Mechanical Dynamics & Analysis (MD&A) recently completed the major inspection and refurbishment of a 1 × 1 combined cycle at the Hermiston Generating Plant that successfully returned the facility’s turbines and generators to full and reliable operation.
The project began with the full major inspection of a late-1990s-vintage, 170-MW 7FA gas turbine—including the robotic inspection of its 7FH2 generator. The A10 steam turbine and its 7A6 generator also were fully inspected and refurbished by MD&A in the same outage.
The plant
Perennial Power’s 474-MW, two-unit Hermiston Generating Plant in northeastern Oregon (Fig 1) provides power to nearly 500,000 households in the Pacific Northwest. It also sends steam to Lamb-Weston’s adjacent potato processing facility.
Both Hermiston units feature identical gas turbine/generators and steam turbine/generators, all commissioned in 1996. The plant has been recognized by the Oregon Occupational Safety and Health Division in the past for its exceptional health and safety record and to date has never experienced a lost-time injury.
The outage
Safety, planning, communication, and coordination were instrumental in the successful Unit 2 outage in fall 2022.
Plant Manager Chad Daniel takes us back to the outage and offers an insightful and educational look at what made it run smoothly.
“I can’t over-stress the importance of pre-outage planning and open communication among the plant, the various technical points of contact, and all contractors,” he explains. “We had 20 contractors on site, MD&A being the largest, plus additional subcontractors.”
Daniel explains that pre-job planning and walkdowns are absolutely critical.
“There are things that come up during walkdowns (crane activities, for example) that may need to be altered, sequences shifted, and you are always looking for safety items. All of these are critical to a successful outage.”
He continues: “With nearly two-dozen contractors onsite and within limited space (Fig 2), communicating and coordinating contractor milestone schedules and needs become crucial (competing for space, LOTO timing, equipment testing, safety concerns, etc).
“Our plant has found that by having multiple internal pre-outage meetings combined with specific responsibilities and work-order and contractor assignments, you make sure that no single person is overloaded. At Hermiston everyone shares those responsibilities, both salaried and non-salaried. Our internal meetings and reporting start several months before the outage. Meetings with contractors are also held onsite or virtually as often as needed.”
“It starts with the plant,” states Daniel. “I feel it is the site’s responsibility to build the dialogue, the trust, and the open communication to bring up any and all questions and make it a streamlined and safety-conscious outage.
“The result,” as he explains, “is that once you get rolling into the outage, you have the relationships, you know who you need to talk to, you have people that you are comfortable with
and have faith in so you can walk through the issues, get them resolved quickly, and keep everyone involved and moving ahead.”
Daniel also addressed weather-related scheduling, offering an important caution for outage planning. Although his part of Oregon does not routinely experience extreme weather, the climate can still be unpredictable, especially in the fall and spring. So, you need to consider temperature swings, and high winds than can impact crane operations.
“When you are planning your outage, whether it’s based on the owner’s needs or the hours on your machine, certainly leave a few extra days for contingency, if possible, particularly for a major inspection where you are going to be down for a substantial amount of time, are performing non-routine work, or work that poses increased risk of delays. You have to be mindful of the end timing of the outage and keep weather conditions in mind for startup. You don’t want to be starting the HRSG, for example, in freezing conditions,” he notes.
7FA gas turbine
MD&A mobilized and completed the disassembly process utilizing a two-shift operation (Fig 3). Detailed visual inspections began, coupled with detailed NDE, followed by the recommended refurbishments.
In the turbine section, first-, second- and third-stage buckets were replaced (Fig 4) due to rubbing wear and loss of the thermal barrier coating (TBC).
First-, second- and third-stage nozzles also were replaced because of foreign object damage, evidence of cracking, and coating loss. Inspections and similar indications revealed the need to also replace the shrouds.
In the combustion section, liners and transition pieces were replaced with refurbished sets due to TBC loss. New inner crossfire tubes and retainers were installed because of wear and outer crossfire tube packing was replaced at reinstallation.
Although no abnormal visible wear was found, forward combustion cans and fuel nozzles were replaced with customer-provided refurbished sets. Flow sleeves also showed no wear, but the flow-sleeve piston rings were replaced.
Liner caps were replaced with refurbished ones, and transition-piece bullhorn brackets were found worn and replaced with new.
For the compressor-section inlet guide vanes (IGVs), MD&A replaced gears, rack, inner and outer bushings, and spacers. IGV blades themselves will need to be replaced at the next major inspection.
Rotating and stationary blades showed no damage. R-0 inlet compressor blades were replaced with a refurbished set and shims were added to stages 14, 15, and 16. The casing and rotor showed no need for immediate action, but the discharge casing retention bars were replaced.
The inactive thrust bearing showed heavy scoring and the T-1 and T-2 bearings revealed pitting and scoring, which were subsequently replaced with refurbished bearings. The active thrust bearing was cleared for service.
7FH2 generator
For the generator, the initial scope of work was visual inspection, robotic wedge-map analysis, electromagnetic core imperfection detection (ELCID), and a full battery of electrical tests.
The borescope inspection showed substantial widespread greasing and several areas that had loose hardware. Field removal was recommended for a more comprehensive stator investigation. Following that, a core wedge map was performed that showed approximately 90% of the wedge system was loose and/or hollow, not meeting MD&A criteria. A full stator re-wedge, replacement of greasing blocking/ties, and axial support tightening was recommended and performed.
MD&A also provided and installed an improved wedge design.
Prior to re-wedging, a significant amount of time was expended cleaning the core. All slots were cleaned, including dovetails.
New filler material and top ripple springs were installed during the re-wedge. A modification was made to the end wedges to improve mechanical strength. The original flux probe was installed without issue, and a final ELCID was performed with acceptable values.
Based on modal bump testing, MD&A recommended that the entire collector and turbine ends have series blocking installed to reduce resonant frequency response. Saturated felt and ties were added to dampen the response.
New axial support hardware was installed, replacing the loose axial supports and hardware found during initial inspections. Locking epoxy was applied on all hardware to ensure no complications during operation.
Hydrogen seals were replaced with new, and field collector rings were ground.
Successful electrical testing was performed at the completion of all work performed.
A-10 steam turbine
MD&A performed a major inspection and overhaul of the 81-MW A10 steam turbine (Fig 5) and its generator stator and field—all installed in 1996. The main steam valves also were removed by MD&A and sent to the company’s St. Louis facility for inspection and repairs (Fig 6).
MD&A specialists performed a complete steam-path structural audit of the A10 machine. Although many minor diaphragm indications could have been repaired by MD&A onsite, ILP diaphragms 9, 10, 11, and 13 were shipped to MD&A’s facility for major repairs. Stages 10 and 11 also had inserts installed on the steam-seal face because of dishing.
HP and ILP rotors remained coupled and were removed for sandblasting and NDE. Minor bucket repairs were performed onsite to correct impact damage and moderate solid particle erosion.
On reassembly, MD&A performed a Topless Laser Alignment® and its On-Site Seal Services fit and installed new diaphragm and gland-steam packing.
7A6 Generator
The 7A6 air-cooled generator was disassembled and its field removed and shipped to MD&A’s St. Louis facility for a full rewind (Fig 7). In addition, the company’s Generator Div mobilized onsite to perform a full stator rewind.
The combined HP stop and control valve was disassembled and the cores shipped to St. Louis for inspection and repair. The Steam Turbine Repairs Div also received two reheat stop valves and two intercept-valve cores for inspection and repair.
Stator. Concurrent with the steam-turbine major inspection, an elevated workspace was constructed onsite to support the generator division in stator disassembly and reassembly work. A baseline ELCID was performed to determine integrity of the current stator core iron. No shorted laminations were noted.
The wedge system was removed, then the flex probe was carefully set aside for reassembly.
With wedges and series loop connections removed, bar removal began. Inner axial supports were left in place and prepared for the reassembly. Connection pieces were cleaned for reuse.
The stator was thoroughly cleaned to remove any contaminants from the wedge/bar removal process. A post wedge/bar removal ELCID indicated no core-iron damage during wedge and bar removal.
Each core slot was cleaned, and a detailed inspection of any abnormalities was conducted. The core compression flange and all exposed areas where the endwindings sit were painted with an epoxy paint for a uniform color on the compression flange.
After thorough cleaning, the rewind began (Fig 8).
Bar boxes were moved to the scaffolding deck with an innovative safety-conscious method of disassembling the scaffolding roof and flying the boxes to the deck with a crane following completion of a detailed lift plan.
Each of the six circuit rings were acceptance-tested, and the outside binding bands installed.
A tapered gauge from the bar manufacturer was used to ensure concentricity was achieved on the four binding bands. Concentricity of each band is a vital step that will properly align each bar and subsequentially the endwinding basket once the rewind is completed.
Two top and two bottom bars were installed to ensure alignment. Bars were fit into a shoe on the collector end and carefully transferred through the bore to the turbine end. All 72 bottom bars were installed, blocked and tied. All 72 top bars were then installed, blocked and tied, along with 12 new resistance temperature detectors (RTDs).
After all bottom bars were installed, a Hipot test was performed to ensure there was no bar armor insulation damage. Another Hipot was performed on all top and bottom bars at the completion of top-bar installation.
Wedges were then installed, and filler was adjusted at each wedge for proper radial compressive force. Axial locking pins were installed, followed by a final ELCID and brazing. The existing circuit-ring copper connection pieces were re-used and brazed to respective top- and bottom-phase connections.
Upon completion of all rewind activities, final electrical testing consisted of winding copper resistance, insulation resistance, and a final Hipot of each respective phase. Each phase produced satisfactory resistance values.
The stator rewind activities progressed as expected throughout this project. The consistent bar shapes and robust bar design aided in completing the project without incident.
Field. The 7A6 generator field was sent to MD&A in St. Louis for testing, disassembly, coil removal and cleaning, further testing, reassembly, and high-speed balance (Fig 9).
During initial electrical testing of the heavily dished collector rings, collector studs, and bore copper, the collector studs failed high-potential testing. This resulted in the replacement of the collector rings which included removing the old collector rings, manufacture of new collector rings, new collector-ring insulation, and reinsulating of the collector studs.
Coils were removed and sent offsite for cleaning. They were then returned and checked by MD&A. After reinstallation, each coil received ac Hipot and turn-to-turn testing.
Also, during the rewind process, the blocking was upgraded to the MD&A standard block and tie design. Turn insulation was coated, requiring a rotor bake cycle.
Electrical testing, high-speed balance, acceptance testing, and shipping followed.
MD&A also provided startup and balance support of the unit, along with full recommendations on what to look for or replace at the next outage. Daniel offered the following: “MD&A has become one of our most trusted, dependable and transparent contractors to work with.”
Balance of plant
Throughout the outage, balance-of-plant work was conducted using both Hermiston plant personnel and a wide variety of contractors.
Major items beyond the base MD&A scope included the following:
- Vogt 3-drum HRSG-related items:
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- Boiler feedwater pump replaced.
- Insulation repaired and replaced on numerous HRSG piping systems.
- NDE inspections on HRSG and feedwater piping.
- SCR dilution-air fan motor replaced.
- Stack-damper linkage repairs.
- HRSG blowdown-tank modification; check valve added to quench-water line.
- Rebuilding of HP and reheat attemperator, IP feedwater, HP feedwater and other valves.
- Completion of state-required internal boiler inspections.
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- Other items included these:
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- More than 200 corrective, demand-task, and PM work orders completed by plant personnel.
- Instrument transmitters and switches calibrated for numerous plant systems.
- Diesel fire pump rebuilt.
- Cooling tower: tower basin silt removal and cleaning, routine inspections, fill-material sample cell weights obtained, minor structural repairs, replaced all circ-water-system 6-in. lateral piping grommets in all four tower cells, circ-water pipe header expansion joints replaced.
- MCCs, SF6 breakers, 52G, and 4160-V contactors tested/inspected/cleaned.
- CO2 and deluge fire systems inspected/tested.
- Lube-oil plate-and-frame heater exchangers for the steam and gas turbines disassembled, plates cleaned, gaskets replaced, and reassembled.
- Steam-turbine pedestal restoration; epoxy repairs.
- Gas- and steam-turbine Mark-V control system health-check inspections completed.
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Outage results
Overall performance of the gas turbine improved as a result of the outage. Corrected output increased by 4701 kW (3.1%) and corrected heat rate decreased by 185 Btu/kWh (-1.9%).
Forecasting
A forecasting note extracted from discussions with plant personnel: “One critical item that helps us prevent negative surprises at Hermiston actually starts years before the outage.” Daniel explains: “We review post-outage equipment and engineering reports as soon as possible after the outage, while the information is fresh. There are always recommendations for future outages in these reports.
“Also, there can be non-critical jobs that can’t be completed during the outage, and they can get overlooked as we go back to post-outage duties. So, we try to issue work orders for these items right away so they can be tracked and remain visible.
“We’ve found that by practicing this, our maintenance budget forecasts are more accurate, and we have fewer surprises during future outages.”
Final notes
Hermiston has received several awards over the years from CCJ for both safe operations and best practices. Examples include self-performing combustion inspections, hydrogen-purge remote activation, and others searchable at https://www.ccj-online.com/
Editors’ discussions with Daniel on this outage noted the overall safety theme. “Best-practice safety adjustments” and “safety communication among all personnel” were repeated and emphasized, as was an attitude of trust and respect for all organizations and personnel involved.
“Every individual onsite, whether a plant employee or contractor, regardless of pay grade or title, has Stop Work authority,” he states.
Essential Power Newington
Owned by Essential Power Investments
Operated by Cogentrix Energy Power Management565 MW, 2 × 1 7F-powered combined cycle equipped with a GE D11 steam turbine, located in Newington, NH
Plant manager: Tom Fallon
Flags make HV grounds visible to ensure proper installation
Challenge. During maintenance outages when conducting high-voltage (HV) activities, personnel work diligently to be sure grounds always are under “control.” Site philosophy is that grounds are the last items on the LOTO and the first off it when restoration activities are conducted. A site-qualified electrical employee always will sign onto a LOTO that contains grounds so he or she can witness attachment/removal. The biggest challenge is making sure grounds are visible during installation to be sure there are no questions about what equipment is properly grounded.
Solution. Staff analyzed options for improving safety as well as visibility to the ground cables when they are installed on the 345-kV transmission lines during transformer testing or generator work (Fig 1). They found a supplier of all-weather, high-visibility reflective ground flags that can be hook- and loop-fastened to the ground clamp, or have a grommet-reinforced hole for zip-tying the connection to the clamp or cable.
Drawing attention to these HV ground connections adds a layer of protection to the LOTO process to ensure the grounds are properly removed before restoring the system. The flags also make it easier for contractors to know which piece of HV equipment they should be working on, given that all transformers look the same. This is a quick visual indicator to confirm you’re at the correct location without checking markings on the units.
Results. Using visual stimuli to let electrical testing contractors, equipment operators, or other personnel in the area know that the equipment is under grounds control, helps to eliminate errors. Plant’s electrical testing contractor said it hadn’t seen anything like this at any of the other plants they have performed testing services for in New England. Staff submitted this as an internal best practice within Cogentrix so the entire fleet is aware of the product and its ease of use, as well as its enhancement of awareness.
Project participants:
Chad Harrison, maintenance manager
Mike Dill, I&E technician
Enhanced thermal monitoring helps protect critical equipment
Challenge. Extreme cold weather is no stranger to Newington and the New England area. For a cycling facility, Newington was designed and constructed with less-than-adequate measures for cold-weather mitigation. Over the years, the facility has been improved in this regard with additional buildings, HVAC equipment, and heat-trace and insulation—with proven success during extreme cold weather.
It was important for plant personnel to learn from recent regional cold-weather events—such as the Polar Vortex of 2013/2014, Bomb Cyclone of 2015/2016, and Winter Storm Elliott during Christmas 2022—to better prepare for future storms. For example, having the ability to monitor remote locations and equipment from the control room was a necessity.
Use of remote temperature monitoring devices would be a beneficial freeze-protection addition and would complement the site’s cold-weather plan in a pronounced way. This was particularly important given NERC’s plan (at the time) to revise standard EOP-11, “Emergency Preparedness and Operations” and mandate that generation owners implement a cold-weather preparedness plan.
Solution. When sharing internal best practices with another asset in the Cogentrix portfolio, Newington personnel investigated a remote temperature monitoring solution called Monnit®. After developing an implementation plan, Monnit sensors were ordered and installed.
The sensors have the ability to check-in at any periodicity the user desires and can proactively alert others via email and text of cold/hot areas of concern. Data captured by each sensor can be trended, an important capability. With the iMonnit software and affordable licensing, users can monitor the entire network of sensors from one location—such as the control room. There also is a cell-phone app that can be downloaded and monitored as needed.
Newington purchased several lithium-battery-powered industrial-grade remote temperature sensors for temperature-critical areas (Fig 2), such as the following:
- Fire sprinkler/deluge buildings.
- HRSG internal sections.
- Critical instrumentation boxes.
- Feedwater piping susceptible to freeze-up during offline periods.
- Auxiliary equipment outbuildings.
Results. With the installation thus far of 38 sensors facility-wide, Newington has the ability to monitor and be alerted on critical areas of concern during extreme cold and hot weather events. Reports can be generated from the software and rules established to automate device concerns, battery levels, or area temperature cold and/or hot thresholds.
These devices were an added feature in the facility’s new NERC cold-weather awareness plant in support of EOP-011-2, which became effective Apr 1, 2023.
Project participants:
Joshua Leighton, operations manager
Eric Pigman, engineering manager
Cogentrix’s Hamilton Liberty staff
Cogentrix’s Hamilton Patriot staff
Fuel filter enhancements facilitate O&M, improve safety
Challenge. Essential Power Newington was designed to operate primarily on natural gas, with the ability to transfer to ultra-low-sulfur diesel (ULSD) as necessary. Historically, ULSD has been burned in winter when natural-gas demand and oil prices are at their peaks.
Duplex fuel filters were provided to remove particulates from the distillate fuel. A pressure gage and alarm switch monitor the differential pressure across the strainer to indicate when filter replacement is required. The filters are located in an off-package liquid fuel/atomizing air module with limited and challenging access for routine O&M. Filter-housing changeover, pressure-equalizing, and drain valves were extremely difficult to access and operate safely.
Filter replacement often was required when the unit was operating—when reliability is paramount. Operation of the various filter valves required kneeling down on a small grating platform underneath control-oil tubing with limited leverage for filter changeover and media removal. The filter was located a few feet below the grating and difficult to reach (Fig 3, left).
Solution. A site team walked down the two gas turbines and agreed on an appropriate in-house design to support filter O&M in a safe, effective manner. Valve extension handles were constructed by site maintenance employees for all drains and equalizing and filter changeover valves. The control-oil tubing for the liquid-fuel stop and bypass valves in each of the GT compartments was rerouted to improve filter access.
Results. With extension handles installed on filter drain, equalizing, and changeover valves for both units, access improved tremendously, allowing safe and effective O&M evolutions (Fig 3, right). The system was installed in fall 2022, and operated throughout the winter of 2022/2023 when liquid fuel was burned, with positive results. Avoiding a safety incident or damage to equipment by poor leverage and ergonomics was the key to this completely in-house design and improvement.
Project participants:
Scott Roy, lead plant operator
Ted Karabinas, maintenance technician
Tom Jamison, maintenance technician
St. Charles Energy Center
Owned by CPV Maryland LLC
Operated by Consolidated Asset Management Services745 MW, 2 × 1 7F.05-powered combined cycle equipped with a GE D11A steam turbine, located in Waldorf, Md
Plant manager: Nick Bohl
RO clean-in-place wastewater discharge mod reduces manhours, cost
Background. St. Charles Energy Center uses two double-pass reverse-osmosis (RO) systems with electrodeionization (EDI) skids to produce demineralized water for the plant’s heat-recovery steam generators. The RO system contains a clean-in-place (CIP) feature for removing accumulated impurities to restore performance and efficiency.
The as-built plant design used a trough located in the water-treatment building to route the CIP wastewater to the plant wastewater collection sump (WCS), which discharges the CIP wastewater back to the local water treatment facility (WTF) for processing and reuse.
St. Charles’s wastewater discharge permit specifies that the pH for this water must be greater than 5 and less than 10 when discharging back to the local WTF. During a CIP, wastewater pH can range from less than 4 to more than 11. Sending water with a pH in this range to the WCS during a CIP increases the chance of permit non-compliance.
Challenge. To prevent a permit violation attributed to low or high pH, the plant would increase cooling-tower blowdown to the WCS to dilute the sump water, or use chemicals—such as sodium hydroxide or hydrochloric acid—to neutralize the wastewater in the CIP tank before discharging it to the WCS.
Both methods were inefficient, costly, and introduced a great risk of human error. Blowing down the cooling tower to dilute the sump contents uses water in the tower that must be made up to maintain proper operational level, while at the same time increasing wastewater costs because of the increase in discharge to the WTF. Plus, there is a safety risk associated with the storage and handling of sodium hydroxide and/or hydrochloric acid to neutralize sump contents.
Solution. The plant addressed these issues by hard-piping the CIP tank discharge line to the filtrate sump, thereby allowing its contents to be pumped out directly into the cooling-tower basin instead of the WCS. The new hard pipe was placed in the original discharge trough to prevent trip hazards (Fig 1). The team also manufactured a section of CPVC with a union so the piping can be assembled and disassembled easily and efficiently to discharge to the filtrate sump (Fig 2).
Results. The discharge mod has reduced the total time it takes to perform a CIP by two hours and has saved up to $700 per CIP. This gives the site greater control over the pH level in the WCS, thereby mitigating the risk of non-compliance with the site environmental permit by not discharging directly to the WCS. Additionally, this mod improves employee safety by eliminating exposure to chemicals for neutralizing pH.
Project participant:
Shawn Burnette
Benefit of using Python to calculate plant performance
Background. Annually, PJM Interconnection requires all plants in its territory to perform an installed-capacity test (iCAP). It is equivalent to the claimed installed capacity in PJM eGADS, and the capability of the generating unit at the expected time of the PJM summer peak. This also is referred to as the “rated capability” or “rated iCAP” which is determined by adjusting plant capability for site conditions coincident with the dates and times of summer peaks over the previous 15 years.
Challenge. The plant had been using an Excel spreadsheet that relied on macros to calculate correction curves for the given ambient conditions of temperature, barometric pressure, and relative humidity, and the 15-yr summer condition averages for those variables.
Correction curves provided by the OEM only included certain ambient conditions, and they required mathematical interpolation to obtain the proper correction factor. To illustrate, Fig 3 gives curves for ambient relative humidity with the evaporator cooler in service and ambient temperatures of 59F, 75F, 94F, and 100F.
After the iCAP testing was complete and all PI data were input to the Excel spreadsheet, site and other performance engineers would question the validity of the Excel result. The discussion related to the “correct” number to use would go back and forth for multiple weeks for each test. This resulted in numerous manhours being used for debating whether the Excel output was correct or incorrect.
Editor’s note: The complex equations used to create the curves in Fig 3 were submitted with this entry, but believed to be of marginal value to most readers and not included here. Please contact Jacob Boyd, plant engineer, if you are interested in digging deeper.
Solution. The best way to facilitate the process was to develop a written code within the computer programming language Python, an interpreted, object-oriented, high-level language with dynamic semantics. In short, it’s a powerful tool to develop a proper calculator for all the curves used in calculating the iCAP net generated output. The program includes approximately 300 lines of code—including equations for interpolation.
A sample of this code was provided with the entry but not included here given its very limited value to the large majority of readers.
The benefit of using Python for calculation of the iCAP is that it takes the human error out of calculating the iCAP value within the Excel spreadsheet, which required annual updating depending on how ambient conditions differed along with the PJM summer peaks. With Python, the only thing the site team must do is insert the numbers for temperature, barometric pressure, and humidity, and the 15-yr averages for each, into the program and press “run.”
After all the required date are input, Python returns the proper correction factors used, plus the corrected net output of each unit to be submitted as the iCAP number.
Results. Since the implementation of Python and validation of the code via hand calculation, the man-hours of involvement required of management—including plant engineer, operations manager, and plant manager—to develop the iCAP number for input to the PJM portal have been reduced dramatically. In addition, the new methodology is so user friendly operators can use this tool during the iCAP test to ensure the plant is on track for hitting the target corrected net output.
Project participant:
Jacob Boyd, EIT, plant engineer
Hunterstown Generating Station
Owned by Platinum Equity LLC
Asset management by Competitive Power Ventures
Operated by NAES Corp810 MW, 3 × 1 7F.04-powered combined cycle equipped with a GE D11 steam turbine, located in Gettysburg, Pa
Plant manager: Tom Hart (former), Mark Kadon (current)
Challenge. Hunterstown’s obsolete robot made racking-out breakers more hazardous than need be. The device was a headache, thereby causing a hazard for employees. This could have led to corners being cut.
Solution. NAES requires remote rack-out when incident ratings exceed 40 calories/cmᶟ. Many times, the old robot would indicate the device was fully racked-out but, in fact, it was in mid-travel when the operator approached. Staff selected CBS ArcSafe to provide new remote raking robots for the plant.
Results. The new robots allow employees to safely rack out any device onsite while being well outside the arc-flash boundary. Staff also purchased a magnetic camera that allows the operator to see remotely what position the breaker is in before approaching (photos).
The robots have a clutch that will disengage before over-torquing the breaker. This mitigates many of the problems experienced previously, and operators no longer have to manually break the device free before using the remote racking device. The 4160-V devices are completely wireless, the only thing that needs to be plugged in is the battery pack.
The operator takes the remote and the camera screen outside of the building and does the racking completely out of the line of fire and well outside of the arc-flash boundary. The 480-V devices do have a wire but the operators are still able to go outside of the building and outside of the arc flash boundary. The process has become exponentially safer for all plant personnel.
Project participant:
John Marino, operations manager
38 CC Norte III
Owned by Abeinsa
Operated by NAES México
907 MW, 2 × 1 7F.04-powered combined cycle equipped with a Toshiba steam turbine, located in Chihuahua, Mexico
Plant manager: Armando Burgueño
Challenge. 38 CC Norte III is located in a region of Mexico with one of the country’s most extreme climates—very hot summers and extremely cold winters. Temperatures as low as -19C have been recorded. High wind speeds are another characteristic of the area.
High winds and low temperatures in wintertime were wreaking havoc with instrumentation—especially level, pressure, and flow transmitters, which were arranged in two of three logic. Out-of-range or lost data, typically attributed to freeze-up of sensing lines, often caused turbine/generators to trip. The result: High EFOF (equivalent forced outage factor) and financial losses.
Solution. In 2021, a year after the plant began commercial operation, diesel-oil-fired hot-air generators were installed to reduce the impact of low temperatures on critical instrumentation (Fig 1). However, this solution was far from ideal. One reason: O&M technicians had to supply diesel to the hot-air generators every couple of hours to keep them in service.
Encapsulating in thermal boxes all transmitters working with water/steam column lines was the solution, along with thermal insulation of exposed lines (Figs 2 and 3).
Results. The table tracks historical EAF (equivalent availability factor), reliability and EFOF data and shows the dramatic improvement gained by migrating from the hot-air generators to the insulated lines and cabinets. The migration was completed early in 2023 and highly successful, as evidenced by comparing the data for January and February 2023.
Another plus was the safety, environmental, and cost benefit of eliminating the diesel-fired hot-air generators.
Project participants:
Armando Burgueño Santacruz, Rafael Sarabia Rodríguez, Javier Ramírez Gutierrez, Francisco Javier Soqui Siqueiros, Juan Jose Carlos Contreras, María Guadalupe Valdez Zabalza, Eleazar Velderrain Alcaraz, and Flavio Cesar Virgen Rey
The world’s largest user organization supporting owner/operators of 7F gas turbines promises a robust in-person event when the group gathers at the Marriott St. Louis Grand, May 20-24, for its 2024 conference and vendor fair.
This year’s program begins with a seven-stop tour of MD&A’s turbine/generator repair facility (users only) on Monday morning (May 20), followed by lunch and an afternoon-long session of practical technical presentations by MD&A’s leading engineers.
Tuesday (May 21) is dedicated to vendor presentations selected by the steering committee. The program is arranged in five 30-min sessions with four services providers presenting simultaneously in each session. Highlights of the topics covered by the vendors can be found here.
The classroom programs on Monday and Tuesday conclude by 4 p.m. so attendees can participate in the vendor fair, which runs until 7. Seventy-five companies (over 130 in total) will be on hand each day to help you navigate their products and services offerings, but only a few will be available both days. Review the exhibitor list here to be sure you don’t miss someone of interest. No need to rush through the aisles: Heavy hors d’oeuvres and open bar won’t allow you to go hungry.
Wednesday is dedicated to user-only sessions with presentations and discussion focusing primarily on safety, combustion, auxiliaries, rotors, exhaust systems and components, and controls. See technical program at a glance to get an idea of the nitty-gritty discussions you’ll be having with fellow users.
Thursday is GE Day. A slew of information coming your way in general session and then in various deep-dive breakout session throughout the day. See those topics here.
The Friday morning session, which was greatly improved by the steering committee last year, includes both the OEM’s traditional deep-dive knowledge-sharing program and two special user-only sessions—one on how to prepare for borescope inspections, the other on coupling alignment. A feature of GE’s Friday program is a one-hour session on effective technical communications and how to maximize the value of the OEM’s customer portal.
This all would not be possible without the tireless efforts of this 7FUG Steering Committee noted below, who, for over three decades, have set the highest standard for technical content and robust problem-solving discussion. They are happy to announce the offering of PDH credits starting at this year’s conference at no added cost. These will help fulfill engineering licensure and company training requirements you may have.
2024 Steering Committee
Chairman: Dave Such, Xcel Energy (2006-2019; 2022)
Vice Chairman: Zach Wood, Duke Energy (2020)
Luis Barrera, Calpine (2014)
Sam Graham, Tenaska (2007-2018; 2022)
Edwin Rivera Hernandez, Dominion Energy (2023)
Clinton Lafferty, TVA (2020)
Doug Leonard, ExxonMobil (2020)
Justin McDonald, Southern Company Generation (2013)
Dan McQuade, Vistra Corp (2023)
Brian Richardson, FPL (2022)
John Rogers, SRP (2019)
Editor’s note: Presenter names, times, and meeting rooms are as of April 23 and subject to change.
Monday, May 20
8 a.m. – noon, Tour of MD&A’s turbine/generator repair facility
1:30 – 4 p.m., MD&A session
Presentations:
- 7F outage planning and solving issues—including best practices, inspection requirements, parts management, and risk mitigation. Richard Rucigay
- Rotor life assessment with 1-2 spacer cracking evaluation—including use of a finite-element model to identify likely crack-initiation sites. An improved spacer design is offered. Mark Passino
- Gas-turbine parts update with wheels availability for rotor life extension. David Fernandes
- 7F component life extension with 7F.04 repair development—covers the typical limiting factors of 7F engine components and how they can be repaired. Case studies are included. José Quiñones PE
- Step-iron liberation from a 7FH2 generator (case history)—including details of the inspection process and repair method. James Joyce
- Controls strategies for life extension.
4 – 7 p.m., VENDOR FAIR
Tuesday, May 21
8:45 a.m., Vendor solutions 1
- TFH2 generator “minor” outages: What can you see? What can you do? AGT Services, Jamie Clark
- Fuel nozzle repair and innovation, Allied Power Group, Jeremy Clifton
- 7F flex seal expansion-joint solutions, Dekomte de Temple, Jake Waterhouse
- Engine-ready advanced TBC for IGTs, Liburdi Turbine Services, Josh Smeltzer
9:30 a.m., Vendor solutions 2
- How to run inlets during extreme events, Donaldson, Bob Reinhardt
- Achieve overhaul-to-overhaul reliability with the right advanced oil analysis, ExxonMobil, Jim Hannon
- Enhancing outage efficiency and reliability through owner engineering expertise, Gulf Turbine Services, Joe Mitchell
- GT rotor-lifting risk associated with cyclic and load-swinging operation, Structural Integrity Associates, Matthew Ferslew
10:15 a.m., Vendor solutions 3
- Rotor life extension: Understanding new benefits and design, EthosEnergy Group, Jeff Schleis
- Understanding the impact of BOP equipment on liquid-fuel-system reliability, JASC, Schuyler McElrath
- Generator stator endwinding vibration operating deflection shape confirms global resonance, Qualitrol—Iris Power, Aaron Doyle
- Interpreting borescope reports: 7F gas turbines, Turbine Generator Advisers, Jason Neville
11:00 a.m., Vendor solutions 4
- Generator monitoring, Environment One Corp, Christopher Breslin
- GTOP4 and FlameSheet™: An alternative to advanced OEM solutions, PSM, Kevin Powell and Katie Koch
- Developing a tactical plan for turbine lubrication lifecycle management to mitigate varnish formation, Shell Oil Products, Chris Knapp
- Navigating F-class rotor end-of-life, Turbine Generator Advisers, David Bitz
11:45 a.m., Vendor solutions 5
- Performance evaluation and instrument calibration, ap4, John Downing
- Effects of GT operational changes on HRSG pressure components (case studies), HRST Inc, Souren Chakirov PE
- R3 modification and upgrade options for the exhaust frame and aft diffuser, Integrity Power Solutions LLC, David Clarida and David Yager
- Everything 7F rotor: Upgrades, life extensions, and supply chain, PSM, Brian Loucks
1:15 – 4 p.m., General sessions (users only)
4 – 7 p.m., VENDOR FAIR
Wednesday, May 22
8 a.m. – 4 p.m., General sessions (users only)
Timelines for the Tuesday afternoon and Wednesday user presentations and discussion sessions had not been finalized before CCJ went to press. However, the topics to be addressed include the following:
- Trip-reduction efforts in a 7FA fleet—including determination of focus areas, single-point vulnerability, and a case study on how some findings were addressed to improve reliability.
- 7F DLN 2.6+ combustor washer distress will provide a brief overview of the RCA for the existing washer and discuss the importance of replacing it with an upgrade.
- Combustion fallout because of inner-support-ring failures.
- Finding turbine-compartment leaks.
- Chemical foam cleaning of 7FA.03 compressors fouled with minerals.
- Compressor IGV adjustments to compensate for gas-turbine operational issues.
- Issues with a non-optical flame detection system.
- Design evolution and inspection quality control of first-stage buckets.
- HMI and controls enhancement.
When you receive your conference registration packet, be sure to look through the programs for Tuesday afternoon and Wednesday. There are sure to be more topics than those listed above; plus, you’ll have access to the final lineup of presentation times.
Thursday, May 23 (GE Day)
8 – 10:45 a.m., GE session (users and GE only)
Following the opening session there are four one-hour GE breakout sessions, each with three concurrent presentations. Here’s the lineup:
11 a.m., Breakout 1: Combustion turbine 101, Compressor and turbine, Digital solutions.
1 p.m., Breakout 2: CT auxiliaries, Power management, Supply-chain overview.
2:15 p.m., Breakout 3: Combustion, Running my plant to 2055 (part 1) Technical dialog (NCR, ER, TIL, RCA).
3:30 p.m., Breakout 4: 7F.04-200 upgrade, Running my plant to 2055 (part 2), Controls.
Here’s what each of the GE breakouts promises in terms of content:
- Digital solutions. How predictive ad prescriptive analytics are leveraged to optimize efficiency, reliability, and profitability.
- Combustion turbine 101. An introductory session covering power-generation and CT fundamentals, combustion theory, 7F evolution, Brayton cycle.
- Compressor and turbine. Latest field experience and best practices, emerging fleet issues, TIL revisions, new PSIB/PSSB releases.
- Power management. Getting comfortable with what’s happening outside the plant fence and thinking about ways to mitigate likely risks.
- Supply-chain overview. On-time delivery of parts, quality assurance, inventory, planning, etc. Rotors are a key topic in this session.
- CT auxiliary systems. Reliability improvements for auxiliaries, liquid-fuel and auxiliary upgrades, TIL revisions, emerging fleet issues.
- Technical dialog. Overview of GE’s engineering-request process, field statistics, top five TILs.
- AutoTune troubleshooting, upgrade on Axial Fuel Staging for the DLN 2.6+ combustor, emerging fleet issues.
- Running my plant to 2055 plus. What SMEs think your plant should be considering for the coming decades and the emerging stressors you may not know about.
- 04-200 upgrade involves an advanced compressor to boost hot-day output and other improvements.
- Controls session includes a fundamental model-based control education with practical troubleshooting.
Friday, May 24
This half-day program encompasses five hour-long sessions, some of which run concurrently. Two segments are sponsored by Power Users, three by GE. Here are the details:
Power Users sessions:
- 8:30 a.m., Borescope preparation and information sharing reviews lessons learned and provides guidelines for a successful inspection.
- 11:00 a.m., Coupling alignment focuses on the methodology and lessons learned to ensure success. A panel of users with overhaul experience leads the discussion.
GE sessions:
- 8:30 a.m., Combustion turbine 401 is an advanced session for users focusing on real-world examples shared by highly experienced colleagues. Controls philosophy is part of the planned discussion.
- 9:45 a.m., Winterization and liquid fuel examines equipment failures caused by cold weather events and how to avoid problems in the future. A focus of the discussion is reliability improvements for liquid fuel systems.
- 11:00 a.m., Customer portal and technical communication reviews portal navigation and provides assistance to users having specific problems. Turnaround time for proposals also is on the program.
Marriott St. Louis Grand
Majestic Ballroom
Monday, May 20 and Tuesday, May 21: 4 – 7 p.m.
Monday |
Tuesday |
Company..Booth |
Company..Booth |
| Advanced Turbine Support…. 13 AGTServices….1 Allied Power Group… 31 AP4 Energy Services LLC…. 49 ARNOLD Group …5 BBM-CPG Technology Inc 28 Bearings Plus …. 40 Camfil Power Systems … 53 Chevron… 69 Conax Technologies…. 74 CTTS …33 CUST-O-FAB… 8 Cutsforth … 42 Dekomte de Temple LLC .. 27 Direct Turbine Controls …. 66 Doosan Turbomachinery Services 50 Emerson… 70 Environex Inc… 64 Environment One Corporation ….4 EthosEnergy…. 54 ExxonMobil …. 25 Falcon Crest Aviation Supply Inc.. 21 Filter-Doc Corporation…6 Frenzelit Inc…. 67 Gas Path Solutions… 16 Gas Turbine Parts & Service Inc …. 65 Hy-Pro Filtrtation…. 60 IC Spares …. 56 Industrial Air Flow Dynamics Inc …20 Integrity Assessment Group (IAG) …35 Integrity Power Solutions …. 37 ISOPur Fluid Technologies Inc …. 52 ITH Engineering ….9 JASC…. 63 K Machine….38 Koenig Engineering Inc… 39 Lectrodryer LLC…. 57 MD&A ….17 Mee Industries Inc.. 44 Munters Corporation… 58 National Electric Coil….3 Nederman Pneumafil …. 29 Nord-Lock Group.. 61 NRG Faist Corporation Inc …18 Oilquip Inc…. 73 ORR Protection Systems Inc …. 46 Parker Hannifin Corporation… 51 Pinnacle Parts and Service Corp ..11 Pioneer Motor Bearing Co …. 19 Power Services Group… 30 Power Valves LLC … 10 PowerFlow Engineering Inc …. 43 Powmat Ltd… 55 Premium Plant Services… 26 Prince & Izant Company… 47 PSM…. 12 Rapid Belts LLC .. 23 Republic Turbines.. 15 Riverhawk. 59 Rochem Technical Services… 71 Roper Pump Company… 34 Schock Manufacturing…. 48 Shell Oil Products.. 45 Stork H&E Turbo Blading Inc…. 68 Structural Integrity Associates….2 Sulzer Turbo Services Houston Inc…. 75 SVI BREMCO….24 Taylor’s Industrial Coatings Inc…7 Tetra Engineering Group Inc… 32 Trinity Turbine Technology …. 22 TTS Energy Services 36 Turbine Services Ltd…. 62 Veracity Technology Solutions LLC….41 Viking Turbine Services Inc…. 14 Young & Franklin… 72 |
AAF International … 65 Advanced Turbine Support … 13 AGTServices …1 Allied Power Group …. 31 Alta Solutions Inc…. 71 AMETEK Power Instruments….2 AP4 Energy Services LLC …. 49 Applied Technical Services … 48 ARNOLD Group …5 Avail Bus Systems .. 63 Badger Industries. 68 Baker Hughes…. 38 Brayton Power… 32 CC JENSEN Inc… 29 Caldwell Energy Company LLC. 10 CECO Environmental …. 37 Chentronics. 47 Chevron… 69 Conval… 40 CRDX – Carbon Reduction Systems… 3 Doble Engineering Company …. 44 Donaldson .. 52 Doosan Turbomachinery Services Inc … 50 Durr Universal Inc ..7 EagleBurgmann Industries LP… 58 Environment One Corporation….4 EthosEnergy 54 ExxonMobil.. 25 Fluitec…. 51 Gas Path Solutions 16 Groome Industrial Service Group …. 22 Gulf Turbine Services … 59 HILCO Filtration … 64 HRST Inc … 30 HYTORC … 62 Industrial Air Flow Dynamics Inc . 20 Iris Power … 35 Kobelco Compressors America Inc … 34 Liburdi Turbine Services .. 55 Macemore Inc … 14 Marioff NA ..11 MD&A … 17 Metroscope Inc … 23 Mitten Field Services LLC 42 Moog …. 46 Nooter/Eriksen Aftermarket Services …28 Outage Support Resource LLC … 19 Paragon …. 15 Power House Resources … 60 Precision Iceblast Corporation … 70 PSM ….12 REXA Inc … 43 ST Cotter Turbine Services … 56 SG Energy Solutions …. 33 Shell Oil Products … 45 Sulzer Turbo Services Houston …75 SVI BREMCO …. 24 TesTex …. 36 TOPS ….9 Toshiba America Energy Systems57 TRS Services 8 Turbine Generator Advisers …. 53 Universal Plant Services … 18 Vector Systems Inc …. 21 Vogt Power … 74 VOOM LLC … 26 Webster Associates. ..6 WL Gore & Associates … 39 Woodward Inc … 41 |
AES Huntington Beach Energy
AES Alamitos Energy
Owned by AES Southland
Operated by AES CorpEach plant, rated a nominal 674 MW, is a 2 × 1 combined cycle powered by GE 7F.05 gas turbines and Siemens SST6-5000 steam turbine, located in Huntington Beach, Calif
Plant manager: Weikko Wirta
Challenge. Achieve world-class starting reliability.
Solution. AES Huntington Beach Energy and AES Alamitos Energy implemented robust process optimization programs to achieve close to 100% starting reliability on its gas and steam turbines since COD in early 2020.
Startup failure (SF) means an outage that results when a unit is unable to synchronize within a specified startup time following an outage or reserve shutdown. NERC defines a startup period to begin with the command to start and end when the unit is synchronized. SF begins when a problem preventing the unit from synchronizing occurs; it ends when the unit is synchronized, another SF occurs, or the unit enters another permissible state.
Both plants have 20-yr power purchase agreements with two starts daily. To meet this requirement, plant personnel were proactively involved with project construction and commissioning activities, together with the EPC contractor’s commissioning team.
AES management and the EPC contractor provided all operations and maintenance personnel 10 weeks of plant-specific training. In addition to this in-person training, the team also received DCS simulator training.
At the end of commissioning, a couple of experienced contract operators were hired to fill open operator positions for a year. Contract operators and the AES operations team updated operating instructions, prepared startup checklists, reviewed and established alarm priorities on the DCS,
The team has been tracking plant operational challenges to achieve 100% startup reliability during the post-COD period. Startup-failure and plant-trip data have been well analyzed and internal RCA discussions have been carried out by the team for improving overall plant reliability.
To achieve 100% starting reliability, a pre-start checklist has been used on every startup/shutdown and signed off by a control room operator and plant equipment operator. Operators have been required to finish familiarization training, as well as to follow well-established plant startup and shutdown procedures.
In addition, plant O&M technicians have been coordinating to meet plant operational priorities and actively avoid equipment failures. Weekly planning and scheduling meetings have managed to effectively resolve plant discrepancies. Operators have been using the OEM’s digital asset performance monitoring system for tracking equipment performance.
Preventive operational checks have been carried out weekly, monthly, and quarterly to prevent plant discrepancies, while predictive and preventive maintenance have been done effectively.
Performance and predictive monitoring tools—such as EtaPRO, advanced pattern recognition, and Predictor vibration monitoring—are used. To immediately resolve plant issues, IC&E technicians have been assigned in swing shifts.
After every annual outage, an effective commissioning and testing procedure checklist is followed before a plant restart. Additionally, the OEM’s M&D support center has been helping and troubleshooting any unknown complications for the gas turbines.
Results. Even averaging more than 250 annual starts in the last three years of operations, plant starting reliability has been averaging 99% (bar charts). This enviable achievement is attributed to the implementation of the process optimizations programs described above.
Project participant:
Damodaran Sri Ramulu, operations manager
Faribault Energy Park
Owned by Minnesota Municipal Power Agency
Operated by NAES Corp
265 MW, 1 × 1 7F-powered combined cycle equipped with a GE A10 steam turbine, located in Faribault, Minn
Plant manager: Shawn Flake
Challenge. Combined-cycle powerplants have changed their operating profiles to accommodate grid demands for flexible generation. Example: MISO territory has a significant amount of wind energy in its portfolio, requiring Faribault to cycle daily because of excess wind generation overnight.
Faribault Energy Park primarily covers intermediate- and peak-load requirements. Today’s energy market has required the plant to provide faster starts and reduce startup costs while maintaining equipment health and reliability over its lifetime.
The cyclic profile of the steam turbine has increased rotor low-cycle fatigue which must be properly managed to reduce the unit’s life consumption per start. Objective is to operate well beyond the typical 30-yr lifespan that plants typically are designed for. Historically, turbine OEMs have provided startup guidelines and ramping practices that were conservative but didn’t manage stress properly.
Solution. Faribault implemented steam-turbine Agility starts for its A10 machine with the primary goal of providing faster combined-cycle starts while consuming rotor life at a rate commensurate with, or less than, baseline consumption. The ST controller calculates the optimal steam temperature to minimize startup times based on the rotor’s warming profile. Rotor cyclic stress is minimized at the same time.
The calculated steam-temperature value is input to the gas-turbine control system and steam-attemperator logic. The GT acts as the primary steam-temperature controller by varying turbine exhaust temperature to the HRSG. Attemperators act as a secondary steam-temperature controller, minimizing—often eliminating—the need to use spray water during startup.
Results. Succinctly, implementing ST Agility starts has decreased fast-start time while reducing rotor stresses that consume life.
More specifically, combined-cycle start times, after a shutdown duration of 16 hours or less, have been reduced by nearly 10 minutes consistently (figure). Typically, with daily cycling, the shutdown duration is eight hours. Faster starts make the plant more responsive to grid needs while saving fuel. Shorter startup times are achieved by releasing the gas turbine at the optimal time to ramp to market based on steam-turbine rotor stresses.
Rotor stresses have been controlled by creating a stress “budget” for each startup. Stress targets, measured in kilopounds per square inch (ksi), are used to reach minimum and maximum stress limits, allowing each start to consume a budgeted amount of life.
Prior to the upgrade, rotor stress trends on warm starts had several peaks and valleys throughout the warmup phase. Controlling the steam temperature to hit plant’s ksi targets has removed the peak and valley effect of a traditional warming cycle. Rotor stresses now reach the peak target, hold peak stresses through warmup, and release on the back end creating a plateau effect.
Project participants:
Shawn Flake, plant manager
Scott Lowe, operations manager
Tim Mallinger, lead operator
