cond. mon.of xmer

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INTRODUCTION

Power Transformers are capital intensive and critical for power utility industries. Most of

the transformers used in the industries are oil filled type. The primary insulation system used inoil filled transformers is Kraft paper, wood, porcelain and oil. Presently chemically treated paper

is used in transformer winding insulation to improve its tensile strength and resistance due to

decay caused by immersion in oil. The average life of a transformer in India is 25-30 years. A

failure occurs in the transformer when the insulation system becomes weak to the extent that itcan no longer act as an insulator to the high voltage to which it is subjected. Various studies on

transformer failure show that 75 % of Transformer failure is caused by insulation breakdown.

Therefore the key for extending the life of the transformer is to keep insulation in good condition.

In order to maintain the quality of insulation we must understand the reasons for its degradation.Following reasons can be listed.

a) Voltage transients caused due to faults on L.V. sidesb) Heat due to overloading or improper cooling

c) Dirt, which may be caused due to improper breathing system

d) Insulating oil degradation due to aging etc.

e) Moisture due to improper breathing, leakages etc

d) Oxygen

Transformer Oil

TransformerOil is a very complex mixture of many different compounds which can bebroadly grouped into:

I) Aromatic Hydrocarbons

II) Napthenic Hydrocarbons

III) Paraphenic Hydrocarbons

Besides hydrocarbons, hetro atoms like Nitrogen and Sulphur are also present in transformer

oil. Thus the properties and qualities of transformer oil very much depend upon its composition which

in turn is controlled by the base material & refining methods.

The transformer oil is separated from the crude oil. The manufacturing of transformer oil

involves two stages. First stage is to prepare the Transformer oil base stock (T.O.B.S) and secondstage to manufacture transformer oil from transformer oil base stock (TOBS). The T.O.B.S. obtained

from the refinery after processing of crude oil, contains above PNA (Paraffins, Napthenes &

Aromatic Hydrocarbons). Out of the three, the aromatic hydrocarbons have to be removed to the

desirable extend to achieve high break down voltage, high, viscosity index and high flash point and

other properties of transformer oil to meet the standard specifications. The T.O.B.S. is treated with

sulfuric acid of high strength for sulphonation of aromatic hydrocarbons. The Aromatic sulphonates

thus formed are extracted with the solvent isopropyl alcohol. After distillation of the remaining

T.O.B.S. the transformer oil is obtained. In a country like India where ambient temperature rarely


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goes below zero degree centigrade pure Napthenic oil is not necessary and hence the oil containing

some Paraphenic compounds is suitable and economical.

2. Necessity of OIL in Transformer.

2.1 The oil is used as insulation between windings & core and windings & tanks. Without oil,

the paper insulation of the windings could be punctured early which in turn will result infailure of the transformer.

2.2 The oil facilitates cooling of the windings and magnetic circuits. If a transformer isenergized without any oil in it, the temperature of the windings and magnetic circuits will

rise rapidly above its limit values & as a result the insulation material becomes charred

and the transformer gets damaged.

2.3 The oil protects the windings and core of transformer from the absorption of moisture. Thehygroscopic nature of the oil absorbs moisture from the windings and hence keeps the

presence of moisture in winding under check. Oil then can be filtered to reduce the

moisture.

3 Contaminants inTransformer OIL.

The oil can develop following contaminants while in use in equipment.

1) Water: Its quantity can be determined by Karl Fischer Titration

2) Sediment and precipitable sludge: These can be determined by method given in Ann. A

of IS 1866:2000

3) Polar substances: These can be determined by fall in values of Dielectric dissipation

factor, Resistivity and IFT.4) Acids: Can be measured by Neutralization value

5) Dissolved gases: These can be measured by Gas Chromatograph.

6) Light Hydro Carbons: Can be determined by Flash Point tests

4. Significance of tests and test methods

There are large numbers of tests which can be carried out on the oil from equipment in

service. But experience shows that only following tests are sufficient to decide whether the oil

condition is adequate for continued operation and if not so, then suggest the type of corrective

action required.

Property Method

1. Appearance IS 3352. Electric Strength IS 6792

3. Water Contents IS 135674. Neutralization Value IS 1448 (P-2)

5. Sediment and sludge Ann. A of IS 1866

6. Dissipation Factor IS 6262

7. Resistivity IS 6103

8. Inter Facial TensionIS 6104

9. Gas Contents IS 9434

10. Pour Point IS 1448 ( P-10)

11. Density IS 1448 ( P- 16)

12. Flash Point IS 1448 ( P-21)


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13. Viscosity IS 1448 ( P-25)

5. Importance of Sampling

Sampling of oil from equipment in service plays most importantpart in the whole exerciseof testing. All efforts should be made to ensure that the samples are the representative of the

insulating oil in the equipment. In many cases it has been experience that improper sampling has

resulted in test results that may point out to the rejection of oil without any justification. Following

points are to be taken care of while sampling.

1) The oil sampling should be done as per the methods outlined in IS.

2) Sampling should be carried out when the equipment is operating in normal service.3) Sampling is done by an experience person

4) Sampling in outdoors during rain, fog and strong winds should be avoided

5) Use amber colored glass bottles or seamless metal containers of stainless steel

6) Clean the sampling orifice by letting run sufficient oil.

7) Rinse the containers with the oil to be sampled8) While sampling let the oil run smoothly against wall of container

9) Proper identification of sample bottle should be ensured

6. Definition of Test Parameters and Their Significance

6.1. Appearance

Visual inspection and odor may render important information about the condition of the

oil. A) Cloudiness in the oil may be the result of excess moisture or contaminants in oil.

B) Acidic smell indicates the presence of volatile acids which can cause corrosion.

C) Color can indicate ageing qualities of oil. As follows:

Clear/ Pale Yellow- Good Oils Yellow- Fairly average oils

Bright Yellow- Marginal Oils

Amber- Bad Oils

Brown Very Bad Oil

Dark Brown- Extremely bad oils

Black- Oils in disastrous condition.

6.2 Density

Density is measured in gm/cm3. It is necessary that the oil should have density less than water.

In case the ambient temperatures fall below pour point of the oil, the water may float on the oil

and may cause arching breakdowns. The density also indicates the type of transformer oil, whetherparaffin base or naphtha base.

6.3 Kinematic Viscosity

The oil should circulate freely in the equipment to maximize heat transfer. Low viscosity oilfulfills this need. Viscosity of oil increases because of oxidation. The rate of oxidation increases with

the contact with air, with temperature rise and with catalytic effect of moisture and metal with which

oil is in contact .Viscosity increase is often accompanied by increase in acidity.

6.4 Flash Point


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The temperature at which the oil gives off so much of vapour that this vapour, when mixed

with air, forms ignitable mixture and gives the momentary flash on application of pilot flame under

the prescribed conditions.

It is an indication of volatile combustible component in the oil. Minimum temperature at which

oil will support instantaneous combustion (a flash) but before it burns continuously (fire point). Flashpoint is an important indicator of the fire and explosion hazard associated with the oil. Therefore,

flash point of new oil should be fairly high because it will gradually decrease in service due tosparking, high working temperature etc. producing sufficient quantities of low molecular weight

hydro-carbons.

6.5 Pour Point

It is the indicator of the ability of oil to flow at cold operating conditions. It is the lowesttemperature at which the fluid will flow when cooled under prescribed conditions.

6.6 Neutralization Value (Total Acidity)

This indicates the presence of combined acids i.e. organic and inorganic (measured in mgKOH /gm of oil). The oxidative ageing of oil gives rise to acidic compounds and formation of

sludge. The degradation can be measured in terms of acidity which can be used as fitness of the oilfor further services. The acidity content in transformer oil should be very low as it will cause

precipitation of sludge and corrosion of metal surface.

6.7 Water Contents

It is the measure of water present in the oil. It is expressed in parts per million (PPM). The oil

and windings always contain moisture. The presence of moisture in oil is highly undesirable as it

affects adversely the BDV of the oil. The moisture present in the oil also affects the solid insulationof transformer.

Water may originate from the atmosphere or be produced by the deterioration of the

insulating materials. When the water contents are low it does not affect the appearance of the oil and

also may not affect the electrical properties of the oil. The solubility of water in oil increases withincrease in temperature and acidity. Above a certain limit i.e. saturation point the water cannot remain

in solution and free water can be seen in the form of cloudiness or water droplets. This results in

decrease of BDV and Resistivity and increase in Dissipation factor.

The total moisture present in a transformer is distributed between paper and oil with paper

having much higher moisture content than oil. When the transformer is energized the moisture begins

to migrate to the coolest part of the transformer and the site of the greatest electrical stress. This

location is normally the insulation in the lower one third part of the winding. Paper insulation has a

much greater affinity for the moisture than the oil. The moisture will distribute itself unequally, with

more moisture being in the paper than in the oil.

As the temperature of the transformer increases paper releases moisture, thus increasing themoisture content of the oil. The solubility of the moisture is not constant in oil but changes due to

temperature.

6.8 Inter Facial Tension

It is a force necessary to detach a planar ring of platinum wire from the surface of the liquid

of higher surface tension that is upward from the water-oil surface and is expressed in mN/M

The interfacial surface tension between the oil and water is measure of the molecular

attractive force between the unlike molecules at the interface. It provides the means of detecting the

soluble polar contaminants and products of deterioration. The IFT changes rapidly during the initial

period of energisation but levels off when deterioration is still moderate.


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6.9 Dielectric Strength/ Break Down Voltage (BDV)

It is a voltage at which the breaks down when subjected to an A.C. electric field with a

continuously increased voltage contained in a specified apparatus and is expressed in kV.The dielectric strength or break down voltage (BDV) of oil is its ability to withstand

electric stresses without failure. One or more of contaminating agents may be present when

low dielectric strength (BDV) values are indicated by test. The BDV of transformer oil is oneof the most reliable tests for proving the conditions of oil and hence should be carried out

meticulously. Free water and solid particles along with high levels of dissolved water reduce

the BDV to a great extent.

6.10 Specific Resistance (Resistivity)

It is the ratio of DC potential gradient in volts per cm. paralleling the current flow within the

specimens to the current density in amperes / sq. cm at a given instant of time under a prescribed

condition This is equivalent to the resistance between opposite faces of a cm cube of the liquid and isexpressed in Ohm-centimeter.

This is a measure of electrical insulating properties of oil. High Resistivity reflects low

content of free flowing particles. This parameter is dealt in conjunction with the DDF in following

paragraph.

6.11 Dielectric Dissipation Factor (DDF)/ Tan delta

It is a tangent of the angle (delta) by which the phase difference between the applied voltage

and resulting current deviates from 90 deg. When dielectric of the capacitor consists of exclusively of

the insulating oil. The delta determines the cleanliness of oil and is related to ageing characteristic of

the oil.

7 FACTOR AFFECTING DETERIORATON OF TRANSFORMER OIL

7.1 Moisture is one of the most undesirable contaminant of oil in service. It finds its way in thetransformer by any of the following route:

i) Accidental leakage

ii) Breathing action

iii) Filling up or topping up operation

iv) Chemical reaction

The presence of moisture in oil reduces its electrical strength. The reduction in electrical

strength is mainly due to the dissolved moisture. The moisture may not be solely responsible for

the reduction in electrical strength, it is solid impurities which absorb water and prove more

dangerous. The cellulose insulation (paper) absorbs moisture very quickly. In new oil, waterabsorption capacity is low, but as the oil ages in services, acids are formed and emulsifying of oil is

increased. The chemical decomposition of oil is the result of atmospheric oxygen reacting with the

hydrocarbons in the transformer oil. Oxidation is the chain reaction. The hydrocarbons react with

oxygen and generate peroxides, hydro peroxides and other free radical R from the hydrocarbon. The

oxidation reaction is greatly catalyzed by metals particularly copper. The copper & iron are capable

of reacting with hydro peroxide giving more free radicals, which react with fresh hydrocarbons. The

above reactions are affected by;

i) Oxygen availability

ii) Temperature, reaction doubles fro every 10 degree rise


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iii) Material in contact with oil like copper, resin, fiber board, natural rubber etc.

7.2 CAUSES OF DETERIORATION

a) Physical contaminationb) Chemical decomposition

c) Gaseous contamination

A) PHYSICAL CONTAMINATION

The foreign material like dust, metallic particles, fibers and other solid impurities from within

the equipment and the moisture contaminate the insulating property of the oil severally.

The insulating material such as paper, wood, cotton, fiber and pressed board used in

transformers generally release fibrous impurities into the oil after having been in contact with

the later for longer period of time at higher temperature.

The varnish used for impregnating the coil of the transformer also gets dissolved to some

extent into the oil and influence the oil quality.

Further, certain components of varnish reacts with copper and form copper soap whichdeteriorates the oil very actively.

B) CHEMICAL DECOMPOSITION

The oil gets decomposed chemically due to oxidation after having come into contact with

atmospheric Oxygen.

The oxidation becomes predominant at elevated temperatures with availability of oxygen in the

oil, with every 100 C rise in temperature the oxidation rate increases almost twice.

The oxidation of oil is a continuous and chain reaction.

The exposed copper in direct contact with oil increases further oxidation in the transformer oil.

C) GASEOUS CONTAMINATION

Oxygen, nitrogen and carbon dioxide from the atmosphere get dissolved into oil via

breathing during inhaling action of the oil.

The gases like methane, ethane, acetylene, ethylene, propylene, butane, carbon dioxide,

carbon monoxide and hydrogen etc. are generated due to one or more of the following

causes.

i) Thermal decomposition of oil due to arcing

ii) Decomposition of oil due to arcing

iii) Electrolysis

iv) Vaporization of oil

v) Chemical reaction between the deteriorated oil and other material.

The subject of Dissolved Gas Analysis is dealt is being separately in this manual.

8. ACTION TO BE TAKEN FOR THE IMPROVEMENT OF TRANSFORMER OILIN SERVICE.

If the tests results on the transformer oil are normal i.e. conform to the specified values as

indicated in IS/IEC then no corrective action is necessary other than the routine maintenance of the

transformer. But if the parameters tested are beyond limits then following steps are needed to be

taken. : 1) Filtration/Reconditioning 2) Reclamation 3) Re-refining 4) Replacement.


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8.1 RECONDITIONING/FILTERATION:

This is a process which eliminates, by physical means only, solid particles from the oil and

decreases water content to acceptable levels. The physical means that are used for removing water and

solids from oil include several types of filtration, centrifuging and vacuum dehydration techniques.

8.2 RECLAIMATION:

This is a process which eliminates soluble and insoluble contaminants from the oil by

chemical and absorption means in addition to mechanical means, in order to restore the properties as

close as possible to the original values. This process is best performed by oil refiner.

8.3 RE-REFINING:

This is the treatment that makes use of primary refining processes that may include

distillation, acid, caustic, solvent, clay or hydrogen treatment and other physical and chemical means

to produce oil with oil characteristics complying with IS 335.

8.4 REPLACMENT OF DETERIORATED OIL BY FRESH OIL.

Before filling the equipment in use with fresh oil it is necessary to rinse the inside of the tankand immersed parts like winding before filling it with new oil.

The above items no. 8.1 to 8.4 are not dealt in details in this manual as they are beyond

the scope of the discussions made in this manual. The users are requested to refer to IS 1866

and other such literature available and also the instruction manuals of the Manufacturers of the

concerned equipment.

9. DISSOLVED GAS ANALYSIS

Dissolve Gas Analysis (DGA) is one of the most widely used diagnostic tools for detecting

and evaluating faults in electrical equipment. However the interpretation of DGA results is often

complex and should always be done with care, involving experienced insulation maintenance

personnel. (Ref:-IEC 60599:1999). The DGA is applicable to electrical equipment, more particularly

to the transformers filled with mineral insulating oil and insulated with cellulosic paper or press-

board-based solid insulation.

The technique of DGA is more of an art than the exact science and hence is to be viewed onlyas guidance and any corrective action should be undertaken only with proper engineering judgment.

This writer has referred to various publications of IS, IEC, ASTM and other writers who have

specialized in the field of DGA. Also this writer has incorporated his own experiences of more than

35 years in this field.

This topic is divided in three parts namely the causes of generation of gases, the technique ofDGA and lastly the guide for interpretation and evaluation of DGA.

9.1 Causes of generation of gases

Mineral insulating oils are composed essentially of saturated hydrocarbons, whose general

molecular formula is CnH2n+2 with n in the range of 20 to 40. The cellulosic insulation material is

polymeric substance whose general molecular formula is [C12H14O4(OH)6}n with n in the range of 300

to 750.


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Fault gases are produced by degradation of the transformer oil and other insulating materials

such as cellulose. In the presence of an active fault, the rate of oil and cellulose degradation is

significantly increased, and the types of degradation products formed will vary with the nature and

severity of the fault. The composition of the gas mixture resulting from the decomposition is energy

dependent. And since the fault processes differ greatly in the energy they dissipate, different types ofGas mixtures are produced for each type of fault processes. By observing the composition of the gas

mixtures produced by the degradation of insulation media, it is possible to distinguish three basicfault processes which differ greatly in their energy characteristics. These are arcing, corona or partial

discharge and pyrolysis or thermal decomposition.

Partial lists of fault gases that can be found in the transformer are shown in following groups.

1. Hydrocarbons & Hydrogen 2. Carbon Oxides 3. Non Fault gases

a) Methane CH 4 a) Carbon Monoxide CO a) Nitrogen N 2b) Ethane C 2H6 b) Carbon Dioxide CO2 b) Oxygen O2c) Ethylene C 2H4d) Acetylene C 2H2

e) Hydrogen H 2

These gases will accumulate in the oil as a result of various faults. Their distribution will be

affected by the nature of insulating material involved in the fault and nature of the fault itself. The

major/minor fault gases can be categorized as follows by the type of material involved and the type offault:

1. Corona

a. Oil Hydrogen

b. Cellulose Hydrogen, Carbon Monoxide, Carbon Dioxide

2. Pyrolysis/ Temperature Faults

In Oil

a. Low Temperature : Methane, Ethane

b. High Temperature: Ethylene, Hydrogen (Methane, Ethane)

In Cellulose

a. Low Temperature : Carbon Dioxide, ( Carbon Monoxide )

b. High Temperature: Carbon Monoxide ( Carbon Dioxide )

3. Arcing: Hydrogen, Acetylene, (Methane, Ethane, Ethylene)

Other causes of gas generation:

Gases may be generated in some cases not as a result of faults but because of many other

reasons such as:

1) Rusting or other chemical reactions involving steel, uncoated surfaces or protective paints.

2) Reaction of steel and water as long as oxygen is available

3) Manufacturing processes of transformer like welding etc.


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4) Decomposition of thin oil film between overheated core laminates.

5) Exposure of oil to the sunlight during repairs.

6) Internal transformer paints.

9.2 TECHNIQUE OF GAS CHROMATOGRAPHY

The Gas Chromatography involves three basic steps : 1) Extraction of gases from Oil sample,

2) The chromatography, 3) Data processor from the output of G.C. ( Gas Chromatograph)

9.2.1 Gas Extraction

The process involves creating a vacuum of less than 0.1 milibar in an airtight flask and

pouring into this vacuum, which will extract maximum gas from the oil. This is further followed bythe churning the oil with magnetic stirrer and if necessary heating the oil to a moderate temperature.

Most of the extraction process is capable of extracting 97% of the gas dissolved in the oil sample.

The gas is then trapped on the upper part of the capillary of the equipment with the help of

mercury and kept isolated from sample under normal temperature and pressure. This gas is then

injected in the Detector system of the G.C. with the help of gas tight syringe specially manufactured

for this purpose.

9.2.2 Chromatography

The Gas Chromatography is an analytical technique for separating the component of gas

mixture on the basis of the relative amounts of each component distributed between a moving carrier

gas and a contiguous stationary phase. Since the detailed GC technique is not in the scope of this

manual the same is not discussed here. However those who are interested may visit the web-site www.gaschromatography.com/basic.asp.

9.2.3 Data Processing.

The out put from the GC is analyzed by the data processor, which produces Chromatogram, a

two-dimensional representation of the amount of gas component as a function of elapsed time since

the separation experiment began. The retention time taken along with the and peak width are the

dimensions of the Chromatogram. Those who are interested may visit the web-site

www.gaschromatography.com/basic.asp.

9.3 INTERPRETATION OF DISSOLVED GAS ANALYSIS

9.3.1 Introduction

Following standards are referred while giving the brief idea of interpretation of DGA,

1) IS.10593: 19922) IEC 60599:1999

3) ASTM D 3612

4) IEEE Trans. Electr. Insul. Vol.EI-13 No.5

Before going ahead with the interpretation of DGA, it is necessary to ensure that :.

1) Whether the measured values are well above the sensitivity of the analytical methods and

equipment2) Whether the gas concentrations are high enough to warrant further investigation.
http://www.gaschromatography.com/basic.asphttp://www.gaschromatography.com/basic.asphttp://www.gaschromatography.com/basic.asphttp://www.gaschromatography.com/basic.asp


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DGA data by itself may not always provide sufficient information to evaluate the DGA. Following

historical information is an integral part of the DGA interpretation.1) How old Is the transformer?

2) Did a bushing fail at some point?3) Did the transformer fail at some time?

4) Is the unit heavily loaded as of today or in past?

5) Has the transformer been repaired after a failure?

6) Has the DGA tests been performed in past?

7) Have the fault gases risen suddenly?

8) Has the oil been degassed?

9.3.2 DGA Interpretation methods

There are several available methods used to dignose the the sources of gassing. Three

commonly used methods are

1) Dornenberg ratio method

2) Rogers Ratio Method

3) Key Gas Method.

However, unlike the diagnosis of blood where rules have been established, diagnosis in oils is

not so clearly defined. It is experienced that the diagnosis of gases does not always yield the same

results when using different methods on the same sample.

For the sake of simplicity, we will discuss only two methods, a) Key Gas Method and b) IEC

method.

The method in IS 10593: 1992 was base on IEC Pub 599:1978, which has since beenmodified in 1999 as IEC 60599. Hence we are referring to this international standard.

9.3.3 Key Gas Method

This method uses the percentage of various key gases to determine the cause :

9.3.3.1 ARCING

Large amounts of H2 and C2H2 are generated with minor quantities of CH2 and C2H4.

CO2 and CO may also be formed if the fault involves cellulose.

The oil may be carbonized.

Key gas Acetylene.

9.3.3.2 CORONA :

Low energy electrical discharge produces H2 and CH4 .

Comparable amount of CO and CO2 may result from discharge on cellulose.

Key gas- Hydrogen

9.3.3.3 OVER HEATED OIL

The decomposition of oil due to overheating produces C2H4 and CH4 with smaller

quantities of H2 and C2H6 .


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Traces of acetylene may be formed if the fault severe or electrical contacts.

Key gas Ethylene.

9.3.3.4 OVER HEATED CELLULOSE

Large quantities CO and CO2 are evolved.

Hydrocarbons gases such as CH4 , C2H4 may be formed.

Key gas Carbon monoxide

9.3.4 Ratio Code Method

9.3.4.1 Types of Faults

It is experienced that the following broad classes of faults have been visually observed

a) Partial Discharge (PD) of corona type, resulting in X-Wax deposition on paper insulation, or of

sparking type, inducing pinhole, puncture in paper, which are very difficult to find.

b) Discharges of low energy (D1) in oil or/and paper large paper punctures, Tracking, carbon

particles in oil (like in OLTC)

c) Discharges of high energy ( D2) ) in oil or/and paper with power follow through, evidenced by

extensive destruction and carbonization of paper, metal fusion at discharge extremities, extensive

carbonization in oil

d) Thermal faults below 300 Deg.C ) in oil or/and paper (T1), when paper turns brownish and above

300 Deg.C. (T2) if the paper has carbonized.

e) Thermal Faults above 700 Deg.C. (T3), there is strong evidence of carbonization of oil, metal

coloration ( at 800 Deg. C.) or metal fusion ( above 1000 Deg.C)

9.3.4.2 Basic Gas Ratios

Each of the above six broad classes of faults leads to a characteristic pattern of hydrocarbon

gas composition. This then can be translated in to a DGA interpretation table based on the use of

three basic gas ratios

C2H2 CH4 C2H4C2H4 H2 C2H6

Following table can be applied to all types of equipment with a few differences in gas ratiolimits depending on the specific type of equipment:

Case Characteristic Fault C2H2 / C2H4 CH4 / H2 C2H4/C2H6

PD Partial Discharges Not Significant < 0.1 < 0.2

D1 Discharges of low energy > 1 0.1-0.5 > 1

D2 Discharges of high energy 0.6-2.5 0.1-1 > 2

T1 Thermal Fault < 300 Deg. C. Not Significant >1 but N.S. < 1

T2 Thermal Fault bet. 300 & 700 < 0.1 > 1 1-4


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T3 Thermal Fault > 700 Deg. C 1 > 4

9.3.4.3 Typical Faults in Power Transformers

Type Fault Examples

PD Partial Discharges Discharge in gas filled cavities due to incomplete impregnation,

high humidity in paper, Oil super saturation or cavitations & leading to

the X-Wax formation

D1 Discharges of Low

energy

Sparking/arcing in oil between bad connections of different or

floating potential, from shielding rings, adjacent discs or windings

broken brazing or closed loops in core

Discharges between clamping parts bushing and tank, high voltage

and ground within windings, on tank walls,

Tracking in wooden blocks, glue of insulation beam, windingSpacers. Breakdown of oil, selector breaking current.

D2 Discharges of high

energy

.Flash over, tracking or arcing of high local energy or with power

Through Short circuits between low voltage and ground,

connectors, windings, bushings and tank,. Copper bus and tank, Windings

and core, In oil duct, turret. Closed loops between two adjacent conductors

around the main magnetic flux, insulated bolts of core, Metal rings

holding core legs

T1 Thermal Fault < 300

Deg. C

Overloading of the transformer in emergency situations.

Blocked items restricting oil flow in windings.

Stray flux in dampening beams of yokes.

T2 Thermal Fault

between 300 & 700Deg.C.

Defective contacts between bolted connections, gliding contact, contacts

within selector switch connection from cable and draw-rod of bushingsCirculating currents between yoke clamps and bolts. Clamps and

laminations i. e. ground wiring, defectives welds or clamps in magnetic

shields.

Abraded insulation between adjacent parallel conductors in windings.

T3 Thermal fault >.700

Deg. C.

Large circulating currents in tank and core

Minor current in tank walls created by high uncompensated magnetic field.

Shorting links in core. Steel, laminations.

9.3.4.4 CO2/CO Ratio

The concerned extracts from IEC, IS and ASTM are reproduced below. It can be seen thatratio of CO2/CO less than 3 indicates fault in cellulose.

Extract From IEC 60599:1999

4.2 Decomposition of cellulosic insulation

The polymeric chains of solid cellulosic insulation (paper, pressboard, wood blocks) contain a

large number of unhydroglucose rings and weak C-O molecular bonds and glycosidic bonds which

are thermally less stable than the hydrocarbon bonds in oil, and which decompose at lower


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temperatures. Significant rates of polymer chain scission occur at temperature higher than 1050 C with

complete decomposition and carbonization above 3000 C. mostly carbon monoxide and carbon

dioxide as well as water are formed in much larger quantities than by oxidation of oil at the same

temperature, together with minor amounts of hydrocarbon gases and furanic compounds. The latter

can be analyzed according to IEC 61198 and used to complement DGA interpretation and conformwhether or not cellulosic insulation is involved in a fault. CO and CO2 formation increases not only

with temperature but also with Oxygen content of oil and the moisture content of paper.

5.4 CO2 / CO Ratio:

The formation of CO2 and CO from oil- impregnated paper insulation increases rapidly with

temperature. Incremental (corrected) CO2 / CO ratios less than 3 are generally considered as anindication of probable paper involvement in a fault, with some degree of carbonization.

In order to get reliable CO2 / CO ratios in the equipment, CO2 and CO values should be

corrected (incremented) first for possible CO2 absorption from atmospheric air, and for the CO2 and

CO background values resulting from the ageing of cellulosic insulation, overheating of wooden

blocks and the long term oxidation of oil (which will be strongly influenced by the availability of

oxygen caused by specific equipment construction details and its way of operation).

Air-breathing equipment for example, saturated with approximately 10% of dissolved air, maycontain up to 300 l/l of CO2 coming from the air. In sealed equipment, air is normally excluded but

may enter through leaks, and CO2 concentration will be in proportion of air present.

When excessive paper degradation is suspected (CO2 / CO < 3) it is advisable to ask for a

furanic compounds analysis or a measurement of the degree of polymerization of paper samples,

when this is possible.

Extract From IS 10593:1992

3.2 Examining CO2 and CO Concentrations Found Dissolved In Oil

For cellulosic degradation by heat alone at current operating temperatures, statistical analysisfor normally operating conservator transformers gives a CO2 / CO ratio of a about 7 although with a

widespread of values ( standard deviation of 4). High temperature degradation of cellulose, no matter

how caused (for example hot spot or arc) tends to increase the relative amount of CO, however the

rates of CO2 and CO production depend greatly on oxygen availability , moisture content and the

temperature of degradation. Consequently, any case in which CO2 / CO is below 3 or above 11 should

be regarded as perhaps indicating a fault involving cellulose provided results obtained according to

2.3 are also indicating excessive oil degradation. If possible, the ratio should be compared with

previous values for similarly loaded transformers of the same design.

In sealed transformers, where the concentrations of CO2 and CO are low during the earlier life

of the transformer, the CO2 / CO ratio is generally below 7 but the ratio is likely to increase as normal

ageing proceeds.

Key Gas Method as per ASTM

Overheated Cellulose:

Large quantities of carbon dioxide and carbon monoxide are evolved from overheated cellulose.Hydrocarbon gases such as methane and ethylene will be formed if the fault involves an oil-

impregnated structure.


14/14

9.3.4.5 Gas Concentration Levels In Service

The probability or risk of having an incidence or a failure in service depends upon gas

concentration levels. Below certain concentration levels, called as typical values or normal values, theprobability of failure is low. The transformer is considered healthy though the possibility of failure

cannot be ruled out, even at these low levels, but it is probable.

The probability of having a failure may increase significantly at values much above typical

concentration level the situation is said to be critical. Even though the failure may never occur at

these high concentration levels, the risk of having one is high. Such failures can be divided in two

categories.

1) Failures that develop within a short time

2) Failures developing over an extended time span. Only such failures can be anticipated by DGA.

A Table showing ranges of 90% typical concentration values observed in power transformers

is given at the end of this manual.

9.3.5 ROLE OF DGAIN REPAIR& POST PERPAIR MONITORING OF TRANSFORMER AT SITE :

9.3.5.1 IMPORTANCE OF BASE LINE AND DATA:

Whenever there is any failure on any power transformer, the first question arises about the

test data prior to the instant of failure of transformer. As such base line data and trend of gassing

results acquire prime importance. The base line data and trend of test results help to analyses the

reason for failure and steps to be taken for repairs. Therefore, DGA of healthy transformer isnecessary.

9.3.5.2 IMPORTANCE OF PRE-PREPAIR RESULTS

Whenever a power transformer fails and is opened for repairs, the DGA results prior to

failure and after the incident of fault may indicate the reason for fault and also the zone of fault

so that during inspection and testing of the faculty transformer , special attention may be paid to the

area indicated by DGA results. In case some faults are noticed during routine DGA tests prior to

failure, the severity of the fault can be assessed by DGA results, like faults in tap changers,

Connection leads etc., and the corrective action like mode of repairs can be decided.

9.3.5.3 POST REPAIRS MONITORING

Monitoring of transformer repaired at site by undertaking various routine tests in addition toDGA requires more attention than the transformer repaired in manufactures work or new

transformer. It is always possible that the some minor faults remain unattended during repairs at side

due to lack of facilities, and / or short repair period. In such case frequent sampling should be under

taken and should be analyzed for assessment of severity of fault.

cond. mon.of xmer

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