501F 2022 conference recap: User sessions – Combined Cycle Journal

501F 2022 conference recap: User sessions

A Covid outbreak a week or so before the 2022 meeting was to start at the Hyatt Regency in New Orleans, February 20, dramatically reduced the number of attendees expected, both user and vendor. Recall that this conference was the group’s return to an in-person program following a virtual meeting in 2021.

Since many owner/operators participating in the 2023 conference were not able to attend last year, the editors have compiled some of that meeting’s technical highlights below to help you “connect the dots” since the 2020 in-person conference.

User presentations

Just shy of a dozen presentations by owner/operators were incorporated into the seven 501F roundtables conducted in 2022: Inlet and exhaust, compressor, rotor, hot-gas section, combustors, auxiliaries, and outage planning and conduct. Summaries follow. Get the details by accessing the PowerPoints on the group’s website at https://forum.501Fusers.org.

Find them in the “2022 Conference Materials” forum post. Only registered users are admitted to this portion of the website.

2021 outage highlights for this unique 2 × 1 combined cycle, described in two presentations, include a steam-turbine major, ST valve inspections, second majors and FD3 upgrades for the gas turbines, and generator inspections on the steamer and one of the gas turbines.

Planning for the outage, the largest in the plant’s history, started in 2019. Given the large amount of work slated for 2021, some was moved forward to 2020 to free up crane time, reduce interferences, and level-out the workload of facility personnel.

History: First unit installed on the greenfield site nearly 30 years ago was a 501D5. A 501FC+ was added two years later. Year 2000 saw installation of a 501FD2 and a steam turbine. Upgrade of the FC+ to FD2 and conversion to the combined cycle followed immediately.

Key topics in the first presentation were implementation of (1) purge credit, to eliminate purging during startup and (2) inlet heating, to improve availability and expand the unit’s operating range. P&IDs are provided for both enhancements. Lessons learned provide valuable guidance.

Note that the current purge procedure uses normal spin-down time at the end of a run to count as the purge credit for the next run. (Consult NFPA 85 for details.) It eliminated the air entrainment into the oil system experienced with the method replaced which was said to have damaged the torque converter wheel. Benefits of purge credit include a 10-min decrease in startup time, longer oil life, reduced stresses on the HRSG, etc.

The second presentation discusses changes to the outage plan made necessary by Covid-19 restrictions, reviews schedule and contractor laydown considerations, and profiles, by way of photos, rotor swaps and upgrades to single-piece exhaust cylinders on both gas turbines.

GT major inspections and exhaust replacements presentation is recommended reading by the editors, who are both familiar with the facility profiled and similar work done at other plants. Original scope of work for this 501FD2-powered 2 × 1 combined cycle, planned as a 30-day effort, was the following:

  • Major inspection of one gas turbine with rotor exchange and turbine upgrade, plus exhaust refurbishment. Second GT: upgrade only.
  • Steam-turbine medium inspection with bearing and valve replacement.
  • Pressure-wave cleaning of both HRSGs, plus floor-liner replacement on one.
  • Controls upgrade for the entire plant.
  • Generator robotic inspections.
  • Rebuilds of one cooling-water pump and one boiler-feed pump.

The work described in greatest detail is that for the exhaust section. Inspections conducted as soon as the units had cooled found that Row 4 tip measurements in one engine were significantly different than those recorded only five months earlier. Plus, two of the unit’s six exhaust struts severed during that time.

For those not familiar with exhaust sections, the presentation provides excellent drawings, complete with detailed callouts, explaining the issues and parts involved. In addition, there are summaries of both fleet and plant experiences involving the exhaust section.

Repair options to correct the major deficiencies identified included weld repair and exhaust cylinder and manifold replacement. A new plan was developed: Extend the outage from 30 to 45 days to conduct majors on both gas turbines and replace the exhaust cylinders and manifolds on both machines.

The presentation concludes with a list of additional findings and corrective actions.

DLN to ULN conversion. Upgrades of SCR systems incorporated in this 2 × 1 combined cycle’s HRSGs were not viewed as adequate to meet new rules governing NOx emissions and expected future limits on ammonia slip. Ultra-low NOx was selected as the preferred solution. It was believed capable of reducing NOx from 25 ppm to 9 to 12 ppm. Pictures describe the work in progress.

Here are the results described by the speaker:

  • Plant output decreased by about 5 MW.
  • Plant heat rate increased by about 290 Btu/kWh.
  • Combustor dynamics were virtually zero.
  • Plant is meeting its NOx requirements, but struggling with CO.
  • Ammonia consumption has been reduced by about half.

One year of experience with FlameTOP. Presentation discusses recent modifications to one of two gas turbines at this 501FD2-powered 2 × 1 combined cycle that are providing the additional power expected (and sometimes more). Here’s a list of the changes:

  • Retrofit of FlameSheet™ combustors to boost engine output and increase efficiency.
  • Installation of PSM’s GTOP system, with its hardware upgrades to increase output and extend maintenance intervals.
  • Addition of inlet bleed heat to the compressor to increase turndown.
  • Installation of AutoTune 3.0/PLP for tighter unit control.
  • Retrofit of PSM’s exhaust cylinder and manifold.
  • Installation of Arnold insulation for the walls, floor, and ceiling of the exhaust transition duct to reduce performance-robbing heat losses.

FlameTOP7 from PSM is said to increase the simple-cycle output of a standard 501FD2 by 20 MW while reducing heat rate by 3.8%. Unit turndown can extend below 40% of the full-load rating with both FlameSheet and inlet bleed heat installed. NOx emissions are less than 9 ppm across the load range.

After flipping through the slide deck, read “Desert Basin reports experience, success with first 501F FlameTOP7” in CCJ No. 66 (2021) for details.

A second plant also reported a GTOP success, this one involving GTOP6 mods to both engines of the 501FD2-powered 2 × 1 combined cycle—including new combustion hardware, 16th-stage compressor blades, first- and second-stage turbine vanes and blades, and other improvements. The benefits: More than 22 MW of additional combined-cycle capacity and a heat-rate reduction of 80 Btu/kWh.

This presentation is valuable for the balance-of-plant (BOP) assessment described, which was part of the process for evaluating the benefits of upgrading the gas turbines. The report for this effort highlighted safety valves and steam silencers as having insufficient capacity. Plus, the steam turbine’s pressure and temperature limits were identified as a potential limitation, along with both the condensate pumps and the boiler-feed pumps. Changes to safety-valve settings were required, too. Other modifications needed post implementation also are discussed.

Multiple gas-turbine events experienced at a 501F4-powered 3 × 1 combined cycle that occurred during a three-month period are described in this presentation. Here’s a description of the events and what was done to correct them:

  • Operators noted that one gas-turbine in the eight-year-old combined cycle experienced a step change in vibration (relative and seismic) and an output loss of about 1 MW. About a week later, personnel reported hearing a fast-rattle/buzz type of noise inside the exhaust end of the machine. It was accompanied by a nominal loss in unit output of about 3 MW. The engine was shut down and inspected. Initial findings: damage to Row 3 and 4 turbine blades, vanes, and ring segments. Repairs were made and the unit returned to service.
  • A second gas turbine tripped along with a loud bang and high relative and seismic vibrations. Vibration levels across the unit reached trip levels and were at or above 16 mils. Inspection findings included damage to Row 3 and 4 turbine blades, vanes, and ring segments, plus the rotor, exhaust cylinder, lube-oil piping, and inlet manifold. Repairs were made and the unit returned to service.
  • A major inspection was initiated on the combined cycle’s third gas turbine about six weeks after a borescope inspection of Row 3 blades and ring segments did not reveal any significant findings. However, first inspection conducted during the major revealed some distorted Row 3 blade shroud platforms and exhaust-cylinder heat erosion. Unit returned to service after a two-month outage.

Details on how cooling flows and exhaust temperatures were measured at load loads to verify model calculations. Input from Siemens Energy based on RCA results also is summarized.

IGV history/maintenance. The presenter walks you through inlet-guide-vane modifications made over the years to prevent sticking by improving bushing lubrication—the first, for the top half of the bushing, ProdMod 98-1410 in 1998. Westinghouse modified the lower half the following year using the procedure described in ProdMod 99-0240. Siemens Service Bulletin 51004 Rev 2 is recommended reading.

IGV seize-up/icing. The same W501FC+ engine with the sticking problem (summary immediately above) experienced freeze-up when moisture accumulated in some of the IGV bushings (lower half in particular) and the ambient temperature dropped to minus-2F. All blades in Row 1 had ice deposits, those in Row 2 had some ice or frost. Operational information related to mitigation efforts is included in the slide deck.

Problem was resolved by installation of a torpedo heater to defrost ice followed by exercising all the bottom-half IGVs. Borescope inspection revealed no damage. A chart provided by the speaker shows first-stage icing potential at several IGV angles. Attendees were referred to Siemens Energy’s TA 2005-015 Rev 1 to learn more about icing and how to avoid it.

Generator main-lead failure experienced by a South American owner/operator covered problem identification, steps to repair, and lessons learned. Background: Four failures occurred: Broken B phase for the KN steam turbine/generator at this 3 × 1 combined cycle was found in December 2008 and occurred again three months later. Since that time, all main leads have been x-rayed during every turbine outage.

The NDE effort paid off: Phase A in one of the W501FD2 gas turbine/generators was found broken in November 2011 (at more than 900 equivalent starts and 38,000 equivalent baseload hours). T1 failed at the brazed joint below the main lead flange connection to the bushing; x-rays showed cracks in T2, T3, T5, and T6 in locations similar to T1. A second failure occurred in this gas turbine in April 2021 at 1327 ES and 113,453 EBH.

Photos of the first and second GT failures are provided in the presentation together with an overview of repairs, inspections, and tests conducted. Best-effort cleaning also is described.

RCA of a 16-kV flashover. This case history pertains to a unit in reserve shutdown. Incident overview: The GSU and isophase bus (IPB) to the generator circuit breaker (GCB) were energized at 16 kV. A flashover event occurred in the C phase of the breaker on a high-side potential transformer. Inspection revealed water/condensation only in C phase.

Heaters in the IPB were working, but the breaker that feeds heaters inside of the GCB had tripped. Subsequent removal of isophase links at the auxiliary transformer for hi-pot testing revealed water inside of the adapter between the isophase and transformer. Cracks were found in the weld that secures the adapter to the top of the transformer. Photos are provided.

Corrective actions:

  • Cleaned and sealed the weld with silicone and spray sealant and began investigating a long-term solution—including possible weld repair.
  • Added GCB heater breaker status to plant rounds.
  • Planned the addition of humidity sensors and thermometer in the GCB and the transmission of data back to the control system for alarming purposes.

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