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.
The MPC test is a newly approved ASTM standard called the D-7843, Standard Test Method for the Measurement of Lubricant Generated Insoluble Color Bodies in In-Service Turbine Oils using Membrane Patch Colorimetry. 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. 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.
- Large frame gas turbines – 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.
Operating Mode – 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.
Seal oils – 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 potential 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?
