There were eight V94.3A user presentations at last year’s meeting, half based on experience in Europe, half in Asia. The European speakers focused on the following: gas-turbine O&M history covering nearly 10 years, generator major, expansion-joint failure analysis and repair/replacement, and combustion tuning to allow an increase in fuel temperature. Presenters from Dubai Electricity & Water Authority discussed GT inspection findings, what is believed to be the world’s fastest major for this frame (11 days), and the underlying cause of fuel-oil flex-hose damage.
Here are thumbnail sketches of the assets upon which the presentations were based:
- Two single-shaft combined cycles with a total full-load output of 870 MW, designed for a nominal 300 starts annually, hot starts (less than 8-hr shutdown) in 15 minutes, warm starts in 50 minutes.
- Two single-shaft combined cycles built in the mid-2000s with a total full-load output of 850 MW.
- Early 2000s repowered oil-fired steam station (2 × 125 MW) burning gas with heavy-oil backup. Current configuration is two 363-MW 1 × 1 × 1 combined cycles.
- Standard 2 × 1 combined cycle rated 850 MW.
- Plant built in stages with 400-MW single-shaft combined cycles installed nearly a decade apart.
- A 590-MW 2 × 0 addition to power and desalination plant.
- Two 375-MW 2 × 1 combined cycles with flash distillers.
Perhaps there’s no better way to learn about plant operations than to listen to a user colleague give an objective review of his plant’s history and be able to ask questions. This speaker’s review covered eight years from commercial start to an extended HGP more than 34,000 EOH and nearly 400 starts later.
He talked about the plant’s experience with hexavalent chrome—sampling and measurement, and dealing with contaminated insulation mattresses. Conclusion: Further investigation is required to assure a safe working environment on the steam turbine.
Another safety topic discussed was working at height, including the use of davits to tie off worker harnesses when climbing on the turbine.
Moving to the compressor, the speaker discussed IGV actuator ring axial wear and repair, plus replacement of rollers, bushings, and pins. A diaphragm exchange made necessary because of wear at vane hooks was another talking point. Exchange of the compressor bearing shell because of damage, the need for new shaft coupling bolts, repair of the coating on the leading edges of airfoils, and other compressor topics kept attendees in their seats.
Mention of a trip caused by the unexpected closing of IGVs during baseload operation was a surprise highlight of the presentation. Analysis revealed the cause was servomotor internal leakage, considered an isolated incident.
In the combustion chamber, minor repairs were required. In the turbine, all vanes were disassembled and reassembled; a few were replaced. Plus, blades in Rows 1, 2, and 3 were renewed.
Recommissioning revealed engine work during the outage enabled a power boost of more than 2%; heat rate also was better.
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The original metal-bellows expansion joint installed between the gas turbine and exhaust duct had 125,000 EOH and more than 1200 starts at the time of failure. Material was described as heat-resistant austenitic stainless steel. The expansion joint was designed for 12,000 cold starts, 620C operating temperature, ±50 mm elongation, and ±1 mm movement in the vertical direction.
Plant personnel knew they had a problem because both the temperature and the concentration of carbon monoxide inside the package had increased significantly. Plant operations were modified to avoid unit trips. Inspection revealed the joint had failed in two locations—at the 12 and 6 o’clock positions—and insulation was damaged. Temporary metal shields mitigated damage to affected components.
Temporary repairs were made about six months after the failure was identified, but the protective pillows and belting holding the pillows became ineffective over time and the replacement of the expansion joint became necessary. The new joint was installed during a steam-turbine outage.
There were difficulties with the installation, which should not be surprising. Examples: misalignment between the exhaust section and the gas turbine as well as cracking and deformation of the transition cone. Leak testing was the final step in the replacement project.
A finding during the root-cause analysis (RCA) investigation was that sliding feet on the exhaust cone were not performing as intended and hang-ups impeded expansion of the joint during turbine starts, causing stresses that contributed to cracking. At user meeting after user meeting the editors hear of problems with sliding feet on heat-recovery steam generators, rotor air coolers, shell-and-tube heat exchangers, etc. They should be inspected and lubricated annually.
The failure of flexible hoses for fuel oil can be avoided in many cases. The speaker describing her experience said that before the unit’s minor inspection, the operator received a fire-detector alarm, and personnel found the flex hose between one burner and the manifold ring completely torn apart. It was replaced. Flex-hose damage also was found on at least one other machine.
Like the condition of sliding feet in the previous experience, the condition of flexible hoses must be monitored. Subject matter expert Brian Hulse, a frequent contributor to CCJ ONsite, acknowledges that hoses are expensive and that users always try to extract maximum value from them before they’re replaced. Replace decisions are not easy because the hoses used on most gas turbines are manufactured with no published shelf-life or working-life limitation.
Hulse says plant O&M personnel should be aware that the following conditions impact hose life and to be on the lookout for them during inspections: chaffing, kinking, prolonged exposure to UV, mechanical abrasion, lying in fluids (water, fuel, oil, etc).
A simple database can help you avoid surprises. Include any recommendations on the care of hoses offered by the gas-turbine manufacturer in the O&M instructions for your machine, note the type of service for each hose cataloged, enter findings of routine inspections, inspection interval, inspection procedure, etc.
Also, bear in mind that some hoses are equipped with an exterior protective sleeve—designed to protect against the hazards of high heat and occasional flame. If this cover is torn, chaffed, or oil-soaked, the hose should be removed from service—especially if it too shows signs of distress.
A generator major was scheduled early based on the OEM’s recommendation to replace all hydrogen seals after about 64k EOH and 1700 starts. Wedge tightness was an initial concern when the unit was removed from service, but the inspection team ruled it “acceptable” based on results of a test method provided by Siemens USA.
Several small cracks were found on the generator’s PPS (hydrogen Performance Plus Seal™) segments. The bumper ring also was damaged. No obvious root cause was identified. The speaker advised that segments can be replaced onsite, but bumper-ring replacement requires a factory visit. Important: Damaged segments cannot be replaced individually; the entire ring must be replaced. Attendees also were made aware of the OEM’s development of a special tool for installing new PPS segments.
Several wrinkles were found in stator top bars. “Advanced” wrinkles could be seen by the naked eye; several other bars sounded hollow on one side when tapped in the same area. Insulation was cracked in areas revealing advanced wrinkles and it was repaired. Engineers determined that wrinkles and delamination were caused by thermal expansion/contraction of the bars during starts and shutdowns, which had increased in recent years. The repairs contributed to a significant reduction in partial discharge, which had been increasing over time.
Generator bushings were changed to ones with cast rather than welded supports to mitigate damage caused by vibration. However, the new design also showed signs of vibration damage on all three phases, as indicated by green dust. Engineers could not determine the cause of vibration. The three bushings had capacitance deviations, likely caused by bad connections between clamp and the inner electrical-field control layer. One bushing was replaced. The other two were relocated to new positions at “star” points, where there is no voltage stress.
An upgraded bearing (MKD11) was installed on the gas-turbine side of the generator because of tilting and problems during turning-gear start. The new bearing has improved lift-oil grooves and coated bearing saddles, but its normal temperature runs about 6 deg C higher. Monitoring of the new bearing is ongoing.
Combustion tuning was discussed by an engineer associated with a practical research project for a large generation company. The goal of the program was to minimize cost of power production while maximizing efficiency and output. Results enable the company to tune its engines at less cost than would be charged by the OEM.
The sticking point described was that while the gas turbine met performance guarantees, it was not possible to operate at the maximum fuel temperature (200C) at low ambient temperatures. The power generator wanted 200C fuel at all times to increase efficiency.
A solution was found whereby fuel temperature was raised and efficiency increased. The annual saving in fuel and carbon costs amounted to more than $US100,000. Plus, NOx emissions were reduced. Work on the project continues with the goal of fine-tuning combustion and saving still more fuel.
Outage time reduction is the goal of virtually all power producers when they are “in the money.” Speaker described how his company was able to reduce the time for major inspections on two gas turbines from 51 days in 2013 to 11 days in 2018 and 2019. Likely you find this hard to believe. Learn what’s truly possible by attending user-group meetings for your engine.
For this case history, be aware that plant personnel were motivated to set a world record for the major inspection of a SGT5-4000F. And they were empowered to do so. There was plenty of relevant in-company experience to draw upon: It owned and operated two-dozen V94.3As.
The first engine to complete its 11-day major (2018) required more than 12,000 man-hours of effort from a field staff of 115 working 11-hr shifts; the second engine’s 11-day major in 2019 took just north of 9400 hours with 95 field staff working 10-hr shifts.
Critical to the achievement were the following:
- Detailed planning and prioritization of work permits to minimize the time needed to isolate various systems.
- Created a fast-track entry process for staff and logistics at the security gate.
- Maximized onsite logistics—such as meals, laundry, transportation, etc—to minimize lost time.
- Conducted a kickoff meeting of all field staff prior to the outage to build a sense of ownership in the project.
- Shifted critical risky activities to outside the overhaul period. The thinking: The shorter the outage the lower the technical risk and the fewer the number of human errors.
Project planning was especially critical to success, the speaker said. Here were some of the key steps taken:
- Activities thoroughly planned in advance with resources mapped to overcome foreseen challenges.
- Staff qualifications were scrutinized and the best team selected.
- Optimized the work-shift model to permit round-the-clock activity.
- Organized and managed spare parts and tools to minimize time constraints.
- Conducted daily project review meetings to identify and eliminate schedule sticking points and to measure progress.
The speaker closed by identifying some considerations to shave days from the outage schedule, including these:
- Consider a rotor swap rather than a shop visit.
- Provide onsite capability for coating compressor blades.
- Review lessons learned and implement optimized findings into your plans.
- Swap out burners, valves, etc.
- Focus on enhanced project management techniques.
Inspection findings were reviewed by an engineer from a major generator. A summary follows:
- Minor inspection revealed TBC loss and some oxidation of the protective layer on the pressure side of two first-stage turbine blades, which were replaced.
- Linear crack indication on the platform of one second-stage blade, also replaced.
- Bearing balls found missing on one side of the turning-gear pinion. It was replaced.
- Lift-oil pump failure was characterized by black-colored oil, metallic chips in the filter, and coupling damage. After failed parts were replaced, oil was run through the filter until clean.
Extended HGP inspections on the gas turbines for one 2 × 1 combined-cycle block (nearly 68k EOH/314 starts) at a two-block plant revealed the following:
- Compressor bearing reverse thrust pads were found scored to a depth of 0.4 mm; coking was in evidence.
- All vanes were removed for NDE, two were replaced because of excessive caulking clearances, IGVs and first- and second-stage vanes were recoated, compressor blades in Rows 1-4 were recoated on the leading edges of the airfoils, some new tiles were required.
During recommissioning, new KV curve settings were required for gas control valves, newly implemented logic called for in product bulletins presented problems, compressor bearing temperature came in higher than expected, the baseload power output was lower than expected, a unit trip was experienced during a switch-over from diffusion oil mode to fuel gas.
The second combined cycle at the plant went through its extended HGP inspection the following year with some of the same findings identified with the first block—such as replacement of a few blades and vanes in the compressor, coating fix on compressor blades. Recommissioning of Block 2 also was similar to that of Block 1.