TR. OIL _dipen

7/28/2019 TR. OIL _dipen

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Transformer Oil Analysis Can

Be Divided into three groups

1. Dissolved Gas in oil Analysis.

2. Transformer Oil Screening Analysis.3. Test for monitoring transformer

winding condition.


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Transformer Dissolve GasAnalysis.


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DGA Of Transformer Oil During normal use, slow degradation of the mineral oil generates

certain gases that collects in the oil.

When a transformer begins to function abnormally, the oil getsdecomposed/breaksdown and produces the free radicals as shownbelow. These free radicals subsequently recombine and producelow molecular weight hydrocarbon. This process is largelydetermined by temperature, but is also influenced by otherconditions.

H CH CH2 CH3 etc

Equilibrium at Fault temperature

H2 CH4 C2H6 C3H8 .

C2H4 C3H6 .

C2H2


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DGA analysis of Transformer oil. Analyzing these gases and their rate of production is

a valuable laboratory tool for evaluating the conditionof an operating transformer.

There are typically nine fault gases which areanalyzed in DGA. Each fault generates certain keygases and a distribution pattern of these gases.

There are three major types of electrical faults which

differs in their severity. The least severe is a partialdischarge or corona, localized hot spots are next inseverity, and the most severe is arcing.


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Classification of faults. Electrical faults in transformer can be broadly

classified as following:

Partial Discharge. Discharge of low energy

Discharge of high energy

Over heating less then 3000C.

Over heating with temp. in between 300 to7000C.

Overheating above 7000C


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Faults in Transformer and its Examples.

Arcing Corona

Overheati

ng of

Cellulose

Overheati

ng of Oil

1 Causes Arcing Corona Overheating of cellulose X X

2 Overheating of oil X X

3 Winding turn-to-turn short-circuit X4 Winding open circuit X X

5 Operation of build-in LTC X X

6 Winding distortion or displacement

7 Lead distortion or displacement

8 Loose connection to bushing terminals, tap X X X

leads, terminal boards

9 Free water or excessive moisture in oil X X

10 Floating metal particles X X

11 Loose connection to corona shields X

12 Loose collars, spacers, core ground straps, X core hold down angle (Braces)

13 Through fault X

14 Overloading X X

15 Damaged yoke bolt insulation X

16 Rust or other damage on core X

17 Damaged shunt packs of tank X

18 Jammed oil circulating path X

19 Cooling system malfunction X

Nature of Fault

Cause of FaultSr

No


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Mineral Oil CnH2n+2

Hydrogen H - H H2

Methane CH4

Ethane C2H6

Ethylene C2H

4

Acetylene H - C- C - H C2H2

Carbon Dioxide O - C - O CO2

Carbon

MonoxideC - O CO

Oxygen O - O O2

Nitrogen N - N N2

Structure of insulating oil and fault gases.Structural Formula of Oil and Fault Gases.


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Fault Gas Composition.

H2 88%

C02 1

C0 1CH4 6

C2H6 1

C2H4 0.1

C2H2 0.2

Corona in Oil

H2 39%

C02 2

C0 4

CH4 10

C2H4 6

C2H2 35

Arcing in Oil

H2 16%

C02 trace

C0 traceCH4 16

C2H6 6

C2H4 41

C2H2 trace

Pyrolysis in Oil

H2 9%

C02 25

C0 50

CH4 8

C2H4 4

C2H2 0.3

Pyrolysis of Cellulose


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Gases to be monitored in DGA as per IEC. Hydrogen (H2) Methane (CH4)

Ethane (C2H6) Ethylene (C2H4) Acetylene (C2H2) Carbon Monoxide (CO)

Carbon Dioxide (CO2) Nitrogen (N2) Oxygen (O2)


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Element Purpose of Test

Hydrogen (ppm) Key indicator of Corona. Secondary indicator of Arcing and Overheated Oil.

Methane (ppm) Secondary indicator of Corona, Arcing, and Overheated Oil.

Ethane (ppm) Secondary indicator of Corona and Overheated Oil.

Ethylene (ppm) Key indicator of Overheated Oil. Secondary indicator of Corona and Arcing.

Acetylene (ppm) Key indicator of Arcing. Secondary indicator of severely Overheated Oil

Carbon Monoxide (ppm) Key indicator of Overheated Cellulose. Secondary indicator of Arcing if the fault involves cellulose.

Carbon Dioxide (ppm) Secondary indicator of Overheated Cellulose. Secondary indicator of Arcing if the fault involves cellulose.

Oxygen (ppm) Indicator of system leaks, over-pressurization, or changes in pressure or temperature.

Nitrogen (ppm) Indicator of system leaks, over-pressurization, or changes in pressure or temperature.

Significance of Testing of Each Fault Gas


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Result Interpretations as per IEC code IEC method looks at the dissolved gas in oil ppm ratio of C2H2 / C2H4,

CH4 / H2 , C2H2 / C2H4 and assigns a code for each gas pair. Forsome of the code combinations, an analysis/probable cause isdefined.

IEC Ratio Code

resulting C2H2 CH4 C2H4

ratio C2H4 H2 C2H6

< 0.1 0 1 0

0.1 -


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Result Interpretations as per IEC codeIEC DGA RatiosC2H2 CH4 C2H4

Case C2H4 H2 C2H60 0 0 0 No Fault, Normal1 0 1 0 Partial discharges of low energy2 1 1 0 Partial discharges of high energy density3 1 0 1 Discharges of low energy, Arcing3 2 0 1 Discharges of low energy, Arcing3 2 0 2 Discharges of low energy, Arcing4 1 0 2 Discharges of high energy, Arcing5 0 0 1 Thermal Fault, 150 C, Conductor Overheating6 0 2 0 Thermal Fault, 150 - 300 C, Oil Overheating, Mild7 0 2 1 Thermal Fault, 300 - 700 C, Oil Overheating, Moderate8 0 2 2 Thermal Fault, 700 C, Oil Overheating, Severe


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Transformer Oil ScreeningAnalysis


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Transformer oil Filtration: It is a processof removing moisture and mechanical

impurities form the transformer oil.

Transformer oil reclamation: It is a

process of removing chemical impuritiesform the transformer oil.

Transformer oil Filtration & reclamation


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Function Of Transformer Oil.

1) Provides insulation.

2) Provides cooling,

3) Helps in extinguishing arcs.

4) Dissolves gases generated by oil & winding

degradation.


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Transformer oil Degradation.Oxidation

Transformer Oil Carboxylic Acids (Acids)+Oil

New oil contains little or no acidic material. As the acidic materialstart to form, the small amount of acidic material is soluble in oil.

However, as more of acidic material forms it would reach to aseparation point and further formation would result in separation ofsolid material. This material would settle at the bottom as sludge.

Acidic material in the oil reacts with various metals present in thetransformer and form salts; another form of sludge, which is also

insoluble in the insulating oil.

Effect of the sludge formation on transformer is very detrimentalfor its continued service. It is therefore essential to monitor thisprocess. For Monitoring oil condition following test are to be doneon oil.


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Test to be conducted on oil .

Sr No. Test Name

ASTM

Standard Ref.

No.

IS

Standard

Ref. No.

1 Dielectric Test ASTM D-877 IS - 6972

2 Moisture Content ASTM D-4928 IS - 1866

3 Interfacial Tension ASTM D-2285 IS - 1866

4 Acidity Test ASTM D-644 IS - 18665 Pow er Factor/Tan Delta Test ASTM D-924 IS - 1866

6 Test for O2 Inhibitor ASTM D-2268 -- -- -- --


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Dielectric Test Of Oil This test measures the ability of the oil to withstand electrical

stress at power frequencies without failure. A low value for thedielectric-breakdown voltage generally indicates the presence ofcontaminants in the oil.

Dielectric strength of oil is affected by the presence of moisture,foreign contaminants and particles generated due to oildegradation.

Significantly oxidized oil may show high dielectric strength inabsence of moisture. It is therefore not advisable to rely solelyon dielectric strength of insulating oil without performing othertest on oil.

Table -1 specifies limit of dielectric strength of oil for variousclass of transformer (based on operating voltage of transformer).


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> 145 KV Min 60 KV Min 50 KV72.5 & < 145 KV Min 50 KV Min 40 KV

< 72.5 KV Min 40 KV Min 30 KV

Requirement

Before Energizing

Transformer With

New Oil

Af ter Energizing

Transformer and

in Normal service

Dielectric Test(Breakdown Voltage)

in KV (IS:6972:1972)

Property/Test Method Equipment Voltage

Table - 1

Limit of Dielectric Strength


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Moisture in Oil. Affects the dielectric properties of the oil.

Affects winding insulation due to its hygroscopic nature.

At normal temp. winding insulation absorbs moisture from oil, thus

affecting its insulation property adversely and may reduce its life.

At increased transformer temp. winding insulation releases the

moisture and due to increased solubility of moisture in oil at thistemp, it will absorb the moisture.

Ageing of oil produces acids, which increases the solubility of water

in oil. Acid coupled with water further decompose the oil and forms

more acid and water.


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Water solubility V/S Temperature.


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Limits of Water Content in oil As Per IS 1866.

Before EnergizingTransformer With

New Oil

AfterEnergizing

The Transformer

and in Normal

Service

> 145 KV Max 15 ppm Max 25 ppm

72.5 KV & < 145 KV Max 20 ppm Max 35 ppm< 72.5 KV Max 25 ppm Max 35 ppm

Requirement

Equipment Voltage


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Interfacial Tension (IFT)

IFT can be defined as the amount of force required (in N/m) to

pull a small wire ring upward a distance of 1 centimeter through

water/ oil.

The new oil before it is accepted for service shall have IFT valueover 0.040 N/m.

As oil ages IFT value start decreasing.

IFT value less then 0.015 N/m indicates sludging.

IFT value in between 0.015 to 0.022 N/m shows an uncertain

condition.

IFT value more then 0.022 N/m indicates no sludging.

IFT value in between 0.015 to 0.022 N/M should be scheduled

for reclaiming.


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Acidity Test (Acid Number)

Acid number can be defined as amount of KOH

required in mg to neutralize the acid in 1 gram of

transformer oil.

New insulating oil has acid number less then 0.05.

An acid number of 0.15 or higher indicates

accelerated acid formation.

When acid number reaches to 0.15 then oil should be

reclaimed.

An acid number of 0.4 indicates sludging in oil.


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Relationship Between IFT and Acid Number.


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Power Factor/ Tan Delta Test.

It is the measure of imperfection of dielectric nature of oil. In an ideal

dielectric oil, the current flowing through it should lead the voltage by

90 degrees when sinusoidal AC voltage is applied. But it is not the

case in reality. The angle by which it is short of 90 degree is calledloss angle. The cosine of the angle (90 - loss angle) is called power

factor and the tangent of the loss angle is called dissipation factor.

The loss factor (angle) relates to the inability of molecules in the oil to

reorient themselves with an alternating electric field. This ability isdependent on the temperature of the sample, the size of the

molecules involved, and their polarity. It is also dependent on the

frequency of the alternating field.


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Power Factor/ Tan Delta Test.

The power factor and the tan delta are both affected by the

molecular size, composition, and relative orientation of

functional groups within the molecules. In general within a series

of similar molecules, the tan delta will increase as the molecularweight increases. It is therefore essential to monitor this process

through either Tan Delta or Power Factor Test.

IEEE suggested to monitor Power factor of Insulating oil while

IS-1866 suggest to monitor Tan Delta of Insulating oil. Somerepresentative values are given in the below table.


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Before Charging

(Max)

After Charging

(Max)

< or = 72.5 KV 0.05 1.00

72.5 - 145 KV 0.05 1.00

> 145 KV 0.05 0.20

Type Of Unit

Tan Delta

@25 C @100 C

New Oil max 0.05% max 0.3%

New oil received in new

equipment

< or = 69 KV max 0.15% max 0.15%

69 288 KV max 0.10% max 0.10%

>345 KV max 0.05% max 0.30%

Suggested Limit for oil

Usedmax 0.10% not specified

Type of oil/UnitPower Factor

As per IEC Standard

As per IS standard

Limit values of Power Factor and Tan Delta.


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Test For Oxygen Inhibitor.

Formation of acids and sludge is caused by oxidation of oil.

Prime importance is to be given to the exclusion of oxygen from oil.

To remove oxygen from the oil, oxygen inhibitor is added. This will act

like sacrificial electrode. Inhibitor presently used in transformer oil is Ditertiary Butyal

Peracresol (DBPC).

The ideal amount of DBPC is 0.3% by total weight of the oil.

Inhibitor amount falls below 0.08% then oxygen freely attacks the

transformer insulation system.

Inhibitor amount less then 0.1% in oil is scheduled for re-inhabitation.


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Test for monitoring transformerwinding condition.


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Why It Is Required??

Life of transformer is Life of Solid Insulation.

Transformer Insulation is made up from Cellulose.

Cellulose is a polymeric material of Cellobiose,-[C12H14(OH)6]n-, where n is in the

range of 300 to 700 units.

Cellobiose it self made up of two glucose units, C6H7O(OH)5 called monomer.

The number of monomer units in polymer is known as degree of polymerization

(DP). .

The new transformer insulation having DP in the range of 1000 to 1400 and at

the end of life its DP value is less then 200.

As paper ages or deteriorates due to heat, acids, oxygen and water, will producewater, CO, CO2, furan derivatives and Cellulose with reduce chain length.

In furan derivatives 2 furaldehyde (FFT) is more stable and often found in oil as

paper degrades.


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How to Monitor Paper Degradationfrom Oil Analysis?

Paper condition can be monitoring bymonitoring following parameters.

CO2 and CO concentration in oil.

CO2/CO ratio.

FFT level in oil.


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Monitoring of CO2 and COconcentration in oil.

IEEE standard C57.104 Guide for the Interpretation of Gases Generated in Oil-Immersed Transformer gives insulation status condition based on accumulatedvalues of CO2 and CO in oil. Accumulated dissolved gas (CO2 and CO) levelprovides four status condition as listed in following table:

CO2

concentration

in oil in ppm

CO

concentration

in oil in ppmCondition 1 Normal 0 - 2500 0 - 350

Condition 2 Modest Concern 2500 - 4000 351 - 570

Condition 3 Major Concern 4001 - 10000 571 - 1400

Condition 4 Imminent Risk > 10000 > 1400


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Monitoring of CO2/CO ratio.

Calculate CO2/CO ratio from each DGA.

It has been observed that with normal loading and temperature, the rate of

generation of CO2 runs 3 to 10 times higher then CO. Normally CO2/CO ratio is around 7.

CO2/CO ration is less then 3 indicate rapid deterioration of transformerinsulation by electrical fault (Hi-temperature Fault).

Ratio of CO2/CO around 2 indicates extreme over heating of transformer and itis strongly recommended that transformer should de-energized and internal

inspection is to be carried out. If ration of CO2/CO is greater then 10 generally indicate thermal fault with

involvement of cellulose (Low Temperature Thermal Fault Involving Cellulose).


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Monitoring of FFT Level In Oil.

As paper ages furan derivatives are produced inoil.

Some of furan derivatives are stable and some

are highly unstable in oil. In furan derivatives 2 -Furaldehyde (FFA) is most stable and often foundin oil due to degradation of paper.

FFA measurement in transformer oil gives theaverage decay integrates over the entire volume

of the transformer insulation. In healthy transformer, there are no detectable

furans in oil, or they are less then 100 ppb.


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Monitoring of FFT Level In Oil.

When transformer ageing starts or significantdamage to paper insulation from heat occurs,furan levels in oil can go up to at least 1000 ppb

and maximum to 70000 ppb. Table -2 can be used for the assessment of

insulation condition in which First column in tableis used for the transformer with non-thermallyupgraded paper and second column is for the

transformer with thermally upgraded paper. From furan analysis & from the table-2 it is easy

to identify the insulation condition and estimatethe residual life of the transformer.


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2-Furaldehyde Furans (ppb) Estimated Estimated % of

(ppb) Thermally DP Remaining Life

Non thermal Paper upgreaded paper

58 51 800 100130 100 700 90

292 195 600 79

654 381 500 66

1464 745 400 50

1720 852 380 46

2021 974 360 42

2374 1113 340 382789 1273 320 33

3277 1455 300 29

3851 1664 280 24

4524 1902 260 19

5315 2175 240 13

6245 2487 220 7

7337 2843 200 0

End of Expected Life of

Paper Insulation and of

The Transformer

Interpretation

Normal Aging Rate

Accelerated Aging

Rate

Excessive Aging

Danger Zone

High Risk Of Failure

Table -2- Furans, DP, Percentage of life Used, of paper insulation.


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EHV TRANSFORMERS/REACTORS (132 KV AND

ABOVE BUT INCLUDING UNIT AUXILIARY

TRANSFORMERS):-

DGA, BDV and Moisture in oil to be done once in sixmonth.

Acidity, IFT, PF/Tan Delta and Furan analysis to be done

once in year.

Test for oxygen inhibitor to be done in once in two year.

If possible metal particle analysis also to be done once in

year.

Contd.

Recommended Test


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Transformer Below 132 KV ...

DGA, BDV and Moisture analysis in oil to be done

once in year.

Acidity, IFT, PF/Tan Delta and Furan analysis tobe done once in year.

Test for oxygen inhibitor to be done in once in

three year.


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Some Examples

Case I 2/27/75

Hydrogen 231 ppm

Oxygen 1043

Carbon Dioxide 2194

Ethylene 5584*

Ethane 1726*

Acetylene 0

Nitrogen 71,154

Methane 3997*

Carbon Monoxide 0

Conclusion : Thermal Fault, 700 C, Oil Overheating, Severe

not involving cellulose.

Ratio Value IEC Ratio code

C2H2/C2H4 0 0

CH/H2 17.3 2

C2H4/C2H6 3.2 2


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Some Examples

Case II 7/23/74

Hydrogen 127 ppm

Oxygen 1947

Carbon Dioxide 2024

Ethylene 32

Ethane 1

Acetylene 81*

Nitrogen 78,887

Methane 24

Carbon Monoxide 0

Ratio Value IEC Ratio code

C2H2/C2H4 2.5 1

CH/H2 0.18 0

C2H4/C2H6 32 2

Conclusion: Discharges of high energy, Arcing not

involving cellulose.


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Limitations of Oil Analysis.

No homogeneous condition with in thetransformer due to which system is

never at true equilibrium. Pinpointing of problem is not possible.

Extremely difficult to reach on any

conclusion based on single Analysis. When fault is detected other techniques

are also required for assistance.


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Thank you

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