Onsite – Page 3 – Combined Cycle Journal

7F, HRSG best practices from River Road Generating Plant

By Team-CCJ | April 25, 2023 | 0 Comments

River Road Generating Plant

Owned by Clark Public Utilities
Operated by General Electric
248 MW, gas-fired 1 × 1 7FA.02-powered combined cycle equipped with a Foster Wheeler HRSG and a GE A12 steam turbine, located in Vancouver, Wash
Plant manager: Robert Mash

‘Hazard hunts’ promote safer working conditions

Challenge. River Road personnel are encouraged to identify hazards that exist in their plant. An operator performing rounds, a mechanic working with a contractor, and typical housekeeping inspections are among the ways to identify hazards that may exist. Motivating the team to continuously and proactively look for hazards to mitigate risk is ongoing.

Solution. Staff developed a “hazard hunt” program that encourages employees to deep dive into specified safety topics or concerns observed. Employees define their own “hunt” criteria and close their findings with either immediate-action or work-order submittal. Findings and lessons learned are shared plant-wide.

Results. Empowering employees to “hunt” for issues they are either concerned or passionate about, typically yields more meaningful results than if you were to just hand a worker an inspection form. Empowerment helps employees excel in their jobs. It also provides ownership of project development.

Project participants:

Justin Hartsoch, operations manager
Margie Brice, EHS
Steve Ellsworth, operations


Spare set of gas-turbine inlet filters improves plant availability, performance

Challenge. The prevalence of wildfires in the Pacific Northwest has dramatically increased in the past several years, a trend predicted to continue. The local air quality during times of forest-fire smoke has caused many concerns, including the performance of the GT inlet filter system.

The increase in differential pressure (Δp) caused by particulates that comprise forest-fire smoke can rapidly reduce plant performance and may lead to equipment degradation. In extreme cases, engine shutdown may be necessary.

Forest-fire events typically occur during extended periods of hot weather, which correspond to an increase in electrical demand and higher power prices.

During a late-summer extreme smoke event in 2020, ambient air quality at River Road was so poor, visibility was reduced to 500 ft. Inlet-filter DP quickly increased to a high level. With many West Coast powerplants experiencing the same issue, and there was a high demand for inlet filters.

As fall approached and the smoke cleared, the plant was subjected to several days of dense fog.  Moisture from the fog mixed with the already heavily loaded filters and increased Δp to alarm levels. Ultimately, the plant was shut down to avoid filter-house damage.

HEPA filters had been ordered for the following spring outage and were not available for a short turnaround in the fall. Lack of availability and long lead time to acquire replacement filters was exacerbated by the collective demand for filters on the West Coast.

Clark Public Utilities’ energy resources manager worked closely with GE O&M to determine the best course of action. The outcome: River Road was able to quickly procure and install a set of non-HEPA filters to get the plant back online in a timely manner.

Solution. Non-HEPA filters remained in service until the spring outage in May 2021 when they were replaced with the HEPA filters on order that had arrived in time for the outage.

Following this experience, and given the rate of increase in the number and intensity of seasonal forest fires, a full set of spare HEPA filters was purchased and stored onsite. A spare set of inlet filter wraps also was procured and stored onsite to respond to future smoke events.

Results were an improvement in availability and performance. The spare set of filters will dramatically reduce downtime during periods when power prices are highest and power is needed most. Plus, the risk of plant efficiency loss has been reduced.

Project participants:

Justin Hartsoch, operations manager
Doug Burson, warehouse and parts procurement
Jared Yeager, operations
Terry Toland, CPU energy resources manager


Remote electronics for hotwell level transmitters eliminate erroneous readings

Background. Two level transmitters are used for calculating the hotwell level at River Road to determine if control valves should open or close to maintain the level setpoint (typically 18 in.). The calculated hotwell level also is used as a starting permissive and to trip the condensate pump on low level.

Challenge. The plant’s two original condenser-hotwell level transmitters were integrally mounted on stilling-well taps connected to the hotwell. This position exposed the transmitter electronics to high vibrations that ultimately caused them to vibrate apart and send erroneous level readings to the DCS.

When the difference between the readings from the two transmitters is greater than 3.2 in., a manual reject alarm changes the level control loop to manual until the deviation alarm is corrected. This caused control-room operators to devote more attention than advisable to that control loop while running the plant.

At times, the difference between the levels from the two transmitters—type Magnetrol E3 Modulevel—was greater than 4 in.

Solution. Install remote electronics kits on the E3 level transmitters and move the electronics away from the vibration prone area (Fig 1).

Results. Following installation of the two remote electronic transmitter kits, the level transmitters have been consistently reading within 0.25 in. of each other. With remote transmitters attached to the floor, the erroneous signals caused by condenser vibration have been eliminated. Plus, the risk of a false condensate-pump low-level trip is reduced.

Project participants:

Steve Dahl, IC&E technician
Jack Blair, IC&E technician


Ammonia-piping upgrade a safety improvement

Challenge. When River Road is operating baseload, it receives a bulk delivery of 29.4% aqueous ammonia two or three times a month. After accepting a load of dirty ammonia that contaminated the ammonia tank and system, a sock filter was installed next to the tank fill connection. Operators used a flexible, chemical-resistant hose with camlock fittings between the ammonia filter housing and the ammonia-tank fill line (Fig 2 left).

The flexible hose and its camlock fittings are a potential source for an ammonia leak during the bulk delivery. In addition, the delivery hose presents a potential trip hazard for both plant operators and delivery drivers when in use during the offloading process. Note that the hose was replaced annually as a preventive measure to reduce the risk of leaks from its degradation.

Solution. Staff developed a plan to mitigate the safety risk to operators and delivery drivers by removing the flexible hose and connections, and installing permanent 2-in-diam, Type-304 stainless steel piping (photo right).

The filter assembly was placed downstream of the ammonia tank fill-line connection within the piping containment area. MOC (management of change) was used to update drawings, procedures, new-piping testing process, and project cost, and project implementation.

Results. Risk was reduced for site and delivery personnel, contractors, and the environment. The hazard reduction was developed and executed by plant O&M personnel. The flexible hoses and connections were eliminated, and the piping modification did not create any additional hazards.

Finally, there was a minimal cost saving by eliminating the need to replace the flexible hose and camlock fittings annually.

Project participants:

Ken Roach, maintenance manager
Mike Buhman, maintenance
Mark Todd, operations


Ergonomic improvement: Motor operators installed on large steam valves

Challenge. Manual steam isolation valves (HRSG high pressure, hot reheat, and cold reheat) were retrofitted in 2002 to allow River Road to “bottle-up” steam pressure during short layups and to permit injection of nitrogen during extended layups. At that time, there was insufficient electrical breaker capacity at local power panels to support three motor-operated valves (MOV).

Absent local panel capacity, power would have to come from the main motor control center (MCC) 600 ft away. Control power also would be needed for a future tie-in to the DCS for operation and valve-position indication.

Note that it took about 10 to 15 minutes to fully open or close each of the valves, requiring considerable physical energy. An ergonomic analysis identified possible injuries that could be incurred while manually operating these valves; the safety committee recommended installing MOVs to mitigate this risk.

Solution. Plant personnel worked with Clark Public Utilities to develop a plan for adding a new 480-V power panel locally from a breaker in the main MCC. The new panel provided spare 480-V breakers to support temporary auxiliary equipment used near the HRSG during outages. Control power then was added to a remote DCS cabinet.

Note that work was required on the existing steam-valve bonnets to accommodate the MOVs.

Result. The three MOVs were installed and tested during the plant’s annual outage. A 480-V, 100-amp service panel was installed locally at the HRSG.

Now operators can open and close the MOVs locally without physical strain and move to the next startup/shutdown task, mitigating ergonomic risk. At the time this Best Practice was submitted to CCJ, the MOV controllers had not yet been connected to the plant DCS to permit remote open/close operation from the control room.

Project participants:

Ken Roach, maintenance manager
Jack Blair, IC&E technician
Steve Dahl, IC&E technician


Register TODAY for the first in-person HRSG Forum meeting in the US in three years

By Team-CCJ | April 25, 2023 | 0 Comments

HRSG Forum debuts under the Power Users umbrella, June 12-15, in the Renaissance Atlanta Waverly Hotel & Convention Center. Bob Anderson, who has moderated the lion’s share of power-industry meetings focused on the information needs of HRSG owner/operators for the last 25 years, will be at the front of the room once again. Although the pandemic kept Anderson off the live stage for the last three years, he continued to serve the user community, broadcasting worldwide via the web on Channel CCJ.

The upcoming meeting and vendor fair will be packed end-to-end with information of incomparable value to users, consultants, and services providers. All three segments of the industry qualify for participation in all sessions. The long-awaited event begins on Monday, June 12, with two special workshops; a traditional conference program—one reminiscent of past HRSG meetings with Bob Anderson—airs Tuesday and Wednesday. EPRI Day is Thursday, focusing on the research organization’s comprehensive work in the fields of HRSGs and high-energy piping.

Here’s an overview of the four-day conference:


The morning workshop focuses on water, specifically the importance of film-forming substances (FFS) in the modern world of powerplant operations. Barry Dooley of Structural Integrity (UK), the workshop moderator, will make the introductory presentation to bring attendees up to speed with a backgrounder on FFS, relatively new technology for powerplants in North America. Dooley, a member of CCJ’s Editorial Advisory Board, has been sharing his FFS experiences with the periodical’s subscribers for five years.

Several speakers—users and chemical suppliers, follow Dooley digging into the details of powerplant experience both here and in other countries. To learn more about the program, click the link.

The afternoon workshop, moderated by Jeff Henry of Applied Thermal Coatings, respected worldwide for his knowledge of boilers, materials, welding, and the ASME Code, will speak to the following:

  • Tools for supporting the safe, efficient operation of aging high-energy piping.
  • Creep damage experienced by operation of elevated temperatures.
  • Structure of welds and damage in welds at elevated temperatures.
  • Characterizing indications found in welds and their size and orientation.
  • Understanding repair objectives.
  • Proper excavation of damage.
  • What the industry-wide loss of expertise means for plant owners and operators.

Before you pack your bags for the HRSG Forum meeting in Atlanta, be sure to do your homework. Absent a textbook, thumb through back copies of CCJ to jog your memory. The more you know, the better organized you are, more value you’ll extract from the meeting. There aren’t many opportunities to access directly the knowledge held by Anderson, Dooley, and Henry, as well as other experts on the program—without later receiving an invoice.


  • HRSG steam-vent silencer safety inspections.
  • Innovative tube repair technology.
  • Ultrasonic detection of spray-water leakage.
  • HRSG safety/relief valve maintenance.
  • HRSG damage monitoring system.
  • Update and stats on HRSG cycle-chemistry control and FAC.
  • NDE and inspections for the aging HRSG fleet.
  • Attemperator inspections and repairs
  • HRSG tube-failure analysis shared by the Qurayyah combined-cycle.
  • Replacing HP evaporators.
  • Wireless monitoring system for high-energy piping.


Learn from the details shared by EPRI from its HRSG and piping program—including the following:

  • Industry challenges, in particular the loss of expertise and what this means to plant owners and operators.
  • Recent activities with high-temperature components.
  • Safety alert: State of knowledge and screening methodology for header endcaps.
  • Mitigating damage related to attemperators/desuperheaters.
  • Recent activities with low-temperature components.

Griffith Energy: 3D printing of control-valve trim promises big savings

By Team-CCJ | April 25, 2023 | 0 Comments

Griffith Energy

Owned by Griffith Energy LLC
Operated by Consolidated Asset Management Services (CAMS)
570 MW, gas-fired 2 × 1 7FA.03-powered combined cycle equipped with NEM HRSGs and a Toshiba steam turbine, located in Golden Valley, Ariz
Plant manager: Scott Henry

Challenge. Griffith Energy typically spent well over $100,000 annually to rebuild its boiler feedwater control valves to accommodate the wear and tear of operation and the need to ensure high availability and reliability.

The plant had been approached several times over the years to replace the original control valves with IMI CCI Drag® valves. Not so simple. In addition to the valve and actuator, such an upgrade would require board approval of a CapEx project, welding, cleaning of the piping, NDE of the welds, new spare-parts inventory, and drawing and manual updates (MOC).

Griffith management hadn’t pursued the installation of new valves primarily because of project scope and cost. At least 16 of the plant’s control valves could have been involved. Note that the plant has had excellent experience with IMI CCI Drag valves—including HP and hot-reheat steam bypass, spray attemperator, and desuperheater valves.

Griffith was aware that IMI CCI had done custom retrofit projects 20 years ago, but not recently—mostly because of a corporate decision to focus on valve sales. Staff requested that the company re-evaluate the possibility of retrofit trim for the Griffith valves. However, flow requirements would have made the disk stack too tall to fit in the existing valve body.

Solution. Over the last few years, advances in additive manufacturing (3D printing) processes became cost-effective and IMI CCI engineers were able to design Drag valve trim to fit the valve body. This was a game-changer. Rather than the need for a large CapEx project, the site would be able to simply install new trim, change the part number in the CMMS system, and be done. IMI CCI provided new valve tags with names, trim characteristics, part numbers, etc.

Griffith entered a pilot program with the valve manufacturer to install the first Retrofit3D trim sets into four of the most critical and difficult applications (Figs 1 and 2). Staff supplied IMI CCI with the OEM’s valve data sheets and historical operating data for engineering to accurately calculate flow/pressure needs across a wide range of plant operations.

Results. The first trim sets were installed in fall 2019 and performed well, as expected. These valves were inspected the following spring after about five months of operation. The trim parts looked like they had just been installed. The valves were reassembled with new soft goods and returned to operation.

The decision was made to upgrade all the remaining valves on HRSG 1 and reinspect after two years. Reinspect/rebuild intervals might be extended based on the as-found condition of the parts. HRSG 2 is consuming the remaining OEM and refurbished-parts inventory. As those parts are scrapped, IMI CCI trim sets will replace them.

The Retrofit3D trim is comparable in cost to the refurbished OEM trim and is expected to last at least three years longer—likely more. This could equate to a $500,000 to $900,000 saving on parts, not including the annual labor cost to rebuild. In sum, this project has resulted in a high-reliability, long-life, low-cost operation that simply requires a change to the inventory record and library.

Steam Turbine Users Group (STUG) celebrates a decade of service to the industry

By Team-CCJ | April 25, 2023 | 0 Comments

Time flies. It seems like only yesterday that the Steam Turbine Users Group was formed by representatives of nine electric power producers. But that occurred in 2013. Five of those nine still serve on the steering committee—including Jay Hoffman and Jake English who were elected the first chairman and vice chairman, respectively. Interesting too, is that in an industry where personnel switch employers relatively frequently only one committee member is at a different company than he was in 2013.

That’s stability, and one important reason STUG meetings are so valuable to steam-turbine owners and operators industry-wide. The committee members who plan the annual conference programs and lead the discussions have deep knowledge of the installed equipment and how it has performed over the years.

To illustrate: Consider the valuable insights provided by the three presentations below available in the STUG conference archives on the Power Users website:

  • Improving Steam-Turbine-Major Outage Efficiencies by leveraging experience shared by colleagues on lessons learned, outage scope and duration, etc.
  • L-0/L-1 Inspection Findings and Lessons Learned for Operation and Future Maintenance Planning offers invaluable guidance on two turbine stages of great concern to many users.
  • Vendor Shop/Field Considerations for Future Maintenance Planning to Avoid QA/QC Issues. The advice shared is of value to virtually everyone with steam-turbine responsibilities.

STUG’s upcoming 10th Anniversary meeting (August 28-31 at the Omni Atlanta Hotel at CNN) offers compelling presentations/discussions for those responsible for improving the reliability, availability, and performance of their plant’s steam turbines. Here’s a peek at the hot topics that likely will be included on this year’s program:

  • How best to deal with stop-valve stem erosion on GE combined-cycle steam turbines. The planned multi-utility panel discussion is expected to cover OEM originals versus OEM upgrades versus third-party upgrades/alternatives and share experiences on the effectiveness of installed upgrades (GE and third party) based on recent valve inspections.
  • Crossover expansion-joint failures and subsequent changes to recommended inspections.
  • Managing the O&M of aging assets (including steam turbines at coal-fired and combined-cycle plants) given the increasing impacts of renewables on system operation. Discussion is expected to cover ARD replacement, L-0 trailing-edge erosion, valve seat cutting, and more.

Keep up with program developments on the Power Users website, where you also can register for the meeting, book your hotel room, etc.

A look back. STUG was born out of necessity. In the early days of the Power Users organization, the primary focus for most steering committees was tackling and managing-through the many issues plaguing the global gas-turbine fleet. As such, less and less time was available during most conferences to cover the combined-cycle steam turbines, generators, and balance-of-plant equipment. This may have been acceptable given the young age of that equipment relative to major maintenance.

However, by the early 2010s, Power Users recognized the growing number of steam-turbine issues—not just within the combined-cycle fleet, but also with the aging fossil fleet of traditional standalone steam turbines.

The STUG steering committee formed in 2013 was charged with “taking the temperature of the steam-turbine industry” by consulting with both users and vendors, and to host a conference aimed at addressing several of the day’s hot topics. The group’s inaugural conference was held in Richmond (Va) in August 2014. More than 60 users and 20 vendors participated.

Since then, STUG has continued to grow in both size and value. Today, STUG meetings are co-located with the annual conferences of the Combined Cycle, Generator, and Power Plant Controls Users Groups under the Power Users’ umbrella. This “Combined Conference” is attended by about 200 users annually.

The 2023 STUG Steering Committee

Chairman: Matt Radcliff, Dominion (2019)
Eddie Argo, Southern Company (2013)
Jake English, Duke Energy (2013)
Jared Harrell, OxyChem (2023)
Jay Hoffman, Tenaska (2013)
Connor Hurst, Tampa Electric (2020)
Mark Johnson, Florida Power & Light (2020)
John McQuerry, Calpine (2013)
Lonny Simon, OxyChem (2013)
Brandon Steward, Southern Company (2023)
Seth Story, Luminant (2018)

Past members of the STUG Steering Committee

Jess Bills, SRP (2013-2021)
Gary Crisp, NV Energy (2013-2020)
Bert Norfleet, Dominion (2013-2019)
John Walsh, Sundevil Power (2013-2016)

Manage the 7F rotor wave to ensure your generation assets are available when needed

By Team-CCJ | April 25, 2023 | 0 Comments

A large number of 7F gas turbines were installed during the boom years of 1999 to 2004. Now, nominally 25 years later, the industry is facing a “7F rotor wave” with many turbine rotors nearing “end-of-life” (EOL, 5000 factored fired starts or 144,000 factored fired hours) and coming due for an exchange, replacement, or lifetime extension. Because maintaining rotor inventory on a user’s balance sheet gets expensive quickly, most owners do not have enough spare rotors to cover their total installed base.

PSM’s Katie Koch, global product manager, and Brian Loucks engineering manager for rotors and casings, told the editors that the Hanwha company has developed an exchange program to help customers better manage their assets by providing fully vetted rotors for up to two major intervals—including any new replacement components—in exchange for EOL assets. Rotor installation can be accomplished during a major inspection. The bottom line: Customers avoid unnecessary downtime and can continue to operate with a reliable asset.

However, the large number of rotors needed is pressing against supply-chain constraints. Simply put: The OEM can’t meet the industry’s needs alone. And other vendors are challenged as well. Development of forgings, especially ones of the nickel alloys required in the 7F turbine section, can take considerable time. Be mindful that rotor demand must be addressed now to ensure power production is not compromised in the future.

PSM’s lifetime extension program can help in this regard, say Koch and Loucks. In their presentation at the upcoming 7F Users Group conference (May 15-19, Atlanta) the duo will explain how PSM can help you manage the rotor wave with its improved nickel turbine wheels, robust back-end conversions, and other offerings.

Digital twins: Alignment between design intent and real-world powerplant operation

By Team-CCJ | April 25, 2023 | 0 Comments

With relevant design and operational expertise, and applied data science, digital twins can be harnessed for areas such as fleet comparisons, plant-specific KPIs, and forward-looking predictions.

However, the twins are only as good as the domain expertise and data tools implemented to provide the analytics. PSM’s Greg Vogel, senior engineering manager for technology programs, will update attendees at the upcoming 7F Users Group conference (May 15-19, Atlanta) about how his company’s gas-turbine GT domain expertise has grown over the last 20 years.

Today, PSM’s design and validation methods and data sets, says Vogel, provide extensive learning opportunities for assessing data trends. By integrating this capability into a fleet of monitored GT assets, the company can tune its models both on a fleet and individual-unit basis.

Tuned digital twins allow operators to understand how a unit (or fleet) should be performing and highlight areas of lost potential as seen in the operational data.  The web-based solution PSM is currently validating provides visualizations that start at a high-level health score and allow subsequent drill-down through analytical layers all the way to the individual twins.

7F Best Practices from Essential Power Newington

By Team-CCJ | April 19, 2023 | 0 Comments

Essential Power Newington

Owned by Essential Power Investments
Operated by Cogentrix Energy Power Management
565-MW, dual-fuel 2 × 1 combined cycle located in Newington, NH. Plant operated baseload from COD in 2002 until it began cycling in 2008
Plant manager: Tom Fallon

Electronic safety orientation program for contractors

Challenge. Essential Power Newington annually processes hundreds of contractors through its site-specific safety orientation program, consisting of an instructional safety-related video and certificate of completion. The rate of certifications increases significantly during outage periods.

The challenge of completing site safety and compliance training efficiently and effectively without impact to outage work schedules can be demanding. Beginning in early 2020, and continuing through 2021, Covid-19 concerns limited personal interaction and congregation in an effort to minimize risk of transmission. With contractors arriving from all areas of the country, the site explored digital and remote avenues which had not been invested in previously.

Solution. Staff explored various electronic resources to deliver its safety orientation video, facility EH&S rules (Fig 1), and NERC CIP compliance protocols to personnel arriving onsite. Critical quality features included the following: (1) ease of use for the end user and administrator, (2) ability to edit content as needed going forward, (3) compatibility with mobile phone use, and (4) ability to electronically verify completion.

Microsoft Office 365’s Forms program was the solution selected. It has the ability to e-mail contractors/vendors a message with an optional QR code and/or forms.office.com hyperlink.

Use of a mobile device and QR code allows quick navigation and orientation, and completion of required tasks. A hyperlink also is provided for PC use. Once the user receives the e-mail and accesses the form using either the QR code or link, he or she is able to review a customizable and site-specific embedded SharePoint link to the site’s 7-min orientation video (Fig 2).

There also are several easily navigable electronic forms to review and verify completion.

Once the video has been watched and the form completed, the user initials the electronic form and submits it to the site’s EH&S manager. From there, data are compiled in a user-friendly electronic database for staff to review and to track the completion status of contractors. Electronic timing of form completion identifies potential attempts at subversion of the orientation process.

Results. The Office 365 Forms program has been tested by several employees and found effective and easy to use. Having the ability to watch the video and review and submit the electronic form from a mobile device provides contractors a user-friendly method for completing site orientation from outside the plant prior to arriving for the Newington outage.

Plus, electronic submission frees up significant paper resources and filing requirements.

Also, headcounts onsite in contractor orientation workspaces are reduced to those infrequent occurrences where electronic submission was not feasible ahead of time. When prequalified contractor personnel arrive onsite, they immediately report to the specified Point of Contact (POC) and receive their orientation-completion hardhat stickers.

The POC is able to quickly review orientation completion status in the electronic repository and directly answer any questions relevant to the training in the context of the contractor’s work scope.

In sum, investment in electronically facilitated site orientation saves resources and time and the efficiency of contractor safety- and compliance-training certification.

Project participant:

John Pierce

Upgrade to boiler-water sample panel helps ensure proper chemistry

Challenge. EPC engineers integrated a firetube boiler into the design Essential Power Newington for use during cold-plant startups to provide steam for turbine seals and HRSG sparging. The auxiliary steam system includes a deaerator supplied with cold demineralized-water makeup. Aux boiler use for HRSG sparging has increased as the plant moved from its original baseload operating profile to more of a seasonal peaking operation.

Sparging can be necessary for days at a time, or longer, depending on market dynamics and ambient temperature. Treatment chemicals are added via small electronic metering pumps. Chemical-pump stroke rates are adjusted manually based on grab-sample analysis in the water lab by an auxiliary plant operator. The original construction did not include any continuous analyzers to ensure proper control of boiler-water chemistry.

Solution. Site personnel reviewed water-chemistry key parameters for the low-pressure firetube boiler, selecting these three characteristics for continuous measurement: blowdown pH and conductivity, and feedwater dissolved oxygen. Staff then worked with a vendor to design a sample panel to measure the three variables using sampling equipment currently used onsite in the HRSG sampling system (Fig 3).

The final challenge for design of the sample panel was to find a location in the aux-boiler building where the panel would be close to the sample sources while also allowing O&M personnel proper access to other equipment. This involved minimizing the wall panel’s depth to maximize aisle space.

Results. Personnel completed installation of the sample panel during a recent plant outage. Analyzer outputs were wired to the DCS, where screen graphics were added and alarm triggers set. The analyzer outputs also were added to the PI historian for long-term trending and alerts.

While several additional continuous analyzers would be necessary to automatically control boiler chemistry, these three continuously measured characteristics help ensure proper chemistry maintenance between grab-sample analyses.

Project participants:

Kyle Malenfant, I&E technician
Michael Dill, I&E technician
Eric Pigman

Automating chemical injection key to tighter control of cooling-tower operation

Challenge. Because Newington was designed to operate baseload, it did not have an automatic scale-inhibitor injection system for the 1.5-million-gal saltwater cooling tower, which operates at 2.0 cycles of concentration and has a 150,000-gpm recirculation rate. A single salinity meter was installed on the circulating-water-pump discharge but there was no means for measuring makeup-water salinity continuously to accurately monitor for tower cycles.

The chemical treatment program for scale and dispersant control is an HEDP/polymer combination, which is injected into the tower basin. River-water makeup quality, 2.0 cycles of concentration, high surface temperatures in the condenser, and desired operating pH range were used to arrive at the optimal concentrations of treatment chemicals. A buffer is included to allow for routine fluctuations in makeup-water quality or upsets.

Given water-sample testing interferences with tower salinity, injection feed rates were based on blowdown flow rates, adjusted manually. This led to many occurrences of over- and under-injection because blowdown rates can fluctuate daily and seasonally.

Solution. Two new chemical-injection metering pumps were installed with microprocessor controls. The scale-inhibitor pump injection controls now run in automatic via a 4-20-amp control signal based on tower blowdown flow rate. In addition, a salinity meter was installed at the river makeup source to accurately monitor for tower cycles for tighter control.

These changes are conducive to a better tower chemistry program, one with both consistent scale protection and chemical control ranges. The makeup-water salinity instrument ensures consistent as-designed tower cycles, which, in effect, increases the concentration in the tower, and by automating the scale-inhibitor pumps, reduces chemical consumption. In sum, these changes reduce chemical costs and maintain a tighter tower-chemistry control program.

Results. With additional training on blowdown control rates and chemical injection operations, the control for combatting scale in the surface condenser is much tighter. Having accurate tower cycles, because of the added makeup salinity meter, allows staff to better regulate tower blowdown and injection feed rates to accurately manage the system during all operational profiles—while still offering opportunities for reductions in chemical consumption.

The scale-inhibitor automation improvement allows for less manual intervention when tower blowdown rates are fluctuating frequently based on plant operating profiles.

Project participants:

Joshua Leighton, Eric Pigman, and Scott Courtois

Warning lights for overhead doors make plant safer for staff, visitors

Challenge. Large overhead roll-up doors are a concern in industrial workplaces—a recognized hazard that could cause serious physical injury or equipment damage if not acknowledged and controlled. Reasons include these: They are heavy, may fall closed while traveling if the head works fails, and may not be equipped to auto-reverse when they come in contact with an object or person.

Solution. Staff analyzed options for improving the safety and communications protocols for traversing through the plant’s large 20 × 20-ft turbine-hall overhead doors (Fig 4), commonly used by a large number of people. Visual indicators were deployed to provide additional warning and to remind personnel and visitors about overhead-door safety and site expectations.

Industrial LED light strips were a practical solution. The power and controls for them are incorporated easily into the operation of the door opener while providing warning lights by flashing RED when the door is in motion. Once the door reaches its fully open limit switch, the light strips turn solid GREEN (Fig 5). When the door moves closed, the LED strips again flash RED until the door fully closes against the pressure limit switch; the lights shut off after 30 seconds. The warning-light system is installed on both sides of the door frame, and both inside and outside.

In addition, large floor markings were developed to remind walking personnel to use the adjacent walk-through door for exiting and entering the turbine hall rather than an overhead door.

In conjunction with installation of the light strips on the door frame and conspicuous floor markings (Fig 6), the site instituted a standing directive that the doors not be driven or walked through while in motion. They can be traversed only when in the fully open position and the lights are solid GREEN.

Results. Use of visual stimuli to let staff and contractor personnel know a door is in motion, and communicating that you must not drive/walk through an overhead door in motion, has helped to prevent equipment damage and other safety events. While nothing is fail-safe, the addition of warning lights and floor markings remind about site protocols and the need to wait for the fully open status before moving through.

Project participants:

Mike Dill, I&E technician
Kyle Malenfant, I&E technician

7F Best Practices from Central Eléctrica Pesquería (CEP)

By Team-CCJ | April 19, 2023 | 0 Comments

Central Eléctrica Pesquería (CEP)

Owned and operated by Techgen
900-MW, 7FA.05-powered 3 × 1 combined cycle located in Pesquería, Nuevo León, Méxicó
Plant manager: Mario Alberto Ontiveros de la Torre

‘Improved’ brush holder offers safety benefits

Background. CEP’s four generators are equipped with the OEM’s EX2100e excitation system to control ac voltage at the generator terminals and/or reactive volt-amperes (VAr). Plant’s excitation system has a collector on the free side of the generator, where carbon brushes transfer the excitation current to the rotating slip rings and produce an electromagnetic field in the generator.

Incident. During normal monthly preventive maintenance, the following occurred when changing a brush on the negative pole: Technician inserted the brush holder, using its insulated handle (Fig 1), unaware that the carbon brush had slid out and been pushed to the middle space between the collector rings. The resulting electric arc damaged the rings and generator rotor.

Solution. After the event, the maintenance and technical control team conducted a root cause analysis (RCA) and investigated collector-brush-system replacement options. GE’s “improved” brush holder (Fig 2) was selected for the following reasons: (1) Reduced the possibility of contact with live brushes, a significant safety benefit; (2) Provided higher reliability by eliminating incomplete insertions; and (3) Assured higher availability by reducing the risk of collector discharges.

Plus, brush wear can be seen easily through the inspection window, or by inspecting the wear indicator on the brush pigtail.


  • Separation from energized components makes for a safer system, especially when changing out brushes with the turbine/generator in operation.
  • Reduced risk of brush hang-ups.
  • Tool-less maintenance given the permanently attached handle, which also reduces the time required for brush change-out.
  • Reduced risk of collector flashovers.
  • Increased brush size/life.
  • Lightweight aluminum construction with a durable and anodized surface coating.
  • Less susceptibility to brush-current selectivity (uneven current distribution between brushes).
  • Direct replacement of single-wide holders without modification to the brush rigging.

Project participants:

Arturo González, technical control chief
Odon Acosta, maintenance chief
Arturo Macías, electrical coordinator

Copper braids outperform carbon brushes for shaft grounding

Challenge. Eliminate an unsafe condition present in the grounding-brush systems for CEP’s gas turbine/generators and implement an operating practice to enhance personnel safety and reduce the risk of equipment damage during routine maintenance.

The original grounding-brush system has a spring-type lock (Fig 3 left) that must be pulled and removed to release the brush for replacement or to perform maintenance, which sometimes must be done with the generator in operation (Fig 3 right).

These factors are conducive to an unsafe condition because of the close distance between the operator and the working generator—a noisy environment with strong air currents.

Solution. After an exhaustive analysis by technical staff, an alternative grounding system was identified—one similar to that used in the steam turbine/generator. It uses copper braids that are extracted easily by pulling the fixing lever (Fig 4 left) and removing the braid to the side (Fig 4 right).

The new grounding system reduces the time required for maintenance: It is of simpler design than its predecessor and maintenance consists only of cleaning with dielectric solvent and verifying that the braid is not too worn (or replacing it if it is).

For insertion, the braid is placed on one side and pressed with the locking lever and it is ready for operation.

Results. The increased accessibility afforded by the new grounding system allows handling the components at a safer distance than previously—further away from the rotating machinery. Plus, the maintenance interval has been extended from one month to two, making the grounding system safer and easier to maintain.

Project participants:

Odon Acosta, maintenance chief
Arturo Macías, electrical coordinator
Plus, Isaí Real, Jorge González, and Jorge Rosalio

Replacement valve actuators provide ergonomic benefits, speed maintenance

Background. CEP has a ZLD (zero liquid discharge) gray-water treatment plant incorporating softening, ultrafiltration, reverse osmosis, and electrodeionization.

Throughput extends to nearly 6200 gpm.

Challenge 1. Reduce or eliminate failures of actuators for valves serving CEP’s five ultrafiltration modules. The original actuators were of a very robust design, each weighing about 200 lb. Thus, their removal for maintenance required cranes and the intervention of specialist personnel from different areas of the plant’s O&M team (Fig 5).

Regular actuator maintenance, typically required every six months because of wear and tear experienced by positioners, instruments, and other components primarily attributed to high vibrations, took about 16 hours. Actuator location complicated maintenance because of ergonomic concerns.

Solution 1 involved replacement of the original actuators with smaller, lighter ones (about 50 lb), thereby improving maintenance access to mitigate ergonomic concerns. Remote positioners were another improvement. Maintenance on the new actuators can be performed in-situ, eliminating the need for cranes and specialist personnel.

Results 1:

  • Improved system availability.
  • Time required for maintenance cut in half.
  • Increased efficiency of maintenance personnel.
  • Reduced costs of maintenance and spare parts.
  • Less noise.
  • Fewer module ruptures attributed to vibration.
  • Ergonomic benefits included fewer accidents and fewer injuries to maintenance personnel.

Challenge 2. Increase the availability of the ZLD, which requires a heat exchanger to increase water temperature before it enters the crystallizer. This heat exchanger must be cleaned of scale deposits every two weeks using EDTA and nitric acid to maintain the level of performance required. Cleaning takes from 18 to 24 hours.

Solution 2. A second heat exchanger, independent of the original with all instrumentation required, was installed for use during cleaning turns and as a backup for the original.

Results 2. ZLD system availability and efficiency are assured.

Challenge 3. Eliminate or reduce recurring problems in the sludge-dewatering portion of the gray-water treatment plant. The two dewatered-product transfer pumps in the line to the cold-lime softening system suffered continual impeller damage and mechanical-seal wear, which caused pipes to plug and contributed to excessive maintenance.

Solution 3. The original multistage centrifugal pumps were replaced by single-stage units equipped with mechanical seals lubricated by service water to flush the seal cavity continuously, mitigating wear.

Results 3.

  • Improved system reliability and availability.
  • Eliminated corrective maintenance; only preventive maintenance is required today.
  • Reduced the cost of maintenance and spare parts.
  • No lubrication problems were associated with the seal flush system.
  • Reduced the cost of system cleaning.

Project participants:

Odon Acosta, maintenance chief
Plus, Moises Arroyo, Daniel Mendoza, Rolando Goytortua, Alma Rivera, Jonathan Herrera, Marco Lopez, Alejandro Domínguez, Juan Carlos Facio, and Luis Melgarejo

Get more power, better performance, less emissions from your gas turbine

By Team-CCJ | April 19, 2023 | 0 Comments

Planning to attend the 7F Users Group meeting at the Renaissance Atlanta Waverly, May 15-19? Registered? If not, sign up now and book your room.

That done, flag 11 a.m. Tuesday (May 16) in your electronic planner/reminder, when four platinum sponsors will begin their one-hour presentations on topics of importance to owner/operators.

If your work-related responsibilities focus on getting more from your gas turbines—more power, more operational flexibility, more time between overhauls, etc—consider attending the PSM session, “7F combustion and full engine solutions for a variety of energy-market applications.”

Greg Vogel, senior engineering manager for technology programs, and Bryan Kalb, combustion engineering manager, will cover two main topics:

If you have attended a gas-turbine meeting or read CCJ in the recent past, you probably have heard about FlameSheet™ and might think you can skip the PSM presentation. Not true. This preso is not a rehash of marketing materials. Rather, it focuses on the operational and fuel flexibility experiences achieved globally, up to the minute, by the innovative radially staged “combustor-within-a-combustor” (Sidebar) now installed or under contract in 27 units (mostly 7F), also including 501F, 7EA, and Fr5/1PA.

Design updates that further enhance the operational window of FlameSheet™ will be presented in detail, along with a road map covering the near- and long-term outlook of the 7F engine.

How FlameSheet™ works

PSM’s novel FlameSheet™ combustor relies on a simple, two-stage radially inflow “combustor-within-a-combustor” design concept that enables staged operation of each at various load conditions. Leveraging trapped vortex stabilization aerodynamics, the outer combustor operates with excellent stability, designers say.

This allows an increased operational zone, because the combustor can operate at much lower loads while maintaining stability and low CO, which generally restrict operation at low loads.

FlameSheet™ also is designed to handle a variety of fuels and fuel blends while keeping NOx and CO emissions low, without need for diluents or an SCR. This flexibility enables the combustor to satisfy industry needs with respect to the rapid onboarding of renewables as well as achieving decarbonization goals by mixing hydrogen with traditional fuels.

Fuel flexibility. Here are some of the highlights regarding fuel flexibility that will be covered:

  • Current experience burning hydrogen blends and details of two major projects happening this spring.
  • Details of E- and F-class combustion retrofit projects operating on hydrogen blends with PSM technology since 2018.
  • Operational update on the first tri-fuel FlameSheet (natural gas, hydrogen-rich refinery off-gas, and back-up liquid fuel).
  • Adaptation and installation of our FlameSheet™ platform to the Frame 7EA, including co-firing with hydrogen.

The operational flexibility portion of the presentation looks at the challenges posed by onboarding of renewables and shut down of traditional base load coal-fired assets. The speakers will explain how PSM can achieve turndown limits, within emissions compliance, under 30% in a 7F gas turbine with its latest generation of FlameSheet™ combustors.

Addition of the company’s GTOP package to FlameSheet™, 7F top-end performance can increase while remaining at low emissions limits for optimal peak performance. Actual installations and results will be presented.

Optimize operations with GTOP

By Team-CCJ | April 19, 2023 | 0 Comments

PSM’s 7F upgrade packages, which provide users the flexibility to optimize performance and maintenance schedules to their individual requirements, are covered in the second part of the session presented by Greg Vogel, senior engineering manager for technology programs, and Bryan Kalb, combustion engineering manager. Part one, outlined here, focuses on the company’s increasingly popular FlameSheet™ combustion system.

GTOP (Gas Turbine Optimization Package) supports three modes of operation—maintenance performance, and peak—and allows users to toggle among the three for optimal performance, depending on operational and business needs. Targeted hot-gas-path and compressor-part upgrades ensure a cost-efficient, reliable upgrade compatible with existing OEM 7F hardware. Remember, too, GTOP is compatible with multiple combustion systems—including FlameSheet™—to maximize the performance improvement.

Recall that GTOP 3.1 and 4.1 upgrades incorporate aerodynamically redesigned compressor parts—R0, S0, and S1—for increased compressor inlet flow and enhanced mechanical integrity. Recent installations and results will be reviewed by the speakers. Plus, the latest GTOP upgrades compatible with both 7F.03 and 7F.04 machines will be described.

New technology will be introduced as part of PSM’s GTOP4 program, which leverages the company’s experience gained in expanding its performance offerings to the 501F engine, promotes more cooling in the first stages of the turbine section. This suggests maintenance and life cycle costs with the PSM improvement may be more favorable compared to those experienced by users with the OEM’s AGP design.

PSM reminds readers of the typical performance improvements (below) recorded by installation of GTOP 3/3.1 on standard 7F.03 engines:

Simple-cycle power

  • Maintenance mode (32k), up to 6%
  • Performance mode (24k), up to 8.8%
  • Peak mode, up to 11.7%

Performance improvements possible with GTOP 4/4.1 will be presented at the 7F Users Group meeting—another reason to attend.

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