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Condition Monitoring of electrical equipments
in thermal power plant
M.G.Morshad , ADGM ( Electrical)
Transformer Maintenance Division
Thermal Power Station II, NLC Ltd
Philosophy of Condition
Monitoring
Electrical
Equipment
Mechanical
Stress
Thermal
Stress
Ambient
Stress
Electrical
Stress
Concept of TEAM
STRESS CAUSES EFFECTS
Thermal
Stress
(T)
1. Over heating due to overload/unbalance
current
2. Hot spot due to worn out of inter lamination
insulation
3. Improper cooling
 Reduces the life of
insulating materials
Electrical
Stress
(E)
1. Over voltage due to lighting / switching impulse
voltage
2. Exposure to faults (SC &EF)
 Insulation Break down
 Partial / Corona
discharge
 Melting of joints /
conductor
Ambient
Stress
(A)
Ambient temperature and Atmospheric moisture
& dust
 High operating
temperature
 Corrosion
Mechanical
Stress
(M)
Vibration due to magnetization effects ,
misalignment, un balancing , foundation looseness,
external effects
 Bearing failure
 Looseness in internal
joints
Causes and effect of TEAM
During service equipments are exposed to TEAM stresses.
Stress limits for electrical equipment
1. Design stress limit
The maximum stress (TEAM) which can be withstood by the equipment , is the design stress
limit. It reduces over a period of time due to deterioration of material quality with aging.
2. Operating stress limit
The stress (TEAM) which are to be withstood by the equipment during its normal operating
period, is the operating stress limit. It remains constant.
The reliability of the equipment can not be ensured whenever the design stress limit becomes
lower than operating stress limit .
0
35
Service life in Years
Design stress limit
Operating stress limit
25
Stresses
High reliability zone
Poor reliability
zone
design stress limit
 Design stress limit mainly depends upon the following factors –
a). Design methodology ,
b). Manufacturing process
c). Quality of the materials used.
 Design stress limit is decided as per the relevant IS
 Design stress limit is tested during factory test( Type & Routine test)
 Based on the design stress limit manufactures provide the operating
parameters in their manuals & routine test report.
 Design stress limits deteriorate with the aging of equipments.
Operating stress limit
 Operating stress limit mainly depends upon the following factors –
a). Loading level of the equipment
b). Protection coordination
c). Ambient condition
d). Routine maintenance as per the recommendation of OEM
Maintenance strategy
The objective is to maintain the design stress limit always above the operating
stress limit for
a) Utilizing the entire service life of the equipment
b) Minimizing the break down of equipment during its service
Condition monitoring
Measuring the operating stress by
analyzing operating data and then
comparing it with design stress
limit.
Preventive maintenance
Routine maintenance as per
the recommendation of
OEM
Predictive maintenance
Attending defects /
abnormalities detected by
condition monitoring
Condition monitoring & maintenance strategy
Design stress limit
Normal operating
stress limit
Condition
Monitoring
Standard
1. Factory test report
2. Commissioning test
report
3. Recommendations given
by relevant IS
Standard
1. Manufactures
recommendations
2. Field experience
3. Recommendations given
by relevant IS
Initiate
Preventive Maintenance
No action required
Deviation
>5%
Deviation
>5%
Yes
Yes
No
No
Initiate
Predictive Maintenance
Condition monitoring
 Measurement of the operating stress (TEAM)
 Comparing operating stress with design stress
 Recommendation for required action
Condition monitoring on regular
basis
 Carried out on all vital
equipment in a define interval
of time (Periodicity ).
 Operating stress (TEAM) is
measured for those component
of the equipment which are
prone to failure.
 Operating stress is compared
with design stress and
recommendation is given for
predictive maintenance.
Condition monitoring for residual
life assessment (RLA)
 Carried out on those vital
equipment which can not be
replaced easily
 It is carried out after expiry of
70% of its life
 Operating stress (TEAM) is
measured for all the vital
component related to its life.
which are prone to failure.
 Operating stress is compared
with design stress and
remaining life is estimated.
Preventive Maintenance
 It is carried out on regular basis for maintaining the
operating stress within the limit.
 It is carried out as per the recommendation of the OEM and
field experience.
0 35
Service life in Years
Stresses
20
Normal Operation
stress limitFailure prone
zone
Non Failure zone
Nominal O & M strategy
Stringent O & M
strategy
Predictive Maintenance
It is carried out for re-strengthening the design stress limit by
replacing , refurbishing the parts of the equipment on the basis of
periodical condition monitoring
Equipments to be covered for Condition monitoring
1) The equipments which can not be replaced easily due to
 Cost
 Market availability
 Link to the production of the plant
2) The components of the machine which are prone to failure
 Electric motor ( Bearing , Cable Connection)
 Transformer ( HV Bushing , Oil, HV & LV Connection)
 Switch Gear ( Cable connection)
Types of equipment
Rotating
equipment
Static
equipment
o Motor
oGenerator
o Transformer
o Switch gear
1. Vibration
2. Stator : core , winding
,Insulation ,cooling
3. Rotor : Core, winding,
Insulation , Cooling
4. Bearing – lubrication,
temperature
5. Terminal connection
1. Transformer : core ,
winding ,Insulation , Oil ,
cooling, Bushings ,
terminal connection
2. Switchgear : Terminal
connection , Insulation
Vibration
• Fundamental of vibration
•Vibration measurement
•Vibration analysis
1. The axis which passes through the center of gravity of a rotating mass is known as
center of gravity (CG) axis.
2. The axis on which the mass actuarially rotates is known as moment of inertia (MI)
axis.
3. The distance between the two axes is known as eccentricity (E) and it is measured
in microns.
4. For balance rotating mass the distance between CG and MI is very less or nil
CG axis
MI axis E
CG & MI axis
1. If the mass distribution of the rotating parts becomes uneven– the distance (E)
between CG and MI axis gets increased .
2. As a result - a centrifugal force of oscillating nature with amplitude equal to E is
experience at the bearings of the rotating mass.
3. This oscillating force is known as Vibration.
MI axis
CG axis
Fundamental reasons for vibration
Vibrating system
1) The exciting force (F)
2) The mass of the vibrating system (M)
3) The stiffness of the vibrating system (K)
4) The damping characteristic of the vibrating system (C)
The net vibrating force can be reduced by –
Increasing mass of the system (M)
Increasing stiffness by tightening bolts and nuts (K)
 Designing the system in such a way that it takes less time to return back to normal state (C )
F
MKC
Net vibrating force = F – (M + K + C)
Reasons that generate exciting forces
1. Misalignment
2. Unbalance of rotating components
3. Looseness
4. Bend shaft
5. Deterioration of rolling element bearings
6. Gear wear
7. Rubbing
8. Aerodynamic /hydraulic problem in fans blower and pumps
9. Electrical problem in motor
10. Resonance
Effect of vibration
1. Stress : Exposure to tensile forces (Deformation)
2. Fatigue : Becoming weak due to exposure to cyclic
tensile force ( Broken in to pieces)
3. Force : Exposure to cyclic hammering force (pitting)
PHYSICAL FEATURES OF VIBRATION
Displacement
Time
Time waveform
Displacement
APK
B
Displacement , velocity , acceleration & frequency
PK
1. Displacement : How much distance the vibrating particle is moving from its rest position
2. Velocity : How fast the particle is moving . It is minimum at A and maximum at B
3. Acceleration : At what rate the velocity of the particle is changing . It is maximum at A
and minimum at B t is
4. Frequency : How many oscillation the particle is completing in one minute. It is directly
proportional to speed (RPM) of the machine.
Measuring
parameters
Units Scale
Information
related to
Physical
meaning Measuring range
Frequency CPM
Source of
Vibration
Numbers of
complete to and fro
motion of vibrating
parts
Displacement Microns
PK,
PK-PK,
RMS
Stress
(Deflection)
Maximum deflection
of vibrating parts
from its neutral
point.
Up to 600 CPM
OR
10Hz
Velocity mm / sec
PK,
RMS
Fatigue
(Deflection X
Frequency)
Repeated deflection
of vibrating parts.
600 to 120000
CPM OR
10 to 2000 Hz
Acceleration G's PK
Force
(Mass X
Acceleration)
Deflection of
vibrating parts at
very high frequency
Above 120000
CPM OR 2000Hz
Vibration measuring parameters
Horizontal ( H) : Rotor unbalance
Vertical (V) : Soft foot
Axial (A) : Misalignment
Limits of range In mm/sec
Class I
(Up to 15 KW)
Class II
(15 to 75KW)
Class III
(>75 KW)Peak RMS
0.4 0.28
A
(Good) A
(Good)
A
(Good)
0.64 0.45
1.0 0.71
1.58 1.12 B
(Normal)2.5 1.8 B
(Normal)4.0 2.8 C
(Acceptable)6.4 4.5 C
(Acceptable)
B
(Normal)10.0 7.1
D
(Unacceptable)
15.8 11.2
D
(Unacceptable)
C
(Acceptable)25 18.0
40.0 28.0 D
(Unacceptable)64.0 45.0
VIBRATION SEVERITY RANGES –AS PER ISO 2372
PK – PK
PK
RMS
Vibration Analysis
1. Frequency
a) Each defects generates a vibration at a particular frequency. Therefore, if the
frequency of the vibration is known , the source of vibration can be traced.
b) Frequency is measure in CPM ( Cycle Per Minute)
c) As frequency is directly proportional to speed of the machine (RPM), it is
expressed in multiple of RPM (X) i.e. 1X,2X,3X etc
2. Amplitude
a) Displacement (stress) ,
b) velocity ( Fatigue) ,
c) Acceleration (Pitting)
2. Phase
a) In phase ,
b) Out of phase
Time wave form
Time
Amplitude
1. Vibration generates a complex time wave form with various frequency.
2. Fourier Transformation converts this complex time waveform to a simple waveforms
of various frequencies (multiples of fundamental frequency) .
3. The conversion of (amplitude – time ) graph to (amplitude – frequency ) graph is know
as FFT ( Fast Fourier Transformation)
Method of capturing vibration Frequency
Time period = 0.5 sec
Amplitude
Amplitude
Time
Frequency
Method of capturing vibration Frequency
Fourier Transformation
converts this complex time
waveform to a simple
waveforms of various
frequencies (multiples of
fundamental frequency) .
The conversion of
(amplitude – time ) graph to
(amplitude – frequency )
graph is know as FFT ( Fast
Fourier Transformation)
B
A
Phase angle between A and B point is 180 Deg.
It means that the movement of one end of
machine with respect to other end is in opposite
direction
BA
CG of the
rotor
Phase angle between A and B point is 0 Deg.
It means that the movement of one end of
machine with respect to other end is in
same direction
PHASE
Cause
Direction of
dominant
vibrating
force
Period of
occurrence
(Frequency )
Phase
angle
Behavior of the vibrating
force
Looseness
( Probability 85%)
Vertical 1 x RPM Erratic
Drop immediately with
speed
Unbalance
( Probability 5%) Horizontal 1 X RPM 0 Deg
Drop slowly with speed
 Thermal condition
dependent
Misalignment
( Probability 10%) Axial 1 X RPM 180 Deg
Drop slowly with speed
 Load Dependent
Fundamentals of vibration analysis
Rotor unbalance
Vibrating force in horizontal direction
Period of occurrence (Frequency) = 1 x RPM
Phase Angle : DE & NDE side zero
Misalignment
Vibrating force in Axial direction
Period of occurrence (Frequency) = 1 x RPM
Phase angle : DE & NDE side 180 Deg
Foot looseness
Vibrating force in Radial direction
Period of occurrence (Frequency) = 1 x RPM
Phase : DE & NDE side Erratic
Condition monitoring of bearings
1200 RPM
950 RPM
20000 RPM
Ball brg
Roller brg.
Sleeve brg
Max speed limit
SPEED(RPM)
10 mm 300 mm
Shaft ID
Speed, shaft diameter and type of bearing used
BEARING SERIES TYPE OF LOAD MISALIGN SPEED
Deep grooved ball brg.
60/62
63/64
42/43
Radial – Medium, Axial - Medium Low High
Angular contact ball brg.
72/73
32/33
Radial – Medium , Axial - Max
(one direction)
Very low High
Four point ball brg QJ Radial – Low , Axial - Heavy Very low Medium
Self-aligning ball brg
12/13/
14/22/23
Radial – Low , Axial - Low (Both
direction)
High High
Thrust ball brg.
51/52/53
/54
Radial – Nil , Axial -Medium (One
direction)
No Medium
Cylindrical roller brg.
N/NU
NJ/NUP
N - Radial only , NU – Radial only ,
NJ -Radial & one direction axial ,
NUP– Radial & both direction axial
Low High
Cylindrical roller thrust
brg
81
Radial – Medium
Axial- Medium (One direction)
Very low Medium
Spherical roller thrust
brg.
29 Radial – High, Axial - Medium Low Medium
Reasons
for bearing
failure
Expected life 30,000
Hrs (3 Years) to
50, 000 Hrs (6 years)
depending upon speed
and type of lubricant
used
Misalignment
Improper
Lubrication
Wrong selection
Quality
High bearing temp
Vibration
Early failure
Early failure
Thermal and electrical stress on
electrical equipment
 Looseness in parts
 Impurities in insulation
 Leakage flux
 Overloading
 Improper cooling
 High ambient temp
Thermal stress
 Insulation failure
 Melting of parts
 Thermal Imaging
 Tan Delta value
INSULATION TEMPERATURE CLASSIFICATION
Insulation Temperature
Classification for Machines
Temperature Index Some Insulation Combinations
Class O (Obsolete) 90°C Oleo, Resinous, Cotton, Wood
Class A 105°C Cotton, Vinyl Acetate
Class E 120°C Phenolics, Alkyds, Leatheroid
Class B 130°C Shellac/Bitumen, Silk, Mica, Polyesters
Class F 155°C Epoxy/Polyesters, Silicone, Mica, Glass
Class H 180°C Epoxy/ Polymides/ Silicone/ Mica/ Glass
Class C 220°C Glass/ Silicone/ Mica/ Nomex/ Silicates
Monitoring insulating properties in electrical machine
Insulation Resistance (IR) Polarization Index (PI) Tan Delta
Solid & liquid insulation Solid insulation Mixed insulation ( Solid + Liquid)
Macro level measurement Macro level measurement Micro level measurement
Insulating material is considered
as a high resistive material with no
leakage current
Insulating material is considered
as a high resistive material with
minor leakage current
Insulating material is considered as
a dielectric of a capacitor with
charging current and minor leakage
current
Measurement of resistive property
of the insulating materials using
leakage current
Measurement of intensity leakage
of current in high resistive
materials by comparison of
leakage current
Measurement of dielectric property
of the insulating material using
leakage current
IR = Applied voltage / leakage
current
PI = IR60 sec/IR15sec Tan delta = Leakage current /
capacitor charging current
Leakage current increases in
insulating materials due to
disintegration (heat / Physical) and
wetness
Leakage current increases in
insulating materials due to
wetness
Leakage current increases in
dielectric materials due to impurities
and wetness
Lower IR value trip the equipment
on earth fault
Lower PI value indicates wetness
of the insulation
Higher tan delta value increase the
heating effect of the insulation
Applicable for all electrical
equipment
Applicable for electrical motor Applicable for OIP bushing ,
transformer winding
Limiting values for Insulation Resistance at different temperature
Temperature Below 6.6 KV 6.6 KV to 11KV 22KV to 33KV More than 66KV
30 Deg C 200 MΩ 400 MΩ 500 MΩ 600 MΩ
40 Deg C 121.2 MΩ 242.4 MΩ 303.0 MΩ 363.63 MΩ
50 Deg C 76.9 MΩ 153.8 MΩ 192.3 MΩ 230.7 MΩ
60 Deg C 47.6 MΩ 95.2 MΩ 119.04 MΩ 142.8 MΩ
70 Deg C 30.3 MΩ 60.6 MΩ 75.7 MΩ 90.9 MΩ
80 Deg C 19.04 MΩ 38.1 MΩ 47.6 MΩ 57.2 MΩ
Conductor (at high potential)
Insulating
materials
Body (at earth potential)
Ir
V
Fundamentals of Insulation Resistance (IR) value
o IR = (V/ Ir) decreases with increase of
leakage current (Ir)
o Leakage current (ir) increases due to
1. Disintegration of insulating material as
result of heat and physical puncture,
2. Wetness as a result of absorption of
moisture
Conductor (at high potential)
Insulating
materials
Body (at earth potential)
Ir
V
Fundamentals of Polarization Index (PI) value
o Initially, IR = (V/ Ir) shows high and then decrease
with time depending upon the intensity of the
leakage current. (Ir)
1. If the insulation is wet , intensity of leakage
current will increase with time causing IR value to
drop with time.
2. If the insulation is dry , intensity of leakage
current will not increase with time causing IR
value to increase with time.
Time (sec)
IR value
6015
R60
R15
PI = (R60 / R15 ) < 1.5 ( Wet insulation)
Time (sec)
IR value
6015
R60
R15
PI = (R60 / R15 ) > 1.5 ( Dry insulation)
Angle δ Cos δ
Capacitance (pF)
[(I/2 f V π) x Cos δ ]
Angle Φ = ( 90 - δ )
Cos Φ =(PF) = Sin δ = Tan δ
(%)
Condition of the insulator
0.0 Deg 1 (I/3140)x1.000 90.0 Deg 0 Pure capacitor
2.0 Deg 0.999 (I/3140)x0.999 88.0 Deg 0.3 Very Good
3.5 Deg 0.998 (I/3140)x0.998 86.5 deg 0.6 Good
4.5 Deg 0.996 (I/3140)x0.996 85.5 Deg 0.7 Acceptable
5.0Deg 0.996 (I/3140)x0.996 85.0 Deg 0.8 Not acceptable
6.0 deg 0.994 (I/3140)x0.994 84.0 Deg 0.9 Not acceptable
90.0 Deg 0 0 0.0 Deg 1.0 Pure resistance
Conductor (at high potential)
Insulator
Body (at earth potential)
IC Ir V
I
IC
Ir
I
Applied voltage
10KV
δ
Φ = (90 – δ)
Power Factor = Cos Φ
Cos (90 – δ) = Sin δ
Sin δ = Tan δ
Fundamentals of Tan Delta value
Leakage flux heating
 Due to continuous cutting of flux , current
is induced in the tank
 It is grounded through bell bolt and
additional flat link
 If it is not grounded properly, due to
looseness of bell bolt, heat is developed in
that area.
Thermogram 230kV Bushings of ICT - 2
40.3 °C
56.9 °C
50
sp1
sp2
sp3
ar1
ar2
ar3
sp4
Object Parameter Value
Emissivity 0.96
Label Value
IR: Max Temperature 76.5 °C
sp1: Temperature 68.5 °C
sp2: Temperature 53.5 °C
sp3: Temperature 50.2 °C
sp4: Temperature 50.4 °C
ar1: Max Temperature 60.5 °C
ar2: Max Temperature 76.5 °C
ar3: Max Temperature 50.9 °C
Thermal Imaging
Parts of motor
Alarm temp
setting
Trip temp setting
Average temp
during
operation
Probable reasons for
high temperature
Bearings
850C - Grease
750C - Oil
950C - Grease
850C - oil
650C - Grease
550C - oil
# Brg failure
# High / Low grease
# Low oil flow
Stator Winding
1200C - Class B
1400C - Class F
1300C - Class B
1500C - Class F
800C -Class B
850C - Class F
# High load
# High core temp
# Insufficient cooling
Stator Core Approximately 100 0C (Max) 70 0C
# Low freq.& volt opr.
# Hot spot
TB Approximately 60 0C (Max)
50 0C equal in
three phases
# Loose connection.
# Uneven lugs
Internal air Approximately 100 0C (Max) 70 0C
# Blocked ventilation.
# Improper fan
External air Approximately 60 0C (Max) 50 0C
# Blocked ventilation.
# Improper fan
Temperature monitoring in electrical motor
Ambient Temp
(50 Deg C)
Temp Rise
(55 Deg C)
Hot spot
Temp
(10 Deg C)
Ambient Temp
(50 Deg C)
Temp Rise
(45 Deg C)
Hot spot
Temp
(10 Deg C)
Alarm :
105 Deg C
Trip :
115 Deg C
Alarm :
95 Deg C
Trip :
105 Deg C
Winding Temp Oil Temp
Average operating
temp : 60 to 75 Deg C
Fan starts : 55 Deg C
Fan stops : 50 Deg C
Pump starts : 65 Deg C
Pump stops : 60 Deg C
Temperature monitoring in Transformer
Electrical test ( Motor Transformer )
Winding
combinati
on
Temp Applied voltage R15 R 60 PI =
R60/R15
Tan
Delta
Remarks
LV – E
5 KV for transformer of
voltage grade > 6.6 KV
2.5 KV for transformer of
voltage grade > 6.6 KV
PI value > 1.5
HV – E
LV – HV
Delta Winding
R-Y Y-B B-R Temperature Current Remarks
Deviation should not be > 2.5%
Star Winding
R-N Y-N B-N Temperature Current Remarks
Deviation should not be > 2.5%
N
Magnetizing
current
component (Im)
= I0 Sin Φ
No Load Current (I0) =
√ (Im)2 + (Ih+e)2
Hysteresis & eddy current
component (Ih+e) = I0 Cos Φ
Voltage
Flux
Parameters Formula 75% 100% 110%
Actual voltage (Vac) (Hz / 50) X V0
Actual Watt (Wac) {(50/Hz)+(50/Hz)2 } x 0.5 x W0
Hysteresis & eddy current (Ih+e) Wac / (1.732 x Vac)
Magnetizing current (Im) √ [(I0)2 - (Ih+e)2]
Core loss & magnetization current for transformer
Voltage
Magnetization
current
Condition monitoring of Transformer through
transformer oil
Oil parameters
Operating parameters:
a) Water ppm,
b) Breakdown voltage (BDV),
c) Tan delta,
d) Resistivity.
Aging parameters
Furan analysis
Oil quality parameters :
a) Colour/ Appearance ,
b) Interfacial tension (IFT),
c) Flash point,
d) Neutralization value
e) Sludge & sediments
Internal fault parameters
Dissolved Gas Analysis (DGA)
 Criteria for operating transformer
 To be tested once in six month
 Parameters can be improved by oil processing (
Hot oil circulation / Filtration)
 Decision for oil processing to be taken up
 Criteria for aging factor of oil
 To be tested once in a year
 Decision for discarding the oil to be taken up
 Criteria for detecting incipient internal fault
 To be tested once in a year
 Decision for oil processing / internal inspection to
be taken up
 Criteria for detecting residual life of the
transformer
 To be tested once in a five years
 Decision for replacing transformer to be taken up
Moisture in transformer oil
1. Atmospheric moisture which is absorbed by oil during
breathing process
2. Chemically bound moisture in the insulating paper which
gets released due to heat and oxidation.
Source of
Moisture
Presence of
Moisture
1. Free water – That is water that has settled at the bottom
in a separate layer. Presence of free water in transformer
oil is indicated by lower IR value of Transformer.
2. Emulsified water – Water that is suspended in the oil and
has not yet settled down into free water . It is indicated
by “caramel” colour oil. A high Tan Delta value indicates
the possible presence of this suspended water trapped in
oil decay products.
3. Water in solution – It remain dissolved in the oil. It is
shows high moisture ppm in oil
Moisture Movement
1. The moisture absorbing capacity of transformer oil increases with increasing
of oil temperature.
2. When transformer is hot ( during service ) , moisture absorbing capacity of oil
gets increased and moisture entrapped in solid insulation (paper) is
absorbed by oil causing decrease of moisture in paper and increase in oil.
3. When transformer is cold ( during idle ) , moisture absorbing capacity of oil
gets decreased and moisture rejected by oil is absorbed by solid insulation
(paper) like blotting paper / towel causing increase of moisture in paper and
decrease in oil .
Hot oil - during
service condition Solid
insulation
(Paper )Cold oil - during idle
condition
Moisture movement
Moisture movement
Damages caused by moisture
Accelerate paper
decaying process
Increase acidity in
oil
Solid insulation
(Paper)
Reduces insulating
ability (BDV) of oil
Reacts with dissolved Oxygen in oil in presence of
heat and produces
Acid Moisturesludge
Affects cooling
process due to
blocking of
cooling duct
Liquid insulation
(Oil)
Moisture in Oil Moisture in Paper
Water content in paper Inference
0.5% Well dried paper
1.5% Minimum water content in paper
2% Maximum water content in paper
3% Paper fiber in oil
4.5% Flash over at 90 Deg C
7% Flash over at 50 Deg C
8% Flash over at 20 Deg C
Inference of Griffin curve
Determination of moisture in solid insulation using Griffin
curve
Griffin curve for water equilibrium in cellulose & mineral oil system
Polar particles in transformer oil
1) Presence of soluble polar particles such as water molecule, sludge & sediments,
varnish, resin etc, decease the insulating properties of transformer oil
2) The polar particle present in the oil gets ionized and initiate flow of leakage current
through oil which causes oil heating
3) The polar particle present in the oil also affects the operating parameters - BDV,
Resistivity & Tan delta of the oil
+
+
+
+
+
+
-
-
-
-
-
-
-
+
+
+
-
+
+
-
+
+
+
- +
-
-
+
+
+
+
+
-
Leakage current
Charging
current
Charging
current
High AC Voltage
50
40
30
20
10
0
10
20
30
40
50
60
Waterppminoil
Dryness of oil
Limit value : Water ppm in transformer oil
New oil
(72 – 170 KV Transformer)
(>170 KV Transformer)
(< 72 Transformer)No free
water
Dry Oil
1. The presence of water molecule in the oil is measured by Karl Fisher Titration
methods.
2. The limit value of water ppm ( part per million) need to be maintained as per the
guideline of IS 335 shown in the above graph
30
40
50
60
80
0
10
20
30
40
50
60
70
80
90
0 10 20 30 40 50 60
BreakDownVoltageinKV
Water ppm in Transformer oil
Limit value : Break Down Voltage in KV
< 72.5 KV Transformer
72.5 -170 KV Transformer
> 170KV Transformer
BDV value of transformer oil mainly depends on water ppm in the oil and it decreases with the
increase of water ppm in oil .In such case BDV of oil is improved by reducing water ppm in oil through
filtration .
 BDV of oil may also decrease due to low resistivity of oil caused by degradation of oil or
contamination of oil with soluble polar particles. In such case oil needs to be replaced after confirming
low resistivity & IFT value and high tan delta & acidity value with colour of oil.
 BDV of oil is determined by applying AC voltage
across a gap of 2.5mm ,filled with transformer oil
to be tested .
 The voltage at which the spark is observed
between the gap , is the BDV of the oil.
 Average of six such BDV value is taken as the
actual BDV of the oil.
35
25
15
6
2
0.8 0.5 0.2 0.1
0
5
10
15
20
25
30
35
40
Resistivity(x1012Ohms–cm)
Conductivity ( Flow of leakage current )
Limit value (at 90 Deg C) : Resistivity
(Very Good)
(Good)
(Min)
Resistivity is measured by
applying 500 V DC voltage
across the oil sample after
heating up the sample at 90
Deg C which is the
maximum allowable
operating temperature of
transformer
Charging current
Leakage current
Total current
O
BA
C
δ3
δ2
0.002
0.2
1
0.001
0.01
0.1
1
TANDELTAVALUE
Concentration of polar particles
Angle value % Value
Ideal
TAN δ 0.000 AB/OB 0.000
δ0 0.0 Deg OC 0.% of OB
Normal
TAN δ1 0.002 AB/OB 0.002
δ1 0.1 Deg OC 0.2 % OB
Maximum
( > 72.5 KV
Transformer)
TAN δ2 0.200 AB/OB 0.200
δ2 11.3 Deg OC 20 % OB
Maximum
(< 72.5 KV
Transformer)
TAN δ3 1.000 AB/OB 1.000
δ3 45 Deg OC 100 % OB
δ1
Normal
Max > 72.5 KV
Transformer
Max < 72.5 KV
Transformer
Tan delta
Oil quality parameters
 Colour
 Acidity
 Interfacial Tension
Pale
yellow
Good
oil
Yellow
Proposition
‘A’ oil
Bright
yellow
Marginal
oil
Amber
Bad oil
Brown
Very bad
oil
Dark
brown
Extremely
bad oil
Black
Oils in disastrous condition
Discarded
oil
Oil Colour
Oil quality – Neutralization value
Acidity
Heat , Moisture and
Oxygen initiate
decomposition /
oxidation of oil & paper
and increases acidity of
the oil
Acid causes corrosion inside
transformer
Acid form sludge and sediments
Good quality
Neutralization value
Acidity
0.25mg KOH / g oil
Oil quality – Interfacial tension (IFT)
IFT
Presence of sludge ,
sediments and polar
particle decrease IFT of
the oil
Reduce fluidity
of the oil
Not Good quality
IFT
Fluidity
18 dynes/cm
Increases oil
heating
Interfacial Tension, Acid Number, Years in Service
72
Determination of oil quality based on IFT & NN
IFT NN MIN = IFT/NN Colour Oil Quality & Observations
30 - 45 0.00 – 0.10 300 - 1500
Pale
Yellow
Very Good
(provides all the required function)
27.1 – 29.9 0.05 – 0.10 271 - 600 Yellow Good(provides all the required function , a drop in IFT to
27.0 may signal the beginning of sludge & sediment)
24 – 27 0.11 – 0.15 160 - 318
Bright
Yellow
Acceptable
(not providing proper cooling and winding protection.
Organic acids are beginning to coat winding insulation;
sludge in insulation voids is highly probable.)
18.0 - 23.9 0.16 - 0.40 45 - 159 Amber
Bad
(sludge has already been deposited in and on transformer
parts in almost 100 percent of these units. Insulation
damage and reduced cooling efficiency with higher
operating temperatures characterize the Very Bad and
Extremely Bad categories.
14.0 - 17.9 0.41 - 0.65 22 - 44 Brown Very Bad
9.0 - 13.9 0.66 - 1.50 6 - 21
Dark
Brown
Extremely Bad oil
1500300
600271
318160456 22
Very Good
Good
Acceptable / Bad / Very Bad / Extremely bad
Internal fault parameters
 Dissolved Gas Analysis (DGA)
Types of Faults & generation of gases
Partial Discharge (Particle Ionization) due to
presence of tiny air bubble and polar particle in
oil
/ Corona (Low intensity glow)
OIL CELLULOSE
H2 H2,
CO,
CO2
Low temperature heating
(150 to 300 Deg C)
Oil or conductor heating
OIL CELLULOSE
CH4, Methane
C2H6 Ethane
CO2,
(CO)
High temperature heating
(300 to 700 Deg C)
Hot spot heating
OIL CELLULOSE
C2H4 Ethylene
H2,
(CH4,C2H6)
CO
(CO2)
Arcing
Continuous High intensity spark
due to
Void in paper insulation
H2,
C2H2, Acetylene
(CH4,C2H6,C2H4)
TYPES OF INTERNAL FAULTS
THERMAL FAULTS ELECTRICAL FAULTS
Gases
CIGRE CPRI CBIP
0 - 5
Yrs
6 - 10
Yrs
11-15
Yrs
0 - 4
Yrs
4 – 10
Yrs
> 10
Yrs
< 4
Yrs
4-10
Yrs
> 10
Yrs
H2 100 200 300 150 300 500 100/150 200/300 300/400
CH4 60 200 200 30 80 130 50/70 100/150 200/300
C2H2 40 200 300 15 30 40 20/30 30/50 100/150
C2H4 80 300 300 30 50 150 100/150 150/200 200/400
C2H6 40 100 200 30 50 110 30/50 100/150 800/1000
CO 700 700 700 300 500 700 200/300 400/500 600/700
CO2 8000 9000 9000 4000 - 10000 3000/5000 4000/5000 9000/12000
H2 ( Hydrogen), CH4 ( Methane) C2H2 ( Acetylene) C2H4 (Ethylene) C2H6 (Ethane) CO (Carbon Monoxide)
CO2 (Carbon Dioxide)
Limit value : DGA
Fault Analysis - by Roger Ratio methods
CH4
H2
C2H6
CH4
C2H4
C2H6
C2H2
C2H4
Faults
0.1 0 0 0 Partial discharge
0 0 0 0 Normal deterioration
1 0 0 0 Over heating >150 Deg C
1 1 0 0 Over heating 150 – 200 Deg C
0 1 0 0 Over heating 200 – 300 Deg C
0 1 1 0 General condition of overheating
1 0 1 0 Circulating current / Overheating of joints
0 0 0 1 Flash over without power flow
0 1 0 1 Current breaking through tap changer
0 0 1 1 Arc with power flow
•Ratio less than 0.1 is designated as 0
•Ratio greater 1 is designated as 1
Duval Triangle
77
Aging parameters
 Indirect – Furan analysis
 Direct – Degree of polymerization of paper
Aging process of transformer’s solid insulation
Moisture
Oil impregnated solid insulation
Heat
Chemical degradation of solid insulation (Paper)
And production of Acids, Peroxides, O2, H2O, Furan contents
Dielectric degradation Mechanical degradation
Conduction & Ionization (Partial Discharge)
Glow discharge (Corona)
Insulation Failure
Oxygen
Limiting values for furan analysis
DP values and aging of transformer
Years
DP ValuesAge (Yrs) DP Values
0 >1000
1 975
12 700
22 450
25 390
35 125
82
Relation between furan content in oil and DP values of
solid insulation
Thank You

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Condition Monitoring of electrical machine

  • 1. Condition Monitoring of electrical equipments in thermal power plant M.G.Morshad , ADGM ( Electrical) Transformer Maintenance Division Thermal Power Station II, NLC Ltd
  • 4. STRESS CAUSES EFFECTS Thermal Stress (T) 1. Over heating due to overload/unbalance current 2. Hot spot due to worn out of inter lamination insulation 3. Improper cooling  Reduces the life of insulating materials Electrical Stress (E) 1. Over voltage due to lighting / switching impulse voltage 2. Exposure to faults (SC &EF)  Insulation Break down  Partial / Corona discharge  Melting of joints / conductor Ambient Stress (A) Ambient temperature and Atmospheric moisture & dust  High operating temperature  Corrosion Mechanical Stress (M) Vibration due to magnetization effects , misalignment, un balancing , foundation looseness, external effects  Bearing failure  Looseness in internal joints Causes and effect of TEAM During service equipments are exposed to TEAM stresses.
  • 5. Stress limits for electrical equipment 1. Design stress limit The maximum stress (TEAM) which can be withstood by the equipment , is the design stress limit. It reduces over a period of time due to deterioration of material quality with aging. 2. Operating stress limit The stress (TEAM) which are to be withstood by the equipment during its normal operating period, is the operating stress limit. It remains constant. The reliability of the equipment can not be ensured whenever the design stress limit becomes lower than operating stress limit . 0 35 Service life in Years Design stress limit Operating stress limit 25 Stresses High reliability zone Poor reliability zone
  • 6. design stress limit  Design stress limit mainly depends upon the following factors – a). Design methodology , b). Manufacturing process c). Quality of the materials used.  Design stress limit is decided as per the relevant IS  Design stress limit is tested during factory test( Type & Routine test)  Based on the design stress limit manufactures provide the operating parameters in their manuals & routine test report.  Design stress limits deteriorate with the aging of equipments.
  • 7. Operating stress limit  Operating stress limit mainly depends upon the following factors – a). Loading level of the equipment b). Protection coordination c). Ambient condition d). Routine maintenance as per the recommendation of OEM
  • 8. Maintenance strategy The objective is to maintain the design stress limit always above the operating stress limit for a) Utilizing the entire service life of the equipment b) Minimizing the break down of equipment during its service Condition monitoring Measuring the operating stress by analyzing operating data and then comparing it with design stress limit. Preventive maintenance Routine maintenance as per the recommendation of OEM Predictive maintenance Attending defects / abnormalities detected by condition monitoring
  • 9. Condition monitoring & maintenance strategy Design stress limit Normal operating stress limit Condition Monitoring Standard 1. Factory test report 2. Commissioning test report 3. Recommendations given by relevant IS Standard 1. Manufactures recommendations 2. Field experience 3. Recommendations given by relevant IS Initiate Preventive Maintenance No action required Deviation >5% Deviation >5% Yes Yes No No Initiate Predictive Maintenance
  • 10. Condition monitoring  Measurement of the operating stress (TEAM)  Comparing operating stress with design stress  Recommendation for required action Condition monitoring on regular basis  Carried out on all vital equipment in a define interval of time (Periodicity ).  Operating stress (TEAM) is measured for those component of the equipment which are prone to failure.  Operating stress is compared with design stress and recommendation is given for predictive maintenance. Condition monitoring for residual life assessment (RLA)  Carried out on those vital equipment which can not be replaced easily  It is carried out after expiry of 70% of its life  Operating stress (TEAM) is measured for all the vital component related to its life. which are prone to failure.  Operating stress is compared with design stress and remaining life is estimated.
  • 11. Preventive Maintenance  It is carried out on regular basis for maintaining the operating stress within the limit.  It is carried out as per the recommendation of the OEM and field experience.
  • 12. 0 35 Service life in Years Stresses 20 Normal Operation stress limitFailure prone zone Non Failure zone Nominal O & M strategy Stringent O & M strategy Predictive Maintenance It is carried out for re-strengthening the design stress limit by replacing , refurbishing the parts of the equipment on the basis of periodical condition monitoring
  • 13. Equipments to be covered for Condition monitoring 1) The equipments which can not be replaced easily due to  Cost  Market availability  Link to the production of the plant 2) The components of the machine which are prone to failure  Electric motor ( Bearing , Cable Connection)  Transformer ( HV Bushing , Oil, HV & LV Connection)  Switch Gear ( Cable connection)
  • 14. Types of equipment Rotating equipment Static equipment o Motor oGenerator o Transformer o Switch gear 1. Vibration 2. Stator : core , winding ,Insulation ,cooling 3. Rotor : Core, winding, Insulation , Cooling 4. Bearing – lubrication, temperature 5. Terminal connection 1. Transformer : core , winding ,Insulation , Oil , cooling, Bushings , terminal connection 2. Switchgear : Terminal connection , Insulation
  • 15. Vibration • Fundamental of vibration •Vibration measurement •Vibration analysis
  • 16. 1. The axis which passes through the center of gravity of a rotating mass is known as center of gravity (CG) axis. 2. The axis on which the mass actuarially rotates is known as moment of inertia (MI) axis. 3. The distance between the two axes is known as eccentricity (E) and it is measured in microns. 4. For balance rotating mass the distance between CG and MI is very less or nil CG axis MI axis E CG & MI axis
  • 17. 1. If the mass distribution of the rotating parts becomes uneven– the distance (E) between CG and MI axis gets increased . 2. As a result - a centrifugal force of oscillating nature with amplitude equal to E is experience at the bearings of the rotating mass. 3. This oscillating force is known as Vibration. MI axis CG axis Fundamental reasons for vibration
  • 18. Vibrating system 1) The exciting force (F) 2) The mass of the vibrating system (M) 3) The stiffness of the vibrating system (K) 4) The damping characteristic of the vibrating system (C) The net vibrating force can be reduced by – Increasing mass of the system (M) Increasing stiffness by tightening bolts and nuts (K)  Designing the system in such a way that it takes less time to return back to normal state (C ) F MKC Net vibrating force = F – (M + K + C)
  • 19. Reasons that generate exciting forces 1. Misalignment 2. Unbalance of rotating components 3. Looseness 4. Bend shaft 5. Deterioration of rolling element bearings 6. Gear wear 7. Rubbing 8. Aerodynamic /hydraulic problem in fans blower and pumps 9. Electrical problem in motor 10. Resonance
  • 20. Effect of vibration 1. Stress : Exposure to tensile forces (Deformation) 2. Fatigue : Becoming weak due to exposure to cyclic tensile force ( Broken in to pieces) 3. Force : Exposure to cyclic hammering force (pitting)
  • 21. PHYSICAL FEATURES OF VIBRATION Displacement Time Time waveform
  • 22. Displacement APK B Displacement , velocity , acceleration & frequency PK 1. Displacement : How much distance the vibrating particle is moving from its rest position 2. Velocity : How fast the particle is moving . It is minimum at A and maximum at B 3. Acceleration : At what rate the velocity of the particle is changing . It is maximum at A and minimum at B t is 4. Frequency : How many oscillation the particle is completing in one minute. It is directly proportional to speed (RPM) of the machine.
  • 23. Measuring parameters Units Scale Information related to Physical meaning Measuring range Frequency CPM Source of Vibration Numbers of complete to and fro motion of vibrating parts Displacement Microns PK, PK-PK, RMS Stress (Deflection) Maximum deflection of vibrating parts from its neutral point. Up to 600 CPM OR 10Hz Velocity mm / sec PK, RMS Fatigue (Deflection X Frequency) Repeated deflection of vibrating parts. 600 to 120000 CPM OR 10 to 2000 Hz Acceleration G's PK Force (Mass X Acceleration) Deflection of vibrating parts at very high frequency Above 120000 CPM OR 2000Hz Vibration measuring parameters
  • 24.
  • 25. Horizontal ( H) : Rotor unbalance Vertical (V) : Soft foot Axial (A) : Misalignment
  • 26. Limits of range In mm/sec Class I (Up to 15 KW) Class II (15 to 75KW) Class III (>75 KW)Peak RMS 0.4 0.28 A (Good) A (Good) A (Good) 0.64 0.45 1.0 0.71 1.58 1.12 B (Normal)2.5 1.8 B (Normal)4.0 2.8 C (Acceptable)6.4 4.5 C (Acceptable) B (Normal)10.0 7.1 D (Unacceptable) 15.8 11.2 D (Unacceptable) C (Acceptable)25 18.0 40.0 28.0 D (Unacceptable)64.0 45.0 VIBRATION SEVERITY RANGES –AS PER ISO 2372
  • 28. Vibration Analysis 1. Frequency a) Each defects generates a vibration at a particular frequency. Therefore, if the frequency of the vibration is known , the source of vibration can be traced. b) Frequency is measure in CPM ( Cycle Per Minute) c) As frequency is directly proportional to speed of the machine (RPM), it is expressed in multiple of RPM (X) i.e. 1X,2X,3X etc 2. Amplitude a) Displacement (stress) , b) velocity ( Fatigue) , c) Acceleration (Pitting) 2. Phase a) In phase , b) Out of phase
  • 29. Time wave form Time Amplitude 1. Vibration generates a complex time wave form with various frequency. 2. Fourier Transformation converts this complex time waveform to a simple waveforms of various frequencies (multiples of fundamental frequency) . 3. The conversion of (amplitude – time ) graph to (amplitude – frequency ) graph is know as FFT ( Fast Fourier Transformation) Method of capturing vibration Frequency
  • 30. Time period = 0.5 sec Amplitude Amplitude Time Frequency Method of capturing vibration Frequency Fourier Transformation converts this complex time waveform to a simple waveforms of various frequencies (multiples of fundamental frequency) . The conversion of (amplitude – time ) graph to (amplitude – frequency ) graph is know as FFT ( Fast Fourier Transformation)
  • 31. B A Phase angle between A and B point is 180 Deg. It means that the movement of one end of machine with respect to other end is in opposite direction BA CG of the rotor Phase angle between A and B point is 0 Deg. It means that the movement of one end of machine with respect to other end is in same direction PHASE
  • 32. Cause Direction of dominant vibrating force Period of occurrence (Frequency ) Phase angle Behavior of the vibrating force Looseness ( Probability 85%) Vertical 1 x RPM Erratic Drop immediately with speed Unbalance ( Probability 5%) Horizontal 1 X RPM 0 Deg Drop slowly with speed  Thermal condition dependent Misalignment ( Probability 10%) Axial 1 X RPM 180 Deg Drop slowly with speed  Load Dependent Fundamentals of vibration analysis
  • 33. Rotor unbalance Vibrating force in horizontal direction Period of occurrence (Frequency) = 1 x RPM Phase Angle : DE & NDE side zero
  • 34. Misalignment Vibrating force in Axial direction Period of occurrence (Frequency) = 1 x RPM Phase angle : DE & NDE side 180 Deg
  • 35. Foot looseness Vibrating force in Radial direction Period of occurrence (Frequency) = 1 x RPM Phase : DE & NDE side Erratic
  • 37. 1200 RPM 950 RPM 20000 RPM Ball brg Roller brg. Sleeve brg Max speed limit SPEED(RPM) 10 mm 300 mm Shaft ID Speed, shaft diameter and type of bearing used
  • 38.
  • 39.
  • 40. BEARING SERIES TYPE OF LOAD MISALIGN SPEED Deep grooved ball brg. 60/62 63/64 42/43 Radial – Medium, Axial - Medium Low High Angular contact ball brg. 72/73 32/33 Radial – Medium , Axial - Max (one direction) Very low High Four point ball brg QJ Radial – Low , Axial - Heavy Very low Medium Self-aligning ball brg 12/13/ 14/22/23 Radial – Low , Axial - Low (Both direction) High High Thrust ball brg. 51/52/53 /54 Radial – Nil , Axial -Medium (One direction) No Medium Cylindrical roller brg. N/NU NJ/NUP N - Radial only , NU – Radial only , NJ -Radial & one direction axial , NUP– Radial & both direction axial Low High Cylindrical roller thrust brg 81 Radial – Medium Axial- Medium (One direction) Very low Medium Spherical roller thrust brg. 29 Radial – High, Axial - Medium Low Medium
  • 41. Reasons for bearing failure Expected life 30,000 Hrs (3 Years) to 50, 000 Hrs (6 years) depending upon speed and type of lubricant used Misalignment Improper Lubrication Wrong selection Quality High bearing temp Vibration Early failure Early failure
  • 42. Thermal and electrical stress on electrical equipment
  • 43.  Looseness in parts  Impurities in insulation  Leakage flux  Overloading  Improper cooling  High ambient temp Thermal stress  Insulation failure  Melting of parts  Thermal Imaging  Tan Delta value
  • 44. INSULATION TEMPERATURE CLASSIFICATION Insulation Temperature Classification for Machines Temperature Index Some Insulation Combinations Class O (Obsolete) 90°C Oleo, Resinous, Cotton, Wood Class A 105°C Cotton, Vinyl Acetate Class E 120°C Phenolics, Alkyds, Leatheroid Class B 130°C Shellac/Bitumen, Silk, Mica, Polyesters Class F 155°C Epoxy/Polyesters, Silicone, Mica, Glass Class H 180°C Epoxy/ Polymides/ Silicone/ Mica/ Glass Class C 220°C Glass/ Silicone/ Mica/ Nomex/ Silicates
  • 45. Monitoring insulating properties in electrical machine Insulation Resistance (IR) Polarization Index (PI) Tan Delta Solid & liquid insulation Solid insulation Mixed insulation ( Solid + Liquid) Macro level measurement Macro level measurement Micro level measurement Insulating material is considered as a high resistive material with no leakage current Insulating material is considered as a high resistive material with minor leakage current Insulating material is considered as a dielectric of a capacitor with charging current and minor leakage current Measurement of resistive property of the insulating materials using leakage current Measurement of intensity leakage of current in high resistive materials by comparison of leakage current Measurement of dielectric property of the insulating material using leakage current IR = Applied voltage / leakage current PI = IR60 sec/IR15sec Tan delta = Leakage current / capacitor charging current Leakage current increases in insulating materials due to disintegration (heat / Physical) and wetness Leakage current increases in insulating materials due to wetness Leakage current increases in dielectric materials due to impurities and wetness Lower IR value trip the equipment on earth fault Lower PI value indicates wetness of the insulation Higher tan delta value increase the heating effect of the insulation Applicable for all electrical equipment Applicable for electrical motor Applicable for OIP bushing , transformer winding
  • 46. Limiting values for Insulation Resistance at different temperature Temperature Below 6.6 KV 6.6 KV to 11KV 22KV to 33KV More than 66KV 30 Deg C 200 MΩ 400 MΩ 500 MΩ 600 MΩ 40 Deg C 121.2 MΩ 242.4 MΩ 303.0 MΩ 363.63 MΩ 50 Deg C 76.9 MΩ 153.8 MΩ 192.3 MΩ 230.7 MΩ 60 Deg C 47.6 MΩ 95.2 MΩ 119.04 MΩ 142.8 MΩ 70 Deg C 30.3 MΩ 60.6 MΩ 75.7 MΩ 90.9 MΩ 80 Deg C 19.04 MΩ 38.1 MΩ 47.6 MΩ 57.2 MΩ Conductor (at high potential) Insulating materials Body (at earth potential) Ir V Fundamentals of Insulation Resistance (IR) value o IR = (V/ Ir) decreases with increase of leakage current (Ir) o Leakage current (ir) increases due to 1. Disintegration of insulating material as result of heat and physical puncture, 2. Wetness as a result of absorption of moisture
  • 47. Conductor (at high potential) Insulating materials Body (at earth potential) Ir V Fundamentals of Polarization Index (PI) value o Initially, IR = (V/ Ir) shows high and then decrease with time depending upon the intensity of the leakage current. (Ir) 1. If the insulation is wet , intensity of leakage current will increase with time causing IR value to drop with time. 2. If the insulation is dry , intensity of leakage current will not increase with time causing IR value to increase with time. Time (sec) IR value 6015 R60 R15 PI = (R60 / R15 ) < 1.5 ( Wet insulation) Time (sec) IR value 6015 R60 R15 PI = (R60 / R15 ) > 1.5 ( Dry insulation)
  • 48. Angle δ Cos δ Capacitance (pF) [(I/2 f V π) x Cos δ ] Angle Φ = ( 90 - δ ) Cos Φ =(PF) = Sin δ = Tan δ (%) Condition of the insulator 0.0 Deg 1 (I/3140)x1.000 90.0 Deg 0 Pure capacitor 2.0 Deg 0.999 (I/3140)x0.999 88.0 Deg 0.3 Very Good 3.5 Deg 0.998 (I/3140)x0.998 86.5 deg 0.6 Good 4.5 Deg 0.996 (I/3140)x0.996 85.5 Deg 0.7 Acceptable 5.0Deg 0.996 (I/3140)x0.996 85.0 Deg 0.8 Not acceptable 6.0 deg 0.994 (I/3140)x0.994 84.0 Deg 0.9 Not acceptable 90.0 Deg 0 0 0.0 Deg 1.0 Pure resistance Conductor (at high potential) Insulator Body (at earth potential) IC Ir V I IC Ir I Applied voltage 10KV δ Φ = (90 – δ) Power Factor = Cos Φ Cos (90 – δ) = Sin δ Sin δ = Tan δ Fundamentals of Tan Delta value
  • 49. Leakage flux heating  Due to continuous cutting of flux , current is induced in the tank  It is grounded through bell bolt and additional flat link  If it is not grounded properly, due to looseness of bell bolt, heat is developed in that area.
  • 50. Thermogram 230kV Bushings of ICT - 2 40.3 °C 56.9 °C 50 sp1 sp2 sp3 ar1 ar2 ar3 sp4 Object Parameter Value Emissivity 0.96 Label Value IR: Max Temperature 76.5 °C sp1: Temperature 68.5 °C sp2: Temperature 53.5 °C sp3: Temperature 50.2 °C sp4: Temperature 50.4 °C ar1: Max Temperature 60.5 °C ar2: Max Temperature 76.5 °C ar3: Max Temperature 50.9 °C Thermal Imaging
  • 51. Parts of motor Alarm temp setting Trip temp setting Average temp during operation Probable reasons for high temperature Bearings 850C - Grease 750C - Oil 950C - Grease 850C - oil 650C - Grease 550C - oil # Brg failure # High / Low grease # Low oil flow Stator Winding 1200C - Class B 1400C - Class F 1300C - Class B 1500C - Class F 800C -Class B 850C - Class F # High load # High core temp # Insufficient cooling Stator Core Approximately 100 0C (Max) 70 0C # Low freq.& volt opr. # Hot spot TB Approximately 60 0C (Max) 50 0C equal in three phases # Loose connection. # Uneven lugs Internal air Approximately 100 0C (Max) 70 0C # Blocked ventilation. # Improper fan External air Approximately 60 0C (Max) 50 0C # Blocked ventilation. # Improper fan Temperature monitoring in electrical motor
  • 52. Ambient Temp (50 Deg C) Temp Rise (55 Deg C) Hot spot Temp (10 Deg C) Ambient Temp (50 Deg C) Temp Rise (45 Deg C) Hot spot Temp (10 Deg C) Alarm : 105 Deg C Trip : 115 Deg C Alarm : 95 Deg C Trip : 105 Deg C Winding Temp Oil Temp Average operating temp : 60 to 75 Deg C Fan starts : 55 Deg C Fan stops : 50 Deg C Pump starts : 65 Deg C Pump stops : 60 Deg C Temperature monitoring in Transformer
  • 53. Electrical test ( Motor Transformer ) Winding combinati on Temp Applied voltage R15 R 60 PI = R60/R15 Tan Delta Remarks LV – E 5 KV for transformer of voltage grade > 6.6 KV 2.5 KV for transformer of voltage grade > 6.6 KV PI value > 1.5 HV – E LV – HV Delta Winding R-Y Y-B B-R Temperature Current Remarks Deviation should not be > 2.5% Star Winding R-N Y-N B-N Temperature Current Remarks Deviation should not be > 2.5% N
  • 54. Magnetizing current component (Im) = I0 Sin Φ No Load Current (I0) = √ (Im)2 + (Ih+e)2 Hysteresis & eddy current component (Ih+e) = I0 Cos Φ Voltage Flux Parameters Formula 75% 100% 110% Actual voltage (Vac) (Hz / 50) X V0 Actual Watt (Wac) {(50/Hz)+(50/Hz)2 } x 0.5 x W0 Hysteresis & eddy current (Ih+e) Wac / (1.732 x Vac) Magnetizing current (Im) √ [(I0)2 - (Ih+e)2] Core loss & magnetization current for transformer Voltage Magnetization current
  • 55. Condition monitoring of Transformer through transformer oil
  • 56. Oil parameters Operating parameters: a) Water ppm, b) Breakdown voltage (BDV), c) Tan delta, d) Resistivity. Aging parameters Furan analysis Oil quality parameters : a) Colour/ Appearance , b) Interfacial tension (IFT), c) Flash point, d) Neutralization value e) Sludge & sediments Internal fault parameters Dissolved Gas Analysis (DGA)  Criteria for operating transformer  To be tested once in six month  Parameters can be improved by oil processing ( Hot oil circulation / Filtration)  Decision for oil processing to be taken up  Criteria for aging factor of oil  To be tested once in a year  Decision for discarding the oil to be taken up  Criteria for detecting incipient internal fault  To be tested once in a year  Decision for oil processing / internal inspection to be taken up  Criteria for detecting residual life of the transformer  To be tested once in a five years  Decision for replacing transformer to be taken up
  • 57. Moisture in transformer oil 1. Atmospheric moisture which is absorbed by oil during breathing process 2. Chemically bound moisture in the insulating paper which gets released due to heat and oxidation. Source of Moisture Presence of Moisture 1. Free water – That is water that has settled at the bottom in a separate layer. Presence of free water in transformer oil is indicated by lower IR value of Transformer. 2. Emulsified water – Water that is suspended in the oil and has not yet settled down into free water . It is indicated by “caramel” colour oil. A high Tan Delta value indicates the possible presence of this suspended water trapped in oil decay products. 3. Water in solution – It remain dissolved in the oil. It is shows high moisture ppm in oil
  • 58. Moisture Movement 1. The moisture absorbing capacity of transformer oil increases with increasing of oil temperature. 2. When transformer is hot ( during service ) , moisture absorbing capacity of oil gets increased and moisture entrapped in solid insulation (paper) is absorbed by oil causing decrease of moisture in paper and increase in oil. 3. When transformer is cold ( during idle ) , moisture absorbing capacity of oil gets decreased and moisture rejected by oil is absorbed by solid insulation (paper) like blotting paper / towel causing increase of moisture in paper and decrease in oil . Hot oil - during service condition Solid insulation (Paper )Cold oil - during idle condition Moisture movement Moisture movement
  • 59. Damages caused by moisture Accelerate paper decaying process Increase acidity in oil Solid insulation (Paper) Reduces insulating ability (BDV) of oil Reacts with dissolved Oxygen in oil in presence of heat and produces Acid Moisturesludge Affects cooling process due to blocking of cooling duct Liquid insulation (Oil) Moisture in Oil Moisture in Paper
  • 60. Water content in paper Inference 0.5% Well dried paper 1.5% Minimum water content in paper 2% Maximum water content in paper 3% Paper fiber in oil 4.5% Flash over at 90 Deg C 7% Flash over at 50 Deg C 8% Flash over at 20 Deg C Inference of Griffin curve
  • 61. Determination of moisture in solid insulation using Griffin curve Griffin curve for water equilibrium in cellulose & mineral oil system
  • 62. Polar particles in transformer oil 1) Presence of soluble polar particles such as water molecule, sludge & sediments, varnish, resin etc, decease the insulating properties of transformer oil 2) The polar particle present in the oil gets ionized and initiate flow of leakage current through oil which causes oil heating 3) The polar particle present in the oil also affects the operating parameters - BDV, Resistivity & Tan delta of the oil + + + + + + - - - - - - - + + + - + + - + + + - + - - + + + + + - Leakage current Charging current Charging current High AC Voltage
  • 63. 50 40 30 20 10 0 10 20 30 40 50 60 Waterppminoil Dryness of oil Limit value : Water ppm in transformer oil New oil (72 – 170 KV Transformer) (>170 KV Transformer) (< 72 Transformer)No free water Dry Oil 1. The presence of water molecule in the oil is measured by Karl Fisher Titration methods. 2. The limit value of water ppm ( part per million) need to be maintained as per the guideline of IS 335 shown in the above graph
  • 64. 30 40 50 60 80 0 10 20 30 40 50 60 70 80 90 0 10 20 30 40 50 60 BreakDownVoltageinKV Water ppm in Transformer oil Limit value : Break Down Voltage in KV < 72.5 KV Transformer 72.5 -170 KV Transformer > 170KV Transformer BDV value of transformer oil mainly depends on water ppm in the oil and it decreases with the increase of water ppm in oil .In such case BDV of oil is improved by reducing water ppm in oil through filtration .  BDV of oil may also decrease due to low resistivity of oil caused by degradation of oil or contamination of oil with soluble polar particles. In such case oil needs to be replaced after confirming low resistivity & IFT value and high tan delta & acidity value with colour of oil.  BDV of oil is determined by applying AC voltage across a gap of 2.5mm ,filled with transformer oil to be tested .  The voltage at which the spark is observed between the gap , is the BDV of the oil.  Average of six such BDV value is taken as the actual BDV of the oil.
  • 65. 35 25 15 6 2 0.8 0.5 0.2 0.1 0 5 10 15 20 25 30 35 40 Resistivity(x1012Ohms–cm) Conductivity ( Flow of leakage current ) Limit value (at 90 Deg C) : Resistivity (Very Good) (Good) (Min) Resistivity is measured by applying 500 V DC voltage across the oil sample after heating up the sample at 90 Deg C which is the maximum allowable operating temperature of transformer
  • 66. Charging current Leakage current Total current O BA C δ3 δ2 0.002 0.2 1 0.001 0.01 0.1 1 TANDELTAVALUE Concentration of polar particles Angle value % Value Ideal TAN δ 0.000 AB/OB 0.000 δ0 0.0 Deg OC 0.% of OB Normal TAN δ1 0.002 AB/OB 0.002 δ1 0.1 Deg OC 0.2 % OB Maximum ( > 72.5 KV Transformer) TAN δ2 0.200 AB/OB 0.200 δ2 11.3 Deg OC 20 % OB Maximum (< 72.5 KV Transformer) TAN δ3 1.000 AB/OB 1.000 δ3 45 Deg OC 100 % OB δ1 Normal Max > 72.5 KV Transformer Max < 72.5 KV Transformer Tan delta
  • 67. Oil quality parameters  Colour  Acidity  Interfacial Tension
  • 68. Pale yellow Good oil Yellow Proposition ‘A’ oil Bright yellow Marginal oil Amber Bad oil Brown Very bad oil Dark brown Extremely bad oil Black Oils in disastrous condition Discarded oil Oil Colour
  • 69. Oil quality – Neutralization value Acidity Heat , Moisture and Oxygen initiate decomposition / oxidation of oil & paper and increases acidity of the oil Acid causes corrosion inside transformer Acid form sludge and sediments Good quality Neutralization value Acidity 0.25mg KOH / g oil
  • 70. Oil quality – Interfacial tension (IFT) IFT Presence of sludge , sediments and polar particle decrease IFT of the oil Reduce fluidity of the oil Not Good quality IFT Fluidity 18 dynes/cm Increases oil heating
  • 71. Interfacial Tension, Acid Number, Years in Service
  • 72. 72 Determination of oil quality based on IFT & NN IFT NN MIN = IFT/NN Colour Oil Quality & Observations 30 - 45 0.00 – 0.10 300 - 1500 Pale Yellow Very Good (provides all the required function) 27.1 – 29.9 0.05 – 0.10 271 - 600 Yellow Good(provides all the required function , a drop in IFT to 27.0 may signal the beginning of sludge & sediment) 24 – 27 0.11 – 0.15 160 - 318 Bright Yellow Acceptable (not providing proper cooling and winding protection. Organic acids are beginning to coat winding insulation; sludge in insulation voids is highly probable.) 18.0 - 23.9 0.16 - 0.40 45 - 159 Amber Bad (sludge has already been deposited in and on transformer parts in almost 100 percent of these units. Insulation damage and reduced cooling efficiency with higher operating temperatures characterize the Very Bad and Extremely Bad categories. 14.0 - 17.9 0.41 - 0.65 22 - 44 Brown Very Bad 9.0 - 13.9 0.66 - 1.50 6 - 21 Dark Brown Extremely Bad oil 1500300 600271 318160456 22 Very Good Good Acceptable / Bad / Very Bad / Extremely bad
  • 73. Internal fault parameters  Dissolved Gas Analysis (DGA)
  • 74. Types of Faults & generation of gases Partial Discharge (Particle Ionization) due to presence of tiny air bubble and polar particle in oil / Corona (Low intensity glow) OIL CELLULOSE H2 H2, CO, CO2 Low temperature heating (150 to 300 Deg C) Oil or conductor heating OIL CELLULOSE CH4, Methane C2H6 Ethane CO2, (CO) High temperature heating (300 to 700 Deg C) Hot spot heating OIL CELLULOSE C2H4 Ethylene H2, (CH4,C2H6) CO (CO2) Arcing Continuous High intensity spark due to Void in paper insulation H2, C2H2, Acetylene (CH4,C2H6,C2H4) TYPES OF INTERNAL FAULTS THERMAL FAULTS ELECTRICAL FAULTS
  • 75. Gases CIGRE CPRI CBIP 0 - 5 Yrs 6 - 10 Yrs 11-15 Yrs 0 - 4 Yrs 4 – 10 Yrs > 10 Yrs < 4 Yrs 4-10 Yrs > 10 Yrs H2 100 200 300 150 300 500 100/150 200/300 300/400 CH4 60 200 200 30 80 130 50/70 100/150 200/300 C2H2 40 200 300 15 30 40 20/30 30/50 100/150 C2H4 80 300 300 30 50 150 100/150 150/200 200/400 C2H6 40 100 200 30 50 110 30/50 100/150 800/1000 CO 700 700 700 300 500 700 200/300 400/500 600/700 CO2 8000 9000 9000 4000 - 10000 3000/5000 4000/5000 9000/12000 H2 ( Hydrogen), CH4 ( Methane) C2H2 ( Acetylene) C2H4 (Ethylene) C2H6 (Ethane) CO (Carbon Monoxide) CO2 (Carbon Dioxide) Limit value : DGA
  • 76. Fault Analysis - by Roger Ratio methods CH4 H2 C2H6 CH4 C2H4 C2H6 C2H2 C2H4 Faults 0.1 0 0 0 Partial discharge 0 0 0 0 Normal deterioration 1 0 0 0 Over heating >150 Deg C 1 1 0 0 Over heating 150 – 200 Deg C 0 1 0 0 Over heating 200 – 300 Deg C 0 1 1 0 General condition of overheating 1 0 1 0 Circulating current / Overheating of joints 0 0 0 1 Flash over without power flow 0 1 0 1 Current breaking through tap changer 0 0 1 1 Arc with power flow •Ratio less than 0.1 is designated as 0 •Ratio greater 1 is designated as 1
  • 78. Aging parameters  Indirect – Furan analysis  Direct – Degree of polymerization of paper
  • 79. Aging process of transformer’s solid insulation Moisture Oil impregnated solid insulation Heat Chemical degradation of solid insulation (Paper) And production of Acids, Peroxides, O2, H2O, Furan contents Dielectric degradation Mechanical degradation Conduction & Ionization (Partial Discharge) Glow discharge (Corona) Insulation Failure Oxygen
  • 80. Limiting values for furan analysis
  • 81. DP values and aging of transformer Years DP ValuesAge (Yrs) DP Values 0 >1000 1 975 12 700 22 450 25 390 35 125
  • 82. 82 Relation between furan content in oil and DP values of solid insulation