Greg Livingstone

Antioxidants (AO) are critical components in turbine oil formulations and largely determine the life and performance of a lubricant. Even though these sacrificial warriors make up about 1% of a turbine oil formulation, they protect the base oil from oxidation and rapid deterioration. An oil void of antioxidants fails rapidly and dramatically in a thermally stressful environment such as a turbine. Antioxidants play the same role in our bodies by protecting cells from the damaging effects of free radicals which are produced when our bodies break down food. That’s why we read so much press about the value of antioxidant rich foods such as blueberries and other plant-based foods. (Although red wine and dark chocolate are my favorite sources of antioxidants.)

Turbine oils have reached the end of their life when their antioxidants have depleted to 25% of new levels. At this point, oil changes are scheduled. Alternatively, some users will remove a percentage of the oil from their sump replacing it with new oil in order to replenish some of their antioxidants. This “bleed and feed” practice however is an expensive way of replenishing the antioxidant.

It is common for plants to inquire about simply replenishing their oil’s antioxidant system while the fluid is still in-service. This is a lower cost option and is a similar practice to many other bulk fluid systems. Many power plants have familiarity with maintaining their cooling water chemistry in wet-recirculating or closed-loop cooling systems – turbine oil formulations can’t be more complex they reason. Similarly, swimming pools aren’t dumped when the water becomes dirty or algae emerge. The chemistry is simply tweaked and the fluid is filtered.

Replenishing antioxidants is a feasible and a cost-effective alternative to extend the life of your turbine oil.

 This is not suitable for all in-service turbine oils and requires a custom antioxidant formulation for each fluid. In order to mitigate risks, up-front testing must be done to qualify the oil. There are two main criteria that must be met in order for an in-service turbine oil to be qualified: compatibility and performance.

 is determined by running a battery of tests on the in-service oil, blending it with fresh antioxidants and then retesting the oil. If there are any adverse effects with the addition of the antioxidants, the oil is not qualified. ASTM D7155 is a turbine oil compatibility guideline that provides a good test protocol for performing these tests.

 of the replenished antioxidant system is another key factor in qualifying turbine oil. The antioxidant package should have synergism with the existing formulation. The replenished antioxidant system should also have a similar rate of depletion as new antioxidant formulation. This is a function of both selecting the correct antioxidants for the formulation and ensuring that the in-service oil is free of reactive degradation products. (i.e. low MPC values.) Laboratory stress tests can do an excellent job of measuring the effectiveness of the replenished antioxidants and estimating the long-term performance of the treated fluid. (Read this post on a suggested stress test: 

http://www.turbomachinerymag.com/blog/content/when-selecting-turbine-oils-look-beyond-spec-sheet

Clearly a level of expertise is required before attempting to reformulate in-service turbine oils. This should not be attempted by those without a thorough understanding of the original oil’s formulation and oil blending expertise. However, this option has the potential of significantly reducing lubricant costs. It is also a more environmentally sustainable practice by doubling (or more) the life of your in-service lubes. With proper testing, the risks of antioxidant replenishment can be also mitigated. In fact, if done correctly, the risks of replacing depleted antioxidants in your in-service oil is lower than changing your oil out and performing a system flush.

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Extending lubricant life through antioxidants

Electrostatic Spark Discharge (ESD) is a phenomenon that occurs when oil generates sufficient static electricity to form sparks. This form of oil degradation has been studied extensively in many systems, including large frame gas turbines. Although most power plants are now aware of this form of turbine oil degradation, there is insufficient clarity on how critical of an issue ESD is.

Many people assume that ESD is caused by triboelectric charging – the reason why you can generate sparks with your fingertips in dry weather when wearing polyester clothing. Research by Dr. Sasaki however has shown that ESD is not caused by the friction of oil passing over another surface but by “internal friction” of the oil (Helmholtz Double Layer). Fast flowing, dry oil passing through small areas is at greatest risk for generating sparks. Often these sparks are generated in the lube oil filters or servo-valve last chance filters. Sometimes, the discharge of energy is so great that we can actually hear popping sounds emanating from the oil housing. This is especially prevalent when the lube oil is not yet up to operating temperature and has a higher viscosity. In most cases, ESD occurs without any audible noise because the size of the electric-arc is very small.

One reason that ESD has become such a high profile issue today is due to changes in turbine oil formulations. The use of more highly refined basestocks in most of today’s turbine oils creates a more conducive environment for ESD. Research by Dr. Duchowski has shown that oils are especially susceptible to ESD if their conductivity is <400pS/m. Group I turbine oils have conductivity values over this critical limit while most Group II and III turbine oils have conductivity values far below. Some new turbine oil formulations have conductivity values of less than 10pS/m, making it quite easy for ESD to occur. 

There’s a good chance that you have sparks in your turbine oil. How serious is this? In some cases, this will lead to localized deposits in last chance filters with a black, thermo-plastic appearance. This can lead to significant impairment of the valve. In other cases, the sparks will create large holes in the main lube oil filters essentially turning your filters into screens. 

The good news is that there is a cure for ESD. Utilizing specially engineered filters or making engineering changes to the system can eliminate ESD. Although ESD is not considered the primary reason for turbine oil failure and varnish formation, eliminating this degradation mechanism from your turbine oil system helps ensure long-lasting, higher performing, cleaner fluid.

Do you have sparks in your turbine oil?

The industry standard for determining when to change your turbine oil is when the antioxidants deplete to 25% of their original level. An accepted practice to extend the life of your turbine oil has been “bleed and feed”. Bleed and Feed is the practice of discarding a fraction of old oil and replacing it with new oil. Often 20-30% of the oil reservoir volume will be exchanged with new oil. This practice has become so widely adopted that few plants even pause to determine the economics of bleed and feed. In essence, this is the most expensive way of replenishing your antioxidants and is one of the most expensive practices for managing your turbine oils. Let’s look at why.

Antioxidants are critical to the life and performance of turbine oils. They make up approximately 1% of the turbine oil formulation. Antioxidants are reactive molecules designed to sacrifice themselves to protect the base oil. We have studied dozens of turbine oil deposits and have found, as one would expect, a significant portion of deposits are composed of depleted additives. In most cases, when turbine oils have reached the end of their life, the base oil is still healthy.

Bleed and Feed is extremely expensive for two reasons. First, almost all of the oil molecules that are being exchanged are still in acceptable condition. So you are replacing good lube molecules with additional good lubricant molecules.  Second, the fresh antioxidants often react very quickly with the degradation products in the system. Several days after the bleed and feed, the effects are hardly noticeable through routine analysis. We have seen many cases where this happens, especially if there are high amounts of sludge and varnish in the system.

Let’s say you have a 5,000 gallon reservoir with 25% remaining antioxidants. To extend the life of the oil, you perform a 25% bleed and feed. At $14/gallon, this costs you $17,500. This should increase your antioxidants to almost 44%. However, the fresh antioxidants immediately react with oil degradation products resulting in only half of the antioxidants effectively being added to the system. Your resulting antioxidants have been increased from 25% to 31%. This is the equivalent of paying 4X more for your oil or $56/gallon!

There are times when bleed and feed makes sense. If a shutdown is not possible making this the only option to allowing the plant to limp by until a planned outage, even a 4X increase in oil price is cheap compared to shutting down. However, bleed and feed as a maintenance strategy or a practice to maintain the antioxidant levels is very expensive.

A better practice is to keep your oil clean and dry until you’ve reached its remaining useful life and then change the entire reservoir with new oil. Many plants have also considered replenishing the antioxidants as an option - a much less expensive option. If done correctly, replenishing spent antioxidants can double the life of your turbine oil.

It’s always healthy to question the status quo, especially if the status quo doesn’t make financial sense. As is often said, the seven most expensive words in business are, “we have always done it this way.” Keep this in mind the next time your oil analysis report indicates a depleted level of antioxidants.

Turbine oil bleed & feed: An expensive option

Turbine oil varnish has been a well-documented reliability challenge for power plants. Traditional oil analysis techniques have been ineffective at predicting the onset of deposit problems in turbine oils – often defined as varnish. This has led to the commercialization of several new analytical tests which measures oil degradation products and can be correlated to the potential of deposit formation of turbine oil. The most widely adopted test is referred to as Membrane Patch Colorimetry (MPC). This test isolates oil degradation products on a membrane and measures the color with a spectrophotometer. The total amount of color generated by the deposits on the patch is reported, following the CIE LAB DE scale.

 is a newly approved ASTM standard called the 

Standard Test Method for the Measurement of Lubricant Generated Insoluble Color Bodies in In-Service Turbine Oils using Me

. Standard guides are often used to interpret the MPC results and assess a fluid’s potential to form deposits.  These Guidelines will vary between different test labs, based on their customer’s experience.  However, they all follow the same general concept that the more deep the color the higher potential the fluid has for deposit formation. Most labs consider MPC results greater than 40 dE as critical.  

Download Rethinking Condition Monitoring Strategies for Today's Turbine Oils

Like with all oil analysis tests proper interpretation should take into account the application and operating conditions. Only by understanding how the results relate to a specific lubrication system does a facility fully understand the reliability risks posed and direct appropriate corrective actions. 

 test isolates oil degradation products on a membrane and measures the color with a spectrophotometer

Different power plant applications can have varying degrees of sensitivity to lubricant deposits. This means that MPC results of 30 dE could pose a high reliability risk for one power station while the same results could translate into little operational concern for another station. Here are some examples of different power plant applications and their sensitivity to varnish-deposits.

 – New generation gas turbines have made significant improvements in efficiency. One contributing technology to efficiency is more precise controls provided by the servo-valves. This translates into control systems with increased varnish-deposits sensitivity, meaning that newer gas turbine models may be more prone to reliability problem than older designs.

 – Gas turbines that are operated in a peaking or cycling fashion can be more sensitive to deposits than base-loaded units. One of the reasons is that turbine oil varnish has temperature variable solubility and transitions in and out of solution based on the fluid temperature and pressure. Cycling units may maintain the lubricant in the reservoir at a constant operating temperature; however the fluid’s temperature in the hydraulic circuit may have dropped to ambient temperature which provides an opportunity for degradation products to precipitate and form deposits in sensitive control zones.

Separate Hydraulic system versus combined system

 –Turbine lubricating systems that utilize the same fluid as a bearing lubricant and a hydraulic fluid for the control system may be more sensitive to deposits formation than those designs with a separate hydraulic reservoir.

 – Hydrogen-cooled turbo-generators are commonly used in single shaft, combined cycle and steam turbine application. Often, the oil acts as a sealant in conjunction with a labyrinth seal to ensure that no hydrogen migrates into the lubricating oil. Some of these seal designs are sensitive to small amounts of deposit formation in the oil flow lines resulting in lowering of the fluid flow rates, less efficient cooling and in some cases, oil starvation. This may cause a seal failure creating a possible safety issue.

There are several other design factors and operating conditions that may determine a turbine lubricating system’s sensitivity to deposits. All of this information should be taken into account when fully interpreting MPC results and assessing the risk to power plant reliability.

Occasionally, we see situations where there is significant varnish in the lubricant system, yet the MPC results are low. This has been observed when the oil has just been changed but no flush was done to the lubricant system. The new oil has a low MPC value, yet varnish is still throughout the lubricant system. We also witness a discrepancy in MPC results and varnish in the system at the end of an outage. If the oil has remained cool for a few weeks, there is an opportunity during this time that the degradation products will have precipitated out of the oil to form deposits in the reservoir. Pulling an oil sample at this point may indicate a low MPC value even though there are deposits in the system.  This is an example of improper sampling that should be avoided.

The reverse can also be true. Sometimes, we see high MPC values yet minimal deposits in the system. This can occur when the fluid is at operating temperature with minimal cold zones to cause precipitation, and the operating pressures are insufficient to drive the degradation products out of the turbine oil.

MPC (ASTM D7843) provides users with a better predictive tool for measuring the degradation products in turbine oil. It’s important to keep in mind that the MPC test is measuring a turbine oil’s 

 to form varnish. Like with all oil analysis results, to properly interpret the data and correlate them to system reliability, one must understand the application and operating conditions. As many analytical tests, it is also significantly more valuable to view the test as a trending tool rather than a test to take a snapshot.

The author is a Certified Lubrication Specialist at Fluitec International, Jersey City, NJ

Questions for you: What are your thoughts on interpreting results using the new ASTM Standard for varnish potential? Does your facility utilize trending to assist with these mitigation practices?