Doble Tan Delta Value High (1.2%) Solution

DRYING OUT

Since you are unlikely to be able to send the transformer for factory drying of the windings, the best field solution is vacuum / hot oil processing. The oil is pumped out of the unit while still warm from operation, into a temporary holding tank or tanker truck. Vacuum is drawn on the transformer to draw as much moisture as possible out of the winding insulation. The vacuum is held, and the oil is heated and pumped back into the transformer while under vacuum, thus drawing additional moisture out of the oil.

After processing, allow the oil to set for 24 hours, then repeat the Doble tests to get a new baseline for future comparison. Also take oil samples and do a complete oil quality analysis and dissoved combustible gas analysis for baseline.

Thank u verymuch for your suggestion. Kindly clarify how much vaccum can be created inside the transformer. The old oil can be used again into the transformer or with new oil.

Do not do anything - without additional testing and analysis.

What is the age and voltage of the HV winding ? . .110, 230, 400kV??

What was the DF of the insulation in the previous test - 6 - 12 months back?

Send a sample of the insulating oil for analysis . . . see what the moisture and gas content is.

Report this information for further analysis . . .

Thank u.

The transformer age is 6 years. Voltage rating is 230/11.5KV. Tan Delta value of previous test on 2010 is 0.89%. Oil Quality and DGA analysis are within limit and shows no abnormality.

There must be a very measurable change in moisture and gas content between a transformer @ 0.89% DF and then @ 1.2% DF, . . . unless some of the readings are questionable . . . either DF & moisture content.

"Within limits" and "no abnormality" carry absolutely no information. What was the moisture content @2010 . . and now? What were the predominant gases in 2010 and now?

The vacuum is not drawn on the transformer, . . . but only within the processing equipment attached to the transformer.

Kindly find the values of water content and gases.

Water content @ 2010 = 9 ppm and @ 2011 = 10 ppm.

Gases:

Hydrogen =@ 2010 3 ppm , @2011 4ppm

Methane = @2010 1ppm , @2011 1 ppm

Ethylene = @2010 0 ppm , @2011 0 ppm

Acetylene = @2010 0 ppm , @2011 0 ppm

Ethane = @2010 0 ppm , @2011 0 ppm

CO = @2010 30 ppm , @2011 34 ppm

CO2 = @2010 345 ppm, @2011 350 ppm

These look like ideal numbers. Nearly a new transformer. Assume gases in 2011 are nearly same as 2010. ?

This means someone is not telling the truth . . . The C&DF people are reading high . . . or the chemists are allowing the gases and moisture to escape.

No use upgrading the oil . . . there is not water to be removed . . .

Do another round of tests? I would start with C&DF.

Just because the moisture content of the oil is low does not mean that the transformer's winding insulation (paper) does not have a significant amount of water in it. The paper can hold 10x or more as much water as oil can. There is always an equilibrium between the concentration of water between the oil and paper, which varies primarily based on the temperature of the transformer windings and oil.

If the Doble PF is high, it means that the insulation is allowing leakage currents. Water is usually the prime suspect. 1.2% is not critically high, but it is higher than desired for a transformer of its age and size.

Yes, you can pull a vacuum on the transformer tank if you drain all the oil out of it first. The vacuum will draw at least some of the water out of the paper insulation, then refilling with hot oil under vacuum will remove as much water from the oil as possible while it goes in. That is how a new transformer is filled in the field. \

Significant dehydration does not occur until a vacuum level of 1000 microns (= 1 TORR = 1 mm Hg) is achieved. 1000 microns = 29.881" Hg vacuum. It will take several hours to draw down the transformer internal pressure to that vacuum, but as it is achieved, the water will boil out of the insulation and be withdrawn.

However, I do agree with olehwi that it might be a good idea to do a second Doble test and compare. Did the tester apply the correct temperature correction factor for the oil temperature at the time the test was done? This can affect the results.

The gases the OP listed in his post are not a problem. Dissolved gases don't themselves contribute to the Doble test results - they will only show signs of problems such as arcing, corona, or overheating, which may or may not show themselves in other ways in the Doble tests.

Thank You very much. I follow the method suggested by you.

@ 2010 tan Delta is 0.89%, Temp. correction factor is 0.80 oil temperature at that time is about 50 C.

@ 2011 tan delta is 1.2%. correction factor is 0.90 oil temperature at that time is about 38 C.

Well now, this is additional information . . . I was of the opinion that you were quoting "corrected numbers".

Where did you get the corrections? My typical tables are CONSIDERABLY DIFFERENT.

The correction for 50C is 0.28 - to - 0.51, depending on the type of transformer, while the 38C corrections is 0.45 - to - 0.57 depending on type of transformer.

Using the above corrections . . . DF @ 20C for the 50C measurement is ~ 0.5,

while the same number for the 38C result is ~ 0.45.

Where is the problem? Where is the high DF? Where is the beef?

Doble's correction table has been used for this temperature correction. In Doble's DTA software the temperature correction are atomatically taken when entering the top oil temperature.

WELL, how interesting, . . . I am also using DOBLE tables - from the original M4000. Similar tables have been used for 40 years, or even longer.

So, the numbers you provided are already corrected by the instrument software? In that case you do not know what the actual measured numbers were, do you??

You should ask the manufacturer of the Tx for the temperature correction.

Primary and secondary voltage of the transformer may please be indicated.

It seems that transformer oil has not been filtered in last 6 years. There is sludge formation in bottom of the transformer tank as well on windings. Oil filteration

by oil filteration machine is desirable. This will minimise the water content, and condition of oil. After that again tests can be carried out.

You must be kidding! 6-year oil under normal circumstances would not have any sludge in it whatsoever. This oil does not have any moisture - 10ppm is nothing to worry about. Thus it would not have any sludge as well.

Filtration of oil does NOT remove moisture - only particular matter.

And moisture can not be drawn out of the insulation by applying even the best vacuum possible.

Thanks very much. But as per my experience sludge formation is found even

after 3 years of use.

Ingressed miosture in oil can be removed upto a certain limit by deployment of vaccum oil filteration plant fitted with heaters and thermostat. Sludge may also formed in oil even after 3to4 years of operation depending on the continuos running oil and winding temperatures, environmental condition of transformer,proper functioning of cooling system etc.