4 ROADMAP FOR BOILER INSPECTIONS AND IN-SERVICE INSPECTION
4.1 Roadmap for Boiler Examination
Figure 4-1 provides a roadmap for (i) solving boiler tube failures – mechanism unknown, (ii) solving boiler tube failures – mechanism known, and (iii) anticipating and preventing future boiler tube failures. The Boiler and Heat Recovery Steam Generator Tube Failures Manual [4-1]
(the BTF/HTF manual) provides detailed guidance on the other steps in the roadmap.
As shown, three avenues are open to the investigator or BTF team depending upon the status of the BTF event:
• Path A: BTF with mechanism unknown. If a BTF has occurred for the first time or a number of repeat failures have occurred and the mechanism is not known, then the charts of typical appearance and location, Tables 4-2 and 4-4, along with Tables 5-1 through 5-35 should be consulted. Note that these tables are based on simple, generally macroscopic features of failure and should be used as a guide to a particular chapter for further analysis.
• Path B: BTF with “known” mechanism. If the BTF Team has knowledge from past failures that a particular mechanism is the likely cause, then Tables 5-1 through 5-35 can be used to go directly to the appropriate chapter in the BTF/HTF manual. Here, the team can follow step-by-step the steps to confirming the mechanism, establishing the root cause and formulating/executing the appropriate solutions.
• Path C: Anticipating and preventing future BTF. Historically, utilities and operators responded to tube damage only after failures had occurred. This reactive response is economically costly and, as the understanding of key mechanisms has improved, not necessary. The modern approach for world class units is to understand the conditions in the boiler, generally through monitoring activities, and to prevent tube failures from occurring [4-1].
Roadmap for Boiler Inspections and In-Service Inspection
Figure 4-1
Roadmap for Boiler Inspections with Three Starting Points for Use of Information Contained in This Report and Referenced to the Boiler and HRSG Tube Failures Manual [4-1].
Roadmap for Boiler Inspections and In-Service Inspection
As indicated in Figure 4-1, establishing an in-service examination program is a critical step for anticipating and avoiding boiler damage. The NDE priorities, as shown in Table 4-1, are to be considered in establishing that program. Details of the steps represented in Figure 4-1 are discussed in Section 4.2 below. Issues will include these steps:
• Setting the examination interval
• Delineating potential damage mechanisms
• Determining locations to be examined
• Identifying examination methods to be used
• Making pre-examination preparations
• Conducting the examination
• Resolving any indications found
• Setting the re-examination interval
Table 4-1
NDE Priorities for Boiler
Boiler Life Phase NDE Priorities Periodic in-service
examination • Formulate an examination plan for the unit including:
– Locations to be examined – Examination period
– Techniques to be employed – Acceptability standards for damage
• Perform periodic examinations as required.
• Proactively use the information obtained from the examinations to:
1. Determine the status of the unit.
2. Check on the rate of damage accumulation compared to the design.
3. Provide feedback on setting the next examination.
4. Monitor the performance of repairs or other mitigation actions taken.
As shown in Figure 4-1, if no damage is found during the in-service examination, then a re- examination interval is established, and later examinations are conducted. If damage is found during an in-service examination, a process will need to start to determine the active mechanism, diagnose the root cause, determine the extent of the damage (does it extend to other areas, how deep or long are indications, has it spread to other parts of the boiler, etc.), and implement repairs and solutions to prevent reoccurrence of the problem. These steps are shown in the middle and
Roadmap for Boiler Inspections and In-Service Inspection
In either event, Tables 4-2 and 4-4, plus the one-page summaries of damage mechanisms (Tables 5-1 through 5-35) should be consulted. These tables are used to help screen damage, based on the location found, and to determine the mechanism causing the damage. From this knowledge, the balance of the indicated steps in Figure 4-1 can proceed. If the correct mechanism is not
identified and the root cause determined, then a commitment to on-going repair/replacement will occur because the wrong solutions will inevitably be chosen.
Table 4-2 provides a list of mechanisms that have been confirmed in the field, organized by boiler component. Footnotes to Table 4-2 provide some specific location information for selected damage types, and where available, a cross reference to a figure in the BTF/HTF manual is given that illustrates the appearance of the specific damage type and/or location.
As the boiler fleet ages, there will undoubtedly be additions to the columns of this table.
Therefore, if the detected damage cannot be confirmed as one listed in the table through subsequent investigation, the investigator needs to review other potential damage types in the BTF/HTF manual. When a list of potential damage types for the specific component has been compiled, the investigator can review Table 4-3 and/or the summaries of each mechanism (Tables 5-1 through 5-35) for additional information about how to proceed.
Table 4-2
Developing a List of Examination Locations – Likely Damage in Various Boiler Components
Component Field-Confirmed Mechanisms
Economizer tubing Acid dew point corrosion Corrosion fatigue
Flow-accelerated corrosion (FAC)1 Fly ash erosion
Low-temperature creep cracking Pitting
Thermal fatigue
Reheater tubing Chemical cleaning damage Dissimilar metal weld failures Fireside corrosion2
Fly ash erosion Graphitization3
Long-term overheating4
Low-temperature creep cracking Pitting
Short-term overheating Sootblower erosion Stress corrosion cracking Thermal-mechanical fatigue Vibration-induced fatigue
Roadmap for Boiler Inspections and In-Service Inspection Table 4-2 (continued)
Developing a List of Examination Locations – Likely Damage in Various Boiler Components
Component Field-Confirmed Mechanisms
Superheater tubing Caustic gouging
Chemical cleaning damage Dissimilar metal weld failures5 Fireside corrosion
Fly ash erosion Graphitization
Long-term overheating
Low- temperature creep cracking6 Pitting7
Short-term overheating Sootblower erosion Stress corrosion cracking8 Thermal-mechanical fatigue Vibration induced fatigue Waterwall tubing Acid phosphate corrosion9
Caustic gouging
Chemical cleaning damage Coal particle erosion Corrosion fatigue10
Explosive cleaning damage Falling slag
Fireside corrosion Fly ash erosion Hydrogen damage Short-term overheating Thermal fatigue
Thermal-mechanical fatigue11 Vibration-induced fatigue Notes:
1. Economizer inlet header stub tubes (see Figure 32-1 in the BTF/HTF manual).
2. Tubes with longer gas-touched lengths (see Chapters 45 and 46 in the BTF/HTF manual).
3. Low-temperature portions of the superheater and reheater (see Figure 59-2 in the BTF/HTF manual).
4. Lowest tube in horizontal platen or leading tube in a pendant section (see Figure 44-2 in the BTF/HTF manual).
5. Where ferritic materials are joined with austenitic stainless steel (see Figure 47-2 in the BTF/HTF manual).
6. Tube bends with high residual stress remaining from fabrication (see Figure 35-1 in the BTF/HTF manual).
7. Bottoms of pendant loops (see Figure 58-1 in the BTF/HTF manual).
8. Bends, welds, supports, and spacers (see Figure 49-5 in the BTF/HTF manual).
9. Locations where boiling first initiates (see Figure 23-2 in the BTF/HTF manual).
Roadmap for Boiler Inspections and In-Service Inspection
Table 4-3 gives a list of common NDE techniques and the acronyms used to reference these techniques. This table also provides direction to the section of the report which contains information on the specific NDE technique.
Table 4-4 can be used in conjunction with Table 4-2 to help screen for potential damage types. It provides the following:
• A summary of all major damage types
• Some additional information about where the damage generally occurs (column 2)
• Example-specific locations (column 3)
• The most generally applied examination techniques (column 4)
• A cross reference to the information about that damage type contained in Section 5
Table 4-3
Location of Additional Information on Examination Techniques Examination Technique Abbreviation or
Acronym See This Section of This Report for Information
AC potential drop ACPD 7.6
Computed radiography using phosphor plates CRT 8.2 Digital radiography using solid-state detectors DRT 8.2
Eddy current testing ET 7.5
Exploratory grinding
Liquid dye penetrant PT 7.4
Low-frequency electromagnetic technique LFET 8.3
Magnetic particle examination MT 7.3
Oxide thickness measurement by ultrasonics UT-oxide 10.1
Pulsed eddy current PEC 10.2
Radiographic examination RT 8.2
Remote visual or internal videoscopic
examination Internal visual 7.1
Replication 9.2
Tube sampling
Ultrasonic attenuation measurements UT-attenuation 8.1
Ultrasonic examination UT 8.1
Ultrasonic phased array examination UT-PA 8.1
Ultrasonic shear wave examination UT-shear 8.1
Ultrasonic thickness measurements UT-thickness 10.1 Ultrasonic time-of-flight diffraction UT-TOFD 8.1
Visual examination VT 7.1
Wet fluorescent magnetic particle examination WFMT 7.3
Roadmap for Boiler Inspections and In-Service Inspection Table 4-4
Summary of Damage Mechanisms, Examination Locations, and Examination Techniques Damage
Mechanism Where Damage Occurs – General Example Locations Examination
Techniques For More Information,
See:
Corrosion fatigue • Water-touched components, especially the economizer
• Steam-touched tubing containing condensate during operational transients
• Welded connections, bends, and attachments with high thermally induced forces and bending moments
• Locations with significant thickness transitions
• Tube-to-header welds
• Scallop bar attachments
• U-bend-to-drain-line welds
• Riser and downcomer tubes
• Internal visual (video probe, borescope)
• UT-thickness (internal rotary probe
• Phased array UT
• Digital RT or Computed RT
• Quantify by tube sampling
Table 5-1
Thermal-
mechanical fatigue
• All boiler sections, most likely at welded connections and
attachments, occasionally at bends
• Locations with significant thickness transitions
• Tube-to-header welds
• Tube bends near header attachments
• Lower slope region near ash hopper
• Visual inspection
• Particle testing
• Eddy current
• Quantify with: UT, ACPD, exploratory grinding, or RT
Table 5-9 Table 5-28
Creep fatigue • Components in creep regime, notably SHs and RHs
• Locations with welded
connections, bends, attachments, and header boreholes
• Tube-to-header connections
• SH header boreholes
• VT
• WFMT
• PT
• Quantify with: UT, ACPT, replication, exploratory grinding
Table 5-14 Table 5-20
Roadmap for Boiler Inspections and In-Service Inspection Table 4-4 (continued)
Summary of Damage Mechanisms, Examination Locations, and Examination Techniques Damage
Mechanism Where Damage Occurs – General Example Locations Examination
Techniques For More Information,
See:
Flow-induced vibration fatigue
• All sections, most notably SHs and RHs
• Welded connections, bends, and attachments
• Vertical screen tubes and
horizontal rear pass tubes • VT
• PT
• Magnetic particle
• Quantify with: UT, ACPD, exploratory grinding
Table 5-9 Table 5-28
Flow-accelerated corrosion
• High-pressure portions of the feedwater system
• Water-touched components in the temperature range 536°F–572°F (280°C–300°C)
• Economizer inlet header stub tubes nearest the feedwater inlet
• Internal visual (video probe, borescope)
• UT-thickness
• Pulsed eddy current (for insulated piping)
• Quantify with UT- thickness, tangential radiographic testing
Table 5-11
Acid phosphate corrosion; caustic gouging; hydrogen damage
• Locations where water/fluid flow adjacent to the tube wall is disrupted
• Locations where stable steam films are likely to form
• Downstream of welds
• Locations with internal deposits
• Locations with high heat transfer or high steam quality
• Horizontal tubes
• Internal visual (video probe, borescope)
• Quantify with: UT- thickness (internal rotary probe or from the outside surface), tube sampling
Table 5-3 Table 5-4 Table 5-5
Roadmap for Boiler Inspections and In-Service Inspection Table 4-4 (continued)
Summary of Damage Mechanisms, Examination Locations, and Examination Techniques Damage
Mechanism Where Damage Occurs – General Example Locations Examination
Techniques For More Information,
See:
Internal pitting • Oxygen pitting prevalent in economizers, possible at any wet surface, especially non-drainable, horizontal surfaces
• Pitting caused by improper chemical cleaning possible at any surface in contact with cleaning solvents
• Locations where condensate forms and remains as liquid during shutdown periods
• Bottoms of pendant loops
• Low points in sagging horizontal tubing
• Internal visual (video probe, borescope)
• Quantify with: UT- thickness (internal rotary probe), tube sampling, guided waves on straight piping
• Magnetostrictive sensor technique
Table 5-16 Table 5-30
Graphitization • Occurs after prolonged exposure to temperatures above 842°F–
1292°F (450°C–700°C)
• Low temperature portions of the SH and RH
• Near weld heat-affected zones (HAZ)
• Miniature fracture mechanics tests
• Bend tests
• Punch testing
Table 5-31
Thermal fatigue • Where there is slag buildup, high heat fluxes, or flame impingement
• Where cyclic thermal stress is sufficiently high
• Fireside waterwall and membranes
• Header-to-stub-tube attachment weld of the economizer inlet
• VT
• Liquid penetrant
• Magnetic particle testing
• Quantify with RT or AC potential drop
Table 5- 7 Table 5-8 Table 5-10
Acid dew point corrosion
• Gas-touched surfaces where the metal temperatures are below the acid dew point
• Tubes, casings, ducts, and
stacks • VT
• Quantify with UT- thickness
Table 5-19
Roadmap for Boiler Inspections and In-Service Inspection Table 4-4 (continued)
Summary of Damage Mechanisms, Examination Locations, and Examination Techniques Damage
Mechanism Where Damage Occurs – General Example Locations Examination
Techniques For More Information,
See:
Stress corrosion cracking
• Locations with the highest potential for concentration of contaminants as well as high stresses
• Condensate collection points (concentration of contaminants)
• Bends, welds, attachments, supports (high stress locations)
• VT
• WFMT (for magnetic materials)
• PT
• ET
• Quantify with exploratory grinding
Table 5-25
Short-term overheating
• Locations where overheating is likely
• Locations where partial or complete blockage of flow through tubes is likely
• Downstream of bends where blockage by oxide, condensate, debris, etc. can occur
• Above orifices in lower waterwalls where blockage results from feedwater corrosion products
• Bottom bends in SH loops
• VT for tube damage, bulging, flame patterns, etc.
• Internal visual (video probe, borescope) for blockages
• Quantify with tube sampling
Table 5-13 Table 5-24
Long-term
overheating/creep
• Steam-cooled tubing where overheating is likely
• Near material changes
• Where there is a variation in gas- touched length among tubes of the same material
• Final leg of tubing just before outlet header.
• Lowest tube in a horizontal platen or leading tube in a pendant section.
• UT–oxide, internal scale, and wall thickness survey
• Quantify with remaining creep life assessment using internal scale and wall thickness survey
Table 5-20
Low-temperature creep cracking
• High-stress locations with
residual stresses from fabrication • Weld connections and header
boreholes • Magnetic particle
• Quantify with UT or ACPD
Table 5-14
Roadmap for Boiler Inspections and In-Service Inspection Table 4-4 (continued)
Summary of Damage Mechanisms, Examination Locations, and Examination Techniques Damage
Mechanism Where Damage Occurs – General Example Locations Examination
Techniques For More Information,
See:
Fly ash erosion • Where nonuniform high gas flows
develop locally • Back pass in the waterwall
• Inlet sections of RH tubes
• VT for the
appearance of rust shortly after washing
• Ultrasonic testing (UT) to quantify damage determining the extent of wall thinning
Table 5-2
Fireside corrosion • Waterwall tubes, generally at the crown of the tube facing the flame
• SH/RH tubing
• Where metal temperatures exceed 1112°F (600°C)
• Leading sides tubes, pendant platens
• Tubes out of alignment
• Spacers and uncooled hangers
• Tubes with longer gas-touched length
• VT for signs of corrosion, wear, etc
• UT to quantify wall thinning
• Pulsed eddy current (PET)
Table 5-6 Table 5-21 Table 5-22
Sootblower erosion
• Waterwall tubes
• SH/RH tubes
• Circular pattern around wall blowers
• SH/RH tubing in the direct path of retractable blowers
• Visual testing (VT) for rusted tube locations after boiler wash
• Quantify with UT
Table 5-12 Table 5-26
Chemical cleaning damage
• Inside surface of fluid-touched
tubes • Waterwall tubing
• SH/RH tubing
• UT for wall thinning
• RT to detect possible blockages
Table 5-15 Table 5-32 Coal particle
erosion
• Fireside of waterwall tubes • Replaceable wear liners near the end of the burner
• Refractories covering waterwall
• Visual inspection
• UT to quantify
Table 5-17
Roadmap for Boiler Inspections and In-Service Inspection