Frame 6 meeting helps maximize the value of legacy assets; register today!

The Frame 6 Users Group moves its 2019 meeting location to the West Coast after conducting last year’s conference in Florida. The venue is the Hilton Orange County in Costa Mesa, Calif, June 10 to 13.

Not much changes in the organization of this group’s meetings year over year. Content always is technical, generally focusing on how to squeeze more life and better performance from legacy assets. Register now and come away with actionable ideas on how to improve availability, increase output, reduce emissions, extend maintenance intervals, etc. 

The steering committee remains the same except that Brian Walker, a major contributor to this forum for decades, has moved on because of new job responsibilities. Jeff Gillis and Sam Moots continue as co-chairmen, supported by veterans Robert B Chapman Sr, James C Rawls, Mike Wenschlag, and Zahi Youwakim.

For readers unfamiliar with this all-volunteer organization, be aware that its highly interactive conferences have five key elements:

Workshop. The need to do more with less should not surprise anyone in the electric power industry these days. Users groups are working diligently to make the next generation of engineers and technicians productive more quickly than, perhaps, ever before in peacetime. Mindful of the need for specialized training, the 6B steering committee integrated a frame-specific half-day workshop on engine design, operation, and maintenance into the 2018 meeting. It was an instant success with John F D Peterson as the instructor and discussion leader. He is one of the organization’s founders and has more than three decades of relevant engine experience.

Anyone who knows Peterson will tell you this session alone is worth the conference registration fee. Few know as much about this frame as he does.

The half-day course, Monday afternoon, June 10 (the day before the conference begins), will be fast-paced and conducted in four sessions of about 50 minutes each, with short breaks between them. Each attendee will receive a course workbook with descriptions of components, definitions of technical terms specific to the 6B, a listing of common operational and maintenance issues, etc. This document will be an invaluable aid for the meeting and at the plant afterwards.

Here’s a summary of the subject matter included in the course:

    • Brief history of gas-turbine technology and the Frame 6B.

    • Theory of gas-turbine operation; engine performance basics.

    • General description of the 6B gas turbine and the typical plant that it serves.

    • Auxiliary equipment and system descriptions.

    • Troubleshooting of critical systems—including lube oil, hydraulic oil, trip oil, fuel gas, rotor ratchet mechanism, etc.

    • Control systems.

    • Glossary of 6B terms and jargon.

Attendee profile. Frame 6B gas turbines are the heart of many cogeneration systems, and the O&M personnel responsible for them are a breed apart from most users the editors meet at industry meetings. The typical 6B user is a highly experienced “lifer” responsible for keeping steam flowing from his or her cogen facility to one or more process units.

The lives of 6B owner/operators rarely are controlled by a grid contract, by the need to “fill in” around must-take renewables, or by power prices. Electricity is simply a byproduct of steam production, a world where an empty steam pipe means you might well be looking for employment elsewhere tomorrow.

Such a challenging environment is conducive to a practical solutions-driven mindset. It’s not news that some cogen-plant owners consider power production a “necessary evil” and keep O&M budgets lean, opting to spend on process facilities first. Their belief is that end-product investments will produce a better return—at least until a gas turbine is forced out of service.

Adding to the financial challenge is that many cogen facilities are not supported by a corporate engineering staff, and instead rely heavily on the talents of very-capable deck-plates personnel. The Frame 6 Users Group contributes to success by providing a “technical solutions lifeline” for its membership and the reason many of these people continue to attend meetings year after year—some since the group was founded more than three decades ago. 

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User discussion: Some 6B turbines nearing replacement age

Discussion on the turbine section always is robust at Frame 6 Users Group meetings, likely because there are many “senior” machines in the fleet—those with well over 100k operating hours. Current thinking of the OEM and a few others is that an end-of-life inspection should be done at about 100,000 hours and that the rotor should be replaced at 200k.

One of the users said he thought there might be an economic benefit to simply replacing the rotor at 100k, at least for 6B engines, because vibration issues are common after an EOL inspection and machines generally run very well after installing a new rotor. Another attendee’s experience added credibility to this suggestion. He said excessive wear was found in the dovetails of the third-stage wheel for one of his units during an EOL inspection and the heavy coating applied in the worn areas presented issues during restack.

Frame 6 veterans had good advice on parts and coatings for attendees having limited experience this frame. When you’re in the market for parts, know the specifics of what you need. Specifications are critical to the bid process. Attention to detail is important: “If you get it wrong,” the group was told, “your machine will not operate as well as expected.”

Consider visiting candidate vendors before making a buying decision and engage with them on coatings, design, alloy, casting, grain structure, airfoil shape, heat treatment, repairability, etc.

Regarding coatings, one user mentioned that the OEM offers an “optimized coating,” enabling a choice based on operating paradigm. It was said that some coatings are better suited for baseload operation, others for peaking service.

First-stage buckets generated significant give-and-take. One user said getting anything but the 16-hole airfoils was challenging. Another user, noting that new first-stage buckets don’t have TBC, asked if other attendees were adding a coating to ensure a 24k interval and one more repair cycle. Adding a coating might not make sense, one colleague replied, it depends on your business goals. “Are you looking for reliability or performance?”

One user concern regarding new first-stage buckets is that cooling holes are so close to the squealer tips that a rub could block air flow. A suggestion was to always check cooling holes when you can to be sure they are open.

First-stage nozzles. TBC is optional; however, repairs can be very expensive if you don’t specify a coating. But be careful: If you “go crazy” with TBC, you might restrict air flow and adversely impact performance. Specify TBC thickness and be sure the shop measures it. Remember, too, if you add TBC to a nozzle that didn’t have it previously, some metal must be shaved off to accommodate the coating thickness.

An attendee troubled by TBC spallation and trailing-edge damage was told not to worry too much because they would not wreck his machine.

Shroud blocks. The group was told that casings like to ovalize over time. Remove shroud blocks until you get to one with the minimum clearance and shave down the ones removed. First-stage shroud blocks must be recoated, not those in the second and third stages; however, you can have challenges with the latter because of honeycomb seals. Be patient, ovalization stops at some point.

Exhaust flex seal eventually will crack and fail because of the challenging operating environment. A telltale clue is over-amping of the exhaust fans, which can’t get enough cooling air into the bearing tunnel. A quick visual inspection of the flex seal was recommended each time the shell is off. If you are not familiar with the exhaust system, look at the photos here taken during the inspection of a 7F machine which is similar in design to the 6B, but larger.

Auxiliaries, generators. There wasn’t as much discussion as you might expect on auxiliaries, but the allotted one-hour time slot in the 2018 program was shared with generators and excitation. Best for users with concerns/questions on this equipment is to send an email to Co-chairs Gillis and Sam Moots (via conference organizer Greg Boland of Creative Ventures Holding) a couple of weeks in advance of the coming meeting and get them on the discussion agenda.

A user described a load-coupling failure on a 1990 unit. He said the OEM replaced the coupling in 1998 because of high vibration, but it failed on startup after 50,000 hours of service. GE wanted a year to deliver a replacement so the owner went to a third-party supplier and purchased a similar coupling. Shortly thereafter, it was said, the OEM issued an advisory to plant personnel saying that it had “lost faith” in its coupling.

Torque converters and the ratchet mechanism got some air time with one user saying that if the latter is not ratcheting, the torque converter likely is the main cause of the failed start. Another user reported binding of the ratchet shaft. Yet another was a problem with varnishing of the sequencing valve—severe enough to require disassembly and cleaning at every major.

Load-gear oil leaks were introduced by a user trying to determine just what is “acceptable leakage” is. He attributed the leakage to a design issue.

A stator rewind was the highlight of the generator session. The user described the removal of the stator frame which was then sent to the shop where the work was done. Project was considered a “great success” by the owner.

The combustion session encompasses discussion of fuel nozzles, liners, flow sleeves, transition pieces (TPs), crossfire tubes, igniters, flame eyes, and combustion cans and piping. One snippet of advice from an attendee: Never buy new flow sleeves. You can repair them many, many times. However, having a spare set on hand was viewed as prudent.

Discussion of combustion hardware was lively. It was said that the OEM only guarantees 15 ppm NOx but that you’ll probably see 9 ppm on 24k DLN hardware. A user said his unit comes in at around 5 ppm using third-party hardware. DLN1+ users reported 3.5-5 ppm.

TPs and first-stage nozzles were not fitting-up properly, one user said, despite flat and square picture frames. Another participant stressed putting TPs and nozzles on a flat surface before installing. Yet another user suggested sending the first-stage nozzles and TPs to the same vendor at the same shop. This enables set up in a proper fixture to mitigate fit-up issues.

Recommendations from the floor:

    • Strip, inspect, and recoat TBC on TPs and liners after a three-year run.

    • Test igniters on the turbine deck to avoid reinstalling them and finding out they don’t work.

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Vendor presentations on combustion hardware, fire safety applicable to all engines

With much of the time at Frame 6 meetings devoted to user presentations and deep discussion, there remains limited time for vendor presentations. Each year, the steering committee chooses two third-party vendor presentations in tune with what owner/operators are experiencing in the field. The topics selected for the 2018 meeting dealt with combustion hardware and personnel safety; both are applicable to all gas-turbine makes and models.

Fuel nozzles.

“Don’t play musical chairs with your combustion parts,” EthosEnergy’s Iain Maclean, the company’s product sales manager for HIT fuel nozzles, told the group. In a gas turbine, flame temperature and distribution are a function of both fuel and air distribution. Optimization is achieved from flow testing the gas in the fuel circuit, flow testing the liner air circuits, and then marrying the two processes for enhanced performance. With emissions limits perpetually tightening, the only way you can confidently repair is if you flow test, Mclean said.

The process of minimizing the range of variation in fuel flow to each can in a low-NOx combustion system is called “wheeling.” Its objective is to have each can operate with approximately the same flame temperature, thereby making it easier to tune the combustion system to obtain lower emissions and dynamics levels, reduce temperature spreads, and improve hardware life.

While wheeling fuel flow is helpful, the reality is that a variation in combustor flame temperature is caused by both fuel variation and air variation, not just the former. To truly minimize flame-temperature variation among the combustors, the variation in “fuel-to-air” ratio must be minimized. Combustor air flow must be known to do this.

Air flow is more difficult to determine than fuel flow because of the large effective area of the liner relative to the effective area of the fuel system. EthosEnergy has developed and offers a service to flow full liners for wheeling purposes and get the effective areas of various liner components, including:

    • Venturi.

    • Head end.

    • Full liner.

    • Dilution holes.

The test-stand configuration is “reverse-flow” as in a real machine and allows for investigation of a range of pressure ratios for standard, DLN1, and DLN1+ units. All testing is done at ISO conditions but EthosEnergy’s ECOMAX® combustion-tuning system can be used to balance out the changing ambient conditions onsite.

By understanding the possible variations in fuel-to-air ratio, estimates of the range in combustor flame temperatures can be determined. Pairing the components properly results in temperature-difference reductions critical for obtaining very low emissions levels and low temperature spreads. The low temperature spreads resulting from flow testing and wheeling can help buy time if any tuning issues arise during operation.

Other advantages include the following:

    • Higher confidence level on startup after an outage.

    • For multi-engine fleets with limited spares, flow-tested components can be normalized for all units to improve flexibility and reduce capital expenditures on spare parts.

Fire protection.

Fire protection is a topic in safety discussions at virtually every user group meeting, one that seems to be generating more interest as plants age. For example, systems installed 20 or more years ago have been cited for unwanted release of the extinguishing agent because of unreliable sensors. In some cases, the extinguishing agent is no longer in favor and should be replaced.

It’s important to keep safety systems current and well maintained. With the many retirements and staff changes of late, perhaps the person with most knowledge of your plant’s fire protection system is gone. That knowledge gap must be filled. The presentation by Chuck Hatfield of Orr Protection Systems is a good first step in the learning process.

Orr promotes itself as a one-stop shop for things having to do with fire protection—including alarm, detection, notification, and suppression. It provides testing, inspection, and maintenance services for all types of fire protection systems offered by the major manufacturers of that equipment.

Hatfield’s presentation addressed CO2, water-mist, and hybrid systems. The last appeared to have greatest interest. Hybrid systems, he said, are becoming more prevalent in powerplant applications—especially the Victaulic Vortex™ system. It uses a supersonic emitter to create a multi-layer shock wave of nitrogen which atomizes the water to a sub-10-micron mist, thereby creating a homogeneous suspension of nitrogen gas and water.

To dig deeper, NFPA 770 provides the standards for hybrid fire extinguishing systems using water and inert gas. Key features of these systems include the following:

    • Nitrogen gas actively dilutes the oxygen level to quickly suppress small fires even in large rooms.

    • Atomized water absorbs heat from the fire to vaporize as steam.

    • As effective as high-pressure water mist system for larger fuel-based fires.

    • Flame is cooled while steam displaces oxygen at fire.

    • No high-pressure pumps are required.

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European user boosts 6B compressor performance by coating blades, installing HEPA filters

The user-only compressor session in 2018 didn’t include any new topics, at least while the editors were in the room. At most 6B meetings, discussions include filter experience (HEPA in particular in recent years), online and offline washing, corrosives and particulates in the air impacting compressor cleanliness (and how to remove them), inlet bleed heat, bearing damage, clashing experiences, coatings, etc.

Proven coatings, when applied correctly, can offer meaningful economic upside. A compressor that remains clean year-round without washing minimizes performance loss (a topic incorporated into the Monday workshop conducted by John F D Peterson) for the entire run cycle, virtually eliminates the cost of demin water and soap for washing and any expense and permitting associated with wastewater disposal, and eliminates any operating penalty that might be associated with washing.

While the Frame 6 Users Group attracts some offshore attendees, the large majority of 6Bs is located outside North America and the experiences of those owner/operators generally are not shared at the US meeting. CCJ’s international activities, which include participation in the best practices program organized by the European Turbine Network (ETN), brought to light coating experience at a Scandinavian industrial facility that might benefit others.

That plant was challenged to reduce fouling-related degradation of 6B performance caused by a harsh coastal refinery environment containing salt, dust, soot, etc. The airfoil shown in Fig 1 was not washed prior to a major inspection after 40k hours of service. Plant management was reluctant to perform online or offline compressor washing given the possibility of engine tripping and/or other problems during restart, as well as the possible negative environmental aspects of water use.

The stainless-steel compressor blades were cleaned and coated with the anti-fouling treatment AFT from United Services Sweden AB during a major overhaul in 2011. No fouling-related degradation was in evidence after 56k hours of operation (seven years) with annual washing only (Fig 2). The photo shown in Fig 3, taken after spraying water on the compressor blades, shows that the coating’s hydrophobic properties remained intact.

The DLN-equipped engine normally operates baseload, dialing back output only when steam demand is low. Inspection and water washing of the GT is done during the annual maintenance period for process equipment. An HGP inspection is scheduled for the engine every 24k hours; a major is done at 48k intervals.

Note that United Services is owned by Peter Asplund, previously affiliated with Florida-based Gas Turbine Efficiency, a compressor-cleaning solutions provider. United’s stated mission is to permanently improve and maintain power-generation energy efficiency by minimizing fouling-related losses.  

The editors communicated with the plant manager (PM) by email to get the details that follow. The plant learned about United Services’ coating through discussions with other users in Scandinavia. One member of the collaborative group of owner/operators had used the coating on his IGVs with positive results. The PM said he reviewed that experience, as well as laboratory test runs, before putting AFT on IGVs and first-stage rotating blades of his 6B about three years before the 2011 major. His trial showed that fouled airfoils were cleaned simply by washing with demin water.   

United Services both cleaned and coated the compressor section in the plant shop without removing blades from the rotor. This work took four days and had no impact on the outage schedule.

The PM said he expected the coating would retain its dirt-repelling properties for the entire period between consecutive majors and that was confirmed by inspection. However, an additional coat of AFT had been added to the IGVs and first-stage blades after a couple of years of service. The recoated rows were viewed as easier to clean with demin water (no soap).

Compressor performance degradation was said to be “considerably less” after the coating was applied and air inlet filters were upgraded. The PM said the 4-MW loss experienced between annual shutdowns with uncoated blades dropped to 1 to 1.5 MW after coating and installing filters offering more efficient capture of fine particulates.

F7 filters allowed the fouling shown in Fig 1, so they were upgraded to HEPA, which are changed triennially. Both prefilters and fine filters are installed; G4 and E11 ratings, respectively.

The inlet plenum later was coated with AFT to smooth out air flow to the engine and contribute to performance improvement. 

A new uncoated rotor recently was installed in the 6B; the original was retired after about 200k hours of service. The PM said he would use this opportunity to monitor performance degradation between annual outages to determine the impact of better filtration with uncoated blades.

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GE Day: 6B dissected from inlet to exhaust

The Frame 6B OEM was responsible for the Wednesday technical program and split the day with the morning dedicated to fleet-wide topics suggested by the steering committee and the afternoon divided among three discussion-focused breakout sessions catering to specific user interests.

A “state of the frame” presentation launched the GE Day program with highlights of the 6B’s 40 years of service to the industry. The first engine was commissioned in Montana in 1979 and advancements in the technology have been ongoing since that time, the group was told. To date, the 1150 6Bs installed globally have operated more than 65-million hours on a wide variety of fuels with a reported reliability of about 99%. Eleven 6Bs were installed in 2017-2018.

Perhaps the most significant announcement of the day was the startup of the first US 6B AGP (Advanced Gas Path) unit two days earlier. The highlighted benefits: 14% increase in output, HGP (Hot Gas Path) intervals of 32K FFH (Factored Fired Hours), heat-rate improvement of up to 5%, and an increase in exhaust energy of up to 8%. Eight units in Saudi Arabia were said to have the AGP upgrade

Beyond the advantages of the AGP offering, the speaker mentioned solutions for better performance, lower O&M costs, and life extension—including extended turndown, efficiency enhancements, and a flange-to-flange 6F.01 drop in module. Five 6F.01 modules were said to have been sold, but not shipped, at the time of the meeting. Three of these will be configured as hot-end drives.

TILs (Technical Information Letters) important to 6B owner/operators and issued between the 2017 and 2018 meetings were reviewed. A handy table indicating document number, title, date of issue, and degree of importance is available on the user group’s website.

If you are not familiar with TILs 2041, 2044, 2046, 2051 2003-R1, 2060, 2064, 2066, 2076, or 1566-R2, it’s a good idea to come up to speed quickly. Two of these documents are safety-related and five others require compliance, a couple at the first opportunity and one prior to next time the affected system is operated.

The compressor sections for 6Bs generally have been bullet-proof over the years. Problems experienced include IGV (Inlet Guide Vane) cracking attributed to corrosion pitting and rubs; root liberation at the leading edge of some R1 rotor blades believed caused by erosion and corrosion or, possibly, IGV miscalibration; S1 stator vane leading-edge cracking/clashing; and tip loss from some airfoils in Rows 2 and 3.

Mitigation actions were offered. One example is replacement of carbon-steel vane rings with ones made of stainless steel to prevent the lock-up of vanes from rusting and minimize the potential for clashing. Blade health monitoring via sensor probes on the first three compressor stages is expected to help warn of possible clashing by monitoring changers in blade deflection and frequency.

Documents offering maintenance advice for the air inlet structure to improve compressor availability/reliability included PSIB20170428A, GEK 116269, PSIB20130813A, and GEK101944. Add missing documentation to your plant library. Need help? Ask your GE representative.

GER3620N, issued in October 2017 and accessible online with a simple Google search, provides inspection and maintenance advice for the engine proper.

A briefing on the OEM’s new blade-health monitoring system, which relies on vibration signature (probes are installed on the compressor casing) to warn of an impending issue, was a highlight of the compressor presentation. Get details from your GE rep.

Parts interchangeability. Given the fleet’s 40-year service life and the number of people who have had O&M responsibility for your 6Bs since COD, it’s easy to believe you might not know the vintage of parts installed in the engines or those on a warehouse shelf. What parts fit where and how was the subject of a short presentation, “HGP considerations,” that’s worthwhile reviewing before the next outage—especially one involving parts replacement in a row of mixed airfoils. Visit the Frame 6 Users Group website.

Controls. When the first 6B went into operation, the control system offered by GE was the Mark II. Some machines in service today still are equipped with the Mark IV, offered from 1982 to 1991. Many have Mark Vs, manufactured from 1991 to 2004. During the user-only discussion session on controls the day before the OEM’s presentations, by show of hands, four attendees said their units were equipped with the Mark IV; about half of the group’s engines had Mark V. Another third had the Mark VI, the remainder Mark VIe.

The OEM urged attendees to upgrade their control systems to the Mark VIe. There are several reasons to do this, chief among them: availability of parts, cybersecurity issues (patching is not supported), technical support during outages, ability to allow new performance-enhancement options the owner/operator might find of value.

Two modernization options were discussed, full-panel retrofit and migration. A complete control system replacement was said to take about 25 days and possibly require more floor space than the existing system occupies. Migration translates to nondestructive key-component replacement through plug-and-play. All field wiring remains as is—no determination/re-termination. Depending on scope and technician deployment, the migration option could take from about a week to 14 days. This option is less expensive than a full panel retrofit.

The speaker went on to describe stepwise conversions from the Mark IV, Mark V, and Mark VI to the Mark VIe—a good starting point for someone considering an upgrade.

Generators were the last topic on the OEM’s 6B technology agenda. This was the longest presentation of the day and rightfully so: Most plant personnel are comfortable with mechanical work and I&C, and typically have little experience with high-voltage electrical equipment—generators in particular.

The speaker began with an examination of lifecycle considerations. Cyclic operation (starts/stops) taxes the rotor, he said, while operating hours impact stator maintenance intervals. Historically, the speaker continued, rewind risk increases for rotors between years 15 and 20 and 35 to 40, for stators between 25 and 30 years.

The value of GEK 103566 (ask your GE site rep for a copy) in planning an effective generator maintenance program was stressed. Rev L updates were discussed to bring users up to date. Key talking points included these:

    • Updated rotor life-management recommendations.

    • Addition of recommendations for when to remove the rotor—only for repairs, not inspections. Condition assessments can be made using a combination of online trending, in-site testing, and visual (borescope) inspection.

    • Recommendation for a low-oxygen stator cooling-water system.

    • Benefits of combined stator and rotor test and inspections.

Types of robotic inspections—in-situ air gap, in-situ retaining ring, and wedge tapping—and   their applicability to the various generator models associated with the 6B, were explained along with their idiosyncrasies and the background information required to assist in condition assessment.

A case study describing the need for a generator rewind based on robotic findings was incorporated into the presentation. The robotic inspection for this unit included a partial stator-slot wedge-tightness check, an EL CID test, and visual inspection of field parts, stator core, and field/stator windings. Here were the findings:

    • Slot wedges in good condition.

    • Some FOD impact damage to the core.

    • Minor dusting in the stator.

    • Four broken leaves found on one main lead terminal stud.

    • Several slots found with springs moved and nearly closed vent holes.

Generator monitoring to enable condition-based maintenance—partial discharge, rotor flux, rotor shaft voltage, endwinding vibration, stator temperature, collector health, and static leakage—was a major part of the presentation. Keep in mind that the benefits of early fault detection are considerable. For example, it enables plant personnel to control unit operation to limit deterioration and prevent a forced outage.

Each of the diagnostic tools noted above was reviewed in terms of the sensors used for detection, what was being monitored, and what it was capable of finding—for example, loose stator bars in the case of partial discharge.

To dig deeper into generator monitoring, inspection, and maintenance, access Clyde Maughan’s course, available at no cost, on the CCJ website. Maughan is well respected for his knowledge of generators, the focus of his 35-year GE career and more than three decades of consulting work after retiring from the OEM. The program is divided into the following manageable one-hour segments:

    • Impact of design on reliability.

    • Problems relating to operation.

    • Failure modes and root causes.

    • Monitoring capability and limitations.

    • Basic principles of inspection.

    • Test options and risks.

    • Basic approaches to maintenance.

The three afternoon breakout sessions each featured three presentations, conducted in parallel, as outlined below. These were followed by a reception and special GE product fair.

   Breakout No. 1:

    • Exhaust and wheel-space thermocouple reliability.

    • Rotor end of life.

    • Combustion systems.

   Breakout No. 2:

    • Control system obsolescence, including generator excitation systems.

    • Repair technology.

    • Peakers.

   Breakout No. 3:

    • Instrumentation.

    • FieldCore.

    • Accessories.

Users talk back. Attendees expressed several concerns during the course of GE Day. Here are a few of them:

    • Level of experience of FieldCore personnel.

    • Amount of time it takes to respond to pac cases.

    • Quotes for non-LTSA customers take too long.

    • Repair improvement and lead-time expectation.

    • Division of responsibility between the Power Services and Baker Hughes organizations.

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Safety a high-profile discussion topic at Frame 6B meetings

The main technical program at Frame 6 meetings begins at 8 a.m. Tuesday morning (June 11 in 2019), following Monday’s engine familiarization workshop and welcome reception and dinner. Roundtable discussions led by members of the steering committee and one of the two invited vendor presentations fill the first-day program until the vendor fair and reception at 5 p.m. The second vendor presentation and remaining discussion topics are on the Thursday morning program; adjournment is at noon, then lunch. Wednesday is GE Day.

Safety is the first discussion topic. That roundtable is led by Co-chair Jeff Gillis, whose position as gas-turbine technology lead for ExxonMobil’s frame gas-turbine fleet worldwide gives him a global perspective on this subject of importance to all attendees. OSHA is not global and America does not have all the answers.

Gillis’ first slide at the 2018 meeting 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:

  • General

    • Life-saving rules.

    • Compartment entry.

  • Safety systems

    • Hazardous-gas detection.

    • Fire suppression.

  • Maintenance

    • 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.

One of the users in attendance thought “life-saving rules” at the top of the list was a good place to start, suggesting immediate removal from the site of anyone working without a LOTO (Lock Out/Tag Out) permit, engaging in horseplay, walking under a suspended load, not observing rules pertaining to electrical isolation, as well as other infractions. Others agreed.

Compartment entry when the unit is operating always generates discussion among users; opinions differ. On the one hand it’s much easier to find leaks and troubleshoot when the unit is in service; on the other, there are hazards in doing this.

European gas turbines trip if the compartment door is opened while the unit is operating, the group was told. GE claims opening compartment doors violates the ventilation scheme. Some units trip on low ventilation air flow because air escapes from the door rather than exiting via the ventilation ductwork.

While the consensus view is that a compartment entry protocol is site-specific, the discussion revealed many users are trying to minimize, if not eliminate, access with the GT in service. Ideas offered: Install hazardous-gas detectors in the compartment to warn of fuel-gas leaks. Retrofit armored windows in package doors and floodlights inside the compartment to allow visual checks from outside. Provide access to important operating data outside the package.

Another idea offered is to check for leaks when the unit is on crank. One user went beyond this, saying you can introduce enough air into the system to leak-check with the unit offline.

Trip reduction worked its way into the discussion because 6Bs are installed at many industrial plants to provide steam, and loss of an engine might upset a process that must run continuously. It was said that the OEM now has a package to alarm rather than trip for some operating conditions. This enables operators to assess the situation and decide what to do. The number of trips related to a single event also has been reduced.

Attendees were warned about the hazards of standing directly in front of a door being opened. Also noted was the need to properly close the compartment door after exiting; there’s not much protection from CO2 if the door is ajar.

The possible dangers associated with tying-off when working on top of the turbine was another topic. Fall protection lines can get tangled and cause injuries—possibly ones more severe than an actual fall. Railings have been installed in some cases. A few users reported having tie-off exemptions during outages for work on top of the turbine.

Having a safety professional assigned during outages was suggested. Use of bump caps in place of hard hats was recommended for work inside the generator stator.

The possibility of a fire at the turbine inlet is a real concern to many because it can consume the filter house in a matter of minutes trapping anyone inside if there’s no way to exit safely on both sides. Safety tip: Ban the use of halogen lights in the filter house, near evap media, etc. One user mentioned an incident involving the use of halogen lighting when an oil sump was being cleaned out. A lamp came into contact with oil-soaked rags, creating a large amount of smoke in a confined space.

There’s a vast amount of safety-related information readily available to owner/operators wanting to improve their procedures to best-in-class. You might want to begin your research on the CCJ website in the search bar above where you can find best practices submitted by colleagues over the years.

For the Frame 6 specifically, Gillis prepared a slide of 6B user-forum safety threads, several slides describing more than 30 Technical Information Letters focusing on 6B safety concerns issued by the OEM (TIL 1700, for example, “Potential Gas Leak Hazard During Offline Water Washes”), and content summaries of four GE Product Service Safety Bulletins issued by GE.

Some material pertinent to 6B owner/operators goes beyond the basic engine. One example, PSSB 20161220, “GT Upgrade Impact on HRSG,” presents the experience of an owner that learned a GT upgrade had been implemented without sufficient evaluation of the safety impacts on the boiler. Specifically, the new steaming capacity was greater than the nameplate rating and the relieving capacity of the existing safety valve.

This is a serious concern, but don’t expect to get an in-depth HRSG discussion going at a meeting focused on gas turbines. For that you need to attend the annual HRSG Forum with Bob Anderson. Next conference: July 22-25 in Orlando.

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How manual controls help in troubleshooting legacy GE gas turbines

Turbine Tip No. 2, from the Dave Lucier’s PAL Turbine Services O&M solutions library, applies to General Electric Frame 5 models K-LA and M-P, and early 6Bs, 7Bs, and 7Cs, equipped with Y&F fuel regulator and Speedtronic™ Mark I, II, and IV controls.

Overfiring a gas turbine during startup can be a serious condition, particularly when the engine is cold. As a GE gas turbine fires and warms up, fuel flow is controlled by the average exhaust temperature—called Txa. During the subsequent acceleration period, the starting means (diesel engine or electric motor), assists in bringing the turbine rotor up to rated operating speed. 

On legacy units, as the coupled rotor passes through a mid-range zone, compressor air flow and pressure may be insufficient to maintain Txa under 950F, as recommended by the OEM. If your control system is incapable of limiting fuel flow to prevent the exhaust temperature from exceeding 950F, be advised that GE provided for manual control of its early gas turbines (years from 1960 to 1980).

In the decade of the 1960s, GE gas turbines used the Young & Franklin fuel regulator for engine control. In the early 1970s, Speedtronic became the electronic control and protection system of choice. In this 20-year span, the OEM provided methods for “overriding” the automatic controls with a manual feature on its gas turbines.    

In Fig 1, an operator is shown “thumbing” General Electric Manufacturing Co’s (GEMAC) 70TC programmer to control exhaust temperature during acceleration of a Frame 5L gas turbine. This action limits Txa temporarily, by manually controlling fuel flow to the combustors. Once the temperature has “crested,” at about 2200 to 2400 rpm, the operator can release his thumb, allowing the timer to run up to its 100% stop.

Several MS5001K-LA gas turbines installed in the mid-to-late 1960s have had their legacy temperature control and protection systems replaced/upgraded with a programmable logic controller (PLC), like the PAL GEMAC in Fig 2.

Recall that the technology of the day in the post Northeast Blackout era (November 1965) was early integrated circuitry. The operator-friendly PLC can perform many of the electronic functions from 50 years ago easier and faster. Example: Manual override with the PAL GEMAC is provided with the F2 function key (arrow in Fig 2)—much simpler to use than the thumbwheel feature it replaced.

Beginning in the 1970s, Speedtronic Mark I controls had a manual resistor on the speed control circuit board called SSZA (Fig 3). It is the upper resistor knob in the photo—named MAN VCE for manual, variable control electronic, or minimum fuel command. Turning the knob to the right (clockwise) decreases the fuel control voltage, thus fuel flow. An alarm will sound. Fig 4 shows the later version of Speedtronic, the Mark II. Its MAN VCE is located on the SSKC card. The audible sound can be silenced, but the annunciator flag remains until the knob is returned to normal.

Case study. A user recently had a problem starting his MS5001N, equipped with Speedtronic Mark I controls. When the turbine reached approximately 1900 rpm the unit tripped because the average exhaust temperature exceeded its allowed operating limit of 1000F.  Subsequent trips made the problem particularly difficult to diagnose. The diagnostics team believed the turbine had to continue operating, so the system could be observed and analyzed.

Plant personnel were unaware of the manual control option and the reasons why GE had installed it. The site engineer was advised to turn the MAN VCE knob clockwise during acceleration (at 1700-1800 rpm). Yes, the alarm sounded. VCE was limited temporarily, so troubleshooting could begin. In this case, it was desirable to run at a safe speed at an exhaust temperature less than 900F. I&C sleuths determined that a 240F comparator “oven” was defective and had to be replaced.

Even modern GE gas turbine control systems (circa 1980-1985), like the Speedtronic Mark IV (Fig 5), provided for manual control during turbine startup—should it be needed. Refer to FSR MAN in the MIN GATE function. During startup and acceleration, manual control is possible with this function, though on later-model gas turbines its use is less likely. The MIN GATE looks at all inputs and selects the one that “calls for” the lowest fuel flow. In this case, MAN VCE can be that one.

On a new Frame 5 gas turbine, the average exhaust temperature was expected to “crest” at about 810F approximately 3 minutes and 20 sections into the start cycle (red arrows in Fig 6), when the turbine was at about 80% speed (nominally 4000 rpm).

Bear in mind that if the temperature drifted too high, the turbine might trip on over-temperature. The operator could limit VCE manually (read 10 Vdc on the right vertical axis) to prevent a trip until the air flow and compressor discharge pressure increased to cool the exhaust. Perhaps a MAN VCE setting of 9.5 Vdc might work better in this case. Later, the ACCE VCE limit could be recalibrated lower to this same limit.

In conclusion, many legacy GE gas turbines have ways to temporarily control fuel flow (manually) to the combustors. During startup, it may be necessary to manually limit fuel flow until rotor speed passes through a critical zone (1800 to 2300 rpm). GE provided the controls to assist the operations team in troubleshooting.

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