ELECTRICAL MAINTENANCE

Transformer Maintenance: The Cheapest Form of Insurance
Part 2: The Cost of Failure

The cost of a transformer failure can be staggering to your operation. Not only is the cost of the replacement and repair high but the cost of lost production or potential for lost business far exceeds the repair costs.

The very typical emergency call will follow along these lines.

• Customer calls reporting power is down in his facility.
• Emergency response crew arrives and determines that the transformer may be suspect. They begin to test the transformer. The transformer is a 2.0 MVA unit (Very Typical).
• Testing shows that the windings have suffered severe damage eliminating the chance for a repair in the field.
• Calls are placed to arrange for a temporary power source to restore the facility. The staff is sent home since no work can proceed.
• At this stage you have experienced an eight hour period of lost production and the clock is running.
• Two 1.25 MVA diesel generators are delivered to the site, connected and energized. Power to the plant is restored.
• Another eight hour period of lost production and the clock is running.
• A temporary transformer is located and rented. Arrangements are made for its delivery to the site. This takes twenty-four hours. The diesels are running still and fuel is being consumed quickly.
• The temporary transformer is installed, tested and put into service. The diesel generators are shut down and the plant is back to normal, for now.
• Your transformer is sent to be repaired, this will take 10 weeks.
• When your transformer is ready it is shipped to site and installed. The plant is shut down again for twenty hours. Again, there is added down time.

Maintenance Programs
We have now defined a start point. Now we have to define what we need to do. Before we explore this there are a few points that are critical to an effective maintenance program.

These are:

• History
• Consistency
• Accuracy
• Safety
• Quality

Consistency means doing things the same way at the same time. Develop a work procedure for your staff for routine inspections and a specification for your maintenance provider to follow during your planned shutdowns. It is critical that you understand and ensure all work routines are followed.

Accuracy means that the data you collect is repeatable and reliable. Record ambient conditions when doing so. Data that is inconsistent has either been recorded wrong or is indicative of a problem. It is very important to know the difference.

Safety is the most important consideration of all when considering inspections of an energized power transformer. Before you approach your transformer consider the safety implications of doing so. Power transformers are found in substations that contain high voltage systems. Further, many of the devices you will be inspecting are sometimes installed in close proximity to energized power circuits. Before you enter into these areas make sure that you and your staff are fully trained and competent to do so!

Quality workmanship given by your maintenance provider is essential. Don't select a service provider based on price alone. Select this person based on their credentials, experience, training and references. He will be servicing one of the most important pieces of equipment in your plant. Don't trust this honor to just anyone.

On-Line Maintenance
Transformer maintenance can be broken down into two categories that we define as "On-line" and "Off-Line". The on-line system is the most cost effective of all because it does not require downtime, highly skilled staff or advanced equipment, it can be performed by any competent person.

General Inspections
There are several devices associated with transformers that will help you to determine the condition of your unit.

Some of these devices are:

• Oil Temperature Gauge
• Winding Temperature Gauge
• Vacuum/Pressure Gauge
• Oil Level Gauge
• Gas Accumulation Relay
• Ammeters
• Volt Meters
• Tap Changer operations Counter
• Tap Changer Position Indicator

There are two types of losses: "Core" and "Copper" losses. The core loss is the no-load loss. It is the electrical energy needed to create the electromagnetic field. This is a very small part of the total loss. The copper losses are the I2R heat losses that are proportional to the actual DC resistance of the transformer windings. These compose most of the loss component and contribute virtually all of the heating effect. The power loss is directly proportional to the square of the load current. Therefore, doubling the load will magnify the heating effect by four times.

The heat will accelerate oil decay that in turn causes winding insulation decay. The same concern is present with dry type transformers as well. It is very important to determine a normal baseline running temperature for your transformer and be sure that it is within the design parameters of the unit. This can only be done by periodic inspection of the transformer under normal loading at various times of the year. A key point to keep in mind is that a dry type transformer will operate at much higher temperatures than an oil filled transformer. Don't be alarmed if you see your dry type transformer operating at 120°C while the oil filled transformers are operating at 45°C.

The best way to determine the operating parameters of your transformer is to consult the nameplate data for that unit. The nameplate will indicate to you the temperature rise allowable and the full load current. Operating the transformer outside of these design parameters will result in loss of life and eventually lead to failure.

If you find the temperature is rising above this normal level, extra efforts should be placed on cooling the unit and eliminating the cause of the heat.

The installation of cooling fans on the radiators is an excellent method of reducing the heating effect. If the transformer is properly rated to accept a fan cooling system then it can actually withstand a 33 per cent to 66 per cent overload without loss of life. In order to achieve this your unit must be of a ONAN/ONAF/ONAFF type. This means that all accessory devices are fully rated to withstand these overload conditions. If the transformer nameplate does not indicate this rating type then the fans will simply keep your unit cool and will not deliver and additional capacity.

A good practice to follow is to record the ambient temperature, the transformer temperature and the running load current. There is a direct relationship between the three and any deviation from this normal progression will indicate the beginnings of a heating or overload problem.

Vacuum Pressure and Oil Level Gauges
Vacuum pressure gauge and oil level gauges are key components in that they can be easily used to detect leaks in a sealed tank design transformer. Many modern oil filled transformers are designed so that their tanks are completely sealed such that they do not vent air to the atmosphere when the oil expands or contracts.

A major advantage to this type of design is that the oil is not exposed to the atmosphere so the possibility of oil oxidation is greatly reduced.

This type of transformer has a nitrogen blanket at the top of the tank to allow for oil expansion. If there is a leak at the top to the tank no oil would be visible. The vacuum pressure gauge will tell you if there is a leak when it stays at a null pressure constantly.

An undetected leak will allow water and air into the tank. This will eventually compromise the insulation quality.

Oil level gauges indicate the level of the transformer oil. They are calibrated to reflect the temperature of the transformer oil as well. Keep in mind that the oil level will change as the transformer temperature changes. Typically, all oil level gauges are based on an oil temperature of 25°C, meaning when the oil is hot the gauge will indicate above the 25°C mark ,and the opposite when it is cold.

Gas Accumulation Relays
Gas accumulation relays are fitted to larger power transformers with conservator holding tanks. These types of transformers will allow atmospheric air to enter and leave the conservator tank when the oil expands and contracts.

The main tank of the transformer is therefore always filled with oil.

The gas relay is positioned on the main tank in a location strategically designed to collect any bubbles in the oil that are created when an internal fault forms.

The accumulation of these bubbles activates the relay that in turn tells the protection and control system to shut down the transformer. The relay is fitted with a gas volume indicator that should always indicate zero under normal conditions. The presence of any gas in this relay is indicative of a very serious problem and should be acted upon immediately.

Another function of the gas relay is to sense sudden pressure changes in the tank and then react with the protective system to trip the transformer off line. Unfortunately, these are reactive types of protection since the fault has already occurred inside the tank.

The latest technology for very large power transformers is on-line hydrogen gas detectors that run continuously. These detectors look for hydrogen gas build up in the oil. Hydrogen gas is the predominant gas for internal voltage related faults such as corona or arcing.

Once again this device will activate an alarm and take the transformer off line.

Volt and Ammeters
Volt and ammeters can be used to monitor the running load and voltage regulation for the transformer. When recording these readings it is important to look for stability and consistency in the reading. At the same time it is important to note that the load current never exceeds the rating of the transformer.

On/Off Load Tap Changers
On/Off Load Tap Changers (OLTC) is an automatic voltage regulation system that is used to regulate the secondary output voltage and keep it constant in the event that the primary voltage changes.

The tap changer is fitted with a voltage sensing circuit that monitors the output voltage of the transformer. If this output changes to a point where it falls outside of a specified range then the tap changer responds.

The tap changer is a set of moving and stationary contacts within a separate oil filled tank. These contacts allow for the removal or addition of turns in the primary winding in very small steps, usually, 0.5 per cent of the winding. This action changes the turns ratio of the transformer and thus adjusts the secondary output voltage back to within normal limits.

The key to monitoring the condition of your OLTC system is to monitor the number of operations that it goes through. Typically after 50,000 operations, an internal inspection, cleaning and oil change is warranted.

The position indicator tells you the range of motion for the tap changer through its thirty-three positions.

Monitoring the tap changer position indicator will give you an excellent idea of where the wear and tear is occurring and what actual taps are subject to the most stress.

Off load tap changers work on the same principle but can only be operated when the transformer is totally shut down because they do not have any capability of breaking either current or voltage. Because they sit static for years at a time, it is possible that their contacts can become coated and less effective.

Further, they should be operated at every shutdown opportunity so that their operating mechanism can be exercised and tank seals freed up.

After every operation it is essential to perform a turns ratio test to verify that the taps are in the correct position. Every off load tap changer should have a locking device installed in its operating handle to ensure that it is never moved while the transformer is on line.

Otherwise the tap changer will be destroyed and serious damage caused to the transformer core and coils.

Oil/Fluid Analysis
The most effective method of monitoring a transformer while it is still on line is to test the insulating fluid because we know that the oil will control the condition of the insulation and it will be affected first. There are several tests that can be performed on the fluid to determine its chemical condition and the condition of the insulation system.

The routine chemical analysis involves the following tests and is known as the "6 Part Test".

1. Dielectric Breakdown (ASTM D 877) measures the insulating quality of the oil by measuring how much voltage is required to cause a flashover between two plates spaced 0.10" apart. This will indicate the insulating qualities of the oil. It is also used to detect free water in the oil. It cannot detect dissolved water which is a much greater concern
2. Interfacial Tension (ASTM D 971) is used to detect polar contaminants that are formed when the oil is oxidized. Polar contaminants are formed in the early stages of oil oxidation compounds.
3. Visual Condition (ASTM D 1524) determines the presence of free floating contaminants or obvious signs of free water floating in the oil.
4. Neutralization Number (ASTM D 974) is used to measure the level of acid buildup in the oil. As oil ages it becomes oxidized and will form a sludge that inhibits cooling and reduces the tensile strength of the paper insulation.
5. Colour (ASTM D 1500) is a qualitative assessment of the colour that can be used to justify results that indicate failing chemical properties such as Interfacial Tension or Neutralization Number.
6. Specific Gravity (ASTM D 1298) measures the specific gravity of the oil and will indicate if the oil has been chemically altered over its life.

Inhibitor Content measures the amount of oxidation inhibitor in the oil. This is a product added to the oil to retard the buildup of acid. The oxidation inhibitor is slowly consumed over the life of the transformer. This rate of consumption is directly related to operating temperature and exposure to the atmosphere. When the inhibitor is consumed acid will begin to form that will eventually lead to oil quality decay.

Water Content/Karl Fischer (ASTM D 1298) measures the amount of water absorbed into the oil in parts per million and the Karl Fischer test allows the prediction of the amount of water that is actually in the paper insulation measured in percent by dry weight.

Power Factor (ASTM D 924) detects the amount of I2R power losses in the insulating oil. Elevated levels of power factor can be attributed to oil contamination from water or oxidation by-products. This method is used in conjunction with the chemical property tests and insulation power factor tests in order to identify specific insulation weaknesses.

PCB Content is a valuable test because of the Ministry of Environment guidelines for the operation and maintenance of PCB equipment. The limit that determines if a device is PCB filled is 50 PPM. Anytime oil work is done on your transformer you should have it tested. It is possible that your unit can be contaminated accidentally by dirty oil processing equipment.

There are four types of PCBs commonly found in transformers. Some tests only test for one type. It is important that the laboratory you use detects all four types of PCBs known as Aroclors which are 1260, 1242, 1254 and 1248. The combination of all four of these is actually your total PCB content.

Furan Content is used to support the findings from the dissolved gas analysis because it is a very accurate test in determining the tensile strength of the paper insulation. As the insulation breaks down it releases Furanic Acid into the oil and this test measures that level. A high Furan content supported by High levels of Carbon Monoxide and Carbon Dioxide are sure signs of paper breakdown.

Metals Content is used to detect the presence of Aluminium, Iron, Copper, Lead and Tin in the oil. This is a good test for large transformers fitted with oil circulating pumps. It can also help support the dissolved gas and Furan analysis when a suspected fault involves hot connections.

Winding Condition Tests
Dissolved Gas Analysis is a very powerful maintenance tool for the transformer industry. This is a very complex science that has taken years to develop and perfect. The test involves collecting a sample of oil from the transformer by using a sealed syringe so that the oil is not exposed to the atmosphere in any way.

The sample is then injected into a Gas Chromato-graph and the concentration of several key fault gases is measured in parts per million.

These key gases are:

• Hydrogen (H2)
• Nitrogen (N2)
• Oxygen and Argon (O2 + A)
• Methane (CH4)
• Ethylene (C2H4)
• Ethane (C2H6)
• Acetylene (C2H2)
• Carbon Monoxide
• Carbon Dioxide (CO2)

Analytical methods such as Doerenburg, Duval, Rogers, IEC and IEEE standards are used in conjunction with each other to identify faults.

By calculating the ratios described in table 3 and simplifying the results to basically a yes or no answer you can determine the general area of an internal fault.

The use of this type of table alone, in some cases, will not allow you to exactly characterize a particular type of fault. In many cases all types of analytical tools are necessary to specifically determine the severity and type of fault. This may also include off line electrical tests such as Turns Ratio, Insulation Resistance and Winding Resistance. Other types of oil samples -- such as Furan, Power Factor and Metals content. -- may also be necessary.

Historical data also plays a major role because the rate of change of each gas is a critical part of the analysis plus the age of the transformer. Also the nature of the load and any historical knowledge of previous problems must all be factored into the analysis procedure. A sample result that indicates a serious problem may be reported in error if the levels of the gases are static. Important time may be lost in having to collect additional samples to look for a trend if a problem is detected.

The amounts of each gas and the ratios of the key gases are compared to known standards to determine if there is an internal fault inside the transformer and what type of fault it actually is.

Typically, the types of faults that are detected are:

• Corona
• Arcing
• Overheating
• Hot Spots
• Insulation Decay

Based on this collective data, a decision can be made as to whether the unit can be kept on line or shut down so that corrective action can be taken in a planned manner.

The entire purpose of this exercise is to identify, classify and repair the problem before a failure that could be catastrophic occurs.

Off-Line Maintenance
Before performing any type of hands-on maintenance, it is essential that you consider all aspects of this work pertaining to safety. Because you are dealing with high energy electrical systems it very important to have proper lock out, tagging and grounding systems in place before beginning any work.

We have looked at several ways of maintaining your transformer so that it will provide you with reliable service and all of the tests and inspections previously discussed in this paper will certainly accomplish this goal.

However, the on-line program will not satisfy all the needs of a well rounded maintenance program because the sample analysis tools and inspection routines cannot detect all faults that can possibly occur.

Therefore, to put a complete program together there must be a period where the transformer is taken out of service and electrically tested, inspected and maintained.

A detailed electrical test program in conjunction with insulating fluid tests will provide you with a full assessment of your power transformer's condition.

Electrical Tests
There are several types of tests that can be performed in the field. Some are more advanced and costly than others and therefore some consideration should be given as to which tests should be performed. Prior to beginning a test program, it is essential to have the results of your oil samples available for review. These results will be a great help in determining the extent of the testing program that is required. If there is any doubt or question as to the integrity of the transformer's condition then all tests should be performed.

The typical field electrical tests for transformers include:

• Insulation Resistance and Overpotential
• Winding Resistance
• Turns Ratio and Excitation Current
• Capacitance and Dissipation Factor
• Ground Resistance
• Infrared Scanning

The core should only be grounded in one place. A second ground on the core steel can cause circulating currents that will cause the core to overheat. In many oil filled units the core can not be tested because the core ground connection is brought outside the tank.

Overpotential testing is similar to insulation resistance testing, except it is performed at a much higher voltage and will provide an excellent assessment of the insulating qualities of the transformer. Because the test is done at high voltages, great care should be taken in selecting a test voltage that will not cause damage to the winding insulation.

Winding Resistance
Winding Resistance is used to measure the actual DC resistance of each coil in the winding. This is a very powerful test when determining the initial condition of the conductors and then to isolate the type of internal fault present. When used in conjunction with dissolved gas analysis and the turns ratio test this can virtually identify specific bad connections or winding problems. It can also show winding, conductor, connection and tap changer decay if compared to previous years or original factory test results.

Turns Ratio and Excitation Current
Turns Ratio and Excitation Current are used to measure the ratio between the number of actual coils in the primary winding versus the number of coils in the secondary winding. The purpose of the test is to determine the difference between the measured ratio and a calculated one based on information specified on the nameplate.

The excitation current is a measured value of the line current actually drawn by the transformer when it is under test. A gross variation between each of the three phases is indicative of a turn to turn fault in that winding. There may be so many turns in a winding that the actual ratio measurement is not sensitive enough to detect the fault.

The test will indicate if there are any turns in a winding shorted together which is a common fault for power transformers.

This test can also be used to support the dissolved gas analysis results if it indicates a high temperature fault.

Capacitance and Dissipation Factor
Capacitance and Dissipation Factor is used to measure the capacitance of the winding and the dissipation factor of the insulation. Another name for this term is insulation power factor. The dissipation factor is a ratio of two types of leakage current through the insulation to ground when a high voltage is applied to it.

When thinking about this test, it is important to understand that no insulation product is perfect. There will always be some current flow through it even if it is in the order of x10^-6 amps.

The current that leaks through the insulation is called leakage current and is composed of both resistive and capacitive components. These two components add together vectorially to form the overall current.

The resistive current causes heat buildup and tracking in the insulation. This is usually caused by water, dirt or acid contamination. The heat generated will cause further insulation decay.

The theory of operation applies equally to all insulated components of electrical power apparatus. This means that this test can be performed on bushings, windings and even lightning arrestors.

When used in conjunction with insulation resistance and oil power factor tests it can be a formidable tool in analyzing the insulation system.

The test takes two forms one being low voltage and the other being high voltage at 10 kV. It is quickly becoming an industry accepted standard that all tests be performed at higher voltages because the feeling is that the higher test voltage will apply greater stress to the insulation thus detecting even the smallest of anomalies.

Ground Resistance is used to determine the condition of the grounding system used to dissipate the electrical energy created during a lightning strike or a short circuit condition. The system is tested using a three point fall of potential test and ideally should provide resistance readings of less than 3.0 ohms.

A grounding system that has a high resistance will provide little protection to the transformer, especially during a lightening strike.

Infrared Scanning is a method of detecting heat from poor cooling or hot connections that may be compromised because of being dirty or loose.

These types of anomalies emit light found in the infrared spectrum. This frequency of light is not visible to the human eye. A camera sensitive to the level of infrared light is used to measure the actual temperature of the problem area.

The temperature is then used to determine the severity of the problem.

Functional Tests
Whenever a transformer is taken out of service, it is important to verify that the auxiliary equipment is operational. This type of equipment includes:

• Cooling Fans
• Pumps
• Temperature Gauges
• Level Gauges
• Gas Detector Relays
• Tap Changer Control (OLTC)

Fred G. Tanguay is Field Service Division Manager with Black & McDonald Limited.
Next month: Part 3: Maintenance Cycles. ET