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For any power generation facility, the turbine is considered the lifeblood of the operation. Any problem requiring an unexpected shutdown of the main turbine is likely to cause a significant unplanned outage, potentially resulting in millions of dollars of downtime costs.
According to a study by General Electric (GE), turbines contribute on average 20 percent of all forced outages in a conventional power plant. Among this 20 percent, GE noted that 19 percent of turbine/generator problems were associated with the lube oil system. For this reason, monitoring turbine oils has become commonplace in the power generation industry.
Figure 1. Contributors to Costly Forced Outage
Turbine oils, particularly those used in steam turbines, are expected to last around 10 to 20 years. For this reason, careful monitoring of both lube oil physical and chemical properties is required, together with common contaminants such as water and solid particles. This is true not just of in-service oils, but also for new oils, which must meet rigorous performance specifications prior to selection and use in a new application.
The testing of turbine oils is of such significance that ASTM has developed a standard devoted exclusively to this area, specifically ASTM D4378-97 “Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam and Gas Turbines.” Some of the tests important to the evaluation of new and used turbine oils are detailed in the following discussion.
Viscosity is the most important characteristic of a turbine oil because the oil film thickness under hydrodynamic lubrication conditions is critically dependent on the oil’s viscosity characteristics. Turbine blade clearances are critical to power plant efficiency and reliability. These blade clearances are directly impacted by lubricant viscosity.
Changes in oil viscosity can result in unwanted rotor positioning, both axially and radially. Axial movements directly impact turbine blade efficiency and in extreme cases can lead to blade damage. Radial movements caused by changes in viscosity can result in oil whip, where the rotor does not settle into one radial position. Oil whip can often be identified from vibration analysis, but is often a direct result of high viscosity.
For in-service turbine oils, the viscosity should remain consistent over years of service, unless the oil has become contaminated or severely oxidized. ASTM D4378-97 identifies a five percent change from the initial viscosity as a warning limit. It is important to note that this is a change with respect to a new oil baseline, not the typical value reported on the lube oil supplier’s spec-sheet. Testing for viscosity should be conducted on a quarterly basis, at a minimum.
The Viscosity Index (VI) is an indication of the oil’s change in viscosity with a change in temperature. Most gas and steam turbine OEMs require a turbine oil with a VI of at least 90, which is met by most turbine oil suppliers. The VI for turbine oils should not vary in-service, because turbine oils typically do not contain VI improvers and therefore do not need to be tested routinely.
Formerly known as the RBOT test, the RPVOT test (Figure 2) was developed for the monitoring of in-service oils to warn of a loss in oxidation resistance. Oxidation is driven by heat and exposure to contaminants like water, entrained air and catalytic metals.
As a turbine oil degrades, it forms weak organic acids and insoluble oxidation products that adhere to governor parts, bearing surfaces and lube oil coolers. After a period of time, these oxidation by-products and carbon insolubles cure on surfaces causing a significant change in critical clearances, and in some instances prevent the oil from providing adequate cooling to the bearings and fouling turbine control elements and heat exchangers.
This accelerated oxidation test is an industry standard for identifying oxidation stability problems with in-service turbine oils. ASTM D4378-97 identifies an RPVOT drop to 25 percent of the new oil RPVOT value with a concurrent increase in Acid Number (AN) as a warning limit.
Many turbine OEMs simplify this by using the 25 percent of initial RPVOT without reference to AN, while others list a 100-minute RPVOT minimum. It should be noted that the RPVOT test is designed to determine a lubricant’s suitability for continued use, not to compare competitive oils. Competitive oil comparisons should be evaluated on the basis of RPVOT longevity, rather then the absolute RPVOT value.
In gas turbines that utilize a common lube oil sump for bearings and system hydraulics the use of ultra centrifuge testing should be used in conjunction with RPVOT as a means to determine varnish formation.
Typically, an oil that has reached its minimum allowable RPVOT values needs to be changed. However, as a short-term measure, the so-called “bleed and feed” method of turbine oil rejuvenation is suitable to extend the life of the turbine oil for a limited time.
Efforts to readditize a severely oxidized turbine oil with oxidation inhibitor can put equipment at risk. An oil that has a RPVOT value below 100 minutes more than likely has diminished its inherent base stock oxidation stability, making readditizing a nonpractical solution.
In such cases, readditization may temporarily boost the RPVOT value but given the diminished nature of the base stock may sharply reduce the time frame before heavy varnishes and sludges are formed. Without the use of special filters such as Fuller’s Earth, to strip all polar materials, contaminants and additives, followed by complete readditization, the rejuvenation of a degraded turbine oil is inadvisable.
In steam and gas turbines, RPVOT testing should be conducted on an annual basis with an increased frequency as the turbine oil approaches 25 percent of its initial value. Some utilities time the test just before scheduled outages, to allow time to plan for an oil change if necessary.
The TOST test attempts to determine the expected turbine oil life by subjecting the test oil to oxidative stress using oxygen, high temperatures, water and metal catalysts, all of which increase sludge and acid formation.
This test was developed to evaluate the anticipated new turbine oil performance. However, because it is impossible to simulate actual in-service conditions in a lab, correlation between test results and actual field performance is difficult. Most turbine OEMs utilize TOST in their specifications to screen out high-risk turbine oils.
Current gas turbine OEM specifications for TOST range from 2,000 to 4,000 hours with new gas turbine technology specifications at 7,000 hours. All TOST reporting above 10,000 is done through non-ASTM test modifications that may not correctly represent a turbine oil’s performance. Reporting of TOST values greater than 10,000 hours is not possible within ASTM D943 procedures due to the limited initial 300 ml test oil sample volume that is depleted during AN testing.
Because a TOST test can take up to a year or more to complete, it is impractical as an in-service oil test and is rarely performed for this reason.
Testing for water, particularly in steam turbines, is important because water is a precursor to oil oxidation and rust formation (Figure 3).
Figure 3. Laboratory Moisture Test - Karl Fischer
Excessive water will also alter an oil’s viscosity, which reduces its load-carrying capacity. Studies also warn that water levels above 250 ppm in hydrogen-cooled generator windings may lead to stress corrosion cracking of generator rotor retainer rings. Water in a turbine oil in warm storage tanks, where the oil is typically stagnant, can promote the spread of microbial growth that will foul system filters and small-diameter gauge and transducer line extensions.
ASTM D4378-97 identifies 1000 ppm or 0.1 percent of water as a warning level, while some gas and steam turbine OEMs have identified 500 ppm. In hydrogen-cooled generators, an upper limit of 250 ppm should be maintained. Because free and emulsified water are the most harmful, it is advisable to keep water levels below saturation, typically 100 to 200 ppm depending on base oil types, additive formulation and age. Testing for water should be conducted on a quarterly basis, at a minimum using coulometric Karl Fischer Titration (ASTM D6304), complete with codistillation.
Sharp increases in AN may indicate contamination or a severely oxidized oil. Organic acids formed by oxidation can corrode bearing surfaces and should be addressed in a timely manner. ASTM D4378-97 offers guidelines of 0.3 to 0.4 mg KOH/g above the initial value as an upper warning level. However, many oil analysts view an upward movement in AN as small as 0.1 as worthy of concern.
Testing for AN should be conducted at least on a quarterly basis using the potentiometric titration method (ASTM D664).
Turbine journal bearing clearances (10 to 20 microns) and hydraulic servovalve clearances (3 to 5 microns) dictate the need for clean oil. Excessive bearing wear and servovalve sticking can result if tight cleanliness standards are not maintained.
Typical OEM recommended turbine oil cleanliness levels are ISO (4406:99) 18/16/13 or an NAS 1638 cleanliness level of 7, although significant component life extension can be achieved by keeping cleanliness levels significantly lower than these limits.
Testing for ISO cleanliness should be conducted on a quarterly basis at the very least.
Rust particles act as oxidation catalysts and can cause abrasive wear in journal bearings. Rust inhibitors are normally kept at proper levels through the addition of makeup oil. Rust inhibitors can impact water separation so field readditization is generally not recommended.
In-service oil testing should be conducted with distilled water as identified in D665 A. ASTM D4378-97 considers a light fail as a warning limit.
Testing for rust should be conducted on an annual basis, or if the lube oil system is exposed to water.
Water shedding characteristics are important to lube oil systems that have had direct contact with water. This is particularly true for steam turbines where gland seal leakage is inevitable. The ability of the oil to shed water will have a direct impact on its long-term oxidation stability.
Demulsibility can be compromised by excessive water contamination or the presence of polar contaminants and impurities. Demulsibility can be tested using ASTM D1401, in which a known volume of oil is mixed with water, and the time taken for the two to separate measured in minutes; the faster the separation, the better the demulsibility.
ASTM D4378-97 does not offer warning limits for demulsibility although some turbine OEMs identify levels of 3 ml emulsion after 30 minutes on new oils. In-service oil warning limits of 15 ml or greater of emulsion after 30 minutes should serve as a warning limit.
The impact of demulsibility depends on the system residence time and anticipated levels of water contam-ination. Demulsibility testing can show failure in the lab, but with sufficient residence time, the turbine oil may shed water at an acceptable rate that does not impact turbine oil performance. Small sumps with lower residence times will require better demulsibility performance than larger sumps. Testing for demulsibility should be conducted on an annual basis, or if the lube oil system is exposed to water.
A turbine oil sample will often test for foam higher than turbine OEM initial suggested levels, but typically present no field foaming issues because of the position of the suction line relative to the lube oil surface, where foam accumulates. If the foam level in the turbine sump is six inches or less and does not overflow the sump or cause level-monitoring issues, then turbine oil foaming is not usually a major cause for concern, although a sudden increase in foaming may indicate a more serious problem.
Lube oil at the turbine sump surface should show at least one clear area (no bubbles) and larger breaking bubbles should be seen at this interface.
ASTM D4378-97 offers warning limits for Sequence I of the foam test of 450 ml for foaming tendency, defined as the volume of foam generated after blowing for 5 minutes at 75°F (24°C), and a foam stability of 10 ml, defined as the residual foam left after a 10-minute settling period. A foam stability of less than 5 ml is a good indication that foam bubbles are breaking and the turbine should not experience foam operational problems.
When addressing a foam problem, cleanliness, contamination or mechanical causes should be investigated before field defoamant readditization can be considered. Excessive readditization can result in an even greater problem with increased air entrainment. Dirt is a leading cause of foam, so ISO cleanliness should be tested as a likely cause.
Testing for foam should be conducted only when foaming presents an operational problem and for product compatibility testing.
Some steam and gas turbine OEMs specify air release limits in their new oil specification requirements. These limits can be as low as four minutes, defined as the time for the air entrained during the test procedure to detrain to 0.2 percent by volume. This is typically not a problem for most ISO VG 32 turbine oils, but can be an obstacle for ISO VG 46 oils, due to the higher viscosity.
In turbines with small sumps and minimal residence time, entrained air mixtures could be sent to bearings and critical hydraulic control elements causing film strength failure problems, loss of system control, particularly in EHC systems and an increased rate of oxidation.
Air release of turbine oils should not vary with in-service time and therefore may not need to be tested for condition assessments routinely, unless a specific problem is suspected.
Turbines with geared shaft connections to the generator often require antiwear or extreme pressure additives to support gear tooth loading. Industry standard testing for gear load performance is the FZG Gear Test, with results reported as Failure Load Stage (FLS). Typical R&O ISO 32 turbine oils carry an FZG failure load stage of 6 or 7. ISO VG 32 R&O oils with antiwear or extreme pressure additives can give an FZG failure load stage of 10, which meets all major turbine OEM specifications.
FZG Gear Tests on turbine oils should not vary with in-service time and do not need to be tested for condition routinely unless a specific wear related problem is encountered.
Flash point testing is done primarily to confirm product integrity from contamination.
ASTM D4378-97 identifies a drop in 30°F (17°C) from the new oil flashpoint as a warning limit.
Flash point testing is required only if product contamination from a different oil or solvent is suspected.
Turbine oil lube oil analysis test packages should be assembled in a manner that provides pertinent, cost-effective information. Specific turbine oil test packages for regular trend analysis and suitability for continued use are described as follows:
Regular Trend Analysis (Monthly/Quarterly)
Suitability for Continued Use (“Turbine Annual”)
Often the most valuable and timely information is right in your hand at the time of sampling. Don’t pass up a great opportunity to assess key performance parameters on turbine oils. The use of clear, clean sample containers will allow for quick and easy quality checks as identified below:
Color - Unusual and rapid darkening can indicate contamination or excessive degradation.
Odor - Sour smelling oil can indicate contamination or excessive degradation.
Air entrainment - Air bubbles in the body of the lube oil sample should clear within 15 minutes.
Foam - After a vigorous shake, foam from the surface should clear within 10 minutes.
Water - Turbine oil samples should be transparent. If you cannot read printing through a clear sample container, then water levels above 300 ppm may be present. A simple crackle test can also prove useful in determining if any free or emulsified water is present.
Solids - Look for solids settling out as signs of external and internal contamination.
Additional onsite lube oil checks can be conducted by a lubricant supplier. These tests might include viscosity, filter patch for particulate, water concentration and thermography.
Knowledge of your turbine oil and its limitations will set the stage for years of reliable service. Keys to this knowledge include having the right tool for the job, and a solid understanding of lube oil analysis for new turbine oil evaluation and in-service oil condition monitoring. By following a few simple rules, like keeping the oil cool, dry and clean and by monitoring with regular, routine oil analysis, turbines oils should provide many years of continued service.
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2. Bloch, H. P. (2000). Practical Lubrication for Industrial Facilities. The Fairmont Press. Lithburn, GA.
3. ExxonMobil Corporation. Turbine Inspection Manual. Fairfax, VA.
4. Swift, S.T., Butler, D.K., and Dewald, W. (2001). Turbine Oil Quality and Field Applications Requirements. Turbine Lubrication in the 21st Century ASTM STP 1407. West Conshohocken, PA.
5. ASTM. (1997). Standard Practice for In-Service Monitoring of Mineral Turbine Oils for Steam and Gas Turbines ASTM D4378-97. Annual Book of ASTM Standards Vol. 05.01.