high carbon dioxide levels

[HighPotter]

We have several transformers that come back from lab testing with high carbon dioxide levels. ( over 10,000 )

Now, we have a small wager on this....
Can the "manner" in which you take the oil sample, substantialy effect the outcome of the test regarding carbon dioxide?

HP

 

[jtkirb]

the way you draw gas samples can screw up the results, but CO specificly? Don't know.

JTK

 

[leoliu]

The sampling procedure will affect the outcome a lot.There are some standards (IEC and ASME) available to tell you home to sample and treat the sample. If you follow the standards, the outcomes shouldn't be too "ridiculous".
By the way, how about other gases levels?

 

[electricpete]

You can decrease the gas levels if the container is not sealed.

10,000 ppm is 1%. I don't think you could ever get this kind of increase from mishandling unless you deliberately put a tube into the oil and blew through it for a few hours.

Exposure to sunlight...seems like I heard something about that once. Don't remember what it did.

Look at the other gases trends for clues as well (did they change abnormally during this sample).



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[amps21]

Monitor the trend, Usually CO2 is high because of insulation heating up. Normally Co2 is not a volatile gas so you cannot loose it compared to other gasses which fall under TCG category like Methane/Ethane/Ethalene/C2H2 etc. Increse in CO2 should be monitored with respective increse or decrease in CO. The standards give an acceptable ratio of CO2/CO. This could be very well contaminated containers (which posibility only u have to rule out). Trend the CO2 gas at this time, thats all i can say. What are the transformer ratings?

Thanks

 

[alehman]

If several transformers have similar high values, I would suspect the tester. Have them tested by another lab.

 

[amps21]

Alehman probably has a valid point.

 

[HighPotter]

Here is an example of the latest testing for the transformer in question (15mva 66/7kv)

hydrogen: 0
methane: 45
ethane: 17
ethylene: 2
acetylene: 0
carbon monoxide: 728
carbon dioxide: 28900


And here are the results from 6 months ago...

hydrogen: 0
methane: 55
ethane: 23
ethylene: 4
acetylene: 0
carbon monoxide: 887
carbon dioxide: 16413


and the results from 5 YEARS ago...

hydrogen : 0
methane: 44
ethane: 17
ethylene: 3
acetylene: 0
carbon monoxide: 650
carbon dioxide: 30665

The oil has not been touched in 12 years


HP

 

[electricpete]

What are typical oil temperatres on these transformers?

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[electricpete]

And what type of presevation system? (conservator, sealed nitrogen, nitrogen with regulator).

And what type cooling system?

Also what are Oxygen and moisture levels?

A few things to consider:
- long-term gas level patterns are often based on an equilibrium between addition rate and removal rate. Change in either one can affect the level. Gases partition between the N2 headspace and the oil (also sometimes the insulation to a much smaller extent). So oil ppm levels can be affected by pressure and by breathing of the headspace.
- We have GSU transformers that ran in the neighborhood of 10,000 ppm CO2, 500 ppm CO for long periods of time. That was the profiled for 10+ years. After oil drained and replaced, levels came back very quickly. Conservator types. Oil temperatres typically 70-90C. Also had air inleakage problems at the pump suctions due to dresser couplings. When we did a modification to elminate the dresser couplings, the oxygen levels dropped and the CO and CO2 dropped dramatically. Now somewhere around 1,000pm CO2 with same temperatures.

I did some round robin test comparision of 3 oil labs when I worked for a large utiltiy. The difference was typically a multiplier accross all gases based on eficiency of gas extraction.

My gut feel says this is not sample/lab error. If the O2 were high then maybe air contamination at fault, but where are you going to get that much CO2. Also consider that the CO2 shows up high two samples long apart... but apparently not on your other transformers? If so poitns to the transformer characteristics, not the sampling/analysis.

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[electricpete]

Going back to the original question - I do remember that certain gasses could be increased by exposure of the sample to sunlight. Not an issue if stored in opaque containers.

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[amps21]

Highpotter,

OK Electricpete has spelled some very valuable points. I would like to add/ask the following:

Is this a Generator transformer ? Looks like the load has been quite steady , but not sure (u need to confirm the units application.) First look @ the COx levels, suggest Not Acceptable limits. IEC team members for DGA standards researched this and suggested that generally any combined COx amount >10K should not be ignored. More over the ratio of CO2/CO, tested recently, is about 40. Anything above 10 should be relooked at. This condition has been described as Cellulose degradation. I am not saying that this is alarming, but then again...

Now there are plenty of variables (apart from type of oil breathing arrangement), Like loading patterns, any over loading, thru faults, over excitation etc.(basically looking @ the units history). It would not be a bad idea to check the core ground insulation (if possible). This is one area which can be a slow heater owing to circulating currents owing to degraded insulation and dual grounds thereof. Eventually this would burn out one or both connections involved and then the core might be at float potetial causing more problems.

Another thing would be trying to chek the rate of CO2 evolution. If this is greater than 100 PPM then it could be something that needs investigation. Some experts think that the lower level heating can be more effectively checked using FuranAnalysis of oil. But monitoring this might be
expensive.

Another thing to be noted is that the moisture levels (which could be due to the kind of breathing etc) in conjunction with heat could be a cause. Not a case for leakless sealed units though.

Well there are other things which i either dont remember right now or i might have to look into much detail.

Another suggestion is talking to the manufacturer about the COx levels.
Some unit specific questions:
Is the unit 12 years old ?
Does this unit have an Onload tap changer?
Any built in reactors or preventive autos etc.
Like Electricpete suggested other gas levels ? (N2/O2 etc.)

Thanks

 

[HighPotter]

To all that have chimed in, thanks for your thoughts. I learn so much at this site.

I do not have the data with me at home, but here are some answers off the top of my head.


The transformer is NOT a GSU

The transformer is sealed nitrogen

The transformer is approx. 24 years old

The transformer has a LTC

 

[amps21]

Highpotter,
Sorry I have only a short time for this post.

The reason i thought that this was a GSU because generally GSUs are loaded constantly @ base-top rating. In such cases it has been seen that the COx levels have been constantly increasing but the RATE was found to be within acceptable.

Now the LTC, generally if the LTC is on low side (mostly in US), there will be a series transformer (to limit the LTC contact duty) and an inductive bridging for tapchanging which would require a preventive auto. Now, i have designed only 1 of such a transformer but i remember that the preventive auto and the Series transformer has a common core ground. (Wherer is the LTC located??). Now u have 2 core grounds.

About the age. The unit being 24 years and had either an oil replacement or filtration about 12 years ago, should be checked for 1. Rate of gas generation 2. If possible FurfurAldehyde generation. (i am still guessing continous loading). REMEMBER, D.GAS.A is ALL ABOUT TREND MONITORING AND HENCE RATE OF GAS GENERATION MONITORING. FOLLOW THE IEEE STANDARD FOR OIL SAMPLING FOR GAS ANALYSIS and make sure u do not change the point of sampling for various samples. Also if possible use glass syringes where u are sure that the oil does not get contaminated from the external parameters.

I am sorry that i have only suggestions at this time and no concrete answers cause this science (gas analysis) is very complex and u are dealing with a lot of variables like oil, load, voltage, history, Design etc. The last thing i want to do is point u in a wrong direction and let u into thinking that there is a problem.

Another remote possibility is that the LTC (if in seperate compartment) is very slowly leaking oil in the main unit. But the fact that no other gasses are showing up probably rules out that possibility. Various other factors involved there which i have to post later.

Thanks

 

[alehman]

This article would seems to indicate there might be cause for concern.

http://www.usbr.gov/power/data/fist/fist3_30/fist3_30.pdf

If there were significant cellulose decomposition, I would expect to see elevated CO and/or CH4. I think the most likely explanation other that testing error is atmospheric contact. Check for oil leaks. What is the moisture content, dielectric strength?

 

[amps21]

Alehman,
I agree with you when u say that elevated CO or CH4 but this will happen only if the following happens:

A. PD in oil involving insulation (H2,CH4, CO & C02) Ratio of CO2/CO has been found to be less than 5.
B. High temperature heating involving cellulose where u might not see significant CH4 but will see C2H6 & C2H4.

There is another form of heating called low temperature heating involving cellulose. Since class A insulation starts to deteriorate @105Deg C, the low temperature heating could be anywhere between that range. These are all theories based on research.

I also agree to moisture in oil could be a reason. But assuming a leakfree unit, only 2 things could do this:

Moist N2 gas introduced in the unit / wet unit when installed. The moisture in oil is a phenomenon controlled by temperature. OIl gives away moisture to paper during lower temperature of oil and paper gives moisture to oil during higher temperatures. SO the best method to determine moisture in oil is % Relative saturation. If this is high enough, we know that the oil-paper insulation system need drying up.

CO2 could very well generate due to wet cellulose. If the oil is dry and the % relative saturation is low, then there could be low temperature heating in the unit. Beleive me, lot of area where this could happen in a transformer (especially older unit)

Thanks

 

[HighPotter]

moisture content -- 7ppm
interfacial tension-- 47.9


Electricpete,
How long would the sample have to be subjected to sunlight? Hours? days?
Our bottles are clear as well as our glass syringes.


thanks for everyones opinions

hp

 

[amps21]

Try this link for info on sampling.

http://www.doble.com/content/pdf/Sampling_of_Dielectric_Liquids.PDF

I have another suggestion: In a Transformer, oil is usually the moisture transferring medium. The moisture is distributed between oil and insulation.(generally paper). Temperature changes quite significantly modify the dissolved water content of oil but only slightly modify the water content of paper.

Thus for proper interpretation of moisture content in oil, the temperature of oil should be defined based on which the lab can provide u with the % saturation of oil with water. I think this is refered to 20 Deg C. With this number u will know how much moisture u have in your oil at the highest temperature so u can decide whether u should change oil or filter etc.

IFT looks OK. Anything above 30 mN/m is good in my xperience.

Thanks

 

[amps21]

sorry for the long posts

thx

 

[electricpete]

My memory is fuzzy on the sunlight. I originally read it in Doble literature. I tried looking on Doble website but couldn't find it (when are they going to give a complete search feature?).

My memory is that the sunlight broke the hydrocarbons down and could produce the hydrocarbon gases, such as CH4, C2H6, C2H4,C2H6. My memory was something like a week long test in direct sunlight increased some of these by 5-10ppm in some of these. I don't remember CO or CO2 in that category but again my memory is fuzzy on all of this.

I googled and found clear instructions that sample bottles should not be clear:

http://www.netaworld.org/files/ItemFileA342.pdf

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