GE Frame 5 Service Manual
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17 during gas path borescope inspections. All interior case surfaces should be visually inspected during a major outage. Key inspection areas for casings are listed below. • Bolt holes • Shroud pin and borescope holes in the turbine shell (case) • Compressor stator hooks • Turbine shell shroud hooks • Compressor discharge case struts • Inner barrel and inner barrel bolts • Inlet case bearing surfaces and hooks • Inlet case and exhaust frame gibs and trunions • Extraction manifolds (for foreign objects) Exhaust Diffuser Parts GE exhaust diffusers come in either axial or radial configurations as shown in Figures 26 and 27 below. Both types of diffusers are composed of a forward and aft section. Forward diffusers are normally axial diffusers, while aft diffusers can be either axial or radial. Axial diffusers are used in the F-class gas turbines, while radial diffusers are used in B/E-class gas turbines. Exhaust diffusers are subject to high gas path temperatures and vibration due to normal gas turbine operation. Because of the extreme operating environment and cyclic operating nature of gas turbines, exhaust diffusers may develop cracks in the sheet metal surfaces and weld joints used for diffuser construction. Additionally, erosion may occur due to extended operation at high temperatures. Exhaust diffusers should be inspected for cracking and erosion at every combustion, hot gas path and major outage. In addition, flex seals, L-seals, and horizontal joint gaskets should be visually/borescope inspected for signs of wear or damage at every combustion, hot gas path, and major outage. GE recommends that seals with signs of wear or damage be replaced. To summarize, key areas that should be inspected are listed below. Any damage should be reported to GE for recommended repairs. • Forward diffuser carrier flange (6F) • Diffuser strut airfoil leading and trailing edges • Turning vanes in radial diffusers (B/E-class) • Insulation packs on interior or exterior surfaces • Clamp ring attachment points to exhaust frame (major outage only) • Flex seals and L-seals • Horizontal joint gaskets Off-Frequency Operation GE heavy-duty single shaft gas turbines are engineered to operate at 100% speed with the capability to operate over a 95% to 105% speed range. Operation at other than rated speed has the potential to affect maintenance requirements. Depending on the industry code requirements, the specifics of the turbine design, and the turbine control philosophy employed, operating conditions can result that will accelerate life consumption of gas turbine components, particularly rotating flowpath hardware. Where this is true, the maintenance factor associated with this operation must be understood. These off-frequency events must be analyzed and recorded in order to include them in the maintenance plan for the gas turbine.Figure 26 . F-class axial diffuser Figure 27 . E-class radial diffuser GE Power & Water | GER-3620M (00015001200140018 )
18 Some turbines are required to meet operational requirements that are aimed at maintaining grid stability under sudden load or capacity changes. Most codes require turbines to remain on line in the event of a frequency disturbance. For under-frequency operation, the turbine output may decrease with a speed decrease, and the net effect on the turbine is minimal. In some cases of under-frequency operation, turbine output must be increased in order to meet the specification-defined output requirement. If the normal output fall-off with speed results in loads less than the defined minimum, the turbine must compensate. Turbine overfiring is the most obvious compensation option, but other means, such as water-wash, inlet fogging, or evaporative cooling also provide potential means for compensation. A maintenance factor may need to be applied for some of these methods. In addition, off-frequency operation, including rapid grid transients, may expose the blading to excitations that could result in blade resonant response and reduced fatigue life. It is important to understand that operation at over-frequency conditions will not trade one-for-one for periods at under- frequency conditions. As was discussed in the firing temperature section above, operation at peak firing conditions has a nonlinear, logarithmic relationship with maintenance factor. Over-frequency or high speed operation can also introduce conditions that affect turbine maintenance and part replacement intervals. If speed is increased above the nominal rated speed, the rotating components see an increase in mechanical stress proportional to the square of the speed increase. If firing temperature is held constant at the overspeed condition, the life consumption rate of hot gas path rotating components will increase as illustrated in Figure 28 where one hour of operation at 105% speed is equivalent to two hours at rated speed. If overspeed operation represents a small fraction of a turbine’s operating profile, this effect on parts life can sometimes be ignored. However, if significant operation at overspeed is expected and rated firing temperature is maintained, the accumulated hours must be recorded and included in the calculation of the turbine’s overall maintenance factor and the maintenance schedule adjusted to reflect the overspeed operation. Compressor Condition and Performance Maintenance and operating costs are also influenced by the quality of the air that the turbine consumes. In addition to the negative effects of airborne contaminants on hot gas path components, contaminants such as dust, salt, and oil can cause compressor blade erosion, corrosion, and fouling. Fouling can be caused by submicron dirt particles entering the compressor as well as from ingestion of oil vapor, smoke, sea salt, and industrial vapors. Corrosion of compressor blading causes pitting of the blade surface, which, in addition to increasing the surface roughness, also serves as potential sites for fatigue crack initiation. These surface roughness and blade contour changes will decrease compressor airflow and efficiency, which in turn reduces the gas turbine output and overall thermal efficiency. Generally, axial flow compressor deterioration is the major cause of loss in gas turbine output and efficiency. Recoverable losses, attributable to compressor blade fouling, typically account for 70-85% percent of the performance losses seen. As Figure 29 illustrates, compressor fouling to the extent that airflow is reduced by 5%, will reduce output by up to 8% and increase heat rate by up to 3%. Fortunately, much can be done through proper operation and maintenance procedures both to minimize fouling type losses and to limit the deposit of corrosive elements. On-line compressor wash systems are available to maintain compressor efficiency by washing the compressor while at load, before significant fouling has occurred. Off-line compressor wash systems are used to clean heavily fouled compressors. Other procedures include maintaining the inlet filtration system, inlet % Speed Over Speed Operation Constant T fir e 100 101102103104105 Maintenance Fact or (MF) MF = 2 10.0 1.0 Figure 28 . Maintenance factor for overspeed operation ~constant TF
19 evaporative coolers, and other inlet systems as well as periodic inspection and prompt repair of compressor blading. Refer to system-specific maintenance manuals. There are also non-recoverable losses. In the compressor, these are typically caused by nondeposit-related blade surface roughness, erosion, and blade tip rubs. In the turbine, nozzle throat area changes, bucket tip clearance increases and leakages are potential causes. Some degree of unrecoverable performance degradation should be expected, even on a well-maintained gas turbine. The owner, by regularly monitoring and recording unit performance parameters, has a very valuable tool for diagnosing possible compressor deterioration. Lube Oil Cleanliness Contaminated or deteriorated lube oil can cause wear and damage to bearing liners. This can lead to extended outages and costly repairs. Routine sampling of the turbine lube oil for proper viscosity, chemical composition, and contamination is an essential part of a complete maintenance plan. Lube oil should be sampled and tested per GEK-32568, “Lubricating Oil Recommendations for Gas Turbines with Bearing Ambients Above 500°F (260°C).” Additionally, lube oil should be checked periodically for particulate and water contamination as outlined in GEK-110483, “Cleanliness Requirements for Power Plant Installation, Commissioning and Maintenance.” At a minimum, the lube oil should be sampled on a quarterly basis; however, monthly sampling is recommended. Moisture Intake One of the ways some users increase turbine output is through the use of inlet foggers. Foggers inject a large amount of moisture in the inlet ducting, exposing the forward stages of the compressor to potential water carry-over. Operation of a compressor in such an environment may lead to long-term degradation of the compressor due to corrosion, erosion, fouling, and material property degradation. Experience has shown that depending on the quality of water used, the inlet silencer and ducting material, and the condition of the inlet silencer, fouling of the compressor can be severe with inlet foggers. Similarly, carryover from evaporative coolers and water washing more than recommended can degrade the compressor. Figure 30 shows the long-term material property degradation resulting from operating the compressor in a wet environment. The water quality standard that should be adhered to is found in GEK-101944, “Requirements for Water/Steam Purity in Gas Turbines.” For turbines with AISI 403 stainless steel compressor blades, the presence of water carry-over will reduce blade fatigue strength by as much as 30% and increase the crack propagation rate in a blade if a flaw is present. The carry-over also subjects the blades to corrosion. Such corrosion may be accelerated by a saline environment (see GER-3419). Further reductions in fatigue strength will result if the environment is acidic and if pitting is present on the blade. Pitting is corrosion-induced, and blades with pitting can see material strength reduced to 40% of its original value. This condition is exacerbated by downtime in humid environments, which promotes wet corrosion. 4% 2% 0% -2% -4% -6% -8% Output Loss Heat Rate Increase Pressur e Ratio Decr ease0% 1%2%3%4%5% 5% Airflow Loss Figure 29 . Deterioration of gas turbine performance due to compressor blade fouling ISO 200°F Acid H2O 180°F Wet Stea m ISO Pitted in Air Effect of Corrosive Environment • Reduces Vane Material Endurance Str ength • Pitting Provides Localized Stress Risers Fatigue Sensitivity to Envir onment Alternating Str ess Ratio Estimated Fatigue Str ength (107 Cycles) for AISI 403 Blades 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0 Figure 30 . Long-term material property degradation in a wet environment GE Power & Water | GER-3620M (00015001200140018 )
20 Uncoated GTD-450™ material is relatively resistant to corrosion while uncoated AISI 403 is more susceptible. Relative susceptibility of various compressor blade materials and coatings is shown in Figure 31. As noted in GER-3569, aluminum-based (Al) coatings are susceptible to erosion damage leading to unprotected sections of the blade. Because of this, the GECC-1™ coating was created to combine the effects of an Al coating to prevent corrosion and a ceramic topcoat to prevent erosion. Water droplets will cause leading edge erosion on the first few stages of the compressor. This erosion, if sufficiently developed, may lead to an increased risk of blade failure. Utilization of inlet fogging or evaporative cooling may also introduce water carry-over or water ingestion into the compressor, resulting in blade erosion. Although the design intent of evaporative coolers and inlet foggers is to fully vaporize all cooling water prior to its ingestion into the compressor, evidence suggests that, on systems that are not properly commissioned, maintained, or operated, the water may not be fully vaporized. This can be seen by streaking discoloration on the inlet duct or bell mouth. If this is the case, additional inspections and maintenance are required, as presented in applicable TILs and GEKs. Maintenance Inspections Maintenance inspection types may be broadly classified as standby, running, and disassembly inspections. The standby inspection is performed during off-peak periods when the unit is not operating and includes routine servicing of accessory systems and device calibration. The running inspection is performed by observing key operating parameters while the turbine is running. The disassembly inspection requires opening the turbine for inspection of internal components. Disassembly inspections progress from the combustion inspection to the hot gas path inspection to the major inspection as shown in Figure 32 . Details of each of these inspections are described below. Standby Inspections Standby inspections are performed on all gas turbines but pertain particularly to gas turbines used in peaking and intermittent-duty service where starting reliability is of primary concern. This inspection includes routinely servicing the battery system, changing filters, checking oil and water levels, cleaning relays, and checking device calibrations. Servicing can be performed in off-peak periods without interrupting the availability of the turbine. A periodic startup test run is an essential part of the standby inspection. The O&M Manual, as well as the Service Manual Instruction Books, contains information and drawings necessary to perform these periodic checks. Among the most useful drawings in the Service Manual Instruction Books for standby maintenance are the control specifications, piping schematics, and electrical elementaries. These drawings provide the calibrations, operating limits, operating characteristics, and sequencing of all control devices. This information should be used regularly by operating and maintenance personnel. Careful adherence to minor standby inspection maintenance can have a significant effect on reducing overall maintenance costs and maintaining high turbine reliability. It is essential that a good record be kept of all inspections and maintenance work in order to ensure a sound maintenance program. Running Inspections Running inspections consist of the general and continued observations made while a unit is operating. This starts by establishing baseline operating data during startup of a new unit and after any major disassembly work. This baseline then serves as a reference from which subsequent unit deterioration can be measured. Data should be taken to establish normal equipment startup parameters as well as key steady state operating parameters. Steady state is defined as conditions at which no more than a 5°F/3°C change in wheelspace temperature occurs over a Bare Al Slurry Coatings NiCd+ Topcoats CeramicNiCdBare 024681 0Worst Best GTD-450 AISI 403 Relative Corrosion Resistance Figure 31 . Susceptibility of compressor blade materials and coatings
21 15-minute time period. Data must be taken at regular intervals and should be recorded to permit an evaluation of the turbine performance and maintenance requirements as a function of operating time. This operating inspection data, summarized in Figure 33, includes: load versus exhaust temperature, vibration level, fuel flow and pressure, bearing metal temperature, lube oil pressure, exhaust gas temperatures, exhaust temperature spread variation, startup time, and coast-down time. This list is only a minimum and other parameters should be used as necessary. A graph of these parameters will help provide a basis for judging the conditions of the system. Deviations from the norm help pinpoint impending issues, changes in calibration, or damaged components. A sudden abnormal change in running conditions or a severe trip event could indicate damage to internal components. Conditions that may indicate turbine damage include high vibration, high exhaust temperature spreads, compressor surge, abnormal changes in health monitoring systems, and abnormal changes in other monitoring systems. It is recommended to conduct a borescope inspection after such events whenever component damage is suspected. Disassembly Inspections • Combustion • Hot Gas Path • Major Major Inspection Hot Gas Path Inspection Combustion Inspection Figure 32 . 7E.03 heavy-duty gas turbine – disassembly inspections • Speed • Load • Fired Starts • Fired Hours • Temperatures – Inlet Ambient – Compressor Discharge – Turbine Exhaust – Turbine Wheelspace – Lube Oil Header – Lube Oil Tank – Bearing Metal – Bearing Drains – Exhaust Spread • Pressures – Compressor Discharge – Lube Pump(s) – Bearing Header – Barometric – Cooling Water – Fuel – Filters (Fuel, Lube, Inlet Air) • Vibration • Generator – Output Voltage – Phase Current – VARS – Load – Field Voltage – Field Current – Stator Temp. – Vibration • Startup Time • Coast-Down Time Figure 33 . Operating inspection data parameters GE Power & Water | GER-3620M (00015001200140018 )
22 Load vs. Exhaust Temperature The general relationship between load and exhaust temperature should be observed and compared to previous data. Ambient temperature and barometric pressure will have some effect upon the exhaust temperature. High exhaust temperature can be an indicator of deterioration of internal parts, excessive leaks or a fouled air compressor. For mechanical drive applications, it may also be an indication of increased power required by the driven equipment. Vibration Level The vibration signature of the unit should be observed and recorded. Minor changes will occur with changes in operating conditions. However, large changes or a continuously increasing trend give indications of the need to apply corrective action. Fuel Flow and Pressure The fuel system should be observed for the general fuel flow versus load relationship. Fuel pressures through the system should be observed. Changes in fuel pressure can indicate that the fuel nozzle passages are plugged or that fuel-metering elements are damaged or out of calibration. Exhaust Temperature and Spread Variation The most important control function to be monitored is the exhaust temperature fuel override system and the back-up over temperature trip system. Routine verification of the operation and calibration of these functions will minimize wear on the hot gas path parts. Startup Time Startup time is a reference against which subsequent operating parameters can be compared and evaluated. A curve of the starting parameters of speed, fuel signal, exhaust temperature, and critical sequence bench marks versus time will provide a good indication of the condition of the control system. Deviations from normal conditions may indicate impending issues, changes in calibration, or damaged components. Coast-Down Time Coast-down time is an indicator of bearing alignment and bearing condition. The time period from when the fuel is shut off during a normal shutdown until the rotor comes to turning gear speed can be compared and evaluated. Close observation and monitoring of these operating parameters will serve as the basis for effectively planning maintenance work and material requirements needed for subsequent shutdown periods. Rapid Cool-Down Prior to an inspection, a common practice is to force cool the unit to speed the cool-down process and shorten outage time. Force cooling involves turning the unit at crank speed for an extended period of time to continue flowing ambient air through the machine. This is permitted, although a natural cool-down cycle on turning gear or ratchet is preferred for normal shutdowns when no outage is pending. Forced cooling should be limited since it imposes additional thermal stresses on the unit that may result in a reduction of parts life. Opening the compartment doors during any cool-down operation is prohibited unless an emergency situation requires immediate compartment inspection. Cool-down times should not be accelerated by opening the compartment doors or lagging panels, since uneven cooling of the outer casings may result in excessive case distortion and heavy blade rubs. Combustion Inspection The combustion inspection is a relatively short disassembly inspection of fuel nozzles, liners, transition pieces, crossfire tubes and retainers, spark plug assemblies, flame detectors, and combustor flow sleeves. This inspection concentrates on the combustion liners, transition pieces, fuel nozzles, and end caps, which are recognized as being the first to require replacement and repair in a good maintenance program. Proper inspection, maintenance, and repair ( Figure 34) of these items will contribute to a longer life of the downstream parts, such as turbine nozzles and buckets. Figure 32 illustrates the section of a 7E.03 unit that is disassembled for a combustion inspection. The combustion liners, transition pieces, and fuel nozzle assemblies should be removed and replaced with new or repaired components to minimize downtime. The removed liners, transition pieces, and fuel nozzles can then be cleaned and repaired after the unit is returned to operation and be available for the next combustion inspection interval. Typical combustion inspection requirements are:
23 • Inspect combustion chamber components. • Inspect each crossfire tube, retainer and combustion liner. • Inspect combustion liner for TBC spalling, wear, and cracks. • Inspect combustion system and discharge casing for debris and foreign objects. • Inspect flow sleeve welds for cracking. • Inspect transition piece for wear and cracks. • Inspect fuel nozzles for plugging at tips, erosion of tip holes, and safety lock of tips. • Inspect impingement sleeves for cracks (where applicable). • Inspect all fluid, air, and gas passages in nozzle assembly for plugging, erosion, burning, etc. • Inspect spark plug assembly for freedom from binding; check condition of electrodes and insulators. • Replace all consumables and normal wear-and-tear items such as seals, lockplates, nuts, bolts, gaskets, etc. • Perform visual inspection of first-stage turbine nozzle partitions and borescope inspect ( Figure 3) turbine buckets to mark the progress of wear and deterioration of these parts. This inspection will help establish the schedule for the hot gas path inspection. • Perform borescope inspection of compressor. Figure 34 . Combustion inspection – key elements Combustion Inspection Key Hardware Inspect For Potential Action Combustion liners Foreign object damage (FOD) Repair/refurbish/replace Combustion end covers Abnormal wear • Transition Pieces – Strip and recoat – Weld repair – Creep repair • Liners– Strip and recoat – Weld repair – Hula seal replacement – Repair out-of- roundness • Fuel nozzles – Weld repair – Flow test – Leak test Fuel nozzles Cracking End caps Liner cooling hole plugging Transition pieces TBC coating condition Cross fire tubes Oxidation/corrosion/erosion Flow sleeves Hot spots/burning Purge valves Missing hardware Check valves Clearance limits Spark plugs Flame detectors Flex hoses IGVs and bushings Compressor and turbine (borescope) Exhaust diffuser Cracks Weld repair Exhaust diffuser Insulation Loose/missing parts Replace/tighten parts Forward diffuser flex seal Wear/cracked parts Replace seals Compressor discharge case Cracks Repair or monitor Cases – exterior Cracks Repair or monitor Criteria • O&M Manual • TILs • GE Field Engineer Inspection Methods • Visual • Liquid Penetrant • Borescope Availability of On-Site Spares is Key to Minimizing Downtime GE Power & Water | GER-3620M (00015001200140018 )
24 • Visually inspect the compressor inlet, checking the condition of the inlet guide vanes (IGVs), IGV bushings, and first stage rotating blades. • Check the condition of IGV actuators and rack-and-pinion gearing. • Verify the calibration of the IGVs. • Visually inspect compressor discharge case struts for signs of cracking. • Visually inspect compressor discharge case inner barrel if accessible. • Visually inspect the last-stage buckets and shrouds. • Visually inspect the exhaust diffuser for any cracks in flow path surfaces. Inspect insulated surfaces for loose or missing insulation and/or attachment hardware in internal and external locations. In B/E-class machines, inspect the insulation on the radial diffuser and inside the exhaust plenum as well. • Inspect exhaust frame flex seals, L-seals, and horizontal joint gaskets for any signs of wear or damage. • Verify proper operation of purge and check valves. Confirm proper setting and calibration of the combustion controls. • Inspect turbine inlet systems including filters, evaporative coolers, silencers, etc. for corrosion, cracks, and loose parts. After the combustion inspection is complete and the unit is returned to service, the removed combustion hardware can be inspected by a qualified GE field service representative and, if necessary, sent to a qualified GE Service Center for repairs. It is recommended that repairs and fuel nozzle flow testing be performed at qualified GE service centers. See the O&M Manual for additional recommendations and unit specific guidance. Hot Gas Path Inspection The purpose of a hot gas path inspection is to examine those parts exposed to high temperatures from the hot gases discharged from the combustion process. The hot gas path inspection outlined in Figure 35 includes the full scope of the combustion inspection and, in addition, a detailed inspection of the turbine nozzles, Figure 35 . Hot gas path inspection – key elements Hot Gas Path Inspection Combustion Inspection Scope—Plus: Key Hardware Inspect For Potential Action Nozzles (1, 2, 3) Foreign object damage Repair/refurbish/replace Buckets (1, 2, 3) Oxidation/corrosion/erosion • Nozzles – Weld repair – Reposition – Recoat • Stator shrouds – Weld repair – Blend – Recoat • Buckets – Strip & recoat – Weld repair – Blend Stator shrouds Cracking Compressor blading (borescope) Cooling hole plugging Remaining coating life Nozzle deflection/distortion Abnormal deflection/distortion Abnormal wear Missing hardware Clearance limits Evidence of creep Turbine shell Cracks Repair or monitor Criteria • O&M Manual • TILs • GE Field Engineer Inspection Methods • Visual • Liquid Penetrant • Borescope Availability of On-Site Spares is Key to Minimizing Downtime
25 stator shrouds, and turbine buckets. To perform this inspection, the top half of the turbine shell must be removed. Prior to shell removal, proper machine centerline support using mechanical jacks is necessary to assure proper alignment of rotor to stator, obtain accurate half-shell clearances, and prevent twisting of the stator casings. Reference the O&M Manual for unit-specific jacking procedures. Special inspection procedures apply to specific components in order to ensure that parts meet their intended life. These inspections may include, but are not limited to, dimensional inspections, Fluorescent Penetrant Inspection (FPI), Eddy Current Inspection (ECI), and other forms of non-destructive testing (NDT). The type of inspection required for specific hardware is determined on a part number and operational history basis, and can be obtained from a GE service representative. Similarly, repair action is taken on the basis of part number, unit operational history, and part condition. Repairs including (but not limited to) strip, chemical clean, HIP (Hot Isostatic Processing), heat treat, and recoat may also be necessary to ensure full parts life. Weld repair will be recommended when necessary, typically as determined by visual inspection and NDT. Failure to perform the required repairs may lead to retirement of the part before its life potential is fulfilled. In contrast, unnecessary repairs are an unneeded expenditure of time and resources. To verify the types of inspection and repair required, contact your GE service representative prior to an outage. For inspection of the hot gas path ( Figure 32), all combustion transition pieces and the first-stage turbine nozzle assemblies must be removed. Removal of the second- and third-stage turbine nozzle segment assemblies is optional, depending upon the results of visual observations, clearance measurements, and other required inspections. The buckets can usually be inspected in place. FPI of the bucket vane sections may be required to detect any cracks. In addition, a complete set of internal turbine radial and axial clearances (opening and closing) must be taken during any hot gas path inspection. Re-assembly must meet clearance diagram requirements to prevent rubs and to maintain unit performance. In addition to combustion inspection requirements, typical hot gas path inspection requirements are: • Inspect and record condition of first-, second-, and third-stage buckets. If it is determined that the turbine buckets should be removed, follow bucket removal and condition recording instructions. Buckets with protective coating should be evaluated for remaining coating life. • Inspect and record condition of first-, second-, and third-stage nozzles. • Inspect seals and hook fits of turbine nozzles and diaphragms for rubs, erosion, fretting, or thermal deterioration. • Inspect and record condition of later-stage nozzle diaphragm packings. • Check discourager seals for rubs, and deterioration of clearance. • Record the bucket tip clearances. • Inspect bucket shank seals for clearance, rubs, and deterioration. • Perform inspections on cutter teeth of tip-shrouded buckets. Consider refurbishment of buckets with worn cutter teeth, particularly if concurrently refurbishing the honeycomb of the corresponding stationary shrouds. Consult your GE service representative to confirm that the bucket under consideration is repairable. • Check the turbine stationary shrouds for clearance, cracking, erosion, oxidation, rubbing, and build-up of debris. • Inspect turbine rotor for cracks, object damage, or rubs. • Check and replace any faulty wheelspace thermocouples. • Perform borescope inspection of the compressor. • Visually inspect the turbine shell shroud hooks for signs of cracking. The first-stage turbine nozzle assembly is exposed to the direct hot gas discharge from the combustion process and is subjected to the highest gas temperatures in the turbine section. Such conditions frequently cause nozzle cracking and oxidation, and in fact, this is expected. The second- and third-stage nozzles are exposed to high gas bending loads, which in combination with the operating temperatures can lead to downstream deflection and closure of critical axial clearances. To a degree, nozzle distress can be tolerated, and criteria have been established for determining when repair is required. More common criteria are described in the O&M Manuals. However, as a general rule, first-stage nozzles will require GE Power & Water | GER-3620M (00015001200140018 )
26 repair at the hot gas path inspection. The second- and third-stage nozzles may require refurbishment to re-establish the proper axial clearances. Normally, turbine nozzles can be repaired several times, and it is generally repair cost versus replacement cost that dictates the replacement decision. Coatings play a critical role in protecting the buckets operating at high metal temperatures. They ensure that the full capability of the high strength superalloy is maintained and that the bucket rupture life meets design expectations. This is particularly true of cooled bucket designs that operate above 1985°F (1085°C) firing temperature. Significant exposure of the base metal to the environment will accelerate the creep rate and can lead to premature replacement through a combination of increased temperature and stress and a reduction in material strength, as described in Figure 36. This degradation process is driven by oxidation of the unprotected base alloy. On early generation uncooled designs, surface degradation due to corrosion or oxidation was considered to be a performance issue and not a factor in bucket life. This is no longer the case at the higher firing temperatures of current generation designs. Given the importance of coatings, it must be recognized that even the best coatings available will have a finite life, and the condition of the coating will play a major role in determining bucket life. Refurbishment through stripping and recoating is an option for achieving bucket’s expected/design life, but if recoating is selected, it should be done before the coating is breached to expose base metal. Normally, for 7E.03 turbines, this means that recoating will be required at the hot gas path inspection. If recoating is not performed at the hot gas path inspection, the life of the buckets would generally be one additional hot gas path inspection interval, at which point the buckets would be replaced. For F-class gas turbines, recoating of the first stage buckets is recommended at each hot gas path inspection. Visual and borescope examination of the hot gas path parts during the combustion inspections as well as nozzle-deflection measurements will allow the operator to monitor distress patterns and progression. This makes part- life predictions more accurate and allows adequate time to plan for replacement or refurbishment at the time of the hot gas path inspection. It is important to recognize that to avoid extending the hot gas path inspection, the necessary spare parts should be on site prior to taking the unit out of service. See the O&M Manual for additional recommendations and unit specific guidance. Major Inspection The purpose of the major inspection is to examine all of the internal rotating and stationary components from the inlet of the machine through the exhaust. A major inspection should be scheduled in accordance with the recommendations in the owner’s O&M Manual or as modified by the results of previous borescope and hot gas path inspections. The work scope shown in Figure 37 involves Oxidation & Bucket Life Base Metal Oxidation Pr essur e Side Sur face Reduces Bucket Cr eep Life Cooling Hole Surface Oxidation Depleted Coating Air foil Sur face Oxidation TE Cooling Hole Incr eases Str ess • Reduced Load Carrying Cr oss Section Incr eases Metal T emperature • Surface Roughness Effects Decr eases Alloy Cr eep Strength • Envir onmental Effects Figure 36 . Stage 1 bucket oxidation and bucket life