TRANSFORMER MAINTENANCE Contd.............

4.6 Transformer Oil Tests That Should Be Done Annually With the Dissolved Gas Analysis. 

4.6.1 Dielectric Strength. This test measures the voltage at which the oil electrically breaks down. The test gives a good indication of the amount of contaminants (water and oxidation particles) in the oil. DGA laboratories typically use ASTM Test Method No. D-877 or D-1816. The acceptable minimum breakdown voltage is 30 kV for transformers 287.5 kV and above, and 25 kV for high voltage transformers rated under 287.5 kV. If the dielectric strength test falls below these numbers, the oil should be reclaimed. Do not base any decision on one test result, or on one type of test; instead, look at all the information over several DGAs and establish trends before making any decision. The dielectric strength test is not extremely valuable; moisture in combination with oxygen and heat will destroy cellulose insulation long before the dielectric strength of the oil has given a clue that anything is going wrong [5]. The dielectric strength test also reveals nothing about acids and sludge. The tests explained below are much more important. 

4.6.2 Interfacial Tension (IFT). This test (ASTM D-791-91) [21], is used by DGA laboratories to determine the interfacial tension between the oil sample and distilled water. The oil sample is put into a beaker of distilled water at a temperature of 25 °C. The oil should float because its specific gravity is less than that of water, which is one. There should be a distinct line between the two liquids. The IFT number is the amount of force (dynes) required to pull a small wire ring upward a distance of 1 centimeter through the water/oil interface. (A dyne is a very small unit of force equal to 0.000002247 pound.) Good clean oil will make a very distinct line on top of the water and give an IFT number of 40 to 50 dynes per centimeter of travel of the wire ring. 

As the oil ages, it is contaminated by tiny particles (oxidation products) of the oil and paper insulation. These particles extend across the water/oil interface line and weaken the tension between the two liquids. The more particles, the weaker the interfacial tension and the lower the IFT number. The IFT and acid numbers together are an excellent indication of when the oil needs to be reclaimed. It is recommended the oil be reclaimed when the IFT number falls to 25 dynes per centimeter. At this level, the oil is very contaminated and must be reclaimed to prevent sludging, which begins around 22 dynes per centimeter. See FIST 3-5 [20]. 

If oil is not reclaimed, sludge will settle on windings, insulation, etc., and cause loading and cooling problems discussed in an earlier section. This will greatly shorten transformer life. 

for the IFT and the acid number. 

Figure 24.—Interfacial Tension, Acid

4.6.3 Acid Number. Acid 

Number, Years in Service.

number (acidity) is the amount of potassium hydroxide (KOH) in milligrams (mg) that it takes to neutralize the acid in 1 gram (gm) of transformer oil. The higher the acid number, the more acid is in the oil. New transformer oils contain practically no acid. Oxidation of the insulation and oils forms acids as the transformer ages. The oxidation products form sludge and precipitate out inside the transformer. The acids attack metals inside the tank and form soaps (more sludge). Acid also attacks cellulose and accelerates insulation degradation. Sludging has been found to begin when the acid number reaches 0.40; it is obvious that the oil should be reclaimed before it reaches 0.40. It is recommended that the oil be reclaimed when it reaches 0.20 mg KOH/gm [20]. As with all others, this decision must not be based on one DGA test, but watch for rising trend in the acid number each year. Plan ahead and begin budget planning before the acid number reaches 0.20. 

4.6.4 Test for Oxygen Inhibitor Every 3 to 5 Years with the Annual DGA Test. In previous sections, the need to keep the transformer dry and O 2 free was emphasized. Moisture is destructive to cellulose and even more so in the 

There is a definite relationship between the acid number, the IFT, and the number of years in service. The accompanying curve (figure 24) shows the relationship and is found in many publications. (It was originally published in the AIEE transactions in 1955.) Notice that the curve shows the normal service limits both 

presence of oxygen. Some publications state that each time you double the moisture (ppm), you halve the life of the transformer. As was discussed, acids are formed that attack the insulation and metals which form more acids, causing a viscous cycle. Oxygen inhibitor is a key to extending the life of transformers. The inhibitor currently used is Ditertiary Butyl Paracresol (DBPC). This works sort of like a sacrificial anode in grounding circuits. The oxygen attacks the inhibitor instead of the cellulose insulation. As this occurs and the transformer ages, the inhibitor is used up and needs to be replaced. The ideal amount of DBPC is 0.3% by total weight of the oil (ASTM D-3487). 

Have the inhibitor content tested with the DGA every 3 to 5 years. If the inhibitor is 0.08% the transformer is considered uninhibited, and the oxygen freely attacks the cellulose. If the inhibitor falls to 0.1%, the transformer should be re-inhibited. For example, if your transformer tested 0.1%, you need to go to 0.3% by adding 0.2% of the total weight of the transformer oil. The nameplate gives the weight of oil—say 5,000 pounds—so 5,000 pounds X 0.002 = 10 pounds of DBPC needs to be added. It’s ok if you get a little too much DBPC; this does not hurt the oil. Dissolve 10 pounds of DBPC in transformer oil that you have heated to the same temperature as the oil inside the transformer. It may take some experimentation to get the right amount of oil to dissolve the DBPC. Mix the oil and inhibitor in a clean container until all the DBPC is dissolved. Add this mixture to the transformer using the method given in the transformer instruction manual for adding oil. 

Caution: Do not attempt this unless you have had experience. Contact an experienced contractor or experienced Reclamation people if you need help. 

In either case, do not neglect this important maintenance function; it is critical to transformer insulation to have the proper amount of oxygen inhibitor. 

4.6.5 Power Factor. Power factor indicates the dielectric loss (leakage current) of the oil. This test may be done by the DGA laboratories. It may also be done by Doble testing. A high power factor indicates deterioration and/or contamination by-products such as water, carbon, or other conducting particles; metal soaps caused by acids (formed as mentioned above); attacking transformer metals; and products of oxidation. The DGA labs normally test the power factor at 25 °C and 100 °C. Doble information [23] indicates the in-service limit for power factor is less than 0.5% at 25 °C. If the power factor is greater than 0.5% and less than 1.0%, further investigation is required; the oil may require replacement or fullers earth filtering. If the power factor is greater than 1.0% at 25 °C, the oil may cause failure of the transformer; replacement or reclaiming is required. Above 2%, the oil should be removed from service and reclaimed or replaced because equipment failure is a high probability. 

4.6.6 Furans. Furans are a family of organic compounds which are formed by degradation of paper insulation (ASTM D-5837).  Overheating, oxidation, and degradation by high moisture content contribute to the destruction of insulation 

and form furanic compounds. Changes in furans between DGA tests are more important than individual numbers. The same is true for dissolved gases. Transformers with greater than 250 parts per billion (ppb) should be investigated because paper insulation is being degraded. Also look at the IFT and acid number. 

Doble in-service limits are reproduced below to support the above recommended guidelines. 

Table 12 below is excerpted from Doble Engineering Company’s Reference Book on Insulating Liquids and Gases [23]. These Doble Oil Limit tables support information given in prior sections in this FIST manual and are shown here as summary tables. 

Table 12.—Doble Limits for In-Service Oils 

Voltage Class 

# 69 kV >69 # 288 kV >288 kV 

Dielectric Breakdown Voltage, D 877, kV min 26 30 

Dielectric Breakdown Voltage 20 20 25 D 1816, .04-inch gap, kV, min. 

Power Factor at 25 °C, D 924, max. 0.5 0.5 0.5 

Water Content, D 1533, ppm, max. 235 225 220 

Interfacial Tension, D 971, dynes/cm, min. 25 25 25 

Neutralization Number, D 974, mg KOH/gm, max. 0.2 0.15 0.15 

Visual Exam clear and bright clear and bright clear 

Soluble Sludge 3ND 3ND 3ND 

1 D 877 test is not as sensitive to dissolved water as the D 1816 test and should not be used with oils for extra high voltage (EHV) equipment.  Dielectric breakdown tests do not replace specific tests for water content. 2 The use of absolute values of water-in-oil (ppm) do not always guarantee safe conditions in electrical apparatus.  The percent by dry weight should be determined from the curves provided.  See the information in  section. “4.5  Moisture Problems.” 3 ND = None detectable. These recommended limits for in-service oils are not intended to be used as absolute requirements for removing oil from service but to provide guidelines to aid in determining when remedial action is most beneficial.   Remedial action will vary depending upon the test results.  Reconditioning of oil, that is, particulate removal (filtration) and drying, may be required if the dielectric breakdown voltage or water content do not meet these limits. Reclamation (clay filtration) or replacement of the oil may be required if test values for power factor, interfacial tension, neutralization number, or soluble sludge do not meet recommended limits. 

4.6.7 Taking Oil Samples for DGA. Sampling procedures and lab handling are usually areas that cause the most problems in getting an accurate DGA. There are times when atmospheric gases, moisture, or hydrogen take a sudden leap from one DGA to the next. As has been mentioned, at these times, one should immediately take another sample to confirm DGA values. It is, of course, possible that the transformer has developed an atmospheric leak, or that a fault has suddenly occurred inside. More often, the sample has not been taken properly, or it has been contaminated with atmospheric gases or mishandled in other ways. The sample must be protected from all contamination, including atmospheric exposure. 

Do not take samples from the small sample ports located on the side of the large sample (drain) valves. These ports are too small to adequately flush the large valve and pipe nipple connected to the tank; in addition, air can be drawn past the threads and contaminate the sample. Fluid in the valve and pipe nipple remain dormant during operation and can be contaminated with moisture, microscopic stem packing particles, and other particles. The volume of oil in this location can also be contaminated with gases, especially hydrogen. Hydrogen is one of the easiest gasses to form. With hot sun on the side of the transformer tank where the sample valve is located, high ambient temperature, high oil temperature, and captured oil in the sample valve and extension, hydrogen formed will stay in this area until a sample is drawn.  

The large sample (drain) valve can also be contaminated with hydrogen by galvanic action of dissimilar metals. Sample valves are usually brass, and a brass pipe plug should be installed when the valve is not being used. If a galvanized or black iron pipe is installed in a brass valve, the dissimilar metals produce a thermocouple effect, and circulating currents are produced. As a result, hydrogen is generated in the void between the plug and valve gate. If the valve is not flushed very thoroughly the DGA will show high hydrogen. 

Oil should not be sampled for DGA purposes when the transformer is at or below freezing temperature. Test values which are affected by water (such as dielectric strength, power factor, and dissolved moisture content) will be inaccurate. 

Caution: Transformers must not be sampled if there is a negative pressure (vacuum) at the sample valve. 

This is typically not a problem with conservator transformers. If the transformer is nitrogen blanketed, look at the pressure/vacuum gage. If the pressure is positive, go ahead and take the sample. If the pressure is negative, a vacuum exists at the top of the transformer. If there is a vacuum at the bottom, air will be pulled in when the sample valve is opened. Wait until the pressure gage reads positive before sampling. Pulling in a volume of air could be disastrous if the transformer is energized. 

If negative pressure (vacuum) is not too high, the weight of oil (head) will make positive pressure at the sample valve, and it will be safe to take a sample. Oil 

head is about 2.9 feet (2 feet 10.8 inches) of oil per pounds per square inch (psi). If it is important to take the sample even with a vacuum showing at the top, proceed as described below. 

Use the sample tubing and adaptors described below to adapt the large sample valve to �-inch tygon tubing. Fill a length (2 to 3 feet) of tygon tubing with new transformer oil (no air bubbles) and attach one end to the pipe plug and the other end to the small valve. Open the large sample (drain) valve a small amount and very slowly crack open the small valve. If oil in the tygon tubing moves toward the transformer, shut off the valves immediately. Do not allow air to be pulled into the transformer. If oil moves toward the transformer, there is a vacuum at the sample valve. Wait until the pressure is positive before taking the DGA sample. If oil is pushed out of the tygon tubing into the waste container, there is a positive pressure and it is safe to proceed with DGA sampling. Shut off the valves and configure the tubing and valves to take the sample per the instructions below. 

DGA Oil Sample Container. Glass sample syringes are recommended. There are different containers such as stainless steel vacuum bottles and others. It is recommended that only glass syringes be used. If there is a small leak in the sampling tubing or connections, vacuum bottles will draw air into the sample, which cannot be seen inside the bottle. The sample will show high atmospheric gases and high moisture if the air is humid. Other contaminates such as suspended solids or free water cannot be seen inside the vacuum bottle. Glass syringes are the simplest to use because air bubbles are easily seen and expelled. Other contaminates are easily seen, and another sample can be immediately taken if the sample is contaminated. The downside is that glass syringes must be handled carefully and must be protected from direct sunlight. They should be returned to their shipping container immediately after taking a sample. If they are exposed to sunlight for any time, hydrogen will be generated and the DGA will show false hydrogen readings. 

For these reasons, glass syringes are recommended, and the instructions below include only this sampling method. 

Obtain a brass pipe plug (normally 2 inches) that will thread into the sample valve at the bottom of the transformer. Drill and tap the pipe plug for �-inch NPT and insert a �-inch pipe nipple (brass if possible) and attach a small �-inch valve for controlling the sample flow. Attach a �-inch tygon tubing adaptor to the small valve outlet. Sizes of the piping and threads above do not matter; any arrangement with a small sample valve and adaptor to �-inch tygon tubing will suffice.

Taking the Sample. 

• Remove the existing pipe plug and inspect the valve opening for rust and debris. 

• Crack open the valve and allow just enough oil to flow into the waste container to flush the valve and threads. Close the valve and wipe the threads and outlet with a clean dry 

Figure 25.—Oil Sampling Piping. 

cloth. 

• Re-open the valve slightly and flush approximately 1 quart into the waste container. 

• Install the brass pipe plug (described above) and associated �-inch pipe and small valve, and a short piece of new �-inch tygon tubing to the outlet of the �-inch valve. 

• Never use the same sample tubing on different transformers. This is one way a sample can be contaminated and give false readings. 

• Open both the large valve and small sample valve and allow another quart to flush through the sampling apparatus. Close both valves. Do this before attaching the glass sample syringe. Make sure the short piece of tygon tubing that will attach to the sample syringe is installed on the �-inch valve before you do this. 

• Install the glass sample syringe on the short piece of �-inch tubing. Turn the stopcock handle on the syringe so that the handle points toward the syringe. Note: The handle always points toward the closed port. The other two ports are open to each other. See figure 26. 

Figure 26.—Sample Syringe (Flushing). 

68 

• Open the large sample valve a small amount and adjust the �-inch valve so that a gentle flow goes through the flushing port of the glass syringe into the waste bucket. 

• Slowly turn the syringe stopcock handle so that the handle points to the flushing port (figure 27). This closes the flushing and allows oil to flow into the sample syringe. Do not pull the syringe handle; this will create a vacuum and allow bubbles to form. The syringe handle (piston) should back out very slowly. If it moves too fast, adjust the small �-inch valve until the syringe slows, and hold your hand on the back of the piston so Figure 27.—Sample Syringe (Filling). you can control the travel. 

• Allow a small amount, about 10 cubic centimeters (cc), to flow into the syringe and turn the stopcock handle again so that it points to the syringe. This will again allow oil to come out of the flushing port into the waste bucket. 

• Pull the syringe off the tubing, but do not shut off the oil flow. Allow the oil flow to continue into the waste bucket.

• Hold the syringe vertical and turn the stopcock up so that the handle points away from the syringe. Press the syringe piston to eject any air bubbles, but leave 1 or 2 cc oil in the syringe. See the accompanying  

Caution: Do not eject all the oil, or air will reenter. 

Turn the stopcock handle toward the Bubble Removal. syringe. The small amount of oil in the syringe should be free of bubbles and ready to receive the sample. If there are still bubbles at the top, repeat the process until you have a small amount of oil in the syringe with no bubbles. 

• Reattach the tygon tubing. This will again allow oil to flow out of the flushing port. Slowly turn the stopcock handle toward the flushing port which again will allow oil to fill the syringe. The syringe piston will again back slowly out of the syringe. Allow the syringe to fill about 80% full. Hold the piston so you can stop its movement at about 80% filled. 

Caution: Do not pull the piston. This will cause bubbles to form. 

• Close the stopcock by turning the handle toward the syringe. Oil again will flow into the waste container. Shut off both valves, remove the sampling apparatus, and reinstall the original pipe plug. 

Caution: Do not eject any bubbles that form after the sample is collected; these are gases that should be included in the lab sample. 

• Return the syringe to its original container immediately. Do not allow sunlight to impact the container for any length of time. Hydrogen will form and give false readings in the DGA. 

• Carefully package the syringe in the same manner that it was shipped to the facility and send it to the lab for processing. 

• Dispose of waste oil in the plant waste oil container. 

4.6.8 Silicone Oil-Filled Transformers.  Silicone oils became more common when PCBs were discontinued. They are mainly used in transformers inside buildings and that are smaller than generator step-up transformers. Silicone oils have a higher fire point than mineral oils and, therefore, are used where fire concerns are more critical. As of this writing, there are no definitive published standards. IEEE has a guide and Doble has some service limits, but there are no standards. Information below is taken from the IEEE publication, from Doble, from articles, from IEC 60599 concepts, and from Delta X Research’s/Transformer Oil Analyst rules. Silicone oil dissolved gas analysis is in the beginning stages, and the suggested methods and limits below are subject to change as we gain more experience. However, in the absence of any other methods and limits, use the ones below as a beginning. 

Silicone oils used in transformers are polydimethylsiloxane fluids, which are different than mineral oils. Many of the gases generated by thermal and electrical faults are the same. The gases are generated in different proportions than with transformer mineral oils. Also, some fault gases have different solubilities in silicone oils than in mineral oils. Therefore, the same faults would produce different concentrations and different generation rates in silicone oils than mineral oils. 

As with mineral oil-filled transformers, three principal causes of gas generation are aging, thermal faults, and/or electrical faults resulting in deterioration of solid insulation and deterioration of silicone fluid. These faults have been discussed at length in prior sections and will not be discussed in great detail here. 

Overheating of silicone oils causes degradation of fluid and generation of gases. Gases generated depend on the amount of dissolved oxygen in the fluid, temperature, and how close bare copper conductors are to the heating. When a transformer is new, silicone oil will typically contain a lot of oxygen. Silicone transformers are typically sealed and pressurized with nitrogen. New silicone oil is not degassed; and, as a rule, oxygen concentration will be equivalent to oxygen solubility (maximum) in silicone. The silicone has been exposed to atmosphere for some time during manufacture of the transformer and manufacturer and storage of silicone oil itself. Therefore, carbon monoxide and carbon dioxide are easily formed and dissolved in the silicone due to the abundance of oxygen in the oil resulting from this atmospheric exposure. In normal new silicone transformers (no faults), both carbon monoxide and carbon dioxide will be generated in the initial years of operation. As the transformer ages and oxygen is depleted, generation of these gases slows and concentrations level off [25]. See figure 29 below for the relationship of decreasing oxygen and increasing carbon monoxide and carbon dioxide as a transformer ages. This curve is for general information only and should not be taken to represent any particular transformer. A real transformer with changes in loading, ambient temperatures, and various duty cycles would make these curves look totally different. 

After the transformer is older (assuming no faults have occurred), oxygen concentration will reach equilibrium (figure 29). Reaching equilibrium may take a few years depending on the size of the transformer, loading, ambient temperatures, etc. After this time, oxygen, carbon monoxide, and Figure 29.—Relationship of Oxygen to Carbon carbon dioxide Dioxide and Carbon Monoxide as Transformer Ages. level off and the rate of production of these gases from normal aging should be relatively constant. If generation rates of these gases change greatly (seen from the DGA), a fault has occurred, either thermal or electrical. Rate of generation of these gases and amounts can be used to roughly determine what the fault is. Once you notice an significant increase in rate of generation of any gas, it is a good idea to subtract the amount of gas that was already in the transformer before this increase. This ensures that gases used in the diagnosis are only gases that were generated after the fault began. 

Carbon monoxide will be a lot higher in a silicone transformer than a mineral oil-filled one. The difficulty is in trying to determine what is producing the CO; is it coming from normal aging of oil or from deterioration of paper from a fault condition. The only solution is a furan analysis. If the CO content is greater than the IEEE limit of 3,000 ppm [26], and the generation rate G1 is met or exceeded, a furan analysis is recommended with the annual DGA. If a thermal fault is occurring and is producing CO and small amounts of methane and hydrogen, the fault may be masked by the normal production of CO from the silicone oil itself. If the CO generation rate has greatly increased, along with other gases, it becomes obvious that a fault has occurred. The furan analysis can only tell you if the paper is involved (being heated) in the fault. 

Some general conclusions can be drawn by comparing silicone oil and mineral oil transformers. 

1. All silicone oil filled transformers will have a great deal more CO than normal mineral oil filled transformers. CO can come from two sources, the oil itself and from degradation of paper insulation. If the DGA shows little other fault in gas generation besides CO, the only way to tell for certain if CO is coming from paper degradation (a fault) is to run a furan analysis with the DGA. If other fault gases are also being generated in significant amounts, in addition to CO, obviously there is a fault, and CO is coming from paper degradation. 

2. There will generally be more hydrogen present than in a mineral oil-filled transformer. 

3. Due to “fault masking,” mentioned above, it is almost impossible to diagnose what is going on inside a silicone filled transformer based solely on DGA. One exception is if acetylene is being generated, there is an active arc. You must also look at gas generation rates and operating history. Look at loading history, through faults, and other incidents. It is imperative that detailed records of silicone oil filled transformers be carefully kept up-to-date. These are invaluable when a problem is encountered. 

4. If acetylene is being generated in any amount, there is a definitely an active electrical arc. The transformer should be removed from service. 

5. In general, oxygen in a silicone-filled transformer comes from atmospheric leaks or was present in the transformer oil when it was new. This oxygen is consumed as CO and CO2 are formed from the normal heating from operation of the transformer. 

6. Once the transformer has matured and the oxygen has leveled off and remained relatively constant for two or more DGA samples, if you see a sudden increase in oxygen, and perhaps carbon dioxide and nitrogen, the transformer has developed a leak. 

In table 14 below are IEEE limits [26], compared with Doble [25] in a study of 299 operating transformers. The table of gases from the Doble study seems more realistic. They show gas level average of 95% of transformers in the study. Note, with the last four gases, limits given by the IEEE (trial use guide) run over 70% higher than the Doble 95% norms. But with the first three gases, hydrogen, methane, and ethane, the IEEE limits are well below the amount of gas found in 95% norms in the Doble study. We obviously cannot have limits that are below the amount of gas found in normal operating transformers. 

Therefore, it is suggested that we use the Doble (95% norm) limits. The 95% norm limit means that 95% of the silicone oil transformers studied had gas levels below these limits. Obviously, 5% had gases higher than these limits. These are problem transformers that we should pay more attention to. 

Table 14.—Comparison of Gas Limits 

Gas Doble 95% Norm IEEE Limits 

Hydrogen 511 200 

Methane 134 100 

Ethane 26 30 

Ethylene 17 30 

Acetylene 0.6 1 

CO 1,749 3,000 

CO2 15,485 30,000 

Total Combustibles 2,024 3,360 

In table 15, the IEEE limits for L1 were chosen. For L2 limits, a statistical analysis was applied, and two standard deviations were added to L1 to obtain L2. For L3 limits, the L1 limits were doubled. 

Table 15.—Suggested Levels of Concern (Limits) 

L1 L2 L3 G1 G2 Gas (ppm) (ppm) (ppm) (ppm per month) (ppm per month) 

Hydrogen 200 240 400 20 100 

Methane 100 125 200 10 50 

Ethane 30 40 60 3 15 

Ethylene 30 25 60 3 15 

Acetylene 1 2 3 1 1 

CO 3,000 3,450 6,000 300 1,500 

CO2 30,000 34,200 60,000 1,500 15,000 

TDCG 3,360 3,882 6,723 na na 

Gas generation rate limits G1 are 10% of L1 limits per month. G2 generation rate limits are 50% of L1 limits per month. These basic concepts were taken from IEC 60599 [12], for mineral oil transformers and applied to silicone oil transformers due to absence of any other criteria. As our experience grows in silicone DGA, these may have to be changed, but they will be used in the beginning. Limits L1, L2, and L3 represent the concentration in individual gases in ppm. G1 and G2 represents generation rates of individual gases in ppm per month. To obtain G1 and G2 in ppm per day divide the per month numbers by 30. Except for acetylene, G1 is 10% of L1 and G2 is 50% of L1. The generation rates (G1, G2), are points where our level of concern should increase, especially when considered with the L1, L2, and L3 limits. At G2 generation rate, we should be extremely concerned and reduce the DGA sampling interval accordingly, and perhaps plan an outage, etc. 

Except for acetylene, generation rate levels G1 and G2 were taken from IEC 60599 reference [12] which is used with mineral oil transformers. Any amount of ongoing acetylene generation means active arcing inside the transformer. In this case, the transformer should be removed from service. These criteria were chosen because of an absence of any other criteria. As dissolved gas analysis criteria for silicone oils becomes better known and quantified table 15 will change to reflect new information. 

As with mineral oil-filled transformers, gas generation rates are much more important that the amount of gas present. Total accumulated gas depends a lot on age (an older transformer has more gas). If the rate of generation of any combustible gas shows a sudden increase in the DGA, take another oil sample immediately to confirm the gas generation rate increase. If the second DGA confirms a generation rate increase, get some outside advice. Be careful; gas generation rates increase somewhat with temperature variations caused by increased loading and summer ambient temperatures. However, higher operating temperatures are also the most likely conditions for a fault to occur. The real question is has the increased gas generation rate been caused by a fault or increased temperature from greater loading or higher ambient temperature? 

If gas generation rates are fairly constant (no big increases and less than G1 limits above), what do we do if a transformer exceeds the L1 limits? We begin to pay more attention to that transformer, just as we do with a mineral oil transformer. We may shorten the DGA sampling interval, reduce loading, check transformer cooling, get some outside advice, etc. As with mineral oil transformers, age exerts a big influence in accumulated gas. We should be much more concerned if a 3-year old transformer which has exceeded the L1 limits than if a 30-year old transformer exceeds the limits. However, if G1 generation rates are exceeded in either an old or new transformer, we should step up our level of concern. 

If accumulated gas exceeds the L2 limit, we may plan to have the transformer degassed. Examine the physical tests in the DGAs and compare them to the Doble/IEEE table (table 16) (Reference Book on Insulating Liquids and Gasses) [23]. The oil should be treated in whatever manner is appropriate if these limits are exceeded. 

If both L1 limits and G1 limits are exceeded, we should become more concerned. Reduce sampling intervals, get outside advice, reduce loading, check transformer cooling and oil levels, etc. If G2 generation limits are exceeded, we should be extremely concerned. It will not be long before L3 limits are exceeded, and consideration must be given to removing the transformer from service, for testing, repair, or replacement. 

If acetylene is being generated, the transformer should be taken out of service. However as with mineral oil transformers, a one-time nearby lightning strike or through fault can cause a “one-time” generation of acetylene. If you notice acetylene in the DGA, immediately take another sample. If the amount of acetylene is increasing, an active electrical arc is present within the transformer. It should be taken out of service. 

If you have a critical silicone (or mineral oil-filled transformer), such as a single station service transformer, or excitation transformer, you should find out if a spare is available at another facility or from Western Area Power Administration or Bonneville Power. If there are no other possible spares consider beginning the budget process for getting a spare transformer. 

Table 16 lists test limits for service-aged silicone filled transformer oil. If any of these limits are exceeded, it is suggested that the oil be treated in whatever manner is appropriate to return the oil to serviceable condition. 

Table 16.—Doble and IEEE Physical Test Limits for Service-Aged Silicone Fluid 

Test Acceptable Limits 

Unacceptable Values Indicate 

ASTM Test Method 

Visual Clear free of particles Particulates, free water 

D 1524 D 2129 

Dielectric breakdown voltage 

30 kV Particulates, dissolved water 

D 877 

Water content maximum 

70 ppm (Doble) 100 ppm (IEEE) 

Dissolved water contamination 

D 1533 

Power factor max. at 25 °C 

0.2 Polar/ionic contamination 

D 924 

Viscosity at 25 °C, cSt 

47.5–52.5 Fluid degradation contamination 

D 44 

Acid neutralization number max, mg KOH/gm 

0.1 (Doble) 0.2 (IEEE) 

Degradation of cellulose or contamination 

D 974 

Note:  If only one number appears, both Doble and IEEE have the same limit. 

75 

If the above limits are exceeded in the DGA, the silicone oil should be filtered, dried or treated to correct the specific problem. 

4.7 Transformer Testing 

When the transformer is new before energizing and every 3 to 5 years, the transformer and bushings should be Doble tested. Transformer testing falls into three broad categories: Factory testing when the transformer is new or has been refurbished, acceptance testing upon delivery, and field testing for maintenance and diagnostic purposes. Some tests at the factory are common to most power transformers, but many of the factory tests are transformer- specific. Table 17 lists several tests. This test chart has been adapted from IEEE 62-1995 reference [19]. Not all of the listed tests are done at the factory, and not all of them are done in the field. Each transformer and each situation is different, requiring its own unique approach and tests. 

Details of how to run specific tests will not be addressed in this FIST. It would be impractical to repeat how to do Doble testing of a transformer when the information is readily available in Doble publications. With some exceptions, this is true for most of the tests. Specific information is readily available within the test instrument manufacturers literature. Another example is the transformer turns ratio test (TTR); specific test information is available with the instrument. However, information on some tests may not be available and will be covered briefly. 

4.7.1 Winding Resistances. Winding resistances are tested in the field to check for loose connections, broken strands, and high contact resistance in tap changers. Key gases increasing in the DGA will be ethane and/or ethylene and possibly methane. Results are compared to other phases in wye connected transformers or between pairs of terminals on a delta-connected winding to determine if a resistance is too high. Resistances can also be compared to the original factory measurements. Agreement within 5% for any of the above comparisons is considered satisfactory. You may have to convert resistance measurements to the reference temperature used at the factory (usually 75 °C) to compare your resistance measurements to the factory results. To do this use the following formula: 

Ts + Tk 

Rs = Rm Tm + Tk Rs = Resistance at the factory reference temperature (found in the transformer manual) Rm = Resistance you actually measured Ts = Factory reference temperature (usually 75 °C) Tm = Temperature at which you took the measurements Tk = a constant for the particular metal the winding is made from: 234.5 °C for copper 225 °C for aluminum It is very difficult to determine actual winding temperature in the field, and, normally, this is not needed. You only need to do the above temperature corrections if you are going to compare resistances to factory values. Normally, only the phase resistances are compared to each other, and you do not need the winding temperature to compare individual windings. 

You can compare winding resistances to factory values; change in these values can reveal serious problems. A suggested method to obtain an accurate temperature is outlined below. If a transformer has just been de-energized for testing, the winding will be cooler on the bottom than the top, and the winding hot spot will be hotter than the top oil temperature. What is needed is the average winding temperature, and it is important to get the temperature as accurate as possible for comparisons. 

The most accurate method is to allow the transformer sit de-energized until temperatures are equalized. This test can reveal serious problems, so it’s worth the effort. 

Winding resistances are measured using a Wheatstone Bridge for values 1 ohm or above and using a micro-ohmmeter or Kelvin Bridge for values under 1 ohm. Multi-Amp (now AVO) makes a good instrument for these measurements which is quick and easy to use. Take readings from the top of each bushing to neutral for wye connected windings and across each pair of bushings for delta connected windings. If the neutral bushing is not available on wye connected windings, you can take each one to ground (if the neutral is grounded), or take readings between pairs of bushings as if it were a delta winding. Be consistent each time so that a proper comparison can be made. The tap changer can also be changed from contact to contact, and the contact resistance can be checked. Keep accurate records and connection diagrams so that later measurements can be compared. 

4.7.2 Core Insulation Resistance and Inadvertent Core Ground Test. Core insulation resistance and inadvertent core ground test is used if an additional core ground is suspected; this may be indicated by the DGA. Key gases to look for are ethane and/or ethylene and possibly methane. These gases may also be present if there is a poor connection at the bottom of a bushing or a bad tap changer contact. Therefore, this test is only necessary if the winding resistance test above shows all the connections and if tap changer contacts are in good condition. 

The intentional core ground must be disconnected. This may be difficult, and some oil may have to be drained to accomplish this. On some transformers, core grounds are brought outside through insulated bushings and are easily accessed. A standard dc megohmmeter is then attached between the core ground lead (or the  top of the core itself ) and the tank (ground). The megohmmeter is used to place a  dc voltage between these points, and the resistance measured. A new transformer  should read greater than 1,000 megohms. A service-aged transformer should read greater than 100 megohms. Ten to one-hundred megohms is indicative of deteriorating insulation between the core and ground. Less than 10 megohms is sufficient to cause destructive circulating currents and must be further investigated [19]. A solid core ground may read zero ohms; this, of course, causes destructive circulating currents also. 

Some limited success has been obtained in “burning off” unintentional core grounds using a dc or ac current source. This is a risky operation, and the current may cause additional damage. The current source is normally limited to 40 to 50 amps maximum and should be increased slowly so as to use as little current as possible to accomplish the task. This should only be used as a last resort and then only with consultation from the manufacturer, if possible, and with others experienced in this task.