Turbomachinery Expo 2015 took place in June in Montreal, Canada under the auspices of the ASME’s International Gas Turbine Institute (IGTI).
Over 3,000 participants were served up more than 1,000 technical sessions covering the length and breadth of the turbomachinery landscape. Topics included supercritical CO2, surface coatings, steam turbines, combined cycle plant challenges, aircraft engines, combustion dynamics, turbochargers, vibration, compressor aerodynamics, wind power and more. The show even featured a historical exhibit of turbomachinery, especially early jet engines (Figure 1).
Perhaps the most valuable session in the whole show was part of the Electric Power track. Entitled, “User Experience with Gas Turbine Technology,” it provided the opportunity to hear exactly how major utilities and oil & gas producers harness GTs to provide power for their customers.
Rick Tomlinson, Turbine Fleet Reliability Engineer at Chevron Power and Energy Management, explained that a wide range of Chevron’s GT’s are used for many different types of duty including liquefaction, shipping, regasification, gas source power and gas processing. Chevron’s fleet amounts to 5,300 MW with an additional 2,000 MW being built.
From 100 gas turbines in 2012, this will expand to 141 by 2017. “Gas turbines are important to our bottom line, being used in power generation, cogen and mechanical drive,” said Tomlinson. “They will be a larger part of our company in the coming years even though GT’s are not our core business.”
This fleet is 30% heavy industrial turbines, mostly for power generation but their use in mechanical drive is growing. Some 60% would be classified as light industrial machines of 20 MW or less. They are mixed evenly between power and mechanical drive, and are mainly deployed in remote areas.
The remaining 10% are aeroderivatives although this is an area Chevron expects to grow significantly in the next few years. Initially, these machines were deployed to produce power. But the mechanical drive portion is increasing.
“There are several new LNG facilities coming online, which will boost our aeroderivative fleet as well as our mechanical drive numbers,” said Tomlinson. “As our history has been in non-aeroderivative turbines, we are working to gain more expertise in this area.”
Tomlinson manages this diverse fleet using a number of metrics. The service factor is 80% overall with the top quartile being 92%. These machines, he said, are running 8,000 or more hours per year.
Another factor in fleet diversity is that Chevron has many 50 Hz and 60 Hz models. Further, there can sometimes be a 50Hz power island in a 60Hz country. This makes reliability even more critical.
“Our most important GT in sour gas injection accounts for millions of dollars per hour if it is not running,” said Tomlinson. “The chairman of Chevron is informed on its maintenance intervals and schedules.”
As the fleet is subjected to continuous duty, downtime is always a challenge. The company uses a centralized fleet support model to deal with maintenance planning and execution, fleet reliability management, sharing of lessons learned and new project support.
The GT team looks at good examples of turbine reliability and how to replicate those in other areas. It focuses on key performance indicators (KPIs) which are prioritized as reliability and availability followed by efficiency, heat rate and then capital parts lifecycle costs. Predictive analytic trending is done by Chevron’s monitoring and diagnostic center.
Looking at the fleet as a whole, there is a lack of F-, G- and H-class turbines. “We focus on the E-class as we have the expertise in that technology and don’t need to get into the higher classes,” said Tomlinson. “We like the reliability, familiarity and size of the E-class.”
Changing energy mix
Ten years ago, Duke Energy, the largest U.S. utility, had 5% gas generation, 55% coal and 36% nuclear. Today, gas is up to 24% at the expense of coal. As a result, Duke now operates more than 200 GTs. This includes 22 7FA/7FBs, 22 501Fs, 60 7EAs, 6 501D5Aa, 30 mature frames (GE Frame 5 to Frame 7s) and 20 Westinghouse W501AA/W191s. The company has established tiers of importance to prioritize those GTs that have the most impact on the bottom line. Most of this fleet is combined cycle, though some simple cycle peaking units help ensure grid availability.
Reliability metrics used for combined cycle plants include: Equivalent Forced Outage Rate (EFOR) which is the percentage of time a unit is forced offline or de-rated compared to the expected amount of time it should run; and Equivalent Availability Factor (EAF), a measure of available capacity compared to rated capacity.
“We have had some issues on EAF for our combined cycle units,” said Rajeev Aluru, Principal Engineer in Generation Services at Duke Energy. “EFOR has been going slightly up and we are looking for what’s causing this.”
Like Chevron, Duke Energy considers the latest gas turbines as a risk due to lack of repair alternatives, lack of expertise, and the fact that they are not yet regarded as proven technology. The company currently has long-term service agreements (LTSAs) but it hopes to transition to self-performing of maintenance and operations.
Aluru gave the example of a row 1 nozzle on a GE turbine. He said that you can change the operational characteristics of the whole machine by adjusting the nozzles slightly, yet how many of his engineers understand that?
This lack of hands-on experience can lead to errors in maintenance. Another challenge is continuous design evolution in turbomachinery. This creates complexity and necessitates retaining a large number of part numbers.
“We need to know as much as the OEM and that’s not easy, but that’s where we want to be,” said Aluru. “As units age, system understanding becomes more important.”
Fuel flexibility is also causing problems. Shale gas, for example, contains plenty of contaminants which lead to variability in the composition of hydrocarbons and the overall chemistry of the gas. Shale has a large percentage of ethane compared to gas from the Gulf of Mexico, which results in a higher BTU product compared to traditional gas. Auto-tuning, therefore, is required to deal with sulfur content. All this affects GT maintenance and availability, as well as lifecycle costs.
The company is wrestling with big changes on its home turf in North Carolina which has enacted a mandate to have 12.5% renewables by 2021, up from 1.5% in 2009. This requires Duke to add more GTs that can ramp up or down rapidly to cope with renewable variability. The utility is adding more than 2,700 MW in the next couple of years.
The U.S.-based utility NRG has a fleet of 250 GTs as well as spare engines on hand to reduce downtime. This consists of mostly LM6000s and five LMS100s, as well as many older E-, D-, C-, B-, A-class and 1960s-era units. There are some F-class units in operation and some H-class machines are planned for Southern California.
“Life would be easier if we were only running 20- and 30-year old machines,” said Joe Schneider, Gas Turbine Maintenance Manager at NRG Tech Services.
For the old units, NRG uses run-to-failure maintenance. Schneider said it cannot financially justify putting in new blades, vanes and controls in these machines. The plant employees self-maintain some units and have LTSAs for others.
“With 250 units, limited staff and resources, and cyclical budget pressure, I’ve changed my mind from self-manage to LTSA,” said Schneider. “Costs are levelized and it’s easier to justify costs as a contractual requirement.”
Read more in the September/October 2015 issue of Turbomachinery International
