Onsite – Combined Cycle Journal

ADVANCED EMISSIONS CONTROL SYSTEMS: Design considerations for SCR, ammonia equipment

By Team-CCJ | April 9, 2024 | 0 Comments

By Vaughn Watson, Vector Systems Inc
Connect with Vaughn on LinkedIn

The efficiency and long-term performance of an SCR system is largely dependent on several key design considerations for its various components. When complex NOₓ reductions on heat-recovery steam generators (HRSGs) are required, there are critical aspects of the system that must be addressed to ensure success. While the catalyst often gets all the credit, and all the blame, when performance declines, careful attention to system design can mitigate or prevent many of the top factors contributing to SCR issues.

Catalyst design itself is crucial to the effectiveness of the emissions control system. Catalyst volume, formulation, and pressure drop must consider the totality of operating scenarios the boiler will encounter. This evaluation should include all load levels, including the minimum emissions-compliant load (MECL), that the boiler will operate within.

All ambient conditions also should be considered. This is especially important for boilers firing multiple fuels or blended fuel streams. Your evaluation must include all operating cases from the HRSG OEM, but also interpolation of DCS data trends, if evaluating an existing unit for catalyst performance.

Additional testing to ascertain the NO/NO₂ ratio is important because high NO₂ speciation can be a major issue to SCR efficiency and require specific SCR catalyst formulations to achieve desired NOₓ reductions. Be sure to consider boiler turndown as well because the NOₓ produced typically is higher, and the decrease in exhaust temperature will limit catalyst efficiency.

SCR catalyst should be inspected at every outage to ensure the catalyst face is not blocked by rust or insulation (Fig 1). This can majorly affect SCR catalyst performance by masking the SCR’s active pore sites.

Bypass can greatly affect NOₓ and ammonia slip. The catalyst support structure, as well as the perimeter seals, should be inspected to ensure there is no bypass of exhaust gas and ammonia. Assure catalyst modules are well packed to prevent ammoniated exhaust gas from passing unreacted through gaps around the catalyst bed. On a high-performance SCR, small amounts of bypass can drastically add up to the inability to meet objectives.

Ammonia distribution within the exhaust-gas cross section is a major factor in the catalyst’s ability to properly reduce NOₓ levels. This important part of the system falls on the design of the ammonia injection grid. AIG design must consider the amount of ammonia and diluent required for the reaction, as well as the ability to inject and mix the ammonia with the NOₓ present in the exhaust gas (Fig 2).

Give careful consideration to injection pressures, mass flow, and density change along the length of each AIG lance. Injection-grid design for advanced NOₓ control will carefully vary injection orifice sizing, spacing, and angle of injection necessary to ensure the NH₃:NOₓ distribution is matched to the volume of catalyst (Fig 3).

Inspect the AIG every outage to ensure there is no significant plugging, which could have a huge impact on catalyst performance. Clean the AIG if you find plugging, then determine the root cause. Often, the design of the AIG can be improved to achieve better performance and provide some resilience against frequent plugging issues.

Avoiding many SCR performance issues begins with the ammonia supply. Work with a reputable and accountable chemical supplier to ensure you are getting the reagent purity necessary for your system. Avoid ammonia contamination in transit to the plant by requiring dedicated trucks for each haul.

Also, require certificates and test reports before offloading to help protect the system against such contaminants like chlorides and calcium. These impurities can damage and plug the various components of the ammonia system.

Specifying the correct purity grade of ammonia is critical for aqueous ammonia systems; reagent-grade ammonia is the best option. The key differentiation is the purity of the water content of the solution which may contain soluble minerals that can plug, foul, erode, and damage SCR system components.

Such impurities in the reagent solution can lead to vaporizer fouling, AIG plugging, and potential catalyst performance problems. Keep in mind that it only takes one bad load of ammonia to experience the headaches associated with ammonia impurity.

By ensuring the foregoing factors are considered in the SCR and ammonia-system design, and addressing problems when they are discovered, are essential to an efficient SCR system capable of advanced NOₓ reduction.

HRSG DESIGN: Impact of Code changes to Gr 91 allowable stress values

By Team-CCJ | April 9, 2024 | 0 Comments

By Cesar Moreno, HRST Inc
Connect with Cesar on LinkedIn

Gr 91 material is named after its main components: 9% Cr and 1% Mo-V. It was developed in the late 1970s, with the focus of its use in the nuclear power industry. The material is part of the Creep Strength Enhanced Ferritic (CSEF) steels group, which includes its predecessor, Gr 9. One of the main factors supporting the creep resistance of CSEF materials is their microstructure. This is why it is critical to maintain proper fabrication procedures to obtain the full capabilities of the material.

Shortly after its development, Gr 91 material soared in popularity. It offered many significant benefits—including reduced minimum wall thickness (up to about 40%) for the same creep life as traditional boiler steels. In addition to the reduction in MWT, Gr 91 boasts up to a 12-fold increase in fatigue life. Additionally, it has about an 18% lower coefficient of thermal expansion than Gr 22, making it especially attractive for applications in cycling units that frequently experience transient conditions.

As the industry continued to develop, and new equipment required more demanding operating conditions, the market for Gr 91 grew quickly. This encouraged the mass production of Gr 91 material which often led to producers maintaining only the minimum requirements in the chemical composition and fabrication process.

Some of the cost-saving measures applied in production—such as lean chemical composition, application of minimum guidelines for heat-treatment cycles, and varying production processes (strand casting versus ingot)—lead to measurable variations in the final compositions of different heats. The combination of these variables is detrimental to the final characteristics of the material.

Given the wide use of Gr 91 material in the industry and the vast amount of data collected over several decades of in-service applications, there is now information available to provide more accurate results for design limitations and life expectancy of the material.

Predicting creep life for Gr 91 generally has a high degree of uncertainty and extrapolating from (relatively) short tests is not reliable. The availability of long-term data (over 30,000 hours in operation) allows for more realistic estimates of the material’s life.

In the 2021 revision of the ASME Boiler and Pressure Vessel Code, the allowable stress values (ASVs) for designs using Grade 91 materials were reduced. This decision was based on a combination of factors, but seemingly driven primarily by the significant differences in the material’s capabilities when produced under ideal production conditions versus those produced following the absolute minimum requirements.

The material is now classified in two categories, Type I and Type II, differentiated by their chemical composition. Type II Gr 91 has the stricter requirements of the two, producing a higher-quality material which more closely resembles the composition used during the original development and testing.

The reduction of ASVs has a direct impact in HRSG design considerations. At a typical operating condition with a tube metal temperature (TMT) of 1100F, the new ASVs for Type I and Type II materials see a reduction of 15.5% and 11.6% respectively. This directly results in a higher MWT requirement for the same operating temperature; conversely, it reduces the allowable TMT for existing designs.

In addition, there are many other industry changes that add to the considerations of the Code change. Many plants have implemented GT upgrades which often create more demanding conditions for the HRSG. Operating profile changes, especially more frequent operation at lower loads also have a significant impact on the expected life of systems using Gr 91 material. Other issues such as non-uniform flow distribution in the burner duct area, increased firing temperature, missing baffles that create bypass lanes, and internal oxide growth can exacerbate the problem.

Most HRSG designs employ Gr 91 material near its limits, which creates a situation where a small increase (15 to 20 deg F) in TMT could have a drastic reduction in the expected life of the material (Figs 2 and 3).

HRST has performed analyses of specific cases using the Larson-Miller Parameter (LMP) for creep-life approximation and found up to a 40% reduction in expected operating hours for an 11-deg-F TMT increase. Given the possibility for these types of situations, consider putting steps in place to evaluate the current condition of your Gr 91 systems.

ASME B31.1 provides requirements for monitoring the condition of external high-energy piping (HEP), also commonly referred to as covered piping systems, or CPS. Inside the HRSG, the design limits should be reviewed using the new ASVs to determine if there are any concerns. Following this review, if the values are not ideal, the evaluation can be repeated using the actual operating conditions of the plant.

Once this has been done a condition assessment can be developed. It should include an individual assessment of each system, stress analysis for the concerning areas, and NDE. Finally, if problems are identified during the assessment, they can be used to determine specific locations of high risk. Destructive assessment can be performed for the material to determine its chemical composition and heat-specific strength, which would help guide the appropriate actions to take at that point.

Variety of best practices keeps advanced-class CCGT running strong

By Team-CCJ | April 9, 2024 | 0 Comments

Kings Mountain Energy Center

Owned by Carolina Power Partners LLC
Managed by CAMS
Operated by NAES Corp
475 MW, gas-fired 1 × 1 M501GAC-powered combined cycle, located in Kings Mountain, NC

Plant manager: Sean Spain

Storm shelter protects staff during weather events

Challenge. A mid 2020 tornado that touched down within a mile of Kings Mountain (KMEC), plus several storms that spawned high winds, encouraged a reassessment of the plant’s capabilities for personnel protection. There was an emergency protection plan, of course, but staff believed it could do better.

The best place to shelter in the existing building was a small room with no windows on an exterior wall. However, it was difficult to accommodate the entire staff safely in that space.

Solution was to implement a Management of Change action to build a tornado shelter. Plant personnel worked with an engineering group to create a blueprint for an independent structure adjacent to the plant (Fig 1) and sent it out for bids. The contractor selected built the specified shelter in its shop and poured the concrete pad.

Once the concrete slab had cured, KMEC O&M staff engaged a crane to install the prebuilt shelter on the pad. Plant electricians installed the lighting in the shelter. Finally, the site’s emergency action plan was updated and a tornado drill was conducted.

Result. KMEC now has a designated shelter to protect personnel during possible future weather events.

Project participants:

The plant’s entire O&M team

‘Magnetite catcher’ helps prevent sticking issues with steam-turbine valves

Challenge. KMEC uses its steam-turbine bypass system for steam-system control during starts, shutdowns, upsets, and other situations when the turbine is not available. Bypass valves are of the Fisher ™ TBX pressure control type with a “flow under the seat” design. Two of the plant’s three bypass valves have experienced sticking during a vast majority of the starts—both hot and cold—since commissioning in 2018, causing upsets and inconveniences.

Fisher was contacted to troubleshoot the problem and run diagnostics on the valves and their actuators. Interestingly, the valves functioned satisfactorily during outage diagnostic testing.

Additional investigation revealed a possible issue with magnetite from the steam system causing operability issues with this valve design. Plant staff contacted other facilities with valves of the same type and learned the sticking issue could be resolved by using “magnetite catchers” (Fig 2) on hot-reheat (HRH) and main-steam (HP) bypass valves.

Solution. When first removed from the valve body, the plug, stem, and cage assembly couldn’t be separated because of the magnetite (Fig 3). But after heating the cage and using hydraulic jacks (Fig 4), the parts were separated.

A valve services company was engaged to retrofit spare sets of HP and HRH bypass valve trim. This was done in four days during a routine outage.

Results. Subsequent to the install of magnetite catchers, several plant cycles have been performed with no sticking issues on the upgraded valves. Current plans are to open and inspect the valves after three years of service to determine overall condition and the amount of magnetite captured.

Project participants:

The plant’s entire O&M team

Improve SCR maintenance to reduce emissions, cost

Challenge. Since commissioning, KMEC has had various challenges in maintaining NOₓ and CO emissions. Staff quickly worked through short-term fixes to achieve better results, but some long-term recurring challenges are associated with increasing pressure drop across the catalysts caused by airborne particles of insulation from the duct-burner area impeding gas flow (Fig 5).

Another problem: An increase in SCR injection-blower discharge pressure attributed to ammonia deposits and the build-up of insulation in the injection nozzles. A tuning grid was installed to help adjust ammonia injection in sections of catalyst so affected (Fig 6).

Solution. During planned outages, CO and SCR catalysts are cleaned to reduce performance-robbing pressure drop. Also, a flange was installed in the SCR injection-blower discharge piping to allow a vacuum truck to connect to the injection piping and remove deposits in the injection nozzles (Fig 7).

To better gauge SCR catalyst performance, a sampling grid was installed on the downstream side of the SCR catalyst modules. It provides an array of 18 sampling locations—three wide in each of the six AIG (ammonia injection grid) zones.

Results. KMEC’s ability to reduce emissions and adhere to permit limits has been improved. Plus staff can perform SCR maintenance better and faster during planned outages, thereby helping to prevent unplanned outages. Another benefit is reduced ammonia consumption and associated cost.

Project participants:

The plant’s entire O&M team

Eliminate generator trips caused by fluctuations in seal-oil temperature

By Team-CCJ | April 9, 2024 | 0 Comments

Athens Generating Plant

Owned by Kelson Energy
Operated by NAES Corp
1080 MW, gas-fired facility equipped with three 501G-powered 1 × 1 combined cycles, located in Athens, NY

Plant manager: Steve Cole

Challenge. Athens Generating Plant has been plagued with seal-oil issues since first fire more than 20 years ago. Throughout the years, the seal-oil systems have received small tweaks and alterations with the goal of improving temperature regulation of the air-side seal oil at the gas turbine (TE) and collector ends (CE) of the hydrogen-cooled generator. Goals: Maintain the 120F ±5 deg F setpoint, and maintain the delta between the air-side and hydrogen-side seals at 3 deg F.

Most recently, Unit 3 tripped offline in early April 2022 because of generator vibrations. After the trip, the OEM’s diagnostic center was contacted to look into what could have caused the excessive vibrations. Its analysis concluded that there may have been a foreign object that passed through the rings, some sort of internal rub, or the fluctuation of seal-oil temperature and pressure, which they had noted in their report as having occurred just before the trip.

The recommendation was that a restart could be attempted while paying close attention to the vibration levels and seal-oil parameters. Athens restarted the unit and observed the vibrations and seal-oil parameters both locally and remotely. Personnel noticed that the upstream local thermometer (Fig 1)—located immediately after the pipe tee where the air-side seal-oil cooler outlet and cooler bypass come together—displayed a different temperature than the gauge installed roughly 14 ft downstream. The difference was about 10 deg F.

The local air-side seal-oil temperature gauge located furthest downstream on the skid (Fig 2) was most closely representative of the temperature read by the DCS at the turbine and collector ends of the generator.

Investigation of historical data on the seal-oil temperatures revealed that the air-side seal oil at the turbine and collector ends of the generator would fluctuate anywhere from 20 deg F cooler to over 10 deg F warmer than the seal-oil temperature setpoint. The regulating valve was maintaining the 122F setpoint, which receives feedback from that thermocouple, with very little error, while the temperatures at the generator TE and CE would fluctuate from as low as 102F to 132F.

Solution. The Athens team presented to the OEM’s engineering team its idea to install a thermocouple in the downstream drywell, where the local gauge is, and change the logic controlling the air-side seal-oil temperature regulating valve to use the value from the new thermocouple. The OEM approved the idea, and a management of change was created.

Athens I&C technicians installed a new thermocouple in place of the local indicator, wired the thermocouple to available terminals in the nearest I/O cabinet, and reworked the logic so the air-side seal-oil temperature was regulated using the values from the new thermocouple.

In addition, a single point of failure was mitigated by adding logic to revert to the old thermocouple, with a limited regulation rate, in the event of the new thermocouple provided inaccurate information. The intent is to keep the unit online while personnel troubleshoot and correct the bad-quality signal.

Results. After the new thermocouple was installed and logic confirmed, Athens put the thermocouple in service as main feedback to control the air-side seal-oil temperature regulating valve. It has had more than 3000 hours of service since the change was implemented and the results have been excellent.

The air-side seal-oil temperatures at the turbine and collector ends of the generator have been maintained within a 3-deg-F error since the new thermocouple was installed. That is much better than the periodic 20-deg-F error Athens was seeing prior to the change.

Since the change, there have been no vibrations or trips associated with the fluctuations in seal-oil temperatures. All three units at Athens have been changed, or are in the process of being changed, to the new seal-oil temperature regulating setup.

Project participants:

Chris Mitchell
Kyle Kubler
Todd Wolford
Eric VanZant
Kevin MacNeill
Jesse Ferenczy

ProEnergy, Egyptian power producer partner on aero maintenance

By Team-CCJ | April 9, 2024 | 0 Comments

ProEnergy recently expanded its global reach in aero-engine maintenance services, signing a total-care service agreement (TCSA) with a subsidiary of the Egyptian Electricity Holding Co (EEHC) for eight of its LM6000 generating units. The state-owned company operates more than 55,000 MW of generation capacity and manages electricity delivery to more than 38-million consumers.

East Delta Electricity Production Co (EDEPC) is the EEHC subsidiary responsible for operation and maintenance of the two plants covered under the contract—288-MW Sharm El Sheikh expansion (five LM6000 PCs and one LM6000 PF) and 84-MW Port Said (two LM6000 PCs). The contract includes management of all maintenance events for the gas-turbine packages—including, but not limited to, hot sections, combustors, and major overhauls. Photos of the plants are below.

An important aspect of the arrangement is EEHC’s commitment to decarbonization of electric generation, which aligns with ProEnergy’s goals. In 2022, one unit at Sharm El Sheikh successfully operated on a hydrogen/natural-gas blend during COP27, the 27th Conference of the Parties of the United Nations Framework Convention on Climate Change.

An Egyptian delegation participated in PROENERGY 23, sharing its LM engine experiences, including operation on the hydrogen/natural-gas blend. Those in the photo are: (1) Carlos Picon, ProEnergy; (2) Mohamed Abu Senna, chairman, EDEPC; (3) Nadia Katry, executive director for commercial and financial affairs, EEHC; (4) Jeff Canon, ProEnergy; (5) Mohamed El Tablawy, executive director for planning, research, and power projects, EEHC; (6) Sergio Picon, ProEnergy; (7) Mohamed Mohsen, commercial director, Tanmeia; and (8) Mohamed Shawky, Tanmeia. Note that Tanmeia is an Egyptian company engaged in power, energy, transportation, and associated O&M.

WTUI AERO DISCUSSION FORUM: O&M advice free for the asking

By Team-CCJ | April 9, 2024 | 0 Comments

Online forums sponsored by gas-turbine user groups are of increasing value to owner/operators, especially given today’s smaller O&M staffs at simple-cycle, combined-cycle, and cogeneration plants and the loss of experienced personnel to retirement and better opportunities. Long gone are the days of on-the-job training when new employees would tag along with experienced crews to grow their knowledge over time.

Thus, today you may be at a loss on whom to call with an important question. If that’s the case, try posting that question to the forum serving your engine model. Oftentimes you’ll receive expert advice at no cost within a day or two. Most likely your issue is not unique. Also, in need of a part in a hurry? Ask colleagues online to loan you their spare until you can replace it.

Forums serving the larger user groups—such as Western Turbine’s LM6000 Forum—typically provide the best results by virtue of their global reach.

To illustrate the value proposition, CCJ editors selected a few questions posted to the LM6000 forum in 2023 along with a summary of the guidance offered. To join, contact Webmaster Wayne Feragen at wferagen@wtui.com.

  1. Generator vent fans

Question: Has anyone retrofitted their “classic” belt-driven generator vent fan—TCF Azen or Hartzell—to direct drive? If so, whom did you use? Any lessons learned? Where did you source the fans?

Replies:

  • We were a test-bed site for direct-drive fans on both the turbine and generator. Turbine fans were a constant problem and we eventually switched back to belt-driven units. Generator fans—all are TCF/Aerovent—haven’t been as troublesome, but we do suffer intermittent high-temperature issues in summer.
    Whenever we test or inspect, everything checks out OK. We have tried a few minor mods to improve and balance air flow through the enclosure, but haven’t seen a difference. Recommendation: If you are content with your belt-driven fans stick with them.
  • If you’re seeking a retrofit solution to direct drive, I’d recommend contacting Eldridge USA. Their expertise in providing turnkey solutions is noteworthy.
  • Switched to a banded, three-rib V belt and haven’t had anymore belt issues on the generator TCF/Aerovent fans that use a 3/BX73 belt.
  • In the past, apparently there were belt-failure problems on all package fans. We implemented a maintenance program that verifies pulley alignment with a laser alignment tool and setting the proper tension using a belt tension tool. Misalignment and improper tension are the primary drivers of belt failure.

Final step: Use soft starters in the MCC buckets to reduce slippage during starts.

Result: Belt issues essentially have been eliminated at our plant. Today, belts typically are replaced only because of age-related cracking.

  1. Problems with the VBV feedback signal

Question: We have some problems with the feedback signal on one of our variable-bleed-valve systems. It comes and goes, and may be good for several hours/days before it fails again. The OEM’s troubleshooting guide says to measure resistances, check connections, etc. Everything seems fine. Does anyone experience a similar problem? A real solution is important to us, especially in winter.

Replies:

  • Try replacing package and on-engine cables. If the plugs have been overtightened, damage may have been done to the cable sockets.
  • Our site is constantly plagued with VBV and VSV (variable stator vane) feedback problems. Have you looked at any high-speed data logs to see what the signal is doing? Some of our issues have been logic errors that do not prevent nuisance trips when one actuator feedback fails. GE provided new logic (not installed yet) said to resolve several issues with feedback faults causing unwanted action. It doesn’t solve root-cause issues, but it does keep the unit online and rejects the faulty signal.

The responding user provided details on how his plant handles the issue described.

  1. Hole in first-stage HPT blade

Question: During our annual borescope inspection, we discovered a through hole on the leading edge of a first-stage HPT blade. There is a slight amount of TBC loss on the combustor swirlers, but no visible damage or coating loss on the nozzles and later-stage PT blades. We are running five LM6000PCs, but this unit is the only one to have this type of damage. The unit underwent a hot section in 2022 and received a rotable, overhauled HPT rotor at that time with a mixture of new and overhauled first-stage blades. Have any other users had a similar experience or seen this type of damage?

Replies:

  • Several years ago, we had similar damage on our HPT. Cause was identified as liberated material from a combustor secondary swirler (venturi).
  • We’ve had similar failures over the last couple of years. One instance was attributed to an HPC blade event; the second to a nozzle failure, but the exact cause of that was not determined.
  • We experienced similar damage in 2012, with DOD into the HPT first-stage blade. Origin was never determined except that it might have been caused by TBC coating released from the combustion chamber. Blade was replaced in the field.
  1. HCU overhaul intervals, troubleshooting

Question: What do forum participants have to say about the overhaul of their hydraulic control units (HCUs)? Our site has had an HCU fail previously (VBV section). Today we are diagnosing an issue with the VSVs on another unit. Both feedbacks are in agreement, but position became erratic at about 83% stepping up in the positive direction. The issue was bad enough to affect load capability.

Today I performed electrical checks on all LVDTs (just for good measure) and torque motors. All passed. Cranked the unit and stroked the VSVs into several positions, but was unable to replicate. We’re going to check the rod/head screens for any material caught, and possibly replace the HCU.

Replies:

  • Our HCUs failed every time because contaminated oil was fed to the HCU and the internal components clogged-up. Oil contamination was traced to (1) topping off of the GT oil tank with generator oil, (2) the failing HCU filter allowing contaminants to pass through, (3) bypass over the HCU filter, etc. In every event we had to send out the HCU for overhaul. One event was attributed to installation of a short HCU in a long filter bowl.
  • The questioner jumped back into the conversation thusly: Yesterday we ended up replacing the HCU. However, when we loaded the unit at about 48 MW the issue returned. We also received a power-supply fault for the chassis that contains the ACT_CNTRL cards (our PG units have redundant ACT_CNTRL cards, one driving A torque motor coil, the other the B/C coils; both cards are in separate chasses). Today, we will go down the servo cables in the package looking for shorts. If none are found, we will replace the power supply and load the unit again.
  • A concerned user warned: Before you restart the unit, you may want to verify the quality of the synthetic oil to be sure mineral oil was not added inadvertently. Have a SOAP analysis done.
    Continuing, he said, the writer of the first reply shares unfortunate lessons learned. The consequences of continuing to operate with contaminated oil can be significant beyond damage to the HCU. Try to understand why the HCU failed, he recommended. If coking starts to develop in the sumps—especially B&C where the temperatures are highest—the risk of bearing failures is greater.
    He then quoted from the troubleshooting recommendations in Chapter 10 if the O&M manual, “If engine is operated for more than 200 hours with MIL-PRF-23699 oil containing more than 5% mineral oil, significant internal coking may occur.”
  • Another user entered the online chat: One thing to check is the mechanical system to make sure it is free to move across the whole range. The Woodward document had a service-life recommendation for the LM2500+ at six years as I recall. Can’t remember if the LM6000 HCU was in the same document. I will check with the Woodward application team and report back.
    Just rechecked GE documentation and found the service life of the LM6000 HCU is six years or 50k hours.
  • The original questioner reported back: Comments very helpful. We traced the issue to a faulty Woodward actuator control module. It was difficult to trace because we have redundant control of the torque motors (one module connected to torque motor A coil, the other connected to B and C). It seemed from the data log like the issue was common because both cards were stepping up their output. It wasn’t until we ran a calibration on the B channel (B and C coils) that we were lucky enough to catch the erratic behavior from that module at that time. Replacement was the solution.
  • Yet another user closed out the discussion by providing a pdf of Woodward’s HCU manual and an information letter providing recommended maintenance intervals for Woodward auxiliary equipment. The only issues encountered at his plant have been contamination through oil and a grounded servo coil.
  1. VBV actuator/LVDT

Question: We had a VBV actuator feedback fail. Looks like the soldered connections behind the actuator’s Cannon connector were heavily corroded; one of the connections actually broke away at the soldered joint. Is anyone seeing this same failure mode? Might the manufacturer, Arkwin Industries in this case, have had a run of improperly soldered joints?

Replies:

  • The soldering looks to be of poor quality (note that photos of the affected joints were provided via the online forum), but I have seen solder melt inside the package before because of heat if the part is in a hot spot.
    Perhaps the part had been refurbished and misrepresented as new. Suggest you reach out to Arkwin to confirm authenticity.
    Another thought: The O-ring could have been leaking if someone had tried to over-tighten the Cannon plug and twisted it.
  • Questioner response: I agree that the soldering looks nasty. I have only seen Arkwin actuators on our machines, even our old PC model. We are planning to send this one out to AGTSI, having used their service previously for actuator overhaul.
  • Another user, looking at a photo provided by the questioner, confirmed that the actuator is a valid GE Aviation procured part—the Federal Supply Code for Manufacturers is correct as is the part number.
  • Questioner response: This actuator was OEM from GE on our power-generation units. We have never replaced a VBV actuator on these unit until now.
    I did hear back from AGTSI and this is what I was told: Unfortunately, we do not off repairs on these as the manufacturer does not offer this service. That said, however, there are third parties that offer this service but we are not sure if they are approved by the manufacturer. AGTSI does offer rotable exchange for new on these units, but it would be quite a bit more expensive than just having the connections soldered.
  • During the back-and-forth online exchange, Score Energy was identified as a possible service firm for this work.
  • Another user offered the following: From what I understand, Score Energy now is allowed to contract with US end users directly for off-engine parts. The company’s Houston office has competitive offerings on rebuilding, exchange for new, and new outright purchases of LVDTs. However, the rebuild shop is in the UK and there is a long turnover time, so I opted for the new one with the used exchange.
  1. Woodward device needed

Question: Having reliability issues with the auto sync on a unit in our fleet. Don’t have a lot of detail, but the site team believes it’s a malfunctioning DSM. The device is an SPM-D10 Synchronizing Unit (PN 5448-906). According to Woodward, this particular device has not been supported by them since April 2016. Does anyone have any spare devices they are willing to part with?

Replies:

  • A user suggested going on the Woodward website and accessing the company’s list of global business partners to identify service and spare-parts local suppliers that might be able to help.
  • A second user strongly disagreed with the claim suggesting that the auto-sync issue is caused by the SPM synchronizer, as it rarely breaks, he said. The problem often arises when settings on the SPM are not correct, resulting in extended synchronization times unless adjustments are made using the keypad for the SPM.
    I urge you to trouble-shoot the circuitry thoroughly before making any financial commitments. If you pursue the purchase option, you might try Maximum Turbine Support or AP4 Group.
  • A third user found the K100 relay was the issue in a similar situation. The contacts must get gummed-up and do not pass good voltage to the input card, he said. It happened on two different units, so plant replaced the relays on all four of its PD engines, which have MicroNet Plus control systems.
    This was for the remote auto sync and not the local TCP. Our site is set up with a remote supervisory control system that controls all the units and tells them to synchronize remotely (enable sync). If we went out to the site and put the TCP in “local” and then moved the hand/off/auto switch from “off” to “auto” it would synchronize just fine, but wouldn’t sync if told to do so remotely. Not sure if this applies to your situation.
  • As the previous user said, make sure the permissive signal (coming from the K28 relay in my unit) is active during auto sync. If it’s taking a long time to auto sync, check the DSM settings and fine-tune as necessary.
  • Yet another user noted that while the SPM-D10 Synchronizing Unit rarely breaks, he had to replace one recently because of a failed breaker-close output relay.
  • The previous user agreed that the DSM was very robust and surmised that if the breaker-close output relay is damaged there could be a loose connection in the breaker closing circuit.
  1. Likelihood of a major combustor problem

Question: After all the discussion about combustor problems at this year’s WTUI conference and the general unavailability of spare parts for these components, we are evaluating the logic of ordering a spare hot-gas section. We have two PF2 engines and neither GE nor the ASPs have much in the way of spares.

What is the likelihood of a major problem in the hot-gas section of these units? Are any numbers available? Does someone have a spare hot-gas section? What is your strategy?

Replies:

  • Very complex question, so the response is multi-faceted. Capital expenditures—such as purchasing a spare hot section—depend on many factors, including the following:
  • Mode of operation—peak, load-following, baseload.
  • Annual operating hours, which impacts the calendar time between hot sections.
  • Inlet filtration quality.
  • Size of installed fleet.
  • Operating experience.
  • Operator experience, fuel quality, number of trips, etc.
    My company will be operating multiple baseload units in several plants trying to run as close as possible to 8760 hours annually. Considering today’s supply-chain challenges, we will own a spare hot section to rotate through the “fleet,” maximizing the number of available hours to operate.
    If an owner operates relatively few hours in a seasonal pattern (for example, high demand in summer or winter), then it might be able to coordinate with the OEM to have the replacement got section available at the “right time” and not have to buy a spare.
  • Having a spare hot section probably is overkill if you have only two units. However, if the units must have super-high uptime, then you need to weigh the cost of the hot section against the cost to the business when the unit is not operational. Something to consider: What happens if you buy a combustor and put it on the shelf and GE updates the design?
  • I think routinely checking your T-48 spread and adjusting your fuel-nozzle pattern accordingly, along with routine borescope inspections of your dome cup area, inner/outer liners, and looking for early signs of spalling TBC, is a good proactive approach regarding hot-section life.
    I would also look at NOₓ water mapping to be sure you are not over-watering your combustor. Over-watering and harmonics are the biggest causes of cracking around the cooling holes located behind the dome cup area that can cause downstream HPT first- and second-stage damage.
  • How many fired hours will your two PF2 units be operating annually? If 8000 to 8500 hours, the best solution is to purchase a spare engine and rotate it into operation at each hot section and major. The spare engine is conducive to a short outage duration for swapping engines and maximizes unit operating hours. The hot section or major maintenance would be completed on the engine removed after the unit is back in service and before the next unit is due.
    Keep in mind that you don’t want both units scheduling hot sections and majors at the same time—if the units are operating nearly the same annual hours. Reason: You would need hot-section parts for two units at the same time, compounding the issue. It would be best to get one unit into the first hot section (or swap the spare engine in) a year early to offset the hot section and major outage intervals for the two units.
    If the units will be operating less than 4000 hours annually and not so critical for availability, you might not need a spare engine.
  • We are currently evaluating our needs for the new PF1 units we are installing, but more than likely will keep at least one spare engine on hand for our 10 units, with the possibility of upping that to two. We did consider purchasing a spare hot section as well, but the cost of the that section with the combustor included is near enough to the cost of having another complete spare engine that we’re not sure it makes sense for us.
  • Follow-on response from the user asking the original question: Looks like we’re actually investing in a spare engine for several reasons—including minimizing downtime, advantages for major maintenance work, and assuring the district heating supply.
    However, the final decision hinges on what costs we should expect for preservation of the spare engine? Are there any maintenance or conservation activities that must be conducted regularly? Is it possible to estimate the costs involved?
  • This response to the second round of questions: Get familiar with WP 3011 in the O&M manual. Plus, consider storing the gas turbine in its container inside a warehouse, or if has to be outside, place it under roof cover. When the container expands and contracts because of weather changes, and especially if it sits in the sun, the ability to keep the internal humidity under control is much more difficult.

7F Users Group 2023: User Presentations and Discussion

By Team-CCJ | April 2, 2024 | 0 Comments

Seasoned owner/operator personnel tackle the biggest industry issues

 The depth and breadth of experience represented by 11 owner/operator presentations at the 2023 7F Users Group Conference can be summed up like this:

  • Chronologically, they represent machines dating back to the original F-class gas turbines (GT) off of the test stands in 1988.
  • Numerically, these users are responsible for at least 150 7F units, maybe closer to 200.

The presenters themselves are some of the most seasoned experts in GT operations and maintenance in the nation; many are names familiar to the GT user group community. Topically, the presentations can be grouped as follows:

  • Two deep dives into specific compressor issues.
  • Two deep dives into specific combustor issues.
  • One addressing myriad control-system issues.
  • One discussing the exhaust end.
  • One on turbine-bucket creep failure.
  • A primer on the latest 7F combustor system (the DLN 2.6+).
  • One on a fuel-gas stop/speed ratio valve actuator.
  • Two “system” presentations on lifecycle management and R&D aspects.

At the risk of sounding like a late-night Ronco commercial, don’t delay. After reading the high-level summaries presented here, go to www.powerusers.org and look at the slides, available for viewing to user members of Power Users (user non-members will have to apply and be approved by the leadership). If you are responsible for 7Fs in your fleet, the editors believe you’ll be glad you did. Don’t forget to register for the 2024 annual conference this May.

Beware shrouded S17 blades

An owner/operator representative with 15 7F units dating back more than 30 years described the company’s strategy for replacing, upgrading, and enhancing the compressors in the fleet and subsequent operating experience. The program began in 2009 and the last of the simple-cycle units is expected to be completed in 2025.

Others with or eyeing shrouded contoured S17 blades as an enhancement, take note. The presenter’s conclusion is succinct and blunt: The enhancements went smoothly and performed well except for the shrouded S17s. Two units experienced pressure-side root rubs in the S17s, which subsequently had to be “surgically removed and replaced.”

Execution lessons learned include making sure to use the right gages (taper versus feeler) in the right places when collecting all the necessary data, walking down the rotor transport route as each site is different, and managing expectations on the condition of a “just in time” rotor in layup.

Addressing T-fairing distress

Described in TIL-2212, T-fairing is a circumferentially loaded platform on the compressor rotor that has an inner flow path between R1 and R2 and R2 and R3 under the tips of variable stator vanes (VSV) 1 and 2. An expert for an owner/operator with a fleet of over 50 7F machines noted the general concerns: VSV tip rubs and liberated material, circumferential gaps and T-fairing shingling leading to rotor imbalance, compressor blade platform damage, and rotor/wheel dovetail slot wear.

The presenter noted that the three TIL revisions to date, the most recent in August 2022, express a progressive level of urgency to address this issue. Recommendations to mitigate the original T-fairing operational risk include:

  • Borescope inspection (BI) as specified in the TIL to inspect for VSV tip loss, excessive gaps, and wear/rubs.
  • Monitor units even more closely if equivalent turning gear (ETG) hours are greater than 15,000.
  • Monitor T1 and T2 seismic vibrations; alarm at 0.50 in./sec, runback at 0.82 in./sec, and trip at 1.00 in./sec.
  • If T1/T2 alarm is triggered via step change, inspect at next opportunity and suspect T-fairing shingling or hard rub.

When replacing T-fairing, ensure lockers did not migrate or disengage per TIL-2391: Torque-check exposed lockers (four per stage) in R3-R6, and BI R7-R14.

Results with DLN2.6+ with AFS/OBB

An owner/operator with 32 7F machines in its fleet reported on turndown performance after retrofitting four FA.04 units at one site, between 2020 and 2022, with dry low NOₓ (DLN) 2.6+ combustion hardware along with axial fuel staging (AFS) and overboard bleed (OBB).

While all of the machines met or exceeded their performance guarantees (numerous graphs provided), the user did underscore effusion-plate cracking found during a spring 2023 BI after 25,000 fired hours affecting 14 of 56 combustor cans. The OEM plans to modify the area with thermal barrier coating (TBC) per TIL-2292 at the next hot-gas-path inspection (HGPI).

Separately, the speaker noted that limited tuning capability on the part of the OEM’s service team for this new technology led to 12 schedule modifications. Up to 12 days were required to tune each 2 × 1 block.

Other lessons learned: Ensure outside instrumentation is heat-traced (a compressor discharge pressure transmitter for the AFS froze up and kicked out AFS operation); ensure that the SSO (safety shutoff) valve blank is removed (caused a two-day delay getting back online); check for looseness in the AFS damper (one-day delay for inspection and tack welding); and have a backup emissions analyzer available.

Combustor end-cap failure RCA

You’ll have to check out the slides to experience the “perfect storm” which led to a catastrophic failure in 2023 of combustor end caps following a flange-to-flange replacement in 2022 of an unflared 7FA.01 (with 181,000 fired hours) to a flared 7FA.04 with DLN2.6+ and AFS.

Some of the elements in the storm were the result of what the presenter called “downgrades” from the replacement (as opposed to “upgrades”)—such as switching the control system from Ovation to Mark VIe and changing the tuning option from manual to the OEM’s Autotune MX.

As recently as October 2022, a BI turned up no significant findings on the unit. The presenter’s frustrations with the OEM are also clear in the slides, especially when poking fun at the OEM’s euphemisms and obfuscating language. Reportedly, the OEM was essentially no help during the short-term recovery of the unit after this catastrophic failure; site personnel had to figure stuff out on their own. As for a long-term solution, a new TIL to fix the bugs in Autotune, which disregarded the high dynamics (a key part of the “storm”), wouldn’t be available until fall 2023.

Cornucopia of controls issues

One of the industry’s leading user experts on GT controls reviewed myriad issues, some associated with TILs, but also controls associated with emergency bearing-oil pumps and lube-oil seal-pump starter failures; liquid-fuel purge systems; non-optical flame detectors; high turbine-compartment temperatures; compressor-bleed-valve drain lines; modified exhaust-temperature-spread monitoring in EMS2100, Mark VIe TTUR card (associated with the primary trip terminal board) failure associated with generator synchronizing out of phase; and compressor discharge temperatures.

Robust exhaust replacement

These slides offer a pictorial view and chronology of an exhaust-system replacement at a 2 × 1 combined-cycle facility. Drivers for the project included exhaust liner cracks, flex-seal failures, horizontal joint separation, high exhaust-frame-blower amperage readings, and frequent exhaust-frame-blower motor change-outs over the five years before the project. Solution was to replace the back end with the OEM’s “Robust Exhaust Upgrade.”

Post-installation photos are included of both units, one after 1500 hours and 15 starts, and the other after 19,000 hours and 70 starts. Graphs show that the blower motors are operating generally below the threshold of high amperage. One caution: Be sure to thoroughly check that no insulation is missing if you are planning one of these replacement/upgrades.

Fleet R&D activities

A representative from the Electric Power Research Institute (EPRI) identified and expounded upon areas where R&D is being conducted on behalf of all EPRI member fleet owner/operators. Examples offered of R&D projects with “proven value” include the following:

  • Using EPRI’s digital-twin technology for managing regular maintenance activities and enhancing GT dispatch.
  • Balancing operational risks from power augmentation with market opportunities to sell additional megawatts during high-price periods.
  • Providing guidance on overall quality control and assurance during major planned HGP outage activities.
  • Applying additive manufacturing to enhance first-stage vane cooling and overall engine performance.
  • Applying process component resonance (PCR) testing to validate repairability of second-stage turbine blades.
  • Demonstrating 20% to 40% hydrogen blending in LM6000 and 501G units.

Second-stage-bucket creep failure

A metallurgist for one of the largest fleet owners in the US analyzed the March 2022 failure of 7FA.03 second-stage buckets in a combined-cycle unit with commercial online date (COD) of 2007. The failure occurred after a shutdown on abnormal vibration following 22,300 hours and 95 starts since the last HGPI in November 2018. A subsequent BI showed S3B material liberation but no evidence of foreign object damage.

Further inspection revealed SB2 degradation on 92 10-hole (cooling) blades supplied by a third party, including airfoil impact damage/cracking on 14 blades, shroud damage on 89 blades, missing leading-edge shrouds on four blades, and shroud cracking on 85 blades. Regarding the SB3 row, all blades lost shroud area, but there was no noticeable root damage or fractured, heavy impact damage.

Fourteen of the third-party S2B blades were compared to original OEM blades and it turned out that airfoil and tip shroud geometries were not placed in the same position and bucket tips were lifted significantly. Six S3B blades similarly compared were consistent except one blade showed localized differences because of bending from impact damage.

Overall, there was “strong evidence” of creep damage in the S2B shrouds and no noticeable evidence of creep damage in the S3B shrouds. Site-to-site comparisons of operating data revealed that the failed unit runs relatively hotter than the other 7F.03s in the user’s fleet—similar to Dot 04s in fact, based on historical exhaust temperature data. Long-term solution was to replace the S2B rows of blades with ones of OEM design.

Component lifecycle management

While these slides act mostly as prompts for a facilitated discussion with the audience, they do offer insights into what is keeping this owner/operator GT expert up at night. In particular, as components approach end of original expected life, there is competition for supply of new parts and shop refurbishment space.

Meanwhile, additional lifecycle issues continue to be discovered, putting additional pressure on fleet owner/operators. Another complicating factor: OEM TILs and bulletins go through many revisions. The presenter cited GER 3620, now on revision P (2021).

If you and your team are trying to set an overall fleet life and refurbishment strategy, this likely is a presentation worthwhile reviewing.

Fuel-gas SRV actuator issue

At this 7FA.05 site, the safety/speed ratio valve (SRV) (with digital valve positioner DVP) tripped on a fault, then the same SRV tripped in the companion unit. The first unit then tripped twice, after the SRV was repaired, because of relay issues. There was actuator gear damage, for which the OEM is performing an RCA. The P2 cavity pressure transmitter reading was fluctuating rapidly, but once the input filtering was changed, the fluctuations were greatly reduced.

Although the site-specific details (including many control system diagrams, jargon, and acronyms) are available in the slides, the action items are probably of most use to readers:

  • Have full SRV spares available, including the DVP, onsite and back-up the DVP software.
  • Make sure spare relays and contacts are available and test new relays in the shop before stocking them in the warehouse.
  • Be familiar with Woodward diagnostic tools and software.
  • Lubricate actuator and stroke valves periodically.
  • Monitor deviation between valve command and feedback.
  • Review alarming strategy and configure additional signals if necessary.
  • Review P2-cavity pressure-transmitter signal input filters and adjust as necessary.

DLN2.6 system tuning

This user presentation with over 50 slides is essentially a primer on the DLN2.6 combustion system. Broad topics covered include an introduction to fire and flames, fuel gas system and combustion components, control variables and terminology, DLN modes and startup sequence, acoustic dynamics, emissions, DLN2.6 tuning, and overview of DLN2.6+ and AFS.

7F Users Group 2023: Vendor Presentation Recaps

By Team-CCJ | April 2, 2024 | 0 Comments

After reading the high-level summaries of the vendor presentations from the 2023 7FUG presented here, go to www.powerusers.org and look at the slides, available for viewing to user members of Power Users (user non-members will have to apply and be approved by the leadership). If you are responsible for 7Fs in your fleet, the editors believe you’ll be glad you did. Access an overview of the end user presentation and discussion topics here.

Gas turbines

Gen 2 combustor-cap effusion plate design is said to have a service life of 48,000 hours and 1800 starts (Fig 1). It takes advantage of the vendor’s stated unparalleled repair experience with liners, transition pieces, and caps over 18 years. Expansive design details include new materials, new cooling-hole dimensions, more closely spaced outer-diameter holes, changes to lip height, and others. Slides offer a thorough review of OEM and Gen 1 designs and operating history. Presenter challenges the notion that the OEM’s Technical Information Letter (TIL) recommendation to include a thermal barrier coating (TBC) to the part will always solve problems.

Design and Development of a DLN 2.6 Combustor Cap Effusion Plate, Aaron Frost, APG

 

Flow testing of transition pieces, an “uncommon practice” in the industry, has been implemented at vendor’s shop for combustion-system optimization. It can help address exhaust-temperature-spread issues, ease combustor tuning, and assist in troubleshooting. Photos of sonic and vacuum flow testing equipment are included, along with diagrams and descriptions of combustion system components.

Combustion System Optimization, Jim Neurohr, Sulzer Turbo Services Inc

 

Single-crystal components are “fully repairable,” with attendant performance improvements, and has been demonstrated through company’s experience, beginning with an EPRI demonstration project. Case studies review first-stage-blade tip restoration and coating, and first-, second-, and third-stage nozzle repairs.

Gas Turbine Parts Repairs and Solutions, Jose Quinones, MD&A

 

Upgraded 1-2 spacers featuring 11% cyclic stress reduction are just one of several component replacement and repair options as a result of company’s reverse engineering, production, and repair development programs. There are “replacement options for all problematic components,” and repairs to correct disc issues, compressor dovetail cracking, first-stage-disc balance weight and groove cracking, first- and second-stage-disc cooling-slot cracking, 1-2 spacer rim cracking, and second-stage-disc lockwire-slot cracking, among others.

7FA Rotor Life Assessment with 1-2 Spacer Cracking Evaluation, Mark Passino, MD&A

 

Failure analysis can be a “strong learning opportunity,” says the presenter of this tutorial, which is based on a chapter from a one-day course offered by the vendor. Collecting O&M data and history, conducting root-cause analysis, elements of expert witness activities, writing good reports, and metallurgical analysis and NDE techniques are all explored (Fig 2). Conclusion? An expert at failure analysis is a “bad-ass miracle worker.”

GT Failure Analysis, Doug Nagy, Liburdi Turbine Services Inc

 

Exhaust noise at a simple-cycle GT site is addressed in a case study including problem definition, site engineering (noise study, vibration testing, and thermography), modeling, engineering solution, and evaluation of performance, which proved to be better than predicted. The 9 × 9 bar silencer array and modified turning-vane set subsequently installed also reduced total pressure loss by 0.5 in. H₂O.

Dynamic Case Studies on Turbine Exhaust Systems—Gas Path Upgrades, Scott Schreeg, SVI Industrial

 

Managing end-of-life (EOL) rotor issues requires at least a two-year planning cycle, maybe three, if you have one of the 400 7F units installed between 2000 and 2004. Reason: A hundred of those rotors will need major service or replacement over the next few years. Presenter covered many life evaluations, upgrade packages, and replacement options—including complete flared and unflared offerings—as the industry struggles to handle the volume of 7F EOL needs.

Managing the 7F Rotor Wave with Ingenuity, Brian Loucks and Katie Koch, PSM, a Hanwha company

 

Hypothetical nighttime emergency trip at full speed/full load is imagined to illustrate how company can work with a customer after the borescope inspection reveals heavy compressor damage. Simulated failure situation steps through mobilization of field service crew, preservation of evidence, on- and offsite activities, in-shop rotor evaluation, client reports, repairs/coatings, replacement parts and manufacturing, rotor balancing, root cause analysis, materials evaluation of failed components, and rotors and components successfully returned to site and put in service.

A Bump in the Night, Jim Neurohr, Sulzer Turbo Services Inc

 

Options for extending unit turndown to remain relevant during the market transition from fossil fuels to non-carbon energy sources are explained. Options are anchored by the vendor’s Ecomax® software, including the integration of inlet-guide-vane (IGV) angles with an inlet-bleed-heat (IBH) engineering upgrade. Interestingly, investment attitudes, based on a popular annual survey of executives, around solar, wind, and storage dropped significantly between 2021 and 2022, while natural gas grew three percentage points.

Turndown or Shutdown? Combatting the Effects of Increased CCGT Cycling, Jeff Schleis, EthosEnergy Group

 

Fleet issues with exhaust frames are described and enumerated, along with company’s upgrades for the flex-seal retention assembly, L seal monoblock, parting joint, and airfoil and insulation packages. Replace, refurbish, and repair decision methodologies are illustrated with several case studies.

7F Exhaust Frame R3 Modifications and Upgrades: 2023 Update, David Clarida, Integrity Power Solutions

 

Upgraded or repaired liner plates in transition ductwork between the turbine exhaust and HRSG can be provided along with exterior (for example, thermography) online, and interior offline, inspections to identify problems and failure areas. Also discussed are services around compliance with the ASME Power Piping Code for high-energy and covered piping systems. Expansion joints, HRSG pipe penetration seals, and HRSG inspection and performance analysis complement vendor’s portfolio of services.

7F Transition Duct Liner Plate & HRSG High Energy Piping Programs, Ryan Sachetti, IAFD

 

Water-repellent air intake filters made of synthetic materials are now available from company which has been exclusively supplying one major GT vendor since 2019 and now has special agreement for the US market beginning 2023. Data from case study of an F-class unit in a coastal wet/foggy northern European plant supports claims of better performance. Other company capabilities: acoustics, wet compression, evaporative coolers, chillers, and anti-icing systems.

New ISO 29461-2 for Gas Turbine Air Inlet Filters, Gianluca de Arcangelis, NRG-Faist

 

HRSGs

Fouling of HRSG tubes, contributing to higher turbine exhaust backpressure adds risk for machine trips and runback during cold-weather operation, which has been under the regulatory microscope in recent years. Actions for preventing gas-side fouling are presented, with a caution not to ignore baffles, relatively inexpensive and often overlooked. Expert examines six topics which, when addressed together, can restore up to six megawatts of output.

Improving HRSG Efficiency with Operational and Design Modifications, Cesar Moreno, HRST Inc

 

HRSG tube-plugging options are worthy of consideration because “tube leaks happen” and often it is necessary to get the unit back online quickly (Fig 3). Generally, though, you should strive to fix the leak and seek to identify and address the cause. Slides run through the typical causes of tube leaks with plenty of detail on four tube plugging options, attention to ASME Boiler & Pressure Vessel and National Board Inspection Codes; and pros and cons of plugging. Always insist on a documented repair plan before beginning a plugging project and be sure to stock tubes and plug materials.

HRSG Tube Plugging Strategies to Simplify Tube Leak Repairs in Aging F-Class Units, Lester Stanley and Rich Miller, HRST Inc

 

Steam turbines

Warming your steam turbine and HRSG between shutdown and startup addresses fatigue issues, emissions and fuel consumption, and performance losses. A D11 case study reveals impressive results, such as combined-cycle start times improving from 266 to 149 min (Fig 4), and reduction of high-pressure-rotor life consumption by 25%. Photos and explanation of sophisticated insulation and electric warming systems for ST/Gs are provided. A beta site is being sought for a new HRSG warming system developed with EPRI. Vendor has added onsite machining services for steam valves.

Complete Cycle Solution for Optimized CCGT Startup, Pierre Ansmann, Arnold Group

 

Generators

Emergency purge of generator H₂ coolant can avoid catastrophic loss during fires, seal-oil issues, H₂ piping failures, and severe weather events.  A photo montage of explosions reveals how serious such loss can be. Fast-purge package, including the fast degas CO₂ skid and gas monitoring and control piping, allows all purge operations to be managed from the control room via DCS or locally on HMI. System also can reduce purge times to less less than one hour.

Benefits of the Generator Fast-Purge Package on a GE7FH2 Generator, Rob Kallgren, Lectrodryer

 

Generator collector performance depends on consistent and adequate brush film, adequate contact pressure, proper ring surface conditions, and continuous brush-to-ring contact. Daily/weekly monitoring with minor maintenance is key. A plethora of photos document and illustrate common problems and solutions such as footprinting (also called ghosting, photographing), brush restrictions, brush-holder spacing and alignment, contamination, wear patterns and mechanisms, repair indications, collector-ring resurfacing, and vibration.

Generator Collector Performance and Maintenance, Jamie Clark, AGT Services

 

Complete stator replacement is reviewed as a veritable photographic journey for a unit which, in October 2020, experienced core looseness at the turbine end and broken off core laminations (Fig 5). Site involved has two 2 × 1 blocks with dual-fuel 7FA gas turbines, one block with a D11 steamer (commissioned in 2011) and the other with an Alstom turbine/generator (commissioned in 2006).

7FH2 Stator Replacement, Shawn Downey, MD&A

 

General, BOP

Incorrect tightening of bolts can lead to catastrophic failure, and bolt stretch is a key factor in proper bolt tightening, because stretch is directly proportional to the tensioning force applied. A detailed list of tips for proper tightening is included in Fig 6.

Coupling-Stud Stretch Measurement Can Make or Break Turnaround Time, Dan Johnston, Riverhawk

 

Polyalkylene glycol (PAG)-based electrohydraulic control (EHC) fluids are compared to several different phosphate ester formulations, with pros and cons delineated for each. After 10 years of use at one site, vendor’s PAG-based EcoSafe EHC S3 DU showed an impressive total acid number, a key performance index. One powerplant with three steam turbine/generators running on the same charge of this fluid reported “no issues with system pumps, servos, or actuators, no detrimental effects on fluid from temperature excursions, and fewer issues with moisture contamination.”

PAG-based EHC Fluid, a Sustainable Alternative to Phosphate Ester for EHC Application, Chris Knapp, Shell Lubricant Solutions

 

The Mobil™ turbine-oil triage chart can be applied for mitigating varnish, says presenter, after you’ve assessed the situation you are trying to address (extend outage intervals, correct operational issues, support future conversions) and gathered basic information and conducted a root-cause analysis. Impact photos from the use of several different Mobil products and services are included.

Mobil™ Turbine Oil Triage Guide, Chandler Rogers, Mobil

 

Third-generation dual-fuel water-injection system components (Fig 7) are said to have performed very well at the customer site referenced: liquid-fuel starts and transfers exceed the “industry standard success rate,” purge-air check valve operates with no leakage, check valves and three-way purge valve experienced no failures over multiple years, and water-injection flow proportioning valve operated multiple years without failures, despite thousands of hours of downtime.

20 Years of Reliability: A System-Based Case Study, Dual Fuel with Water Injection, Schuyler McElrath, JASC

 

Comprehensive weather readiness assessment can help ensure that your site complies with latest regulatory mandates that plants provide maximum and minimum ambient dry-bulb temperatures to which units can operate without a forced outage, derate, or failure to start. Checklists for turbine/generators; fuel supply, plant air, lube oil, cooling, and water systems; and cabinets and compartments are included.

Extreme Temperature Readiness, Jason Neville, TG Advisors

 

Expanding sleeve bolt technology can avoid problems like seized fitted bolts and studs, which often have to be destroyed to be removed and can lead to damage to the coupling holes themselves, extending downtime. Vendor’s EZFit technology can be considered a permanent replacement for other prevalent designs.

Turbine/Generator Coupling-Bolt Solutions, Peter Miranda, The Nord-Lock Group/Superbolt

 

Tutorial on the use of hydrogen as a fuel includes H₂ properties, sources, value-chain considerations, percentage in blends, industry experience, and challenges to adoption.

H₂ as a Fuel for GTs in the Power Industry, Gus Graham, CRDX Carbon Reduction Systems

 

High-pressure water-mist systems for fire suppression are explained, then compared to other options such as CO₂, Halon, dry chemical, inert gas, and low-pressure water mist. Three HP water-mist delivery-system designs (skids, fluid containers, piping) are illustrated. Meeting water quality recommendations is a must when using these systems, and design should meet the NFPA definition of water mist—99% of droplets at minimum operating pressure are less than 1 mm in diameter (layman’s version).

Water Mist Fire Suppression for Power Generation, Dale Shirley, Marioff NA

 

Controls

Findings and observations from the perspective of an owner’s engineer during the upgrade of two gas turbines from a Mark VI/EX2100/LS2100 to a Mark VIe/EX2100e/LS2100e control system are presented.

Control Solutions, Abel Rochwarger, GTC Control Solutions, a division of AP4 Group

 

The impact of instrument-related events on machine reliability opens this slide set, with statistics worth contemplating—for example, upgrades and maintenance would have prevented 40% of the reported failure events. Balance of preso reviews reliability assessments for exciters and load commutated inverters (LCI), component replacement intervals, maintenance and testing of on-shelf electronics, TILs associated with these components, and performance evaluation.

Exciter and LCI Controls Reliability for 7FA Gas Turbines, John Downing, TC&E, a division of AP4 Group

 

Reactive, proactive, and predictive M&D services have been developed around the company’s digital products, primarily Autotune, now serving over 100 assets. Examples of the three types of M&D are included. Under proactive, for example, are checking combustor dynamics signals during transients and early signs of combustion anomalies. Predictive examples are based on comparing unit performance to a larger fleet of machines.

Digital-Twin Alignment Between Design Intent and Real-World Power Plant Operation, Gregory Vogel, PSM, a Hanwha company.

WORK MANAGEMENT: A proven method for improving operational reliability

By Team-CCJ | April 2, 2024 | 0 Comments

By Rishi Velkar and Todd Robison, NV Energy

Combined-cycle plants built during the construction boom of the late 1990s/early 2000s are now about 70% through their 30-yr design lives. Although not originally designed to cycle, ever-increasing amounts of solar energy readily available on the grid, especially in the Southwest, make it economically prudent for these plants to cycle off completely from time to time throughout the year.

However, cycling and plant age contribute to premature equipment failure, negatively impacting reliability and increasing operating costs. It’s important for plant personnel to be proactive to properly address issues affecting availability and avoid outages of long duration.

The following case history concerns NV Energy’s Chuck Lenzie Generating Station, a 2 × 1 natural-gas-fueled combined cycle located about 30 miles north of the Las Vegas Strip. The plant has two power blocks, each equipped with two 7F gas turbine/generators and one D11 steam turbine/generator.

Lenzie, which went into service in 2006, achieved an equivalent availability factor (EAF) of 98.6% in 2023, its highest ever. While the number of starts doubled from about 63 per turbine in 2022 to more than 140 per turbine in 2023, the Lenzie team was able to reduce the plant’s forced-outage hours to only 153 compared to more than 1000 hours from the prior years. This was achieved primarily because of Lenzie’s strong adherence to NV Energy’s work management policy/practices (figure).

Recall that the primary purpose of work management is to recognize, define, prioritize, and document the maintenance effort required to restore and preserve system function for reliability. Work identification encompasses both reactive (corrective) and proactive (preventive) work and requires cooperation between the operation and maintenance staffs. The outcome is quality work that improves plant reliability and availability.

Process plants typically have a Computerized Maintenance Management System (CMMS) incorporating work orders that can build up over time if not properly maintained. Lenzie started 2023 by reviewing, with representatives from both operations and maintenance, each work order in backlog.

Result: The backlog of corrective maintenance orders was reduced from 600 to 120, the preventive work orders from 100 to 20. Note that NV Energy refers to a storage place for work orders that have not been closed as “The Backlog.”

An accurate Backlog is necessary to continually evaluate maintenance requirements and successfully perform work planning and scheduling activities. Duplicate work orders, and jobs that had become irrelevant or impractical, were purged from the Backlog; they divert attention from real priorities and make it impossible to accurately gauge the workload.

The next step in the work-management process is a critical one involving the work planning done by way of scheduling software. Work scheduling is the process of work management that enables the plant to improve the effectiveness and efficiency of the maintenance effort by doing the right work at the right time using the right resources.

The process of work scheduling is essentially determining the when and who of the work-management process by prioritizing the work backlog and then matching it to the available resources. This is conducted using the principle of joint prioritization—the collaborative prioritization of work among key stakeholders.

Another critical piece of the puzzle is to maintain the Short Notice Outage Workorder list (SNOW), a list of work orders that take an outage to complete. It is vital to plan the work in advance so when an opportunity presents itself during an outage, forced or planned, the work can be completed, not put off until the last minute. At Lenzie, the SNOW list is reviewed and modified/updated multiple times annually.

However, the most important practice that a powerplant should adopt is to have constant communication between its operations and maintenance organizations. Since operations is the most important customer at any plant, it is the eyes and ears in the field and the first alert to issues. But these must be communicated to maintenance and it is vital for management to provide a platform to support these discussions. At Lenzie knowledge is transferred during the morning meeting at 6:10, after the shift change. This is where operations makes maintenance aware of any issues that present a reliability risk.

Also, as power companies plan to retrofit and upgrade legacy equipment and processes as plants approach end of life, one topic often left out of the discussion is the importance of stocking critical spare parts. Having critical spares on hand can reduce downtime significantly. During 2022-2023, Lenzie personnel identified and stocked more than 200 spare parts in the warehouse.

Finally, keep in mind that Lenzie was able to exceed its EAF goal by adopting a proactive maintenance approach. Given that combined cycles likely will be cycling more in the future, this might be a good time to review your plant’s mode of operation and method of maintenance planning.

Air-Cooled Condensers: ACCUG 2023 Conference Recap

By Team-CCJ | April 2, 2024 | 0 Comments

The 13th annual meeting of the Air-Cooled Condenser Users Group (ACCUG) was held June 20 – 22 (2023) at Dominion Energy’s offices in Glen Allen (Richmond), Va. Strong international participation, interaction, and discussion enhanced the benefit of this event to all ACC owner/operators, service providers, and technical consultants worldwide.

The presentations discussed below, which focus on chemistry and corrosion, design and performance, and operation and maintenance, are available at acc-usersgroup.org. The next meeting of the ACCUG will take place in London this July. Registration is now open.

Chemistry and corrosion

Barry Dooley, Structural Integrity (UK) and conference co-chair, opened the conference with a backgrounder on ACC corrosion and cycle chemistry, stating that flow-accelerated corrosion (FAC) damage to ACCs is the same worldwide with all chemistries and plant types. This led to a discussion of global ACC inspections and common indicators of both single- and two-phase FAC, and a review of the phase transition zone in the LP steam turbine.

Dooley included details on corrosion damage and analysis, and a reference to document ACC.01, Guideline for internal inspection of air-cooled condensers, available at no cost on the user group’s website.

He concluded with an update on film-forming substances, and various technical guidance documents for plants with ACCs, available at www.iapws.org, and also free of charge.

Andy Howell, EPRI and conference co-chair, then examined ACC steam-side finned-tube corrosion downstream of tube entries. He focused on “new information, and a new investigation.”

Howell began with erosion and corrosion of carbon steel in the LP turbine exhaust contributing iron oxide to the condensate, which would impact the surface of the ACC heat exchanger tubing (Fig 1).

More evidence of metal loss typically is found in the ACC steam distribution upper duct and at the tube entries (Fig 2). Metal-loss drivers are velocity and corrosion. At the tube entries, turbulence (velocity) is the highest, and the initial steam condensate is the most corrosive (lower pH).

Observations in 2022 identified metal loss downstream of the tube entry (Fig 3). This is the new information and investigation. Previously, industry focus was on the tube-entry area, and downstream corrosion had not been widely investigated or reported.

So, what are the implications of this down-tube corrosion? According to Howell, investigations are important because:

  1. This may be a major source of iron transport to the steam cycle.
  2. There is potential for tube leaks (air in-leakage).
  3. Investigations will help clarify whether all ACCs are susceptible and may provide more opportunities to reduce metals transport throughout the steam cycle.

Dooley then returned with a detailed look at film-forming substances, focusing on the latest international activities. For more on this topic, see FFS: Sixth International Conference, CCJ No. 75, p 75.

Sam Dunning, Virginia City Hybrid Energy Center, next offered a plant experience report on air in-leakage. Dominion Virginia Power’s VCHEC features two circulating fluidized-bed boilers and one 610-MW turbine/generator, commissioned in 2012. Fuels are waste coal and biomass.

The air-cooled condenser, by SPG Dry Cooling (formerly SPX), contains 10 streets of six bays each, with 36-ft-diam fans. Steam jet air ejectors remove non-condensable gasses from the ACC. Hogging ejectors are used to evacuate the ACC and dual-stage holding ejectors are used for normal operations.

Following a 2021 outage, VCHEC was dispatched to full load. Operators noticed that when switching from hoggers to holding ejectors, backpressure was not maintained. Hoggers were returned to service.

Typical air in-leakage indicators suggested a major leak in the ACC. The energy center was derated by 200 MW for two days and by 100 MW for five days. Troubleshooting, including use of all typical methods of leak detection, met with no success.

Then, a large leak was found in the hogging-ejector isolation valves. It allowed air to be pulled back into the discharge side of the out-of-service hoggers. Said Dunning, “inspection of the valve internals showed the rubber (EPDM) seated valves had lost more than half of their seals” (Fig 4). The rubber had become brittle and the adhesive used to hold the seal in place had deteriorated. Other valves were checked and all were experiencing the same failures.

Valves were replaced in-kind for operations, and later replaced with metal-seated ones.

Dunning’s observation and recommendation: The seat design of the rubber-lined seal limits the rating level of vacuum valves. High-performance butterfly, including triple offset styles, should be considered. He added that “if rubber-seated valves are currently in vacuum service, periodic inspections should be conducted more frequently as the valves age.”

Design and performance

Carlo Gallina, Cofimco (Italy), presented FRP-carbon twin shaft for axial fan blades. Said Gallina, “research and experience showed the need for an improved shaft to connect the blade airfoils to the hub. This led to the pultruded FRP-carbon twin shaft to improve the blade load capacity of large fans in both ACCs and cooling towers.”

He reviewed the basics. Lift must be generated for each blade, but varies because of aerodynamic disturbances—including mechanical obstacles (walkways, etc), wind gusts, and fan location within the ACC. Bending moment and lift are transferred to the hub, drive system, and structure, all influenced by the varying loads.

“Therefore,” he explained, “the blade connection to the hub must be strong enough to withstand high loads generated at the shaft.”

Rigid solutions transmit loads to the structure and can cause vibrations. “Using pultruded FRP-carbon shafts gives the blades suitable flexibility, and reduces vibration. Plus, the high strength of carbon limits blade deflection.” Plus, plus, the natural frequency of these blades is far from typical fan forcing frequencies.

Next, Gallina introduced the Cofimco twin shaft for axial fan blades featuring a “binocular shape” (Fig 5, right). He then reviewed full details of work at Cofimco’s test rig complex in Italy. Conclusions:

  • The twin-shaft blades can withstand severe duty points and manage high, abrupt loads.
  • Blades generally can be operated from zero to 100% speed when driven by a VFD.
  • Vibrations and loads introduced to the structure are greatly reduced.

Huub Hubregtse, ACC Team (The Netherlands), discussed Common performance problems for ACCs. “In general,” he began, “there is a lack of technical knowledge by operators, and many ACCs have performance problems, especially in summer. Not all operators have enough knowledge of the processes to analyze the system.”

He outlined and discussed the primary impacts on performance:

  • Fans in respect to air flow and static pressure.
  • Recirculation of hot air.
  • Fouling.
  • Steam distribution in heat exchangers.
  • Leaks.
  • Noise (indirectly).

Static pressure reduces air flow and increases motor power requirements. He discussed fan measurement criteria for air flow, static pressure, and absorbed power.

“Recirculation means hot air from the top is sucked down to the fan inlet, resulting in warmer air for cooling,” he explained. The main cause is the difference in suction pressure at the fan inlet and the pressure at the outlet of the ACC. This can be caused by a nearby building, wind, or other factors. To check this, he suggests measuring air temperature in the plenum and air temperature at a distance.

“Fouling from dust, seeds, and insects can obstruct the space between the tube fins, resulting in higher static pressure and less air flow,” he continued. Most fouling can be removed with high-pressure washing (1300 to 1600 psig). Other fouling can be difficult and require blasting with sodium bicarbonate or similar method. “The performance impact of cleaning can be enormous,” he offered.

Hubregtse continued: Steam flow through the ACC heat exchangers is controlled by the small (15 mbar) pressure difference between inlet and outlet. Flow reduction causes can be fouling, vacuum pumps, or layout of the suction piping. Testing with thermal imaging should reveal the problems.

Imaging can show low pressure differentials in the middle of the tubes, for example. The suction processes will take vapor/steam before they take air. If there is a leak, air can penetrate the system, blanketing the inside of the finned tubes. A simple vacuum drop test can indicate leak rate.

But finding the leak can be difficult. “The most common and reliable way to find leaks is to spray helium gas near a suspect location and test the ACC for helium in real time. Helium testing can be expensive (and time-consuming), but is reliable,” he explained.

Although noise is not directly related to performance, “some operators reduce the speed of the fan when noise is a concern,” he noted. If this occurs, “the blade angle has to be increased to compensate for the loss of air flow.” One danger is that the fan can go into stall, reducing the air flow.

Keith Paul, EPRI, followed with Infrared drone inspection of an air-cooled condenser to analyze heat distribution. The subject site was New York Power Authority’s Zeltmann Power Project, a 576-MW, 2 × 1 7F-powered combined cycle in Astoria, NY, commissioned in 2005.

Before the site visit, drone calibration runs were conducted at Evapco Test Labs in Maryland. “We ran the same drone, tested camera resolution and distances, and tested air in-leakage detection with intentional in-leakage.”

His conclusion: “Based on our experience at Zeltmann, and at Evapco’s test lab, we cannot say that drone infrared inspections provide definitive leak-detection services. This is still a work in progress.” The site switched to still cameras.

On the positive side, initial results at Zeltmann allowed the plant to focus on specific sections for possible repairs in an upcoming outage.

“EPRI is now developing a test methodology to use acoustic cameras mounted on a drone to inspect air-cooled condensers,” Paul explained. This is based on success with handheld acoustic cameras. This ongoing drone work is a potentially strong time-saving technique.

Hector Moctezuma, Valia Energía (Mexico), offered an Update on a hybrid cooling retrofit installation, first presented to ACCUG in 2014. He spoke first about the plants in his country.

“Plants are often not able to reach maximum output during summer due to high steam-turbine backpressure from the main condenser, which limits use of duct burners and sometimes means reducing CT output to avoid a steam-turbine trip,” he said.

More specifically, “This significant power output reduction is due to ACC under performance in summer and with windy conditions.” ACCs have also experienced physical degradation through the years, mainly severe fouling and tube damage.

“With the help of SPIG USA, a parallel condensing system (PCS) was chosen in which exhaust steam is simultaneously condensed in both a wet evaporative and the existing dry cooling system” (Fig 6).

“The goal is to remove the steam-turbine backpressure limitation during all periods with ambient temperature higher than 86F (1000 hours per year) by adding enough wet cooling capacity to the existing 32-cell ACC.”  The design considers local water limitations.

The speaker reviewed results for the nominal 500-MW Unit IV at Rio Bravo Energy Park after addition of the wet cooling module in Fig 7. The highlights:

  • Elimination of the backpressure limitation, with a significant sustained improvement of up to 80 mBar (2.36 in. Hg).
  • Power output increase of 20 MW attributed to the condenser pressure reduction and ability to increase condenser load.
  • Heat-rate improvement due to lower condenser pressure (lower backpressure on steam turbine).
  • Power-consumption increase by auxiliaries of about 500 kW for the cooling-water pumps, blowdown and makeup pumps, and cooling-tower fans.

This gives “consistent and repeatable operational reliability under adverse summer conditions after nine years of operation,” he stated.

György Budik, MVM EGI (Hungary), presented on the Hybrid delugable cooler in Dominion’s Greensville CCPP which satisfies the facility’s auxiliary cooling needs using a 50/50 mixture of glycol and demin water. The cooler is located at the opposite end of the plant from the 80-cell ACC (Fig 8).

Hybrid wet/dry coolers like Greensville’s (Fig 9), Budik explained, “offer a dramatic reduction in cooler size relative to all-dry coolers, and, therefore, a significant reduction in civil and maintenance work.” The speaker reviewed some delugable systems installed by his company, including the first such units, which were installed in Iran.

The auxiliary cooler consists of 16 modules arranged side by side, the first five (left side) and the last five (right side) are dry, the remaining six (bays 6 – 11) are capable of deluge service.

Bays have two cooling modules, each with two 12-m-long aluminum cooling elements, best illustrated in the Fig 10 photo. The cooling modules serving all bays are connected in parallel to a common inlet and outlet manifold.

In the deluging bays, sprinkler pipes are installed at the top of the cooling elements, providing a continuous downward flow of water on the external surfaces of the heat exchangers. The Fig 10 illustration explains this.

The operating principle of the deluge system is that partial evaporation of the deluge water keeps relatively cold the rest of the water on the heat-transfer surface, thereby providing additional cooling.

Deluge water is supplied to the heat exchangers from the tank shown in the figure. Water not evaporated is collected in a trough at the bottom of the module. The trough drains to the deluge water tank. A makeup line keeps the amount of water in the system constant. Note that water of good quality is required for makeup, with first-pass RO product acceptable.

Motors driving the deluge pumps are equipped with variable-frequency drives. Operation of the deluge system is not recommended at ambient temperatures lower than 98F, all-dry operation providing sufficient cooling. Use of the deluge system would result in unnecessary water loss from drift, evaporation, and blowdown.

At temperatures above 98F, the number of fans operating in deluge modules are governed according to the following control steps:

  • Step 0: standby, steady state.
  • 1: 12 VFD-controlled fans in bays 6-11 start simultaneously.
  • 2: Front-side fans in bays 1-5 and 12-16 start.
  • 3: Dummy step.
  • 4: Remaining fans in bays 1-5 and 12-16 start.
  • 5: Deluging starts in two bays.
  • 6: Deluging expanded to four bays.
  • 7: Deluging expanded to all six bays (Nos. 6-11).

Note that with Step 7 actuated, design performance conditions are achieved with one fan out of operation.

Next objective for the new hybrid cooling technology demonstrated at Greensville likely is its use in conjunction with dry cooling systems for combined-cycle plants (sidebar). The deluge ACC is touted by its EU sponsors as being the most efficient dry-cooling solution for high peak ambient temperatures. Plus, it is said to resist adverse ambient conditions such as high-speed winds and hot air recirculation.

Other benefits include less auxiliary power consumption, smaller footprint, and lower construction costs compared to dry-only systems. And less water consumption compared to all-wet systems.

ACC with deluge cooling: Not yet, but likely soon

Literature from Enexio Water Technologies GmbH touts Deluge ACC, described in the diagram, as the latest technological achievement in hybrid cooling, where the primary interest is in dry cooling, but where limited water resources are available for use during certain times of the year.

Recall that while dry cooling methods offer an order-of-magnitude reduction in cooling-water consumption compared to wet cooling, overall power-cycle efficiency generally is higher when wet cooling can be part of the solution.

Enexio is one of the consortium partners of the EU-funded Horizon 2020 research and innovation program called MinWaterCSP. Its goal is the development of cooling technologies and water management plans to reduce cooling-system water consumption by up to 95% relative to wet-only cooling systems.

Galebreaker Industrial’s Gary Mirsky presented CFD study of airflow and performance improvement potential. His example was a 2 × 1 plant rated at 578 MW (steam turbine output, 295 MW) commissioned in 2008.

The goal was to increase backpressure trip limits as part of a larger upgrade to increase both gas-turbine output and ACC heat rejection. Another objective: Mitigate wind effects on ACC performance.

The ACC is two units, each with three streets and five cells per street. There are buildings in the immediate area. The best performance solution was a combination of options with both perimeter and cruciform screens.

Operations and maintenance

Mike Owen then presented the latest ACC-related research activities at Stellenbosch University in South Africa. It is home to an active research group specializing in ACC and dry-cooling activities, and is a frequent participant at ACCUG events.

Topics this year included prediction of large-diameter axial-flow fan noise and performance, dynamic blade loading, modeling improvements, machine learning for performance monitoring, and fan drive-train dynamics.

Owen also covered specifics of operation and controls—including air-extraction valves, fan speed range and fan hardware, fan gearbox/motor/VFDs, two-stage air ejectors, drain pot, and pumps. Most of these items would be mentioned during the site tour of Greensville on the last day of the conference.

Jeff Petrillo, Dominion, introduced the group to the Greensville County Power Station with ACC lessons learned. He presented a site overview to familiarize those joining the tour with the facility’s layout and principal equipment. The latter included the following:

  • 80-fan (VFD) ACC with 10 streets (five east, five west).
  • One condensate receiver tank with two deaerators.
  • Four liquid-ring vacuum pumps.
  • Two two-stage steam-jet air ejectors.
  • One drain pot with two pumps.

Jacques Muiyser, Howden Netherlands, presented ACC fan dynamics: Potential problems and solutions. The basis of this discussion: ACC fan blades and/or connection bolts can fail because of high dynamic loads. Muiyser discussed sources and consequences of dynamic/cyclical blade loads, and development work to confirm that a stronger hub design with a more rigid bolt-to-bolt connection can help avoid bolt failure from fatigue.

He began with a refresher course on blade dynamics and mechanical properties, also covering flow distortions attributed to obstructions and crosswinds before moving on to case studies.

In the first case study, owner/operators noticed isolated U-bolt failures at a site. Strain-gauge measurements revealed resonance at high fan speed. Performance measurements then showed the blade angle could be increased while reducing fan speed to avoid the failures while maintaining performance.

In the second case, recurring issues were blade separation at the leading edge, and blade clamping-bolt failures (straight bolts). For the blades, strength was corrected with additional laminate on the leading edge. The clamping bolt issues were corrected by adding a secondary hub ring, connecting all of the clamping pieces.

In Case Three, straight-bolt failures shortly after installation showed signs of failure, primarily at edge cell fans. Root cause was high dynamic loads attributed to winds and high-speed resonance. A modified hub ring was installed to reduce equivalent dynamic loads.

“The hub ring assembly has proven to be an excellent retrofit solution for sites with high dynamic loads. This solution has been tested on site and the design has been refined through testing in the laboratory and numerical simulations,” said Muiyser.

Edwin Houberg, Sumitomo Drive Technologies/Hansen Industrial Transmissions, introduced the Hansen M4ACC gearbox for forced-draft and the Hansen M5CT for induced-draft applications.

The first features mono-block housing, no external piping, and an integrated drywell to reduce leakage risk. One option is a patented mobile brake system to slow down and stop the gear unit during maintenance activities.

The M5CT is a “new right-angle industrial gearbox series dedicated to induced-draft cooling technology,” he explained. This features an extended bearing span with heavy-duty roller bearings for strong shaft support. Numerous instruments and accessories are available.

Jeff Ebert, Galebreaker, then discussed Mitigation of extreme high seasonal winds. His example was a 353-MW gas-fired powerplant in Saskatchewan, Canada, commissioned at the end of 2019. Seasonal winds there can blow at 19 m/s, reducing plant performance.

Galebreaker was asked to determine the best windscreen configuration, height, and solidity to resolve the performance issues.

Ebert described the evaluations and installation that was completed in April 2023.

Various options were considered and material was delivered in October 2022. This was Galebreaker’s first sloped-structure ACC project (Fig 11).

Various tubular products were added for structural support.

Hubregtse returned to discuss gearboxes for ACCs, listing these critical items to include in specifications:

  • Fan shaft power.
  • Power absorbed during worst conditions (during a storm, for example).
  • Inverter installed, variable or direct.
  • Service factor.
  • Lubrication.
  • Vibrations.
  • Temperature range.

A standard service factor, usually between two and three, allows for vibrations, extreme conditions, startup power, and wear. This is also valid for gears, bearings, shafts, and housing.

He also covered thermal power (heat generated inside the gearbox), forces in gearbox, gearbox selection, lubrication, humidity in oil, vibrations, and deformations.

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