfer tripping (under-reach scheme)
• Distance relays provide back-up protection for adjacent
lines which is obvious from Fig. 7.11(a) as the contacts
T2 and T3 operate after a certain time delay.
• Figure 7.11(b) shows a signal sending arrangement.
• Figure 7.11(c) shows a solid state logic for the trip
circuit.
• In this scheme, the carrier signal is transmitted over the
faulty line.
• Therefore, there is an additional attenuation of the
carrier signal.

(b) Permissive under-reach transfer tripping scheme
• To overcome the possibility of undesired tripping by
accidental operation or mal-operation of the signaling
channel, the receive relay is supervised by the zone 2 relay.
• The zone 2 relay contact is placed in series with the receive
relay RR as shown in Fig. 12(a).
• Figure 12(b) shows the schematic diagram of the signal
sending arrangement.
• Figure 12(c) shows the solid state logic for the trip circuit.
In this scheme also the carrier signal is transmitted over the
faulty line section which causes an additional attenuation
of the carrier signal. Fig. 12 Permissive under-reach transfer tripping scheme

(c) Permissive over-reach transfer tripping scheme
• In this scheme, the zone 2 unit is arranged to send a carrier signal to
the remote end of the protected section of the line.
• In this case, it is essential that the receive relay contact is supervised
by a directional relay.
• Figure 13(a) shows its trip circuit. Zone 2 relay is used to monitor the
receive relay contact RR. The unit at zone 2 must be a directional
unit (it may be a MHO unit) to ensure that tripping does not take
place unless the fault is within the protected section.
• Figure 13(b) shows a signal sending arrangement.
• Figure 13(c) shows its solid state logic. The scheme in which the
second zone relay is used to transmit carrier signal to the remote end
of the protected line section is called “Overreach Transfer Scheme”.
Fig. 13 Permissive over-reach transfer tripping scheme

(ii). Carrier Acceleration Scheme
Fig. 14 Carrier acceleration scheme
• In this scheme, the carrier signal is used to extend the reach
of the zone 1 unit to zone 2, thereby enabling the measuring
unit to see the end-zone faults.
• When an end-zone fault occurs, the relay trips at that end
and sends a carrier signal to the remote end.
• This scheme employs a single measuring unit for zone 1 and
zone 2 unit (MHO unit).
• The zone 1 unit is arranged to send the carrier signal to the
other end.
• The receive relay contact is arranged to operate a range
change relay as shown in Fig. 14(a).

Fig. 14 Carrier acceleration scheme
• On receipt of the carrier signal from the other end, the range
change relay extends the reach of the mho unit from zone 1
to zone 2 immediately.
• This scheme is not as fast as permissive transfer tripping
schemes as some time is required for the operation of the
mho unit after its range has been changed from zone 1 to
zone 2.
• It does not operate due to accidental or mal-operation of the
• carrier channel.
• In this scheme, the carrier signal is transmitted over the
faulty line.

(iii) Carrier Blocking Scheme
Fig. 15 Stepped time-distance characteristics of relays for carrier blocking scheme
• In this scheme the zone 3 unit looks in the reverse
direction and it sends a blocking signal to prevent the
operation of zone 2 unit at the other end for an external
fault.
• When a fault occurs at F1 (see Fig. 15), it is seen by zone 1
relays at both ends A and B.
• The carrier signal is not transmitted by the reverse looking zone 3 unit because it does not see the fault at F1.
• When a fault occurs on F2, which is an end-zone fault, it is seen by zone 2 units at both ends A and B and also by
zone 1 unit at B.
• The fault is cleared by zone 1 unit at B and instantaneously by the zone 2 unit at A.
• The zone 2 unit has two operating times, one instantaneous and other delayed.

Fig. 16 Carrier blocking scheme
• The instantaneous operation is through Z2 and RR, see
Fig. 16.
• The delayed operation is through T2. As the fault is an
internal one, there is no transmission of the carrier
signal.
• When a fault occurs at F3, it is seen by the forward
looking zone 2 unit A and the reverse looking zone 3 unit
at B.
• If this fault is not cleared instantaneously by the relays of
line BC, the zone 2 relay at A will trip after the zone 2
time lapse, as back-up protection.

Reverse Looking Relay with Offset Characteristic
Fig. 17 Carrier blocking scheme with offset zone 3 relay
• In the blocking scheme, the reverse looking relay becomes
inherently slow in operation for a close-up three phase
external fault because this type of fault lies at the boundary
of the characteristic.
• To tackle this difficulty, the reverse looking zone 3 relay
with offset characteristic, as shown in Fig. 17(a) is desired.
• The offset characteristic is also desirable to provide back-
up protection for bus bar faults after the zone 3 time delay.
• As the offset characteristic can also see end-zone internal faults, it will send a blocking signal to the remote end,
unless some measures are taken against the same.

• To stop the blocking signal for internal faults, the carrier sending circuit is provided with an additional closed
Z2 contact, as shown in Fig. 17(b).
• When an internal fault occurs, Z2 operates and it opens the carrier sending circuit even if the fault point lies in
zone 3 jurisdiction.

Busbar Differential Protection Scheme
• In early days only conventional over current relays were used for busbar protection.
• But it is desired that fault in any feeder or transformer connected to the busbar should not
disturb busbar system.
• In viewing of this time setting of busbar protection relays are made lengthy.
• So when faults occurs on busbar itself, it takes much time to isolate the bus from source which
may came much damage in the bus system.
• In recent days, the second zone distance protection relays on incoming feeder, with operating
time of 0.3 to 0.5 seconds have been applied for busbar protection.
• This scheme of protection can not discriminate the faulty section of the busbar.

Current Differential Protection
• The scheme of busbar protection,
involves, KCL, which states that,
total current entering an electrical
node is exactly equal to total current
leaving the node.
• Hence, total current entering into a
bus section is equal to total current
leaving the bus section.

Now, let us apply KCL at node X. As per KCL at node X,

• So, it is clear that under normal condition there is no current flows through the busbar protection
tripping relay.
• This relay is generally referred as Relay 87.
• Now, say fault is occurred at any of the feeders, outside the protected zone.
• In that case, the faulty current will pass through primary of the CT of that feeder.
• This fault current is contributed by all other feeders connected to the bus.
• So, contributed part of fault current flows through the corresponding CT of respective feeder.
• Hence at that faulty condition, if we apply KCL at node K, we will still get, iR = 0.

• That means, at external faulty condition, there is no
current flows through relay 87. Now consider a situation
when fault is occurred on the bus itself.
• At this condition, also the faulty current is contributed by
all feeders connected to the bus.
• Hence, at this condition, sum of all contributed fault
current is equal to total faulty current.
• Now, at faulty path there is no CT (in external fault, both
fault current and contributed current to the fault by
different feeder get CT in their path of flowing).

• The sum of all secondary currents is no
longer zero. It is equal to secondary
equivalent of faulty current.
• Now, if we apply KCL at the nodes, we
will get a non zero value of iR.
• So at this condition current starts flowing
through 87 relay and it makes trip the
circuit breaker corresponding to all the
feeders connected to this section of the
busbar.

Differential Protection of Sectionalized Bus
• During explaining working principle of current
differential protection of busbar, we have shown a
simple non sectionalized busbar.
• But in moderate high voltage system electrical bus
sectionalized in than one sections to increase
stability of the system.
• It is done because, fault in one section of bus
should not disturb other section of the system.
Hence during bus fault, total bus would be
interrupted.

DC Circuit of Differential Busbar Protection
• A typical DC circuit for busbar differential protection scheme is given below.
• Here, CSSA and CSSB are two selector switch which are used to put into
service, the busbar protection system for zone A and zone B respectively.
• 96A relay is multi contacts relay. Each circuit breaker in zone A is connected
with individual contact of 96A.
• Similarly, 96B is multi contacts relay and each circuit breaker in zone-B is
connected with individual contacts of 96B.
• On an interval fault in zone A or bus section A, the respective bus protection
relay 87A, be energized whereas during internal fault in zone B, the
respective relay 87B will be energized.

• As soon as relay coil of 87A or 87B is energized respective no. contact 87A-1 or 87B-1 is closed.
• Hence, the tripping relay 96 will trip the breakers connected to the faulty zone.
• To indicate whether zone A or B busbar protection operated, relay 30 is used.

Voltage Differential Protection of Busbar
• The current differential scheme is sensitive only when the CTs do not get saturated and maintain same
current ratio, phase angle error under maximum faulty condition.
• This is usually not 80, particularly, in the case of an external fault on one of the feeders.
• The CT on the faulty feeder may be saturated by total current and consequently it will have very large
errors.
• Due to this large error, the summation of secondary current of all CTs in a particular zone may not be
zero.
• So there may be a high chance of tripping of all circuit breakers associated with this protection zone even
in the case of an external large fault.
• To prevent this mal-operation of current differential busbar protection, the 87 relays are provided with
high pick up current and enough time delay.

• The greatest troublesome cause of current
transformer saturation is the transient dc
component of the short circuit current.
• This difficulties can be overcome by using air core
CTs.
• This current transformer is also called linear
coupler.
• As the core of the CT does not use iron the
secondary characteristic of these CTs, is straight
line.
• In voltage differential busbar protection the CTs of all incoming and outgoing feeders are connected in series
instead of connecting them in parallel.

FEEDER AND BUS BAR PROTECTION

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