Transformer Oil Tests

Transformer Oil Tests That Should Be Completed Annually with the Dissolved Gas Analysis

Dielectric Strength

This test measures the voltage where 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 D-1816. Using the D-1816 test, the minimum oil breakdown voltage is 20 kV for transformers rated less than 288 kV and 25 kV for transformers 287.5 kV and above. 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. The dielectric strength test also reveals nothing about acids and sludge. The tests explained below are much more important.

Interfacial Tension

This test (ASTM D-791-91), 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 ºC. The oil should float because its specific gravity is less than that of water (specific gravity of water 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. As the oil ages, it is contaminated by tiny particles (oxidation products) of the oil and paper insulation. Particles on top of the water extend across the water/oil interface line that weaken the surface tension between the two liquids. Particles in oil weaken interfacial tension and 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 that 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. If oil is not reclaimed, sludge will settle on windings, insulation, cooling surfaces, etc., and cause loading and cooling problems, as discussed earlier. This will greatly shorten transformer life. A definite relationship exists between the acid number, the IFT, and the number of years in service. The accompanying curve (Picture 1) 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 for both the IFT and the acid number.

Picture 1: Interfacial Tension, Acid Number, Years in Service

Acid Number

Acid 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 begins 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 potassium hydroxide per gram (KOH/gm). As with all others, this decision must not be based on one DGA test, but watch for a rising trend in the acid number each year. Plan ahead and begin budget planning before the acid number reaches 0.20.

Test for Oxygen Inhibitor

Previously, the need to keep the transformer dry and O2 free was emphasized. Moisture is destructive to cellulose, and even more so in the 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 that 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 similar to 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. Replacement of the inhibitor also generally requires treatment of the oil. The ideal amount of DBPC is 0.3% by total weight of the oil (shown on the transformer nameplate).
Test the inhibitor content 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. For example, 5,000 pounds—so 5,000 pounds x 0.002 = 10 pounds of DBPC needs to be added. Adding a little too much DBPC does not hurt the oil. Dissolve 10 pounds of DBPC in the transformer oil that you have heated to the same temperature as the oil inside the transformer. It may take experimenting some 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’s instruction manual for adding oil. In either case, do not neglect this important maintenance function. It is critical to transformer insulation to have the proper amount of oxygen inhibitor.

Power Factor

Power factor indicates the dielectric loss (leakage current) of the oil. This test may be completed by the DGA laboratories. It may also be completed 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 ºC and 100 ºC. Doble information indicates that the inservice limit for power factor is less than 0.5% at 25 ºC. 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 ºC, the oil may cause failure of the transformer, so replacement or reclaiming is required. Above 2%, oil should be removed from service and replaced because equipment failure is imminent. The oil cannot be reclaimed.

Oxygen

Oxygen must be watched closely in DGA tests. Many experts and organizations, including EPRI, believe that oxygen levels in the oil above 2,000 ppm greatly accelerate paper deterioration. This becomes even more critical with moisture above safe levels. Under the same temperature conditions, cellulose insulation in low oxygen oil will last 10 times longer than insulation in high oxygen oil. It is recommended that if oxygen reaches 10,000 ppm in the DGA, the oil should be de-gassed and new oxygen inhibitor installed. High atmospheric gases (O2 and N2) normally mean that a leak has developed in a bladder or diaphragm in the conservator. If there is no conservator and pressurized nitrogen is on top of the oil, expect to see high nitrogen but not high oxygen. Oxygen comes only from leaks and from deteriorating insulation.

Furans

When cellulose insulation decomposes due to overheating, organic compounds, in addition to CO2 and CO, are released and dissolved in the oil. These chemical compounds are known as furanic compounds or furans. The most important one, for our purposes, is 2-furfuraldehyde. When DGAs are required, always request that furans testing be completed by the laboratory to check for paper deterioration. In healthy transformers, there are no detectable furans in the oil, or they are less than 100 parts per billion (ppb). In cases where significant damage to paper insulation from heat has occurred, furan levels may be at least 100 ppb and up to 70,000 ppb. Furanic content in the oil is especially helpful in estimating remaining life in the paper insulation, particularly if several prior tests can be compared and trends established.
Use the furan numbers in table shown on Picture 2 for assessment. Do not base any evaluation on only one test, use several DGAs over a period of time to develop trending. The first column in table on Picture 2 is used for transformers with non-thermally upgraded paper, and the second column is for transformers with thermally upgraded paper.

Picture 2: Furans, DP, Percent of Life Used of Paper Insulation


Testing is completed for five different furans which are caused by different problems. The five furans and their most common causes are listed below:

♦ 5H2F (5-hydroxymethyl-2-furaldehyde) caused by oxidation (aging and heating) of the paper;
♦ 2FOL (2-furfurol) caused by high moisture in the paper;
♦ 2FAL (2-furaldehyde) caused by overheating;
♦ 2ACF (2-acetylfuran) caused by lightning (rarely found in DGA);
♦ 5M2F (5-methyl-2-furaldehyde) caused by local severe overheating (hotspot);

Doble inservice limits are reproduced below to support the above recommended guidelines (table shown on Picture 3). Additional guidelines given in table shown on Picture 4 are useful.

Picture 3: Doble Limits for Inservice Oils


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.
3
ND = None detectable.
These recommended limits for inservice 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.

Picture 4: Additional Guidelines for Inservice Oils


1 
When an oil is allowed to sludge in service, special treatment may be required to clean the core, coil, and tank.