Onsite – Page 3 – Combined Cycle Journal

SCR SYSTEM PERFORMANCE: Ammonia-system maintenance considerations

By Team-CCJ | August 21, 2023 | 0 Comments

By Vaughn Watson, Vector Systems Inc

The long-term performance of an SCR system depends on the efficiency of its critical components (Fig 1). While the catalyst often gets all the credit, and all the blame when performance declines, proper maintenance and routine inspection of the ammonia system can alleviate and prevent many factors that contribute to SCR issues in your plant.

It starts with ammonia supply. It is important to work with a reputable and accountable chemical supplier to ensure you are getting the ammonia purity necessary for your system. One way to avoid ammonia contamination is to require dedicated trucks for each haul. Also, requiring certificates and test reports before offload is important for keeping the system free of contaminants like chlorides and calcium, which can damage and plug various ammonia-system components.

Specifying the correct purity grade of ammonia is critical. For aqueous ammonia systems, reagent-grade ammonia (99.95% NH₃ diluted by weight with demineralized water) is the best option. The key differentiation is the purity of the water content of the solution, which if not demineralized could contain soluble minerals that can plug, foul, erode, and damage SCR equipment. Impurities in the reagent solution can lead to vaporizer fouling, ammonia-injection-grid (AIG) plugging, and potential catalyst performance problems. It only takes one bad load of ammonia to experience the headaches associated with ammonia impurity.

For ammonia vaporizers, impurities can plug the spray nozzles or drip rings. They also can cause calcification that hinders vaporization efficiency and can lead to liquid reagent carryover. Channeling and plugging of the vaporizer can lead to NOₓ exceedances and excess ammonia usage.

For electric vaporization systems, inspections of the heater-panel components should be done to ensure all circuits and protective devices are functioning. Inspect the electric heater as well to ensure there is no water intrusion, which can affect heater resistance.

On hot-gas recirculation systems, rotate idle fans weekly, by hand or electrical bump of the motor, thereby ensuring all bearing parts are properly lubricated. Change bearing oil semi-annually using the specified lubricant and check oil levels regularly. Grease bearing seals annually (two or three pumps maximum) using the specified product. Do not use synthetic grease and do not over-grease. Too much grease can leak into the static oil lubricant. Open the coupling cover and regrease the coupling approximately every other month with the product specified.

Inspect the AIG for proper ammonia distribution every outage. Plugging of reagent ports can have a major adverse impact on catalyst performance. If plugging is found, the AIG should be cleaned and its root cause investigated. Note that AIG design can be improved to mitigate plugging and achieve better performance.

For example, specify Type 304 stainless steel for your AIG and eliminate burrs in drilled lances where chips might collect and salt could accumulate.

Catalyst should be inspected every outage to ensure its face is not blocked by rust or insulation. This can majorly affect catalyst performance by masking its active pore sites. The catalyst frame also should be inspected for any areas that may allow exhaust gas and ammonia bypass, which can greatly affect NOₓ and ammonia slip (Fig 2).

Ensuring these key maintenance and inspections are done regularly, and addressing problems when they are discovered, are essential to an efficient SCR system. To assist end users, Vector Systems offers comprehensive maintenance checklists for download at no charge for the following equipment:

Six plants earn Best of the Best honors in CCJ’s annual Best Practices Awards program

By Team-CCJ | August 15, 2023 | 0 Comments

The COMBINED CYCLE Journal and the steering committees of the industry’s leading users groups—including 7F, 501F, 501G, 7EA, 7/9HA, Western Turbine, CCUG, STUG, GUG, PPCUG, Frame 6B, Frame 5, 501D5-D5A, AOG, and V—collaborate to expand the sharing of best practices and lessons learned among owner/operators of large frame and aeroderivative gas turbines.

Thirty-eight plants listed below participated in the 2023 Best Practices Awards program with six selected by industry experts for Best of the Best honors. Details of the Best Practices submitted will be published in future issues.

CCJ launched the industry-wide Best Practices Awards program in late 2004. Its primary objective, says General Manager Scott Schwieger, is recognition of the valuable contributions made by plant and central-office personnel to improve the safety and performance of generating facilities powered by gas turbines.

Industry focus today on safety, outage management, and performance improvement—including starting reliability, fast starting, thermal performance, emissions reduction, and forced-outage reduction—is reflected in the lineup of proven solutions submitted this year.


Amman East Power Plant
Owned by AES Corp, Mitsui, and Neberas Power
Operated by AES Corp

  • FAC encourages replacement of LP evaporator
  • Overhead-crane lift safer with load display
  • ACC washing system changes promote safer operation, improved performance
  • Admin building HVAC operational improvement

Broad River Energy Center
Onward Energy

  • Rigorous planning significantly improves outage results

H O Clarke, Topaz, and Braes Bayou
Owned by WattBridge
Operated by ProEnergy

  • Modeling for successful proactive remote monitoring and diagnostics
  • Seasonal shelters protect plant equipment in winter
  • Roving work crews effectively support small onsite staffs

Exira Station
Owned by Western Minnesota Municipal Power Agency
Operated by Missouri River Energy Services

  • Freeze-protection improvements assure high availability, reliable starts in winter

River Road Generating Plant
Owned by Clark Public Utilities
Operated by General Electric Gas Power

  • HP steam drum leak repairs
  • ‘Operator in Training’ program proves its value
  • Operators receive reverse-osmosis specialist certification
  • Racks simplify diaphragm handling, transport

Ventanilla Combined Cycle
ENEL Generacíon Perú

  • Transformer monitoring in real time ensures reliable operation, improves safety
  • HRSG tube cleaning restores lost performance
  • Improved cooling tower water chemistry yields significant savings, environmental benefits
  • Cooling tower upgrade enhances personnel safety, improves performance


AES Alamitos Energy and AES Huntington Beach Energy
Owned by AES Southland
Operated by AES Corp

AES Levant Peaker Power Plant
Owned by AES Corp, Mitsui, and Neberas Power
Operated by AES Corp

Athens Generating Plant
Owned by Kelson Energy
Operated by NAES Corp

Cape Canaveral Next Generation Clean Energy Center
Florida Power & Light

Owned by Abeinsa
Operated by NAES Corp

CPV Towantic Energy Center
Owned by Competitive Power Ventures
Operated by NAES Corp

CPV Valley Energy Center
Owned by Competitive Power Ventures and Diamond Generating Corp
Operated by DGC Operations LLC

Energía Del Valle de México II (EVM II)
Owned by Energia del Valle de Mexico Generador SAPI de CV
Operated by NAES

Essential Power Newington LLC
Owned by Essential Power Investments LLC
Operated by Operated by Cogentrix Energy Power Mgt

Fairview Energy Center
Owned by Osaka Gas USA, DLE, and Competitive Power Ventures
Operated by NAES

Faribault Energy Park
Owned by Minnesota Municipal Power Agency
Operated by NAES

Hunterstown Generating Station
Owned by Platinum Equity LLC
Managed by Competitive Power Ventures
Operated by NAES Corp

Jackson Generation
Owned by J-Power USA
Operated by NAES

Kings Mountain Energy Center
Owned by Carolina Power Partners LLC
Managed by CAMS
Operated by NAES

Kleen Energy Systems LLC
Owned by EIF Kleen, LLC
Operated by NAES

Lawrence County Generation Station
Owned by Hoosier Energy, REM, and Wabash Valley Power Assn
Operated by NAES Corp

Lee County Generating Station
Owned by Rockland Capital
Operated by NAES Corp

Linden Cogen
Owned by JERA Co, EGCO Group, Development Bank of Japan, and GS-Platform
Operated by NAES Corp

Mariposa Energy Project
Owned by Diamond Generating Corp
Operated by DGC Operations LLC

Milford Power
Owned by Starwood Energy Group Global and JERA Co
Operated by NAES Corp

Quail Run Energy Center
Owned by Starwood Energy Group Global
Operated by NAES Corp

REO Cogeneration Plant
Lansing Board of Water & Light

Rolling Hills Generating
Owned by LS Power
Operated by PIC Group

St. Charles Energy Center
Owned by Competitive Power Ventures
Operated by CAMS

Sentinel Energy Center
Owned by Diamond Generating Corp, Partners Group, and Voltage Finance LLC
Operated by DGC Operations LLC

Plant Wansley Combined Cycle
Southern Company

Wildflower Indigo Generation LLC
Owned by indirect affiliates of Diamond Generating LLC
Operated by DGC Operations LLC
Managed by DGC Asset Management LLC

Wildflower Larkspur Energy LLC
Owned by indirect affiliates of Diamond Generating LLC
Operated by DGC Operations LLC
Managed by DGC Asset Management LLC

Worthington Generation Station
Owned by Hoosier Energy
Operated by NAES Corp

Regenerating a refinery cogen’s Frame 7EA rotors

By Team-CCJ | August 14, 2023 | 0 Comments

Phoenix Rotor™ gives facility the best of both worlds


  • Units returned to 200,000 factored fired hours
  • Lengthy outages avoided
  • CapEx savings of around 40% compared with a new rotor from the OEM

THE CHALLENGE: Going beyond rotor end of life 

Gas turbine rotors have a finite lifetime. Heavy-duty gas turbine rotors in particular, like the GE Frame 7EA. Back in June 2007 (and later updated in 2011), the OEM issued a safety-critical Technical Information Letter (TIL) placing restrictions on running these units beyond 200,000 factored fired hours (FFH) or 5,000 factored fired starts (FFS).

TIL-1576 cites the risk of catastrophic failure and serious injury to nearby personnel. You could also face insurance claims being denied if you operate your units beyond these limits.

But for a power generation facility, the gas turbine is the key component. It’s the heartbeat of the entire operation.

So, plants with rotors approaching one or other of these end-of-life limits are faced with a tough decision: Do they buy an expensive new rotor from the OEM? Or do they purchase an aftermarket rotor that might not fit the operating timeline of the plant … and which often isn’t backed by warranty?

That was the position our client found itself facing in 2018. But, in fact, those weren’t the only two options available.

THE SOLUTION: Marrying the old with the new 

Our client owns a cogeneration facility in the Gulf Coast area that supplies electricity and steam to an adjacent refinery. One of their GE Frame 7EA gas turbine unit rotors was a year or two away from reaching its end of life. But our client realized they would be operating that unit well beyond the estimated eight years offered by an aftermarket rotor.

The plant was looking for a life extension option that was low risk, cost-effective, flexible, and minimized downtime. It just so happened we had recently developed the ideal solution.

Our Phoenix Rotor™ gives clients the best of both worlds: long-term operation without the high costs of purchasing a brand-new unit from the OEM. Using new and CPOTM (certified previously operated) components, our hybrid 7EA rotor is certified for 200,000 FFH. In essence, it adds an additional 25 years to your unit.

Our client was open to our Phoenix Rotor solution but, given the magnitude of the decision, due diligence was a must. What they already had with us, however, was a relationship of trust built up over many years.

Going back to 2005, we had performed all their outages. We had carried out all their parts repairs and maintenance. And they relied on us for just about everything on their 7EA gas turbines. That included handling the purchase and installation of valves when they had changed from hydraulic to electric controllers.

Building on that platform, we walked our client through the know-how that informed our engineers’ thinking. We answered all their questions. And we gave them a warranty, demonstrating how much we stood behind our solution.

THE IMPACT: Adding another quarter of a century 

With the client giving us the green light, we delivered and installed their first Phoenix Rotor on time. They then operated our rotor for a season without any issues. So pleased were they that they gave us the green light for a second rotor, which we installed the following year.

Now, nearly four years later, both rotors have been running without any issues. As have another eight Phoenix Rotors we’ve since installed for other clients.

Each of our rotors has given our client cost savings of around 40% compared with purchasing a new rotor from the OEM. And with a replacement they could drop in as soon as their old rotor was removed, they’ve avoided the potential for lengthy outages.

Not only have we regenerated the heartbeat of our client’s plant, but in the process we’ve cemented a relationship built on trust. By taking the time to listen to their wants and needs, we’ve shown them we truly are a partner who understands their business.

Learn more about rotor life extension and EthosEnergy’s other rotating equipment services and solutions at ethosenergy.com

Anomaly detection: Small deviations can mean big bucks

By Team-CCJ | August 9, 2023 | 0 Comments

Primex, the latest entrant into the field of operational anomaly detection and machine-learning (ML) services for gas-turbine-based plants, introduced its technology to the wider combined-cycle (CC) community through a series of four webinars held in June and July 2023. The legacy application of the technology has been for SO2 scrubber and BOP performance at coal-fired plants. The firm lists several big owner/operators as customers, several of which apply the service to CC units, and considers itself a services provider, not a software supplier.

ML, in its basic configuration, harnesses computing power to recognize patterns in large data sets, in this case the input and outputs of an operating system, either the entire plant, or its subsystems. ML first “trains” on the system to develop the baseline, or normal, operating patterns among the variables important to the system. Real-time data going forward is compared to the baseline to detect anomalies.

The technology is system agnostic—that is, it doesn’t care what the system is, just its streams of input and output data. However, deep domain expertise with the operating system is necessary to convert the ML results into actionable insights. For this and other reasons, the Primex team stresses that ML is not a substitute for human expertise. The technology pulls the data from the plant-wide data network, such as PI.

The webinars make a clear distinction between machine learning (ML) and artificial intelligence (AI) and they answer other questions commonly asked by powerplant managers. Many more questions remain and interested parties should contact Primex for additional information. This is typical for virtually all ML technology firms. The one requirement in ML pattern recognition is a stable baseline for comparisons, which may be difficult for CC units which start and stop frequently and cycle up and down in load.

Stewart Nicholson, founder, believes that the software offers more granularity and a deeper level of precision and confidence over traditional methods of analyzing performance–such as vendor performance curves. One example cited: An additional megawatt of output could have been worth nearly half a million dollars over 12 months (2021-2022) in the PJM market.

Use cases presented in the webinars include generation monitoring and diagnostics (for example, fault detection), performance optimization, predictive maintenance (for example, early warning of unusual degradation), performance comparison (such as before and after a major outage, or unit event like a GT water wash or HRSG chemical clean), generation and resource demand forecasting (improving bidding strategies and fuel procurement), and regional supply and demand forecasting.

“The service helps you make better decisions and make them sooner,” the experts conclude. Visit www.primexprocess.com for details.

Golden Nuggets from the Steam Turbine Users Group: Part 6

By Team-CCJ | August 9, 2023 | 0 Comments

With the 2023 Steam Turbine Users Group (STUG) approaching August 28-31 in Atlanta, part of the greater Power Users Combined Conference, reviewing some of the content from last year’s meeting should encourage you to attend or send someone from your organization to experience this valuable content in person. Presentation abstracts below are based on information available only to end users in the slide decks posted at www.powerusers.org. Those seeking deeper dives into specific topics should note the presentation titles in italics at the end of each summary and access the source material on the website.

Add expertise during your STF 30 (Alstom) ST/G outage

If you have an Alstom STF 30 ST/G, you won’t want to miss this presentation on outage experience at a 2 × 1 combined cycle by an owner/operator with six sister ST/G units in the fleet. One of the more valuable contributions you’ll find in the slides are the decisions made by the operating/engineering folks as issues were discovered with the equipment.

Detailed lessons learned provided at the end can be summed up with three considerations: Have more expertise on hand, such as a turbine field advisor/engineer (TFA) as part of the contract and/or a commissioning expert for new complex components; increase communication between shop and field (to discuss dimensions, for example); station site personnel at the shop during critical phases; and order parts 12-18 months ahead of the outage.

“Alstom ST Major Outage Observations/Lessons Learned”

First outage experience: lessons learned, plus fun photos

This owner/operator presentation on experience with its first outage (10 year) on a Mitsubishi TC4F 573-MW ST/G in a 3 × 1 configuration includes as a bonus experience with a 2021 outage of HP stop valves, HP control valves, intercept valves, and reheat stop valve. One issue here was OEM’s lack of tooling.

A more salient piece of advice in the lessons learned from the big turbine outage: “Always make friends with a local machinist.” Other suggestions include: ensure actuator soft parts and piston rings are in alignment with type of oil, test all OEM tooling during the outage, and sharp-tooth packing is worth more than a dull tooth.

While the details of both outages are worth reviewing, this quote from the plant after restart says much about how the outage went: “The unit did not even squeak when put on turning gear and spun up.”

“Mitsubishi CC ST First Major Outage Observations/Lessons Learned”

Diaphragm failure takes unit out five months after successful 20-year major

This presentation on a D11 first major outage (20 years in) includes a twist of an ending: While the ST/G major was very successful with a subsequent “exceptional startup,” low vibration, and better than expected performance, four months later site staff observed a loss of approximately 20 MW, elevated reheat pressure, and other maladies. A month later, the unit was shut down to investigate.

Damage to rotor stages 12 to 18 was noted with debris on the blades which could not be removed (Fig 16). Rotor and diaphragms were sent to a shop in Houston, and extensive, surprising (considering the major concluded five months prior) damage to the diaphragms had to be repaired. Root-cause analysis report was being finalized but the direct cause reported was failure of the Inconel 82 partition repair which resulted in the blade damage and restricted the throat area of the turbine.

“D11 Major Outage”

NERC CIP-003-9 response requirements: Roadmap to compliance and security

By Team-CCJ | August 9, 2023 | 0 Comments

The third and final in the NAES, ABS Group, Network Perception cybersecurity webinar series covered NERC CIP-003-9: What Now? Response Requirements. While the NERC standard is still subject to revisions and tweaks in the coming months, there is enough “writing on the wall” for low-impact bulk electric system (LIBES) sites to begin the long slog towards compliance and security (two different goals). It begins with a comprehensive inventory of any and all vendors who have electronic access to your site, along with all possible devices, pathways, and equipment they can access.

The first webinar emphasized the need for full supply chain visibility, developing a full network model that can inform the site about what could happen, and no longer relying on your control system OEM for compliance or security. In the second webinar, the panel of experts recommended that you automate the detection of vendor access, and alarm, log, and record all vendor sessions during which changes are made to the system; institute granular controls per vendor and test and validate them regularly; and develop methods for terminating a previously authorized vendor session, if necessary.

The third webinar hammered on the point that it’s all about your site’s supply chain. The opening salvo were words of caution and advice not to apply your processes and procedures for medium and high impact BES to your low-impact ones, and think of cybersecurity like safety. That is, you need to have a culture of cyber-vigilance. “Responsibilities cannot be assigned, they have to be accepted,” one panelist said.

Regarding what clearly is the big challenge, vendor electronic remote access (VERA), sites need to be able to document all network paths that vendors could use, and develop and document methods to authorize, monitor, alert/alarm, and record all remote vendor access. “All network paths possibly available to a ‘bad actor’ need to be exposed and understood in terms of who is connected, what can they do, when do they connect, where can they go, how do I know, and what can I do (e.g., disconnect them, if necessary). For one thing, this means that all firewall rules need to be re-assessed, though not restricted to the point that normal plant operations are impacted if vendors are cut off.

Section 6.2, for example, requires the site to be able to disable VERA if necessary, disable inbound and outbound communication, and remove physical layer connectivity. It also requires that you collect evidence that you can do, and have done, these actions.  Section 6.3 requires that you document anti-malware technologies and how they are updated and configured; and document intrusion detection/prevention software, use of automated or manual log reviews, and automated and/or manual alerting.

6.3 also requires that you detect known or suspected malicious communications, which begs the question: how do you define malicious code for specific systems?

Consistency in your processes, procedures, and responses is the key to avoiding trouble should you face an audit or an RFI (request for information), the panelists stressed. At the end, the panel noted that Network Perceptions has software, NP View, capable of generating a model, or network topology, of a site’s electronic devices, monitoring multiple vendors, and producing consistent documentation.  It is said to be “basically what’s used by the auditors.”

Access CCJ recaps and recordings of the three webinars here:


Low-impact assets and NERC CIP-003-9: Should dos vs must dos

By Team-CCJ | August 9, 2023 | 0 Comments

Perhaps the best way to think about how to respond to NERC-CIP-9, which seeks to protect the bulk electric system from a coordinated attack on smaller, low-impact assets which can result in a catastrophic event on the interconnected system, is this: Rather than think in terms of complying with the new standard, think about defending yourself in court after a malicious attack through your facility.

The panel of specialists in the second of three NAES webinars on the subject put it a bit more gingerly: What you should do vs what you must do. Example: Regarding remote access by vendors, a site must determine who, how, and where vendors access devices and have a program to document its methodology for remote access controls. What should you do? Suggests the panel, automate the detection of vendor access, alarm occurrences of such access (to the control room, for example), and long and record all sessions in which vendors made changes to the system.

That might not sound so terrible until you realize that some of your primary vendors might have fifty people authorized to access equipment on your site remotely.

Here’s another example: A site must have procedures to disable access to the network boundary (not the device) and physical or electronic methods for removing access. What you should do is:

  • Have granular controls per vendor
  • Test and validate controls per vendor and cyber-asset
  • Have methods for terminating a previously authorized session (even mid-session)
  • Form a global access management team with a two-man rule

There are several of these examples available in the recording of the webinar.

The panel concedes that some of the key language in the draft is fuzzy, but NERC will be making modifications during the 18 months owner/operators have to comply. The term asset, for example, is not explicitly defined in 003 (unlike in 002); thus, it is difficult to define the scope a site implementation. Another term, the asset boundary, which experts call a “term of art,” is not a NERC-defined term.

What should sites do know? That’s difficult to say, but be prepared for today’s “shoulds” to become tomorrow’s “musts.”

Access CCJ recaps and recordings of the three webinars here:

Latest NERC CIP addresses control-system supply chain

By Team-CCJ | August 9, 2023 | 0 Comments

Just as plant owner/operators should “be prepared for an ever-changing cybersecurity attack surface, they should also plan to control their own destinies with respect to regulatory compliance,” noted a panel of experts during a webinar hosted by NAES Corporation titled “NERC CIP-003-9: What you need to know about the new requirements and how to comply.”

If you are one of the 72% of organizations who don’t have full visibility into their control-system supply chains, the 47% of organizations who don’t have the internal resources to manage operational technology (OT)/industrial cybersecurity (ICS) incidents, or the 75% of ICS networks successfully attacked by malicious external actors, don’t fret. NAES NERC/CIPS Services, and its partners, Network Perception and ABS Group, also scheduled two follow-on webinars which deep-crawl through the weeds of this latest compliance challenge.

For those of you whose plants are categorized as “low-impact” BES (bulk electricity system) assets and don’t think this latest standard affects you, think again. “NERC is coming for you,” these experts stressed.

One of the major implications of CIP-003-9 is that “plants should no longer rely on their control system OEMs for compliance or security [two different things].” “There are limits to risk transfer,” they say. Owner/operators, and other “responsible entities” (as referred to in NERC language), must now seek full supply-chain visibility.

Why? For one, a malicious actor can attack all users of a specific plant software (that is, many BES assets) by infiltrating the third-party vendor supplying or servicing that software. This looms large when you consider that the vast majority of combined-cycle control systems in America are sourced from only a few gas-turbine vendors and one or two control-system OEMs (along with the skids and subsystems with PLCs and other devices from a variety of vendors networked into the control system).

“You’d be surprised how frequently control system vendors traffic through their remote access points, and how unaware plant staff are,” observed one expert. Section 6.3 of the new standard, approved by FERC in March, requires one or more methods for detecting known or suspected in/outbound malicious communications through vendor electronic remote access points.

This means plants need comprehensive remote access solutions, and perhaps a full network model. “If two hosts haven’t communicated,” you can’t know whether they could have communicated or not.” A model helps you understand what could happen, not what did happen, these experts stressed.

What’s happening at the GUG meeting, August 28 -31

By Team-CCJ | August 5, 2023 | 0 Comments

The ninth annual meeting of the Generator Users Group, launched in fall 2015 in Las Vegas, is an important component of Power Users’ 2023 Combined Conference in the Omni Atlanta Hotel at CNN Center, August 28 – 31.

Technical program for the upcoming meeting was developed by the all-volunteer steering committee of engineers and managers identified in the sidebar—many with decades of relevant experience. A preview of the presentations scheduled for the week beginning August 28 follows.

GUG steering committee, 2023

Chair: Jeff Phelps, consulting engineer, Southern Company
Vice Chair: Craig Spencer, director of outage services, Calpine

Dave Fischli, director of engineering and programs, Duke Energy
Andres Olivares, generator specialist, Calpine
Joe Riebau, director of compliance and electrical engineering, Constellation Power
Jagadeesh Srirama, senior electrical engineer, NV Energy
Doug Coleman, generator engineer, Duke Energy

Expectation is that most of this year’s presentations will be made available to owner/operators through the Power Users website a few months from now—except for those made by GE and Siemens-Energy. Access the GE PowerPoints at https://mydashboard.gepower.com; the Siemens-Energy presentations on the company’s Customer Extranet Portal, https://siemens.force.com/cep.

Slide decks from 2022 and earlier meetings already are accessible to registered users. If you are not registered, sign up now at www.powerusers.org: It’s easy and there’s no charge.

Monday, August 28, begins with a training workshop on stator endwinding support systems, presented by Siemens-Energy, GE, and NEC, which ends with lunch. The afternoon program is dominated by presentations from users and EPRI. Here are the highlights:

  • Generator sweep frequency response testing.
  • Generator monitoring.
  • Generator inspection/data app.
  • Case study of a generator ground fault after two years in service.
  • Stator winding ground fault: collateral damage from a core-iron hot spot.
  • Generator case-history findings.
  • Brushless exciter experience.

Tuesday, August 29, features presentations by vendors and consultants until the afternoon break, when owner/operators take over the podium. Yet another preso on endwinding support systems kicks off the program, with Jason Sinkhorn of EME Associates focusing on design, philosophy, and construction. Following Sinkhorn are:

  • Brushless exciter system overview by Daniel Besmer and Jacques Leger of Electric Machinery.
  • Advances and case study on EMI monitoring by Consultant Kent Smith, representing Cutsforth.
  • A rapid 7A6 field rewind case study by engineers from MD&A.
  • Turbogenerator rotor rewind: Maximize the value of maintenance, Rob Rettler, Toshiba America Energy Systems.
  • Generator fields: Testing, evaluations, and repairs, Jamie Clark of AGT Services Inc.
  • Generator high-speed-balance case studies by Keith Collins of MD&A.
  • Generator rotor concerns, Howard Moudy, NEC.
  • Core restacking in the horizontal position, Rhett Smith of EthosEnergy Group.
  • Circulating currents and overheating issues associated with isolated-phase bus ducts, Mohsen Tarossoly, EBI.

Topics of the user presentations are:

  • Generator protection auto-trip philosophy.
  • NERC compliance challenges.
  • Excitation-system upgrade and replacement case history.

Tuesday’s technical program ends at 5 when the three-hour Vendor Fair begins.

Wednesday, August 30, features presentations by Siemens-Energy in the morning and GE in the afternoon.

The Siemens-Energy lineup:

  • Issues and maintenance practices for (1) gas (air/H₂) coolers, (2) hydrogen gland seal rings, (3) hydrogen seal-oil systems, and (4) generator bushings.
  • Generator additive manufacturing.
  • Fleet major findings.
  • Changing operating regime
  • Stator core inspection and repair experience.

The GE lineup:

  • Model 324 phase connection cracking—including TIL-1965/1966 retirement and its replacement with a new TIL.
  • Model 390 phase connection cracking, with a focus on RCA progress.
  • Collector brush design history and maintenance best practices, plus RCA progress and supply-chain status.
  • TIL-2119, “Generator Pole-to-Pole Connection Replacement.”
  • Velomitor radio interference.
  • CTS hydrogen leakage PSIB: Reinforce replacement of new design.
  • RCA of 89SS switch failure.
    18Z/21Z aluminum spacer: Risk with potential stator rewind.
  • Stator-bar putty repair.
  • Stator-core integrity/aging factors.
  • Fault event investigation.
  • Fast stator rewind: Its applicability and benefits.

Thursday, August 31, features user presentations and open discussion. Here are some of the topics identified before press time:

  • AeroPac I main lead failure.
  • Blocked rotor cooling holes.
  • Collector flashover event and related supply-chain issues.

Keep in mind that meeting information is updated regularly on the GUG pages of the Power Users website at www.powerusers.org. Alternatively, come up to date when you register for the conference.

Golden Nuggets from the Generator Users Group: Part 5

By Team-CCJ | August 5, 2023 | 0 Comments

With the 2023 Generator Users Group (GUG) approaching August 28-31 in Atlanta, part of the greater Power Users Combined Conference, reviewing some of the content from last year’s meeting should encourage you to attend or send someone from your organization to experience this valuable content in person. Presentation abstracts below are based on information available only to end users in the slide decks posted at www.powerusers.org. Those seeking deeper dives into specific topics should note the presentation titles in italics at the end of each summary and access the source material on the website.

Considerations in the rewinding of stators

Gary Slovisky, NEC’s director of generator services, began by saying that understanding “why” a rewind must be performed is an important first step. For example, is it because of age/deterioration? Or might it be design weaknesses and/or unit idiosyncrasies?

Understanding “what” also is very important, he said. What design or unit idiosyncrasies are problematic or can be improved? What rewind components are critical to quality and can they be reused or upgraded, or should they be replaced? Slovisky then identifies components generally reused as part of the rewind. Next step: Stator-core testing and requalification using El Cid and Core Loop or Full-Flux tests.

Focus of the presentation is on GE’s 7FH2 generator. The slide deck likely would be of use to anyone with responsibilities relating to stator rewinds. It offers good general information on the following:

  • Rewind decision.
  • Specific problems—such as dry ties, vibration/resonances, rigid phase leads.
  • Endwinding redesign and modification.
  • Pros and cons of the various stator ground insulation systems.
  • Tangent Delta testing.

“Effectively Rewinding High-Voltage Generator Stators”

Better core monitoring may allow an increase in maintenance intervals

Derek Hooper, president, B-Phase, describes a new technology which promises to give local temperature and stator-bar motion in the slot during operation. Objective is to extend the time between maintenance outages given the availability of more meaningful information. Users may find it beneficial to follow the development of this technology at future GUG meetings.

“Generator Core Monitoring”

The challenging nature of recent core issues on H₂-cooled generators

AGT Services’ Jamie Clark, well known to users for his deep knowledge on the nature and repair of various generator issues—such as loose cores and low insulation values on stator and field windings in large hydrogen-cooled machines—opened his presentation at the 2022 GUG meeting with this statement: “The past 24-36 months has been very ‘eye-opening’ with respect to GE’s 7FH2 generator fleet.”

He then discusses why four planned minor outages morphed into majors during the spring 2022 outage season. AGT Services was awarded two of the four projects—each requiring a full stator rewind and field exchange. One reason for the dramatic turn of events is simple arithmetic.

More than 5000 generators (about 60% with GE nameplates) have been built since 1995 with design stator lifetimes of 25-30 years and design field lifetimes of 10-15 years. Do the shop and personnel resources required to test, inspect, and repair, and make new windings, to keep these generators operating reliably exist—especially given the recent retirements of highly experienced engineers and technicians? There are no simple solutions.

Clark outlines the work scopes for both projects completed by AGT Services and provides many photos to help define both the challenges faced and the repair work done (Figs 10-13). Think of this slide deck as a useful tutorial for those associated with generator maintenance.

“7F Generator Issues – Minors turn to Majors”

Generator literature searches

Jane Hutt’s recent passing leaves the generator community short a guiding light to technical information resources on these rotating machines. Hutt’s presentation at GUG 2022 was her last and quite possibly her best effort on the subject.

By way of background, Hutt was the primary developer, webmaster, and site manager of the Web-based International Generator Technical Community (IGTC), which serves about 6000 member engineers, technicians, and academics worldwide involved in the design, service, maintenance, and reliability of electric generators. Plus, she was an advisor to the board of directors of the Generator Users Group, which operates under the Power Users’ umbrella.

Her slide deck offers a comprehensive, thoughtful guide for conducting an efficient literature search of the internet, industry technical societies, conferences, IGTC, and other sources. It provides excellent guidance on where to look and what information to trust—particularly on the failure and repair of generator equipment.

“An Approach to Performing Time-Efficient Generator Literature Searches”

Other presentations available through the Power Users website cover a sudden excitation increase (field), summary of fleet-wide issues, failure during pre-commissioning, and main lead failure.


Scroll to Top