• Real-world case studies with EMI
• Wireless monitoring solutions

A recent webinar presented by Cutsforth Inc focused on electromagnetic interference monitoring (EMI), a valuable diagnostic tool for detecting impending problems with generators, motors, isophase bus, bearings, and other plant equipment. Primary presenter and discussion leader was Kent Smith, well respected in the electric power industry for his deep knowledge of EMI, honed by years of service as the lead generator expert for one of the world’s largest utilities and as the chairman of the Generator Users Group, one of the planets in the Power Users universe.

Plant personnel not able to participate in the webinar when it aired can access a recording here via the expansive Cutsforth webinar library. The editors believe you will benefit professionally from Smith’s case studies which illustrate findings by way of data scans. Smith, who was supported by Cutsforth’s Steve Tanner, VP business development, shared several case histories, including these:

Generator monitoring with EMI. Water was affecting the calibration of hydrogen analyzers. A cooler leak was found and the unit repaired. Generator reached end of life without a winding replacement.

Motor monitoring with EMI. Plant’s six pump motors had started multiple times without cooldown between starts; the possibility of damage to the induction-motor rotor bars was a concern. EMI and motor-current signature analyses were performed. One motor registered higher EMI values than the others. It was found to have salt-encrusted winding and some cooling passages plugged with salt. Cleaning was the fix.

Excitation power rectifier. Data revealed significant arcing and discharge in the lower frequency band and suggested a loose connection in the excitation system. Connections checked when the unit was in a “not-in-demand” (NID) state were found loose and tightened. EMI data returned to normal after exiting the NID state.

Wet stator bars and loose wedges. Generator was going into a rotor-out outage. Retaining-ring and stator-wedge replacements were scheduled, plus a hydraulic integrity test (HIT). Replacements were made with no issues.

However, when performing the HIT skid test, plant personnel couldn’t pull the required vacuum on the unit. Capacitance mapping and helium leak testing was performed. The findings: four significant clip leaks, minor plumbing leaks, wet bar found on the “B” phase. Corrective action: Leaks were repaired, bar dried out, and the unit HiPot-tested to an operational level. The generator was returned to service with a rewind planned for the following year.

Bearing electrolysis. EMI trending located a loose ground lead.

Isophase-bus flex link. One unit had been monitored for years because of its high EMI readings. The brushing box was suspected because of the frequency content, time-domain waveform, and sniffer readings. Overheated flex links and moisture intrusion found by transformers was repaired, but improved EMI improved only slightly. During the next outage flex links under the generator were removed and inspected. The results of that investigation were not available at the time of the webinar.

Water pumping stations. Electromagnetic signature data were collected and analyzed for two pumping stations, each having nine synchronous-motor-driven pumps. The motors were equipped with rotating pilot exciters and rotating main-exciter-to-feed-motor main fields.

The worst-case motor at one pumping station was found with pilot-exciter brush rigging and commutator arcing. It was experiencing alignment/rotor wobble and had loose connections at the bus connector and/or insulator.

The worst-case motor at the second pumping state had similar issue characteristics, plus loose windings in the slot causing slot discharge.

Bearing electrolysis. A generator was removed from service with high vibration on the No. 1 turbine bearing attributed to electrolysis, which caused pitting and melting of the babbitt material. An enhanced shaft grounding system, with a sensing point for voltage, was installed. Plus, a ground current monitor was installed for the turbine. Instrumentation was connected to the main server to access the EMSA data.

Engineers believed there were the following three possible sources of the high voltage:

• Static voltage build-up because of a brush rider in the turbine blading.
• A magnetic driving force from turbine-shaft magnetism.
• Static exciter thyristor firing voltage transition.

Turbine bearing data are presented both graphically and in tabular form.

The unit was removed from service several times because of high vibration, with bearing electrolysis believed to be the cause. The bearing was replaced and clearances validated. Vibration analysis suggested electrolysis was still occurring. The fix was installation of a high-frequency blocking filter on the exciter field circuit. That eliminated the high vibrations and electrolysis.

Wireless monitoring solutions

Chuck Requet, principal applications engineer, and Steve McAlonan, director of business development, began their presentation by explaining the value proposition of the company’s InsightCM™ architecture, which can accommodate multiple measurement technologies in a single platform.

Vibration monitoring was a focal point of the presentation, which can be accessed here. InsightCM was said to support industry-standard viewers for vibration—including trend, waveform, spectrum, waterfall, orbit, polar, bode, shaft centerline, full spectrum, envelope (amplitude demodulation), order (even angle), time synchronous average, and autocorrection.

Wireless is particularly advantageous for monitoring the many common assets—such as pumps, fans, compressors, etc—that would benefit from more attention. Also, when assets are not deemed critical enough to warrant 24/7 screening, or may be located in remote, difficult, or hazardous locations. InsightCM supports two wireless families, NI and Erbessd, which, in turn, support Bluetooth 5.

An example illustrating the value of wireless was for a large user with 35,000 sensors. This project was said to have three-year breakeven cost for hardwired vibration of $80-million. Wireless reduced the install cost by 70% and the planned major design effort was shifted to “minor modification.” The breakeven went from three years to 18 months.

EthosEnergy Group presented two complementary webinars in early fall: “Turndown or shutdown?” and “How to keep your aging GE gas turbine running longer”. Presenter and moderator for the first was Jeff Schleis, chief engineer, products and application. He was supported by Principal Engineer Chris Chandler, an expert in turbine optimization and engineered solutions for gas turbines.

Schleis noted at the outset that for a significant number of gas-turbine owners and operators today, “the unspoken question is ‘turndown or shutdown’?” Greater investment in, and prioritization of, renewables generation is reducing the capacity factors of gas-fired assets because of increased cycling operation. Result is many plants are examining the benefits of extended turndown and wondering if it can improve the bottom line.

Most likely, it was said, a bottom-line improvement will be experienced where the share of renewables in electric production exceeds 40%. According to data from S&P Global Market Intelligence, 13 states are poised to exceed the 40% threshold in 2023.

Schleis cautioned that knowing the financial impact of cycling versus the net loss to generate at off-peak times is not easy to evaluate accurately. Fewer starts, lower fuel costs, and ultimately extending the time between outages all factor into the return on investment. Enabling turndown beyond the unit’s current capability can tip the economic scales and reduce the negative impact of cycling.

The moderator identified the following steps on the path to extended-turndown profit: 1, understand turndown limits; 2, conduct testing; 3, consider modifications; 4, validate financial analysis; 5, install an integrated solution. If the stars align, you will improve the bottom line.

To get a better feel for what attendees were experiencing, Schleis asked a couple of questions:

First, concerned current operations. The takeaways included:

• Cycling more, 72%.
• Cycling less, 4%.
• Operating at different times of the day, 31%.
• Running less, 18%.

Answers to the second question revealed where attendees were on the path to extended turndown:

• Actively operating in an extended-turndown mode, 17%.
• Creating a formal business case, 9%.
• Testing turndown limits, 15%.
• Researching solutions, 31%.
• Operating profile does not benefit from extended turndown at this time, 25%.

Benefits of turndown discussed included the following:

1. The switch from starts-based to hours-based maintenance provides a greater opportunity for parts (and rotor) life extensions. Plus, it decreases the severity of parts repairs.
2. Decrease in midday losses attributed to renewables generation because you continue to run when large amounts of solar/wind kilowatt-hours drive down prices.
3. Cogeneration plants may satisfy their contractual requirements at reduced load. When steam production is more profitable than power, turn down the unit to maximize thermal energy with minimum power generation. Another strategy: Run redundant units for reliable steam production at minimum power generation.

Ecomax®, an EthosEnergy solution, is discussed as a critical tool for maximizing turndown. As the diagram shows, its automatic tuning feature manipulates control curves and IGVs to keep your GT within emissions limits. Plus, automatic tuning of GT control curves reduces the isotherm. Getting down to 50% of the baseload rating, or lower, might also mean reducing air flow through the machine. Addition of inlet bleed heat and automatic adjustment of the IGV angle can contribute here.

One of the case studies presented illustrates how EthosEnergy achieves its operational goals. A cogeneration plant with three GE Frame 6B engines served as the example. Key points:

• Premix minimum load decreased from 70% to 50%.
• Testing proved turndown to 30% possible before CO limits are exceeded.
• NOₓ emissions are maintained below 25 ppm.
• Exhaust gas temperature is limited to 1022F (max isotherm of 1085F) to maintain 950F in HRSG piping, by design.
• Process steam production was maximized with minimum generation and no duct firing.

If there was a positive outcome of the pandemic for power O&M professionals it might be the emergence of the webinar as an indispensable training tool. Power Users relied on the virtual medium to conduct the annual meetings of its various user groups for a year or two until Covid subsided. Its HRSG Forum continues to present technical webinars periodically to keep its vibrant global membership informed.

OEMs and service providers also are increasing their use of webinars to help customers grow in their jobs and make better decisions. GE Vernova has done good job in this regard, the editors believe, with its Gas Power Resources library. It allows you to search by type of resource (articles, white papers, webinars, etc—each served by a single-click button on the site’s home page), product of interest (gas turbine, steam turbine, generator, etc), topic (asset management, cybersecurity, outage planning, etc), and via a keyword search.

What follows are thumbnails of webinars presented by GE Gas Power engineers during late 2023 that may be of interest to CCJ readers. The editors listened to them online and then, to confirm facts, went to the website and found the recorded webinars quickly by clicking on “webinars” and “gas turbines” (or “steam turbines”). Couldn’t be easier to get useful information. Take a test drive.

Managing your F-class rotor: Mitigating risk and enhancing value with Penny Leahy, F-rotor product line leader; Srinivas Ravi, principal rotor engineer; and Frederic Sbaffo, senior engineer—fleet management.

Learn about proper planning throughout your rotor’s lifetime and what you can do to run your equipment to its highest potential. Plus, explore the benefits of preventive maintenance to avoid serious issues—such as corrosion.

Preparing for the unexpected: Outage planning for steam turbines with Matt Foreman, ST platform leader; and Mark Kowalczyk, global repairs leader.

Focuses on how GE Verona can help you plan and prepare for any scenario that might be encountered in the next three to five years. Learn what goes into putting together a solid plan for a successful outage, and why getting started sooner is always better than later.

Generator exchange-rotor program is designed to help users ensure routine maintenance doesn’t extend outages beyond their planned durations. Chad Snyder, global segment leader for upgrades of generators, steam turbines, and HRSGs is the session leader.

He leads a discussion on how a generator rotor exchange could help you reduce risk and valuable time during both planned and forced outages. Also, how exchange rotors can be enhanced to accommodate your particular cyclic-duty plant operations to ensure capacity, availability, and reliability.

Outages: Lessons learned and continuous improvement reviews the unprecedented challenges experienced by GE Vernova and its customers during the pandemic and how the OEM and users collaborated for success.

Amir Hafzalla, president of FieldCore; Eric Gray, president of GE Gas Power Americas; and Mark Albenze, president of GE Gas Power Services, explain how remote technologies and innovative changes are supporting the OEM in its efforts to successfully deal with today’s challenges. The executives then review the processes developed in partnership with users to enhance the outage experience. Finally, they present real-world examples of lean practices being implemented company-wide and the impact they have had on outage results.

The editors rated as most valuable to owner/operators GE Vernova’s mid-October webinar, Freeze protection considerations for gas turbine power plants operating in regions subjected to ambient temperatures as low as minus 50F. You might know a thing or two about freeze protection, but is that enough to keep your plant out of harm’s way?

A panel of three consulting engineers from the company’s product services group—Alston Scipio, PE, Will McEntaggart, and Ronald Wifling—review solutions you may have forgotten or never were aware of in the first place. The presentations/discussions were chaired by Tom Freeman, chief customer consultant, well known to owner/operators of GE frame engines.

Gas turbines and combined-cycle plants were the focal point of the 90-min webinar. Systems and equipment outside the plant fence/boundary were not part of the discussion. The session began with safety moment to get attendees thinking about such things as possible impacts of off-normal weather conditions, the importance of proper PPE, potential dangers of slippery ladders and steps, being aware of the consequences of icing conditions—such as stranded workers, falling ice, etc.

Stressors also were injected into the discussion—including how to deal with intermittent cold weather, ice rain/sleet, freezing fog, less than resilient grid connections, supply limitations for fuel and other fluids, long durations between cold snaps such that you drop your guard regarding freeze effects, etc.

Plant configuration (indoor/outdoor) and site location are important considerations for the analytical effort required. They influence ambient max/min temperatures, potential wind/snow/ice impacts of elevation, water availability, emissions limits, plant emergency plans, etc.

A significant portion of the webinar is dedicated to mechanical systems and their vulnerabilities. Discussion here covers air inlet systems, cooling-water considerations, power augmentation systems and their layup, hydraulic oil systems for steam and gas turbines, gas fuel system and pressure, and liquid fuel system—among others.

Next comes instrumentation considerations, both for exhaust systems and instrument air. Discussion continues with air-operated valves, then operability, with protection of the air-inlet system against icing called out along with assuring proper combustion.

A valuable adjunct to the discussion is the list of applicable O&M manuals (GEKs) and technical information letters (TILs) provided. Read them to advance in your job. Plus, there’s a comprehensive winterization checklist to refer to so you don’t forget anything.

Robert Threlkeld generally called after receiving his copy of CCJ, “to catch up.” Sometimes he had questions on the content, other times an article triggered an experience that he thought worthwhile sharing. The last time we spoke, in mid-May, he was torn between attending the HRST Academy in Avon, Colo, and the HRSG Forum in Atlanta—only a week apart in June 2023.

Threlkeld had attended the Forum several times over the years, but never the Academy. He was trending in favor of the latter given his association with HRST Inc as an external advisor to the company’s board of directors since retiring as a Tenaska Inc plant manager a couple of years ago. Plus, the meeting’s Rocky Mountain location would beat a trip to Atlanta any day. A possible vacation in Greece also was on his mind.

That Robert didn’t call after CCJ No. 75 mailed in late August, our assumption was he was on vacation or busy helping a school or hospital near his home cope with the demands of operating and maintaining their energy systems. “Assuming” was a terrible error in judgment. We didn’t know his cancer had returned with vengeance until long-time Tenaska colleague and Navy brother, Dr Robert Mayfield, called to tell us of his death November 28.

Mayfield remembers, “The first time I met Robert was at Lindsay Hill where he was plant manager. Both of us were graduates of Auburn University and naval-officer commanders. He was dedicated to his family, friends, and country. During the last two decades we chatted weekly. Our conversations touched on topics such as the Navy, Auburn football, families, and helping each other when things were hard at work. Vitality and life characterized him; he will not be forgotten.”

Threlkeld will be remembered by the editors and the electric generation community for the many best practices he and his O&M teams at the Lindsay Hill and Central Alabama Generating Stations—both 3 × 1 combined cycles powered by 7F gas turbines—published over the years in the pages of CCJ. Both plants are among the industry leaders in Best Practices Awards earned since the program’s introduction in 2005—Lindsay Hill and Central Alabama each receiving three Best of the Best Awards over the years (photo).

Threlkeld’s presentation, “Developing best practices,” at the 2004 Maintenance Workshop conducted by the HRSG User’s Group, is a classic for encouraging owner/operators to participate in programs such as CCJ’s to avoid having to re-learn lessons and to encourage continuous process improvement.

In that presentation he stressed operational consistency. The tools used at his plants included grading of heat rate, ramps, excess energy, and availability. Experience taught him that best practices help in training of new operators; reducing heat rate and long-term maintenance; saving in fuel-gas, back-feed, and imbalance costs; plus other benefits.

Threlkeld retired from the US Navy in 2001, having served for 20 years. Much of that time was spent at sea on warships, including the USS Carr, a guided-missile frigate, and USS John Rodgers, a Spruance-class destroyer. The Carr’s XO touted his considerable abilities as the ship’s chief engineer. Speaking to his character, the XO noted Robert’s “bravery” in speaking the truth to power with reports not always welcomed, but necessary when one serves the greater good.

Another shipmate remembered him this way: “He was as good of an officer as there ever was, and even a better man.” Yet another said, “The Carr’s motto was ‘Courage, Will, Determination.’ For some people those are nothing more than words, but for Robert they were a way of life.”

Bob Schwieger

H O Clarke, Topaz, and Braes Bayou

Owned by WattBridge
Operated by ProEnergy
1248 MW (Clark and Braes Bayou each have eight 48-MW LM6000PC engines; Topaz, ten 48-MW LM6000PC machines). All are gas-fired peaking units located in the Houston area
Plant manager: Kevin Chaffin

Challenge. By their nature, peaking units must have high availability. As a result, O&M teams are challenged to maintain LM6000 units based on broad life-limit calendars, scheduled inspections, and experienced intuition. They are blind to the actual condition of equipment between inspections and must operate reactively to alarms. This approach risks reliability and availability during peak load times, as even a few hours downtime at the wrong point in a season can wreak havoc on plant economics for the year.

Solution. Create proactive remote monitoring and diagnostics (RM&D) models to detect incremental changes in equipment operation not identifiable with standard monitoring techniques. When identified, these changes should be reported via easy-to-understand advisories that include recommended actions.

The technology behind RM&D—predictive analytics—gives valuable insights into the actual condition of equipment and its performance. Result: Users can avoid outages during peak run times, proactively schedule maintenance, source equipment ahead of time, and adjust how and when to operate units. This solution has proven successful with various components—including fuel nozzles, bearings, and gearboxes.

Results. ProEnergy’s O&M team provides recommendations to promptly rectify a given issue, with a view toward operational availability. This strategy provides a real-time view of equipment condition and protects operational strategy, saving time and money. Below are two case studies from WattBridge and a third-party RM&D user:

Case Study 1: Zero lost time through early detection. A user in the West received an advisory regarding an accessory gearbox before an alarm activated. An increase in bearing temperatures indicated a drop in lube-oil pressure. Plant was advised to closely watch the equipment during operations and to replace the lube-oil pump during regularly scheduled downtime. Upon replacement, operational values returned to normal with no loss of operating time.

Case Study 2: Catastrophe avoided with operational adjustments. During a peak runtime, a WattBridge site received an advisory of impending bearing failure, which could have catastrophic consequences for the turbine. The onsite team was advised adjust operating parameters to accommodate the damaged part, and a full-time remote operating center (ROC) watch was set for the unit. A replacement engine was sent to the site, which resulted in no additional damage to the original unit and a minor loss of productivity during peak load time.

Project participants:

Kevin Chaffin and the ProEnergy O&M organization

2023 Best of the Best from the LM6000 fleet

• Exira: Freeze-protection improvements assure high availability, reliable starts in winter
• WattBridge: Roving work crews effectively support small onsite staffs
• WattBridge: Seasonal shelters protect plant equipment in winter
• WattBridge: Modeling for successful proactive remote monitoring and diagnostics

H O Clarke, Topaz, and Braes Bayou

Owned by WattBridge
Operated by ProEnergy
1248 MW (Clark and Braes Bayou each have eight 48-MW LM6000PC engines; Topaz, ten 48-MW LM6000PC machines). All are gas-fired peaking units located in the Houston area
Plant manager: Kevin Chaffin

Challenge. Today’s O&M environment faces a triple challenge: First, staff shortages abound and filling these roles with skilled, trained, and experienced technicians is difficult nationwide. Second, training inexperienced yet promising staff puts additional stress on the existing staff and tends to be site-specific and difficult to repeat at scale. Third, because O&M services at plants typically operate on razor-thin margins, additional investment for recruiting and training compounds the first two challenges.

Solution. ProEnergy O&M services leveraged geography to alleviate staff shortages and centralize training new staff. In 2022, the company operated four peaking-power facilities with a total of 30 LM6000PC gas turbines in the greater Houston area. The company embraced the small-team concept and embarked on a mission to streamline work management through standards and automation.

Each site is staffed with a small contingent of technicians. A roving services crew supports each site for major work items, can work on multiple turbines, and visits on an as-needed basis. In addition, all sites leverage technology from the 24/7 remote operations center (ROC) and remote monitoring and diagnostics (RM&D) support from the ProEnergy ROC in Houston and Sedalia, Mo.

Staffing. Each eight-unit plant site is staffed by one (each) instrumentation and electrical (I&E) technician, mechanic, auxiliary operator, and site supervisor. Staffing is the same for 10-plant sites, except they have two I&E techs. Roving plant services teams each have two I&E techs and two mechanics.

Results. Leveraging the geographic density of plants in the Houston area, creating an effective shared-services team, and streamlining work processes enables ProEnergy to thrive with a small O&M team. Based on 2022 performance, the company operates peaking-power facilities with industry-leading reliability and availability.

In 2022, the WattBridge fleet was dispatched for more than 1.3 million MWh of much-needed power throughout the year at an average starting reliability of 99%. Furthermore, as Texas endured record heat during the hottest July in 128 years, the H O Clarke and Topaz facilities met energy security needs with starting reliabilities of 99.6% and 99.7%, respectively.

Project participants:

Kevin Chaffin and the ProEnergy O&M organization

2023 Best of the Best from the LM6000 fleet

• Exira: Freeze-protection improvements assure high availability, reliable starts in winter
• WattBridge: Roving work crews effectively support small onsite staffs
• WattBridge: Seasonal shelters protect plant equipment in winter
• WattBridge: Modeling for successful proactive remote monitoring and diagnostics

H O Clarke, Topaz, and Braes Bayou

Owned by WattBridge
Operated by ProEnergy
1248 MW (Clark and Braes Bayou each have eight 48-MW LM6000PC engines; Topaz, ten 48-MW LM6000PC machines). All are gas-fired peaking units located in the Houston area
Plant manager: Kevin Chaffin

Challenge. Climatic stress has no geographic boundary. As more-frequent extreme-cold events strain supply capacity, the challenge is keeping powerplants online. Virtually any facility in the world is susceptible to icing issues considering that turbine icing begins at 40F and air compression begins freezing at 34F.

Solution. Traditionally overlooked in warm climates, winterization solutions can ensure sustained cold-weather operation. To winterize balance-of-plant (BOP) equipment, O&M teams must balance operational strategies and procedures with costs.

What started at ProEnergy (PE) as an emergency effort—creating temporary, home-built structures in advance of a record freeze—resulted in effective, low-cost, and simple-to-use removable shelters as standard practice across all of the company’s plants. In 2022, PE operated four peaking power facilities in the greater Houston area comprised of 30 LM6000PC gas turbines.

Rather than building costly, hardened shelters, PE worked with a vendor to create custom weatherization shelters installed and uninstalled via zippers. These shelters apply to the water-spray injection skids, the NOₓ skids, and the plant instrument air compressors. An insulated covering is also used for the instrument panel on the turbine package.

Results. A temporary, urgently needed solution for one location has now grown to a permanent, inexpensive solution across an entire fleet. The ProEnergy O&M team conceived of this best practice even before related NERC compliance goals were instituted and now apply it to every new plant that comes online for improved energy security.

Though located in the warm Gulf Coast, the H O Clarke Generating Station—the first WattBridge facility, the world’s largest LM6000 owner and operator—was prepared for the unprecedented. The station came online just a week and a half before Winter Storm Uri, a historic ice event that disabled more than half of the Texas power grid.

Recognizing that preparations were in order, the PE O&M team executed creative, low-cost solutions by erecting scaffolding around NOₓ, water spray, and water pumps. Also ordered were 36 electric heaters (two per structure), built wind breaks for air compressors, and staffed the plant 24/7 for periodic rounds.

When the storm came, H O Clarke proved resilient with its newly innovated winterization strategy in place. The Ercot market reflected an extreme need for generation, and the station remained 100% available, running 141 uninterrupted hours with enough power for 200,000 homes. By the time Ercot revoked its emergency order, it had run for six days.

After that, ProEnergy explored options to make this successful short-term solution into a long-lasting one. The team explored a variety of structures, including permanent shelters and a wide variety of temporary, seasonal structures, and selected the zipper-based structures shown in the photo.

Applied at the second facility to come online, Topaz Generating Station, the O&M team deploys these structures starting in December each year and removes them in spring. In addition, WattBridge sites institute 24/7 plant staffing when expecting temperatures under 28F. These structures will be available at all of the company’s sites in 2023—including H O Clarke, Topaz, Braes Bayou, Mark One, and Brotman.

Project participants:

Kevin Chaffin and the ProEnergy O&M organization

2023 Best of the Best from the LM6000 fleet

• Exira: Freeze-protection improvements assure high availability, reliable starts in winter
• WattBridge: Roving work crews effectively support small onsite staffs
• WattBridge: Seasonal shelters protect plant equipment in winter
• WattBridge: Modeling for successful proactive remote monitoring and diagnostics

Exira Station

Owned by Western Minnesota Municipal Power Agency
Operated by Missouri River Energy Services
140 MW, 3 × 0 gas-fired peaking facility with diesel-oil backup, located in Brayton, Iowa. The LM6000PC engines are equipped with Sprint
Plant manager: Ed Jackson

Background. Exira Station’s design minimum operating temperature is ‒26F. Plant often is called on to run at sub-zero temperatures and has operated as low as ‒30F.

Operating in extreme cold always is challenging. To ensure the facility is prepared to run in all conditions, plant personnel developed a winterization checklist. The four-page 56-step document lists everything necessary to prepare the plant for wintertime operation. Some steps are quick and simple and only require a couple of minutes or so to complete. Others are more involved and could take up to several days.

While the checklist addresses the more obvious and general things the plant must do to prepare for winter, Exira had several other challenges requiring unique solutions. The list below highlights some of those problems along with their solutions.

Challenge 1. Package heat tracing was unable to keep up with sub-zero temperatures if fans are on. This caused water lines in the package to freeze unless water was flowing in the lines and created a “race” to get water flowing when operating in sub-zero temperatures before lines freeze.

Water injection starts at 5 MW, so the time it takes to push start buttons and fans start, until purge, warm up, and load to 5 MW are complete, is crucial; bad things can happen quickly. If there is a failed start for any reason during this time and another start is needed, there might not be enough heat in the package to prevent a line from freezing before water injection starts.

Solution 1A. Buy more time by operating the supplemental inlet heaters in Fig 1 (which normally don’t start unless the ambient temperature is less than ‒20F) during the start sequence when the ambient drops below zero. This adds a little more heat and helps prevent freeze-up. You can return to auto operation after water-injection flow starts.

Solution 1B. Keep as much heat in the enclosure as possible. MRES and other Midwest operators, have insulated their package bases to do this (Fig 2).

Challenge 2. Failed starts are extremely problematic in cold weather: You may not get another start attempt if the water lines freeze. It’s critical to reduce or eliminate failed starts.

Solution 2A. It’s important to eliminate inconsistent light-offs attributed to low fuel-oil temperatures by setting the fuel-oil-tank immersion heaters to maintain the oil at 60F.

Solution 2B. Starting on fuel oil takes longer to reach the 400F lite-off temperature than starting on gas. To reach 400F faster, within 40 seconds, increase the fuel-oil-valve lite-off percent from 12% to 14%.

Challenge 3. After a stop and subsequent cooldown period with the fans running, the package is cold. A restart would start fans and purge again. Since components already are cold from fans running during the previous cooldown, things could freeze faster than previously. You may not be able to start again because of freeze issues.

Solution 3A. Shared solutions with Solution 1 above.

Solution 3B. Give the package time to warm back up after a start. Exira has adjusted its offer parameters to the RTO to limit restarts in winter to every four hours, giving the packages time to heat back up. If the RTO wants to shut down and restart, and the time between stop and start is minimal, plant has sometimes self-scheduled to “bridge” the runs to prevent restarts as noted above. Bear in mind that starts are fickle in sub-zero temps and a failed start cannot be afforded.

Challenge 4. Cooldown times can be longer than necessary during subzero temps. Fans running longer than necessary can increase the time it takes for the package to warm up, or could freeze pipes.

Solution 4. Exira added logic to stop a cooldown if (1) it has been running for at least 15 minutes, (2) the zero speed detected is true, and (3) the enclosure temperature is less than 32F.

Challenge 5. Fans can run for reasons other than package cooling—gas-sensor drift, for example. If fans start when water is not flowing, the piping and water valves can freeze-up. Consider buying a new valve if you freeze-up the one in service. The bottom line: Prevent fans from running if water is not flowing or going to flow.

Solution 5. Logic was added to stop fans if the unit is not in a sequence (that is start, stop, cooldown, crank, etc) and enclosure temperature is less than 32F. There is still protection against gas leaks, as the gas valve will close if LEL continues to drift up. The operator can still take action to run fans from the DCS if needed to purge.

Challenge 6. Fuel-oil filters can wax-up faster than the operators can change them. Exira’s oil terminals are over 90 minutes away and the fuel must be trucked in. During extreme cold, by the time oil gets to the plant it is less than 20F—possibly as low as 5F.

Oil-tanker capacity is about 7500 gallons, but the plant can burn much more than that hourly. In fact, oil often burned faster than Exira can receive it. Problem is that when filling a tank as you draw from it, the cold oil sinks to the bottom of the tank and is immediately pumped to the operating units. The cold oil waxes up all the filters and creates differential pressures high enough to trip the units if plant personnel don’t respond quickly.

The tankers line up and are offloaded continuously, filling the tanks with cold oil faster than the tank immersion heaters can keep up, and the fuel-oil temperature drops.

Solution 6A. Keep storage tanks at their maximum levels at all times. This way the fuel has enough time in the tank to warm up to 60F and if the plant must operate on oil hopefully there’s sufficient volume to get it through the run.

Solution 6B. Exira installed a bypass to allow fuel oil to flow through a prefilter and back to the tank (Fig 3). This permits the plant to circulate fuel when the unit is shut down—circulating it through the filter and cleaning it continuously, thereby preventing filter plugging when producing power. Operators are busy enough during oil runs and extending the time between filter changes makes a huge difference.

Solution 6C. Exira is installing a fuel receiving and conditioning system, soon to be commercial. It will have two 150-kW inline fuel-oil heaters, and filters, in the line from the tankers to the storage tanks. This will help prevent waxing by heating the fuel before it gets to the tank.

Plus, when fuel is not being received from the tanker, the system can switch to recirculating oil in the storage tank to help the immersion heater get the temperature back to where it needs to be, while filtering the oil at the same time.

It will be possible to recirculate, heat, and filter one of the plant’s two tanks while filling the other. A 4-in. articulating unloading nozzle also is being added, giving Exira the ability to quickly connect to tankers. An Allen Bradley Flex I/O rack will bring the unloading system into the plant control system for better monitoring and control.

Challenge 7. The legacy cement pad used to park trailers was dished for containment, making it dangerous to use when the sloping sides were covered by ice.

Solution 7. The original pad was removed and a new one poured, eliminating the problematic slope. This pad has a redesigned drain for containment to increase safety.

Challenge 8. The demineralized-water trailer sits outside on a cement pad with fire hoses to connect to plant piping that send raw water to the trailer, and demin water from the trailer to the plant. This creates many problems—including freeze-up of access doors preventing operators from gaining access to the trailer, and the need to handle hoses in sub-zero temperatures. Staff cannot leave the hoses outside overnight and when needed in the morning must pull them out, connect them, and get water flowing before it freezes.

When finished making water for the day, staff must shut down the demin system and disconnect the hoses and pull them into a heated building before they freeze-up. If the demin system shuts down automatically because of a system upset, personnel must rush to get hoses pulled inside before the water in them freezes.

It’s almost impossible to handle a frozen 2.5-in.-diam water hose. At times, personnel had to abandon the hoses in place and run new ones to keep water flowing. Also, trailers have been frozen in place with large ice dams preventing staff from replacing the trailers.

Solution 8. Exira is enclosing the demin-trailer pad and making it a heated building (Fig 4). When complete, it will accommodate two trailers side by side. A 26- × 18-ft roll-up door is being installed to close the building. This will greatly increase safety by preventing ice in the demin-trailer area and not having to handle water hoses during extreme cold conditions. Also, it will increase reliability by allowing access to the trailer and hoses at any time.

Project participants:

Ed Jackson, plant manager
Tyler Furgeson
Tony Knapp
Devon Meyer
Baker Group (contractor)

2023 Best of the Best from the LM6000 fleet

• WattBridge: Roving work crews effectively support small onsite staffs
• WattBridge: Seasonal shelters protect plant equipment in winter
• WattBridge: Modeling for successful proactive remote monitoring and diagnostics
• Exira: Freeze-protection improvements assure high availability, reliable starts in winter

Broad River Energy Center

Owned and operated by Onward Energy

865 MW, dual-fuel facility in Gaffney, SC, with five 7FA.03 simple-cycle units, each equipped with an IST once-through steam generator

Plant manager: Malcolm Hubbard

Background. Having five GT/HRSG trains, each consisting of a 7FA.03 and a once-through steam generator, managing outages at Broad River Energy Center can be challenging, depending on work scope, available time, available contract support, and other factors. Outages are among the top three or four expense entries on the plant’s balance sheet, thereby demanding attention to detail and taxing the efforts of plant personnel to optimize and organize tasks.

Past outages often fell victim to schedule and cost overruns. Quality of workmanship was another concern given the amount of rework often required and availability impacts caused by contractor quality oversight.

The current staff has been challenged by ownership to reduce outage cost and duration, and improve quality control, compared to past practices with different owners and operators.

Challenge. A new manager was hired for Broad River with outage planning a high priority and goals of reducing outage expenses, increasing reliability, and improving customer relations. These strategic objectives were a focus with quality improvements being a dependency of each.

While outage philosophies are similar across the industry, the mechanics of how to prepare and optimize is highly dependent on staffing levels, knowledge and experience of personnel, and tools used to make the tasks and work packages more manageable.

Solution. Broad River deployed Quad C®, a software tool to assist in outage planning, believing it would help improve coordination, enable earlier discovery of challenges, promote better communications with vendor and owners, and build a foundation for optimal outage oversight. One of the key objectives was to create a continuous-improvement plan that would efficiently allow the facility to mature the planning and execution process over time.

Plan goals included the following:

• Consistency across the entire team.
• Standard reporting.
• Easy to use.
• Better oversight of risks and lessons.
• Reduce outage cost.
• Shorten outage duration.
• Provide a single location for outage files.
• Improve accountability and engagement.

Quad C provides a simple and user-friendly menu of modules that allow the addition of future outages, planned or unplanned, for ease of tracking fleetwide (Fig 1). The cornerstone module is the “Playbook” which is easy to follow, provides quick status indicators, and manages key tasks. New tasks can be added to the Playbook easily to help plan upcoming outages, without having to go back and review notes (Fig 2).

Action assignments can be managed through the Playbook, optimizing time, effectiveness, and creating an automated workflow (Fig 3).

Numerous status reports and indicators are available to assess and communicate with others, improving planning support needs. A planning indicator shows status compared to the target, based on the phase and timing. The sample of status metrics in Fig 4 illustrates a simple status report of Playbook activities (Fig 4).

As one matures with planning, a dynamic readiness graph allows staff to compare outages and easily identify improvement areas, impacts, and risks that best support an owner’s strategy of continuous improvement, cost reductions, and quality elements for the plant (Fig 5).

The application’s tactical approach has allowed for a focus in the five key areas of improvement highlighted in Fig 6.

Results:

1. Durations of outages have been reduced by about 11% when comparing similar schedule scope items.
2. Savings have been recorded from about $115k to more than $400k, depending on comparative data.
3. A positive annual reliability impact exceeding $275k.
4. A reduction of outage-related work orders resulting from quality issues and reduced trips/forced outages because of outage quality concerns.

End notes. Takeaways from Broad River’s experience in outage planning include the following:

• Use a tool that allows the outage team to communicate easily and track progress—one that isn’t overly complicated and/or burdensome for a small staff.
• Do not reduce scope items to meet a deadline and call the outage “successful.”
• Collect data from the software that helps manage future outages better with the use of lessons learned, opportunities, and collaboration.
• Openly communicate to the owners and key contractors through a process that improves support, coordination, and results.

Project participants:

Malcolm Hubbard, plant manager
Joel McLain
Kevin Whitney

Broad River’s 2023 Best Practices

• Starting reliability on oil improves with filtration
• Rigorous planning significantly improves outage results