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Turbine Oil Degradation

November 01, 2013
Greg Livingstone
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What: podcast interview transcript for STLE's blog: The STLE Compass | click here to play the full podcast

Topic: Turbine Oil Degradation

Interviewee: Greg Livingstone, Chief Marketing Officer for Fluitec International. Contact information can be found in our member directory.

SNIEGOWSKI: Hello, I’m Kara Sniegowski. Welcome to the STLE Compass, brought to you by the Society of Tribologists and Lubrication Engineers. The STLE Compass is your convenient and reliable resource for the latest information and developments in the tribology and lubrication engineering fields. In today’s episode we’ll be looking at turbine oil degradation with the help of Greg Livingstone. Greg is the Chief Marketing Officer at Fluitec International based out of Jersey City, New Jersey. He is responsible for Fluitec's marketing and Science & Technology group. Greg has been involved with lubrication contamination control and condition monitoring for the last two decades. He's a Certified Lubrication Specialist and has held industry leadership roles in several committees including ASTM’s Turbine Oil Analysis and Problem Solving Committee and STLE’s Power Generation and Wind Turbine technical groups. He has over 40 published papers focused on lubricant condition monitoring and contamination control. And with that introduction, we’ll go ahead and get started with today’s discussion. So, welcome and thanks for joining us today Greg!

LIVINGSTONE: Thank you very much.

SNIEGOWSKI: Glad to have you, yet again. Before we get started, can you give us some background on the types of oils that are used in turbines?

LIVINGSTONE: Yes, of course. When most people refer to turbine oils, they refer to rust- and oxidation-inhibited circulating oils that are typically used in steam and gas turbines. These are mineral-based oils that have ISO viscosity grades of 32 or 46, and in some cases in hydroelectric turbines, we may see a viscosity grade up to a 68. We’ve seen a fairly big change in how turbine oils are formulated and manufactured over the last couple decades. A couple decades ago, a turbine oil would typically be made from a Group I base stock and about 98-99% of the formulation is a Group I base stock, however, in most cases now, turbine oil formulations are using a Group II base stock, combined with more complex antioxidants and more complex additive systems. The reason it’s important to know that, for today’s discussion, is that different oil formulations/chemistries, as they’re exposed to thermo-mechanical stresses and as they degrade in service, they will produce different degradation products and yield different performance results. That’s a quick overview of the types of turbine oils that we see in the market today.

SNIEGOWSKI: Jumping off of that – what is oil degradation and where or when would it occur?

LIVINGSTONE: Typically we just refer to oil degradation as a phenomenon that happens due to thermal and mechanical stress when the fluid is in service. That being said, it’s not necessarily the only time we see turbine oils degrade – sometimes we’ll see degradation due to improper or prolonged storage. Recently we saw an example of a turbine oil that was shipped to a customer in Polypropylene totes, then stored outside for a period of time before this new turbine was commissioned. The UV light, or sunlight, penetrated the polypropylene, and caused some significant additive depletion and fluid degradation before the fluid was actually opened and used, therefore had to all be discarded. But, in most cases, we refer to oil degradation as something that happens to oil when it goes into service. Keep in mind, when a fluid does degrade, there are two things we’re looking for. There are chemical changes and also physical changes that happen to the fluid. Chemical changes in the fluid are typically the first thing that happens, so it’s important to understand those from a condition monitoring perspective, and that’s why chemistry is an important aspect of CM, however, in many cases we see that chemical changes in the oil don’t result in any kind of negative performance attribute. For example, antioxidants are sacrificial, they’ll deplete, it’s easy to measure these, however an oil that doesn’t have any antioxidants in it, or if the antioxidant system is depleted, it won’t cause any system failure or problems, but once the antioxidants deplete and if the oil starts to generate deposits, sludge, and varnish, then these physical changes will directly tie to mechanical and performance problems that we see in the field.

SNIEGOWSKI: You mention one example of oil degradation that you’ve seen in the field – are there other challenges or examples you’ve seen in the field, and how have you remedied that in the past?

LIVINGSTONE: We see a lot of challenges with oil degradation in the field. In most cases, the failure mode of the fluid is due to some form of degradation, certainly with turbine oils it is. In gas turbines it’s very common to see issues related to varnish and sludge, causing fail-to-start conditions or unit trips – actually tripping the gas turbine offline when it’s operating. We also see performance problems with the clogging of small oil orifices. One interesting example in the gas turbine oil world that we’re seeing a lot more of – hydrogen seal failures. We are starting to see more and more of these failures especially with some models of gas turbines – they’re really costly failures for plants, and traditionally there hasn’t been an assumption that it’s a varnish-related or oil degradation-related problem. We’re starting to see a pretty strong tie to oil degradation and some of the hydrogen-seal or gas-seal failures that we’re seeing in the field now as well. So, we look at turbine oils that are used in compressor applications, we are seeing much higher bearing temperatures due to deposits and varnish, which can cause premature wear to the bearing and also bearing failures, and we also see premature gear wear, as gears get coated with these degradation products and deposits, all of which lead to premature gearbox failure. We have seen an issue with heat exchangers being clogged and these deposits can act as a very nice insulator and really lower the performance of heat exchangers, and if we look at steam turbines, one of the failure modes are higher bearing temperatures, which are fairly common, but also some of these degradation products may indirectly affect how the steam turbine oil can interact with contaminants such as steam leaks or water that can get into the system. One quick example of some of the issues that we’ve seen in steam turbines that’s fairly unique – and I think one of the values in really trying to understand why your fluid is failing and the mode of failure is that we’ve seen in some steam turbines – there is a steam chemistry that’s used in the plant and if there is a steam leak, there is a specific degradation mode that can happen with the steam chemicals as it mixes with the oil chemistry, producing a different type of deposit. It’s interesting to be able to characterize and understand what’s happening and what the original mode of failure is because in this particular case, these deposits that may occur from steam leaks, are not readily detectable with most oil analysis tests. So, it’s really important to understand not only how the fluid is failing and what can be measured in oil analysis tests, but to try and back up and understand why.

SNIEGOWSKI: So, what are some of the different degradation mechanisms that can occur in turbine oil systems and why might we care?

LIVINGSTONE: I’ll answer the second part of the question first – so, why do we actually care why or how the fluid is failing? There are two important aspects of this. The first is that if you understand the different modes of degradation that’s impacting the fluid, in many cases we find that it’s possible to stop that mode of degradation. The next aspect of this is that you can’t effectively solve the problem if you don’t know what the problem is and what’s causing it. So, understanding why the fluid is failing or how it’s failing is really important and if we talk a little bit here about condition monitoring as well, you can’t set up the right condition monitoring tests unless you know how the fluid is failing. So, it’s very important to understand these different modes of degradation.
In the case of turbine oils, there are many types of degradation, but there are four that we look at most often: oxidation, thermal degradation, additive depletion and contamination, and we’ll look at each of these briefly.

Oxidation will happen to all oils in service. Essentially, it’s just the loss of electron from the oil molecule or atom. However, the oxidation will be catalyzed and sped up with temperature and certain catalysts, so if you have much more oxygen in the environment, oxidation will happen much quicker. But on the whole, oxidation is a fairly slow-acting phenomenon that happens with all oils in service. Quite honestly, it happens to our human bodies and it happens to food if you leave it out on the counter, so oxidation is a very common form of degradation.

A more rapid form of fluid degradation that we see in turbine oils is thermal degradation. Thermal degradation essentially is a mechanism that happens when you have temperatures in excess of 300 degrees C. At that point, you’re starting to cleave or crack the hydrocarbon backbone of the lubricant. There are a couple different causes of thermal degradation in turbine oil systems – spark discharge is one – the accumulation of static electricity due to molecular friction that’s generating static as you have dry, super non-conductive oil at high flow rates passing through small orifices, you can create very powerful sparks that will cause the oil to degrade. Micro-dieseling is another form of thermal degradation – it’s a high temperature event where you have the implosion of an air bubble as it transfers from a low pressure zone (from the reservoir)  to a high pressure zone (into a pump) and that pressure will cause that bubble to implode and create a localized, very hot spot. And occasionally we’ll see a high temperature zone that’s greater than 300 degrees C and that will also thermally degrade the oil. So, in the case of turbine oils, if you have a very hot steam leak somewhere into the oil, that extremely hot steam could cause some rapid degradation to happen.

The third form of degradation – additive depletion – the primary thing that we’re looking at in turbine oils are the antioxidants. They are sacrificial in nature and are designed to be more reactive than the base oil, so as the fluid degrades and produces these free radicals and these different degradation products, antioxidants are designed to stop this chain reaction and stop this oxidative cycle from happening.

Contamination is another key mechanism for fluid degradation. The key contaminants we see in turbine oil applications are air getting in the fluid, water can be a major contaminant and can cause loss of lubricity, rapid changes in viscosity and rapid depletion of antioxidants and other additive components – we also see other contaminants or other liquids that may get into the turbine oil that could result in premature degradation. Examples of this may be incompatible formulations, or maybe preservative oils or vapor phase inhibitors that may not be compatible with the formulation. There may also be cleaners that are used in maintenance outages that are also incompatible with the fluid.  All of these different aspects are different modes of degradation that we commonly see in turbine oils.

SNIEGOWSKI: We hear a lot about varnish – where would this fall in the oil degradation process? Is it part of it?

LIVINGSTONE: It absolutely is. Taking into account that all of the different modes of degradation that I just referred to will first cause some type of chemistry change to the oil. The physical manifestation of this oil degradation is typically varnish. It’s not the only one. Occasionally we’ll see other physical attributes of the fluid change – in some extreme cases you may see the viscosity start to increase, but in most cases in turbine oils the physical manifestation of oil degradation is, in fact, varnish.

SNIEGOWSKI: What are some remedies for varnish or degradation in general

LIVINGSTONE: There are many different ways of solving varnish or oil degradation. The most important point here, though, is that you can’t effectively go about solving the problem unless you understand what’s causing it to begin with.  Understanding the mode of degradation is critical. In many cases, such as spark discharge or micro dieseling, if you identify that as a contributing mode of degradation to your turbine oil, there are proven methods that you can eliminate and stop that mode from happening altogether. First, you have to understand what is causing the fluid to degrade and then you can take corrective action. One common thing that a lot of people look at – they will install a varnish control technology. We have seen a real evolution of advanced, highly functioning and high performing varnish mitigation equipment in the field and typically these are branched into three general categories: electrostatic oil cleaners, or agglomerators, depth media filters, and chemical filtration. Those are the three types of varnish remedial technologies that we see and the key part is applying the right technology at the right time. The key difference between the three technologies: chemical filtration will allow you to remove the soluble products when they are both in solution and suspension, whereas depth media and agglomeration or electrostatics are removing these products when they are suspended in the oil. So, there’s a difference when you apply these technologies. Say the oil is operating at 50-65 degrees C, all of these degradation products are in solution, so in a situation like that, it’s more effective to put a chemical filter on the system that can remove these degradation products while they’re soluble and while they’re in solution in the turbine oils.

SNIEGOWSKI: Are there some oils or ingredients in oils that tend to lead to varnish over others? And if so, what are some ingredients/formulations to avoid or to select?

LIVINGSTONE: That’s an interesting question. Years ago, there was a general feeling in users and power plants in the industry that turbine oil is turbine oil and there isn’t a big performance difference in the types of formulations we see in the field. I think there’s an understanding now and we’re starting to see some very big differences in turbine oil formulations and some turbine oils will perform much better than others and there have been some additive components that have been identified that are not necessarily so good for varnish. For example, there’s a type of amine antioxidants – Phenyl Alpha Naphthylamine….also known as PANA that has been shown to provide a very high oxidative stability to the product, but also conversely, develops a lot of deposits as it degrades. So there are some oil chemistries that formulators will try to minimize or avoid when formulating products. The most important aspect though, is that even though there’s a different range of performance in new turbine oils, all of the turbine oil will perform well if it’s monitored and maintained correctly. Choosing the best oil is important and avoiding certain additive components that lead to varnish are important, but once you make the decision and the fluid is on site, the critical aspect is how you monitor and maintain the fluid.

SNIEGOWSKI: When you’re talking about the selection process, are there tests to determine the amount of varnish or degradation that might occur with a particular oil – and if there are, what tests would you run, when would you run them and why?

LIVINGSTONE: To more concisely answer this in a short time frame, the key aspects of monitoring in-service turbine oils are looking at the antioxidant health of the fluid. That can be measured through a couple of tests – FTIR is a good tool to look at phenolic antioxidants and linear sweep voltammetry is also a good tool to look at the antioxidant health of the fluid.

Antioxidant health is critical – the next important part is the potential of the fluid to develop deposits and varnish. There are several different tests that can be applied for assessing this. The most common one is the membrane patch colorimetry test, ASTM D7843. But there are other tests as well that are valuable – ultracentrifuge, there’s no ASTM method, but it’s a methodology that exerts a very high amount of G force and will separate the heavier components such as sludge and varnish, so you can visually assess the amount of deposits, or the deposit-tendency of the fluid, and gravimetric patch tests as well. Some labs see a value in running a combination of these different tests to provide even more insight into the varnish potential of the fluid.

The third critical aspect to look at for monitoring the degradation of in-service turbine oils is to look at how the fluid will interact with contaminants. This is a property that could change over time. Some of the main contaminants that we’re concerned with include air – looking at air release values is important and monitoring these values, and also foam tendencies. If a lot of air does get into the fluid, is the chemistry of the fluid still stable enough to allow the foam bubbles to dissipate quickly or is the surface tension of the fluid changed enough that you may have a foam problem now? The other key contaminant that we want to look at are demulsibility – or how will the fluid interact when the water or steam gets mixed in with the turbine oil. Demulsibility retention is an important aspect. We want the turbine oil to continue throughout its life to rapidly shed water.

SNIEGOWSKI: To finish out our discussion, what would you like to make sure listeners take away and use going forward?

LIVINGSTONE: I would say that understanding the mode of fluid degradation is very interesting, but it’s beyond academic. There is a very high value in power plants and turbine oil users in really understanding how and why the fluid is failing. There are now advancements in testing methodology that we can characterize and extract out of the oil historical data that has been stored up in the oil that allows us to understand why and how the fluid is failing and characterize the deposits being generated. Going through that process is a very powerful and valuable activity for a power plant to enable them to, in some cases, eradicate that form of degradation and in other cases, make much better decisions on how to go about solving oil degradation. And ultimately, if you can solve oil degradation, or at least understand and monitor it, the end result is you are truly maximizing the life of the turbine oil and minimizing any performance problems that will come up.

SNIEGOWSKI: Good ending to today’s discussion. Thank you so much Greg and we’ll see you soon!

LIVINGSTONE: Thanks so much, Kara.

SNIEGOWSKI: Greg, thank you so much for joining us today and for your insight. For more news, information and research on power generation and turbines please visit our website. Thanks for joining us today! This has been another episode of the STLE Compass, pointing you in the right direction.

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