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Correct interpretation of maintenance data from transformers is vital for increased reliability, long life, and advanced information on possible need of replacement.
Information accumulated through routine inspections and periodic tests on transformers in operation will usually provide you with a warning of approaching service problems. Then corrective measures can be taken. More importantly, if the available transformer maintenance records are effectively interpreted, it's not unusual for an impending failure to be predicted. This, in turn, allows appropriate replacement measures, alleviating the impact of a sudden loss.
Recognizing the warnings of impending failure requires careful surveillance of the records to seek out significant trends or aberrant behavior. Persistence and a basic knowledge of a transformer's expected operational characteristics will help you realize the full benefit of a maintenance program.
Importance of variations in sound level
The audible sound level of a transformer, either dry-type or liquid-filled, is largely dependent on the ratio of the applied voltage to the number of active turns in the primary winding (volts per turn) or on the degree of distortion in the load current. To a lesser degree, it's dependent on the tightness of core and coil clamping components and the external tank structure.
If a noticeable change in sound level is detected that cannot be explained by changes in loading practices, your first check should be the input or output voltage on the transformer because its sound level is very sensitive to changes in voltage. If the voltage increases, the sound level will also increase.
As such, you should verify that the measured voltage is within the nameplate rating for the tap setting on the transformer. If it consistently exceeds the tap voltage by more than 5%, the transformer is over-excited and should be deenergized and a tap selected that is within 5% of the applied voltage. Transformers designed to existing standards can be safely operated at overvoltages of up to 5%, but the sound level will increase noticeably.
If the applied voltage is within the range of the tap setting on the transformer, and there is an unexplained increase in sound level, there could be internal damage that has shorted one or more winding turns in the primary winding. This would reduce the effective number of turns and increase the volts per turn and the sound level. If this problem is suspected, the transformer should be removed from service for acceptance tests. For liquid-filled transformers, if these tests are inconclusive and the unit is to remain in service, oil samples should be taken for gas-in-oil analysis on at least a monthly basis until the analyses refute or confirm the internal winding problems.
An increase in sound level can also be the result of load current distorted by harmonics. Check the connected load for any changes. There may possibly be a developing problem with a load component that has introduced load distortion on the transformer. As various load segments are switched in and out, listen to the sound level for any abrupt changes. Load current with a high harmonic content can cause higher temperatures than the designer anticipated in the magnet core or in the windings. If any noticeable increase in sound level is caused by load harmonics, you should take steps to minimize or eliminate the additional loading on the transformer.
Evaluating tank heating
Hot spots on the tank surfaces of liquid-filled transformers, or enclosures of dry-types, that are severe enough to blister or discolor the paint may indicate the existence of open or shorted internal lead connections. These deficiencies may create changes in the current paths, resulting in induced currents in the tank wall. When tank heating occurs, the transformer should be deenergized as soon as possible and electrical tests performed. Winding resistance and impedance measurements are especially important when tank heating is observed, as changes in these characteristics will indicate changes in the internal connections.
For liquid-filled transformers, an oil sample should be taken for gas-in-oil analysis. If tank heating persists, or a gas-in-oil analysis indicates an increase in combustible gas above the limits shown in Fig. 1, an internal inspection should be made to observe any evidence of irregularities in the internal connections. If a defective connection is identified, an experienced repair organization may be able to make a field repair and recondition the transformer. The surface of the oil should be examined for evidence of carbon or burnt insulation. If the oil is discolored to the point that the internal parts cannot be seen, the transformer should be removed to a repair facility for untanking and examination.
First, when reference is made to oil (askarel), this is done in a generic sense and the term relates to a group of synthetic, fire-resistant, chlorinated, aromatic hydrocarbons used as electrical insulating liquids.These liquids serve as a heat transfer medium. If a liquid-filled transformer is equipped with a pressure gauge, pressure readings should be taken during those times when top-oil temperature readings are taken. Comparison of the pressure readings should be noted on a regular basis and correlated to the temperature readings. Whether a transformer has a pressure gauge or not depends on the type of oil preservation system. The general types of oil preservation systems are as follows.
* Free Breathing. These transformers have vents above the oil that allow air to enter and exit as the oil expands and contracts due to variations in the operating temperature.
* Sealed. A sealed transformer does not have vents but is designed to withstand the internal pressure variations resulting from the compression of the gas space above the oil as the oil volume changes due to thermal expansion and contraction.
* Conservator. These type transformers have a main tank that is completely filled with the insulating liquid and a separate external reservoir. This external tank is provided with a quantity of fluid slightly greater than that displaced by the expansion and contraction of the insulating fluid in the main tank. The external tank is mounted above the main tank and is connected by a short pipe that allows the insulating liquid to flow back and forth.
* Automatic gas seal. Transformers of this type have a space filled with nitrogen above the liquid. The open space is connected to a nitrogen bottle and a regulator. The regulator bleeds off nitrogen from the transformer tank when the liquid rises and adds nitrogen when the liquid falls. This procedure maintains the internal gas pressure within an allowable range.
In addition to the above types, there are other variations. Most transformers in commercial applications are either free breathing or sealed. A sealed unit will usually have a pressure gauge. But, a free breathing unit will not.
A sealed transformer with a welded-on cover should maintain a consistent relationship between top-oil temperature and pressure. If a review of the maintenance record indicates that periods of maximum temperature do not have correspondingly high pressure readings (with minimum pressure readings at lowest temperatures), a leak in the gas space should be suspected. If the peaks and valleys of the pressure readings do correspond to similar peaks and valleys in the temperature readings but the values of the pressure readings are declining over time, you should check the liquid level for loss of fluid and inspect the transformer for fluid leaks.
Many sealed units with bolted-on covers and gasket seals will lose gas pressure if a positive pressure is maintained for an extended period of time. These same units may allow the entrance of air if a negative pressure is maintained over an extended period. Concern in regard to this condition should depend on the ambient weather conditions (humidity, precipitation, and airborne contamination), and the degree of cyclic variations in oil temperature. Be careful not to create conditions that will draw moisture or other contaminants into the transformer through a leak.
When conditions exist that would tend to allow the entrance of contaminants, and the pressure readings indicate a leak, the transformer should be deenergized and a pressure test performed. Most leaks can be found and effectively sealed; however, large gasket areas, especially those using cork or composition gaskets, will often allow the gradual decline of gas pressure, even though an identifiable leak cannot be found.
When operating transformers with minor gas leaks, you should closely monitor oil tests of the fluid dielectric and water content. If there is no noticeable deterioration, the concern for a gradual loss of gas pressure should be minimal.
Significance of liquid level
For liquid-filled transformers, the liquid level should vary with the top-oil temperature, as the tank pressure varies with a sealed transformer. If the indicated liquid level pattern does not follow the rise and fall of the top oil temperature, you should investigate for oil leaks. If none can be found, you should check the liquid level gauge's operation at a convenient outage.
The liquid level should not descend below the minimum indication on the gauge or rise above the maximum indication during extremes of operating conditions. If these limits are exceeded, you should consult the manufacturer or instruction book to establish the proper oil level and the existing level should be checked at the earliest available outage.
If the oil level is consistently below the minimum indication, the transformer should not be operated until the internal level is checked to ensure that no live parts are exposed above the fluid and that the minimum oil level reaches the upper tank opening of any existing external cooling radiators.
You should carefully follow the manufacturers' instructions when adding oil to a transformer. If the instruction book cannot be located, the manufacturer should be contacted as there are often critical variations in the replenishment fluids used, and the manner in which they are introduced to the fluid already in the transformer.
Oil temperature interpretation
For liquid-filled transformers, an operating temperature above normal limits can be indicative of internal problems with the core and coil components, or with the normal exchange of heat from the core and coil assembly to the surrounding air. However, an understanding of what should be the normal operating temperature of a transformer often leads to confusion. Most liquid-filled transformers are rated with a temperature rise of either 55 [degrees] C or 65 [degrees] C. This rated temperature rise will be printed on the nameplate and is defined in various standards as the average winding temperature rise above ambient. The temperature rise must therefore be added to the ambient or surrounding air temperature to arrive at the expected full-load temperature for existing conditions.
Even with the understanding that the nameplate temperature rating is an average winding temperature rise above ambient, there is no gauge on a transformer that measures the average winding temperature because it cannot be directly measured. It can only be measured through a series of tests that would be impractical to make outside a factory test installation. The temperature measured on the gauge is the top-oil temperature and sometimes a simulated winding temperature. Both of these measurements will indicate the temperature rise plus the ambient.
The important point to note here is that the nameplate temperature rise is not the temperature one sees on the temperature gauge of a transformer when operating at full load. The rise in gauge temperature cannot be precisely correlated to the nameplate temperature rise with the information available to most users. But, this correlation can be approximated if the transformer is operating correctly. The relationship between the measured top-oil temperature and the average winding temperature varies somewhat from design to design but usually the top oil-temperature will be 5 [degrees] C to 10 [degrees] C lower than the average winding temperature. The winding temperature indicator, if one is provided, will usually read the winding's hottest spot temperature, which is from 5 [degrees] C to 10 [degrees] C higher than the average winding temperature. Remember that all measured temperatures must have the ambient temperature subtracted to come up with the temperature rises referred to on the nameplate and in the standards.
Another variable that confounds analysis of temperature readings is the time delay experienced between a change in load, or a change in ambient temperature, and the eventual transformer temperature change. The time to reach a temperature equilibrium following a change in either or both of these conditions can be 4 hrs or more for a typical transformer in a commercial application. Therefore, you should compare temperature readings at the same time of day. If done, the variables will be minimized, assuming that the patterns for load variations and changes in ambient temperature are somewhat consistent for corresponding time periods.
The effect of varying ambient temperature over long time spans can be eliminated in large part if the ambient temperature is recorded so that it may be subtracted from the temperature values read on the gauges.
If temperatures under similar load conditions are showing an increase when ambient temperatures are subtracted, you may have thermal problems developing in the transformer and acceptance tests, including winding resistance measurements and dissolved gas analysis, should be performed and compared with prior tests.
Performing oil tests
Oil tests can be separated into two general categories; those that assess the immediate serviceability of the oil and those that assess the degree of aging.
To evaluate the immediate serviceability of the oil, two important tests are carried out: determination of dielectric strength and determination of water content. You should review these test measurements to verify no sudden changes that would indicate the possibility of the entrance of moisture or other contaminants. If there is a sudden change, the transformer should be carefully inspected for leaks and the oil processed if the dielectric is below the 28kV level, or water content is above 30 ppm (parts per million). You should refer to the manufacturer's instructions for oil processing practices appropriate for the transformer.
The principal indicators to assess the degree of aging of the insulation system (lead conductor insulation, winding insulation, core insulation, and the fluid insulation) are interfacial tension, color, and acidity. These indicators should be reviewed for any abrupt changes as they would normally change very little from year to year. A significant change in these values may indicate overheating of all or part of the insulation system.
If there is an interfacial tension decrease of 20% or more, or an acidity increase of 25% or more (with a change in the color of at least one full point on the ASTM-D1500 color scale between annual readings), the oil should be resampled and tested for confirmation of the results. These abrupt changes denote an accelerated aging of the insulation system, which would be indicative of overheating of the insulation. The transformer should be scheduled for acceptance tests as soon as possible if these results are verified.
As a liquid-filled transformer insulation system ages, the oil and paper gradually deteriorate, producing combustible gases that are dissolved in the oil. Study of these gases has led to the recognition of the products of normal aging as well as certain combinations of gases that, in sufficient quantities, can provide warning of developing problems. Performing a gas-in-oil analysis provides a valuable maintenance tool, especially if done on a regular basis, so that normal trends for each transformer can be established. The laboratory report of the test results will list the key combustible gases detected and their quantities expressed in ppm.
Fig. 1 (see page 54), taken from the Guide for Interpretation of Gases Generated in Oil-Immersed Transformers (ANSI/IEEE C57.104), lists the 90% probability norms of combustible gas levels for transmission rated transformers (normally 115kV and higher). These values should be used as a guide only. There is no universal agreement among experts on limits for particular gases; as such, it's important to establish normal trends for individual transformers.
Similar norms have not been established for lower voltage transformers as a separate category. However, experience is accumulating that indicates the limits shown in Fig. 1 are suitable guidelines that may be used for lower voltage transformers (4.16kV to 34kV).
The most important gas to note is acetylene ([C.sub.2][H.sub.2]). This gas requires arcing for its production and levels above 35 ppm should be investigated. Ethane and ethylene are next in order of concern and indicate an intense hot spot. If an elevated level of carbon monoxide is also detected, paper insulation is involved in the hot spot. Elevated levels of methane without correspondingly high values of ethylene and ethane indicate a hot spot of less intensity. The presence of a high level of carbon monoxide would again indicate that paper insulation was involved. Hydrogen indicates that corona is present in the oil. Corona results from the partial breakdown of oil when it is electrically stressed to a critical value. Hydrogen theoretically should be a key gas in maintenance analysis but, in practice, the level of hydrogen varies so widely from test to test that its usefulness is obscure.
If the limits in Fig. 1 are exceeded, or if established trends for a particular transformer suddenly change, the transformer should be acceptance tested.
ANSI/IEEE C57.104 and its references give complete information on interpreting gas analysis data and should be consulted for more information on this subject. Another useful document is Guide for Failure Investigation, Documentation, and Analysis for Power Transformers and Shunt Reactors, ANSI/IEEE C57.125, which gives diagnostic test recommendations for various combinations of detected combustible gas levels.
Insulation resistance measurements
Insulation resistance tests taken with a megohm meter are valuable maintenance measurements since they are easy to make with portable instruments and may be effective in finding defective insulation. However, on liquid-filled transformers, these readings are often erratically variable from test to test. There may be a measurement range as much as 50%. The variations are due in large part to the nature of the insulating oil that takes into solution substances that tend to polarize under the application of the DC voltage stresses produced by the megohm meters. Insulation resistance measurements on dry-type units are usually more consistent, and therefore, more useful than on liquid-filled transformers. Another significant factor affecting megohm readings of liquid-filled units is that there are various combinations of solid and liquid insulations that are used in transformer construction.
An additional factor to consider when measuring insulation resistance is the temperature of the transformer because heat affects each material differently. Insulation resistance is usually measured when the transformer is cooling down. But when doing so, a problem exists in that each material cools at a different rate. The dual uncertainty of the exact temperature of each insulation component, and the degree to which its resistance variation affects the overall reading, makes temperature correction of the megohm values very imprecise. Because of these variations, trends in insulation resistance readings within [+ or -]50% are seldom significant and should always be supported with other tests such as dissolved gas analysis, measurement of oil dielectric strength, and determination of water content.
Meaning of changes in power factor
Power factor measurements are not usually recommended for dry-type transformers. If insulation power factor measurements are carried out for a liquid-filled transformer, and corrections are made for temperature according to the instructions for the particular test set, the measurements should show little variation over long periods of time. If there is a sudden increase in the reading, or if it exceeds 2%, obtain an oil sample for water content measurement, dielectric strength measurement, and color evaluation.
High power factor readings are usually caused by moisture in the insulation system. If oil tests indicate the water content is less than 30 ppm, the color of the sample is acceptable, and the dielectric strength is good, a high water content in the insulation system is unlikely. Clean the external bushing surfaces and check for cracks or other defects. If no bushing defects are identified, take an oil sample for dissolved gas analysis and review the results for any abnormality.
If the above steps do not give an explanation for the high power factor, return the transformer to service. Then, sample the oil for dissolved gas analysis on a monthly basis until the absence of increasing combustible gas indicates the transformer is performing normally. At that point take a careful reading of the power factor and suspend testing until the next periodic maintenance is scheduled. At that time take another reading of the power factor to see what change has taken place.
Because transformers are usually very reliable, it's easy to forget to carry out routine maintenance procedures. But recognizing that a transformer can represent a relatively sizable capital expenditure, that these units are a critical component in providing dependable electrical service, and that a safe electrical system includes transformers operating correctly, it's important to take the time and effort to properly maintain this type equipment.
The full value of a maintenance program can be realized by reviewing accumulated maintenance data with the above guidelines in mind. Simple routine observations and measurements, which should be made and recorded on a regular basis, can provide valuable insights into the internal operation of most transformers. The disciplined review of these observations along with periodic tests such as oil evaluation, insulation resistance measurements, and sometimes dissolved gas analysis, can give optimum assurance that a transformer is not being allowed to fail due to a correctable defect. These measures will also increase the likelihood of recognizing the inevitable approach of a failure due to a cause that might not be correctable. This knowledge will allow preparation for a scheduled changeout of the defective transformer and eliminate the chaos and expense that usually accompany an unplanned outage.
Charles T. Raymond, P.E. is an Engineering Consultant located in Ballston Spa, N. Y. He recently retired as Manager of Transformer Services for G.E. Co. in Schenectady, N.Y.