1
Instrument Transformers (IT)
Classifications
• Protective IT
– Used in association with relays trip
coils, pilot wires etc.
• Measuring IT
– Used in conjunction with ammeter,
wattmeter etc.
2
Instrument Transformers: - IEC 60044
IEC 185 & 186
9Current Transformer (CT).
9Voltage Transformer (VT) = Potential
Transformer (PT).
3
Standards Related
• IEC BS 60044
• IEC BS 60185
• IEC BS 60186
4
CT Topics:
Construction.
Primary & secondary currents
Burden.
Open circuit & short circuit.
Secondary earthing.
Magnetic equivalent CKT.
CT specification & errors for measuring and protection.
Polarity.
• Loading of 100/1 A & 100/5 A.
• More dangerous 100/1 or 100/5 A in case of OC.
5
Symbols
current transformer: one output at the secondary
two alternative symbols
two coils with the same core double core current transformer
6
Typical Current Transformers
7
knee-point of excitation curve
8
CT Accuracy Classes - BS
Class Current Ratio Error Phase Displ
Measuring - M
0.1 ±0.25Æ0.1% ±10'Æ5'
0.2 ±0.5Æ0.2% ±20'Æ10'
0.5 ±1.0Æ0.5% ±60'Æ30'
1 ±2.0Æ1.0% ±120'Æ60'
3 ±3% Not spec.
5 ±5% Not spec.
Protection - P
5P ±1% ±60'
10P ±3% ±60' 9
VT Accuracy Classes - BS
Class Votgae Ratio Error Phase Displ
Measuring - M
0.1 ±0.1% ±5'
0.2 ±0.2% ± 10'
0.5 ±0.5% ±20'
1 ±1.0% ±40'
3 ±3% Not Specified
Protection - P
3P ±3% ±120'
6P ±6% ±240'
10
Knee Point
– Point on magnetisation curve, at which
an increase of 10% of secondary
voltage would increase the magnetising
current by 50%.
– The protective current transformer
generally operates in the knee region
11
Typical specification for a 11 kV CT
9System voltage:11 kV
9 Insulation level voltage (ILV) : 12/28/75 kV
9 Ratio: 200/1/1 A
9 Core 1: 1A, metering, 15 VA/class 1
9 Core 2: 1 A, protection, 15 VA/5P10
9 Short time rating:20 kA for 1 second
15VA : Burden
5 : Accuracy Limit Factor ( Guaranteed error up to 5%)
P :Protection
10 : Times of secondary voltage
Isec =1 , V= 15/1 =15 Volts , 15V * 10 =150Volts
CT will have no more than 5% error up to 150 V secondary
12
Burden Calculations:
13
Special Dangers With Current Transformers
14
Open Circuit Voltage
• Open secondary causes Φs to go to zero.
• Ip drives the core to saturation each half cycle.
• The action of Ip changing from maximum to zero
back to maximum causes Φp to change from
saturation in one direction to its saturated value
in the opposite direction.
15
CT
Never Leave The Current-Transformer
Secondary Winding Open Circuited,
otherwise a dangerously high voltage
may be induced across the secondary
terminals by the resultant high flux
density in the core.
16
Current Injection test
9 Primary Injection test
The advantages of primary injection are that the CT
itself is subjected to test and that it is not necessary to
disturb any of the secondary protective circuits.
17
Primary Injection Test Sets
18
Primary Injection Test
19
Secondary Injection test
9 Secondary injection does not test the CT itself.
Varying the injected current enables the operating
settings of the connected relays to be set up or
checked and the continuity of the relay circuit to be
verified. 20
POLARITY CHECK
21
Ratio check
22
Magnetization Curve
It is recommended that an autotransformer of at least
8 amperes rating be used when the current
transformers being tested are rated at 5 amperes
secondary.
transformers with secondary ratings of 1 ampere or
less have a knee point voltage higher than the local23
mains supply.
VOLTAGE TRANSFORMERS
¾ Types Of VT’s
a) Oil-filled withdrawable moving portion with an
air insulated fixed portion (for 3.3 to 13.8 kV ) or a
compound insulated fixed portion (for 22/33 kV ).
b) Air insulated or dry-type with drawable
moving portion with an air insulated fixed portion
c) Tilting air insulated dry-type
¾ Polarity check As CT test
¾ Ratio check
This check can be carried out when the main circuit is
first made alive. The voltage transformer
secondary voltage is compared with the secondary
voltage of a voltage transformer already connected
24
to the same primary bars.
Typical specification for a 11 kV VT
9 System voltage: 11 kV
9 Insulation level voltage (ILV) : 12 /28/75 kV
9 Number of phases: Three
9 Vector Group: Star / Star
Ratio: 11 kV/ 110 V
9 Burden: 100 VA
Accuracy: Class 0.5
9 Voltage Factor: 1.2 continuous and 1.5 for 30 seconds
With provision for fuse
25
Vector Group
26
Classification of Faults
1- Faults are classified into two major groups
• Balanced
• Unbalanced
2- Balanced Faults are the most severe. They involve all three phases possibly
connecting the fault point directly to ground (arc-resistance neglected) they
cause extremely severe fault currents and system disturbances.
3- Unbalanced Faults include phase-to-phase, phase-to-ground, and phase-to
phase to- ground faults. They are not as severe as balanced faults because not
all phases are involved.
4- During unbalanced faults negative and zero-sequence currents will flow
through “earth”.
5- Negative sequence currents, if sustained will cause overheating to machines.
Note that all Generators are “protected” against prolonged zero sequence
currents, which would otherwise cause overheating.
27
Relays
¾ Over current and earth fault
Widely used in All Power Systems
1-Non-Directional
2-Directional
¾ DIFFERENTIAL
For feeders, Bus-bars, Transformers,
Generators etc
1- High Impedance
2- Low Impedance
3- Restricted E/F
4- Biased
5- Pilot Wire
28
Relays
¾ Distance
For transmission and sub-transmission lines and
distribution feeders, also used as back-up
protection for transformers and generators
to provide unit protection e.g.:
1- Permissive under reach protection (PUP)
2- Permissive overreach protection (POP)
3- Unblocking overreach protection (UOP)
4- Blocking overreach protection (BOP)
5- Power swing blocking
6- Phase comparison for transmission lines
7- Directional comparison for transmission lines
29
Relays
¾ Miscellaneous:
1- Under and over voltage
2- Under and over frequency
3- A special relay for generators,
transformers, motors etc.
4- Control relays: auto-reclose, tap change
control, etc.
5- tripping and auxiliary relays
30
Relay Generations
Electromechanical Relays Electronic Relays
9 Overshooting Errors
9 Need more maintenance and 9Overshooting Errors-No
calibration. 9Setting through dip-switches
9Wide functions in same relay
9 Limited functions
9 Setting through dials & taps
31
Digital Relays
9 Simple & Smaller Size
9 Cheaper
9 Less Maintenance
9 Fault record & event logger,
9 Relay data accessed remotely.
32
The next generation of protective relays
9Past – electromechanical
9Present - static and µP
9Future - Intelligent?
(ANN, ES based, GA, etc …)
33
Inverse Over current Characteristic with different
TSM
34
Inverse Over current Connection
35
Over Current Relay Setting
Inverse Over current calibration FIND THE PLUG SETTING
/FL
x 100 %
/CT
( If intermediate, use next
higher )
FIND THE EFFECTIVE
CURRENT
/CT x % plug setting
(as a fraction)
FIND RELAY OPERATING
LINE
/SC
Effective Current
DRAW HORIZONTAL LINE
THROUGH THE REQUIRED
TIME DELAY TO CUT
VERTICAL RELAY
OPERATING LINE, POINT ‘P’
READ OFF THE TIME
MULTIPLIER AT
CROSSOVER POINT
(TAKING NEXT HIGHER (‘Q’)
IF NECESSARY)
/FL = Full load current of circuit
/CL = Rated primary current of CT
/SC =
36
Short circuit current (i.e. calculated short circuit current at point of
fault)
Setting of an Inverse Time Overcurrent Relay
1-Connect the secondary injection current set to the relay (
coil and contact)
2- Applying the normal rated current should not affect the
relay to trip and current injection counter will continue
counting without stopping if the relay is healthy.
3-At the specified time dial, apply number of multiples of
the rated currents and record the tripping time for each
value.
4-The resultant records to be compared with the actual
values from relay characteristic curves as in Figure
5-Chang the time dial and repeat steps 4 and 5 to verify the
characteristic curves.
37
Inverse Over current Characteristic with different TSM
38
Example for Setting of an Inverse Time Overcurrent Relay
It is required to determine the current and timing settings
on an OCIT relay to give a 1.35s delay with a short-circuit
current of 5 000A. Full-load current is 450A and the CT
ratio is 400/1A.
/
400/1 FL = 450 /
SC = 5000
A A
450
Plug setting = x 100 = 112.5 (use 125%) Desired Time Delay
400 1.35 s
Effective current = 400 x 1.25 = 500 A
5000
Relay operating line = = 10 R
500
Desired time delay = 1.35 s
Time multiplier seeing at crossover (‘P’) = 0.44 by interpolation. use next higher 0.5
(‘Q’)
Reading across, actual time delay achieved = 1.5 s
39
Directional Over-current Relay
•“ O” The over current relay is sensitive only to current and
operates on an inverse time-current curve
•“D” The directional element has both voltage and current
inputs and compares the phase angle between the current
and the voltage, allowing it to determine the direction of 40
current flow
Directional Over-current Relay
• If non-directional relays are used, two or more lines may be tripped when a
fault occurs.
•Relays R1, R3 and R5 will trip for faults in the direction of S1,
R5 will have the highest setting.
•
•Relays R2, R4 ad R6, will trip for faults in the direction of S2, R2 will have
the highest setting.
• Relays R3 and R6 will not see a fault between breakers 4 and 5, and relays
R4 and R5 will pickup before any relays (e.g. R2) that can see the fault.
41
Inverse Time Over-current Relay
42
Inverse Time Over-current Relay
• If Fault current is 4 kA in line B ,
• R2 will operate in 0.2 sec’s,
• R1 will take 0.5 seconds to operate, 0.3 seconds after R2.
• If R2 does its job in 0.2 seconds, the relay R1 will “reset”.
• Should R2 fail to operate, or breaker 2 fails to open then
43
R1 will trip in 0.5 seconds, thereby opening breaker 1 to clear the fault.
Ground Over-current Relays (Earth fault relays)
• It is set to extremely current sensitive and with a very short operating time
• The ground relay (G) can be set for a much lower pickup than the phase
relays.
• It is useful on Transmission Networks e.g. for a transformer, to cover “low-
44
end” winding faults
Unrestricted E/F
45
Restricted E/F (REF) - ANSI 64
9 High Sensitivity REF with Neutral Resistance Earthing
9 Low Sensitivity REF with Solidly Earthing.
All CTs should have the same ratio and accuracy
46
Restricted E/F
47
Differential Protection
No Internal Fault
48
Differential Protection
Internal Fault
49
Percentage Differential Relay
• Operating current of 2A
• Average restraining current of 9A ( [10+8] / 2 ) .
• The percentage is therefore 22% (=2/9) .
• The relay would not operate if it were set on the 40% slope.
50
• Various slopes can be selected.
Operating Characteristics Of
Percentage Differential Relay
51
Percentage Differential Protection
OperatingCurrent
Slope% = X 100
Averagerestraincurrent
52
9Voltage Balance
53
Connection of VT’s and CT’s for Protection Relaying
Secondary Voltage = Primary Voltage / VT Ratio
Secondary Current = Primary Current / CT Ratio 54
Calculations for Secondary Voltage and Currents in a Relay
Circuit
55
Relay Code Numbers (ANSI)
56
Relay Code Numbers (ANSI)
57
Relay Code Numbers (ANSI)
58
Distance Relays
This relay calculates impedance from the voltage and current applied to it
It closes when the impedance is below its set-point (pick-up) of the relay.
59
Distance Relays
It does this in the electromechanical relay by developing positive torque
(contact closing) that it is proportional to the current, and negative torque
(restraint) proportional to the voltage applied to it.
It will thus wish to close its contacts when the voltage is low and/or the
current is high.
It responds to the ratio of voltage to current. ( V/I = Z )
60
Distance Relays
Distance relay-operating principles explained fundamentally by the balanced beam
impedance unit:
(a) distance relay to line GH;
(b) simplified explanation diagram with a beam unit.
61
Distance Relays
62
Distance Relays
•To protect 90% of the 40 kM line, we set the relay “reach” at
ZR = 27 x (240/1000) = 6.48 ohms
• Whenever the relay “sees” an impedance of 6.48 ohms or less, the relay
will operate.
• For normal load currents, the impedance seen by the relay will be too
high to cause it to operate.
63
Distance Relays
• All 3 zones of R1 trip CB No.1
• All 3 zones of R2 trip CB No. 2
• Zone 1 of relay 1 is set with a reach of 90% of line A and trips the
breaker instantaneously.
It looks like an instantaneous over-current relay for all faults
within its range.
64
Distance Relays
• The reach of zone 2 of relay 1 is set to cover around 50% of line B.
It will recognize any fault in this with time delay 0.3 seconds.
• Zone 2 of relay 1 provides primary protection for the remaining
part of line A and remote backup for the first 50% of line B.
• Zone 3 of R1 is set to reach beyond the end of line B and delays
tripping for 0.6 seconds.
• Zone 3 of relay 1 provides backup protection for the last 50% of 65
line B
Distance Relays
• If a fault occurs in the middle 80% of the line, both relays will see a
zone 1 fault and trip instantaneously.
•If a fault occurs in the first 20% of line (closest to R1)
R1 will trip its breaker instantaneously
R2 will see a zone 2 fault and delay tripping for 0.3 seconds.
• If the fault is in the last 20% of the line from R1
R2 will trip its breaker at high speed
R1 will delay its breaker.
66
Inter-tripping and Acceleration
Direct Under-reach Transfer Trip
• The max. trip time delay allowed On all but minor sub-transmission and
distribution systems is 300 m. seconds
• Communications channel between the two ends of the circuit is provided
using PLC, Microwave, Fiber Optic and so on. 67
Permissive Under-reach Transfer Trip Relaying
• For an internal fault at location A,
1-The first zone “under-reaching” relay (Ru) at CB 2 will see
the fault, it will immediately trip CB 2
2- It will send a signal to bus 1.
3- The contact (T) will close “permitting the second zone
overreaching relay (RO), which will trip CB 1.
68
• zone 2 timer is “shorted out”.
Directional Comparison Relaying
• It uses the transmitted signal as a means of blocking tripping.
• Tripping can only occur when no signal is received.
• For an internal fault at A
1- Neither CS (Carrier Starting) relay will not operate
2- No carrier signal will be transmitted from either terminal and
non will be received.
3- The receiver relay contacts R will be closed.
4- Both trip relays (T) will energize since no signals are received to
block tripping, there will be high speed tripping at both ends.
69
Directional Comparison Relaying
• For an external fault at B
1- Trip relay (T) at CB 1 will operate, the CS relay at 1 will not.
2- At CB 2, the CS relay will operate but the T relay will not.
3- A carrier signal will be transmitted from bus 2 and will be
received at busses 1 and 2.
4- At bus 1 this signal will block tripping by the T relay.
5- At bus 2 this signal simply helps assure that no tripping will
occur.
70
Phase Comparison Relaying
•This scheme uses the signals sent over the communication channel
to compare the phase angles of the currents at either end of the line.
• For an internal fault (at A), the currents at the busses are 180
degrees out of phase,
• For an external fault (at B), the two currents are almost in phase.
71
Pilot Wire Relaying
• The pilot wire relay is often used for protecting short lines ( <= 15 Km ).
• It is also used for protecting longer lines, using other forms of
communications, such as Power Line Carrier (PLC) and fiber optic.
72
Pilot Wire Relaying
•Over-current relays can not be used , the magnitude of fault current for a
fault on the protected line section and for faults on adjacent sections is not
much different.
• Distance relays can not be used where the accuracy in measuring the line
impedance (or distance) might be plus or minus a few kM.; this is sufficient
for a 40 to 100 kM line, but not for a line shorter than about 15 kM.
73
Pilot Wire Relaying
• If a pilot wire becomes open circuited the relay will, however, trip for an
internal or external fault.
• In order to assure that the relay will not trip for load current with an open-
circuited pilot wire, the relay pickup is set above the maximum anticipated
load current. 74
Pilot Wire Relaying
• If the pilot wire becomes shorted, one or both relays may be completely
disabled.
• It will not be able to discriminate between internal and external faults, and
will operate for both types of faults.
• Pilot wire monitoring relays are always installed to alarm operators if an
open or short occurs on the pilot wire circuit.
•A pilot wire is usually buried with the utility cable. In some cases the 75
circuit is rented from the local Telephone company.
Co-ordination procedure
The data required for a relay setting study are:
• A one-line diagram of the power system involved, showing the type
and rating of the protective devices and their associated current
transformers.
• The impedances in ohms, per cent or per unit, of all power
transformers, rotating machines and feeder circuits.
• The maximum and minimum values of short circuit currents that are
expected to flow through each protective device.
• The starting current requirements of motors and the starting and
stalling times of induction motors.
• The maximum peak load current through protective devices.
• Decrement curves showing the rate of decay of the fault current
supplied by the generators.
76
Co-ordination procedure
The data required for a relay setting study are:
• Performance curves of the current transformers.
• The relay settings are first determined so as to give the shortest
operating times at maximum fault levels
• Check if operation will also be satisfactory at the minimum fault
current expected.
• It is always advisable to plot the curves of relays and other
protective devices, such as fuses, that are to operate in series, on a
common scale.
• It is usually more convenient to use a scale corresponding to the
current expected at the lowest voltage base or to use the
predominant voltage base.
• The alternatives are a common MVA base or a separate current
scale for each system voltage.
77
Microprocessor-based Relays
Relay for Generator Protection
78
Microprocessor-based Relays
Feeder Management Relay
79
Microprocessor-based Relays
Motor Management Relay
80
Microprocessor-based Relays
Circuit Breaker Management Relay
81
Microprocessor-based Relays
Bus Bar Protection Relay
82
Microprocessor-based Relays
Over-current Relay (Dual Powered Version)
83
Microprocessor-based Relays
Microprocessor devices comprise:
1. Hardware
2. Firmware
3. Software
Hardware and Firmware :
1. Power supply module
2. Main board
3. Co-processor board
4. Internal Communication board*
5. Input module
6. Input and output boards
7. IRIG-B board
84
System Architecture - Busbar Protection Relay
85
Bus Zone Protection scheme - protecting double
Bus-bar with transfer bus 86
Sample of the functions implemented in relays can be split into five
main elements:
1. Operating system
2. System services software,
3. Platform software,
4. Communication software,
87
5. Protection and control software.
