This document discusses condition monitoring of transformers using predictive maintenance technologies. It begins with an outline of the presentation topics, which include various predictive maintenance technologies for transformers like visual inspection, oil testing, infrared thermography, acoustic testing, and dissolved gas analysis. The document then discusses specific technologies in more detail, such as oil sampling and testing procedures, infrared imaging case studies that identified faults, and the steps for dissolved gas analysis from sampling to reporting. The goal of condition monitoring is to reliably maintain equipment and reduce breakdowns.

1. NTPC
National Capital Region
Commercial Division
Workshop on Condition Monitoring
of Transformers
Welcomes
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2. POWER TRANSFORMER
CONDITION MONITORING
Transformer is no nuisance equipment. It is a static equipment & works reliably unless
abused. Transformer do not develop fault within itself if proper condition monitoring as
well as periodic measures are adopted.
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UDAIPUR 29.02.2012

3. Presentation Outline CENPEEP
• NTPC Roadmap-Knowledge based maintenance
• PdM technology Matrix-NTPC
• Equipment Technology Matrix- Transformer
• PdM technologies used in Transformer
• Visual Inspection
• Oil Testing
• IRT
• Acoustics (Corona & PD)
• DGA
• Sweep Frequency Response Analysis-SFRA
• Doble Test (Tan delta)
• DP
• Axial winding Collapse-Hoop Buckling
• Testing of Transformer & Maintenance Schedule
• Oil Sampling & Testing Schedule
• Reporting
• RLA Methodology of Transformer

4. Preventive Maintenance (PM)
Corrective Maintenance (CM)
Proactive Maintenance (PAM)
Predictive Maintenance (PdM)
Reliability Centered Maintenance (RCM)
Risk Evaluation & Prioritization (REAP)
Knowledge Based Maintenance
Road-Map
Now
(2010)
We
were
here
(2003)
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5. Type of Maintenance Activities
• Also called breakdown or reactive
maintenance.
• Maintenance required after breakdown.
• Time based, scheduled maintenance
• Condition based. Useful to assess the
condition of equipment on line, detects
incipient faults. No shutdown required exp:
Vibration Monitoring, Oil analysis etc.
CM
PM
PdM
Forced
Preventive
Predictive
PAM
• Root Cause Based Maintenance to eliminate
the Maintenance requirement.
Proactive
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6. Goal
• The goal of RCM is to preserve equipment
function with the required reliability and
availability ( wrt present operating
conditions) at the lowest cost.
•To Contribute in improving Efficiency by
increasing reliability & availability of
equipments.
RCM
(Reliability Centered Maintenance)
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7. RCM is based on answers to
7 FUNDAMENTAL QUESTIONS
for each Equipment
1. What are the functions and associated
performance standards of the assets in its
present operating context?
2. In what ways does it fail to fulfill its functions?
3. What causes each functional failures?
4. What happens when each failure occurs?
5. In what way does each failure matter?
6. What can be done to predict and prevent each
failure?
7. What if a suitable pro-active task can not be
found?
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8. Economic Mix of all ( Rationalization of
PM,reduction in BM & increase in PdM)
Best possible mix: Increase in PdM, reduction
in PM & CM.
PdM CM
PM
PAM
Present
PM
CM
Objective of RCM
After RCM
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9. • Identification of Equipment of concern based on
plant History data, Break down W.O details etc.
•Identification of failure modes
and selection of appropriate task/strategy
for mitigation.
•Analysis & report preparation by the help of RCM
Software.
•Approval of Report by local Management & then its
scheduling for implementation.
• Continue this process by revisiting the equipments
Called “RCM Living Programme”.
Methodology CENPEEP

10. PdM Process: Information to Action
“Communication is 70% of the Issue”
Acquire Data Infer Information
From Data
Take Corrective
Action
Ÿ Utilize Field and Personnel
Experience
Ÿ Utilize Analysis Systems and Neural
Networks
Ÿ Maintenance Orders
Ÿ Post Maintenance Tests
Ÿ Operations & Procedures
Adjusted
Maintenance History
Operators Log
Batch Tests
Design Information
Process Parameters
(Temperature / Pressure / Flow)
Predictive and Condition
monitoring techniques
Performance
(Oil Analysis/ vibration
/ thermography, acoustics etc.)
NDE Inspection
Visual Inspection
FEED BACK
Predictive Maintenance (PdM)
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11. PdM (Condition Monitoring) Technology presently
used
• Visual observations/Operator rounds.
• Vibration Monitor
• Thermography : Hot spots, Cold spots (Air ingress
detection)
• Acoustic : partial discharge in transformers ( non
contact), Valve passing mechanical equipment (
contact method), Brg, detection etc.
• Lube Oil Monitoring.
• Wear debris analysis ( WDA) : Full spectrum
analysis, particle contents Analysis.
• Electrical tests (Motor Current Signature analysis)
Broken Rotor Bars
• DGA : oil transformers

12. ContactAir borne
Transformer Y Y Y Y Y Y X Y
PUMP Y X Y Y X X FLOW Y
FANS X X Y X X X X Y
BUSHINGS X Y Y X X X X Y
CONTROL
CABINET
X Y Y X X X X Y
OLTC Y X Y X X Y X Y
DGA Special
Tests
Visual
Equipment Ultrasonic Test IRT Vib Sound
EQUIPMENT TECHNOLOGY MATRIX
FOR TRANSFORMERS IN GENERAL
• USE OF MULTIPLE TECHNOLOGIES
• HEALTH OF EACH EQUIPMENT IS MEASURE OF
HEALTH OF TOTAL EQUIPMENT.
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13. Use of Multiple technology to get information &
validation Of Data
Motor
Current
Lube Oil
Thermography Performance
Monitoring
Vibration
Pressure
To Control
Room
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14. Insulation Cavities/Damage of
insulation/Bad contacts/Sparking
in oil/Looseness/ Internal
arcing/Flux Concentration
Open or Shorted Winding
PD
ACOUSTICS
Abnormal Sound
Insulators/Leakages
Winding Deformation, Broken
or loose clamping/
Electric Discharges in
Insulators & Overhead
Conductors
Radiator Bank Cooling
Efficacy & Oil Flow/Oil Levels
Hot Spots
SFRA
DGA
IRT
IR
Physical
Inspection
Core Deformities
Abnormality/Test
Equipment Technology & Data Matrix
for Transformers Fault Based
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One technology is not adequate for diagnostics Use Of Multiple
Technologies and integration of data is essential

15. Different PdM Technologies
for Transformer

16. Visual Inspection
• Check
– Temperature Gauges
– Oil Levels
– Oil Leaks
– Oil Sample Area
– Control Cabinets
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17. Oil Tests
• DGA
• Quality
• Furfural
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18. Infrared Imaging
• Transformer Profile
• Bushings and Lightning Arrestors
• OLTC Profiles
• Fan and Pump Motors
• Control Cabinets
• ISO Phase Bus
• Profiles on Radiators
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19. Functional Tests
• Run Pumps and Fans
– Survey with IR
• Operate OLTC and Listen ( if in
practice, operated on load)
Special Tests
• Event Detection
• Pump Flow
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20. Control Cabinet
• Hot Wiring
• Chattering Breakers and Relays
• Jumpered Connections
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21. OLTC
• Profile
• Differential
• PD Counts
• Range
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22. Cooling Pumps
• Vibration
–Axial Movement
• Ultrasonic Level
–Contact
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23. Radiators, Fans and Piping
• Temperature Profile
• Air Flow
• Vibration
• Fan Motor Temperature
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24. Case Study : Infrared Thermo-graphy
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25. Transformer Radiator Bank
Oil flow being shut off from the right
resulting in a delta T greater than 20
deg C
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26. Tap Changer
Tap Changer body temp was more than 7 deg higher
than Main body temperature.
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27. Hot Bushing Rod
Hot bushing Rod is shown in
the thermogram. This
Bushing rod had a measured
temperature of 93.7 Deg C
Which was more than 60 deg
hotter than adjoining rod.
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28. Fan Control Circuit showing 2 overheated terminals. The thermogram
showing two terminals with temp of 135 deg c & 153.6 deg c.
Fan Control Circuit of a Transformer.
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29. Y phase
B phase
Y phase
R phase
Overhead line Jumpers
Y phase line jumper is hotter than R & B phase
by appx.15-17 degrees. Fault classification is Intermediate(>10
Degree c & < 35 degree c).
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30. Temperature of R-Phase wave Trap
termination of connection at bus bar
is >105 degrees c. Normal temp of
wave trap connectionof other phase
is between 42-45 degreec. This
Temperature rise is in critical
category. (> 75degrees).
Wave Trap
R phase
Other phase
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31. R phase CTL jumper at bus bar
junction is heated. Normal temp of
other jumper connection is appx. 57
degree c whereas heated area temp
is >150 degree c. The fault is in
critical category.
CTL Jumpers
R phase
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32. Hot Cable Termination: Loose connection
• Junction box is hotter
• Cable termination is poor
• Temperature rise is 62 deg C which
can cause flashover any time.
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33. Electronic card: Heating
Area1
Min Mean Max
33.2 42.6 48.2
Area1
Min Mean Max
33.2 42.6 48.2
UNIT#1CKA00-RACKB/C- PVM01
*>52.2°C
*<32.3°C
35.0
40.0
45.0
50.0
Card is heated at Heat sink area .
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34. Dissolved Gas Analysis
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35. Sampling to Reporting Step wise
Approach for DGA
• Sampling procedure
a) Qualitative
b) Quantitative
• Testing and interpretation of buchholtz gas
a) Chemical Test Interpretation
b) Gas Chromoto-graphy
• Action based on interpretation of buchholtz gas
a) Keep in Service: after physical inspection only
b) Complete Inspection & Recommended Electrical
Testing
• Reporting procedure.
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36. Sampling procedure: Qualitative &
Quantitative sampling
Qualitative sampling is carried out to confirm the Gas/air
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37. Chemical Test Interpretation
Solution 1
(5% Silver
Nitrate)
Solution 2 (5%
Ammonical Silver
Nitrate)
Exit Gas
Inflammability
Fault Indicated
No Reaction No Reaction Non Inflammable No Fault, Air only
Present
Heavy White
curdy
Precipitates
Yellow Precipitate Inflammable Under Oil Arcing
hot spot
Black
Precipitate
Black Sooty
Precipitate (Solution
Opaque)
Inflammable Cellulose
degradation
• In under-oil arcing and under-oil hot metal reactions, the main gas evolved is
hydrogen together with acetylene.
• During the destructive distillation of cellulose, carbon monoxide, carbon
dioxide, methane evolves.
• These tests should be done immediately after a fault is indicated by a Buchholtz alarm, as
acetylene is very soluble in oil, and on long standing over oil may be totally absorbed
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38. Quantitative Analysis & Permissible
Limits
• For quantitative analysis, gas chromoto-graph is required.
• The gas sample earlier collected as per the sampling procedure , is to be sent to the place where
the required facility for testing of the gas is available.
• The test results will indicate the concentration of various fault gases in gas.
• These fault gas quantities are required to be multiplied by Ostwald coefficient (k) to get the
concentration of dissolved gases in oil. Ostwald coefficient (k) for various gases in mineral
insulating oil is given below (as per IEC 599):
Ostwald co-efficient K=
Concentration of gas in liquig space
concentration of gas in gas space
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Name of
the Gas
Chemical
Symbol
Permissible
Limits
Hydrogen H2 100
Methane CH4 120
Acetylene C2H2 35
Ethylene C2H4 50
Ethane C2H6 65
Carbon
Dioxide
CO2 2500
Carbon
Monoxide
CO 350
1. Sampling should be done from moving oil
2. If the problem is not very serious Degas the equipment & enhance monitoring ( weekly basis)
3. Do Sampling on 3 monthly basis for Generator Transformer & 6-Monthly basis for other
transformers
S.No. Gas k at 20 Deg. C k at 50 deg. C
1 N2 0.09 0.09
2 02 0.17 0.17
3 H2 0.05 0.05
4 CO 0.12 0.12
5 CO2 1 .08 1 .00
6 CH4 0.43 0.40
7 C2H6 2.4 1.80
8 C2H4 1 .70 1.40
9 C2H2 1 .20 0.90

39. Interpretation of Fault by Ratio Method
S
N
Fault Type Ratio Code
Diagnosis
C2H2
C2H4
CH4
H2
C2H4
C2H6
1 No Fault 0 0 0 Normal Ageing
2 PD of Low Energy Density 0 1 0 Insulation Cavities,or
humidity
3 PD of high Energy Density 1 1 0 Damage of solid insulation
4 Discharge of low energy 1->2 0 1->2 Sparking in oil or
looseness
5 Discharge of high energy 1 0 2 Arcing of oil
6 Thermal Fault <150 deg C 0 0 1 Conductor overheating
7 Thermal Fault 150-300deg C 0 2 0 Flux Concentration
8 Thermal Fault >300 deg c 0 2 1 Bad Contacts
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40. Interpretation based on rate of rise of
individual dissolved gasses in oil
Sr No Gas Rate of Rise Diagnosis Action
1
CH4, C2H4, C2H6 <10% per month Unsatisfatory ,
Local heating
Incraese the
Sampling Rate &
observe rate of rise
If each of the above gas>150
PPM
>10% per month Serious local
heating in oil
Advised internal
inspection as per
convenience
2
C2H2, H2 <10% per month Serious ,
intermittent arc
discharge in oil
More frequent
sampling & internal
inspection at the
earliest
>10% per month Critical.
Continuous arc
discharge in oil
Internal inspection
as soon as
possible
3
C2H2,H2,CO <10% per month Serious , arc
discharge in coils
Electrical testing &
internal inspection
as soon as
possible
>10% per month Critical ,
continuous arc
discharge in coils
Quick de
energisation for
electrical testing &
internal inspection
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41. Permissible Dissolved Gas Levels in oil
Gas Symbol Permissible Levels (ppm)
Oil Immersed Transformers
Hydrogen H2 <20n +50
Methane CH4 <20n +50
Acetelene C2H2 <5n+10
Ethylene C2H4 <20n +50
Ethane C2H6 <20n +50
Carbon Monoxide CO <20n+500
Carbon Dioxide CO2 <100n+1500
Total Fault Gasses <110n+710
Where n is the number of years of Operation
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42. NTPC Criterion for TCG
TCG Limit( ppm) Interpretation
720 Operating Satisfactory
721-1920 >Normal Combustible Level fault may be
present
1921-4630 High level of decomposition immediate action
>4630 Can Result in failure of Transformer
NTPC uses IEEE judgment criteria H2:CH4:C2H2:C2H4:C2H6:CO:CO2
Japnese Utilites monitor Delta TCG & if deltaTCG>=700 /month they declare
it abnormal transformer
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43. Case Studies
• Transformer B
Rating: 125 MVA, 10.75/220 KV
Make : BHEL
Transformer was refurbished in 2007
Transformer Tripped on Buchholtz Protection.
Action1: Transformer was removed from service.
Action2: DGA Done.C2H4>1000 PPM
Action3: Detailed Inspection done. All three
windings were found damaged.
Action4: Transformer was repaired by
manufacturer. transformer was
charged after dry out and testing.
Transformer A
Rating: 167 MVA, 400/220/33 KV
Make : BHEL, Bhopal
Transformer Hand Tripped on abnormal sound.
Action1: Transformer was removed from service.
Action2: DGA Done.C2H2>200 PPM
Action3: Detailed Inspection done. Overheating of
core clamping plate bolt & damage of
OLTC contacts.
Action4: Transformer was repaired at site by
manufaturer and the transformer was
charged after dry out and testing.
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44. Test the Equipment for following after
confirmation of Gas
a) IR values of windings
b) Measurement of HV/LV ratio at all the tap positions
c) Winding resistance measurement
d) Magnetizing current test
e) Magnetic balance test
f) Impedance measurement test
• In case of any abnormality, a detailed internal inspection of the
equipment may be done to detect the exact fault. Suitable corrective
actions must be taken before charging the equipment.
• In case no abnormality is found in DGA of main tank oil sample,
electrical tests and quantitative gas analysis, the equipment may be
recharged.
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45. • Partial Discharge
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46. Partial Discharge Measurement in transformers
Why partial discharge in Transformers happen?
Discharges are due to electric arcing, which
vaporizes the dielectric fluid in the discharge
path, creating a bubble cavitations effect.
These sudden burst of acoustic energy are
transmitted by the fluid to the external wall,
where an acoustics emission sensor can
sensitively pick them up.
Frequency Range for PD: 100-450 KHZ
Discharges Typically take place in a regular pattern as associated with the AC waveform
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47. PD Detection by Acoustic Emission
• AE discharge detection is based on the detection of mechanical
signals emitted from this discharge.
• The discharge appears as a small “explosion” which excites a
mechanical wave that propagates throughout the insulation.
• Typical Acoustic signal generated by a PD is 20 to 30 dB above the
ambient magnetic noise of the core.
• The frequency spectrum of acoustic wave due to partial discharge is
very broad.
• The bandwidth of interest is from 50KHz to 400 Khz. PD spectrum
has peak around 70 KHZ and 150KHZ.
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48. AE PD Detection Setup
 Accelerometer -T5-013
 Sonic/Ultrasonic Fault
Detector- 5550FD.
 Digital Oscilloscope (100MHz)
 Personal Computer
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49. Case Study: Correlation between Acoustics &
DGA
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50. Equipment threshold is set above normal noise level of the core
Normal Noise
level of core
Core having
Partial
Discharge
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Comparison : Normal with core having
Partial Discharge

51. Use of Airborne sensors to detect
Electrical Discharge
Airborne sensors can be used to detect electrical
discharges taking place in insulators & overhead
conductors.
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52. Sweep Frequency Response Analysis
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53. SFRA IN TRANSFORMERS
However the same transformer can develop fault when subjected to external
abnormalities some of the probable reasons are:
External Short Circuit in downstream distribution system : it exerts tremendous
electromagnetic forces on transformer windings . The winding can move radially or
laterally & can thus weakens the mechanical structure of the transformer. This creates
the possibility of fault.
It is difficult to see inside the transformer. So in that case, why to wait for problem
to develop?
To diagnose the problem prevent expensive equipment breakdown & to take
control of the equipment the technique of sweep frequency response analysis is
used to detect the faults in transformer.
SFRA is the ratio if output voltage or current to input voltage or current
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54. SFRA in Transformers
Following abnormalities can be detected through SFRA
• Core Movement
• Winding deformation & Displacement
• Partial Winding Collapse
• Broken of Loose Clamping Structure
• Shorted or Open Winding
It is a Non intrusive Technique.
SFRA is a OFF line testing
It can be used for any voltage rating of power Transformer.
Measurement of SFRA can be part of regular transformer maintenance
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55. Why SFRA IS Done?
Test is carried out to obtain:
Initial signature for future reference
Periodic measurement as a maintenance check: Once in Two Years.
Immediate after Major external Short Circuit
Transportation & re location of Transformer.
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56. Frequency Response Analysis –FRA & SFRA
• The test is frequency response analysis but as we are sweeping
through different frequencies of interest so it is called
SWEEP FREQUENCY RESPONSE ANALYSIS
• In simplest way it is the ratio of output voltage or current to input
voltage or current
It is a measured technique rather than an estimated one
Two Coil arrangement subject to winding movement
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57. Comparison of coil Movement
• Peaks are called resonances. It corresponds to capacitances & inductances
within the coil.
• A change in resonance must be linked to the physical in inductance & capacitance
hence we can deduce that there is a mechanical change in the winding.
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58. SFRA Results on a Transformer
It is not always necessary to have reference results, comparison with sister units or
with phase is also possible
SFRA Results of a good & Bad Phase
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59. Case Study : Axial Collapse
• In axial Collapse one winding shifts relative to the other winding like a
expandable telescope. In this case the transformer tripped out on a fault
during a storm.
• DGA results before & after gave an indication of formation of C2H2
( From zero to > 80 PPM) .It indicates a major arc within the transformer.
Other dissolved gasses supported the diagnosis.
• Electrical testing included power factor, capacitance, winding resistance,
excitation & turn ratio gave acceptable results
• SFRA however gave indication of partial collapse on one winding.
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60. SFRA : Axial collapse of winding
SFRA : Axial Collapse of Winding
Shift of Resonance towards Right as shown in red Axial Winding Collapse of
Transformer
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61. SFRA : Detection of Hoop Buckling
• What is HOOP Buckling?
Hoop Buckling or winding compressive failure is a common cause of
deformation in transformers. In this the winding is bent but not broken.
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62. Residual Life Assessment in
Transformers
• IR Test
• DGA
• CO+CO2
• FURFURAL
ANALYSIS
Coil paper insulation is the most vulnerable thing in transformer as it deteriorated
much faster.
RLA of transformer is carried out on the basis CO+CO2 & Furfural
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63. Low Voltage Test Procedure
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64. Insulation Resistance Test CENPEEP

65. Measurement of Capacitance & Tan
Delta
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66. Capacitance & Tan Delta Measurement CENPEEP

67. Magnetising Current Measurement CENPEEP

68. Measurement of LV Magnetising
Current
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69. Measurement of Turn Ratio CENPEEP

70. Verification Of Polarity
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71. Magnetic Balance Test CENPEEP

72. Check of Polarity/Voltage Vector
Relationship
Vector Checking Circuit
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73. Earth Pit Resistance testing
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74. Winding Resistance Test CENPEEP

75. Measurement of LV Resistance
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76. Different types to Transformers in NTPC
• Different types to Transformers in NTPC
• Based on type of insulating oil used:
• Many of the transformers above 33 KV voltage level are filled with EHV grade
Mineral oil.
• All the transformers up to 33 KV, excluding indoor ones, are filled with mineral
insulating oil confirming to IS 335.
• All indoor transformers and many of the ESP rectifier transformers are filled with
silicone liquid.
• The mineral oil used in all indigenously made transformers is of paraffinic based
crude origin and that in all the imported transformers is of Naphthanic based crude
origin
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77. Oil Sampling Frequency In
Transformers
Description Power T/f>132 KV Others< 132 KV
First Sample Just prior to first charging Just prior to first charging
2nd Sample 15 days after first charging 15 days after first charging
3rd Sample After 3 months of first
charging
After 3 months of first charging
4th Sample After 6 months of first
charging
After 1 year of first charging
Subsequent Sample 6 monthly Every year
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78. Testing of Oil
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Various Tests Performed on oil:
1. BDV : As per IS :1866 Min 60 KV ( all 6 readings)
2. Moisture: < 10 PPM
3. Resistivity:
4. Tan Delta : Max 0.2 at 90 deg c
5. Acidity : Max 0.25 mgKOH/g
Oil Sampling should be done once in six months of after major/minor
repair/ overhaul.

79. Reporting
REPORTING FORMAT
• 1. EQUIPMENT LOCATION:
• 2. NAME OF EOUIPMENT:
• 3. RATING:
• 4. MAKE :
• 5. DATE OF FIRST COMMIS SIONING:
• 6. DATE OF LAST FILTRATION:
• 7. DATE OF LAST MAINTENANCE:
• 8. DATE AND TIME OF TEST
• 9. DATE AND TIME OF REPORTING :
• 10. RESULTS & RECORDING OF RESULTS:
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80. Transformer Maintenance Schedule

81. Transformer Maintenance Schedule
ACTIVITY SCHEDULE
• Oil filtration and top up, if required
• Attending oil leakage, if any
• Fan motor PM
• Cooler cleaning
• Oil pump PM
• Operating mechanism greasing
• Checking of transformer earthing
between top bottom of bell tank
• Silica gel inspection & regeneration/replacement of silica gel, if required
• Conservator rubber bellow and MOG checking and rectification ,if required
• Conservator cleaning
• Core coil tightness checking
• OLTC inspection including diverter chamber
• Operation of OLTC from normal to extreme taps & back to normal- min 6
rotation
• Testing of OLTC oil and filtration, if required
• Transformer winding inspection and de-sludging with hot oil jet washing
Annually (based on oil test
results)
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
5 years Condition based in 5years
5 years Condition based in 5years
1 year after 1st commissioning
and then 5 years
5 yearly
Annually
10 years
Equipment: Main Transformer
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82. Transformer Maintenance Schedule
EQUIPMENT ACTIVITY SCHEDULE
•HV BUSHING • Physical Checking & cleaning
• Capacitance measurement
• Tan Delta measurement
• Insulation resistance measurement
• Connection tightness
Annually
Annually
Annually
Annually
Annually
• LV &
NEUTRAL
BUSHING
• Physical Checking & cleaning
• Capacitance measurement
• Tan Delta measurement
• Insulation resistance measurement
• Connection tightness
Annually
Annually
Annually
Annually
Annually
• NGR • Cleaning and tightness checking
• Resistance measurement
• Insulation Resistance of NGR including cable
Annually
Annually
Annually
• CONTROL
CIRCUIT
• Cleaning and tightness ofconnections
• Meggering of control wires Earthing checking
• Operational check of fans/ pumps MB panel sealing including
cable entry spare holes
• Sealing of JBS of all protective devices & Motors
Annually
Annually
Annually
Annually
• EARTH
Clearances
• 765KV- 6400mm (min)
• 400KV-3500mm (min)
• 220KV-2100mm (min)
Annually or
any work on
transformer
Equipments: Accessories
HV LV & neutral bushing, NGR & Control Circuit
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83. Transformer Maintenance Schedule
ACTIVITY SCHEDULE
• External cleaning
• Cleaning and connection tightness of HT/LT terminals
• Cleaning and tightness of joints in both bus bars
• Cleaning of support insulators
• Sealing of terminal box and tightness of terminal in control panel
• Sealing of terminal box and control panel, if any
• Oil filtration
• Attending oil leakage, if any
• Checkingof transformer
• Silica gel breather inspection and regeneration/replacement of silica gel if required
• Conservator cleaning
• Painting, if required
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
5 Yearly
5 Yearly
Equipment: LT Transformer
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84. Transformer Maintenance
Schedule
EQUIPMENT ACTIVITY SCHEDULE
•HV BUSHING • Physical Checking & cleaning
• Capacitance measurement
• Tan Delta measurement
• Insulation resistance measurement
• Connection tightness
Annually
Annually
Annually
Annually
Annually
• LV &
NEUTRAL
BUSHING
• Physical Checking & cleaning
• Capacitance measurement
• Tan Delta measurement
• Insulation resistance measurement
• Connection tightness
Annually
Annually
Annually
Annually
Annually
• NGR • Cleaning and tightness checking
• Resistance measurement
• Insulation Resistance of NGR including cable
Annually
Annually
Annually
Equipments: Accessories
1. HV & LV Bushings
CENPEEP

85. Transformer Maintenance Schedule
ACTIVITY SCHEDULE
• Turns ratio
• Magnetic balance
• Magnetization current
• Insulation Resistance
• Winding Resistance
• Check of CTs
• Cleaning and tightness checking of control cable in MB
• Meggering of control wires
• Tightness and sealing of JBs of all protective devices
• Relay testing and calibration
• Trip, alarm and interlock checking Transformer pit earth resistance
• Calibration of OTI and WTI
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
Annually
5 Yearly
Equipment: LT Transformer Tests
CENPEEP

86. THANK YOU

87. Case Study

88. Continue

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90. Continue…

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