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8/12/2019 Solution to Power Generation_ Transformer Oil Testing
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8/12/2019 Solution to Power Generation_ Transformer Oil Testing
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7/13/2014 Solution to Power Generation: Transformer Oil Testing
http://www.powervikas.com/2013/01/dga-faults-in-transformer-key-gases-insulating-oil -power-transformer-condition-monitoring-high-voltage-electrical- testing 2
2. TYPES OF FAULTS IN THE TRANSFORMERFault conditions occur primarily from the thermal and electrical
deterioration of oil and electrical insulation. Each combustible
gas level will vary depending upon the fault process.
2.1 ArcingLarge amounts of hydrogen and acetylene are produced, with
minor quantities of methane and ethylene. Arcing occurs
through high current and high temperature conditions. Carbon
dioxide and carbon monoxide may also be formed if the fault
involved cellulose. In some instances, the oil may become
carbonized.
2.2 CoronaCorona is a low -energy electrical fault. Low-energy electrical
discharges produce hydrogen and methane, w ith small
quantities of ethane and ethylene. Comparable amounts of
carbon monoxide and dioxide may result from discharge incellulose.
2.3 SparkingSparking occurs as an intermittent high voltage flashover
without high current. Increased levels of methane and ethane
are detected w ithout concurrent increases in acetylene,
ethylene or hydrogen.
2.4 OverheatingDecomposition products include ethylene and methane,together with smaller quantities of hydrogen and ethane. Traces
of acetylene may be formed if the fault is severe
or involves electrical contacts.
2.5 Overheated CelluloseLarge 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 involved an
oil-impregnated structure.
2.6 Partial DischargeThe temperature plays a less important role in the chemical
reaction occurring in the partial discharges since the vapor
temperature in the discharge zone is not higher than 60-150C.
Hydrocarbon cracking in the partial discharges occurs as a
result of excitation of molecules and their subsequent
dissoc iation by collision w ith high energy electrons, ions,
atomic hydrogen and also free radicals.
3. DISSOLVED GAS ANALYSIS (DGA)
Methods for
Calculating Short
Circuit Current of
Electrical System
Generator Rotor
Protection
Transformer Oil
Testing
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The DGA analysis is performed in three steps:
Extraction of all the gases in the oil sample.
Measurement of the quantity of each gas in the extracted gas.
Calculation of the concentration of each gas in the oil sample.
DGA is a pow erful diagnostic and it has capability to detect
faults in the incipient stage before they develop into major
faults and cause serious damage to transformer. The
conventional Bucholtz Relay is universally used in transformer,
to protect against severe damages. However, the limitations of
this is that enough gas must be generated first to saturate the
oil fully & then to come out and collect the relay.
The DGA technique detects gas in parts per million (ppm)
dissolved oil by the use of gas extraction unit and
a gas chromatograph. It checks whether a transformer under
service is being subjected to a normal aging and
healthy or whether there are incipient defects such as hot
spots, arcing, overheating or partial discharge. Such incipient
faults otherwise remain undetected until they lead to an actual
major failure.
The most commonly measured gases are:
O2 (Oxygen)
N2 (Nitrogen)
H2 (Hydrogen)
CO (Carbon Monoxide)
CO2 (Carbon Dioxide)
CH4 (Methane)
C2H2 (Ethane)
C2H4 (Ethylene) and
C2H2 (Acetylene)
Other extracted gases are sometimes analyzed, such as C3H8,
C3H6, and C3H4 to refine a diagnostic. However this approach
is not w idely used. A high degree of success has been achieved
in the area of determining a link betw een:
Ratios of common fault gas concentration and specific fault
types:
The evolution of individual fault gases and the nature and
severity of the transformer fault.
4. INTERPRETATIONS OF DGA RESULTS ANDDIAGNOSTICS METHODS.There are many techniques of incipient fault diagnosis Review
of the most commonly used gas-inoil diagnostic method is IEEE
C57.104-1991. This method covers not only the determinations
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of the fault severity and its nature, but also offers some
suggestions regarding the follow up actions to be taken.
It is the only method that covers both the gases dissolved in oil
and the gas present in the nitrogen cover of sealed type
transformers. The method proceeds as follow s:
Calculate the total of dissolved combustible gases (TDCG):
TDCG = H2 + CO + CH4+ C2H6 + C2H4 +C2H2
Classify the condition of the transformer according to the limits
for each gas for the total of combustible gases.
Evaluate the rate of increase of combustible gases in ppm/day.
Determine what actions should be taken according to the level
of combustible gases and their rates of increase. This method
defines four possible transformer conditions:
1) TDCG < 720 PPM : Operating satisfactorily
2) TDCG = 721 to 1920 PPM: Faults may be present
3) TDCG = 1921 to 4630 PPM: Faults are probably present
4) TDCG > 4630 PPM: Continued operations could result in
failure.
These conditions are also determined accordingly to individual
gas levels. If any one of the gases exceeds a
given level (Refer Table-1) the transformer is classified
accordingly
4.1 Gas Content in Oil Due to Fault
Short Circuit Current
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Continuous Monitoring of Key Fault Gases(H2 AND CO)
Key Gas method becomes applicable to transformer w ith
developed faults w here absolute values of key gases are
considered. The key gases are acetylene, hydrogen, ethylene
and carbon monoxide.
Follow ing table illustrates the nature of faults, when key gas is
abnormally high.
KEY GAS NATURE OF FAULT
Acetylene C2H2 =Electrical arc in oil
Hydrogen H2 = Corona , partial discharge
Ethylene C2H4 = Thermal degradation of oil
Carbon Monoxide = Thermal ageing of oil
Various Types of Faults Depending on theGas Composition
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ELECTRICAL TESTS
Preventive maintenance testing of in-service transformers has
the primary objective of monitoring conditions in the insulation
and evaluating the useful life still available in the transformer
tested.
Winding ResistanceThe w inding resistance is measured in the field to identify
shorted turns (although this is better identified in the ratio test),
poor joints, high resistance connections or contacts and open
circuits. The resistance is measured on all taps of a tapped
winding to ensure that the OLTC dose not open circuit during
the tap changing operation.
Insulation Resistance and PolarisationIndexThe perfect dielectric can be represented, at pow er frequencies,
as a lumped prefect capacitance. The application of a direct
electric field to this capac itance w ill results in a charging
current flow ing for a short time giving the capac itor sufficient
charge to support a voltage of V= Q/C. The time taken for the
capacitance to achieve this equilibrium will be determined by
the supply source resistance.
In practical dielectrics the charging current does not cease after
this short period but decreases gradually to a minimum value.
The taken for this minimum value to be reached depends upon
the dielectric and can range from seconds to days. The
insulation resistance is defined from Ohms Law as the ratio of
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the applied voltage to this residual current.
In practical applications the charging current can consist of
volume and surface currents. Therefore the insulation resistance
measurement of plant w ill be affected by the condition of the
insulation itself and the cleanliness of the insulation surfaces.
This effect can be allowed for in some plant types by the use of
guarding electrodes.
The time dependency of the insulation resistance can result
from electronic and ionic conductivity, dipole orientation
(dielectric absorption), and space charge polarisation. As the
charging current time constants are affected by the presence of
impurities, the time taken for the leakage current to settle dow n
can be used as an insulation condition indicator. The ratio of
the insulation resistance value take ten minutes after
application of the measurement voltage to that taken one
minute after voltage application is known as the Polarisation
Index. Generally insulation in good (dry) condition has a PI
greater than 1.2.
Winding and Bushing Power FactorOne of the major tests performed in the field is the
measurement of the w inding and bushing capac itance and
pow er factor.
Capacitance measurements of each of the w indings to ground
and betw een w indings is performed to provide an indication of
the condition of the w inding insulation and some indication of
the structural integrity o f the w indings. Similar measurements
are performed on the bushings to provide an indication of the
condition of the insulation in the condenser bushing and of the
pow er factor test points.
As described above, the perfect dielectric can be represented
as a lumped perfect capacitance. The charging current flow ing
in the capac itance w hen an AC filed is applied should lead the
applied voltage by 90. In practical insulating systems losses
(caused by conduction and polarisation currents) cause the
current to lead the voltage by less than 90. The complement of
the angel betw een the voltage and current vec tors is called the
dielectric loss of the angle or DLA. The tangent of this angle,
tan , provides an indication of the losses in the insulation and
is know n as the POWER FACTOR or DIELECTRIC DISSIPATION
FACTOR (DDF).
The power factor of the w indings and the bushings is usually
measured in the field as a condition assessment tool. The
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pow er factor can give an indication of the moisture content of
the paper and oil in the transformer and the bushings. Major
deterioration of the insulation w ill also be detected.
Low Voltage Excitation Current TestThe low voltage excitation test is performed to identify shorted
turns or severe core damage. This method is a natural extension
of the pow er factor test and makes use of the same equipment.
The test results of a three-phase core form transformer w ill give
a pattern of tw o similar currents and one lower current. This is
usually the H2 phase of the transformer as the magnetic
reluctance of this phase is low er than the other tw o phases
resulting in a low er excitation current value.
Transformer Turns RatioThe ratio of the transformer is normally measured at
commissioning or after major refurbishment. The test is also
performed to identify incipient faults or after a transformer fault
trip to identify shorted turns. A turns ratio measurement can
show that a fault exists but does not determine the exact
locat ion of the fault.
Tap Changer Dynamic ResistanceMeasurementThe dynamic resistance measurement detects carbonized spots
and weak contacts in the mechanism of a tap changer. The
advantage of this diagnostics is that not only end positions of
the tap changer contacts can be checked but the complete
stroke of contact movement while changing between taps. This
also allow s one to diagnose the diverter switch in the tap
changer mechanism.
New Condition Monitoring ToolsMoisture, in conjunction w ith the other factors, acts on the
paper insulation reducing the papers strength and volume. This
reduces the papers, and the transformers, ability to perform its
function. Therefore two new s tests have been introduced to
determine the moisture content in the cellulose accurately and
movement of the w inding structure respectively.
Recovery Voltage Measurement (RVM)One of the critical measures of transformer condition is the
moisture content of the paper insulation. It is well know n that
an increase in the paper moisture content w ill result in a
corresponding increase in the transformer ageing rate.
One method of determining the moisture content of paper is to
use equilibrium diagrams that relate oil/water content, sample
temperature and paper moisture content. How ever, as
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transformers in the field are rarely in equilibrium, this method
has varying degrees of accuracy.
A second method of determining the paper moisture content is
to drain oil and take an a paper sample from the insulation. This
method is more accurate, but costly and exposes the
transformer to the atmosphere and the possibility of moisture
ingress. RVM provides an indication of the paper moisture
content without the drawbacks of the above two methods.
RVM is non-intrusive and has proven to be accurate w hen
compared to know n paper moisture contents in oil test cells.
Moisture and the decay products from insulation degradation
are polar in nature. When an electric field is applied to a
dielectric containing polar contaminants, the polar products
become aligned w ith the electric field. If the levels of these
contaminants increase, the time required for the dipoles to align
with the applied field is reduced. This is equivalent to a
reduction in the system time constant. The RVM determines the
equivalent paper moisture content by measuring the time
constant of the insulation system. Instrumentation software
calculates the equivalent paper moisture content from the
system time constant and temperature.
Frequency Response Analysis (FRA)The conventional techniques of ratio, resistance, DDF and even
HV testing are often unable to detec t w inding deformation,
except in the most serious of cases. Any changes in the spatial
position of the w inding structrue will result in relative changes
to the internal inductive and capac itive network of the winding
structure w hich produce changes in the frequency response of
the transformer.
FRA measures the frequency response of the transformer
windings up to 10 MHz. This method involves injecting a low
voltage signal of varying frequency into each end of the
winding and measuring the response at the other end of the
winding.
The transformer under test is always disconnected from
adjacent equipment. This is done to eliminate the effect of
connect ing equipment although it is reported that short lengths
of busbar are not usually a problem. Winding movement is more
likely to occur in older, aged transformers that have reduced
winding c lamping pressure. This is particularly true when the
transformer is placed under a high mechanical load such as
experienced during fault conditions.
The advantage of obtaining a baseline signature of the
transformer is that future tests w ill be able to determine the
extent of any w inding distortion that occurs after the
measurement has been taken. This test is particularly valuable
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as a baseline reference for a new transformer prior to placing in
service as w ell as for older transformer after re-refurbishment.
A spectrum analyzer is used to excite, monitor and record the
response from the transformer. A softw are program downloads
the recorded data to a PC for analysis. Results for each phase
are then plotted against frequency. Each w inding is tested
separately. To ensure repeatable measurements, all other
windings in the transformer are left floating. The test tap
position selected to ensure that the maximum amount of
w inding is included in each measurement.
INSULATING OIL ANALYSISA regular program of oil testing is recommended to monitor for
changes in oil quality. Specialized tests are also performed that
identify specific compounds in the oil and helps determine
whether fault conditions exist inside the unit. The recommended
battery of tests include the follow ing:
Liquid pow er factor at 25o and 100o C
Dielectric breakdown strength
Moisture
Neutralization number(Acidity)
Interfacial tension
Color/Visual Examination
Sludge/Sediment
Inhibitor
Dissolved gas analysis
Dissolved metal analysis
Furanic compounds
Liquid Power FactorThe IEC standard method for this test is IEC 247. This involves
measuring the pow er loss through a thin film of the liquid being
testing.
Water, contamination, and the decay products of oil oxidation
tend to increase the pow er factor of the oil. New oil has very
low pow er factor values much less than 0.1% at 25o C and
1.0% at 90o C. As the oil ages and moisture accumulates, or ifthe unit is contaminated, the liquid pow er factor tends to
increase. This increase in liquid pow er factor is a direct
indication that materials harmful to the paper and to the
continued operation of the transformer are building up.
Many transformer ow ners make the mistake of having this test
run at only one temperature. While the 90o C test is more
sensitive, both temperatures need to be used. The relationship
between the 25o and 90o values can help in making a
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diagnosis as to w hether the problem is moisture, oxidation, or
contamination.
Dielectric Breakdown StrengthThe dielectric breakdow n voltage is a measure of the ability of
oil to w ithstand electric stress. Dry and clean oil exhibit an
inherently high breakdown voltage. Free w ater and solid
particles, the latter particularly in combination with high levels
of dissolved w ater, tend to migrate to regions of high electric
stress and reduce the breakdow n voltage dramatically. The
measurement of breakdow n voltage, therefore, serves primarily
to indicate the presence of contaminants such as water or
conducting particles. A low breakdow n voltage value can
indicate that one or more of these are present. How ever, a high
breakdown voltage does not necessarily indicate the absence
of all contaminants. This test is performed in accordance w ith
IEC 156.
MoistureThe purpose for which the dielectric tests were invented monitoring moisture content can be done directly. IEC 733 is
well established and can measure moisture down to low parts
per million levels.
While acceptable values have been established by voltage class
for moisture (less than or equal to 30 ppm for voltages up to
145 kV, 20 ppm for voltages above 145 kV as used by TNBT),
these are somewhat misleading. A truer picture of moisture in
the transformer must take the sampling temperature into
account so that % saturation of the oil by moisture and %
moisture by dry w eight of the solid insulation can be
calculated. A transformer at 20o C that has 20 ppm moisture in
the oil is considerably wetter than a similar unit, w ith a similar
20 ppm moisture, but that is operating at 40o C. A new
transformer should be less than 0.5% moisture by dry w eight.
Anything over 3.0% (or 30% saturation) is considered extremely
wet. Most owners dehydrate transformers w hen the moisture
level exceeds 1.5 to 2.0% moisture by dry w eight.
Neutralization Number (Acidity)This value, measured by IEC standard method IEC 1125Areported as mg KOH/g sample, reports the relative amount of a
number of oil oxidation products, primarily acids, alcohols and
soaps. As the oil continues to oxidize, acid number increases
gradually, generally over a period of years. Running the acid
number regularly provides guidance as to how far oxidation of
the oil has proceeded. Th acceptable limit is test is usually used
as a general guide for determining w hen an oil should be
replaced or reclaimed.
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Acceptable values for acid number are 0.20 and low er.
Unacceptable values are over 0.20. These are the values used
by TNBT. How ever, there are countries that use values that are
even as low as 0.05. The are reasons why. First of all, if one
examines paper from a 0.05 acid number transformer, it is
readily apparent that even at this low acid number value that
decay products are depositing in and damaging the paper
fibers. Once the damage starts, the life of the insulation is
compromised. Second, between 0.05 and 0.10, visible sludge
will start to form in operating transformers.
The short answer is that the questionable range of 0.05 to 0.10
is where the oil starts to lose its effectiveness w ith respect to
one or more of the functions that it is supposed to fulfill.
Studies have been performed that indicate that the paper w ill
lose 75-80% of its strength (and therefore be at the end of its
effective life) before the acid number reaches 0.40 mg KOH/ g
sample a value that some still consider to be below the value
where the oil needs to be serviced.
Interfacial TensionThe test method for interfacial tension (IFT), IEC 6295, measures
the strength in mN/m of an interface that w ill form betw een
service aged oil and distilled w ater. Because decay products of
oil oxidation are both oil and w ater soluble, their presence w ill
tend to weaken the interface and depress the interfacial tension
value. Brand new oil is frequently 40-50 mN/m. An acceptable
value for in-service oil is greater than 25 mN/m or greater;
unacceptable results are below 28 mN/m.
Color/VisualField examination of insulating liquids (IEC 296) includes
examination for presence of cloudiness or sediment and general
appearance as w ell as a color examination. As oil ages, it will
darken gradually. Very dark oils or oils that change drastically
over a short period of time may indicate problems. Any
cloudiness or sediment indicates the presence of free w ater or
particles that may be detrimental to continued operation of the
equipment. Taken alone, without consideration of past history
or other test parameters, color is not very important fordiagnosing transformer problems. If the oil has an acrid or
unusual odour, consideration should be given to carrying out
further tests.
Sludge/SedimentThe test in IEC 296 distinguishes betw een sediment and sludge.
Sediment is insoluble material present in the oil. Sediment may
consist of insoluble oxidation or degradation products of solid
or liquid materials, solid products such as carbon or metallic
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oxides and fibres or other foreign matter.
Sludge is polymerized oxidation products of solid and liquid
insulating material. Sludge is soluble in oil up to a certain limit.
At sludge levels above this, the sludge comes out of the
solution contributing an additional component to the sediment.
The presence of sludge and sediment may change the electrical
properties of the oil and hinder heat exchange, thus
encouraging deterioration of the insulating materials.
Inhibitor ContentInhibited oil deteriorates more slow ly than uninhibited oil so
long as active oxidation inhibitor is present. However, once the
oxidation inhibitors are consumed, the oil may oxidise at a
greater rate. The determination of residual oxidation inhibitor in
in-service transformer oil is carried as per IEC 666.
Dissolved Metals AnalysisDissolved metals analysis (in particular, for three metals: iron,
copper, and aluminum) can be of use in further identifying the
location of transformer faults discovered by dissolved gas
analysis. For example, dissolved metals analysis indicating the
presences of conductor metals may indicate a fault is occurring
in the w inding or at a connection w hile the presence of iron
indicates involvement of the core steel.
Furanic CompoundsWhen paper breaks dow n, the cellulose chains are broken and
glucose molecules (which serve as the building blocks of the
cellulose) are chemically changed. Each of the glucose monomermolecules that are removed from the polymer chain becomes
one of a series of related compounds called furans or furanic
compounds. Because these furanic compounds are partially
soluble in oil, they are present in both the oil and the paper.
Measuring the concentration in the oil can tell us quite a bit
about the condition of the paper.
The standard method typically tests for five compounds that
are normally only present in the oil as a result of the paper
breaking dow n. Those five compounds, and their probable
causes, are:5-hydroxymethyl-2-furaldehyde (5H2F), typically formed by
oxidation of paper.
2-furyl alcohol (2FOL), typically formed in connection with a
high moisture content.
2-furaldehyde (2FAL), very common, formed by all overheating
and aging conditions.
2-acetyl furan (2ACF), very rare, may be related to electrical
stress.
5-methyl-2furaldehyde (5M2F), typically formed as a result of
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overheating.
These are typically present in very low concentrations,
microg/kg or parts per billion, requiring detailed extraction
methods and analysis using a very sophisticated instrument: a
high performance liquid chromatograph. Typically, we find that
total furan concentrations relate w ell to the following
conditions:
i) 25 parts per billion (ppb) is a new transformer with only
background presence of furans.
ii) Up to 100 ppb is an in service transformer that has aged
normally (Acceptable level).
iii) 100 to 1000 ppb is a unit that may have accelerated ageing
(Questionable level).
iv) Over 1000 ppb has significantly aged and should be
investigated (Unacceptable level).
Very high levels, 1000 ppb and above starts to enter the
danger zone. Transformers with total furans 1000 ppb and
above have a much higher failure rate because they are starting
to reach their end of life or because small areas of the paper
have been destroyed by localized overheating.
Interpretation of Test ResultsTypically, the justification for running transformer oil tests is to
provide the maintenance program w ith information to allow the
efficient and safe continued use of the equipment. In this
context, transformer oil tests listed in the table above (except
for DGA, furans, metals, and PCBs) are run on a regular basis
usually annually or every six months. Trends of the oil quality
are monitored so that w hen the oxidation inhibitor nears
depletion and/or when one or more of the other test
parameters enter the questionable range, the oil can be
serviced to restore it to new oil quality before any lasting
damage to the insulation system is done.
Oil servicing includes reclamation by processing the oil through
filtering (to remove solid materials), through heat and vacuum to
remove moisture and dissolved gases, and through a chemical
adsorbent such as fullers earth to remove acids, sludges, and
decay products. Oil can generally be reclaimed, however far the
oxidation process has proceeded, and it can generally be
reclaimed any number of times to like new oil quality. Oil that
has aged in a transformer, how ever, has caused degradation
products to build up inside the transformer, particular on and
inside the structure of the solid insulation. Removing and
replacing the oil regardless as to whether the replacement oil
is new or reclaimed has little effect w ith regard to cleaning up
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the inside of the transformer. Reclamation of the transformer oil
in the transformer, frequently referred to as hot oil cleaning,
cycles the oil from the transformer through a processing rig
where the oil is cleaned up. Because the oil passing over the
internal structures of the transformer has been heated, it
redissolves the acids and sludges, even those that are inside
the solid insulation. Depending on how far oxidat ion of the oil
has been allow ed to proceed, a reclaiming project may require
a volume of oil passing through the transformer that is
anywhere from 4 to 20 times the liquid volume capacity of the
transformer. If done properly, reclaiming can frequently be done
without deenergizing the transformer. Energized reclaiming
saves on equipment dow ntime, and the loading and vibration
of the energized equipment actually makes the cleaning of the
internal structures proceed more effectively. Limiting factors on
whether reclamation can proceed on an energized basis include
the moisture content, voltage class of the equipment, volume
and access to the oil, and presence of incipient fault conditions.
Faults identified and diagnosed by DGA, furans, and/or metals
analysis must be corrected to ensure that the unit can continue
to operate safely. These faults typically require an outage to
repair as they are related to electrical or mechanical problems
with the internal components. Since it is not always practical to
immediately schedule an outage (and if the fault is not
immediately destructive of the equipment), the monitoring
interval betw een DGA tests or furan analyses may be decreased
normal intervals for DGA may be 3 months to one year
sometimes to daily retests w here problems are particularly
severe. Except for highly critical units, furans and metals are run
only w hen they w ill be useful to help diagnose fault conditions.
The key issue behind testing is to use the information to
improve operations. Too frequently, limited funds are spent on
testing units w here no remedial act ion will ever be taken. It
would be much more cost effective to reallocate those funds to
more critical units perhaps shortening testing intervals where
testing results are a determinant in the continuing maintenance
of that equipment.
Conclusion:An attempt has been made in this paper to review modernchemical and electrical diagnostic methods for proper
transformer maintenance. DGA is the most w idely used method
for investigating incipient faults. So, w ith this case study we
can analyze the higher concentration of C2H4 indicates thermal
Fault, maximum fall in condition 3 in which fault probably
present and then monitor the rate of rise of individual gases,
indicates higher concentration of key gases. But there is no fault
and transformer presently in service condition.
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The transformer just like human beings needs a physical check-
up, for a clean bill of health. No single test procedure is
adequate to supply all the necessary information needed to
properly evaluate a transformer, resulting in the various test
performed by the condition monitoring unit.
The frequency of the tests w ill be determined by many factors
such as the age, loading and history of operation. These tests
may fulfill three distinct but general functions:
i) Prove the integrity of a piece of equipment at the time of
acceptance.
ii) Verify the continued integrity of the unit at periodic intervals
of time.
iii) Determine the nature of the extent of the damage w hen a
unit has failed.
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