D11 issues take center stage as users share O&M experiences @ STUG

The Steam Turbine Users Group (STUG), now co-located with the Combined Cycle Users Group (CCUG), was held in Orlando August 25-27. The confab offered a plethora of O&M experiences for owner/operators. Here are some of the highlights.

First, it bears noting that the organizers (www.powerusers.org) unveiled an audience “polling” feature. While it may seem gimmicky, it’s actually a lightning fast way to crowd-source responses among peers. If you had a burning issue or question with your machine, attending the STUG and getting 50-100 users to address your concern in real time is probably in itself worth the time and expense.

Issues with the General Electric D11 steam turbine, obviously a popular machine with CC operators, took up a good portion of the air time at STUG. The opening presentation, probably among the strongest at the meeting, gave ten ideas to shorten a D11 outage, based on this owner/operator’s experience with one at a utility service territory site and another at merchant/IPP site. His ideas ranged from appointing an experienced outage leader to installing a dedicated freight elevator.

It goes without saying that each steam turbine major outage will be different depending on the activities required. As a simple benchmark however, the utility owned/operated unit completed the outage in 60 days and had 60,000 hours of run time. The non-utility site team completed outages in 40 and 30 days (two D11s at this site), each with around 100,000 operating hours. An audience member stressed that you can’t do a D11 major outage in 40 days if you have blade issues.

Owners of D11s are undoubtedly familiar with problems across the fleet with the N2 packing box. An audience member noted that QA/QC procedures at the vendor’s manufacturing facility were deficient during the height of the combined cycle sales and installation bubble (1997-2001) and that the root cause was poor castings from Japan.

Another user addressed N2 packing head cracking and h-p and i-p shell cracking in a 1995 vintage machine. Regarding the former, the surprise was discovering cracks in locations different from those mentioned in the vendor’s Technical Information Letter (TIL), cracks that were visible to the naked eye.

Several users reported they manage the N2 packing issues by having a spare or two handy. Depending on the types and location of cracks, repair can be two times the cost of replacement said one user who found cracks around the bowl in addition to the seat. GE’s policy is that they will grind the cracks out but will not weld-repair them, with the possible exception, as noted by one user in the audience, of an excavated pressure tap crack.

Other users have done weld repairs, however, so the solution is anything but straightforward. But more frequent monitoring and inspection are necessary after repair. In one user case, GE requires the heads to be inspected every year. Restrictions on performance are also possible.

Polling break: 50% of the users have experienced h-p/i-p shell cracking

Later in the day, the audience was treated to a visceral video of what happens when a D11 stop valve pressure seal head gasket fails. This presenter noted that there are lots of problems with these valves and lots of troubleshooting required.

In this instance, however, minor issues were precursors to the major gasket failure, including steam leak-off piping modified during a recent outage and incorrectly routed to the drain tank (rather than the steam seal header), i-p cycle pressure set point too high causing valves to throttle, and drain tank overfilling during startup, and backing up to the stop valve. Also pertinent, this 2×1 plant cycles twice per day.

This user has several D11s in its fleet but apparently all of them are different enough that there is no interchangeability of components.

A user with 10 D11 steam turbines in his company’s portfolio discovered one rotor with a 17 mil bow in it six months after its second major outage, apparently caused by piping stresses from pipe hangar issues. Other findings were both expected and surprising, he said. He also reported on water induction induced vibration damage to h-p and i-p turbine stages and dozens of major cracks found in a valve chest caused by water induction and aggressive day/night on/off cycling.

In a general session on h-p and i-rotors, another user reported on a 21 mil rub-induced rotor bow which was subsequently spot heat-treated to get the bow under 3 mil. A snapped N2 packing box was the cause. Still another reported on a 14 mil rotor bow, which was mostly corrected with heating lathes.

Polling break: 23% of the users conduct a major steam turbine/generator inspection at 6 years or less, 26% between 6-8 years, and 30% at eight years or more.

During a presentation on turbine bearing failures resulting from lube oil cooler leaks, the user stressed what a nightmare it is trying to rid lube oil piping of water. He lamented eight months of heartache from excessive amounts of water in the lube oil system. An audience member warned that lube oil tanks sitting at low levels accumulate water, more so in high humidity climates. One 10,000 gal tank holding 2000 gal of lube oil accumulated 1000 gallons of water over a two-year period!

Other audience members offered these cautions:

      • Always assume the worst of tanker trucks

      • Gasket areas and metal dips and joints are sources of gunk

      • Varnish can accumulate on the tank sidewalls

      • Lube oil coolers can and will leak and the integral-fin variety are difficult to check through eddy current testing

      • Rental chillers, especially if workers are unfamiliar with how they operate, used to maintain temperature while flushing, can shock a lube oil system and knock gunk off the equipment

Polling break: 43% of steam turbine users perform main stop valve freedom testing daily, 38% weekly.

An interesting note here, especially for those who are responsible for the gas turbines at CCs, according to an audience member: Many steam turbine/generators have common lube and hydraulic oil systems, which is not common for GTs.

One audience member asked about after-seat drain line overheating. In response, the organizers engaged their polling mechanism:

Polling break: Only 13% had experienced this issue, while 66% responded no.

Finally, there were an item of note from the session, Future Outage, Maintenance, and Operational Challenges. One user highlighted her company’s first use of a submarine drone to inspect cooling water pumps. These have become critical reliability components as one user claimed the lead time for a replacement is 6-9 months and the motor alone costs a quarter of a million dollars. Plus, spares have special storage requirements. As one user put it, “it’s not easy to store a 30 ft vertical pump.

Polling break: 55% of users apply condition-based evidence to the inspection interval for their vertical circulating water pumps, while 34% base the interval on calendar time or operating hours, and 12% run them to failure.

Posted in CCUG |

Comments are closed.