TRANSFORMER PROTECTION

1. Power Transformer & Distribution
Transformer Protection

2. Transformer Protection
Session -1
Outlines :
• What fails in Transformer?
• Types of Transformer Faults
• Transformer Protection Philosophy
• Selection Of Protection Scheme for Power and Distribution
Transformer
• Conventional Protection Scheme For Power Transformer
• Grouping of Protection
• Power Transformer Magnetizing Inrush Current and
Methods of Minimizing magnetic inrush Current
2

3. What Fails in Transformers?
Windings
- Insulation deterioration
from:
▪ Moisture
▪ Overheating
▪ Vibration & Impact
forces due to
through-fault current
▪ Voltage surges
▪ Mechanical Stress
from through-faults
▪ OLTCs
- Malfunction of mechanical
switching mechanism
- High resistance contacts
- Overheating
- Contamination of
insulating oil 3
▪ Bushings
- General aging
- Contamination
- Cracking
- Internal moisture
▪ Core Problems
- Core insulation failure
- Shorted laminations
- Core overheating
▪ Miscellaneous
- CT Issues
- Oil leakage
- Oil contamination
▪ Metal particles
▪ Moisture

4. Classification of Transformer Faults
4
•Transformer Faults
•Internal Faults
•Quick Acting
•Slow Acting
•External Faults

5. 2
❑ Internal Faults:
Faults develop inside transformer tank bushings, conservator or radiators may be
defined as internal faults. Transformer internal faults can be classified into two
groups.
Quick acting faults:
► Electrical faults which cause serious damage immediate after the
inception.
► Phase to phase or phase to earth fault in windings, inter-turn fault in
windings, core fault, bushing failure etc.
Slow acting faults:
► Faults those develop slowly over time. These type of faults may suddenly
convert into quick acting faults.
► Poor electrical connection of conductors that causes limited arching
(partial discharge) in oil, leakage in tank, clogged or contaminated oil,
formation of slug in oil etc.
► Oil quality degradation causes rise of temperature even below full load
operation.
► Poor voltage regulation or bad load sharing between transformer running
in parallel may cause overheating due to circulating current.

6. ❑ External Faults:
Continuous over loading
Power system faults
Over voltage
Under frequency
Environmental impact etc.
► Overloading of transformer reduces life time of transformer
► Power system faults causes mechanical stress to transformer
► Over voltage, transient over voltage or under frequency causes
over fluxing which increases iron loss and damages insulation.

7. 7
❑ Protections provided by external protective relays:
▪Transformer Differential Protection (87T)
▪Restricted Earth Fault (REF) Protection (87N)
▪Time Delayed Over Current & Earth Fault Protection (51/51N)
▪Instantaneous Over Current & Earth Fault Protection (50/50N)
▪Directional Over Current & Earth Fault Protection (67/67N)
▪Over Fluxing Protection (24)
❑ Mechanical/Self Protection (Provided within the transformer ):
▪Main Tank Buchholz Protection ( Alarm/Trip)
▪OLTC Buchholz Protection (Trip)
▪Pressure Relief Device (PRD) Protection (trip)
▪Winding Temperature Protection (Alarm/Trip)
▪Oil Temperature Protection( Alarm/Trip)
▪Oil Level Alarm
Protection Functions/Relays Applied in Transformer

8. 8
Protection Philosophy of Distribution & Power Transformer
Protection
Function
<10 15/20 20/35 25/41 35/50 50/75 66/100 80/120
87T1 X √ √ √ √ √ √ √
87T2 X X X X X √ √ √
87N/64R X X √ √ √ √ √ √
50/51 √ √ √ √ √ √ √ √
50N/51N √ √ √ √ √ √ √ √
67/67N (║) X √ √ √ √ √ √ √
49 X √ √ √ √ √ √ √
24 X √ √ √ √ √ √ √
Buchholz √ √ √ √ √ √ √ √
PRD √ √ √ √ √ √ √ √
WTI √ √ √ √ √ √ √ √
OTI √ √ √ √ √ √ √ √
Fuse √ X X X X X X X

9. 9
Protection Philosophy of Transformer

10. Conventional Protection Scheme of a Two Winding Transformer
50 51
Δ
50 51 50N
87T
87N
51N 49

11. ❑ Redundancy is a key factor for transformer protection. Therefore, protection
functions/relays are divided into “Group A Protection” “Group B protection” to
obtain reliable redundancy.
The group A and group B protection are connected through separate DC
source.
All the Group-A and Group-B protection functions energize separate
lockout relays (86-1 & 86-2) respectively to trip the circuit breaker during
fault.
Generally Group-A protection consists of 87T, 50/51(HV), 49, Buchholz,
WTI, PRD.
Generally Group-B protection consists of 87N, 49, Buchholz, OTI, PRD,
OSR
Cross tripping is also configured/established between 86-1 & 86-2.
In numerical relays mechanical/self protections tripping are configured and
activated by switching on opto-input of relays.
In case of LV 50/51 only LV CB shall be tripped (by separate lockout
relay). But if 67/67N are available and activated then 67/67N will trip both
HV & LV CB.
Note: Here HV winding is considered as delta and LV as star.
Grouping of protection:

12. According to Faraday's law of electromagnetic
induction the voltage induced across the winding is is given as e =
dφ/dt. Where φ is the flux in the core. Hence the flux will be
integral of the voltage wave.
If the transformer is switched on at the instant of voltage zero, the
flux wave is initiated from the same origin as voltage waveform, the
value of flux at the end of first half cycle of the voltage waveform
will be,
•
•
Where φm is the maximum value of steady state flux. The
transformer core are generally saturated just above the maximum
steady state value of flux. But in our example, during switching on
the transformer the maximum value of flux will jump to double of
its steady state maximum value. As, after steady state maximum
value of flux, the core becomes saturated, the current required to
produced rest of flux will be very high. So transformer primary will
draw a very high peaky current from the source which is
called magnetizing inrush current in transformer or
simply inrush current in transformer.
Power Transformer Magnetizing Inrush Current

13. Power Transformer Magnetizing Inrush
Current
13

14. 14
Transformer steel core retains a static magnetic field if power is removed (i.e. if
the transformer is taken out from service).
This residual field causes a high inrush current when power is reapplied (i.e. if
the transformer is put back into service).
This high inrush current exists only at the source side of power transformer.
This inrush current remains until effect of the remnant magnetism is reduced,
usually after a few cycles of the applied alternating current.
Transformer protection devices must be selected to allow this harmless inrush to
pass through it.
Power Transformer Magnetizing Inrush Current

15. 15
Factors that affect the Inrush Current-
▪ Switching instant on the voltage waveform at which the transformer is
energised.
▪ The magnitude and polarity of the residual flux present in the
transformer during re – energisation.
▪ Rating of the transformer.
▪ Total resistance of the primary winding.
Average Values of Magnetizing Inrush Current of Power Transformer:
Power Transformer Magnetizing Inrush Current
MVA
Rating
Magnetizing Inrush Current (times rated current)
Cold Rolled Steel Hot-Rolled Steel
HV LV HV LV
1.0 8.4 14.0 4.8 7.0
5.0 6.0 10.0 3.9 5.7
10.0 5.0 10.0 3.2 3.2
50.0 4.5 9.0 2.5 2.5

16. 16
❑Methods of Minimizing Magnetic Inrush
Current:
❑Neutral Earthing Resistors: Optimal neutral resistor on the transformer can
significantly reduce the inrush current magnitude and duration. The neutral
earthing resistor limits the current going through the neutral which in turn
controls the inrush of current during the first and second phase energisation.
❑Pre – Insertion of resistors: Resistors are typically inserted into the capacitor –
energising circuit for 10 – 15msec prior to the closing of the main contacts,
through the closing of an additional set of contacts. Synchronisation between
the resistor and the main contact is required and is usually achieved by
connecting the resistor contact rod directly to the main contact control rod.
Once the switching has been achieved, the resistor is then switched off from the
circuit.
❑Controlled Switching: In this method, simply the transformer will be energised
phase by phase at the corresponding voltage peak (switching angle of voltage
will be Π/2). This strategy of switching seems to be accurate and reliable.
However, the drawback of such a mechanism is the cost involved in the
implementation of the technique. The practical power system employs the use
of gang operated circuit breakers. When using the point – on wave switching
strategy, the circuit breakers are needed to be replaced with single pole circuit
breakers. The figure (8), shows the block diagram of this strategy.
Power Transformer Magnetizing Inrush Current

17. Component DC 2nd
3rd
4th
5th
6th
7th
Typical Value 55% 63% 26.8% 5.1% 4.1% 3.7% 2.4%
❑Relay Solutions to the Inrush Current Problem
Since the inrush current exists only at the source side of power
transformer, so it appears at the differential protection circuit and will
operate the relay if it is not blocked or bypassed. The most effective
method applied to avoid differential protection operation during
transformer energization is the-
▪Harmonic restraint method
Power Transformer Magnetizing Inrush Current
❑ Amplitude of Harmonics in a Typical Magnetizing Inrush Current
Wave Shape:

18. 18
Power
Transformer
Magnetizing
Inrush
Current

19. Transformer Protection
Session -2
Outlines :
• Transformer Differential Protection (87T)
• Transformer Restricted earth fault protection (REF)
• Thermal overload protection (49)
• Transformer Over Fluxing Protection (24)
• Distribution Transformer Protection by Fuse
• Mechanical self-protection body protection of transformer
(Buchholz relay, oil surge relay, PRD, OTI, WTI, MOG)
19

20. Transformer Differential Protection (87T)
Basics:
▪Transformer differential
protection is a unit protection
scheme that compares currents
of each side of the transformer.
▪Any difference in currents
between/among the sides that is
beyond the set value indicates
transformer internal fault and
the relay instantaneously trips
the relevant circuit breakers.
Y
87T2
87T1

21. Transformer Differential Protection (87T)
21
❑ Principle of Operation:
The operating principle of transformer differential protection is
basically the Merz-Price circulating current measuring principle
as shown below.
Under normal condition I1
and I2
are equal and opposite so that the
resultant current through the relay is zero.
An internal fault produces an unbalance or 'spill' current that is
detected by the relay, leading to operation of the CB to isolate the
fault.

22. Challenges to Transformer Differential
Protection
• Transformation ratio Current Mismatch
• Differing CT Ratios.
• Delta‐Wye Transformation of Currents.
• Phase Angle Correction.
• Zero Sequence elimination.
• Tap Changer Current Mismatch.
• Magnetic Inrush, Harmonic Content, Over
Excitation
• CT Saturation.

23. 1/14/2020
Differential Protection - Principle
R I diff = 0
• Nominal current through the protected equipment
I Diff = 0 : No tripping
23

24. 1/14/2020
Differential Protection - Principle
• Through fault current
I Diff = 0 : No tripping
R I diff = 0
24

25. 1/14/2020
Differential Protection - Principle
Tripping
• Internal Fault
I Diff ≠ 0 :
R I diff ≠ 0
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26. 1/14/2020
Biased differential protection
1 A
100/50 KV
100 / 1 200 / 1
1 A
0 A
LOAD
= 200 A
Why bias characteristic
?
OLTC Setting is at mid tap
R
I1
I2
26

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Biased differential protection
100/50 KV
100 / 1 200 / 1
0.9 A 1 A
0.1 A
Relay pickup setting = O.2 A, So the Relay restrains
LOAD
= 200 A
OLTC SETTING IS AT +10%
Differential current = 0.1 A
R
27

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Biased differential protection
100/50 KV
100 / 1 200 / 1
9 A 10 A
1 A
Relay Pickup Setting is O.2 A
OLTC SETTING IS AT 10%
2000 A
R
Operates
So the Relay
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Biased differential protection
100/50 KV
100 / 1 200 / 1
9 A 10 A
19 A
2000 A
R
Bais coil Bais coil
9 A 10 A
29

30. Transformer Biased Differential Protection

31. Differential Protection Setting Calculations
Unrestraint Differential Threshold
31

32. 32
❑ Differential Protection Start:
Differential and bias currents are
above the operate-restrain
characteristic.
❑ Section 1
Minimum operating current
required to initiate differential
protection trip.
❑ Section 2
Minor slope to cope up with false
differential currents due to higher
load current
❑ Section 3
Higher tolerance to substantial CT
saturation at high trough fault
currents
Transformer Biased Differential Protection Operating Characteristics

33. Trip Characteristic – 87T
• Trip Characteristic – 87T
▪ 87T Pickup
- Set above the magnetizing current and other CT inaccuracies & OLTC
- 0.2 to 0.4 p.u. (typical setting)
▪ Slope 1
- Set to accommodate +/- 10% CT inaccuracies
- OLTC adds another +/- 10%
- Used for currents < 2X nominal
- Typically set for 25% to 30% (can be set lowerfor non
OLTC transformers)
▪ Slope 2 “breakpoint”
- Typically set at 2X rated current
- This setting assumes that any current over 2X rated is a fault condition and
is used to desensitize the element against unfaithful replication of currents
due to CT saturation
Slope 2
- Typically set at 50% to 70%
- Prevents relay misoperation for though faults with CT saturation.
33

34. Trip Characteristic – 87T
Inrush Restraint (2nd and 4th harmonic)
- Relay uses 2nd and 4th harmonics
- Percent harmonics defined as – Amount of 2nd and 4th harmonics depend on:
Magnetizing characteristics of transformer core
Residual magnetism in core
- Typical Settings : -15% for most transformerer (can be 10% or lower on new transformers
with low core losses and steep magnetizing curves. Setting below 10% risks blocking for
internal faults.)
- Over excitation Restraint (5th harmonic)
- Typically set at 30%
- Raise 87T pickup to 0.60 pu during over excitation
- No cross phase averaging is needed, as the magnetizing currents during over excitation
condition are symmetrical
• Trip Characteristic – 87H
- Typically set at 8 to 12 pu rated current
- This valueshould be set to above possible inrush current.
- Relay oscillograph analysis software can be used determine the inrush current level and
fine tune the setting.
- Also, need to know if the high set element uses fundamental component of current (typically
the case) or total RMS current and set the pickup appropriately.
34

35. Transformer Differential Protection With Matching CT
35

36. REF Introduction
Why REF is Needed?
REF provides much better sensitivity
Fault currents on primary side (IP
) are low in case of earth fault on resistive earthed windings,
hence no full winding protection is possible relying only on differential protection
0.
2
1.
0
Current
(x full
load)
1.
0
0.
2
IP
IF Sourc
e
IS
I
F
R
R
Fault position from
neutral
Differential relay setting % of Star winding protected
10% 58%
20% 41%
30% 28%
40% 17%
50% 7%
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37. 1/14/2020
Earth fault on Transformer winding of resistive
neutral
132/33kV
IF
Voltage ratio=a:1
Turns Ratio= (aX1.732):1
a=(132/33)=4
x
a*1.732
The ratio of transformation between the primary winding and the short circuited turns
also varies with the position of the fault, so that the current which flows through the
transformer terminals will be proportional to square of the fraction of the. winding which
is short circuited.
Earthing resistance is rated to pass
full load current on earth fault.
Full load current IFL
= vph
/R
For a fault at = x
Fault current IF
=x.IFL
Effective turns Ratio= a*1.732: X
IP
IF
= x
a*1.732
IP
=
x*IF
a*1.73
2
=
(0.577.X2
.IFL
)/a
R
Vp
h
37

38. If Primary CT ratio is based on full load primary current then fault
current on CT secondary= 0.577*X2
.
If differential setting Id= 20%
For relay operation 0.577*X2
> 20%
X> 59
Therefore differential relay will operate if fault is beyond 59% of
secondary winding
Differential relay setting % of winding protected
10% 58%
20% 41%
30% 28%
40% 17%
50% 7%
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Earth fault on Transformer winding of resistive
neutral

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Earth fault on Transformer winding of solid
Grounding
2
T
X
If
V2 V
Fig.
3
132/33kV
39
fault current limited only by the leakage reactance of the winding

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Restricted Earthfault Protection
P1
S1
P2
S2
P1
S1
P2
S2
P1
S1
P2
S2
P1
P2
S1
S2
Stability level : usually maximum through fault level of
transformer
REF Case I : Normal Condition
Under normal conditions no current flows thro’ Relay
So, No Operation
40

41. 1/14/2020
Restricted Earthfault Protection
REF Case II : External Earth Fault
External earth fault - Current circulates between the phase & neutral CTs;
no current thro’ the relay
So, No Operation
41

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Restricted Earthfault Protection
REF Case III : Internal Earth Fault
For an internal earth fault the unbalanced current flows thro’ the relay
So, Relay Operates
42

43. -Pickup of 0.2 to 0.5 A (5A rated CTs) can be applied
when using same ratio CTs on both phase and ground
circuits.
-Use 6 cycle time delay to provide security against
mis-operations during external phase-to-phase to
ground faults with CT saturation. The time delay must
not be set below 2 cycles.
Trip Characteristic – 87GD (REF)

44. 44
Over Fluxing Protection (24)
Transformer over-fluxing may be a result of -
• Overvoltage & Low system frequency.
EMF = E = 4.44fΦmN =>E/f = 4.44 ΦmN ; Φm ∞ K* E/f (V/Hz)
✔Transformers are designed to operate at or below a maximum magnetic flux density of the core.
✔Above that design limit, the eddy current in the core and nearby conductive components causes
overheating which within a very short time may cause severe damage.
✔Over excitation occurs when volts per hertz level rises (V/Hz) above the rated value
✔This may occur from:
Load rejection (generator transformers)
Malfunctioning of voltage and reactive support elements
Malfunctioning of breakers and line protection (including transfer trip communication
equipment schemes)
Malfunctioning of generator AVRs
▪The voltage rise at nominal frequency causes the V/Hz to rise
▪This causes the transformer core to saturate and thereby increase the magnetizing
current.

45. Overfluxing
Typical Transformer Withstand
V/f (pu) 1.1 1.15 1.2 1.25 1.3 1.35 1.4 1.45 1.5
Minutes 65 7 2 0.8 0.4 0.22 0.13 0.09 0.06
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46. 46
❑ During over load condition excessive load current
through the transformer causes over heating of
transformer winding and insulating oil.
❑ To prevent damage of the winding insulation, thermal
overload protection is applied.
❑ It is basically an over current protection implemented in
both windings of the transformer.
❑ Tripping is time delayed. Firstly, alarm is generated then
tripping is executed.
Thermal Overload Protection (49)

47. 1. Buchholz Relay (Main Tank & OLTC)
2. Pressure Relief Device
3. Oil Temperature
4. Winding Temperature
5. Oil Level Indicator/ Magnetic Oil Gauge (Only Alarm)
Mechanical/Self Protections of Power Transformers-

48. Transformer Conservator tank assembly

49. 1/14/2020
Oil
conservator
Bucholz Relay
BUCCHOLZ PROTECTION
49

50. Transformer Bucholz Relay

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Accumulation of gaz
Oil Leakage
Severe winding faults
Buccholz Protection Application
BUCCHOLZ PROTECTION
51

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Buchholz Relay
Petcoc
k
From
transformer
Deflector
plate
Trip
bucket
To oil
conservat
or
Mercury
switch
Alarm
bucket
BUCCHOLZ PROTECTION
52

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Buchholz Relay
Accumulatio
n of gaz
BUCCHOLZ PROTECTION
53

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Accumulatio
n of gaz
Buchholz Relay
BUCCHOLZ PROTECTION
54

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Color of gaz indicates
the type of fault
White or Yellow :
Insulation burnt
Grey :
Dissociated oil
Accumulation
of gaz
BUCCHOLZ PROTECTION
55

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Accumulatio
n of gaz
Gaz can be extracted
for detailled analysis
Buchholz Relay
BUCCHOLZ PROTECTION
56

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Accumulation of gaz
Oil Leakage
Severe winding faults
Bucholtz Protection Application
BUCCHOLZ PROTECTION
57

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Oil Leakage
Buchholz Relay
BUCCHOLZ PROTECTION
58

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Oil Leakage
Buchholz Relay
BUCCHOLZ PROTECTION
59

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Oil Leakage
Buchholz Relay
BUCCHOLZ PROTECTION
60

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Oil Leakage
Buchholz Relay
BUCCHOLZ PROTECTION
61

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Accumulation of gaz
Oil Leakage
Severe winding faults
Buccholz Protection Application
BUCCHOLZ PROTECTION
62

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Severe winding fault
Buchholz Relay
BUCCHOLZ PROTECTION
63

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Severe winding fault
Buchholz Relay
BUCCHOLZ PROTECTION
64

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Severe winding fault
Buchholz Relay
BUCCHOLZ PROTECTION
65

66. 66
Pressure Relief Device (PRD)
Basics:
During an internal faults of a power transformer, there will be an increment
in temperature associated with formation of gases, impurities in oil etc.
This pressure may be sufficient enough to damage the transformer.
Pressure relief device (PRD) is applied to prevent the transformer from this
danger.
Pressure Relief Device is a safety element of the transformer that employs to
prevent heavy damages of the tank in the case of sudden rise of the internal
pressure.
These device has been designed in order to remove the excess pressure in a very
short time as soon as the pressure in the tank rises above predetermined safety limit
PRD operates and allows the pressure to dip instantaneously and avoids damage of
the transformer body.
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67. 67
Fig. Pressure Relief Device
1/14/2020

68. 68
Pressure Relief Device (PRD) Operation:
The pressure relief device consists of a spring which normally is uncompressed and
when transformer tank pressure increases the spring gets compressed and gives a path
of gases to go out of the transformer.
Compressing the spring closes an electrical contact, and this contact gives trip command to
circuit breakers associated with alarm.
Following Figure (shows the pressure relief device in the normal condition (before the fault
inception):
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69. 69
Following figure shows the fault condition at which the
compressed gases get passage to let the gases out from the
transformer.
Pressure Relief Device (PRD) Operation:
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70. 70
Winding & Oil Temperature Protection
By making a "Thermal Image" of the
winding the winding temperature indicator,
simulates the winding temperature.
The temperature of the winding depends on
the transformer load (i.e. the current through
the winding) and the temperature of oil.
Temperature is measured with a bulb in a
pocket.
It has a specially designed heating element, to
measure the transformer load.
This heating element is a thermal model of
the winding.
The heating element is connected to the
current transformer (CT) via a Matching
Resistance or a Matching Unit, to allow setting
the correct winding temperature gradient.
Winding Temperature Indicator
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71. Winding Temperature Indicator Basic Scheme

72. 72
Operation of Winding Temperature Protection
Generally winding temperature indicator consists of four N/O
contacts which normally close as per the pre set value of temperature.
These contacts can be assigned as follows:-
1.The first contact is used for automatic operation of first fan
group.
2.The second contact is used for automatic operation of second fan
group, this value is higher than the first contact setting.
3.If the cooling fans are not sufficient to retain the transformer
temperature to its normal value, the third contact is applied to feed
alarm circuit.
4.As a last step, the fourth contact is applied for tripping to prevent the
transformer from high temperature condition. Normally it trips the
load side breaker, (i.e. the secondary side CB)
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73. 73
Oil Temperature Protection
Oil Temperature Indicator:
Oil temperature indicator is similar
to winding temperature indicator
except that it depends only on the
temperature transferred by the bulb
(no current transformer is used).
It consists only of two contacts.
These contacts are similar to the
third and the fourth contacts of the
winding temperature indicator but
with preset values less than winding
temperature indicator by
approximately 5-10 degrees.
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74. 74
Oil Level Indicator
Oil level indicator with magnetic joint is usually used on transformer
conservator.
It is mounted on the body of the conservator.
Its function is to give a visual alarm of the oil level contained in the
conservator.
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75. Transformer Oil Level Indicator

76. Protective Relay Testing and Maintenance
Session -2
Outlines :
• Testing Precautions
• Testing Procedure
• Test Set used for relay testing
• Relay Testing Report preparation and Preservation
• Relay testing using current injection set
76

77. Protective Relay Testing and
Maintenance
• Protective relays are used extensively across the power system to remove
any element from service that suffers a short circuit, starts to operate
abnormally or poses a risk to the operation of the system. The relaying
equipment is aided in this task by instrument transformers that sense
power conditions and circuit breakers that are capable of disconnecting
the faulty element when called upon by the relaying equipment.
• Due to their critical role in the power system, protective relays should
be acceptance tested prior to being placed in service and periodically
thereafter to ensure reliable performance. In a normal industrial
application, periodic testing should be done at least every 2 years in
accordance with NFPA 70B 2016.
• Protective relay testing may be divided into three categories: acceptance
testing, commissioning, and maintenance testing
77

78. Testing Precautions
• To preclude inadvertent trips, before starting any relay test with protected
equipment in service, testing personnel must be familiar with relays and
associated circuits. When test blocks are used, ensure that removing or
inserting plugs will not open a CT secondary. Opening a secondary with the
primary energized will result in high voltage which can destroy the CT or
other equipment, be dangerous to personnel, and/or cause an inadvertent
trip. If test blocks are not available, before the relay CT circuit is opened,
CTs must be shorted by the shorting blocks provided by the manufacturer
or by shorting switches. Before removing any relay from service, be very
cautious; the unit may need to shut down for relay testing, or the unit may
have redundant protection and can continue to operate during testing. In
any case, do not allow the unit to operate without any relay protection
while testing.
78

79. • Visual and Mechanical Inspection
• Verify Protective Settings
• Insulation Resistance Tests
• Additional Electrical Tests
• Targets and Indicators
• Protection Element Tests
• System Functional Tests
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80. Protective Relay Testing
• a. Mechanical inspection:
• (1) Check to see that connections are tight. Loose connections may
indicate excessive vibration which must be corrected.
• (2) The relay must be examined for excessive debris. Debris can cause an
inadvertent path to ground causing the relay to trip or be damaged. Debris
can be removed by using canned air available at most electronics stores.
Never use an air compressor or plant air to remove debris due to possible
static electricity and moisture.
• b. Electrical tests and adjustments:
• (1) Using a digital multimeter, check the input voltage to the relay. If the
relay has a dual power supply, ensure jumpers are in the correct position
to provide the correct voltage.
• (2) If so equipped, the test function switch on the relay should be used to
ensure that all indicators are working correctly. Also, the reset should be
exercised to ensure this function is working.
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81. • Verify Protective Settings
• As-left relay settings should match the most
recent coordination and arc-flash study or
engineered setting files. Verify that all settings are
in accordance with the most recent protective
device coordination study or setting sheet
supplied by the equipment owner. This
information is often furnished on a time–current
curve of the coordination study displaying the
characteristics of the relay.
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82. Additional Electrical Tests
• Apply voltage or current to all microprocessor-based
relay analog inputs and verify correct registration of the
relay meter functions and verify SCADA metering values
at remote terminals.
Targets and Indicators
• For electromechanical and solid state relays, determine
pickup and dropout of electromechanical targets. Verify
operation of all light-emitting diode indicators and set the
contrast for liquid-crystal display readouts.
•
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83. Protection Element Tests
(1) Pickup. Gradually apply current or voltage to see
that pickup is within limits. Current or voltage
should be applied gradually to yield data which
can be compared with previous or future tests.
(2) For timing tests, it is important to test the relay
at multiple points on the timing curve. If a relay
does not operate within given specifications, it
may be necessary to adjust the relay.
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84. Test Equipments Use for Relay Testing

85. Relay Testing Report preparation and
Preservation
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86. 86

87. 87

88. 88

89. Relay testing using Current Injection SET
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90. Over current Relay test result