What follows are abstracts of presentations and key points made by suppliers from the 2019 meeting—timeless content not covered previously by CCJ online or in print. The information shared here should help you decide to participate in the 2020 virtual meeting—it takes little effort, costs nothing, and you can learn so much.

To dig deeper on the topics that follow, access speaker PowerPoints on the Power Users website, which are available to registered owner/operators only. If you don’t already have a “library card,” register today. It takes only a few minutes.

“Generator Inspection Outages—Contingency Planning,” Jamie Clark, AGT Services.

Jamie Clark’s message was simple: Increased cycling of ageing gas-turbine (GT) assets, both simple cycle and combined cycle, is causing problems for owner/operators. The proof: Service providers say as much as 60% of their shop effort during outages is emergent work. “We’re running older units harder than ever,” he continued, “harder than they were ever designed to run.”

The speaker recommended that attendees follow the latest guidelines regarding periodic inspections. These have changed recently, he said. One example: The most recent OEM guidance has no reference to field removal unless prior robotic inspections dictates via findings, or operational events—such as motoring, sync out of phase, generator trips, etc—warrant.

He also suggested users do the following before the outage:

• • Take flux-probe readings.
  • Do EMI testing (refer back to the third item in the section above on user presentations).
  • Conduct partial-discharge testing.
  • Review reports from, and since, the previous outage to review what was not done as recommended.

Clark next discussed the pros and cons of robotic inspection. At the top of the “pro” list is that robotic inspection avoids the cost and risk of field removal/reinstall. However, findings from that inspection might suggest field removal, in which case you pay twice unless it’s possible to postpone work until the next outage.

The speaker called attention to the fact that robotic inspection equipment is a limited resource, especially with competent operators and generator specialists guiding the work. He suggested releasing robotic-inspection RFPs at least six months prior to the outage and ensuring service-provider commitments are in hand within three months of outage start.

Clark then reviewed reasons for pulling the field and explained work that can be done with the field in. The latter seemed particularly helpful to attendees. Here’s what he said regarding the stator: Minor endwinding repairs (tightening, partial-discharge damage, for example) are possible, as is belly-band tightening and possibly even core tightening—provided EL CID validation is possible.

Concerning the field, collector-ring grinding and replacement typically are possible, along with brush-rigging repairs and upgrades. Retaining-ring NDE also can be done, in addition to a few other tasks.

If it becomes necessary to pull the field, Clark reminded, be sure the proper tooling is accessible—including coupling/journal shoes, skid pan, body shoe, slings, turnbuckles, and rigging from stator ends. Don’t overlook the benefits of field extraction platforms—for 7FH2s in particular, and possibly AeroPacs. This is not “incidental equipment, requiring possibly two 53-ft tractor trailers. Cranes are another consideration: A 7FH2 field weighs more than 75,000 lb, a GE 324 field about 50 tons. How close can the crane you need get into your unit? Access is almost always an issue.

Clark continued, “So now your field is out and you’ll be shipping it offsite, what do you need to know?” Come up to speed on permitting procedures and details. Figure it will take a couple of weeks to get a permit and line up trucking for the optimal route. Be aware of the permit time required and on-road time, the speaker said, advising that it’s rarely a good idea for an owner to manage shipping.

Doing field repairs? Figure seven to 10 days minimum, 30 days maximum for these typical repairs:

• • Main-lead repair usually requires a No. 1 coil (both poles)—a partial rewind. But keep in mind that if you opt for this plan, the remainder of the field is “old.”
  • Crossover repairs may require a full rewind.
  • Slot armor delamination requires a full rewind.
  • Turn shorts usually indicate a global condition: Rewind.

An exchange field might be the best course of action if operating commitments are firm. Keep in mind, the speaker said, that while all 7FH2s and 324s are the same mechanically, they can be different electrically—for example, in numbers of coils and turns per coil, etc. A few points to remember: Only accept an exchange with current high-speed balance and at-speed flux probe data, no turn shorts, high-quality vibration data, and assurance of interchangeability.

If field removal is in your plan, think about what stator repairs are prudent. Clark concludes his presentation with recommendations for rewedging, repairs to endwindings and connection rings, and a complete stator rewind. The last typically takes between 20 and 35 days, but may go to 12 weeks if bars must be replaced and they’re not available off the shelf.

“Rotor Turn Insulation Failure,” Tyler Foutz, EthosEnergy Group.

Tyler Foutz’ short presentation concerned a rotor with 22k hours of run time that was exhibiting intermittent vibrations and flux-probe data discrepancies. Turn shorts were suspected and confirmed. The retaining rings were removed and endwindings inspected. Decision was to rewind. A root-cause analysis confirmed insulation failure and side-wall interference. Repair quality was confirmed by high-speed balance/flux probe.

“What You Need to Know About the New IEEE Standard to Extend the Life of Your Existing Electrical Bus System,” Steve Powell, EBI-Electrical Builders.

Steve Powell, known to users for his insightful presentations at annual meetings, reviewed the design, construction, testing, and performance of bus systems, as established by IEEE C37.23-2015 for metal-enclosed gear. He covered voltage ratings, rated insulation levels, continuous current, rated short-circuit and momentary withstand current, short-time withstand current, and temperature limits.

Powell reminded users that isolated phase bus systems have no backup and if a failure occurs, the plant will be offline until the bus is repaired. He urged attendees to follow the OEM’s recommended service schedule (annually during a normal shutdown or every 18 months) and to confirm what you think you see (or don’t) with EMI testing and thermal imaging. He also discussed the value of periodic offline inspection and cleaning.

“Modification of a Westinghouse Stator from Diamond Coil to Bar Design,” Andrew Adam, PE, EthosEnergy Group, and Caleb Munholand, The High-Voltage Coil Manufacturing Co.

The RFQ for a generator stator rewind stated no changes would be allowed to the nominal 54-MVA (13.8 kV) three-decades-old design except for insulation class (B to F). This stator was one of the largest diamond coils ever manufactured and the OEM and only one vendor still made the component. EEG, currently the OEM for legacy Westinghouse gas turbines and generators with access to original design prints and parameters, was the successful bidder.

EthosEnergy faced manufacturing challenges, as described in the presentation, motivating conversion to a Roebel bar design; design and manufacturing details are summarized in the slides. Because overall performance and output of the generator is largely dictated by the field, the speakers said, overall generator capability remained essentially unchanged. The new winding has the same number of turns as the original, resides in the same core iron, has the same amount of copper (or more), and has equivalent losses.

The stated advantages associated with specifying the three-turn Roebel bar design over the three-turn diamond coil are these:

• • Elimination of top-strand heating. Temperatures within the winding are evenly distributed because of roebeling.
  • Elimination of installation issues associated with the diamond-coil design mitigates significant user schedule and performance risks.

“Fiber Optic Generator Monitoring,” Derek Hooper and George P Dailey, PE, BPhase Inc.

Better techniques and instrumentation for monitoring the performance powerplant equipment are always welcome. The presenters focus on the use of fiber optics for reducing the risk of generator in-service issues caused by high core temperatures and loose wedges. The presentation includes many slides on development history for those interested in how the technology has evolved.

The stated value of the BPhase developments is the following:

• • The core monitoring system can detect any excursion from normal core operating conditions. The data allows plant personnel to see a core thermal event in progress, enabling a controlled shutdown before serious damage occurs.
  • The wedge tightness analysis system allows maintenance personnel to follow the degradation of the wedge package over time, enabling the planning of rewedging without need for disassembly or robotic inspection. This can predict coil wear through mechanical vibration and core damage through slot pounding—as the condition will be detected before significant damage can occur.

While acknowledging that fiber-based systems cannot perform visual inspections, the presenters say they can certainly reduce operational risk from wedge tightness and core-related issues, thereby reducing overall risk during extended operation as necessary.

“Generator Degassing and Purging: Best Practices for Safe Plant Operation,” Christopher Breslin, Environment One Corp.

Hydrogen is explosive, colorless, and odorless, as well as difficult to contain. Yet it has been used widely as a generator coolant since the late 1930s because its windage/frictional losses are less than for air and it has excellent heat-transfer characteristics.

It is essential for plant personnel to know and understand the hazards associated with hydrogen and that all equipment for handling and storing this gas must be certified and maintained in top condition. Finally, because purging is an inherently complicated exercise, and can be dangerous if performed improperly, all personnel involved must be well trained, non-sparking tools must be used, carbon dioxide must be readily available in sufficient quantity, appropriate safety signage must be in evidence in critical areas, and keyed lockouts must be provided for “air” and “hydrogen.”

Chris Breslin, known by users for his practical and valuable presentations, reviews primary elements of the hydrogen auxiliary system, including useful one-line diagrams, provides guidelines for the purging process and best practices for safe plant operation, and reviews requirements/considerations for automated de-gassing. Consider the presentation for a lunch-and-learn session in the plant conference room.

“Comparison of Low- and High-Frequency Partial-Discharge Measurements on Rotating-Machine Stator Windings,” G C Stone and H G Sedding, Iris Power (Canada).

The speakers are among the industry’s top experts in the partial-discharge (PD) testing of electrical equipment. They draw the following conclusions in their relatively short but informative presentation: Low- and very-high-frequency PD detection methods in machines each have very different advantages. For offline applications, it is clear that low-frequency testing is preferred because PD can be better detected regardless of where it occurs in the winding.

For online testing, of transformers for example, the very-high and ultra-high methods are preferred by users because the risk of false indications caused by noise is lower; therefore, test credibility is higher.

“Realities of Global Vacuum Pressure Impregnated (GVPI) Impregnated Generator Stator Repair and Rewind,” W Howard Moudy, NEC-National Electric Coil.

Howard Moudy may have made more presentations at user-group meetings in the last decade than anyone else—in the process covering all types of generator failures and their fixes. At the 2019 GUG conference his topic was the repair and rewinding of a GVPI stator for a 13-yr-old, 100-MVA, air-cooled generator serving a geothermal plant in Indonesia. The unit tripped with damage to the winding and core. Contributors to the failure as determined by a root-cause-analysis investigation included the following:

• • Endwinding vibration/resonance.
  • Core looseness/hot spots.
  • Key-bar deterioration at the core exit—ground-wall fretting and thermal deterioration, and strand fatigue.
  • Vibration transmitted from the phase-ring assembly.

The owner expressed preference for mechanical removal of the winding despite NEC’s deep experience with the generally preferred water-blasting process. Contract was awarded to a local company with NEC in an oversight role. The local firm did not have appropriate tooling for the job which NEC supplied later to enable job completion. However, other findings created uncertainties in the customer’s mind that led to replacing the entire core. A couple of dozen photos describe the work.

NEC came away from the project with the confidence in its ability to rapidly rewind/rebuild air-cooled GVPI stators anywhere in the world. In this case the time to manufacture a new stator winding and ship it to Indonesia was 38 days.

In his concluding remarks, Moudy acknowledged that the initial cost of GVPI generators is attractive but that there are maintenance concerns and limitations associated with a decision to go with GVPI. Finally, he said that with proper engineering and planning, GVPI generators can be rewound effectively to a coil VPI design that is more easily maintained and conducive to long-term reliable operation.

What follows are abstracts of presentations and key points made by users from the 2019 meeting—timeless content not covered previously by CCJ online or in print. The information shared here should help you decide to participate in the 2020 virtual meeting—it takes little effort, costs nothing, and you can learn so much.

To dig deeper on the topics that follow, access speaker PowerPoints on the Power Users website, which are available to registered owner/operators only. If you don’t already have a “library card,” register today. It takes only a few minutes.

Replacement of bushings. The focus of presentations by owner/operators was near equally divided among stators, rotors, and inspection/testing/general. One concerned the replacement of bushings on a nominal 265-MW (1980 COD) hydrogen-cooled generator that runs only four to five months annually at baseload. The well-illustrated presentation covers testing and repairs conducted to enable decision-making, issues faced during replacement (confined space, terminal plate bonded to the bushing plate, etc), and challenges post replacement—including the loss of hydrogen and a blown isophase connection.

Stator, rotor rewinds. The same user also presented on the rewind of both rotor and stator on a 65-MVA, 13.8-kV generator. Periodic maintenance testing revealed a high dc leakage value (120 microamps leakage at 1.25 times the dc value) and a winding resistance unbalance of more than 5%. Plus, rotor inspection revealed shorted turns and loose blocking.

During the rewind, one of the contractor’s staff got a drop of glue in his eye and the use of goggles was made mandatory. After the rewind, the endwinding was re-blocked. Return to service was not smooth, the unit tripping within one second after start attempts. The gremlin: The shorting cable installed on the CT circuit was not removed after generator testing.

Then issues surfaced in the excitation system. Personnel found one diode wired incorrectly on the rotating diode bridge. It took three days to rewire the diode bridge.

EMI testing. A hot topic in generator circles continues to be electromagnetic interference (EMI) testing to detect failing electrical connections—in particular, those inside generators and bus systems. Two significant presentations were made on the topic at the 2019 GUG meeting, with the dialog continuing at the 2020 conference beginning next week.

EMI has been used since the 1950s, possibly earlier, to locate defects in power lines that cause radio and TV interference. Application to powerplant equipment began in about 1980, motivated by the work of several Westinghouse engineers who found that energy discharges in electrical equipment—such as arcing and partial discharge—produce a broadband high-frequency emission pattern. The radio-frequency (RF) currents produced, the engineers said, flow in the machine neutral connection with a magnitude and spectrum signature that can be recognized and differentiated from other RF signals which may be present.

“EMSA [electromagnetic signature analysis] Training,” the first of the EMI presentations last year, is highly recommended by the editors for the background it provides. A significant portion of the presentation is devoted to work done since 2015 by National Instrument and a major utility to develop an affordable instrument for “continuous” monitoring of EMI in generators and transformers.

Fast forward to today, the utility has installed the instrument developed on more than 80 generators and 120 transformers in its fleet. A full-spectrum reading, taken about every 15 minutes, produces data for trending.

The presentation is particularly valuable for what the utility has learned over the years. Here’s a summary of that experience across the four frequency bands of primary interest:

• • 30 to 500 kHz. In this region, diode and SCR/Thrystor firing patterns are seen and the following issues can be identified, among others: dirt contamination on diodes, SCRs, and Thyristors; loose excitation cables/connections; missing SCR firing patterns, etc.
  • 500 kHz-5 MHz is where issues in the core slots of motor and generator windings likely would be identified—including loose wedges, slot discharge, and back-of-the-core arcing.
  • 5 to 30 MHz. Issues associated with motor or generator endwinding structure are likely identified in this frequency band—including loose winding basket, corona in the endwindings, broken strands, etc.
  • 30 to 100 MHz. In this frequency band, issues associated with the generator output bus and isolated-phase bus generally are found. Look for cracked insulators, insulator contamination, water intrusion, etc.

Another resource on the subject is the CCJ article “Simple EMI Test Detects Failing Joints, Promotes High Plant Availability,” by Consultants Clyde V Maughan and James E Timperley. You can access it by using the search function on the CCJ home page at www.ccj-online.com.

The second presentation last year on electromagnetic interference, “EMSA and IPB,” is a case history spanning several years that probably would be of interest to anyone having had to deal with moisture and other issues associated with isophase bus (IPB). In the end, EMI testing confirmed the generator was not the source of the problem as suspected by most “experts”; rather, it was a defective through bushing from the IPB to the B-phase potential transformer.

Field vibration, thermal sensitivity. One user presented several case histories, each with one or more detailed graphs of meaningful operating data and several highly instructive photos. The first case of an instantaneous increase in generator field vibration was caused by loss of mass. A step change in vibration was noted during a routine startup of the gas-turbine driver. Amplitudes were acceptable to allow the unit to remain in service until a planned shutdown about two days later.

Investigators found a liberated fan blade and stator winding damage when the generator was opened for inspection. The root cause: Improper installation of the bolt locking tab on the affected fan blade.

A second case history presented by the same user also concerned the liberation of a fan blade—this time in the generator coupled to the steam turbine. Once again, the unit was allowed to remain in service following the step change in vibration until a planned shutdown, this time in four hours. Inspection revealed a liberated fan blade and stator winding damage, plus many other bolts well below the design torque value. The root cause was high bending stresses on the bolt which led to fatigue cracking. Note that the fan was designed with a single bolt per blade.

A change in mass distribution caused a step increase in vibration (typically about 2 mils) on yetanother generator, but here it was because one of the retaining rings was pushed off-center by the copper winding under certain operating conditions. This has occurred periodically for many years. Correction: Bring the unit to turning gear, then back to speed to reset the retaining ring in the proper position.

Thermally induced vibration attributed to end-turn blocking was experienced by a large 2-pole field with eight coils per pole. Root cause: Blocking between the No. 8 coil and centering ring rotated out of position during installation. At high field current, the vibration increased by 1 to 3 mils and was not consistent in behavior. Multiple compensation balance-shot attempts were made over a five-year run.

Thermally induced vibration attributed to copper binding in slots was the subject of still another case history. Investigators found copper yielding in the slot exit area of three coils exceeded the design clearance in the slot. Looking at the generator’s operating history, engineers found the unit had experienced full-load rejection (FLR) a couple of times during the tuning of a new control system.

They believed that over-speed during the FLRs caused the position of the copper to shift relative to existing worn grooves in the slot liners. Copper expansion was limited and vibration increased/decreased proportional to field current. The field was rewound and the affected copper turns replaced.

Accidental energization. Your generator is designed to guard against inadvertent energization, but owner/operators should be aware unusual conditions that bypass the protection scheme for your machine can occur. And even with protection in place, the speaker said, there is no certainty that an inadvertent energization event will not cause at least minor damage. He noted that energization even for a few cycles is conducive to high current flow and possible arcing.

This introduction to the subject should provide the incentive to read on.

First the background: Accidental energization occurs when 3-phase voltage is suddenly applied to the generator terminals. Such an event is classified as “severe” when the rotor is at standstill or on turning gear.

What happens upon energization is that a rotating flux at synchronous frequency is introduced into the field. High-amplitude currents, similar to negative-sequence currents, circulate in the rotor. The generator behaves like an induction motor and the rotor attempts to accelerate. The result is rapid and excessive heating, particularly at locations of high current density and/or high-resistance connections—such as wedge-to-wedge and retaining-ring interference fits. Damage typically is associated with the rotor forging and rotor components, not the field winding, stator core, and stator winding.

Industry experience, the speaker continued, suggests that inadvertent energization events that are cleared quickly—within one second—will cause minimal damage—possibly no damage at all. However, events longer than a second are almost certain to cause damage, severe damage if the event is more than a few seconds in duration.

The case history presented, supported with many high-resolution photos, describes an inadvertent energization event that occurred when the subject 224-MVA, 20-kV generator (COD 1958) was on turning gear. The machine has a field winding with eight coils per pole and is of the tight-fit wedge design. The field had been rewound in 2003.

The details: A disconnect switch was closed onto a live bus and the stator winding was immediately energized; the normal protection scheme was bypassed. The rotor attempted to accelerate and instrumentation revealed that a speed of 285 rpm was reached. Duration of the fault was 2.1 seconds.

Calculations were made in an attempt to compare the event with values that engineering standards indicate a machine should be able to withstand for a negative sequence event. Engineers concluded that this event may have exceeded the requirements established by the standards but not necessarily at levels that would suggest severe damage occurred.

Limited visual inspection by experts revealed surface heating, as evidenced by burned paint, had occurred between adjacent slot wedges. Thus, some damage had occurred. Heat-affected metal was expected but couldn’t be assessed without disassembly. Investigators recognized that damage to the forging was possible, but viewed the tight-fit wedge design as having a positive impact.

The consensus conclusion was that the unit could be returned to service provided start/stop cycles were restricted until repairs could be made following a thorough inspection at the next outage in about a year. It appeared that the risk of continued service was not that a catastrophic failure might occur but rather that crack initiation and propagation might worsen the damage and increase the repair scope.

That’s about what happened. Disassembly about 14 months after the event revealed a greater number of burn marks than the optimistic best-case projections based on the partial inspection. Surface discoloration suggested worst-case heat-affected regions were concentrated at wedge-to-wedge interface areas rather than wedge-to-forging areas.

Topics addressed by other user presentations included the following:

DC resistance testing provides the capability to detect high-resistance joints, corroded conductors and connections, poor-quality connections, and shorted turns, a highly experienced engineer told the group. Instrumentation capable of very low resistance measurements with sufficient accuracy, precision, and resolution is required and the speaker provided desirable specifications. Next, the expert outlined a test procedure and reviewed three case studies. Access the presentation for details.

Endwinding looseness in small machines was the subject of another presentation available in the Power Users library. It covers inspection findings, planning, analysis, repair, and recommendations.

GVPI (global vacuum pressure impregnation) stator ground fault. Lesson learned concerned the need to inspect NGT cable for shielding and grounding.

Brushless exciter component failure. This is a “how it really happened” case study that begins with the generator protection relay tripping the unit on “loss of field.” The root cause of the problem was found to be a diode module that had failed in such a manner the generator field was shorted out of the circuit. The diode modules were rebuilt with new diodes and fuses.

Lesson learned by the presenter was that the sizing of fuses for this application was not so simple as one might expect. In this case, the extended exposure to heat created a condition in which the diode shorted but the fuse did not open.

In-service failure of an AeroPac II generator attributed to a breach of FME (foreign material exclusion) procedures. No obvious findings were in evidence from an initial visual inspection but electrical testing revealed a grounded phase. The field was removed and metal BBs and other debris was found at the bottom of the frame under the core of the generator in the 6 o’clock position. A section of the core had melted. A dead-blow hammer was discovered midway in the stator and determined to be the cause of the failure.

The second half of the presentation covered repair options and plan of action. The path taken: The extent of the failure and unknowns in restacking a GVPI unit prompted the owner to swap out the failed generator stator (and rotor) with a spare available in company storage. The equipment, manpower, and schedule required for this effort are detailed in the presentation. FME controls in place at the power producer’s plants were reviewed and modified to avoid a repeat.

The annual conference of the Power Plant Controls Users Group was conducted online for the first time this year. The two-week event, exclusive to owner/operators, began November 10 with a program focused on user experiences and vendor presentations. The latter were limited to 30 minutes each and conducted in two half-hour sessions. Each vendor was assigned a “breakout room” and users were connected to their presentations of choice. While attendees could not participate in more than two vendor presentations during the live Week One program, all presentations—both user and vendor—are available now on the Power Users website, mostly in video format.

Highlights of the Week One user and vendor presentations, developed by the editors, are below.

Week Two (November 17 only) was GE Week, characterized by meaningful technical presentations, Q&A, and open discussion on topics of interest to the user community. Those presentations can be accessed through the OEM’s MyDashboard website. PPCUG2020 concluded end-of-day November 17.

PPCUG2020, Week One user presentations

User presenters wasted no time getting granular in reporting on their plant and portfolio level experiences with GT exhaust thermocouples (t/cs), corporate digital transformation programs, control system and logic mods to support deeper cycling automation, Mark VI control system upgrade, and steam turbine/generator initiated generator purge.

Exhaust thermocouples in 7F machines have been a source of operating issues and instrument failures for years. One combined cycle reported on multi-unit experience with a spring-loaded t/c replacement design. No failures were experienced for the first five years. After that, the plant experienced rapid failures on one unit, then another. You’ll have to access the presentation on the Power Users website to get the details. The plant has not “given up on the design.”

Digital transformation. Big owner/operators often implement big portfolio-wide programs. A representative from one of America’s largest electric utilities reported on progress with its digital transformation program. Truly massive in scale, it includes in-house built sub-programs for digitizing work optimization, work orders, lockout/tagout (LOTO), drone management, machine learning for critical assets, and a reporting, documentation, and comments platform organized to specific plant components and subsystems.

To head off heat-recovery steam generator damage from cycling, one plant reported on modifying the control elements and logic of its originally designed baseload combined-cycle unit to achieve greater automation and avoid the inconsistencies of manual operator intervention. Three focus areas are condensate removal through HRSG drains, attemperator sprays, and damage monitoring. Much of the work in the attemperator area was based on recommendations from an EPRI report.

In upgrading from a Mark V to a Mark VI to solve obsolescence issues, this combined-cycle plant, equipped with four gas turbines, also installed GE’s digital platform. Goals were to use the same control system for all the turbines onsite; make the logic easier to read and consume; minimize HMI changes; share EGD (Ethernet global data) signals; monitor, track, and document relevant test data and results; and automate frequent testing procedures such as lift oil system and emergency bearing oil pumps.

The GT generator remote auto-purge system at this plant never worked properly, and staff wanted to make it operate the way it was supposed to. Fortunately, engineers found a few unused contact outputs in the H2 controls cabinet, upgraded the firmware, added sensors for other purge gases like CO2, and integrated the purge sequence into a graphical interface. Once this was done, operators wanted a similar capability for the steam turbine/generator purge. The remote feature is especially needed in this location because of the frequency of severe weather events—such as hurricanes.

Some of the hair-raising in-field piping configurations, different from design, and discovered only when hardware mods were made, can only be appreciated from the presentation, available to users on the Power Users website. You probably guessed that when operators at other plants learned about the new ST/G remote auto purge system, they wanted one too, so engineers designed one for non-GE units.

PPCUG2020, Week One vendor presentations

Vendor presentations focused on flexibility strategies, small and large control system solutions for gas turbines, integrated control and monitoring solutions for older facilities, legacy controls support, and single-point-of-failure analyses.

Siemens Energy’s Galen George addressed a round-robin of options for achieving flexibility when a combined-cycle plant’s load curve shifts because of renewable energy coming online in the market or service territory. Siemens’ Jim Badgerow supplemented the discussion by illustrating how battery energy storage systems can work with traditional GT plants.

PSM reviewed how the company’s Autotune rack-mounted controls solution, now 10 years mature in version 3, can satisfy small goals, like saving minutes on a simple-cycle unit startup, and large ones, like customizing a unit for greater fuel flexibility, capacity augmentation, and better turndown. Autotune is a machine-learning solution—it captures data from successful and unsuccessful starts/load change events. Need for tuning decreases as learning progresses.

MD&A’s Michael Broggi, along with Craig Corzine, CSE Engineering Inc (MD&A purchased the rights to CSE’s IBECs HMI platform), touted IBECs ability to integrate disparate control systems in older plants—such as turbine excitation, continuous emissions monitoring (CEMS), vibration monitoring, gas condition monitoring, generator relays, auxiliary PLCs, and balance of plant. Critical areas for success focused on by the presenters are time synchronization, sequence of events, high-speed data transmission versus historian-type data rates, data export, encryption, alarms, and reports.

TC&E’s John Downing presented his firm’s capabilities with digital front ends (DFE) for exciter controls. The company boasts over 200 Innovation Series load commutated inverters (LCIs) with DFEs. TC&E has partnered with Basler Electric and Emerson for full exciter replacements. Some of the additional reliability scope can include water-cooled busbar and resistor components testing and replacement; check valves, 3-way pump valves, and other pump panel components, and Nato board replacement.

Gas Turbine Controls. Capping Week 1, Chief Engineer Abel Rochwarger addressed solutions for GE TIL-1524 (when one exhaust TC fails high) and GE TIL-1275 (high P2 pressure control), as well as for speed-pickup spikes, date cards from 1990-2001, and other cards in the Mark V and VI control systems.

Cemtek KVB-Enertec’s Gary Caccciatore discussed the benefits of using the company’s cross stack TDL/DOAS technology to measure O2, CO, CH4, NOx, and NH3 on gas-turbine inlet monitoring in pace of the typical extractive CEMS technology. Advantages include immediate response time, accuracy, and reduced CEMS maintenance and spare parts.

The annual conference of the Steam Turbine Users Group is being conducted online for the first time this year. The four-week event, exclusive to owner/operators, began November 11 with a program focused on user experiences and vendor presentations. The latter were limited to 30 minutes each and conducted in two half-hour sessions. Each vendor was assigned a “breakout room” and users were connected to their presentations of choice. While attendees could not participate in more than two vendor presentations during the live Week One program, all presentations—both user and vendor—are available now on the Power Users website.

Highlights of the Week One user and vendor presentations, developed by the editors, are below.

Week Two was GE Week, characterized by meaningful technical presentations, Q&A, and open discussion on topics of interest to the user community. Those presentations can be accessed through the OEM’s MyDashboard website.

Week Three’s program begins on Wednesday, December, 2 at 9 a.m. Eastern with the first three hours allocated for private meetings with vendors; schedule these online just as you would a doctor’s appointment. Presentations by users are next, from noon to 2 p.m. followed by these two hour-long live vendor presentations with Q&A:

• • MD&A, 2 p.m., “Using Turbine Performance to Improve your Maintenance Strategy.”
  • Shell Lubricants, 3 p.m., “Choosing and Maintaining Lubricants for your Steam Turbines.”
  • A virtual vendor fair, complete with video chat rooms, runs from 4 p.m. until the end of the day’s program at 5.

STUG2020 concludes with the Week Four program on December 9. Program format is the same as that for December 2. The featured vendor presentations on the last day of the conference are these:

• • Arnold Group, 2 p.m., “Advanced Steam Turbine Warming for Increased Startup Flexibility.”
  • EthosEnergy Group, 3 p.m. “Multiple Upgrades Improve Reliability of a D11.”

STUG2020, Week One user presentations

“D11 Last-Stage-Bucket Inspections and Findings” at five plants suggests that leading- and trailing-edge erosion of L-0 blades is driven by operating hours and exhaust temperature versus starts. More specifically: The fewer the hours and the higher the temperature the less erosion. Inspections indicate that stellite shielding noticeably reduces the erosion rate, moisture-removal troughs in the last-stage diaphragm do as well.

Other findings are the following:

• • Erosion rate for combined-cycle turbines is higher than for steamers at coal-fired plants, in most cases. Plus, trailing-edge erosion is more prevalent in the combined-cycle fleet.
  • Erosion proceeds quickly after COD, then slows. Thus, if you blend out surface irregularities, the airfoils actually erode faster than they would have had you left them alone.
  • The highest level of erosion typically occurs from the top of the blade to 3 in. below it.
  • Blade damage is related to the moisture content of the steam more so than water chemistry.

Experience with 40-in. titanium L-0 blades—Case History One. Owner/operators of Toshiba steam turbine/generators received an alert in fall 2018 regarding the failure of 40-in. titanium L-0 blades at a Japanese powerplant. The OEM recommended inspections every 24k operating hours or 600 starts.

Personnel from a US combined-cycle plant with two steam turbine/generators affected by the notification shared with STUG2020 attendees their inspection and repair experiences from spring 2018 through spring 2020. The two steam turbines (called ST10 and ST20) typically were starting 125 to 225 times annually prior to the alert.

Readers are reminded that the PowerPoint for this presentation is posted on the Power Users website and accessible only to owner/operators. With two steamers and two OEMs involved (GE, the gas-turbine supplier, provided some ST outage support), a review of the author’s slides may facilitate your understanding of this ongoing project.

A spring 2018 L-0 inspection done before the alert was issued revealed no crack indications. However, some trailing-edge wear was in evidence near the dovetails, as was some so-called “wormholing.”

A follow-up inspection of ST10 was conducted the following spring when the unit was out of service to correct diaphragm dishing. Results were dramatically different than those recorded a year earlier. This time, every L-0 blade had cracks emanating from wormholes—from two to three indications per blade to between 20 and 30. Plus, one airfoil had a 0.75-in.-long through-crack.

The titanium blades on the generator end of the machine were removed and were replaced with a pressure plate because a replacement row of blades was not immediately available. The trailing edges of the L-0 blades at the opposite end of the cylinder were checked by fluorescent penetration inspection (FPI), blended, and reinstalled. The emergency pressure-plate repair was effective with no vibration or thrust issues after restart. However, the loss of output was significant at about 17 MW.

Another advisory was released by Toshiba in mid-June 2019. It reported that low-load operation of the turbine increased the rate of trailing-edge erosion because of flow reversal. It also indicated the lower portion of the trailing edge, extending from the platform to about one-quarter of the way up the blade, was most susceptible to damage. Cracks initiated by fretting of the midspan snubber sleeve were identified as well. The fix there would be upgraded material.

The pressure plate was removed from ST10 in fall 2019, replaced with non-OEM refurbished L-0 blades except for one new GE L-0 blade. The unit achieved full capacity on its return to service following a low-speed balance.

Both turbines passed their trailing-edge FPI inspections in spring 2020, leading personnel to assume it would be smooth sailing until the major. But that did not happen as stress corrosion cracking of dovetails was found in ST20. Temporary pressure plates replaced ST20’s L-0 rows and the unit was returned to service with a reduction in output of about 40 MW.

ST10 was restarted with new L-1 blades, upgraded materials, and new locking hardware.

Attend STUG2021 to get an update on this project and others as well.

Experience with 40-in. titanium L-0 blades—Case History Two. Another combined cycle equipped with a Toshiba steam turbine then shared its experience with 40-in. titanium last-stage blades in a double-flow low-pressure section. This plant, which began commercial operation in 2005, was designed as a 2 × 1 facility but constructed as a 1 × 1, reducing the output of the 330-MW steamer to about 100 MW.

The owner/operator making the presentation bought this combined cycle in 2016 with 20k to 25k service hours and lots of time on turning gear.  There was no record of the plant having had an inspection to that point. The new owner inspected the ST’s last-stage blades in-situ during a valve outage shortly after purchase.

A major inspection was conducted in fall 2017. Plan was to visually check the last-stage blades, but during the outage the OEM recommended adding an eddy-current inspection. This was the owner’s first and last experience (to date) with 40-in. titanium blades. It sold the facility in 2019.

Most blades had worse-than-expected erosion of their trailing edges. The distressed area extended from the platform upwards about 20 in. and from the tailing edge inwards about ¼ in. Some blades also had leading-edge erosion to the same degree. Plus, one airfoil was found with a 150-mil-deep indication about 4 in. up from the platform.

Plant personnel attributed the erosion to multiple years of low-load operation—that is, low steam flow. What happens, the speaker said, is that the root section of the L-0 blades acts like a pump, pulling droplets of moisture back into the trailing edges of the airfoils. This phenomenon is described in the article referenced previously.

New titanium blades, including supporting hardware, were ordered for both rows of last-stage blades. Today there’s a two-year delivery time for these parts.

The following points were mentioned during the presentation and follow-on discussion:

• • Data provided by pressure transducers installed in the condenser hotwell, said one user, shows promise in helping to determine the degree of wear suffered by last-stage blades.
  • The general feeling of the group was that the leading edges of L-0 blades should not be blended to address erosion. Thinking on whether to blend the trailing edges, or not, was split 50/50.
  • Stress corrosion cracking is a concern and water chemists should be involved in decisions concerning the low-pressure section.
  • Do crawl-throughs and borescope inspections of the LP section at every opportunity.
  • Decisions on the lowering of backpressure during winter should be made carefully. Low pressure can exacerbate moisture formation and erosion. As one user noted, it’s a tradeoff between maintenance and additional power.

The speaker ended his presentation by noting that his company sold the plant a year after the major so he did not know when the blades would be inspected again and if they would be replaced with the ones on order.

STUG2020, Week One vendor breakout presentations

ARNOLD Group

Advanced Single-Layer Turbine Warming System

Pierre Ansmann and Norm Gagnon covered the basics of steam-turbine warming for increased startup flexibility in their breakout presentation, which began by answering the question, “Why install a turbine warming system?” Highlights of their PowerPoint, available on the Power Users website, include the following:

• • Maintenance and operational benefits.
  • Differences in warming-system arrangements.
  • System durability and reliability.
  • Importance of proper insulation for a warming system.
  • Controls.
  • Cost and schedule of the initial installation.
  • Periodic maintenance plan.

In their review of alternative warming-system arrangements, the duo rejected those integrating heating circuits in insulation blankets, installing the heater on a thin mattress below the blanket, and using glass-fiber-insulated heating cable. The optimal system for the upper casing, they said, is a heater on a metal-mesh baffle; for the lower casing, permanent mounting of heating cable below the split line.

Ansmann and Gagnon explained that the ARNOLD system features interlocking high-performance blankets which conform perfectly to the turbine surface. High-quality materials and manufacturing, and long-term high-temperature resistance, allow the company to guarantee reuse of its insulation system for 15 outages without a decrease in efficiency.

More than five-dozen thermocouples, strategically located on the turbine, ensure proper heating. Each of the 18 or so heating zones has t/cs installed on the heating wires to double check if the zone is responding correctly and at the specified temperature. Below every heating zone, multiple t/cs are mounted on the casing to confirm even heating of the turbine.

The speakers said the ARNOLD warming system can maintain your turbine in a hot-start condition for at least four or five days after shutdown. No preheating of the turbine is required prior to a restart within this time period, reducing startup fuel consumption and auxiliary power.

C C Jensen, Oil Maintenance

Remote Monitoring of Lube Oil and Diesel Conditioning

Oil conditioners/kidney-loop filters are known for their ability to keep oil, and the machines relying on it, clean and healthy. In his presentation, Axel Wegner shows you how to keep lube and diesel oils in top condition; plus, how to receive alerts as soon as anything oil-related drifts out of spec—such as cooling-water temperature, excessive wear of machine parts, ISO particle count, etc.

Wegner’s message is clear: The optimal condition-monitoring and filtration system for any machine and oil type allows you to identify problems remotely and to take action before they get out of control. This presentation is one you might want to consider sharing with your plant’s O&M staff during a lunch-and-learn session.

Intek Inc

Essential Monitoring for Quickly Identifying and Repairing Air In-Leak Sources

Collin Eckel presented case studies highlighting a new process that combines repair of air in-leaks—identified through a condenser helium leak audit—and condenser vent-line air in-leakage measurements using the company’s Multi-Sensor Probe (MSP).

Recall that the presence of helium at the condenser exhausters indicates a leak. Intek’s MSP, installed in the vent line between the condenser and exhauster, measures and continuously calculates the condenser’s total air in-leakage rate.

Data from the MSP allows users to narrow the search areas for potential leaks, thereby increasing the success rate for finding and repairing them, and reducing the time for doing so. As air in-leaks are repaired, the MSP’s air in-leak value indicates the size of the leak eliminated by subtracting the new value from the total air in-leakage rate recorded before the repair was made.

Nord-Lock Group

Solutions for the D11 Closure System, Coupling Bolts, and Casing Tensioners

Adrian Price discussed the company’s Boltight D11 closure system and casing tensioners, focusing on how these products can cut maintenance costs by reducing the time required for (1) accurate, damage-free bolting, and (2) the tops-on/tops-off process—from as much as several days to several hours.

Co-presenter Steve Busalacchi walked attendees through the EzFit coupling-bolt solution and its benefits: reduced downtime, accurate radial force, safer installation, and the ability to achieve preload with hand tools. He profiled recent cases demonstrating the technology’s value in the field; plus, the preemptive steps plant personnel can take to minimize flange-bolt faults in future maintenance situations.

Users reviewing Busalacchi’s presentation will benefit from a better understanding of the principles of mechanical expansion bolts—what they are, how they work, and how they mitigate the problems associated with fitted bolts.

Parker Motion & Flow Control Products Inc

Legacy Denison EHC Hydraulic Pumps and Steam Turbine Applications/Support

Steve Westmoreland, a senior design engineer at MFCP, had good news for users trying to get by with their Denison EHC pumps, typically used to provide the hydraulic power for opening/closing valves on steam turbines. The workhorse Denison PV-09, which dates back 70 years, is no longer offered. The pump is obsolete and parts are not available from Parker, which bought Denison in 2004. Plus, it is becoming increasingly difficult to rework existing parts.

Westmoreland introduced attendees to the Parker PV+ variable-volume piston pump, available in horizontal and vertical arrangements, as a replacement for the PV-09. The following benefits of the PV+ over the PV-09 were highlighted:

• • The pump/motor interface is a simple bolt-together process; no laser alignment necessary.
  • Response time has been halved.
  • Higher efficiency (volumetric and mechanical).
  • A hydrostatic saddle bearing/swashplate replaces wear-prone rollers and bearings.
  • Improved suction characteristics—especially important to units operating at high altitude.
  • Separate cooling/filtered-oil loop to cool shaft bearings and seal, and the hydrostatic bearings.

Siemens Energy

Advanced Crack Detection in Free-Standing Steam Turbine Blades

The risk of steam-turbine blade flutter increases at low loads and vibration monitoring can detect this condition, thereby allowing owner/operators to take corrective action with the goal of maximizing fatigue life. Think of this presentation as a primer on how blade vibration monitoring is implemented. It also discusses a proven technique developed by Siemens to detect cracks in free-standing blades.

Lifecycle Maintenance Planning and Execution for Reliability and Cost Control

The second presentation made in the Siemens breakout explained the company’s bid strategy and outage planning. The key message here was to begin planning as early as possible and engage the OEM’s experts, and others, to assist in decision-making.