High oil temperature????!!!!!

- What type of engine and which application are you using this engine for?

- What type of engine cooling (not oil cooling) is present?

Dear Just 'eazy' not greasy..;-),
Thanks for your instant response, and sorry for the descrepancy in the information I furnished.

The question is based on a ISO 68 turbine oil, used in a closed system to serve a 45 MW turbine. The operating temp. maintains at 105 deg.C and upon opening, varnish is always found in the bearing on both halves.
Chance of entrained air is not ruled out, yet not evident as slow rising bubbles not seen. And, TAN and viscosity value is well within the acceptable limits. If varnish is one of the consequent by-product of oxydation, why that was not reflected in TAN or in visc value? What other problems can cause warnish formation?

To add to the above, the oil was changed to BP Energol. But, the problem still exists.
Hope the above suffice.

well you have pretty much laid out what you have as far as oil. what is missing is how you cool the oil. is it air/liquid or liquid/liquid type cooler and the parameters of that. that is one area most of us need to consider when problems like wha you are experiencing. whats the Temp diff across your coolers? sufficinet heat x-fer is the key to temp management.
hope this helps

Dear Sajeev

The scenario that you described, varnish occurring inside a turbine system without a predictive sign from oil analysis, is very common. Acid number is only one indication of oil degradation and represents only one of several by-products produced from the oxidation process. A similar degradation process that produces different by-products and can be responsible for varnish is thermal degradation. Thermal degradation is more common in gas turbine applications. It is common for varnish to form in Group II products (such as BP Energol - a very good product) after a small amount of oil degradation. Therefore it is common to experience severe varnish problems without any predictive sign from oil analysis.

A brief list of common root causes of varnish in gas turbines is:

• High operating temperatures (sounds like this may be a potential root cause)
• Common lube/turbine reservoir
• Adiabatic compression of air bubbles (in which you are currently investigating)
• Hot spots in the system
• Water contamination
• Electrostatic spark discharges from mechanical filters

You are addressing this dilemma from a root cause perspective, the correct way to go about the problem. After you exhaust your investigative efforts, you may come to the conclusion that the high temperatures and severe operating environment are inherent to the design of your system. (This is true for most gas turbine applications.)

So the questions therefore become:
1. How do I prevent varnish from occurring?
2. What testing can I incorporate to act as a predictive tool and measure varnish potential?

The answer to the first question is employing electrostatic oil cleaners as a technology to remove the insoluble degradation by-products as they are formed, rather than letting them agglomerate and form varnish. This technology is widely used in turbine applications and has been proven successful at solving varnish and cleaning up a system where varnish has formed.

In terms of using oil analysis as a predictive tool to measure varnish potential, there is a lab in the US that has developed a very reliable test. If you are interested, please e-mail me and I would be pleased to put you in direct contact with the lab.

You are not alone with this problem. Most turbine applications eventually have to develop a plan to deal with varnish. Best of luck and please feel free to contact me if you would like some more information.

Greg Livingstone

Greg, can you send me the name of the US lab that can detect varnishing potential in used turbine oils. We do TAN-C, FTIR for oxidation and nitration, colour and particle count and sometimes find precursors to varnish, but I would like to add to our arsenal if there is another test. We are also experimenting with electrostatic filtration for the past 3 months, but it seems ineffective at cleaning up the oil so far - Patch tests are getting darker, not lighter!

David Spears

quote:

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Originally posted by Sajeev:
Dear All,
What other methods than

1.Re-designing a cooler
2.Change to synthetic
3.Maintaining proper bearing clearance
4.Remove oil tank heater etc..

- are suggested for high oil temperature?
- How can we bring down the temp. down to optimum <82 deg.C from 105?

If your answer is 'to increase the frequency of oil changes' or 'to live with it', then what efficient methods are recommended to combat the consequent problems like oxidation or varnish formation?
Your valuable response awaited.

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Sajeev
While I have no experience with gas turbine applications, I have been involved with the offshore marine industry for many years and have been confronted with high oil (90 wt gear oil) temperatures from time to time. We did the due dilegence thing and finally decided to try by-pass filtration to remove solid contaminants - although analysis reports were not red flag level. This action reduced the oil temperature about 4 degrees as I remember. Solids hold heat better than liquids. At a later date we introduced a surface modifier to the lubricant and achieved a further drop in temperature of approx. 8 degrees. This stategy has since been used on 3 other vessels and allows one to sleep better.
Doug

Dear Sajeev

First than all, you should check the viscosity grade of the oil. Most of the Gas Turbines uses ISO VG 32 and ISO VG 46. If your are using a wrong (high) viscosity this could be the main problem.

Now, for detecting varnish in the oil, you said that viscosity and TAN are Ok, but, what about the color and odor of the oil. Remember that if Color is high and odor is present, these could be a sign of thermal degradation. With the temperatures you try, it is sure that thermal degradation will be occur in mineral oil.

The solutions you could implement are:
1- Check the oil viscosity, according to the Lubrication Manual of the Gas Turbine.
2- Clean the system with a proper High Speed Oil Flushing, and Chemical Cleaning if required in next Outage.
3- Fill the tank with Group III Oil (ASTM D-943 + 10,000 hours).

I hope this helps you.
Regards from Argentina.
Ing. Cristián Schmid.

Dear Sajeev,

Here is a link to a paper concerning an oil centirfuge product called the Spinner II. The article concerns the positive of this type of product on bearing failures due to heat and contamination.

http://spinner.tricordsupport.com/docs/turbinbearingfailure.pdf.

Also, as you know, synthetic lubricants are engineered to have better volatility and oxidation control characteristics.

Amsoil offers an RCG product which is the synthestic match to ISO 68 and BP Energol lubricants.

The lab that has developed the test to determine varnish potential is:

Analysts Inc.
Louisville, KY
Contact: Brian Thompson, 502-491-2013

They run a quantitative spectrophotometric analysis that has a very high correlation to varnish potential. They also have a large database of samples to aid in data interpretation.

Tests such as viscosity, AN, RPVOT, ultracentrifuge, ISO Particle count, KF Water are all very important, but varnish can impact turbine performance before these tests identify a problem.

Contamination control devices (centrifuges, filters) are also important, but do not remove the particles associated with varnish generation, which are typically well under 1-micron in size.

Electrostatic oil cleaners have been used to solve varnish problems in dozens of turbine applications. Their rate of cleaning however is not always linear with the quantitative spectrophotometric test.

I hope that this helps. Great comments on this thread.

Well , I would like to throw the same question with another application to all.

I have no experience with gas turbines, but some what in rotary ( High Pressure Screw Compressors upto 300 psi)compressors.

We experienced the same problem is VG 68; Group II base oils in Industrial Compressors working 24 X 7 hrs at 90- 105'C.

We have faced similiar problems of varnishing causing oil thickening ,high TAN etc..in hydraulic oils.

Normally Group II base oils have better thermal & oxidative stability.then howcome they aren't able to withstand high temperatures? Is additive solubility an issue?

Your valuable comments to overcome this problem!

Very good questions about Group I vs. Group II. You are correct, Group II's have a much high tolerance to resist oxidation and degradation, but a lower tolerance to hold degradation by-products in solution. (Due to solubility as you pointed out.) It is easy to make a strong argument to switch to Group II's for a whole host of performance issues, but solving varnish is not one of them.

Oxidation is not the only mechanism that degrades lubricants. Thermal and compressive degradation, which occurs at much higher temperatures and produces different by-products than oxidation, are other mechanisms. If varnish is caused by higher temperatures, a Group II product may not provide any more protection than a Group I. For example, adiabatic compression may create localized temperatures over 1,000F degrees. In this situation, a Group II may not perform as well as a Group I in varnish formation. If the application only exerted oxidative stresses to the oil, a Group II product may work better. I believe that this is an important but under-researched topic, as the majority of the research that has taken place has been in a laboratory.

Compressors undergo similar degradation processes as gas turbines. Here's a good picture of a varnished compressor:

Sajeev,
Having a bigger oil sump (oversized if possible) will be beneficial in an effort to lower oil temp (will allow an increase in the amount of oil to be used, and therefore, will increase the residing/cooling time). The choice of oil’s viscosity is very important, as Ing. Cristián Schmid pointed out. Considering the fact that you are in Kuwait (relatively high ambient temp) makes Christian’s point even more important. Filtration seems to be a must for you considering your location (i.e. sand storms). It will prolong longevity of your oil and the equipment, but it will not completely solve your varnish problems if you’re using Group-2 oil. Consider increasing capacity of oil sump, and check more frequently the level of oil in your current sump (any decrease will definitely raise oil’s temperature).

John

High oil temperature can be from a number of factors. If the compressor has experienced high temperatures in the past, then oil varnish may have formed inside the coolers as well as the whole of the oil lubrication system. This must be cleaned out so that the compressor can effectively dissapate heat, which usually entails running a cleaning product in the compressor for 500 hours or so. Additionally, the compressor must be able to get proper air flow (or water flow for water cooled units) In dusty environments, it is recommended to routinely blow out the outside of the cooler to ensure proper operation. If the compressor is running in a hot environment, more frequent oil changes are recommended, which can be indicated by a proper oil analysis program, and a synthetic lubricant is recommended

boy I think about all options have been said here and all are very valid.
turbines are not my bag BUT even with filtration, testing etc IMHO there is a useful life to most all lube oils both to chemistry change and just satuation limits syn or dino when or has system ever been changed out?
perhaps its due.

bruce CLS