7F Users Group

Ed Fuselier of Direct Energy, the 7F Users’ 2013 – 2014 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). The system was designed, procured, manufactured, installed and commissioned by Stellar Energy. 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• Enables the plant to run for two hours—so-called super-peak mode—exclusively on chilled water withdrawn from the TES tank (chillers not operating).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 uppercoils 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.

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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. 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.

Compressor session

Compressor presentations and discussion traditionally take most of the first morning at 7F User Group meetings and 2013 was no different. The session ran nearly three hours, including the coffee break. The other sessions—safety, controls, auxiliaries, combustion, turbine, and generator—typically are budgeted half that time or a bit less.

Catastrophic failure. 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 compressor session. Users may have heard this before, most recently in the CCJ from John Molloy, PE, M&M Engineering Associates Inc, in the 4Q/2012 issue, 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 (RCA) 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.

“Forced Forward Stator Replacement,” well presented and well received, featured a valuable review of compressor issues and OEM responses (Technical Information Letters and product changes) that owner/operators have endured since the unit profiled began operating in spring 2005.

The historical perspective was of particular value to the first-timers in attendance—about half of the registrants. If you didn’t absorb all that the speaker had to say, access the presentation at www.7Fusers.org. The archives section of the organization’s website is for owner/operators only and requires a “library card.” Register today online; it’s simple to do.

The two 7FAs for this combined cycle were commissioned with the so-called “original” compressor blades and the OEM’s modified water washing system. Given the many design iterations for these components it is difficult to understand from this summary exactly what was installed in this user’s engines at the time. However, he did say that the airfoils in the R0 and R1 rows of his units were susceptible to erosion, foreign object damage, and associated cracking.

One of the reasons to attend user-group meetings is that you can query the speaker to learn exactly what components his or her case history is referencing. With all the OEM’s design changes over the years, and the wide variety of third-party parts available, there probably are more than a hundred unique engines in the fleet.

Back to the case history. The plant began inspections recommended in TIL 1509 for R0 and R1 in fall 2005. A crack was found in an R0 blade on one unit in spring 2008 and blades were replaced with the “original” airfoils. The owner implemented the OEM’s recommendations based on fleet and user experience, including the following:

• No R0 upgrade.
• No online water washing.
• Aggressive semiannual inspection schedule.
• Monitor the OEM’s upgrade progress through the 7FA Users Group and the GE sales team.
• Evaluate third-party solutions.

In planning for the fall 2011 major inspection, the owner’s engineers fully evaluated all upgrade options, including the OEM’s “enhanced compressor” upgrades—such as Package 3 to address R0 and stator failures, Package 5, marketed as a “proactive enhancement” to address R1 cracking and other issues.

In conducting its assessments, the outage team focused its analysis on issues presenting the highest operational risks—including R0/R1 cracking, stator cracking, aft stator rocking. Analyses complete, the owner, a transactional customer, opted to wait until it had adequate time to evaluate field experience with both OEM and third-party alternatives before deciding on the specific upgrades to install.

When Unit 1 was opened for the fall 2011 major, extensive corrosion pitting from contaminated air was in evidence on blades in R1-R3, R6, and S1-S4; some pits exceeded the maximum allowable depth after prescribed corrective blending. The pitting photos shown by the speaker were very similar to those presented by M&M Engineering’s Molloy in the article referenced above.

The user presenting said his 18-stage compressors suck in air heavily contaminated by vehicular emissions and salt. He also mentioned a four-month shutdown in spring 2009 to address problems with the HRSGs. During that time there was considerable air flow (natural draft) through the gas turbines. Experience of others suggests that air curtains and portable dehumidification systems are beneficial. The owner also believes that ineffective water washing contributed to the pitting attack.

The poor condition of the compressor air path required a significant increase in scope for the major inspection. Re-blading was necessary. Plant personnel considered themselves lucky because no blades were liberated despite the extensive pitting. GE was selected to destack and overhaul the rotor and rebuild it with new blades, a job that took six weeks. The speaker said there was not adequate time to evaluate the capabilities of third-party services providers and invite them to bid on the work.

The plant had a spare rotor (with an enhanced R0), so it was inserted into Unit 1 and that engine’s rotor overhauled for Unit 2 during its major inspection in late fall 2011. Unit 2’s compressor also had extensive pitting damage. Interestingly, the plant is now operating two GTs with rotors having different features: One has a Package 5, the other a Package 3.

Follow-on corrective action includes the following:

• Increased frequency of water washing to multiple times weekly. R0 erosion is being monitored.
• Inlet inspections are characterized by greater vigilance for oil, dirt, grease, moisture, etc.
• An air-filter upgrade program will be complete by year-end.
• Upgraded water washing system is being evaluated. Investigation of erosion potential is part of the evaluation.

A second presentation by this user described “Aft Stator Replacement” for the same gas turbines. Since 2006, he said, semiannual inspections have been conducted for compressor rubs and shim migration; TILs 1502, 1562, and 1769 were mentioned. In 2008, a “cases-off” hot-gas-path (HGP) inspection included aft blade tip blending, installation of third-party S17 vanes and exit guide vanes, and pinning of shims by a third party.

The first significant finding of stator rock was during the fall 2009 borescope inspection. Rocking of from 30 to 50 mils was in evidence. The following spring, rocking of up to 67 mils was found. Inspection intervals were reduced to between 1000 and 2000 hours from that point on. Vane rock increased to as high as 95 mils. Owner was concerned because at 120 mils the gas turbine must be shut down.

Engineers set about evaluating upgrade options for the aft stator section of the compressor for possible implementation during the fall 2011 major inspection. The first option, replace in-kind, really was not a viable alternative: It doesn’t solve the problem because the case was already damaged and the likelihood of shim migration was good.

The OEM’s so-called Bigfoot mod/ Package 4 was an alternative, but that was viewed as an extremely intrusive and permanent machining procedure that would become the critical path for the major. It also involved a significant upfront commitment for parts and labor for a procedure with limited operational experience (fleet leader at 13,000 hours at the time). Plus, there were emerging stator twist concerns.

A fallback position would be to wait until the 2014 HGP to implement a solution, as was the strategy described earlier for the forward stator section. But a third-party was offering multiple-vane segments using field-validated airfoils that were viewed positively. Fleet leader had 24,000 hours at the time and these parts and their installation were much less costly than the OEM’s solution. Deal! The new parts have since passed the 12,000-hr mark and are said to look like new.

Another compressor presentation that got high marks, “17th-Stage Compressor Wheel Dovetail Cracking,” provided attendees several lessons learned/best practices. When preparing for a major inspection, an owner’s engineers were warned about the possibility of finding dovetail cracking on the 17th-stage wheel. Rotor out, cracks ranging from about 125 to 155 mils radial and 60 to 220 mils axial were illuminated by red dye on the aft side of every flat-bottom blade slot. The rotor had experienced 2025 actual starts and had recorded 44,365 hours of service at that point in its life.

The OEM told the owner to blend-out cracks up to a depth of 100 mils; also, to smooth all blunt edges and transitions of the blend and dye-pen the affected area to be sure the indication is gone. If a crack remains after blending 100 mils, the OEM said, take a picture, estimate the size of the crack, and submit a PAC (Power Answer Center) case. One crack was known to exceed 100 mils, so the owner leveraged EPRI research and decided that blending to 125 mils was acceptable.

Caution: At the 2012 meeting, an attendee told the group it was his understanding that if you blend and can’t remove the crack it will propagate faster than if no blending had been done.

The forward sides of all slots also were dye-penned; all of those were cracked as well—from about 60 to 155 mils axial. EPRI’s stress analysis concluded that 7FA discs with flat-bottom dovetail slots will crack somewhere in the neighborhood of 1000 to 1500 actual starts. The disk examined was considered good for another 900 factored starts.

A field service team from Sulzer Turbo Services was dispatched to the plant to blend out the cracks. This is a difficult job to do in the field, the speaker said, but Sulzer successfully removed all cracks. The owner’s plan is to order the new 17th stage wheel/stub shaft with round-bottom blade slots and install it during the next HGP, which becomes a major because the rotor must be unstacked.

An RCA revealed that rim dovetail cracking is caused by thermal transient stresses associated with cyclic operation. Hot restarts are the most damaging operating scenario; during a shutdown, the rotor rim cools quickly and the wheel center stays hot. One user in the audience commented that rim cracks are not self-arresting. He added while round-bottom disc slots avoid stress concentrations characteristic of flat-bottom slots, they also will crack, but are expected to last twice as long as discs with flat-bottom slots.

There were two brief compressor-section presentations, one with the speaker talking through a series of photos of S17 vane segments from the time they were removed from the engine for repair of the bolted shroud until they were reinstalled in the unit. A hiccup was reported on final fit-up. A poll of attendees revealed about half a dozen users operating with shrouded S17 vane segments provided by a third-party supplier—one engine having more than 25,000 hours on those parts.

A user who presented last year on the difficulty in extracting damaged R0 blades using a come-along and air hammer, and the galling of the blade slots experienced with that method of extraction, was back at the podium again this year. He reported success (no galling) on another gas turbine by using a cutting wheel to remove the airfoil and then a milling tool to evacuate the blade slots. He said it took about three shifts to mill out all of the R0s. Outside California, he added, you can use a plasma torch and probably get the job done in one shift. The first rotor goes to the shop this fall to replace the stub shaft and integral wheel with the galled slots.

By show of hands during the open discussion period, about 80% of the group has done a compressor upgrade of some sort—most with the OEM. Other talking points included ice damage on R0 and how to avoid it. This has been a discussion subject at several user group meetings over the years. Use the search function at www.ccj-online.com to access more information. There also was mention of systems for compressor-blade health monitoring—both OEM and third-party—but relatively few attendees had experience with these promising diagnostics.

Safety

Fall protection was a major topic of discussion because many serious injuries result from falls of only a few feet. One fatality reportedly was caused by a 12-ft fall. Lifelines, suggested tie-off points, etc, were included in the give-and-take.

The pros and cons of enclosure entry while the GT is in operation also were debated. Some attendees see the benefits of periodically inspecting the inside of the turbine enclosure to identify leaks, catch other developing concerns, and to facilitate troubleshooting.

Others argued that opening compartment doors could put individuals at risk should unexpected conditions inside the compartment expose personnel to hot gas, a combustible environment, fire, or other acute hazards. They do not allow operators to enter the package with the GT in service. One case history noted involved an operator who opened the compartment door and saw something glowing in the combustion section (caused by the failure of a dual-fuel nozzle), narrowly avoiding injury.

An attendee said operators at his plant periodically open the compartment door for a 30-sec look-see to identify possible issues using the senses of sight, smell, and hearing. But they are not allowed to break the plane of the package with equipment in service. Another user said his plant allows operators to enter the package but they must be wearing a long-sleeved shirt and gloves, and inform the CRO before entering and after leaving.

The dangers of CO2 fire extinguishing systems were discussed as well. One user’s experience was that when CO2 dumps into the No. 2 bearing compartment it spills out and floods the surrounding area. This can be dangerous because low-lying areas can take considerable time to ventilate properly. He recommended conducting a CO2 test and tracking its migration to develop appropriate safety procedures. A recommendation from another user was to install hazardous gas detectors outside the package to improve their reliability.

Two more safety topics discussed: (1) Emergency exits and fire breaks in air-inlet filter houses, and (2) extraction of injured workers from confined spaces. The latter can be particularly challenging if the people who must be rescued are overweight. Regular practice with first responders was suggested.

Combustion session

An owner reported that one of its 7FA.03s, with a DLN2.6 operating on LNG, tripped on high exhaust spread as the combustion system transferred from Mode 4 to Mode 6. A restart was attempted with the same result. First thought was that the root cause was in the fuel system, not the combustion hardware. Reason: Nitrogen in the LNG boils at -320F, lower than the -258F for methane, and engineers surmised that nitrogen vaporized first, rapidly diluting the boil-off gas (that is, the surge in nitrogen reduced the calorific value of the fuel at the burner tip).

Engineers believed this was the cause of the lean blowout (LBO) event, but because the Modified Wobbe Index was in the flammable regime at the burner tip, they predicted a DLN issue in addition to low MWI. The OEM was consulted and what sounded like a trial-and-error approach to a solution was initiated. The PM3 split was increased at the mode change and this was effective in avoiding LBO, but peak-2 dynamics increased as a result. Engineers also learned that peak-1 dynamics increased with MWI and peak-2 dynamics decreased with MWI.

Finally, engineers were able to tune the combustion system to hold dynamics under 2 psi, maintain NOx between 10 and 15 ppm as allowed by the plant’s permit, eliminate the LBO threat, and permit turndown to about 50% load. The editors spoke with the presenter afterward and learned his employer—a gas company that also produces electric power—saves the highest-value LNG for its gas customers.

The owner receives LNG from many sources worldwide and product variability can be significant in terms of its use in finely tuned combustion systems. A review of CCJ’s EcoElectrica LP plant report, published in 4Q/2012, shows the highly reliable operation of that plant depends significantly on its high-quality LNG with minimal variation in composition.

Another presentation focused on the conversion of an early (Serial No. 1) 17-in. DLN2.6 combustion system to an 18-in. system. This was done to enable parts compatibility with other units and the ability to use 24K hardware offered by the third-party supplier with which it has a long-term parts agreement. The speaker attributed much of the challenging project’s success to fellow 7F users who shared lessons learned from their conversion experiences. The presentation triggered significant open discussion on experience with 24K and 32K hardware.

Turbine session