INSULATING OIL,
FLUID AND GASSES
E E T E 2 / 4 6 4 P OWE R SYST E M E LE M E N T
T EST IN G AN D M AIN T EN AN CE
Introduction
Insulating oils, fluids, and gases are
used as dielectrics in the electrical
equipment and apparatus. The
liquids used in the transformers are
mineral oil and synthetic fluids,
such as askarel, silicone, RTemp,
Wecosal, Alpha 1, and GE R113.
Power Transformer
transformers have their windings immersed
Distribution Transformer
Mineral oil is also
used as a dielectric
in circuit breakers,
reclosers,
interrupters, and the
like.
Sectionaliser
Load break
Oil Circuit Breaker
The most common insulating gas used in circuit breakers and completely
enclosed substations is sulfur hexafluoride (SF6).
High Voltage SF6 Circuit Breaker
Medium Voltage SF6 Circuit Breaker
• The ability of insulating oils, fluids, and gases to serve as effective dielectric and coolant is
adversely affected by their deterioration.
• The deterioration of insulating oil, fluids, and gases is due to contamination, overheating,
electrical stress, and oxidation.
• Moisture is the most common contaminant which adversely affects the insulating
properties of these liquids and gases.
• High temperatures from increased load and/or environmental conditions accelerate the
deterioration process.
• To assure continuity of service, safety, and maintenance, a condition monitoring program,
consisting of electrical and chemical testing, is necessary for these dielectrics.
Insulating Oil
• To properly maintain the transformer oil free of contaminants, regular
inspection of the transformer and purification of the oil is needed.
• Hydrocarbon (mineral oil #10) oil is used as an insulating fluid in
transformers and circuit breakers because of its high dielectric strength
and chemical stability.
Deterioration of Insulating Oil
I. Effect of Oxygen on Oil
Moisture contamination is the most common cause of deterioration in the
insulating quality of oil. This contamination can be readily corrected by
purification.
Atmospheric oxygen and oxygen contained in water are the sources
available for the oxidation of insulating oils.
The rate of oxidation also depends on the temperature of the oil; the
higher the temperature is, the faster the oxidative breakdown. An
increase in temperature of 10°C (50°F) generally doubles the rate of
oxidation.
II. Moisture in Oil
Water can be present in oil in a dissolved form, as tiny droplets mixed
with the oil (emulsion), or in a free state at the bottom of the container
holding the oil.
Demulsification occurs when the tiny droplets unite to form larger drops,
which sink to the bottom and form a pool of free water. Emulsified water
typically requires vacuum dehydration, as the emulsification cannot
typically be broken by filtration or by excellerated gravity (centrifuge).
A very small amount of emulsified water has a marked influence in
reducing dielectric strength of oil. Free moisture in oil usually shows up
above 50 to 60ppm depending upon temperature.
Accepted levels of water in oil are shown in Table 4.1.
Electrical Power Equipment Testing and Maintenance 2nd Ed.
By: Paul Gill
The amount of moisture that can be dissolved in oil increases rapidly as the oil
temperature increases, as shown in Figure 4.1.
Electrical Power Equipment Testing and Maintenance 2nd Ed.
By: Paul Gill
Therefore, an insulating oil
purified at too high a
temperature may lose a
large percentage of its
dielectric
strength
on
cooling,
because
the
dissolved moisture is then
changed to an emulsion,
unless
vacuum
dehydration is used as the
purification process.
Vacuum Dehydration Oil Purification System
III. Absorption of Moisture by Insulating Materials
Solid insulation (paper insulation) in transformers is very porous and
thirstily absorbs water. Some of the water that is dissolved in the oil is
absorbed from the oil by the cellouse (paper) winding insulation. As
more water is dissolved in the oil, more water is absorbed by the
insulation of the transformer windings. Once absorbed, it is difficult to
remove.
The most effective method for drying out the insulation in
transformers is with heat and vacuum. Sometimes a vacuum cannot be
applied in the field; then the transformer insulation must be dried by
circulation of hot, dry oil. This oil should then be cooled and dried.
Since the dielectric strength of insulation is reduced by absorption of
moisture, it is important that the insulation not be allowed to absorb it
in the first place.
IV. Absorption of Nitrogen by Oil
Special precaution should be taken in operating transformers
with nitrogen over the oil to avoid bubbling of the oil due to
release of dissolved nitrogen when the pressure drops.
Experience has shown that the automatic gas- pressure regulating
system should be adjusted to limit the nitrogen pressure range
from 1/2 to 3 psi (lb/sq.in.) gauge to avoid formation of these
bubbles and subsequent troubles due to corona deterioration.
Function of Insulating Oil in an electrical equipment
❖ It serves and provide insulation
❖ Serves as a cooling agent
❖ Helps to extinguish arc caused by switching and fault
event
❖ Use as sample for diagnosis of the health of the
equipment
Insulating Oil Testing
➢ Transformer oil reacts with oxygen to form organic acids, esters, and phenolic
compounds which ultimately leads to sludging of the transformer.
➢ The rate of this phenomena
increases with an increased
exposure
to
air
and
temperature. Also it should be
noted that oxygen is more
soluble in oil than found in air.
Not only will the sludge
adversely affect the dielectric
properties of the oil, but it will
also interfere with dissipation
of heat within the transformer.
ASTM International, formerly known as American
Society for Testing and Materials, is an
international standards organization that
develops and publishes voluntary consensus
technical standards for a wide range of materials,
products, systems, and services.
ASTM has over 30,000 volunteer members from more than 140 countries
around the world who are producers, users, consumers and general
interest parties. These members write ASTM standards through their
service on one or more of our 140-plus technical committees.
The routine tests and sampling
procedures that are conducted on
insulating oil are shown in Table 4.2
Dielectric
Breakdown
Voltage Test
(Cup Tests)
➢ This is an AC overvoltage test applied
to the insulating liquids to detect their
breakdown strength.
➢ The dielectric test simply consists of
placing a liquid sample from the
transformer or (circuit breaker) in a
cup containing two electrodes of
specified gap.
➢ The test is repeated for a least five
different samples to determine the
average dielectric strength.
Dielectric Breakdown Voltage Test
Acidity Test
❖ The acidity test measures the content of acids formed by
oxidation. The acids are directly responsible for sludge
formation. These acids precipitate out, as their
concentration increases, and become sludge. They also react
with metals to form another form of sludge in the
transformer.
❖The ASTM D974 and D664 are laboratory tests whereas
D1534 is a field test which determines the approximate total
acid value of the oil.
Acid Number
Interfacial Tension (IFT)
➢ The IFT test is employed as an indication of the sludging characteristics of
power transformer insulating liquid. It is a test of IFT of water against
liquid, which is different from surface tension in that the surface of the
water is in contact with liquid instead of air.
➢ The attraction between the water
molecules at the interface is influenced
by the presence of polar molecules in the
liquid in such a way that the presence of
more polar compounds causes lower IFT.
The polar compounds are sludge
particles or their predecessors.
Color Test
➢ This test consists of transmitting light through oil samples and comparing the color
observed with a standard color chart. The color chart ranges from 0.5 to 8, with the
color number 1 used for new oil.
Visual Examination
Power Factor Test
• The power factor of an insulating liquid is the cosine of the phase angle
between applied sinusoidal voltage and resulting current. The power factor
indicates the dielectric loss of the liquid and thus its dielectric heating. The
power factor test is widely used as an acceptance and preventive
maintenance test for insulating liquid.
• Power factor tests on oil and transformer liquids are commonly made with
ASTM D-924 test cell.
➢ Oil having a power factor of less than 0.5% at 20°C is usually considered
satisfactory for service.
➢ Oil having a power factor between 0.5% and 2% at 20°C should be
considered as being in doubtful condition and at least some type of
investigation should be made.
➢ Oil having a power factor of over 2% at 20°C should be investigated and
should be reconditioned or replaced.
The question of what decision to make regarding disposition of the oil
depends on what is causing the high power factor. Dielectric strength tests
should be made to determine the presence of moisture.
Specific Gravity
➢ Specific gravity of oil is defined as the ratio of the mass of a given volume of oil
to the mass of an equal volume of oil of water at a specified temperature. This
test is conducted by floating a hydrometer in oil and taking the reading at the
meniscus. For oil free of contaminants, such as water, askarel, or silicone, the
reading should be less than 0.84.
Water Content Test (Karl Fisher Method)
➢ This test is based on the reduction of iodine according to the traditional Karl
Fisher reaction. Three methods are used to conduct this test. Methods A and C
utilize iodine present in a titration solution while Method B electrically
generates the iodine in the equipment. Moisture content of 69kV and higher
voltage transformers should be measured regularly and lower voltage
transformers on indication of flow dielectric strength of the oil.
Electrical Power Equipment Testing and Maintenance 2nd Ed.
By: Paul Gill
Insulating Fluids
Mineral Oil
Silicon Oil
Synthetic Ester Oil
Natural Ester Oil
Properties
Applications
Combustible Gas Analysis of Insulating Oil
An oil-filled transformer insulation system consists of insulating oil and
cellulose (paper) materials. Under normal use, transformer insulation
deteriorates and generates certain combustible and noncombustible gases. This
effect becomes more pronounced when the transformer insulation is exposed to
higher temperatures.
When cellulose insulation (i.e., winding insulation) is overheated to
temperatures as low as 140°C, carbon monoxide (CO), carbon dioxide (CO2),
and some hydrogen (H) or methane (CH4) are liberated.
The rate at which these gases are liberated depends exponentially
on the temperature and directly on the volume of the insulation at
that temperature. When insulating oil is overheated to
temperatures up to 500°C, ethylene (C2H4), ethane (C2H6), and
methane (CH4) are liberated. When oil is heated to extreme
temperatures, such as an electrical arc, hydrogen (H) and
acetylene (C2H4) are liberated in addition to the above mentioned
gases.
The main cause of gas formation in a transformer is due to the
heating of paper and oil insulation and electrical problems inside
the transformer tank.
There are two methods for detecting these gases:
(1) total combustible gas analysis (TCGA), and
(2) dissolved gas analysis (DGA)
TCGA
The method is applicable to power transformers with a nitrogen blanket or
conservator system.
The equipment used for measuring TCG is basically a Wheatstone bridge
circuit. A combination of air and combustible gas sample is passed over a
resistor where catalytic burning takes place on the resistor, which causes a
proportional change in resistance. Based on the change in resistance of the
resistor, the TCG is measured in percent.
Assessing the Transformer Condition Using the TCGA in the Gas Space
A new transformer should be tested within a week after
energization. If it is not gassing and does not start gassing,
subsequent tests should be made progressively increasing
intervals until the 12-month normal interval is reached. When
sudden increases in the combustible gas quantities or generating
rates in the gas space of an operating transfer occur and internal
fault is suspected, IEEE Standard C57.104-1991 recommends the
procedure to be used as shown in Table 4.5.
Electrical Power Equipment Testing and Maintenance 2nd Ed.
By: Paul Gill
DGA
• The oil sample is subjected to a vacuum to remove the combustible gases.
These gases are then passed through a gas chromatograph and each gas is
then extracted and analyzed for type and quantity. The quantity of each gas is
given in part per million (ppm) or percent of the total gas present. The analysis
of each gas present provides a useful tool in determining the condition of the
transformer. The interpretation of the analysis has not yet been perfected to
an exact science and is therefore subject to interpretation.
Insulating Gases
❖ Insulating gases, such as SF6, N2, fluorocarbons (freons), H2, and CO2 are
used in varying degrees as insulating medium in electrical equipment and
apparatus. Since SF6 is used as the principal insulation in high- and mediumvoltage circuit breakers, information is provided on this gas in this section.
❖ SF6 in its normal state is odorless, tasteless, nontoxic, noncorrosive, nonflammable, and inert.
❖ Its dielectric strength is 2–3 times that of air, has high thermal stability, and
good arc extinguishing properties.
❖ In circuit breakers, its self-healing properties enable it to regenerate itself
following an AC interruption.
❖ The SF6 liquefies at a temperature of below 50°F at a pressure of 220 psig,
and on the lower end of the vapor pressure curve the gas becomes a liquid at
−20°C at a pressure of 50 psig.
Maintenance of SF6
❖ One maintenance item of concern is to
monitor the leakage of SF6 gas from the
electrical apparatus.
❖ This can be easily accomplished by using a
refrigerator-type freon detector. This is a
flameless detector that can detect leaks as
small as one ounce per year.
❖ The other concern is the contamination of the
gas. There are five types of contaminants in
the SF6 gas that must be identified which will
require corrective actions.
❖ These contaminants are conducting particles,
moisture, oil contamination, gaseous
contamination, and arc- decomposition
products.
Conducting Particles
❖Particles of metallic or carbonaceous matter may be found in the gas,
especially in the gas-insulated bus.
❖ At normal operating voltages these particles may cause local ionization of the
gas. Under normal circumstances no internal flashover results from this
ionization because the SF6 gas will absorb the free electrons as rapidly as they
are generated.
❖ However, if the voltage gradient gets high enough, ionization proceeds faster
than the ions can be absorbed by the gas molecules, and ion avalanche leads
to an internal flashover.
Moisture
❖ The SF6 gas shipped from the factory has very low moisture content, less
than 40 ppm by volume. Moisture is usually introduced into the gas during
installation by inadequate evacuation of the equipment before filling. Water
molecules adhering to the solid surfaces inside the equipment will diffuse
into the gas after filling.
Oil Contamination
❖ Oil and oil vapor containing free carbon molecules can cause flashover
of the SF6 gas. Operating experience has shown that clean oil and oil
vapor free of carbon does not degrade the performance of the gasinsulated equipment in any way.
Gaseous Contamination
❖ The gaseous contamination in the SF6 gas may result from three different
sources. The first source of contamination is from the factory where it
may have been introduced into the gas. The second source of
contamination is in filling or operation of the gas-insulated equipment
due to improper handling and procedures. The third source is due to arc
decomposition products.
Arc Products
❖ The SF6 gas is referred to as a self-healing gas. This is because the gas
absorbs the free electrons generated by the arc which causes the gas to
ionize. These ions recombine to reform the SF6 gas. Not all of the ions
and free atoms recombine properly and some permanent breakdown
products can form. Therefore, all arced SF6 gas should be regarded as
containing toxic byproducts.
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