Steven C Stultz, Consulting Editor

Editor’s note: Registered users can access the comprehensive slide deck developed by EPRI for its HRSG Technology Transfer Workshop, go to www.powerusers.org, click the HRSG Forum logo and then the “Conference Archives” button at the top of the screen.

As a final day attached to the HRSG Forum’s 2023 Conference and Vendor Fair, June 12 – 15, at the Renaissance Atlanta Waverly, the Electric Power Research Institute presented EPRI heat-recovery steam generator technology transfer day, open to all Forum attendees.

Principal organizers were these EPRI program leaders:

• Bill Carson, HRSG.
• Tom Sambor, Power Plant Piping.
• John Siefert, Materials.

Primary agenda topics included the following:

• Current industry challenges.
• Safety issues with header end caps.
• Activities with high-temperature components.
• Steam leaks in high-temperature intersections (tees).
• Damage related to attemperators/desuperheaters.
• Activities with low-temperature components.

Bill Carson opened the program with a safety session on personal protective equipment, followed by an overview of information available through the EPRI website. Those interested should visit https://enroll.epri.com.

Eugene Eagle, Duke Energy, the utility chair of the HRSG program, then presented an overview of EPRI Program 218, Heat-recovery steam generators, and research areas that include damage mitigation, improved performance, life management, flexible operation, and HRSG innovations. He included specific values gained from EPRI Program technology research activities. For more details, visit Program 218: Heat Recovery Steam Generators | Program Home (epri.com)

Today’s challenges

Tom Sambor offered an interesting assessment of the state-of-the-industry, and summarized HRSG infrastructure challenges (table), stating “Uncertainty is increasing; resources are decreasing.”

Sambor focused on the increasing need for an “integrated life-management” strategy, which EPRI has organized into seven parts. An integrated-life management approach for a component relies on, at a minimum, an equivalent consideration of mechanics (structural analysis, thermal hydraulics, etc), metallurgy, and nondestructive evaluation.

EPRI has numerous examples where each of these elements, he stated, are performed “poorly” by power generation service providers as they frequently lack a “rigorous approach.” See “Integrated Life Management of Grade 91 Steel Components: A Summary of Research Supporting the Electric Power Research Institute’s Well-Engineered Approach” for free download.

Sambor then reviewed how EPRI has a suite of information available for HRSGs that fits within each part of an integrated life-management strategy in detail.

Fundamentals. The “industry is reliant on NDE as the only tool in the toolbox,” despite industry codes and standards emphasizing the importance of materials testing and engineering evaluation, Sambor stated. He referenced a series of documents that the HRSG program at EPRI has on fundamentals, increasingly important because of the loss of both service-provider expertise and engineering and support staff within utilities.

Service experience. Sambor explained how the examination of unexpected, premature, or early-in-life industry failures has led EPRI to identify some components or systems as systemic “industry issues.”

Specifically, attemperators/desuperheaters, flat end closures, seamless and welded intersections, stainless-steel flowmeters, seam welded fittings/piping, small-bore DMWs, and, more generally, CSEF steels were all identified as industry issues relevant to HRSGs.

He identified that flat end closures, intersections, and attemperators/desuperheaters would be discussed as part of the day-long technology-transfer meeting because there have been recent and historical examples for each identified issue. See “Life Assessment Primer for Heat Recovery Steam Generator Internal and External Piping.”  

Specifications. Sambor next noted the increasing need for specifications that go above and beyond the minimum requirements in relevant HRSG codes and standards. Emphasizing this need is the fact that the previously discussed industry issues are typically associated with components that comply with the ASME Code.

To that end, EPRI has developed a range of guidance initiatives that includes product forms, processes, components, and plants. Sambor further explained that “EPRI is uniquely positioned to provide comprehensive technical assistance for material/component replacement or new construction,” including specification guidance.

Guidelines. Sambor then reviewed numerous guidelines focusing on strategies to avoid pressure-part failures—including those during startup and shutdown, HRSG materials selection, and operating HRSG drains, etc. He highlighted the need for reducing uncertainty and pointed to additional information available for that purpose.

NDE and FFS. Interesting discussions followed on nondestructive evaluation and analysis. Showing large-feature cross-welds in Grade 91 material, Sambor stated that there is “limited detectability of creep damage in modern alloys via NDE.”

He also stated that “NDE alone is not an adequate life-management strategy. Mechanics and metallurgy (at a minimum) must be considered, and the uncertainty in these areas needs to be reduced as much as practical.”

Further support for this statement: “A significant portion of the costs to perform NDE is for no-value-added activities such as scaffolding, insulation removal, surface preparation, and project management,” he explained.

He also addressed fitness-for-service (FFS), noting that EPRI has a large ongoing effort in this area. FFS methods developed as part of this work are being used for tees and other geometries. EPRI also has the capability, in its lab or otherwise, to subject components removed from service to post-mortem evaluation and analysis. See “An Informed Perspective on the Adoption of Comprehensive Fitness-for-Service in an Integrated Life Management Strategy.”  

Repair or replace. Decisions can be difficult, and repairs are “typically not one-size-fits-all.” Each needs to be engineered, but more critical is the determination of root causes. “Root causes must be identified and mitigated,” he said.

Sambor offered an extensive list of information that is available to assist in repair/replace decisions. Subjects include weld overlay, tube and tube-to-header repairs, steam turbines, fans, and deaerators. Another long list focuses on CSEF steel alternative weld repair and includes effects of filler metal or process, weld geometry, and other component specifics such as girth and dissimilar metal welds.

After outlining a multitude of research programs and results, Sambor stated that “research is not complete. EPRI continues to assess repairs on materials removed from service,” and encourages owners/operators to donate samples.

Technology transfer. Sambor concluded this section of the program stating that EPRI technology transfer includes numerous activities that are publicly available, such as:

• EPRI presentations at industry workshops.
• Participation in codes and standards.
• Published papers and articles to raise awareness.
• Industry alerts. See example here.

He then said that “Technology transfer is not a one-way street. Reach out to EPRI if you have experienced and/or identified a unique failure or have a question” (email ppa@epri.com).

New construction challenges

With modern gas turbines, exit gas temperatures of 1150F and steam temperatures of 1050F are exceeding the practical limits for Grade 91 steel (Fig 1).

So, the question becomes: “Do you (the owner/operator) opt for advanced stainless/higher chrome CSEF steels, or push the 9Cr performance envelope?”

Advanced alloys offer options, but also some learning curves. For example, there could be options when transitioning from stainless steel to CSEF steel within the HRSG (Fig 2). The transition shown could be in the piping (Option A) or in the tubing (Option B).

Said Sambor, “EPRI is aware of steam leaks or failures in each case” (Fig 3).

There are similar issues with tube oxidation/exfoliation (Fig 4).

Basically, care must be taken because modern gas turbines could be “abusing the HRSGs,” cautioned Sambor.

Header end caps

John Siefert next took the stage to discuss the state of knowledge and screening methodologies for header end caps, a growing industry safety concern. Flat-end closures are used in many HRSG headers primarily for their space-saving design (Fig 5). See “Life Management of 9%Cr Steels—Assessment of Header End Cap Geometries.”

While surface stresses can be high during startup and shutdown, which may lead to fatigue damage, the state of stress in the weld during normal operation also makes end caps susceptible to creep damage. EPRI is aware of failures attributed to both damage mechanisms. It is impossible to know if a failure is caused by fatigue or creep without a rigorous and integrated analysis of the root causes.

Case studies show that failure incidents are not new, and a few “catastrophic failures” were reviewed where the end cap was ejected without warning.

Siefert discussed the various end-cap designs and design rules, typical creep redistribution stresses, and cyclic operation thermal stresses, material chemical analyses, and typical inspection techniques.

EPRI’s recommendation is to implement an integrated life-management plan that considers the following:

• Geometric configuration (including fabrication quality).
• Design margins (excess thickness, for example).
• Operating conditions (temperature imbalances and transients).
• Metallurgy and risk (deformation and damage susceptibility).
• Access for inspection, including where resulting damage is likely to occur.
• Lifetime predictions.
• Consequences of failure including plant operations and personnel.

Recent activities

Sambor returned to the podium to review the global installation totals for 9Cr steels, both Grade 91 and Grade 92. The totals include more than 1000 supercritical and ultra-supercritical steam systems and more than 2600 combined cycles installed globally in the past 25 years.

Several factors, including material ductility, can compound and increase the risk to rupture for these materials (Fig 6).

Two interesting points:

• For most of the ASME Boiler and Pressure Vessel Code’s existence, the use of ductile materials has largely protected the industry from widespread creep concerns in the high-temperature regime.
• If materials are to be classified by Section II as possessing low creep ductility, then an optimized set of design rules should be invoked by Section I to responsibly design safe structures, as there is no explicit design life.

Noted Sambor, “The thrust behind Grade-91 Type-2 composition was to reduce the future population of low-ductility heats.”

After reviewing Code Case 3048, Design rules for CSEF steels which are creep intolerant for construction (May 4, 2022), he summarized: “Extensive challenges remain to improve design rules for complex materials, structures, and operating modes.”

He then presented a recent case study of a reheater tube-to-header failure to emphasize the importance of rigorous analysis. Sambor recalled that he once shared photos of the failure with several individuals and asked their opinion on what caused the failure; all were quick to attribute the failure to fatigue. He then showed various metallographic sections of the failure, all of which illustrated that the failure region was “loaded” with creep damage, indicating the failure was due to creep rather than fatigue.

The importance of this determination, Sambor emphasized, is that the utility/plant now is aware of a systemic problem (attributed to component configuration and operating conditions) rather than a one-off failure.

He finished off the discussion on high-temperature components with a presentation on new efforts towards online creep and fatigue damage trending of HRSG components and the development of various web-based calculators available through EPRI.

Tee intersections

Siefert returned to discuss another Safety Alert for steam leaks in high-temperature intersections, specific to tees.

An EPRI Industry Alert, Seamless tee intersections, was issued February 2023, suggesting that a single unit generally may have four to eight at-risk tees.  See Fig 7 for terminology. Discussions covered damage mechanisms, design, fabrication, operation, and metallurgy.

The damage mechanism discussion concluded that all the tee steam leaks to date could be attributed to the creep mechanism. Siefert emphasized that external metallurgical laboratory evaluation has also reached that same conclusion.

One reason for creep-related failures associated with these tees is inadequate design requirements, which may result in a lack of reinforcement and/or significant variability between supposedly identical tees.

In terms of fabrication, Siefert highlighted that the steam leaks “do not suggest gross issues linked to shop or field post-weld heat treatment,” which is a common concern with CSEF steel material. He instead identified a case where a tee crotch weld repair was performed and another case where a vee shape was roughly machined into the ID surface of the tee crotch, both fabrication issues that have affected the lives of tees.

Operation discussions summarized that units with tee steam leaks have all been operating within their design envelope (that is, operating below their design temperature/pressure), and summarized analyses that EPRI has performed to determine if cyclic operation (fatigue) is a concern.

For one case study analyzed, there is no evidence that the inelastic strain range calculated during cyclic operation would result in fatigue cracking within the number of cycles the tee has experienced, and there was no evidence to support ID-initiation for any of the observed damage.

Siefert finished the tee discussion on the topic of metallurgy, where he detailed a recent failure that is the first reported tee steam leak in a Grade 22 system, which means that this industry issue is not isolated to only CSEF steels. He also highlighted a case study where a tee was found to be the incorrect alloy, X20 rather than Grade 91, and emphasized the importance of positive material identification (PMI) on tees in the field for this reason.

Finally, Siefert emphasized the importance of metallurgical risk on CSEF steel tees by illustrating how the time-to-creep crack initiation could decrease by a factor of 10 because of increased metallurgical risk.

Attemperators/desuperheaters

Sambor covered common approaches for diagnosis and mitigation of attemperator damage issues using historian data, instrumentation, metallurgical analysis, and operating data.

In his first example, he illustrated how a review of historian data revealed “several easy to identify, detrimental phenomena occurring.” Further, he explained how historian data can be used to perform an energy balance around the attemperator to determine if a detrimental condition exists, and mentioned that EPRI has a tool available for doing so.

In a second example, Sambor emphasized the importance of adding surface-mounted thermocouples at select locations upstream and downstream of attemperator piping for improved attemperator diagnostics. He showed how, in one case study, the historian data did not indicate an issue with the attemperator, but thermocouple data on the downstream elbow did reveal that relatively cool spray water was impinging on the relatively hot piping, which is a thermal fatigue concern that has resulted in steam leaks.

Since a concern with adding more thermocouples often is how to collect the data, Sambor mentioned that EPRI has developed a low-cost data logger for doing so. Finally, he emphasized that some issues with attemperators could be associated with less-than-ideal operational strategies, such as trying to roll the steam turbine with a too-high gas-turbine exhaust gas temperature.

Sambor finished the topic with a recent bypass desuperheater case study that involved laboratory evaluation and an analysis of plant operating data. He highlighted how easy it has become to analyze what he labels “big-data” from the plant (data evaluated was for dozens of tags at one-minute intervals for a calendar year) and the importance of doing so; the operating data he illustrated revealed the same detrimental patterns occurring for most startups and shutdowns, rather than just the occasional occurrence.

Low-temperature components

Sambor finished the day by leading a discussion on HP drums. Based on the comments made by attendees, it was clear that additional technology transfer around integrated life-management strategies for drums was necessary. This will be included in a future HRSG Forum event.

Steven C Stultz, Consulting Editor

Barry Dooley, Structural Integrity Associates (UK), opened the Cycle Chemistry Workshop on Day One of the HRSG Forum’s 2023 Conference and Vendor Fair, June 12 – 15, at the Renaissance Atlanta Waverly, with Film-forming substances for combined-cycle/HRSG plants: History, background, and needs.

He first presented IAPWS nomenclature background for film-forming substances (FFS), made up of two categories:

• Film-forming amines/amine products (FFA/FFAP).
• Proprietary non-amine-based film-forming products (FFP).

Most experience to date, he explained, is with the first category. Dooley then gave clear visual representations on FFA chemical structure (Fig 1) and the common topic of hydrophobicity.

One overall caution came early: “Dancing water balls,” he explained, “are thought to indicate protection, but we now know that hydrophobicity does not necessarily mean protection” (Fig 2). This would be explained further with examples, such as Fig 3. In these conventional subcritical-plant reheater tubes, the example on the left was dosed with a non-amine FFP. The example on the right was never dosed with any FFS.

Dooley clarified that “It is unclear if hydrophobicity is a key aspect of corrosion control. In solution, some FFAs can actually be hydrophilic and increase surface wetting.”

This message reinforces the complicated nature of simple visual assumptions.

Detailed FFS background is available in Film-forming substances: Sixth International Conference, CCJ No. 75, p 75, and A wakeup call on film-forming substances, CCJ No. 60, p 12.

One important presentation takeaway was the list below of “Key highlights from fossil and combined-cycle/HRSG FFS applications”:

1. There are universal reductions (measured) in feedwater Fe and Cu transport, but “no equivalent understanding” of the mechanisms of oxide growth reductions.
2. There are general (visual) observations of hydrophobic films on water-touched surfaces, but “it is underlined that hydrophobicity does not prove presence of a film or any protection.” Refer back to the sketch of control angle in Fig 2.
3. There is generally good shutdown protection of water-touched surfaces.
4. Film formation remains “very questionable” on steam-touched surfaces.
5. Studies of adsorption of film onto metal surfaces as a function of FFS hopefully will provide information for changing the FFS applied.
6. Arresting flow-accelerated corrosion (FAC) is difficult to “see” other than by reduction of iron. Air-cooled-condenser corrosion/FAC is the exception. See report ACC.02: Guidelines for internal inspection of air-cooled condensers, available at no cost on https://acc-usersgroup.org
7. There are FFS application problems reported in some plants worldwide: internal deposits, tube failures especially under deposit corrosion, formation of “gunk” (gel-like) deposits in drums and on heat transfer surfaces, in steam turbines, and strainers/filters. Dooley offered detailed examples.

Looking forward, Dooley outlined the “path to needed research.” Clarifying first that most work to date has been with metal surfaces rather than oxide surfaces in operating plants, Dooley highlighted the need for fundamental work on the “effect of FFS on growth mechanisms of Fe, Cu, and Cr oxides in water and steam.”

Similarly, “much work is needed in the future on the effect of a wide range of FFS additions to allow more rugged and permanent advantages such as the ability to change from one FFS to another.”

Current activity and discussion are the pathway to an IAPWS Certified Research Need (CRN) by the International Association for the Properties of Water and Steam Power Cycle Chemistry Group.

In summary, he stressed application of two key rules, as the industry awaits a more complete understanding:

Rule 1, Make sure plant chemistry is optimized before application of an FFS.

Rule 2, Conduct a comprehensive review before any FFS application. Refer to IAPWS TGD8-16 (2019), Application of film-forming substances in fossil, combined cycle, and biomass powerplants, in particular Section 8, available gratis at http://iapws.org.

Doug Hubbard, retired manager of Chemical Engineering at American Electric Power, followed Dooley with Do you need a film-forming substance? How do you know?

He discussed corrosion protection during layup conditions, outlining AEP’s guidelines to stop offline corrosion. Principal AEP options are:

1. Dry layup: Completely remove and keep all water and moisture off metal surfaces (ideal relative humidity: below 40%).
2. Use FFS to keep water from coming in contact with metal surfaces.
3. Wet layup: Remove and keep all oxygen out of water. Use nitrogen blanket.
4. Keep fluid moving.

These are in order from best to worst, but “any one of them is better than doing nothing,” stated Hubbard. He also reviewed “layup stumbling blocks,” such as on-line schedule uncertainties.

He then covered standard “corrosion protection during operation,” citing the IAPWS limits for total feedwater iron:

• Economizer inlet OT < 1 ppb (actual, optimized < 0.5 ppb).
• Economizer inlet AVT (O) < 2 ppb (actual, optimized < 0.5 ppb).
• Economizer inlet AVT (R) < 2 ppb (actual, optimized < 2 ppb).

One basic test shown for iron is the Millipore: snow white should indicate optimized corrosion protection (Fig 4). Said Hubbard, “I have never seen Millipores snow white and total iron not meeting IAPWS limit.”

So, the question on need for FFS remains.

He then offered some “experienced-based opinions:”

1. Layup protection:

• If capacity factor is below 15%, FFS will not have time to “film cycle.”
• If capacity factor is above 60%, FFS could be too expensive to feed.
• If unit runs hard and is then down for a long period of rime, this could be an ideal use of FFS.

2. In-service corrosion protection:

• FFS is not needed for AVT O/OT units.
• If there is significant two-phase FAC, FFS could be part of the solution once cycle chemistry is optimized.

3. Failure mitigation with FFS:

• Good option for pitting attributed to oxygenated stagnant water.
• Unclear for pitting due to chloride/sulfates.
• Unclear for under-deposit corrosion.
• No known value for existing corrosion fatigue (driven by strain).
• However, if you are trying to prevent corrosion fatigue, FFS may be of value by slowing down the corrosion part of corrosion fatigue.

Hubbard ended with important guidance: “Make sure you define clearly with your FFS manufacturer the goals expected while feeding FFS, with very specific measurables to determine if goals are being met. The FFS manufacturer needs to sign off on these goals and measurables,” he emphasized.

David Little and Bruce Opsahl, Nalco Water, were next with HRSG protection with Powerfilm™ 10000, a non-amine FFS. While outlining the various reasons for considering filming technology, Little emphasized that FFS applications are “not a substitute for a good base steam-cycle chemistry program.”

Nalco introduced Powerfilm 10000 as “a non-amine filming corrosion inhibitor designed to protect powerplant boiler systems from offline corrosion and stresses caused by cyclical operation.”

Little and Opsahl offered a case study of a 2 × 1 combined cycle in north Texas where market-driven layup practices had raised concerns about asset longevity. The plant faced wet layup of the HRSGs for long periods of time. A program was launched to reduce corrosion product transport, measured as total iron, to 5.0 ppb (EPRI action level).

Powerfilm was injected at the condensate-pump discharge. A low continuous dose (0.4 to 2.0 ppm based on feedwater flow rate) was applied during baseload operation, cycling load, and two–shifting on/off with hot standby. A high continuous dose (5 to 10 ppm) was applied for several days prior to shutdown and wet layup (1 month or less) or dry layup.

Using an online laser nephelometer, 3000 iron concentration data points were collected over a four-month period (Fig 5). Filter pad (Millipore) grab samples also were used.

Their summary of results showed that the nephelometer gave economic, portable, real-time collection of iron transport data, and concentrations remained below the target. Also, “iron reduction continued despite increased cycle events of the steam turbine.”

Dale Stuart, ChemTreat, then presented The use of FFA to mitigate corrosion in HRSG units and offered various examples in the US. He said the purpose is to “provide a passive layer when conventional chemistry fails.”

Based on the examples shown, Stuart summarized that:

1. The FFAs used formed a bonded layer of persistent film.
2. The FFAs were volatile and traveled through the system.
3. Treatment was thermally stable, but required increased dosage at higher temperatures because of its higher volatility and desorption coefficient.

Eric Zubovic, Veolia, then discussed the Impact of film forming amines on condenser efficiency concluding that use improves condenser performance by promoting dropwise condensation on the tubes. He concluded that polyamine (FFA) increases heat-transfer efficiency, noting that a continuous feed (at the proper feed rate) is needed to maintain dropwise condensation. He also concluded that “turbine backpressure can be improved between 0.42 and 0.60 in. Hg with dropwise condensation.”

Chris Dumas, Kurita, presented Cetamine® treatment of an HRSG in Spain, a presentation also made at the 2023 IAPWS International Conference on Film Forming Substances. His conclusions: (1) Cetamine G85X is offering beneficial protection during cycling operation and preservation periods. (2) It can be used as an additional treatment to conventional AVT or AVT+PT. (3) It has reduced startup times and use of blowdown. For more detail, see Film-forming substances: Sixth International Conference, CCJ No. 75, p 75.

Many interesting questions and discussions followed these presentations. Topics included good chemistry versus FFS in a new baseload plant, FFS selection for cycling units, iron sampling processes including filters, methods of pH control, and FFS versus changes to materials.

Dooley’s Q&A summary: “Excellent questions; we know that many plants do not do their homework before application of an FFS. The pre-application process is the most important, and it is critical to first review IAPWS Technical Guidance Document TGD8-16 (2019),” freely available at www.iapws.org.

Contact Dooley (bdooley@structint.com or bdooley@IAPWS.org) for further information on FFS and the IAPWS FFS conferences.

Steven C Stultz, Consulting Editor

The afternoon workshop on Day One of the HRSG Forum’s 2023 Conference and Vendor Fair, June 12 – 15, at the Renaissance Atlanta Waverly, focused on welding and metallurgy. It was a combined effort among Jeff Henry and Kevin Hayes, Applied Thermal Coatings, and Amy Sieben, Industrial Air Flow Dynamics (IAFD) and had the official title Powerplant materials, welding, and welding engineering support: What the industry-wide loss of expertise means for plant owners and operators.

Henry began with what a recent failure suggests about the state of our industry. It concerned the failure of a 10-in.-diam tee after 80,000 hours of service (Fig 6). The component, from a 635-MW coal-fired boiler producing steam at 3700 psig/1050F, suffered a through-wall crack at the crotch position on one side of the tee, and another partially through-wall crack on the other side, both ID-initiated.

Also, cracks at the toe of both the run and branch girth welds were OD-initiated.  Multiple tees on two other units suffered similar creep-related damage.

The material specified was Grade 91. Units were built “to Code,” but analysis found that the materials did not match the plant’s RFQ specifications, although they “came from a reputable OEM.”

Other materials discrepancies were found at the plant.

This is just one example of multiple tee failures in multiple units in the US, and “EPRI has estimated the number of tees potentially at risk could be in the thousands,” Henry said.

Historical perspective 

Years ago, the US electric power industry was seen as a vital component of the economy. “To that end, the industry was regulated to control the risk to which utilities could be exposed and to provide a level of financial security that would encourage investment in the resources (people, equipment, etc) necessary to ensure an ample supply of power,” explained Henry.

This arrangement, he said, “benefited not only the utilities but also the companies that supplied the major plant components—including the steam generators and the turbine/generator equipment.”

OEMs became comprehensive service organizations capable of addressing all aspects including design, manufacturing, erection, commissioning, operations, and materials expertise. OEMs also provided detailed supplier oversight, and direct participation to ensure quality.

“With deregulation, the OEMs’ service capabilities were gradually dismantled,” he said.

Henry then reviewed the ASME Boiler & Pressure Vessel Code, stating that “from the beginning, the focus was on safety. Code was not intended as a design handbook or manual for best manufacturing practices. Design and manufacturing for efficiency and reliability were the OEM’s responsibility,” he explained. The OEMs also provided extensive support to, and participation on, the Code technical committees.

Henry further explained that the ASME Code is for new materials (that is, construction). Repair is in accordance with the National Board Inspection Code (NBIC) and the National Board of Boiler & Pressure Vessel Inspectors.

Today, plant operators are looking for assistance and are often left to choose from a “small pool of technical resources with more narrowly focused capabilities,” particularly regarding materials, welding, and welding engineering. University programs, he further suggested, are also becoming more specialized.

“Plant operators themselves are already stretched to the breaking point,” he added.

Pressure-part materials

Henry turned to a comprehensive overview of some of the more important metallurgy issues encountered in today’s powerplants. He focused on:

• Principles of ferrous metallurgy.
• Pressure-part life and creep (Fig 7).
• Creep damage in welds.

He entitled his presentation Pressure part materials—the basics, but it was quite detailed and comprehensive in the areas of ferrous metallurgy (crystal structures, etc), martensite/pearlite/bainite, microstructures and properties, defects (“all materials contain defects”), hardenability, alloying of steels, common pressure part materials (carbon/low-alloy/CSEF and austenitic stainless steels plus “unwanted but tolerated residual elements in the ore that came along for the ride,” pressure part life and creep, and the structure of welds.

This was all what he called “an overview of some of the more important materials issues faced by plants today.”

Kevin Hayes followed with a discussion on welding and welding engineering support, specifically What industry-wide loss of expertise means for plant owners and operators.

“There is currently a shortage of welders in the US, and the potential shortfall of welders needed by 2027 will be 360,000, according to workforce data provided by the American Welding Society. Potential negative effects of a reduced labor pool include the following:

• Increased potential for weld-related defects.
• Competition by employers for limited resources.
• Use of automation, resulting in less hands-on skilled welders.
• Potential impacts on outage schedules.

He offered an interesting sidebar caution: “Temporary repairs tend to become permanent.”

Hayes also had several suggestions on the path forward, stating that one competitive advantage will be to have multi-skilled team members (print reading, multiple welding and heat treatment processes, weld machine programming, multiple weld repair processes, etc).

“With the welding and welding engineering support shortage,” he said, “tomorrow’s team members will not be the same as the previous generation’s team members.”

Hayes then turned to detailed looks at potential welding defects, and the best methodology for executing an effective weld repair, including but not limited to:

• Understand the root cause of the damage or failure and base-material composition.
• “Sample, sample, sample”—boat samples, in-situ replication, visual and other testing.
• Evaluate previous repairs.
• Consider original design, fabrication, and current operating conditions.
• Define the proper repair method, work scope, and resources required. Creep-related damage, for example, may require full excavation of damage (Fig 8).
• Execute the plan, then document what was performed and lessons learned.

Another key point: “Be prepared to expand the repair scope to address unexpected conditions.” And most important: “Verify personnel have received proper safety training.”

He then reviewed “NBIC Repair and Alterations, Part 3, Welding Method 6 and Supplement 8 Requirements.”

Pressure-part replacements

Amy Sieben followed with HRSG pressure-part replacements. Citing the age of many units today, she addressed the increasing need for component replacements.

Sieben listed the following as the primary common mechanisms for pressure-part failures:

• Flow-accelerated corrosion.
• Under-deposit corrosion.
• Fatigue cracking.
• Corrosion fatigue/chemical attack.
• Creep/fatigue interaction.
• Dew point corrosion.

This led to discussions on replacements versus chemical cleaning, and the opportunities for material upgrades.

Case studies offered interesting looks at access, trolley systems and lifting/turning frames (Fig 9). Many examples are shared in the presentation.

Other case studies were given on tube and header replacements, NDE and post-weld heat treatment, tube plugging and repair methods, types of tube-to-header welds and weld preparation, and tube restraints.

Sieben then reviewed “the other 10% of failures”—such as baffle/casing systems, desuperheaters and drains, duct liner and expansion joint failures, GT exhaust frames, blowdown piping, etc.

She ended with advanced NDE detection methods, removal and inspection, thermal imaging, radiography, and use of drones.

There are several reasons stacks don’t get much attention from operators on their rounds—among them:

• They’re static and there’s nothing much to see externally except perhaps peeling paint.
• Forgetting the switchyard, they’re likely a longer walk from the control room base than any other plant component.
• Internal access is not possible with the plant in operation.

This means you don’t know much about the true condition of your stack unless you make it a priority to conduct an internal and up-close external inspection annually. Regular inspections can identify problems before they cause an outage, a loss in performance, potential safety issue, etc.

SVI Dynamics’ Scott Shreeg identified several common failure points for a steel stack to be aware of when conducting your annual inspection (photos). They are:

• General corrosion.
• Stress or fatigue cracks caused by repetitive or excessive movement. These usually develop at openings or discontinuities in the metal.
• Buckling of the stack shell caused by corrosion thinning of the shell material.
• Cracking of the stack shell and its support structure from fatigue attributed to thermal cycling.

Annual inspection checklist

When perusing the list below keep in mind that the inspection and maintenance programs for unlined stacks (single wall) and stacks with a floating liner differ in some respects.

• Check bolts and nuts for degradation—including anchor bolts, those restraining platforms and ladders, etc.
• Examine the following for general condition, plus any evidence of corrosion and cracks in base metal and welds:
  • • Baseplate.
    • Anchor chairs.
    • Breech opening reinforcement.
    • Shell plate.
    • Circumference stiffeners.
    • Shop and field joints (welded and bolted).
    • Lateral supports.
    • Access doors.
    • Dynamic stability devices.
    • Exterior conditions of test ports.
    • Exterior lagging.
    • Expansion joints.
    • Grounding lugs and cables.
    • Guy wires (visual check for degradation and broken wire strands), cable clamps, and anchors.
    • Platforms and ladders: gratings, handrails, and platform supports.
    • Outer shell-plate coating.
    • Concrete foundation. If cracks are large, a follow-up concrete NDE may be necessary.
• Thermal imaging is recommended when the inspection must be performed with the unit in service. It is particularly helpful for detecting areas where excessive heat transfer exists because of liner or lagging insulation loss.

Triennial steel-stack inspection

• Visual inspection of shell plate for the full height of the stack.
• Random ultrasonic (UT) shell-plate thickness measurements every 10 ft from the bottom of the stack to the top.
• Follow-up with penetrant or UT inspections of questionable welds.
• Full-height interior visual inspection, including expansion joints.
• Drainage condition.
• Condition of silencers and their supports.
• Condition of turning vanes, flow dampers, and stack rain cap.
• Visual inspection for internal floating liner sheets, studs, insulation, batten channels.

When your stack needs go beyond simple inspection

SVI Dynamics has more than 25 years of experience in steel stack design, fabrication, construction, and inspection. This means the company can be a valuable partner for your plant, given its ability to determine the root cause of stack issues uncovered during an inspection and to suggest solutions using today’s most advanced engineering analysis software.

The company’s inspections are conducted to the widely accepted ASCE stack inspection code, with enhancements based on SVI’s experience. Inspections are supervised and reviewed by a registered professional engineer with details provided to the plant.

Inspection reports include the details of stack measurements taken, a summary of root-cause investigations conducted in response to defects found (if any), engineering calculations as needed to support decisions regarding stack structural integrity, and recommendations for follow-up inspection, repairs, and replacements.

By Vaughn Watson, Vector Systems Inc

The performance of an SCR system depends on the robustness and efficiency of the sum of its parts. The flow-distribution devices placed into the exhaust stream are no exception. Each of the critical parts of the system must be designed and built to effectively provide the proper distribution and mixing for the catalyst to perform the required reaction with minimal bypass and carryover.

The catalyst tends to get all the credit for singlehandedly achieving emissions goals, and all the blame when there are performance issues. But the SCR is a system that has several key components.

Every manufacturer sizes the required volume of catalyst to achieve the performance based on parameters such as exhaust flow and emissions-reduction efficiency. To achieve this, the catalyst needs a required set of parameters—typically velocity profile (nominally ±15%), temperature profile (nominally ±25 deg F), and NH₃:NOₓ maldistribution (<10% RMS).

In a simple-cycle gas-turbine application, the exhaust flow to the SCR system poses a particular set of design considerations for the unit to operate effectively. Consider that designers are dealing with a turbulent high-temperature exhaust stream—one resembling a tornado—that must be cooled to the proper temperature, distributed uniformly across the cross-sectional area of the catalyst bed, and mixed effectively with ammonia for the catalyst bed to achieve the required NOₓ reduction efficiently.

Most simple-cycle applications involve the introduction of a significant amount of ambient air to cool the turbine exhaust gas down to a temperature that the catalyst can safely handle based on its formulation.

The cooling air must be mixed with the turbulent exhaust gas to achieve the desired temperature. The cooled exhaust stream then must be straightened and spread out so the velocity and temperature requirements of the SCR catalyst are met across the catalyst bed. Depending on exhaust-duct cross-section, this can create a geometrical challenge for gas flow traveling to the catalyst.

The common practice is to use a perforated plate as a flow-straightening device. Perf-plate design is essential to proper exhaust-gas distribution. The perf plate has a pattern of holes across the exhaust cross section to force the gas to flow through an open-area pattern, also known as hole porosity. This creates about 1 in. H₂O backpressure to mix the flows from the gas turbine and the cooling-air system, and to straighten the combined flow through the hole pattern of the perforated plate.

Simple-cycle exhaust ducts that have steep approach angles to the catalyst bed often require a more sophisticated perforated plate design—one that features variable open-area sections to push turbulent exhaust flow upwards toward the ceiling and corners of the exhaust duct.

The perforated plate lives in a very torturous environment because of the high velocities, high temperature gradients, and backpressure putting mechanical and thermal stresses on the flow-straightening device and its frame. Thus, careful design, robust framework, and heavy-gauge plate are required (Fig 1). Care must be taken to manage thermal growth without binding.

Strength is important. This is why corrugated bent perf panels often are used to add rigidity to the perf-plate sheets—to stiffen them (Fig 2). Light-gauge plates and floating angle supports are not up to the task of restraining anywhere from 1 million to 5 million lb/hr of exhaust flow.

If your SCR system is not meeting expectations, consider engaging a consultant with years of relevant design and problem-solving experience to review your situation and develop a plan to improve its performance.

The headline should not surprise any reader of the COMBINED CYCLE Journal. It’s a “given.” The challenge is how to maximize the saving at the least cost.

Until relatively recently, the widely preferred method for cleaning tubes in heat-recovery steam generators serving cogeneration and combined-cycle plants was dry-ice blasting. It effectively dislodges iron oxides, ammonia salts, and other foulants which drop to the floor and are shoveled into barrels for removal offsite. However, dry ice only reaches what it can “see.” Plus, the longer it sits at the plant awaiting use, the less effective it is.

Today, there’s a promising new option to consider—KinetiClean™. It’s getting positive reviews from owner/operators and industry experts, such as EPRI (results are available through the research organization’s HRSG program for members). The name derives from a patented shock-wave technique now owned by Groome Industrial Service Group, one of the pioneers in dry-ice blasting.

KinetiClean is a three-step process. First, shock waves created by a det-cord curtain (Fig 1) dislodges deposits from the HRSG’s tubes, then compressed air removes any loosened deposits that remain (Fig 2), and the floor is vacuumed clean.

Of importance is that detonation (a/k/a det) cord is a flexible linear explosive having a core of PETN (chemical name: pentaerythritol tetranitrate) encased in a textile outer jacket—it is not dynamite. Also, that the explosive does not come in direct contact with any plant equipment.

Regarding the safety aspects of PETN, keep in mind that it is installed and detonated by a team of well-trained licensed professionals. That it is “safe,” consider that KinetiClean has maintained an enviable EMR rating of 0.81 for the last couple of years. The Experience Modification Rating is a calculation used by insurance firms to determine workers’ compensation premiums. A rating less than 1.0 generally is considered good, or relatively safe.

Access a short video explaining the KinetiClean process. More detail—including actual footage of tube cleaning—is presented in the recorded webinar, “HRSG tube cleaning technology.”

The major advantage KinetiClean has over dry ice, based on Groome’s research and experience, is that it recovers about 75% of the backpressure lost to the deposits; dry ice typically recovers 30% to 50%.

Two case histories summarized in the webinar offer some insight to the results possible by implementing KinetiClean. The first concerned a 7EA-powered cogen unit that had not been cleaned in its 20-plus years of service. It had been derated to operate at 75% of its baseload rating and was in jeopardy of not meeting its contractual requirements.

The facility was able to return to baseload operation following eight 12-hr shifts of cleaning activity. Other results: 6 MW was recovered, stack temperature reduced by 12 deg F.

Case-history 2 compared the results of cleaning with dry ice and KinetiClean. Experience with dry-ice blasting of the HRSG behind an SGT6-5000F gas turbine indicated a pressure drop of 2-in. H₂O was to be expected. Six 12-hr shifts with KinetiClean reduced backpressure by 3.6 in.

The Groome team said a pressure drop of 3 in. offers an extremely good ROI. In this case the estimated annual fuel saving was $315,000, the estimated annual energy saving was $185,000.

To determine how much you might save by using KinetiClean, a calculator is incorporated into the YouTube video.