‘Perhaps the best 7F meeting ever’

That’s what many of the more than 180 owner/operators attending the 2010 7F Users Group Conference and Vendor Fair told Chairman Richard Clark of SCE Energy and Vice Chair Sam Graham of Tenaska Inc as the five-day meeting drew to a close last May. It was quite a compliment given the rich history of the group, which celebrates its 20th anniversary in 2011.

Graham, the maintenance manager at the 3 x 1 Tenaska Virginia Generating Station (TVGS), took the reins from Clark, operations manager for Mountainview Generating Station’s two 2 x 1 combined cycles, at the end of the conference and will chair the group through the upcoming meeting. Ben Meissner of Progress Energy is the vice chair. Other members of the 2010-2011 steering commit[tee are identified in Sidebar 1.

Dr Robert Mayfield, who serves on the steering committee, told the editors that one of the reasons for the very positive unsolicited comments was a change in conference format to allow for a more robust open forum between the users and GE engineers. The owner/operators had more than a day and a half of face time with the OEM’s experts and thoroughly covered such timely gas-turbine topics as:

  • End-of-life recommendations.
  • Combustion and hot-gas-path (HGP) inspections.
  • Enhanced-compressor updates.
  • Outage lessons learned.
  • Best practices and safety.
  • Control-system enhancements.

In addition, there was a session on the users’ top-10 GE issues, another on the capabilities of GE Energy Services’ repair shops, and a half-day D-11/A-10 steam-turbine workshop. Finally, the OEM’s team demonstrated, via its so-called Knowledge Café, the following new tools for customers: self-help portal, outage optimizer, on-site support, parts edge, and power smarts.

Mayfield assures that the 2011 meeting will exceed expectations once again. The Houston location gives users the opportunity for a first-hand look at GE’s repair facilities; tours will be conducted on Monday, May 9. Highlights of the upcoming conference are presented in the box, under the group’s logo. For more detail and program updates as changes occur, plus information on how to register, visit www.7Fusers.org.

The summary agenda may be a helpful addition to your request for permission to attend the May meeting. It clearly shows this conference is a non-stop learning experience that starts daily at 7 am with informal discussions over breakfast, migrates to in-depth technical sessions from 8 to nearly 6 pm with only an hour break for a collaborative lunch among colleagues, and concludes with a vendor fair from 6 to 9:30 pm (different companies participate each day).

Do the math: This translates to 14.5 hours a day, or more “classroom” time in one week than you would get in one semester for a three-credit college course. Think of the 7F meeting as a compressed high-level education on one of the world’s most sophisticated pieces of rotating machinery for less than $2000—including conference registration, hotel accommodations, and air fare. (Food is not a cost factor: Sheila Vashi and her colleagues from Marietta (Ga)-based Vision-Makers will make sure you’re well fed.)

The answer to the “What’s in it for the company?” question that you’ll probably get from management: The best practices and lessons learned from the many user presentations, and the knowledge gained on technological advances from the vendors, are sure to pay a minimum 10-fold return on the “tuition” investment over the next year alone (Sidebars 3 and 4).

User presentations, discussion

First topic on the agenda of the closed user sessions at 7F meetings is the compressor. It usually generates more interest than the combustion, turbine, generator, and auxiliaries segments of the program because the open discussion encompasses the air inlet house as well as the compressor and its issues.

The 2010 compressor session ran the entire morning of Day Two and featured several of the more than one dozen user presentations made in Atlanta. The session kicked-off with a presentation on tip-crack experience at two plants, one a five-unit peaking facility and the other a 2 x 1 combined cycle.

Tip cracking

Recall that tip cracking of R0 and R1 compressor blades is caused by rubs and is an acknowledged fleet-wide problem; consult Technical Information Letter (TIL) 1509, first issued in May 2005. The OEM identified the following among the possible causes of rubs: over speed, fast starts, open doors, foundation distress, and wet operation.

The speaker had long-term knowledge of the cracking issue. The peaking plant went commercial in 2001 and the combined cycle in 2002 and both have suffered chronic R1 rubs and have experienced cracking and tip loss. Important takeaways from this presentation: Hard rubs are conducive to tip liberations over time and the guidance offered in TIL-1509 may not be sufficiently rigorous to assure the level of equipment protection most owner/operators desire. Further, poor blending and tip surface finish can create sites from which cracks can propagate.

Peaker experience. One 7FA suffered the loss of a corner at the tip of an R1 blade within a year of COD. A fluorescent penetrant inspection (FPI) was conducted to verify blade integrity after every eight starts until repairs could be made. At the next outage, the R0 and R1 blades were tip-ground and the damaged blade blended.

Tip cracking occurred on one R1 blade in 2003 and on another R1 blade in 2004. After the crack was found in 2004, the R1 blades were “roof-topped” to remove any microcracking that may have started from burrs (cracks start on the outer edges of the blade tip).

The roof-topping process involves grinding off the square edges at the top of each rotating blade from the leading edge to the trailing edge. The grinding angle is arbitrary; goal is to remove about 20 mils of material. There is no impact on blade clearances.

For the next several years, borescope inspections and TIL-1509 inspections were conducted annually. No further tip cracking was reported during this period. But damage to S0 and S1 stator vanes on one unit was found during the fall 2008 inspection. A 30-day outage was planned for the following spring to replace the S0 airfoils. By then, the affected engine had accumulated just over 3200 fired hours of operation and nearly 450 starts (an average of about 60 starts per year).

During the outage, tip loss was found on two R1 blades, along with collateral damage (Fig 1). For the blade at the left, the crack initiated from one of the blend marks on the convex side of the airfoil tip in the roof-top area, 2 in. from the leading edge. The failure was attributed to poor roof-top repair.

The rotor was not removed to replace the damaged stator vanes. A borescope identified the affected lower-half vanes and the OEM’s stator removal tool was used to remove the necessary vane segments. The speaker said the tool was cumbersome to maneuver and destructive to the segments; however, vanes were not damaged.

S0 and S1 vanes were replaced using the manufacturer’s NUV (non-uniform vane) stator solution to limit the frequency response of R1 blades. One lower-half S2 segment and several upper-half S2 segments were replaced as well.

Additional work included pinning of shims, opening of R0 and R1 clearances, blending of all damaged rotating blades, and polishing of R0 and R1 blade tips to a more demanding specification than recommended by the OEM. A third-party contractor verified proper tip grinding using the latest UT (ultrasonic test) tools.

The combined cycle gas turbines suffered heavy rubs within six months of its COD as was the case at the peaker station. But as the speaker said at the outset, hard rubs are conducive to tip liberations over time. In this case, it took six years, nearly 29,000 fired hours and more than 1100 starts for a 3 x 3 in. piece of an R1 blade to liberate. A root-cause analysis (RCA) revealed the tip fracture indeed was from rub-induced stress with crack propagation caused by high cycle fatigue (HCF).

Borescope inspections had been performed semi-annually and TIL-1509 conducted annually. In spring 2006, an R0 tip loss was blended and an HGP inspection was done in spring 2008. The compressor was carefully examined after the spring 2009 borescope inspection revealed the piece missing from the R1 blade.

The OEM’s team found more than 500 indications but was reluctant to condemn the rotor, the speaker said, believing excessive blending and restricted operation were an option—theoretically, at least. The owner opted to purchase a new rotor and perform a Package 5 enhancement. Outage was completed 51 days from discovery.

End notes. (1) A lesson learned: Record every compressor part removed and make sure you have all the parts (and tools) you should have before buttoning-up the unit. Four days after this outage, a stator blade that had been removed was found at a compressor bleed valve.

(2) A subject of ongoing debate: Might a vibration profile and off-normal compressor discharge pressures/temperatures have indicated animpending tip liberation. Blade health monitoring capabilities only recently have been installed at some M&D (monitoring and diagnostic) centers; time will tell.

(3) Lingering questions: Can you grind down a tip rub to healthy material and repair? Might the wound be permanent?

R0 dovetail cracking

An owner with considerable 7FA O&M experience reported multiple changes of R0 blades on a flared compressor with uncambered inlet guide vanes (IGVs). In spring 2008, he said, an OEM crew removed the original set of non-P-cut R0 blades from the unit after 233 fired starts, 2781 fired hours, and 10 trips. Dovetail cracking found during a scheduled inspection using phased-array UT was the reason for replacing the row with a new set of standard non-P-cut blades.

Those new blades failed in the same manner, but 17 months later after only 115 fired starts, 1611 fired hours, and one trip. The second set of R0 blades was replaced by jacking up the bellmouth case 18 in. without removing the turbine compartment roof or forward wall. Note that an Alumazite® coating was applied to the R0 dovetail side slot prior to installing the third set of blades. Also worth noting: The third set of blades has the same part number as the second set, but the airfoil profile is different (Fig 2).

Inlet guide vanes (IGVs) were not changed as part of this project. However, changes were required to IGV angle and startup logic. Specifically, IGV mechanical stops were re-established to allow an operating range of from 20.5 deg (fully closed) to 92.5 deg (fully open).

In addition, control-constant mods were made to change IGV position during startup and the speed at which IGVs open. IGV position while on turning gear had been 26 deg, now 20.5; IGV angle during startup was changed from 28.5 deg to 24; turbine speed when IGVs open was 85.5, now 84.8; IGV position at full-speed no load (FSNL) remains the same at 45 deg.

In wrapping up, the speaker stimulated the group with the following comment: Buying new blades requires an exchange-type program. Simply put, when you buy new blades, the OEM makes you turn in the set removed. This means you can’t hire a metallurgist to conduct your own failure analysis and it raises questions regarding further use of blades inspected and found healthy.

For example, what did the OEM do to recertify those “healthy” blades? How good are the blades after having been subjected to stresses that cracked other blades in the same row? One attendee suggested having a third party verify blade integrity before installation. Another said you might want to consider using recertified blades in machines that would not have more than a couple of hundred starts before the next overhaul. Yet another user essentially told the group not to worry by sharing that his plant had one unit with 30,000 hours on recertified blades.

By show of hands, roughly two dozen owner/operators in the room said they have units that had experienced R0 dovetail cracks.

Clashing conundrum

Clashing of rotating blades and stationary vanes in Frame 7 compressors has been reported by many users, as well as by Rod Shidler of Florida-based Advanced Turbine Support Inc, at recent meetings of the 7EA and 7F Users Groups.

The opportunity for owner/operators to “compare notes” on common issues of importance, and their solutions, suggests attendance at user-group conferences be considered “mandatory.” If not from colleagues, where else would you expect to learn about the next problem that will keep you up nights? To illustrate: At a recent 7EA meeting one user discussed clashing on five of six peaking units at one site, noting that clashing was found on the sixth unit a year later and only 20 fired starts/60 fired hours since the last borescope inspection when it had received a clean bill of health. Several other plants represented at the meeting reported similar findings.

The OEM presented at the same meeting, quickly addressing the clashing issue. Its representative said 12 incidents were reported at five sites (a poll of attendees alone revealed more than that number of incidents) but no forced outages resulted. In most cases, the R1 blades had no damage. Suggestion was to “catch” clashing early and restake to prevent further migration.

The presenter with the six 7EAs affected by clashing reported that the OEM considered clashing insignificant in terms of posing a risk to continued operation. It advised that the damaged areas be examined by FPI, blended smooth, polished, and flapper-peened by one of its qualified technicians at the next opportunity.

As for root cause, there was no answer. The OEM considered that it might be a system-level assembly issue causing casing distortion or concentricity/alignment offset.

Location: 6 o’clock. Discussions among 7EA users focus on R1/S1 clashing; among 7F users the focus is R2/S2. No matter: In virtually all instances, reports indicated the clashing was concentrated at or near the 6 o’clock position.

The first 7F speaker on the subject offered the following information on the six gas turbines affected by clashing at his company:

  • All the engines are installed in 2 x 1 combined cycles. All went commercial in the 2001 timeframe; regular borescope inspections were “clean” up to within six months of the event.
  • Five of the compressors are unflared and have cambered IGVs (four of these units are at the same site); one is flared with uncambered IGVs.
  • Clashing of the four units at the same site occurred between 1050 and about 1200 fired starts and 35,000 and 45,000 fired hours (Figs 3 and 4).
  • Clashing on one unflared unit was caused by an IGV failure and affected both R2/S2 and R3/S3.
  • The single event on a flared compressor was R3/S3 and occurred at a site with four flared units.

Damaged blades and vanes were cropped as shown in Fig 5. Interestingly, only one machine showed a drop off in performance after cropping, and that was very slight. The owner conducts annual borescope inspections to verify compressor health and has initiated an RCA and a proactive monitoring program. Last includes putting a trigger file in the Mark V control system that looks at step changes in vibration and other critical variables, and collecting pressure and vibration data through borescope plug holes with special transducers.

A quick poll of the audience before the next speaker presented on his company’s experience with 7FA clashing revealed that attendees also responsible for 7EAs said 17 of those machines had been damaged by R1/S1 clashing.

Peaker clashing. This case history focuses on clashing of R2 blades and S2 vanes on three dual-fuel simple-cycle 7FAs at one site (Figs 6 and 7). All engines are equipped with unflared compressors, static filters, and cambered IGVs. Each had recorded approximately 400 fired starts and 2500 fired hours when the indications were discovered during routine annual borescope inspections at the end of the winter run in spring 2008.

Here are some details on the unit that suffered the most severe clashing:

* It had recorded 39 fired starts since the previous borescope inspection, when no damage was evident.
* The R2 blade-rub area on trailing-edge roots was approximately 1 in. long; depth of penetration was 0.125 and 0.375 in.
* Seven S2 vanes were damaged at the leading edge.
* The owner/operator made several changes to its O&M procedures after examining the results of the March 2008 borescope inspection, including these:
* Perform a 360-deg borescope inspection of R2/S2 at the end of the winter run season (typically at the end of March) or after 20 starts at or below 32F.
* Record clearances between the R2 trailing-edge root and the S2 vane leading-edge tip (at a point adjacent to the rotor body) on all 7FAs in the company’s fleet when personnel have access to take those measurements. Do the same for R3/S3.

A follow-up borescope inspection was conducted in July 2008 after a couple of dozen more fired starts. The damage had not worsened since its discovery. But the good news didn’t last for long. The annual inspection in spring 2009 indicated that clashing damage had increased after the winter run (total of 30 fired starts since the spring 2008 check-up).

The unwelcome observation prompted management to authorize a more extensive borescope inspection of the entire R2/S2 row. Results: Damaged blades numbered 10; S2 vanes were described as having “smeared and rolled metal” (Fig 8). Next, the trailing edges of all R2 blade platforms, and the first 2 in. of the blades’ trailing edges, were examined using the latest eddy current diagnostic tools. Close inspection of the damage areas on the 10 blades affected (pressure and suction sides in the trailing-edge platform area) revealed no recordable indications.

Engineers continue to ponder the possible causes of clashing and how to prevent it. The first presenter on the subject thought it might be trip-related given there were no indications on one of its units following a no-trip year and there were indications the year a trip had occurred.

A check of thrust-bearing clearances offered no clues. The thought that clashing might be related to cold starts cannot be supported because of incidents reported at one plant (at least) where no freezing temperatures were experienced. Some experts now think the gremlin may be a surge event, but this cannot be confirmed.

Learn more on the subject by attending the 2011 meeting in Houston.

Inlet bleed heat

Cracking of piccolo pipes for the inlet bleed heat system has been discussed recently at several conferences focusing on maintenance of large GE frames. Recall that the IBH system injects hot compressed air into the inlet air stream to prevent icing at the compressor inlet. A problem experienced by many owner/operators is stress cracking on the piccolo pipes where they attach to their respective pipe guides (Fig 9). Simply welding the cracks was not a solution; they just cracked again.

The solution offered to 7F User Group attendees, which had been suggested by at least one other user a year or so earlier, looks like it might qualify for an industry best practice and put the subject to rest. The two-piece support system (Fig 10) which replaces the existing guide sleeve is easy for plant personnel to install and costs less than 20% of the OEM’s recommended solution.

New supports were installed during an HGP inspection in 2009 and have solved the cracking problem (Fig 11). The speaker offered the following budget in round numbers: 5-in.-diam, Sch-120, Type-316L stainless steel pipe—$5000; 10 hours of machining time—$1000; two welders for four days—$3000; and NDE inspection—$1000.

Compressor discussion

The open discussion session following the compressor presentation went on for about an hour before the subject shifted to the turbine end of the machine. Here are some snippets from the compressor exchange:

  • One user familiar with the OEM’s new compressor wash system reported seeing some erosion of concern.
  • Filter-house air leaks: Sometimes looking for sunlight while standing inside doesn’t tell you everything. Consider using a fire hose; water will weep through any available opening, supporters of the idea say.
  • Subject: R0 compressor blades. Everyone could get involved in this discussion. Who’s back to standard blades? Who’s using the latest OEM solution? Who’s still running P-cuts? No consensus view.
  • Pinning of rocking stator vanes and rotor clocking received plenty of air time as well. All alternative solutions discussed.
  • Loose shims got significant attention. Several users reported problems with shims going through their units in the last year; several others said shim migration was revealed in borescope inspections and corrected before liberation.
  • Forced-cooling philosophy generated some interest. There was general agreement that the failure rate of HRSG tubes would go up significantly if forced-cooling were imposed immediately following a GT shutdown. The solution: Wait an hour or two before starting forced cooling
  • Rotor lifetime limits imposed by the OEM continue to be a discussion catalyst. Many users still believe the limits are arbitrary and unsupported—at least to their satisfaction—by rigorous engineering analysis. One user recently told the editors during a plant visit that one of his plant’s rotors with more than 5000 starts was resting on blocks waiting for the OEM to change its criteria. He believed that would happen.
  • A user reported on a state-of-the-art compressor-blade health monitoring system installed on two of three 7FAs at his site with the expectation of avoiding a possible catastrophic failure. First installation was done in 2008 during a major; the second unit, in 2009. First reports had been received by the plant owner just before the meeting.
  • System implementation requires drilling of the compressor casing and installation of sensors to monitor blade displacement during startup; alarm is on a 40-mil deflection. User has no screen at present, monitoring is done by the OEM.
  • Another attendee said GE already had installed the system on six to eight machines. A question in virtually everyone’s mind: Would you trust the data to the degree that you would take an engine out of service if the M&D center said to do so? There is no sure answer today given the limited experience with the health monitoring system, but diagnostics in place reportedly assure that the probes are working properly and the readings are reliable.
  • Turbine section
  • High vibration that forced the shutdown of a 7FA+e engine was caused by forward migration of first-stage buckets and resultant damage (Fig 12). The unit had 788 factored starts and 17,801 factored hours at the time of the incident. Buckets were made of a coated directionally solidified, nickel-base superalloy (GTD-111).
  • The owner/operator’s engineering team believed the bucket lock wire was able to rotate in the direction opposite to that of engine rotation, free itself from the groove (Fig 13), and wriggle out dowel pins, which went downstream (recovered from the exhaust duct).
  • Forward migration of a bucket cuts off its cooling-air supply and the airfoil burns. Collateral damage includes coating detachment from first-stage nozzles and melting of the base metal (Fig 14), and denting of downstream buckets by the liberated pins (Fig 15).
  • The thorough inspection conducted by the owner/operator revealed scratch marks between the bucket lock wire and dowel pins which were believed to have been caused by rotation of the wire. If such detail is of interest, keep in mind that 7F User Group members can access this and other user presentations at www.ge7fa.users-groups.com.
  • Engineers hypothesized as to why and how (1) the lock wire might rotate and (2) the dowels might work themselves free. One thought was it might be thermal expansion/contraction of the lock wire during startup and shutdown. Another was use of inappropriate dowel pins and improper overlap location when the lock wire was installed (Fig 16). Yet another thought was that the lock wire and the wheel groove were mismatched in size and the lock wire had freedom to move.
  • An attendee said he believed that improper installation of the lock wire and too much time on turning gear are key causes of the situation described by the presenter. Regarding the former, the owner/operator suggested others should check spare lock wire and pins against the OEM’s specifications and to store them in a manner to prevent damage.
  • Also, before installing, check that (1) the lock wire is smoothly curved and has no sharp bends or kinks, (2) the groove is proper (use go/no-go gauge), and (3) there is no debris in the groove. Finally, review TIL-1214-3R3 regarding proper installation of dowel pins.
  • Turbine discussion was limited by time. The noon hour was closing in. The first bit of discussion developed around a user’s concern about first-stage wheel cracking of a 7241 model. Another attendee offered that his turbine wheels had been blended/polished/peened at the first major.
  • He obviously considered this the right thing to do—at least until someone else in the room said, statistically speaking, you have a one-in-four chance of wheel cracking following b/p/p and only a one-in-nine chance of cracking if you don’t do anything. As is often the case in open discussion forums, definitive answers/solutions are rare. However, you benefit greatly from the diversity of opinion because it opens your eyes to how others think and the many alternatives you should consider before making a decision.
  • Stage 3 strategy was the last topic before lunch. One user suggested changing third-stage buckets at the second HGP and retaining fit nozzles and shroud blocks for continued service.

Outage case histories

There were three case histories of outage experiences in the nearly two days of user presentations. Those three cases involved two stations, each equipped with two 2 x 1 7FA-powered combined cycles.

The combined cycles at the first station had operated for nearly 10 years and there was much work to do during the fall 2009 major inspection. The following describes key activities on the first of the two blocks at that plant. Personnel tracked lessons learned on Block 1with the belief they would facilitate work on the second 2 x 1. Everyone was encouraged to provide input and in the end 239 lessons learned were documented, one third of them for the steam turbine.

Work scope for Block 1 called for 112,000 man-hours of effort; 127,000 were required. Despite the 13% increase in man-hours, the outage budget was achieved. Actually it came in at 1% under plan. Outage duration had been planned for 43 days, but 50 were required.

Operating history of the gas-only 7FA+e gas turbines (DLN 2.6), each of which had operated for slightly more than 50,000 fired hours, included 2271 fired starts and 55 trips for GT1, and 2479 fired starts and 89 trips for GT2. Overhaul described below starts at the air inlet and proceeds through the engine to the generator. Scores of suggestions/requirements in all applicable TILs were completed during the outage.

The air inlet houses saw little refurbishment work over their lifetimes. In fact, the air filters—standard Donaldson-type conical/cylindrical—and evap media had never been replaced. Plant personnel believe they had extracted maximum value from the air filters; when removed, the pressure drop through them was 5 in. H2O.

After the filter houses were stripped of evap media, drift eliminators, and filters, inspectors found corrosion on parts of the support structures for those elements. The affected frames were prepped for a new coating—a two-part epoxy, Carbomastic 615HS, from Carboline Co.

The speaker mentioned that a grit blast was not acceptable for coating prep work because media could carry over into the turbine. Instead, pneumatic/mechanical needle scalers were used to remove rust from the frames. Aggressive cleanup procedures were put in place to assure that all particulate matter was removed from the inlet house prior to engine restart.

Note that the filter house is made of carbon steel, but lined with stainless from the silencers to the downward transition duct to the compressor inlet. Ductwork from the air inlet to the compressor bellmouth was carefully inspected for “opens” using daylight and water. No serious deficiencies were noted.

Rehab work complete, the drift eliminators could be reinstalled along with new evap media, and the new air filters. All seams in the evap-cooler section were sealed with Sikaflex®, the tradename for a family of one-component polyurethane adhesives, sealants, and coatings.

Gas turbines. The rotors for both gas turbines were pulled and sent to Sulzer Turbo Services’ Houston shop for inspection. Several R0 compressor blades in GT1 had crack indications on their respective roots. A replacement set, supplied by the OEM, was installed at the third-party shop under the direction of the owner’s engineers. Third-stage turbine parts on both rotors were evaluated by metallurgists and found suitable for continued use.

The GT2 rotor had a runout of 4.5 mils at the marriage joint. The joint was broken and the compressor and turbine rotors destacked and refurbished by Sulzer under the direction of the owner’s engineers and Turbine End-User Services Inc (TEServices), a Houston-based consultant specializing in such work. To learn more about what’s involved in correcting runout, visit www.ccj-online.com/archives.html, click 4Q/2009, click “Rotor overhaul. . .” on cover.

Shop time for the GT1 rotor was 14 days; that for the GT2 rotor, 21 days.

The generators for both 7241s were inspected by AGT Services Inc, Amsterdam, NY. The third-party services provider found the stator and field acceptable for continued service without wedge or rotor work and the owner’s engineers concurred. The collector was resurfaced using a stationary method.

Heat recovery steam generators. Valves were the focus of the HRSG overhauls. In-situ inspections revealed extensive cracking in the high-pressure (HP) valve bodies, which was not expected. Valves were removed from their respective main steam lines, weld-repaired at a qualified shop, and welded back in place. Based on this experience, replacement valves were ordered for Block 2 and for one of the company’s other plants.

All safety and relief valves were inspected, repaired, and tested for continued service. No flow-accelerated corrosion (FAC) was found in the HRSGs. Four P91 elbows were checked and one crack identified. Feedwater heater modules at the boiler stacks were CO2 blasted to remove foreign material from tube external surfaces.

Steam turbine. In November 2006, Stellite liberated from the seat of the main stop valve (MSV) damaging the HP nozzle and the first few rows of blades in the HP turbine (Figs 17-19). The owner chose to derate the unit by 10% and operate it as is until the 2009 major.

Shop repairs regained the lost performance. The first three rows of HP blades were replaced and the remaining damage was blended with acceptable service limits. Three L-1 blades in the LP section were found with leading-edge cracks, which were an unwelcome surprise. The owner’s engineers, Sulzer personnel, and third-party experts collaborated on a successful in-situ blending solution. The LP turbine work was the primary reason for the stretch-out in the outage schedule

The generator required a full re-wedge by AGT Services. The collector was resurfaced in the same manner as the collectors were refurbished for the GT generators.

Other work accomplished during the major included the following:

  • Condensate/feedwater system was inspected for FAC; no indications were found.
  • High-energy pipe inspection. Four P91 elbows were checked by Gas Turbine Materials Associates (GTMA), San Antonio. A crack was found adjacent to a weld on one of the four elbows and repaired. A formal high-energy pipe inspection plan was put under development.
  • Cooling towers: Structural repairs, removal of sediment from the basin, replacement and calibration of blowdown control-valve actuators.
  • Vibration monitoring. Replaced vibration monitoring equipment on the steamer. New system has the capability to analyze rotor stability anomalies in real time.

There were two more outage case histories presented at the meeting. Both had to do with problems identified during restarts after major overhauls. The first issue occurred while starting up one of the gas turbines at a 2 x 1 combined cycle.

The details: GT came up to FSNL as expected; unit walk-downs suggested everything was fine. The unit was auto-synched and placed in exhaust-temperature matching with a 700F setpoint for a steam-turbine cold start. At about 90 minutes into the startup (850F on the temperature-matching setpoint) the roving operator reported smoke coming from the No. 2 bearing-tunnel vent.

Unit was tripped and flames were noticed coming out of the tunnel via the lube-oil return penetration. CO2 was discharged manually to this area.

Action taken: Unit was spin-cooled and the bearing tunnel entered by way of the outlet vent. Wires were found in good shape; however, tunnel surfaces were covered with soot. Oil was found at the bearing end of the tunnel with no evidence of its source.

All of the lower piping and control wiring were removed from the lower half of the bearing tunnel to allow removal of the arch plates lining the lower half of the tunnel. This task is particularly difficult with the unit assembled.

Once the plates were removed, the inspection team found that the lower insulation pads were saturated with oil and that free oil was trapped between the outer tunnel wall and the insulation. Investigators learned that a portable electric-power pack had been turned over by the maintenance crew and the oil ran out. Visible oil was cleaned up, but the spill was not reported to personnel responsible for managing the outage.

The entire lower half of the bearing tunnel had to be stripped, wiped down, reinsulated, and reassembled, adding three days to the outage. Lesson learned: Protect this area with plastic and oil-soak pads during the outage and establish hold points with contractors to inspect the area before reassembly.

The final case history illustrated once again the importance of thoroughly checking work by contractors. The abbreviated version of what happened is this: An error during re-termination of CTs to field wiring that reversed polarity on one phase permitted an uncontrolled ramp from FSNL to rated output on a freshly overhauled GT. Ramp rate was 77 MW/min, allowing the breaker to close at 154 MW in two minutes.

The OEM, which performed the major, showed little concern, according to the speaker. The unit was dispositioned to run with no further investigation. There had been no issues at the time of the presentation that could be tied back to the fast-load event. An RCA showed the wires and their terminal points were clearly marked; the I&C tech just connected the wires incorrectly and no one caught the mistake. Get the details, including wiring diagrams, at http://ge7fa.users-groups.com.

The second discussion session focused mainly on safety. Group consensus was that most injuries seem to occur on first-time events—such as lifting GT rotors, removing generator rotors, etc—where institutional knowledge on actions to be taken, and where people should be and not be, are limited.

Most also agreed that there was a general lack of expertise in the industry on rigging. It’s incumbent on the plant owner, one attendee said, to assure that the contractors used—whether they be union or nonunion—have the capabilities and experience to make critical lifts. More plant training should be done in the rigging area, another user said, so staff understands what must be done and what their roles are.

Confined-space rescue and yo-yo tie-offs also got air time—the latter especially where scaffolding is required. Two points made: You probably don’t understand how difficult it is to extract a 200-lb person from a confined space until you’ve tried. Suggestion was made to get a 200-lb dummy and attempt it. You also probably do not know how difficult it is to handle extractions when those being rescued are combative. You never can be over-prepared where safety is involved.

The safety give ’n take ran a solid 20 minutes and was particularly meaningful. There were many examples of what works, what doesn’t, and the injuries (and deaths) that result when risks are underestimated and staff is not properly trained. You can get plenty of ideas of what to include in your plant’s safety program by accessing www.ccj-online.com, click 1Q/2010, and click “Best Practices Awards, Safety” on the cover. Then go backwards in time to get even more ideas from previous first-quarter issues.

A non-safety topic in this discussion session concerned long-term service agreements, contractual service agreements, parts agreements, etc. An informal show-of-hands poll revealed that the trend away from OEM long-term agreements continues. Attendees indicated that about 40% of their agreements are now with third parties—including OEMs playing in another manufacturer’s sandbox. A similar poll two years ago had third parties holding only 25% of the GT service business.

An international owner/operator with four 1 x 1 7FA+e-powered combined-cycle plants told the group about his company’s experience with a fractured diffusion-air pipe on a DLN 2.6 combustor. Plant began commercial operation in April 2009 and completed its first combustion inspection in winter 2010.

A month later, just six weeks before the 7F Users Group meeting, operators received alarms of “High concentration of fuel gas” and “High temperature in the GT enclosure.” Concurrently, the strength-of-flame detector for No. 12 combustor jumped from 70% to 100%. The unit was shut down immediately and an inspection initiated.

The No. 12 fuel nozzle was changed the next day. Engineers found the dummy nozzles in PM2 and PM3 melted by the radiant heat of the flame. Also, evidence of HCF was present (Fig 20). The crack initiation point (yellow circle) was analyzed using a scanning electron microscope, which revealed no significant crack, defect, and/or corrosion.

Next step was to measure the vibrations and stresses on diffusion-air pipes Nos. 2, 8, and 12 (Fig 21). Strain gages also were installed on PM1, PM2, PM3, and atomizing air pipes. Engineers found the highest strain at the starting point. Also, strain amplitudes were proportional to output power, and on combustor 12 they were larger than on the other combustors examined.

The RCA was not successful in identifying the root cause by fracture analysis. Here’s what the analysis team found, and didn’t find:

  • Material. No material defect could be identified.
  • Welding. Quality was not good.
  • Acoustic vibration. There was none when the combustor was operating.
  • Operational vibration. The level of stress did not exceed the material’s fatigue limit, but the margin to that limit was relatively small.
  • Excessive stress. Striations characteristic of HCF were found.
  • Creep. There was no creep fracture.
  • Stress corrosion cracking. No corrosion found.
  • Low cycle fatigue. Not in evidence.

Conclusion was that poor welding and high stress attributed to vibration might have been the underlying causes of the failure. Action: Review weld quality on other combustors and improve as necessary.

Another user reported a trip on high compartment temperature. Flame burned through blanks in the combustor end cover provided for dual-fuel use. This unit had no oil capability. The speaker thought that the end cover might not have been bolted snugly. Or possibly a brazed joint might have been cracked, allowing fuel to leak into the open space. Flame “cooked” the IGV actuator line; a new actuator was installed.

An attendee said his plant had a similar incident. No root cause was offered by either of the affected parties.

Discussion moved to HGP hardware performance and interval extension. Experience at 24,000 hours was noted.

Enough can’t be said about having an experienced crew patrolling the aisles with microphones to ensure that everyone can hear all questions and comments. Anyone can carry a portable microphone, but knowledgeable steering committee members with “mikes” contribute to the dialog and keep it moving. It’s rare that someone on the steering committee wouldn’t have had experience to contribute on any topic that comes up in a 7F meeting.

1. Classic tip crack is shown at the left with crack initiation about 2 in. from the leading edge. Impact caused the damage at the right

2. Stake marks indicate this is the third set of R0 blades. The next change-out will require the OEM to install its “Biscuit” mod before installing the blades

3. Damage to trailing edge of rotating blades. More specifically, deformation and some lift-up of material near the platform at the trailing edge

4. Damage to S2 leading-edge tip. Most damage was from the 6 o’clock position to the horizontal joint

5. Cropped S2 leading edge during an outage. Technicians took precise measurements of the damaged area on each vane then cropped the worst airfoil and cut back the entire row to the same point

6, 7. R2 blade trailing-edge (left) and S2 vane leading-edge (right) clash indications typically look like this when viewed through a borescope

8. Smeared and rolled metal on adjacent stator vanes (damage area on vane at left, 1 x 0.25 in.; at right, 1 x 0.375 in.) proved clashing was increasing in severity since its discovery a year earlier

9. Stress cracking is relatively common on piccolo pipes where they attach to their respective pipe guides and in the areas where pipe guides attach to the floor. Stress cracks also may be found in the duct floor and in the pipe guides themselves

10. Redesigned guide sleeve for piccolo pipes is easy to make and doesn’t require cutting the existing pipes

11. Installation of the new guide sleeves went according to plan and has eliminated the need for annual crack repair

12. Bucket damage at the leading edge and coating detachment resulted from forward migration of the airfoils

13. Lockwire is clearly out of the groove provided, compromising its ability to hold buckets in position

14, 15. Fallout from the first-stage bucket migration issue includes damage to first-stage vanes and second- and third-stage buckets

16. Inner tip of the lock wire should point in the direction of rotor rotation to help prevent the lock wire from moving

17. Steam turbine’s MSV threw some Stellite (see insert) from its seat in November 2006, damaging HP nozzles and blades (see Figs 18 and 19)

18. HP nozzle block was repaired and returned to service

19. Blades in the HP section (first stage shown) were banged up badly by liberated Stellite

20. Analysis of fracture surface revealed striations characteristic of HCF along the red arrows. Starting point of the cracks appeared to be in the yellow circle at the back ends of the arrows

21. Vibration sensors and strain gauges were installed on the diffusion-air pipes serving combustors Nos. 2, 8, and 12