DGA for Transformer

Is this a homework question? It looks like it

If this isn't a homework question I am a little more worried about the calibre of our new distribution engineers.

There is not enough information supplied for any meaningful comments.

_{Jack - Actually works in the power industry.}

Based on evaluation metrics from ANSI/IEEE C57.104, I would give the following evaluations:

TX#1 - Gases are normal; no unusual conditions based on the data provided.

TX#2 - Ethane gas usually indicates localized overheating under the oil. These values are high enough to note, but not severe. It could be a bolted conductor connection (at a bushing, etc.) or a contact in the NLTC (No-Load Tap Changer) that hasn't made good contact pressure. Re-test in 3-6 months to see if it increases more, and investigate if it does. This will require internal inspection - what are ratings of this unit?

TX#3 - The only gas of concern here is the level of H2, which is somewhat high. That often indicates corona discharge under the oil. I would like to see historic data to know if it has been increasing, but if it is stable, then no major concerns. Another possible cause is if someone used a galvanized component (bolts, etc.) inside the TX - sometimes water in the oil will be catalyzed by the zinc to split into H2 and O2; that's not so common,but I have heard of it happening.

Didn't whoever analyzed the oil give you an evaluation, or are you trying to get a second opinion?

Thanks for your answer

First i will start from last.

are you trying to get a second opinion?

Yes this is my goal when i put this question.

TX#1

I agree with you

TX#2

I agree with you

But what is the impact when C2H6 is kept without any oil treatment because to reach high level need years as per the history.

Tx#3

Also test for Passivator and corrosive sulphur at oil was done and found OK.

Electrical tests will be done for the transformer (is it will show something or need partial discharge test.

Regarding TX#2, if Ethane is the only significant contributor to the total combustible gas (TCG), then I wouldn't worry a lot. Although it is increasing some, the rate is not severe. I would watch it through a few more test cycles, unless it starts to increase more rapidly. You can safely operate with several thousand ppm of combustible gases (except if it's acetylene) in the oil with little concern.

For TX#3, the inhibitor and corrosive sulfur tests only tell you about the quality of the oil, not what is happening in the transformer. A partial discharge test could show you if there is corona/discharge under the oil, or it may require an internal inspection to show the point of generation of the hydrogen (if it is a localized hotspot). At the level you have (~400ppm), I also would not be too worried yet. Since you didn't give historical info, I can't comment on a trend. If it isn't increasing, or not quickly, then I would consider just monitoring (annual or 6-month interval) testing until you see a change in rate.

Be wary of oil testing companies that try to sell vacuum reprocessing services to remove the gases from the oil. Yes the gases are removed, but it does not solve the problem that caused the gases, and it destroys your baseline values for trending. Instead, find a qualified service company that will help you investigate and correct the cause of the gases, then reprocess after the problem is fixed.