7F owner/operators capture five top Best Practices Awards

The 7F Users Group and CCJ are working together to expand the sharing of best practices and lessons learned among owner/operators of large frame engines. One of the organization’s objectives is to help its members better operate and maintain their plants, and a proactive best practices program supports this goal.

The editors presented a summary of the best practices submitted by 7F users in 2019 during the organization’s annual meeting at the Renaissance Schaumburg, May 20-24. The entries judged as the Best of the Best are profiled below. They were submitted by the plants identified in color in the adjacent chart. Best practices from the remaining facilities will be shared in an upcoming issue. More detail on this year’s best practices will be available in CCJ #61 (print quarterly), publishing in late September.  

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

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

Thumbnails of the five plants receiving 2019 Best of the Best awards follow (click plant name to access best practices content):

Effingham and Woodbridge have received several Best of the Best awards between them in previous years. You can access those articles at www.ccj-online.com by simply typing the plant names into the search function box on the home page (top right).

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Lawrenceburg: 2019 Best of the Best

Performance, flexibility upgrades boost profitability in dynamic market

Lawrenceburg Power operates in the PJM Interconnection. Plant owner Lightstone Generation wanted a reliable, cost-effective upgrade to simultaneously maximize capacity payments and align combustion and hot-gas-path (HGP) inspections at a 32,000-hr maintenance interval. 

The plant operates in a shale-gas region and can receive fuel from multiple sources that may contain high levels of ethane. Inconsistent fuel properties were identified as the expected root cause for some fuel-nozzle tip burnouts that caused forced outages on multiple units at the site. 

A challenge that Lawrenceburg faced was identifying upgrade solutions with predictable impacts on heat-recovery steam generators (HRSGs), the steam turbine/generator (STG), and balance-of-plant (BOP), as well as on startups and shutdowns of the power blocks.

Lawrenceburg Power entered into a long-term service agreement (LTSA) with PSM in fall 2017. In March 2018, Power Block 1 was shut down to implement the first two PSM FlameTop upgrades for addressing the plant’s operational challenges. FlameTop combines PSM’s FlameSheet™ combustion system (sidebar) and GTOP3.1 (Gas Turbine Optimization Package).

Converting the block’s gas turbines from DLN2.6 to FlameSheet combustion systems increased the allowable variation in the fuel’s Modified Wobbe Index (MWI) from 10% to 30%. 

The GTOP3.1 package, which includes upgraded hardware to increase compressor flow and reduce combustor pressure drop as well as the amount of turbine cooling and leakage air required, was installed on each GT to improve performance. 

FlameTop mode switching logic and AutoTune also were incorporated so the plant could both maximize peak-fire capability and achieve the desired 32,000-hr maintenance interval. PSM AutoTune provides real-time tuning of the gas turbine fuel splits to maintain stable combustion dynamics while managing gas turbine NOx production throughout the plant’s dynamic Ohio River Valley weather patterns.

Lawrenceburg Power engaged an engineering firm to review the new conditions that the upgrade might present to the HRSGs, STG, and BOP equipment. In addition, a steam-turbine contractor was used to perform a pre-outage performance test and to make recommendations on opening the diaphragm clearances to allow the expected increase in flow through the machine—a benefit of GTOP3.1.

The engineering firm also performed a review of HRSG purge times, eventually settling on a 6-min decrease to maintain required volume of air changeout. The 6-min reduction in purge time, together with the FlameSheet combustors not requiring a reduction of speed to flame and warmup but rather flame and warmup at purge speed, provides a significant reduction in start time.

A study was conducted using the site’s high-fidelity simulator to ensure changes in startup and shutdown procedures would not introduce a safety issue or cause equipment damage. Numerous simulated startups and shutdowns were performed by site personnel and PSM engineers to refine logic changes and minimize stresses on BOP equipment and the STG. New startup and shutdown procedures were developed prior to the first fire of the upgraded gas turbines.

By incorporating FlameTop, the plant gained nearly 11% in output in Peak 3 firing mode. Each GT upgrade was commissioned with six operating modes—including extended maintenance (40k hr), maintenance (32k), performance (24k), peak 1 (10 deg F over peak firing temperature), peak 2 (20 deg F), and peak 3 (30 deg F). 

Steam-turbine diaphragms were modified to accommodate the increase steam flow thereby increasing power-block output. Staff is managing operation in each mode to ensure that the HGP will occur at 32k actual hours of operation.

The site has realized significant ammonia savings (approximately 50%) because of the reduction in turbine NOx emissions attributed to FlameTop. The units also turn down an additional 10 to 15 MW as compared to pre-outage conditions and on a reduced isotherm which helps to maintain BOP equipment health while operating at minimum load. 

Commissioning of the upgrade confirmed simulated startup logic, startup procedures, optimized mode transfers, and refined fuel splits for stability. End result was a combined-cycle startup optimization that reduced start times by 30 minutes (hot) to 45 minutes (cold) without additional stress to the BOP. No hardware issues attributed to shale-gas fuel property swings have been noted since the FlameSheet installs.

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Training, automation, standardization streamline calibration processes, cut cost

Instrument calibration at Lawrenceburg Power was a labor-intensive process involving paper-based procedures resident in a Microsoft Access database. Based on a manual review and assessment of the calibrations required, a tool set could be assembled from the vast inventory of test equipment the plant maintained—including gauges, meters, decade boxes, etc.

Execution of a calibration required the technician to manage the multiple pieces of equipment while referring to the printed calibration procedures, determining pass/fail status, and recording the results on the hard-copy document. The documents served as the permanent record and were eventually stored in a physical filing cabinet.

Although this system worked, staff identified several problems with it, including the following:

    • User controls were non-existent, questioning data integrity.

    • A lack of standardization caused inconsistent calibration results.

    • Clerical errors were associated with hand-written records and the paper-based workflow.

    • Calibration was time-consuming, introducing the opportunity for process uncertainties.

Maintenance technicians at Lawrenceburg are all multi-craft and responsible for a wide range of daily tasks. Instrument calibration is just one of those assignments. For this reason, and the sheer amount of instrumentation the technicians manage—about 3600 components, 300 of which require critical calibrations during outages—they needed a data management system that was easy to implement and use.

Also, the responsible personnel wanted to standardize tools and reduce the considerable amount of equipment required and had to be maintained. Ensuring NIST (National Institute of Standards and Technology) traceability was an absolute requirement and had to be easily enforced.

To improve data integrity, the technicians aimed to minimize the opportunities to “cheat the system” or “pencil whip.” They also sought a solution that would provide a professional calibration certificate, audit trail, and provide analytics of the results—such as data trending and hysteresis errors.

The MC6 multifunction documenting calibrator from Beamex Oy Ab was the solution implemented. No matter who uses the system, the work is performed and results are recorded similarly, improving system reliability and confidence in the data. Additionally, the software allows printing of custom-designed calibration labels.

Thus far, the results have included the retirement of 80 measurement standards which saves a significant amount of money in recertification costs, implementation of a paperless system that is intuitive and easy to learn, improved data integrity and reliability, exposure of shortfalls in calibration of mission-critical instrumentation, and time saving of up to 50% on calibration work.

Plus, technicians were able to integrate some of the plant’s existing standards with the Beamex technology. Example: A HART Scientific temperature dry-block used with the MC6 to automate temperature calibrations. By using a more accurate system, technicians learned that many of Lawrenceburg’s switches and drum levels were out of tolerance, which could have caused an emergency outage and cost the plant dearly if not resolved quickly.

Metrology training boosts staff confidence in performing calibrations

Prior to implementation of Lawrenceburg’s new calibration process described in the text, plant personnel had no formal metrology training. This was conducive to inconsistent calibration results and made employees tasked with instrument calibration uncomfortable.

The plant had a large inventory of calibration equipment that required annual recertification and once recertified would sit in a drawer for up to a year. Technicians wasted time looking for the correct equipment, hoses, and fittings to perform calibrations.

Solution to the issue of inconsistent calibration results was to develop a training program so all technicians would gain a better understanding of metrology and perform calibrations in the same manner.

Another goal was to standardize tools and reduce the considerable amount of equipment required to be used and maintained, as well as to reduce the time it took to locate the proper equipment to perform the calibrations.

The second goal was achieved by arranging field calibration equipment in sets (two sets were made) and organizing them in the instrumentation shop for easy accessibility. Senior Technician Ron Cash designed and built a calibration test bench with all the necessary equipment to train technicians on calibration procedures.

One of the things he did was to convert all the field devices and calibration equipment to Ralston quick-test type fittings and then assemble two fitting and hose sets that will work for any calibration being performed.

Today, with technicians more comfortable performing their calibration duties, the accuracy and repeatability of results have improved markedly.

Fire-protection upgrades make Lawrenceburg a safer place to work

Lawrenceburg Power’s fire alarm system consisted of several alarm panels from different manufacturers, all integrated into a main panel in the control room. When an alarm was received it was time-consuming and difficult to distinguish what device triggered the alarm because of all the integration.

Staff decided to replace the entire fire alarm system with Notifier NFS2- 3030 panels, Onyx work station, new signaling devices, and speaker/strobes to have a fire/mass notification system that would meet NFPA 72: National Fire Alarm and Signaling Code.

The advantage of a mass notification system is that it immediately informs end users of a situation and how to proceed. Notifying occupants via the mass notification system is done by email, loud speaker/intercom, and graphics-board messaging using a message board from Light Engineered Displays Inc.

Lawrenceburg’s mass notification system is used for any emergency application—including fire, weather, natural-gas leaks, chemical spills, medical emergency, intruder, terrorist situations, generation alerts, start/lunch/stop times, etc.

When an alarm comes in today, the operator’s screen automatically changes to the screen where the device is located, the device flashes and changes color based on the event, and the message is displayed and played over the system. The message tells you the type and location of the situation and informs everyone except the responders what to do and where to report to. The operator can just look at the screen and know which area and device that he/she needs to direct the responders to.

The system is set to alarm a minimum of five times; it alarms on a fire and gas leak until reset by the operator allowing offsite responders the ability to see the location and type of event on a display board as they enter the property. Lawrenceburg’s fire detection/mass notification system monitors the control room, electrical rooms, transformers, black-start generators, gas turbines, etc. The detection systems used are heat, smoke, and combustible gas; the plant controls FM-200, CO2, dry pipe, deluge and pre-action fire suppression systems, and monitoring of wet-pipe systems.

The second part of the project was to replace the gas-turbine Chemetron Fire Systems Micro 1 EV control panels. Chemetron had discontinued repairing the Micro 1 EV control boards in April 2008 and obsoleted the product shortly thereafter. The plant had four of these panels and previously had experienced a CO2 dump because of a failed control board.

With few spare parts available, Lawrenceburg received some spares from its fire service vendor which had been taken out of service at other locations. The plant had experienced many false alarms from these systems. They had limited memory and when not properly cleared out and fully reset would sound the alarms.

An issue with many GE 7EA gas turbines installed in the 1990s and early 2000s is that the 45FTX fire protection shutdown relays are wired in parallel. These seven (or nine) 120-Vdc relays located in the PEECC (packaged electrical and electronics control compartment) fire- protection relay cabinet, activate from the each of the Chemetron fire-system control-panel Aux 1 relays and from the Chemetron discharge pressure switches.

A problem occurred in some locations where repeat actuation of this circuit during a routine CO2 inspection damaged the Aux 1 relay base because of the momentary excessive current draw of these seven (or nine) relays. The Aux 1 base, soldered to the main Micro 1 integrated-circuit board, cannot be replaced in the field, thereby requiring a complete Chemetron Micro 1 control panel replacement, which is no longer available.

Staff was concerned this could be a possibility on Lawrenceburg’s 7FAs as well, and the plant replaced them with the same Notifier NFS2- 3030 panels used in the fire alarm system described earlier. New wiring and some conduit also was installed because of the extreme heat this equipment is exposed to. This was integrated into the main fire control panel and it also populates on the Onyx work station.

The final part of the upgrade was to install pre-discharge pneumatic time-delay systems on each of the gas-turbine CO2 systems in accordance with NFPA 12. The 2005 edition of this standard requires the implementation of pneumatic time delays and pneumatic pre-discharge alarms into both new and existing CO2 extinguishing systems where the agent is introduced into normally occupied or occupiable spaces.

Dryers improve performance of hydrogen-cooled generators

Most manufacturers of hydrogen-cooled generators recommend having dryers to remove moisture from the gas. When wet, hydrogen loses its beneficial properties for generator cooling, becoming more dense and increasing windage losses. These losses take the form of additional heat production during generator operation and increased fuel requirements to generate the same output.

Moisture also reduces the ability of the generator gas to remove heat from the system, the specific heat of water vapor being lower than that of hydrogen. Recall, too, that some generator failures have been tied directly to moisture in the unit. Perhaps most notable were the failures attributed to stress corrosion cracking in the retaining rings. However, there are other failure modes either caused by, or enhanced by, excessive moisture in the generator.

Lawrenceburg Power’s six hydrogen-cooled generators were supplied without dryers. An in-situ robotic inspection of one gas-turbine generator in one of the two 2 × 1 power blocks revealed red dust on one side of the core iron while the robotic trolley was moving axially down the length of the bore. The dust was found in what appeared to be concentric bands spaced at certain locations down the bore.

In 7FH2 generators like those at Lawrenceburg, such bands of red dust typically are indicative of belly-band looseness.

Hydrogen coolers were removed from the generator to inspect the back-iron condition and get a better assessment of how loose the core iron was. The inspection was not confined to where the heaviest concentrations of red dust were identified during the in-situ inspection, but rather to assess the overall condition of accessible core laminations.

The inspection photos revealed red rust in different slots and in different positions of the robotic trolley as it took pictures. These slots all reveal red dust at approximately the same location and position, indicating rings (most likely where the belly bands are located).

After removing the hydrogen coolers on one of the two gas turbines being inspected, the belly bands were checked for tightness. None was found out of spec. With no looseness observed with the knife check, staff concluded that the rust indications were likely from moisture collecting in those areas over the history of the plant.

The plant leadership team decided to forego further testing on the second gas-turbine generator and worked with supplier Lectrodryer to install hydrogen dryers on the power block’s three generators during the outage.

Since installation of the dryers, the plant has been able to maintain a hydrogen dewpoint of minus 20F to minus 50F on all three generators. EMI testing on the generators recently confirmed improvement over testing in prior years, with the only modification being the addition of the dryers. Lawrenceburg was scheduled to install the same dryers on the three generators in the second power block during spring 2019.

Burner management system upgrade improves reliability, facilitates troubleshooting

Design of the burner management systems (BMS) supplied with Lawrenceburg’s HRSGs were difficult to troubleshoot when a component failed, causing longer-than-expected downtimes and added repair cost. Compounding the difficulty, the original Fisher 399A regulators were obsolete.

The system safety design incorporated two “slam-shut” stop valves and a vent valve (double block and bleed) on the pressure reducing station. If the BMS became unstable and a trip initiated, the slam-shut valves would close and the vent would open. This would stop the gas flow instantly, causing system backpressure to spike. By design, the regulator diaphragm is in the flow path and when subjected to high backpressure it was the most likely component to fail.

Cornerstone Controls Inc, an Emerson partner, was contacted to review the BMS failures. Working together, Lawrenceburg and Cornerstone personnel determined that the Fisher 399A regulators should be replaced based on how the BMS station operates. The solution selected was two Fisher EZH pressure-reducing regulators. In addition, the system required one Universal Vortex dual-path pilot-gas heater and one Fisher 627 regulator.

The new pressure-reducing station is configured as a “wide-open monitor.” In this arrangement, the upstream working regulator controls system outlet pressure. The downstream monitor regulator senses a pressure lower than its set point and tries to increase outlet pressure by going wide open.

If the working regulator fails, the monitoring regulator takes control and holds the outlet pressure to the outlet-pressure setting. The EZH regulators have metal trim and are not affected by system trips. The piping system also was redesigned to allow for easier troubleshooting.

Since the BMS was upgraded, gas pressure is more stable and the plant has had no failures associated with the burner management system.

Switch to self-contained hydraulic valve operators improves turbine-bypass performance

Top performance from steam-turbine bypass systems during startups, shutdowns, and trips at combined-cycle plants is critical for achieving the operating-flexibility and availability goals critical to the plant’s financial success.

Lawrenceburg Power uses a triple-pressure cascading bypass system which helps in managing thermal imbalances between the gas turbines and heat-recovery steam generators in cycling scenarios. It includes high-pressure (HP), hot-reheat (HRH), and low-pressure (LP) bypass valves.

In this control scheme, the HP bypass valve maintains HP pressure to minimize thermal stresses on the drum. The HRH bypass, downstream of the reheater, maintains HRH header pressure, and reduces steam pressure/temperature to the condenser. Finally, the LP bypass valve maintains LP drum pressure and protects the condenser by reducing LP steam pressure/temperature to an acceptable exhaust condition.

The pneumatic actuators supplied with the turbine bypass valves were problematic, sometimes even failing to operate on a trip. Plant personnel noted that some of the actuators had multiple volume boosters and the oscillations were “ridiculous.” Before the unit was able to settle out, the control system was already calling for the valves to move to a new position. Think of the valves as being in perpetual motion.

Reheat pressure oscillations caused by pneumatic-actuator stiction, overshoot, or dead time cause significant fluctuations in HRH header pressure. Because of the sluggish performance with the TBS blending the lead and lag units it regularly took 3.5 hours for a warm startup.

After reviewing alternative actuators, staff decided to move away from pneumatic actuation in favor of REXA self-contained hydraulic operators. Personnel originally were skeptical about moving to a hydraulic medium because of issues experienced with oil cleanliness in the past, but they liked the compact/sealed design of the REXA product and were sold by the fact that there were no filters and no requirements for oil maintenance. The new actuators were installed on the existing valves as a drop-in-place solution. Performance improvement was noticed within minutes after the first startup.

Lawrenceburg effectively reduced its blending time by 80 minutes for a warm start. The blending scenario occurs between five and 50 days annually (or greater depending on the market), reducing fuel consumption and increasing operating time. Better control of steam pressures and temperatures also promote longer life for the HRSGs. 

Trip events associated with the turbine bypass system, common with the original pneumatic actuators, have been eliminated completely. The new actuators operate with zero overshoot or hysteresis, and their response is virtually instantaneous after initiation of the command signal. An added benefit is extended trim life in all turbine bypass valves because the actuator is now driving the plug to the correct seated position.

Geodesic domes over clarifiers minimize contaminant ingress, evaporation losses

Chemicals was one of the biggest expenses for Lawrenceburg’s water treatment plant, with purchase and delivery costs running into the hundreds of thousands of dollars annually.

Another big expense was related to the failure of bearings for the plant’s clarifier rakes, which occurred several times. When a bearing failed, Lawrenceburg would curtail power production, thus reducing revenue. Plus, bearing replacement, which could take several days, was expensive considering the man-hours involved, cost of the new bearing, the time to drain the clarifier and remove the sediment, the cost of renting a crane, etc.

Disassembly of one of the failed rake bearings revealed that the failure was caused by water and contaminant ingress, not over- or under-greasing as might be expected. The clarifier design allowed rainwater to collect in the bearing area with no means of escape. A historical review of other equipment in the immediate area revealed that there have been repeated repairs in the past because of environmental factors.

In their review of the water treatment plant, staff discovered there was a huge loss of sodium hypochlorite (NaClO) from the clarifiers because of evaporation.

Installing geodesic domes over the clarifiers was a promising way considered by staff to reduce evaporation caused by the sun and wind. Plant personnel worked closely with manufacturer Ultraflote LLC’s engineers and agreed on a dome design suitable for Lawrenceburg.

Bottom-line improvement: The domes have reduced the annual consumption of sodium hypochlorite by 40%, saving tens of thousands of dollars. The domes also have eliminated the loss of generation caused by premature failures of the rake bearings and surrounding equipment.

Lawrenceburg Power LLC, owned by Lightstone Generation and operated by Consolidated Asset Management Services (CAMS), is an 1186-MW facility in Lawrenceburg, Ind, equipped with two 2 × 1 combined cycles. Plant manager is Mark Johnson.

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Effingham: 2019 Best of the Best

Effingham County Power, owned by The Carlyle Group and operated by Cogentrix Energy Power Management, is a 525-MW plant in Rincon, Ga, equipped with a 2 × 1 combined cycle. General manager is Bob Kulbacki.

Reduce imbalance and variance charges with consistent plant operation

Effingham County Power was awarded one of the eight Best of the Best awards presented in 2019, bringing its total to seven since 2010. No other plant has received more than five. What’s particularly noteworthy about Effingham’s run is that it has spanned three owners, four plant managers, and several teams of judges. The only common denominators are ties to its former operator, CAMS—Consolidated Asset Management Services, and an empowered staff that embraces a process of continuous improvement.

Effingham’s owner back in 2010 was Progress Energy Ventures, then came ArcLight Capital Partners (with minority partners GE Energy Financial and the Government of Singapore), and now The Carlyle Group.

Plant managers over the last 10 years: Eric Garrett, today Senior VP Operations for CAMS; Ken Earl, now VP Operations for eastern plants in the CAMS portfolio; Nick Bohl, currently the CAMS plant manager for Competitive Power Ventures’ (CPV) St. Charles Energy Center, a 2 × 1 combined cycle powered by 7F.05 engines; and the incumbent, Bob Kulbacki.

The first of Effingham’s 2019 best practices shared in this issue of CCJ ONsite follows:

During commissioning of Effingham County Power, procedures were developed for hot, warm, and cold starts based on steam-turbine first-stage metal temperature.  Suggested generation tags were provided to the plant along with the startup procedures. 

Over the years, staff learned the generation tags didn’t apply to the entire temperature range of the three types of starts. For example, the temperature range for warm starts extends from 450F to 750F. The amount of time to start up is affected by temperature and if an improper generation tag has been approved, the plant could incur imbalance and variance charges. 

Because warm and cold starts are not performed frequently at Effingham, personnel wanted to develop a template for conducting these startups—one that would ensure repeatability and contribute to lower costs. Reducing startup costs is a priority at merchant plants like Effingham. This can be done by reducing startup time, thereby saving gas and the amount of ramp energy sold to off-takers.

Having several established ramp profiles for the starts performed allow for the operators to submit accurate daily status information to the trading floor. The ramp profiles also can be provided to off-takers when developing power contracts so they are aware of the plant’s different startup scenarios.    

Another issue encountered was how various conditions affected hot starts, which Effingham performs about 95% of the time. These conditions included executing a hot start with a depressurized HRSG, a cold HRSG following maintenance, and an extended amount of time between hot starts. Staff found that using the same ramps for these different conditions could lead to imbalance and variance costs or improper warming of a cold HRSG.

Since warm and cold starts are performed infrequently, staff knew it would be a long process to develop accurate ramps for various temperatures. A log sheet was developed which listed the type of start, amount of time in shutdown, and the steam-turbine first-stage metal temperature. Along with these data, the operators were tasked with listing the time they performed crucial steps of the startup. 

Ramps used for the startup were recorded along with recommended ramps for the next start. The operators also listed any lesson learned during their startup so that the issue could be avoided during the next time. 

All the data sheets were reviewed and saved on the shared drive for each operator to review prior to performing a non-routine start. After several startups with similar start conditions had been performed, staff developed a guide with times for all operators to use and fine-tune. The leadership team continued to review the non-routine starts and once the goal of reducing startup time and imbalance charges was achieved, these ramps were published on a spreadsheet and provided to the applicable groups associated with generating and selling power for the plant.

In documenting starts versus start temperatures, staff was able to develop several warm ramps that were applicable to a wide temperature range. With this information, the Effingham team developed lower-, middle-, and upper-range ramps which were useful for the complete warm-start range. Ramps also were developed for hot starts with a cold HRSG, since the starts differed when a cold HRSG was involved.

This project spanned several years and is re-evaluated each time a non-routine start is performed. The ramps developed have benefitted management and operators involved in providing plant-specific data to outside organizations. Effingham is responsible for submitting a daily status to traders, which includes ambient temperatures, maximum generation, and the startup ramps. 

Most of the plant’s starts are hot and the ramps don’t vary with the short shutdown time. As the amount of time the plant is offline increases, the steam-turbine first-stage metal temperature decreases more. This requires adjustment of start ramps to assure the plant is warmed up within established thermal limits.

Having the required data available in a convenient spreadsheet allows for Effingham to provide requested ramps quickly when called by the traders or corporate engineering. An additional benefit of this project has been more consistent plant operation because of the guidelines provided operators for non-routine starts.

The result: Imbalance and variance charges have decreased while performing plant starts in accordance with procedures developed in-house.

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Don’t forget to verify the ability of HRSG feet to slide

There was a very audible popping sound emanating from Effingham County Power’s HRSGs during unit startup. The cause: Binding of the units’ grease-starved sliding feet during casing expansion. The sliding feet are 40 × 18 in. and they had only two grease zerk fittings—one per side of the webbing in the center of the foot.  

The absence of machined passageways to transfer the grease to the outermost areas of the bearing pad was the root cause of the issue. After years of cycling and the extreme pressure exerted on the bearing pads, the grease had formed its path of least resistance: It remains in the center of the sliding feet, forcing about 90% of the bearing-pad surface to be metal-on-metal. Thus, the feet are not able to slide freely while the HRSG expands and contracts. 

Once the HRSG begins to grow thermally, pressure is exerted on the sliding feet causing them to bind. When the pressure is high enough to cause the sliding feet to move, a loud noise results and HRSG components are subjected to mechanical shock.

The first corrective action: Remove any trapped grease from under the feet. The thought was that if there was old hardened grease in this area, it could be blocking the addition of fresh grease to the feet. The plant used a pressure washer to remove the grease which was collected and disposed of properly. However, after adding fresh grease, the noise was still present after startup.  

Staff contacted the HRSG OEM to obtain drawings of the sliding feet to verify if the undersides of the feet were channeled or flat. After discussions with the vendor, it was determined that adding more zerc fittings to the feet was the best solution for the problem. The feet located between the stationary support and the turbine were the first to be modified because this section had the highest growth rate of all the HRSG sections.

Two holes were drilled and tapped into the HRSG feet and zerc fittings were installed. The new holes are located in the far corners of the feet, off-center of the existing zerc fittings. This new configuration has a zerc fitting on all four sides of the sliding feet. With four zerc fittings, the grease is distributed throughout the bearing pads allowing proper lubrication. 

The benefit of this best practice is that the sliding feet are operating properly. Since the new zerc fittings have been installed, and grease is being distributed to the entire bearing surface, the popping sound following startup has not been heard. By decreasing the stress on the HRSG and letting it grow as designed, Effingham will save a substantial amount of money in weld repairs—and likely extend the lives of its boilers. 

Fans extend the lives of HRSG lower penetration seals

Effingham County Power was replacing failed penetration seals in the floors of its heat-recovery steam generators (HRSGs) about annually. The plant’s two HRSGs are arranged with two headers, each serving four seals. Replacement of the plant’s 16 seals costs about $100,000 in materials and labor.

During each overhaul, cracks were discovered adjacent to the seals. No one could determine if the cracks were caused by the failed seals or if the cracks caused the seals to fail. Certified welders were brought to repair the HRSG casings before replacing the seals—at an additional cost of $50,000 to $75,000 depending on how extensive the cracks were. 

After the 2018 spring outage, new penetration seals were installed and the HRSG casings were repaired. The seals replaced had failed after only about 500 hours of service—cause unknown. Supplier of the penetration seals sent technicians to inspect and replace the damaged components. They determined that the premature seal failures were caused by casing cracks blowing hot flue gas onto the seals. 

Investigation revealed casing insulation had deteriorated, exposing the metal to gas-turbine exhaust gas. This caused the HRSG floor to buckle, warp, and crack, allowing the gas to escape and damage the lower seals and the casing. The temperature around the seals was roughly 850F; the maximum design temperature for the external side of the seals was only 700F.

In April 2018, Effingham installed three external blowers and associated ductwork on each HRSG to provide cooling air to the seal area. The cost of the three blowers and ducting to the seals was $1600 per HRSG. The blowers are driven by 120-Vac motors that are plugged into a plant receptacle. The auxiliary operator verifies the blowers are in service prior to the plant startup. He also checks that the blowers are running during rounds; the fans are de-energized when steam is no longer in the HRSGs. 

The plant established a PM to check temperatures in the area of the seals weekly. A spreadsheet was developed to track the temperature scans, which are reviewed to verify the integrity of the seals. 

After the installation of the blowers and ducting, the area under the HRSG is cooler allowing personnel access to the blowers and seals. The seals are easy to inspect and to determine if they are starting to fail by observing any color changes in the seals’ outer material.       

There was a forced maintenance outage to repair the HRSG casing and replace the damaged seals. Several engineers inspected the area and determined excessive heat had damaged the HRSG casing and that it had to be replaced. Several vendors were contacted to bid on the replacement.   

The blowers and ductwork reduced the temperature in the seal area by 250 to 300 deg F. While the blowers have been in service for only a year, they have extended the lives of the lower seals. This allowed plant dispatch through the critical summer run season, increasing Effingham’s bottom line.

Casing replacement and new lower penetration seals are scheduled. After all work is complete the blowers and ducting will be reinstalled and operated to extend casing life.

Logic change increases gas-turbine reliability

Effingham County Power’s two gas turbines were supplied with a single duct-pressure transmitter for information only; exhaust-duct pressure was protected by three hardwired switches. One switch was arranged to alarm on the control-system HMI when its set point was exceeded. Set points for the other two switches were set to provide a trip signal to the control system. If two out of three set points were exceeded, the unit would trip.     

Since the trips typically occur when the unit is fully loaded, possible mechanical damage can occur. Also, there can be significant monetary cost to the plant because of the loss of generation from this event. 

Staff discovered the pressure-switch set points would drift because of gas-turbine vibration and changes in ambient conditions.  In 2016, the plant experienced several GT trips because of high pressure in the exhaust duct. After each trip and prior to restart, the switch set points were checked; in all cases they required adjustment to the correct value.

The plant’s short-term solution was to change the tubing to all three switches to allow checking of the set points with the unit online or offline. The increase in frequency of checking the set points helped to increase the unit’s reliability.

There was little time for the operator to take action when the set point was exceeded until the trip signal was received. This was observed several times when there were storms in the area causing changes in ambient pressure. Based on this observation, controls engineers were asked to add feedback logic to the system that would allow the GT to reduce exhaust-duct pressure by reducing load automatically without initiating a unit trip.

Staff discussed the Effingham plan with the GT and HRSG OEMs and determined the maximum allowable exhaust-duct pressure to prevent component damage. Once this value was determined, runback and alarm set point values were selected. 

A third-party controls engineer was engaged to review the plan and design the necessary logic. The only way this change could work was to swap out the pressure switches with transmitters, which was done by plant personnel during the fall maintenance outage.

Once the control-system logic change was made and tested, the units were dispatched; no issues were encountered.  Transmitter outputs are displayed on the HMI control screens for operators to monitor when the units are online.

There have been several instances this past year in which the plant has been operating at the alarm set point with the units not in baseload service. In an attempt to maximize output, the load was increased. This increased exhaust-duct pressure, with the runback set point and the control system reacting as designed and reducing the unit load below the set point. 

Effingham is charged $150/MW for lost generation. Typically, the unit trips when fully loaded which results in a financial penalty of approximately $15,000 per occurrence. Total cost of replacing the switches with transmitters and the logic change was $13,500. In 2016 the plant tripped three times on high exhaust-duct pressure. Since the logic change was implemented, it has not tripped on high exhaust pressure.

Land application: A practical way to dispose of cooling-tower blowdown

Effingham County Power’s evaporative cooling tower blows down its high-conductivity water into a 2-million-gal holding pond. This water then is sprayed on land in the area of the plant in accordance with Georgia Dept of Natural Resources operating guidelines. The system has five Bermad 720-55 control valves, each serving a different irrigation zone. Valve operation is controlled by programmed logic to ensure the system operates within permit limits.  

The valves had recurring issues related to the clogging of sensing and control lines with algae and sediment. Adding to the challenge, the valves are located in underground vaults usually filled with at least 5 ft of water because of the wet environment.

By design, this style of control valve receives system pressure at the top of its diaphragm, which fully closes the valve. The fouling problem arises because the line that closes the valve deadheads at the top of the diaphragm and over time and mud and algae accumulate in low flow areas conducive to plugging.

When an operator finds a zone is not operating correctly, he/she has to isolate the zone and flush the lines manually from an available above-ground source.  This ultimately does not completely flush the system because of its location and design.

Effingham’s solution was to pump down each vault, then detach sensing and control lines and free-up the blockages. Next, install a new line on the top of the valve, above the diaphragm, and run it up and out of the control-valve vault. A ball valve was added for manual flushing, which was added to the existing monthly PM tasks for the system. All work was performed by plant personnel. 

The operators reported increased system pressure after completion of the modification, indicating the zones not in service were fully closed. Operators also walk down the system during operation to confirm all zones are working correctly. This means individual zone discharge limits can’t be exceeded because of malfunctioning control valves. 

The zones have not required flushing outside the normal monthly PM schedule since implementing the best practice. This has contributed to more-reliable operation of the land-application spray system and eliminated the labor required for periodic manual flushing of the five zones.

Chemical unloading checklists help avoid accidents

Almost every type of plant that receives, stores, and uses chemicals has procedures for checking in and transferring the products to onsite storage. The reality is the procedures often are on a shelf or a shared drive. Typically, they are lengthy documents that don’t get printed or carried into the field when operators are multi-tasking.

There have been several incidents in which the delivery truck was connected to the incorrect storage tank or improperly lined-up for the unloading process. If the wrong combination of chemicals is mixed together the result can be an unsafe situation for personnel at the plant and the nearby community.

Since deliveries to the plant can happen at any time, at Effingham County Power the auxiliary operator is the individual generally assigned to monitor the unloading process. Once the tanker truck arrives onsite, there is a limited amount of time to unload the chemical before incurring additional costs. Therefore, it’s important that the operator report to the unloading area, brief the driver, and verify the chemical and the line-up are correct. 

To ensure the unloading evolution is performed safely and correctly, an approved checklist should be used as guidance. The checklists are saved on the company’s shared drive for easy access. It takes time to retrieve the checklist and report to the unloading area. Drivers are prevented from starting the process, possibly leading to additional costs. 

Both plant management and operations recognized a need for a better and safer process. The solution was to preprint chemical unloading checklists and keep them at the chemical offloading areas in a weather-proof container. 

With this improvement, the correct checklist is available at the point of delivery. It includes both verification of product and destination; also, pre-transfer equipment checks for both transfer equipment and safety equipment—such as wheel chocks and safety showers. 

Once all the checks are complete, the auxiliary operator and truck driver sign the checklist to acknowledge all checks have been performed and it is safe to commence the chemical transfer. Once the transfer is completed and the truck has departed the site, the checklist is attached to the all the paperwork associated with that chemical. If there is an issue with the evolution, the names of all involved with the transfer are available to conduct an investigation.

The preprinted checklists have been popular and successful. The plant operators don’t have to scramble to find the paperwork. The checklists include all pre-delivery checks and notifications necessary to meet the procedural requirements and assure safe chemical transfer.

By having the driver and auxiliary operator sign the checklists, there is an added insurance that they are performing the evolution correctly. Since having these checklists at the unloading areas, the amount of time that the delivery trucks are onsite has been reduced. Implementing these checklists and storing them at the unloading areas has resulted in no safety observations being discovered during transfers.

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Woodbridge: 2019 Best of the Best

High-energy-piping program simplifies inspection, recordkeeping

Like any new facility, all of the programs and procedures needed to operate and maintain Woodbridge Energy Center had to be created from scratch. One, the High Energy Piping Program (HEPP), immediately stood out to the plant team as an area that could benefit greatly through customization and simplification. The challenge was how to make a relatively complicated and lengthy program efficient and easy to understand by operations personnel while creating a sense of ownership through participation

HEPPs have two main goals: Safe operation of the site and long-term reliability of the plant’s piping systems. To achieve these goals at Woodbridge, its 22,000 ft of piping was broken down into 495 data points (425 pipe supports and 70 welds). Those data points were then condensed into a form making inspections easy to perform, understand, and track over the life of the site. Typically, this area is where most HEPPs fall short because of the massive amount of data needed for inspection and formatting of the results.

Team Woodbridge decided the first area to go after was the actual inspection form itself. With the goal being a form that was visually easy to follow and understand, Plant Engineer Michael Armstrong took the general arrangement drawings for the different piping systems and added indexed markings showing the location of the hangers (Fig 1) and welds (Fig 2) included in the program.

The last hurdle was the clear and concise presentation of the inspection results. A spreadsheet was developed (Fig 3) that listed the index numbers from the referenced drawings along with related design information (pipe size, pipe support ID, growth direction, plus support type, symbol, and stiffness) for each pipe support/hanger. It also included a section for hot readings, cold readings, and comments.

This enabled the individual performing the inspection to take the annotated piping system drawings with the inspection forms and walk down each support/hanger easily and efficiently.

Regarding weld inspections, a similar sheet was developed; however, the site team is not trained to perform the vast array of necessary inspections so the drawings and inspection forms are provided to the third-party contractor prior to starting work.

The bottom line: An otherwise complex program was developed into an efficient and easy-to-understand process that (weld inspections excluded) the team can self-perform. The ability to self-perform the hanger inspections already has proven valuable when issues were discovered by plant staff that likely would have gone unnoticed by contractors not familiar with the site. Being able to catch these problems in-house greatly increased the team’s confidence in its own ability to quickly identify issues without having to comb through multiple levels of contractor-provided documentation.

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Mods to haz-gas-analyzer blowback system eliminate alarms, runbacks

The 7FA.05 gas turbines at Woodbridge Energy Center were constructed with a new style of hazardous-gas detection system. It uses instrument air and an aspirator to pull air samples from two different compartments on the unit through dedicated LEL (lower explosive limit) sensors.

The LEL sensors have the capability of shutting down the turbine should two sensors in either compartment go into a state of alarm, which is defined as high LEL readings and/or a loss of sample flow through the LEL detector itself. The latter had caused numerous runbacks and required daily attention in order to stop loss-of-flow alarms from coming in constantly.

Initially, one, or both, of the filters installed in each of the sample lines was the suspected cause of the problem. After going through every combination of filter design and mesh, plus a short stint without filters, the issue persisted. Eventually, the opportunity arose to take the entire system offline, allowing the site team enough time to blow high-pressure instrument air back through the sample lines to clear them of any debris left over from construction.

Much to everyone’s surprise, this stopped the alarms from coming in for several months before they slowly started becoming a part of the daily routine once again. At this point, it appeared as though the solution was as simple as a finer mesh sock filter on the end of the sample probe. Unfortunately, that filter was/is not available from the OEM and any attempt by the site team to create its own filter ended with loss-of-flow alarms caused by the inability of the aspirator to create a sufficient amount of vacuum on the system.

Until a better aspirator and/or filter design became available, the solution to the loss-of-flow alarm issue was to blow back the sample lines quarterly. This process is neither quick nor easy given the location of the analyzers and their OEM’s tubing configuration. The analyzers also must be taken out of service for an extended period during this process—not ideal because the unit primarily operates at baseload.

To expedite the process of clearing the sample lines, the plumbing had to be reconfigured. The first step was to bring a permanent source of instrument air to the area just upstream of the particulate filter mounting block. This eliminated the need to run temporary air hoses for the blowback process over extended distances.

Once this air supply was sourced and brought into the area, the OEM-installed compression fittings were removed in favor of a quick-connect style. This allows the technicians to quickly move the lines from their normal line up into the blowback configuration. A ball valve was also installed as a means to block and control the air flow during the blowback process.

After implementing the changes, the blowback process was reduced from a several-hours-long task for each gas turbine to one that takes no more than a few minutes. This reduction in analyzer downtime has allowed the site to perform this work while the plant is in operation with minimal risk of an inadvertent runback.

Lastly, now that the process is quick and easy, it is being performed monthly and has completely eliminated the loss-of-flow alarms that had plagued the site for over two years.

Qualification Card University underpins in-house training program

As Woodbridge Energy Center began its third year of commercial operation with a very low turnover rate, it was faced with an unexpected problem in terms of continuing education for staff. After initial training, employees have access to the CAMS Workforce Development Program, which offers a combination of online and hands-on training programs in craft skill areas—such as mechanical, electrical, I&C, and auxiliary operations.

Though most personnel had completed a majority of the training programs, very few had completed all of the training necessary for their Qualification Card. Since Woodbridge is operating at a high capacity factor (nearly baseload), it does not provide sufficient time for learning opportunities that do not interrupt the workflow and routine. Therefore, team members were not able to easily re-engage with training material nor provide additional opportunities for training new hires because of the time constraints.

To address the problems of staff engagement, new-hire training, and the lack of down time, a new training program was introduced: Qualification Card University (QCU). This training program is led by a “professor” (Production Manager Justin Hughes), uses a set class schedule, and provides a group learning atmosphere.

Initially, the class was held for two hours every Friday afternoon with the weekly topic being chosen off of the Auxiliary Operator Qualification Card. The topic was rotated frequently a means to provide fresh and ever-changing content to the team members who already completed their qualifications, or nearly so. It also provided a means of covering a broad range of content areas for recent employees just starting out in the qualification program.

By the end of the first month of QCU classes there was a dramatic increase in class participation, especially during the 20-min open discussion period at the end of the main lesson. This led to a few classes going well beyond the two-hour mark, and it also kick-started the Workforce Development Program to the point that there was a waiting list for employees to perform their final checkout exams for the various craft skill areas.

While both of those results were beyond expectation, the real measure of overall program success came at the end of the year. An extended fall outage forced classes to be put on hold for a few months until the team was surveyed at the year-end safety meeting. Personnel were asked to respond to this question: “What can the management team provide employees to make their careers and overall time at the site better going into 2019?” The overwhelming response to this question: Bring back Qualification Card University.

The program was restarted the second week of January 2019 and has already been expanded (at the plant team’s request) to include topics outside of the written portion of the QCU program—such as hands-on training, “field trips” around the site to various pieces of equipment, and “guest speakers” from the plant team. By blocking out and dedicating two hours each week while also creating a group learning environment for the entire staff, QCU doubled the craft skill area completion rates and reignited the team’s enthusiasm for continued learning.

Portable fire-extinguisher improvements make for a safer workplace

Combined-cycle facilities require a portable fire-extinguisher program to meet NFPA 10 requirements. Production Team Leader Ray Melcer reviewed the existing portable fire-extinguisher program at Woodbridge Energy Center and identified areas needing improvement.

The review found fire extinguishers without adequate signage and not in the normal path of travel, which created inefficiencies during the monthly inspection process. Furthermore, many extinguishers and inspection tags were exposed to environmental conditions, resulting in degradation over time.

The first issue tackled was meeting the locational requirements and ensuring the extinguishers were in the normal path of travel with the appropriate signage. The team ended up relocating 15 of the 68 portable fire extinguishers in the field to meet NFPA 10 requirements. This action ensured fire extinguishers were not obstructed or obscured from view.

The team also placed 47 new signs above fire extinguishers to raise awareness of each extinguisher’s location. The monthly inspection checklist also was amended to capture the proper order in which fire extinguishers were inspected throughout the facility.

To address the environmental issues and to promote equipment longevity, team members installed covers on each outdoor portable fire extinguisher. They go on over top of the extinguisher, protecting it from weather, cooling-tower plume, etc. The covers are relatively inexpensive ($15 each) and are easily installed and removed via a Velcro strap. The easy removal of each cover allows for quick fire-extinguisher use during times of need. The covers are a bright red color and increase visibility of where each extinguisher is located.

The team also purchased aluminum inspection tags to replace the standard paper inspection tags. Only slightly more expensive than the paper, these tags hold up against wear and tear and help demonstrate compliance during annual fire-protection audits by local authorities.

The team successfully implemented portable fire-extinguisher best practices that strengthened NFPA 10 compliance and improved safety. By rearranging where the fire extinguishers are located in the facility and raising awareness through signage, the team enhanced the visibility of a critical safety resource. This also shortened the time to complete the monthly checklist by one or more man-hours.

Moreover, the team’s effort improves longevity by installing individual covers and changing out inspection tags to something more durable. This project cost less than $1000; payback was projected at six to eight months through equipment resilience and saved man-hours.

Woodbridge Energy Center, owned by Competitive Power Ventures and operated by CAMS, is a 725-MW outdoor facility in Keasbey, NJ, with two 7FA.05 engines powering its combined cycle. Plant manager is Chip Bergeron.

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Elwood: 2019 Best of the Best

Developing the next generation of multi-skill employees

Elwood Energy started commercial operation in 1999. In 2012, prior to the plant’s first ownership change and exit from a PPA environment, the leadership team realized it would have to develop its next generation of employees. Few job candidates with suitable experience demonstrated sufficient promise to thrive in a multi-skill position.

Retirement and attrition left Elwood with only four of its 13 OMTs (operating/maintenance technicians). Opting for potential over experience, based on early success with a developmental program, the nine candidates hired had either a two- or four-year degree, but minimal relevant experience. Now five years into this program, the average age of the group is 27, with relevant experience averaging four years.

Elwood Energy operates in the PJM capacity performance market where performance is rewarded and failure to perform can be very costly. One hour of unplanned outage for one unit can vary from $35,000 in lost capacity payments to $600,000 in penalties during a capacity performance event. For a PJM peaking facility typically operating a unit 400 hours annually, every hour troubleshooting a failure to start can be very costly.

An employee who can work through an issue in two hours can be much more valuable than a less capable employee requiring six hours. Developing a dedicated competent multi-skill staff of OMTs is essential to maintain equipment reliability as well as to promptly resolve equipment malfunction.

Critical to success were the following actions, among others:

  1. 1. When candidates with demonstrated progressive and relevant work experience are not available, seek out and recruit those with a demonstrated potential to learn. Recruit candidates with two- to four-year degrees who have a demonstrated good work ethic and high aptitude for electrical, I/C, and mechanical maintenance. Offer part time work to promising candidates still in college.

  2. 2. Put emphasis on retaining experienced employees. Leverage their experience across your developing employees at every opportunity. Success in developing your future generation of employees requires experienced working supervisors who enjoy developing others.

  3. 3. Ensure your highly experienced employees can delegate and control increasingly complex skills as employees’ capabilities increase. The highly experienced employees may need growth assignments as well.

  4. 4. Develop a qualification program that captures the operational and maintenance skills and knowledge expected of OMTs.

  5. 5. Provide well-considered annual performance appraisals.

  6. 6. Foster a competitive environment where the more capable and driven employees can develop a strong culture.

  7. 7. Know what developing job skills are worth to competitors and be sure to match compensation increases with increasing skills. Slow recognition of increased value may end up in a lost developmental candidate.

  8. 8. Have an incentive plan that is aligned with the goals of the owners regarding EFORd, starting reliability, unit trips, compliance with regulations, and plant net income.

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Hiring for capability and leveraging of Elwood’s existing capabilities has been essential to the plant’s success. Elwood has experienced numerous transitions in four ownership changes—switching from PPAs to PJM and then to the PJM capacity performance environment requiring rotating shift coverage.

During this period of change, staff has maintained a safe work environment and strong operational performance—with low EFORd, high starting reliability, and low unit trip performance demonstrated yearly. The O&M team missed very few market opportunities that lost energy margin or capacity payments.

While recent college graduates can approach work with great enthusiasm and capability, they don’t know what they don’t know. They also are less likely to bring with them undesirable expectations and behaviors than many experienced candidates. One of the changes we managed was moving from working directly for the ownership to one of working for service provider NAES Corp.

NAES has provided support in a few key areas that some of the ownership structures did not. Safe work performance, a key measure of operational excellence, is communicated by NAES and embraced by the Elwood staff. Programs, guidance, and support to develop safety, environmental, and NERC programs greatly enhanced the development of Elwood personnel.  

The leadership team has effectively managed the change from a summer peaking facility working under a PPA with the facility unmanned at night and weekends, to a significantly riskier environment where capacity payments can be lost any hour of the year.

The foregoing strategy has been a key factor in achieving challenging business goals year after year despite the significant changes experienced. The new team forged has achieved years of consistent employee performance development conducive to supporting Elwood Energy’s business objectives well into the future.

Elwood Energy, owned by J-Power USA and operated by NAES Corp, is a 1350-MW, nine-unit peaking facility in Elwood, Ill. Plant manager is Joseph Wood.

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Rowan: 2019 Best of the Best

Plant Rowan, owned by Southern Company and operated by Southern Power, is a 985-MW generating complex in Salisbury, NC, that has a 2 × 1 combined cycle and three simple-cycle units. Plant manager is Chris Lane.

Plant personnel identify, eliminate causes of compressor bleed valve failures

Plant Rowan’s 7F compressor bleed valve (CBV) design—consisting of a vented-to-atmosphere, air-to-close/spring-to-open air-actuated butterfly—lends itself to unpredictable failures at the worst possible times. Following numerous failures and subsequent replacements plant personnel took it upon themselves to tear down and perform a “workbench RCA” on a failed CBV following what was a very frustrating winter morning.

The conclusions were simple: Moisture was the leading contributor to failures, but on multiple fronts. It wasn’t simply a corrosion issue, nor only a freezing issue during winter operations. Rather, any moisture drawn through the air cylinder vent plug would linger causing possible issues year-round.

Trapped moisture accounted for nearly 90% of the failures experienced at various times throughout the year. The remaining issues were simple wiring gremlins. Those were resolved easily by refreshing flexible conduit runs and fittings as well as instituting annual wire-terminal checks.

Moisture issues were resolved thusly: First, plant had a removable insulation pad “hut” fabricated and placed over the CBV pairs (Fig 1). This would keep rain away from the valves/actuators and limit pack assemblies. Second, and most critical, 6 × 12-in. heating pads were installed on each air-cylinder body (Fig 2). This eliminated potential freezing and helped prevent condensation formation inside the cylinder as it takes in ambient air each cycle (dewpoint control).

Success! There have been zero failed starts attributed to bleed valves “failing to actuate” in over six years. It took almost no time to realize a return on investment with this small project.

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