Frame 5N rotor returned to plant better than new following EOL inspection, repairs

Posted on November 12, 2013 by Team CCJ

Gas-turbine rotors have a finite lifetime. For GE frames, Technical Information Letter (TIL) 1576 mandates an end-of-life (EOL) inspection for safety reasons after 200,000 factored hours of operation or 5000 factored starts, whichever comes first. A user attending the CTOTF™ Fall Conference, September 8-12, in Coeur d’Alene, Idaho, recently had completed an EOL inspection on a Frame 5N rotor with more than 5000 starts at the Dresser-Rand Turbine Technology Services (D-R) shop in Houston and offered to share that experience with colleagues through CCJ ONsite. 

Many owner/operators of legacy GE engines—such as Frame 5s, 6Bs, and 7B-EAs—will be planning and conducting lifetime evaluations in the next couple of years, but may be unsure about how to prepare for an EOL inspection. They also may be unfamiliar with the various shop activities associated with such an important overhaul. This article offers some perspective.

Additionally, some users remain skeptical regarding the need for an EOL inspection, having listened to several colleagues at user-group meetings discuss how their units were disassembled, inspected, and reassembled with no findings. But in the case profiled here, a significant crack was found in the first-stage turbine wheel, verifying the positive value of the process.

Rotor experts, such as D-R Engineering Manager Greg Snyder, can predict with reasonable accuracy what they would expect to find during EOL inspection based on information extracted from plant records. It is in your best interest to make PI and other data available to the shop selected well in advance of the inspection to facilitate planning and decision-making. These data include the following:

• Location (ambient conditions).

• Operating hours at base load and partial load.

• Number of starts: fast, normal, slow.

• Number of trips/load rejections.

• Ramp rates.

• Shutdown times between restarts.

• Control parameter time-history data.

• Fuel type.

• Operational profile.

• Maintenance history and previous inspection findings.

• Upgrades and parts replacements since COD.

The 5N rotor shipped to D-R by the owner had an interesting history. It was assembled in 1970; TIL 471, issued later, advised of potential “forging discontinuities” created during manufacture of the first- and second-stage turbine wheels. While no indications were found—or at least reported—during manufacture, UT reports from 1981 and 1984 each identified three indications in the first-stage wheel. Experts believed these were “birth defects,” the accept/reject defect size used during manufacture likely being larger than the indications found during the 1980s inspections.

As part of the major outage in summer 1981, the rotor was shipped to a GE shop for grinding of the No. 1 journal; the rotor was not unstacked. Details of the three indications in the first-stage wheel found via straight- and angle-beam UT were archived and the OEM recommend re-inspection in four years or 500 fired starts, whichever came first.

During a combustion inspection in September 1984, three indications were in evidence once again. However, one of the 1981 indications was not found and the OEM chalked that up to a reporting error. The new third indication was identified with straight-beam UT. One of the remaining two indications was reported as having grown but obviously was still of minor concern because GE extended the interval for re-inspection to six years or 1200 fired starts, whichever came first.

A boresonic UT inspection performed in accordance with TIL 471-C, conducted during a hot-gas-path outage in September 1990, revealed no indications.

Discrepancies such as those described above should not come as a surprise for several reasons, including these:

• Wheel and disc design and inspection tools of the 1970s and 1980s were rudimentary by today’s standards.

• The type and critical size of indications for acceptance/rejection of rotor components following manufacture were not as well understood as they are now.

• Data archiving typically was manual.

• People make mistakes, especially inspectors when inexperienced and not properly trained. Regarding this point, users should be sure to check the qualifications of all technicians performing inspections on their rotors, monitor the inspection process, work closely with shop engineering personnel in the evaluation of inspection results, and participate in the repair/replace decision-making process.

After your rotor arrives at the shop, it will be inspected and then disassembled (Fig 1). A standard inspection of the assembled rotor (Fig 2) includes balance, run-out, and dimensional checks, and

nondestructive examination (NDE). The owner said the nuts came right off the through-bolts during disassembly, which is not always the case.

Detailed inspections of high-temperature rotor components—including all turbine discs and the last four compressor wheels—using advanced NDE methods are conducted after disassembly (Fig 3). The sensitivity of the tools and techniques used provides increased confidence that there are no “visible” issues with individual rotor components. Such higher-order inspections also provide a baseline assessment for comparison during future inspections. They include the following:

• Volumetric UT using phased-array probe technology, advanced 3-D signal processing, and archiving of digital data.

• Eddy current.

• Fluorecent magnetic particle.

• Visual.

• Dimensional.

• Metallurgical evaluation.

• Hardness measurement.

Note that inspection of wheel dovetails (Fig 3B) requires removal of compressor blades and turbine buckets. The former effectively are destroyed in the process, so consider ordering new blades well in advance of the shop visit to gain an advantage in negotiations. In this case, the owner ordered new compressor blades but chose to use its spare set of turbine buckets. The compressor blades were later coated in the shop to protect against corrosion.

Rotor evaluation next. Inspection findings were reviewed and interpreted by an experienced engineering staff. This is one of the most important steps in the overhaul. Action taken on issues identified typically is one of the following: retire, repair, rejuvenate, and accept as is. Engineering assessments and detailed analyses guide repair and rejuvenation processes.

Areas of concern on the Frame 5N rotor identified by conventional inspection methods and the corrective actions taken are described below:

• Compressor stage-16 disc, dovetail cracks, blended out.

• Turbine stages 1 and 2, bucket rock, applied coating to dovetails.

• Fretted rabbets, installed patch rings, 12 small and one large.

• Compressor rotating blades, migration, shifted back into place and restaked.

• R0 compressor blades, erosion and foreign object damage (FOD), replaced.

• Through-bolts, nuts, and other hardware, wear and tear damage, reworked or replaced.

The most significant finding on this rotor was a 180-deg circumferential indication in the forward rabbet fillet of the first-stage turbine wheel (Fig 4). A crack like this could compromise the integrity of the component and militate against its continued use. More information was required for proper engineering disposition.

The depth of the indication cannot be determined with confidence from eddy current or other techniques, especially because it is located in a relatively small radius up under the rabbet surface. D-R engineers decided, with the owner’s consent, that the first step should be to remove up to150 mils of material in the area of interest, which was considered a reasonable depth based on inspection results, calculations, and experience.

The indication cleared at 135 mils, as confirmed by eddy-current inspection. An additional 10 mils was removed for added assurance in the event there were any remaining indications below the detection capability of the inspection tools. Next steps: Apply final contour, then polish and shot peen the surface. Note that the contour was laser-scanned before and after the repair to enable a stress comparison for the actual part.

Finite-element models were constructed for both the original (OEM design) and repaired geometries (Fig 5). The primary goal was to show that the repaired configuration was as at least as good as the original.

The mesh refinement in the model provided confidence that the local concentrated stresses in the fillet were acceptable. Through-bolt dead loading was considered important and was modeled with good fidelity. Low- and high-cycle fatigue and creep loading were factored into the analysis.

The mean-stress comparison in Fig 6 showed the new contour, at right, reduced the peak stress in the fillet area by about 70% compared to the original design (left). Also, the point of peak stress was moved to the side of the fillet. The combined section stresses (membrane plus bending) are slightly higher than the original, but the much lower stress-concentration values more than offset the slight nominal stress increase attributed to the smaller cross section.

In sum, the repair achieved the following:

• Reduced substantially the stress in the fillet area compared to the original contour.

• Improved fatigue durability for both steady-state and high-cycle loadings.

• Enhanced component durability with additional surface treatments—polish and shot peen.

Final point: D-R engineers consider the repaired configuration superior to the original configuration in the region of the repair with respect to allowable number of starts and hours of operation.

Repairs complete, the rotor was reassembled, inspected, and returned to the plant. In-shop time from receipt to final assembly was three weeks (Fig 7).

HEADS-UP for 7FA owner/operators: Cracking of R0 dovetails

Posted on November 12, 2013 by Team CCJ

If you’ve been particularly busy lately and weren’t aware of Technical Information Letter (TIL) 1907, “Rotor Forward Shaft Dovetail Crack,” issued by GE on Oct 7, 2013, it’s important to review the document as soon as possible, several users told the editors. It concerns cracking of dovetails in the R0 disc at the edge of contact between the blades and the wheel.

It is not easy to describe in a few words which of the many variations of 7FAs are affected, so the first thing to do is to get the TIL and figure out if you should be concerned. Photos within the advisory provide encouragement to be proactive. The OEM conducted a webinar last week on the subject. If you missed that, perhaps you can see a recording.

One owner/operator mentioned R0 dovetail cracking during the GE F-class Roundtable at the spring 2013 CTOTF™ meeting in Myrtle Beach, SC. There wasn’t much discussion on the topic because no one other than the affected user had heard about this type of failure. Turns out, it was the first such incident reported publicly. By the time the CTOTF’s 38th annual Fall Conference took place in Coeur d’Alene, Idaho, September 8-12, another failure of this type had been reported and there was a high level of interest among attendees.

GE engineers had little to say about the issue during the OEM/owner session of the fall GE F-class Roundtable, chaired by Pierre Boehler of NRG Energy, but the subject got more air time in the user-only portion of the program. Serendipitous was how the owner described the original finding in the fall of 2012.

The upper half of the compressor was exposed to accommodate other work when someone looked down and noticed a crack in one dovetail. Actually, there were cracks in several of the 32 dovetails, on the suction side of the wheel. Chilling. The rotor was pulled from the unit and shipped to a GE shop where the forward shaft was replaced. There is no procedure for repairing disc cracks at this time.

The affected machine had been re-equipped with the latest OEM R0 blades—stronger airfoils, beefed-up platforms, etc, to address fleet issues and improve durability. The blades were fine. Informal discussion among users pointed at the following possibility: Stresses in the new blades when passing through critical speeds during engine starts are transferred to the dovetail region of a wheel that might have benefitted from more conservative design.

It would appear that the OEM believes units in peaking or cycling service are more susceptible to R0 dovetail cracking than base-load machines, users said, given the inspection intervals specified in TIL 1907. An ultrasonic inspection is recommended every 900 factored fired starts for starts-based machines; 48,000 factored fired hours for hours-based gas turbines.

Inspections can be conducted in-situ, according to Rod Shidler, president, Advanced Turbine Support LLC, the borescope experts. He said the inspection is being performed by the

company’s technicians using the phased-array ultrasonic inspection technique. They have found no R0 dovetail cracks to date. Accessibility to the dovetails is enabled by moving inlet guide vanes (IGVs) to the wide-open position. This inspection can be completed in one shift.

7EA USERS GROUP

Webinar effective for technology, regulatory updates

Many powerplant supervisory personnel who could benefit from attending user group meetings often do not get to the annual conferences covering their gas turbines. Some have never gone. You know the usual reasons: internal meetings, no travel budget, short-staffed, etc.

   For those who attend at least every other conference, 12 or 24 months is a long time to go between meetings and many things you should be aware of, but might not be, can happen during that time. Examples include new regulations, new/revised OEM technical information letters, best practices, equipment upgrades, etc.

   Pat Myers, a member of the 7EAUsers Group steering committee , understands well the challenges of managing a multi-unit powerplant while trying to keep up with the seemingly endless number of equipment, personnel, ownership, and regulatory changes that characterize the generation sector of the electric power industry today.

   Example: In addition to his day job as plant manager of American Electric Power Co’s Ceredo Generating Station, Myers was selected to head a special corporate committee charged with reviewing and upgrading, where necessary, AEP’s practices for the safe

handling and combustion of natural gas. This included compliance with NFPA® 56, “Provisional Standard for the Commissioning and Maintenance of Flammable Gas Piping Systems,” which was being developed in parallel with the AEP initiative.

   Myers, who spent more than two decades in the employ of a major gas transmission company before joining AEP, recognized that NFPA 56 would be a “game changer” regarding traditional practices of handling and burning natural gas at powerplants. He believed it was important for the industry to understand the safety standard’s requirements as soon as it was made public.

   Myers thought a webinar might be a good way to communicate this information and allow answering questions live as well. He and the other members of the steering committee endorsed the idea of an exclusive online 7EA Users Group “meeting” on September 1, the day NFPA 56 was to be announced publicly. Three other presentations also were scheduled for the webinar, believed to be the first by any independent user group serving gas

turbine owner/operators in theUS.

   Owner/operators of 7B-EA engines worldwide were invited to participate at no cost in the user-only event, which was sponsored by Allied Power Group LLC,Houston. There were 88 owner/operators signed on when the webinar started and 53 were still connected when the “meeting” ended nearly two hours later. The broadcast had been scheduled for one hour but the presentations typically ran 15 minutes rather than the planned 10 and Q&A averaged more than 10 minutes per speaker.

   Host for the webinar was Amy Alix, an engineer in Progress Energy Florida Inc’s Combustion Turbine Operations group, and member of the 7EA User Group’s steering committee. CCJ Senior Editor Scott Schwieger was responsible for the behind-the-scenes work in the “broadcast booth.” The webinar was not recorded.

   The technical program was as follows:

“NFPA 56, What You Need to Know to Protect Personnel and Property,” Mike Bethany, lead mechanical engineer, CEC Combustion Services Group, Cleveland.Bethany, CEC President John Puskar’s back-up on the NFPA 56 committee, is an expert in gas purging by virtue of his onsite involvement in dozens of such projects.

“7EA R2 and R3 Bucket Rail Loss Repair Options and Preventive Measures,” Aaron Frost, technical director, Allied Power Group LLC,Houston. Frost is one of the industry’s top experts in the repair of HGP parts.

“Control System Upgrades,” Glenn Corbiere, operations supervisor, Stony Brook Energy Center, Massachusetts Municipal Wholesale Electric Co (MMWEC), Ludlow, Mass. Corbiere profiled the conversion of four 7Es from Mark II control systems to PLC-based controls and one 7E converted to DLN-1/Mark V in 1993 to PLC-based controls.

“Onsite Hot Section Fir Tree Build-up,” Pat Long, engineer, Calpine Corp’s Turbine Maintenance Group. Long has spent three decades on the

deck plates doing what was necessary to get plants back in operation. This was the first time he had participated in a user group meeting.

“Bucket-Rock Solution: Reduce Turning-Gear Speed,” Ken Knecht, maintenance foreman, Beluga Power Plant, Chugach Electric AssociationInc. Knecht, a millwright by trade, has been repairing, and supervising repairs to, gas turbines for 30+ years. This was the first time he had participated in a user group meeting.

NFPA 56.  

   CCJ has followed the development of NFPA 56 since Myers first brought it to the editors’ attention more than a year ago. Early details on the safety standard appeared in both the journal and CCJONsite, an electronic letter that reports on developments at user-group meetings. Access the 2011 Outage Handbook at www.ccj-online.com and read “NFPA 56 a ‘game changer’.”

  Bethany’s presentation reviewed much of the material in that article and went a step further by telling webinar participants what they should do now that the provisional standard was “official.” First, he hammered home the point that OSHA compliance starts with a consensus standard being in effect. Non-compliance with a consensus standard usually is the basis for an OSHA citation.

  While the designation “provisional standard” may appear to have only “baby teeth,” that thought couldn’t be further from the truth. It only means that the standard’s development was expedited. The possibility of an OSHA citation for not heeding it is very real.

   For those who were caught unawares and take issue with some of the standard’s requirements, note that NFPA’s automatic revision cycle has already begun and new comments are being accepted. This standard will become a “code” as soon as a state adopts it into law.Connecticut, where the fatal gas explosion at the Kleen Energy combined cycle occurred in February 2010, is one state likely to do that.

   Bethany urged everyone to buy a copy of the code at www.nfpa.org ($33.75) and  read it. Next, develop the required implementation plan for your operation. This is very important:

You must have a plan and it must include procedures, a hazard review process, and training. More specifically:

Procedures for the retrofit of systems to enable safe purging and reintroduction of gas. Detailed plans for routine gas practices. Checklists for hazard review processes. Training of employees and monitoring of contractor personnel.

   Be prepared, the expert noted. The implementation plan will impact regular operational activities and organizational and personnel behaviors will have to change.

   To learn more, email CEC’s Puskar (jpuskar@combustionsafety.com) for a copy of his whitepaper summary highlights of NFPA 56.

Bucket rail loss

Allied Power Group’s Technical Director Aaron Frost reviewed rail-loss repair options and preventive measures following the Q&A onBethany’s presentation. Although Frost’s focus was rail loss on 7EA R2 and R3 buckets, the wear issue is problematic for owners of other engines as well—such as Frame 6B and 7FA+e R2 and R3 buckets and 501FD R3 turbine blades. Thus many users outside the 7EA community can benefit from what he said.

   The problem, Frost said, is that in many instances the honeycomb becomes a cutting tool and machines away the tip rail of shrouded turbine buckets/blades (Fig 1). He noted that GE Energy uses a cutter-tooth design for its shrouded buckets, whereas Siemens does not. But in either case, he continued, the chance that the honeycomb machines off the bucket rail or that the bucket rail wins is the same (Fig 2).

   The crux of the wear problem, Frost said, is that the Haynes 214 (GE) and Hastelloy X (Siemens) honeycomb materials oxidize over time, forming either an aluminum oxide or chrome oxide surface scale during exposure to high temperatures. Both oxides are abrasive and capable of machining away bucket/blade rails (Fig 3).

   Allied’s proven method for preventing such damage is to coat rails with an abrasive plasma-deposited aluminum oxide coating (Figs 4, 5). This makes the bucket/blade the cutting tool instead of the honeycomb. It also eliminates the need for cutter teeth, improves seal effectiveness, and protects the side of the rail against wear associated with rotor

movement during startup and shutdown. Finally, the removal of cutter teeth improves long-term shroud and airfoil creep life because of the reduction in weight.

   Houston-based Allied, long a supporter of user-group activities, sponsored the 7EA User Group’s first webinar.

 

Control system upgrade

Corbiere told webinar participants that Stony Brook has been well cared for throughout its three decades of service. MMWEC management understands that equipment must be upgraded and replaced for a generating facility to maintain its value. So it came as no surprise when budgets were approved for replacement of the original Speedtronic Mark II control systems on four of the plant’s five gas turbines to provide greater operating flexibility.

   A significant amount of the plant’s revenue comes from ancillary services that Stony Brook provides the grid—specifically capacity, availability, and black start. In one of the shoulder months, the plant may be called only a couple of times to deliver power. A failure to start would result in financial penalties.

   MMWEC bids Stony Brook’s two peakers (the plant also has a 3 x 1 combined cycle) into the New England ISO’s 10-min forward reserve market with a critical “10 minutes from dispatch signal to base load” requirement. These unit are audited by the ISO for compliance at each startup.

   With the Mark II’s, Stony Brook operators weren’t confident they’d make the contract output within the 10 minutes when called upon. Something always seemed to be failing. One example: The multi-voltage power supplies needed for the Speedtronic II. Plant techs couldn’t find new ones anywhere; rebuilds were available, but not reliable.

   New control systems for these engines was the only viable option. Half a dozen vendors responded to the public RFQ. In the end it came down to the OEM and Innovative Control Systems Inc,Clifton Park,NY (today a unit of Pittsburgh-based Emerson Process Management, Power & Water Solutions). ICS was awarded the contract based on its experience with similar upgrades for water- and steam-injected dual-fuel Frame 7 gas turbines, plus cost, schedule, etc.

   Access the details in “StonyBrookEnergyCenter: Assets well cared for get better with age,” in CCJ’s 2Q/2010 issue at www.ccj-online.com.

Bucket rock

Bucket rock is a concern of many 7B-EA owner/operators. Several solutions are available. The final two presentations on the webinar offered both a “quick fix” to keep engines with severe rock in operation and a best practice for possibly preventing bucket rock altogether.

   Solution No. 1: Metal spray. Calpine’s Long reported on a restoration technique used at one plant to reduce the play between bucket roots and wheel fir trees and bring rock back within OEM specs. The background: A 7EA commissioned in 1982 had about 120,000 hours of service time. It is now operating about 3400 hours annually; the balance of the year is spent on turning gear. Platform and shank pin migration was discovered during a planned outage; rock was considered excessive by the OEM.

   The plant was not scheduled for a major inspection for another two years and an interim fix would suffice. Proposed solution was to build up fir-tree surfaces. The OEM’s offering did not meet the plant’s requirements regarding timing and cost; plus it was not equipped to do the job onsite. Praxair Surface Technologies was the plant’s choice. It had a mobile field service unit and could meet schedule and cost expectations.

   Long said others who might be considering metal spraying to reduce bucket rock should be aware of the following requirements/concerns:

Regarding safety, (1) warn personnel about looking directly at the electrodes to prevent eye flash burns, (2) provide hearing protection because of the noise associated with the dust collector and metal delivery system, (3) recognize that working quarters are cramped in the turbine case area, and (4) forewarn personnel when the rotor must be rotated.

Two 3-phase 480-V connections are required—one for the metal delivery system, one for the dust collection system.

An air compressor capable of delivering 185 scfm is necessary.

   Preparatory steps included these:

Remove all buckets and shroud blocks. Build cardboard walls in the annulus created by the combustion wrapper and the exhaust

case. Cover all bolt holes. Use weather stripping to seal off portions of the rotor that shouldn’t be exposed to the

media-cleaning and metal-spray operations. Install heavy plastic under the rotor and tape some over the annulus areas (Figs 6, 7). Use templates of shim stock to block off cooling slots in the rotor while both blast cleaning

and building up the fir trees (Fig 8).

   Procedure: First step was to use a low dusting alumina to clean surfaces that would be metal-sprayed. The rotor was rolled once for the blasting step and five buckets at a time for metal spray. Electrodes for metal spraying were 75% nickel, 25% aluminum. The air

compressor was used to blow the fast-cooling molten mixture onto the fir-tree surfaces—five trees at a time. Correct buildup of metal was determined by inserting bucket in its wheel position and measuring rock with a dial indicator. Total onsite time for the Praxair team working a single shift was four days.

   Solution No. 2: Reduce rotor speed on turning gear. Chugach’s Knecht began by explaining that bucket rock is most prevalent in machines that cycle, most severe in units that operate on turning gear (TG) for long periods—unless shaft speed is about 1 rpm or less, or more than perhaps 150 rpm when bucket motion is restricted by centrifugal force.

   Rock occurs because buckets move slightly in the wheel dovetail as they pass top and bottom dead center, wearing the softer wheel material. You can tell if your turbine has bucket rock by listening for the distinctive clanging sound at the back end of the unit when it is on turning gear. Access http://www.ccj-online.com/tgmod/ and compare the difference in audible wear and tear on buckets at 6 rpm versus 0.5 rpm.

   Knecht said the ways to prevent/correct bucket rock are the following:

Reduce TG run time. Increase or reduce turning-gear speed. Metal spray the unloaded side of wheel fir trees. Metal spray the unloaded side of bucket dovetails. Replace the turbine wheel.

  What Beluga did to deal with bucket rock was to install a variable-frequency drive (VFD) controller on a Frame 7’s TG motor to reduce turning-gear speed from 6 to less than 3 rpm. This upgrade was made during a gas-turbine controls retrofit from the OEM’s Speedtronic system to a PLC-based system.

   Here’s how the Alaskan plant operates its turning gear when the GT comes offline:

Coast to zero speed. It’s important to be sure you’re at 0 rpm. The VFD starts the turning-gear motor at a selected acceleration rate (to avoid damaging the

jaw clutch were it to grab the entire machine train at full speed from a standstill). Jaw clutch engaged, TG motor accelerates to full speed (1750 rpm). Turbine shaft now is

turning at 6.04 rpm and the unit is in the normal cool-down condition. When wheel-space temperature is 350F (going down to the generally accepted 200F is not

necessary), the VFD decelerates the TG motor at a pre-selected rate—so the shaft does not out-run the jaw clutch.

Motor continues to run at the speed selected (for example, 875 rpm to turn the shaft at 3 rpm) to hold the current run status.

   During a restart, TG speed is increased to “full,” raising turbine shaft speed to 6.04 rpm. Normal startup procedure is followed from that point on.

   Knecht, who retired from Chugach shortly after the webinar, said another benefit of being able to turn the shaft at 0.5 rpm or less is that it enables precise rotor positioning during inspection and maintenance activities. Knecht now is with Allied Power Group LLC, based inAlaska.

Between meetings

Two participants in the 2010 7EA Users Group meeting developed entries for  CCJ’s  2011 Best Practices Awards program based on theirMemphispresentations and each walked off with a BEST OF THE BEST plaque. Keep in mind that you heard all this first at the 7EA.

   Myers brought home to American Electric Power Co the top award in the Safety Procedures & Administration category, presented to the company’s Natural Gas Plant Fleet, for its proactive efforts in preventing accidents involving the handling and combustion of natural gas.

   AEP’s natural-gas fuel facilities and operations review team, chaired by Myers and comprised of generation and EHS professionals, was established to proactively evaluate the safety of the company’s internal requirements, practices, and plant designs associated with natural-gas fuel venting, purging, blowdown, and line-charging activities, and to make recommendations for improvement.

   Access the 1Q/2011 issue at www.ccj-online.com and read “Developing procedures for the purging, handling of natural gas” for details.

   Mark Lane, O&M supervisor of Lincoln Generating Facility, a 656-MW, gas-fired simple-cycle facility in Manhattan, Ill, operated by NAES Corp, returned to his plant with the top award in Environmental Stewardship.

The OEM had provided a low-lube-oil level alarm switch, but there was no logic to stop the lube-oil pumps. Unless an operator happened to enter the unit, an event like this would most likely go unnoticed until the low-lube-oil alarm comes in with a spill potential of about 500 gal. Theoretically, a spill could continue until lube-oil pumps lose suction—meaning a loss of as much as 2000 gal. At this volume, oil could end up on the ground.   He explained to 7EA users last year that with a unit on ratchet there was need to circulate oil while a kidney-loop oil filtration skid was connected and operating—meaning that the auxiliary and hydraulic oil pumps were in operation. A torque-converter hydraulic oil line failed mechanically and more than 500 gal of oil was spilled onto the compartment floor before the leak was discovered.

   Details on the plant’s solution, including logic diagrams, also can be found in the 1Q/2001 issue (“7EA lube-oil spill-prevention logic mods”).

   Finally, updates on several former members of the 7EA User Group steering committee:

Dave Ulozas, now VP generation for MidAmerican Energy Co. Mike Hoy, now manager of project development and engineering for TVA’s New Unit

Services group and a member of the Combined Cycle Users Group steering committee. Paul Bruning, now supervisor of thermal engineering for Puget Sound Energy. Mark Sherrill, now technical director of Turbine Generator Maintenance Inc.