TRANSFORMER OIL

NAGARAJA.M.C
Executive Engineer (E), R.T South Division, KPTCL,
Rajajinagar, K.P.T.C.L, Bangalore :560010
 Transformer oil or insulating oil is a highly refined mineral oil that is
stable at high temperatures and has excellent electrical insulating
properties.Mineral insulation oil, refined from crude oil.

The function of the oil is to protect the solid insulation used in

the construction of the equipment, to quench arc and to dissipate the
heat generated in the equipment during the operation. In order for oil to
carryout these functions it must have certain properties:-

 Low viscosity- so that, it can move freely

 High flash point- to be able to quench arcs safely
 High electrical properties-to perform as an insulating liquid
 Chemical stability-to resist oxidation and provide a long service life
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 SIGNIFICANCE OF VARIOUS TEST PARAMETERS
 Appearance: The appearance of oil may show cloudiness or sediments which may indicate the
presence of free water, insoluble sludge, carbon, fibers, dirt etc.
 Flashpoint: A low flash point is an indication of the presence of volatile combustible products in
the oil. Prolonged exposure of the oil to very high temperature under fault conditions may
produce sufficient quantities of low molecular weight hydrocarbons to cause a lowering of the
flash point of the oil.
 IFT: The interfacial tension between the oil and water is a measure of the molecular attractive
force between their unlike molecules at the interface.40 dynes/cm for new oil ensures freedom
from all types of dissolved impurities. Also it provides a sensitive means for detection of polar
contaminants in the oil including those deterioration products acquired in service.
 Viscosity: Good oil should have low viscosity so that it offers least resistance to flow, there by
not affecting the cooling of transformer adversely. Low viscosity also assist initial penetration of
the oil into narrow ducts and promotes circulation through the winding to overcome local
overheating.

 Resistivity: Resistivity of oil reduces considerably due to presence of moisture, acidity and polar
contaminants. Unsatisfactory results indicate a greater extent of contamination and it may not be
possible to restore the oil to a satisfactory level by reconditioning. This will affect the total
insulation and consequently lower the Insulation Resistance values which is not good for the
operation of the the transformer. Even small traces of contaminating material will give a marked
lowering of the oil resistivity value. Low resistivity indicates the presence of moisture and
conductivity contaminants.

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 SIGNIFICANCE OF VARIOUS TEST PARAMETERS
 Dissipation Factor: It is an established method used for the detection of gross defect in the
insulation. Dissipation factor represents the overall loss in the bulk of the insulation. Tan delta
characteristics provide useful information regarding the state of the insulation. Higher Tan delta
value indicates the presence of dirt, conducting particle and other extraneous contaminants in
the insulation. At some point in the system the insulation would have failed allowing current to
flow along paths where it is not desired. The subsequent damage to the equipment may involve
burnt conductors, ruined magnetic core materials and destructive fires. The high dielectric loss
can trigger a thermal break down

 Neutralisation Number: Neutralisation number or the acid content of the insulating oil is
defined as the number of milligrams of KOH required to neutralize completely the acids present
in one gram of the oil. The presence of acids, besides corroding the various part of the
equipment i.e. transformer, it also lowers the di-electric strength of the oil and often polymerize
to form insoluble sludge which can clog the cooling system.
 Water Content: Water may originate from the atmosphere or be produced by the deterioration
of insulating materials. High water content accelerates the chemical deterioration of insulating
paper and is indicative of undesirable operating conditions.

 Break down Voltage: The breakdown voltage is of importance as a measure of the suitability
of oil to withstand electric stress. Dry and clean oil exhibits an inherently high breakdown
voltage. Free water and solid particles, the latter particularly in combination with high levels of
dissolved water, tend to migrate to regions of high electric stress and reduce breakdown voltage
dramatically. The measurement of breakdown voltage, therefore serves primarily to indicate the
presence of the contaminants such as water or conducting particles.
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 Highest equipment voltage, KV
Sl. No. Property
<72.5 72.5 to 170 >170
1 Appearance Clear, free from sediment and suspended matter
2 Density at 29.5°C (gms/cm3), 0.89 0.89 0.89
max

3 Viscosity at 27°C (cSt), Max 27 27 27

4 Flash point, (°C), Min 140 140 140
5 Pour point, (°C), Max -6 -6 -6
6 Neutralization value (mg 0.03 0.03 0.03
KOH/gm), Max

7 Water content (ppm), Max 20 15 10

8 Interfacial Tension (mN/m), Min 35 35 35
9 Di electric dissipation factor at 0.015 0.015 0.01
90°C

10 Resistivity (90°C) in 1012 ohm- 6 6 6

cm, Min

11 Breakdown voltage (KV), Min 40 50 60 5

 WATER CONTENT
Test Method IEC 814
 Water, in minute quantities, is harmful in power equipment because it is attracted to the
places of greatest electrical stress and this is where it is the most dangerous Water
accelerates the deterioration of both the insulating oil and the paper insulation,
liberating more water in the process (heat catalysed).
 This is a never ending circle and once the paper insulation has been degraded(loss of
mechanical strength) it can never (unlike the oil) be returned to its original condition.
Origins of Water
Water can originate from two sources.
Atmospheric
Via the silica gel breather (dry silica gel is always blue).
Via leaks into the power equipment, i.e. bad gasketing, cracked insulation, a
loose manhole cover, a ruptured explosion diaphragm etc.
(if oil can get out, water can get in).
Internal Sources

 Paper degradation produces water.

 Oil degradation produces water.
 Wet insulation contaminates the oil, (temperature dependent).
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 DIELECTRIC STRENGTH
Test Method: IEC 156

 The dielectric strength of an insulating oil is a measure of the oils ability to

withstand electrical stress without failure.
 The test involves applying a ac voltage at a controlled rate to two electrodes
immersed in the insulating fluid. The gap is a specified distance. When the
current arcs across this gap the voltage recorded at that instant is the dielectric
strength breakdown strength of the insulating liquid.
 Contaminants such as water, sediment and conducting particles reduce the
dielectric strength of an insulating oil. Combination of these tend to reduce the
dielectric strength to a greater degree.
 Clean dry oil has an inherently high dielectric strength but this does not
necessarily indicates the absence of all contaminates, it may merely indicate that
the amount of contaminants present between the electrodes is not large
enough to affect the average breakdown voltage of the liquid.
 Authorities now agree that careless sampling and testing technique has been the source of 99
percent of “bad “dielectric readings”

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 ACIDITY OR NEUTRALISATION NUMBER(NN)
Test Method: ASTM D974
 Acids in the oil originate from oil decomposition/oxidation products. Acids
can also come from external sources such as atmospheric contamination.

 These organic acids are detrimental to the insulation system and can induce
corrosion inside the transformer when water is present.

 An increase in the acidity is an indication of the rate of deterioration of the oil

with SLUDGE as the inevitable by-product of an acid situation which is
neglected.

 The acidity of oil in a transformer should never be allowed to exceed 0.25mg

KOH/g oil. This is the CRITICAL ACID NUMBER and deterioration
increases rapidly once this level is exceed.
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 INTERFACIAL TENSION(IFT)
Test Method : ASTM D971

• The Interfacial Tension (IFT) measures the tension at the interface between
two liquid (oil and water) which do not mix and is expressed in dyne/cm.

• The test is sensitive to the presence of oil decay products and soluble polar
contaminants from solid insulating materials.

• Good oil will have an interfacial tension of between 40 and 50 dynes/cm. Oil
oxidation products lower the interfacial tension and have an affinity for both
water (hydrophilic) and oil. This affinity for both substances lowers the IFT.
The greater the concentration of contaminants, the lower the IFT, with a badly
deteriorated oil having an IFT of 18 dynes/cm or less.

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 IFT-NN RELATIONSHIP
 Studies have shown that a definite relationship exists between acid number(NN) and
Interfacial Tension(IFT). An increase in NN should normally be followed by a drop in
IFT. The IFT test is a powerful tool for determining how an insulating oil has
performed and how much life is left in the oil before maintenance is required to
prevent sludge.

 The IFT provided an excellent back up test for the NN.

 IFT not accompanied by a corresponding increase in NN indicates polar

contamination which have not come from normal oxidation.

 Although a low IFT with a low NN is an unusual situation , it does occur because
of contamination such as solid insulation materials, compounds from leaky pot heads
or bushings, or from a source outside the transformer.

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 CONTAMINATION BY GASES

Gases present can be divided into two categories

1. Those which are dissolved in the oil from the
atmosphere.
2. Those which are generated inside.

Atmospheric gases – oxygen, nitrogen and carbon dioxide.

Dissolution depends on nature of gas, composition of gas,
temperature and pressure.

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 • QUALITY INDEX SYSTEM
• Dividing the Interfacial Tension(IFT) by the Neutralisation Number(NN) provides a
numerical value that is an excellent means of evaluating oil condition. This value is
known as the Oil Quality Index(OQIN) or Myers Index Number(MIN). A new oil , for
example has a OQIN of 1500.
OQIN = IFT 1500=45.0(typical new oil)
NN 0.03(typical new oil)
TRANSFORMER OIL CLASSIFICATIONS *
1. Good Oils
NN 0.00 - 0.10
IFT 30.0 - 45.0
Colour Pale Yellow
OQIN 300-1500
2. Proposition A Oils
NN 0.05 - 0.10
IFT 27.1 - 29.9
Colour Yellow
OQIN 271 - 600

3. Marginal Oils
NN 0.11 - 0.15
IFT 24.0 - 27.0
Colour Bright Yellow
OQIN 160 - 318 12
4. Bad Oils
NN 0.16 - 0.40
IFT 18.0 - 23.9
Colour Amber
OQIN 45 - 159

5. Very Bad Oils

NN 0.41 - 0.65
IFT 14.0 - 17.9
Colour Brown
OQIN 22 - 44

6. Extremely Bad Oils

NN 0.66 - 1.50
IFT 9.0 - 13.9
Colour Dark Brown
OQIN 6 - 21

7. Oils in Disastrous Condition

NN 1.51 or more
Colour Black
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 DISSIPATION FACTOR
Test Method: IEC 247

The Dissipation test measures the leakage current through

an oil, which is the measure of the contamination or
deterioration i.e. Reveals the presence of moisture resin,
varnishes or other products of oxidation oil or of foreign
contaminants such as motor oil or fuel oil. The test is not
specific in what it detects i.e. is more a screening test.

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TRANSFORMER OIL RESULTS ANALYSIS
Oil Color Acid (NN) IFT Oil Status Transformer Condition
Water White 0.03-0.10 30-45 Excellent Good
Yellow Tint 0.05-0.10 27-30 Good Sludge dissolved in oil
Yellow Solution 0.11-0.15 24-27 Marginal Acid coating insulation, sludge ready to
deposit in transformer
Orange 0.16-0.40 18-24 Bad Sludge in radiators, core & coil
Reddish-Brown 0.41-0.65 14-18 Very Bad Sludge hardening & layering,
insulation is shrinking & weakening
Brown 0.66-1.5 9-14 Extremely Bad Radiators blocked with bad sludge,
increased operating temperature
Black Over 1.5 Below 9 High Risk Transformer failure is likely

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 The IEEE Guide for reclamation of Insulating Oil and Criteria for Its Use (IEE Std 637-
1985) has four group classifications for oil evaluation.
Group I: Oils that are in satisfactory condition for continued use.
Group II: Group III: Oils that required only reconditioning for further service.
Oil in poor condition. Such oil should be reclaimed or disposed of depending upon
Group IV: economic considerations
Oil in such poor condition that it is technically advisable to dispose of it.
Test Suggested Limits for In-Service Oils Group I by Voltage Class

Dielectric Breakdown Voltage ASTM Test Method

Voltage, 60Hz, 0.100 gap <69KV 69KV-288KV >345KV
(min)
26 26 26 D-877

Neutralization Number,
mg KOH/g (max)

Interfacial tension, 0.20 0.20 0.10 D-974

mN/m (min)

Water ppm (max) 24 26 30 D-971

35 25 20 D-1533

For oil that does not meet the recommended thresholds above, there are two
options. One, the oil can be utilized in a lower voltage application, assuming it
was utilized above a 69KV application. Two, the oil can be reconditioned or
reclaimed to meet the Group I classification. Listed below are the thresholds for
oil treatment
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Suggested Limits for in-Service oils Group II & Group III

 TestMethod Group II Group III ASTM Test

 Neutralization Number Mg KOH/g (max) 0.20 0.50
D 974
 Interfacial Tension, mN/m (min) 24 16
D-971

In terms of what is actually occurring in the transformer,

listed below is a sample table that provides a general summary of
what's happening in the transformer based on the neutralization
number and the interfacial tension value.

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 GAS ANALYSIS
• Dissolved gas analysis (DGA) and the information it can provide are
particularly important in analysing the health of the transformer and determining
whether oil treatment is necessary. The rate of insulation decomposition will
increase significantly in the presence of faults. By drawing a sample and having
the gas composition analyzed, it's possible to distinguish between different fault
types.

• Although transformer oil testing is important, the results will be of no use

if you don't know how to interpret them. If the oil doesn't meet the
recommended level base on the IEEE Guide for Reclamation of Insulating Oil ,
then it should be reconditioned, reclaimed or disposed of based on the test
results.

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29
 • TRANSFORMER OIL GAS ANALYSIS
• Test Method IEC 567
 Transformers are vital components in both the transmission and distribution of
electrical power. The early detection of incipient faults in transformers is extremely
cost effective by reducing unplanned outages. The most sensitive and reliable
technique used for evaluating the health of oil filled electrical equipment is dissolved
gas analysis (DGA). .
 Insulating oils under abnormal electrical or thermal stresses break down to liberate
small quantities of gases.The qualitative composition of the breakdown gases is
dependent upon the type of fault. By means of dissolved gas analysis (DGA), it is
possible to distinguish faults such as partial discharge (corona), overheating (pyrolysis)
and arcing in a great variety of oil-filled equipment.
 Information from the analysis of gasses dissolved in insulating oils is valuable in a
preventative maintenance program. A number of samples must be taken over a period
of time for developing trends. Data from DGA can provide
 Advance warning of developing faults.
 A means for conveniently scheduling repairs.
 Monitor the rate of fault development
NOTE : A sudden large release of gas will not dissolve in the oil and this will cause the
Bucholtz relay to activate.
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31
 • ORIGIN OF GASES IN TRANSFORMER OIL
 Fault gases are caused by corona (partial discharge), thermal heating (pyrolysis) and arcing.
 PARTIAL DISCHARGE is a fault of low level energy which usually occurs in gas-filled voids
surrounded by oil impregnated material. The main cause of decomposition in partial discharges
is ionic bombardment of the oil molecules.
 The major gas produced is Hydrogen. The minor gas produced is Methane.
THERMAL FAULTS
 A small amount of decomposition occurs at normal operating temperatures. As the fault
temperature rises, the formation of the degradation gases change from Methane (CH4) to
Ethane (C2H6) to Ethylene (C2H4).
 A thermal fault at low temperature (<300deg/C) produces mainly Methane and Ethane and
some Ethylene. A thermal fault at higher temperatures (>300deg/C) produces Ethylene. The
higher the temperature becomes the greater the production of Ethylene.
 ARCING is a fault caused by high energy discharge.
 The major gas produced during arcing is acetylene. Power arcing can cause temperatures of over
3000deg/C to be developed.
 NOTE : If the cellulose material (insulating paper etc.) is involved , carbon monoxide and
carbon dioxide are generated.
 A normally aging conservator type transformer having a CO2/CO ratio above 11 or below 3
should be regarded as perhaps indicating a fault involving cellulose, provided the other gas
analysis results also indicate excessive oil degradation.
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GAS NORMAL ABNORMAL INTERPRETATION

H2
< 150 ppm > 1000 ppm Arcing corona

CH4
< 25 ppm > 80 ppm Sparking

C2H6
< 10 ppm > 35 ppm Local Overheating

C2H4
< 20 ppm > 100 ppm Severe Overheating

C2H2
< 15 ppm > 70 ppm Arcing

CO
< 500 ppm > 1000 ppm Severe Overloading

CO2
< 10 000 ppm > 15 000ppm Severe Overloading

N2
1-10 % NA -

O2
0.03 % > 0.5 % Combustibles 33
 The gases generated inside the transformers
are hydrogen and hydrocarbon gases.

The causes are:

 Thermal decomposition.
 Electrical stress.
 Electrolysis.
 Vaporization.
 Chemical reaction

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 PERMISSIBLE LIMITS
Permissible concentrations of dissolved gases in the oil of a healthy
transformer (Transformer Union AG)
Less than four
Gas 4 – 10 years > 10yrs
year in service

Hydrogen 10 / 150 ppm 200 / 300 ppm 200 / 300 ppm

Methane 50 / 70 ppm 100 / 150 ppm 200 / 300 ppm

Acetylene 20 / 30 ppm 30 / 50 ppm 100 / 150 ppm

Ethylene 100 / 150 ppm 150 / 200 ppm 200 / 400 ppm

Carbon
200 / 300 ppm 400 / 500 ppm 600 / 700 ppm
Monoxide

Carbon Dioxide 3000 / 3500 4000 / 5000 9000 / 1200

ppm ppm ppm
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Interpretation of Transformer faults by Various Methods

Key Gas Method

Fault Key Gases

Partial Discharge Methane and Hydrogen
Arcing Acetylene
Thermic/Overheating Ethylene
Degradation of Cellulose Insulation Carbon Monoxide

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Periodic DGA reveals increase of gas concentration of
key gas Ethylene even when load was reduced, indicating
severe thermal fault - overhead joint.

IEC indicates shorting links in core. Over heating of

copper due to eddy currents, bad contacts / joints

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 DGA indicates P.D. of high energy discharges in gas
filled cavities resulting from incomplete impregnation or
super-saturation or cavitation or high humidity leading
to tracking or perforation of insulation.

Transformer is heading towards serious fault,

internal inspection has to be effected at one stage or
other. However, as an immediate step, oil can be filtered
& kept under observation.
Not a remedy.

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Implementing your own preventive maintenance programme
(Overseas Example)

Early detection by dissolved combustible gas in oil analysis could

have prevented removal from service of this arc Transformer. The
industrial facility was unable to shut down the unit due to the fact
that they would have to stop all production. The client did monitor
the gas volume and fortunately a new Transformer arrived before
inevitable failure would have occurred. Upon subsequent visual
examination it was found that Transformer had arced from its
primary winding to ground. Upon further examination it was found
that the insulating spacers were completely burned on the primary
winding.

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 The Typical Faults That May Occur During Routine
Tests Are:

a. Arcing due to clearance to the tank and to adjoining winding

b. Overheating of the joints in OLTC and brazed points
c. Power follow through with continuous arcing
d. Inter turn windings failure
e. Shield ring failure
f. Core bolt fault

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 GREATEST ADVANTAGE OF DGA TECHNIQUE

a. Avoidance of unplanned outage as transformer defects are detected

at incipient stages itself so that timely remedial measures can be
undertaken to prevent damage or total loss of equipment.
b. Status of health check for transformer periodically
c. Is a quality test for new transformer / repaired transformer before
dispatch, installation & commissioning
d. Cleaning transformer without internal faults, when they have tripped
due to other reasons

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GREATEST ADVANTAGE OF DGA TECHNIQUE
• Avoidance of unplanned outage as transformer defects are
detected at incipient stages itself so that timely remedial measures
can be undertaken to prevent damage or total loss of equipment
• Status of health check for transformer periodically
• Is a quality test for new transformer / repaired transformer
before dispatch, installation & commissioning
• Cleaning transformer without internal faults, when they have
tripped due to other reasons
• Several gases where transformers have been saved from total
destruction, the confidence in DGA technique is so high that the
transformers are sent to repairs by no other evidence other than
that of DGA
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