ROTORS AND CONTROLS VEX 7EA USERS

VANE CLASHING, ROTOR END-OF-LIFE, CONTROL UPGRADES AND OBSOLESCENCE DEBATED DURING EVENT

The annual GE 7EA Turbine User Group met in Monterrey, California in October. Some 138 users were treated to three days of slicing and dicing every aspect of turbine maintenance, including a morning from GE reviewing relevant Technical Information Letters (TILs), an examination of vane clashing, a discussion on rotor life, a panel on control system repairs and upgrades, and a briefing on inlet air fogging.

Pat Myers of American Electric Power and leader of the 7EA User Group moderated a roundtable on compressor blade clashing. Panelists included Michael Hoogsteden and Rod Shidler of Advanced Turbine Support (ATS), Tom Brooks, Sr. of Power Systems Manufacturing (PSM) and Rodger Anderson of DRS Power Technology.

Clashing occurs when a stationary vane moves forward more than half an inch and the leading edge tip of the vane makes contact with the trailing edge of a rotating blades. The causes are said to include casing deformation due to differential cooling, and expansion resistive forces, as well as surge-and-stall events during startup and shut down, and a vane vibration resonance frequency shift due to vane and slot lock up.

“Clashing creates higher stress areas on blades resulting in cracking and blade liberation,” said Myers. “Vane or blade failure at the front end of the compressor will result in corn cobbing of the compressor.”

Clashing on the 7EA was first recognized in 2009 on the S1 leading tip of the stator. GE recommends replacing the vanes and ring segments with redesigned components that reduce the potential for blade lock up.

However, this can be expensive. Alternatives include the use of Non- Destructive Testing (NDT) and a borescope to verify the presence of clashing and see how it is progressing. If detected, one way to mitigate the damage or at least slow it down is to lubricate the clashed areas. Myers said this seems to help though it did not solve the problem entirely in his peaking units. He also suggested cropping the vanes to avert future trouble.

Another theory for the cause of clashing is bending of the case due to temperature shifts. One user said that when the machine goes from cold to hot, the casing moves by half an inch. Anderson of DRS set up an inclinometer at one plant to measure the shift in incline of the casing as it heats up. This showed enough deflection to move the tip closer by about 20 thousands of an inch. That does not sound like much, but it could well be a big reason for clashing.

What happens is that the casing is bolted firmly in place at each end but has a flex plate in the middle that can move. This leads to bowing of the compressor as it gets hot. Anderson also explained that casing thickness varies slightly due to the casting process which has a tolerance of plus-or-minus one-third of an inch. This is another element that can take away precious clearance.

ATS performs thousands of inspections a year and over the last few years has noticed the increase of clashing in 7Es and 7Fs. Shidler said that regular borescope inspections will not detect this phenomenon. One has to look closely and know what to look for.

In the past, said Hoogsteden, clashing damage occurred mainly to the stator vanes in the lower half of the compressor, where corrosion is more prevalent. But more recently, damage has been identified in the upper half of the compressor. “In the past month, we have inspected 40 7EAs and about 45% have clashing damage,” said Hoogsteden. “The TIL on clashing talks about R1 and S2 damage, but we are starting to see it on R2 and S2 as well.”

The TIL recommends visual inspection of blades and vanes. However, the problem can be difficult to see sometimes. ATS recommends performing an in situ eddy current or dye-penetrant examination on all affected stator vanes and blade platforms that have come into contact in stages 1 and 2.

Rotor life and death

Wednesday featured a rotor lifecycle roundtable where vendors and consultants answered questions regarding a TIL by GE indicating that 200,000 hours or 5,000 starts were the end-oflife limits for the 7EA.

Myers moderated and speakers included Ashok Koul of Life Prediction Technologies, Mike Burton and Paul Tucker of First-TBS, Richard Curtis of ETA Technologies, Chad Garner of PSM, Greg Snyder of Dresser-Rand TTS, David Taylor of Masaood John Brown and Ted Papageorgiou of TurboCare.

One user asked why an hour’s limit should exist if you find nothing wrong after a thorough inspection on an aging machine that has reached the OEMmandated limit. Panelist responses were many and varied.

Koul said that each inspection technique had a detection limit that could miss certain types of damage or crack sizes. One must assume that a crack exists at the fracture-critical locations in the rotor assembly and compute an inspection interval for future engine overhauls based on analysis guidelines provided in MIL-STD-1783B of USAF.

Most agreed that you did not necessarily have to shut down the machine once the TIL limits were passed. “I disagree that you have to replace the rotor at OEM end of life,” said Tucker. “It is ultimately an end user choice, but if you find nothing, in our view, it is good to go. However, you should continue to inspect critical parts and follow up with eddy current inspections.”

Curtis added that for base-loaded machines, the life of the rim of the turbine wheels is an important factor in overall turbine life, since these areas see the highest temperatures. In addition to inspection, modeling (engineering analysis) should be used to uncover any undue risk before the next major inspection.

A user’s decision to go over the OEM limit depends on the company’s appetite for risk, Papageorgiou said. The rotor is going to reach its useful life limit and encounter fatigue or creep, or lead to a forced outage situation — but the question is when. While the OEM is pushing for a complete rotor replacement, users can change out specific components and that, in most cases, might be as good as having a new rotor.

Another user wondered if onsite inspections could be done before sending out a rotor for repair. Curtis explained that there is only a limited amount of inspection you can perform on a stacked rotor, since critical features such as bolt holes or wheel and spacer bores cannot be accessed.

A site-specific engineering and risk analysis can still be performed with a model by inputting ambient conditions, compressor discharge temperature and other operating conditions. But in reality, de-stacking the rotor is required to tell how the machine is doing at what the OEM defines as end-of-life.

Some vendors claim that they could remove a rotor, ship it to their repair facility, conduct testing and have it reinstalled within 30 days. One panelist said that was an adventurous target due to how long destacking can sometimes take.

The type of inspection can also be a factor. A basic rotor inspection can be done rapidly. However, a lifetime assessment and lifetime extension is more complex: you have to know the history of the rotor, how many trips, hot starts, cold starts, and so on. Such an inspection should be planned and prepared months in advance to minimize the risk of delays.

And when it comes to lifetime extension, more advanced NDT inspection is called for to help the user decide how to progress with the rotor. Damage found during these inspections might be addressed with something as simple as blending a flaw or as complex as replacing specific disks, spacers and bolting.

“These three types of rotor inspections get progressively more complex,” said Papageorgiou. “If you have several units, it is a good idea to obtain a spare to make the logistics simpler.”

A user from deep inside the Amazon basin in Brazil said it was not feasible to ship his turbines to repair facilities. So he wondered about the value of secondhand turbine rotors as a spare. The advice from Curtis was to look for spare rotors or components from a baseloaded (hours based, low starts) machine if you are a peaking (startsbased) application, and vice versa, look for low-hour parts from a peaking operation if you run base load.

Several users questioned whether the TIL was a commercially driven document. The consensus from the panelists was that it might be 50% commercial, but they also noted that the OEM has a legal responsibility to warn users on lifecycle issues. Tucker said that these limits were far from new. “The OEM named these as the limits for the 7EA long before the TIL was published,” he said.

The OEM is using a worst-case scenario with these design limits. So by no means will all users be suffering from heavy damage at that point. In fact, the latest TIL allows for a life extension of around 50,000 hours. But it is up to the OEM to make fleet-wide recommendations which by their nature will be conservative. After all, there have been some failures and warranty claims. So the OEM is putting out TILs as there is risk.

Tucker stated that there have not been any failures on the 7EA relative to the issues covered in the end-of-life TIL. That does not mean there have not been damaged rotors, though. Koul said that second- and third-stage rotors in the assembly are most damage prone.

Several panelists addressed insurance. Far from only wanting to follow OEM guidelines by insisting a rotor be replaced when it reaches end-of-life limits, many insurers advocate thorough inspections, analysis and modeling, and taking mitigation measures to extend the unit’s life while evaluating risk.

One panelist wondered if it is possible to inspect only a few units in a fleet where all units have the same operating profile and ambient conditions. The panelists agreed that you have to inspect them all. Factors such as material variability and OEM quality-control practices mean that there will be variability among components and machines.

A murmur of approval could be heard when one user asked if the panelists had ever recommended going beyond the OEM-specified end-of-life. Koul said, yes, if you backed that up with an MIL-STD-1783B-based analy-sis and a strict inspection regiment that specifies what parts to look at and when to use a certain inspection technique.

A fleet of non-7EA turbines, for example, had been repeatedly inspected after the OEM’s design life limits of 100,000 hours were exceeded, and the fleet was still running at 300,000 hours. Cracked discs had been found at overhaul and replaced during that time.

Curtis emphasized that end-of-life decisions are done at the user’s risk. Inspection and repair firms can provide plenty of data so that decisions are more informed. “The increase in risk in going beyond the TIL limits does not warrant buying a new rotor based on our numbers,” said Curtis. “But the risk is your own.”

Finally, a user asked that if you destack and inspect at 200,000 hours and decide to continue running the machine, what do you do once you get to 50,000 more hours? Koul said you have to destack again if you want to know for sure. Otherwise, there is high risk of missing a sizeable crack.

Control upgrades

Thursday morning’s panel addressed control reliability and upgrade options for legacy systems. Moderator Ray Lathrop of Corn Belt Power Systems introduced John Downing of Turbine Controls and Excitation Group, Peter Zinman of Gas Turbine Controls, Craig Corzine of CSE Engineering, Kevin Kochinka of ABB, Ricky Morgan of Turbine Technology Services, Randy Riggs of Powergenics and independent consultant Luke Williams.

The subject rolled right into the heart of the matter: trouble with the GE Mark Vie control system. Downing emphasized that it was excellent software but the communication modules have a tendency to fail when you reboot the panels.

Many users have reported modules locking up both online and offline. Zinman added that the Input/Output (I/O) modules were not as robust as those on the Mark IV, V or VI, and that repair can be time consuming or cost prohibitive. There are also issues with parts availability.

“If someone says they are thinking of upgrading to VIe, we ask why,” said Zinman. “If you need a Mark Vie part and GE doesn’t have it in stock, there are not a lot of alternatives. But if you keep an older system, you have the option of independent repair and spare parts suppliers.”

How about Mark VI systems where the Human Machine Interface (HMI) and historian elements are failing? Some panelists offer HMIs for the Mark IV and V. Williams mentioned that you can image your HMI and load it onto another PC. Morgan and a couple of others said they had HMIs being tested currently for the Mark VI.

A discussion broke out concerning cards failing and burning out in lightning strikes. Williams said that the most effective method of preventing lightning damage is a ground grid that connects all the site equipment to the same ground potential. Of particular importance is equipment that has a copper wire interface with the control equipment.

“More often, these days, there is cost cutting during construction, which leads to less wiring and poorly grounded junction boxes,” said Downing. “Another area to watch for is corroded wiring and grounding.”

Meanwhile, users complained of screen lockups on the HMIs. One engineer said he had to reboot his systems every day due to this problem. As a result, GE went onsite and fixed it. Downing added that configuration errors may be involved.

GE was said to have locked down software so plant personnel and non- OEM engineers have difficulty making changes to the logic on the Mark VIe or adding additional I/O such as pressure switches and transmitters. The latest systems require passwords that even most OEM engineers cannot access. Replacement modules come with activation keys that must be properly included in the configuration files and downloaded to the controller to allow new modules to come online.

One user expressed satisfaction with an aging Mark V system and wondered how he could keep it alive. Corzine stated that you can extend life expectancy of Mark V systems as long as you have access to spare parts and technical engineering support. Some panelists said they supply replacement cards while others can repair them. The Mark IV can also be supported in the aftermarket.

Downing stressed that maintenance was key. He called the Mark IV, V and EX2000 robust platforms, which are less susceptible to cyber intrusions as there is a lower level of Ethernet access to the Internet. If well maintained, users can stay in these platforms for many years to come. The panel included some companies who stock Mark IV, V and Excitation parts as well as repair services for the circuit cards in these controllers. Some service providers have experts in these controllers that the OEM no longer provides.

While the Mark V hardly ever fails, it is far from perfect. Williams related a story from Bolivia where he calibrated Mark I and II systems installed in 1975. These systems had suffered the worst conditions and the worst maintenance he had ever seen. Yet they continued to run, and the turbine still produced power.

“That control hardware was bulletproof and it stayed that way through the Mark V,” he said. “Don’t accept that these older systems have reached end of life and have to be replaced.”

Alternatively, Morgan said there are plenty of systems available to replace aging controllers that cannot be repaired. Such systems can be integrated into plant-wide controls.

“If you already have PLCs and technicians that are familiar with them, that is a factor to consider when selecting a replacement system,” said Morgan. “But if you have people that have familiarity with GE controllers, you also have to take that into account.”

Inlet air fogging

The meeting included 109 exhibitors; and several provided presentations. Thomas Mee, CEO of Mee Industries, talked about improving gas turbine performance through inlet air fogging. He mentioned the original fogging overspray unit was installed at Watson Cogen 20 years ago. One user from that facility who was in attendance said the system was still running. He added that while that plant had media-type evaporative coolers as well as fogging for overspray, it is now taking out the evap coolers and replacing them with fog to reduce the amount of pressure drop.

Mee said his company had installed over 900 fog systems on gas turbines (197 on the 7EA, nine in the past year). The big news from his talk was a letter from GE stating that the company has no issues with fogging. Earlier, GE had issued a TIL banning fogging and water washing on 7FA machines (Turbomachinery International Sept/Oct 2010). “GE has no objections to fogging provided its TILs are followed,” said Mee.

Droplet size is the single most important factor in fogging, said Mee. He gave the users tips on understanding the spectrum of droplet sizes being emitted by the nozzles. For example, you only have about a second and a half maximum for the droplets to reach the inlet duct. By that time, they have to have evaporated enough for any remaining droplets to be less than 10 microns in diameter.

Further, it is important to use nozzles with small droplets and larger spray plumes to get the droplets evenly distributed in the air flow so that evaporation can occur. Similarly, you do not want a temperature difference at the top and bottom of the compressor inlet.