The document discusses transformer oil analysis. It describes the key components of a transformer's insulating system as the oil and paper. Transformer oil classifications include naphthenic oil, paraffinic oil, and silicon oil. The document outlines specifications for new and in-service transformer oils according to various standards. It explains the importance of various oil properties like appearance, acidity, dielectric strength, and oxidation stability and how they impact transformer performance and life.

1. TRANSFORMER OIL Analysis
M.G.Morshad / ACM ( Elect)
Transformer Maintenance Division / TPS II

2. Transformer Insulating system
Oil Paper
1. Acts as a Coolant
2. Act as an insulation
3. Protects the Paper from chemical
attack
4. Prevention of sludge buildup
5. Used as Diagnostic Tool
1. Mechanical Strength
2. Dielectric Strength
3. Dielectric Spacing

3. Transformer oil classifications
NAPTHANIC OIL
 Naphtha oil is more easily oxidized than Paraffin oil.
 But oxidation product i.e. sludge in the naphtha oil is
more soluble than Paraffin oil.
 Thus sludge of naphtha based oil is not precipitated in
bottom of the transformer.
 Hence it does not obstruct convection circulation of the
oil, means it does not disturb the transformer cooling
system
PARAFFINIC OIL
 Oxidation rate of Paraffin oil is lower than that of
Naphtha oil
 But the oxidation product or sludge is insoluble and
precipitated at bottom of the tank and obstruct
the transformer cooling system.
 It has high pour point due to the wax content
 In India it is generally used because of its cheaper and
easy availability.
SILICON OIL
Fire retardant, hence it is used only for fire prone area.
 Lower heat dissipation capacity and high moisture
absorbing capacity
 Costlier than mineral oil
Transformer
Oil
Mineral Oil
(petroleum product )
Synthetic Oil
(Chemical Product)

4. Oxidation Inhibitor in mineral oil
Mineral insulating oil undergo oxidative degradation process in the presence of oxygen to
form acid & sludge. To prevent these process , oxidation inhibitor is used for interrupting
process of oxidation and thereby minimize oil deterioration and extend the operating life of
the transformer the oil.
Depending on the presence of oxidation inhibitor, mineral insulating is categorized as –
1. Uninhibited oil 2. Inhibited oil
1. Uninhibited oil
New insulating oil as normally refined contains small amounts of certain chemical
compounds that act as oxidation inhibitors. These naturally occurring materials retard oil
oxidation until such time as they are expended. The rate at which the inhibitors in the oil
are used up is dependent upon the amount of oxygen available, soluble contaminants in
the oil, catalytic agents in the oil, and the temperature of the oil
2. Inhibited oil,
To increase the oxygen inhibitor beyond its natural limit, oxygen inhibitor is added in the oil
for reducing the rate of oxidation process in a view to increase the life expectancy of the
transformer . Phenolic materials are quite good for this purpose and the two most
commonly used inhibitors are 2,6-ditertiary- butylphenol (DBP) and 2,6-di-tertiary-butyl-4-
methylphenol or 2,6-di-tertiary-butyl-paracresol (DBPC).

5. 5

6. Heat transferring
capacity of transformer
oil
Approximate Oil
requirement for
transformer
Capacity Oil Requirement
Up to 1.5 MVA 0.85 KL / MVA
1.6 to 16 MVA 0.50 KL / MVA
> 16 to 250 MVA 0.28 KL / MVA
Approximate solid
insulation requirement
for transformer
6
Solid insulation Requirement
Thick Press board
( Barrier )
5% of total oil weight
Thin press board
(Barrier)
3% of total oil weight
Paper insulation
( Winding insulation )
2% of total oil weight

7. TRANSFORMER OIL SPECIFICATIONS
IEC -60296 – General Specification
• Functional Properties:
Viscosity, Pour point, Water content, BDV, Density, Tanδ.
• Stability Properties:
Appearance, Acidity, IFT, corrosive Sulfur, Antioxidant additive
• Performance Properties:
Oxidation Stability, Sludge
• HSE Properties:
Flash Point, PCB content, PCA content
7

8. TRANSFORMER OIL SPECIFICATIONS
NEW OIL:
An unused mineral insulating oils intended to use in transformers for
insulation and cooling purpose.
• IS-335/1993 – Specification for uninhibited new insulating oils.
• IS-12463/1988 – Specification for inhibited mineral insulating oils.
• IEC -60296/2003 – Specification for unused mineral insulating oils
for transformers and switchgear. This standard cover both uninhibited
and inhibited oils.
• ASTM – D3487/2000- Standard Specification for Mineral
Insulating Oil used in Electrical apparatus. This standard also covers
both uninhibited and inhibited oils.
8

9. TRANSFORMER OIL SPECIFICATIONS
Unused Mineral Insulating oils filled in New
transformers
• IS – 1866/2000 – Code of Practice for Electrical Maintenance and
supervision of Mineral Insulating oil in Equipment.
(Refer Table.1 for limiting values of various parameters)
• IEC – 60422/1998 – Supervision and maintenance guide for
mineral insulating oils in electrical equipment.
In service Mineral Insulating oils
• IS – 1866/2000 – Code of Practice for Electrical Maintenance and
supervision of Mineral Insulating oil in Equipment.
9

10. TRANSFORMER OIL SPECIFICATIONS
IS-335/1993 ( New Oil)
• Appearance ------------
• Density at 29.5˚C (Max)
• Kinematic Viscosity (Max)
1) at 27˚C ------------------
2) at 40˚C ------------------
• IFT at 27˚C (Min) ---------
• Flash Point (Min) ---------
• Pour Point (Max) ---------
• Neutralization Value
1) total Acidity (Max) ----
2) Inorganic acidity ------
• Corrosive Sulphur -------
• Clear and transparent
• 0.89 g/cm2
• 27 cSt
• Under consideration
• 0.04 N/m
• 140˚C
• -6˚C
• 0.03 mg KOH/gm
• Nil
• Non-corrosive
• Electric Strength (BDV)
1) New unfiltered Oil(Min)
2) After filtration (Min)
• Dielectric dissipation factor (tan δ)at 90˚C(max)
• Specific resistance (Resistivity)
1) at 90˚C (Min)
2) at 27˚C (Min)
• Oxidation Stability
1) Acidity (max)
2) total sludge (max)
• 30 KV (rms)
• If the above value is not attained, the oil shall be
filtered to 60 KV (rms)
• 0.002
• 35 x 1012
ohm-cm
• 1500 x 1012
ohm-cm
• 0.4 mg KOH/gm
• 0.1 % by weight
10

11. TRANSFORMER OIL SPECIFICATIONS
IS-335/1993 (Ageing characteristics)
• Ageing characteristics
a) Resistivity (Min)
1) at 27˚C
2) at 90˚C
b) Tanδ at 90˚C (Max)
c) Total acidity (Max)
d) Total sludge (Max)
• Presence of Oxidation inhibitor
• Water content
• SK value
• 2.5 x 1012
ohm-cm
• 0.2 x 1012
ohm-cm
• 0.20
• 0.05 mg KOH/gm
• 0.05 % by weight
• The oil shall contain natural
anti oxidant additives.
• 50 ppm
• Under consideration
11

12. TRANSFORMER OIL SPECIFICATIONS
IS-1866/2000-Recommended Limits of Unused Mineral Oil filled in New Transformer
Property Highest voltage of Equipment (KV)
<72.5 72.5-170 >170
Appearance Clear, Free from sediment and suspended matter
Density at 29.5˚C (g/cm2),Max 0.89 0.89 0.89
Viscosity at 27˚C (cSt),Max 27 27 27
Flash Point (˚C),Min 140 140 140
Pour Point (˚C),Max -6 -6 -6
Total acidity(mgKOH/gm),Max 0.03 0.03 0.03
Water content (ppm), Max 20 15 10
IFT at 27˚C (mN/m),Min 35 35 35
Tanδ at 90˚C, Max 0.015 0.015 0.010
Resistivity at 90˚C(x10e12ohm-cm),Min 6 6 6
BDV (KV),Min 40 50 60

13. TRANSFORMER OIL SPECIFICATIONS
IS-1866/2000-Violation Limits for in service oils
Property Highest voltage of Equipment (KV)
<72.5 72.5-170 >170
Appearance Clear and without visual contaminations
Water content (ppm), Max No Free water 40 20
BDV (KV),Min 30 40 50
Total acidity(mgKOH/gm),Max 0. 3 0. 3 0. 3
IFT at 27˚C (mN/m),Min 15 15 15
Resistivity at 27˚C(x10e12ohm-cm),Min 1 1 1
Resistivity at 90˚C(x10e12ohm-cm),Min 0.1 0.1 0.1
Tanδ at 90˚C, Max 1.0 1.0 0.2
Flash Point (˚C),Min Maximum decrease of 15˚C from initial value
Sediment and sludge No sediment or perceptible sludge should be
detected. Results below 0.02% by mass may be
neglected.

14. TRANSFORMER OIL SPECIFICATIONS
IS-1866/2000-Frequency of testing
Property Frequency of testing
Appearance In conjunction with other Quantitative tests
Water content After filling or refilling prior to energizing, then after
three and 12 months, subsequently along with DGA
BDV After filling or refilling prior to energizing, then yearly
Total acidity Yearly
IFT After filling or refilling prior to energizing, then yearly
Resistivity After filling or refilling prior to energizing, then yearly
Tanδ After filling or refilling prior to energizing, then yearly
Flash Point Yearly
Sediment and sludge Yearly

15. TRANSFORMER OIL SPECIFICATIONS
IS-1866/2000-Recommended Actions
Property Recommended Actions
Appearance As dictated by other tests
Water content Check Source of water and consider reconditioning
BDV Recondition the oil or alternatively, if more
economical or other tests dictate replace oil
Total acidity Replace or reclaim oil
IFT Replace or reclaim oil
Resistivity Replace or reclaim oil
Tanδ Replace or reclaim oil
Flash Point Replace the oil, equipment may require inspection
Sediment and sludge Where sediment is detected recondition the oil
15

16. TRANSFORMER OIL SPECIFICATIONS
IS-1866/2000-Classification of oils in service.
• Group 1: This group contains oils that are in satisfactory condition
for continued use. The frequency can be followed as described
earlier.
• Group 2: This group contains oils that requires reconditioning for
further service. (Low BDV and High water content). The frequency
can be followed as described earlier after reconditioning.
• Group 3: This group contains oils in poor condition that it can
restore satisfactory properties only after reclaiming. Insulating oils this
group should be reclaimed or replaced depending on economic
considerations.
• Group 4: This group contains oils, in such poor state that it is
technically advisable to dispose of them.
16

17. 17
In order to take account of different user of mineral oil requirements, equipment
has been placed in various categories as O, A, B, C, D, E, F, G
O : 400 KV and above
A : 170 to 400 KV
B : 72.5 to 170 KV
C : transformers <72.5 KV. OCB, switchgear
D : Instrument transformers >170 KV
E : Instrument transformers <170 KV
F : Diverter tanks of on-load tap-changers
G : Circuit breakers <72.5 KKV
Categories of equipment

18. PHYSICAL PROPERTIES OF OIL
Physical
Properties
Definition Purpose Effects
Appearance
The oils should be clear,
transparent, and free from
suspended matter.
To determine the presence of moisture,
sediments, carbon, fibers, dirt in the oil
which changes the appearance of the oil,
Decreases the Electrical
strength, IFT value etc.,
Density
It measures the weight of oil
with respect to the mass of
an equal volume of pure
water at the same
temperature
To ensure that the free water always
remains at the bottom and oil can
circulate easily due to lighter weight.
(Lower the density better the heat
transferring capacity )
Since density is inversely
proportional to temperature ,
heat dissipation capacity of
the oil decreases with the
decrease of temperature
Kinematic
Viscosity
It measures the resistance of
the oil to continuous flow
without the effect of external
force
To ensure the mobility of oil at low
temperature since presence of
sediments, moisture and aging of the oil
increases the viscosity value. (Lower the
viscosity better the oil quality & heat
transferring capacity)
Heat removal capacity from
windings increases with Low
viscosity at low temperature
and prevent localized
overheating.
Interfacial
Tension
It measures the molecular
attractive force between
water and oil molecule.
To determine the presence of polar
contaminates such as of sludge and
other degrading products as a result of
oxidation (Higher the IFT better the oil
quality heat transferring capacity )
Oil with lower IFT reduces
the cooling effect due to
presence of sludge & oil
decay product

19. PHYSICAL PROPERTIES OF OIL
Physical
Properties
Definition Purpose Effects
Flash point
It is the lowest temperature at
which oil vapour gets
ignited.
To determine the self ignition
temperature of oil for safe operation
and storing . (Higher the flush point
safer the operation & storing
hazards)
Low value to the specified
value – Risk of fire in
transformer
Pour point
It is the lowest temperature at
which oil stops to flow due to
solidification.
To determine the lowest temperature
at which oil stop flowing due to
solidification. (Lower the flush point
safer the operation & storing
hazards)
Low value to the specified
value – transformer oil stop
flowing.
Sludge &
Sediments
Solid matter comprises
insoluble in solvent. It can be
determined by Centrifuge
method
Oxidation or degradation products
of insulating materials, fibers of
various origins, carbon, and metallic
oxides etc., arise from the conditions
of service of the equipment. (Good
oil must be free form sludge &
sediments )
Reduces the electric strength
and hinder heat transfer.
19

20. CHEMICAL PROPERTIES OF OIL
Chemical
Properties
Definition Causes Effects
Neutralization
Number
or Acidity
It is the number of
milligram of Potassium
hydroxide required to
neutralize completely the
acids present in 1 gm of the
transformer oil.
Oxidation of
insulating oil due to
aging
Corrosion of various parts of transformer,
Lower the electric strength and causes
Insulation degradation
Oxidation
Stability
It the evolution of acid and
sludge formation tendency
of new mineral oil due to
oxidation
Moisture
Metal corrosion which minimizes the life of the
transformer
Moisture
It measures in ppm the
presence of moisture in
the oil
By breathing
action,
Chemical reaction
Decreases electric strength (BDV)
Electric dissipation factor (Tan Delta)
Resistivity
Dissolved
Gases
It measures of dissolved
Gases produced in the oil
due to decomposition of oil
Thermal
degradation Arcing,
Partial discharge
H2 = Partial discharge
H2,CH4 = Low energy discharge
CH4 = Low temp hot spot
H2, C2H2 = Arcing
C2H4 = High temp

21. ELECTRICAL PROPERTIES OF OIL
Electrical
Properties
Definition Causes Effects
Dielectric
Strength
It is the minimum voltage that oil can
withstand due to its dielectric strength
Solid impurities
Water content , Fiber
Conductive particles
Higher the value, Higher
the purity
Resistivi
ty
The resistivity of a liquid is a measure of its
electrical insulating properties under
prescribed conditions. High resistively
reflects low content of free ions and ion-
forming particles and normally indicates a
low count ratio of conductive contaminants.
Moisture , Acidity
Solid contamination
Higher the value , better
the condition of the oil
Dielectric
Dissipation
Factor / Tan
Delta PF = Cos φ = Cos ((90-∂) = Sin ∂ = Tan ∂
Heat dissipation in the insulator due to leakage
Current = OA x OB Tan ∂ (Watt)
Since heat dissipation in the insulator increases
With increase of PF / Cos φ / Tan ∂ - this factor is
known as dielectric dissipation factor and should be
as low as possible
Soluble varnishes, resins ,
Moisture
Increased value causes in
increase in temperature,
increase in corrosion(Applied voltage V)O
Φ = (90-∂)
∂
A
B
C Capacitive current
Actual current

22. TRANSFORMER OIL TEST PACKAGE
(As per IS: 1866)
22

23. Inference of the oil test result
1. Determination of moisture in the solid insulation
( on the basis of Ooman graph)
2. Decision of hot oil circulation / drying out for improving dielectric
properties by removing moisture from oil & solid insulation
( On the basis of Water PPM,, BDV)
3. Decision of providing air bellow at conservator, Silica jel breather
leak arrester for preventing air ingression
( On the basis of presence of oxygen )
4. Decision of discarding oil for loosing its dielectric or cooling
properties
( On the basis of Resistivity, Tan delta ,BDV, IFT , Acidity , Colour)
5. Tracing of internal fault due to thermal and electrical stress
(On the basis of DGA)
6. Aging status of the solid insulation
( On the basis of Furna Analysis ,CO2 / CO ratio)

24. 24
Moisture
(Dielectric Status)
1. Decomposes solid insulation
2. Reduces BDV
3. Increases oil heating
Slug & Sediments
(Aging status)
1. Reduce cooling effects
2. Indicates decomposition
of solid insulation
DGA
(Internal status)
1. Reduce life
2. Unforeseen failure
3. Sever damages
Water ppm
BDV
Tan ∂
Resistivity
Test results
are within
the limit
Test for
1. Hot oil circulation
2. Drying out
Replace Oil
Transformer is healthy.
No action is required.
No
No
Yes
Yes
Test for
Test results
are within
the limit
IFT
Acid Number
Sludge
content
Oil Colour
Test results
are within
the limit
Yes
(CO2/CO)<5
O2 >2000
Number
(CH4, C2H4,
C2H2) > Limit
value
Test for
Conduct
Furan
Analysis
No
Test results
are within
the limit
Yes
Replace Oil
1. RLA Study & DP test
2. Refurbishing of
solid insulation
3. Disposal of
transformer
Duval
Triangle
Analysis
(H2, CH4, C2H4,
C2H6, C2H2) >
Limit value
Roger
Ratio
Analysis 1. Internal Inspection
2. Tightness checking
3. Spare parts
changing
No

25. 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 QUALITY WITH COLOUR

26. ACIDITY OR NEUTRALISATION NUMBER(NN)
 Acids in the oil originate from decomposition/oxidation of oil.
 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
.
The acidity of oil in a transformer should never be allowed to exceed 0.25mg KOH/g oil.
INTERFACIAL TENSION(IFT)
 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.

27. 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

28. Interfacial Tension, Acid Number, Years
in Service

30. Condition of paper with increase of acid
content in oil

31. Moisture in transformer oil
1.Moisture may be present in four possible forms
1.Free water – That is water that has settled out of the oil in a separate layer. It is this water which is indicated by
a lower IR value of the transformer.
2.Emulsified water – Water that is suspended in the oil and has not yet settled out 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.
4.Chemically bound water – It remains chemically attached to the insulating paper and it is released when
oxidized.
Water dissolved in
oil (High Temp)
Water dissolved in
oil (Low temp)
Water
available
in the
paper
insulation
Temp
Water solubility
level in TR oil
0 Deg C 22 ppm
10 Deg C 36 ppm
20 Deg C 55 ppm
30 Deg C 83 ppm
40 Deg C 121 ppm
50 Deg C 173 ppm
60 Deg C 242 ppm
70 Deg C 331 ppm
80 Deg C 446 ppm
90 Deg C 592 ppm
100 Deg C 772 ppm
With the increase of temperature ,water saturation level of oil
increases and transformer oil absorbs moisture from the paper
insulation till its gets saturated .
Moisture movement
Moisture movement
With the decrease of temperature ,water saturation level of oil
decreases and transformer oil exudes moisture which is absorbed by
paper and subsequently deposited as free water at the insulation layers
and bottom of the transformer .
2. Movement of Moisture between oil and paper insulation

32. Moisture in transformer oil – Relative saturation
Water content in oil sample taken at 60 Deg C
(as per lab analysis)
45 ppm
Water solubility level in oil at 60 Deg C
(as per graph)
242 ppm
Relative saturation (RS) at 60 Dec C (45/242)x100 = 18.36%
Percent saturation water
in oil adjusted to 20°C
Condition of cellulosic insulation
0 – 5 % Dry insulation
6 – 20 %
Moderate wet, low numbers indicate fairly dry to moderate levels of
water in the insulation. Values toward the upper limit indicate
moderately wet insulation
21 – 30 % Wet insulation
> 30 % Extremely wet insulation
Condition of solid insulation based on relative saturation (RS) of oil
as per IEEE 62:1995 (B6)
Relative saturation (RS) indicates migration of moisture quantity between solid insulation and oil
during operation

33. Moisture in transformer oil
3. Moisture Distribution
The internal moisture distributed not
uniformly.
When the transformer is energized water is
attracted to areas of strong electric fields,
since water is a polar liquid having a high
permittivity or dielectric constant.
 It also begins to migrate to the coolest part
of the transformer . This location is normally
the insulation in the lower one-third of the
winding
 Paper insulation has a much greater affinity
for water than does oil. Thus, insulation acts
just like blotting paper or paper towels; it
soaks up water superbly. The water will
distribute itself unequally, with much more
water being in the paper than in the oil.
33

34. Moisture in transformer oil
4. Damages caused by moisture
 Moisture in oil reduces the insulating ability (BDV) of the oil .
This may occur from the following events:
 During periods of high load and high ambient temperatures, oil absorbs the moisture from
the paper that may decrease BDV of the oil and causes dielectric breakdowns.
 With sudden high loads, water can boil off conductor surfaces and the vapour bubbles can
cause dielectric failures as they rise to the top.
 During the cool-down period after high load, the relative saturation of oil will increase. At its
extreme at 100% relative saturation, water will precipitate out and greatly reduce the dielectric
strength of the oil.
 Moisture in paper causes the following destructive effects :
 Moisture and oxygen cause paper insulation to decay much faster and to form acids, metal
soaps, sludge, and more moisture.
 Sludge settles on windings and inside the structure, causing transformer cooling to be less
efficient. Acids cause an increase in the rate of decay, which forms more acid, sludge, and
moisture at a faster rate
 Expansion of the paper insulation, altering the mechanical pressure of the transformer
clamping system.
 Loss of insulating ability (Dielectric Breakdown Voltage)
 Increased corrosion of the core and tank
Progressive consumption of oil additives
34

35. Determination of moisture accumulation in
solid insulation through water ppm in oil
35

36. 36
Calculation of moisture accumulation in solid
insulation through water ppm in oil
Parameters Formula Value
Oil capacity of Transformer V 80,000 Liters
Density of oil D 0.86 Kg / Liters
Mass of the oil M = V x D 68800 Kg
Mass of the solid insulation SM = M x 0.1 6880 Kg
Water ppm in oil at 60 Deg C
( Lab test ) WCO 20 ppm
Corresponding water content
in solid insulation
( as per the graph)
WCP 2.2%
Approximate weight of water
in solid insulation SM X WCP /100 150 Kg

37. Effects of moisture accumulation in
the solid insulation

38. 38
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

39. +
+
+
+
+
+
-
-
-
-
-
-
-
+
+
+
-
+
+
-
+
+
+
- +
-
-
+
+
+
+
+
-
Leakage current
Charging
current
Charging
current
High AC Voltage
Effect on presence of polar particles in Transformer oil
The insulating properties of transformer oil decreases with the increase of soluble polar particles
such as water molecule, sludge & sediments, varnish, resin etc, in the oil.
The polar particle present in the oil gets ionized under the influence of high AC voltage. These
ionized particles gets attracted by the opposite polarity causing the flow of leakage current through
the oil (insulator). The intensity of the leakage current increase with increase of concentration of
polar particulates in the oil. Because of this reasons BDV, Resistivity & Tan delta value of the
transformer oil gets affected due to presence of polar particles such as water molecule, sludge &
sediments, varnish, resin etc in the oil.

40. 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.

41. As transformer oil is act as pure insulator, its resistance ( R ) should be is
always as high possible.
Resistance R = ρ x L/A where L = length & A = Area of the oil of the oil
column and ρ = Resistivity i.e. Resistance of per unit length of oil.
Hence to maintain high resistance ,resistivity of the oil should be as high as
possible or conductivity should be as low as possible.
With the increased concentration of polar particle in the oil, the conductivity
gets increased proportionally due to flow of leakage current.
Hence low Resistivity indicates :
1.Contamination of oil with polar particles produced by oxidation of oil due to
overheating , moisture & oxygen or aging of oil.
2.In such case oil replacement is required after confirming low IFT value, high
tan delta & acidity value with colour of oil.
3.Some time excess moisture contamination also can reduce resistivity. It is
confirmed with low BDV. In such case oil filtration can improve the oil resistivity .
4.Because of covalent, oil also shows low resistivity at increased temperature.
Resistivity

42. 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

43. DDF / Tan Delta
O
Φ = (90-∂)
∂
B
C
A
OA = Applied voltage,
OC = Charging current,
OB = Total current ( Charging current + Leakage current)
Charging current = OB Sin φ ,
Leakage current = OB Cos φ ,
PF = Cos φ = Cos ((90-∂) = Sin ∂ = Tan ∂ ( since ∂ is very small)
Dielectric leakage current = OB Cos φ = OB Tan ∂
Heat dissipation in the oil due to leakage current = V x I x PF
= OA x OB Cos φ = OA x OB Tan ∂ (Watt)
Applied Voltage
Capacitor
chargingcurrent
Being a pure insulator, transformer oil behaves like dielectric of a capacitor under high AC voltage and it
absorb charging current at 900
leading with respect to the applied voltage and maintain the PF angle of the
insulator at 90 Deg.
With the increase of concentration of soluble polar particle in the oil, PF angle (Φ) decrease and angle ∂
increases due to flow of leakage current. As result of this Tan delta value of the Transformer oil gets increased .
 Since oil is a covalent compound, its resistivity decrease at increased temperature and conductivity increases.
As a result of this Tan Delta value is also increased with temperature.
 Since heat dissipation in the insulator increases with increase of PF / Cos φ / Tan ∂ - this factor is known as
dielectric dissipation factor DDF and should be as low as possible.
Inferences :
1.Increase in Tan delta value indicates the contamination of oil with soluble ionized particles such as water
molecule, sludge & sediments, varnish, resin etc or due to loosing of insulating properties of oil as a result of
accelerated aging..
2. Oil heating increases with the increase of tan delta value.

44. Charging current
Leakage current
Total
current
O
BA
C
δ3
δ2
Limit value ( At 90 Deg C) : Tan Delta
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 value is measured
by applying 1000 V AC
voltage across the oil
sample after heating up the
sample at 90 Deg C which
is the maximum allowable
operating temperature of
transformer

45. Resistivity & tan delta
(indicates deteriorating status of the dielectric
due to oxidation & contaminations of oil)
Presence of the Polar
particles / Increase in
temperature
200
C 900
C
Presence of dissolved & free water /
Increase in temperature
200
C 900
C
Water ppm & bdv
(indicates present status of the dielectric
due to contaminations of oil with water )
Resistivity Ώ cm
Tan Delta %
BDV in KV
Effect of temperature on oil parameters

46. 46

47. Transformer oil processing
Removal of
Free & dissolved water,
Dissolved combustible gas
Solid particulate matter
RECLAIMING
( Chemical process)
for oil having higher acid number
and lower IFT
RECONDITIONING
( Mechanical process)
for oil having higher water ppm
Removal of
Free & dissolved water,
Removal of -
Sludge & sediments
(Polar, Acidic &
Colloidal materials)
OFF Line
process Circulating hot oil through
filter & vacuum chamber
in FILTER MACHINE
ON Line
process Circulating oil
continuously through
cartridge banks filled with
molecular sieve
Circulating oil
continuously through fuller
earth column
OFF Line
process

48. Off line reconditioning through filter machine
Magnetic
Filter
Automatic
Heater
Fine
Filter
Gear
Pump
Vacuum
Pump
Vacuum
Chamber
Transformer
Tank filled
with oil
Transformer oil is sucked from the bottom of the tank and passes through the magnetic
filter where metallic particles are removed and then it is heated up to 60 Deg C with the
help of automatic heaters. Heated oil is then pushed into a vacuum chamber where it is
made to fall in droplets forms for increasing surface area and timing so that dissolved water
in the oil gets evaporated ( under 760mm of vacuum, water gets evaporated at 40 Deg C)
and extracted by vacuum pump along with other dissolved gases. Then the degassed oil is
passed through fine filter where particles of size 3 to 5 micron is removed and pushed into
the top of the tank through gear pump. This process is going on continuously till the oil
parameters - water ppm, BDV, Resistivity & Tan Delta are achieved.

49. 49
Molecular sieve material
When transformer is in service, moisture available in the paper insulation is absorbed by oil
due to increase in water saturation level as result of oil temperature.
In such condition if the oil is circulated through the water absorbing cartridge filled with
molecular sieve material, moisture present in the oil gets absorbed by the sieve.
As a result of this process, moisture available in the paper is extracted by sieve through the
media of transformer oil.
This process is applicable only when the transformer is in service .
On line reconditioning through molecular sieve

50. Oil Reclaiming / Regeneration process as per IEC
60422
Oil reclamation remove oxidation inhibitors. Additives
shall be replaced in the reclaimed oil after the reclaiming
process and before the equipment is re-energized The
most widely used additives are 2,6-di-tert-butyl-
paracresol (DBPC) and 2,6-di-tert-butyl-phenol (DBP).

51. 51

52. Dissolved Gas Analysis (DGA)
 Due to normal aging or internal faults different types of gases
are generated which subsequently dissolve in oil.
 Hence dissolved gas analysis of the transformer oil gives indication of
the nature of fault inside the transformer.
 A sudden increase in key gases and the rate of gas production is more
important in evaluating a transformer than the accumulated amount of gas
 The advantages of dissolved gas analysis are -
52

53. Generation of gases
1. Hydrocarbons
& Hydrogen
Methane CH4
Ethane C2H6
Ethylene C2H4
Acetylene C2H2
Hydrogen H2
2. Carbon oxides
Carbon
monoxide
CO
Carbon
dioxide
CO2
3. Non fault gases
Nitrogen N2
Oxygen O2
At elevated temperature between 500K and 200K, following reaction
takes place and gases are produced which remains dissolved in the oil.
C (Solid) +2H2 (Gas) CH4 (Gas)
2CH4 (Gas) + 2H2 (Gas) C2H4 (Gas) + 2H2 (Gas)
C2H4 (Gas) C2H2 (Gas) + H2 (Gas)
C2H4 (Gas) + H2 (Gas) C2H6 (Gas)
C2H2 (Gas) + 2H2 (Gas) C2H6 (Gas)
Types of gases
53

54. Types of Faults & generation of gases
1. Corona
OIL CELLULOSE
H2 H2,CO,CO2
1. Low temperature heating
OIL CELLULOSE
CH4,C2H6 CO2,(CO)
2. High temperature heating
OIL CELLULOSE
C2H4,H2,(CH4,C2H6) CO,(CO2)
2. Arcing
H2,C2H2,(CH4,C2H6,C2H4)
TYPES OF FAULTS
THERMAL FAULTS ELECTRICAL FAULTS
54

56. NormalOperation&aging
Thermal Fault
Overloading
Over heating of oil and paper
FailureofPumps,Fans
Misdirectionflowofcoolingoil
duetoloosenessofoildirecting
baffle
Hot spot - causing overheating of oil & paper
Blockingofoilductbysludge
presentintheoil
Improper cooling
Badleadsconnection/Poor
contactinthetapchanger
Electrical Fault
Deteriorated /damaged insulation
Dischargingofstaticelectrical
chargesthatbuilduponshields
orcoreandstructureswhich
arenotproperlygrounded
Electricalarcingbetween
windingsandground,between
windingsofdifferentpotential,
orinareasofdifferent
potentialonthesamewinding,
Arcinginthetransformerdue
toshortcircuit/groundfault
Arcinginthetransformerdue
tovoltagesurgesuchasa
lightningstrikeorswitching
surge
Hummingduetoloosenessof
windingsthatcauseswinding
heatingasresultoffriction
FormationofKey
gasesintheoilas
resultof
decompositionof
oilandburningof
paperinsulation.
External
Conditions
Exposureofoiltotheenvironmentduetooil
leakandnotprovidingairbellows&silicajel
breatherintheconservator
Accumulationof
environmental
gases-O2,CO2,
N2,H2Ointheoil Types of Faults & generation of gases

57. Dissolved Gases
CIGRE
(1976)
ELECTRA
(1978)
ALSTHOM
(1980)
ERDA
H2 ( Hydrogen) 235 28.6 200 100
CH4 ( Methane) 100 42.2 200 200
C2H2 ( Acetylene) 330 - 200 30
C2H4 (Ethylene) 145 74.6 200 300
C2H6 (Ethane) 270 85.6 200 200
CO (Carbon Monoxide) 670 289 1000 -
CO2 (Carbon Dioxide) 4250 3771 10000 -
Acceptance limits (1)

58. Acceptance limits (2)
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
58

59. Acceptance limits (3)
as per IS: 9434 / 1992 , IS: 10593 / 1983 & IEC 599 –1978
GAS
LESS THAN FOUR YEARS
IN SERVICE (PPM)
4-10 YEARS IN
SERVICE (PPM)
MORE THAN 10 YEARS
IN SERVICE (PPM)
HYDROGEN 100-150 200-300 200-300
METHANE 50-70 100-150 200-300
ACETYLENE 20-30 30-50 100-150
ETHYLENE 100-150 150-200 200-300
ETHANE 30-50 100-150 800-1000
CARBON
MONOXIDE
200-300 400-500 600-700
CARBON DIOXIDE 3000-3500 4000-5000 9000-12000
59

60. Fault identification (1) - by Key gas
methods
Type of faults Dissolved Gasses
Over heating of solid insulating materials
(Insulating papers, Cloths, Parma Wood , Press Board )
Key Gas - Carbon mono oxide
(CO & CO2)
Overheating of oil
Key Gas – Ethylene
(CH4 ,C2H4 & H2)
Arcing in oil
Key Gas – Acetylene
(H2 ,C2H2)
Overheating of Paper and Oil
Key Gas - Carbon mono oxide
(CO, CO2, CH4, C2H4 & H2)
Arcing of Oil and Paper
Key Gas – Acetylene
(C2H2, H2, CO, CO2)
Corona Discharge
Key gas Hydrogen
(H2)
Partial Discharge
Key gas Hydrogen
(H2)
60

61. Fault identification (2) - by gas ratio
methods
61

62. Significance of acetylene (C2H2) in oil
 Generation of acetylene (C2H2) of any amount above a few ppm
indicates high-energy arcing.
 Trace amounts (a few ppm) can be generated by a very hot thermal fault
(500 Deg C or higher).
 One time arc, caused by a nearby lightning strike or a high voltage
surge, can also generate a small amount of C2H2.
 If C2H2 is found in the DGA, oil samples should be taken weekly or even
daily to determine if additional C2H2 is being generated.
 If no additional acetylene is found and the level is below the acceptable
limits, the transformer may continue in service.
 However, if acetylene continues to increase, the transformer has an
active high-energy internal arc and should be taken out of service
immediately.
 Further operation is extremely hazardous and may result in explosive
catastrophic failure of the tank, spreading flaming oil over a large area.
62

63. Significance of CO/CO2 ratio in oil
 If there is a sudden increase in H2 with only carbon monoxide (CO) and carbon dioxide (CO2)
and little or none of the hydrocarbon gases, CO2/CO ratio indicates the degradation of cellulose
insulation due to overheating.
 With normal loading and temperatures, the CO2 / CO ratio is found to be between 7 to 20 .
 If H2, CH4, and C2H6 increase significantly with CO2/CO ratio less than 5 , it indicates the
probability of problem.
 If the ratio is 3 or under, severe and rapid deterioration of cellulose is certainly occurring
 The ratio should be based on the gas generation of both CO2 and CO between successive DGAs
and not on accumulated total CO2 and CO gas levels
 Extreme overheating from loss of cooling or plugged oil passages will produce a CO2/CO ratio
around 2 or 3 along with increasing Furans
63

64. Significance of atmospheric gases (O2 & N2)
in oil
 Oxygen may be present inside the transformer due to ingression of air
through breather, leaks and air packets tapped in the winding.
 The oxygen reacts on the cellulose of the insulating paper and leads to the
formation of organic acids, which dissolved in oil and consequently form sludge.
 This sludge blocks the free circulation of the oil and thus increases the
operating temperature.
 The presence of sludge in transformer oil reduces the resistively and
increases the tan delta of the oil.
 Many experts and organizations, including EPRI, believe that presence of
oxygen above 2,000 ppm, in the oil greatly accelerates paper deterioration with
moisture above safe levels.
 It is recommended that if oxygen reaches 10,000 ppm in the DGA, the oil
should be de-gassed and new oxygen inhibitor needs to be installed.
 Nitrogen may be present inside the transformer due to leaking of N2
filled bellow provided in the conservator tank air and exposure of oil to
atmosphere through leaks , breathers etc.
Presence of nitrogen in the air indicates the leaking of conservator bellow or
exposure of oil to the atmosphere. 64

65. Fault Analysis ( 1) - by Roger 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
65

66. Fault Analysis (2) - by IEC 599 and CBIP
methods
C2H2
C2H4
CH4
H2
C2H4
C2H6 Ratio of the dissolved gases
0 1 0 Ratio less than 0.1
1 0 0 Ratio from 0.1 to 1.0
1 2 1 Ratio from 1.0 to 3.0
2 2 2 Ratio greater than 3
Fault detection chart
C2H2
C2H4
CH4
H2
C2H4
C2H6 Faults & Causes
0 0 0 No fault Normal aging
0 1 0
Partial discharge of low intensity . Discharge in gas filled cavities, resulting from incomplete
impregnation / super saturation / cavitations of high humidity
1 1 0
Partial discharge of high intensity As above but leading to tracking / perforation of solid
insulation
1 to 2 0 1 to 2
Discharge of low energy Continuous sparking in oil, between bad connection of different
potential or to floating potential. Break down of oil between solid material
1 0 2
Discharge of high energy Discharges with power follow through. Arcing / breakdown of oil
between windings or coils or between coils & earth , tap changer breaking current
0 0 1 Thermal fault of low temp (150 Deg C) General overheating of insulated conductor
0 2 0
Thermal fault of low temp (150 to 300 Deg C) Local over heating of the core due to
concentrations o f flux , increasing hot spot temperature, varying from small hot spots in core,
shorting links in core
0 2 1
Thermal fault of medium temp (300 to 700 Deg C) Over heating of copper due to eddy current,
bad contracts / joints, circulating current between core and tank
0 2 2
Thermal fault of high temp (more than 700 Deg C) Over heating of copper due to eddy
current, bad contracts / joints, circulating current between core and tank
66

67. fault analysis (3) – by IEEE (Std). C57-104™
Condition 1: Transformer is operating satisfactorily.
Condition 2: A fault may be present. Take DGA samples at least often enough to
calculate the amount of gas generation per day for each gas.
Condition 3: A fault or faults are probably present. Take DGA samples at least often
enough to calculate the amount of gas generation per day for each gas.
Condition 4: TDCG within this range indicates excessive decomposition of cellulose
insulation and/or oil. Continued operation could result in failure of the transformer.
67

68. 68
Recommendations – IEEE (Std). C57-104™

69. Fault analysis (4) - by DUVAL triangle
 In order to display a DGA result in the Triangle, one must start with the
concentrations of the three gases, (CH4
) = A, (C2
H4
) = B and (C2
H2
) = C, in ppm.
 Calculate the sum of these three values: (CH4
+ C2
H4
+ C2
H2
) = S, in ppm,
 Calculate the relative proportion of the three gases, in %:
X = % CH4
= 100 (A/S),
Y = % C2
H4
= 100 (B/S),
Z = % C2
H2
= 100 (C/S).
 Plot X, Y and Z in the DUVAL Triangle
 Point of intersection will be laying in a particular zone indicated in the triangle
 Interpret the reason from the DUVAL table
This special graph for Duval triangle can be
obtained by sending email to duvalm@ireq.ca.
69

70. Duval Triangle
70

71. Classification of faults- Duval method
Faults
Thermal Type Electrical Type
T1
Thermal Fault
t<300 Deg C
T2
Thermal Fault
300<t<700 Deg C
T3
Thermal Fault
t>700 Deg C
PD
Partial Discharge
T2
Thermal Fault
300<t<700 Deg C
T3
Thermal Fault
t>700 Deg C
71

72. Duval Table for interpretation
72

73. 73

74. 74

75. solid insulation
 Paper and cloth used in transformer is known as solid insulation.
 The main constituent of paper and cloth is fibrous material known as Cellulose
 Cellulose is an organic compound whose molecule is made up of a long chain of
glucose monomers (rings), typically numbering between 1000 and 1400
 With breaking down of cellulose chain, the number of glucose ring decreases in
the cellulose molecule
 Degree of polymerization (DP) is the average number of glucose rings in the
cellulose molecule and DP values state the aging status of the insulating paper
 DP value > 900 indicates good paper whereas DP value < 200 indicates bad
papers.
Glucose Glucose Glucose
75

76. Reasons for degradation of solid
insulation
1. Thermal degradation ( Heat) :
Heat produced during the operation of transformer breakdowns the glucose
monomers in the cellulose molecule. Because of this, the chain length of
cellulose gets reduced and free glucose molecules, moisture, CO, CO2
gases
and organic acids are produced. Because of this reason overheating of
transformer leads to reduction of its life
Cellulose Glucose molecule +H2
O+CO+CO2
2. Hydrolytic degradation (Moisture):
Water and acid separate the bonds between the glucose units in cellulose chain
and produce free glucose. Because of this reason only after careful drying of
insulating paper, transformers are put into service
HEAT
76

77. 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
Lighting /Switching
impulse
Dielectric degradation Mechanical degradation
Short
circuit
Conduction & Ionization (Partial Discharge)
Glow discharge (Corona)
Insulation Failure
Oxygen
77

78. 78

79. DP values and aging of transformer
Years
DP Values
Age (Yrs) DP Values
0 >1000
1 975
12 700
22 450
25 390
35 125
79

80. Interpretation of DP values
80

81. Furan analysis
 The mechanical properties of insulating paper can be established by direct
measurement of its tensile strength or degree of polymerization (DP).
 Direct measurement of these properties is not practical for in-service transformers since
it requires removal of a few strips of paper from suspect sites.
 This procedure can conveniently be carried out during transformer repairs. The results of
these tests will be a deciding factor in rebuilding or scrapping a transformer.
 Since it is usually not practical (and often dangerous to the transformer) to obtain a
paper sample from a de-energised, in-service transformer an alternative method has been
found.
 When a cellulose molecule de-polymerises (breaks into smaller lengths or ring
structures), a chemical compound known as a furan is formed.
 By measuring the quantity and types of furans present in a transformer oil sample, the
paper insulation overall DP can be inferred with a high degree of confidence.
The types and concentration of furans in an oil sample can also indicate abnormal stress
in a transformer, whether intense, short duration overheating or prolonged, general
overheating.
 Furan analysis can be used to confirm Dissolved Gas Analysis where carbon monoxide
present indicates problems with solid insulation
81

82. Inference of the chemical compounds obtained
during furan analysis of transformer oil
82

83. Aging & Furfural in oil – BHEL study
Age (Years) Furfural (mg/Ltr)
2 0.01
5 0.02
6 0.03
7 0.04
8 0.05
9 0.06
10 0.08
11 0.10
12 0.12
13 0.15
14 0.18
15 0.21
16 0.24
17 0.30
18 0.37
19 0.48
20 0.60
21 0.75
22 0.90
23 1.05
24 1.20
25 1.35
26 1.80
27 2.25
28 2.70
29 3.15
30 3.65 83

84. Relation between furan content in oil and DP
values of solid insulation
84

85. Limiting values for furan analysis
85

86. 8686
conversion table I
1% = 10,000ppm
Percent (%) ppm
0.0000% 0 ppm
0.0001% 1 ppm
0.0010% 10 ppm
0.0100% 100 ppm
0.1000% 1000 ppm
1.0000% 10000 ppm
2.0000% 20000 ppm
3.0000% 30000 ppm
4.0000% 40000 ppm
5.0000% 50000 ppm
6.0000% 60000 ppm
7.0000% 70000 ppm
8.0000% 80000 ppm
9.0000% 90000 ppm
10.0000% 100000 ppm
20.0000% 200000 ppm
30.0000% 300000 ppm
40.0000% 400000 ppm
50.0000% 500000 ppm
60.0000% 600000 ppm
70.0000% 700000 ppm
80.0000% 800000 ppm
90.0000% 900000 ppm
100.0000% 1000000 ppm
1ppm = 0.0001%
ppm Percent (%)
0 ppm 0.0000%
1 ppm 0.0001%
2 ppm 0.0002%
3 ppm 0.0003%
4 ppm 0.0004%
5 ppm 0.0005%
6 ppm 0.0006%
7 ppm 0.0007%
8 ppm 0.0008%
9 ppm 0.0009%
10 ppm 0.0010%
20 ppm 0.0020%
30 ppm 0.0030%
40 ppm 0.0040%
50 ppm 0.0050%
60 ppm 0.0060%
70 ppm 0.0070%
80 ppm 0.0080%
90 ppm 0.0090%
100 ppm 0.0100%
200 ppm 0.0200%
300 ppm 0.0300%
400 ppm 0.0400%
500 ppm 0.0500%
600 ppm 0.0600%
700 ppm 0.0700%
800 ppm 0.0800%
900 ppm 0.0900%
1000 ppm 0.1000%
2000 ppm 0.2000%
3000 ppm 0.3000%
4000 ppm 0.4000%
5000 ppm 0.5000%
6000 ppm 0.6000%
7000 ppm 0.7000%
8000 ppm 0.8000%
9000 ppm 0.9000%
10000 ppm 1.0000%
100000 ppm 10.0000%
1000000 ppm 100.0000%

87. 87
Torr mm Hg Atm. PSI kg/sq.cm kPa mBar
760 760 1.00 14.69 1.03 101.31 1013.3
600 600 0.79 11.66 0.82 79.98 800.0
500 500 0.66 9.67 0.68 66.65 666.7
400 400 0.53 7.68 0.54 53.32 533.3
300 300 0.39 5.83 0.41 39.99 400.0
200 200 0.26 3.84 0.27 26.66 266.7
100 100 0.13 1.99 0.14 13.33 133.3
80 80 0.11 1.56 0.11 10.66 106.7
60 60 0.08 1.13 0.08 8.00 80.0
40 40 0.05 0.711 0.05 5.33 53.3
20 20 0.03 0.426 0.03 2.67 26.7
10 10 0.01 0.142 0.01 1.33 13.3
5 5 0.01 0.142 0.01 0.67 6.7
2.5 2.5 0.00 0.00 0.00 0.33 3.3
1 1 0.00 0.00 0.00 0.13 1.3
conversion table II

88. 88
Water Boiling
point (Deg C)
Vacuum Gauge
Reading
(mmHg)
0 755.42
10 750.79
20 742.47
30 728.18
40 704.68
50 667.50
60 610.62
70 526.30
80 404.24
90 234.24
92 193.01
94 149.10
96 102.38
98 52.73
100 0.00
conversion table III

89. TR Oil
Temp
Water solubility
level in TR oil
0 Deg C 22 ppm
10 Deg C 36 ppm
20 Deg C 55 ppm
30 Deg C 83 ppm
40 Deg C 121 ppm
50 Deg C 173 ppm
60 Deg C 242 ppm
70 Deg C 331 ppm
80 Deg C 446 ppm
90 Deg C 592 ppm
100 Deg C 772 ppm
conversion table III