By changing to API?Group II base oils, gas turbine fluid formulators have improved their products oxidative and thermal stability. With that switch, however, came reduced solubility and the costly side effect of increased varnish formation.
The importance of careful fluid selection cannot be overstated. There are no indications that original equipment manufacturers plan to revert back to Group I oils; in fact, as time progresses, the likelihood of moving to even more refined oils, such as Group III and Group IV, increases. Likewise, the demands placed on turbines and the operating conditions required to meet them are here to stay.
Varnish management will no doubt continue to be a priority for natural gas turbine operators when selecting a turbine fluid. With that in mind, it is worth examining how operators make their fluid selections-including test methods-to ensure their decisions are in line with the latest formulations available on the market. In fact, one traditional test for varnish formation potential, the Rotating Pressure Vessel Oxidation Test, may no longer be useful for modern fluids.
Defining the Problem
While power generators benefit from more efficient turbines and the output they deliver, the demands and stress on the turbine oil tend to rise. Manufacturers have no choice but to demand more performance from their turbine fluids as higher temperatures accelerate oxidation, which is responsible for numerous lubricant problems such as viscosity increase, varnish formation, sludge formation, additive depletion, base oil breakdown, filter plugging, loss of foam control, acid number increase, rust formation and corrosion.
For natural gas turbine operators and power plant maintenance managers, varnish formation is an issue that continues to interfere with operational efficiencies and mechanical performance, contributing to lost circulation, increased wear and corrosion, equipment failure and, by extension, downtime. Peaking units in particular are challenged by varnish, due to cyclical warming and cooling.
Varnish formation has a long history in machinery, but only recently has it become a bigger issue to manage. A principal reason for the noticeable increase in varnish formation is that, unlike traditional products that used Group I base oils, the majority of modern turbine fluids are made with more highly refined Group II base oils. The switch has uncovered several advantages for manufacturers, including the ability to add more complex and effective antioxidant chemistries that demonstrate better oxidative and thermal stability than when used in Group I oils.
The new added-performance capabilities are a necessity for gas turbines, which are the most demanding application for turbine oils. They also represent the fastest-growing market in North America for power generation, which underscores the importance of focusing on this formulation category. Despite their natural resistance to oxidation, an unfortunate side effect of using Group II base oils is reduced solubility.
Hydrocracking (the process used to manufacture Group II and III base oils) contributes to improved oxidation properties, but it also removes the compounds that would otherwise help the oil solubilize chemical additives. To address this problem, additive companies have been tasked with adapting their chemistries to keep them in solution.
Another reason for the increasing prevalence of varnish is the reality that natural gas turbine fluids are required to perform more functions in increasingly harsh environments. As more advanced metallurgies are developed, the efficiency and firing temperatures of gas turbines continue to increase. In some industrial turbines, the same reservoir of fluid simultaneously provides lubrication to the turbine bearings, generator bearings, atomizing air compressors, lift oil system, trip oil system, generator hydrogen seal system, load gears and a multitude of servo valves within the hydraulic circuit.
As it stands, operators look to testing and performance ratings-often specified by the OEM-to choose a turbine fluid that protects against oxidation and resists varnish formation. By all accounts, a data-based judgment is the most logical approach to making a decision, along with a field trial. Operators and maintenance managers require assurance that the investment they make will be able to mitigate the risk of failure.
New-generation turbine fluids degrade at non-linear and unpredictable rates-which can be attributed to the specific antioxidants used, as well as the natural oxidation-resistance characteristics of Group II base oils. As a result, the RPVOT (ASTM D2272) fails to provide a reliable warning as to when the lubricant will start to degrade and generate system deposits. Thus, various tests are performed over time and trending is used to show the bigger picture.
However, if operators have a reservoir with mixed brands or formulations of turbine fluids, RPVOT testing is recommended as part of a larger, more comprehensive test slate to help evaluate the condition of the fluid.
Over the years, several tests have surfaced as valuable, and experts recommend using a combination of both new and well-established tests when determining the right turbine fluid. The lubricant specialist should be aware of the measuring tools available and what they may indicate.
Understanding how a turbine oil is handling the problem of oxidation can enhance attempts to correct the root cause of fluid oxidation. Linear sweep voltammetry tests are designed to measure oxidation reserve (the amount of protection remaining) and oxidation progress (the amount of oxidation that has occurred).
Voltammetry is often the technique of choice for measuring antioxidants, as it is indicative of field testing rather than lab testing. For example, ASTM D6971-more commonly known as the Remaining Useful Life Evaluation Routine (RULER) test-measures hindered phenol and aromatic amine antioxidants in lubricants. Antioxidants are one of the first components of the turbine oil formulation to be impacted by thermal, oxidative and mechanical stress. When calibrated against new oil, the remaining antioxidant concentration can be determined to estimate the lubricants remaining oxidative life and provide early warning for incipient lubricant failure.
However, the effectiveness of voltammetry tests depends on the operation of the in-service fluid.
The testing toolkit offers several more useful methods:
The Standard Test Method for Kinematic Viscosity of Transparent and Opaque Liquids (ASTM D445) is still invaluable. Viscosity is one of the most important oil properties because the oil film thickness under hydrodynamic lubrication conditions is critically dependent on the oils viscosity characteristics.
Cleanliness can be measured by the Method for Coding the Level of Contamination by Solid Particles test (ISO 4406), in which particulate contamination levels per milliliter of fluid are quantified.
A relatively new lab method of extracting the insoluble contaminants from an in-service turbine oil sample onto a membrane patch is the ASTM D7843 Test-Measurement of Lubricant Generated Insoluble Color Bodies in In-service Turbine Oils using Membrane Patch Colorimetry (MPC). This test can be used as a guide on the formation of lubricant-generated insoluble deposits. It is considered a highly sensitive and reliable test for detecting subtle changes in insoluble levels while offering the ability to predict varnish formation. The results are intended to be used as a condition monitoring trending tool.
The Turbine Oil Oxidation Stability Test (ASTM D943) attempts to determine the expected turbine oil life and performance by subjecting the oil sample to oxidative stress using oxygen, high temperatures, water and metal catalysts, all of which could increase sludge and acid formation. Because it is impossible to simulate actual in-service conditions in a lab, correlation between test results and actual field performance is difficult. As such, most turbine OEMs use TOST in their specifications to screen out high-risk turbine fluids. Further, this test does not account for other signs of deterioration such as sludge formation or catalyst coil corrosion.
ASTM D4310, Standard Test Method for Determination of Sludging and Corrosion Tendencies of Inhibited Mineral Oils, can be used for sludge measurements. The Coking Tendencies of Lubrication Oils (FTM-791-3462) test evaluates thermal oxidative stability of fresh turbine oil on hot surfaces.
The Air Release Properties of Hydrocarbon Based Oils test (ASTM D3427) evaluates the ability of turbine fluids to separate entrained air. Some gas turbine OEMs set air-release limits in their latest oil specification requirements. These limits are defined as the time needed for the entrained air in the fluid to reduce in volume to 0.2 percent under set conditions and at the specified temperature. In turbine systems with small sumps and minimal residence time for the fluid to rest between passes, entrained air mixtures could be sent to bearings and critical hydraulic control elements, causing film-strength failure problems, loss of system control and an increased rate of oxidation.
In addition to looking at the above test results when comparing and selecting turbine fluids, it is also recommended that operators implement some of these tests in routine oil inspections. While traditional methodologies for monitoring the oxidative health of used turbine fluids-viscosity, acid number and RPVOT-are still beneficial, tests such as the membrane patch colorimetry test and the RULER test are more likely to reveal turbine oil degradation at earlier stages, as well as identify a fluids deposit tendencies.
Neil Buchanan is senior technical advisor for Petro-Canada America Lubricants Inc. He is a licensed professional engineer (P.Eng.), a Certified Maintenance & Reliability Professional, and a Society of Tribologists and Lubrication Engineers Certified Lubrication Specialist. He is also an STLE Certified Oil Monitoring Analyst I and II. For more information, email LubeCSR@petrocanadalsp.com