CTOTF: Kirn passes the chairman’s baton to Borsch

CTOTF2010LogoTM_Web_8The big news from CTOTF’s™ 38th annual Fall Turbine Users Conference and Trade Show in Coeur d’ Alene, Idaho, September 8-12, was the announcement by Chairman Robert G (Bob) Kirn that he would be retiring from TVA in early October and that this would be his last CTOTF meeting in an official capacity. He had been chairman since 2008—only the fourth chair in the group’s rich history.

Kirn left at the top of his game, so to speak. Under his leadership, CTOTF meetings have expanded to include a vibrant opening-day program consisting of the Industry Issues and O&M and Business Practices Roundtables and the very popular and insightful Regulatory and Compliance Roundtable on Day Two. The technical program remains as strong as it ever has been in the group’s four decades of service to the industry—bolstered by recent addition CT-Tech™, which provides expanded instruction and training in plant operations and design theory on user-identified subjects.C 1

The more than 30 subject-matter experts that comprise the CTOTF Leadership Committee organized and conducted four full-day and a dozen half-day technical and regulatory sessions, plus two CT-Tech workshops and a robust equipment/services exhibition, at the Coeur d’ Alene Resort.

There were more than five dozen formal presentations, a few panels, and several discussion sessions hammered into a program that began at 7 am with breakfast and ended at 9 pm every evening except on the final day of the meeting. Kirn, who used to play football for the US Merchant Marine Academy (Kings Point), challenged the session chairs and vice chairs to use every second on the clock productively.

Jack Borsch, VP of O&M at Colectric Partners and a former plant manager, was elected the all-volunteer organization’s fifth chairman (Fig 1). His former position, executive vice chair for turbines, has been filled by Rich Evans of Old Dominion Electric Co-op, a long-term CTOTF committee member and plant manager (Fig 2). Evans’ professional experience spans both aero and advanced-frame engines.C 2

The remaining members of the CTOTF executive committee—Ed Sundheim, director of engineering services for Essential Power LLC, and Ray DeBerge, a GT fleet superintendent for Ameren Missouri, continue in their current positions.

A report on the fall meeting will appear in a later issue; this article reflects timeless material presented at the 2013 spring meeting. The next CTOTF meeting, the 39th annual Spring Turbine Users Conference and Trade Show, will be held April 6-10, 2014 at the PGA National Resort & Spa  in Palm Beach Gardens, Fla. Mark your calendar to sign up when registration opens Feb 1, 2014 at www.ctotf.org.

CTOTF spring 2013

The 2013 Spring Turbine Users Conference and Trade Show got into the nitty gritty of gas-turbine (GT) operations and maintenance on the second day of the meeting, conducted at the Marriott Grande Dunes in Myrtle Beach, SC, April 7-11. Day One, Monday, April 8, was devoted to presentations and discussion on training, information resources, and best practices, plus a vendor fair in the evening.

Tuesday’s program focused on regulatory and compliance issues and GE E-class and legacy engines; the sessions were conducted in parallel. This was the first CTOTF meeting that the Regulatory and Compliance (R&C) Roundtable, chaired by Scott Takinen, director of executive projects for fossil generation at Arizona Public Service Co, ran an entire day.

Judging from the robust content and discussion, it probably could have gone two days without anyone yawning. The morning R&C program addressed environmental regulations, with Vice Chair Kimberly Williams of NV Energy at the front of the room; Vice Chair Alan Bull of NAES Corp, directed the afternoon session on NERC and FERC regulations.

Chairman Pierre Boehler and Vice Chair Ed Wong, both with NRG Energy Inc, divided the GE E-class and legacy program into two segments: OEM presentations in the morning and presentations by third-party equipment and services providers, plus user-only open discussion, in the afternoon. 

Proposed changes to NSPS for GTsC 3

That plant managers and supervisors are having a difficult time keeping up with environmental regulations was obvious from the strained facial expressions on many attendees during Williams’ opening presentation, “Proposed Revisions to Combustion Turbine NSPS.” Don’t let the plain-vanilla title fool you.

The presentation’s content provided credibility to a message delivered by a user on Monday that went something like this: Don’t be lulled to sleep thinking the federal government is just trying to eliminate coal as an energy source for electric generation; it has declared war on all fossil fuels, and natural gas is next.

Williams eased the group into the subject matter, starting with a history of the New Source Performance Standards for GTs, then providing details of the onerous changes proposed to those regulations, and finally, what impacts EPA’s suggested changes could have on asset owners if enacted as written. It’s fair to say that many of the users participating in the heavily attended session (standing room only) found it difficult to believe what they were hearing.

One example is the proposed change to the definition of “reconstruction,” a trigger for NSPS, which may result in more restrictive operating and compliance requirements. Under the current definition, Williams said, “reconstruction” is taken to mean the replacement of components of an existing facility to the extent that the fixed capital cost of the new components exceeds 50% of the fixed capital cost of a comparable entirely new facility—including major process equipment, instrumentation, auxiliary facilities, buildings and structures, etc.

The new definition, if EPA has its way, would be to use only 50% of the cost of the compressor, combustor, and turbine sections as the “reconstruction” trigger. In EPA think, this typically means that the third time a turbine is overhauled or refurbished it would be considered “reconstructed.” That translates to an NSPS review every 10 years because maintenance costs are cumulative over time.

Curiously, EPA is on the record with the following: “This proposed rule [the proposed revisions in sum] would not result in additional costs or additional reductions of emissions of criteria pollutants.” Another of the agency’s comments: “We do not intend for these editorial revisions to substantively change any of the technical or administrative requirements of the subpart [that portion of Part 60 of Title 40 of the Code of Federal Regulations pertaining to gas turbines] and have concluded that they do not do so.”

If you’re not familiar with the foregoing and want to come up to speed quickly, access Williams’ presentation in CTOTF’s online Presentations Library (Sidebar). It earned the NV Energy engineer the user group’s award for the best presentation at the spring 2013 meeting (Fig 3). To dig deeper, access the proposed rule and all the comments submitted to EPA.

Background. Williams, who has 15 years of experience in the environmental aspects of oil production and electric generation, told attendees at the recently concluded CTOTF fall meeting in Coeur d’ Alene, Idaho, that her spring presentation was still current. She began her presentation last spring by reminding attendees where NSPS fits in the alphabet soup of EPA regulations.

Simply put, it establishes pollution control standards of performance for new and modified stationary sources in certain categories—such as electric generating units. These standards are separate from, and in addition to, the Best Available Control Technology/Lowest Achievable Emission Rate limits associated with Prevention of Significant Deterioration/New Source Review rules.

NSPS for gas turbines date back to 1979, Williams said, when the standards were presented in 40 CFR 60 Subpart GG and made effective on Oct 3, 1977. More restrictive standards were issued in July 2006 and published in 40 CFR 60 Subpart KKKK—so-called Quad K.

The Utility Air Regulatory Group (UARG), a voluntary, not-for-profit group of electric utilities, other electric generating companies, and national trade associations, filed a petition for reconsideration in September 2006. EPA’s proposed revision was published on Aug 29, 2012. This version has not been promulgated—yet. Williams did not discuss the possibility of ongoing appeals and the degree of success they may or may not have, or when the proposed rules could become law.

The Quad K standards in effect today apply to stationary gas turbines that commenced construction, modification, or reconstruction after Feb 18, 2005. EPA’s proposed changes to those rules include the following, among many others:

  • Modify the test for “reconstruction” as described earlier.
  • Include startup and shutdown activities in emissions standards. Today’s NOx limits do not apply to engine starts and stops, or to engine malfunctions. Williams said that EPA is considering designating the first 30 minutes of operation as “part load,” subject to a higher NOx limit. She suggested that this would complicate monitoring.
  • More restrictive NOx averaging periods, now 30 days for gas turbines in combined cycles with a peak-load heat input greater than 850 million Btu/hr (HHV), and four hours (rolling average) for simple-cycle GTs with a peak-load heat input equal to or less than 50 million Btu/hr (HHV). Note that the first example is for a 2008-vintage GE 7FA, the second for a P&W SwiftPac® built in 2008.

To illustrate the level of detail associated with some of proposed changes, consider that the 30-day average for large frame engines in combined cycles would be acceptable for any unit using the output-based standard (see next bullet). However, those using the input-based standard would have to comply with a four-hour average. Proposed changes to the NOx averaging period for simple-cycle turbines are far more complex.

  • Change the output-based NOx standard from gross to net basis with units of lb/MWh.
  • Add a new form of input-based NOx standard with units of lb/million Btu.
  • New compliance monitoring requirements. Example: Units using post-combustion NOx controls to comply with emissions rules can no longer rely on Part 75 CEMS (Continuous Emission Monitoring System) because the specified analyzer span is inconsistent with Part 75.
  • New definition for turbine tuning, which would be limited to 30 hours annually: As proposed it means planned maintenance of a lean, premix combustion system involving adjustment of the operating configuration to maintain proper combustion dynamics.

Upgrades versus new capacity. Williams’ presentation was the perfect segue for NV Energy Staff Engineer Susan Hill, who provided attendees a methodology for evaluating the regulatory impacts of upgrades that might allow the utility to postpone new capacity additions. Hill’s presentation was developed into a separate article and is featured in this issue.


NERC/FERC compliance matters dominated the afternoon session of CTOTF’s Regulatory and Compliance Roundtable with Vice Chair Bull making formal presentations on the latest version of PRC-005, “Transmission and Generation Protection System Maintenance and Testing,” and the key elements of a strong internal compliance program.

Bull, an electrical engineer with more than a decade of industry experience, has NERC compliance responsibility for all of NAES’s facilities in North America. Roundtable Chair Takinen chipped in with a case history on APS’s audit experience in the WECC (Western Electric Coordinating Council) region.

A considerable amount of equipment is aggregated into “protection system” as defined by PRC-005: protective relays, communications systems, voltage and current sensing devices, station DC supply, and control circuitry. NERC spent five years updating the standard, which includes specific maintenance and testing guidelines. PRC-005-2, adopted by the NERC Board of Trustees on Nov 7, 2012, was awaiting regulatory approval by FERC at the time of the spring conference.  

In simple terms, the purpose of PRC-005-2 is to assure that all protection systems affecting the reliability of the bulk electric system are maintained in working order. Since the spring meeting a draft of PRC-005-3 has been circulated for comment. It adds passages on the maintenance and testing of reclosing relays that can affect the reliable operation of the bulk power system.

Violations. Judging from the large number of PRC-005-1 violations self-reported or identified during audits over the last several years, many owner/operators could use a primer on how to avoid citations. And that’s what Bull prepared for attendees. The presentation was robust, encompassing nearly 100 slides, the vast majority content-rich.

The failure of users to maintain proper documentation and to do all the maintenance required by the standard accounted for most of the violations, as the summary list below suggests. The violations generally indicate a lack of procedural rigor and/or unfamiliarity with the tasks required. They include:

  • No summary of protection-systems maintenance and testing procedures.
  • Maintenance and testing intervals not defined.
  • Basis for maintenance and testing intervals not documented.
  • Protection-system maintenance and testing program did not include all the component types as defined by NERC.
  • Missing documents. More specifically, an inability to document implementation of maintenance and testing procedures.
  • Failure to complete maintenance and testing procedures within prescribed intervals.

The first part of Bull’s presentation helped attendees refresh their knowledge of the types of protection systems used in electric generating facilities. It included a list of more than a dozen generation protection relays you’re likely to find in most plants. Bull noted at this point that the existing definition of “protection system” does not include auxiliary relays; therefore, maintenance and testing of such devices is not explicitly required at this time.

Bull’s review of NERC’s changes to PRC-005-1 was comprehensive and especially valuable to those in the group who had difficulty complying with the first version. Details were well organized. There were individual slides for each of the components/systems aggregated into the “protection system,” as defined by NERC. They identified the component of concern, the maximum maintenance interval, and the maintenance activities required.

How to access CTOTF presentations

The user group’s library of presentations is arranged in chronological order by meeting (most recent first). If you don’t already have a “library card” and you are a GT owner or operator, register now at no cost.

Confirmation of your acceptance as a CTOTF member with full IBBCS (Internet Bulletin Board Communications Service) privileges generally will be emailed to you within 72 hours. As a member, access CTOTF IBBCS and sign in. Scroll down the page to “Presentation Library” and click on that link.

For example, in one slide for communications systems, one entry is for “any communications system with continuous monitoring on periodic automated testing for the presence of the channel function, and alarming for loss of function.” The maximum maintenance interval is every 12 calendar years (second major for a base-load combined cycle). One of the maintenance activities specified is to “verify that the communications system meets performance criteria pertinent to the communications technology applied—for example, signal level, reflected power, or data error rate.”

Bull then reviewed the proposed timelines for implementation of the various requirements of PRC-005-2, which ranged from 12 months to the 12-yr maximum interval. This was the perfect introduction to well over a dozen slides detailing “appropriate evidence” to assure that you have the required paperwork to verify the results and prove you conducted the necessary maintenance and tests properly. Several slides answering frequently asked questions closed out the presentation. Bull’s slides are available at forums.ctotf.org in the Presentations Library.

Bull opened this presentation on the culture of compliance with a FERC policy statement: A company should act “aggressively to adopt, foster, and maintain” an effective culture of compliance, and have in place “rigorous procedures and processes that provide effective accountability for compliance.”

Interestingly, while there are no FERC requirements for having an Internal Compliance Program (ICP), it is important that your facility’s/company’s compliance culture be viewed positively by regional auditors. Having a highly rated compliance program could reduce, possibly eliminate, the civil penalty that otherwise would be imposed if a violation were to occur.

Regional auditors, the vice chairman continued, are required to assess and document your company’s compliance culture as part of the audit process. Such assessments involve completion of a compliance-culture survey, plus ICP review. Among the variables that auditors factor into their assessments are these:

  • Compliance history and repetitive violations.
  • Failure to comply with compliance directives.
  • Self-disclosure and voluntary corrective action.
  • Degree and quality of cooperation during the audit process.
  • Concealment of violations.

Thirteen assessment areas are used by the audit team to evaluate your plant’s/company’s ICP. Here are questions the auditors ask themselves:

  • Was the ICP well documented and widely disseminated throughout the entity?
  • Has the plant/company named and staffed an ICP oversight position and is that position supervised at a high level? Does the oversight position have independent access to the CEO and/or board of directors?
  • Is the ICP operated and managed independently of those responsible for compliance with reliability standards?
  • Does the plant/company have sufficient resources for its ICP?
  • Is the ICP a living document?
  • Does the ICP:
    1. Have the support and participation of officer-level management?
    2. Provide for appropriate and sufficient staff training?
    3. Include formal, internal self-auditing for compliance with all applicable reliability standards on an established periodic basis?
    4. Include disciplinary action for employees involved in violations of the reliability standards, if appropriate?
    5. Have internal controls—including self-assessment and self-enforcement to prevent recurrence of reliability-standard violations? 

E-class and legacy GE engines

The GE E-class and Legacy Roundtable never disappoints. Many gas turbines in the multiple fleets served—including Frame 5s, 6Bs, 7B-Es, and 7EAs—are more than 20 years old; relatively few are held captive by long-term service agreements. With owners increasingly parsimonious, the plant-level engineering and maintenance solutions required to keep these machines operating, or ready to run, promote valuable discussion and sharing of ideas, best practices, and lessons learned.

  The OEM filled the morning session of the day-long program, covering a wide range of subjects—including the following:

  • Technology updates to enable faster starting.
  • Repairs and service updates.
  • Mitigation of vane rock.
  • Casing and exhaust system maintenance.
  • Lubrication specifications.
  • Rotor lifetime strategies and issues.
  • Turning-gear improvements.
  • TIL (Technical Information Letter) updates.

The exclusive afternoon program for owner/operators included several of the same subjects, but from a third-party or user perspective. To illustrate:

Hy-Pro Filtration. Richard Trent, manager of technical field services, presented on lubricant improvement and varnish mitigation. The lube-oil expert’s refresher on fluid cleanliness, lubricant challenges, varnish mitigation strategies, and related topics crammed material worthy of a two-day seminar into one hour. He touched on ISO codes, patch tests, the impacts of fluid cleanliness on bearing life, types of filter media and testing, beta ratio, filter-element sparking, how varnish forms, varnish potential measurement, etc.

In sum, this presentation, available through CTOTF’s Presentation Library, could serve as a “short course” for plant personnel who could benefit from a primer on lube oil. Plus, many of these topics have been covered previously in the CCJ and can be accessed via the keyword search feature at www.ccj-online.com.

PSM’s Product Line Manager Ian Summerside reviewed his company’s successes in upgrading about four dozen E-class turbines with its sub-5-ppm-NOx LEC-III® combustion system and refreshed attendee minds on how well buckets and shrouds of its design have performed. PSM, he said, is now working to complete its product-line offering for the entire engine—including nozzles and compressor blades, as well as rotor inspection and overhaul services.

User presentations are particularly valuable and there were several—including a rotor lifetime assessment conducted in a third-party shop and an exhaust-system retrofit. Here’s a summary:

Gasket tear. Seasoned users know everyone on the deck plates has something of value to share and many bring a couple of photos on a thumb drive so others might benefit from their experiences. Such informal “presentations” often take only five minutes or so, but the learning is cumulative. One example from this session involved a piece of 7EA inlet expansion joint that caused compressor damage.

Plant personnel repaired the rubber joint about a year before a portion of it tore loose and went downstream (Fig 4). Note the hole in the expansion joint at the top center of the photo. One piece of liberated rubber wrapped around an inlet guide vane (Fig 5), while other pieces went into the compressor and banged up several R1 blades (Fig 6). Blending was necessary.

First lesson learned: It’s virtually impossible to make a high-quality repair on rubber expansion joints of the type used at the engine inlet. One reason is that the material degrades over time. A couple of users attending the session believed it can be difficult to get more than three years of service from such a joint; actual life depends in large part on the operating profile and the ambient environment. Second lesson learned: Rubber isn’t “soft” to a delicate compressor blade turning at 3600 rpm.

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Rotor inspection, repair, and life assessment are on the minds of managers at most plants with legacy engines. A user with a Frame 5 that in 2012 surpassed 5000 fired starts—a trigger for mandatory rotor end-of-life inspection as specified by TIL-1576—discussed his experience during the session (Fig 7). The gas-only summer peaking unit, located in an outdoor package in the Northeast, began commercial operation in 1971. Its only hot-gas-path/major inspection prior to this overhaul was in 1981.

To mitigate fatigue risk, the scope of work included eddy-current inspection of bolt holes, bores, and rim features, and advanced ultrasonic testing of disks, together with materials evaluations. No indications were found during the advanced NDE or metallurgical assessments. Inspections, materials characterization, and shop work were performed at Dresser-Rand Turbine Technology Services’ facilities in Houston..

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Dye-penetrant and eddy-current inspections identified a substantial number of indications (most very shallow) in the rabbet fillet area of the first-stage wheel. The wheel was repaired and stress analyses were conducted to confirm the viability of the repaired part for continued service (Fig 8). The rotor was reinstalled and the unit re-commissioned for service in 2013.

Conclusions drawn from analyses conducted on the rabbet-fillet repairs were these:

  • The repaired fillet has much lower stress than the original.
  • Steady and high-cycle loadings were considered. In both cases, analysis of the repaired geometry suggests improved fatigue durability.
  • Additional surface treatments of the repaired design—such as polishing and shot peening—are expected to further enhance durability relative to the original configuration.
  • The repaired configuration is believed superior to the original (in the region of the repair) with respect to allowable number of starts or hours of operation.

Exhaust-frame refurbishment. A user reported that the exhaust system for one of his company’s Frame 7Es required refurbishment after suffering years of wear and tear in cycling service. The overhaul was managed by Integrity Power Solutions LLC, an OEM licensee. IPS President David Clarida was on hand during the presentation to answer questions. For a backgrounder on the overhaul of exhaust systems for GE frames, access How to inspect, replace GT exhaust system components. Specific issues identified and addressed during the presentation included the following:

  • High temperature in the load compartment.
  • Cracking at the outer diffuser/airfoil joint (Fig 9) is relatively common in the fully welded design shown because it restricts thermal expansion. An alternative and more forgiving approach is the “floating tail” method of attachment, where a portion of the airfoil’s trailing edge is not welded to the diffuser, allowing for thermal growth. Recall that the airfoils surround structural struts, shielding them from direct contact with hot exhaust gas.
  • Cracking of the inner diffuser (Fig 10) is rare. In this case, the crack occurred at a weld, which might indicate an improper fabrication procedure.
  • Disengagement of the flex seal (Fig 11) is considered a serious issue because it allows air to leak out of the exhaust-frame cooling circuit.
  • A gap at the horizontal flange of the inner diffuser (Fig 12) is fairly common, and problematic because it allows cooling air to escape.
  • Distortion (Fig 13) has allowed the horizontal flange for the outer diffuser, and the exhaust-frame casing, to move out of alignment.
  • Failure of the exhaust frame’s outer cover (Fig 14) is quite common. A design upgrade was possible here, but not implemented.
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to enlarge

The game plan for this project was relatively simple: Replace outer and inner diffusers, airfoils, and flex seal in-kind (Type-304 stainless steel, Fig 15), along with insulation packs and bolting. A thorough inspection found the existing exhaust-frame horizontal and vertical flanges acceptable for reuse. Recall that the exhaust frame bolts to the turbine casing on one end and the aft diffuser on the other. No reinstallation or re-commissioning issues were mentioned by the speaker.

What took a bite of out of these R3 turbine buckets? President Rod Shidler and Field Service Manager Mike Hoogsteden of Advanced Turbine Support LLC had no sooner finished presenting on the results of recent inspections of  Siemens 501FD2s and GE aeros at the spring meeting when one of the company’s technicians forwarded photos of significant damage to the trailing edges of 41 third-stage buckets on a GE7FA (Fig 16). It looked as if something took a bite out of the buckets.

What apparently had happened was that a repair weld holding a section of flex-seal ring pipe in place cracked allowing the pipe section to liberate and damage the buckets, located only an inch or two away from the flex seal. Two of the lessons learned: (1) Be sure this part of the engine is on your inspection check list. (2) Repair welds in the exhaust section have an element of risk given the high temperature (nominal 1000F) and very turbulent nature of the gas stream—especially so when the work is done on engines subject to daily thermal cycles.

To understand exactly what happened, please read on. A necessary first step is a review of the arrangement and general design of the components involved. For this information, the editors reached out to IPS’s Clarida, who had been fielding questions on virtually the same subject at the GE E-class and Legacy Roundtable (see section immediately above). The exhaust systems on most GE E- and F-class units are nearly identical.

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Clarida began by pointing out that the same components often are referred to by different names in industry discussions so it’s important to look at the diagrams as you read further. Fig 17 shows the arrangement of 7FA components from the R3 bucket row to a point about 6 ft beyond the turbine exhaust flange. Note, in particular, the locations of the flex seal, flex-seal ring pipe, and exhaust-frame outer diffuser, and the proximity of the flex-seal ring pipe to the shroud blocks and the rotating R3 buckets.

The flex seal essentially is formed by a couple of layers of thin-gauge sheet metal that slide into a slit in the flex-seal ring pipe on one side and a slit in the exhaust-frame casing on the other side (Fig 18). Its purpose: Provide a barrier between the hot exhaust gas and cooling air for the bearing housing while allowing the exhaust-frame casing and outer diffuser to expand and contract independently of each other.

By their nature, function, and environment, flex seals are subject to wear and tear conducive to failure. When the barrier between the exhaust and cooling air is breeched, one of two things is likely to happen: Air from the exhaust-frame blowers escapes into the exhaust stream, thereby starving the bearing housing of cooling, or if the backpressure is high enough, exhaust gas would flow into the cooling circuit and possibly overheat the bearing housing. Thus regular inspection by a trained professional is important.

Clarida said that the flex-seal ring pipe is in two sections—one for the upper half of the unit, one for the lower half. They meet at the horizontal joint. The flex seal is divided into several sections. When a flex-seal segment fails, one possible solution (not recommended) is to cut out a section of ring pipe in the affected area, replace the damaged seal segment, and reweld the section of ring pipe in place. The alternative is to remove the upper half of the casing and replace the entire ring pipe and flex seal in the affected half of the unit.

This obviously is the more expensive and time-consuming option, but Clarida said it is the only way to ensure against the weld cracking and ring-pipe segment liberation shown in the photos provided by Advanced Turbine Support (Figs 19-21). It is very difficult to make quality weld repairs of the type required, he continued, because of the tight spacing between the shroud blocks and the ring pipe. The circumferential welds at the ends of the pipe segment being replaced are particularly challenging.

Generators, HV electrical, I&C

No user group serving gas turbine owner/operators covers generators, high-voltage (HV) equipment, and I&C to the degree CTOTF does. The day-long Gen-EI&C Roundtable conducted at the spring conference, chaired by Moh Saleh, Engineering Manager at SRP’s Desert Basin Generating Station, offered four presentations with actionable content.

The opening presentation, “7FH2 Generator Noise,” by Vice Chair for Generators Craig Courter, maintenance manager at Guadalupe Power Partners LP, was the perfect segue for the second: “Generator Belly Bands,” by Bill Dollard, manager of contracts and business development for AGT Services Inc, Amsterdam, NY. The HV portion of the program was anchored by a presentation on “The Use of Ultrasound for Arc Flash and Electrical Failure Detection,” by VP Engineering Mark Goodman of UE Systems Inc. Goodman’s presentation was developed into a standalone article in this issue.

The final formal presentation, “Early Warning of Stator-Vane Cracking in Combustion Turbines,” by David Sinay, power industry market manager for Mistras Group Inc, Princeton Junction, NJ, was included in the I&C portion of the proceedings, directed by Vice Chair John-Erik Nelson, principal mechanical engineer for Braintree Electric Light Dept’s Potter 2 and Watson Generating Stations.

In his opening remarks, Courter noted that generators, particularly those installed during the “bubble” years, continue to report key-bar rattle events. Left uncorrected, the condition is conducive to deterioration of the generator stator. The “rattle” can be detected with the Harmonic Noise Index (HNI), a test proprietary to GE that analyses acoustic data. It is a useful tool, the vice chair said, for identifying, prior to disassembly, what may be happening inside a generator.

Unit operating data indicated a slight uptick in vibration on the collector-end bearing. Operating temperature was normal and the low-frequency noise was heard only at base load. The sound was directional and there were no visual indications. Testing proceeded this way, Courter said:

  • A generator load test verified that noise attributed to high deck vibration occurred only at base load.
  • Onsite vibration analysis, based on a three-point test, identified the exciter end as having higher levels than the opposite end of the unit.
  • A third-party vibration analysis confirmed the plant’s findings.
  • The harmonic content of the acoustic data was analyzed using HNI to determine the extent to which the 2/rev frequency and its harmonics were present in the overall noise level.

The HNI level calculated was higher than that of a normally operating hydrogen-cooled generator serving a 7FA gas turbine. It also was within an HNI range that suggested significant core/key-bar interaction (Figs 22 and 23). The average sound pressure level at base load was the highest of all load points examined. Having accurate diagnostics, Courter said, allowed the plant to run until the next planned outage and to plan and obtain competitive bids for repairs with no exploration costs and no surprises.

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Dollard began his presentation by explaining exactly what belly bands—a/k/a core compression bands or belts—are and why they may be needed (Fig 24). Simply put, their function is to control radial vibration between the core and stator frame (key bars, building bolts, etc).  As the field rotates, he said, it applies a force to the core that makes it slightly egg-shaped (Fig 25). Depending on the OEM, stator-frame design, size (large units are most prone), the distortion may lead to key-bar vibration.

Dollard asked attendees, “How do you know belly bands are the problem?” He answered that question by offering the following tell-tale signs:

  • An increase in stator-frame vibration, usually in the radial direction.
  • A step-change or gradual increase in “sound” level.
  • Noisier than a sister unit.
  • Acoustic survey indicates the unit is more noisy on one end than the other.
  • Visual inspection of key bars or building bolts reveal greasing or dusting.

There are three types of belly-band projects, Dollard told the group. They are: (1) inspection and tightening, (2) replacement of existing belly bands, and (3) installation of new belly bands on units that didn’t have them originally, or extra belly bands on units that already have one or more.

It is relatively easy to inspect belly bands installed during frame manufacture, because access doors generally have been provided for this purpose (Fig 26). After removing doors, Dollard said, check bolt torque and verify tightness with a “ring” test of the belly band. If tightening is required, grinding of shims and/or buckles and welding inside the outer wrapper likely will be required (Fig 27) and care must be taken to prevent foreign material from entering the generator (Figs 28 and 29).

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A user asked, “Why might you replace or add belly bands?” Replacement usually is motivated by improper design, the AGTServices expert said. For example, the band might be of the wrong diameter relative to core OD, or the material might not be quite right for the application. Poor installation or broken bands are other reasons for replacement.

When belly bands must be installed in an operational unit to reduce vibration, it often is necessary to provide one or more access doors. Blisters, where used to facilitate the flow of cooling air, must be removed first (Fig 30). Then doors are cut in the wrapper with grinders (Fig 31), until about 1/32nd of an inch of steel remains.

Chisels are used from this point on to help keep debris from getting inside the unit. FME (foreign material exclusion) considerations contribute to the time-consuming process. It normally takes a couple of weeks to add belly bands on a GE 324 generator (Fig 32). Final welding after installation of belly bands is shown in Fig 33.  

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Testing after completion of work should include standard outage electrical testing and an EL CID test if the field was removed. You might want to check core torqueing as well, if accessible—in particular if data indicate the possibility of core looseness. Validate your efforts with an acoustical survey on restart and a visual check during the next major outage. Finally, does the generator sound quieter? Does the floor not shake as much?

Dollard’s presentation focused on GE generators. Regarding Westinghouse units, he mentioned that they generally should be core-torqued every 10 years or so and that requires removal/replacement of belly bands where installed.

Sinay introduced users to acoustic-emission monitoring technology capable of detecting cracking of compressor stator blades while the unit is operating. Mistras Group’s Acoustic Combustion Turbine Monitoring System (ACTMS™) has been installed on six gas turbines to date and is credited with at least one documented “save,” having detected and located an S1 vane crack in an F-class gas turbine at a combined-cycle plant owned and operated by Florida Power & Light Co (Fig 34).

C 34

He reminded attendees that vane cracking in some engine models is a recognized industry concern. ACTMS’s non-intrusive sensors, mounted on the turbine case by magnets or waveguides that transfer the cracking energy to the sensor while dissipating heat. A typical installation on a GE 7FA has 12 sensors arranged in a conical array to detect cracking in rows S0 through S5, an area of concern.

The sensors are wired to a monitoring system located outside the turbine enclosure that evaluates sensor signals in real time. Use of multiple sensors enables ACTMS to locate the position of a crack in three dimensions for follow-up verification during a borescope examination. Details on how ACTMS works are in Sinay’s presentation, available through CTOTF’s Presentations Library along with the other presentations summarized here.

Wet-tower inspection checklist

A highlight of the spring Combined Cycle Roundtable, was an inspection checklist presented by Ken Mortensen, an R&D project manager for SPX Cooling Technologies. The SPX/Marley veteran has managed several engineering and operations departments over his 34-yr career, so he knows wet towers from all angles—including water quality, materials selection, operations, maintenance, makeup treatment, etc.

The MIT-educated chemical engineer suggested that plant personnel pull background information for the inspector before he or she comes onsite—particularly helpful are:

  • A tower data sheet and a general arrangement drawing.
  • Service records—including details of any reconstruction, maintenance, or upgrades done since COD.

 Mortensen’s inspection checklist should be a “keeper” for any maintenance manager to build on. Here’s an outline of what he suggested:

  • Tower casing and partitions. Check for leaks, cracks, holes, brittleness. Verify attachment hardware is intact and that access doors are in good working order and closed during operation.
  • Structure. Spot-check tightness of hardware, identify the cause of any cracking found, verify columns are plumb and that diagonal bracing is in place. Girts straight? Compression blocks in place?
  • Fan deck. Verify panel integrity, and that perimeter air seals are in place and attached.
  • Access systems. Check for (1) loose stair treads, guardrails, and stringers, (2) absence of structural or hardware degradation on ladders and stair tiebacks, (3) weld integrity on metal ladders, (4) no broken or deteriorated members on walkways, and (5) condition of safety cages.
  • Cold-water basins. Look for excessive sludge and accumulated debris (remove, of course, if found), check basin seals and joints, ensure anchorage is sound and tight and that concrete basins have no spalling or cracking. Examine surrounding areas for evidence of basin leaks.
  • Piping and valves. Verify that fluid handling equipment—including supports—is in good condition and operational, and gaskets, O-rings, and bearing pads are in place. Check flanged connections for proper tightness.
  • Nozzles and spray arms. Randomly inspect nozzles for clogging. Check diffusion rings and splash plates, bands and gaskets. Look for splits in spray arms and nozzles.
  • Hot-water decks. Inspect for damage or deterioration of splash boxes, leaks in downtakes, deck sagging/support degradation, silt or scale buildup, corrosion or delamination. Ensure deck seals are in place and caulked.
  • Fill. Look for clogging, scale, algae, erosion, sagging, torn sheets, ice damage, cracking of fill support members, etc.
  • Drift eliminators. Verify cleanliness. Look for gaps between packs or at the structure, sagging, or other damage.
  • Fan stacks. Inspect for structural and UV damage, ensure tip clearances are within OEM tolerances.
  • Gearboxes and motors. Verify correct oil levels and leak-tightness—especially at the pinion seal and fittings.
  • Driveshaft and couplings. Ensure proper alignment; check flex elements for signs of deterioration, cracking, or brittleness.
  • Fans. Measure fan pitch to confirm it is within tolerances provided by the OEM. Assure that blades, hubs, clamps, etc, are in satisfactory condition.

Inspection complete, be sure that the plant’s SME (subject matter expert) sits down with the inspector for a debriefing on critical findings. Then develop a plan for inspections, maintenance, and upgrades going forward. A thorough inspection report with photos should be the final deliverable.

To learn more about how to extract top performance from wet cooling towers, access CCJ ONscreen’s webinar on the subject conducted by David Brumbaugh, president, DRB Industries LLC. Your private viewing is available at no cost. Access it today at www.ccj-online.com/onscreen.