número 3 año 2010 la noción filosófica de memoria
3. La presencia del pasado: Historia y memoria
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Screening Table for Steam-Touched Boiler Tube Failures (Chapter 2)
The following table provides information that can be used to perfrom an initial screening of a boiler tube failure to identify a likely degradation mechanism that may have contributed to the failure. The table also includes a reference to the applicable chapter in EPRI report 1012757 for more information on the respective dergardation mechanism.
Table 2-2
Screening Table for Water-Touched Boiler Tube Failures
Typical FractureSurface Appearance Other Likely Macroscopic and
Metallographic Features Typical Locations Possible
Mechanism Chapter in Volume 2 Thick-Edged Fracture
Surface
Thick-edged Outside surface initiated, intergranular crack growth with significant microfissuring aligned parallel with the main crack and significant secondary cracking; evidence of grain boundary creep cavitation and creep voids.
Predominant in lower temperature regions in tube bends, particularly at intrados on outside surface, and other locations subject to high residual, forming, or service stresses.
Found in the lower temperature regions of the reheater and in primary superheater.
Low temperature creep
cracking Chap. 35 Volume 2
Table 2-2 (continued)
Screening Table for Water-Touched Boiler Tube Failures
Typical FractureSurface Appearance Other Likely Macroscopic and
Metallographic Features Typical Locations Possible
Mechanism Chapter in Volume 2 Thick-edged In ferritic materials, thick, internal oxide
scales cracked longitudinally (alligator hide appearance); potentially external wastage typically at 10 o’clock and 2 o’clock positions;
generally longitudinal (axial) orientation; damage on heated side of tube; microstructural damage by overheat and intergranular or transgranular creep.
Also longitudinal cracking on austenitic tubing.
Highest temperature locations: near material transitions, where there is a variation in gas-touched length, in or just beyond cavities, in the final leg of tubing just prior to the outlet header.
Long-term Overheating
(Creep) 44
Thick-edged, leak Usually fusion line cracking at or near the heat-affected zone on low alloy side of weld, circumferential orientation.
At dissimilar metal welds (transitions between ferritic and
austenitic materials) Dissimilar Metal Weld Failure 47
Thick-edged (may manifest
as a pinhole) Cracking is transgranular or intergranular usually with significant branching; initiation can be at ID (most common) or on OD, circumferential or longitudinal orientation;
may involve blowout of window-type pieces.
Bends and straight tubing with low spots; points with the highest concentration of contaminants; high-stress locations are particularly susceptible at bends, welds, tube attachments, supports, or spacers
Stress Corrosion Cracking 49
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Table 2-2 (continued)
Screening Table for Water-Touched Boiler Tube Failures
Typical FractureSurface Appearance Other Likely Macroscopic and
Metallographic Features Typical Locations Possible
Mechanism Chapter in Volume 2 Thick-edged Typically straight, transgranular cracking, OD
initiated and associated with tubing (at tube bends or attachments) or headers (particularly at the ends).
Tubing-related failures associated with attachments or bends in tubing; header-related generally at ends of header
Fatigue 52
Thick-edged, leak May have helical fracture path; most commonly in HAZ of C or C-Mo steel tubes, although may also be remote from weld; key is microstructure appearance of graphite particles or nodules.
Low temperature regions of the SH/RH; adjacent to
weld fusion line at heat- affected zone most common Graphitization 59
Thick-edged Brittle fracture; typically ID initiating cracks. Locations where explosive cleaning has been used Explosive Cleaning Damage 51 Thin-Edged Fracture
Surface
Thin-edged (unless
creep-assisted) External polishing of tube surface; very
localized damage. Most prominent in backpass regions; bends near to
walls Fly ash Erosion Chap. 21 Volume 2
Table 2-2 (continued)
Screening Table for Water-Touched Boiler Tube Failures
Typical FractureSurface Appearance Other Likely Macroscopic and
Metallographic Features Typical Locations Possible
Mechanism Chapter in Volume 2 Thin-edged External damage; wastage at 10 and 2 o’clock
(fluegas at 12 o’clock); longitudinal cracking;
perhaps alligator hide appearance; real key to identification will be the presence of low-melting-point ash in external deposits.
Highest temperature tubes: leading tubes, near transitions, tubes out of alignment, tubes around radiant cavities
Fireside Corrosion (coal-fired units and oil-fired units) 45
(Coal-fired units) 46 (Oil-fired units) Thin-edged Often shows signs of tube bulging or
fish-mouth appearance, longitudinal orientation. Most commonly near bottom bends in vertical loops of
SH/RH; outlet legs, and near material transitions Short-Term Overheating 48
Thin-edged, pinhole or thin
longitudinal blowout Wall thinning caused by external wastage flats around tube from sootblower direction; little or no ash deposits on tube.
First tubes in from wall entrance of retractable blowers;
tubes in direct path of retractable blowers Sootblower Erosion 50
Thin-edged External damage; obvious metal-to-metal
contact on tube surface. Rubbing/Fretting 57
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Table 2-2 (continued)
Screening Table for Water-Touched Boiler Tube Failures
Typical FractureSurface Appearance Other Likely Macroscopic and
Metallographic Features Typical Locations Possible
Mechanism Chapter in Volume 2 Pinhole Damage
Pitting Internal tube surface damage; distinctive aspect ratio of damage - deep relative to area; partial or total (through-wall) dissolution of the tube wall metal may be observed.
For pitting: Tubes where condensate can form and remain during shutdown: bottoms of pendant loops on either SH or RH, low points in sagging horizontal tubes
Chemical Cleaning Damage
or Pitting 58 or 60
Various Other Damage Types Depends on the underlying
cause Usually obvious from type of damage and
correspondence to past maintenance activity. Maintenance Damage 61
Table 2-2 (continued)
Screening Table for Water-Touched Boiler Tube Failures
Typical FractureSurface Appearance Other Likely Macroscopic and
Metallographic Features Typical Locations Possible
Mechanism Chapter in Volume 2
Depends on defect Materials Flaws 62
Usually thick-edged or
pinholes Care required to separate weld defects from another
problem located at a weld. Welding Flaws 63
Thin-Edged Fracture Thin-edged (unless
creep-assisted) External polishing of tube surface; very
localized damage. Most prominent in backpass regions; bends near to
walls Fly ash Erosion Chap. 21 Volume 2
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Long-Term Overheating/Creep in SH/RH Tubes (Chapter 44)
Description
Macro Features• Failures are generally longitudinal (axial to tube) and located on the heated side of the tube.
• Generally a thick-edged failure corresponding to low ductility.
• Reheater tube failures in conventional boilers tend to look more ductile than superheater tube failures due to thinner-walled materials.
• Primary evidence of overheat of SH/RH tubes is thickened external scales with Y-shaped grooves that give the appearance of alligator hide.
• In ferritic tube materials, particularly in T91 material, indicators include thickened internal oxide scales and longitudinal cracks.
Micro Features
• Ferritic tubes will exhibit a spheroidized microstructure and creep cavities in the immediate vicinity of the rupture or the part-through-wall cracks.
• Austenitic stainless steels will exhibit sigma phase microstructure and grain boundary creep cavities (microvoids).
Figure 44-1
Typical appearance of a tube failure by LTOC with axially oriented thick-edged crack.
Figure 44-2
Typical appearance of an LTOC failure in a reheat tube.
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Contributing Causes/Susceptible Components
Locations susceptible to longterm overheating/creep include the following:
• Near material changes such as in the middle of at tube circuit just before the change to a higher grade material
• Where there is a variation in the gas-touched length among tubes of the same material
• In the final leg of tubing just before the outlet header, where steam temperatures are the highest
• Tubing nearest to the flue gas inlet, especially for supplementally fired units
Figure 44-4
Example of alligator hide appearance of a tube subject to LTOC.
Figure 44-5
Example of wastage flats on a tube subject to LTOC.
Figure 44-6
Example of spheroidized microstructure and creep cavitation associated with a long-term overheating/
creep failure in 2¼ Cr - 1 Mo material (MAG: 500X, Nital etch).
Source: 1004503, 2002
Figure 44-8
Typical grain boundary creep cavitation/
microcracking at and adjacent to a crack.
Source: J. Hickey, Irish Electricity Supply Board
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Table 44-4
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions
All causes of overheating • Review SH/RH circuit material diagrams, calculate and plot GTL as a function of steam and metal temperatures; plot positions of failures.
• Direct measurement of temperatures by thermocouples, especially on new units, prior to there being enough oxide to measure. This is a proactive approach.
• Indirect estimation of temperature by steamside oxide scale thickness measurements.
• Metallurgical analysis of tube structure,especially for austenitics, and oxide thickness and morphology of selected tube samples.
• Visual examination for evidence of slag buildup, laning, bowed, or misaligned tubes acting as leading tubes.
• Make local repairs as appropriate.
• Perform selective sampling and/or ultrasonic measurement to determine extent of problem.
• Perform remaining life estimate of affected tubes (Chapter 14).
Table 44-4 (continued)
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions
Initial Design and/or Material Choice
• Original alloy choice and extent inadequate for actual operating temperatures.
• Inadequate heat treatment of original alloy.
• Tubes at failure location have gas-touched lengths (GTL) longer than design estimate and/or row-to- row variation in gas-touched length.
• Side-to-side or local gas temperature differences.
• Radiant cavity heating effects.
• Lead tube/wrapper tube material not resistant enough to temperature.
• Perform GTL analysis.
• Review temperature data from thermocouples installed in vestibule or across the header.
• As above.
Buildup of Steamside Oxide Scale • Review SH/RH circuit material diagrams, calculate and plot GTL as a function of steam and metal temperatures; plot positions of failures.
• Direct measurement of temperatures by thermocouples, especially on new units prior to there being enough oxide to measure. This is a proactive approach
• Indirect estimation of temperature by steamside oxide scale thickness measurements.
• Metallurgical analysis of tube structure,especially for austenitics, and
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Table 44-4 (continued)
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions
Restricted Steam Flow due to Chemical or Other Deposits, Scale, Debris, etc.
(This can cause short-term overheating as well – see Chapter 48).
• Selective sampling of suspect locations to verify whether local
blockage is leading to excessive temperatures. • Clean out tubes and remove source of blockages.
Operating Conditions or Changes in Operation • Perform metallographic analysis to determine if the tube is
overheated or carburized due to delayed combustion. • Make local repairs as appropriate.
• Perform selective sampling and/or ultrasonic measurement to determine extent of problem.
• Perform remaining life estimate of affected tubes.
• See long-term action.
Previous similar problems in adjacent SH/RH • Check temperature distribution through the circuit by
performing analysis of GTL and measured temperatures. • As above.
Table 44-4 (continued)
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions
Combustion conditions
– Restore boiler design (or optimized) conditions.
Blockage or Laning of Boiler Gas Passages • Can be recognized using cold air velocity technique.
• Visual examination to identify local flow blockages.
Thinned Tube Wall
• Wrong wall thickness tube installed.
• Tube wall thinned by a wastage mechanism, such as sootblower erosion or fly ash erosion.
• NDE evaluation to determine the wall thickness.
• If another mechanism is suspected, initiate actions to confirm their involvement.
• Check short-term actions for wastage mechanisms: fireside corrosion (Chapters 45 and 46), sootblower erosion (Chapter 50), or fly ash erosion (Chapter 21).
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Aspect Alert for Other Cycle Components Actions Indicated
Tube overheating as evidenced by buildup of internal
oxide scale • Potential for exfoliation of oxide from ferritic materials, which can carry over into turbine sections.
• Exfoliating scale from austenitic materials can lead to tube blockage and failures by short-term overheating (see Chapter 48).
• Chemical cleaning of SH/RH sections.
• Monitoring plan to assess the severity of oxide buildup in affected tubes, including UT inspection for direct measurement of oxide scale and tube sampling to confirm type and extent of scale.
Tube overheating as evidenced by buildup of internal
oxide scale • SH/RH tubes are more susceptible to damage from fireside
corrosion if coal is corrosive. • Correct cause of overheating if possible; upgrade to more resistance materials as required.
Total redesign of the superheater or reheater • May change absorption patterns through the SH/RH sections
and may increase temperatures in other circuits. • Check temperatures in the redesigned section and other sections.
Figure 44-9
Schematic representation of steamside oxide thickness versus tube wastage (wall loss). Such a plot can be used to distinguish between long-term overheating/creep and fireside corrosion mechanisms. [1 in. = 25.4 mm].
Source: TR-102433, 1993
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Fireside Corrosion in SH/RH Tubes (Chapter 45)
Description
• Typically, multilayered fireside scale and ash deposits that are generally tightly bound to tubes at room temperatures and will typically consist of three layers
1. A hard, brittle, and porous outer layer, which makes up the bulk of the deposit and has a composition similar to that of boiler fly ash.
2. A white intermediate layer consisting of compounds of complex alkali sulfates, including alkali iron trisulfates. When this layer has a chalky consistency, corrosion has been found to be mild or nonexistent; when fused and semi-glossy, corrosion has been found to be severe.
3. A black, glossy inner layer, composed primarily of oxides, sulfates, and sulfides of iron.
• Tube wastage will often be evident and manifested as flat spots on the tube at the 10 o’clock and 2 o’clock positions (12 o’clock is the upstream position).
• Fireside corrosion damage will be primarily distinguished from long-term overheating by the presence of low melting point ash compounds.
• Greatest wall loss will generally be seen in tubes that have been operated at the highest temperatures over a period of time.
Figure 45-1
Schematic representation of fireside corrosion development for superheaters and reheaters involving a molten intermediate layer (alkalis, sulfates). This case
Figure 45-2
Tube sample exhibiting fireside corrosion. Note the presence of multilayered
scale along with wastage flats at the 10 and 2 o’clock positions of the tube’s
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Contributing Causes/Susceptible Components
Corrosion will generally be the worst in the highest temperature locations. Parts at highest risk therefore include the following:
• Leading sides of all tubes in pendant platens, especially hottest (leading) tubes and steam outlet tubes.
• Tubes out of alignment that act as leading tubes.
• Tubes in the outlet (final) sections towards the header, because these are at the highest temperatures.
• Just prior to a change of material, e.g., in T22 just prior to the austenitic material, as the lower Cr content. material may be operating above its design point.
• Wrapper tubes.
• Tubes that surround a radiant cavity (i.e., they may pick up more heat).
• At bottom bends of platens, especially those facing the fireball.
• Tubes with a longer GTL. (GTL is the distance measured along the tube circuit from the inlet header to the point of corrosion. See long-term overheating, Chapter 44.)
• Spacers and uncooled hangers and the fins and studs on tubes.
Figure 45-6
Typical locations where fireside corrosion can occur.
Figure 45-3
Two tube sample segments showing fireside corrosion. The left shows the ash
pattern as removed; the right shows the tube with the ash removed. On this
segment, the 12 o’clock position shows a smooth contour typical of a fluxing
fireside corrosion reaction, and the 10 and 2 o’clock positions show alligator
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Table 45-2
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions
For all root causes of fireside corrosion • Collect and evaluate ash and deposits to identify presence of low melting point constituents, particularly alkali iron trisulfates.
• Use corrosion probes to monitor deposit compositions and wastage.
• Use NDE measures (typically UT) to identify wall thinning.
• Choose repair strategy based on severity of corrosion rate.
• Implement long-term actions in conjunction with on-going program of remaining life assessment and monitoring.
Influence of overheating of tubes (These root causes will only increase the corrosion rate, – not initiate it, unless there is a corrosive coal)
• Measure steamside oxide thicknesses and evaluate whether overheating has occurred.
• Perform selective tube sampling and metallurgical analysis to confirm steamside oxide and wall thickness.
• Monitor temperatures using thermocouples installed across the SH/
RH outlet legs in vestibule to identify hottest platens across the boiler
• As above.
Poor initial design: choice of material • Evaluate temperatures across the element (via thermocouple or steamside oxide measurements) to determine if sections particularly near material changes are running too hot.
• As above; primary emphasis on upgrading to a more resistant material.
Table 45-2 (continued)
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions
Poor initial design: extra gas-touched
length • Evaluate temperatures across the element (via thermocouple
or steamside oxide measurements) to determine if sections particularly near material changes are running too hot. See discussion of gas-touched length in Chapter 44 for long-term overheating.
• As above
Internal oxide growth which occurs during operation • Measure oxide scale thickness and use selective sampling to c
onfirm the results. • As in primary list above (repairs followed by long-term strategy) plus chemical cleaning of steamside scale.
High temperature laning • Monitor temperatures.
• Consider the use of the cold air velocity technique. See Chapter 21, Volume 2, on fly
ash erosion for a discussion of the technique.
• As in primary list above (repairs followed by long-term strategy).
Tube misalignment (out of bank) • Visual examination. • Realign tubes; implement ongoing program of remaining life
assessment and monitoring.
Operational problems when coal type is changed • Evaluate whether operating procedures such as sootblowing can
be economically changed to protect SH/RH tubes.
Rapid startups causing reheater to reach temperature • Check startup probe and that initial gas is limited to 1000°F • Modify startup procedures if feasible.
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Table 45-2 (continued)
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions
Root Causes Related to Fuel Factors
• Use of, or change to, fuel with corrosive ash, particularly those with high S, Na, K, or Cl
• Evaluate coal composition using corrosivity index.
• Analysis for low melting point of ash components using probes.
• Analysis of metallurgical cross-sections, particularly for Cl, S, C, Na, and K.
• Install continuous readout corrosion sensors if unit switches coal or uses spot market coal
• As in primary list above (repairs, followed by long-term actions).
Root Causes Related to Combustion • Choose repair strategy based on severity of corrosion rate.
• Implement long-term actions from choices in Figure 45-12 in conjunction with ongoing program of remaining life assessment and monitoring
Use of low NOX combustion systems • Monitor for levels of O2, CO, H2S, and HCl along damaged or susceptible locations.
• Establish a combustion fluid dynamics model and use the model to evaluate potential improvements in combustion parameters.
• As above, plus:
– Increase combustion air to avoid reducing conditions (however may increase corrosion by other mechanisms, and may adversely affect NOX control).
Table 45-2 (continued)
Actions to Confirm and Immediate Actions and Solutions
Major Root Causes Actions to Confirm Immediate Actions and Solutions Use of startup oil, which coats
the tube and leads to tube carburization
• Check for unburnt startup oil deposits on tubes.
Excess of unburnt or partially burnt particles leading to an increase in carburization
• Perform metallurgical examination, including evaluating carbides, and check for phase mechanisms and may adversely affect NOX control).
• Perform metallurgical examination, including evaluating carbides, and check for phase mechanisms and may adversely affect NOX control).