What are the practical values of the "varnish potential" test method?

Thanks for the good posting John.

First of all, ASTM D02 C01 is creating a test to measure the varnish potential of turbine oils. This will help users like you as currently every lab has their own methodology to determine varnish potential. They are extremely varied and most do not have any research linking their results to real life varnish.

Second, test methods to measure "soft contaminants" do a lot more than determine varnish potential. The very first sign of degradation that occurs in lubricants (especially Group II and above) are the creation of soft contaminants. Having the ability to measure these contaminants will signal oil degradation before RPVOT, acid number or any other conventional oil analysis test. That being said, how useful is it in your application - hydro-electric turbines? In my experience…limited. These fluids are under such low stress that I've rarely seen an elevated varnish potential unless there was a mix of Group I and Group II oils. That being said, if you have a dam that has upgraded the controls, understanding the fluid's varnish potential is of value. An annual test is more than sufficient.

Third, you are right - electrostatic filters are NOT silver bullets. They have been marketed as the end-all solution to varnish and fluid degradation. Unfortunately, in many applications, that is just not the case. Gas turbines are a good example. The problems that cause varnish in these applications are varied. The chemistry of varnish (reflecting the degradation mechanisms) may be different in the fuel control valve versus the IGV valve. It's complex. As many gas turbine users who have installed electrostatic filters and even the couple who have installed cellulose filters have found out, there is more to it than simply adding a fluid conditioning system (although this is part of the solution).

Fourth, I appreciate your skepticism regarding electrostatic filters. They do however clean the fluid in a different, and inherently safer way than cellulose filters and in many applications provide significant benefits. Conversely, cellulose filters are advantageous in many other applications. There is not one fluid conditioning technology (much to the chagrin of several people that post on this site) that is best for all applications. Performing a test of the different technologies with your specific fluid and in your operating conditions provides the best measurement of value. Regardless, I always appreciate a healthy dose of skepticism.

Greg, thank you for your response.
What is still puzzling to me is, what should I do if there have been found soft contaminants present in oil. How much is too much, and what the remedial actions would be helpful or recommended for a particular stage to reverse the trend, if possible. For example, we know what we should do when viscosity drops or increases 5% or 10%, and so forth. There are also limits/warnings/recommendations concerning presence of acid at various levels, as well as guidance regarding remained useful life of anti oxidants. Is there anything like that in place concerning varnish potential test?

Hi John - you bring up some good points. All of these issues are being considered. I wish that varnish testing was as simple as other oil testing parameters, but there are several factors that make it difficult. First, we are trying to quantify the amount of soft contaminants in the oil, most of which are under 1-micron in size and very difficult to measure. Colorimetry is the best option. Second, we are trying to correlate the quantity of soft contaminants to the “varnish potential” of the lubricant. Varnish potential meaning the likelihood that these soft contaminants will form deposits in a system. Third, and by far the most difficult, is providing meaningful interpretations to end-users. Every system has different tolerances to varnish formation. For example, a Frame 7FA has different operating conditions that that create varnish, and different tolerances than a Frame 7EA. Fourth, there is a range of treatment technologies, all of which work differently. It is difficult to make a general statement about solving varnish in light of the fact that these technologies are so different.

All that being said, just because it is complex doesn’t mean that it is not important for us to figure out. In fact, I think that we are far down the path in understanding most of these issues.

Luckily for you, varnish in hydro-electric applications (especially dams with old control systems) is of very little concern. Healthy dialogue – thanks for bringing up these points.

Just like all oil tests, no one test can do it all. Any "varnish" test needs to be correlated with other lab tests (FTIR,RULER, RPVOT, AN etc) and correlated with actual inspections of the inside of reservoir walls, deposits on servos, etc.

Only then can you use the "varnish" test values to trend your use of filtration, mechanical modifications and other attempts to eliminate the root cause of your "varnish" problems.

Care must be taken not to "read" too much into the varnsih test levels, what is a normal level for one oil and equipment type, is almost certainly abnormal for another.

We have seen examples of an oil company taking one of our carefully calculated set of limits for one their oils and a gas turbine, and trying to apply it to one of their competitors oil on a steam turbine....when made aware of their faux pas, they of course said no harm was intended...thus we do not do the test for outside parties who may have an agenda to try and bias...we only do the tets for end-users who open up to us with their problems...

I think any ASTM test method for varnsih has got to be worded so as to include the issues of correlation with other tests, correlations with inspections and use a trending tool only....similar to the new FTIR test...Andy