by Team CCJ | May 22, 2013 8:10 pm
Tuesday, the first full day of the 7F Users Group’s 2013 Conference, started on the double-quick and maintained that pace until the final bell. Chairman Sam Graham, maintenance manager at Tenaska Virginia Generating Station, cracked the whip on a user-only morning session that featured six content-rich compressor-section presentations and a lively open discussion on safety. The meeting broke precisely at noon and resumed 60 minutes later (Graham is navy punctual) with sessions on controls and auxiliaries. Vendor presentations followed the user-only portion of the program and they concluded a couple of minutes before the three-hour vendor fair opened at 5:30.
Graham didn’t spend much time on his opening remarks—perhaps three minutes. There were more important things to do. The first was to thank Paul White of Dominion Resources for his 15 years of service to the 7F Users as a member of the steering committee and one of the group’s guiding lights during its development into a world-class engineering organization.
White has transitioned to an advisory role at Dominion and now spends a significant amount of time mentoring engineers and sharing best practices and lessons learned over his many productive years in the generation business. While some companies complain about the shortage of experienced engineers, Dominion is proactively addressing the issue with its mentoring program. Paul Whitlock of Dominion has replaced White on the 7F steering committee.
Graham then passed the microphone to last year’s chairman, Ben Meissner of Duke Energy, who updated attendees on www.7fusers.org, which went live just before the 2012 meeting. The organization’s electronic headquarters hosts a lively, interactive 7F Forum and is equipped with a fully searchable archive. Both are accessible only by certified users—currently more than 700 from 75 owner/operators. The modern design and user-friendly website got two-thumbs up from attendees. If you are employed by an owner and/or operator of 7F engines and are not yet registered, do so today. This will give you access to presentations from the 2013 conference; Meissner expects that they will be posted to the site within two weeks after the meeting’s close.
The big chill.
Ed Fuselier of Direct Energy, the 7F Users’ incoming chairman, gave what may have been the day’s most uplifting presentation with an overview of the recently completed inlet-chiller retrofit at Frontera Energy Center, a nominal 500-MW combined cycle located in south Texas. The plant operates in an energy-only market, and with electricity prices generally highest in summer when temperatures are high, replacing the evaporative cooler with a chiller made good financial sense.
Frontera’s inlet chilling system includes a 3.5-million-gal thermal energy storage tank (TES) rated at 70,000 ton-hr; the cylindrical steel vessel stands 65 ft high and measures 90 ft in diameter (photo). TES provides significant operating flexibility (Fuselier called it a 60-MWh storage battery) while minimizing capital and operating costs. Specific benefits of the chiller/TES system include the following:
• Increases plant output by 53 MW on a 100F day.
• Halves auxiliary load during the day (5 MW versus 10) by storing energy overnight.
• Reduces capital cost. The chiller package is 7000 tons; 14,000 tons would have been required absent the TES.
• Allows the chiller auxiliary load to fit on the plant auxiliary bus without an additional transformer.
• Enables the plant to run for two hours—so-called super-peak mode—exclusively on chilled water withdrawn from the TES tank (chillers not operating).
Innovation is evident in the inlet-air house arrangement. The original inlet system was scrapped and a new inlet incorporating self-cleaning filters and chiller coils was installed by Donaldson Company Inc. Frontera wanted its new inlet system to fit on the existing structural steel to avoid disturbing the inlet bleed heat system and silencers. Another cost-saving goal was to avoid reconfiguring ductwork. This objective meant Donaldson would have to provide a unit with the same bottom-biased outlet transition that characterized the original inlet house.
But that is not ideal for chiller coils because, with this arrangement, more air would flow through the bottom-most coils than through the upper ones. Result: The upper coils would produce colder air than the bottom ones and the two temperature regimes would not mix before entering the compressor bellmouth. Such stratification is not permitted by the gas-turbine OEM. The solution was Donaldson’s “variable fin-pack density.” Simply put, its engineers used CFD analysis to design the inlet with the optimal number of fins per inch on each coil to produce chilled air of uniform temperature on the downstream side of the chiller section.
Chillers are a competitive necessity for many plants in the Texas market (Johnson County, Jack County). Given Frontera’s location and the market served, chillers can operate at this facility a significant portion of the year. Temperatures at the plant site typically exceed 80F more than 3500 hours annually. Although cold snaps are rare (temperatures are 50F and above about 8400 hours annually), their possibility was not overlooked by the owner’s engineers. Should the temperature drop to about 30F, the plan is to circulate water from the cooling-tower basin through the coils to provide the heat necessary to prevent freeze-up. A water/glycol mixture will be circulated through the coils in the unlikely event the temperature drops to 25F.
Source URL: http://www.ccj-online.com/7f-users-weather-a-blizzard-of-information-on-day-one-direct-energy-tailors-chiller-retrofit-to-maximize-economic-gain/
by Team CCJ | May 22, 2013 8:09 pm
It seems hard to believe, but a corrosion pit, so small that it’s hardly visible, can bring down a large frame gas turbine. That was the sobering message from the first user to address the opening compressor session at the 7F Users Group conference, held this week at the Hyatt Regency in Greenville, SC. Users have heard this before, most recently from John Molloy, PE, of M&M Engineering Associates Inc, in the 4Q/2012 issue of CCJ, “Minimize the risk of catastrophic failure from contaminated inlet air.”
The case history presented to the 7F users described the wreck of a simple-cycle machine with 700 starts while it was at full speed, no load. Borescope inspection revealed extensive damage to the rotating and stationary compressor blades. But that assessment hardly described the damage found when the unit was opened and the rotor removed. It did not appear that any airfoil was left unscathed. Close examination revealed only one clean fracture surface: An R1 blade was sliced off neatly at the platform. Investigators at the shop identified a second R1 blade with a big crack, perhaps only a few hours or one or two starts from failure.
The area in the lower casing once occupied by S5-S9 was cratered and occupied by slag. No one knew where the base casing material was. There was a deep gouge, about ½ in. deep and 6 in. long, in the mid compressor case which could not be weld-repaired. What to do about that?
There were three options for the rotor: rebuild the existing one, 10 to 12 weeks; buy a refurbished compressor rotor, five to six weeks; buy a fully refurbished unit rotor, four weeks. Casing options were: Repair existing casing, three weeks; buy a used casing, three weeks; order a new casing, 10 months. The casing repair option seemed contradictory because the OEM said welding was not possible. The owner opted for rebuilding the existing rotor and buying a used casing.
But the return to service would prove to be a torturous journey. The used casing was found, upon receipt, to have a patch ring at stage 10—an unpleasant surprise. Plant personnel learned that it was installed to correct a manufacturing error and that the casing had operated its entire life that way. The not-so-perfect casing, though disappointing, was accepted as is. During re-commissioning operations the unit tripped on high exhaust spread. Debris distributed throughout the fuel system was the cause. It seems like workers “missed a spot” during cleanup. The debris hideout was on the upstream side of the purge valve. All fuel nozzles were removed and sent to a repair shop for cleaning and inspection; debris was collected and analyzed.
Root-cause analysis suggested the failure was caused by the coexistence of a local high stress point and a corrosion pit which led to crack initiation and the eventual liberation of a single R1 compressor blade. Corrosion was likely initiated by poor water quality early in the service life of the unit, about the time of the millennium. A check of available records revealed that chlorinated river water was used as makeup for the evap cooler at that time. Today, a reverse osmosis system provides evap-cooler makeup and water quality is monitored. One final note: Borescope inspections had been done regularly, the last one only a dozen starts before the wreck, but telltale pits and cracks had never been noticed because they were not in a “hot area” for inspection.
Source URL: http://www.ccj-online.com/lowly-corrosion-pit-initiates-catastrophic-compressor-failure/
by Team CCJ | May 22, 2013 7:42 pm
The editors first learned of stellite delamination in a large valve designed for high-pressure (HP)/high-temperature steam service at the 2009 7F Users Group conference. But all the attention that incident received was a brief mention late in a long user presentation profiling the major inspection of a combined-cycle plant. No questions were asked about the issue, at least none that the editors can recall, and the incident slipped through their minds—possibly yours too. The photo included here is of stellite liberated from the seat of a 20-in. hot-reheat block valve installed at that presenter’s plant and collected in the strainer for the steam turbine’s combined stop and control valve.
Another alert concerning stellite liberation came from GE Energy, which issued Technical Information Letter 1626 on Jan 30, 2009. 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, dated Dec 31, 2010, recommended a “one-time seat stellite inlay UT inspection during valve installation or next planned maintenance inspection.”
Yet another alert about stellite liberation was sounded by Ed Sundheim, director of engineering for Essential Power LLC, Princeton, NJ, who had intended presenting on the subject at the spring 2011 conference of the Combustion Turbine Operations Technical Forum™, but the lunch bell sounded before he got to the podium. Instead, Sundheim provided the editors his notes to develop a CCJ article, accessible to you with one mouse click.
More recently, the Dogwood Energy Facility was recognized with a Best Practices Award at the spring 2013 conference of the CTOTF™ for its efforts in the identification and repair of a cracked seat on the 12-in. HP stop/check valve for one of its HRSGs. Except here, the seat material was Type-316 stainless steel; no stellite was involved.
The industry recently learned of many more incidents of stellite liberation. A leading valve services company reported earlier this year at an industry meeting that in 2011 and 2012 it had 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 involved stellite liberation.
The repair projects profiled were split roughly 50/50 between valves within the 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 ASME Boiler & Pressure Vessel Code and in the National Board Inspection Code as well as jurisdictional requirements. Valves outside the Code boundary were performed according to ASME B31.1.
Stellite liberation has gained recognition as an important industry concern. EPRI reportedly has established a committee to dig into the details with the expectation of finding a better method for bonding stellite to valve discs, seats, and slides. A report on the stellite issue will be published in the next issue of the CCJ. In the meantime, here are some facts you should be aware:
• Disbonding of stellite associated with combined-cycle plants has occurred primarily in parallel-slide gate valves and non-return globe valves for HP and hot-reheat service. Hardfacing has been liberated from valve seats, guide rails, and discs.
• Inspection of valves in plants installed during the late 1990s and early 2000s are highly recommended if this hasn’t been done previously. Experts generally agree that straight-beam ultrasonic examination is best for identifying disbonding.
• Before opening your valves have a game plan for repair or replacement in case you find damage. Three options:
1. Replace the existing valve with a new one.
2. Cut the valve out of the line and send it to the manufacturer or a third-party shop for repairs.
3. Repair the valve inline.
• Before formulating your plan, consider the following:
1. The lead time for new valves can extend beyond a year.
2. Shops capable of doing quality valve work generally have a backlog.
3. Quality repairs are difficult to make inline because of preheat and access requirements.
4. Field-service organizations with the requisite valve repair experience are extremely busy.
• There is no industry standard for applying hardfacing. All manufacturers have their own techniques; you might want to qualify them before allowing work to begin. In general, the welding methods used for applying wear-resistant materials such as Stellite 6 and Stellite 21 have been satisfactory for conventional steam-plant service. But they apparently have met their match with the high temperatures and cycling experienced in F-class combined cycles. Quenching associated with attemperator overspray also is believed to be a factor in disbonding.
Source URL: http://www.ccj-online.com/headsup-stellite-delamination-in-hp-hrh-steam-valves/
by Team CCJ | May 22, 2013 7:39 pm
The performance thieves lurking in many heat-recovery steam generators sometimes can be eliminated with relatively little effort and at low cost, Lester Stanley, PE, told owner/operators attending HRST Inc’s HRSG Spotlight Session at the 7F Users Group annual conference being held this week at the Hyatt Regency, Greenville, SC.
The ideas and experience offered by Stanley and colleague Bryan Craig, PE, during the four-hour workshop on Monday morning were of high interest, judging from the questions and floor discussion generated. That these attendees were a motivated group there was no doubt. All had to arrive a day early, pay an extra fee, and be in their seats by 8 a.m. to get maximum benefit from the program. Interestingly, there were about twice the number of users participating in the HRSG Spotlight Session than there were playing in the annual 7F Golf Tournament, which was held at the same time.
HRSGs and steam turbines have been the book-ends for the industry’s most successful meeting of frame gas-turbine owner/operators for many years. Prior to 2011, the HRST’s F-class workshops covered a wide variety of topics in nominal 15-minute increments. For the last three years, the boiler experts have focused on three subjects during each session to provide the level of detail necessary to facilitate implementation of initiatives suggested for improving efficiency, availability, and safety, while reducing emissions.
This year’s topics were the following:
* HRSG performance thieves.
* Advanced inspection techniques.
* Inspection and maintenance of HRSG inlet and firing ducts, and gas-turbine diffuser ducts.
These subject areas were natural extensions of material covered in 2012 (superheater and reheater fatigue, economizer cracking, and drum-nozzle cracking) and in 2011 (flow-accelerated corrosion, desuperheater issues, and steam-drum cracking). The electronic links provided in this article connect to CCJ ONsite’s coverage of the 2011 and 2012 presentations, bringing the three years’ worth of interrelated material together for you.
Stanley focused on these four performance thieves during his opening presentation:
* Gas baffling.
* Gas-side fouling
* LP economizer recirculation.
* Buoyancy instability/vapor locking.
Baffles force turbine exhaust gas through the tube bundles, maximizing heat transfer and performance. Even gaps of only 2 in. between adjacent tube panels, between tube panels and the inner liner, and between headers in the crawl-space area can cause significant losses, Stanley told the group. Baffle integrity in evaporator and economizer sections is particularly important, he said.
Damaged or missing baffling is easy to identify during a gas-side inspection (Fig 1) and relatively easy and inexpensive to correct with standard carbon-steel components and conventional welding techniques (Figs 2 and 3). Perhaps the most costly component of baffle repair and/or replacement is the installation of scaffolding. Therefore, it makes good sense to do this work when cleaning tube panels, which also requires scaffolding.
Stanley noted that thermal performance loss is not the only adverse impact of ineffective baffling; it has been known to contribute to flow-accelerated corrosion (FAC) as well. Also, when baffles in the firing-duct area are not in good condition, duct-burner flames can be disrupted and tubes and the SCR can suffer thermal damage—all in addition to performance loss.
Though baffle work is relatively simple to do, if your unit has excessive gaps in many locations, the plant maintenance budget might not be able to swallow the whole refurbishment project in one gulp. Stanley discussed one such case where performance modeling provided justification and prioritization of the work. Some gap locations create more performance decrease than others, he said. In the real-world example described, Stanley said that the annual benefit of coil-to-coil baffle fixes in all six access lanes of an F-class HRSG was about $1 million. However, baffle restoration in only two of the lanes produced 60% of that benefit making the investment decision an easy one. In this case, the plant reported a 2 MW increase in output after repairs were made.
Gas-side fouling, as most attendees knew, can be caused by one or more of the following: rust, ammonia salts, sulfur compounds, and liberated insulation. They also were aware that the consequences of fouling include an increase in gas-turbine backpressure, a thermal-efficiency penalty, and the release of particulates up the stack, especially at startup. But many were not sure of the financial impact of fouling. Stanley worked up a short calculation that showed gas-turbine power production decreased by 0.105% for each 1-in.-H2O increase in backpressure. For a 7FA with a nominal rating of 183 MW at ISO conditions, this translates to a “de-rate” of 192 kW. In addition, fouling reduces HRSG thermal efficiency because it reduces heat transfer and steam production.
Someone asked about the optimal time for cleaning fouled heat-transfer surfaces. Stanley said this was an economic decision and could be different for every plant. He added that high backpressure often drives the decision, to avoid the consequences of an unnecessary turbine trip. Next, the boiler expert suggested that plants develop their thermal-performance and backpressure yardsticks to determine the optimal time for cleaning. Stanley pointed out that rust is relatively easy to remove, SCR ammonia salts not so. Regarding the latter, he warned about the difficulties in cleaning tube bundles after they had bridged over—that is, totally packed to the fin OD with ammonia salts. “Clean before crisis,” Stanley urged.
The next 10 minutes or so was dedicated to a review of the types of cleaning, the effectiveness of various media, and the advantages of so-called deep cleaning—a process developed by HRST Inc. Stanley said that, in general, best results in the cleaning of fouled finned-tube surfaces have been achieved using CO2 and compressed-air blasting, perhaps in series. Water deluge or hydroblasting can do the job in some instances, he continued, but waste collection and disposal would likely militate against the use of water.
The next performance thief
Stanley discussed was LP economizer recirculation. Bryan Craig wrote in a recent issue of HRST’s Boiler Biz that recirculation often is used to raise the temperature of condensate entering the LP economizer above the turbine-exhaust dew point to minimize corrosion of panels in the back end of the unit. However, this comes with a cost. Recirculating water flow to increase the inlet temperature reduces overall output from the HRSG in a small, but measurable way, he stated. The amount of performance reduction depends on the water-temperature set point, and also the location from which the recirc flow is taken.
Some LP economizers recirculate a portion of the flow from the economizer outlet back to the inlet to achieve temperature control (Fig 4); others recirculate from an intermediate point within the economizer, design permitting (Fig 5). HRST engineers have concluded that if recirc must be used, it is more efficient to take the flow from an intermediate point than from the economizer outlet. The temperature set point also comes into play: Reducing the set point improves efficiency.
Craig used Fig 6 to illustrate this point. The chart is based on a typical F-class HRSG with a 12-row LP economizer and a condenser hotwell temperature of 105F. If recirc flow is taken from the economizer outlet, reducing the temperature set point from 140F to 130F increases steam-turbine output by 160 kW. Assuming the plant operates 5000 hr/yr and is paid $50/MWh for the electricity it produces, the 10-deg-F reduction in the set point is worth $40,000 yearly. For the 130F set point, extracting recirc flow from the midpoint of the economizer increases steamer output by another 180 kW, more than doubling the annual revenue gain to $85,000.
Eliminating recirc altogether, and allowing cold water to enter the LP economizer, increases steam-turbine production by 330 kW, which is worth about $82,000 per year. This suggests it may make sense to forego recirculation and plan on replacing the last one, two, or three rows of LP economizer surface every eight years or so, give or take a couple of years. Also worthwhile considering: The first time you replace the back-end surface, switch to an alloy material suitable for the wet environment and eliminate the need to do it a second.
Buoyancy instability. Stanley began the final segment of his presentation by reviewing the performance loss caused by buoyancy instability in panelized economizers. Nearly all economizers have some down-flowing tubes, he said; most have down-flow in half the tubes. Buoyancy instability causes flow to stagnate in some of the down-flow tubes, or to reverse direction. When water does not flow as designed, the effective heat-transfer surface is reduced and heat absorption decreases.
Also, stagnant and reverse-flow tubes become hotter than neighboring tubes increasing the level of stress. The risk of this happening is greatest at low loads. Hundreds of thermal cycles can occur within a day, leading to fatigue failures in less time than you might think. Modification of flow circuitry can correct the issue. If a performance assessment advises that buoyancy instability is a problem early in the life of a unit, changing the location of splitter plates in the upper header should be considered to optimize the flow pattern. Stanley said the relocation of splitter plates is not as difficult as it might appear. In some cases, he said, it can be easier than plugging economizer tubes.
Buoyancy instability in return-bend economizers causes water in some circuits to flow very slowly or not at all, others to flow quickly. If the gas temperature is above the saturation temperature, stagnant tubes will vapor-lock—that is a steam bubble trapped in the return bend will block flow, generally until unit load is high enough to clear it. It is difficult to modify existing systems to correct this problem.
Source URL: http://www.ccj-online.com/how-to-boost-hrsg-performance-and-increase-your-plants-bottom-line/
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