Transformer Oil IFT vs NN - which is early indicator (SDMyers) 1

[electricpete]

Referencing the document: "A Guide To Transformer Maintenance" by Myers/Kelly/Parrish (SDMyers), copyright 1981, 1988.

Page 519 Reads: "Several independent studies have shown that an increase in neutralization or acid number should normally be followede by a drop in I.F.T and a deepening of color". This suggests NN changes before IFT during the aging process.

Page 521 - Graph of IFT (vertical axis) vs Neutralization number (horizontal axis) shows "good oil" at the upper left (high IFT/low NN) and "bad oil" at the lower right (low IFT, high NN). There is a curve in between showing the gradual progression from good to bad... somewhat resembles exponential decay curve. At the very left side of the curve for very low NN (good oil), the curve is almost vertical with a steep negative slope of dIFT vs NN. From the shape of the curve we would deduce that traveling along the curve we would see IFT change long before NN. This appears to contradict the quoted statements on page 519.

Can anyone explain this apparent contradiction?

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[electricpete]

I should clarify the abbreviations:
IFT = Interfacial Tension
NN = Neutralization Number (also called total acid number)

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[xabproject]

Dear electricpete,
Please see whether the following would suffice:

1. IFT is classified, along with tests for color, flash point,viscocity, RI, etc., under the PHYSICAL TESTS whereas the NN test is a CHEMICAL TEST, classified so along with Test for corrosive sulfur, water content, etc.

2. Because of the highly hydrophilic nature of the liquid changes in IFT are not as sensitive to the changing oil quality as the NN is.

3. Standard substation Maintenance practices for vital installations include IFT, NN, BDV, Moisture/Water Content tests once every six months and these results together give adequate advance information on the deteriorating oil conditions.

Best regards

 

[xabproject]

Also, please see 'ntt' links under thread242-116334 under the forum IEEE Code issues
Best regards

 

[electricpete]

Thanks xabproject, that is great info.

Is what you are saying in #2 that variations in moisture and other factors cause relatively large variations in IFT which would obscure small changes such as those from early stages of oxidation? So perhaps if I look at that aging curve it is true that IFT has a higher slope of change during aging than NN, but it also has more "noise" associated with change in IFT from factors unrelated to aging?

The reason I am asking this question is that I am looking at our rotating machinery oil analysis. For our machiners with larger reservoirs, we don't schedule routine oil changes but instead do condition-based changes based on the oil samples. We look at NN (also called acid number) but we don't look at IFT. I was wondering if there would be any benefit to adding IFT for these applications.

It makes me wonder why IFT is important enough for transformers but not for rotating machines.

From your comments I understand that the reason for looking at IFT is not aging but moreso for contaminants. Moisture is one contaminant although moisture by Karl Fischer is almost always tested in both transformers and rotating machines.... so maybe the focus is non-moisture contaminants. I wonder why this aspect is more important in transformers than in rotating equipment? (especially considering dielectric breakdown is also tested ). It seems rotating equipment oil reservoirs are more likely to encounter contamination since they are usually vented to the atmosphere. Aging and oxidation are likewise a bigger issue for rotating equipment... so why don't any rotating equipment standards call out IFT?

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[electricpete]

Since it relates to the original question and follow-on question, I am going to post the info from your NTT link here for handy reference:

"Acid Number
ASTM D 974
Oxidation of insulating fluids and/or additives in the fluid results in the production of acidic compounds. The periodic measurement of acidity provides a means of monitoring the progress of oxidation. The build-up of acidic compounds precedes the formation of sludge in the transformer which is the end-product of oxidation.

Interfacial Tension
ASTM D 971
Determining the presence of polar contaminants in insulating oil is accomplished by measuring the tension of oil against water. The interfacial tension of an oil is sensitive to the presence of the products of oxidation of the oil and can be used, together with acidity measurements, as an indicator to monitor sludge development. Foreign substances such as dissolved varnishes andother organic coating materials can also affect IFT. The presence of polar contaminants generally lowers the interfacial tension value."

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[electricpete]

I guess I can see two benefits of adding IFT (for rotating equipment apps which now look at NN but not IFT):

#1 - Provides increased ability to detect contaminants.
#2 - Provides better ability to identify aging/sluding through overlapping indications. If I see both NN going up and IFT going down at the same time, I have pretty good confidence the oil is aging. If I see only one of those two indications, then I should probably look for some contaminant other than aging byproducts.

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[xabproject]

Dear electricpete,
Thanks for the enticing and memorable "conversation". I too go by your decision to include IFT based on #1 and #2 of your last reply.
Something equally interesting follows - about your question
"why IFT is important enough for transformers but not for rotating machines?" The thermosyphon mechanism that is largely responsible for making the oil go around in the ON cooling phase of a oil filled/cooled transformer apparently has less scouring action/dislodging force compared to the assisted flow that is encountered in rotating equipment application is my wild guess

Oil Deterioration in Transformers: In transformers, sludge sticks to the surfaces through which heat is dissipated; the sludge forms a barrier to the flow of heat from the oil to the coolant and from the core and coils to the oil. If allowed to continue, the sludge may block off the flow of oil through the cooling ducts. As a result, the transformer insulating oil becomes hotter and the transformer could be damaged, particularly between the coil turns of the windings. Deterioration of the coil-turn insulation may eventually lead to short circuits between coil turns and the breakdown of the transformer. When oxidation progresses to the point where sludge is being precipitated, the first step should be to remove the sludge from the transformer by a high-pressure stream of oil and to either replace the sludged oil or treat it with activated clay to remove the acid and sludge precursors. Complete treatment of the oil is normally less costly than replacing it with new oil.
Acidity Test: If properly refined, new transformer oils contain practically no acids. The acidity test
measures the content of acids formed by oxidation. The oxidation products polymerize to form sludge which then precipitates out. Acids react with metals on the surfaces inside the tank and form metallic soaps, another form of sludge. Sludging has been found to begin when the acid number reaches or exceeds 0.4 mg of KOH/g (0.4 is considered to be the normal service limit). New oil has an acid number of less than 0.05 mg of KOH/g. The acid number (also referred to as the neutralization number) equals the milligrams of potassium hydroxide (KOH) required to neutralize the acid contained in 1 g of oil. It is questionable whether an oil that has deteriorated to the point where its acid number exceeds 0.6 mg of KOH/g can be restored to good condition by a single renovation. It is almost certain that two or more renovations, spaced 6 months to 1 year apart, would be necessary. It is recommended that an upper limit of 0.2 mg of KOH/g be used to determine when oil should be renovated, as at that point a single renovation would probably restore the oil to very good condition. Oil showing an acid number of 0.15 mg of KOH/g or larger can be expected to show accelerated acid formation. Tests have been made which indicate that acidity is proportional to the amount of oxygen absorbed by the oil. It is estimated that 0.0015 m3/L (0.2 ft3/gal) of oxygen absorbed in oil will cause an acidity of about 0.4 mg of KOH, which is the approximate acidity number at which sludging is assumed to start.
Interfacial Tension (IFT) Test: The acidity test determines conditions under which sludge may form, but does not necessarily indicate that actual sludging conditions exist. The IFT test is employed as an indication of the sludging characteristics of power transformer insulating oil. It is a test of interfacial tension of water against oil, which is different from the surface tension of oil against air. The attraction between the water molecules at the interface is influenced by the presence of polar molecules in the oil in such a way that the presence of more polar compounds causes lower interfacial tension. The test measures the concentration of polar molecules in suspension and in solution in the oil and thus gives an accurate measurement of dissolved sludge precursors in the oil long before any sludge is precipitated. It has been established that an interfacial tension of less the 0.015 N/m (15 dyn/cm) almost invariably shows sludging. An IFT of 0.015 to 0.022 N/m (15 to 22 dyn/cm) shows an uncertain condition, and an IFT value of more than 0.022 N/m (22 dyn/cm) is generally indicative of no sludging. Transformer oils whose IFT is in the range of 0.015 to 0.022 N/m (15 to 22 dyn/cm) should be scheduled for reclaiming, regardless of acidity values.
Interpretation of Test Results: When the results from all tests are integrated, a sound conclusion can be drawn as to the condition of the oil. Qualitative relationships exist between acidity and IFT which are useful in interpreting test results. Note that the rate of change of IFT is a more sensitive indication of early stages of deterioration. The IFT measurements are particularly useful in judging the effectiveness of oil renovation processes; identifying at an early stage new oil with poor life expectancy, thus, permitting treatment while it is still practical; and indicating when oil should be discarded and replaced. The rate of change of acidity is often a more sensitive indication of deterioration near the sludge point. However, this is only true if the oil does not
contain alkali impurities. Such impurities neutralize the acids as they are formed, resulting in a low-acidity value.