Saturday, 30 January 2016
Table 17.—Transformer Test Summary Chart
Part to be Tested Test to be Performed
Windings Resistance Across Windings Turns Ratio/Polarity/Phase Excitation Current at All Tap Positions Short Circuit Impedance Insulation Resistance to Ground (megohmmeter) Capacitance (Doble) Power Factor/Dissipation Factor (Doble) Induced Voltage/Partial Discharge/Riv
Bushings Capacitance (Doble) Dielectric Loss (Doble) Power Factor/Dissipation Factor (Doble) Partial Discharge (Doble) Temperature (Infrared) Oil Level (Sight Glass) Visual Inspection (Cracks and Cleanliness)
DGA Insulating Oil Dissolved Gas Analysis Dielectric Strength Interfacial Tension Acid Number Visual Inspection Color Water Content Oxygen Inhibitor Power Factor/Dissipation Factor
Tap Changers - Load Contact Pressure and Continuity Temperature (Infrared) Turns Ratio at All Positions Timing Motor Load Current Limit Switch Operation and Continuity
Tap Changers - No Load Contact Pressure and Continuity Centering Turns Ratio at All Positions Visual Inspection
Core Core Insulation Resistance to Tank Ground Test (megohmmeter)
Tanks and Associated Devices Pressure/Vacuum/Temperature Gages - Calibration Temperature (Infrared) Visual Inspection (Leaks and Corrosion)
Conservator Visual Inspection (Leaks and Corrosion)
Air Drier Desiccant Proper Color
Valves in Proper Position
Sudden Pressure Relay Calibration and Continuity
Buchholz Relay Proper Operation and Continuity
Cooling System Temperature (Infrared)
Heat Exchanger Radiators Clear Air Flow Visual (Leaks, Cleaning, and Corrosion)
Fans Controls
Visual Inspection and Unusual Noise
Pumps Rotation and Flow Indicator
Motor Load Current
REFERENCES
1.IEEE Standard C57.12.01-1989 Standard General Requirements for Dry-Type Distribution, Power, and Regulating Transformers (ANSI).
2.IEEE Standard C57.12.00-1993 Standard General Requirements for Liquid-Immersed Distribution, Power, and Regulating Transformers (ANSI).
3.Power Transformer Maintenance and Testing, General Physics Corporation. 1990.
4.Guidelines for the Life Extension of Substations EPRI, TR-105070. April 1995.
5.Transformer Maintenance Guide, by J.J Kelly, S.D. Myers, R.H. Parrish,S.D. Meyers Co. 1981.
6.Transformer General Gasketing Procedures, by Alan Cote, S.D. Meyers Co. 1987.
7.NFPA 70B-1998 Recommended Practice for Electrical Equipment Maintenance.
8.Bushing Field Test Guide, Doble Engineering Company. 1966.
9.Testing and Maintenance of High-Voltage Bushings, FIST 3-2, Bureau of Reclamation. 1991.
10.IEEE Standard C57.19.00, 1991 General Requirements and Test Procedure for Outdoor Power Apparatus Bushings.
11.IEEE Standard C57.104-1991 Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers.
12.International Electrotechnical Commission (Draft IEC 60599 Edition 2), Mineral Oil-Impregnated Electrical Equipment in Service-Interpretation of Dissolved and Free Gas Analysis. 1997.
13.Dissolved Gas Analysis of Transformer Oil, by John C. Drotos, John W. Porter, Randy Stebbins, published by the S.D. Meyers Co. 1996.
14.IEEE Standard C57.94, 1982, Recommended Practice for Installation, Application, Operation and Maintenance of Dry-Type General Purpose Distribution and Power Transformers.
15.Criteria for the Interpretation of Data for Dissolved Gases in Oil from Transformers (A Review), by Paul Griffin, Doble Engineering Co. 1996.
16.Maintenance of High Voltage Transformers, by Martin Heath Cote Associates, London, England. 1989.
17.Thermal Monitors and Loading, by Harold Moore, from Transformer Performance Monitoring and Diagnostics EPRI. September 1997.
18.IEEE and IEC Codes to Interpret Incipient Faults in Transformers, Using Gas in Oil Analysis, by R.R. Rogers C.E.G.B, Transmission Division, Guilford, England. Circa 1995.
19.IEEE Standard 62-1995, IEEE Guide for Diagnostic Field Testing of Electrical Power Apparatus, Part 1: Oil Filled Power Transformers, Regulators, and Reactors.
20.FIST 3-5 Maintenance of Liquid Insulation: Mineral Oils and Askarels. 1992.
21.ANSI/ASTM D 971-91, Standard Test Method for Interfacial Tension of Oil Against Water by the Ring Method.
22.EPRI Substation Equipment Diagnostics Conference VII, Experience with In-Field Water Contamination of Large Power Transformers, by Victor V. Sokolov and Boris V.
Vanin, Scientific and Engineering Center “ZTZ Service Co.,” Ukraine. 1999
23.Doble Engineering Company “Reference Book on Insulating Liquids and Gases” RBILG-391. 1993.
24.ANSI/IEEE C57.92-1981, Guide for Loading Mineral Oil Immersed Transformers.
25.Doble Engineering Company Client Conference Minutes 1998 Insulating Fluids No. 65PAIC98.
26.IEEE P1258, Trial-Use Guide for the Interpretation of Gases Generated in Silicone-Immersed Transformers. 1999.
27.ASTM D-1933-97. Standard Specification of Nitrogen Gas as an Electrical Insulating Material.
28.ASTM D-3487-88, Standard Specification for Mineral Insulating Oil Used in Electrical Apparatus.
29.ASTM D-5837-96, Standard Test Method for Furanic Compounds in Electrical Insulating Liquids by High Performance Liquid Chromatography.
30.ASTM F-36-99, Standard Test Method for Compressibility and Recovery of Gasket Materials.
31.ASTM D-2240-97, Standard Test Method for Rubber Property – Durometer Hardness.
Monday, 16 November 2015
Tuesday, 8 September 2015
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 Carboncarbon 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.
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.
If the above limits are exceeded in the DGA, the silicone oil should be filtered, dried or treated to correct the specific problem.
Friday, 7 August 2015
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.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
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.
Thursday, 11 June 2015
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 minium 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.
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
1
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. See figure
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 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.
Sunday, 7 June 2015
4.5 Moisture Problems
Moisture, especially in the presence of oxygen, is extremely hazardous to transformer insulation. Each DGA and Doble test result should be examined carefully to see if water is increasing and to determine the moisture by dry weight (M/DW) or percent saturation that is in the paper insulation. When 2% M/DW is reached, plans should be made for a dry out. Never allow the M/DW to go above 2.5% in the paper or 30% oil saturation without drying out the transformer. Each time the moisture is doubled in a transformer, the life of the insulation is cut by one-half. Keep in mind that the life of the transformer is the life of the paper, and the purpose of the paper is to keep out moisture and oxygen. For service-aged transformers rated less than 69 kV, results of up to 35 ppm are considered acceptable. For 69 kV through 288 kV, the DGA test result of 25 ppm is considered acceptable. For greater than 288 kV, moisture should not exceed 20 ppm. However, the use of absolute values for water does not always guarantee safe conditions, and the percent by dry weight should be determined. See table 12, “Doble Limits for In-Service Oils,” in section 4.6.5. If values are higher, the oil should be processed. If the transformer is kept as dry and free of oxygen as possible, transformer life will be extended.
Reclamation specifies that manufacturers dry new transformers to no more than 0.5% M/DW during commissioning. In a transformer having 10,000 pounds of paper insulation, this means that 10,000 x 0.005 = 50 pounds of water (about 6 gallons) is in the paper. This is not enough moisture to be detrimental to electrical integrity. When the transformer is new, this water is distributed equally through the transformer. It is extremely important to remove as much water as possible.
Fault Examples
Partial discharges Discharges in gas-filled cavities in insulation, resulting from incomplete impregnation, high moisture in paper, gas in oil supersaturation or cavitation, (gas bubbles in oil) leading to X wax formation on paper.
Discharges of low energy
Sparking or arcing between bad connections of different floating potential, from shielding rings, toroids, adjacent discs or conductors of different windings, broken brazing, closed loops in the core. Additional core grounds. Discharges between clamping parts, bushing and tank, high voltage and ground, within windings. Tracking in wood blocks, glue of insulating beam, winding spacers. Dielectric breakdown of oil, load tap changer breaking contact.
Discharges of high energy
Flashover, tracking or arcing of high local energy or with power follow-through. Short circuits between low voltage and ground, connectors, windings, bushings, and tank, windings and core, copper bus and tank, in oil duct. Closed loops between two adjacent conductors around the main magnetic flux, insulated bolts of core, metal rings holding core legs.
Overheating less than 300 °C
Overloading the transformer in emergency situations. Blocked or restricted oil flow in windings. Other cooling problem, pumps valves, etc. See the “Cooling” section in this document. Stray flux in damping beams of yoke. Overheating 300 to 700 °C
Defective contacts at bolted connections (especially busbar), contacts within tap changer, connections between cable and draw-rod of bushings. Circulating currents between yoke clamps and bolts, clamps and laminations, in ground wiring, bad welds or clamps in magnetic shields. Abraded insulation between adjacent parallel conductors in windings.
Overheating over 700 °C
Large circulating currents in tank and core. Minor currents in tank walls created by high uncompensated magnetic field. Shorted core laminations.
Notes: 1. X wax formation comes from Paraffinic oils (paraffin based). These are not used in transformers at present in the United States but are predominate in Europe. 2. The last overheating problem in the table says �over 700 °C.” Recent laboratory discoveries have found that acetylene can be produced in trace amounts at 500 °C, which is not reflected in this table. We have several transformers that show trace amounts of acetylene that are probably not active arcing but are the result of high- temperature thermal faults as in the example. It may also be the result of one arc, due to a nearby lightning strike or voltage surge. 3. A bad connection at the bottom of a bushing can be confirmed by comparing infrared scans of the top of the bushing with a sister bushing. When loaded, heat from a poor connection at the bottom will migrate to the top of the bushing, which will display a markedly higher temperature. If the top connection is checked and found tight, the problem is probably a bad connection at the bottom of the bushing.
When the transformer is energized, water begins to migrate to the coolest part of the transformer and the site of the greatest electrical stress. This location is normally the insulation in the lower one-third of the winding [5]. Paper insulation has a much greater affinity for water than does the oil. The water will distribute itself unequally, with much more water being in the paper than in the oil. The paper will partially dry the oil by absorbing water out of the oil. Temperature is also a big factor in how the water distributes itself between the oil and paper. See table 11 below for comparison.
Temperature Water Water (degrees C) in Oil in Paper
20° 1 3,000 times what is in the oil
40° 1 1,000 times what is in the oil
60° 1 300 times what is in the oil
The table above shows the tremendous attraction that paper insulation has for water. The ppm of water in oil shown in the DGA is only a small part of the water in the transformer. It is important that, when an oil sample is taken, you record the oil temperature from the top oil temperature gage.
Some laboratories give percent M/DW of the insulation in the DGA. Others give percent oil saturation, and some give only the ppm of water in the oil. If you have an accurate temperature of the oil and the ppm of water, the Nomograph (figure 23, section 4.5.2) will give percent M/DW of the insulation and the percent oil saturation.
Where does the water come from? Moisture can be in the insulation when it is delivered from the factory. If the transformer is opened for inspection, the insulation can absorb moisture from the atmosphere. If there is a leak, moisture can enter in the form of water or humidity in air. Moisture is also formed by the degradation of insulation as the transformer ages. Most water penetration is flow of wet air or rain water through poor gasket seals due to pressure difference caused by transformer cooling. During rain or snow, if a transformer is removed from service, some transformer designs cool rapidly and the pressure inside drops. The most common moisture ingress points are gaskets between bushing bottoms and the transformer top and the pressure relief device gasket. Small oil leaks, especially in the oil cooling piping, will also allow moisture ingress. With rapid cooling and the resultant pressure drop, relatively large amounts of water and water vapor can be pumped into the transformer in a short time. It is important to repair small oil leaks; the small amount of visible oil is not important in itself, but it also indicates a point where moisture will enter [22].
It is critical for life extension to keep transformers as dry and as free of oxygen as possible. Moisture and oxygen cause the paper insulation to decay much faster than normal and form acids, sludge, and more moisture. Sludge settles on windings and inside the structure, causing transformer cooling to be less efficient, and slowly over time temperature rises. (This was discussed earlier in “3. Transformer Cooling Methods.”) Acids cause an increase in the rate of decay, which forms more acid, sludge, and moisture at a faster rate [20]. This is a vicious cycle of increasing speed forming more acid and causing more decay. The answer is to keep the transformer as dry as possible and as free of oxygen as possible. In addition, oxygen inhibitor should be watched in the DGA testing. The transformer oil should be dried when moisture reaches the values according to table 12. Inhibitor should be added (0.3% by weight ASTM D-3787) when the oil is processed.
Water can exist in a transformer in five forms.
1. Free water, at the bottom of the tank.
2. Ice at the tank bottom (if the oil specific gravity is greater than 0.9, ice can float).
3. Water can be in the form of a water/oil emulsion.
4. Water can be dissolved in the oil and is given in ppm in the DGA.
5. Water can be in the form of humidity if transformers have an inert gas blanket.
Free water causes few problems with dielectric strength of oil; however, it should be drained as soon as possible. Having a water- oil interface allows oil to dissolve water and transport it to the insulation. Problems with moisture in insulation were discussed above. If the transformer is out of service in winter, water can freeze. If oil specific gravity is greater than 0.9 (ice specific gravity), ice will float. This can cause transformer failure if the transformer is energized with floating ice inside. This is one reason that DGA laboratories test specific gravity of transformer oil.
The amount of moisture that can be dissolved in oil increases with temperature. (See figure 19.) This is why hot oil is used to dryout a transformer. A water/oil emulsion can be formed by purifying oil at Figure 19.—Maximum Amount of Water too high temperature. When the oil Dissolved in Mineral Oil Versus Temperature. cools, dissolved moisture forms an emulsion [20]. A water/oil emulsion causes drastic reduction in dielectric strength.
How much moisture in insulation is too much? When the insulation gets to 2.5% M/DW or 30% oil saturation (given on some DGAs), the transformer should have a dry out with vacuum if the tank is rated for vacuum. If the transformer is old, pulling a vacuum can do more harm than good. In this case, it is better to do round-the-clock re circulation with a Bowser drying the oil as much as possible, which will pull water out of the paper. At 2.5% M/DW, the paper insulation is degrading much faster than normal [5]. As the paper is degraded, more water is produced from the decay products, and the transformer becomes even wetter and decays even faster. When a transformer gets above 4% M/DW, it is in danger of flashover if the temperature rises to 90 °C.
4.5.1 Dissolved Moisture in Transformer Oil. Moisture is given in the dissolved gas analysis in ppm, and some laboratories also give percent saturation. Percent saturation means percent saturation of water in the oil. This is a percentage of how much water is in the oil compared with the maximum amount of water the oil can hold. In figure 19, it can be seen that the amount of water the oil can dissolve is greatly dependent on temperature. The curves (figure 20) below are percent saturation curves. On the left line, find the ppm of water from your DGA. From this point, draw a horizontal with a straight edge. From the oil temperature, draw a vertical line. At the point where the lines intersect, read the percent saturation curve. If the point falls between two saturation curves, estimate the percent saturation based on where the point is located. For example, if the water is 30 ppm and the temperature is 40 °C, you can see on the curves that this point of intersection falls about halfway between the 20% curve and the 30% curve. This means that the oil is approximately 25% saturated.
Caution: Below 30 °C, the curves are not very accurate.
4.5.2 Moisture in Transformer Insulation. The illustration at right (figure 21) shows how moisture is distributed throughout transformer insulation. Notice that the moisture is distributed according to temperature, with most moisture at the bottom and less as temperature increases toward the top. In this example, there is almost twice the moisture near bottom as there is at the top. Most service-aged transformers fail in the lower one-third of the windings, which is the area of most moisture. It is also the area of most electrical stress. Moisture and oxygen are two of the transformer’s worst enemies. It is very important to keep the insulation and oil as dry as possible and as free of oxygen as possible.
Failures due to moisture are the most common cause of transformer failures [5]. Without an accurate oil temperature, it is impossible for laboratories to provide accurate information about the M/DW or percent saturation. It will also be impossible for you to calculate this information accurately.
Experts disagree on how to tell how much moisture is in the insulation based on how much moisture is in the oil (ppm). At best, methods to determine moisture in the insulation based solely on DGA are inaccurate. The methods discussed below to determine moisture in the insulation are approximations and no decision should be made based on one DGA. However, keep in mind that the life of the transformer is the life of the insulation. The insulation is quickly degraded by excess moisture and the presence of oxygen. Base any decisions on several DGAs over a period of time and establish a trend of increasing moisture.
If the lab does not provide the percent M/DW, IEEE 62-1995 [19] gives a method. From the curve (figure 22), find temperature of the bottom oil sample and add 5 °C. Do not use the top oil temperature. This approximates temperature of the bottom third (coolest part) of the winding, where most of the water is located. From this temperature, move up vertically to the curve. From this point on the curve, move horizontally to the left and find the Myers Multiplier number. Take this number and multiply the ppm of water shown on the DGA. The result is percent M/DW in the upper part of the insulation. This method gives less amount of water than the General Electric nomograph on the following page.
This nomograph, published by General Electric in 1974 (figure 23), gives the percent saturation of oil and percent M/DW of insulation. Use the nomograph to check yourself after you have completed the method illustrated in figure 22. The nomograph in figure 23 will show more moisture than the IEEE method.
The curves in figure 23 are useful to help understand relationships between temperature, percent saturation of the oil, and percent M/DW of the insulation. For example, pick a point on the ppm water line, say 10 ppm. Place a straight edge on that point and pick a point on the temperature line, say 45 °C. Read the percent saturation and percent M/DW on the center lines. In this example, percent saturation is about 6.5% and the % M/DW is about 1.5%. Now, hold the 10 ppm point and move the sample temperature upward (cooler), and notice how quickly the moisture numbers increase. For example, use 20 °C and read the % saturation of oil at about 18.5% and the % M/DW at about 3.75%. The cooler the oil, the higher the moisture percentage for the same ppm of water in the oil.
Do not make a decision on dryout based on only one DGA and one calculation; it should be based on trends over a period of time. Take additional samples and send them for analysis. Take extra care to make sure the oil temperature is correct. You can see by the nomograph that moisture content varies dramatically with temperature. Take extra care that the sample is not exposed to air. If after using the more conservative IEEE method and again subsequent samples show M/DW is 2.5% or more and the oil is 30% saturated or more, the transformer should be dried as soon as possible. Check the nomograph and curves above to determine the percent saturation of the oil. The insulation is degrading much faster than normal due to the high moisture content. Drying can be an expensive process; it is prudent to consult with others before making a final decision to do dryout. However, it is much less expensive to perform a dryout than to allow a transformer to degrade faster than normal, substantially shortening transformer life.
Tuesday, 2 June 2015
4.4.5 Rogers Ratio Method of DGA. Rogers Ratio Method of DGA [18] is an additional tool that may be used to look at dissolved gases in transformer oil. Rogers Ratio Method compares quantities of different key gases by dividing one into the other. This gives a ratio of the amount of one key gas to another. By looking at the Gas Generation Chart (figure 18), you can see that, at certain temperatures, one gas will be generated more than another gas. Rogers used these relationships and determined that if a certain ratio existed, then a specific temperature had been reached. By comparing a large number of transformers with similar gas ratios and data found when the transformers were examined, Rogers could then say that certain faults were present. Like the Key Gas Analysis above, this method is not a “sure thing” and is only an additional tool to use in analyzing transformer problems. Rogers Ratio Method, using three-key gas ratios, is based on earlier work by Doerneburg, who used five-key gas ratios. Ratio methods are only valid if a significant amount of the gases used in the ratio is present. A good rule is: Never make a decision based only on a ratio if either of the two gases used in a ratio is less than 10 times the amount the gas chromatograph can detect (12). (Ten times the individual gas detection limits are shown in table 9 and below.) This rule makes sure that instrument inaccuracies have little effect on the ratios. If either of the gases are lower than 10 times the detection limit, you most likely do not have the particular problem that this ratio deals with anyway. If the gases are not at least 10 times these limits, this does not mean you cannot use the Rogers Ratios; it means that the results are not as certain as if the gases were at least at these levels. This is another reminder that DGAs are not an exact science and there is no “one best easy way” to analyze transformer problems. Approximate detection limits are as follows, depending on the lab and equipment:
Dissolved Gas Analysis Detection Limits.
Hydrogen (H2) about 5 ppm Methane (CH4) about 1 ppm Acetylene (C2H2) about 1 to 2 ppm Ethylene (C2H4) about 1 ppm Ethane (C2H6) about 1 ppm Carbon monoxide (CO) and carbon cioxide (CO2) about 25 ppm Oxygen (O2 ) and nitrogen (N2) about 50 ppm
When a fault occurs inside a transformer, there is no problem with minium gas amounts at which the ratio are valid. There will be more than enough gas present.
If a transformer has been operating normally for some time and a DGA shows a sudden increase in the amount of gas, the first thing to do is take a second sample to verify there is a problem. Oil samples are easily contaminated during sampling or at the lab. If the next DGA shows gases to be more in line with prior DGAs, the earlier oil sample was contaminated, and there is no further cause for concern. If the second sample also shows increases in gases, the problem is real. To apply Ratio Methods, it helps to subtract gases that were present prior to sudden gas increases. This takes out gases that have been generated up to this point due to normal aging and from prior problems. This is especially true for ratios using H 2 and the cellulose insulation gases CO and CO2 [12]. These are generated by normal aging.
Rogers Ratio Method Uses the Following Three Ratios.
C2H2/C2H4, CH4/H2, C2H4/C2H6
These ratios and the resultant fault indications are based on large numbers of DGAs and transformer failures and what was discovered after the failures.
There are other ratio methods, but only the Rogers Ratio Method will be discussed since it is the one most commonly used. The method description is paraphrased from Rogers’ original paper [18] and from IEC 60599 [12].
Caution: Rogers Ratio Method is for fault analyzing, not for fault detection. You must have already decided that you have a problem from the total amount of gas (using IEEE limits) or increased gas generation rates. Rogers Ratios will only give you an indication of what the problem is; it cannot tell you whether or not you have a problem. If you already suspect a problem based on total combustible gas levels or increased rate-of-generation, then you will normally already have enough gas for this method to work. A good system to determine whether you have a problem is to use table 5 in the Key Gas Method. If two or more of the key gases are in condition two and the gas generation is at least 10% per month of the L1 limit, you have a problem. Also, for the diagnosis to be valid, gases used in ratios should be at least 10 times the detection limits given earlier. The more gas you have, the more likely the Rogers Ratio Method will give a valid diagnosis. The reverse is also true; the less gas you have, the less likely the diagnosis will be valid. If a gas used in the denominator of any ratio is zero, or is shown in the DGA as not detected (ND), use the detection limit of that particular gas as the denominator. This gives a reasonable ratio to use in diagnostic table 9. Zero codes mean that you do not have a problem in this area.
Table 9.—Rogers Ratios for Key Gases
Code range of ratios C2H2 CH4 C2H4 Detection limits and 10 x detection limits are shown below: C2H4 H2 C2H6 C2H2 1 ppm 10 ppm C2H4 1 ppm 10 ppm CH4 1 ppm 10 ppm<0.1 0 1 0 0.1-1 1 0 0 H2 5 ppm 50 ppm 1-3 1 2 1 C2H6 1 ppm 10 ppm >3 2 2 2
Case Fault Type Problems Found
0 No fault 0 0 0 Normal aging
1 Low energy partial 1 1 0 Electric discharges in bubbles, caused by insulation voids or super discharge gas saturation in oil or cavitation (from pumps) or high moisture in oil (water vapor bubbles).
2 High energy 1 1 0 Same as above but leading to tracking or perforation of solid partial discharge cellulose insulation by sparking, or arcing; this generally produces CO and CO2.
3 Low energy 1-2 0 1-2 Continuous sparking in oil between bad connections of different discharges, potential or to floating potential (poorly grounded shield etc); sparking, arcing breakdown of oil dielectric between solid insulation materials.
4 High energy discharges, arcing
1 0 2 Discharges (arcing ) with power follow through; arcing breakdown of oil between windings or coils, or between coils and ground, or load tap changer arcing across the contacts during switching with the oil leaking into the main tank.
5 Thermal fault less 0 0 1 Insulated conductor overheating; this generally produces CO and than 150 °C CO2 because this type of fault generally involves cellulose (see note 2) insulation.
6 Thermal fault temp. range 150-300 °C (see note 3)
0 2 0 Spot overheating in the core due to flux concentrations. Items below are in order of increasing temperatures of hot spots. Small hot spots in core. Shorted laminations in core. Overheating of copper conductor from eddy currents. Bad connection on winding to incoming lead, or bad contacts on load or no-load tap changer. Circulating currents in core; this could be an extra core ground, (circulating currents in the tank and core); this could also mean stray flux in the tank.
These problems may involve cellulose insulation which will produce CO and CO2.
7 Thermal fault temp. range 300-700 °C
8 Thermal fault temp. range over 700 °C (see note 4)
Notes: 1. There will be a tendency for ratio C2H2 /C2H4 to rise from 0.1 to above 3 and the ratio C2H4 /C2H6 to rise from 1-3 to above 3 as the spark increases in intensity. The code at the beginning stage will then be 1 0 1. 2. These gases come mainly from the decomposition of the cellulose which explains the zeros in this code. 3. This fault condition is normally indicated by increasing gas concentrations. CH4 /H2 is normally about 1, the actual value above or below 1, is dependent on many factors such as the oil preservation system (conservator, N2 blanket, etc.), the oil temperature, and oil quality. 4. Increasing values of C2H2 (more than trace amounts), generally indicates a hot spot higher than 700 °C. This generally indicates arcing in the transformer. If acetylene is increasing and especially if the generation rate is increasing, the transformer should be de- energized, further operation is extremely hazardous.
General Remarks:
1. Values quoted for ratios should be regarded as typical (not absolute). This means that the ratio numbers are not “carved in stone”; there may be transformers with the same problems whose ratio numbers fall outside the ratios shown at the top of the table.
2. Combinations of ratios not included in the above codes may occur in the field. If this occurs, the Rogers Ratio Method will not work for analyzing these cases.
3. Transformers with on-load tap changers may indicate faults of code type 2 0 2 or 1 0 2 depending on the amount of oil interchange between the tap changer tank and the main tank.
Example 1
Example of a Reclamation transformer DGA:
Rogers Ratio Analysis
Hydrogen (H2) Methane (CH4)
9 ppm 60 C2H2/C2H4 = 3/368 = 0.00815
Code 0
Ethane (C2H6) Ethylene (C2H4)
53 368 CH4/H2 = 60/9 = 6.7 2 Acetylene (C2H2) 3 C2H4/C2H6 = 368/53 = 6.9 2 Carbon Monoxide (CO) Carbon Dioxide (CO2) Nitrogen (N2) Oxygen (O2) 7 361 86,027 1,177 This code combination is Case 8 in table 4, which indicates this transformer has a thermal fault hotter than 700 °C. TDCG 500
Ethylene and ethane are sometimes called “hot metal gases.” Notice this fault does not involve paper insulation, because CO is very low. H2 and C2 H2 are both less than 10 times the detection limit. This means the diagnosis does not have a 100% confidence level of being correct. However, due to the high ethylene, the fault is probably a bad connection where an incoming lead is bolted to a winding lead, or perhaps bad tap changer contacts, or additional core ground (large circulating currents in the tank and core). See the two bottom problems on table 10 later in this chapter. This example was chosen to show a transformer that was not a “clear cut” diagnosis. Engineering judgment is always required.
A small quantity of acetylene is present, just above the detection limit of 1 ppm. This is not high energy arcing due to the small amount; it has more likely been produced by a one-time nearby lightning strike or a voltage surge.
Example 2
Latest DGA Prior DGA No. 2 Prior DGA No. 1
Hydrogen (H2) 26 ppm 27 17
Methane (CH4) 170 164 157
Ethane (C2H6) 278 278 156
Ethylene (C2H4) 25 4 17
Acetylene (C2H2) 2 0 0
Carbon Monoxide (CO) 92 90 96
Carbon Dioxide (CO2) 3,125 2,331 2,476
Nitrogen (N2) 67,175 72,237 62,641
Oxygen (O2) 608 1,984 440
Rogers Ratio Analysis Based on Latest DGA:
Codes
C2H2/C2H4 = 2/25 = 0.080 0
CH4/H2 = 170/26 = 6.54 2
C2H4/C2H6 = 25/278 = 0.09 0
Notice that methane is increasing slowly, but ethane had a large increase between samples 1 and 2 but did not increase between samples 2 and 3. Note that two key gases (CH2 and C2H6) are above IEEE Condition 1 in table 5, so the Rogers Ratio Method is valid. By referring to table 9, this combination of codes is Case 6, which indicates the transformer has a thermal fault in the temperature range of 150 °C to 300 °C.
Life history of the transformer must be examined carefully. It is, again, very important to keep accurate records of every transformer. This information is invaluable when it becomes necessary to do an evaluation.
The transformer in this example is one of three sister transformers that have had increased cooling installed and are running higher loads due to a generator upgrade several years ago. Transformer sound level (hum) is markedly higher than for the two sister transformers. The unit breaker experienced a fault some years ago, which placed high mechanical stresses on the transformer. This generally means loose windings, which can generate gas due to friction (called a thermal fault) by Rogers Ratios. Comparison with sister units reveals almost triple the ethane as the other two, and it is above the IEEE Condition 4.Gases are increasing slowly; there has been no sudden rate increase in combustible gas production. Notice the large increase in O2 and N2 between the first and second DGA and the large decrease between the second and third. This probably means that the oil sample was exposed to air (atmosphere) and that these two gases are inaccurate in the middle sample.
Carbon Dioxide Carbon Monoxide Ratio. This ratio is not included in the Rogers Ratio Method of analysis. However, it is useful to determine if a fault is affecting the cellulose insulation. This ratio is included in transformer oil analyzing software programs such as Delta X Research Transformer Oil Analyst. This analysis is available from the TSC at D-8440 and D-8450 in Denver.
Formation of CO2 and CO from the degradation of oil impregnated paper increases rapidly with temperature. CO2 /CO ratios less than three are generally considered an indication of probable paper involvement in an electrical fault (arcing or sparking), along with some carbonization of paper. Normal CO2 /CO ratios are typically around seven. Ratios above 10 generally indicate a thermal fault with the involvement of cellulose. This is only true if the CO2 came from within the transformer (no leaks), and these ratios are only meaningful if there is a significant amount of both gases. Caution must be employed because oil degradation also produces these gases, and CO2 can also be dissolved in the oil from atmospheric leaks. The oil sample can also pick up CO 2 and O2 if it is exposed to air during sampling or handling at the lab. If a fault is suspected, look carefully to see if CO is increasing. If CO is increasing around 70 ppm or more per month (generation limit from IEC 60599), there is probably a fault. It is a good idea to subtract the amount of CO and CO2 shown before the increase in CO and CO2 began, so that only gases caused by the present fault are used in the ratio. This will eliminate CO and CO2 generated by normal aging and other sources. When excessive cellulose degradation is suspected (CO2 /CO ratios less than 3, or greater than 10), it may be advisable to ask for a furan analysis with the next DGA. This will give an indication of useful life left in the paper insulation [12].
You cannot de-energize a transformer based on furan analysis alone. All this test does is give an indication of the health of the paper; it is not a sure thing. But furan analysis is recommended by many experts to give an indication of remaining life when the CO2 /CO ratio is less than 3 or greater than 10. Some oil laboratories do this test on a routine basis, and some charge extra for it.
Table 10 is adapted from IEC 60599 Appendix A.1.1 [12]. Some of the wording has been changed to reflect American language usage rather than European.
4.5 Moisture Problems
Moisture, especially in the presence of oxygen, is extremely hazardous to transformer insulation. Each DGA and Doble test result should be examined carefully to see if water is increasing and to determine the moisture by dry weight (M/DW) or percent saturation that is in the paper insulation. When 2% M/DW is reached, plans should be made for a dry out. Never allow the M/DW to go above 2.5% in the paper or 30% oil saturation without drying out the transformer. Each time the moisture is doubled in a transformer, the life of the insulation is cut by one-half. Keep in mind that the life of the transformer is the life of the paper, and the purpose of the paper is to keep out moisture and oxygen. For service-aged transformers rated less than 69 kV, results of up to 35 ppm are considered acceptable. For 69 kV through 288 kV, the DGA test result of 25 ppm is considered acceptable. For greater than 288 kV, moisture should not exceed 20 ppm. However, the use of absolute values for water does not always guarantee safe conditions, and the percent by dry weight should be determined. See table 12, “Doble Limits for In-Service Oils,” in section 4.6.5. If values are higher, the oil should be processed. If the transformer is kept as dry and free of oxygen as possible, transformer life will be extended.
Reclamation specifies that manufacturers dry new transformers to no more than 0.5% M/DW during commissioning. In a transformer having 10,000 pounds of paper insulation, this means that 10,000 x 0.005 = 50 pounds of water (about 6 gallons) is in the paper. This is not enough moisture to be detrimental to electrical integrity. When the transformer is new, this water is distributed equally through the transformer. It is extremely important to remove as much water as possible.
Table 10.—Typical Faults in Power Transformers [12]
Fault Examples
Partial discharges Discharges in gas-filled cavities in insulation, resulting from incomplete impregnation, high moisture in paper, gas in oil supersaturation or cavitation, (gas bubbles in oil) leading to X wax formation on paper.
Discharges of low energy
Sparking or arcing between bad connections of different floating potential, from shielding rings, toroids, adjacent discs or conductors of different windings, broken brazing, closed loops in the core. Additional core grounds. Discharges between clamping parts, bushing and tank, high voltage and ground, within windings. Tracking in wood blocks, glue of insulating beam, winding spacers. Dielectric breakdown of oil, load tap changer breaking contact.
Discharges of high energy
Flash-over, tracking or arcing of high local energy or with power follow-through. Short circuits between low voltage and ground, connectors, windings, bushings, and tank, windings and core, copper bus and tank, in oil duct. Closed loops between two adjacent conductors around the main magnetic flux, insulated bolts of core, metal rings holding core legs.
Overheating less than 300 °C
Overloading the transformer in emergency situations. Blocked or restricted oil flow in windings. Other cooling problem, pumps valves, etc. See the “Cooling” section in this document. Stray flux in damping beams of yoke.
Overheating
300 to 700 °C
Defective contacts at bolted connections (especially busbar), contacts within tap changer, connections between cable and draw-rod of bushings. Circulating currents between yoke clamps and bolts, clamps and laminations, in ground wiring, bad welds or clamps in magnetic shields. Abraded insulation between adjacent parallel conductors in windings.
Overheating over 700 °C
Large circulating currents in tank and core. Minor currents in tank walls created by high uncompensated magnetic field. Shorted core laminations.
Notes: 1. X wax formation comes from Paraffinic oils (paraffin based). These are not used in transformers at present in the United States but are predominate in Europe. 2. The last overheating problem in the table says �over 700 °C.” Recent laboratory discoveries have found that acetylene can be produced in trace amounts at 500 °C, which is not reflected in this table. We have several transformers that show trace amounts of acetylene that are probably not active arcing but are the result of high- temperature thermal faults as in the example. It may also be the result of one arc, due to a nearby lightning strike or voltage surge. 3. A bad connection at the bottom of a bushing can be confirmed by comparing infrared scans of the top of the bushing with a sister bushing. When loaded, heat from a poor connection at the bottom will migrate to the top of the bushing, which will display a markedly higher temperature. If the top connection is checked and found tight, the problem is probably a bad connection at the bottom of the bushing.
When the transformer is energized, water begins to migrate to the coolest part of the transformer and the site of the greatest electrical stress. This location is normally the insulation in the lower one-third of the winding [5]. Paper insulation has a much greater affinity for water than does the oil. The water will distribute itself unequally, with much more water being in the paper than in the oil. The paper will partially dry the oil by absorbing water out of the oil. Temperature is also a big factor in how the water distributes itself between the oil and paper. See table 11 below for comparison.
Table 11.—Comparison of Water Distribution in Oil and Paper [5]
Temperature Water Water (degrees C) in Oil in Paper
20° 1 3,000 times what is in the oil
40° 1 1,000 times what is in the oil
60° 1 300 times what is in the oil
The table above shows the tremendous attraction that paper insulation has for water. The ppm of water in oil shown in the DGA is only a small part of the water in the transformer. It is important that, when an oil sample is taken, you record the oil temperature from the top oil temperature gauge.
Some laboratories give percent M/DW of the insulation in the DGA. Others give percent oil saturation, and some give only the ppm of water in the oil. If you have an accurate temperature of the oil and the ppm of water, the Nomograph will give percent M/DW of the insulation and the percent oil saturation.
Where does the water come from? Moisture can be in the insulation when it is delivered from the factory. If the transformer is opened for inspection, the insulation can absorb moisture from the atmosphere. If there is a leak, moisture can enter in the form of water or humidity in air. Moisture is also formed by the degradation of insulation as the transformer ages. Most water penetration is flow of wet air or rain water through poor gasket seals due to pressure difference caused by transformer cooling. During rain or snow, if a transformer is removed from service, some transformer designs cool rapidly and the pressure inside drops. The most common moisture ingress points are gaskets between bushing bottoms and the transformer top and the pressure relief device gasket. Small oil leaks, especially in the oil cooling piping, will also allow moisture ingress. With rapid cooling and the resultant pressure drop, relatively large amounts of water and water vapor can be pumped into the transformer in a short time. It is important to repair small oil leaks; the small amount of visible oil is not important in itself, but it also indicates a point where moisture will enter .
It is critical for life extension to keep transformers as dry and as free of oxygen as possible. Moisture and oxygen cause the paper insulation to decay much faster than normal and form acids, sludge, and more moisture. Sludge settles on winding and inside the structure, causing transformer cooling to be less efficient, and slowly over time temperature rises. (This was discussed earlier in “3. Transformer Cooling Methods.”) Acids cause an increase in the rate of decay, which forms more acid, sludge, and moisture at a faster rate [20]. This is a vicious cycle of increasing speed forming more acid and causing more decay. The answer is to keep the transformer as dry as possible and as free of oxygen as possible. In addition, oxygen inhibitor should be watched in the DGA testing. The transformer oil should be dried when moisture reaches the values according to table 12. Inhibitor should be added (0.3% by weight ASTM D-3787) when the oil is processed.
Water can exist in a transformer in five forms.
1. Free water, at the bottom of the tank.
2. Ice at the tank bottom (if the oil specific gravity is greater than 0.9, ice can float).
3. Water can be in the form of a water/oil emulsion.
4. Water can be dissolved in the oil and is given in ppm in the DGA.
5. Water can be in the form of humidity if transformers have an inert gas blanket.
Free water causes few problems with dielectric strength of oil; however, it should be drained as soon as possible. Having a water- oil interface allows oil to dissolve water and transport it to the insulation. Problems with moisture in insulation were discussed above. If the transformer is out of service in winter, water can freeze. If oil specific gravity is greater than 0.9 (ice specific gravity), ice will float. This can cause transformer failure if the transformer is energized with floating ice inside. This is one reason that DGA laboratories test specific gravity of transformer oil.
The amount of moisture that can be dissolved in oil increases with temperature. (See figure 19.) This is why hot oil is used to dry out a transformer. A water/oil emulsion can be formed by purifying oil at Figure 19.—Maximum Amount of Water too high temperature. When the oil Dissolved in Mineral Oil Versus Temperature cools, dissolved moisture forms an emulsion [20]. A water/oil emulsion causes drastic reduction in dielectric strength.
How much moisture in insulation is too much? When the insulation gets to 2.5% M/DW or 30% oil saturation (given on some DGAs), the transformer should have a dry out with vacuum if the tank is rated for vacuum. If the transformer is old, pulling a vacuum can do more harm than good. In this case, it is better to do round-the-clock re circulation with a Bowser drying the oil as much as possible, which will pull water out of the paper. At 2.5% M/DW, the paper insulation is degrading much faster than normal [5]. As the paper is degraded, more water is produced from the decay products, and the transformer becomes even wetter and decays even faster. When a transformer gets above 4% M/DW, it is in danger of flash-over if the temperature rises to 90 °C.
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