It wasn’t long ago that the Frame 6 Users Group could be defined by the phrase “business as usual.” The steering committee had remained the same for many years, as did the core attendee base and conference organizer. The meeting format essentially was “etched in stone.”
So was the program content, to some degree, because the 6B is a familiar GE gas turbine in cogeneration systems at process plants where staff typically is challenged to keep legacy assets operating on a low O&M budget, often without the support of a corporate engineering staff. The presentations and discussions at annual meetings provided know-how and proven solutions to help achieve that goal.
In 2020, Jeff Gillis, a senior engineering advisor at ExxonMobil Research & Engineering Co, continues to chair the group, supported by veteran steering committee members
J C Rawls, technology engineer in BASF-Geismar’s utilities department; Mike Wenschlag, Chevron Global Power, El Segundo refinery; and Zahi Youwakim, utility plant engineer, Huntsman Petrochemical.
Robert B Chapman Sr, turbine repair engineer for Chevron Maintenance & Planning Execution, joined the committee two years ago. More recently, Kevin Campbell, a cogeneration specialist at the El Segundo refinery, and Kevin Bovia, a mechanical reliability engineer at BASF-Geismar, were added to the roster.
They replaced Geoff Kret of Total Petrochemicals USA, Sam Moots of Colorado Energy Management, and Brian Walker of Foster Wheeler Martinez Inc, whose corporate responsibilities had changed, plus Atlantic Power Corp’s John Vermillion.
Wickey Elmo of Goose Creek Systems, who managed the user group’s activities for several years, retired at the end of the 2016 conference and was replaced by the incumbent Greg Boland.
Perhaps the biggest hiccup in the group’s three-decades-plus of service to the industry was the need to cancel the 2020 Conference and Vendor Fair because of the coronavirus pandemic. Some online sessions in the planning stage will help keep owner/operators current on fleet developments. Details will be posted at www.frame-6-users-group.org when they become available.
What follows is a report based on presentations and discussions conducted at the 2019 meeting at the Hilton Orange County in Costa Mesa, Calif, June 10-13, where Brian Walker received the 2019 John F D Peterson Award from Chairman Gillis, and the award’s namesake, for his many years of outstanding service to the Frame 6 community. Walker came up through the trades, accumulating more than two decades of experience in E/I&C work prior to his appointment as maintenance manager and HSSE coordinator at the Foster Wheeler Martinez combined-cycle cogeneration facility in Northern California.
Sean Bonato of Montana Dakota Utilities Co also accepted an award from Gillis, this one commemorating 40 years of operation by the industry’s first Frame 6 (MS6431A), installed at MDU’s Glendive Power Plant. Commissioning was July 15, 1979. The Glendive Frame 6, rated 41 MW according to Platts data, shares the site with a 43-MW LM6000. Both are dual-fuel capable, says Platts.
Workshop and schedule
Monday afternoon, June 10, the day before the 2019 conference began, Peterson, one of the user group’s founders, conducted his highly regarded four-hour introductory course on the Frame 6B. This session is offered by the steering committee to acquaint new members on the (1) history of improvement in both thermal and mechanical performance since the engine’s introduction in 1978, and (2) opportunities offered by the Frame 6 Users Conference for the best possible technical exchange and interaction with other owner/operators of the versatile engine, OEM engineers, and representatives of third-party products and services providers supporting the fleet.
The workshop is invaluable for first-timers and a welcome refresher for many veterans. It begins with a brief history of gas-turbine development (specifically the Frame 6) and moves quickly through Brayton Cycle basics. Key performance indicators are next, followed by an overview of engine components—compressor, combustion system, turbine, auxiliary equipment, and fundamental control concepts. Common failure mechanisms and problems solved over the years (nozzle oxidation and creep, first-stage bucket life, etc) follow. The final segment of the program reviews resources available to users to enable better O&M decisions.
Anyone who knows Peterson would likely tell you this session alone is worth the conference registration fee. Few in the industry know as much about this frame as he does.
The formal meeting kicks off Tuesday morning at 8 a.m. and features several roundtable discussions and a vendor presentation before the opening of the vendor fair at 5 p.m. The roundtable topics last year (most years): safety, auxiliaries/generators/excitation, I&C, best practices, compressor, and combustion section. The featured presentation, by Jamie Clark of AGT Services, concerned case histories on a 6A3 field rewind and stator re-wedge.
Wednesday—so-called GE Day—is reserved for OEM presentations (new/updated Technical Information Letters, rotor end of life, new technology offerings and updates, etc) and breakout discussion sessions. In 2019 the breakouts focused on the rotor, generator and engine accessories, FieldCore, combustion systems, I&C, and repair technology. A reception and GE product fair closed out the day.
Thursday, always a half-day at Frame 6 meetings, featured a roundtable discussion on the turbine section plus the second of two vendor presentations—this one by PSM on rotor repair and life extension.
Safety is the first discussion topic at Frame 6 meetings and most other user-group conferences. This roundtable is led by Gillis, whose position as gas-turbine technology lead for ExxonMobil’s worldwide fleet of engines gives him a global perspective to share with attendees. OSHA is not global and America does not have all the answers.
Gillis’ first slide was designed to stimulate thinking, aided by morning coffee. He put up a list of possible topics in three categories to get the discussion rolling, including:
- Life-saving rules.
- Compartment entry.
- Hazardous-gas detection.
- Fire suppression.
- Fall protection and PPE (Personal Protective Equipment).
- Scaffolding and access.
- Safety professionals and other personnel.
- Inlet-filter-house fire prevention and escape.
- Rescue considerations.
- Fuel-nozzle failures resulting in a casing breach.
The first topic introduced concerned a unit trip on high oil temperature without alarm notification. Plus, recorded data did not indicate any change in temperature. The alarm for high oil pressure also was found faulty. The gremlin was a loose wire. Termination strip was repaired and the unit returned to service in the late afternoon. The user sharing the experience said termination strips can take just so much abuse and suggested that the person you assign to work on them should be someone you trust with a screwdriver.
An attendee shared his experience with a black-start unit brought up to full speed/no load (FSNL) that couldn’t be synchronized. The safety issue was that the Mark VI auto-synch feature was not turned off and the breaker closed with electricians in the generator auxiliary cabinet. The group was polled to see how many attendees close the generator breaker with someone in the GAC. No hands were raised.
One outcome from this incident was a modified startup procedure that requires operators to confirm excitation at 50% speed on black-start units. Also, electricians must check the GAC to confirm there are no faults prior to startup. Finally, a warning sign was hung on the cabinet door and operators are required to issue stop-work permits to electricians during engine starts.
Another technicion mentioned that PPE safety boxes are located at strategic locations around his plant. They include PPE-use requirements for specific tasks and equipment. Tooling also is located throughout the plant. One example given was the placement of toolboxes on top of the HRSGs to reduce the need for technicians to travel back and forth to a central location, saving time and reducing the risk of injury.
One user offered an observation that safety procedures often are “ignored” between outages, when the safety “police” are not on duty.
Fire protection is discussed at every meeting. Last year a user mentioned that the CO2 system at his plant discharged before the alarm activated. Having reliable alarms and external lighting to warn of a release is critical to personnel safety. One got the impression that controls for fire- suppression systems—water mist and CO2—were not as reliable as they should be. Hard to find qualified vendors to maintain these safety systems, according to a few participants. One said he double-checks third-party certifications and any work done on the system.
Attendees were urged to check package integrity for leaks because if leakage persists—at louvers, for example—you can’t maintain the inert atmosphere while the unit cools. Louver mechanisms on legacy units were identified as a problem area and characterized as being “rinky- dink.”
Chairman Gillis noted several safety threads on the organization’s online user forum— including experience with optical flame detectors, how to deal with ill-fitting compartment doors and hardware replacement to correct, functional tests to confirm proper operation of water-mist fire-suppression systems during unit commissioning, opening of compartment doors with the CO2 system activated, and alternatives to IGD combustibles detectors.
He also listed in his presentation the Technical Information Letters (TILs) published by the OEM that should be reviewed by the safety manager at each plant (sidebar). If you don’t have copies of the pertinent documents, request them from your plant’s GE representative.
In the Auxiliaries Roundtable, discussions focused on sulfur buildup in stop/speed ratio valves that could prevent restarting after a unit trip, the value of a flash drum in the continuous blowdown line enabling beneficial use of the steam produced, the value of inlet bleed heat for deicing and unit turndown, and other topics of value.
An attendee reported a trip on low lube-oil pressure revealed that regulator valves had not been serviced in 32 years of service and the brittle diaphragms failed. The diaphragms on valves serving other units were replaced “just in time.” Another user, who reported going 24 years before changing out diaphragms, warned, “Make sure you reinstall the orifice.”
Other notes from the session illustrating the value of participating in the Frame 6 Users Group’s annual meeting, included the following:
- Discussion of torque-converter orifice fitting issues.
- Upgrade of a jaw clutch to SSS clutch.
- Hardened coupling that led to hydraulic ratchet-pump failure.
- How to avoid coupling failures on your load gear and auxiliary lube-oil pump.
- Recommendation: Conduct accessory- and load-gear inspections during majors. Take the necessary precautions to avoid an oil spill.
- Pitting of load-gear tips or teeth was reported by several plant personnel. Consensus was that everywhere there is a nozzle, there’s pitting at the tip of the tooth.
- Suggested inspection interval for AC auxiliary and DC emergency lube-oil pumps was five years.
- Failures of flexible hoses were reported between the reservoir and hydraulic pump.
- Checking of nitrogen pressure in the hydraulic oil accumulator was recommended during major inspections.
- Coupling issues in the shaft hydraulic oil pump were reported by several participants. Replacement intervals varied from annually to each hot-gas-path inspection to every major.
- Problems with an oil mist separator at one plant were traced to weak vacuum.
The I&C Roundtable included a debate on the pros and cons of upgrading control systems versus retaining/maintaining legacy controls. Several users supported the idea of sticking with legacy systems because there’s a vibrant third-party supplier community available for support—including parts and knowledgeable technicians.
An operator with Mark VI controls said his plant upgraded to Mark VIe because of parts availability. Yet a recommendation from another participant was to keep spares of critical boards for Mark VIe and VIeS controls in-house because they are hard to find and lead times are long. Be prepared, he said.
Guidance offered to those considering new control systems included the following:
- When planning a rip-and-replace project, don’t forget the wiring, instrumentation, and other equipment that may not be included in the contractor’s scope of supply. And don’t chintz on the contingency because you will have discoverables.
- Expect issues with lengths of wiring requiring junction boxes and other connections.
- Think about routing wires under the subfloor.
- Always say “yes” to a factory acceptance test (FAT). Rigorously run through all the logic, graphics, etc, with supplier personnel. You can’t do this effectively in the field.
- Remember to double-check control constants after upgrading. Consider including this step in the FAT.
- All linear variable differential transformers (LVDTs), used for accurately measuring linear position or displacement, are not created equal. Check part numbers to be sure you have the correct spares. Also, install LVDTs in “friendly” locations to both minimize the potential for failures and to facilitate access.
- Servos impacted by varnish buildup is a perennial hot topic. A user said his plant came to expect trips because of varnish so they decided to change servos annually. Then they found the infant mortality rate was worse than expected so they went back to replacing servos when they fail.
- Dump-valve issues? Toggle the logic to be sure the valve is operating properly.
- Heads-up: Users say compressor bleed valves sent to shops for refurbishment sometimes are not reassembled correctly. Quality control should be stressed with suppliers and plant staff should verify correct assembly before the CBVs are transferred to your warehouse.
- Y&F 9500 combined stop/speed ratio and gas control valves were said to be robust, requiring little service. However, one attendee reported his experience with the OEM’s field service team on one valve was not up to par and recommended using Young & Franklin for the inspection and overhaul of its valves. Also mentioned was the importance of following packing procedures to the letter to prevent leak-by.
- Attention to detail when filing permits was stressed. One user noted that DLN tuning required after an outage was not specified in its permit. Ouch.
- Kudos: PSM received “likes” from several attendees for its LEC III™ low-emissions combustion system.
Best Practices was introduced as a roundtable in 2019. Topics were varied. First was a fit-up test for first-stage nozzles and transition pieces (TPs) two to three weeks before the outage to avoid surprises. Other BPs included these:
- Do a proper repair spec and follow your parts through the shop for best results.
- Specify a full thermal barrier coating (TBC) for TPs. It will extend part life.
- Exhaust-gas thermocouple jumpering: Don’t jumper to the adjacent T/C or to the one with the highest or lowest temperature. Use the algorithm in TIL 1524 to calculate the exhaust spread.
- Check T/Cs during startup for possible problems ahead. If you find a T/C lagging the others by about 100 deg F, and eventually catching up, consider replacement at your next opportunity.
- Replacement of wheel-space T/Cs can be challenging. Before carefully removing the defective T/C to avoid breakage, use a Sharpie® marker to indicate the proper depth of insertion and mark the replacement T/C accordingly so you know when it’s fully inserted.
- Parts stocking strategies also generated meaningful discussion.
The sharing of best practices among owner/operators contributes to safer working conditions and increases in unit availability and reliability fleet-wide. The Frame 6 users have been proactive in this regard, contributing their experiences during the annual meetings, in the group’s online forum, and via CCJ’s Best Practices Awards program.
Two innovative entries recognized with awards last year, submitted by steering committee member J C Rawls of BASF-Geismar, are profiled later in this section. One discusses a home- grown boiler efficiency controller that improves performance through process automation, the second a performance dashboard that tells at a glance if a particular system or piece of equipment is meeting operational expectations.
The Compressor Roundtable included discussion of the following:
- HEPA hydrophobic filters. A user said his HEPA filters had been in service for two years and provided very dependable output over that time. Compressor remained clean.
- Some users touted the benefits of removing inlet silencers—including a lower delta p across the inlet system while mitigating compressor damage. One said the noise level didn’t get much higher—except for one octave band that could be heard for miles, which was remedied. A few more users said they were planning to remove their silencers in the coming year.
- Dos and don’ts: Avoid compressor water washing before an outage to avoid corrosion; do perform an offline wash after an outage.
- A suggestion to the group: Clear the bellmouth drain after a compressor wash; you don’t want a couple of feet of water accumulating at the compressor inlet where it can be sucked into the unit on restart.
- Inspection of the inlet bleed heat system was recommended during scheduled maintenance outages (TIL 1320).
- Alternatives for staking Row 1 compressor blades were discussed—including the biscuit mod.
- Move compressor bleed valves from inside the package to the outside for better reliability.
There were three short presentations by owner/operators at the 2019 meeting—high wheel-space temperature issues, exhaust-plenum replacement, and rotor life extension—and two by vendors—generator minors that turned into majors and rotor lifetime evaluation—at the 2019 meeting.
High wheel-space temperature issues were discussed by an owner/operator with three 42-MW 6Bs (Model 6581B) that had been commissioned in 2003. Two units completed their second major inspections in 2018, the third in 2019. High temperatures were noticed in the second and third turbine stages of one machine during startup following the major inspection.
The root-cause analysis (RCA) by plant personnel was thorough. The investigation reviewed the following possible causes or contributors to the issue:
- People: T/C installation method, installation restriction, space restriction, air filtration, and filter house.
- Equipment: damaged T/C wiring, improper installation, functionality check (yes, no, results?), T/C integrity, broken T/Cs.
- Material (HGP components): T/C source (new, refurbished?), borescope, cooling, condition of nozzles, condition of buckets, repair history.
- Measurements and seal clearances: Shroud clearances, nozzle clearances, bucket clearances, turbine clearances, diaphragms.
- The findings:
- Wrong insertion. T/C was reading diaphragm temperature because the insertion length was incorrect. See fifth bullet in the Best Practices Roundtable summary above.
- Investigators found the T/C guide-tube cap was machined incorrectly, preventing the T/Cs from reaching the ends of their caps. When corrections were made the T/Cs installed smoothly to the correct insertion length.
- Lessons learned:
- High wheel-space temperature is a common problem on 6Bs.
- During a major inspection, before installing the turbine casing, make sure the wheel-space T/Cs are installed correctly.
- Borescope T/C guide tubes.
- Apply heat on the T/C guide-tube caps and verify response via the control system.
- Teamwork involving all personnel with expertise to share is critical to rapid problem-solving.
The exhaust-plenum replacement case history had some twists and turns. One of the
principal vendors being considered for this project emailed plant personnel the following message on a Monday morning in April 2019: Our company will be shutting its doors for business as of today. It is a Chapter 7 bankruptcy, not Chapter 11, which allows for a financial reorganization of the firm. Most employees were laid off on that day.
The week had to get better from that point forward.
Interestingly, another candidate vendor for this project, Shock Manufacturing, was formed about six years earlier by Gene Schockemoehl, who had been president of the company filing for bankruptcy. Turns out, Schock had a plenum design plant personnel believed more durable than that offered by the bankrupt company.
It features closely spaced, large-diameter Type-304 stainless steel pins to hold the insulation in place between the inner and outer shells of the plenum. Pins are welded directly to the outer casing where the temperature is between about 150F and 170F during operation.
Welds for the scallop-bar design offered by the bankrupt company, by contrast, are on the hot side of the exhaust casing where the temperature is more than 1000F. Frequent cycling is conducive to studs shearing off at the top of the bar and failure of the insulation system.
Rotor life extension is a topic on the minds of many 6B owner/operators because operating hours accumulate quickly in process plants that run continuously. Recall that the OEM requires inspections, refurbishment, and/or replacement of B- and E-technology rotors at 5000 factored starts or 200,000 factored hours, whichever comes first (to dig deeper, consult the latest versions of TIL-1576 and GER 3620). For most attendees at this user-group meeting, the hours limit is applicable.
The user presenting sees a 200,000-hour rotor lifetime evaluation (LTE) for his 6B without merit because the best you can do after spending all the money for the inspections, component refurbishments, new consumable parts, etc, is get approval to run another 100,000 hours (about eight years at his plant). The alternative he prefers is to bring the rotor into a qualified shop, replace all of its life-limiting components, and extend rotor lifetime by 200,000 hours.
He told the group that this course of action would involve the following at a minimum:
- Replace the last three or four stages of compressor wheels.
- Replace all compressor blades.
- Replace some turbine wheels and spacers.
- Replace all tie bolts and marriage bolts.
PSM’s presentation, “F6B rotor repair and lifetime extension solutions for improved lifecycle costs,” Thursday morning, offered an alternative to the OEM’s LTE program, described on the previous day.
The presentation began with the requisite “who we are and what we can do for you,” shop locations, international affiliations, numbers of LTE projects completed and the frames involved, availability of seed rotors for swaps to eliminate outage time, rotor-disk manufacturing experience, computer program and analysis capabilities for modeling, materials analysis, NDT capabilities (eddy current, ultrasonic, microstructural review, etc). You can access information of interest on the Frame 6 website.
What might have been the most interesting segment of this presentation for hands-on users came at the end—recent findings.
Example 1: 7EA compressor-rotor distress was identified in multiple locations—specifically pitting in disc webs and distress in blade slots previously blended and/or cracked. FCD was said to accelerate aft slot cracking; previously blended slots re-cracked during the subsequent interval.
Example 2: Rabbet-fit cracking was attributed to improper interference between disc snaps. The speaker said PSM reviewed critical specifications and ran calculations before shop personnel were allowed to “chase out” the crack. Re-contouring of the OEM’s geometry was said to produce a life benefit.
Example 3: A 6B rotor (more than 5000 factored starts and about 40,000 factored hours) was found to have a flaw in the first turbine wheel, which was attributed to fast starting of the machine. Calculations and modeling conducted based on site data predicted the failure and suggested a material change and design refinements that would improve low-cycle fatigue life.
Example 4: Inspection of a 9E compressor revealed blade-slot cracks that had migrated through the rim. Multiple indications also were found on pumping vanes. Plus, cracking was found in the counterbore of the forward turbine stub shaft. This led engineers to believe in the possibility of component retirement during the upcoming LTE; they suggested the owner/operator develop a contingency plan.
AGT Services’ presentation, “Frame 6/6A3 ‘minor’ outages turned to majors with field rewinds,” is summarized here.
The first presentation after opening remarks reviewed how GE communicates with its customers and the value to plant personnel of the OEM’s TILs, PSSBs, Product Service Information Bulletins (PSIBs), and GEKs covering installation, product specifications, troubleshooting, maintenance, technical recommendations, etc. There’s much owner/operators can learn by becoming familiar with these resources and reading thoroughly sections pertinent to tasks at hand.
The speaker selected one TIL (2122) and one PSBB (20180709) for detailed coverage. The first focused on replacement recommendations for threaded fasteners; the latter, hexavalent chromium concerns, which had been covered during the Safety Roundtable the previous day.
The motivation for TIL-2122 was the liberation of a stud in a combustion assembly that caused damage in the hot gas path. The process used in fastener manufacturing was identified as the primary contributing factor and the OEM conducted a risk assessment for all parts supplied by the negligent vendor, which was disqualified based on findings.
A fleet-wide program was initiated to address high-risk applications, with low-risk applications managed through TIL-2122. It advises the replacement of questionable components that are accessible at the next interval; fasteners that are part of an assembly would be replaced in the normal repair process.
Attendees then were reminded of some important older TILs, in particular 1585 and 1986, also mentioned during the Safety Roundtable and listed in the sidebar. Focusing on the combustor for a moment, the speaker advised a review of the following:
1377-3, Extendorized combustion liners, revised stop locations. 1437-2, DLN1 liquid-fuel operation recommendations.
1770, DLN1/1+ tuning requirements.
1952, Modified repair process for 6B standard combustor fuel nozzles. 1991, 6B transition piece to S1N floating seal engagement.
2041-R2, 6B secondary fuel-nozzle inspection and repair guidelines.
Plus, 1574 and 1713, which also were called out during the Safety Roundtable.
Next, the speaker suggested attendees review these GEKs and GERs and to build the reviews into the plant’s O&M policy:
- GEK111694, Flex hoses.
- 229A6027, Pressure testing of flexible metal hose. Note: All parts are tested by the OEM’s suppliers before shipment.
- GEK121358, DLN1+ gas-only electrically actuated GCV and SSRV.
- GEK 111331, O&M recommendations for media-type gas-turbine inlet-air evap coolers. GEK 111787, Combined hydraulic- and lift-oil system.
- GEK 116736, Water-mist fire protection system.
- GER 3620, the OEM’s O&M guidebook. Note: The editors recommend this be read cover to cover by all plant O&M personnel.
- GER 4217, a helpful guide to 6A/6B history and upgrades.
Final slide highlighted the value of registering for and using MyDashboard, the OEM’s 24/7 connection (https://registration.gepower.com/registration) for technical, performance, and planning information on your assets. Use it to file warranty claims, view manuals and technical documents, search GE’s solutions database, get outage reports, and much more.
Safety TILs and Product Service Safety Bulletins affecting 6B gas turbines
TIL 2101, Modification of manual lever hoist for safe rotor removal. 2044, Dry flame sensor false flame indication while turbine is offline. 2028, Control settings for GE Reuter Stokes flame sensors.
2025, GE Reuter Stokes FTD325 dry flame sensors, false flame indication. 1986, Braid-lined flexible metal-hose failures.
1918, 6B Riverhawk load-coupling hardware and tooling safety concern. 1838, Environmentally induced catalytic-bead gas-leak sensor degradation. 1793, Arsenic and heavy-metal material handling guidelines.
1713, 6B, 6FA, 6FA+E, and 9E false-start drain system recommendations. 1709, 6B load-coupling recommendations.
1707, Outer-crossfire-tube packing-ring upgrade.
1700, Potential gas-leak hazard during offline water washes. 1633, Load-coupling pressure during disassembly.
1628, E- and B-class gas-turbine shell inspection.
1612, Temperature degradation of turbine-compartment light fixtures. 1585-R1, Proper use and care of flexible metal hoses.
1577, Precautions for air-inlet filter-house ladder hatches. 1576-R1, Gas-turbine rotor inspections.
1574, 6B standard combustion fuel-nozzle body cracking. 1573, Fire-protection-system wiring verification.
1566-R2, Hazardous-gas detection system recommendations. 1565, Safety precautions to follow while working on VGVs.
1557, Temperature-regulation valves containing methylene chloride. 1556, Security measures against logic forcing.
1554, Signage requirements for enclosures protected by CO2 fire protection. 1537-1, High gas flow at startup—Lratiohy logic sequence.
1522-R1, Fire-protection-system upgrades for select gas turbines. 1520-1, High hydrogen purge recommendations.
1429-R1, Accessory and fuel-gas-module compression-fitting oil leaks.
1368-2, Recommended fire-prevention measures for air-inlet filter houses. 1275-1R2, Excessive fuel flow at startup.
1159-2, Precautions for working in or near the turbine compartment or fuel handling system of an operating gas turbine.
2018-1003, Online collector-maintenance awareness.
2018-0709-R2, Observation of hexavalent chromium on parts during outage. 2016-1220, GT upgrade—Impact on HRSG.
2016-1209, Gas-turbine water-cooled flame sensor false flame indication. 2016-1117, Lifting and rigging devices.
2016-1104, Gas-turbine operational safety GEK update.
Rotor. The following speaker updated the group on rotor end-of-life (EOL) initiatives. He began with a review of GER 3620 (revision N) and the factoring methodology for hours and starts used in establishing maintenance intervals. Next came a series of highlight slides discussing (1) rotor life and the failure methods and mechanisms that influence it, (2) rotor life management and the inspection-based analytical modeling and analysis used to gauge remaining life, and (3) service-center observations and findings related to 6B rotors. Explanations and impacts of creep, fatigue, and fracture were summed up in a couple of slides on mechanical design and metallurgy.
The presentation’s value to users is familiarization with technologies, concepts, methods, calculations, etc, used in rotor EOL determinations and subject matter they should have a good understanding of.
Improvements. This presentation focused primarily on experience with the Advanced Gas Path (AGP) mod on 6Bs and compressor improvements to extract greater value from your assets. Perhaps you recall that the first AGP for a 6B engine went into service two days before the group’s June 2018 meeting. This speaker reported that as of the 2019 conference five AGP sets had been delivered, with the fleet leader (the first unit) at more than 8000 factored fired hours (FFH). Also mentioned was that beginning this year (2020) all new Frame 6Bs would be AGP-equipped.
The AGP enhancements for a 6B, it was said, typically can deliver from 2% to 15% more power, a heat-rate improvement of up to 4%, an HGP interval of 32k FFH, higher firing temperature, and 2% to 7% more exhaust energy. The exact benefit for a given unit depends on an engine’s operating history and component profile.
Regarding the interval extension to 32k FFH, the value is quite significant, going from four major inspections, 16 combustion inspections, and four HGP inspections, for a 200,000-hr lifecycle, to three majors and three HGP inspections. Run a back-of-the-envelope calculation for your 6Bs to get an idea of the benefit for your plant.
A supporting case history (favorable to the OEM), was for an original 6541B coming up on an HGP inspection with a need for new replacement-in-kind parts. The unit, equipped with Mark VI
controls and DLN1 Advanced Extendor, operates baseload 8000 hr/yr on natural gas. Assumptions were $50/MWh for power, steam revenue at $5 per 1000 lb/hr, and a fuel cost of
$5/million Btu. With a 15% increase in power output, heat-rate improvement of 5.1%, and an increase in exhaust energy of 7.6%, the annual benefit was calculated at $2.3 million in round numbers.
Architectural changes to the compressor and turbine sections are key to the AGP engine’s performance improvements. Advanced airfoil design, use of materials and coatings with greater tolerance to corrosion and erosion, implementation of blade-health monitoring, and use of stainless-steel stator vane segments for the first four compressor stages are among the many beneficial changes. Get more specifics from the presentation posted on the Frame 6 website. CCJ