The 501F and 501G User Groups co-located for the third consecutive year last February. The partnership works well and is a win/win/win for the users, equipment and services providers, and Siemens Energy, Orlando, the OEM for both engines. Technical user-only sessions are combined or separate depending on the subject matter; members of both groups come together for the vendor fair and all meals and social events.
The 2010 meetings for both groups are scheduled for the Disney Yacht & Beach Resort, February 21-25. Caren and Lisa Genovese will be coordinating the conference as in the past. Refer questions to email@example.com.
Owner/operators of 501F (501G) engines interested in participating in the 2010 meeting who are not registered members of the 501F (501G) Users Group are urged to submit their professional profiles as soon as possible via the membership drop-down menu at http://501F.Users-Groups.com/Membership/UserCandidate.shtml or http://501G.Users-Groups.com/Membership/UserCandidate.shtml. Only registered members are invited to attend the annual conferences.
In a perfect world, the steering committees, through their plant-level contacts would personally invite each employee at every generating facility equipped with 501Fs and 501Gs to join these organizations. But committee members are volunteers all with real day jobs— like yourself. There is just not enough time for the one-on-one approach.
So, consider this a personal invitation from 501F Chair Paul Tegen and 501G Chair Steve Bates to join these productive user groups and share your ideas on improving plant performance and safety, reducing operating costs and emissions, etc. Membership (there’s no fee) has tremendous value even if you can’t get to the meetings in person.
The websites for both organizations are repositories for conference presentations and correspondence among members that can help you solve problems. Plus, there’s access to an e-mail system that puts you in direct contact with other members who can answer your questions, loans you a much-needed part, etc. Sign up today and make your job easier.
Vendor profiles. Likewise, companies wanting to participate in upcoming meetings as a sponsor or exhibitor must submit a vendor profile. This is done at http://501F.Users-Groups.com/Membership/AffiliateCandidate.shtml. Only companies approved by the steering committee receive invitations to exhibit.
The 2009 501F/501G meeting in Glendale, Ariz, ran a full four days. Sessions went from bell to bell; plus, there was a group dinner Monday (Day One) evening, vendor fair Tuesday evening (sidebar, p 105), and group dinner Wednesday evening (sidebar, p 106).
The G group got rolling first with a robust Monday morning program of user presentations and discussion covering redesign of valves for the rotor air cooler (RAC), retubing of a kettle boiler, R1 blades and vanes, generator rewind, installation of a new rotor and compressor, and generator vibration. F owner/operators eased into the day, their first formal group session starting after lunch. F users looking to broaden their horizons were welcomed at the G session.
Siemens Energy, Orlando, saw an opportunity in the relaxed Monday morning and offered a special 100-min 501F mods and upgrades breakout session for the F group, expanding its normal coverage of the subject and opening up room on the Siemens Day schedule for other topics. There were “real world” results on mods and upgrades to report on this year: Much of the development work the company has been doing over the last several years is out of the laboratory and off company test rigs and now in beta trials or full commercial operation.
Among the topics covered—thermal performance upgrade and low-load CO control—were implemented last spring at Iberdrola Renewables Inc’s Klamath Cogeneration Plant, managed by Ray Martens, a member of the 501F steering committee. That experience is profiled in special feature beginning on p 110 which also includes details on the plant’s conversion from WDPF to Siemens’ relatively new SPPA-T3000 control system.
Monday afternoon was busy, with the F and G groups coming together for an opening plenary that included a report by the TXP Focus Group to the full membership. Recall that issues with this system prompted the steering committee to support an auxiliary TXP group under the leadership of Mike Magnan, PPL Generation LLC. Ivan Kush of Calpine Corp assumed responsibility for this effort when Magnan transferred to a renewables position after the 2008 meeting. Members have worked closely with Siemens since 2004 via regular web forums.
After the plenary, attendees had a choice between controls and generator breakout sessions. Dividing the audience into multiple subject areas has two big benefits: Attendees get to select the topic of greatest interest to them and the more intimate setting improves the group discussion.
Tuesday was Siemens Day for the G users. Presentations by the OEM focused on compressor hook-fit wear, R1 ring segments, combustor baskets, R4 deflection, blade-ring oxidation, an update on the rotor-bolt failure issue, bellyband seals, exhaust-cylinder repairs, RAC leakage, torque converter, and several other topics. G users who could not make the meeting can access the Siemens presentations on the company’s Customer Extranet Portal (CEP). If you are not registered for access to that information resource, contact your Siemens representative today.
The F owner/operators spent Tuesday immersed in user presentations and group discussion on a broad range of topics, including: fleet safety issues, a compressor forced-outage case history, major inspection, FD3 upgrade (this topic is covered in detail in the Klamath article referenced earlier), turbine enclosure platforms, exhaust diffuser failure, and torque converter failure.
Plants that do not send at least one representative to every 501F annual conference miss out on the lessons learned by others and best practices adopted by the industry. This increases your chances of overlooking a critical O&M finding and/or making the same mistake someone else has already paid for. No reason for that. There isn’t a user group in the GT sector that doesn’t provide a minimum 10:1 return on the attendance investment. You always come back to the plant with an idea or two that will cut costs by more than $10,000.
Wednesday the group programs were the reverse of those the day before, with the F attendees participating in Siemens Day and the Gs hosting user presentations and open discussion. The OEM’s track featured presentations on hot topics associated with the compressor, combustion system, turbine section, generator, and exhaust end and casings; plus, a NERC (National Electric Reliability Council) advisory on the potential for lean blowout, cold-end bearing, repair quality, and outage support planning. G discussions focused on a R4 turbine-blade failure, general quality issues, unit updates, and lessons learned during the previous fall’s outages.
On Thursday, the final day of the meeting, the G users were invited to the morning F session, which offered topics of interest to members of both groups—for example, combustion dynamics, gas-only pilot nozzle issues, inlet-screen failure, and inlet and exhaust sections. The steering committees for both groups also solicited feedback from attendees both on the value of the Siemens presentations and the user-only sessions and what might be done to improve the conference.
Thursday afternoon featured two breakout sessions: one on steam turbines, the other on operational issues associated with the use of liquid fuel. Each of these sessions, which ran until 4 pm had a user-only component and an accompanying Siemens presentation.
Having a steamer session as part of the meeting makes perfect sense because most 501F and G engines are incorporated into combined-cycle plants and there is no independent steam-turbine user group to serve owner/operators. The 7F Users Group also covers steam turbines; plus, it has had a half-day workshop on heat-recovery steam generators (HRSGs) included in its value proposition for several years (p 2).
The liquid-fuel session was important because some users are converting gas-only systems to dual fuel. Most activity in this area is related to the concerns public power generators have regarding the possible need to burn oil to meet customer expectations in the event of a gas emergency (loss of a pipeline, for example). There also is the possibility that payments for firm power may be tied to having both gas and oil capability.
To learn more about what’s involved in a gas-to-gas/oil conversion, access www.combinedcyclejournal.com/archives.html, click 2Q/2009, click “Termocandelaria” on the cover. See also in the same issue, the article on the Arvah B Hopkins repowering.
Case history No. 1. A 501FC installed in mid 2000 that operated 16 hr/day suffered a performance loss of more than 10 MW. An off-line detergent wash recovered the lost megawatts. Over the next month, both a performance loss and decrease in compressor discharge pressure were noted.
Unit was shut down, forced-cooled, and detergent washed. Inlet guide vanes and R1 compressor blades were hand cleaned to remove a black substance. Unit was returned to service; lost megawatts again were regained. Plant personnel assumed there was a bad oil leak at the No. 1 journal but were not able to prove this. Inlet filters and evap media were near end of life and thinking was they might be a contributing factor. While looking for a bearing oil leak, a tear in a second-row compressor blade was found.
The OEM’s engineering team reviewed a photo of the tear and thought there was a high probability that it was caused by impact damage. A borescope inspection downstream of R2 was recommended. Another R2 airfoil was found missing a corner of its blade tip. That failure was believed to have been caused by high cycle fatigue and the liberated piece considered the cause of the tear in the first blade. A forced outage ensued and 177 compressor blades were replaced.
Case history No. 2. Same turbine described in the preceding case history tripped about four months later when the fire suppression system was initiated. Probe that initiated the trip is located at the left-side exhaust louver. A plant inspection team entered the compartment and found an insulation blanket smoldering directly under the exhaust louver and fire-sensor probe. The cause was thought to be a loose union in the oil vent line that allowed an insulation blanket to become soaked with oil and ignite.
Oil vent line was tightened, insulation blanket replaced, and the FM-200 bottles refilled. Engine was restarted and taken to base load while checking for potential fire hazards. Everything looked good. An hour later there was another unit trip initiated by the same fire protection probe as the first time.
A search for the gremlin was initiated immediately. Eureka! The root cause was an exhaust leak at the forward flange of the exhaust manifold. Crack was welded closed, exhaust manifold reinsulated, the FM-200 system refilled again, and the unit started. An infrared temperature gun was used to closely monitor the temperature of the fire detection probes until the unit reached thermal equilibrium at base load.
Lessons learned included the following:
- Make every effort to determine the root cause of forced outages and abnormal operating conditions.
- Locate fire detection probes where they provide the protection needed and are least likely to cause accidental activation of the suppression system. Install thermocouples adjacent to the fire detection probes above the exhaust manifold and program the DCS to alarm if the temperature exceeds the preset limit.
- Be sure you have easy access to spares, a backup charge of suppressant (if a water mist system is not installed), and anything else necessary to reactivate the protection system in timely fashion.
There was some follow-on discussion regarding potential issues associated with a breach in the exhaust manifold beyond unwanted activation of the fire suppression system. For example, exhaust gas bypassing downstream catalyst could put the plant out of compliance on NOx and/or CO in areas with particularly stringent air emissions limits. A possible safety risk: The presence of gas from a failed start or flowing gas for a system check.
Case history No. 3. This is the powerplant equivalent of a Sherlock Holmes mystery that can be traced to an OEM Technical Advisory (2004-017) that the user never saw. Editorial comment: This happens. E-mails can be deleted accidentally, hardcopy mail can be misplaced, etc. A good reason every plant should be represented at the user group meeting serving its model of gas turbine is that the OEM always reviews TAs and other alerts issued during the past year. It’s the easiest way to find out if you have missed something.
Here’s how this mystery began, progressed, and was eventually solved:
- Fall 2004. First scheduled outage after COD. Borescope inspection revealed no indications on compressor blades.
- Spring 2005. Casing was removed. No relevant indications were found during a visual inspection of rows 1-16.
- Fall 2005. Unit was in service for two years at this point. One blade had impact damage to its leading edge; liberated material left a notch measuring about three quarters of an inch by a third of an inch. Inspection of the inlet came up empty and the damage was attributed to FOD (foreign object damage), source undetermined.
- Spring 2006. Borescope inspection identified nicks in one R2 blade (leading edge), one R3 blade (tip of trailing edge), two R4 blades (both trailing edge), and one R5 blade (leading edge). Once again, inspection of the inlet house revealed no obvious source and plant staff assumed that the “new” damage noted might actually have been caused by the material liberated previously.
- Fall 2006. Minor impacts were noted on the leading edges of several R7 and R11 blades. No cause identified.
- Spring 2007. NDE (nondestructive examination) evaluation revealed no new indications. Might the gremlin have exited the engine?
- Fall 2007. No such luck. A new ding was found on the leading edge of one blade. Plant personnel returned to the inlet house and methodically combed it from the clean side of the filters to the trash screen and on the downstream side of the trash screen as well.
Perhaps the air filters were loose or pulling away from the wall during air-puff cleaning, allowing insects and debris to enter. Some insect debris was found; loose filters were tightened; a few aluminum nuts that held the filters in place had been stripped. All joints were thoroughly inspected and vacuumed. Once again, the source of the stealth foreign material was not found. The pesky gremlin had to be laughing at this point.
- February 2008. A quick inspection at the inlet revealed a ding that did not exist the previous fall. The unit was released for service after blending.
- Spring 2008. Borescope inspection revealed several indications throughout the compressor. A cover lift and significant repairs were necessary. The entire inlet structure was inspected once more, this time hand-over-hand and from top to bottom. Nothing. But then a second look at the inlet screen revealed a couple of places where small pieces seemed to have gone missing.
Sherlock’s magnifying glass carried the day. It confirmed that pieces of metal had liberated from the screen at the edges of the structure. Close examination showed that the metal had failed at weld joints and other attachment points. Solution: Welded trash screens were replaced with woven screens. There are several 501s at this site—a couple of FC+ engines and several FD2s. The ones with the woven screens had operated for years without any indication of metal liberation.
At user-group meetings for Siemens 501 and V engines, D-class through G-class, the one constant is in the area of generators. Difficult to recall a presentation in the last few years that was not made by Tom Schuchart or Jim Lau of Siemens or Howard Moudy of National Electric Coil (NEC). All three were in Glendale.
Moudy spoke at the 501F/501G user-only generator breakout session on Monday afternoon, bringing attendees up to date on spark erosion of stator bars and rotor pole-to-pole crossovers.
He said that NEC has been involved intimately in the investigation of several failures attributed to spark erosion, finding that the primary contributor to failure is loose bars in the stator core slots. Loose bars are conducive to vibration, which causes sparking. Vibrating coils make and break contact with the core, initiating the spark that causes erosion.
The type of semi-conductive side packing used in the stator core slots can be part of the problem, Moudy continued. NEC has found in its investigations several alternatives to side ripple springs, which it prefers for assuring long-term tight fit-up of stator bars in their slots.
He described two such systems: One uses flat semi-conductive side packing, the other a combination of semi-conductive tape and RTV silicone. Both were said to hold bars tight in the rotor slots at least initially. But over time the materials could shrink, enabling the bars to loosen and vibrate. This would not happen to a side packing system using ripple springs.
Moudy was on a roll, determined to convince the group that spark erosion should occur far less frequently than it does—if ever. Maintaining stator bars tight in their slots is the fundamental requirement for preventing this phenomenon, he emphasized. But gaps sometimes do occur despite best efforts. To minimize the damaging effects of high current levels in these instances, it is important to have a minimum value of surface resistivity on the bar semi-conductive coating.
Failures attributed to spark erosion have occurred in generators made by more than one OEM, Moudy added, wrapping up. Common denominators include large, air-cooled machines rated 18 kV or higher. However, it also has been observed on similarly designed air-cooled generators rated 13.8 kV.
Concerns with rotor connectors are not new, but they continue, he said switching subjects. While causes may vary among designs and OEMs, concerns can be addressed. Moudy offered several case studies illustrating the point and noted that NEC has corrected pole-to-pole crossover issues both in the shop and in the plant—even with the rotor still in the stator.
The company’s experience with pole-to-pole crossover issues indicates that start/stop cycles are a major factor in their occurrence. A statistical data base covering a range of generator designs, Moudy said, allows NEC to help customers better predict when repairs probably will be required.
He concluded his prepared remarks by inviting users to learn more about spark erosion and rotor connectors, and other generator issues as well, by visiting the NEC library at www.national-electric-coil.com.
The 501G Users Group once again had an enviable turnout for its annual meeting, averaging more than two attendees for each of the 12 plants in operation and the one under construction.
As mentioned at the beginning of this report, profiles of user experiences and group discussion dominate the 501G User Group’s sessions on all but Siemens Day.
Case history No. 1. Conversion of a 501G control system from TXP to SPPA-T3000 began with the reasons for making the change. Those stated typically were the same as the ones given for conversions from TPP to T3K for other Siemens frames: legacy control-related problems, TXP obsolescence, high cost of replacement parts, NERC CIP (critical infrastructure protection) compliance, and employee preference.
Project highlights and lessons learned were similar to those for the WDPF conversion to T3K for the 501FD2 engines at Klamath Cogeneration plant (p 110), including:
- Proper planning and preparation are critical to success.
- Schedule too aggressive.
- Significantly improved troubleshooting capabilities.
- No DCS-related trips during commissioning.
- Performance improvements.
The last is particularly important to any owner/operator investing in a conversion project such as this: “In the end, what do I get; what can I expect for my money?” This user compared data for the year immediately before the upgrade to that for the first six months after it. Starting reliability improved by 20 percent age points from 67% to 87%; equivalent base hours (EBH) of operation between trips increased from 393 to 515; EBH between runbacks nearly doubled from 127 to 224.
Case history No. 2. Problems caused by poorly performing valves in combined-cycle plants cannot be overstated: boiler tube failures and cracks in main steam piping caused by leaking spray valves on attemperators, condenser damage caused by leaking bypass valves, water loss from leaking boiler drains, etc. So it should come as no surprise that some users are experiencing problems with kettle-boiler bypass and flow control valves.
Binding of kettle-boiler valves can be linked to issues with one or more of the following parts: seat energizer rings, shafts, bearings/bushing, valve body, packing-gland follower and possibly the valve positioner. First problem the user encountered—this was back in mid 2007—was valve sticking on a back-seat. Manufacturer said it was the seat energizer ring. New parts were ordered, the valves pulled, and parts replaced/repaired. Sticking problems continued.
It soon became clear that if the problem was going to be solved, the plant would have to find the solution. Factors considered included: (1) bushings and shaft galling; (2) shaft straightness, bushing and packing bores; (3) concentricity of bores; (4) clearance between shaft and bushing and the interference on the bushing to the valve body; and (5) clearance on the packing follower to shaft,
The engineering effort pointed to the need for changes to materials and dimensions. Examples: Bushings were switched to Stellite® and an interference fit of 0.003 in. was added to the valve body; valve shaft was changed to Type-410 stainless steel and the shaft-to-bushing clearance was opened up by five thousandths.
The refitted valve was put in a test stand, heated to 800F, pressurized to 250 psig, and stroked 1500 times. No lock-up was experienced. Testing complete, the valve was disassembled and all components inspected. No issues—such as galling—were identified.
All valves for one of the plant’s three units were modified with the new internals in fall 2008. Between then and the meeting four months later there were no generation incident reports related to the RAC valves.
Case history No. 3. Kettle boilers for two of the plant’s three units were experiencing a high frequency of tube leaks, which were detected through the air-side drain system. A typical repair consisted of plugging the leaking tubes and performing a hydro to verify both plug integrity and that all leaking tubes had been identified. This strategy obviously works for just so long.
The fact that the kettle boilers for one unit had no leaks was not lost on plant personnel. Close inspection and review of drawings indicated the boilers for two units had been installed incorrectly: They were set on the foundation and mounting hardware was tightened and did not allow for thermal growth. The tube bundles and shells wanted to grow but could not expand and the tubes deformed.
To learn more about kettle boilers and some of the issues plant personnel encounter, access www.combinedcyclejournal.com/archives.html, click 2Q/2008, click 501F Users Group on the cover. Work done by Scott McLellan and his colleagues at Arizona Public Service Co’s West Phoenix Generating Station on rotor air coolers begins on the first page of that report. ccj