Presentations by owner/operators at the Generator UG meeting—Part II

This is the second and final group of presentations by owner/operators at the second annual meeting of the Generator Users Group (GUG), today organized under the Power Users Group umbrella. The GUG meeting was conducted in parallel with the annual conferences of the Combined Cycle Users Group (CCUG) and Steam Turbine Users Group (STUG) in San Antonio, Aug 22-25, 2016.

The summaries below were compiled by Clyde V Maughan, president, Maughan Generator Consultants, the muscle behind the launch of the GUG in 2015. Presentations by consultants and suppliers, also profiled by Maughan, are aggregated separately. If you missed the first part of CCJ ONsite’s coverage of the San Antonio meeting, it’s only one click away.

User presentations made at the GUG’s second annual meeting and summarized in this issue are listed below; links provided enable quick access to the topics of greatest interest to you.




Users wanting to dig deeper into one or more of these areas can access the presentations of interest on the Power Users website. You must be registered to participate in the forum, a relatively simple process if you’re not already signed up.

Interpretation and correlation of EL CID results to rated flux testing

The generator discussed in this presentation is a nominal 400-MVA, hydrogen direct-water-cooled unit which was installed in a coal-fired plant (COD 1980). The stator was fully rewound in 2004, during which time a significant core fault (287-mA peak value) was discovered by EL CID test after the new winding was installed. Subsequent rated-flux testing and progressive EL CID flux testing confirmed the concern. Part of the winding was removed and a slot-bottom section repaired (with no root cause determined). After repairs, the core was left with EL CID 65-mA peak.

Top-tooth burning and progressive thermal artifacts have been monitored during subsequent inspections with hot spots greater than 10 deg C noted; however, no EL CID readings exceeded 100 mA. The conditions on this core prompted the following questions:

      • Does trending the EL CID results offer meaningful condition trending information?

      • Do the EL CID results correlate to the rated-flux test results?

Investigations were conducted to answer these questions, with results discussed by the presenter.

 After digitizing select EL CID readings, early minor EL CID indications were corrected to rated-flux hot-spot data with the following mixed results:

      • In most cases, EL CID signature correlates to areas where a hot spot exists, but not always.

      • Both tests have inconsistencies in results across time periods.

      • EL CID was judged “more repeatable,” provided the same excitation is used.

      • More-frequent EL CID testing is preferred over less-frequent rated-flux testing.

Comparisons were made of various data: pre-rewind, post winding removal, post high-flux testing, and post repair and high-flux test. With adjustments, EL CID historical data were fairly consistent for trending progressive degradation of the core. Attempts were made to correlate high-flux and EL CID data, with mixed results.

At this point, some fundamental questions remain—for instance:

      • At what EL CID value should additional steps be taken—is a value below 100 mA appropriate in some cases?

      • Is it possible that rated-flux testing can initiate or advance existing damage deep within the core?

Understanding the detail of core-flux testing remains something of a mystery because results cannot always be taken at face value. It appears there is great opportunity for benefit related to efforts such as discussed by the presenter. For example, he is developing digital tools to facilitate fast and easy trending of EL CID results. These will be shared at a later date and users should find them extremely valuable. An update on progress is likely at the 2017 GUG meeting in Chandler (Phoenix), Ariz, Aug 28-31.

P Eng Ryan Harrison is attached to the ATCO Power central engineering group supporting the company’s fleet of generators and excitation, protection, and distribution systems.

Continuous EMI monitoring

Motors, generators, transformers, and switchgears typically are monitored with hand-held instrumentation. One informal survey found about half of the nation’s powerplants use portable EMI (electromagnetic interference) monitors. EMI also can be tracked with a radio-frequency current transformer (RFCT) placed, for example, on the generator grounding cable (Fig 1).

The speaker told generator users that a new input card had been developed by National Instruments to monitor continuously the output from the RFCT. Duke Energy currently has this instrumentation on 72 transformers and 53 generators at 15 sites. Capabilities of the diagnostic equipment were said to be considerable: full-spectrum scan, live-frequency visual, live-frequency audio, historical-spectrum viewing, power-spectrum trending—five bands with remote access from anywhere on the Duke Intranet.

Fig 2 compares two full-spectrum plots of sister units. The red trace is for a unit that had significant vibration problems, with multiple plant trips from secondary CT wiring being cut. The CT wiring has been stabilized but this trace still shows significant electrical activity. The blue trace is the sister unit at the same location and reveals no signs of any major issues.

The full-spectrum plot in Fig 3 compares scans of the same unit taken approximately two months apart. It shows electrical activity increased slightly over time. The fact that there is significant activity in the high-frequency areas leads engineers to believe there’s also significant electrical activity near the isolated phase bus (IPB).

In addition to the full-spectrum scan, plant personnel took local measurements with an EMI “sniffer.” It also indicated significant electrical activity in the IPB area. Local measurements show high EMI levels in the bushing-to-bus transition area, as well as in the potential-transformer area. Plans are in place to inspect these areas during the spring 2017 outage.

The diagnostic systems discussed were said to provide plant personnel valuable equipment condition information; interpretation of this information will become better as more experience is gained.

Kent Smith, a 35-yr utility veteran, is manager of generator engineering for Duke Energy

Generator overheating phase-to-phase failure

The subject 300-MVA, 18-kV generator was manufactured in 2000 and installed in a combined-cycle plant. On Feb 27, 2015, the plant was removed from service to upgrade the steam turbine/generator’s DCS. The change involved converting from the steamer OEM’s DCS to one installed by a different OEM on the gas turbines.

The plant returned to service Mar 16 at 10:10 a.m. Six hours later, the steam turbine tripped on relays 27, 86-1, and 87G. Both gas turbines tripped as well. The initial walk-down of the steamer revealed smoke coming out of the exciter-end generator bearing cavity; the generator frame was too hot to touch anywhere. Data analysis revealed a peak instantaneous fault current of 74 kA.

Generator cooling-water flow was controlled with a throttle valve; the throttle-valve’s position was controlled by logic, with inputs from stator hot-gas RTDs. The hot-gas RTDs were accidentally configured as “J”-type thermocouples at the ADC signal processing card during the DCS upgrade, so the “measured” temperature never exceeded 27C, thus leaving the valve throttled “off.” Back calculated, the generator gas temperature actually had reached an estimated 213C.

The DCS malfunction caused gross overheating of the generator. Damage was severe during the four-hour operating period (photos left and center), which led to the connection-ring failure shown at the right in the photo array.

Copper splices were applied to the connection ring and phase dropper, and were reinsulated locally. The stator and coolers were thoroughly cleaned and stator endwindings were treated with wicking resin. The core was requalified by both EL CID and loop/ring testing. The rotor exterior was cleaned.

The unit returned to service May 2. A stator rewind kit, purchased as a contingency, will be installed on a planned basis at the next turbine major outage—or sooner.

Craig Spencer, director of outage services for Calpine Corp’s generator fleet, oversees maintenance for over 230 machines in 20 unique frame sizes from 13 different OEMs

Handley Generating Station Unit 4 excitation failure

Handley 4 is an Allis Chalmers hydrogen- and water-cooled generator with brushless excitation. It went into service in 1976 and is used today primarily in peaking service. The main exciter is rated at 600 V/4500 amps. Conversion to DC is accomplished through a rotating 3-phase rectifier comprised of inboard and outboard diode wheels, each with eight fuses, eight heat sinks, and 16 diodes per phase.

Handley 4 was called upon to perform a required reactive capability test which dictates unit operation at maximum megawatt output and at maximum lagging MVARs for 15 minutes. The test was to be completed under a recently developed procedure for reactive capability testing. During ramp-up from no-load, the generator briefly exceeded the published maximum excitation limit. It was quickly brought back within the machine capability curve.

The MVAR output was above historical levels, but all generator parameters were acceptable and within manufacturer limits. Approximately 12 minutes into the test, the over-excitation limiter and instantaneous limiter alarms were received and the unit tripped from service.

Subsequent investigations identified significant damage to the diode wheels. All fuses on the inboard wheel were found open. Severe damage was noted on two of the diodes. Both of these fuses were associated with the same phase and had completely blown apart (Fig 1).

Parts from the failed fuses were ejected, damaging remaining components in the wheel as well as the wheel itself (Fig 2). Severe heating and arcing damage was noted on two heat sinks and their associated insulation.

Repairs required complete disassembly of both the inboard and outboard diode wheels. All fuses and diodes were replaced, damage to the inboard wheel was repaired and NDE tested, and heat-sink insulation and the two damaged heat sinks were replaced.

During the repair process, components of the undamaged outboard diode wheel were electrically tested. A large number of fuses were found open-circuited—including five out of eight fuses on one phase. Although each of these fuses is equipped with a fuse-failure pop-up indicator, none of the indicators activated. (Pop-up indicators only activate if the fuse fails electrically.) The owner’s engineers concluded that fatigue failure of the fuse elements caused the open circuits. Periodic testing of fuses is necessary to ensure their integrity.

Further investigations concluded that only two of eight fuses were in service on one phase at the time of the failure. This caused overloading of the two circuits, and subsequent overheating of two heat sinks. The insulation under the heat sinks burned and allowed electrical tracking and a phase-to-phase fault in the inboard diode wheel. The surge in fault current caused the two remaining fuses to blow apart, and the unit tripped from service.

Actions to prevent future incidents include daily inspections of the diode wheel, increased testing of diode-wheel components, revision to fleet reactive capability test procedures, and improved operator training.    

Joe Riebau, senior manager of electrical engineering at Exelon Power, has more than three decades of experience in the testing and maintenance of powerplant electrical equipment

Experience with Alstom air-cooled generators—Part II

Initial awareness of the phase-connection issue discussed by the speaker came in August 2010 following a stator-winding in-service failure. Root cause: phase-bar resonance. The failed unit was repaired and returned to service.

An aggressive plan implemented for the company’s seven air-cooled generators of the type described focused on inspection and repair of “at risk” units. It called for repairing damaged strands (where necessary) and improving the support blocking scheme at phase bars. The blocking-scheme mod has evolved and periodic maintenance is anticipated, including periodic natural-frequency testing. A monitoring program is in place to avoid a repeat failure event.

A winding in satisfactory condition is shown in Fig 1 (left). A close-up of the area is alongside. The failed joint is shown in Fig 2. The extensive burn damage resulted from the arc which continued to carry current for several seconds after ground relay trip as the field current decayed.

Fig 3 (left) revealed cracked strands (at the tip of the pen), which are shown close-up at right. Fig 4 shows the repaired connection with additional blocking and tying.

The Alstom design places a resistance temperature detector (RTD) in each of the 12 phase-lead slots. Operational data show that the RTDs in slots with many cracked strands clearly exhibited a higher temperature rise than all remaining RTDs prior to cracked-strand repair. Data mined following the repairs show the temperature rise of each RTD returned to values consistent with the overall average of all 12 stator RTDs. Thus careful attention to RTD readings offers an opportunity to remove a unit from service before winding failure.

Jeff Phelps, principal engineer, supports Southern Company’s generator fleet

Emergency field rewind

Numerous maintenance problems with generators in the Duke system were described with slides narrated by the utility’s Fred King and AGTServices Inc’s Jamie Clark (access the presentation for more excellent photography). Issues included broken J-straps (Fig 1). On another unit, a flux-probe test revealed shorted turns in a large coil. Inspection revealed the root cause as movement of turn insulation (Fig 2).

Failure of an exciter lead is shown in Fig 3 (left) with the upgraded connector to its right. Several cases of endwinding and connection-ring vibration have been experienced by Duke generators with indications as seen in Fig 4. Each of these was corrected by tie replacement and/or application of bonding resin (Fig 5).

Answers to several informal industry survey questions were provided by the presenters for everyone’s benefit. The percentages of “yes” responses follow the questions below:

    • Have you experienced J-strap failures? 50%

    • Do you require a pressure test on bore seals on hydrogen-cooled units? 89%

    • Have you found field slot-liner problems requiring field rewind? 53%

    • Have you operated a unit with one field ground? 47%

    • Do you require new copper for field rewinds? 5%

    • Do you require a high-speed balance after field rewind? 70%

    • Do you specify stator wedge materials for rewedge/rewind projects? 53%

Fred King is a senior generator specialist with more than three decades of electrical experience at Duke; Jamie Clark is AGTServices’ sales manager

SFC flashover at Mystic Generating Station

Mystic station consists of eight generating units, six of which are arranged in two separate 2 × 1 combined-cycle blocks. The gas turbines require use of a static frequency converter (SFC) for startup. A precise start-up procedure is followed, one using multiple buses ranging from the 5-kV SFC output circuit to the 16-kV-rated generator bus.

Startup consists of operating the SFC and excitation concurrently to bring the units up to 2400 rpm. The SFC is then switched off and disconnected, and combustion takes the units up to 3600 rpm. Finally, excitation is reapplied near 3600 rpm as the units become ready for synchronization to the grid.

During a troublesome start of one gas turbine, the SFC circuit failed to disconnect from the generator bus. This led to a direct connection between the SFC and generator after 2400 rpm. Then excitation was reapplied at 3600 rpm and voltage increased to 16 kV. The application of 16 kV on the 5-kV-rated SFC circuit led to failure of the SFC and caused multiple cable failures in trays linking the SFC to the generator bus.

A subsequent investigation determined the cause of the event as failure of the SFC disconnect switch to remain open after 2400 rpm. Insufficient noise filtering in the plant DCS and absence of feedback loop between field breaker and SFC disconnect switch position were deemed contributing factors.

Corrective actions implemented consisted of protection logic modification to add interlocks between SFC disconnect switches and field breaker, as well as between the SFC disconnect switches and generator neutral ground disconnect switch. Dead-band filters also were installed in the plant DCS to improve noise filtering, and field-breaker trip logic was modified to achieve faster tripping.

Temporary conduit running from the length of the generator bus to the second plant SFC was installed to reach plant operational availability within one week, but complete repair to original condition took significantly longer and required OEM involvement.

Kapil Inamdar is an engineer on the central engineering staff responsible for providing technical support to Exelon powerplants; Joe Riebau is senior manager of electrical engineering

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Vendor presentations provide GUG attendees short courses on important topics—Part II

At annual meetings of the Generator Users Group (GUG), presentations by consultants and vendors, and participation by engineers from these companies in discussion sessions, are critical to the all-volunteer organization’s success. GUG activities are supported by the electric-power industry’s three major OEMs—GE/Alstom, Mitsubishi Hitachi Power Systems Americas (via MD&A), and Siemens Energy—and several third-party equipment and services providers. The latter group includes AGTServices, Doble Engineering, Environment One Corp, EthosEnergy Group, IRIS Power, National Electric Coil, Schweitzer Engineering, and Turbine Generator Maintenance (TGM).

Six consultant/vendor presentations from the 2016 meeting in San Antonio, August 22-25, are summarized below; four others were presented in the previous issue of CCJ ONsite. The links here enable quick access to the topics of greatest interest to you.

Users wanting to dig deeper into these areas can access the presentations on the Power Users website. You must be registered to participate in the forum, a relatively simple process if you’re not already signed up.

Endwinding vibration

Endwinding vibrational forces and duties have increased as generator ratings have increased and as more compact designs have evolved. Simultaneously, cost reductions for less robust designs have tended toward more vibration problems. Examples of dust generation from vibration are shown in Fig 1. Note that endwinding vibration has been found to have the highest total loss mitigation value on recent common generator failures. If not detected before failure, considerable collateral damage may occur (Fig 2).

Two common ways are used to assess vibrational issues:

      • Periodic visual inspection looking for evidence (dusting, fretting, greasing).

      • Periodic impact (bump) testing to identify natural frequencies and ensure they are not causing resonance.

Because each of these alternatives requires an outage, there has been a trend toward installing endwinding vibration detectors (fiberoptic non-metallic accelerometers) on units with suspected or known vibration issues. Sensors are installed in locations where high vibration is most likely. Displacement values are commonly read, but velocity/acceleration values may provide better analytical information. Displacement under 5 mils is usually considered safe, with 10 mils cause for concern and 20 mils considered dangerous.

The bottom line: Endwinding vibration monitoring systems can be a valuable resource on suspect windings to provide early warning and allow optimum scheduling and planning of needed repairs.

Mladen Sasic has dedicated most of his career to instrumentation for generator condition monitoring—in particular, core lamination insulation testing and wedge-tightness assessment

Stator global VPI technology

Siemens presented an overview of its generators using global vacuum pressure impregnation (GVPI)—including operating experience and repair options. The company introduced its GVPI system in 1988 and today has more than 1650 such stator windings in service with a total capability of 239,000 MVA. Thus far, these machines have combined for more than 25-million operating hours and 320,000 start/stop cycles—in round numbers. The units employ indirect-air, indirect-hydrogen, and water cooling. Voltage ratings extend to 22 kV, outputs to 870 MVA.

Design features of the GVPI insulation system for a stator bar are highlighted in Fig 1. The insulation ground-wall materials are applied over the copper in the following sequence: inner corona protection, ground-wall insulation, inner-outer corona protection, mica splitting layer interspersed with contact tape, and outer-outer corona protection layer.

The speaker said that, to date, there has been no report of a stator-bar failure attributed to this insulation system. GVPI windings, he continued, do not require re-wedging, re-tightening of enwinding structure, or re-tightening of the laminated core—for the entire lifecycle of the generator, with a reliability factor of greater than 99.9%.

Damage to GVPI stator windings is very unlikely, and when it occurs, the cause typically is impact by a foreign object. Should such damage occur, the OEM has repair procedures to suit both the situation and customer preferences.

Some operational issues that have been experienced include dusting of de-bonded structural components, which may occur at any bonded interface in the end winding (Fig 2). Also, stator endwinding natural frequencies may experience a shift over time and if they approach the driving frequency, loosening will be accelerated. This condition can be addressed by adding tangential blocking between the top-layer bar ends near the series connections.

Localized erosion of outer corona protection has been found on several units at the ends of the core (Fig 3). Methods have been developed for the repair of such findings.

Scott Robinson has global responsibility for Siemens’ generator service business—including R&D, management of technical issues, product development, customer satisfaction, etc

Generator testing and overhauls

EthosEnergy Group’s (EEG) two-hour session was divided into these three topics:

      • Generator deterioration causes and corrective actions.

      • Overview of the company’s generator maintenance capabilities.

      • Illustration of EEG’s capabilities by review of 16 case studies.

The first slide illustrated the complexity of a powerplant and the “insignificance” of the generator. While comparatively small in size, the importance and complexity of the generator is hard to over-emphasize. In the figure, the generator is the tiny white object within the red ellipse.

The design life of generators is commonly considered to be about 30 years. Aging considerations include fatigue life of the forgings, stop/start cycles completed, equivalent operating hours remaining, the machine’s position on the “bathtub curve,” rate of increase of component failures, and the point at which plant’s economic feasibility becomes negative.

The four major stresses imposed on the generator were considered individually: electrical, mechanical, thermal, and environmental.

Electrical stresses listed were core back-iron overheating caused by over-excitation operation, overheating of core ends caused by under-excitation operation, core manufacturing or repair defects, partial-discharge activity, and surface contamination and moisture.

Mechanical stresses: core looseness, vibration and fretting, stator winding slot looseness and 60-Hz/120-Hz vibration, stator endwinding looseness and vibration, rotor component stresses caused by centrifugal forces, and abrasive material contamination.

Thermal stresses: core insulation damage, poor ventilation, continuous operation at high temperature or overload, differential expansion between components, and thermal cycling.

Environmental stresses: water absorption, oil contamination, acidic or alkaloid atmospheres, and carbon dust.

EthosEnergy Group has found that causes of in-service failures have been: 37% bearings, 33% stator windings, 11% unspecified, 6% shaft/coupling, 5% external devices, 5% rotor, and

3% brushes/slip-rings. By contrast, major problems found during inspection/test have been: 61% bearings, 10% unspecified, 8% stator windings, 8% shaft/coupling, 7% brushes/slip-rings, 4% external devices, and 2% rotor.

Test and inspection were discussed briefly. Tests commonly used on stators are: winding copper resistance, insulation resistance and polarization index, EL CID/loop test, partial discharge, insulation tan delta/power factor, and AC/DC hipot.

Tests commonly used on fields are winding copper resistance, insulation resistance and polarization index, repetitive surge oscillography (RSO), pole (and turn) drop, AC/DC HV hipot (on major repairs and rewinds).

Repairs (solutions) were discussed in detail. Topics covered included: stator core restacking, cleaning methods, repair of partial discharge indications, stator wedge testing and replacement, stress corrosion cracking of 18/5 retaining rings, exciter and collector issues, bearing and journal damage. Get the details by accessing the presentation via the Power Users website.

Remainder of the presentation was a detailed description of company capabilities for repairing generators, illustrated by a review of 16 case studies of work performed by EEG repair crews.

Darian Garcia is a project manager and Pawel Kwiatkowski is an application engineer with EthosEnergy Group

 Generator rotor thermal sensitivity

Rotor thermal sensitivity normally can be attributed to one or a combination of the following factors: insufficient or unequal clearances, asymmetrical coil expansion, bound slot wedges, blocked ventilation passages, and shorted turns. Each of the above was discussed in this presentation.

Insufficient or unequal clearances can exist from one coil to another and/or from the coil ends to the steel end plate. This condition can cause forces to be applied that may result in a bending of the rotor forging and increased vibration.

Asymmetrical coil expansion can be caused by restriction of one or more coils and result in unequal coil expansion because of the lack of an adequate slip plane between coils and forgings. This may result in unequal expansion forces on the body forging causing it to bend and vibrate.

Bound slot wedges often result from deficient wedge design/incorrect installation, resulting in asymmetrical and restricted expansion which can place bending forces on the forging and cause vibration.

Blocked ventilation passages can occur throughout the ventilation circuits with one location mentioned in particular: radial discharge holes (photo).

Shorted turns can have a variety of causes: conductor movement, incorrect blocking issues, conductor restriction leading to ratcheting or distortion, connector issues, foreign material. The location and magnitude of the shorted turns has a significant influence on the level of thermal sensitivity; specifically, the closer the coil with shorted turns is to the pole head the greater the influence of the short.

The presentation also reviewed NEC’s solutions to the thermal sensitivity problems discussed.

W Howard Moudy is National Electric Coil’s director of operations

Emergency field rewind

Numerous maintenance problems with generators in the Duke system were described with slides narrated by the utility’s Fred King and AGTServices Inc’s Jamie Clark (access the presentation for more excellent photography). Issues included broken J-straps (Fig 1). On another unit, a flux-probe test revealed shorted turns in a large coil. Inspection revealed the root cause as movement of turn insulation (Fig 2).

Failure of an exciter lead is shown in Fig 3 (left) with the upgraded connector to its right. Several cases of endwinding and connection-ring vibration have been experienced by Duke generators with indications as seen in Fig 4. Each of these was corrected by tie replacement and/or application of bonding resin (Fig 5).

Answers to several informal industry survey questions were provided by the presenters for everyone’s benefit. The percentages of “yes” responses follow the questions below:

      • Have you experienced J-strap failures? 50%

      • Do you require a pressure test on bore seals on hydrogen-cooled units? 89%

      • Have you found field slot-liner problems requiring field rewind? 53%

      • Have you operated a unit with one field ground? 47%

      • Do you require new copper for field rewinds? 5%

      • Do you require a high-speed balance after field rewind? 70%

      • Do you specify stator wedge materials for rewedge/rewind projects? 53%

Jamie Clark is AGTServices’ sales manager; Fred King is a senior generator specialist with more than three decades of electrical experience at Duke

GE’s generator product/services offerings

As a major generator manufacturer and supporter of the Generator Users Group, GE had most of the third day of the 2016 user-group conference for discussion of its product line. There were several presentations, several summarized briefly below. The editors suggest following up by reviewing the various GE powerpoints posted to the Power Users website.

      • GE has three general lines of generators: air-cooled, 30-340 MW; hydrogen-cooled, 90-590 MW, and water-cooled, 530-1800 MW. For cost and quality reasons, the company has adopted a modular design philosophy using long-time proven features and components.

      • The OEM’s recommendations are detailed in GEK103566, recently updated. GE is migrating towards removal of the first-year inspection requirement, and the latest GEK document focuses more directly on updated recommendations with less-intrusive inspections.

      • Generator uprate. This informative presentation discussed the important and not-well-understood generator kilowatt and kilovolt-ampere output issues, and the need for generator modification or replacement to safely support a plant uprate.

      • Generator fundamentals. Discussion included interesting sketches that illustrated how and why a generator can convert rotating torque energy from the turbine into electrical power for the grid. Various physical configurations of air- and hydrogen-cooled generators were described with numerous photos. Some of the major generator components were described in detail—including the stator core, stator wedging system, field winding, hydrogen seals, and excitation systems.

      • Excitation systems can be challenging components, as illustrated by a listing of 12 different excitations systems for GE and nine for Alstom, which was acquired recently by GE. Brushless and static excitation systems were discussed in detail, followed by coverage of generator protection systems.

      • GE Power Services. Worldwide, the OEM has more than 10,000 generators in service and about 1600 GW of installed capacity (both round numbers). With the recent purchase of Alstom, GE is now an amalgamation of 16 companies that existed 40 years ago. It was characterized as a growing and dynamic business.

      • Generator vibration and torsional dynamics. Every generator has some degree of thermal sensitivity and there are many possible causes; if the root cause is identified, corrective action can be taken. Motoring and negative-sequence events generally are well understood, and they occur occasionally. Depending on the severity of conditions, corrective actions may range from none need to scrapping of the rotor. Several additional important topics were addressed briefly: TIL 1292, “Generator Rotor Dovetail Inspection,” and turbine/generator torsional dynamics, generator vibration monitoring, generator bearing-metal temperature, and grid series compensation and SSR.

      • Global repair solutions. GE has power-generator repair facilities worldwide in 55 locations and staffed, in round numbers, by 4000 employees. Many of these sites are large, high-capability facilities. In the US, high-speed balance can be done only in Schenectady, NY, and Richmond, Va.

      • Generator monitoring. In support of industry trends toward condition-based maintenance (CBM), GE has increased focus on monitoring instrumentation. Some of the following devices were discussed:

          • Upgraded stator leak monitoring system (said to eliminate the need for hydraulic integrity testing during routine maintenance outages).

          • Robotics upgrade.

          • Partial-discharge sensors.

          • Shorted-turn flux probe.

          • Endwinding vibration detectors.

          • Collector health monitor.

          • Rotor shaft-voltage monitor.

Examples of instrumentation success stories also were presented.

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Optimization strategies for improving combined-cycle performance

Ten years ago, or so, in most areas of the country it didn’t much matter how long it took to start up a steam turbine. Most of those units were in baseload service, or nearly so, with fewer than about a dozen starts annually. Transitioning to the new world of competitive generation and must-take renewables, and their demands for daily start/stop, fast ramp, and other operating capabilities for which most steamers were not designed, has not been easy.

Attend meetings of the Steam Turbine Users Group and you’ll see first-hand what your industry colleagues are doing to remain competitive. Control-system upgrades that include both automated starting and shutdown, and heating blankets, for example, have eliminated cold starts at many plants and reduced start times by as much as 50% in some cases, more in others. Consider attending the next STUG meeting (Phoenix, August 28-31) to learn more.

Attendance at meetings of the user group supporting your plant’s steam-turbine (ST) and balance-of-plant (BOP) control systems also is recommended: Refinements are ongoing and it’s important to know what’s worth the investment in time and money and what might not be.

At the most recent meeting of the Ovation Users Group, the editors sat down with engineers from conference host Emerson Automation Solutions to understand better how they help turbine owner/operators build more flexibility into their operations and improve plant performance to competitively and profitably satisfy changing load demand and cycling requirements.

The company’s extensive BOP experience, they said, shows that for power blocks experiencing heavy cycling, it’s critical to look at the complete operational cycle from shutdown back through startup to drive maximum performance. Understanding the latest controls methodologies for applying targeted automation and advanced control strategies can help sites achieve quantifiable and sustainable combined-cycle efficiency improvements.

The first step in this process requires the site to understand the plant’s current operating performance, relative to the fleet, to determine if and where there are opportunities for improvement. Developing and leveraging a “matrixed database” of the combined-cycle sites in the US to establish the baseline performance against which all sites with equivalent equipment can be measured provides important insight into the world of the frequent startup and shutdown process. This can be done in several ways.

One method involves collecting relevant historical operating data from the DCS or other historian and then manually calculating key performance metrics—if historian data are available and dead bands are sufficient—such as the fuel burned, start time expended, or emissions generated to complete a specific segment of an operation or process.

This information helps answer questions like these, faced daily by owner/operators:

      • What is the optimum shutdown load path I can use to plan tomorrow’s unit release or are there steps I can take to ensure my restart tomorrow will be hot based on my projected release time?

      • How much fuel or time does it take to develop floor pressure in the drum and how much NOx was emitted during that time?

      • What are those same values measured from gas-turbine (GT) start to synchronization?

Given ongoing O&M pressures and the limited resources of most power generators, a better option might be to have the control-system vendor write logic directly into the DCS that automatically calculates and reports on critical startup efficiency parameters. The raw data are there, it’s just a matter of extracting them in a meaningful way. Trying to replicate these data at the corporate historian level often results in some loss of integrity because of data compression and archiving techniques. This effort requires a highly structured process and close collaboration between the DCS vendor and the site.

DCS-integrated dynamic performance metrics serve to benchmark current power block performance and support evaluation of opportunities for improvements. Additionally, they are later used to track and document actual improvements as the optimization project progresses.

Data collected then are used to develop accurate models of the complete operational cycle, from the beginning of shutdown back through startup. The development of these process models provides the most accurate picture of the dynamic process capabilities and allows for the mathematical solution of optimal loading paths.

Through this process, the Emerson engineers said, they have found that effectively managing the process energy state on shutdown can have a significant impact on the fuel necessary to restart the process. Achieving this demands coordination among all major control areas such as heat-recovery steam generator (HRSG), BOP, ST, and GTs.

Once the optimized startup and shutdown processes are validated (and statistically significant variables identified) using the developed models, the next step is to focus on minimizing variability through increased task automation to reduce dependency on personnel to perform “routine operations.”

This typically includes modifying start times and loads, automating load control, coordinating loading of GTs and ST, and subsequently reducing thermal stress (through predictive temperature control) in the HRSGs and steam turbine/generator. Using advanced control and automation strategies (model-based and predictive technologies) that holistically control the site’s mass energy balance will minimize energy losses and maintain the process within engineering constraints.

There is no silver bullet for improving combined-cycle plant performance, and while sites are the experts on their process, the Emerson team encourages power generators to consider the multi-discipline approach available from industry experts knowledgeable about optimization. Successful vendors adhere to a highly structured process to identify opportunities for improvement, the participants said, and then select targeted automation and advanced control applications. Implementing the optimal combination of these tools can provide significant benefits—including improved startup time, reduced emissions, improved unit stability, and increased ramp rate—all while justifying the project financially based on reduced fuel consumption and fewer trips.

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REGISTER TODAY: Three of year’s most important meetings for plant owner/operators only a month away

501F Users Group, Doble’s Life of a Transformer, HRSG Forum with Bob Anderson

Things may appear upside down and sideways to those involved in electric-power generation and delivery these days. But while the industry works through a period of turbulent change, the simple fact remains: Central generating plants must continue to operate reliably and efficiently to satisfy the needs of a growing economy.

Three meetings only a month away can help you achieve those goals. But you can only attend two because the 501F Users Group and Doble’s Life of a Transformer™ seminar both take place the week of February 19. The HRSG Forum with Bob Anderson debuts February 28 and runs through March 2. Decision-making is simple because the subject matter among the meetings is separate and distinct.

Conference summaries follow with links to program details, meeting and hotel registration, etc.

Four OEMs among the 100 vendors vying for 501F business in Reno

Attendance at the 501F Users Group meeting is highly recommended for owner/operators of these gas turbines—even personnel with double-digit years of experience. The after-market players are changing and their product/services offerings are evolving—oftentimes faster than you might think. It’s virtually impossible to do the job company management expects unless you keep up with what the suppliers are doing, particularly the OEM and its major competitors.

The user organization, chaired by Cleco Power LLC’s Russ Snyder, has been serving owner/operators for nearly two decades; the 2017 meeting promises to be the most important since the group’s founding. The program highlights hours of user presentation/discussion, four-dozen presentations by third-party equipment and services providers (so-called Vendorama), vibrant vendor fair, evening events, and special closed-session, in-depth presentations to users by industry heavyweights Siemens Energy, Mitsubishi-Hitachi Power Systems Americas, Ansaldo Energia’s PSM, GE Power, and Sulzer.

Snyder told the editors, “All owners of 501F equipment will certainly leave the conference with a better understanding of their options in the marketplace for maintaining their equipment.” Note that this will be GE’s first participation in the conference, made possible by its license from PSM for pre-2016 501F components and technology.

Here are the important links:

    • Chairman’s overview and key contacts. (link)

    • Preliminary agenda. (link)

    • Meeting registration. (link)

    • Hotel reservation. (link)

    • CCJ’s most recent report on the 501F Users Group. (link)

Vendorama 2017: Another learning dimension

Last February (2016), 94 companies showcased their offerings in the exhibition hall. Nearly half of those vendors participated in Vendorama (six presentations conducted in parallel in each of seven time slots). Vendorama presentations provide users a superior learning experience, most offering owners engine reliability/availability benefits when implemented. This is the most robust forum of its type offered by the gas-turbine user-group community. Below is the 2017 schedule:

9:30 – 10:00

  • Parts Strategy to Reduce Customer Lifecycle Cost, MHPSA
  • Next Generation Vibration Protection Systems, Alta Solutions
  • New Expansion Joint Design for 501 F&G Turbine Exhaust, Eagle Burgmann EJS
  • Lifecycle cost considerations for GT inlet filtration systems, Camfil Power Systems
  • Best Practices: Freeze Protection and Winterization Programs, Brace Intergrated Services
  • Back-up liquid Fuel System Reliability for Lucrative Capacity Payment Opportunities, JASC

10:25 – 11:15

  • Next Generation Turbine Insulation, Arnold Group USA
  • Advancements in Reliability, Sulzer Turbo Services Houston
  • Fluid Film Bearing Related, Pioneering Motor Bearing
  • Controls Capabilities for 501F (Auto-tune), PSM
  • What filter do I really need (and should it be HEPA), CLARCOR Industrial Air
  • Simplifying Gas Turbine Piping & Tubing Connections, Parker Hannifin Corporation

11:20 – 11:50

  • 501F Exhaust Wall Seal, Coverflex Mfg Inc
  • Common CT exhaust liner and silencer systems issues, Sound Technologies
  • Generator Auxiliary Upgrades: Emphasis on Hydrogen Safety, Lectrodryer
  • 501 Turbine Update, Emerson
  • Reliable Lubricant Solutions to Eliminate Varnish, American Chemical Technologies
  • Innovative Repair Capability for 501F, GE

1:05 – 1:55

  • Advancements in Reliability, Sulzer Turbo Services Houston
  • Next Generation Turbine Insulation, Arnold Group USA
  • Aeropak 1 and 2 Stator Rewind Preparedness, AGTServices
  • CT Exhaust Expansion Joints and Penetration Seals, Frenzelit Expansion Joints
  • What Maintenance Matters? Navigating Technical Priorities in New Paradigm, NEC
  • 8000-Hour Parts Life Extension on a 501F Using Dry Air Injection, Powerhouse

2:00 – 2:30

  • HEPA Filtration and the Issue of Corrosion, AAF International
  • Advancements in SCR Technology, Peerless
  • Turbine Section Component Repair, value differences between OEM and third-party repair shops, MHPSA
  • F-class Starting System & Turning Gear Design and O&M, Koenig Engineering
  • Impact of Creep-Fatigue Cracking in Grade 91 Pressure Parts, Tetra Engineering Group
  • Benefits of Maximum Access for Borescope Inspections, Advanced Turbine Support

2:55 – 3:25

  • Outage Preparation, TOPS, LLC,
  • Particle counting: Small adjustments to oil sampling process can make trendable data believable, Hy-Pro
  • Circular Non Seg Bus – the perfect bus duct solution for Gas Turbines, Crown Electric Engineering
  • New Method for Intelligent Sampling and Storage of Vibration Waveforms, SETPOINT Vibration
  • Maintaining and Upgrading Existing Inlet Air Fogging Systems, Mee Industries
  • Online Transformer Oil Conditioning, CC Jensen Oil Maintenance

3:30 – 4:00

  • Best Practices for Expansion Joint Inspection, Industrial Air Flow Dynamics
  • Switchgear life extension for gas Turbine sites with emphasis on the Citadel, National Breaker Services
  • Applying Pressure Wave Technology for HRSG Cleaning, GE
  • 501FD2/3 Row 4 Turbine Blade Repair Quality, Allied Power Group
  • Dealing with Moisture for Air Inlet Filtration Technology, Nederman-Pneumafil

Transformer design, manufacturing, operation, maintenance, testing—from A to Z

Doble Engineering Co’s Life of a Transformer™ seminar offers a multi-level learning experience that addresses the information needs of recent hires with little or no training in high-voltage equipment up to and including those of senior plant personnel. This year’s event will host hundreds of transformer specialists, maintenance strategists, asset managers, substation O&M managers, and plant and corporate electrical engineers, February 19-24, at California’s Hyatt Regency Huntington Beach.

Attendees can participate in sessions from one or more of the following courses:

    • Transformer professional program.

    • Transformer professional program—Advanced training.

    • Transformer maintenance program.

    • Transformer differential protection program.

    • Special one-day laboratory seminar.

Plus, early arrivers on Sunday, February 19, can join a tour of GE’s Transformer Remanufacturing Service Center, Los Angeles, from 2:30 to 6 p.m.

Learning objectives include the following:

    • Become familiar with transformer designs and manufacturing techniques.

    • Write transformer specifications.

    • Interpret factory and field test data.

    • Apply transformer maintenance best practices.

    • Integrate intelligent condition-monitoring technologies.

    • Develop repair, refurbishment, and replacement strategies.

    • Learn how to improve safety and grid reliability.

Most everything you’ll want to know about this meeting can be accessed via the following links:

    • Detailed agenda, including session descriptions and thumbnail biographies of the speakers. (link)

    • Training tracks. (link)

    • Special one-day seminar: Transformer condition assessment using laboratory diagnostics. (link)

    • Meeting registration. (link)

    • Hotel reservation. (link)

    • Read CCJ’s summary of Doble VP Paul Griffin’s user-group presentation, Asset Health Review of Transformer Fleets.

HRSG issues? Here’s where you can the guidance to resolve them

The HRSG Forum with Bob Anderson debuts on the EPRI Campus in Charlotte, NC, Feb 28-Mar 2. Anderson is one of very few people with the technical qualifications, plant experience, interpersonal skills, and discussion leadership to conduct a meaningful forum on heat-recovery steam generators for combined-cycle and cogeneration plants. He has honed his unique skillset over the last decade, participating in interactive user-oriented HRSG meetings in this country, Australasia, Canada, Europe, and elsewhere. Anderson joined Competitive Power Resources, an independent consulting firm specializing in HRSGs and related auxiliaries, upon retirement from Florida Power Corp/Progress Energy after 33 years of service. He held a variety of positions at those utilities, including director of gas-turbine major maintenance and manager of combined-cycle services.

Use the links below to access the conference program. It reflects the gamut of presentations and discussion sessions on HRSGs of importance to owner/operators of generating plants equipped with gas turbines ranging in size from the popular aero models up through the latest H and J machines. The know-how gained by participating in this forum will help users and maintenance professionals be more successful, and their plants more profitable.

Anderson assures attendees will benefit greatly from the expert interaction in Q&A sessions following the presentations and in the discussion sessions he so deftly leads. Plus, he says, they’ll have the opportunity to mingle and chat one-on-one and in small groups at receptions and meals. Other benefits: continuing education credit, complete meeting minutes, copies of presentations, and names and contact information of fellow participants.

Use these links to access program and registration information:

    • Agenda. (link)

    • Speaker bios. (link)

    • Meeting registration. (link)

    • Lodging/directions. (link)

    • Sponsors/exhibitors. (link)

Bob Anderson is a long-time CCJ contributor, having penned his first article in Issue 1 of the COMBINED CYCLE Journal and his most recent in the quarterly’s current issue, Number 50. The editors selected a few articles he has either written or contributed to recently to provide background on key subjects that will be addressed at the meeting.

    • Keep heat in cycling HRSGs to mitigate thermal fatigue. (link)

    • Attemperators: HRSG enemy No. 1. (link)

    • Ultrasonic flowmeter differentiates between water and steam in HRSG drain lines. (link)

    • AHUG: Sharing HRSG knowledge globally. (link)

    • Mining data to identify problems and improve performance takes perseverance and know-how. (link)

    • Understanding thermal transients and how to make SH/RH drains operate effectively. (link)

    • SPECIAL REPORT: HRSG assessments identify trends in cycle chemistry, thermal transient performance. (link)

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SPS preparing aero stats for Western Turbine’s annual meeting in two months

The countdown to the 27th annual meeting of Western Turbine Users Inc has begun (sidebar). Sal DellaVilla, CEO, Strategic Power Systems®, called to say SPS engineers are busy preparing their reports for presentation at the breakout sessions for LM2500, LM5000, LM6000, and LMS100 engine owner/operators.

As part of this effort, they compiled RAM key performance indicators from the company’s interactive ORAP® database for 2016 and compared them to averages for the previous five years—an industry report card if you will. The information presented in the companion tables comes from 607 aero units for 2016 and 1,092 units for the 2011-2015 period. The aeroderivative gas turbines in the sample include engines from GE, P&W, and Siemens AGT (formerly Rolls-Royce) and represent units operating worldwide.

To summarize the facts: There was a minimal increase in annual operating (service) hours for peaking units from the 2011-2015 period to 2016; availability decreased by about 1.1% for 2016 and reliability was pretty consistent within the two time periods. Cycling units operated 163 hours less in 2016 than they averaged in 2011-2015; availability stayed exactly the same, while reliability decreased slightly (0.1%). Baseload units operated 176 less hours in 2016 versus 2011-2015 and annual starts decreased.


The regional analysis in Table 2 shows capacity factor was down by 6.9% in the West, but showed an increase of 10.5% and 10.3% in the Midwest and Northeast, respectively. Another interesting thing to note is that all regions with the exception of the West, had a reduction in reserve standby factor.

Register today for WTUI 2017

Owner/operators of GE aeros should register now for the 27th meeting of the Western Turbine Users Inc—it’s only two months away. Venue is the South Point Hotel & Spa, Las Vegas, Nev.

The annual conference brings together O&M personnel responsible for LM2500, LM5000, LM6000, and LMS100 engines in land (electricity production and gas compression) and marine service from across the globe to share experiences and get valuable training from the experts—including the OEM and the four depots that overhaul these machines (ANZGT, IHI, MTU Maintenance, and TransCanada Turbines).

Most of what you need to know is only a click or two away on the organization’s website:

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