Interpretation of DGA Results

[seanmcc]

We have a transformer equiped with a HYDRAN Dissolved Gas Analyser, the unit displays the total of all dissolved gases in the oil in ppm. This level has been steadily rising. We have been sending regular oil samples for lab analysis. The results have been inconclusive. The results show a steady increase in Hydrogen and Carbon Dioxide with a steady decrease in oxygen. The so called nasty gases Acetylene, Ethylene and Methane have showed only fractional change (measurement error). Any thoughts as to possible causes?

Many Thanks, Sean

 

[electricpete]

Here's my general idea from working with transformers several years ago.

CO2 indicates solid insulation overheating. Worse when accompanied by CO.

H2 can come from a variety of things. Normally if low-temperature hot metal it would be accompanied by Methane (then ethylene at higher temperatures). That seems to rule out metal. I think that partial discharge (without arcing) can produce hydrogen alone.

I'm sure there are many more possibilities. Maybe ratio method would cover this case?

 

[ausphil]

Check IEC 60599:1999, its cumbersome but gives reasonable guidelines. If gas levels are rising but concentrations are under the specified levels, keep an eye on it, but don't start to panic until the levels get up. Don't try ratio analysis until the gases are over these levels either. IEC60599 gives estimations of gas increases of over 10% per month as defining the fault as active. Around the 50% per week figure is serious.

Things to take into account - Tx age, oil/paper ratio, free breathing/nitrogen bags etc. Furan and DP test if its an old Tx can determine electrical age of paper if worried.

I'll go along with Electricpete on the suggested causes, and also add that H2 can be produced by coatings and reactions of the oil with stainless steel.

 

[hy]

I would add the oil quantity, kVA or MVA of the Tx.
We have some similar problems in new 83.33MVA autotransformers, que maker claims its a gas evolving problem of the oil, but no paper backs it.

Our opinion and is backed by other external opinions is that may be a design problem. As only H2 and CO2 is present, low furan content, the only thing it could be is a "hot area" of bad refrigeration (intra-winding or not).

Is the Tx old, and this "began" to happen now ?

The more the questions and answers, the better the diagnostic process.

 

[tgott]

Unfortunately, there is no universally accepted means for interpreting DGA. Electricpete is correct in what H2 and CO2 typically indicate. I'd suggest reading as many papers on the subject as you can and contacting Doble Engineering. Also reference IEEE C57.104-1991, "IEEE Guide for the Interpretation of Gases Generated in Oil-Immersed Transformers". GE has a paper GET-6552 "Power Transformer Dissolved Gas Analysis". Very good paper by Joseph B. DiGiorgio, Ph.D. can be found at

http://www.nttworldwide.com/tech2102.htm

http://www.doble.com/

http://www.usbr.gov/power/data/fist/fist3~30/3~30_4~4.htm

 

[electricpete]

Good comments by all. I especially liked the links.

Maybe a stupid question, but here goes.... Have you checked the moisture levels?

(high moisture levels can be a contributor to insulation decomposition even at normal temperatures and a contributor to partial discharge).

 

[cshro]

Yes is a good idea to see the moisture content and the acidity level, the CO2 increase look like accelerate celulose aging because a celulose overheating is folow by CO increase. Tray to see the CO content and it is biger that 300-350 ppm do CO2/CO ratio, if it is lower that 3 and biger that 10 is posible to have a celulose overheating.
H2 increase usualy indicate a partial dicharge but try see the hidrocarbons load dependence. View the transformer condition (tgott link (3) table 4 and 5, I know it and is a good documentation)
Look this folowin link (I don't trust it very much but you can try)

http://www.nttworldwide.com/diag.htm