GE 9FA Gas Turbine Plant For Sale

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UPDATE: Many user-focused organizations cancel conferences, planning underway for 2021

Most meetings organized by user groups and other organizations focused on the information needs of gas-turbine, combined cycle, and cogeneration-plant owner/operators, and scheduled for March through July 2020, have been canceled.

The list includes the following:

    • Fourth International Conference on Film Forming Substances.

    • Western Turbine Users Inc’s 30th Anniversary Conference and Expo.

    • CTOTF’s 45th Spring Conference & Trade Show.

    • 7F Users Group’s Annual Conference & Vendor Fair.

    • European HRSG Forum’s Seventh Annual Meeting.

    • Frame 6 Users Group’s Annual Conference & Vendor Fair.

    • Frame 5 Users Group’s 2020 Conference.

    • Ovation Users’ Group’s 33rd Annual Conference.

Those groups still planning to meet, as of March 24:

However, with business and personal plans unpredictable because of the pandemic, it behooves you to check the status of conferences of interest as the meeting dates get closer.

Looking forward to 2021, among the organizations canceling their 2020 conferences only the Fourth International Conference on Film Forming Substances and the European HRSG Forum have not finalized plans for next year. Here are the details for the others:

    • Western Turbine Users Inc, March 21-24, Palm Springs, Calif, Renaissance Hotel/Palm Springs Convention Center.

    • CTOTF, April 11-15, Greenville, SC, Hyatt Regency Greenville.

    • 7F Users Group, May 24-28, St. Louis, Mo, Marriott St. Louis Grand.

    • 501D5-D5A Users, June 8-10, St. Louis, Mo, Ritz-Carlton St. Louis.

    • Frame 5 and Frame 6 Users Groups, June 14-17, San Antonio, Tex, La Cantera Resort & Spa.

    • Ovation Users’ Group, July 25-29, Pittsburgh, Pa, Westin Convention Center Hotel.

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RECAP: CCUG updates users on key elements of the integrated plant

The 2019 conference of the Combined Cycle Users Group (CCUG) was a prime example of “working together,” co-located with the generator (GUG), steam turbine (STUG), and powerplant controls (PPCUG) user organizations. Attendees were invited to participate in sessions conducted by all four groups at the Marriott St. Louis Grand, St. Louis, Mo, August 26-29.

On Monday morning, CCUG offered an Environex Inc training session for all: “Strategies for improving SCR/CO catalyst performance and lifecycle.” Dan Ott, president, reviewed catalyst types, reaction and oxidation chemistry, dual-function configurations, ammonia system design, low-turndown performance, lifecycle testing, and ways to improve NOx compliance.

Owner/operators can view Ott’s slides, and those of the other presenters, on the Power Users website. Registration for access is simple and most worthwhile: More than a hundred presentations were made at the so-called Combined Conference.

2020 Conference and Vendor Fair

August 31 – September 3
San Antonio Marriott Rivercenter

Meeting is co-located with the Steam Turbine, Generator, and Powerplant Controls Users Group conferences.

Contact Sheila Vashi at

At 1 p.m., all participants came together for introductions by Duke Energy’s Jake English, conference business manager and member of the STUG steering committee. He emphasized the founding principle of sharing information and keeping the discussions technical, not commercial.

NV Energy’s Jimmy Daghlian then presented the CCUG’s 2019 Individual Achievement Award to Consultant John Peterson, formerly with BASF and a founder of the Frame 6 Users Group, and Steve Royall of PG&E. This year’s Clyde Maughan Award went to James Timperley, EMSA Technical Services (formerly with American Electric Power Co and Doble), presented by Kent Smith of Duke Energy and past chairman of the Generator Users Group.


FBI Special Agents Kyle Storm and Jaret Depke presented the first of two keynotes: “Confronting cyber and counterintelligence threats from the FBI’s perspective.” Jeff Chann of GE, followed with the second: “Managing your plant over the next decade.” Chann addressed the common concern of survival in the changing market. His message: “If we don’t react, the balancing authority will go around us and find the solution.”

The tone was set for not how to thrive, but how to survive. The message: Contribute to the overall portfolio, be best in your zone, mix in, and realize that your plant’s capabilities on Day One are not what’s needed tomorrow.

Content from well over 100 presentations/discussions was shared at the 2019 Combined User Group Conference. What follows are highlights from a few of the CCUG presentations to give you a flavor of the meeting and to encourage your participation in the 2020 conference at the San Antonio (Tex) Marriott Rivercenter, August 31-September 2.

Critical valves and piping

Thick metal parts are having problems sooner than expected, largely because of repeat thermal transients (cycling). PG&E’s Tim Wisdom characterized the challenges of cycling in Fig 1.

As Wisdom put it, “We are seeing damage to main-steam and hot-reheat valves, and cracking of the HP drum internal downcomer nozzles. The correlation between cyclical duty and increased owner/operator time and expense on high-energy piping (HEP) programs is becoming more apparent during every outage.”

Major valves are failing early regardless of material, including F91 (forged P91). Components thought to be reliable for 30 years “are failing at around one-third the expected life,” he cautioned.

The valves discussed suffered from delamination of hard-facing materials (stellite liberation) which is generally repairable, but also from deep-body cracking which is not. Wisdom also addressed the common issues of cracking in steam and bypass lines (Figs 2 and 3).

A heads-up: One site had to stop and wait for a state-authorized inspector to approve temporary repair measures for a P91 spool piece because the valve was within the code boundary of the HRSG. The ensuing discussion on the delay included a reminder of long lead times on new critical components.

So how do you prepare to cycle twice each day?

    • Consider how you will manage added costs. Major maintenance expenses can double, and maintenance intervals can be reduced by half.

    • Continue to leverage industry resources. (See what others are doing.)

    • Know the lead times for replacements. “Look at things and have a plan.”

    • Anticipate!

He followed with some valuable lessons learned:

    • Ensure that you have spare critical valves and stay abreast of design improvements.

    • Compile risk rankings for all critical components in your HEP program.

    • Ensure that all high-energy piping is part of the risk and inspection program. (Code only recommends 4 in. and larger.)

    • Eliminate risk of dissimilar metal weld failures—for example, P91 to Type 316 stainless steel.

    • Ensure your main steam and HRH strainers can capture liberated materials from degraded valves.

Returning to his cycling discussion, he offered a motivating mental image: “We need to be ready at all times. We have become the light switch.”

GT performance

Award recipient Peterson discussed “Maintaining best gas turbine performance” with an informative historical review—including the increase in compression ratios for frame gas turbines over the years. The key today, he stated, is “the efficient compression of air.”

He listed the primary factors for compressor losses:

    • Mechanical damage (foreign object impact and tip-rub contact).

    • Mechanical wear of seals.

    • Airfoil surface erosion, corrosion, and fouling.

    • Guide-vane calibrations.

    • Air and oil leaks.

Commonly used expressions for these factors are recoverable loss, unrecoverable loss, air flow loss, and compression efficiency loss.

He then reviewed various cleaning techniques including:

    • Abrasive cleaning.

    • Online washing with and without detergent.

    • Offline washing (periodic cold crank wash).

    • Hand cleaning of airfoils.

A case study on excessive Frame 6 fouling, and discoveries inside the filter house, led to a tangential discussion on the pros and cons of hydrophobic HEPA filters.


Aaron Berry, Puget Sound Energy (PSE), led the discussion on corrosion under insulation (CUI), a common threat to carbon steel, alloy, and 300 series stainless steel piping systems. The topic has become standard at most industry events, largely attributed to cycling and intermittent service.

High-risk areas, he explained, are feedwater systems, small bore fittings, dead legs, areas near HRSG penetration seals, and thin-wall interconnecting tubing. Mineral wool insulation, he stated, is the worst environment for CUI. Long periods of equipment layup increase risk.

PSE operates five combined cycles varying in age from eight to 25 years, in environments ranging from marine to arid.

Berry’s key message: CUI is detectable and preventable. He covered various inspection techniques including:

    • Strip and inspect.

    • Pulsed eddy current.

    • Guided wave ultrasonic.

    • Radiography.

“Have a long-term program, and start inspecting,” he said. “Don’t wait for failures.”

Chasing BTUs

HRST’s Jordan Bartol next went deep on how HRSGs can influence overall plant performance. “We’re chasing Btus and trying always to improve plant heat rate.”

Units built in the early 2000s are now at mid-life. Target areas for HRSG heat rate improvements are:

    • Economizer design and operation.

    • Attemperator operation.

    • Fouling (increased backpressure).

    • Exhaust gas bypass.

    • Casing hotspots.

    • Exhaust leaks.

    • Steam turbine interaction reviews.

Economizer approach temperature is a critical parameter, discussed in detail. Bartol then turned to a typical three-pressure duct-fired HRSG with reheat, and the benefit of adding 12 tube rows to the HP economizer (Fig 4).

In his example, adding these rows increases steam turbine output by 2.5 MW for a 1 × 1 F-class plant with duct firing. But this also requires a bypass to prevent economizer steaming during unfired operation.

The additional surface can be included in a new HRSG if heat rate while duct firing is important. Retrofits might prove difficult because of space limitations, but the SCR duct may have room available and, if so, should be considered.

For the increasingly familiar topic of attemperation, Bartol listed some negative consequences of lowering the steam temperature set point in the control room, using, as an example, a 7FA with typical three-pressure HRSG. Such action can do more harm than good, he warned. The increased spray-water flow can damage downstream pipes and tubes, contribute impurities to steam, and decrease steam-turbine performance.

In the HRSG tube bundles, baffles reduce exhaust-gas bypass. Gaps that allow hot gas to bypass heat-transfer tubes hurt performance; even small gaps can allow significant bypass. Properly maintained gas baffles therefore become critical to good performance (Fig 5).

“Baffles are relatively inexpensive yet very important devices,” he said. “But they must be properly designed for thermal expansion, must be sturdy, and must be part of each inspection. Fixing a small portion can result in a large performance gain.”

Casing hotspots may have a smaller impact on performance, but can lead to cracks and have a negative impact on safety. Exhaust leaks also affect performance. Common leak causes are failing bellows, torn fabric seals, failed penetration seals, and failed expansion joints.

For steam-turbine interaction, “Watch pressure drop in the reheater section” (from exit of HP stage to entrance of IP stage). A 10-psi increase can reduce steam turbine output by 0.2 MW in the F-class example (Fig 6).

Piping damage, drain control

HRST’s Guy Thompson followed with the negative impacts of superheater, reheater, and piping drain problems and the formation of condensate, another increasingly encountered topic.

His focus was on low-point drains in the high-temperature reheaters and superheaters. During the past 15 years, emphasis has been on drain size, drain valves and automation, and operating practices to ensure condensate removal.

He then offered some rules of thumb to reduce resultant tube and header damage, generally recommending 2-in. drains for the range of pressures encountered by F-class HRSGs.


Intek (Tim Harpster and Tony Bonina) offered case studies on distinctive instruments for monitoring steam-turbine surface condensers. Specifics focused on both early detection of performance issues and long-term monitoring for:

    • Cooling-water flow rate.

    • Vacuum equipment capacity.

    • Air in-leakage detection.

    • Data systems validation.

Discussions also covered:

    • Steam pressure and temperature.

    • Cooling-water inlet and outlet temperatures.

    • Differential pressures across waterbox orifices.

Case studies showed specific results of RheoVac® condenser monitors, Rheotherm® flow and fouling sensors, and integration with other temperature and pressure instrumentation. Benefits included improved circulation and reduced backpressure.

SCR, AIG tuning

Jeff Bause, CEO of Groome Industrial Service Group, addressed SCR catalyst replacement and tuning of the ammonia injection grid. He first noted ongoing improvements in catalyst technology.

Case studies focused on the importance of AIG cleaning for efficiency, conversion rate, and system capacity.

One suggestion: Use a permanent sampling grid specifically designed to continually test AIG effectiveness, take samples throughout the grid (no probing), and make AIG tuning easier and more precise using detailed probe maps.

Catalyst-replacement case studies covered specific NOx conversion data, ammonia slip, and ammonia consumption comparisons before work, after work, and after tuning.

Forward-looking discussions included the increasing presence of sulfur from shale gas, the smaller size of some replacement catalysts, and use of dual-function catalysts to reduce both space and backpressure.


The North American Electric Reliability Corp (NERC) Critical Infrastructure Protection (CIP) plan is a set of alerts and requirements designed to secure the assets needed for operating North America’s bulk electric system.

Frank Lyter (Talen Energy) presented a CIP update with discussion points for:

    • Reducing risk to the bulk electric system.

    • Standardizing industry processes.

    • Enhancing feedback to NERC.

    • Issuing timely NERC alerts.

Upcoming CIP Standards (CIP-003-7 and 8) will take effect in early 2020 to address:

1. Physical security.

2. Electronic access security.

3. CIP exceptional circumstances—for example, supply quality concerns.

4. Transient cyber assets.

Laptops and removable media included in No. 4 above are among the greatest new security challenges, he said. They are in wide use throughout each site, particularly during outages, and involve many individuals, groups, and companies. Checklists and processes initiated by Talen Energy were shown and discussed in detail.

NERC alerts also were reviewed—including concerns over Chinese supply and drones used for both security and surveillance. Alerts and bulletins provide guidance on such timely issues. In 2019, an alert was issued on drones offering this specific guidance:

    • Purchase drone devices and components from reputable vendors.

    • Understand how and where drone data are being stored.

    • Determine how the drone will interact with infrastructure and networks.

    • Perform detailed risk assessments.

    • Implement multiple internal reviews and controls.

Multiple controls could include monthly checklists, contractor report reviews, and analysis tracking documents. Also, standardizing forms across an owner/operator fleet can streamline the review processes.

Lyter’s message: “We now need to consider vulnerabilities not normally considered.”


Calpine Corp’s Stan Avalone and Craig Cannon discussed the fast-growing topic of film-forming substances (FFS, including amines), focusing on recent company experience. Calpine’s HRSG reliability issues have been severely impacted by unscheduled layups and both single- and two-phase flow-accelerated corrosion (influenced, in part, by unit age).

The presenters’ experience, water beading in a condenser has shown the benefit of a polyamine protective film. Once formed, in their example, the protective film remained intact even after dosage fell below the required level or was interrupted for a short period of time (Fig 7).

Nitrogen blanketing remains the industry standard for long-term layup, but layups with amines can help reduce corrosion and the potential for under-deposit corrosion in evaporator tubing. Unlike other protection methods, the presenters explained, “the FFS technique is implemented in advance of the unit outage while the equipment is still operating.”

Application methods and recommendations were outlined, along with the caution of over-feeding.

Calpine’s future plans include studying the differences in available and emerging FFS products, expansion of this chemistry to more units, and combining the feed of neutralizing and filming amines to make initiation and long-term optimization easier at each site.

Outage planning and management

Phyllis Gassert, director of asset management at Talen Energy and the CCUG 2019 chair, began by asking three fundamental yet critical questions:

1. When is the right time to start planning a major outage?

2. Who should be involved in the planning process?

3. When do you start including the contractors?

“Any outage of three weeks or more needs at least two years of planning,” stressed Gassert. “Bring your managers into the entire planning process, and put your plans in each contractor bid.”

Gassert’s presentation covered all important areas including maintenance, defining the roles of not only contractor staff but also your own, and physical site management. Beyond the many traditional items, Gassert added some interesting thoughtworthy items:

    • When planning parking, don’t forget shift overlap (more cars).

    • For parts, plan space for both incoming and outgoing (more parts).

    • Prepare purchase orders and change orders in advance (to avoid interruptions, stress, and possible careless errors).

    • Watch carefully for contractors’ incoming assumptions or undisclosed expectations—cranes, elevators, facilities, etc.

Go for the realistic, not the best, schedule. And remember: “Under budget and on schedule means nothing if someone gets hurt.”

Gassert was asked, “When do you implement scope freeze?” The answer: at three months out. Any deviation requires at least two authorized signatures.

Workforce and community

Dr Robert Mayfield, a former submarine commander and today plant manager of Tenaska Westmoreland Generation Station, shared some insights on life in his combined-cycle environment.

“Knowledge must be created and captured, shared, and transferred, and organized and integrated. Our biggest problem today is skill sets.”

Westmoreland is a nominal 1000-MW combined cycle with only 24 employees. Perhaps more significant, 80% of the staff has moved from a union coal-plant position to this non-union combined-cycle environment.

His comments touched on numerous aspects of daily management and life at the facility, including interpersonal relationship of staff and regard for the community, while focusing on the common issues of today’s environment. Items such as:

    • Increasing merchant operations (PPAs fading away).

    • Long-term agreements being modified or expiring.

    • Ageing equipment and personnel.

    • The need for more predictive maintenance.

    • Competition for employees.

    • OEM lack of experience.

    • The need to do more with less.

His closing comments offered some hope, while touching on labor and skills shortages:

    • Stay away from management fads.

    • Welcome briefings on bad news.

    • Seek employee opinions.

    • Train operators to take action.

    • Offer tours, tours, and more tours. Get employees noticed and involved.

    • Promote community volunteerism.

    • Be aware of changes in the energy market.

    • Be ready for an unannounced audit or inspection at any time.

    • Praise employees and calibrate when necessary.

In discussing training, he repeated Henry Ford: “The only thing worse than training your employees and having them leave is not training them and having them stay.”

He ended with a thought-provoking quote by Dale Carnegie: “Employees don’t leave companies, they leave people.”

Wednesday was reserved for presentations by the 2019 diamond sponsors, General Electric and Siemens, and platinum-plus sponsor Mechanical Dynamics & Analysis (MD&A). Participation was limited to users and personnel from the three sponsoring organizations.

Siemens personnel offered details on the following:

    • Company organizational update.

    • Energy market outlook in the US (including battery integration).

    • Review of NERC critical infrastructure protection and cybersecurity data.

    • Maximizing market participation through grid support and ancillary services.

    • Increasing combined-cycle flexibility through exhaust purge credits, attemperator operation, and integrated Flex-Power Services™.

    • Gas-turbine upgrades for higher capacity, increased efficiency and longer inspection intervals.

    • Brownfield engine exchange programs (replacements and site repowering).

Experts from MD&A addressed specifics of balancing to reduce vibrations, not only on the turbine, but on other balance-of-plant (BOP) rotating equipment as well. Cautions were issued on common mistakes made while balancing. Details were then given for low- and high-speed balancing on location and at MD&A facilities, along with specific criteria for gas-turbine, steam-turbine, and generator rotors.

Alignment discussions and graphics focused on couplings and internals, specifications, and the impact of foundation settlement. Coupling example details covered both 16-point and laser methods and equipment.

GE spearheaded the afternoon discussions with a range of topics including:

    • Fleet status.

    • BOP considerations for gas-turbine upgrades.

    • Layup, restoration, and restart guidelines.

    • Remote monitoring experience for HRSGs.

    • Ensuring combined cycle relevance in today’s renewable energy world.

    • Selected case studies.

    • Roundtable discussions.

Available Siemens, MD&A, and GE discussions in other user group tracks provided unique opportunities for CCUG participants to expand into specifics for generators, steam turbines, and powerplant controls.

The following day, MD&A conducted tours of its gas and steam turbine/generator repair facility in St. Louis.

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Get up to speed fast on grid-scale storage with this no-cost resource

Some veteran gas-turbine (GT) asset managers have already been given responsibility for grid-scale storage facilities. Others may find their asset portfolio shift in this direction soon.

If you are in this camp, or if you just want some technical guidance around this new asset class, get a copy of the Advancing Contracting in Energy Storage Working Group’s (ACES) Best Practice Guide (BPG), available online at no charge. 

According to lead investigator and storage sector veteran consultant Richard Baxter, the ACES BPG was written primarily for non-technical stakeholders in storage projects—lenders, lawyers, new project developers, and others – to help them “define what it is they are being asked to participate in, ask the right questions, and evaluate and compare project opportunities.” Baxter further notes the overall objective is to “more quickly get the sector to coalesce around generally accepted practices.”

Grid-scale storage is a wholly new electricity asset class being developed primarily around exciting, but complex, new battery technologies. It’s on the cusp of rapid growth. GT veterans might liken it to the early to mid-1990s when IPP and merchant generation projects around advanced gas-turbine technology were entering the industry.

One thing’s for certain: You can’t pick up your operational practices from other less dynamic energy technology projects, warns Baxter, whether GT, solar, or wind, and impose them on battery storage. Energy storage is “more akin to a living organism” and standardized maintenance protocols will only come with far more field experience than the sector has today.

Still, GT experts will recognize some analogies to their facilities. For example, performance of lithium-ion batteries, the prevailing technology, is affected by ambient temperature. For GTs, it’s efficiency and output. Batteries, however, chemically and physically degrade; deviations from ideal operating temperature can have “severe consequences” on battery cell life (chart)—just think of your digital devices. Parasitic energy is consumed to maintain that ideal temperature within the enclosure. Assuring uniform flow of coolant around battery pack outer enclosures is essential, but a challenge.

ACES’s BPG confirms what was learned last year at storage-industry meetings: There is little consensus deriving basic grid-scale battery performance parameters—such as reliability, round- trip efficiency, and degradation rates. Safety is in the same category. The BPG quotes an earlier 2014 DOE report, “It is almost impossible to have a meaningful technical discussion about ESS [energy storage system] performance or reliability.”

While the report acknowledges there has been progress within storage communities to address these gaps, the CCJ summary from last year suggests there is still a ways to go. The Energy Storage Association’s (ESA) Corporate Responsibility Initiative also is addressing safety and reliability issues.

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Macroetching aids in removing heat-affected zones of rubs

With a little luck, you’ll never experience significant rub damage to your rotors. By design, OEMs usually provide generous clearance between the rotor and non-rotating parts except where it’s unavoidable: bearings and seals. OEMs mitigate the rubbing risks associated for those close clearance components with smart material selection—such as Babbitt, brass, and nylon. Those features work well enough when everything operates according to design, but that doesn’t always happen.

When significant rub damage does occur, say Calpine Corp’s Craig Spencer and GenMet LLC’s Neil Kilpatrick, repair options can be limited based on location and severity, but ideally the remedy requires only removal of the heat-affected material, which can be tricky if not done with the proper process.

Shaft rub basics. When your rotor is turning, any solid material that comes into contact with the rotor surfaces has the ability to cause rub damage. The severity of that damage depends on the total amount of energy and rate of energy transfer which occurs during the rub.

The most common rub occurs when some hard substance (grit) gets caught between the rotor and the bearing or the seals and that grit exceeds the given clearance, causing the grit to machine the surface of the rotor, making a groove with no evidence of heat, metal adhesion, or bulging.

Normally, a few small grooves pose no appreciable risk, and can simply be polished out (Fig 1; A, B, D).

If there are more than a few grooves, and/or if they are relatively deep grooves—such as from a hydrogen seal (Fig 1; C), bearing oil seal (E), or labyrinth seal (F), you may need to perform a step machining of the shaft surface, and replace the seals, and possibly the bearing, to fit to the new diameter.

Another common rub occurs when seal strips are set to an inadequate clearance during a maintenance outage. Generally speaking, these seal strips will wear in the necessary clearance in time, sometimes yielding deposits from the seal strips adhered to the shaft. Usually there’s no appreciable damage to the shaft substrate, and only shaft polishing is needed to remove the deposits. However, severe cases should be metallically evaluated after polishing, as noted with friction rubbing described below.

Less common, but potentially much more severe, is a friction rub created by contact between the turning rotor and a non-rotating member of the unit assembly as a result of an abnormal operating condition—such as a loss of lubrication or an abrupt lateral event like an L-0 blade liberation. Because of the relatively high energy transmission in a relatively short amount of time, these friction rubs often do show evidence of heat, metal adhesion, or bulging at the rub site. Fig 2 shows an example of shaft bluing from heat and metal adhesion attributed a friction rub.

Possible remedial options for friction rubs include, in order of severity:

    • Machining out the damage to a smooth bottom groove.

    • Machining the damaged zone smooth and locally heat treating to temper back the heat-affected material.

    • Machining out the damage and replacing the removed material using TIG welding.

    • Replacing the shaft in whole or in part.

To better understand the need for these repairs, we should better define the physics of this type of damage.

Friction rub physics. The profile of a friction rub is depicted in Fig 3, where the rotor (in gray) rotates against a stationary object.

Because of the great momentum in the rotating shaft, it usually will continue to rotate no matter how hard it makes contact with the stationary object, at least for some time. High-energy friction contact can result in highly localized extreme temperatures within the shaft in proximity to the rub, often exceeding 1300F. Given that shafts normally are made of high-strength, low-alloy steel, this heating is often enough to locally transform the structure to soft austenite.

While the rub is active, heat flows into the rotor as depicted in Figs 4 and 5. As temperature builds in the hot zone (B-B), the hot metal tries to expand, but the cold surrounding metal is much stronger and more stable and compressional yielding occurs. As temperature increases, compressional yielding increases and locally reduces the strength.

During this intense rubbing, it’s common to form adhesive metal-smearing deposits on the surface.

When rubbing stops, the hot zone effectively is quenched down to the temperature of the surrounding metal. In typical rotor magnetic-steel components, this means that a local hardening transformation to martensite can occur. At the same time, a significant contraction of the former hot zone occurs, and the stress state of transformed metal zone will change to what can be a very high tensile stress.

Martensite is very hard and brittle, and so it is not uncommon for cracks to develop at this point because of the residual tensile stress. Rub severity is somewhat proportional to the likelihood for cracking to occur.

With this type of damage, crack initiation and propagation from normal operating stresses cannot be predicted, but, clearly, the probability of cracking is likely significant. This condition also means that the part (rotor forging, blower hub, blower blade, etc) is now capable of erratic and unpredictable behavior. This makes it imperative to treat or otherwise remove the damaged material, collectively known as the heat-affected zone (HAZ) from the shaft if it is to remain in service.

HAZ removal. As noted above, there are several repair options, depending on the location and severity of a shaft rub.

Usually, the most cost-effective and expedient manner to deal with a HAZ on a shaft involves machining it off. Because you want to preserve as much of the shaft substrate as possible to endure operational stresses, this machining is an iterative process, where usually skim cuts of the surface on the order of a radial depth of 5 to 25 mils are taken, and the remaining surface is evaluated for a need for additional skim cuts.

Depending on method of evaluation, there are challenges to accurately determining the remaining HAZ after a skim cut. If you look at Fig 2 of the as-found rotor, the damaged area is obvious. However, as you can see in Fig 6, the HAZ is much more difficult, if not impossible, to identify visually after a skim cut. The entire surface looks the same.

Within the HAZ, changes have occurred in the microstructure of the rotor steel. As a result, the steel in the HAZ is harder. Given that it’s not practical to cut up the shaft to examine the microstructure under a microscope to check for HAZ, it is common practice to check the hardness of the shaft as a proxy for determining if HAZ remains.

Typical hardness testers use a pen-like device to shoot a diamond-tipped projectile into the shaft surface and measure its response. It tests one location at a time with each impact. The reading is a highly localized average of the hardness at the test location.

And there’s the figurative rub: How can you be certain that you’re testing the correct location with this highly localized test on a rotor surface which looks like Fig 6? After a skim cut, it’s too easy to lose your references for locating the potential remaining HAZ, meaning you may get a false negative report showing no remaining HAZ simply because it was tested in the wrong location. This opens the door to possible crack initiation in service due to the remaining hard material.

A better alternative to evaluating remaining HAZ is a process called macroetching. It involves first polishing the surface with about a 600 grit or finer sander, and then applying an acid solution to the surface (10% Nital in this case). The changes in the steel microstructure cause variations in the grain structure and precipitates around the grain boundaries. The macroetching solution helps to accentuate these grain boundaries in a way which can be visually discerned with the naked eye in localized regions on the shaft.

In Fig 7, you can see the results of macroetching after the first skim cut, as well as measurements of Brinell hardness (HB). The hardness in the primary macroetching indication measured 457 HB, while measurements outside of the HAZ measure a nominal 271 HB. If you’ve got really sharp eyes, you may be able to discern in Fig 7 how there is a center whitish island of material surrounded by a material which is darker than the balance of the rotor surface. Such an appearance is typical of significantly hardened material.

Unfortunately, the rotor surface in Fig 7 is somewhat mottled by contact after the etch was performed. For a better perspective of what a rotor surface looks like shortly after macroetching, refer to Fig 8, which was captured after the second skim cut. There’s no need to do a hardness check because it’s obvious that there’s still a HAZ in the rotor.

Conclusion. Rather than hardness testing, you should insist on macroetching to evaluate remaining HAZ when dealing with magnetic steel. Don’t assume that the shop uses macroetching as a standard practice. Even if the shop isn’t familiar with macroetching, they should have a metallurgist/NDE contact who is. But in every case, the work must be done by qualified personnel.

Stainless steels are more difficult to examine with macroetching, so if your rub involves a stainless component, like a generator rotor endwinding retaining ring, it is even more important to consult with an expert metallurgist for options.

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Starting reliability improvement: Rock Springs lauds start system retrofit

The turnkey digital front end (DFE) solution for aging, unreliable, or obsolete gas turbine load-commutated inverter (LCI) starting systems, described last year in CCJ ONsite, now has a user testimonial and operating experience supporting it.

John Chaya, operations manager at Cogentrix’ Rock Springs (Maryland), reports that the installation by Turbine Controls & Excitation Group Inc (TC&E), Denver, Colo, went “as expected,” testing proceeded with only the normal number of “bugs” to sort out, and all machine starts since Nov 8, 2019 have been successful. All acceleration and ramp rates were matched to the original OEM specifications.

All four 7F peakers at Rock Springs (commercial in 2003) will soon be served by two DFE LCIs, with the second unit install to occur this year.

Chaya notes that the motivation for the retrofit was that the majority of unit unavailability was attributed to the LCI. The precipitating event occurred in October 2017 when two units were out of service for 12 hours. Obtaining spare parts was becoming an issue as well. The units experienced 120 starts in 2019, mostly in the summer.

“The TC&E/TMEIC team was very professional and did the work in the time frame promised,” The timeline was three days for component changeout, two days for testing and commissioning during the 2019 fall outage.   

Other benefits attributed to the project by Chaya: startup procedures remained the same and the electronics and interface screens are much larger and easier to read (Figs 1 and 2). One piece of advice he offers the next users: Be sure to request training for troubleshooting, even though “it’s pretty intuitive to get through the manuals.”      

TC&E/TMEIC completed three DFE LCI upgrades last year.

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