F-Class CCGT Power Plant For Sale

COMBINED CYCLE POWER PLANT FOR SALE

395-MW, 1×1 CCGT plant with GE 9FA gas turbine,
GE D-10A steam turbine, Alstom HRSG

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Diffuser-duct upgrade mitigates 7FA exhaust-system reliability concerns

Consulting Editor Steve Stultz’s reports on the last HRSG Forum with Bob Anderson and Australasian HRSG Users Group annual meeting discussed ageing issues associated with steam systems installed in the late 1990s and early 2000s. As these systems in combined-cycle and cogeneration plants reach half-way in their design life, overheating of all components has become a growing concern. High operating temperatures and gas flow velocities are taking their toll.

Rich Miller, a site technical advisor for HRST Inc told Stultz that a common 7FA diffuser-duct inspection discovery is loose or broken studs, those components that secure the liner plates and C-channels within the casing. A typical diffuser-duct liner installation can have 1500 to 2000 (or more) studs. Traditionally, the studs are welded to scallop bars, imbedded in insulation, and, in turn, welded to the casing. The studs secure the liners, while allowing them to expand and contract with temperature changes.

The first key indicator of a problem is loose or broken studs—often 10 to 20, or more, per inspection. As one owner/operator reports, “It starts with a few broken studs, and there’s never a real budget to fix that stuff. You do what you can.”

The result can be improper (incomplete) repair, perhaps more cosmetic than structural. As one technician puts it, “You’ve got limited time to do 20 studs. So you weld them up and get out of there.” But the loose or broken studs could indicate something much more severe.

Another clear and related damage indicator is liner sheet fatigue cracks propagating from the stud holes (Fig 1).

Scallop bars and temperature. HRST has seen a lot of this, according to Miller, “Most scallop bars either are of the single-stud or three-stud design, and the duct designs we’ve changed out are predominantly scallop bars in segments of varying length.”

Discussing the effects of operations and temperatures, he explains “The bottom of the scallop bar welds to the casing and is buried in insulation. The top is where the studs attach, so there is a radical temperature difference between the bottom and the top.”

The top experiences typical 7FA exhaust temperatures of 1100F to 1200F. The bottom will be at 200F to 300F, or less.

Miller points out, somewhat in its favor, that “the scallop bar design works well—until the bars start breaking, as Fig 2 illustrates.” This is where both age and temperature change can create the problem, and cycling can accelerate the damage.

Most scallop bars are Type-409 stainless steel (same as most liner plates). The studs are Type-304 stainless steel, normally welded with more temperature-resistant Type 309. The expansion rates are not compatible and the welds fail. But the problems are not only with the welds. Once a scallop bar breaks, it vibrates. And for all diffuser-duct materials, fatigue strength decreases with temperature.

If plates and C-channels begin to work loose, insulation materials can be released and can foul the tubes and catalysts. As Miller puts it, “The only way to know what’s going on under the liner is to tear it apart.” That’s precisely what HRST did at an installation in Iowa.

HRST’s first 7FA diffuser-duct redesign/retrofit was at a 2 × 1 system commissioned in 2004. Stud failures began 2005, but the frequency increased steadily. By 2013, with the number of stud failures continuing to escalate, the owner/operator became concerned about possible scallop bar cracks hidden under the liner materials.

In 2015, one unit experienced liner-sheet liberation, causing a forced outage. The liberation led to immediate insulation fouling of the CO catalyst, and a backpressure jump of 4 in. H2O. Outage costs included both liner repair and catalyst cleaning, and operators became wary of repeat events.

The site had recorded stud repair data for each unit through each maintenance outage, and kept an accurate cost history. Upgrade justifications included annual stud and liner repairs, scaffold costs and time, backpressure-induced derates, catalyst cleaning costs, and a recognition that previous repairs were not addressing the root causes.

Owners ordered an upgraded diffuser-duct insulation and liner system from HRST, which had proposed eliminating the scallop bars. Instead, HRST would use one of its liner stud types, namely shoulder studs and square washers. In the end, the studs work “independently,” says Miller, which “removes the whole thermal expansion issue. The top of the stud does not care what the bottom is doing.”

Demolition began, and stripping off the old liner plates revealed that most of the scallop bars were either cracked or broken.

Future stud and liner failures were just waiting to happen, explains Miller. “Some might say a repair has lasted a couple years and they would hope to get another five out of it. I don’t think it works like that. Once the bars start breaking, the failure rate can radically increase. It could be twice as bad in two years instead of five.”

Pre-planning was important for both materials and contractor selection. Early award of liner design allowed installation drawings to be part of the contractor bid package, and materials were ordered months in advance. This reduced unknowns and potential supply issues, and allowed meetings to begin with the installation contractor.

After demolition, crews supervised by HRST installed the bottom half of the liner first. Because the scallop bars had been eliminated, studs were welded to the casing one at a time in a density for heavy duty service (Fig 3).

Then, with the lower half complete, scaffolding was erected on the new liners and upper-half work began, first the studs, then the insulation, and finally the liner panels and corner angle.

“It’s a complicated geometry,” notes Miller, “round and tapered with an expansion joint to work around. It’s like a cone with the end cut off. And you can’t rely on the original drawings to get it just right. Early hands-on inspection and measurement are critical.”

The diffuser-duct sections at this site are unusually long (total 31 ft), but the process would have been the same for a more traditional 19-ft installation. The first replacement, completed on schedule, has now been running since 2016.

After these two units, HRST performed diffuser duct retrofits in Georgia then moved to Wisconsin, to a 2 × 1 7FA.03-powered combined cycle that began operating in 2004. Both units received diffuser-duct replacements in 2018.

By this time, each HRST project had gained efficiency from experience. The first unit in Iowa was completed in three weeks working two shifts around the clock. The first Wisconsin unit was completed in about three weeks working one 12-hr shift. The second unit was completed in 15 working days, Monday through Friday, one 10-hr shift per day.

But the design had also changed.

“At the first Iowa unit we put the studs in one at a time. But in Wisconsin we decided to put these on a bar fabricated previously at a shop. The bars are however long they need to be, based on the geometry. The weld point in the field then becomes bar plate-to-casing.”

He continues: “The studs upstream to downstream are evenly spaced, but the distance in the lateral position upstream to downstream can be different stud-to-stud (perhaps a sixteenth of an inch). And the liner sheets reflect that. We pre-design and pre-make the liner sheets and stud bars, and the vast majority don’t need any trimming. There is just some custom fitting.”

Ya’ gotta’ listen. “A lot of the details become even more clear with experience,” reflects Miller “And at our most recent site we had a 28-year-old foreman, sharp as a tack, who wanted to show the world we could do this more efficiently.” The result was an innovative scaffold system that allowed multiple, simultaneous activities (Figs 4, 5).

“They put some outriggers on the interior side of the duct,” explains Miller, “and they outfitted it so we could work on the top and the bottom at the same time. This was huge!”

“It’s like a suspended scaffold,” noted the owner/operator. “You can work top and bottom at the same time, and there’s room to get more people in there than you would think.” States Miller, “Each job is contractor-dependent, and you need to listen to everyone’s ideas.”

To learn more about diffuser-duct retrofits and other HRSG topics, connect with the HRST team at the upcoming annual HRSG Forum with Bob Anderson (Hilton Orlando, July 22-25) where you’ll find HRST’s boiler experts in Booth 412.

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Acoustic leak detection benefits boiler owners, but not all systems are HRSG-qualified

Independent users groups serving owner/operators at cogeneration and simple- and combined-cycle plants powered by gas turbines are an invaluable resource for station personnel. Almost all have online forums available 24/7/365 to help answer technical questions quickly and get you moving in the right direction with possible solutions. Most colleagues offering their unbiased assistance have deep O&M experience and understand your challenges; plus, there’s no charge for their help.

Power Users, the umbrella organization providing administrative support for the 7F, Combined Cycle, Generator, Steam Turbine, and Power Plant Controls Users Groups operates online forums for each of those organizations. Plus it collaborates with the HRSG Forum with Bob Anderson on an online discussion forum focused on heat-recovery steam generators. Anderson is the discussion moderator. Register today to participate at www.powerusers.org.

Recently, a user asked for advice through the forum on an acoustic leak detection system described in a brochure. Just so happens that Anderson has first-hand experience with instrumentation for detecting boiler leaks. By way of background, he managed both conventional steam and combined-cycle plants for Florida Power Corp, was manager of combined-cycle services for Progress Energy, and is recognized worldwide as an authority on boiler and HRSG design and O&M.

Anderson responded thusly, “Week before last I was in England and met with a company that sells a monitoring system like the one described in the brochure you forwarded. They have many systems on conventional boilers, but have never attempted to install one on an HRSG. The brochure you provided references HRSGs at the top, but all of the photos and information relates to conventional boilers. What specifically has this company done on HRSGs?

“I think online leak detection is an important tool for HRSG operators. But I’d be wary of buying a system today from anyone unless they can demonstrate a successful track record in multiple HRSG applications.”

Anderson then dug into the history of boiler leak detection to provide valuable perspective and to suggest a direction for the user to pursue. He said acoustic online monitoring for leaks in conventional boilers has been used successfully since the mid-1980s. It was first developed to monitor P11 superheater headers for early signs of leakage associated with ligament cracking, users having discovered that the creep life of these headers was not meeting expectations.    

Installation of a leak detection system, he continued, permitted a boiler with known ligament cracking to continue operating. When such damage was first discovered, it was not known how long ligament cracks that joined up, and/or went through-wall, would leak before breaking. Once fracture-mechanics techniques were improved and it was determined that ligament cracks were unlikely to fail catastrophically, leak detection systems became optional.

While several vendors made leak detection systems for conventional boilers, no one attempted to deploy one on an HRSG until a few years ago. These systems depend on filtering out all background noise except for the sound of the leak. Since the HRSG gas path is much noisier than that in a conventional boiler, no vendor attempted to spend the development money to see if their system could be made to work on an HRSG.

A few years ago, Anderson went on, EPRI contracted a company called Triple 5 to develop a leak detection system for HRSGs—and it worked. This system is now commercially available to anyone. Triple 5 was bought out by Mistras Group Inc a few years ago, but it still sells and monitors these systems. About two-dozen of the Triple 5 acoustic monitors have been installed on HRSGs to date.

The Mistras (Triple 5) system uses wave guides (rods) clamped to header/pipes and welded to casing. Hardwired accelerometers are attached to the wave guides. The monitoring system is remotely monitored by Triple 5 which notifies the plant when/if leaks occur. Very small leaks are detectable.

As the leak grows it is often possible to determine how many starts/stops remain before the leak goes critical. This is of great use in getting the unit to a less expensive time to repair the leak.

Interestingly, Nick Grigas of Triple 5 will be presenting on acoustic leak detection at the upcoming HRSG Forum with Bob Anderson, in the Hilton Orlando, July 22-25. Recent developments he will discuss include deployment of a wireless (Hart) system to facilitate installation. You’ll be able to visit with Grigas during the exhibition to dig deeper into the details of leak detection at Booth 104.

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Coating critical steam-valve parts with chrome carbide avoids stellite delamination issue

Stellite liberation from large valves installed in main and hot reheat (HRH) steam systems serving F-class combined cycles, considered a major industry problem 10 years ago, has been eliminated by substituting chrome carbide as the hard-facing material for critical valve parts.

The editors first learned of stellite delamination at the 2009 7F Users Group Conference where the liberated material from a 20-in. HRH block valve was displayed. The industry had been made aware of stellite liberation by GE, which issued Technical Information Letter 1626 about three months ahead of the 7F meeting. It advised steam-turbine owners to check the condition of the stellite inlay sections used in fabricating seats for the OEM’s combined stop and control valves.

Revision 1 of that TIL, published at the end of 2010, recommended a “one-time seat stellite inlay UT inspection during valve installation or the next planned maintenance inspection”—this to identify any lack of bonding between the inlay and base metal on units with fewer than 50 starts.

Disbonding of stellite associated with combined-cycle plants has occurred primarily in parallel-slide gate valves and non-return globe valves. Hardfacing has been liberated from valve seats, guide rails, and discs. Tight shutoff of valves has been compromised in some cases.

Many incidents of stellite liberation were reported. To illustrate: CFM/VR-TESCO LLC (formerly Continental Field Machining), a leading valve services company said that in 2011 and 2012 it repaired 50 valves manufactured from F91 (forged body) or C12A (cast body) and ranging in size from 12 to 24 in. More than half of these jobs involved stellite liberation.

These repair projects were split roughly 50/50 between valves within the Code (ASME Boiler & Pressure Vessel Code) boundary and those that were part of the boiler external piping. Repairs on the former were performed according to guidelines presented in Section I of the Code and in the National Board Inspection Code; those outside the Code boundary were performed according to ASME B31.1.

There hasn’t been much discussion on stellite disbonding the last few years—at least at meetings attended by the editors, which include the Combined Cycle Users Group, Steam Turbine Users Group, and HRSG Forum with Bob Anderson.

However, mention was made by one owner/operator regarding the successful use of ValvTechnologies Inc’s IsoTech® parallel-slide gate valves on his company’s HRSGs in eliminating the need for stellite. According to the manufacturer, critical parts for its severe-service valves, used where steam temperatures exceed 1000F, are provided with its RiTech® 31 coating.

This chrome carbide refractory coating is much harder than Stellite 6 (68-72 RC versus 34-38 RC). It is applied in state-of-the-art HVOF (high-velocity oxygen fuel) spray booths using a proprietary compressive spray technique to achieve high bond strength. Applications extend up to ASME/ANSI Class 4500 at 1800F for valves up to 36 in.

The chrome carbide hard-coated web guide ensures the discs are kept parallel through the entire valve stroke. As the valve is cycled under differential pressure, the hard surfaces reportedly burnish and polish each other, avoiding the scratching and galling cited by some others.

The user sharing his experience with the ValvTechnologies product said their parallel slide gate valves have been operating on four or five of his company’s HRSGs for three years or so and the only hiccup was a stem-packing leak on one valve which was quickly corrected. This testifies to the vendor’s claim that RiTech® 31 hard-coating technology is impervious to the effects of high-temperature cycling typically experienced today in combined-cycle main-steam isolation and HRH applications. The company guarantees coating integrity for 10 years or 10,000 cycles—whichever comes first.

Finally, the user mentioned that a representative of the manufacturer annually visits each plant where ValvTechnologies valves are installed to verify that they continue to meet expectations.

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HRSG inspection tips

It’s important to have a comprehensive checklist of what to inspect on your HRSG, and how, before conducting a condition assessment of your equipment for plant management and/or due diligence purposes. Your checklist may have scores of items to review but it’s impossible to identify everything to look at—usually because your depth of knowledge and experience is lacking in one or more areas for a particular boiler design. 

Bob Anderson was in the middle of noting “hot topics” for the open discussion sessions at the upcoming HRSG Forum with Bob Anderson at the Hilton Orlando, July 22-25, when the editors called the other day. We asked him to identify a couple of things he believes plant personnel might forget to check during a walk-down.

Ensuring proper lubrication of sliding feet found under the column supports on the hot end of some HRSGs was the first thing he mentioned. He explained that it’s important for these plates to move freely as the boiler expands and contracts during startup and shutdown to avoid stressing structural steel unnecessarily. Another tip Anderson offered was to check that the washers under the hold-down nuts are free to rotate. He sometimes finds the nuts tight, as they should be for non-moving columns, thereby preventing sliding.

Another simple check that owners often forget, Anderson continued, is the proper routing of the discharge pipe from the atmospheric vent at the top of a Consolidated safety valve body and/or the proper routing of the drain at the bottom of the valve. It’s important that the vent not point at the walkway, to protect personnel; also, that it not point upward, allowing the collection of rainwater. Important, too, is that the vent and the drain not be tied together, as that would affect the valve’s blowdown setting. Finally, be sure the shipping plug has been removed from the vent hole.

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