• Wet compression: a combination of inlet fogging and compressor water injection carried out in the inlet duct. A quantity of water in excess of that required to reach 100% relative humidity sprays into the inlet air stream resulting in liquid droplets of water entering the first stages of the gas turbine. These droplets evaporate in latter compression stages, providing cooling and reducing power required for compression.
To maintain component integrity, a thermal barrier coating (TBC) is applied to the hot gas path components in the hottest regions of the machine to insulate the base metal from the gases at the firing temperature. Additionally, air from the gas compressor or, in some cases, steam flows through internal cooling passages of the blades and vanes to maintain metal temperatures within an acceptable range. If air is used, it exhausts through vents in the blades and enters the hot gas path. When steam cooling is used in advanced technology gas turbines, it is routed from the blade passages to the HRSG steam cycle to generate additional power in a steam turbine.
The TBC generally comprises several layers with the top layer containing a ceramic oxide, often zirconium oxide. A manufacturer will conduct extensive laboratory and field testing of its formulation to establish a life expectancy and maintenance intervals for the specific gas‐
turbine model. While failure mechanisms are not completely understood, coatings generally exhibit cracking and spalling from the surface toward the end of life, exposing the base metal to high‐temperature gases, which may lead to burning away of a base metal and, in some cases, liberation of parts in the combustion zone, a blade or vane.
Failures inside a gas turbine can be fantastic. Consequential damage following the initial failure may include the compressor, combustion section, turbine blades and vanes, the exhaust diffuser, and the casings of the compressor and turbine. Figure 2.7 shows the condition of the rotating blades of the gas compressor after a liberation of a second‐row (R‐1) blade. The owner replaced all rotating and stationary blades of the compressor section, in addition to combustion parts, and the first two rows of the turbine damaged by molten metal and shrapnel from the combustor following the compressor blade failure. Rather than reblade a new compressor rotor, a spare rotor was purchased and flown in from across the globe to reduce lost production.
Figure 2.7 Compressor consequential blade damage. Source: Reproduced by permission of General Electric.
Figure 2.8 shows a failed section of the turbine first stage wheel that held seven blades. The lower left‐hand corner of the photograph shows where first‐row blades once were. The air‐
cooling holes are visible on the blade base plates. The first‐stage vanes are visibly damaged by splatter, as is the second rotating blade row due to shrapnel passing through the operating unit.
Damage to the gas turbine resulting from this failure required replacement of all blades and vanes in the compressor and turbine sections, the compressor and turbine rotors, all of the combustion hardware, most of the compressor casing sections, the complete turbine casing, and half of the exhaust diffuser. The inlet bell housing had minor damage that was repairable.
The repair cost was more than the price of the original machine. The component that failed was outside its warranty period, and therefore not covered by the manufacturer. Consequential damage repair was therefore the responsibility of the owner.
2.3.1 Gas Turbine Major Maintenance
To guard against catastrophic failures, gas‐turbine manufacturers recommend a program of major maintenance based on the operation and technologies used for the components inside the machine. For a typical large‐frame gas turbine, inspection intervals for the combustion section, hot gas path, and major inspections are specified.
The combustion section, containing the hardware that combines the fuel with air from the compressor section and provides combustion gas to the turbine section generally has the short- est operating life of the major sections of the gas turbine. These parts include the fuel nozzles, combustion cans where the fuel burns, and transition pieces that connect the combustor cans to the turbine section inlet vanes. Combustion inspections (CI) may be recommended every 8000 hours for some gas‐turbine models and all parts within the combustion section are removed and replaced with new or refurbished parts.
A hot gas path Inspection (HGPI) encompasses the combustion section as well as the turbine section of the gas turbine. During this outage, parts in the combustion section would Figure 2.8 Failed turbine wheel and consequential damage. Source: Reproduced by permission of Phillips 66.
be replaced as in the case of the combustion inspection. Blades and vanes of the turbine section may also be replaced due to damage suffered during the maintenance interval, or based on the equivalent operating time accumulated. Rows of blades and vanes closer to the combustion section have a shorter expected life than the exhaust blade row, due to the operating temperature.
The HGPI will also include disassembly of the bearings supporting the turbine section rotor. The bearings will be sent to a specialty maintenance facility to reapply the Babbitt.
The lubricating oil may also be inspected, and replaced if necessary.
A major inspection is a full disassembly of the gas turbine internal rotating and stationary parts. The inspection includes a CI and HGPI, as well as an inspection of the compressor section. As with the CI and HGPI, components are replaced as described above. Compressor parts have longer expected lives than the parts exposed to the hot combustion gases; so, main- tenance and replacements are less frequent. Compressor blades and vanes may have a design life as long as the rotor.
Rotor‐life extension or rotor‐life assessment inspections are the least frequent of all gas turbine inspections. The first assessment of the rotor life may be after 12 years of continuous operation. Typically, manufacturers do not guarantee a rotor life. They will specify the expected rotor lifetime and can inspect the rotor after that period to see how well the rotor has maintained its integrity. Parts that are subject to the highest stresses, or the most severe duty, can be inspected, or the entire rotor may be disassembles and thoroughly inspected. Those parts that show signs of failure are usually replaced. The owner may choose to inspect all the components or simply replace the rotors at the end of the design life depending on their risk tolerance.
Without a full rotor replacement, most manufacturers will not recommend the rotor for further service. However, a gas turbine rotor is very expensive, and industry experience can be a guide to decision making.
Labor for gas turbine major maintenance is specialized. Craft labor specifically trained to perform the maintenance as well as the supervision are required to be at the owner’s facility prior to and during the actual outage. Planning for the outage, which includes identification of the labor, materials, parts, and offsite maintenance facilities can begin as much as 6 months in advance of an outage. The client and supplier work closely together to define the scope and timing of the outage, safety and training requirements specific to the site, and so forth.
Additional work that develops during the outage due to the inspection nature of the mainte- nance can add significantly to the costs and duration of the outage. Operating history that could imply extra work would be thoroughly reviewed and analyzed during the planning period to reduce risks during the outage.
2.3.2 Equivalent Fired Hours
Manufacturers’ maintenance intervals for gas turbines are based on equivalent running hours, or equivalent fired hours of operation. A turbine operating for an hour at full load under steady‐state conditions is typically measured as one equivalent hour. Starting and stopping add equivalent hours due the thermal stress imposed on the hot components. A fast start, or trip from full load, add additional hours, as do operations at peak conditions, those above the full load guarantee, changes to liquid fuel, steam addition for power augmentation, and so
forth. A manufacturer will provide a methodology and equations to determine the equivalent fired hours in the operating manual or in a contract for major maintenance.
After laboratory testing, and extensive field experience, manufacturers are quite certain of the mean time to failure for their TBC and each part within the gas turbine. Based on the life expectancy, they provide a conservative maintenance interval that is short enough to prevent most failures but long enough to remain competitive in a global market. Since outage times may depend on seasonal pricing, the availability of a skilled workforce, and other consider- ations, owners generally have a buffer around the recommended interval to provide some flexibility in scheduling a gas turbine maintenance outage. Beyond the buffer period, in this case 800 hours, the manufacturer will not accept liability for warranty coverage, leaving the owner with a substantial risk. The owner could be responsible for all costs of repair less any allowance for a normal major maintenance inspection.
2.3.3 Failure Costs
After accounting for a regularly scheduled maintenance outage, repair costs from a failure could be as high as $10 to $30 million on a large‐frame gas turbine. Furthermore, parts included in the collateral damage of the failure may not be immediately available, resulting in an outage lasting 12 to 18 weeks instead of a planned outage that may only be 10 days.
Repair and lost production costs would be just the beginning of higher operating costs for an owner following a failure. Insurance as well as borrowing costs can increase. The owner may find it difficult or impossible to obtain insurance, which could place the owner in default of loan covenants requiring payment in full of any outstanding debt. The only good news would be that the unit could be repaired to nearly its original condition.
2.3.4 Reading Assignment
Read Clark et al. (2012).
1. What portion of the world’s electricity production is from gas turbines?
(a) 10%
(b) 20%
(c) 30%
(d) 35%
2. Reasons to improve TBCs include:
(a) Improved gas turbine efficiency.
(b) Greater thrust‐to‐weight ratio.
(c) Higher durability.
(d) All of the above.
3. Functions of the TBC include:
(a) Thermal insulation.
(b) Reflective to radiant heat from combustion.
(c) Strain compliance during thermal cycles.
(d) All of the above.