If you weren’t there, you missed ‘a really big show’ in terms of content
No user delegate could have asked more of a steering committee than the 501F leadership delivered at the 2007 Annual Conference, last January, in San Diego—except perhaps to have avoided the deluge that accompanied that meeting. The group, chaired by Paul Tegen of Cogentrix Energy Inc, shared its venue for the first time with the 501G User’s Group.
The three-and-a-half days of meeting time included more than a dozen formal presentations both by users and by Siemens personnel, and a half dozen more by non-OEM suppliers; discussion forums on the compressor, combustion system, turbine, and inlet/exhaust sections; and a cramped four-hour vendor fair that resembled Times Square on New Year’s Eve (without noise makers). There were a couple of first-class social events as well.
The 501F and 501G met separately most of the time, but did combine forces for certain presentations and for the vendor fair. In sum, there were more than 160 users in attendance. A report on the G meeting appears elsewhere in this issue.
Both groups will co-locate again in 2008 at the Contemporary Resort in Walt Disney World, Orlando, January 14-17. See the advertisement on the next page for details.
The report that follows presents details on three user presentations. Another, the T3000 control system conversion (from TXP) at the High Desert Power Project, had been profiled previously (access www.combinedcyclejournal. com/archives.html, click 2Q/2006, click “Upgrading controls. . . .” on the issue cover).
Keep in mind that some user presentations address sensitive information and it is made available only to those with “a need to know”—very specifically, 501F users. To keep current on fleet issues of interest, you must attend the meeting in person.
All presentations by third-party equipment and services providers are summarized as are key Siemens Day discussions. Additionally, the OEM prepared a special half day seminar at the end of the meeting on repair technologies and processes. It encompassed superalloys, NDE (nondestructive examination) advancements, new coatings, incoming inspection, etc. That material is accessible to all Siemens users via the Customer Extranet Portal.
Mike Magnan, plant manager, PPL Lower Mt Bethel Energy LLC, was one of several 501F User Group members who worked together to form the I&C focus group in 2004. The team included Ivan Kush, a controls specialist with Calpine Corp. Idea behind the initiative was to present to Siemens, in an organized manner, the concerns of owner/operators regarding the TXP control system. Magnan continues to provide the leadership for the so-called I&C Forum, which is especially vital today given Siemens’ announcement early last year that it would phase out its Simatic S5 and Simadyn products—critical components of the TXP—effective October 2006.
Background on how the I&C Forum works and how you can participate (easiest way, e-mail Magnan at email@example.com and say “Count me in”) can be found on the CCJ website. Access www.combinedcyclejournal. com/archives.html, click 2Q/2006, click 501F User’s Group on the issue cover, scroll to “Web forum facilitates communication between users, OEM.” That portion of the 501F report also provides a summary of Siemens’ announcement regarding future support of the TXP platform.
More information on Siemens’ TXP service group—organization, names of key personnel, plant-level training, details on the TXP Remote Expert Center (high-level support 24/7), spare parts, long-term service program, etc—was provided by Jeff Miller, manager of service solutions, on Siemens Day. A short summary of what Miller had to say appears near the end of this report. Access Miller’s presentation via the OEM’s Customer Extranet Portal for details.
Most powerplant personnel are enamored of “big iron” and shy away from controls, which remain mostly invisible to the O&M staff. It could be one of those “out of sight, out of mind” things. No matter, Magnan rallied the group around the I&C Forum with a background on progress thus far, future goals, etc. He was trolling the audience—which included a significant number of first-timers—like a marine recruiter looking for a “few good men” (or women) to actively participate in the forum and provide muchneeded guidance to the user’s group as a whole.
Gary Giddings, Progress Energy Florida’s Hines Energy Complex.
Matt Kaleyta, CT manager, Dynegy Generation Fleet Operations.
Mike Magnan, plant manager, PPL Lower Mt Bethel Energy LLC.
Raymond Martens, plant manager, Klamath (Ore) Cogeneration Plant.
Russ Snyder, plant manager, Cleco Evangeline LLC’s Evangeline Power Station.
Bill Wimperis, director of engineering and construction, Constellation Generation Group, supports the committee as-needed.
Web meetings with Siemens. Magnan then updated the users on the two web meetings conducted in 2006—the first in mid July, the second in mid September. The July session included an update on graphic enhancements to the operations monitor (OM) screen to help operators immediately identify unloads and load rejections. Specifically, flashing red boxes now appear at the bottom of every graphic when an unload or load rejection occurs.
Three other topics on the July webcast: leak-detection logic associated with the overspeed trip valve; TXP training schedule; update on I/O card support. Regarding the last item, one of the users’ concerns was that if a plant does not participate in the Siemens long-term service plan, it could take weeks for the OEM to repair any obsolete circuit boards. Plus, Siemens will not guarantee a turnaround time for repairs unless an LTSP is in place.
Two non-OEM alternatives for repair of TXP cards and power supplies are listed below. Both companies told the editors that they also stock some TXP cards.
- Gas Turbine Controls Corp, Ardsley, NY. Contact Mike Napoli (mnapoli@gasturbinecontrols. com, 914-693-0830 x-24).
- Powergenics LLC, Midlothian, Va. Contact Randy Riggs (rriggs@ powergenics.com, 804-320-2761). The September web meeting was highlighted by the following discussions:
- Web4TXP. Provided users guidance on how to configure the TXP control system to allow access to control room displays via the company intranet or via the internet.
- AP optimization process. Discussed the issues with improperly loaded application processors: inefficient processor operation; high peaks and low valleys could prevent implementation of additional control mods or product enhancements.
Here’s how the optimization process works: The TXP Hotline (officially, the Remote Expert Center, Orlando) dials into the control system and retrieves current AP information. The electronic cache is analyzed and then optimized by repackaging or by shifting around existing applications packages to “flatten” the AP load.
- Controls upgrades to accommodate inlet heating. The 501F User’s Group is probably the most active of the GT user organizations in promoting both awareness and avoidance of inlet icing. The next section of this report includes a discussion of icing-avoidance solutions from a non-OEM supplier. Following that, the Siemens Day “Modernization, upgrades” presentation summary identifies two anti-icing options available from the manufacturer.
Reason for the I&C Forum’s interest in icing is that the Technical Advisory 2005-015 addressing the subject mentions that TXP modifications are necessary to accommodate both Siemens’ icing solutions because they heat with compressor bleed air. Controls mods would be an add-on to the cost of the inlet heating system and to the penalty taken for power lost by bleeding off air from the compressor.
One user said that to his knowledge no 501F user has yet purchased a Siemens inlet heating system. He added that participants in the forum generally were of the opinion that a thorough cost/benefit analysis of all inlet heating options (including non- OEM steam coils and glycol/water heat exchangers) is warranted before a purchase decision is made.
Another concern with integrating inlet heating into an automated plant controls scheme is that if icing were detected, the GT might be unloaded automatically to the lowest operating point which, in turn, could compromise a power services agreement and penalize the plant financially.
Magnan pointed out that inletguide- vane position is rigidly controlled by the TXP to assure emissions compliance and to minimize the possibility of harmful combustion dynamics. Thus the only way to change IGV angle to mitigate an icing condition is to drop load— at this point in time, at least. Siemens, he continued, does not endorse changing the IGV schedule. However, the OEM is said to be working on a modification to improve operational flexibility.
Magnan concluded the I&C Forum session at the San Diego meeting by urging users to help colleagues by sharing control-system parts. Participation in the forum would enable such arrangements. Details from past web meetings are available on the CEP; announcement of the next I&C Forum session is also.
Following the I&C Forum session attended by all 501F users, Magnan and Kush cochaired a users-only breakout session on the TXP; that was followed by a collaborative breakout on TXP issues between users and Siemens engineers. Total time for both breakouts was about 90 minutes.
Don’t let unexplained FOD/DOD wreck your compressor
In the summary of Siemens Day presentations, the OEM’s Steve Holland mentioned a hardware upgrade to mitigate compressor R2 diaphragm distress reported on a few of its 501FCs, generally before the first major. Release of a design mod for the troublesome one-piece gussets is expected this summer.
One of the GTs damaged by R2 gusset liberation was Unit B in Power Block (PB) 1 at Progress Energy Florida’s Hines Energy Complex in Bartow. Harry Carbone, PE, principal engineer for the utility’s GT fleet, made the presentation. He is a frequent speaker before user groups; a respected high-tech troubleshooter with problem-solving experience on virtually all aspects of major frame packages.
Hines is a huge facility, consisting of four 2 × 1 F-class combined-cycle power blocks. PB1 has two Siemens 501FC+ engines, PB2 and PB3 each have two Siemens 501FD2s, and PB4, now in commissioning, has two GE 7FAs. The power blocks operate about three-quarters of the year— base-load during the day and a minimum power most evenings.
The PB1B compressor failed in June 2006. Operations backgrounder: First major conducted in 2004 at slightly more than 35,000 actual operating hours (OH); a combustor inspection was completed in spring 2006 at just under 48,000 OH. A borescope inspection conducted during the CI revealed minor FOD (foreign object damage), but not enough to initiate an alarm.
In May 2006, engine power and compressor efficiency began trending downward; a water wash did not help recover the lost output. Plant personnel could not identify a reason for the performance degradation. Everything appeared normal; the unit did not alarm or trip.
In June, after only about 1000 OH since the CI, the unit was taken out of service for a borescope examination. Damage identified warranted lifting the upper casing half for closer look (Figs 1, 2). Engineers found the R2 vane section with a shot-peened surface appearance, gussets missing, and no aft seal ring (Fig 3).
The one-piece gusset (Fig 4) has more area and less weld than the two-piece design (Fig 5), and is the focal point of the cracking problem as the illustration shows. There have been no reports of cracking on the two-piece gusset. Carbone’s scorecard for the damaged compressor looked like this:
- R1, one cracked weld (3% failure rate).
- R2, all welds cracked and all gussets missing (100% failure rate).
- R3, seven welds cracked (23% failure rate).
Here’s how Progress Energy engineers theorized the failures occurred:
- The rotor OD is spinning at about 275 mph in cavity 1, more than 275 mph in cavity 2, and at about 400 mph in cavity 3. Investigators surmised that the highest velocity was in cavity 2 (where most of the damage was done) because the 12 bolt heads in that location acted as fans. Incidentally, those bolt heads had a shot-peened appearance like the R2 vane section.
- The circular and radial velocity profiles in the cavities are impeded by the one-piece gusset, thereby imposing forces on those structural members that may be cyclic because of vortices and/or unsteady flow conditions. These forces excite the gussets—perhaps at their natural frequency—and produce alternating stresses that are larger than the endurance limit of the material. Fatigue failure is likely over time.
Based on the analysis conducted, the utility made these internal recommendations:
- Remove the one-piece gussets from FC units and modify to two-piece or scrap and install new two-piece gussets. Replace one-piece gussets in R2, the row considered most likely to fail, at or before 8000 OH; R3, on or before 16,000 OH; R1, between 16,000 and 24,000 OH. Also, if the case is opened for any reason, replace all one-piece gussets found.
- Borescope inspection. Check for cracks in the R2 seal ring, cracks or peen marks in the ID shroud ring, any FOD or DOD (domestic object damage) after R2, and/or any other abnormalities. Don’t dismiss as “minor” any FOD/DOD in R2 or downstream.
One of the benefits of participating in a model-specific user group like the 501F is that you learn first hand about the latest causes of unavailability and performance deterioration experienced by the fleet. Another: You generally get to hear direct from the OEM about product modifications and upgrades to mitigate causative issues and keep your engines in top condition.
Until recently, Siemens referred to such modifications as ProdMods. At this meeting, however, the OEM’s Mark Kamphaus introduced a new term, “BSols,” for business solutions, which essentially has the same meaning. Owner/operators typically favor the implementation of most Prod- Mods, but their confidence increases knowing that a colleague had the same problem as they now do and implemented the mod with positive results.
The 501F steering committee works diligently at identifying users who are among the first to implement a particular mod and encouraging them to share their experiences with colleagues. In San Diego, Heath Ivey, lead planning and scheduling specialist for Cleco Midstream Resources LLC’s Evangeline Power Station, St. Landry, La, addressed the group on his plant’s experience in implementing the “Balance access tube/Filter bleed pipe support” ProdMod.
By way of background, Evangeline is equipped with three W501FC+ GTs; they began commercial operation in July 2000. For readers unfamiliar with the balance access tube, Ivey describes it as a pipe that traverses the compressor discharge case and permits access to rotor balance plugs without lifting the upper compressor casing (Fig 6). It is retained by sleeve supports on both ends of the pipe.
Looking at Fig 6, the balance access tube is at a negative angle from right to left. The support sleeve at the right is welded to the inside wall of the outer shell. The right end of the balance access tube terminates at a flange that is bolted to the outside wall of the shell. Thus the tube can be removed by unbolting the flange and pulling it through the shell. The inner support tube at the left (identified by the letters “[s] teel”) terminates at the torque tube. At the upper left, you can see the fuel gas ring for one of the combustor cans (basket removed).
Why the ProdMod. Having the above description above facilitates an understanding of the issue and the “fix.” Turbulence in the compressor discharge case causes fretting of the balance access tube if it is allowed to “rattle” in the support tubes. Should such fretting cause the balance access tube to break, the free end will flutter about and any pieces of metal liberated can damage combustor cans and possibly travel to the turbine where blade, vane, and rotor damage are possible.
The ProdMod involves replacing the original carbon-steel components with ones of more durable stainless. You can reduce the vibration that induces fretting by increasing the contact area between the access and support tubes. Do this by making the new access tube about 4 in. longer than the original. Be sure to verify proper alignment of the balance access tube before new support sleeves are welded in place.
Fig 7 shows where an inner support tube was cut off flush with the compressor case. The threaded hole is for a compressor rotor balance plug. Important point: The inner support tube is back-welded to the torque tube housing before rotor installation. Thus a major inspection (which requires rotor removal) is needed to remove the last piece of the inner support tube barely visible in the picture.
Fig 8 shows that a section of this inner support tube has been replaced to eliminate any possible damage that occurred to it from fretting. Length of the repaired support tube is the same as that of the original. The 2-in.-diam × 6-in.-long outer support tube is welded to a 5-in.-square × ½-in. thick base plate (Fig 9).
Lots of things go wrong with operating equipment, and for a variety of reasons. So it’s logical to think that if you work in powerplants long enough, you will either experience a failure or see the results of one firsthand. When a failure occurs, owners generally want to know why because there probably will be insurance issues to deal with—possibly legal as well—and they want to prevent a recurrence. Idle generating plants lose money rapidly.
The Gulf hurricanes of two years ago reminded asset managers how important it was to have disaster plans in place and to make them living documents. It’s not much of a stretch to extend that thinking to equipment failure, which can cause a financial disaster as great as any hurricane.
“Failure investigation principles for combustion turbines: Combining science and art,” was an invited presentation at the San Diego meeting. What Principal Engineers Ron Munson, PE, Mechanical & Material Engineering LLC, and Dr Swami Swaminathan, Turbomet International, had to say was important for all powerplant management and O&M personnel to hear. In case you’re unfamiliar with Austin-based M&M Engineering, it is one of the foremost failure-analysis consultancies in the power industry.
The first thing Munson and Swaminathan set out to do was to get everyone on the same page regarding, “What is a failure?” One man’s failure may be another’s hiccup. The M&M team answered the question as a plant manager might: A failure is the inability of a turbine to perform its function with reasonable safety. This may be caused by a fractured or cracked turbine blade, plugged fuel nozzle, or dirty air filters.
More succinctly, any condition leading to inability to perform is a failure. However, insurance companies and their policies have different definitions to separate mechanical breakdown from normal maintenance.
But the definition of a “failure,” they continued, can vary greatly. The financial people in the organization may look at it as a repair cost beyond planned maintenance budget, an outage exceeding the scheduled time, or as an occurrence that exceeds the insurance deductible.
Failure analysis is another term that can have a broad definition. For example, some might consider it identifying the damage mechanism; to others it might be determining both the damage mechanism and cause; still others will see it as the root cause of the damage. These certainly represent different levels of effort.
The cost and certainty of each of the three levels of failure analysis defined above will vary significantly. To illustrate: Assume that it costs X to determine the damage mechanism with a certainty of 80 to 99%; identifying both mechanism and cause can cost 3X to 10X with a 50% to 90% certainty; finding the root cause (RCA) can run from 5X to 100X with a certainty below 100% (in failure analysis, there is no 100%). At this point, you can envision at least a few members of the owner’s team asking something like, “How much do we really want to know, how much to we really have to know?”
The basic steps in the failure investigation came next and it was an eyeopener regarding the number of things that had to be done. They included securing and preserving the damaged equipment, documenting each and every step; assembling the RCA team; dismantling the engine to the extent necessary; conducting nondestructive and destructive metallurgical analyses; preparing a report of the findings and presenting it to the RCA team.
Assembling an RCA team that will be both collaborative and objective, as well as protect the interests of all parties, is a difficult task. You want representatives of the owner/operator, OEM engineers, the EPC and its subcontractors if still in warranty, insurance adjuster, and repair vendor on the team. However, you must control team size for efficiency.
You do not want an RCA team comprised only of the OEM’s personnel and its contractors. The OEM has commercial issues that cannot be overcome. Proceed with caution if an LTSA (long-term service agreement) is in place. LTSAs can restrict the accessibility of the offending hardware and limit the usefulness of any analysis.
Keep in mind, too, that there generally will never be a single root cause for any failure. The RCA team’s output will be a weighted list of contributory causes.
Definitions, administration, and politics in hand, it’s now time to begin sifting through metallurgical, mechanical design, and related evidence. Important to remember at this stage is that GTs are particularly susceptible to the occurrence of undocumented failure mechanisms because they contain components made from state-of-the-art alloys designed for high-temperature service.
These “superalloys,” as they are known, are routinely introduced into service after short testing cycles (less than 10,000 hours). But complex interactions of alloy constituents may not come to light until a machine has operated 30,000 or 40,000 hours. Munson’s Axiom is worth noting:
“The more sophisticated the alloy, the more insidious and unpredictable the damage mechanism.”
The M&M team next gave the users a short course in strengthening and degradation mechanisms. It was obvious after a couple of slides that most in the room could benefit from a Metallurgy 101 course, if only to learn the language. In the degradation portion of the presentation a very important observation was noted: Superalloys used in gas turbines are very sensitive to fabrication and/or processing factors; further, that all manufacturers are not created equal.
This should not be new to readers of the COMBINED CYCLE Journal. The extensive coverage given to P91/T91 steels for heatrecovery steam generators and high-temperature steam piping has stressed repeatedly the importance of tight quality control in manufacture and assembly— particularly during preheating, welding, and post-weld heat treatment.
Metallurgists will tell you the metal does not lie. The complete history of a superalloy’s manufacture and service can be read from its microstructure. In summing up, the speakers suggested that metallurgists have a role, but they only provide a piece of the puzzle. Be objective, they advised; if the data are contradictory to your theory either the data are wrong or your theory is wrong.
Experience with non-OEM HGP parts
Competition is a driver of technology advancements. This certainly is evident in hot-gas-path parts for F-class GTs. Non-OEM suppliers are challenged by having to do what they do better, faster, and at a lower cost to the user than the turbine supplier. Otherwise, why would anyone buy from them?
PSM, Jupiter, Fla, is a third-party provider of HGP parts and well known to 501F users; more importantly, generally well respected. The company is rapidly building an enviable experience base in R1-R4 blades and vanes, fuel nozzles, transition pieces, etc, said Tim te.Riele, VP of airfoil engineering, who was invited to update the 501F User Group on the company’s progress in extending the service lifetimes of critical engine parts.
His presentation began with a review of some HGP problems experienced by 501F owner/operators, including the following:
- First- and second-stage vanes. Premature platform oxidation/ erosion and airfoil cracking.
- R1 blades. (1) Large cracks that typically develop on the leading edge of the platform on the concave side, requiring premature removal of the affected blades. (2) Failure of brazed tip plates, which can compromise airfoil cooling.
- Third-stage vanes. Metal creep has allowed these parts to move aft in some machines and contact downstream rotating components.
- Transition pieces (TPs). Failures, sometimes resulting in the liberation of metal, have dictated premature replacement of TPs; in some cases, downstream damage has been significant. PSM, te.Riele continued, has addressed these issues with new designs to minimize or eliminate them. He supported this comment with a précis of work done by the company; plus, he reviewed operational experience. Here are the major points made by te.Riele:
- TPs. Made significant changes in 2002-2003 to the body shape, cooling scheme, mounting method, and sealing system of the TP that was being offered by the OEM for the 501F, to improve its durability (Fig 10). PSM introduced the redesigned TP—and pilot fuel nozzles as well—to the Calpine Corp fleet in 2003. Since then, dozens of sets of these TPs have been installed by Calpine and several commercial owners with excellent results, te.Riele said. The TP fleet leader has approximately 24,000 hours of operation without refurbishment.
- First-stage vanes. Enhanced platform cooling to extend the service life of these components by nearly three-fold compared to the vanes originally supplied by the OEM for the 501F (Fig 11). What designers did was redirect cooling air from the airfoil to reduce platform operating temperature without impacting engine performance or emissions. Fleet-leading firststage vanes have accumulated approximately 30,000 operating hours to date without removal or refurbishment.
te.Riele mentioned two field issues that recently have come to light: The first, in evidence on both OEM and PSM vanes in cyclic applications, results in severe trailing-edge oxidation/erosion on about 10%-15% of the firststage vanes. The second causes airfoil leading-edge erosion on the convex side. This is seen most often on some parts from early sets of PSM vanes.
The fixes: A solution to trailingedge oxidation/erosion is in the final stages of design verification; it is planned for commercial release in the fall. The leading-edge erosion issue has been remedied with a design change in the company’s current production offering.
- R1 blades. Design features incorporated included improved platform cooling, an electronbeam- welded tip plate, and a patented trailing-edge stress-reducing undercut. The improved cooling features have enabled R1 blades in base-load applications to achieve 24,000 hours of service (Fig 12), which was one of the OEM’s goals for the 501F. PSM experts say repairs at the first HGP inspection typically will be minimal.
Blades in cycling units also should meet the 24,000-hr requirement, but it is likely they will require a more extensive repair regimen than base-load parts. One field issue that occurs in cyclic environments for both OEM and PSM R1 blades, noted te.Riele, is thermal/mechanical fatigue (TMF), which causes cracking of the platform.
Fleet leaders in both baseload and cycling service have approximately 20,000 hours of service on their R1 blades. PSM is expected to release a fix to reduce—possibly eliminate— platform cracking next spring. A repair procedure will be issued at that time as well.
- Second-stage vanes were redesigned as a bolted pair to eliminate airfoil cracking. Also, the base alloy was changed from MarM509 (cobalt) to weldable Inconel 939 (nickel). Field experience, said te.Riele, shows that the boltedpair arrangement has eliminated airfoil cracking.
Oxidation/erosion on the ID platform experienced by the OEM was not addressed in the original PSM design, he continued, because it was not considered a major field issue at the start of the component design process. However, PSM has experienced similar deterioration and subsequently incorporated multiple design changes to mitigate the issue. The fleet leader had about 13,000 hours on its second-stage vanes before they were refurbished in spring 2006 because of an upstream failure of OEM TPs.
- R2 blades. PSM’s design goes beyond the OEM’s trailing-edge stress-reducing undercut to further reduce stress. The fleet leader has about 20,000 hours of operation on its PSM blades. te.Riele announced that a set of R2 blades with a new dense vertically cracked (DVC) thermal barrier coating (TBC) had been delivered to the first customer for this product and that it was now a commercial option for the fleet.
- Third-stage vanes offered by PSM make use of the same cooling circuit design as the OEM, but the base alloy has been changed from X-45 (cobalt) to weldable Inconel 939. The latter was shown, by way of inspection at 13,000 hours, to eliminate the creep issue. The fleet leader is at approximately 20,000 hours of operation to date.
Doing more with less
The typical 2 × 1 combined-cycle plant has two-dozen or fewer employees. Many of these people are from outside the industry—particularly at plants remote to population centers. The highly automated nature of GTbased generating facilities, coupled with a relatively standard fuel and relatively standard equipment, make this possible.
People with good computer, mechanical aptitude, electrical, and I&C skills can become productive members of a GT-based plant’s O&M team very quickly. One plant manager at a 600-MW, 2 × 1 facility told the editors recently that two-thirds of his staff had never been in a powerplant before he hired them. And his facility had achieved virtually all operating goals since startup.
That’s laudable. However, making a good O&M staff excellent requires training beyond basic skills. And operational excellence is a necessity in today’s competitive power markets to assure that your facility is dispatched first and delivers when required by contract. High availability, starting reliability, and efficiency are table stakes in the game of competitive power generation.
Dave Huckeba, who until recently was director of business development for the GPiLearn unit of General Physics Corp, Columbia, Md, was invited by the steering committee to help plant supervisory personnel make their staffs more effective through computer-based training.
User-group presentations are time-challenged and if Huckeba’s presentation had a fault it was in too much information about General Physics, industry and plant trends, and trends in webbased training (WBT). Perhaps a better approach would have been to suggest to plant supervisory personnel—based on the company’s extensive experience in training—what O&M personnel need to know to make a positive contribution to the bottom line and how long that learning process might take.
If you have never investigated the attributes of WBT, it’s certainly something to look into. GPiLearn’s growth numbers are startling in the electric power industry. The client base grew from four customers at the beginning of 2002 to more than 140 at the end of 2006—including many “heavy hitters” such as Calpine, PSEG, Suez, Reliant, PSEG, TVA, Ameren, Edison International, etc. And client retention was near 100% over that period. Courseware more than doubled over the five-year period from less than 300 hours to more than 600.
The advantages of WBT over traditional methods are particularly significant, including: the time it takes to deliver information, 24/7 access to subject matter/lessons, self-paced learning, consistency of information across the user base, ease of updates, ability to track progress of system users, and low cost.
Huckeba quickly ran through two case histories, one for Dynegy and the other for Duke Energy. For Dynegy, General Physics customized a training program for the 501F that the power producer’s instructors could implement at multiple sites and formulated a skills-based training program (using Job Performance Measures that each of 12 sites could customize themselves). For Duke, General Physics created curriculums for operations, electrical, mechanical, and I&C personnel to support the company’s “pay for skills” paradigm.
To learn more, visit www. GPiLearnWBT.com. Questions? Contact Denise Barbato (dbarbato@ gpworldwide.com, 410-379-3659).
Looking for gas leaks Users are always looking for better ways to do things so the 501F steering committee invited John Woods (firstname.lastname@example.org, 800-633- 3591, www.flangebandit.org) of Missouri to show the group how to find leaking flanges in natural gas fuel lines faster and at less cost than the industry norms.
Woods is one of the three principals— two with powerplant experience— at Joplin-based Flange Band-It™ LLC who came up with the idea to use the equivalent of a large rubber band with a sniffer hole to eliminate the make-work associated with taping flanges and then removing tape after testing is complete.
At most plants, the O&M staff verifies leaktight bolted flanges this way: Wrap masking or aluminum tape around flanges that connect the gas supply manifold to the burners, punch a small hole in the tape, and use a portable combustible gas detector “smell” for gas. Two problems with this method, said Woods.
First, installing and removing tape is expensive. The heat that engulfs the GT fuel system bakes the tape on the flanges, making it brittle and difficult to remove. Unless the old tape is scraped off, continued Woods, when the time comes to conduct the test again, it’s difficult to get a tight seal with the new tape (Figs 13, 14). And a tight seal is necessary to have confidence in the test results.
Second, if flanges must be broken there is the chance that residual tape will flake off and find its way into fuel lines. Doesn’t take much to block gas nozzles and hinder a startup. Large frame users are well aware what a failed start costs when the plant is “in the money.”
Woods was armed with the results of time-and-motion studies that showed the cost of using tape. He also had a few testimonials to share. By the time Woods finished the short presentation, many found merit in the new product and thought it was at least worth a try.
Flange Band-It is made of flexible, elastomeric material that can be ordered to fit over virtually any standard flange size. Depending on the application and the material, it can withstand temperatures of up to 500F.
Howard Moudy of National Electric Coil, Columbus, Ohio, focused on the Siemens AeroPac generator and information NEC had compiled from multiple experiences involving inspections and rewinds of this and similar machines. Dialog with other AeroPac owners and operators confirmed NEC’s experiences.
He said that AeroPacs have exhibited high levels of spark erosion/slot discharge; some have had a significant presence of ozone. Several AeroPpacs and similar units have failed in only four to six years of operation. Moudy mentioned that NEC had seen a parallel history, and had similar experiences, with the Westac (for Westinghouse air-cooled) generator, another Siemens product.
The presentation covered the results of NEC’s investigations into the original AeroPac design and how several factors contribute to premature deterioration and/or failures (Fig 15). He also presented recommendations for improving the winding design and manufacturing process during the course of a rewind to make the units better suited for longterm reliable operation.
Readers are referred to a complementary presentation on AeroPac generators made by Jim Lau during the Siemens Day activities. A brief summary of the company’s spark-erosion investigation and ongoing work to prevent it can be found in the last few paragraphs of this 501F conference report. More detail is available by accessing Lau’s presentation on the Customer Extranet Portal (customers only).
How to heat GT inlet air The 501F Users Group allocates more program time to inlet icing than any other organization serving GT owner/ operators—at least based on an informal survey by the editors. Perhaps it’s because steering-committee member Ray Martens, the plant manager at Klamath (Ore) Cogeneration, has witnessed first-hand the damage ice can do to a compressor.
A few years ago, Martens installed cameras on both sides of Klamath’s GTs for visual confirmation of icing and did some in-house programming to sound an audible alarm when conditions were ideal for ice formation. When the alarm sounded, operators checked the cameras and increased load immediately if ice was building up; IGVs (inlet guide vanes) opened and the pressure drop across the vanes decreased to prevent further icing. Load and other operational adjustments were fine-tuned later.
That OEMs listen to their customers was in evidence at the group’s 2006 meeting when Siemens announced a 501F product modification (ProdMod) to sound an audible alarm when an icing condition exists and/or initiate an automatic runback. The Klamath system described above has since been replaced by the Siemens ProdMod.
Ice formation at the bellmouth and on IGVs is not your only concern; ice sometimes forms on the secondstage diaphragm, which is more difficult to see via the cameras.
Additionally, icing of inlet filters can block air flow and perhaps trip your GT on high “delta p”; ice, and possibly water, can damage your filters, thereby allowing airborne particulates to enter the compressor; water that gets into the inlet air house, and any ice that forms there, can be sucked into the compressor and damage blades and vanes; corrosion of silencers and other parts of the inlet air house caused by moisture ingestion is a source of solid particles that can contribute to compressor damage.
The bottom line: Give your GT the protection it requires to achieve top availability and efficiency by preventing water, ice, and airborne particulates from entering the compressor. This is easier than it might sound if you retrofit the inlet air house with the filters, rain hoods, louvers, etc, that work best for weather conditions in your area.
Keep in mind that inlet air systems installed during the boom years—2000 to 2004—often were purchased in “lots” to a common design by turbine OEMs; they were not custom-designed for your plant location. As it turns out, that’s the plant owner’s responsibility.
Hydrometeors. The 501F steering committee invited Pneumafil to speak about heating inlet air as a means for protecting GTs against ice damage. Rick Smith made the presentation, but he has since left the company and the editors worked through Steve Klocke (sklocke@ pneumafil.com, 704-398-7661), VP of aftermarket sales, to ensure accuracy of the summary that follows.
As most powerplant personnel know, icing can occur when free liquid or solid water is entrained in the inlet air and the temperature is near freezing or below. Also, that air with no free water can contain enough moisture to allow condensation and possibly ice formation.
Smith introduced many in the room to a new term—hydrometeor— when he began talking about rain, fog, and snow as precursors of ice formation. The American Meteorological Society’s website defines the term as any product of condensation or deposition of atmospheric water vapor, whether formed in the free atmosphere or at the Earth’s surface; also, any water particle blown by the wind from the Earth’s surface. Editorial translation: A hydrometeor is a particle of moisture in any of its various forms and of any size.
The term is an interesting one because liquid or solid particles slamming into compressor components at high velocity can be said to behave like tiny meteors, at least based on physical examination of IGVs and first-row blades that have experienced moisture ingestion.
New terminology in place, Smith went about describing tools for rejecting hydrometeors—including hoods, louvers and blades, pads/coalescers. Hoods are used to exclude large, fastfalling droplets and ice crystals from the air (Fig 16). They are designed to create an inlet velocity lower than the terminal velocity of the droplet or particle.
Louvers and blades are used to trap, coalesce, and drain large and intermediate-size droplets from the air (Fig 17). They work this way: A droplet’s inertia causes it to impinge on a surface; surface tension causes droplets to coalesce and drain. Pads/ coalescers (Fig 18) operate on fog particles (typically in the range of 10 to 40 microns in diameter) much the same way as louvers and blades remove larger droplets.
The need for heat. If your goal is to protect both the filters and bellmouth from icing, the heating system must be the first component the inlet air encounters. If only the bellmouth is of concern, the heater can be installed in the ductwork, thereby reducing both the size and cost of that component. However, heating systems located inside ductwork must be designed so they don’t pose an FOD (foreign object damage) hazard.
Methods of adding heat include (1) high- and low-pressure compressor bleed air, (2) electric heating elements (tubular), and (3) standard water/glycol or steam heat exchangers.
Routing some of the engine’s combustion air to the face of the inlet reduces output and makes some noise. When HP compressor bleed air is the source of heat, the delivery system is a series of small-diameter vertical pipes supplied by a manifold.
Least-cost design is to drill the holes into the vertical pipes and distribute the hot air perpendicular to the ambient air stream. But this is an extremely noisy solution. Installing nozzles—each with its own silencer-equipped orifice—in the vertical pipes reduces the noise level below 100 dB(A).
When LP bleed air is the source of heat, designers install a single large silencer to lower the air pressure and attenuate the expansion noise (to about 92 dB(A)). Hot air then is routed to a distribution grid consisting of small slotted stainless-steel ducts.
Electric heat is recommended only when no other heat sources is available. A typical F-class GT in a cold clime could require as much as 4 MW to perform the service required—obviously power that might be sold.
Water/glycol exchangers are relatively common at generating stations and generally make use of energy that might otherwise be wasted. The low pressure drop through these exchangers, coupled with the use of waste heat, and inherent freeze protection make them ideal for heating GT inlet air.
Steam coils also are well known to powerplant personnel (Fig 19). Where steam is available, these are a good choice. Startup and shutdown procedures must caution against freeze-up.
Smith next ran through a primer on how to calculate heat load and then reviewed a heating-coil retrofit case history. Fig 20 shows a steam coil being lifted into place at a plant in Colorado. Steam source is the heat-recovery steam generator; drains return to the HRSG via the blowdown tank. Reason for the retrofit: The air inlet system had been ingesting snow and freezing fog, and the filters were blinding and causing runbacks.
More specifically, steam is taken from the intermediate-pressure auxiliary steam header at 365 psig/514F; a control valve modulates the amount of steam admitted to the coils. Minimum coil operating pressure is 40 psig to prevent freezing. Condensate is collected in a large standpipe just below the inlet filter and a control valve maintains a constant water level.
Total cost for the two systems installed at this facility was about $1.5 million. Total installation time was three months but the actual outage time was only three days per inlet. Note that the turbine OEM had anticipated installation of an inlet heating system and the DCS was configured to accommodate it. Thus electrical and controls installation and integration were fairly simple.
John Schuck, who manages the Office of Business Excellence in President Craig Weeks’ Operating Plant Service Div, kicked off the core of the Siemens Day presentations with an update on improvement actions taken by the OEM in 2006 and how results compared with customer expectations.
After introductory remarks by Rick Mould, executive vice president of the division and head of its US/ Canada region, Schuck reviewed the 2006 improvement targets established based on customer survey data. He focused on technical information, technical responsiveness (speed with which solutions are implemented), warranty claims resolution, outage reports/invoicing, and service agreements—essentially the communications and outagesupport aspects of the company’s long-term program (LTP) for customers. Technical experts would later address possible performance enhancements, modernization and upgrade, new I&C offerings, component repair, etc.
One of Schuck’s first slides illustrated the value of the LTP to customers. Here are the metrics he cited: (1) Availability of W501Fx engines managed under the program averaged 1.8 percentage points higher than those not in the LTP; reliability was 0.9% higher with LTP participation than without. Customer satisfaction ratings also were significantly higher for users with LTPs.
Schuck then shared with the group the results of the company’s technicalinformation needs assessment and how Siemens revitalized its internal processes to deliver documents— technical advisories (TAs), urgent technical advisories, service bulletins (SBs), and product improvement bulletins (PIBs)—with improved content and graphics and in a more timely manner. He listed all such documents published in the last year, which can be accessed through the Customer Extranet Portal (CEP).
Schuck seemed especially proud of the CEP’s improved utility— one of the actions driven by customer feedback. Ease of accessibility to technical and outage documents, shop repair reports, contact information for Siemens experts, etc, certainly was one reason for last year’s 35% increase in registered users with F machines.
At the end of 2006, owner/operators of F frames accounted for onethird of the nearly 1000 participants. An especially valuable feature of the CEP for time-constrained plant personnel is the automatic e-mails it generates when an item in one of their specified interest areas has been posted.
Think of the CEP as a library or data warehouse that never closes and contains useful product information as well as the latest outage reports for all past and current projects you may have had with the OEM. If you don’t already have CEP access only you know why and the reason may no longer be valid.
Schuck clearly was “on a mission” during his time at the podium—a figure of speech because he had a portable microphone clipped to shirt and was moving all the time, making eye contact with virtually everyone in the room. You might have characterized the “mission” as “no customer left behind.”
Next, Schuck discussed proposed improvements to the customer issues resolution process, which will be driven from the CEP and allow customers to enter and track issues electronically. A plan for improving the accuracy and timeliness of field reports and invoices followed.
Explanation of the service division’s six-sigma program was next, complete with report card and timeline for completion. Related to that effort was a description of Siemens’ quality incident reporting (QIR) process and the company’s commitment to communicate to each customer the root cause of the incident reported and suggested corrective action—if requested. All that takes is for the Siemens field engineer to check “yes” on the QIR report form next to the question: “Should the customer be kept in the loop as part of follow-up?”
The good news is all of Schuck’s slides are available on the CEP. You may want to review them to better understand the procedures in place to facilitate communications with the Siemens service organization.
Harvey Grassian, who was director of market and customer analysis at the time of the meeting, lightened up the room when Schuck exited. Grassian and Jean Matkovich were responsible for quantifying customer satisfaction and for reporting to management where the company is not adequately responding to market needs.
The information they collect is used to improve products, services, processes, etc, thereby creating a stronger bond between the OEM and end users. In simple terms, Siemens’ six sigma approach to customer satisfaction follows this flow path: (1) Assess the voices of customers; (2) analyze what was said; (3) improve business processes, commercial offerings, technologies, services, etc; and (4) validate with customers the improvements achieved.
Grassian was the primary architect of the OEM’s customer satisfaction business process, which was implemented in its current form five years ago. In July he brought that know-how into Schuck’s group, leaving the established survey work to Matkovich.
The F users gave Grassian the best send-off a customer analyst could ask for—a 10% year-over-year increase in survey responses and a similar improvement in the overall level of satisfaction F customers have for Siemens products and services. What really made him happy was the very significant increase in the numerical score (in excess of 20% year over year) calculated from responses to the following question: Based on your current level of satisfaction, how likely would you be to recommend Siemens products?
Wearing a well-deserved smile, Grassian reviewed the “key factors” showing statistically significant improvement over the last five years. They included price, responsiveness, technical information, outage reports, starting reliability, spare parts, availability/reliability, outage results, and GT service workmanship.
Areas of improvement not yet statistically significant included warranty, invoicing, required maintenance, and outage planning. Not one to sugar-coat results, Grassian identified the following areas as ones that, as indicated by reporting customers, in Siemens’ view required further improvement: on-time component repair, component-repair business practices, and mods and upgrades.
A question Grassian added to the most recent survey asked: “What are the five top issues Siemens should be working on to meet your needs?” Judging from the dialog at other usergroup meetings you probably would get the same results if “industry” replaced “Siemens” in the question.
Parts life was of greatest importance to customers, based on a numerical weighted score that awarded five points for the issue ranked first on questionnaires, four points for second, and so on. Second through fifth places were as follows: compressor, technical information, price, and controls.
Mark Kamphaus, global director of service engineering, put real-world numbers to the improvements in availability, reliability, and starting reliability noted by Grassian. Terms important to this discussion are defined in the Siemens Day section of the 251 Users report elsewhere in this issue. For an update of operating fleet statistics, access Kamphaus’ presentation on the CEP.
Kamphaus closed with a summary of product modifications available to frame owner/operators for improving key performance indicators. Until recently, these were known as Prod- Mods in Siemens slang; now they are called “BSols,” short for business solutions. The 10 solutions reviewed were identified by both title and a Siemens serial number to facilitate accessing details on the CEP. You can download this presentation from the CEP as well—a good first step because the 50-word précis of each solution can help identify where to focus your attention.
As the F users returned from the morning coffee break, Steve Holland made presentations on the current status of hardware upgrades, process enhancements, and technology improvements. He covered hardware upgrades first, including the redesigned R2 compressor blade and R2 diaphragm gusset.
Recent technology improvements reviewed by Holland included the following:
- Improved compressor sealing. Honeycomb seals, designed to reduce leakage between rotating and stationary components, are operating in several units. Their benefit: improved compressor and unit performance.
- New R16 compressor blade. Use of the latest software tools enabled the design of a R16 blade with improved aerodynamic loading.
- Dual-fuel pilot nozzle redesigned to improve atomization, better accommodate temperature gradients, and improve dynamic response capability.
- New combustor basket features an improved TBC coating and spring-clip design.
- New transition piece offers enhanced wear resistance, oxidation resistance and higher temperature capability.
- Improved turbine vane seals are designed to boost turbine performance. They can be retrofitted in most legacy vanes.
- Updated vane for turbine R1 incorporates the latest high-temperature materials, enhanced aero design and cooling schemes, more durable coating, and improved sealing.
- New R1 turbine blade with integrally cast tip, advanced aerodynamics, and internal cooling is designed to better resist erosion, cracking, and distress.
GT repair network
With parts life the No. 1 priority of customers according to Grassian’s survey, and component-repair business practices identified by reporting customers as an area needing further improvement over the last five years of customer surveys, the three-part GT Repair Network presentation by Paul Richmond, marketing specialist, and colleagues John Young, repair network quality manager, and John Junkin, manager of gas turbine repair engineering, was well-timed.
Quality was the first subject discussed and all the metrics were shared with the group—including the number of instances that repairs to specific parts were considered unacceptable for installation by the customer.
A case history was next—dissatisfaction with the fuel nozzle and support housing. It reviewed specificrepairs and bench checks performed to ensure quality compliance— including calibration procedures for test instruments. Reasons for customer dissatisfaction then were presented along with actions taken by Siemens to improve.
A second case history looked at vane repairs and how the company’s repair network rethought and then reconfigured its processes to address issues with the field installation of repaired vanes. Last steps included a video for field engineers summarizing the new repair process and identifying both critical and non-critical inspection points. Last component of the process is feedback from the field. Engineers onsite are charged with communicating any installation issues, customer comments, and recommendations for further improvement.
Top technology issues
Jon Kemmerling, manager of GT service operations for the SGT6-5000F, had the toughest assignment of the day: Getting users to focus on technology after too much lunch. He led off with a brief update of the inletmanifold strut issue: Distress at the fillet weld that attaches the pipe-type struts to the side wall of the component. More detail was presented on this issue at the 501G (SGT6-6000G) Users meeting by David B Grant. That report is included elsewhere in this issue.
Compressor diaphragm wear.
Kemmerling commented on characteristics, location, and rate of wear. He reported measured data and provided a fleet assessment. Siemens is reviewing, Kemmerling continued, fleet diaphragm performance with an eye on scheduled compressor inspection intervals, the time to implement any needed repairs, and availability of spare parts. He “summarized” in 42 slides how Siemens’ eight-step resolution process was applied to this issue. The slides are available for users to review on the CEP.
R1 turbine-blade lockup.
There have been a few reported incidents of blade lock-ups caused by debris (primarily iron oxides) accumulation. As a risk mitigation strategy, Siemens has issued technical advisories on blade inspections at CIs or similar opportunities. All repaired blades also are modified to include a design feature to address debris accumulation. Ongoing R1 blade redesign efforts would further reduce the possibility of debris built-up. A variety of other options—such as air filter and strainer, dehumidifiers, and coatings—are being considered to minimize sources of debris.
Exhaust cylinder cracking
has been reported in F class machines. The concern has been addressed in part by ensuring advanced repair techniques, welder training and qualification, and timely inspections. The design is also being reanalyzed for increased durability.
Greg Perona, marketing manager for GT modernization, presented details on the OEM’s product improvement portfolio for the SGT6-5000F. His presentation was divided into three major topics: (1) products to improve performance and operational flexibility, (2) products to extend inspection intervals, and (3) emissions and alternative fuels. To explain the company’s offerings for performance improvement, Perona presented a series of slides with prepackaged programs for achieving specific user goals. Here are some examples for frames FC through FD2:
1. Improve compressor performance.
Scope includes: Improve sealing, retrofit new R16 blades in FD units, optimize GT mass flow and temperature. Benefits may include: Improve combined-cycle base-load heat rate by up to 1%, or improve combined-cycle base-load power by up to 3%. The package can be optimized for power or efficiency.
2. Improve turbine efficiency.
Scope includes: Improve sealing (install riffle and vertical seals for vanes, rope seals, R1 ring segment, isolation ring), optimize GT mass flow and temperature. One potential benefit: Improve combined-cycle base-load heat rate by up to 1%.
3. Turbine power improvement. Scope includes: Retrofit new R1 blades, improve sealing, and optimize GT mass flow and temperature. Benefits may include: Increase combined- cycle base-load power output by up to 3%, improve combined-cycle base-load heat rate by up to 1%.
4. Maximize performance improvement. Scope includes: Combine packages 1-3 above and retrofit new R4 turbine airfoils. Major benefits may include: Increase combinedcycle base-load power output by up to 6%, improve combined-cycle baseload heat rate by up to 2%.
A case study by New Energy Associates of a 2 × 1 501FD2-powered combined cycle located in the Southwest offered a view of the potential returns for upgrades, optimized for the specific plant (gas at $7/million Btu, 5000 EOH), that increased output by approximately 22 MW and improved heat rate by approximately 1.4% (90 Btu/kWh). Assumptions: Upgrades installed in 2007, increase in the mean dispatch is achieved by 2010. Result: Annual return averages $5.8 million.
OTC upgrade. For users who operate at part load a significant amount of time, Perona suggested the OTC (outlet-temperature corrected) upgrade—an idea borrowed from the V fleet that is now installed on nearly two dozen F machines. Briefly, OTC is a turbine control process that manages operation in a closed loop to a corrected exhaust temperature based on variations in ambient temperature and engine speed. It is a beneficial alternative to setting IGV angle according to load. Benefits may include an improvement in part-load heat rate of up to 2% and reduced emissions drift.
Icing condition alarm, inlet heating options. Icing always seems to be on the agenda of 501F meetings. Ray Martens, a member of the group’s steering committee and plant manager at Klamath (Ore) Cogeneration, has been a driver of many such discussions. Perhaps it was Martens’ years running GTs in Alaska that made him particularly sensitive to icing. One thing for sure, he made many unwary users respect the fact that icing can occur just about anywhere when atmospheric and operating conditions converge in a “perfect storm” of misfortune; significant damage can result.
Perona described Siemens’ icing condition alarm, developed in response to customer requests. It is designed to warn of potential icing conditions by monitoring relative humidity and temperature at the inlet as well as IGV position. If the alarm indicates icing potential, operator intervention is required to raise load to the level recommended, shut down the engine, or (not recommended) ignore the alarm at risk.
Two options were presented for inlet heating. One protects the inlet system downstream of the silencers, the other protects the entire inlet system, including the filters. Details are available on the CEP.
Extending the time between inspections is a goal of most owner/ operators. Perona spoke to this, explaining the component upgrades required both to reduce trip factors and increase the number of equivalent starts and equivalent base hours between inspections. Recommended reading: SBs 51009 and 55004, plus “Operating experience, analytical procedure help OEM extend intervals between GT inspections” (access at combinedcyclejournal.com/archives. html, click 4Q/2005, click article title on issue cover).
Perona closed out his presentation with a review of the company’s upgrades aimed at reducing emissions and increasing fuel flexibility. The emissions discussion focused on the company’s ultra-low NOx combustion system (again, details on the CEP); the fuel flexibility portion of his remarks targeted the expected widespread use of liquefied natural gas in the future. To gain insight on the behavior of F frames when burning LNG, access “Burning LNG may require mods and upgrades to turbines designed for pipeline gas” at combinedcyclejournal.com/archives. html, click 1Q/2006, click article title on issue cover.
Last three speakers for the day were Jim Lau, generator service engineering, who presented on a ground-fault incident that damaged an AeroPac generator, Jeff Miller, director of operations, who reviewed Siemens’ aftermarket initiatives with respect to the TXP control system, and Ron Hitzel, international I&C sales manager, who demonstrated the capabilities of the company’s T3000 control system.
Lau addressed the company’s review of a ground fault that occurred in the center of the stator slot on one AeroPac I generator after 33,500 hours of operation. Investigators determined that the root cause was spark erosion initiated by movement of the coil in the slot.
Work is ongoing to develop a rewind option to address spark erosion of AeroPac I generators; also to identify a non-rewind option to suitably address spark erosion while maximizing the remaining lifetime of the existing stator’s winding insulation.
Results of borescope inspections of generators throughout the fleet will be factored into to this work. Finally, the leading rewind and non-rewind spark-erosion mitigation techniques will be verified in the core model and in a spare core before being released to the fleet.
Miller reviewed (1) the capabilities of the TXP service-support team, (2) availability of spare parts, (3) facilities available for training plant personnel, and (4) the benefits of a long-term service program for instruments and control systems. Clearly, one of his objectives was to assure the user community that despite Siemens’ announcement in early 2006 that it would shortly discontinue the production of TXP/Simadyn parts, the company was not abandoning its customers.
Rather, it was still accepting orders for parts at the time of the 2007 meeting, current plans are to continue repair services for TXPrelated equipment until 2015, and a robust parts replacement/exchange option is available through the company’s long-term service program.
Hitzel, as the company’s interface with customers for the T3000, represents the future of the Siemens powerplant controls business. To say he is bullish on the capabilities of this system would be a gross understatement. He reviewed the system’s architecture and features and benefits, then demonstrated how the system works with a passion for equipment that few in this industry possess today.
Background on the T3000 and short case histories on early conversions from TXP can be found in “Upgrading controls to maximize performance, availability.” Access this article at www.combinedcyclejournal. com/archives.html, click 2Q/2006, click the article title on the issue cover. A backgrounder on combustion dynamics monitoring, an important component of the T3000, is available in the CCJ archives for 3Q/2006, click “Monitoring—and mitigating—combustion dynamics” on the issue cover (2007 Outage Handbook). ccj