During a planned major outage, last stage blades were found with cracking in the blade attachment. The blades were of a free-standing design, which means they are not coupled to adjacent blades by means of a shroud, snubber or tie wire. The cracking was clustered in groups and were not present 360 degrees around the row.

Analysis Completed:

TG Advisers scanned the blade with blue light technology to create a solid model. TGA then meshed the solid model to complete a finite element analysis (FEA) of the blade. Using the FEA software, TGA completed a series of calculations including blade natural frequencies and blade root stresses.
The blade natural frequencies on large blades are important to ensure that the blade is well tuned, meaning it will not be excited by a multiple of running speed.
Analysis Findings: The results of the blade frequency calculations showed that the blade was well tuned against multiples of running speed. However, a key finding was that the stresses in the blade attachment, when vibrating at its first natural frequency, was highest at the location of observed cracking.

Free-standing blades are susceptible to aeroelastic vibration, both at high flows (unstalled flutter) and low flows (stall flutter) and certain combinations of LP exhaust pressure. It has been shown that adjacent free-standing blades with approximately the same natural frequencies are most susceptible to unstalled flutter. An industry best practice to reduce exposure to aeroelastic vibration on free-standing blades is to frequency test each blade and mix-tune the blades. This simply means to ensure there is a multiple hertz natural frequency variation between adjacent blades. This can be accomplished passively using manufacturing tolerances or actively by the manufacture of two different part numbers with slightly different geometry to produce the desired frequency variation.

Improvements:

Since the cracking was found during a routine major outage, the design change options were limited to return the unit to service as soon as possible. Ultimately TG Advisers recommended the following:

1. Mixtuning of blades – It was confirmed that the blades were not originally mixed tuned.
2. Material change – This upgrade offered improved strength.
3. Shot peening of blade attachments – This helps resist cracking by introducing a compressive stress layer on the surface.

To date, there has been no issues with the upgraded blades.

Best Practice:

If you have a turbine with large free-standing blades, ensure the blades are mix-tuned when assembling or replacing blades! Periodically audit flow and backpressure conditions to ensure they are compliant with allowables. Complete thorough inspections of the blade root and rotor attachments when possible. In addition to major outages, on many designs inspections of the L-0’s can be completed through the condenser after peak run seasons.

Turbine Generator Health Assessment Background:

TG Advisers began its health assessment program in 1991 and has completed over 350 turbine generator assessments to date.  Our database of units includes steam (nuclear, fossil, biomass) and gas turbine (aerodervative and industrial) units across all major OEM’s, vintages, and outputs ranges (8 MW to 1,500 MW+).  In recent years, the health assessment program has been applied to balance of plant equipment, boilers, ID fans, and cooling towers. 

Assessment Goals:

1. Establish current unit condition – function of design and past/future duty cycle
2. Define turbine generator problem areas and assess each for severity and likelihood of occurrence.
3. Define actions, outage scope, and capital needs to mitigate key asset risks
4. Allow for integration directly into plant workflow systems
5. Provide financial return with improved availability and optimizing outage and maintenance intervals and scopes.    

Establishing Unit Condition: 

TGA leverages decades of OEM, utility, and consulting experience in conjunction with plant operations and maintenance interviews, outage report reviews, and operational data assessments to establish unit condition.  

Unit Specific Problem Areas:

TGA divides a given turbine generator unit into on average 50 “Problem Areas”.  Problem areas are failure modes and chronic conditions judged to be of concern. For a steam turbine, problem areas are segmented by turbine elements, valves, generator, and system.  The advantage of breaking the unit into “problem areas” is that all background/history and actions for a given issue that could impact the availability of the unit is contained in a single location.  

Each of the approximately 50 problem areas will be evaluated for unit specific history and trends, inspection findings, part replacement history, effectiveness of past repairs, and TGA’s experience on like units.  In the next step of the assessment, the respective problem areas for a given unit are assigned weight risk rating. 

Problem Area Risk Analysis

When considering risk, TGA considers both the likelihood of occurrence as well as the duration of a forced outage and/or outage extension if the respective issue is encountered.  Multiplying the risk (severity) by the probability of occurrences yields a weighted “Availability Factor.”

The resulting availability factors range from 0 to 12.  As part of the health assessment, a color map is provided of all unit “Availability Factors” to drive priority of spend and scope.   

Figure 1: Availability Factor Range

Figure 2: Snapshot of Availability Factor Roll Up

Outage Interval Evaluation, Outage Scope, and Troubleshooting:

Based on the availability factor roll up, past/current duty cycle and mode of operation TGA will provide recommended outage intervals and scopes.  In addition, TGA will provide troubleshooting recommendations and key contingencies for unit specific issues as part of the assessment. 

Financial Return: 

Value is derived in multiple ways from a TG Advisers health assessment.  A example list is provided below:

• Bridges knowledge gaps due to staff retirements, turnover
• Increased availability and reduced forced outage costs
• Identifies major risk areas
• Enables contingency planning for emergent issues
• Mitigates short term repeat outages
• Allows for a T-18 Planning Process
  • Critical spare parts identified and procured
  • Allows time to develop comprehensive repair scopes and competitive pricing options
  • Mitigates expediting costs
• Targeted outage scopes – often opportunities for reduced outage scope and/or extensions beyond standard OEM outage recommendations. 
• Facilitates long and short term capital and O&M planning
• Fosters timely post outage updates
  • Captures lessons learned, best practice integration
  • Optimize outage intervals 
  • Ongoing monitoring recommendations
• Integration of best practices and lessons learned from other sites with like units.

Analysis Completed:  TG Advisers first looked at the operating history of the unit since the last boresonic test, to determine the total number of stop/start cycles and overspeed test events. Crack growth in the bore of a field is primarily driven through Low Cycle Fatigue (LCF), which is associated with stop/start cycling of the unit, as well as unit overspeed events, including overspeed testing. Potential crack growth rates for any flaws in the bore can then be calculated using these cycle and event numbers. Conservative assumptions were also made for the cycles and overspeed events from current day through the projected next inspection date.

A simple Finite Element Analysis (FEA) model of the field was created using a field body shipping drawing provided by the plant. Slot dimensions were included in the field body section as well. Material properties of the specific rotor material were taken into account. Initial crack sizes were determined from the results of the last boresonic. The real flaws that existed at that time point were utilized as the initial crack sizes for fracture mechanics calculations. 

When considering turbine or generator rotor boresonic test results, flaws at the surface of the bore are of greatest concern, as these flaws are on a free surface where crack growth rates are highest. Stress levels in a field, specifically hoop stresses present from the rotation of the rotor, are highest at the bore surface. Larger diameter sections typically have the greatest stress levels as well due to the additional mass, though the field body section is more complicated due to the presence of winding slots.

The FEA model output the stress present at the location of every existing flaw in the rotor. These stress magnitudes were then used in a linear fracture mechanics analysis, where an initial flaw size was assumed, and the actual mechanical properties of the metal were used to determine the remaining cycles and overspeed events before the cracks present in the rotor could reach critical size. A safety factor was also applied to the critical crack size in these calculations per typical OEM practices. Critical crack sizes were compared to the actual rotor geometry to ensure the calculated values made sense from a physical standpoint.

Analysis Findings:  The results of the fracture mechanics analysis showed that the risk of delaying the boresonic inspection for multiple years was low. Per the actual cycle and overspeed event data from the plant, if a boresonic inspection was carried out immediately, there would have been little to no difference in flaw size from the previous inspection 10+ years prior, as the unit had minimal cyclic behavior.

Based on the analysis outcome, TGA provided the plant with specific numbers for allowable total overspeed events and normal stop/start cycles the unit could undergo until the next boresonic would be carried out. 

Improvements:  The analysis carried out allowed the plant to reach the next planned major outage, and perform the boresonic reinspection as part of that planned outage scope.

To date, there has been no issues with the field. 

Best Practice:  When looking to defer maintenance on your unit, whether a turbine or generator, the decision should be based off of sound engineering analysis. Wherever possible, calculations should be used to assess the risk level of extending the operational interval. In the case of boresonic inspections, the failure mode is well known and established. Often the provided re-inspection intervals are generic. Performing a one-off evaluation of your specific rotor may be able to extend the interval between boresonic inspections, once the flaws of your specific rotor are applied to the analysis.

Inspection Findings:

During an outage, phased array ultrasonic testing of DFLP shrunk-on discs found no recordable indications on any of the disc bores or keyways. OEM guideline reinspection intervals for the shrunk-on discs set an hourly recommendation that required multiple reinspections between majors. However, since reinspection intervals were established, operating pattern of the unit changed significantly.

Analysis Completed:

Two methods of crack propagation were considered – stress corrosion cracking and low cycle fatigue. SCC is a well-documented industry phenomenon that occurs in wet steam environments with increased probability as the unit’s service hours exceed 150,000. SCC crack growth rates are driven by a number of factors including material yield strength, stage operating temperature, and steam chemistry. It is dependent on operating time and not cycles. LCF is caused by repeated stresses during both regular start and stop cycles and overspeed cycles. 

TG Advisers used FEA modeling to quantify startup and overspeed stresses in both the shrunk-on disc keyway and the blade attachment.  The maximum stresses seen in the rotor steeples and in the disc bore and conservative material properties were used to calculate the minimum critical crack size. A safety factor was applied to that value to set a reinspection crack size.

FEA modeling of rotor blade attachment showing stresses in the steeples

The crack growth evaluation method is based on fracture mechanics principles and assumes an initial flaw—in this case TGA assumed a flaw the size of the minimum detectable from the clean PAUT inspection. The crack propagation from each phenomenon is calculated based on the actual number of cycles and operating hours the unit has completed, then summed to create a total crack growth amount. This value is compared to the reinspection crack size to determine when reinspection intervals should be set. 

Analysis Findings:

The following two scenarios illustrate the effects of duty cycle on the LP reinspection intervals. One of the most significant benefits in this type of automated analysis program is that only the operational hours and stop/starts need to be input in order to output a visual representation of crack progression.

In the dynamic reinspection plots, the reinspection crack size is indicated with the solid red line. The dashed red line shows the calculated crack propagation based on the user inputted duty cycle. When the two lines meet is when a reinspection is required.

The two major contributing crack growth phenomena (SCC and LCF) are shown in green and blue lines respectively. The circles reflect the amount of crack propagation from SCC/operational hours (green) and LCF/cycles (blue) experienced to date. The scenario shown in Figure 1 shows a base loaded operation where most of the crack propagation has come from SCC (green) and there is only a small amount from LCF (blue). In this instance, the solid black line shows the calculated crack propagation is currently 73.8% of the way to the reinspection crack size.

To compare, Figure 2 shows the same unit but with an operational profile that focuses on cycling. It has three times as many cycles as the previous scenario and significantly fewer operational hours. However, crack propagation is still in a similar range. 

Improvements:

In this specific case study, when the actual operating profile of the unit was reviewed, the reinspection intervals for the shrunk-on disc and blade attachments were found to be excessively frequent. Therefore, the dynamic reinspection interval methodology allowed for a reduction in the frequency of outages driven by reinspection of the shrunk-on disc and blade attachments of the DFLP.