7F Users Group: A really big show

Okay, it’s a bite off Ed Sullivan and it’s real­ly not a “show,” but there may be no better way to describe the stature achieved by the 7F Users Group’s annual meeting in the gas-turbine-based sector of the electric power indus­try. The 2008 Conference in Greenville, SC, May 13-16, attracted more owner/oper­ators (254), more exhibitors (72), more sponsors (19), and more user speakers (15) than any frame user-group meeting in histo­ry—unofficially, of course.

At a 7F conference there’s something of value for every participant, all the time. Corporate Amer­ica could learn a thing or two about organization and what the term “value prop­osition” means from the empowered steering com­mittee of industry profes­sionals—volunteers all—who develop this week-long event that Sheila Vashi and her colleagues from Mariet­ta (Ga)-based Vision-Mak­ers make happen.

Paul White, manager of gas-turbine (GT) O&M for Dominion Energy, chaired this year’s meeting at the Hyatt Regency Greenville and then passed the baton to the 2009 Chair Ed Fuse­lier, director of engineer­ing (operations) for Direct Energy (Sidebar 1). Next year’s meet­ing will be at Atlanta’s Renaissance Waverly Hotel, May 12-15.

Owner/operators of GE 7F engines interested in participating in the 2009 meeting who are not registered members of the 7F Users Group are urged to submit their profes­sional profiles as soon as possible via the membership drop-down menu at http://GE7FA.Users-Groups.com/Membership/UserCandidate.shtml. Only registered members are invited to attend the annual conferences.

Likewise, companies interested in participating in upcoming meetings as a sponsor or exhibitor must complete a vendor profile for review by the steering committee. Do this at http://GE7FA.Users-Groups.com/Membership/AffiliateCan­didate.shtml. Only com­panies approved by the steering committee receive invitations.

Greenville venue adds another dimension to the meeting. GE 7FAs power the majority of large com­bined cycles across America and also find application in large process-plant cogen­eration service and increas­ingly as peakers. More than 1000 of these engines have been manufactured in Greenville for customers around the world; North America is home to about 700 operating units.

A highlight of this year’s meeting was a tour of the OEM’s 7F manufacturing facility. Actually there were several tours—two Monday afternoon for the early reg­istrants and two on Tues­day, the day before the tech­nical meeting—because of tour-group size limitations. If you have never visited GE’s Greenville plant and you have an opportunity to do so, go.

The value beyond the exercise associated with walking up and down manufacturing aisles about a quarter of a mile in length is one of perspec­tive. Plant personnel see assembled engines daily; sometimes during an overhaul they’ll see the upper cas­ing half removed and get a “feel” for what’s under the “hood”; a few times in a career they may see the rotor outside the casing. But only rarely do they see a rotor disassembled to get a first-hand view of the individual parts and how they go together.

In addition, there’s the even greater appreciation you gain for the engineer­ing, machining, and quality control that make these behemoths possible. If you’re not in awe of what is accom­plished in a factory like GE Greenville the first time you visit, perhaps you should consider another business.

Conference overview. Tuesday, officially the first day of a 7F meet­ing, is when most people arrive. It features special events and an oppor­tunity to talk shop with colleagues during the welcome reception in the early evening. This year’s special events included the annual 7F golf tournament (Sidebar 2), the GE shop tours noted above, and a special half-day session on F-class heat-recovery steam generators (HRSGs).

Day Two: Wednesday was a full day of user presentations and open-discussion roundtables dedicated to the 7FA’s compressor, turbine, and combustion sections. Vendor fair and reception ran from 6:30 to 10 pm and the ballroom was a hotbed of activity most of that time. An added feature this year was six 20-min sponsor presentations during the exhibition to update users on developments in repair technologies as well as on some new highly engineered products (Sidebar 3). These are profiled on pages 137-141.

Thursday was GE Day and the morning of Day Four (Friday) fea­tured user presentations and open discussions on auxiliaries and gen­erators.

Preconference session on HRSGs

The “spotlight” session that HRST Inc, Eden Prairie, Minn, has con­ducted in conjunction with the 7F meeting for the last several years is designed for senior-level plant personnel who want a refresher on heat-recovery steam generators and an update on industry concerns with large triple-pressure HRSGs. The course starts after lunch Monday, the day before the 7F sessions begin, and runs almost until the doors open for the welcome reception.

Attendance is capped at 60 to ensure that everyone’s questions are answered and that a collegial environment conducive to productive discussion is maintained. Regarding the value of participation, you be the judge: Users have to pay a special registration fee and forego golf to attend the session, and this year, like last, there were no empty seats.

The course agenda is as follows:

• Characteristics of F-class HRSGs. This is a short refresher.
• Non-pressure-part problem areas.
• Pressure-part problem areas.
• Layup and offline corrosion.

Training is only one of HRST’s core competencies. It’s a service line that evolved from the company’s boiler solutions work: inspection and analysis, field technical advice, engi­neered products (such as casing pen­etration seals, access doors, etc), and design upgrades.

You may be aware that HRST hosts a three-day HRSG Academy twice annually for those needing to dig into the nitty-gritty of boiler O&M. It’s ideal training both for the novice and intermediate-level per­sonnel. If you know relatively little about HRSGs, you’ll learn basics from boiler experts (not teachers) and gain the confidence necessary to do the best job possible after return­ing to the plant.

Non-pressure-part issues. Amy Sieben, PE, handled the segment on issues with non-pressure parts, covering inlet ducts, firing ducts, casing penetration seals, and access doors. She began with inlet-duct liners, reminding everyone that the big square “washers” that hold the liner in place should not be able to spin. Sieben suggested checking every washer during every sched­uled inspection—combustion, hot gas path, and majors.

Spinning washers? The editors “auditing” the course wondered how a roomful of top plant personnel could really think that spinning washers were more important than playing golf. But they were if your responsi­bilities included maintaining top effi­ciency and maximizing availability.

Here’s why. Washers left spinning often will saw through the stud free­ing the liner plate. Liner plates may lift up or come off altogether, allow­ing insulation to be sucked out, travel downstream, and blind the tube fins, CO catalyst, and/or SCR catalyst. Sometimes you can remove the insu­lation, sometimes that’s not so easy. Sieben mentioned one plant that had to toss the catalyst and install new. Expensive: The bill was $1 million. You can play golf anytime.

One word of caution when you find “spinners”: Be sure the maintenance team tack welds them to the stud or nut, never to the liner itself. Liner plates are designed to grow and slide independently.

Sieben rolled right through the pre­sentation, showing users how to check tube baffles for mechanical integrity and how to fix damage when you find it; where to look for cracks and worn or broken supports on flow distribu­tion baffles; ditto for duct-burner ele­ments. By then there was no thought of golf in anyone’s mind.

Liners downstream of burners got some attention, too. Be on the lookout for wear and tear caused by the selection of inappropriate materi­als, Sieben warned. Many liners, she continued, are designed to the bulk gas temperature without considering the radiant energy from the burner, which can easily add hundreds of degrees Fahrenheit. This is a mis­take. In some cases, the best material for a liner in this area is Type-310 stainless steel, not the much-less-expensive Type 304.

Casing penetration seals gener­ated considerable interest. Many illustrations of why rain in-leakage occurs at roof seals, the damage those leaks can do, and the housekeeping problems they create (Sidebar 4). Overheating at steam-pipe penetra­tions because of inadequate separa­tion was another topic covered. Then Sieben moved on to floor drains.

After viewing 50—yes 50—slides on problems with casing penetra­tion seals you had to come away with the feeling that their location, and the type of seal selected for a given application, often were afterthoughts at the design stage. This part of Sie­ben’s presentation obviously was of great value to maintenance man­agers in the room. It showed them where to look for seal problems and identified corrective action—to the extent that design oversights could be corrected.

But the slides also should be man­datory viewing for anyone participat­ing in the design review of their com­pany’s next HRSG. Sieben showed how easy it would have been to avoid many of the problems dogging the industry today. No reason to repeat the mistakes of the past.

Problems with pressure parts were addressed by Bryan Craig, PE. He covered super­heaters/reheaters (warped tubes, fatigue cracking, desuperheaters, condensate man­agement), evap­orators (drum issues, flow-accel­erated corrosion), economizers/pre­heaters (fatigue cracking, FAC, dewpoint corrosion).

Craig began with warped tubes. Visual examination is all that’s nec­essary to find them. Causes of “spa­ghetti” tubes include desuperheater leakage, water hammer, shipping/construction damage, differential heating/cooling, etc. The good news, he said, was that, in general, warped tubes are reliable provided the stress mechanism is not repeated.

HRST is well known in the indus­try for its desuperheater trouble­shooting work. Craig covered the importance of location and proper piping design, how to identify and prevent leakage, nozzle types, etc. He had a series of valuable slides that identified risks associated with startup and low-load operation—including condensate management, ramp rates, water hammer—and how to mitigate them.

Regarding condensate manage­ment, for example, Craig showed with simple diagrams what happens when condensate is not purged from lower headers before every start—that after explaining how conden­sate got there in the first place. For attendees charged with troubleshoot­ing their steam systems, he gave some pointers on proper drain sizing, location, operation, etc.

Many of these topics are discussed in detail in the “HRSG Users Hand­book,” available through the HRSG User’s Group (www.hrsgusers.org); HRST contributed to that effort.

HRSG lay-up and storage. Sie­ben returned to the front of the room to provide guidance on proper lay-up and storage of HRSGs. The message was that many bad things that can happen when boilers are not laid-up properly—for example, oxygen pit­ting, corrosion fatigue and under-deposit corrosion on the water side of the unit; corrosion of tubes, fins, pipes, and hangers on the gas side. Pictures of oxygen attack in a steam drum got everyone’s attention.

The pros and cons of wet and dry storage were reviewed thoroughly, as were the benefits of stack damp­ers and duct balloons. Guidelines on the selection of nitrogen, desic­cants, dehumidified air, and vapor corrosion inhibitors for dry storage certainly would help attendees make good decisions.

Gas-side corrosion control was another discussion topic. Sieben’s real ugly photos of boiler floor cor­rosion and piles of rust on the floor under finned tube bundles made everyone sit up and pay atten­tion, even as the afternoon wound down.

Compressor section

User presentations stimulated much of the discussion during the compres­sor session, which ran until lunch on Day Two. First-hand accounts of problems/solutions by owner/opera­tors are the lifeblood of user-group meetings. The 7F steering commit­tee, in particular, places great value on the participation of plant person­nel from the podium. In Greenville, 15 users presented (Sidebar 5); next year’s goal is 20.

To get to that level, and beyond, the committee developed an essay on how to select and develop a plant “experience” for presentation (p 132). It’s a valuable roadmap for first-time presenters and a good review for many others. The essay also offers guidance on how to prepare for your delivery—this to ensure that the experience is both professionally rewarding and enjoyable.

Inlet filters were scheduled first. Subject was one plant’s experience with a service firm that tracks filter cleanliness, removes them when a specified pressure drop is reached, cleans filters with high-pressure air, and reinstalls them. Filter integrity is verified using standard industry tests.

Firm also disposes of used filters in an EPA-approved manner for cus­tomers that want that service and rents warehouse space for spare fil­ters. Back-of-the-envelope arithmetic probably is sufficient to decide if this type of service is more cost effective than just replacing filters in-kind using plant staff.

Those users opting to buy filters and in need of a quick refresher on filtration basics are referred to www.combinedcyclejournal.com/archives.html, click Spring 2004, click “Select­ing gas-turbine inlet air systems. . .” on cover.

Inlet bleed heat. A 300-series stainless-steel expansion joint in the IBH system for a 7FA+e engine in daily cycling service failed. Recall that the IBH system protects the compressor in cold weather and per­mits GT operation at loads perhaps as low as 50% of rated output while holding emissions in check. The sys­tem’s inlet valve is closed when the unit is at full capacity and opens as load drops, admitting 130-psig com­pressed air.

Failure of the expansion joint was identified by a loud, high-pitch (20 kHz) noise which could be heard 100 yards from the unit. Noise was caused by air whistling through cracks in the convolutions. Ultrasonic probe iden­tified crack locations, most often on inner convolutions. Analysis revealed that crack propagation generally was slow. Plant personnel think at least some cracks may have been visible for as long as six months before whis­tling began. Longest crack was just under a foot in length.

Important to note is that IBH sys­tems are not part of the OEM’s scope. They are installed by the mechanical contractor, which means each sys­tem is unique. Another thing plant personnel discovered was that GE documents do not discuss life-cycle requirements.

This system was designed for the base-load service intended; however, the plant now serves the 5-min mar­ket and GT load can change by 30 MW within that time period. Engi­neers found that the expansion joint was designed for 1400 cycles, which translates to a lifetime of 2.5 years in peaking duty. The joint did bet­ter than that, however, lasting 2200 cycles.

The entire expansion-joint assem­bly was replaced with one designed for 20,000 thermal cycles (40-yr life expectancy); cost was only double that of the original. Speaker sug­gested that his colleagues check their IBH systems and compare design conditions to actual. He also warned that noise might not precede failure.

Someone in the audience suggest­ed that plants located on the seacoast may be especially vulnerable because there was the possibility that chlo­rides would attack the 300-series stainless.

Inlet guide vanes. A user said that the IGV actuator arm failed in fatigue on a 7FA that operates con­tinuously at up to full load. Another reported the same type of failure. He found a great deal of wear and back­lash on the rack-and-pinion drive and thought that might have had something to do with the failure. Yet another user thought some actua­tor arms supplied to the OEM might have been “beefier than others.”

There was considerable discus­sion on this and other actuator prob­lems—including Belleville washers being installed incorrectly (upside down) by the OEM.

How did that happen? Damage to one R7 blade near its root was found on a base-load Model 7231 DLN2.6-equipped 7FA. Initial thought was that it might have been caused by something left in the machine during the last hot-gas-path inspection in 2004. However, no other damage—upstream or downstream—was in evidence. Might the damage have occurred during reassembly?

Plant has an LTSA and the OEM provided detailed engineering instructions on how to blend, polish, inspect using fluorescent penetrant, and peen the affected area. It would have been a big deal to replace just one blade.

This case history ignited much discussion on precautions to ensure that nothing is left inside the GT after an outage. One user said his company has well-defined procedures for entering the work area when the compressor and/or turbine upper casings are removed. Equipment, tools, parts that enter/leave this area are carefully monitored. Strict rules require reporting something that dropped, where it dropped, what was dropped (and removed).

One potential source of debris that’s easy to forget is work shoes. It’s easy for rocks to get wedged between the treads on shoe soles/heals. Boots must be checked, even vacuumed at times. Someone sug­gested that the experience described from the podium might very well have been caused by a pebble. One of the conclusions of the group: You have to weigh carefully the push for ever-faster inspections and repairs against the time required to assure something important won’t be over­looked.

Stacking-bolt failure. Owner with a dozen and a half 7FAs pre­sented on a stacking-bolt failure that initiated a forced outage on high vibration in late July 2007. The rotor, for a Model 7221 7FA, had more than 65,000 total operating yours and more than 1000 starts over its lifetime. It had been installed in one unit from 1996 to 2003 and in anoth­er from 2004 until the time of failure. Unstable vibration signatures first appeared in May 2006. Secondary damage caused by the stacking-bolt failure included dents in and crack­ing of 17th-stage compressor blades, plus wear/missing metal on the inner barrel.

More pertinent facts: The unit was taken out of service for a combustor inspection about five months before the forced outage. A field balance was done at that time and it reduced shaft vibration from about 8 mils to 2. During the week before the outage vibration increased to 12 mils.

Disassembly revealed deteriora­tion in the form of a “little dip” on the surface of the compressor rotor wheel at the aft nut. No defective assembly was noted from records. The rotor had been overhauled and reassem­bled by GE twice and stacking bolts/nuts had been replaced. Crack initia­tion was at three points on the inner side of the rotor. Main crack propaga­tion was from the inner to outer side. A corrosion pit was thought to have initiated the crack.

Low- and high-cycle fatigue dur­ing start/stop operations caused the bolt failure at the aft nut. Crack is detectable by “doping” the vibration monitoring algorithm, but this owner developed an ultrasonic inspection device/procedure to check its other units. Such failure reportedly is most likely to occur on non-robust-back-end rotors—typically 7221s and some 7231s.

Compressor roundtable. Many items were discussed and many observations were made during the compressor-roundtable discussion. Bullet points below hit some of the highlights:

• Two users with Model 7231s reported damage to the trailing edges of R3 blades. Migration of S3 vanes was said to have been the cause. OEM attributed the damage to relatively minor surge and blended the blades.
• An owner reported losing an S1 shim from the upper half of the casing and had to blend several blades where damage occurred. This generated considerable dis­cussion on shim fixes—includ­ing both GE and non-OEM tech­niques. General feeling was that for R0 through R4, protruding shims should be pulled out if pos­sible. Reason: the ring segments that characterize the first five sta­tor rows typically are rust-welded in place and wouldn’t move with shims missing.
• One participant commented on the OEM’s new water-wash system. He said erosion happens and his concern is that the unit makes it through a major-inspection inter­val without major work. Technol­ogy came into question, but users with LTSAs say they don’t have options and are not concerned.
• A user reported that the titanium nitride sacrificial coating to pro­tect the base metal of compres­sor blades against water erosion seems to work, but for only a cou­ple of thousand hours.
• A participant reported that two regular (non P-cut) R0 blades cracked at the base; online water washing was not employed. Dis­cussion was dizzying, all over the lot: What can you do with what type of compressor blades, the old online washing system, the new online washing system, in a chloride environment, in a non-chloride environment, etc?
• Two types of blade cracking noted: suction side (less prevalent) and down in the dovetail, below the platform. Fretting leads to crack­ing; under-cut to relieve stress. Much discussion on this, many affected.
• Restart logic after a shutdown: Can restart from immediately after shutdown until two hours later; cannot restart between two and eight hours after shutdown because the case cools faster than the rotor and rubs result; eight hours or more after shutdown you can restart at any time.

However, if you grind down tips you can start at any time. OEM says it’s a site-by-site thing. Language in the applicable technical information letter is very strict, but the OEM will relax suggestions depending on site conditions and specific parameters. Some users say they were told that the TILs are “guidelines.”

Lube-oil systems

Ask a plant manager where his or her biggest headaches originate and there’s a good chance they will be linked to water or lube-oil chemistry. Maintaining lube-oil in top condition at a combined-cycle plant can be par­ticularly challenging. First, you have to learn the basics of a fluid chem­istry and testing procedures that weren’t taught in any chemistry class you took in high school or college.

Once you think you understand the language of lube oil, the real learning begins. Another challenge: You have to deal with independent lube-oil systems for each gas turbine/generator and the steam turbine/generator. Yet another: The prime mover’s hydraulic and lube-oil sys­tems often are served by a common sump, complicating oil selection and treatment.

An owner reported to the group about its efforts to extend lube-oil life. A key element of this program is to standardize where possible lube-oil specifications, testing, and treat­ment across a fleet of more than two dozen 7FAs at nearly a dozen sites. A fleet of this size certainly can justify a subject specialist in central engi­neering.

First step was to conduct a fleet baseline assessment by gathering per­tinent data for each unit—such as par­ticle counts and the potential for var­nish formation. Particle counts were obtained using ISO (International Standards Organization) Cleanliness Code 4406, varnish-potential rating using Quantitative Spectrophotomet­ric Analysis (QSA). Here are a couple of things this user learned during this phase of the project:

• Oil tested immediately looked good; 72 hours later the “still,” cooler sample produced much dif­ferent numbers.
• ISO 4406 tests may be conducted using a laser particle counter or pore-blockage technique. Laser accuracy is impacted adversely when the oil contains water; par­ticle counts run higher.
• Sampling location is important. To illustrate: The speaker report­ed a 3-in. layer of foam where No. 1 bearing drains into the sump.
• Tests using an electrostatic oil cleaner produced mixed results. The unit ran for two weeks on oil at room temperature and the var­nish potential dropped dramati­cally. Oil was allowed to sit for a week and a follow-up test revealed varnish potential had shot up again. The electrostatic oil cleaner then was retested with a new fil­ter element. Much better results were achieved in only three days; a week later, varnish potential was up, but not by much.
• Test of a chemical treatment to put varnish back into solu­tion got good results. Was much less expensive than changing oil, which could have easily cost more than $100,000 by the time you pay for the oil, cleaning the system, and disposing of the waste.
• Temperature impacts the clean-up process. This user believes the electrostatic oil cleaner meets expectations only when the oil is cool. Good results were achieved on hot oil with a high-end special­ty filter.
• Tests using an anti-spark filter were promising. There was vir­tually no evidence of static dis­charge.
• One of the major suppliers of tur­bine oil has reformulated a prod­uct associated with high particle counts.

The floor discussion that followed this presentation might have gone on forever had it not been for lunch. When it comes to lube oil, everyone has at least some experience and most have an opinion or two. The takeaway from the dialog was that the electrostatic oil cleaner was good for cleaning up hard particles while an alternative particle agglomera­tion device was particularly effective on soft particles.

A couple of attendees said they saw little, if any, improvement in oil quality when using the electrostatic unit on an operating turbine. A con­cern with the system agglomerating soft particulates was that some of the agglomerated material would be squeezed through the filter.

Lube oil was back on the pro­gram Friday morning. Speaker began with a review of problems encountered during six years of base-load operation with conventional tur­bine oil, including much varnish and several trips attributed to it. No sin­gle element was ever identified as the main culprit. Turbine oil lasted about two years or so before varnish build­up became an issue. Servos fouled and adversely impacted operation of gas valves. Electrostatic oil clean-up system removed only insoluble var­nish; varnish byproducts remained in solution until they agglomerated into large particles.

Solution for this user: Don’t try to manage varnish, just don’t make it. Plant switched to polyalkaline glycol (PAG). Presentation was made after six months of operating experience with the new fluid. Tests conducted just prior to the meet­ing showed additives still were in their original concentrations, so it was assumed that the fluid had not degraded.

Other important points made:

• PAG can oxidize at high tempera­tures, but byproducts are soluble in the base oil.
• PAG-compatible materials must replace all rubber and paper in the system—for example, O-rings, gaskets, etc.
• The small amount of original oil that remains in the system after draining does not adversely impact PAG, so a detergent flush is not needed.
• Verify proper operation of the emergency dc lube-oil pump with the higher-gravity PAG. Power draw will increase.
• PAG is the base fluid. Additives determine its suitability for lube-oil and hydraulic control purpos­es.
• Most heavy industrial experi­ence with PAG has been in turbo­compressors. One unit was said to have operated for more than 80,000 hours.

Interestingly, equipment/services suppliers directly involved in the lube-oil projects profiled above, and firms with similar offerings, were available for consultation at the vendor fair—specifically, American Chemical Technologies Inc, Analysts Inc, C C Jensen Inc, EPT Inc/Clea­nOil, ISOPur Fluid Technologies Inc, and Kleentek.

The beehive of activity on the exhibition floor suggested users were actively looking for additional information on subjects addressed by colleagues from the podium or during the open discussion. Behind closed doors, supplier names are mentioned.

Readers can get useful background on lube-oil issues by accessing back articles at www.combinedcyclejour­nal.com/archives.html: Click Sum­mer 2004, click “Maintain lube oil within spec. . .” on the issue cover; click 3Q/2005, click “The lowdown on the sticky subject of lubricant var­nish”; click 3Q/2006, click “Gas-tur­bine valve sticking. . .” and “Assess the condition of your oils. . . .”

Turbine session

There were two user presentations in this session before the open discus­sion period. First described an in-situ first-stage wheel repair for a 7FA+e. Damaged wheel had a burr in a dove­tail groove; shot-peening was essen­tial because of the burr’s location. Repair was successful. The speaker also reported on repairs on a sister unit. First- and third-stage wheels were damaged by a balance weight. They also were successfully repaired and shot-peened in place.

A failure of the cooling tip cap on a first-stage bucket for a 7FB was reported on next. Operating data gave no indication of the problem. Unit had fewer than 6200 fired hours and only 450 starts since commercial start. Speaker said another user had the same experience, accompanied by extensive leading-edge oxidation.

Platform creep indications were identified on first-stage buckets; bucket migration was in evidence. The buckets were installed a year earlier during a combustor inspec­tion and had seen fewer than 2200 fired hours. They were removed and inspected using an immersion UT process. Speaker said the OEM was working on a new bucket design.

Recommendations from the podi­um: Conduct borescope inspections annually, be ready for surprises, and line up a set of replacement buckets in case they’re necessary.

Other issues discussed concerned the forward seal pins and a bucket lockwire that was found disengaged. Improper installation if the lockwire was thought to be the cause of that issue. Users were urged to carefully monitor unit repairs and to ensure rigorous QA/QC during installation of locking hardware.

The roundtable discussion that followed the prepared presentations covered a wide range of issues and observations—including high wheel-cavity temperatures, second-stage bucket shroud failures, starts limit for second-stage buckets, condition of third-stage buckets, casing galling, weld repair of turbine cases, quality issues associated with the various casting houses supplying buckets and nozzles (defects can be traced by serial numbers), etc.

The 7F Users Group steering com­mittee does a particularly good job guiding the roundtable discussions. The discussion leader is at the front of the room and there are commit­tee members working the aisles with handheld microphones. That is not unusual.

However, this is a big group.

Holding the interest of the audience through the entire roundtable and keeping 250 people focused on a single subject is a difficult job. Good equip­ment is a must. Also, participants in the audience must be accessed with a “mike” quickly. A few extra seconds of dead time spawns local conversation groups that would kill the session. Having four or five motivated floor stewards who can “fly” up and down the aisles is necessary.

Another thing you learn sitting through one of these sessions is that while everyone’s either an owner and/or operator of a 7F there a many different versions of this machine—not just 7221s, 7231s, 7241s, but also units with components made of different materials, slight but mean­ingful design variations, etc. Perhaps the most outstanding attribute of the floor stewards is their intimate knowledge of the entire product line.

When someone asks a question that leaves others scratching their heads, at least one member of the floor team understands and can translate. That’s necessary to keep the dialog moving. Also necessary are floor stewards like these who are not tempted to make a presentation themselves—another discussion killer.

Combustion session

A user presentation on the Modified Wobbe Index and the impact of vari­able fuel-gas quality on a DLN2.6 combustion system drove the entire session. Discussion included liquids in the gas supply, flashbacks, com­bustion dynamics, emissions, flame stability, the OEM’s OpFlex™ Wide Wobbe control system, etc.

GE Day

GE Energy’s 7F technology team presented on Thursday morning the company’s latest modifications and improvements for the compressor, including R0 blades, as well as for the turbine, stator vanes, and aux­iliaries. The team leader discussed the benefits of technology invest­ment. The afternoon was dedicated to breakout sessions on combustion, controls, and accessories that includ­ed a Q&A period.

F-class technology milestones achieved in 2007, as reported by the OEM, included the following: The 1000th unit shipped; fleet surpassed 20-million operating hours; fleet achieved 99.4% operating reliability, 98.8% starting reliability, and 95.5% availability.

Looking ahead, GE expects com­mercial rollout of a redesigned compressor for the 7F fleet during 2Q/2009 (concurrent introduction for new units and the installed base), 2Q/2010 for the 9F fleet, and 4Q/2010 for the 6F fleet.

Auxiliaries, generators

User presentations on auxiliaries included a steam-turbine Mark V to Mark VI upgrade, bolting and gasket issues, and failure of an atomizing air compressor. One might think that such a pedestrian subject as bolting and gasketing would have no place at an F-technology meeting; guess again. The speaker detailed numerous gas leaks on startup after maintenance on a 7FA+e because of improper gasket selection, poor gasket installation, and/or loose or uneven tightening of flange bolting. Last might have been caused by galling experienced with the GE fasteners.

Here were the steps taken by this owner to minimize the possibility of a similar experience in the future:

• Color-coded gaskets.
• Replaced the OEM-supplied bolts and locknuts with studs, nuts, and lockwashers.
• Established torque ratings.
• Developed check-off sheets for QC personnel to ensure proper gas­ket material is installed, proper arrangement of studs/nuts/lock­washers is employed, and proper torque is applied.

The last user case his­tory was particularly inter­esting. The atomizing air compressor for this dual-fuel 7FA commissioned in the mid 1990s was compro­mised by standing water in the unit that caused rapid deterioration of the impeller, shroud, and hous­ing. A standby compressor was available and placed in service. Speaker noted that if you lose atom­izing air you have 11 seconds before you start losing metal.

Water was thought to accumulate when the compressor was on standby during gas firing. Lesson learned: Just because you see water coming out of the drain doesn’t mean there’s no water level in the compressor.

The generator session featured a user’s viewpoint on the failure of a generator breaker disconnect switch, and a presentation by How­ard Moudy of National Electric Coil, Columbus, Ohio, on generator issues and maintenance. The latter closes out this report.

As a leading provider of generator services, NEC typically gets a call when a large electrical machine is ailing. Those most likely to respond from NEC are the service managers, one of whom is Moudy, who probably has witnessed just about every prob­lem a generator could have. He is a confident speaker at industry meet­ings, where his experience and ency­clopedic memory are valuable assets for helping users meet management’s expectation of high availability.

In Greenville, Moudy focused on the 7FH2 and 324 generators that most attendees had, dividing his presentation into three parts: basic observations, general maintenance practices, and specific issues con­cerning the rotor. He began by urg­ing users to check end windings for looseness and vibration every out­age; visual indications include dust­ing and greasing. But that was not enough for this group, attendees wanted to know the source of the damaging vibration.

Moudy explained: Steady-state forces—sometimes called “slot pound­ing forces”—are a function of the 120-Hz (twice the operating frequency) vibration forces that result from the magnetic flux traveling through the rotor and stator. These pounding forces cause the coil to vibrate radial­ly in the slot. End turns overhang the core and if not properly supported, they will vibrate.

Transient (surge) forces usually occur during a generator fault. If suf­ficiently large, these forces can break ties and loosen windings—even displace them. Moudy said a bump test to assess your genera­tor’s susceptibility to damag­ing vibration should be con­ducted as part of every major outage. It identifies mechan­ical resonances excitable by the 120-Hz electromagnetic forcing frequency. You want to tune the unit to avoid resonances in this range.

Maintenance practices. Moudy urged users to do all they could to maintain industry-standard main­tenance practices during changes of ownership, workforce reductions, budget cuts, and other distractions. This is a prerequisite for assuring high reliability, he said. Knowledge management is particularly impor­tant, he continued, because without historical records it is harder to diag­nose a generator’s condition or get to the root cause of the failure quickly. To help users objectively evaluate their generator preventive mainte­nance programs, Moudy offered these guidelines:

Standard equipment monitoring

• Temperature: Monitor continu­ously, to ensure it is within manu­facturer’s limits.
• Grounds: Continuously, to guard against insulation failure.
• Vibration: Continuously, to iden­tify bearing problems, loose com­ponents, possibility of imminent failure.
• Lube oil analysis: Semi-annually, or more often, to check for contam­ination and indications of bearing babbitt deterioration.

Visual inspection

• Stator winding: Look for dust, grease, oily surfaces, broken ties, discoloration, and foreign object damage before every outage to help determine scope.
• Stator core: Inspect for damaged iron, loose iron, discoloration, and foreign objects during every major outage with the rotor out.
• Rotor: Look for discoloration from overheating, loose or shifted blocks, and arcing during every outage with the rotor out.

Stator electrical tests

• Insulation resistance or “Megger” with PI (Polarization Index), to determine presence of contamina­tion, every outage.
• Winding resistance, to verify integrity of brazed connections, every outage.
• Hi-pot, to “stress” insulation to prove its integrity, every major outage.
• DC ramp, to determine insulation strength, every major outage.

Rotor electrical tests

• Insulation resistance or “Megger” with PI, to determine presence of contamination, every outage.
• Winding resistance, to verify integrity of brazed connections and find broken conductors, every outage.
• Flux probe, to identify shorted turns when the unit is in opera­tion, annually.
• Pole balance, to identify shorted turns when the unit is stationary, every major outage.

Specialty tests

• ElCID (Electromagnetic Core Imperfection Detection), to iden­tify shorted laminations, every major outage.
• Core loop, to detect shorted lamina­tions, after rewinds or core repair.
• Wedge tightness, to locate loose wedges, every major outage.
• Partial discharge, to identify insu­lation deterioration and verify coil tightness in slot, yearly.
• Bump, to detect end-winding reso­nant frequencies, every major out­age.

NDE tests

• Magnetic particle, to locate sur­face cracks in magnetic steel components, fans, rings, wedges, shaft, coupling, and hubs, every major outage.
• Dye penetrant, to find surface cracks in nonmagnetic parts, fans, rings, and wedges, every major outage.
• Ultrasonic, to pinpoint interior cracks in metal components, rings, and shaft, every major outage.

Rotor issues. Moudy discussed two rotor issues specific to 324 gen­erators serving 7FA gas turbines: turn-insulation migration and dove­tail-groove cracking. The experi­enced users in the room had heard all about this before and probably had taken corrective action. So there was an opportunity for them to turn off the “concentration button” for a moment. But with more than half of the attendees first-timers there were plenty of people who wanted to hear what Moudy had to say.

Turn-insulation migration occurs when the resin bond between the insulation and copper separates and the insulation—for lack of a better term—migrates. Peaking units are said to be in the highest-risk group. Moudy suggested monitoring and inspection to identify the problem if it exists, then discussed NEC’s Spe­cialized Engineering Solution™ as one corrective procedure (visit www.national-electric-coil.com to learn more).

Dovetail groove cracking in the rotor forging of 324 generators pre­dates identification of turn-insu­lation migration, which the OEM acknowledged as an issue in early 2000. Concern is that the cracks could initiate catastrophic damage to stator and rotor.

The background: Rotor dovetail cracks can be initiated by fretting at the interface between steel wedges in slot No. 1 and the surface of the rotor dovetail-shaped slot. Crack propaga­tion is a result of high-cycle fatigue caused by rotor bending. The higher the rotor L/D ratio, the easier the rotor bends; thus L/D ratio is a pos­sible correlator with this failure.

A collateral problem is created dur­ing severe negative-sequence current events—such as when motoring dur­ing turning-gear operation or with the rotor at rest. What happens is that material in the vicinity of the crack overheats, significantly changing material properties. Moudy said that independents like National Electric Coil have developed effective methods for addressing this problem. ccj