Cleaning / Back wash of Generator Air Cooler


Generator Air Cooler


Power Generation is done by AC Generator in various CPP and Mega Power Generating units. Generator carries a large amount of Currents and which needs to be controlled by proper Cooling & Mechanism.

Type of Cooling:

  • Generator Hydrogen Coolers
  • Generator Air Coolers
  • Stator Water Coolers
  • Lube Oil Coolers
  • Motor Air Coolers
  • Bearing Oil Coolers
  • Exciter Coolers
  • Cooler Services
  • Spare Parts

Air Cooled Generators In most of the Generators having capacity up to 100 MW; preferred cooling system is Air cooled Generators. Here the Generator is mounted with Cooling fans on both DE & NDE ends and when the Generator on load it circulate the air in a closed compartment which enabled by Generator cooler (Water cooled supplied by Pumps) and the Heat transfer takes place.

Electrical generators produce not only electricity but heat from electrical resistance 
(I2*R) and windage losses that are a byproduct of creating electrical power from rotating equipment.
We should remove this heat from the generator’s cooling gas to the plant cooling water. Hydrogen and air coolers are an integral part of the overall heat removal system. Warm gas from the stator and rotor pass through the coolers,transferring heat to the fins and cooler tubes.

 Stator Water Coolers

When Gas Cooling Alone is Not Enough
Large generators create more losses in the conducting components than can be safely removed through gas cooling on the exterior of these conductors. These large machines have Deionized (DI) water pass through the conducting bars to keep them cool. The heat rejected to the water needs to be removed externally from the generator.

Lube Oil Coolers

  Rotating power generation equipment relies on sleeve bearings to align their shafts.
Heat, generated through friction, is picked up by the lubricating oil used in these bearings and needs to be removed.
Exciter Air Coolers
... Cooling Your Other Generator
Large utility hydrogen-cooled generators sometimes require excitation power from an external source. This power is created from a small air-cooled generator which has its own system of cooling equipment. 
They remove the heat generated by electrical losses as well as frictional windage losses maintaining appropriate temperatures in the generator to protect insulation and integrity of the generator. They tend to become fouled on the tubeside and require periodic cleaning to maintain peak performance. These coolers, depending on age,
may have the older spiral fin or may contain the newer platefin design. In most cases, when the coolers are replaced, it is more economical to replace with the platefin design.

Marine and TEWAC
Motor Coolers
Marine and Industrial TEWAC motor installations must be especially rugged to withstand shocks and corrosive environments.
Leak Detector
The leak detector system is designed to prevent catastrophic failure of the motor or generator should water leak into the cooling air, which dissipates the heat by sensing moisture before it can leak into the air.
Platefin Coolers
High quality platefin technology as a premier heat transfer surface for all of our utility and industrial applications. The platefin surface offers the benefit of providing higher energy transfer efficiency and improved heat transfer in a more compact, economical and robust design.
Repairs / Reconditioning
We can extend the life of your coolers by repairing key elements such as water boxes and/or tubesheets when needed. After blasting we apply a polymer filler and epoxy coating.

Transformer Oil Testing



There are several diagnostic tools are available now a days for condition assessment of oil filled transformer. Dissolved gas Analysis (DGA) is widely used in diagnostics of the transformer condition. 

The life of a power transformer is primarily governed by the life of the insulation system. The insulation system is required to provide electrical insulation between the various current carrying components of the transformer and to provide mechanical support to the windings. The insulation system consists of the paper insulation and insulating oil. This paper will describe the various tests performed on transformers by the condition monitoring unit. These tests can be divided into two main sections which are: electrical tests and insulating oil analysis.


Fault 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 Arcing

Large 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 Corona

Corona is a low-energy electrical fault. Low-energy electrical discharges produce hydrogen and methane, with small quantities of ethane and ethylene. Comparable amounts of carbon monoxide and dioxide may result from discharge in cellulose.

2.3 Sparking

Sparking occurs as an intermittent high voltage flashover without high current. Increased levels of methane and ethane are detected without concurrent increases in acetylene, ethylene or hydrogen.

2.4 Overheating

Decomposition 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 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 involved an oil-impregnated structure.

2.6 Partial Discharge

The 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 60-150°C. Hydrocarbon cracking in the partial discharges occurs as a result of excitation of molecules and their subsequent dissociation by collision with high energy electrons, ions, atomic hydrogen and also free radicals.


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 powerful 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 widely used. A high degree of success has been achieved in the area of determining a link between:
  • 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.


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 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 follows:
  • 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


Continuous Monitoring of Key Fault Gases (H2 AND CO)

Key Gas method becomes applicable to transformer with developed faults where absolute values of key gases are considered. The key gases are acetylene, hydrogen, ethylene and carbon monoxide.
Following table illustrates the nature of faults, when key gas is abnormally high.


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 the Gas Composition


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 Resistance

The winding 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 Polarisation Index

The perfect dielectric can be represented, at power frequencies, as a lumped prefect capacitance. The application of a direct electric field to this capacitance will results in a charging current flowing for a short time giving the capacitor 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 Ohm’s Law as the ratio of 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 will 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 down 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 Factor

One of the major tests performed in the field is the measurement of the winding and bushing capacitance and power factor.
Capacitance measurements of each of the windings to ground and between windings is performed to provide an indication of the condition of the winding insulation and some indication of the structural integrity of the windings. Similar measurements are performed on the bushings to provide an indication of the condition of the insulation in the condenser bushing and of the power factor test points.
As described above, the perfect dielectric can be represented as a lumped perfect capacitance. The charging current flowing in the capacitance when 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 between the voltage and current vectors is called the dielectric loss of the angle δ or DLA. The tangent of this angle, tan δ, provides an indication of the losses in the insulation and is known as the POWER FACTOR or DIELECTRIC DISSIPATION FACTOR (DDF).
The power factor of the windings and the bushings is usually measured in the field as a condition assessment tool. The power 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 will also be detected.

Low Voltage Excitation Current Test

The low voltage excitation test is performed to identify shorted turns or severe core damage. This method is a natural extension of the power factor test and makes use of the same equipment. The test results of a three-phase core form transformer will give a pattern of two similar currents and one lower current. This is usually the H2 phase of the transformer as the magnetic reluctance of this phase is lower than the other two phases resulting in a lower excitation current value.

Transformer Turns Ratio

The 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 location of the fault.

Tap Changer Dynamic Resistance Measurement

The 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 allows one to diagnose the diverter switch in the tap changer mechanism.

New Condition Monitoring Tools

Moisture, in conjunction with the other factors, acts on the paper insulation reducing the paper’s strength and volume. This reduces the paper’s, and the transformer’s, ability to perform its function. Therefore two news tests have been introduced to determine the moisture content in the cellulose accurately and movement of the winding 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 known that an increase in the paper moisture content will 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. However, as 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 when compared to known 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 with 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 detect winding deformation, except in the most serious of cases. Any changes in the spatial position of the winding structrue will result in relative changes to the internal inductive and capacitive network of the winding structure which 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 connecting 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 clamping 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 will be able to determine the extent of any winding distortion that occurs after the measurement has been taken. This test is particularly valuable as a baseline reference for a new transformer prior to placing in service as well as for older transformer after re-refurbishment.
A spectrum analyzer is used to excite, monitor and record the response from the transformer. A software program downloads the recorded data to a PC for analysis. Results for each phase are then plotted against frequency. Each winding 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 winding is included in each measurement.


A 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 following:
  • Liquid power 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 Factor

The IEC standard method for this test is IEC 247. This involves measuring the power loss through a thin film of the liquid being testing.
Water, contamination, and the decay products of oil oxidation tend to increase the power factor of the oil. New oil has very low power factor values – much less than 0.1% at 25o C and 1.0% at 90o C. As the oil ages and moisture accumulates, or if the unit is contaminated, the liquid power factor tends to increase. This increase in liquid power factor is a direct indication that materials harmful to the paper and to the continued operation of the transformer are building up.
Many transformer owners 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 diagnosis as to whether the problem is moisture, oxidation, or contamination.

Dielectric Breakdown Strength

The dielectric breakdown voltage is a measure of the ability of oil to withstand electric stress. Dry and clean oil exhibit an inherently high breakdown voltage. Free water and solid particles, the latter particularly in combination with high levels of dissolved water, tend to migrate to regions of high electric stress and reduce the breakdown voltage dramatically. The measurement of breakdown voltage, therefore, serves primarily to indicate the presence of contaminants such as water or conducting particles. A low breakdown voltage value can indicate that one or more of these are present. However, a high breakdown voltage does not necessarily indicate the absence of all contaminants. This test is performed in accordance with IEC 156.


The 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 weight 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, with a similar 20 ppm moisture, but that is operating at 40o C. A new transformer should be less than 0.5% moisture by dry weight. Anything over 3.0% (or 30% saturation) is considered extremely wet. Most owners dehydrate transformers when the moisture level exceeds 1.5 to 2.0% moisture by dry weight.

Neutralization Number (Acidity)

This value, measured by IEC standard method IEC 1125A reported 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 when an oil should be replaced or reclaimed.
Acceptable values for acid number are 0.20 and lower. Unacceptable values are over 0.20. These are the values used by TNBT. However, 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 with respect to one or more of the functions that it is supposed to fulfill. Studies have been performed that indicate that the paper will lose 75-80% of its strength (and therefore be at the end of it’s 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 Tension

The test method for interfacial tension (IFT), IEC 6295, measures the strength in mN/m of an interface that will form between service aged oil and distilled water. Because decay products of oil oxidation are both oil and water soluble, their presence will 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.


Field examination of insulating liquids (IEC 296) includes examination for presence of cloudiness or sediment and general appearance as well 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 water 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 for diagnosing transformer problems. If the oil has an acrid or unusual odour, consideration should be given to carrying out further tests.


The test in IEC 296 distinguishes between 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 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 Content

Inhibited oil deteriorates more slowly 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 Analysis

Dissolved 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 winding or at a connection while the presence of iron indicates involvement of the core steel.

Furanic Compounds

When paper breaks down, the cellulose chains are broken and glucose molecules (which serve as the “building blocks” of the cellulose) are chemically changed. Each of the glucose monomer molecules 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 down. 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 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 well 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 Results

Typically, the justification for running transformer oil tests is to provide the maintenance program with 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 when 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, however, 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 with regard to cleaning up 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 oxidation of the oil has been allowed 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 downtime, 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 between DGA tests or furan analyses may be decreased – normal intervals for DGA may be 3 months to one year – sometimes to daily retests where problems are particularly severe. Except for highly critical units, furans and metals are run only when they will 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 where no remedial action 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.


An attempt has been made in this paper to review modern chemical and electrical diagnostic methods for proper transformer maintenance. DGA is the most widely used method for investigating incipient faults. So, with 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.

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 will 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 when a unit has failed.