Ammonia oxidation in simple-cycle SCRs can cause understatement of catalyst activity

Special to CCJ ONsite

By Larry Muzio and Sean Bogseth, Fossil Energy Research Corp, and Frederic Vitse, GE Power Portfolio

Selective catalytic reduction (SCR) is widely used to reduce NOx emissions from gas-turbine powerplants—both simple- and combined-cycle units. Once the catalyst is installed it is important to monitor its activity periodically. This involves removing a sample from the unit and testing for its activity in a laboratory. Test frequency can vary from yearly to every two to three years, depending on site-specific issues relating to potential catalyst poisons. 

Protocols developed by Germany’s VGB for testing SCR catalysts from coal-fired boilers are described in Refs 1 and 2. EPRI’s Catalyst Testing Protocol, published in 2007, is explained in Ref 3. EPRI later (2015) released testing guidelines for SCR and CO catalysts used in gas-turbine powerplants (Ref 4).

This article discusses issues with testing SCR catalysts used in simple-cycle gas-turbine systems that are not addressed in the testing guidelines. The catalysts in simple-cycle units typically operate in a temperature range of 750F to 850F; more typically, 800F to 850F. 

The guidelines in Ref 4 for testing gas-turbine SCR catalysts describe two ways to monitor catalyst life: 

    • Monitor the parameter “catalyst activity, K,” over the life of the catalyst.

    • Monitor the NOx reduction achievable by the catalyst at the NH3 slip limit—again over the life of the catalyst.

The authors focus here on measuring catalyst activity in the laboratory. Note that K varies with the chemical composition of the catalyst, its geometry (for example, mass transfer in the catalyst channels), and operating parameters (for example, temperature and area velocity). Area velocity (Av) is the ratio of flue-gas flow to the active catalyst surface area. Lower Av means more catalyst per unit of flue gas.

To determine catalyst activity, the NOx reduction is measured across the catalyst and its activity is calculated from the equation:

where deltaNOx is the measured NOx reduction across the catalyst and Av is the area velocity, which depends on the area of the catalyst in the catalyst channels.

Laboratory test conditions typically are arranged to duplicate full-scale temperature and area velocity. The EPRI guidelines specify that the activity be determined at a NH3/NOx ratio of 1.2. 

The challenge with simple-cycle SCR catalysts operating at relatively high temperatures (800F to 850F) is that reactions other than the basic SCR reaction can occur—as indicated by equations A to C below.  

These parallel oxidation reactions of ammonia essentially compete for the ammonia that is injected and used for SCR NOx reduction. For instance, the EPRI GT SCR catalyst testing guidelines specify that an inlet NH3/NOx ratio of 1.2 be used to measure the activity. If ammonia oxidation reactions described by equations A to C are taking place in parallel, then the ammonia available for the SCR reaction (Eq A) is less than the NH3/NOx = 1.2 injected as specified in the guidelines. This will result in a lower NOx reduction and an artificially low activity K. If not accounted for this can lead to a premature recommendation to change the catalyst. 

A second impact of these side reactions is that even if the required NOx reduction can be achieved, the required reagent consumption can be higher than anticipated. 

It is not the authors’ purpose to discuss what catalyst formulations and properties promote these oxidation reactions. Rather, some typical examples presented below show the impacts of the oxidation reactions along with recommendations on how to deal with these issues during laboratory testing. 

The following discussion focuses on laboratory tests of SCR Catalysts A and B. Fig 1 shows test results in terms of NOx reduction and NH3 slip as a function of the inlet NH3/NOx ratio for Catalyst A at 850F and an area velocity of 10.8 m/hr.

The following observations are noteworthy in this figure:

    • NOx reduction continues to increase markedly as the injected NH3/NOx ratio increases from 1.0 to 2. One normally expects this curve to flatten at NH3/NOx ratios just over 1.0 at laboratory conditions.

    • At NH3/NOx ratios greater than 2, the NOx reductions achievable are quite high.

    • NH3 slip does not start to increase until the NH3/NOx ratio approaches 1.5. Typically, one would expect the NH3 slip to increase as the NH3/NOx ratio exceeds 1.0.

These characterizations point to the side reactions involving NH3 oxidation competing with the basic SCR reaction. The magnitude of the oxidation reactions can be quantified by calculating the NH3/NOx ratio based on the measured NOx reduction that is actually occurring, along with the measured NH3 slip:

The difference between the injected NH3/NOx ratio (NH3/NOx-in) and the “effective” NH3/NOx ratio (NH3/NOx-eff, Eq 2) is the amount of the injected NH3 that was oxidized via the parallel reactions discussed above and not used for SCR NOx reduction. To determine this effective NH3/NOx ratio, an accurate NH3 slip measurement is required, along with the inlet and outlet NOx concentrations during the laboratory tests. 

To illustrate these oxidation reactions, the data in Fig 1 are replotted in Fig 2 using the NH3/NOx-eff ratio, as calculated from Eq 2, as the x-axis.


As can be seen in Fig 2, these trends appear more “as expected” for an SCR process: 

    • NOx-reduction trend curve flattens as NH3/NOx-eff increases above 1.0.

    • NH3 slip begins to increase at NH3/NOx > 1.

For the performance data shown in Fig 1, if the SCR system must achieve 90% NOx reduction, the actual injected NH3/NOx ratio required would be a nominal 1.7. By contrast, Fig 2 shows that the actual NH3/NOx ratio participating in the NOx reduction need only be about 1.0 for 90% NOx reduction—provided there was no NH3 oxidation in parallel with the SCR reaction. 

In terms of tracking catalyst activity and life using an inlet NH3/NOx ratio of 1.2 as specified in the testing guidelines, the catalyst activity would be calculated to be 16.3 m/hr. Using the effective NH3/NOx = 1.2 results in an activity of 29.7 m/hr—almost double. Clearly, unless oxidation is accounted for, management of Catalyst A is difficult using the current EPRI testing guidelines. 

Not all catalysts exhibit the same degree of ammonia oxidation. An easy way to compare catalysts is to compare the relationship between the injected NH3/NOx ratio and the NH3/NOx-eff calculated from Eq 2. This comparison is shown in Fig 3 for Catalyst A and a second catalyst, Catalyst B, tested under similar conditions. Using a linear curve fit through the data shown in Fig 3 indicates that for Catalyst A, 48% of the injected ammonia at NH3/NOx = 3 is oxidized and does not participate in the SCR reactions.

For Catalyst B, the ammonia oxidation is less than 12% at NH3/NOx = 3. Also, the amount of oxidation increases as the amount of ammonia injected increases: At NH3/NOx-eff of 1.0, Catalyst A and B oxidize 20% and 0%, respectively. 

Table 1 compares the activity K measured for Catalysts A and B if the measurements are done at either an inlet NH3/NOx ratio of 1.2 according to the testing guidelines, or at the effective NH3/NOx ratio defined in Eq 2. Note that Catalyst B exhibits little oxidation: There is little difference in the measured activity (76 versus 76.5 m/hr). However, for Catalyst A, which exhibits a higher level of ammonia oxidation, there is a large difference in the activities (38 versus 48 m/hr). 

If the activity measurements shown in Table 1 are to be used to make performance predictions, there will be a large difference in these predictions for Catalyst A. Fig 4 shows the predicted performance for Catalyst A operating at an area velocity of 19 m/hr and inlet NOx of 25 ppm with a velocity and NH3/NOx maldistribution of 15% RMS and 10% RMS, respectively. 

If the SCR system must achieve 90% NOx reduction, and the activity measurement was only made at NH3/NOx  = 1.2 based on the inlet ratio, one might conclude that the catalyst is “beyond end-of-life.” However, making the measurement at an “effective” NH3/NOx ratio of 1.2 (Eq 2), the catalyst can still achieve 90% NOx reduction.

If activity measurements are to be made on these catalysts operating at high temperatures, you should consider how these activity measurements will be used. 

Even if the catalyst activity measurements are being made to track relative activity (K/Ko) where the catalyst vendor has specified a K/Ko value at the “end-of-life,” there can be issues. If the amount of ammonia oxidation changes as the catalyst ages, then the K/K0 parameter based on an activity measured using an inlet NH3/NOx ratio of 1.2 may also be in error. 

Impact of catalyst size. When testing a catalyst for which the oxidation reactions of ammonia are not negligible, special care must be taken to understand the impact of catalyst length. Table 2 shows that, all other parameters remaining constant during lab tests, the catalyst length can substantially favor the overall kinetics of ammonia oxidation over the deNOx reaction.

For NH3/NOx = 1.2, the longer catalyst sample resulted in an increase in the ammonia oxidation by more than a factor of 2. As a result, the NOx reduction decreased from 90% to 82%.  At the higher NH3/NOx ratio of 1.4, the ammonia oxidation increase was less, about 3%, but still reduced NOx from 92.6% to 86.8%. 

Therefore, if catalyst performance is to be validated by lab testing at reduced scale, particular attention should be given to the amount of ammonia oxidation observed at that scale. If the amount of ammonia oxidation is large, a performance test at full-scale catalyst length is recommended to capture a representative activity under field conditions. 

Recommendations. For SCR catalysts operating at temperatures of 800F to 850F, oxidation of a portion of the injected ammonia must be addressed when characterizing catalyst performance in the laboratory. The current testing guidelines for gas turbine SCR catalysts are silent in terms of these parallel oxidation reactions at such high temperatures.

When laboratory catalyst tests are conducted, measure ammonia slip along with the inlet and outlet NOx measurements. This will allow calculation of the effective NH3/NOx ratio (Eq 2), resulting in a more accurate determination of the actual catalyst activity as well as quantifying what fraction of the injected ammonia is oxidized and does not participate in the SCR NOx reduction process. 

As mentioned earlier, the gas-turbine SCR testing guidelines also describe a test where catalyst performance is tracked over time by measuring the NOx reduction that can be achieved at the NH3 slip limit with laboratory operating parameters matching full-scale operating parameters.  While this procedure is not directly influenced by ammonia oxidation, it would be good if along with the NOx reduction achievable at the NH3 slip limit, the test results also include the inlet NH3/NOx ratio needed to yield the NH3 slip limit. This would allow changes in ammonia oxidation to be monitored as the catalyst ages.


  1. 1. “Guidelines for the Testing of deNOx Catalysts,” VGB-R 302 He, VGB Technical Association of Large Power Plant Operators, 1998.

  2. 2. “Common Best Practices for Bench Scale Reactor Testing and Chemical Analysis of SCR deNOx Catalyst,” Supplement to VGB-R 302 He, 2nd Ed, STEAG GmbH, May 2006.

  3. 3. “Protocol for Laboratory Testing of SCR Catalyst Samples,” 1014256, 2nd Ed, EPRI, 2007.

  4. 4. “Laboratory Testing Guidelines for Gas Turbine Selective Catalytic Reduction (SCR) and CO Catalysts,” 3002006042, EPRI, 2015.


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Inspection, maintenance priorities for ageing HRSGs

Editor’s note: The traditional annual conferences of all user groups serving the gas-turbine sector of the US electric-power industry scheduled between Mar 1, 2020 and Dec 31 have been canceled because of the Covid-19 pandemic. The 30th anniversary meeting of the Western Turbine Users (slated for March 29 to April 1 at the Long Beach Convention Center) was one of the organizations so affected.

Ned Congdon, PE, of HRST Inc, who was scheduled to speak in the Special Technical Presentations session on March 31, shared his talking points on problems to anticipate with ageing HRSGs with Contributing Editor David Benjamin, an aero user, who developed the article that follows from those notes.

Many heat-recovery steam generators (HRSGs) were installed during the combined-cycle boom of 2000 to 2005, putting them roughly halfway through their 30-yr design lifetimes. While the majority of boilers experience some form of tube distress by this point, there is much that can be done to bolster their health. With good operations and maintenance informed by experienced judgment, typical design lives can be extended appreciably. It is crucial to know what to look for, and when to take corrective action. Informed forethought can help avoid costly repairs requiring extended forced outages.

Congdon highlighted the following points in his presentation, among others:

    • Duct-burner flame management.

    • Internal oxide deposits on superheater and reheater tubes.

    • Duct-burner liner replacements.

    • Creep-damage assessment of piping for superheated steam.

    • Return-bend economizer failures.

The HRSG expert discussed the ways in which careful duct-burner flame management is essential for maintaining the health of an ageing boiler. Many simple operational parameters are commonly overlooked and can contribute significantly to the likelihood of tube failures. It is crucial to maintain proper flame shape, to ensure a uniform vertical distribution of flue-gas, and to prevent flames from overextending and impinging on downstream tube panels.

For HRSGs with supplementary firing, the highest tube-metal temperatures and heat fluxes typically occur on the tube banks immediately downstream of the duct burners. Tube-overheating failures typically occur in this area. Sometimes, finless screen tubes with reduced heat-transfer characteristics are placed in front of the primary superheater/reheater surface to take brunt of the heat flux. In that case, the risk of a tube overheating is highest for the superheat/reheater surface immediately downstream of the screen tubes.

Duct-burner flames should be checked by operators during rounds. When looking through a viewport, a good rule-of-thumb is that the flame should extend no more than half to two-thirds of the length of the firing duct. Flames should be independent of each other, and should be completely horizontal. It is important all flames be of uniform length; higher elevation flames may be longer, which signifies non-uniform gas flow. The visible portion of the flame should end no closer than 6 ft from the first tube panel. Be sure flames never contact the tubes!

A good 21st century alternative to viewports is a set of duct-burner cameras. They may be mounted on the floor, roof, or walls of the firing duct and send a wireless signal to a DAQ device connected to the plant’s main control system. Cameras require purge air for cooling. Because the cameras are monitored from the control room, they can help identify early signs of burner trouble while avoiding the hazards and inconsistencies of frequent (or infrequent) viewport use.

Flow control. Congdon noted that users often will be forced to repair perforated flow-distribution plates in the hot gas path, and may chose not to replace them because of the high frequency of their decay. While it may be possible to remove perforated plates without going out of emissions compliance, insidious maintenance issues can develop.

The most frequently observed problem resulting from removing perforated plates from the gas path is bad flame shape—local back-eddies are a particular issue that damages liner and burner components. Another issue associated with perforated-plate removal is excessive flame length in the upper portion of the duct. This can lead to non-uniform tube metal temperatures, overheating of the tubes at high elevations, and, ultimately, tube failures.

Flow-distribution plates slow down the gas velocity in the lower portion of the firing duct where turbine outlet pressure is highest.  Without the perforated plates in place, the exhaust flow profile would naturally favor the lower portion of the firing duct, and higher elevations would have significantly less exhaust gas flow.

With reduced gas flow, mixing is diminished. The stoichiometry becomes offset, since burner elements put out uniform quantities of fuel, but the quantity of air is suppressed at higher elevations. Even though the flow velocity is lower, the flame takes much longer to consume the fuel, resulting in an extended flame length. This is often referred to as a “long lazy flame.”

Thus, it generally is not a good idea to remove perforated plates from the gas flow path. The result is often slowly forming damage to the higher portions of the tube panels, where inspections tend to be less common. Such tube damage often goes unnoticed until a full-on leak demands a forced outage. A drone inspection can aid O&M teams to pinpoint upper-level tube damage in boilers where an uneven gas flow profile is suspected.

Internal deposits. Congdon discussed several problems associated with the growth of oxides along the inside walls of superheater and reheater tubes made of steels containing chromium. In small quantities, oxides protect the tubes from corrosion. However, too much internal oxide growth, or an uneven distribution profile, can insulate sections of tubes, creating temperature imbalances that can cause creep damage and ultimately lead to failure.

Many chromium steel alloys have been used in the manufacture of superheater and reheater tubes. High-chrome alloys, such as T91, generally produce less oxide growth, but also tend to be more expensive. Many ageing boilers were fabricated with lower chromium-containing alloys, such as T11 and T22, and are highly prone to oxide growth over time. Superheater and reheater panels with high heat flux are especially vulnerable to damage from internal oxide growth, because tubes in these sections generally were not designed with a high margin for wall thickness or deviation in temperature gradients.

Internal oxide growth along a superheater or reheater tube can result in tube swelling over an extended period of time, and may eventually lead to a complete rupture. The oxide layer insulates the internal surface of the tube, adding an additional thermal resistance to the heat-transfer path between the flue gas and the steam. This causes the tube metal to reach thermal equilibrium at a higher temperature, overheating the metal.

With added thermal resistance from an excessive internal oxide layer, the operating temperature of the tube metal goes up. The tube wall then becomes slightly more plastic, and the tube slowly begins to yield to the hoop stress generated by the steam. Over time, the tube will swell as the tube metal starts to yield as creep.

Aside from reducing burner heat release, there is little that can be done to reduce internal oxide growth in low-chromium-content steel alloy tubes. Superheater and reheater tube panels with high heat flux should be inspected regularly during the latter half of the boiler’s design life. Internal oxide growth can be qualitatively assessed by borescope inspection, and can be quantitatively measured using NDE techniques.

If excessive oxide growth is suspected, it’s a good idea to measure tube ODs at strategic locations to get an idea of how much swelling has taken place. Swollen tubes must be replaced; they generally cannot be saved. If the OD has swollen by 3% or more, HRST recommends derating the burner until the tubes can be replaced.

A quantitative engineering analysis is required to determine by what percentage the burners must be de-rated to preserve the lifespan of the tubes to the next available outage. It is generally good practice to be proactive in identifying and replacing swollen tubes before they rupture.

High levels of internal oxides also can result in the liberation of oxide flakes and particulates into the steam. This can be erosive to steam turbine blading. If excessive oxide growth is suspected, consider installing a duplex strainer before the steam-turbine inlet, if there is not already one in place. This can prevent erosion damage to the first few stages of blading from liberated oxides.

Firing ducts. Congdon discussed failures of stainless-steel liner panels typical of older boiler designs. Type-309 stainless steel often was used to line firing ducts in boilers installed 15 or more years ago. Type 309 has good oxidation resistance, but tends to warp in high-temperature environments.

Many users find themselves having to repeatedly reline boiler walls around the duct burner during maintenance outages. Some users who had encountered this problem found success in retrofitting the lining with ceramic-fiber modules. While there is a high one-time cost incurred by this, it reduces the frequent need to reline the firing ducts. A cost-benefit analysis may favor this decision in the long-run, while it may also increase reliability and reduce downtime.

Steam-line creep. In ageing plants, it can be helpful to investigate the health of high-temperature steam lines with regard to creep damage. The potential for creep damage can be analyzed remotely using process modeling software to determine the most likely weak spots in the pipes. The analysis can then be assimilated into a site-specific test program to strategically focus the NDE on the most probable locations for damage.

Return-bend economizers. Congdon discussed the commonly encountered failure of return-bend economizers resulting from tube-to-tube temperature differentials with a top-supported structural design. Ageing return-bend economizers often are prone to failures at the bends. Temperature differentials may develop between economizer tubes during transient startup periods, causing uneven thermal expansion of the tubes. Return-bend economizers usually are top-supported at the inside of the tube bends by a support beam.

Tubes at high temperatures will elongate and no longer support the load of the economizer. Thus, the mechanical load concentrates on the cooler tubes, causing an off-design distribution of weight. The result is a higher concentration of stress at the bends of the cooler tubes, which can lead to cyclic stress, fatigue, corrosion fatigue, and stress corrosion cracking failures.

Temperature differentials occur naturally during startup in return-bend economizers where cold water flows into the top of the top-supported header. These conditions may be exacerbated by air pockets in the bends, which are not vented easily. Operationally, maintaining a small but steady water flow through the economizer during startup can help smooth out the temperature differences.

A good long-term maintenance solution is to retrofit a support system that isn’t prone to transient differential stress loading. HRST developed a support system design for return-bend economizers that can redistribute the stresses to the bottom of the unit. Supports can be retrofitted to eliminate the support rods in favor of a bottom-supported design with spring isolators to help buffer transient deformations. This design prevents high stresses at upper tube bends, eliminating the risk of failure in those locations.

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Easily connect with and view presentations from key suppliers @ 7FUG 2020, Part IV

One of the unique aspects of the 7F Users Group’s 2020 Digital Conference is the opportunity to interact online with the OEM and nearly 50 third-party solutions providers. Ten companies in the latter group were selected by the steering committee to conduct live technical presentations which are available for on-demand playpack. The remaining solutions providers participated in the conference with virtual booths in the Vendor Fair conducted Tuesday and Wednesday of Week One. They connected directly with users via video (or audio) links.

In case you missed the opportunity to visit with one or more of these companies at the Vendor Fair, the editors have compiled brief summaries of the products/services they showcased, along with links to that information. The names of experts to contact for details are included, in addition to a variety of downloadable case studies, white papers, etc.

Part I. Exhibitors not included in the listing below were profiled in CCJ ONsite earlier. Products and services offered by virtual exhibitors Allied Power Group, GTC Control Solutions, Nel Hydrogen, Nitto Inc, Parker Hannifin Corp, Dekomte de Temple, Conax Technologies, Donaldson Company, ESC/Spectrum, and Hilco can be reviewed in Part I of this four-part series.

Part II of the series featured offerings from Mercer Thompson/IEM Energy Consultants, AP+M, Braden Filtration, Bureau Veritas, Groome Industrial Service Group, Pioneer Motor Bearing, VAW Systems, National Electric Coil, Nord-Lock Group, and Rochem Technical Services. [link to

Part III of the series summarized offerings from Parker Hannifin Gas Turbine Filtration, Moog Inc, Turbine Logic, AP+M, Liburdi Turbine Services, Strategic Power Systems Inc, C C Jensen Oil Maintenance, Badger Industries, Emerson Automation Solutions, and SVI Dynamics.

JASC Controls

Pitfalls to avoid for enhanced liquid-fuel-system reliability (users only)

Schuyler McElrath, one of the electric-power industry’s leading experts on liquid fuel systems for gas turbines, has new product development as one of his responsibilities at JASC Controls. His presentation simplifies the complexity inherent in liquid fuel systems and focuses on what design features owner/operators should be aware of to assure reliable starts on oil, reliable transfers from gas to oil, and vice versa, and reliable operation on both fuels. McElrath stresses that while some issues can be addressed with hardware upgrades, system infrastructure changes are an equally important part of the performance improvement process.  


Advanced steam-turbine-casing warming for startup (users only)

ARNOLD is perhaps best known globally for the insulation systems it provides for all types/designs of gas and steam turbines. Outside North America it is equally well known for its onsite turbine machining services. Turbine warming systems have matured as product line in the last several years given the need for gas and steam turbines to start faster to satisfy grid requirements.

Pierre Ansmann, the company’s global head of marketing, Norman Gagnon, ARNOLD’s North American project manager, and controls expert Joris Ringelberg provide users a primer on turbine warming systems. Their presentation covers the following:

    • Maintenance and operational benefits for individual customers.

    • Differences between various warming-system arrangements.

    • Durability and reliability.

    • The importance of proper insulation for a warming system.

    • Warming-system controls.

    • Cost and duration of initial installation and periodic maintenance.


A look inside Sulzer Turbo Services (users only)

Michael Andrepont, GM operations (gas turbines), and Jim Neurohr, area sales manager, take you on a 6-min tour of Sulzer Turbo Services’ Houston shop and explain the company’s capabilities regarding the 7FA—including HGP component, combustion hardware, and fuel-nozzle repairs, field services, rotor life evaluation, LTSAs, etc. Sulzer is one of the world’s leading independent service providers in the repair and maintenance of all makes and models of industrial gas and steam turbines, compressors, and expanders. It offers a wide range of manufacturing, engineering, reconditioning, balancing, and coating services.


GT upgrades: Low-load impact on HRSGs (users only)

Anand Gopa Kumar, who leads HRST’s Analysis Dept, provides users critical insights on how increasing the turndown capability of their gas turbines to provide the operational flexibility required in many areas of the country today may impact the HRSG. He identifies areas within the boiler at risk of exceeding their design capabilities and possibly susceptible to long-term damage. Kumar also suggests modifications to the HRSG and associated equipment (including attemperators, internal liners, superheater tubes, steam separators, etc) to enable the desired turndown with minimal risk.


7FA component lifetime extension (users only)

José Quiñones, PE, director of engineering for MD&A’s San Antonio Service Center, the company’s gas-turbine parts service facility, presents a tutorial on the life-limiting factors of hot-gas-path components. Included are typical steps to follow when conducting a lifetime-extension project. Plus, the upgrades, mods, and improvements—including advanced coatings—you should consider to extend the lifetimes of critical parts.

Gas Path Solutions LLC

Exhaust-diffuser relining and upgrades (users only)

Brian Nason, business manager, and Michael Busack, sales and field services manager, discuss the reconditioning services and upgrades offered for 7FA exhaust diffusers manufactured by C&W Fabricators, Quest, Braden, and others. Among the company’s replacement solutions: inlet flex seal joint, outlet expansion joint, and internal free-floating liner system. Turnkey installation is provided.

Koenig Engineering Inc

Everything you should know about turning gears but don’t (users only)

Tim Connor, aftermarket sales and field service manager, reviews findings from turning-gear teardown inspections, highlighting common failure modes and how to avoid them. An in-depth review of turning-gear operation and major components is especially beneficial for plant personnel with limited experience. Finally, Connor offers an action plan for ensuring long-term turbine starting and rolling reliability.


Pushing the needle: New strategies to improve gas-turbine energy efficiency through lubrication (users only)

Lubrication experts Mike Galloway, Jim Hannon, and Charlie Smith show how oils offering energy-efficiency benefits can improve your bottom line. They dig into the technical science and offer field and lab data to quantify the value of advanced lubrication strategies.

EagleBurgmann Industries LP

Expansion-joint maintenance from an owner/utility perspective (users only)

Mark Ahonen, aftermarket sales manager, provides an in-depth look at the 7FA exhaust joint—covering maintenance, repairs, upgrades, and a general owner’s guide of critical areas to monitor.

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Polling Power: User feedback from the 7F 2020 Digital Conference

A valuable feature of Power Users conferences is audience polling, which was pioneered by the 7F Users Group a few years ago. The steering committee and presenters use polling to ask owner/operators for their opinions on industry trends, the information needs of attendees, etc. Because the feedback is virtually instantaneous, it can identify where clarification or more detail is required on a particular subject during the presentation of interest.

Below are some of the polling questions asked during the 7F 2020 Digital Conference. The responses both characterize the audience and provide a snapshot of what your industry colleagues are thinking on topics of importance to owner/operators. Users can access presentations from the conference, a plethora of recorded technical presentations, and ask questions on the forum at the Power Users website.


How many times have you attended a 7F Users Group conference (including this year)?

  My first meeting, 46%

  Two years, 20%

  Three to five years, 21%

  Six or more years, 13%

How would you rate your level of 7F knowledge?

  Newbie, 14%

  Rookie, 10%

  Intermediate, 37%

  Seasoned, 25%

  Expert, 4%

What is your primary role?

  Maintenance manager, 12%

  Plant manager, 10%

  Maintenance engineer, 16%

  Turbine engineer, 28%

  Asset manager, 11%

  Other, 22%

How often do you interact with power traders or dispatchers?

  Multiple times a day, 7%

  Daily, 22%

  Weekly, 12%

  Rarely, 29%

  Never, 29%


What is the average age of your 7F and steam-turbine units based on COD?

  Less than 10 years, 15%

  10-15 years, 24%

  16-20 years, 48%

  More than 20 years, 13%


What system/component gives you the biggest headache, or impacts reliability the most, on your unit(s)? Check all that apply.

  Valves (for example, gas, compressor bleed valves, etc), 45%

  Instrumentation (for example, transmitters, T/Cs, etc), 38%

  Protection systems (for example, haz-gas detection, etc), 14%

  Inlet filtration system, 4%

  Covid-19, 12%

  Starting system (for example, static starter, etc), 7%

Three years into the future, how do you see your CCGT operating profile changing?

  More starts, fewer hours, 50%

  More starts, more hours, 13%

  Fewer starts, fewer hours, 5%

  Fewer starts, more hours, 16%

  No change, 15%

Three years into the future, how do you see your CCGT operating and ramp profiles changing?

  More part-load operation, more ramping, 65%

  More full-load operation, less ramping, 6%

  More full-load operation, more ramping, 9%

  More part-load operation, less ramping, 3%

  No change, 16%

Which type of flexibility would you choose if you could upgrade your plant today?

  Higher maximum output, 17%

  Lower minimum output, 31%

  Faster ramping, 5%

  Faster startup, 12%

  All of the above, 35%

Plant managers, maintenance managers/engineers, turbine engineers: If you had the ability to cost-effectively cycle overnight versus turndown, would you want to cycle?

  Yes, 29%

  Absolutely not, 49%

  Maybe, 22%

Traders, asset managers: If you had the ability to cost-effectively cycle overnight versus turndown, would you want to cycle?

  Yes, 41%

  Absolutely not, 37%

  Maybe, 22%

Which type of generating unit do you think the more flexible CCGT displaced to produce additional megawatt-hours?

  Less-flexible CCGTs, 21%

  Simple-cycle GTs, 36%

  Steam turbines, 17%

  All of the above, 26% 

How would you react if your trader/dispatcher asked you to cycle between 2 and 4 a.m.?

  No way, 26%

  Are you crazy? 21%

  OK, as long as power payments make up for the increased maintenance cost, 54%

What was the cause of your last failed start (pick one only)?

  Valves, 23%

  Static frequency converter, 3%

  Burners and nozzles, 7%

  Controls, 22%

  Instrumentation, 20%

  Hardware, 8%

  Excitation and generator, 14%

  Other, 4%

What concerns you the most at your site for forced-outage days (pick one only)?

  Transformer, 19%

  Instrumentation, 29%

  Rotor, 15%

  Bearings, 7%

  Steam-turbine unavailable, 19%

  Other, 11%

What is your most recent annual unit/block start/stop count on average?

  Fewer than 100 start/stops per year, 67%

  100-200 start/stops per year, 33%

  More than 200 start/stops per year, 0%

In the last 10 years, what start/stop count trend are you experiencing?

  Minimal or no change, 56%

  Up to 50% increase, 29%

  Roughly doubled, 11%

  More than doubled, 3%

Which 7F HGP TIL most keeps you up at night?

  2045, 7F AGP Stage 3 bucket tip shroud creep, 40%

  2181, Stage 1 nozzle creep degradation model, 23%

  2006, 7F and 9F Stage 3 bucket airfoil distress, 17%

  Other/none, 20%


What rodent issue have you seen the most?

  Cable damage in cable tray, 27%

  Wire damage in electrical cabinets, 38%

  Insulation damage on piping, 15%

  Other, 20%

Do you currently use adjustable rigging in your lift planning for turbine rotor or case removal?

  Yes, 66%

  No, 34%


How familiar are you with gas-turbine combustion?

  I’m a flame-stability expert, 5%

  I’m pretty good with what runs in my units, 42%

  I know the difference between a DLN 2.6+ and DLN 2.6, 27%

  Harry Potter’s wand must be involved, 20%

  Gas turbines have combustors? 7%

What is your biggest concern when it comes to combustion operability?

  Tuning, 24%

  Hardware, 22%

  CDM and T/C health, 17%

  AutoTune, 15%

  Cold weather, 17%

  Nothing, my unit runs well, 6%

Have you experienced fuel-nozzle damage?

  Yes, 56%

  No, 44%

What was the cause of the fuel-nozzle damage?

  Quat operation, 8%

  Fuel contamination, 28%

  Other, 45%

  Unknown, 19%

If it was quat operation or unknown, are you changing your quat limits seasonally?

  Yes, 13%

  No, 86%

Do you have issues during cold weather with high-dynamics alarms that require operator response?

  No, 45%

  Rarely, 41%

  Frequently, 14%


What is your most common unplanned stator repair/upgrade finding during an outage?

  Endwinding dusting/greasing or resonance repair, 69%

  Belly-band tightening (or new belly-band install), 8%

  Stator rewedge, either full or partial, 23%

  Stator core looseness, 0%

What is your most common unplanned field /rotor repair/upgrade finding during an outage?

  Slot content (amortisseur spring) migration, 35%

  Main lead cracking or separation, 8%

  Field turn shorts, 49%

  Field ground, 8%

Does your site or HQ/fleet have a spare/exchange 7FH2 field?

  Yes, 21%

  No, 79%

How much time is on the outage schedule for generator rotor removal and replacement—including setup and tear down?

  Less than one day, 7%

  Two days, 28%

  Almost one week, 48%

  Too long, 17%


Have you converted to electric actuators on your gas control valves?

  Yes, 13%

  No, 87%

Are you planning to convert the hydraulic actuators on your gas control valves to electric?

  Yes, 11%

  No, 57%

  Don’t know, 32%


How well do you know RLE (rotor lifetime extension)?

  Extremely well. We currently are in discussions and formulating a plan, 35%

  Have discussed it with our engine representative, 24%

  Know what the acronym stands for, 35%

  Don’t know about RLE, 7%

What’s your rotor maintenance plan?

  Exchange rotor, 29%

  Lifetime extension, 32%

  New rotor, 12%

  Not decided/do not know, 27%

Is your rotor affected by TILs 1971 and/or 1972?

  Yes, 46%

  No, 20%

  Not sure, 31%

  It was, 3%

Is your turbine rotor maintenance hours- or starts-based?

  Hours, 52%

  Starts, 16%

  Multiple units, some with both 27%

  Was hours, now starts, 4%

  Was starts, now hours, 1%

Do you have maintenance factoring calculated in your DCS logic?

  Yes, 14%

  No, 37%

  Not sure, 16%

  Tracking outside the DCS, 33%

Are you planning on conducting 7F rotor maintenance in the next five years?

  Yes, based on GER-3620 guidance, 57%

  No, 29%

  Learning more before deciding, 14%

Exhaust system

How often do you inspect your exhaust-frame flex seals?

  HGP interval only, 47%

  Annually, 50%

  More frequently than annually, 3%


How long does your oil last?

  Five years or less, 10%

  Six to nine years, 31%

  More than nine years, 60%

How many hours do you lose annually because of an oil-related failure?

  Less than 12, 81%

  12 to 24, 5%

  24 to 48, 9%

  More than 48, 5%

What are your MPC values?

  Less than 15, 77%

  15 to 35, 20%

  More than 35, 3%

Does your lab report the MPC hold time as required?

  Yes, 13%

  No, 28%

  Not sure, 59%

What type of lube oil do you use?

  Mineral groups 1 and/or 2, 58%

  Synthetic hydrocarbon groups 3 and/or 4, 26%

  PAG, 16%

Have you used an aftermarket turbine-oil additive?

  Yes, 31%

  No, 69%

Do you use a varnish-removal system?

  No, 30%

  Yes, rotating on several units, 33%

  Yes, full time, 37%

When did you install your varnish-removal system?

  Following a failed lab result, 60%

  Following an onsite failure, 28%

  With a new charge of oil, 12%

Have you changed the type of lube oil in your gas turbine?

  Yes, 29%

  Considering it, 20%

  No, 51%

What type of evaluation was done prior to changing the type of oil?

  Full technical evaluation, 60%

  Lube-oil supplier performed the evaluation, 18%

  Relied on the experience of others, 22%

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