Transformer Oil 236g6u

TRANSFORMER OIL The oil in transformer construction serves double purpose of cooling and insulating. For use in transformer tanks, oil has to fulfill certain specifications and must be carefully selected. All oils are good insulators, but animal oils are either too viscous or tend to form fatty acids, which attack fibrous materials (e.g. cotton) and so are unsuitable for transformers. Vegetable oils are apt to be inconsistent in quality and, like animal oils, which alone are suitable for electrical purposes, some have a bituminous and others a paraffin base. The crude oil, as tapped is distilled, producing a range of volatile spirits and oils ranging from the very light to the heavy, and ending with semi-solids like petroleum jelly, paraffin wax, or bitumen. The chemical composition of oil consists of four major generic class of organic compounds, namely, paraffins, napthelenes, aromatics and olefines. All these are hydrocarbons and hence insulating oil is called a pure hydrocarbon mineral oil. It is desirable to have more of saturated paraffins, less of aromatic and/or napthalenes and none of olefines. 11.1 Characteristics of Oil : Refer Table-11.1 for the characteristics of oil as per IS:335-1983 are listed below : Table-11.1 : S.No

Characteristics o

Limit / Requirement 0.89 g/cm3

1

Density at 27 C, max

2

Kinematic viscosity at 27o C, max o

27 cSt

3

Interfacial tension at 27 C, min.

0.04 N/m

4

Flash point, Pensky-Marten (closed), 140oC min.

5

Pour point, max.

-9oC

6

Neutralization value (total acidity), maximum.

0.03 mg KOH/g

7

Corrosive sulphur

Non-corrosive

Electric strength (breakdown voltage) minimum. 8

(a) As received (b) After filtration

9

30 kv (rms) 50 kv (rms)

Dielectric dissipation factor (Tan ) at 0.005 90oC, max. Specific resistance (resistivity), min.

10

(a) At 90oC (b) At 27oC

30 x 1012 cm 500 x 1012 cm

Oxidation stability : (a)Neutralization value after oxidation , max.

11

(b) Total sludge after oxidation, max.

0.40 mg KOH/g 0.10% by weight

12

Presence of oxidation inhibitor

The oil shall not contain antioxidant additives

13

Water content (as received), max.

50 ppm by weight

11.1.1 Physical Properties : •

Density - This has significance when transformer is operated in a very low temperature zone. The maximum value of density fixed at 270C ensures that water in the form of ice present in oil remains at the bottom and does not tend to float on the oil up to a temperature of about -100C.

•

Viscosity - determines the rate of cooling, and varies with temperature. A high viscosity is an obvious disadvantage because of sluggish flow through small apertures which it entails.

•

Interfacial Tension (IFT) - This is a measure of the molecular attractive force between oil and water molecules at their interface.

•

Moisture Content - The amount of free and dissolved water present in the oil is its moisture content and is expressed in ppm. Presence of moisture is harmful since it adversely affects the electrical characteristics of oil and accelerates deterioration of insulating paper.

•

Flash Point - The temperature at which the vapour above an oil surface ignites spontaneously is termed as flash point. A flash point not more than 1600C is usually considered for safety reasons.

•

Fire Point - The temperature at which an oil will ignite and continue burning is about 25% above the flash point, or about 2000C.

•

Pour Point - It is the temperature at which oil will flow under the prescribed conditions. If the oil becomes too viscous or solidifies, it will hinder the formation of convention currents and thus cooling of equipment will be severely affected.

11.1.2 Electrical Properties : •

Electric Strength (BDV) - It is the voltage at which breakdown occurs between two electrodes when oil is subjected to an electric field under prescribed conditions. Electric strength is the basic parameter for insulation system design of a transformer.

•

Resistivity (Specific resistance) - This is the most sensitive property of oil requiring utmost care for its proper determination. Resistivity in -cm is numerically equivalent to the resistance between opposite faces of a Cm3 of the liquid. Insulation

resistance of windings of transformer is also dependent upon the resistivity of oil. A low value indicates the presence of moisture and conductive contaminants. •

Dielectric Dissipation Factor (DDF) - It is numerically equal to Sine of the loss angle (approximately equal to Tangent of loss angle for dielectrics) and is a good tool to indicate the quality of an insulation. A high value of DDF is an indication of the presence of contaminants or deterioration products such as water, oxidation products, metal soaps, soluble varnishes and resins.

11.1.3 Chemical Properties : •

Purity - The oil must not contain impurities such as sulphur and its compounds, as sulphur causes corrosion of metal parts and accelerates the formation of sludge.

•

Acidity - Among the products of oxidation of transformer oil are CO2, volatile watersoluble organic acids, and water. These in combination can attack and corrode iron and other metals. The provision of breathers not only prevent the ingress of damp air, but helps on out-breathing to absorb any moisture produced by the oxidation of oil.

•

Oxidation Stability - It is the measure of neutralization value and sludge after oil is aged by simulating the actual service conditions of a transformer. It is important to find out for new oil but not for oil in service and shows the presence of natural inhibitors which impart anti-oxidation characteristics to oil.

11.2 Sampling : The condition of oil should be checked before use. Samples of oil from the transformer should be taken from the bottom of the tank as both water and water saturated oil are heavier than clean and dry oil and sink to the bottom of the container. The sample bottles should be rinsed with oil. 11.2.1 Receptacles for samples : Receptacles for samples should preferably be bottles of clear glass with ground glass stoppers and of 1 litre capacity. Sample bottles should not be filled to the top. They shall be clean and dry. If the electrical test cannot be carried out immediately, these bottles shall be hermetically sealed to prevent contamination of oil. Touching the inside of a receptacle with a damp hand or wiping round with an apparently clean dry cloth may seriously reduce the breakdown strength of a sample of good oil. 11.2.2 Samples from tank : When taking samples from the tank, remove all dirt from the sampling valve of plug. To ensure that the valve is clean, allow some oil to flow into a separate receptacle before collecting sample for testing for its dielectric strength as per the latest edition of IS:6792. It is expected that every sample es the test, if the normal transit and storage precautions are taken.

11.3 Testing of Transformer Oil :

There are nine number tests recommended in the code of practice for maintenance and supervision of mineral insulating oil in equipment (IS:1866 - 1983). These tests can be further subdivided into three groups as shown in the following flow chart for the purpose of action if test results are outside permissible limits as mentioned in Table-11.3 TESTS

Break Down Voltage Test & Water Content.

Tan , Resistivity, Interfacial Tension & Acidity Tests.

Dissolved Gas Analysis

Interpretation

Interpretation

Oil needs Filtration

Oil needs Reclamation or Replacement

Monitoring is necessary to find out the gravity of incipient fault.

Result of Filtration

Result of Reclamation or Replacement.

Transformer needs attention during usual outages.

Removal of Acids, Sludge, Oxidation and oil decay products, oil aging products, etc.

Transformer needs immediate attention.

Group-II

Group-III

Removal of Free Water, Dirt, Rust, Metallic cuttings, Filter dust, etc. Group-I

Interpretation

Note : Tests like Moisture, Flash point and Sedimentation are also required to further probe into deteriorated condition of the oil. Table-11.3 (Groups I & II) : S.No

1

Test Electric strength (Break Down Voltage) (As per IS:6792)

Equipment Voltage

Permissible limits

Action if outside permissible limit

145 KV and above 60 KV rms 72.5 KV - 145 KV 50 KV rms Below 72.5 KV

40 KV rms

Recondition / Filter

Water Content. 2

72.5 KV - 145 KV (As per IS:2362 - 1973) Below 72.5 KV

3

Sediment and / or perceptible sludge.

4

Specific resistance (Resistivity at 900C).

5

Dielectric dissipation factor (Tan ) at 900C.

6

145 KV and above

Neutralization value (Total Acidity)

All Voltages

All Voltages

15 ppm 20 ppm

Recondition / Filter

25 ppm No Sediment and / or precipitable Recondition / Filter sludge should be detectable. 0.1x1012 Cm (Min)

Recondition / Filter if the Tan value permits, reclaim or replace if not.

145 KV and above 0.2 (Max.) Reclaim or Replace. Below 145 KV

1.0 (Max.)

All Voltages

0.5 mg KOH/gm oil (Max.)

Reclaim or Replace.

Reclaim or Replace.

7

Flash Point

All Voltages

Decrease in the flash point 150C (Max.) of the initial value, minimum value (1250C).

8

Interfacial tension at 270C

All Voltages

0.018 N/m (Min.) Reclaim or Replace.

Note : Dissolved Gas Analysis (DGA) test is conducted to ascertain the healthiness of Transformer and not of the Oil. 11.4 Significance of Various Routine Tests : The significance of various routine tests such as Break Down Voltage Test, Test to find the Water Content, Resistivity, Di-electric Dissipation Factor (Tan ), Acidity, Interfacial Tension are described below. 11.4.1 Break Down Voltage (BDV) Test : Break Down Voltage is the voltage at which the oil breaks down when subjected to an AC electrical field with a continuously increasing voltage contained in a specific apparatus. The voltage is expressed in KV. Because of traditions, availability of the equipment and the simplicity of the method, the BDV of an oil still ranks as the most common field and laboratory oil screen test. However in reality the significance of the test is that it will only detect free water, dirt and conductive particles not acids or sludges. Thus this test does not give true indication of the deteriorated condition of the oil. An oil which is significantly oxidised may show a high dielectric strength in the absence of moisture. The electric strength is also affected by the presence of foreign particles, such as cellulose fibres, which absorb moisture and orient themselves across point of stress and cause arcing. The

presence of oil deterioration particles, water and foreign contaminants results in a general overall reduction in the efficiency of the apparatus. Normal methods of oil filtration only maintain the electric strength but do not improve the deteriorated oil. It is therefore inadvisable to solely rely on the electrical strength of the oil by periodic tests without ing its other characteristics. BDV can reveal conductive contaminants, such as the rust or other metallic cuttings, dirt, cellulosic fibres, filter dust or free water but it will not pinpoint the presence of dissolved water below 80% saturation, acids or sludges. Keeping in mind higher operating temperatures experience has shown that erroneous conclusions can be drawn if the oil is tested at a temperature in excess of 400C because of the phenomena of water solubility. Sample of BDV should be protected from with light, air and moisture. The sample should be drawn quickly kept in a sealed container and tested within a matter of few hours. 11.4.2 Water Content Test : Water content is expressed as parts per million (ppm) w/w in oil. Water may originate from the atmosphere or be produced by the deterioration of the insulating material. Its presence in oil is harmful as it lowers the electric strength and resistivity of the oil and accelerates the deterioration of the solid insulating materials, particularly paper. A mineral oil of low water content is necessary to achieve adequate electrical strength to maximize the insulation system life and to minimize metal corrosion. 11.4.3 Resistivity Test : It is the ratio of the DC potential gradient in volts per centimeter paralleling the current flow within the specimens to the current density in amperes per square centimeter at a given instant of time and under prescribed conditions. This is numerically equal to the resistance between opposite faces of a centimeter cube of the liquid. It is expressed in Cm. Resistivity of transformer oils monitors the amount of conductive contaminants, such as metal, salts, water, aldehydes, ketones and alcohols. Water content and acidity influence the values of the specific resistance. An indication of the presence and effect of water content can be obtained from a resistivity comparison at 270C and 900C. For any given oil there is generally a relationship between Tan and resistivity. If the Tan increases, there is a reduction in resistivity.

11.4.4 Dielectric Dissipation Factor (Tan ) Test : Dielectric Dissipation Factor is a Tangent of the angle by which the phase difference between applied voltage and resulting current deviates from /2 radian when the dielectric of the capacitor consists exclusively of the transformer oil. Measurements of Tan , Resistivity and to a lesser extent the interfacial tension of the oil enable contamination due to polar substances to be detected and periodically assessed. [Polar substances are oil soluble compounds resulting from the oxidation of the oil itself, or

from the solution in the oil of external contaminants or materials used in the construction of the equipment]. Power factor has been a traditional field test. However this test measures the leakage current through the oil, which is a measure of the contamination or deterioration. It does tell the presence of polar materials but other tests must be made to determine what polar compounds are present. When water is held in solution no appreciable effect on the oil's power nor dielectric strength may take place. However since oil oxidation further increases oil's ability to dissolve moisture, some type of sludges have very little effect on the overall power factor. This test is very sensitive to the presence in oil of the soluble contaminants and aging products. Changes in this characteristic can be monitored regularly. 11.4.5 Acidity Test : It is the measure of the free organic and inorganic acids present together in the oil. It is expressed in of the number of milligrams of KOH required to neutralize the total free acids in one gram of the oil. This is most common method that measures the acidity in transformers. The organic acids are detrimental to the insulation system and can induce rusting of iron when moisture is also present. An increase in neutralization number is an index to the rate of deterioration of the oil. Sludge will be the inevitable product of an acid situation that is neglected. A low acidity in oil is required to minimize electrical conduction and metal corrosion and to maximize the life of the insulation system. How high acidity value can lead to sludge formation is demonstrated in the following Table-11.3.5 (Historical Database indicating relationship between Acidity and Sludge formation in Oil filled Transformers - 11 Years test on 500 Transformers). Table-11.4.5 : Acidity S.No

mg of KOH/gm of Oil

Percent of 500

Units Sludged

1

0.00 to 0.10

00

00

2

0.11 to 0.20

38

190

3

0.21 to 0.60

72

360

4

0.61 and above

100

500

11.4.6 Interfacial Tension Test : 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. It is expressed in N/m or Dynes/Cm. The characteristic changes fairly rapidly during the first stages of aging. Afterwards the rate of change decreases as the value themselves become lower.

The old workhorse of transformer oil quality testing is the less the tension. Interfacial tension test results are thus related to the degree of the oils oxidation. The very first sign of the sludge in solution may be in the range of 0.027 to 0.030 N/m while a badly sludging deteriorated oil has an IFT of 0.018 N/m or less. IFT test measures the tension at the interface between two immissible liquids oil and water and is expressed in N/m. This test is extremely sensitive to the presence of oil decay products and soluble polar contaminants from solid insulating materials. Good clean oil will normally lay on top of water and will yield an IFT of 0.040 to 0.050 N/m. Oil oxidation contaminants will lower the IFT even further. These contaminants are hydrophilic which means they have an affinity for water molecules as well as for oil molecules. At the interface the hydrophilic materials extend across to the water so that a vertical linkage is established and thus the lateral linkage [Which makes up the surface tension] is weakened. The interface is now less distinct and the tension at the interface is reduced. The greater the concentration of contaminants less the tension. IFT values and sludge formation can be understood from the following Table - 11.4.6 (Historical Database indicating relationship between IFT and Sludge formation in Oil filled Transformers - 11 Years test on 500 Transformers). Table-11.4.6 : Interfacial Tension

S.No

Percent of 500

Units Sludged

100

500

N/m 1

Below 0.014

2

0.014 to 0.016

85

425

3

0.016 to 0.018

69

345

4

0.018 to 0.020

35

175

5

0.020 to 0.022

33

165

6

0.022 to 0.024

30

150

7

Above 0.024

00

000

11.5 Relationship between Various Tests & Factors affecting Test Results : The factors which affects the various test results are given in Table - 11.5 for a better understanding of the results from interpretation point of view.

Table-11.5 :

S.No 1

Test

Factors Responsible for Results

Factors not Responsible for Results

Break Down Voltage Free water, dirt, Dissolved water below conductive particles 80% saturation, acids and contaminants such and sludges. as rust, metallic

cuttings, filter dust.

2

Sludges, oxidation products, oil decay Dielectric Dissipation products, Factor (Tan ) contaminants, free water.

3

Resistivity

Contaminants such as metal salts, water in all forms, acids.

Interfacial Tension

Hydrophilic contaminants like soluble polar impurities, oil decay products dissolved sludge, oxidation by products.

4

Dissolved water.

-

-

5

Acidity

Organic and inorganic acids, KOH consuming impurities.

-

6

Water

Free water, dissolved water, combined water.

-

11.6 Dissolved Gas Analysis : Gases may be formed in all oil-filled electrical equipment due to natural aging, but also to a much greater extent as a result of faults; i.e. heat flux generated in the core winding. The principal mechanisms of gases formation includes Oxidation, Vapourisation, Insulation decomposition, Oil breakdown, and Electrolytic action. Operation with a fault may seriously damage the equipment and it is valuable to be able to detect the fault at an early stage of development. Usually, under normal conditions, the gas dissolved in the transformer oil has the following composition : Nitrogen - 70 to 79%, Oxygen - 20 to 30%, and Methane - 0.1 to 0.2%; Hydrogen & Acetylene are absent. A sharp change in the composition (for example, 50 to 70% Hydrogen, 3 to 10% Methane, 10 to 25% Acetylene, 4 to 8% Oxygen) testifies to a grave internal fault accompanied by arcing (insulation puncture, shorted turns, flashover in the system of the tap-changer, etc.). In case of minor faults not accompanied by violent oil decomposition and gas evolution, the gas composition may be : 2 to 5% Hydrogen, 0.5 to 1% Methane, 0.5 to 2% Acetylene, 85 to 92% Nitrogen and 5 to 8% Oxygen. Such gas composition bears witness to a fault, such as shorted parallel conductors in the windings, poor s in the tap connections or soldered ts, or closed paths in the magnetic system of the core, which, if not remedied, may eventually lead to serious trouble. In case of a fault, its type and its severity may often be inferred from the composition of the gases and the rate at which they are formed. In the case of an incipient fault, the gases formed remain partly dissolved in the liquid insulation; free gases will divide between the gaseous and liquid phases by diffusion. Diffusion and achievement of saturation both take time, during which serious damage to the equipment can occur undetected.

Periodic analysis of oil samples for the amount and composition of dissolved gases forms a means of detecting faults. (Normally once in a year for transformers 10MVA & above rating) . Depending upon the energy released in the core upon the occurrence of faults, the gases are also different. Normally the faults are of four types as per the energy releases are concerned. a. Arcing - Arc breakdown of insulating oil is charcterised by the production of hydrogen and acetylene as the predominant fault gases. They are accompanied by some ethylene and lesser amounts of other thermal products, depending to some degree, on the amount of power follow through which accompanies the arc. The presence of Acetylene is the key indicator of an arc. b. Partial Discharges (Corona) - Low-energy electrical discharges produce mainly hydrogen and methane, Hydrogen is the key indicator. Other fault gases like ethane and ethylene may also be present in small quantities. c. Overheated Oil - Decomposition products include ethylene and methane, with smaller quantities of hydrogen and ethane. A large quantity of Ethylene is a key indicator and, if the fault is severe, traces of acetylene may be present. d. Overheated Cellulose - Large quantities of carbon monoxide and carbon dioxide are evolved from overheated cellulose. Other gases will also be present if the fault involves an oil-impregnated structure. As cellulose will degrade under normal transformer operating temperatures, CO and CO2 will be found in significant quantities in healthy transformers. A significant increase in the CO/CO2 ratio is usually a key indicator of overheated cellulose. 11.6.1 Threshold fault gas levels : Threshold fault gas levels of various gases for transformers which have been in service for a few years, as suggested by Dornenberg and Strittmatter and the U.S. Bureau of Reclamation are mentioned below :

S.No

Fault Gas Contents

Dornenberg U.S Bureau & of Strittmatter Reclamation

1

Hydrogen - H2

200 ppm

500 ppm

2

Methane - CH4

50 ppm

125 ppm

3

Ethane - C2H6

35 ppm

75 ppm

4

Ethylene - C2H4

80 ppm

175 ppm

5

Acetylene - C2H2

5 ppm

15 ppm

6

Carbon monoxideCO

500 ppm

750 ppm

7

Carbon dioxide CO2

6,000 ppm

11,000 ppm

The age and history of the transformer must be considered in evaluating dissolved fault gas data. The important factor is the rate of change of fault gas levels.

11.6.2 Analysis of Gas Dissolved in Oil : A convenient basis for fault diagnosis is the calculation of ratios of the concentrations of the gases present. The ratios used in the interpretation methods summerised in Table-11.6.2 are : C2H2 ,

CH4 ,

C2H4

C2H4

H2

C2H6

This shows various limits of the ratios corresponding to normal aging and to various types of fault from which a diagnosis of the nature of a fault may be obtained. The table also shows a code for each range of the ratios of the characteristic gases; numerals have been allocated so that 000 represents normal aging conditions. Table-11.6.2 : Code of Range of Ratios Ratios of Characteristic Gases

Case

C2H2

CH4

C2H4

C2H4

H2

C2H6

< 0.1

0

1

0

0.1 to 1

1

0

0

1 to 3

1

2

1

>3

2

2

2

Characteristic Fault

Typical Example

No 0 1

2

3

No fault

0

0

0

Normal ageing

Partial Discharges of low energy density

0

1

0

Discharges in gas-filled cavities resulting from incomplete impregnation, or supersaturation or cavitation or high humidity.

Partial discharges of high energy density.

1

1

0

As above, but leading to tracking or perforation of solid insulation.

Discharges of low energy *

1-2

0

Continuous sparking in oil between bad connections of different 1-2 potential or to floating potential. Breakdown of oil between solid materials.

4

Discharges of high energy

1

0

2

Discharges with power follow through. Arcing-breakdown of oil between windings or coils or between coils to earth. Selector breaking current.

5

Thermal fault of low temperature < 150oC **

0

0

1

General insulated conductor overheating.

0

2

0

6

Thermal fault of low temperature 150oC to 300oC

Local over-heating of the core due to concentrations of flux.

Increasing hot-spot temperatures varying from small hot-spots in core, shorting links in core,

***

7

Thermal fault of medium temperature 300oC to 700oC

0

2

1

over heating of copper due to eddy currents, bad s/ts (pyrolitic

8

Thermal fault of high temperature > 700oC ****

0

2

2

carbon formation) up to core & tank circulating currents.

* **

***

****

For the purpose of this table there will be a tendency for the ratio C2H2/C2H4 to rise from a value between 0.1 and 3 to above 3 and for the ratio C2H4/C2H6 from a value between 0.1 and 3 to above 3 as the spark develops in intensity. In this case the gases come mainly from the decomposition of the solid insulation, this explains the value of the ratio C2H4/C2H6. This fault condition is normally indicated by increasing gas concentrations. Ratio CH4/H2 is normally about 1, the actual value above or below 1 is dependent on many factors such as design of oil, preservation system, actual level of temperature and oil quality. An increasing value of the amount of C2H2 may indicate that the hot point temperature is higher than 1000oC.