A transformer maintenance program must be based on thorough routine inspections. These inspections must be in addition to normal daily/weekly data gathering trips to check oil levels and temperatures. Some monitoring may be done remotely using supervisory control and data acquisition (SCADA) systems, but this can never substitute for thorough inspections by competent maintenance or operations people.
After 1 month of service and once each year, make an in depth inspection of oil-filled transformers. Before beginning, look carefully at temperature and oil level data sheets. If temperature, pressure, or oil level gages never change, even with seasonal temperature and loading changes, something is wrong. The gage may be stuck or data sheets may have been filled in incorrectly. Examine the DGAs for evidence of leaks, etc.
Transformer Tank
Check for excessive corrosion and oil leaks. Pay special attention to flanges and gaskets (bushings, valves, and radiators) and lower section of the main tank. Report oil leaks to maintenance, and pay special attention to the oil level indicator if leaks are found. Severely corroded spots should be wire brushed and painted with a rust inhibitor.
Top Oil Thermometers
These are typically sealed spiral-bourdon-tube dial indicators with liquid-filled bulb sensors. The bulb is normally inside a thermometer well, which penetrates the tank wall into oil near the top of the tank. As oil temperature increases in the bulb, liquid expands, which expands the spiral tube. The tube is attached to a pointer that indicates temperature. These pointers may also have electrical contacts to trigger alarms and start cooling fans as temperature increases. An extra pointer, normally red, indicates maximum temperature since the last time the indicator was reset. This red pointer rises with the main pointer but will not decrease unless manually reset; thus, it always indicates the highest temperature reached since being set. See the instruction manual on your specific transformer for details.
Winding Temperature Thermometers
These devices are supposed to indicate hottest spot in the winding based on the manufacturers heat run tests. At best, this device is only accurate at top nameplate rated load and then only if it is not out of calibration. They are not what their name implies and can be misleading. They are only winding hottest-spot simulators and not very accurate. There is no temperature sensor imbedded in the winding hot spot. At best, they provide only a rough approximation of hot spot winding temperature and should not be relied on for accuracy. They can be used to turn on additional cooling or activate alarms as the top oil thermometers do.
Winding temperature thermometers work the same as the top oil thermometer above, except that the bulb is in a separate thermometer well near the top of the tank. A wire-type heater coil is either inserted into or wrapped around the thermometer well which surrounds the temperature sensitive bulb. In some transformers, a current transformer (CT) is around one of the three winding leads and provides current directly to the heater coil in proportion to winding current. In other transformers, the CT supplies current to an auto-transformer that supplies current to the heater coil. The heater warms the bulb and the dial indicates a temperature, but it is not the true hottest-spot temperature.
These devices are calibrated at the factory by changing taps either on the CT or on the autotransformer, or by adjusting the calibration resistors in the control cabinet. They normally cannot be field calibrated or tested, other than testing the thermometer, as mentioned. The calibration resistors can be adjusted in the field if the manufacturer provides calibration curves for the transformer. In practice, most winding temperature indicators are out of calibration, and their readings are meaningless. These temperature indications should not be relied upon for loading operations or maintenance decisions.
Fiber optic temperature sensors can be imbedded directly into the winding as the transformer is being built and are much more accurate. This system is available as an option on new transformers at an increased cost, which may be worth it since the true winding “hottest-spot” temperature is critical when higher loading is required.
Thermometers can be removed without lowering the transformer oil if they are in a thermometer well. Check your transformer instruction manual. Look carefully at the capillary tubing between the thermometer well and dial indicator. If the tubing has been pinched or accidentally struck, it may be restricted. This is not an obvious defect, and it can cause the dial pointer to lock in one position. If this defect is found, the whole gage must be returned to the factory for repair or replacement; it cannot be repaired in the field. Look for a leak in the tubing system; the gage will be reading very low and must be replaced if a leak is discovered. Thermometers should be removed and tested every 3 to 5 years as described below.
Thermometer Testing
Every 3 to 5 years, and if trouble is suspected, do a thermometer testing. Suspend the indicator bulb and an accurate mercury thermometer in an oil bath. Do not allow either to touch the side or bottom of the container. Heat the oil on a hotplate while stirring and compare the two thermometers while the temperature increases. If a magnetic stirring/heating plate is available, it is more effective than hand stirring. Pay particular attention to the upper temperature range at which your transformers normally operate (50 °C to 80 °C). An ohmmeter should also be used to check switch operations. If either dial indicator is more than 5 °C different than the mercury thermometer, it should be replaced with a spare. A number of spares should be kept, based on the quantity of transformers at the plant.
The alarms and other functions should also be tested to see if the correct annunciator points activate, pumps/fans operate, etc.
If it is not possible to replace the temperature gage or send it to the factory for repair, place a temperature correction factor on your data form to add to the dial reading so the correct temperature will be recorded. Also lower the alarm and pump-turn-on settings by this same correction factor. Since these are pressure-filled systems, the indicator will typically read low if it is out of calibration. Field testing has shown some of these gages reading 15 °C to 20 °C lower than actual temperature. This is hazardous for transformers because it will allow them to continuously run hotter than intended, due to delayed alarms and cooling activation. If thermometers are not tested and errors corrected, transformer service life may be shortened or premature failure may occur.
Oil Level Indicators
After 1 month of service, inspect and every 3 to 5 years, check the tank oil level indicators. These are float operated, with the float mechanism magnetically coupled through the tank wall to the dial indicator. As level increases, the float rotates a magnet inside the tank. Outside the tank, another magnet follows (rotates), which moves the pointer. The center of the dial is normally marked with a temperature 25 °C (77 °F).
High and low level points are also marked to follow level changes as the oil expands and contracts with temperature changes. The proper way to determine accurate oil level is to first look at the top oil temperature indicator. After determining the temperature, look at the level gage. The pointer should be at a reasonable level corresponding to the top oil temperature. If the transformer is fully loaded, the top oil temperature will be high, and the level indicator should be near the high mark. If the transformer is de-energized and the top oil temperature is near 25 °C, the oil level pointer should be at or near 25 °C.
To check the level indicator, you can remove the outside mechanism for testing without lowering transformer oil. After removing the gage, hold a magnet on the back of the dial and rotate the magnet; the dial indicator should also rotate. If it fails to respond or if it drags or sticks, replace it. As mentioned above, defective units can be sent to the factory for repair.
There may also be electrical switches for alarms and possibly tripping off the transformer on falling tank level. These should be checked with an ohmmeter for proper operation. The alarm/tripping circuits should also be tested to see if the correct annunciator points and relays respond. See the transformer instruction book for information on your specific indicator.
If oil has had to be lowered in the transformer or conservator for other reasons (e.g., inspections), check the oil level float mechanism. Rotate the float mechanism by hand to check for free movement. Check the float visually to make sure it is secure to the arm and that the arm is in the proper shape. Some arms are formed (not straight).
Pressure Relief Devices
These devices are the transformers’ last line of defense against excessive internal pressure. In case of a fault or short circuit, the resultant arc instantly vaporizes surrounding oil, causing a rapid buildup of gaseous pressure. If the pressure relief device does not operate properly and pressure is not sufficiently relieved within a few milliseconds, a catastrophic tank rupture can result, spreading flaming oil over a wide area. Two types of these devices are discussed below. The instruction manual for your transformer must be consulted for specifics.
Caution: Never paint pressure-relief devices because paint can cause the plunger or rotating shaft to stick. Then the device might not relieve pressure, which could lead to catastrophic tank failure during a fault. Look at the top of the device; on newer units, a yellow or blue button should be visible. If these have been painted, the button will be the same color as the tank. On older units, a red flag should be visible; if it has been painted, it will be the same color as the tank.
If they have been painted, they should be replaced. It is virtually impossible to remove all paint from the mechanism and be certain the device will work when needed.
Newer Pressure Relief Devices
Newer pressure relief devices are spring-loaded valves that automatically reclose following a pressure release. The springs are held in compression by the cover and press on a disc which seals an opening in the tank top. If pressure in the tank exceeds operating pressure, the disk moves upward and relieves pressure. As pressure decreases, the springs reclose the valve. After operating, this device leaves a brightly colored rod (bright yellow for oil, blue for silicone) exposed approximately 2 inches above the top. This rod is easily seen upon inspection, although it is not always visible from floor level. The rod may be reset by pressing on the top until it is again recessed into the device. The switch must also be manually reset. A relief device is shown in the open position in figureabove.
Caution: Bolts that hold the device to the tank may be loosened safely, but never loosen screws which hold the cover to the flange without referring to the instruction manual and using great care. Springs that oppose tank pressure are held in compression by these screws, and their stored energy could be hazardous.
Once each year, and as soon as possible after a known through-fault or internal fault, inspect pressure devices to see if they have operated. This must be done from a high-lift bucket if the transformer is energized. Look at each pressure relief device to see if the yellow (or blue) button is visible. If the device has operated, about 2 inches of the colored rod will be visible. Each year, test the alarm circuits by operating the switch by hand and making sure the correct annunciator point is activated. If the relief device operates during operation, do not re-energize the transformer; Doble and other testing may be required before re-energizing, and an oil sample should be sent for analysis
Every 3 to 5 years, when doing other maintenance or testing, if the transformer has a conservator, examine the top of the transformer tank around the pressure relief device. If oil is visible, the device is leaking, either around the tank gasket or relief diaphragm. If the device is 30 years old, replace the whole unit. A nitrogen-blanketed transformer will use a lot more nitrogen if the relief device is leaking; they should be tested as described below.
A test stand with a pressure gage may be fabricated to test the pressure relief function. Current cost of a pressure relief device is about $600, so testing instead of replacement may be prudent. Have a spare on hand so that the tank will not have to be left open. If the tank top or pressure relief device has gasket-limiting grooves, always use a nitrile replacement gasket; if there is no grooves, use a cork-nitrile gasket. Relief devices themselves do not leak often; the gasket usually leaks.
Older Pressure Relief Devices
Older pressure relief devices have a diaphragm and a relief pin that is destroyed each time the device operates and must be replaced.
Caution: These parts must be replaced with exact replacement parts, or the operating relief-pressure of the device will be wrong.
The relief pin determines operating pressure; a number, which is the operating pressure, normally appears on top of the pin. Check your specific transformer instruction manual for proper catalog numbers. Do not assume you have the right parts, or that correct parts have been previously installed–look it up. If the operating pressure is too high, a catastrophic tank failure could result.
On older units, a shaft rotates, operates alarm/trip switches, and raises a small red flag when the unit releases pressure. If units have been painted or are more than 30 years old, they should be replaced with the new model as soon as it is possible to have a transformer outage.
Once each year and as soon as possible after a through-fault or internal fault, examine the indicator flag to see if the device has operated. They must be examined from a high-lift bucket if the transformer is energized. A clearance must be obtained to test, repair, or reset the device. See the instruction manual for your specific transformer. Test alarm/trip circuits by operating the switch by hand. Check to make sure the correct annunciator point activates.
Every 3 to 5 years, when doing other maintenance or testing, examine the top of the transformer tank around the pressure relief device. If the transformer has a conservator and oil is visible, the device is leaking, either around the tank gasket or relief diaphragm. The gasket and/or device must be replaced. Take care that the new device will fit the same tank opening prior to ordering.
Sudden Pressure Relay
Internal arcing in an oil-filled power transformer can instantly vaporize surrounding oil, generating gas pressures that can cause catastrophic failure, rupture the tank, and spread flaming oil over a large area. This can damage or destroy other equipment in addition to the transformer and presents extreme hazards to workers.
The relay is designed to detect a sudden pressure increase caused by arcing. It is set to operate before the pressure relief device. The control circuit should de-energize the transformer and provide an alarm. The relay will ignore normal pressure changes such as oil-pump surges, temperature changes, etc.
Modern sudden pressure relays consist of three bellows with silicone sealed inside. Changes in pressure in the transformer deflect the main sensing bellows. Silicone inside acts on two control bellows arranged like a balance beam, one on each side. One bellows senses pressure changes through a small orifice. The opening is automatically changed by a bimetallic strip to adjust for normal temperature changes of the oil. The orifice delays pressure changes in this bellows. The other bellows responds to immediate pressure changes and is affected much more quickly. Pressure difference tilts the balance beam and activates the switch. This type relay automatically resets when the two bellows again reach pressure equilibrium. If this relay operates, do not re-energize the transformer until you have determined the exact cause and corrected the problem.
Old style sudden pressure relays have only one bellows. A sudden excessive pressure within the transformer tank exerts pressure directly on the bellows, which moves a spring-loaded operating pin. The pin operates a switch, which provides alarm and breaker trip. After the relay has operated, the cap must be removed and the switch reset to normal by depressing the reset button.
Once every 3 to 5 years, the sudden pressure relay should be tested according to manufacturer’s instructions. Generally, only a squeeze-bulb and pressure gage (5 psi) are required. Disconnect the tripping circuit and use an ohmmeter to test for relay operation. Test the alarm circuit and verify that the correct alarm point is activated. Use an ohmmeter to verify the trip signal is activated or, if possible, apply only control voltage to the breaker and make sure the tripping function operates. Consult the manufacturer’s manual for your specific transformer for detailed instructions.
Buchholz Relay
The Buchholz relay has two oil-filled chambers with floats and relays arranged vertically one over the other. If high eddy currents, local overheating, or partial discharges occur within the tank, bubbles of resultant gas rise to the top of the tank. These rise through the pipe between the tank and the conservator. As gas bubbles migrate along the pipe, they enter the Buchholz relay and rise into the top chamber.
As gas builds up inside the chamber, it displaces the oil, decreasing the level. The top float descends with oil level until it passes a magnetic switch which activates an alarm. The bottom float and relay cannot be activated by additional gas buildup. The float is located slightly below the top of the pipe so that once the top chamber is filled, additional gas goes into the pipe and on up to the conservator. Typically, inspection windows are provided so that the amount of gas and relay operation may be viewed during testing.
If the oil level falls low enough (conservator empty), switch contacts in the bottom chamber are activated by the bottom float. These contacts are typically connected to cause the transformer to trip. This relay also serves a third function, similar to the sudden pressure relay. A magnetically held paddle attached to the bottom float is positioned in the oil-flow stream between the conservator and transformer tank. Normal flows resulting from temperature changes are small and bypass below the paddle. If a fault occurs in the transformer, a pressure wave (surge) is created in the oil.
This surge travels through the pipe and displaces the paddle. The paddle activates the same magnetic switch as the bottom float mentioned above, tripping the transformer. The flow rate at which the paddle activates the relay is normally adjustable. See your specific transformer instruction manual for details.
Once every 3 to 5 years while the transformer is de-energized, functionally test the Buchhholz relay by pumping a small amount of air into the top chamber with a squeeze bulb hand pump. Watch the float operation through the window. Check to make sure the correct alarm point has been activated. Open the bleed valve and vent air from the chamber. The bottom float and switching cannot be tested with air pressure.
On some relays, a rod is provided so that you can test both bottom and top sections by pushing the floats down until the trip points are activated. If possible, verify that the breaker will trip with this operation. A volt-ohmmeter may also be used to check the switches. If these contacts activate during operation, it means that the oil level is very low, or a pressure wave has activated (bottom contacts), or the transformer is gassing (top contacts). If this relay operates, do not re-energize the transformer until you have determined the exact cause.
Transformer Bushings
Caution: Do not test a bushing while it’s in its wood shipping crate, or while it is lying on wood. Wood is not as good an insulator as porcelain and will cause the readings to be inaccurate. Keep the test results as a baseline record to compare with future tests.
After 1 month of service and yearly, check the external porcelain for cracks and/or contamination (requires binoculars). There is no “perfect insulator”; a small amount of leakage current always exists. This current “leaks” through and along the bushing surface from the high-voltage conductor to ground. If the bushing is damaged or heavily contaminated, leakage current becomes excessive, and visible evidence may appear as carbon tracking (treeing) on the bushing surface. Flashovers may occur if the bushings are not cleaned periodically.
Look carefully for oil leaks. Check the bushing oil level by viewing the oil-sight glass or the oil level gage. When the bushing has a gage with a pointer, look carefully, because the oil level should vary a little with temperature changes. If the pointer never changes, even with wide ambient temperature and load changes, the gage should be checked at the next outage. A stuck gage pointer coupled with a small oil leak can cause explosive failure of a bushing, damaging the transformer and other switchyard equipment. A costly extended outage is the result.
If the oil level is low and there is an external oil leak, check the bolts for proper torque and the gasket for proper compression. If torque and compression are correct, the bushing must be replaced with a spare. Follow instructions in the transformer manual carefully. It is very important that the correct type gasket be installed and the correct compression be applied. A leaky gasket is probably also leaking water and air into the transformer, so check the most recent transformer DGA for high moisture and oxygen.
If the oil level is low and there is no visible external leak, there may be an internal leak around the lower seal into the transformer tank. If possible, re-fill the bushing with the same oil and carefully monitor the level and the volume it takes to fill the bushing to the proper level. If it takes more than one quart, make plans to replace the bushing. The bushing must be sent to the factory for repair or it must be junked; it cannot be repaired in the field.
Caution: Never open the fill plug of any bushing if it is at an elevated temperature. Some bushings have a nitrogen blanket on top of the oil, which pressurizes as the oil expands. Always consult the manufacturer’s instruction manual which will give the temperature range at which the bushing may be safely opened. Generally, this will be between 15 °C (59 °F ) and 35 °C (95 °F). Pressurized hot oil may suddenly gush from the fill plug if it is removed while at elevated temperature, causing burn hazards. Generally, the bushing will be a little cooler than the top oil temperature, so this temperature gage may be used as a guide if the gage has been tested as mentioned in 4.1.3.
About 90% of all preventable bushing failures are caused by moisture entering through leaky gaskets, cracks, or seals. Internal moisture can be detected by testing. Internal moisture causes deterioration of the insulation of the bushing and can result in explosive failure, causing extensive transformer and other equipment damage, as well as hazards to workers.
After 1 month of service and yearly, examine the bushings with an IR camera; if one phase shows a markedly higher temperature, there is probably a bad connection. The connection at the top is usually the poor one; however, a bad connection inside the transformer tank will usually show a higher temperature at the top as well. In addition, a bad connection inside the transformer will usually show hot metal gases (ethane and ethylene) in the DGA.
Once every 3 to 5 years, a close physical inspection and cleaning should be done. Check carefully for leaks, cracks, and carbon tracking. This inspection will be required more often in atmospheres where salts and dust deposits appear on the bushings. In conditions that produce deposits, a light application of Dow Corning grease DC-5 or GE Insulgel will help reduce risk of external flashover. The downside of this treatment is that a grease buildup may occur. In high humidity and wet areas, a better choice may be a high quality silicone paste wax applied to the porcelain, which will reduce the risk of flashover.
A spray-on wax containing silicone, such as Turtle Wax brand, has been found to be very useful for cleaning and waxing in one operation, providing the deposits are not too hard. Wax will cause water to form beads rather than a continuous sheet, which reduces flashover risk. Cleaning may involve just spraying with Turtle Wax and wiping with a soft cloth. A lime removal product, such as “Lime Away,” also may be useful. More stubborn contaminates may require solvents, steel wool, and brushes.
A high pressure water stream may be required to remove salt and other water soluble deposits. Limestone powder blasting with dry air will safely remove metallic oxides, chemicals, salt-cake, and almost any hard contaminate. Other materials, such as potters clay, walnut or pecan shells, or crushed coconut shells, are also used for hard contaminates. Carbon dioxide (CO2) pellet blasting is more expensive but virtually eliminates cleanup because it evaporates. Ground up corn-cob blasting will remove soft pollutants such as old coatings of built-up grease. A competent experienced contractor should be employed and a thorough written job hazard analysis (JHA) performed when any of these treatments are used.
Corona (air ionization) may be visible at tops of bushings at twilight or night, especially during periods of rain, mist, fog, or high humidity. At the top, corona is considered normal; however, as a bushing becomes more and more contaminated, corona will creep lower and lower. If the bushing is not cleaned, flashover will occur when corona nears the grounded transformer top. If corona seems to be lower than the top of the bushing, inspect, Doble test, and clean the bushing as quickly as possible.
If flashover occurs (phase to ground fault), it could destroy the bushing and cause an extended outage. Line-to-line faults also can occur if all the bushings are contaminated and flashover occurs. A corona scope may be used to view and photograph low levels of corona indoors under normal illumination and outdoors at twilight or night. High levels of corona may possibly be viewed outdoors in the daytime if a dark background is available, such as trees, canyon walls, buildings, etc. The corona scope design is primarily for indoor and night time use; it cannot be used with blue or cloudy sky background. This technology is available at the Technical Service Center (TSC), D-8450.
Caution: See the transformer manual for detailed instructions on cleaning and repairing your specific bushing surfaces. Different solvents, wiping materials, and cleaning methods may be required for different bushings. Different repair techniques may also be required for small cracks and chips. Generally, glyptal or insulating varnish will repair small scratches, hairline cracks, and chips. Sharp edges of a chip should be honed smooth, and the defective area painted with insulating varnish to provide a glossy finish.
Hairline cracks in the surface of the porcelain must be sealed because accumulated dirt and moisture in the crack may result in flashover. Epoxy should be used to repair larger chips. If a bushing insulator has a large chip that reduces the flashover distance or has a large crack totally through the insulator, the bushing must be replaced. Some manufacturers offer repair service to damaged bushings that cannot be repaired in the field. Contact the manufacturer for your particular bushings if you have repair questions.
Once every 3 to 5 years, depending on the atmosphere and service conditions, the bushings should be tested. Contamination on the insulating surface will cause the results to be inaccurate. Testing may also be done before and after cleaning to check methods of cleaning. As the bushings age and begin to deteriorate, reduce the testing interval to 1 year. Keep accurate records of results so that replacements can be ordered in advance, before you have to remove bushings from service.
