Typical Boiler Tube Damage from Flexible
Operation or Cycling
3002002086
12354308
12354308
Typical Boiler Tube Damage from Flexible
Operation or Cycling
3002002086
Technical Update, December 2013
EPRI Project Manager
B. Carson
ELECTRIC POWER RESEARCH INSTITUTE
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DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES
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United Dynamics Advanced Technologies Corporation (UDC)
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ACKNOWLEDGMENTS
The following organization, under contract to the Electric Power Research Institute (EPRI),
prepared this report:
United Dynamics Advanced Technologies Corporation (UDC)
2681 Coral Ridge Rd.
Brooks, KY 40109
Principal Investigator:
J. Cavote
This report describes research sponsored by EPRI.
The 224 photographs used in this report are used with the permission of UDC and David N.
French Metallurgists and Engineers.
This publication is a corporate document that should be cited in the literature in the following
manner:
Typical Boiler Tube Damage from Flexible Operation or Cycling. EPRI, Palo Alto, CA: 2013.
3002002086.
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ABSTRACT
Power generation plants are under increasing pressure to cycle the boiler system to meet demand
at the exact time it occurs. To survive in the new commercial sphere, it is essential that we adjust
to a dynamic, flexible operating paradigm. The ability to adjust the overall system response to
load demand is paramount; cycling is a fact in today’s power-for-profit business dynamic.
The challenge is that for most fossil power plants in operation today—which were designed and
manufactured to be operated under baseload conditions—cycling to meet fluctuating demand
levels causes disproportionate wear and tear on boiler and plant components, which often leads
to damage. To accommodate the desire to cycle the production output levels of fossil-fired
systems, it is necessary to ramp the system faster than the original design anticipated. History has
revealed that rapid warmups and cooldowns are the most severe hardships that a boiler system
must endure. Going through the cycle of startup, operation, and shutdown creates higher
component stresses that lead to more severe maintenance issues than typify continuous operation
at rated capacity. Slow transitions from startup to operation as well as proper cooldowns prolong
life and reduce the possibility of pressure part failure.
This report presents recent inspection and failure data, inspection photographs, and diagrams as
information that can help utilities reduce failures associated with increased cycling. Because
many inspection and repair decisions are based on historical data and cycling is a fairly new
phenomenon, additional information will be needed to get up to speed on cycling failures.
To build a consensus of recommendations for preventing boiler cycling failures, we researched
more than 25,000 individual boiler inspections and more than 3,000 individual boiler failures
from the past 40 years. These data were combined with research culled on a worldwide basis.
Numerous issues related to boiler availability must also be considered and incorporated.
Sections 2–11 of the report cover the issues directly attributed to the cycling or load swinging of
the boiler system, and Sections 12–19 provide component-specific guidance for the inspection of
cycling effects in a coal-fired boiler.
Keywords
Baseload operation
Boiler tubes
Cycling
Damage assessment
Fatigue
Flexible operation
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CONTENTS
1 INTRODUCTION ..................................................................................................................1-1
1.2 Vulnerability of Boiler Components to Cycling ...............................................................1-2
1.2 Purpose of This Report ..................................................................................................1-5
1.3 Methodology ..................................................................................................................1-5
1.4 Conversion Factors for Units Used in This Report .........................................................1-6
2 LONG-TERM OVERHEAT (CREEP) ....................................................................................2-1
2.1 General Description .......................................................................................................2-1
2.2 Influence of Cycling on Creep Behavior .........................................................................2-3
2.3 Location of Creep Damage ............................................................................................2-3
2.4 Appearance ...................................................................................................................2-4
2.5 Causes ..........................................................................................................................2-5
2.5.1 High Temperature ..................................................................................................2-5
2.5.2 Material Properties .................................................................................................2-6
2.5.3 Steam-Side Scale Formation .................................................................................2-6
3 ABRASION (FRETTING/RUBBING) ....................................................................................3-1
3.1 General Description .......................................................................................................3-1
3.2 Cycling’s Influence on Abrasion .....................................................................................3-2
3.3 Location.........................................................................................................................3-2
3.4 External Appearance .....................................................................................................3-2
3.5 Cause ............................................................................................................................3-3
3.6 Prevention/Correction ....................................................................................................3-3
3.7 Acceptable Repairs .......................................................................................................3-3
3.8 Inspection Techniques ...................................................................................................3-3
3.9 Inspection Case History .................................................................................................3-3
4 THERMAL FATIGUE ............................................................................................................4-1
4.1 General Description .......................................................................................................4-1
4.2 Cycling’s Influence on Thermal Fatigue .........................................................................4-1
4.3 Locations .......................................................................................................................4-1
4.4 Appearance ...................................................................................................................4-4
4.5 Causes ..........................................................................................................................4-5
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4.6 Progressive Stages of Fatigue Cracking ........................................................................4-6
4.7 Prevention .....................................................................................................................4-7
4.8 Repairs ..........................................................................................................................4-7
4.9 Inspection Techniques ...................................................................................................4-7
4.10 Inspection Case Histories ............................................................................................4-7
5 CORROSION FATIGUE .......................................................................................................5-1
5.1 General Description .......................................................................................................5-1
5.2 Cycling’s Influence on Corrosion Fatigue.......................................................................5-1
5.3 Locations .......................................................................................................................5-2
5.4 Internal Appearance ......................................................................................................5-4
5.5 External Appearance .....................................................................................................5-5
5.6 Causes ..........................................................................................................................5-5
5.7 Prevention .....................................................................................................................5-6
5.8 Repairs ..........................................................................................................................5-6
5.9 Inspection Case Histories ..............................................................................................5-6
6 FATIGUE ..............................................................................................................................6-1
6.1 Cycling’s Influence on Fatigue .......................................................................................6-1
6.2 Appearance ...................................................................................................................6-2
6.3 Repairs ..........................................................................................................................6-2
7 DISSIMILAR METAL WELD CRACKING .............................................................................7-1
7.1 General Description .......................................................................................................7-1
7.2 Cycling’s Influence on DMWs ........................................................................................7-2
7.3 Location.........................................................................................................................7-2
7.4 External Appearance .....................................................................................................7-2
7.5 Internal Appearance ......................................................................................................7-3
7.6 Causes ..........................................................................................................................7-4
7.7 Prevention .....................................................................................................................7-4
7.8 Repairs ..........................................................................................................................7-4
7.9 Inspection Techniques ...................................................................................................7-5
7.10 Inspection Case Histories ............................................................................................7-5
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8 FALLING SLAG EROSION ..................................................................................................8-1
8.1 General Description .......................................................................................................8-1
8.2 Cycling’s Influence on Falling Slag Erosion ...................................................................8-1
8.3 Failure Location .............................................................................................................8-1
8.4 External Appearance .....................................................................................................8-2
8.5 Internal Appearance ......................................................................................................8-4
8.6 Causes ..........................................................................................................................8-5
8.7 Prevention .....................................................................................................................8-5
8.8 Inspection Techniques ...................................................................................................8-5
8.9 Inspection Case Histories ..............................................................................................8-5
9 LIGAMENT CRACKING .......................................................................................................9-1
9.1 General Description .......................................................................................................9-1
9.2 Cycling’s Influence on Ligament Damage ......................................................................9-3
9.3 Location.........................................................................................................................9-3
9.4 Internal Appearance ......................................................................................................9-4
9.5 Cause ............................................................................................................................9-5
9.6 Repairs ..........................................................................................................................9-5
9.7 Inspection Techniques ...................................................................................................9-5
9.8 Inspection Case History .................................................................................................9-6
10 SHORT-TERM OVERHEATING .......................................................................................10-1
10.1 General Description ...................................................................................................10-1
10.2 Short-Term/Long-Term Overheating ..........................................................................10-1
10.3 Cycling’s Influence on Short-Term Overheat Damage ...............................................10-3
10.4 Failure Location .........................................................................................................10-3
10.5 External Appearance .................................................................................................10-4
10.6 Internal Appearance ..................................................................................................10-4
10.7 Causes ......................................................................................................................10-5
10.8 Prevention .................................................................................................................10-5
10.9 Repairs ......................................................................................................................10-6
10.10 Inspection Techniques .............................................................................................10-6
10.11 Inspection Case Histories ........................................................................................10-6
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11 LOW-TEMPERATURE CORROSION...............................................................................11-1
11.1 General Description ...................................................................................................11-1
11.2 Cycling’s Influence on Dew-Point Corrosion Damage ................................................11-3
11.3 Location .....................................................................................................................11-3
11.4 External Appearance .................................................................................................11-5
11.5 Causes ......................................................................................................................11-6
11.6 Prevention/Correction ................................................................................................11-6
11.7 Repairs ......................................................................................................................11-7
11.8 Inspection Techniques ...............................................................................................11-7
11.9 Inspection Case Histories ..........................................................................................11-7
12 INSPECTION OF THE ECONOMIZER .............................................................................12-1
12.1 Cycling Effects on the Economizer ............................................................................12-1
12.2 Inspection Guidelines for the Economizer ..................................................................12-3
12.3 Inspection Case Histories of Economizers ...............................................................12-34
13 INSPECTION OF THE WATERWALL SLOPE/HOPPER/ COUTANT ..............................13-1
13.1 Cycling Effects on Waterwalls (All Areas) ..................................................................13-1
13.2 Inspection Guidelines for the Waterwall Slope/Hopper/Coutant .................................13-3
13.3 Inspection Case Histories for the Waterwall Slope/Hopper/Coutant .........................13-10
14 INSPECTION OF FURNACE WATERWALLS .................................................................14-1
14.1 Cycling Effects on Waterwalls (All Areas) ..................................................................14-1
14.2 Inspection Guidelines for Waterwalls .........................................................................14-3
14.3 Inspection Case Histories of Furnace Waterwalls ....................................................14-18
15 INSPECTION OF REAR-WALL HANGER TUBES...........................................................15-1
15.1 Cycling Effects on Rear-Wall Hanger Tubes ..............................................................15-1
15.2 Inspection Guidelines for Rear-Wall Hanger Tubes ...................................................15-3
15.3 Inspection Case Histories for Rear-Wall Hanger Tubes ...........................................15-10
16 INSPECTION OF CONVECTION PASS WALLS/HEAT RECOVERY AREA ...................16-1
16.1 Inspection Guidelines for Back/Convection Pass Walls .............................................16-2
16.2 Inspection Case Histories for Back/Convection Pass Walls .......................................16-7
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17 INSPECTION OF THE SUPERHEATER/REHEATER PENDANTS AND PLATENS ........17-1
17.1 Cycling Effects on the Superheater/Reheater Pendants and Platens.........................17-1
17.2 Inspection Guidelines for Superheater/Reheater Pendants and Platens ....................17-2
18 INSPECTION OF HORIZONTAL AND VERTICAL WRAPPER TUBES ...........................18-1
18.1 Inspection Guidelines for Horizontal and Vertical Wrapper Tubes .............................18-1
18.2 Inspection Case Histories for Horizontal and Vertical Wrapper Tubes .....................18-18
19 INSPECTION OF THE HORIZONTAL SUPERHEATER AND REHEATER ..........................1
19.1 Cycling Effects on the Horizontal Superheater and Reheater .........................................1
19.2 Inspection Guidelines for Horizontal Superheaters and Reheaters .................................1
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LIST OF FIGURES
Figure 1-1 Typical startup ramp curve provided by boiler manufacturers..................................1-2
Figure 2-1 An example of long-term creep ...............................................................................2-1
Figure 2-2 Neubauer’s classification of creep damage .............................................................2-3
Figure 2-3 This failure shows some minimal stretching before failure, unlike the shortterm overheat ...................................................................................................................2-4
Figure 2-4 100 mils (2540 µm) of oxide scale ...........................................................................2-5
Figure 2-5 Typical creep failure ................................................................................................2-5
Figure 3-1 A superheater tube that has been rubbed and abraded by an alignment clip ..........3-1
Figure 3-2 A water-cooled spacer tube from a T-fired unit........................................................3-2
Figure 3-3 The scissors (crossover) tube from a T-fired unit superheater division panel ..........3-2
Figure 3-4 An excessive crown weld has rubbed the adjacent tube .........................................3-3
Figure 3-5 Inspection report indicating sootblower abrasion wear ............................................3-4
Figure 4-1 Circumferentially oriented cracks are typical of thermal fatigue ...............................4-1
Figure 4-2 Common locations of thermal fatigue in a boiler ......................................................4-3
Figure 4-3 Thermal fatigue in a tube ........................................................................................4-4
Figure 4-4 Under magnification, the dagger-like morphology is apparent .................................4-4
Figure 4-5 Longitudinal section through circumferential grooves (5x magnification) .................4-5
Figure 4-6 Catastrophic tube separation from thermal fatigue ..................................................4-6
Figure 4-7 Width and depth are not reliable gauges of a thermal fatigue crack’s severity.........4-6
Figure 4-8 Inspection reports with indications of thermal fatigue in a front waterwall (first
report), circumferential cracking on a sidewall (second report), quench cracking in a
waterwall (third report), and circumferential cracking in a reheat outlet (fourth report) ......4-8
Figure 5-1 Common locations of corrosion fatigue ...................................................................5-3
Figure 5-2 This attachment on the cold side of the waterwall tubes is a likely area for
compound stresses and a prime candidate for corrosion fatigue ......................................5-4
Figure 5-3 A through-wall crack in a ring section ......................................................................5-4
Figure 5-4 This ring section of two tubes shows fatigue cracks in various locations .................5-5
Figure 5-5 Inspection reports with indications of corrosion fatigue in waterwalls (first and
second reports), the aperature floor (third report), and the rear wall of a burner
(fourth report) ...................................................................................................................5-7
Figure 6-1 Differential movement causes fatigue failure ...........................................................6-1
Figure 7-1 An attachment weld considered a DMW .................................................................7-1
Figure 7-2 DMWs fail from the outside to the inside .................................................................7-3
Figure 7-3 DMW failure typically looks like the weld was simply missing ..................................7-3
Figure 7-4 A crack on the T-22 side of a tube ..........................................................................7-4
Figure 7-5 Common locations of DMWs in the boiler ...............................................................7-5
Figure 7-6 An inspection report indicating a DMW oriented in the horizontal plane ..................7-6
Figure 7-7 An inspection report indicating a typical DMW failure ..............................................7-7
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Figure 7-8 Inspection report indicating an inevitable leak .........................................................7-8
Figure 8-1 General arrangement of hopper bottom ..................................................................8-1
Figure 8-2 Common locations of falling slag erosion in a boiler ................................................8-2
Figure 8-3 Tube indentation .....................................................................................................8-3
Figure 8-4 Tube gouging ..........................................................................................................8-3
Figure 8-5 Tube cracking at the toe of a weld ..........................................................................8-4
Figure 8-6 Polished tubes ........................................................................................................8-4
Figure 8-7 Crushed tubes ........................................................................................................8-5
Figure 8-8 Inspection reports with indications of tubes crushed by slag fall (first and
second reports) and sootblower erosion on a rear waterwall (third report) ........................8-6
Figure 9-1 A bore hole with radiating cracks ............................................................................9-1
Figure 9-2 A boat sample with ligament cracking spanning two bore holes ..............................9-2
Figure 9-3 Common locations of high thermal stress in the boiler ............................................9-4
Figure 9-4 Ligament cracks ......................................................................................................9-4
Figure 9-5 A longitudinal crack .................................................................................................9-5
Figure 9-6 Branching longitudinal cracks..................................................................................9-5
Figure 9-7 An inspection report indicating a ligament crack on a superheater header ..............9-7
Figure 10-1 A short-term reheat failure ..................................................................................10-1
Figure 10-2 A typical short-term overheat failure ....................................................................10-4
Figure 10-3 Stretch marks adjacent to the failed area ............................................................10-5
Figure 10-4 Inspection reports indicating various damage from short-term overheating: a
bulged tube (first report), a leak in a waterwall tube (second report), thin-edged
rupture in a secondary superheat outlet tube (third report), and tube blockage in a
final superheater (fourth report) ......................................................................................10-7
Figure 11-1 Dew-point corrosion found upstream of the typical location (Top: closeup of
corrosion; bottom: diagram of its location.) .....................................................................11-2
Figure 11-2 In this tube, what appears to be out-of-round is actually accumulative wall
loss from corrosion .........................................................................................................11-3
Figure 11-3 Common locations of low-temperature or dew-point corrosion in the boiler .........11-4
Figure 11-4 One of the many appearances of dew-point corrosion ........................................11-5
Figure 11-5 Economizer inlet header corrosion ......................................................................11-5
Figure 11-6 A tube that has failed because of corrosion.........................................................11-6
Figure 11-7 Raising the temperature of the flue gases will halt dew-point corrosion or
cold corrosion .................................................................................................................11-7
Figure 11-8 Inspection reports indicating damage from low-temperature corrosion:
fireside corrosion on a waterwall (first report) and acid dew-point corrosion in
economizer tubes (second and third reports) ..................................................................11-8
Figure 12-1 An economizer arrangement ...............................................................................12-2
Figure 12-2 Ash has blocked various gas lanes, restricting flow .............................................12-3
Figure 12-3 Excessive lane spacing results in gases taking the path of least resistance ........12-4
Figure 12-4 An economizer with the convection pass wall removed .......................................12-4
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Figure 12-5 An eroded circular flow baffle ..............................................................................12-4
Figure 12-6 Common areas of ash erosion in a boiler ............................................................12-5
Figure 12-7 Economizer inspection sites after debris removal................................................12-6
Figure 12-8 Blackened appearance .......................................................................................12-7
Figure 12-9 An eroded-through protective tube shield ............................................................12-7
Figure 12-10 Misalignment can cause accelerated erosion and high-pressure drop over
the area ..........................................................................................................................12-8
Figure 12-11 Pad welds made in this manner are at risk of developing leaks .........................12-9
Figure 12-12 A tube shield that has been eroded through ......................................................12-9
Figure 12-13 A dislodged harmonic baffle is blocking the gas lanes.....................................12-10
Figure 12-14 Economizer tube loops with the rear convection pass wall removed ...............12-10
Figure 12-15 Common header erosion .................................................................................12-11
Figure 12-16 Ringed fins are difficult to assess ....................................................................12-12
Figure 12-17 The likely areas for fly ash erosion in the baffle system ...................................12-13
Figure 12-18 A small area of the baffle can cause a large problem with fly ash and
retract erosion ..............................................................................................................12-13
Figure 12-19 Header erosion at a nipple ..............................................................................12-14
Figure 12-20 Corrosion on a header nipple ..........................................................................12-15
Figure 12-21 Missing convection pass peg fin (This will cause a breakdown in refractory
on the cold side.) ..........................................................................................................12-15
Figure 12-22 A disengaged support lug ...............................................................................12-17
Figure 12-23 A support lug disengaged from the convection pass wall ................................12-18
Figure 12-24 The sagging element could droop to a point where the retractable
sootblower might engage it ...........................................................................................12-18
Figure 12-25 A broken stainless steel support system in failure ...........................................12-19
Figure 12-26 Common locations of sootblower erosion in the economizer ...........................12-20
Figure 12-27 Erosion on the extended fins of an economizer ...............................................12-22
Figure 12-28 The wall thickness of the tube must be measured ultrasonically .....................12-23
Figure 12-29 A shield eroded through ..................................................................................12-23
Figure 12-30 Likely areas of retractable sootblower erosion ................................................12-24
Figure 12-31 Poor tube alignment is a contributor to ash erosion down in the bank .............12-25
Figure 12-32 Ash erosion is likely at any junction .................................................................12-25
Figure 12-33 The return bends of the ecomomizer...............................................................12-26
Figure 12-34 The likelihood of abrasion exists at every economizer junction .......................12-27
Figure 12-35 Protective shielding that has overheated and warped .....................................12-28
Figure 12-36 Return-bend shields that concentrate erosion on the tube ..............................12-28
Figure 12-37 Shielding and baffle techniques can control erosion ........................................12-29
Figure 12-38 Inlet header and stub tube ..............................................................................12-29
Figure 12-39 Ligament cracks ..............................................................................................12-30
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Figure 12-40 Circumferential crack on tube to stub at header ..............................................12-31
Figure 12-41 Borescope inspection reveals ligament cracks oriented in a radial location .....12-31
Figure 12-42 A crack in a header tee ...................................................................................12-31
Figure 12-43 Three radial cracks .........................................................................................12-32
Figure 12-44 Circumferential cracking..................................................................................12-32
Figure 12-45 Quench cracking of tube bore holes as a result of cold feedwater injected
on startup .....................................................................................................................12-33
Figure 12-46 Tube-to-header welds .....................................................................................12-34
Figure 12-47 Inspection reports indicating cycling-related problems in the economizer: fly
ash erosion (first and third reports), sootblower erosion (second report), and
thermal fatigue cracking (fourth report) .........................................................................12-35
Figure 13-1 Note the ID crack opposite the rupture ................................................................13-1
Figure 13-2 Lower-slope tube arrangement ...........................................................................13-2
Figure 13-3 A dented/suppressed tube ..................................................................................13-3
Figure 13-4 A deflected hopper bottom/coutant......................................................................13-4
Figure 13-5 Bulged tubes are clear evidence of an overheated tube ......................................13-4
Figure 13-6 Membrane crack that can be arrested using the keyhole method ........................13-5
Figure 13-7 Sootblower wall opening .....................................................................................13-5
Figure 13-8 The typical effect of fireside corrosion on tubes...................................................13-6
Figure 13-9 Tubes that have been pad-welded ......................................................................13-6
Figure 13-10 Circumferential tube cracking ............................................................................13-7
Figure 13-11 A crack in a seal skirt attachment ......................................................................13-7
Figure 13-12 Slag-covered tube .............................................................................................13-8
Figure 13-13 A shotgun dent in a vertical ...............................................................................13-8
Figure 13-14 Poor butt welds requiring intense inspection .....................................................13-9
Figure 13-15 Thinning in sidewall tubes adjacent to slope tubes ............................................13-9
Figure 13-16 Slope tube impacted more than 10% ..............................................................13-10
Figure 13-17 Inspection reports indicating a crushed front waterwall tube (first report), a
coutant tube crushed by slag fall (second report), and sootblower erosion (third
report) ..........................................................................................................................13-11
Figure 14-1 The location of the waterwall tubes .....................................................................14-2
Figure 14-2 Slag spalling off tubes during an outage .............................................................14-3
Figure 14-3 A severely bowed waterwall panel ......................................................................14-3
Figure 14-4 A clear sign of overheating: a blackened, circumferentially cracked
appearance ....................................................................................................................14-4
Figure 14-5 An obvious bulge ................................................................................................14-4
Figure 14-6 Multiple bulges reveal multiple events of DNB ....................................................14-5
Figure 14-7 High-intensity light capable of overheating an adjacent waterwall tube ...............14-5
Figure 14-8 A membrane that exceeds the cooling limitation to tubes ....................................14-6
Figure 14-9 A crack propagating from membrane to tube ......................................................14-7
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Figure 14-10 Severe erosion ..................................................................................................14-7
Figure 14-11 Extensive sootblower erosion in a pad-welded tube ..........................................14-8
Figure 14-12 A good example of what can go wrong around a sootblower opening ...............14-8
Figure 14-13 Pre-blow erodes behind the tube.......................................................................14-9
Figure 14-14 Coal particles erode tubes adjacent to burners .................................................14-9
Figure 14-15 One appearance of corrosion ..........................................................................14-10
Figure 14-16 Severe corrosion on a waterwall .....................................................................14-10
Figure 14-17 Cracking visible after ash removal...................................................................14-12
Figure 14-18 Multiple shot gunshot impacts .........................................................................14-13
Figure 14-19 A visible crack is never a good sign ................................................................14-13
Figure 14-20 A gash in a vertical tube ..................................................................................14-14
Figure 14-21 A tube cracked by a water lance .....................................................................14-15
Figure 14-22 Another tube cracked by a water lance ...........................................................14-15
Figure 14-23 A tube failure resulting from splashing from the ash pit ...................................14-16
Figure 14-24 Fretting can lead to a tube failure ....................................................................14-16
Figure 14-25 An OD crack in a boiler tube ...........................................................................14-17
Figure 14-26 Replace this type of pad weld when possible ..................................................14-17
Figure 14-27 Accidental cutting of a neighbor tube ..............................................................14-18
Figure 14-28 A rectangular window weld creating unacceptable stress in the repair and
tube ..............................................................................................................................14-18
Figure 14-29 Inspection reports indicating sootblower erosion (1 and 3), gouging from
past maintenance work (2), cracked membrane (4), thermal fatigue or cracking from
quenching (5, 6, and 14), a failed attachment clip (7), gas injector erosion (8),
impact gouge damage (9), a thermal fatigue–cracked weld (10), an explosionproduced hole (11), a tube crushed by fly ash erosion (12), slag fall damage (13),
and thermal fatigue cracking in a supercritical waterwall (15) .......................................14-19
Figure 15-1 Location of the rear-wall hanger tubes ................................................................15-2
Figure 15-2 Likely locations of erosion and abrasion in rear-wall hanger tubes ......................15-3
Figure 15-3 Tube thinning from sliding-slag erosion ...............................................................15-4
Figure 15-4 A severely corroded tube ....................................................................................15-4
Figure 15-5 Abrasion between restraint and tube ...................................................................15-5
Figure 15-6 Black color and cracks indicate possible overheat ..............................................15-5
Figure 15-7 Erosion at the intersection of tubing and refractory .............................................15-6
Figure 15-8 Dangerous gaps between shields .......................................................................15-7
Figure 15-9 An overheated shield bowing away from the very tube it is supposed to
protect ............................................................................................................................15-7
Figure 15-10 A broken alignment lug .....................................................................................15-8
Figure 15-11 Distortion caused by overheated alignment bars ...............................................15-8
Figure 15-12 Remove any remnants of an attachment ...........................................................15-9
Figure 15-13 Excessive, poorly applied pad welds .................................................................15-9
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Figure 15-14 Inspection reports indicating fly ash erosion at a deflection arch intersection
(first report), thermal fatigue in refractory (second report), and damage in wall
hanger tubes (third report) ............................................................................................15-10
Figure 16-1 Locations of the convection pass tubes ...............................................................16-1
Figure 16-2 Refractory is exposed with the peg fin missing ....................................................16-2
Figure 16-3 The rear corners are likely locations for increased fly ash erosion ......................16-2
Figure 16-4 A crack in the weld ..............................................................................................16-3
Figure 16-5 Fly ash erosion at the header-to-tube connection................................................16-4
Figure 16-6 Tubes in the convection pass that, if out of alignment, will catch fly ash and
become thinned by erosion ............................................................................................16-4
Figure 16-7 Convection pass header coupler in B&W units have had cracking in this
location ...........................................................................................................................16-5
Figure 16-8 In some B&W units, the section between rear convection pass wall headers
cracks and tears up the rear wall ....................................................................................16-6
Figure 16-9 Tubes in the convection pass walls that are bowed into the gas lane will
erode quickly ..................................................................................................................16-6
Figure 16-10 Polished tubes that measured above minimum wall thickness ..........................16-7
Figure 16-11 Inspection reports indicating fly ash erosion on a back pass wall (first
report) and low-temperature corrosion on a convection pass wall (second report)..........16-8
Figure 17-1 Locations of the superheat and reheat pendants.................................................17-1
Figure 17-2 Superheat and reheat lower loops ......................................................................17-2
Figure 17-3 An overheated tube concealed by ash and slag ..................................................17-3
Figure 17-4 Many shallow dents caused by shotgun blast .....................................................17-4
Figure 17-5 A tube with excessive restriction of steam flow....................................................17-4
Figure 17-6 A weld that is more likely to be problematic than one made by the proper
technique........................................................................................................................17-5
Figure 17-7 Wet steam erosion can be aggressive ................................................................17-6
Figure 17-8 Burned and deformed shields redirect sootblower and fly ash.............................17-7
Figure 17-9 Poor alignment or bowing is usually attributed to overheating .............................17-8
Figure 17-10 A bark-type surface on tubes sometimes indicates overheating ........................17-9
Figure 17-11 These flex ties are not engaged due to excessive bowing ...............................17-10
Figure 17-12 A broken alignment bar ...................................................................................17-11
Figure 17-13 Slag and ash trapped in a misaligned bundle of tubes ....................................17-12
Figure 17-14 One of the many forms of corrosion ................................................................17-13
Figure 17-15 Corrosion in this area is usually liquid-phase corrosion ...................................17-13
Figure 17-16 A DMW crack visible at the OD that provides little if any information on the
remaining useful life .....................................................................................................17-14
Figure 17-17 Replace DMWs before they fail .......................................................................17-15
Figure 17-18 Inspect vertical tubes ......................................................................................17-16
Figure 17-19 The entire circuit of an overheated tube should be inspected for other
damage ........................................................................................................................17-17
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Figure 17-20 Erosion in a shield and underlying tube ...........................................................17-18
Figure 17-21 Unacceptable coarse contrast in the weld weave ............................................17-19
Figure 17-22 Erosion has occurred in more than one cycle ..................................................17-20
Figure 17-23 A bowed tube is a target for retractable sootblower wash ...............................17-21
Figure 17-24 Cycling aggravates rubbing .............................................................................17-22
Figure 17-25 Extreme sootblower erosion ............................................................................17-23
Figure 17-26 Tubes penetrating the roof are subject to fly ash erosion ................................17-24
Figure 17-27 Where a tube arrangement presents a target to the retractable sootblower,
erosion usually occurs ..................................................................................................17-25
Figure 17-28 Retract erosion behind a wrapper tube on the individual vertical tubes ...........17-26
Figure 17-29 Ash corrosion can be found anywhere in this area ..........................................17-27
Figure 17-30 Crushed tubes follow the same rules as dented tubes ....................................17-28
Figure 17-31 A gap in a shield provides a focused stream of ash ........................................17-28
Figure 18-1 Horizontal and vertical wrapper tubes .................................................................18-1
Figure 18-2 Retractable sootblower accelerated erosion is the probable cause in this
area ................................................................................................................................18-2
Figure 18-3 Redirected erosion can severely thin tubes .........................................................18-3
Figure 18-4 A broken support lug can abrade the adjacent tube ............................................18-4
Figure 18-5 Rubbing/abrasion between physical elements ....................................................18-5
Figure 18-6 Crossovers or scissors tubes are likely to rub each other ....................................18-6
Figure 18-7 A panel disengaged by tube bowing....................................................................18-6
Figure 18-8 Broken alignment hardware ................................................................................18-7
Figure 18-9 Hard-to-access abrasion at a rigid mechanical alignment lug ..............................18-7
Figure 18-10 A complex junction of tubing .............................................................................18-8
Figure 18-11 Handcuffs provide fertile ground for abrasion and sootblower erosion ..............18-9
Figure 18-12 Distorted/burned tube shields may redirect erosion flow, increasing the
likelihood of tube thinning .............................................................................................18-10
Figure 18-13 A tube with extreme shotgun dents .................................................................18-11
Figure 18-14 Slag-covered tubes can cover underlying corrosion or erosion .......................18-12
Figure 18-15 This pad-welded area has been welded more than onceInspect for the
following indications of overheating in horizontal and vertical wrapper tubes: ...............18-13
Figure 18-16 Redirected retract erosion can cause severe thickness reduction in odd
locations .......................................................................................................................18-14
Figure 18-17 Yoke tubes are prime locations for erosion from sootblowers and abrasion
from tube-to-tube rubbing .............................................................................................18-15
Figure 18-18 Wrapper alignment tubes subject to abrasion and sootblower erosion ............18-15
Figure 18-19 Condensate in horizontal tubes will cause internal corrosion...........................18-16
Figure 18-20 A knuckle tube holding division panels in left to right locations ........................18-17
Figure 18-21 A single circuit can be overheated...................................................................18-17
Figure 18-22 Extreme bowing requiring replacement ...........................................................18-18
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Figure 18-23 Inspection reports indicating fretting/rubbing in a wrapper tube (first report),
a tube gouged by abrasion (second report), a crack in a superheat platen (third
report), thermal fatigue in a superheater pendant (fourth report), and sootblower
erosion (fifth report) ......................................................................................................18-19
Figure 19-1 The rear of the areas is a likely location for fly ash erosion .................................19-2
Figure 19-2 A flat area created by fly ash erosion ..................................................................19-3
Figure 19-3 Be sure to check the underlying tube for wall loss before the shield is
replaced .........................................................................................................................19-4
Figure 19-4 A shield eroded through can be a target for accelerated erosion .........................19-4
Figure 19-5 Distorted tube shields must be removed and inspected before a final repair
is selected ......................................................................................................................19-5
Figure 19-6 Inspect all pad welds carefully.............................................................................19-6
Figure 19-7 Bowing is likely caused by overheating ...............................................................19-6
Figure 19-8 A convection pass wall tube that has been rubbed by an adjacent element ........19-7
Figure 19-9 A disengaged support bracket abrading the return bend .....................................19-8
Figure 19-10 Erosion, abrasion, and corrosion .......................................................................19-9
Figure 19-11 Corrosion from an acidic combination of ash and water .................................19-10
Figure 19-12 A disengaged hanger allowing the element to droop into the crawl space .......19-10
Figure 19-13 Debris acts like a baffle, redirecting gas flows .................................................19-11
Figure 19-14 Peg fins act as a heat shield to protect the high crown seal areas...................19-11
Figure 19-15 Tubes drooping down into the furnace indicate that tube ties are broken
in the penthouse area ...................................................................................................19-12
Figure 19-16 Thermal fatigue cracking cannot be assessed by the width of crack at the
surface .........................................................................................................................19-13
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LIST OF TABLES
Table 1-1 Typical design life expectancies due to creep ..........................................................1-3
Table 1-2 Typical fatigue lives considered by the original design (These cycles would be
reached sooner during cycling operation because of the nature of cycling.) .....................1-4
Table 1-3 A failure study when cycling is considered ...............................................................1-4
Table 1-4 Units of measurement and their conversions............................................................1-6
Table 2-1 Initial creep temperature...........................................................................................2-2
Table 2-2 Thermal conductivities of various materials ..............................................................2-7
Table 10-1 Short-time elevated temperature tensile strength .................................................10-3
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INTRODUCTION
With power demand matching production, electricity production levels must meet demand at the
exact time it occurs. For fossil plants, many of which were originally designed for baseload
operation, cycling to meet fluctuating demand levels causes disproportionate wear, tear, and
damage to boiler and plant components.
Power plants are designated baseload based on their lowest-cost generation, efficiency, and
safety at rated output level. Baseload power plants are not subject to changes in generation
profiles to match system power consumption demands; it is more economical to operate them at
constant generation values. Use of combined-cycle plants or combustion turbines is thus
minimized because these plants can be cycled up and down to match more rapid fluctuations in
consumption. Baseload generators, such as nuclear and coal, often have very high permanent
costs, high plant load factor, and very low marginal costs. On the other hand, peak load
generators, such as natural gas, have low permanent costs, low plant load factor, and high
marginal costs. Typically, baseload plants are large and provide most of the power used by a
grid. Thus, they are more effective when used continuously to cover the power baseload required
by the grid.
As power utilities were deregulated, they became part of a more competitive overall market.
Power generation plants are under increasing pressure to cycle the boiler system. However, most
fossil power plants in operation today were designed and manufactured to be operated under
baseload conditions. With today’s demand for more frugal operations, plants must now be able to
operate on a more flexible basis, with load variations and two-shift operation becoming the
prevailing scheme, for example, in heat recovery steam generator (HRSG) units.
To survive in the new commercial sphere, it is essential that we adjust to a dynamic, flexible
operating paradigm. The ability to adjust the overall system response to load demand is
paramount; cycling is a fact in today’s power-for-profit business dynamic.
We are not alone—this is a worldwide phenomenon. It is a major concern to many utilities and
power plant operators.
Finances are the reason for implementing cyclic operation. To exploit the cycling benefits, units
are operated with the load as low as possible and ramp up as fast as the plant system allows. In
addition, cycling requires frequent startups and shutdowns.
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To accommodate the desire to cycle the production output levels of fossil-fired systems, it is
necessary to ramp the system faster than the original design anticipated (see Figure 1-1). History
has revealed that rapid warmups and cooldowns are the most severe hardships that a boiler
system must endure. Going through the cycle of startup, operation, and shutdown creates higher
component stresses that lead to more severe maintenance issues than typify continuous operation
at rated capacity. Slow transitions from startup to operation as well as proper cooldowns prolong
life and reduce the possibility of pressure part failure.
Figure 1-1
Typical startup ramp curve provided by boiler manufacturers
When a unit is taken off load, various parts of the boiler cool at varying rates, contingent on their
mass, insulation, and location in the boiler. Control of the applied heat is vital to minimize
startup times. Also important but often forgotten is ensuring a consistent temperature to avoid
thermal extremes during startup and shutdown. This is mostly important in waterwall tubes,
where casing air in-leakage can locally cool the furnace tubes. This is also aggravated when the
drum water level is maintained by the addition of cold water from the boiler feed system, which
has had time to cool down.
Thermal extremes—both in the form of quenching from cool to hot and drastic temperature rise
from hot to cool—can be avoided by sensibly managing the unit off its load conditions.
Considerations must be given to the type of plant, steam generating equipment types, and the
fuels used. Cold starts quantify less than in warm and hot starts. In most situations, frequent hot
or warm starts in the fossil plant operation are the most damaging operation.
1.2 Vulnerability of Boiler Components to Cycling
A typical boiler is constructed of different materials, including very thick drum metal, thinner
tube metal, refractory and insulation materials, and thick iron castings. All of these materials heat
and cool at different rates. This situation worsens when a material is exposed to different
temperatures at the same time.
Although many components can suffer from cyclic operation in current plants, the main concerns
during cycling are the steam drum, superheater and reheater headers, and connecting piping. All
of these components are prone to creep fatigue because of their heavy wall thickness.
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Historically, the problem with superheaters, reheaters, and associated components has been
thermal fatigue, in which the problems are exacerbated by weak heavy-section components,
complex geometries, and bending stresses.
Fatigue stresses can result from piping movement in the plant during heatup and cooldown, when
load changes occur. Here, the advantage is with strong, thin-wall members having innate
flexibility and deadweight that does not overwhelm pipe support systems that are in proper
working order. However, during startup, rapid changes in temperature in the plant can lead to
significant through-wall temperature differences.
During shutdowns, the temperature changes are more problematic, often causing a buildup of
condensate in remote sections of boiler tubing and headers. This condensate becomes a major
issue during the next startup, especially in superheaters and reheaters.
With no steam flow in the blocked tubes, metal temperatures rise to equal the flue gas
temperature before all condensate evaporates. When flue gas temperatures are too high, shortterm, high-temperature tube rupture occurs.
Weekend shutdowns have the worst effect in terms of temperature changes, and the risk of air
getting into the system is very high. The common view is that this will lead to thermally induced
corrosion fatigue of waterwalls, feedwater heaters, and economizers, where high local stress and
temperature gradients will cause cracking of protective magnetite films. This is particularly the
case if there is significant bending or increased loads from differential expansion and if a power
plant has been in service long enough to form an oxidation notch.
Cycling operation sets a rate and range of change in transient temperatures and pressures
throughout the system. In equipment, premature end of life and failure are predictable in cycling
operation. This circumstance consists of the excessive life depletion due to the increasing
number of stress phases experienced by boiler components as a result of temperature swings.
Before we can identify the solutions, we must understand the added problems specially related to
cycling. The historical dynamics shown in Tables 1-1 through 1-3 affect the rate and range of
damage that the boiler system will likely see increase in cycling operation.
Table 1-1
Typical design life expectancies due to creep
Component
Creep Life (hours)
Primary superheater outlet header
>180,000
Final superheater elements (part)
180,000
Final superheater outlet header
>250,000
Intermediate reheater outlet header
180,000
Reheater crossover pipes
180,000
Final reheater outlet header
180,000
Steam pipework (CrMoV)
250,000
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Table 1-2
Typical fatigue lives considered by the original design (These cycles would be reached
sooner during cycling operation because of the nature of cycling.)
Component
Fatigue Life (hours)
Economizer nonreturn valves
2500
Economizer inlet headers
1500
Economizer inlet header stubs
1500
Drum furniture
2000
Drum shell (welds)
4000
Downcomer attachment welds
2000
Circulating pump bodies
2000
Intermediate superheater outlet header
4000
Intermediate stage superheater inlet headers
2200
Crossover intermediate superheater headers
2200
Final superheater outlet header (P91)
1800
Second-stage reheater outlet header
5000
Second-stage reheater stubs
2000
Boiler stop valves
1200
Table 1-3
A failure study when cycling is considered
Component
Total Number of Failures
Percentage of Failures Due to
Cycling
Boiler tubes
33
33%
Headers
6
83%
Superheater tubes
47
19%
Reheater tubes
10
40%
Condenser
27
38%
High-pressure heater
17
70%
Low-pressure heater
3
33%
Superheater platens/pendants accumulate condensation in the bottom or lower loops when
temperatures fall below the ambient saturation temperature. The temperatures drop while the unit
is off and at the beginning of the startup cycle. This condensate restricts the flow through the
elements until it is boiled out. There are periods when only some of the pendants/platens have
established a flow while others are still blocked and will experience localized overheating and,
possibly, failure.
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Unlike the superheater circuits, the reheater flow is not established until after the turbine roll. If
this reheat flow is delayed, there is a risk of overheating and failure of the reheater elements. The
steam flow volume is reduced in low-load operation. In extreme circumstances, the reheat flows
through the boiler cease to be stable, and local overheating can occur.
In the waterwall areas with natural circulation drum boilers, residual heat in the upper sections
biases the circulation so that some tubes have a retarded flow. If these tubes are close to the
burners, the high heat flux can result in localized overheating.
Header cracking can be caused by the abrupt flow of a cold liquid into the header, which
quenches the bottom of the header more than the top. The header is then subjected to a thermally
induced bending moment that imparts permanent stresses to the header material. The thicker the
header, the greater the temperature difference and the greater the value of the stress induced.
It is not unusual to find temperature imbalances from side to side in boilers. The temperature
imbalance can be caused by uneven flue gas distribution across the boiler from ash and slag
buildup in the gas passes. Operators have little information to indicate the temperature
imbalance.
The fact that a component is designed to operate in the time-dependent regime identifies it as
having a finite life and places it in the class of critical components, which generally include the
following:
•
Final superheater outlet header
•
Hot reheater outlet header
•
Components that are excessively thick and that can be sensitive to temperature transient
conditions
Another geometric consideration is configurational complexity—complex geometry generally
has higher local stresses than simple geometry. Plant-specific and industry experiences and
records—that is, previous failures, over-temperature operation, inspection results, and
maintenance records—can provide valuable information in determining critical components and
vulnerable locations.
1.2 Purpose of This Report
This report presents research on recent inspection and failure data to provide information that
helps reduce failures due to increased cycling. Because many inspection and repair decisions are
made based on historical data and cycling is a fairly new phenomenon, additional information
will be needed to get up to speed on cycling failures.
1.3 Methodology
To build a consensus of recommendations for the prevention of boiler cycling failures, we
researched more than 25,000 individual boiler inspections and more than 3,000 individual boiler
failures from the past 40 years. These data were combined with information gathered on the topic
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on a worldwide basis. We must also consider and incorporate numerous issues related to boiler
availability. In order to complete our objectives, we must study the following systemic
relationships: the controlling influence usually comes from the boiler, and safety, emissions, and
cost are interconnected. In many cases, they are in conflict with one another.
The failures covered in Sections 2–11 can be directly attributed to the cycling (on-off-on) or load
swinging of the boiler system. Many failures work in conjunction with other mechanisms in the
final failure mode of the tubes. Other operational issues can have an impact on the failures listed.
Sections 12–19 provide component-specific guidance for the inspection of cycling effects in a
coal-fired boiler.
1.4 Conversion Factors for Units Used in This Report
Table 1-4 sets forth the units of measurement used throughout this report with their International
System of Units (SI) conversions.
Table 1-4
Units of measurement and their conversions
English Unit
SI Unit
Conversion Factor
Inch (in.)
Millimeter (mm)
1 in.=25.4 mm
Foot (ft)
Meter
1 ft=0.3 m
Degree Fahrenheit (°F)
Degree Celsius (°C)
°C=(°F-32) x 5-9
British thermal unit (Btu)
Joule (J)
1 Btu=1055 J
Pounds/square inch (psi)
Megapascal (MPa)
1 psi = 0.0069 MPa
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2
LONG-TERM OVERHEAT (CREEP)
2.1 General Description
Creep can be defined as a time-dependent deformation at elevated temperature and constant
stress. Creep failures result from an extended period of slight overheating above the design metal
temperature, a slowly increasing level of stress, or the accumulation of periods of excessive
overheating (during startup, for example). A failure from such a condition is referred to as a
creep failure or, occasionally, a stress rupture. Figure 2-1 shows an example of creep from longterm overheating.
Figure 2-1
An example of long-term creep
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The temperature at which creep begins depends on the alloy composition. Table 2-1 gives the
approximate temperature for the onset of creep for the common steels used in boiler
construction. Note that the actual temperature for the onset of creep depends on the stress;
stresses below normal Code-allowable levels increase the temperature, whereas stresses higher
than Code-allowable levels decrease it.
Table 2-1
Initial creep temperature
Type of Steel
Onset Temperature
o
Carbon steel
800 F (427°C)
Carbon + 1/2 Molybdenum
850 F (454°C)
1-1/4 Chromium-1/2 Molybdenum
950 F (510°C)
2-1 /4 Chromium-1 Molybdenum
1000 F (538°C)
Stainless steel
1050 F (566°C)
o
o
o
o
Usually, the end of useful service life of a boiler’s high-temperature components (the superheater
and reheater tubes and headers, for example) comes as the result of a failure by a creep or stress
rupture mechanism. The root cause might not be elevated temperature. Fuel ash corrosion or
erosion might reduce the wall thickness so that the onset of creep and creep failures occurs
sooner than expected.
The American Society of Mechanical Engineers’ (ASME’s) Boiler and Pressure Vessel Code
recognizes creep and creep deformation as high-temperature design limitations, and it provides
allowable stresses for all alloys used in the creep range. One of the criteria used in the
determination of these allowable stresses is 1% creep deformation in 100,000 hours of service.
Therefore, the Code recognizes that over the operating life, some creep deformation is likely.
Creep failures do display some deformation or tube swelling in the immediate region of the
rupture.
At elevated temperatures and stresses much lower than the high-temperature yield stress, metals
undergo permanent plastic deformation (creep). Figure 2-2 is a creep curve for a constant load—
a plot of the change in length versus time. The weight or load on the specimen is held constant
for the duration of the test. Four portions of the curve in Figure 2-2 are of interest, as follows:
•
Region A of the curve is an initial steep rate that is at least partly of elastic origin.
•
In Region B, the deformation rate is nearly linear with increasing time, usually referred to as
steady-state creep.
•
Region C is the region of great interest because inspection intervals need to be shortened to
measure the increasing microstructural damage.
•
Region D of the creep curve shows a rapidly increasing creep rate that culminates in failure.
Even under constant-load test conditions, the effective stress might actually increase because
of the damage that forms within the microstructure.
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Figure 2-2
Neubauer’s classification of creep damage
Creep deformation occurs by grain-boundary sliding. That is, adjacent grains or crystals move as
a unit relative to each other. Thus, one of the microstructural features of a creep failure is little or
no obvious deformation in individual grains along the fracture edge.
2.2 Influence of Cycling on Creep Behavior
Regarding cycling, creep might be the only active mechanism that is not caused by cycling. We
know that only components operating above 900°F (482°C) are inclined to creep damage.
Temperature transients at or above 900°F (482°C) and constant stress increase the overall creep
rate, regardless of cycling. The crucial issue is that if creep is coupled with fatigue from cycling,
the damage will be much higher than what could occur if the same fatigue or creep acted
individually.
2.3 Location of Creep Damage
Creep damage occurs in high-temperature locations in steam-filled tubes, such as superheat and
reheat areas, at locations characterized as follows:
•
Partially blocked by debris, scale, or deposits that restrict flow
•
Exposed to radiant heat (line-of-sight) or excessive gas temperature because of blockage of
gas passages or situated before the final outlet header
•
Situated before the change to a higher grade of steel or have an incorrect or lesser grade of
steel material
•
Containing higher stresses due to welded attachments and orientation; can occur in
waterwalls when the water-side deposits are excessive
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2.4 Appearance
Creep failures are visually characterized by the following:
•
Bulging or blisters in the tube
•
Thick-edged fractures, often with little obvious ductility
•
Longitudinal stress cracks in either or both inner diameter (ID) and outer diameter (OD)
oxide scales
•
External or internal oxide scale thicknesses that suggest higher-than-expected temperatures
•
A microstructure with intergranular voids and cracks
The first two stages will not leave microstructural evidence of creep damage. Somewhere along
the span labeled III of Figure 2-2, the first microstructural evidence of damage appears. The
steam-side magnetite forms axial cracks because the scale cannot follow the creep deformation.
A cusp then develops in the steel as steam penetrates the cracks and reforms the oxide. The cusps
enlarge, and individual voids or pores develop in the metal in front of the cusp tip. The location
of these first voids or holes varies; they are often observed at the junction of three or more
grains, occasionally at nonmetallic inclusions.
Individual voids grow and link to form cracks several grains long, and, finally, failure occurs.
The ultimate rupture is through a tensile overload when the effective wall thickness is too thin to
contain the steam pressure. High-temperature creep produces a longitudinal fracture. The extent
of the fracture and its appearance might vary.
A small fracture will form a blister opening, whereas a large fracture creates a wide, gaping,
fracture-like appearance. The fracture surface is thick-edged (see Figure 2-3), with extensive
secondary cracking adjacent to the main fracture. The tube surface might have a thick, hard
oxide scale, as might the tube’s internal surface (see Figure 2-4). Figure 2-5 presents a closeup
view of a typical creep failure.
Figure 2-3
This failure shows some minimal stretching before failure, unlike the short-term overheat
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Figure 2-4
100 mils (2540 µm) of oxide scale
Figure 2-5
Typical creep failure
2.5 Causes
The root causes of high-temperature creep can be verified by investigating the coolant circuitry,
the gas passages, and the tube material properties. Tube sampling may be necessary to check for
blockages and deposits that restrict the steam flow. Measurement of the tube metal and furnace
gas temperatures can verify abnormal gas flow patterns. Wall thickness measurements are
necessary to verify that stress levels have not increased due to erosion or corrosion.
2.5.1 High Temperature
As previously explained, creep ruptures occur primarily in the superheat and reheat areas. Longterm overheat is a result of operating problems, wrong material, incorrect flame patterns, or
restricted coolant flow.
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Although creep failures are expected for superheaters and reheaters operating at design
conditions, deviations from these parameters will promote early failures. The steam temperature
always varies somewhat from tube to tube. However, when the range of temperatures is wider
than accounted for in the design, the hottest tubes fail sooner than expected.
2.5.2 Material Properties
Because creep deformation occurs by grain-boundary sliding, the larger the grain-boundary area,
the more easily creep deformation will occur. Creep deformation and creep strength are sensitive
to grain size—a larger grain size improves creep strength. For austenitic stainless steels (SA213
TP321H, for example), the Code requires a specific grain size to ensure adequate creep strength.
The elevated temperatures where creep occurs lead to other microstructural changes. Creep
damage and microstructural degradation occur simultaneously. For carbon steels and carbon-1/2
molybdenum steels, iron carbide will decompose into graphite.
For the low-alloy steels of T11 and T22, the carbide phase spheroidizes. Thus, creep failures will
include the degraded microstructures of graphite or spheroidized carbides along with the grainboundary voids and cracks characteristic of these high-temperature, long-term failures.
2.5.3 Steam-Side Scale Formation
A more likely cause of premature failure is the slow increase in tube metal temperatures resulting
from the formation of steam-side scale. Steam reacts with steel to form iron oxide along the ID
surface of the tube. For superheaters and reheaters, the scale that forms is essentially magnetite
alloyed with chromium, molybdenum, manganese, and silicon from the alloy steels of T-11 and
T-22. For waterwalls, the iron oxide can be contaminated with impurities from the boiler water
and corrosion debris from the economizer and pre-boiler circuits of the condenser and feedwater
heaters. In either case, the thermal conductivity of the steam-side scale is about 5% of the
thermal conductivity of the steel tube. Therefore, an effective insulating layer forms and prevents
proper cooling of the tube metal by the steam. The net effect of the scale is to raise the tube
metal temperature.
Depending on the scale thickness—which is, in turn, dependent on the time and temperature of
operation—tube metal temperature increases of 25–75°F are likely. Such a large increase raises
tube metal temperatures beyond the safe design range. These elevated temperatures result in
increased creep deformation rates, more rapid oxidation and corrosion (thinner walls and higher
stress), and accelerated onset of creep failures. An increase of 60°F (from 1040o F to 1100o F
[560°C to 593°C], for example) will decrease creep life by 90%.
Steam reacts with steel to form iron oxide and magnetite, as follows:
3 Fe + 4 H20 = Fe3O4 + 4 H2
The thermal conductivity of magnetite is about 6% that of steel (see Table 2-2). Additionally, the
insulating effect raises tube metal temperatures. Waterwall tubes are chemically cleaned to
prevent overheating. A 50°F rise in a superheater tube caused by steam-side scale buildup
reduces the expected life by 80%. An increase in temperature increases the oxidation and
corrosion rates, increases creep deformation, and can dramatically increase tube failure rates.
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Table 2-2
Thermal conductivities of various materials
2
Material
Thermal Conductivity (Btu/ft hr) F°In
Analcite
8.8
Calcium phosphate
25.0
Calcium sulfate
16.0
Magnesium phosphate
15.0
Magnetic iron oxide
20.0
Silicate scale (porous)
0.6
Boiler steel
310.0
Firebrick
7.0
Insulating brick
0.7
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3
ABRASION (FRETTING/RUBBING)
3.1 General Description
Abrasion is a significant materials-related problem (thinning) found in operating fossil energy
power plants. It is also a problem in the grinding and pulverizing of coal for use in burners,
whereas erosion is a problem in the daily operation of the plants. Many systems and components
of pulverized coal power plants are affected by abrasion and erosion damage, including coal
preparation, slurry handling, burner nozzles, and boiler tubes. Damage from abrasion and erosion
can lead to failure and lower safety margins.
Figure 3-1 shows a superheater tube that has been abraded by an alignment clip. The taper of the
clip makes this type of damage difficult to inspect and detect.
Figure 3-1
A superheater tube that has been rubbed and abraded by an alignment clip
By understanding the mechanisms of abrasion, a better maintenance approach can be developed,
which will result in higher efficiency, less maintenance, and fewer catastrophic failures in fossil
energy plants.
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3.2 Cycling’s Influence on Abrasion
The continual cycling (on-off-on) or load swinging of the boiler system causes significant
movement of the boiler components. This movement is controlled by a design dynamic that
assumes annual maintenance outages plus a reasonable tube leak percentage, such as 5%. When
cycling, these assumptions are inadequate to sustain reliable, consistent operations.
3.3 Location
All tubes are vulnerable at junctions or crossover locations where there is tube-to-tube contact.
3.4 External Appearance
Abrasion-caused damage typically manifests itself as thinned tubes. In Figure 3-2, note the
abrasion wear on the spacer tube, and in Figure 3-3, note the rubbing between tubes. Shields are
not very effective due to the high temperatures in this area. Figure 3-4 shows an excessive crown
weld that has rubbed the adjacent tube. Movement in the two tubes and a sharp contact point
cause the rubbing.
Figure 3-2
A water-cooled spacer tube from a T-fired unit
Figure 3-3
The scissors (crossover) tube from a T-fired unit superheater division panel
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Figure 3-4
An excessive crown weld has rubbed the adjacent tube
3.5 Cause
Wear can be defined as damage to a solid surface caused by the removal or displacement of
material by the mechanical action of contacting a solid. It can cause significant surface damage,
and the damage is usually thought of as gradual deterioration. Misalignment or attachment to a
structure is usually the cause.
3.6 Prevention/Correction
The remedy for abrasion wear is alignment and/or replacement based on history and proactive
inspections.
3.7 Acceptable Repairs
Replacement is the preferred repair. However, the following other repairs might be selected
based on the plant’s risk exposure:
•
Replacements based on established criteria for acceptable minimum remaining wall
justification
•
Tube wall restoration (pad weld) based on established criteria for acceptable minimum
remaining wall justification
•
Shields as required
3.8 Inspection Techniques
See Sections 12–19 for inspection guidance on individual areas of a boiler.
3.9 Inspection Case History
Figure 3-5 is a sample of an inspection report that indicates abrasion wear in a tube.
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Figure 3-5
Inspection report indicating sootblower abrasion wear
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4
THERMAL FATIGUE
4.1 General Description
Thermal fatigue is the result of cyclic stress caused by variations in temperature. Damage takes
the form of fatigue cracks that can occur anywhere in a metallic component where relative
movement or differential expansion is constrained, particularly under repeated thermal cycling.
Thermal fatigue can be found in piping and equipment in all industries. Examples include the
mixture points of two streams of widely disparate temperatures, such as locations where
condensate comes in contact with steam and steam quenching occurs.
4.2 Cycling’s Influence on Thermal Fatigue
Fatigue is an ambient temperature failure mechanism that develops from a variable stress; the
peak stress is higher than the safe operating stress, called the fatigue limit. Common fatigue
failures occur in pulverizer shafts, pump shafts, fan blades, and so on.
Thermal fatigue involves a variable stress at an elevated temperature high enough to form iron
oxide on the crack surfaces. Circumferential cracks in superheater and reheater tube-to-header
welds are a common form of thermal fatigue (see Figure 4-1).
Figure 4-1
Circumferentially oriented cracks are typical of thermal fatigue
4.3 Locations
All materials of construction are susceptible to thermal fatigue. Austenitic stainless steels and
nickel-based alloys are somewhat more sensitive because of their lower thermal conductivity,
where larger thermal gradients are possible.
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In steam-generating equipment, the most common locations are at rigid attachments between
neighboring tubes in the superheater and reheater. Slip spacers designed to accommodate the
relative movement can become frozen and act as a rigid attachment when plugged with fly ash.
Tubes in the high-temperature superheater or reheater that penetrate through the cooler
waterwalls can crack at the header connection if the tube is not sufficiently flexible.
These cracks are most common at the end where the expansion of the header relative to the
waterwall will be greatest. Steam-actuated sootblowers can cause thermal fatigue damage if the
first fluid exiting the sootblower nozzle contains water. Rapid cooling of the tube by the water
will promote this form of damage. The use of water lances or water cannons on waterwall tubes
can have the same effect.
Figure 4-2 shows the locations in the boiler where thermal fatigue is common.
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TF = thermal fatigue; BRN = burner; CRN = corner
Figure 4-2
Common locations of thermal fatigue in a boiler
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4.4 Appearance
Figure 4-3 is a closeup view of a tube affected by thermal fatigue. Thermal fatigue cracks
propagate transverse to the stress. However, cracking can be axial, circumferential, or both at the
same location. Thermal fatigue cracks usually initiate on the surface of the component, are
generally wide, and are filled with oxide due to exposure to elevated temperature. Cracks can
occur singly or in multiples. In steam-generating equipment, cracks usually follow the toe of the
fillet weld because the change in section thickness creates a stress raiser. Often, cracks start at
the end of an attachment lug, and if there is a bending moment as a result of the constraint, they
will develop into circumferential cracks in the tube. Water in sootblowers can lead to a crazing
pattern, with the predominant cracks being circumferential and the minor cracks being in an axial
direction. In cross-section, the cracks are always dagger-shaped (see Figure 4-4), transgranular,
and oxide-filled.
Figure 4-3
Thermal fatigue in a tube
Figure 4-4
Under magnification, the dagger-like morphology is apparent
Figure 4-5 shows a longitudinal section through circumferential grooves. The corrosion
resistance of the surface layer has been compromised by carburization.
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Figure 4-5
Longitudinal section through circumferential grooves (5x magnification)
4.5 Causes
The two key factors affecting thermal fatigue are the magnitude of the temperature swing and the
number of cycles. The likelihood of initiating damage and the extent of damage increase with
wider temperature swings and an increasing number of cycles. Startup and shutdown of
equipment can cause thermal fatigue. There is no set limit on temperature swings; however, as a
practical rule, cracking is suspected if the temperature swing exceeds about 200°F. Damage is
also promoted by rapid changes in surface temperature that result in a varied temperature through
the thickness or along the length of a component—for example, cold water on a hot tube
(thermal shock), rigid attachments and a smaller temperature differential, and inflexibility to
accommodate differential expansion.
Time to failure is a function of stress and the number of cycles. The presence of notches (such as
the toe of a weld) and sharp corners (such as the intersection of a nozzle with a vessel shell) and
changes in section thickness can serve as initiation sites. At elevated temperatures, crack
propagation is enhanced by the formation of oxides or other corrosion products. In the simplest
case of cyclic stress at elevated temperatures, the protective oxide cracks, exposing fresh metal to
further oxidation. A surface crack is wedged open by the formation of these scales because the
oxide occupies a greater volume than the metal from which it forms. The oxide edge imposes
higher stresses at the crack tip, and the crack propagation rate increases.
In some cases, thermal fatigue can be catastrophic, such as in the tube separation pictured in
Figure 4-6. Note that the width and depth of a thermal fatigue crack are not reliable gauges of the
crack’s severity (see Figure 4-7).
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Figure 4-6
Catastrophic tube separation from thermal fatigue
Figure 4-7
Width and depth are not reliable gauges of a thermal fatigue crack’s severity
4.6 Progressive Stages of Fatigue Cracking
The process of fatigue consists of the following five stages:
1. Cyclic plastic deformation prior to fatigue crack initiation
2. Initiation of one or more microcracks
3. Propagation or coalescence of microcracks to form one or more macrocracks
4. Propagation of one or more macrocracks until the remaining uncracked cross-section of a
part becomes too weak to carry the loads imposed
5. Final, sudden fracture of the remaining cross-section
Whereas thermal fatigue cracks are usually dagger-shaped, oxide-filled, and transgranular,
corrosion fatigue cracks are typically more rounded. The relative rates of corrosion wastage
along the sides of the crack and crack propagation determine the overall shape of the crack.
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4.7 Prevention
Thermal fatigue is best prevented through design and operation to minimize thermal stresses and
thermal cycling. Several methods of prevention apply, depending on the application. Designs
that incorporate reduction of stress concentrators, blend-grinding of weld profiles, and smooth
transitions should be used. Controlled rates of heating and cooling during startup and shutdown
of equipment can lower stresses, where appropriate. Differential thermal expansion between
adjoining components of dissimilar materials should be considered. Designs should incorporate
sufficient flexibility to accommodate all differential expansions. In steam-generating equipment,
slip spacers should slip, and rigid attachments should be avoided. Drain lines should be provided
on sootblowers to prevent condensate in the first portion of the sootblowing cycle.
4.8 Repairs
Replacement is the only suggested repair for components damaged by thermal fatigue.
4.9 Inspection Techniques
Because cracking is usually surface-connected, visual examination, magnetic particle testing, and
liquid penetrant are effective methods of inspection. External shear wave ultrasonic inspection
can be used for nonintrusive inspection and where reinforcing pads prevent nozzle examination.
Heavy-wall reactor vessel internal attachment welds can be inspected using specialized
ultrasonic techniques.
4.10 Inspection Case Histories
Figure 4-8 shows four examples of inspection reports that indicate the presence of thermal
fatigue.
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Figure 4-8
Inspection reports with indications of thermal fatigue in a front waterwall (first report),
circumferential cracking on a sidewall (second report), quench cracking in a waterwall
(third report), and circumferential cracking in a reheat outlet (fourth report)
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Figure 4-8 (continued)
Inspection reports with indications of thermal fatigue in a front waterwall (first report),
circumferential cracking on a sidewall (second report), quench cracking in a waterwall
(third report), and circumferential cracking in a reheat outlet (fourth report)
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Figure 4-8 (continued)
Inspection reports with indications of thermal fatigue in a front waterwall (first report),
circumferential cracking on a sidewall (second report), quench cracking in a waterwall
(third report), and circumferential cracking in a reheat outlet (fourth report)
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NDE = nondestructive evaluation; MWT = minimum wall thickness
Figure 4-8 (continued)
Inspection reports with indications of thermal fatigue in a front waterwall (first report),
circumferential cracking on a sidewall (second report), quench cracking in a waterwall
(third report), and circumferential cracking in a reheat outlet (fourth report)
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5
CORROSION FATIGUE
5.1 General Description
Corrosion fatigue is a term for water-side damage under both stress (>25,000–30,000 psi
[172.4–206.8 MPa]) and varying corrosivity. Another form of corrosion fatigue, more properly
called stress-assisted corrosion, forms when stresses are high enough to crack the magnetite
scale in an occasionally corrosive environment, that is, one with varying corrosivity. Corrosion
fatigue is a form of deterioration that can occur without concentration of a corrosive substance.
5.2 Cycling’s Influence on Corrosion Fatigue
Corrosion fatigue can occur in any location where stresses of sufficient magnitude are in play.
These failures more often occur in boilers that are in peaking service, used infrequently, or
otherwise operated cyclically. Unfortunately, the oldest boilers in a fleet are normally the ones
placed in this type of service. Rapid boiler ramp (startup or shutdown) greatly increases the
vulnerability to corrosion fatigue. Some serious corrosion fatigue problems have been eliminated
merely by modifying startup and shutdown rates.
The relative importance of stress and corrosivity on power generation boilers is still questioned.
Two factors are required—a strain (or stress) large enough to fracture the magnetite scale and
boiler water with excessive oxygen concentration or a too-low pH. Therefore, the damage might
not occur with only a high-strain, too-rapid startup when the boiler water chemistry is correct. It
is damage from high and variable corrosivity and constant stress or high and variable stress.
Hence, the preferred terminology is stress-assisted corrosion.
The condition is a result of the cyclic loading externally (OD) combined with a corrosive
environment internally (ID). These cracks can have their origin in surface imperfections or pits.
This condition should not be confused with cracks that are initiated on the outside of the tubing.
The physical description of these OD cracks is usually dagger-shaped, transgranular, wide, and
oxide-filled.
Weekend shutdowns have the worst effect in terms of temperature changes, and the risk of air
getting into the system is very high.
The common view is that this will lead to thermally induced corrosion fatigue of waterwalls,
feedwater heaters, and economizers, where high local stress and temperature gradients will lead
to the cracking of protective magnetite films. This is particularly the case if there is significant
bending or increased loads from differential expansion, when a power plant has been in service
long enough to form an oxidation notch.
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5.3 Locations
Figure 5-1 shows the locations in a boiler where corrosion fatigue is common. Corrosion fatigue
is typically located on the water side of waterwall and economizer tubes, generally at
attachments and restraints (see Figure 5-2 for an example of a waterwall attachment site that is
particularly vulnerable). Specifically, corrosion fatigue occurs at the following locations:
•
Windbox casing attachments
•
Buckstay connections
•
Sidewall-to-slope connections
•
Division wall at slope penetration
•
Burner elevations
•
Boiler water seals (weir box)
•
Boiler ash hopper seal plates
•
Gas recirculation duct attachments
•
End-of-membrane connections
•
Economizer fin welds
•
Fin-welded tubes
•
Scallop tie bars
•
Waterwall gusset plates
•
Penthouse floor attachments
•
Rear wall arch
•
Furnace wall penetrations
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CF = corrosion fatigue
Figure 5-1
Common locations of corrosion fatigue
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5-3
Figure 5-2
This attachment on the cold side of the waterwall tubes is a likely area for compound
stresses and a prime candidate for corrosion fatigue
5.4 Internal Appearance
Cracking usually occurs on the inside surface of the water-touched tubes on the cold side of the
tubing. It is unusual for cracking to also occur on the hot side of a tube. These cracks are oriented
perpendicular to the principal stress. In the laboratory, cracks have been seen to be
circumferential or in any orientation that is consistent with the stress. Cracks have also been
found at grooves along the ID of tubes that have been only partly full of water (cracks usually
run at a right angle to the grooves). This can be caused by intermittent steam blanketing within
generating tubes, at oxygen pits in water lines or feedwater lines, in welds at slag pockets or
points of incomplete fusion, in sootblower lines where vibration stresses are developed, and in
blowdown lines. Figure 5-3 shows a through-wall crack in a ring section, and Figure 5-4 depicts
fatigue cracks in another ring section.
Figure 5-3
A through-wall crack in a ring section
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Figure 5-4
This ring section of two tubes shows fatigue cracks in various locations
5.5 External Appearance
The cracks always propagate at right angles to the direction of the principal stress. When
principal cyclic stress is produced by fluctuations in internal pressure, longitudinal cracks are
produced; when the principal cyclic stress is a bending stress produced by thermal expansion and
contraction of the tube, cracks will be transverse. Corrosion-fatigue cracking commonly occurs
adjacent to physical restraints. Cracks can originate on the external surface, the internal surace,
or both, simultaneously.
Cracks originating on the internal surfaces might be associated with pits. The pit site serves as a
stress-concentrating notch, making it a preferred site for initiation of corrosion-fatigue cracks.
5.6 Causes
In carbon steel, the combination of cracked magnetite from mechanical strain and a corrosive
environment will cause corrosion fatigue. The corrosion resistance of carbon steel is provided by
a layer of magnetite, iron oxide (Fe3O4). When this protective scale is damaged, corrosion
fatigue can form. Mechanical and chemical factors directly affect this condition.
Chemical factors include pH excursions and high levels of dissolved oxygen in the boiler water.
Mechanical factors leading to corrosion fatigue include the following:
•
•
•
•
•
•
•
Boiler pressure
Thermal gradient through the tube
Heat flux (Btu/square foot [square meter])
Restraint during thermal expansion
Weight of restraint
Startup and shutdown ramp acceleration
Subcooling on startups in natural circulation boilers
Corrosion fatigue is more likely in peaking units where many thermal cycles are experienced.
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5.7 Prevention
Plants can take the following preventive measures regarding corrosion fatigue:
•
•
•
Reduce the stress on cold-side tube attachments. Reinforcement of the attachment will
exacerbate the condition.
Reduce subcooling in natural circulation boilers (top-to-bottom temperature differential) on
startups.
Control and improve the water chemistry and chemical cleaning.
In some cases, serious corrosion-fatigue problems have been eliminated merely by modifying
startup and shutdown rates.
5.8 Repairs
Tube replacement is the preferred method of repair. Even in forced outage conditions, pad
welding is not recommended because complete removal of all cracks is rare, making repeat
failures in the same general area likely.
5.9 Inspection Case Histories
Figure 5-5 presents four examples of inspection reports that indicate the presence of corrosion
fatigue.
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Figure 5-5
Inspection reports with indications of corrosion fatigue in waterwalls (first and second
reports), the aperature floor (third report), and the rear wall of a burner (fourth report)
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Figure 5-5 (continued)
Inspection reports with indications of corrosion fatigue in waterwalls (first and second
reports), the aperature floor (third report), and the rear wall of a burner (fourth report)
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5-8
Figure 5-5 (continued)
Inspection reports with indications of corrosion fatigue in waterwalls (first and second
reports), the aperature floor (third report), and the rear wall of a burner (fourth report)
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5-9
MWT = minimum wall thickness
Figure 5-5 (continued)
Inspection reports with indications of corrosion fatigue in waterwalls (first and second
reports), the aperature floor (third report), and the rear wall of a burner (fourth report)
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6
FATIGUE
Fatigue and fatigue damage are the predominant mechanisms affecting boiler life. Fatigue
damage is a direct consequence of cycling and aggravates other conditions at play during
cycling.
6.1 Cycling’s Influence on Fatigue
Differential expansion or unequal heat-raising of tubes is caused by irregular distribution of the
effects of varying wall thickness and tubes’ ability to absorb the gross heat input to the
components.
Cyclic loading is caused by the following:
•
•
•
Constraint of thermal expansion
Mechanical stresses from poor design or manufacturing
Vibration
Differential movement, such as seen in Figure 6-1, can cause a fatigue failure. In Figure 6-1, the
movement is due to the difference of the attachment and support systems.
Figure 6-1
Differential movement causes fatigue failure
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6.2 Appearance
The appearance of fatigue is characterized by the following:
•
•
•
Transgranular
Usually OD-initiated, but it might start at an ID pit or groove if the stress concentration is
large
Thick-lipped failure, that is, little ductility except for the final rupture due to overload
6.3 Repairs
Remove and replace the fatigue-damaged component, and correct the underlying cause of the
failure.
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7
DISSIMILAR METAL WELD CRACKING
7.1 General Description
Dissimilar metal weld (DMW) cracking is caused by temperature-induced stresses that accelerate
the creep process. The total stress to the joint includes stresses that arise from differences in the
coefficient of thermal expansion; from internal steam pressure, tube deadweight, and throughwall thermal gradients; and from constraints to thermal expansion due to tube support
malfunction. Cracking of DMWs occurs in the ferritic side of a weld between an austenitic and
ferritic material.
DMWs are found not only in tubing welds. Attachments from stainless steel to ferritic steel
tubing (such as the one pictured in Figure 7-1) are also considered DMWs.
Figure 7-1
An attachment weld considered a DMW
The condition is especially acute when the weld metal used is an austenitic stainless steel similar
to E309. The cracking occurs because the coefficients of expansion between ferritic steels and
austenitic stainless steels differ by about 30%.
At the operating temperature, the differences in expansion lead to a high-temperature stress at the
heat-affected zone (HAZ) on the ferritic side. When the operating temperature is above about
950°F (510°C), the HAZ is within the creep range, and failure occurs by a creep-cracking
mechanism. At these elevated temperatures, the problem is exacerbated by diffusion of carbon
out of the HAZ to the weld metal. Loss of carbon reduces the creep strength, and the cracking
potential is enhanced. In environments that promote liquid-ash corrosion, the problem can be
accelerated by stress-assisted corrosion.
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The large thermal strain in the ferritic HAZ will preferentially corrode. The result is long, narrow
oxide wedges that parallel the weld fusion line. Similar failures occur in the pressure welds
(autogenous welds without filler metal added).
7.2 Cycling’s Influence on DMWs
Cycling generates a temperature change in the DMW. With the effects of differential expansion
in the DMW, the time to failure is reduced with each completed cycle until failure is reached.
The DMW mechanism can be summarized as follows:
•
•
•
•
•
•
•
The coefficient of expansion of the ferrite alloy is about 30% lower than that for austenitic
stainless steel.
At operating temperature, the greater expansion of the stainless steel creates a tensile stress in
the HAZ of the ferritic steel.
The lower carbon content of the weld leads to carbon diffusion from the HAZ to the weld
metal.
Loss of carbon reduces the creep strength in the HAZ.
Creep cracks form in the HAZ of the ferrite adjacent to the fusion zone.
High temperature and large bending stress exacerbate the problem.
Stresses are from intrinsic loads, primary loads, and secondary loads plus the temperature
stress.
7.3 Location
Usually, ferritic tubes that are welded to austenitic stainless steel and operate in the creep range
are located in the superheat or reheat area. There are conditions where tubes, even waterwall, are
overlaid with stainless material and can be affected.
7.4 External Appearance
The tubes are cracked circumferentially. The cracks form at the toe of the weld in the HAZ of the
ferritic alloy. Most common are welds between tubes, but support lugs or attachments of
austenitic stainless steels to ferritic stainless are also affected. Poor geometry of the weld,
excessive undercut, and other stress-intensification factors will exacerbate the crack formation.
DMWs fail from the outside to the inside, as shown in Figure 7-2. As a result, visual inspection
if of little use. Various nondestructive evaluation (NDE) methods are available; however,
proactive replacement is the desired and most economical method of DMW management. DMW
failure typically looks like the weld was simply missing (see Figure 7-3). If a DMW failure
impacts other DMWs, the affected DMWs should all be replaced.
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Figure 7-2
DMWs fail from the outside to the inside
Figure 7-3
DMW failure typically looks like the weld was simply missing
7.5 Internal Appearance
DMW cracking produces a circumferential fracture in the joint, with the fracture parallel to the
weld fusion line in the ferritic steel. The fracture surface will have a shape similar to weld beads
and appear as though the ferritic steel was not fused to the weld metal. Initiation of the crack can
occur anywhere along the fusion line. A brittle, thick-edged fracture results from the linking up
of creep voids adjacent to carbide precipitates along the grain boundaries. In Figure 7-4, a crack
can clearly be seen on the T-22 side of the tube cross-section.
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Figure 7-4
A crack on the T-22 side of a tube
7.6 Causes
DMWs fail by the formation of creep cracks in the HAZ of the ferrite steel T-22. The coefficient
of expansion of the stainless steel is about 30% greater than that of the T-22. At operating
temperatures, the greater expansion of the stronger stainless steel strains the HAZ of the T-22.
Over time, carbon diffuses out of the T-22 into the stainless steel; note the row of carbide
particles that defines the fusion line. The loss of carbon decreases the creep strength of the T-22,
and the combination of high strain and lowered strength causes creep cracks to form.
7.7 Prevention
Proactive replacement of DMWs is the best way to prevent this type of damage. Better DMW
performance can be obtained by controlling the critical factors of stress and temperature. For
example, the weld joint can be relocated to a position at a lower temperature, or nickel-based
filler metal could be used to lower the stress from differences in thermal expansion. Frequent
inspection and maintenance of tube hangers, supports, and spacers can be performed to reduce
secondary loads.
7.8 Repairs
Replace DMWs before failure occurs. Using a safe end for this purpose is recommended. Safe
ends are fabricated with a ferrite steel end and a stainless steel end joined together with an
INCONEL 1 weld.
Leaks can be rewelded using nickel-based weld materials. Nickel-based electrodes with a
coefficient of expansion closer to the ferritic alloys have proven successful. They transfer the
temperature stress from the ferritic side to the austenitic side of the weld. However, the stainless
steel HAZ is stronger, and cracks do not form.
1
INCONEL is a registered trademark of Special Metals Corp.
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7.9 Inspection Techniques
See Sections 12–19 for inspection guidance for the individual components of a boiler. Figure 7-5
shows the locations in a boiler where DMWs are common.
Figure 7-5
Common locations of DMWs in the boiler
7.10 Inspection Case Histories
The example inspection report shown in Figure 7-6 is significant in that any DMW oriented in
the horizontal plane is at risk by design. In this orientation, the constant uneven load on the weld
will probably lead to premature failure.
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7-5
SSH = secondary superheater
Figure 7-6
An inspection report indicating a DMW oriented in the horizontal plane
The report shown in Figure 7-7 covers a typical DMW failure. The appearance is that of a clean
break, as if it were never welded.
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Figure 7-7
An inspection report indicating a typical DMW failure
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7-7
The example report in Figure 7-8 assumes the occurrence of a leak and treats it as a failure.
Figure 7-8
Inspection report indicating an inevitable leak
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8
FALLING SLAG EROSION
8.1 General Description
Slag erosion can occur at the lower furnace wall, which directs ash into the bottom ash hopper
(coutant) (see Figure 8-1 for a diagram of a hopper bottom). The sloping wall tubes within 3–4 ft
(0.9–1.2 m) of each sidewall near the bottom will experience the greatest erosion. Falling slag
erosion produces flat surfaces by removing metal. A longitudinal, thin-edged fracture results
when the wall thickness can no longer restrain the internal pressure.
Figure 8-1
General arrangement of hopper bottom
8.2 Cycling’s Influence on Falling Slag Erosion
During cycling operation, combustion consistency is quite variable. This lack of consistency
produces slag accumulation on the waterwalls. If operations is not alerted to this, the
accumulation can become thick. By gravity or sootblowing, the slag is dislodged and falls into
the lower slope and ash pit.
The reverse of this condition is that a sudden change in temperature will cause accumulated slag
to fall off, also impacting the lower slope. This is likely to occur on a turndown or tripping of the
unit.
8.3 Failure Location
Falling slag can occur in the hopper bottom as well as on any vertical waterwalls. Figure 8-2
shows the locations in a boiler where falling slag erosion is common.
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FS = falling slag; BRN = burner
Figure 8-2
Common locations of falling slag erosion in a boiler
Determine the important factors that result in a slagging problem. Analysis so far indicates that
the silica percentage and ash-softening temperature can be used to categorize the slagging
tendency of a coal. Visual examinations and ultrasonic tube wall thickness measurements can
detect and monitor falling-ash erosion. Ultrasonic surveys should be conducted during boiler
overhaul outages to determine the extent of erosion and provide data for planning corrective
actions.
8.4 External Appearance
The external appearance of slagging can take several forms, including the following:
•
•
Dented (high priority >10% restriction) (see Figure 8-3). Tube indentation causes a
restriction of water flow from the bottom up. Replacement is the only viable option. A
restriction of more than 15% should be the threshold for replacement.
Gouged (medium priority <20% wall loss) (see Figure 8-4). Be aware that a gouge can
produce a lip or crater, which makes the gouge look far worse than if the crater were not
there. Grind the crater down to the tube surface, and then you can use a gauge to determine
the actual depth of the gouge.
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8-2
•
•
Cracked (high priority if propagating) (see Figure 8-5). It is not unusual to find a crack at or
near a pad or butt weld. A careful look is recommended.
Polished (low priority unless wall loss >10% wall loss) (see Figure 8-6). Polished tubes
show distinct activity. This does not mean that the tube is eroded below tolerance, however.
An ultrasonic testing meter can help an examiner assess this condition.
Figure 8-3
Tube indentation
Figure 8-4
Tube gouging
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8-3
Figure 8-5
Tube cracking at the toe of a weld
Figure 8-6
Polished tubes
8.5 Internal Appearance
The tube will appear to have an internal obstruction and/or thin wall. Figure 8-7 shows two
crushed tubes. The tube pictured on the left of Figure 8-7 has about 15% loss of area, and the
tube on the right has about 80% loss of area.
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8-4
Figure 8-7
Crushed tubes (Left: loss of area of approximately 15%; right: loss of area of
approximately 80%.)
8.6 Causes
Refuse and/or ash collected on the furnace walls and the pendant superheater (slagging)
ultimately falls free from weight or vibration, resulting in falling-slag erosion or impact damage.
Coal properties and boiler design are important factors in evaluating slagging problems. The root
cause of falling-slag erosion can be verified by evaluating the slagging potential of the fuel.
8.7 Prevention
Corrective actions depend on the severity of the erosion problem. If erosion is severe, the
reduction in boiler availability due to tube failures must be included in the costs of burning a fuel
of higher slagging. If a change in fuel is not justified, increasing the tube wall thickness or
installing wear bars can provide additional protection from failures. Frequent sootblowing can
reduce the size and severity of ash deposits.
8.8 Inspection Techniques
See Sections 12–19 for inspection guidance for the individual areas of a boiler.
8.9 Inspection Case Histories
Figure 8-8 presents three sample inspection reports in which erosion from falling slag is
indicated.
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8-5
Figure 8-8
Inspection reports with indications of tubes crushed by slag fall (first and second reports)
and sootblower erosion on a rear waterwall (third report)
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8-6
Figure 8-8 (continued)
Inspection reports with indications of tubes crushed by slag fall (first and second reports)
and sootblower erosion on a rear waterwall (third report)
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8-7
Figure 8-8 (continued)
Inspection reports with indications of tubes crushed by slag fall (first and second reports)
and sootblower erosion on a rear waterwall (third report)
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8-8
9
LIGAMENT CRACKING
9.1 General Description
The following three factors relative to boiler operation influence ligament damage in hightemperature headers:
•
•
•
Combustion
Steam flow
Boiler load
Most manufacturers design the boiler with burners arranged in the front and/or rear walls,
depending on the size and capacity of the unit. Heat distribution within the boiler is not uniform:
burner inputs can vary, air distribution is uneven, and slagging and fouling can occur. Even if
burners are optimized for equal firing, the temperatures of the combustion gases exiting the
furnace are lower near the sidewalls than at the middle of the boiler. This occurs because the
perimeter of the furnace is constructed of water-cooled tubes, and there is more heat transfer
from the combustion gases near the cooler wall tubes. Figure 9-1 shows a bore hole with cracks
radiating from the center outward.
Figure 9-1
A bore hole with radiating cracks
Air distribution can also vary from side to side and across the unit, causing unbalanced flow of
combustion gases exiting the furnace. On coal-fired and some oil-fired boilers, slagging and
fouling cause biasing of combustion gas flow and uneven heat absorption in the furnace and
convection passes. The net effect of these combustion parameters is to cause variations in heat
input to the superheater and reheater.
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9-1
Combined with the combustion parameters, the superheater and reheater experience differences
in the steam flow in individual tubes within the bank. A tube carrying greater steam flow will
experience a smaller steam temperature increase than a tube with reduced flow, assuming that
equal heat is absorbed by both tubes.
Spatial variations in gas temperature and tube-to-tube variations in steam flow can combine to
result in significant variations in tube outlet leg temperatures entering the headers. Because the
overall bulk header temperature is close to the controlled outlet steam temperature, large
temperature differences can occur at tube bore locations. A difference in the outlet leg and the
bulk steam temperature is not uncommon, even under normal baseload conditions. It should be
noted that on tangentially corner-fired boiler designs, the combustion gases flow in a cyclonic
path within the furnace. As a result, more heat absorption is expected to occur toward the outside
of the superheater, such that the temperature distribution will vary. As a consequence of the
through-wall temperature differences and the temperature differences between individual outlet
legs and the bulk header steam, the header experiences localized stresses much greater than the
stress associated with steam pressure. Further, during increasing and decreasing load changes,
the reversal of the through-wall temperature differences and the reversal of individual tube leg
steam temperatures relative to the header cause reversal of corresponding stresses at the bore
hole penetrations. These increased and reversing stresses lead to ligament cracks. Figure 9-2
shows a boat sample that was removed from a header that had ligament cracking reaching from
bore hole to bore hole.
Figure 9-2
A boat sample with ligament cracking spanning two bore holes
Boiler startups and shutdowns result in significant transient thermal stresses as a result of the
steam temperature changes in the thick-walled headers. Changes in boiler load further increase
the temperature difference between the individual tube legs and the bulk header. As boiler load
increases, the firing rate must increase to maintain pressure. During this transient, the boiler is
temporarily over-fired to compensate for the combined effect of increasing steam flow and
decreasing pressure. As a result, there is a temporary upset in steam temperature from individual
tube outlet legs relative to the bulk header temperature. During load decreases, the opposite
occurs—the firing rate decreases slightly faster than steam flow in the superheater.
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The cracks are oriented along the axis of the bore hole and propagate along the bore and across
ligaments between adjacent holes. If not detected in their early stages, these cracks will
eventually propagate through the tube stub-to-header welds, resulting in steam leaks. Bore hole
cracking combined with general creep of the header can lead to more catastrophic stub weld
failure.
9.2 Cycling’s Influence on Ligament Damage
Thick-walled superheater/reheater headers develop substantial thermal stress due to thermal
transients in the fluid passing through. Because it takes time for the heat to flow centrifugally
through the wall, an extensive radial temperature gradient develops across the header wall as the
inner surface follows the fluid temperature and the outer surface lags behind. A temperature
variance between the inside and outside of a thick header of as little as 50°F can cause a thermal
compressive stress on the inside surface.
An additional thermal stress can occur during a hot restart in which the boiler has been shut
down for a short time, but elements such as the superheater/reheater outlet header have not
cooled significantly and are therefore still near their normal 1000°F (538°C) operating
temperature. As the boiler is restarted, the initial flow of steam reaching the hot parts might be
much colder than 1000°F (538°C), resulting in a thermal shock and very high thermal tensile
stress on inner surfaces. These suddenly cooled inner surfaces would normally want to shrink to
a smaller radius but are constrained by the bulk of the surrounding hot header.
9.3 Location
Thermal stress occurs in tubes of thick-walled devices, such as steam drums and headers.
Figure 9-3 shows the locations in a boiler where high thermal stress is common.
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9-3
SCW = superheater center wall
Figure 9-3
Common locations of high thermal stress in the boiler
9.4 Internal Appearance
Ligament cracking appears as radial cracks from a hole (see Figure 9-4). Figures 9-5 and 9-6
show a longitudinal crack and branching longitudinal cracks, respectively, as viewed with a
borescope.
Figure 9-4
Ligament cracks
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9-4
Figure 9-5
A longitudinal crack
Figure 9-6
Branching longitudinal cracks
9.5 Cause
A rapid temperature rise or too-rapid drop in temperature in cooling during startup and shutdown
could lead to boiler damage. During cold startup of the boiler, the superheater headers are subject
to humping as a result of top-to-bottom temperature differences.
Operations have a great impact on the longevity or failure of pressure parts. This comes from
operational practices that contribute to reduced time to failure.
In the case of water lances or water cannons, the results will be quench cracking and thinning.
9.6 Repairs
Sectional replacement is the only suggested repair.
9.7 Inspection Techniques
See Sections 12–19 for inspection guidance for the individual areas of a boiler.
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9.8 Inspection Case History
Figure 9-7 is an example of an inspection report that indicates a ligament crack on a superheater
header.
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Figure 9-7
An inspection report indicating a ligament crack on a superheater header
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10
SHORT-TERM OVERHEATING
10.1 General Description
Steam-generating units are designed to balance the heat input from the combustion of fuel with
the formation and superheating of steam. Water is boiled and steam is generated at constant
temperature in a tube. A state of equilibrium is established in the furnace between heat
generation from combustion and steam generation at nearly constant temperature.
Within the furnace, flame temperatures can approach 3000°F (1649°C), which, through furnace
wall heat absorption, is reduced to 1700–2000° F (927–1093°C) in exiting flue gases. A
temperature gradient between the tube wall and the fluid within the tube provides the driving
force for heat transfer at any given point. The heat absorbed is converted into steam at its
saturation temperature, a function of the operating boiler pressure. A similar balance exists
within the superheater and reheater between the hot flue gas and steam superheating. When this
balance is maintained, the metal temperature of the tube is appropriate for the material; however,
when the balance is upset, tube metal temperatures can rise, and failures will occur.
10.2 Short-Term/Long-Term Overheating
At the simplest level, failure occurs when the stress, as a result of service conditions, exceeds the
strength of the metal at service temperature. When a sudden increase in temperature happens and
the hoop stress due to the internal pressure equals the strength of the steel, failure occurs; it is
said to be short-term overheat (see Figure 10-1 for an example). When the tube temperature
slowly rises, as with internal oxide buildup in a superheater tube over several years, the hoop
stress exceeds the creep strength, and failure occurs—this is called long-term overheat.
Figure 10-1
A short-term reheat failure
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Both abnormal coolant flow and excessive gas temperature can cause overheating in watercooled furnace tubes. Steam-touched tubes are more likely than water-touched tubes to
experience short-term overheating failure versus long-term overheating (creep) failure; however,
either mechanism can occur in the boiler, depending on specific operational variables. In
addition, material strength decreases as the temperature increases.
When the tube stress (usually, the hoop stress) exceeds elevated-temperature material properties
of the tube, a failure will occur. Typically, this requires one of two things. The first possibility is
that the tube metal temperature is higher than expected. The design stress has not changed, but
operating conditions have raised the metal temperature so that the operating stress relative to the
strength at operating temperature is excessive. The second possible effect is that hoop stress has
increased. The tube metal temperature is correct, but corrosion (from the ID outward, from the
OD inward, or both) or erosion has reduced the wall thickness so that the actual hoop stress is
too high.
Obviously, both effects can occur simultaneously. These overheating failures can be divided into
two principal types—(1) short-term, high-temperature failures or (2) long-term creep or stress
rupture failures. In short-term, high-temperature failures, the metal temperature at the instant of
rupture can be several hundred degrees hotter than design, and failure occurs in minutes. Shortterm overheating failure occurs as a result of one incident of high temperature in tube metal.
In long-term creep or stress rupture failures, the metal temperature at the instant of rupture is 50–
100°F above the design conditions or at the design condition in the creep range of the metal
involved. Failure usually occurs in several months to several years.
In furnace tubes, as water converts to steam, bubbles form along the tube surface at discrete
points. The moving fluid sweeps the bubble away, and the process starts over. The size of the
bubble is small—perhaps 0.04 in. (1.0 mm) in diameter. This process of conversion and bubble
formation is known as nucleate boiling. If the heat flux is excessive or fluid flow is inadequate, a
collection of bubbles can coalesce to form a steam blanket. This coalescence or blanketing is
known as departure from nucleate boiling (DNB). Heat transfer through a steam blanket is
minimal, and the blanketed tube metal area can experience rapid temperature increases.
Such metal temperature can occur in minutes or even seconds. DNB will not occur in a
superheater because only steam superheating occurs; however, overheating failures can occur in
both superheaters and reheaters during startups due to steam blockage. DNB is an important
consideration in the design of boilers because if the tube fails to receive an adequate supply of
incoming feedwater, the cooling tube can quickly exceed its burnout or failure point.
The temperature of the overheat event can be estimated from the microstructures in the steel. If it
was above A1, bainite might have formed when the austenite was cooled. If the temperature is
below A1 and in the range of 100°F (38°C), long-term overheating occurs.
Because different alloys can successfully operate at different temperatures, the failure
temperatures are specific to the alloy. Table 10-1 compares the tensile strength at elevated
temperatures of SA-192 with SA-213 TP321H.
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Table 10-1
Short-time elevated temperature tensile strength
Tensile Strength
Test Temperature
SA-192
SA-213 TP321H
80°F (27°C)
55,000 psi (379 MPa)
84,000 psi (MPa)
300°F (149°C)
59,000 psi (407 MPa)
68,000 psi (MPa)
500°F (260°C)
59,500 psi (410 MPa)
62,500 psi (MPa)
700°F (371°C)
52,600 psi (MPa)
60,000 psi (MPa)
900°F (482°C)
41,000 psi (MPa)
56,000 psi (MPa)
1100°F (593°C)
20,000 psi (MPa)
49,300 psi (MPa)
1300°F (704°C)
9,900 psi (MPa)
38,000 psi (MPa)
1500°F (816°C)
5,600 psi (MPa)
23,000 psi (MPa)
Overheating is not detectable by normal NDE methods because the failure event results from a
sudden temperature rise and the metal degradation is rapid. Laboratory metallurgical
examination of fracture surfaces and microstructure features can provide information pertinent to
the failure investigation.
10.3 Cycling’s Influence on Short-Term Overheat Damage
A very aggressive ramp rate will cause a reheat or superheat tube blocked with condensation to
fail from short-term overheat. If drum water levels drop too low during startup, tubes can
become starved for coolant and fail from short-term overheat.
10.4 Failure Location
Short-term overheat occurs in steam-cooled and water-cooled tubes in reheaters, superheaters,
and waterwalls in locations characterized by any of the following:
•
•
•
•
Plugged by debris, scale, or condensate from incomplete boil-out
Exposed to high heat transfer rates from improper alignment or firing of burners
Having low coolant flow due to poor circulation, an upstream tube leak, or a tube dented by
slag fall
Marked by another condition that impedes heat transfer, such as steam blanketing or oxide
scale
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10.5 External Appearance
Distinctive visual characteristics associated with short-term overheating damage in superheater
tubing include the following:
•
Overall swelling of the affected tube
•
A longitudinally oriented, thin-edged fracture surface with a fish-mouth appearance and a
final ductile failure
•
Generally increased hardness near the rupture
•
Microstructural changes dependent on the tube temperature at the time of rupture
Short-term overheating produces considerable tube deformation in the form of metal elongation
and reduction in wall area or cross-section. A fish-mouth-type rupture with thin-edged fracture
surfaces is typical for ferritic steel (see Figure 10-2).
Figure 10-2
A typical short-term overheat failure
Other appearances are possible, depending on the material and the extent of the overheated
portion of the tube. There might be a thick, brittle, dark scale (oxide) layer on external surfaces.
10.6 Internal Appearance
In addition, there might be a thick, brittle, dark scale (oxide) layer on internal surfaces.
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10-4
10.7 Causes
There are three causes of these rapid failures. The first is tube blockage. Exfoliated oxides
broken loose during thermal transients, such as rapid shutdowns, collect due to gravity at bends
to form blockages. Resulting failures typically occur away from the blockage, especially near
changes in tube wall thickness or material types. An alternative blockage in a superheater or a
reheater involves condensate collecting at low points in the steam circuit. A rapid startup will
lead to high metal temperature because no steam flows before the condensate have time to
evaporate.
The second cause of rapid failure is tube leaks. In a waterwall tube, an undetected tube leak low
in the furnace will starve that tube. Higher in the furnace, reduced fluid flow allows DNB to
occur at normal firing conditions.
The third cause is flame impingement. Very high heat fluxes will cause DNB and rapid, hightemperature failure. Misdirected or worn burners can lead to flame impingement. In addition,
foreign objects associated with boiler maintenance have been discovered inside tubes. Even
though tube-wall thinning characterizes all rapid overheating failures, rapid overheating is not
necessarily the cause of all ruptures that exhibit tube-wall thinning. Erosion and corrosion are
other mechanisms that can cause thinning and subsequent rupture. Overheating can occur in
tubes thinned by erosion or corrosion.
Figure 10-3 shows an overheat failure with obvious stretch marks etched in oxides adjacent to
the failed area.
Figure 10-3
Stretch marks adjacent to the failed area
A reduction of coolant flow, excessive combustion gas temperatures, or a condition that impedes
heat transfer can cause overheating. A reduction of coolant flow can be caused by a blockage in
the tube circuits or loss of boiler water drum level.
10.8 Prevention
Corrective actions involve measures to prevent blockages of tubes, control drum water levels,
ensure coolant circulation, and reduce excessive firing rates.
Redesign or relocation of inclined or horizontal tubing might be required to prevent film boiling,
which will contribute to the problem. Rifled tubing has long been used to promote turbulence,
increase the fluid-side heat transfer coefficient, and prevent DNB.
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10-5
10.9 Repairs
Replacement is the only suggested solution.
10.10 Inspection Techniques
Once this type of failure has occurred, it is too late for inspection.
10.11 Inspection Case Histories
The fourth case history displayed in Figure 10-4 illustrates the complexity of a tube failure. The
original root cause was a blockage that caused a short-term overheat failure.
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10-6
Figure 10-4
Inspection reports indicating various damage from short-term overheating: a bulged tube
(first report), a leak in a waterwall tube (second report), thin-edged rupture in a secondary
superheat outlet tube (third report), and tube blockage in a final superheater (fourth report)
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10-7
Figure 10-4 (continued)
Inspection reports indicating various damage from short-term overheating: a bulged tube
(first report), a leak in a waterwall tube (second report), thin-edged rupture in a secondary
superheat outlet tube (third report), and tube blockage in a final superheater (fourth report)
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10-8
Figure 10-4 (continued)
Inspection reports indicating various damage from short-term overheating: a bulged tube
(first report), a leak in a waterwall tube (second report), thin-edged rupture in a secondary
superheat outlet tube (third report), and tube blockage in a final superheater (fourth report)
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10-9
Figure 10-4 (continued)
Inspection reports indicating various damage from short-term overheating: a bulged tube
(first report), a leak in a waterwall tube (second report), thin-edged rupture in a secondary
superheat outlet tube (third report), and tube blockage in a final superheater (fourth report)
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11
LOW-TEMPERATURE CORROSION
11.1 General Description
Low-temperature corrosion produces tube-wall thinning that eventually results in ductile rupture
of the steel. A thin-edged fracture surface is produced when the load-carrying ability of the steel
is exceeded. The external surface will have a gouged/pitted appearance where the corrosion
activity has occurred.
The combustion of most fossil fuels produces flue gases that contain sulfur dioxide, sulfur
trioxide, and water vapor. At some temperature, these gases condense to form sulfurous and
sulfuric acids. Although the precise dew point for sulfuric acid depends on the sulfur trioxide
concentration, at 10 parts per million sulfur trioxide in the flue gas, the dew point is about 280°F
(138°C). (The dew point is the temperature at which air must be cooled at barometric pressure
for water vapor to condense into water.)
Any point along the flue gas path—from combustion in the furnace to the top of the chimney—is
a possible site. Any flue gas leak can also cause this type of corrosion.
Dew-point corrosion is exacerbated in coal-fired boilers by the presence of fly ash. Fly ash
accumulates throughout the flue gas path, and the resultant deposit acts like a sponge to collect
both moisture and acid, especially during shutdown cycles. In Figure 11-1, the corrosion was
found upstream from where dew-point corrosion would normally be found. This would indicate
very low-temperature operation or the chemical effects of coal ash corrosion.
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11-1
Figure 11-1
Dew-point corrosion found upstream of the typical location (Top: closeup of corrosion;
bottom: diagram of its location.)
Another corrosion problem associated with dew-point corrosion in oil-fired boilers is oil ash.
There is the potential for acid corrosion following water washing. Strictly speaking, this is not
dew-point corrosion; however, a solution of oil ash in water does result in an acid pH. Therefore,
unless these salts are neutralized, a strong acid forms in the wash water just before it evaporates
to dryness. To prevent fireside pitting corrosion during water washing, the final rinse should be a
basic solution. The most common and least expensive is washing soda (sodium carbonate)
dissolved in water. Such a solution will neutralize the acids in the oil ash and prevent pitting.
The concentration of contaminants (sulfur and chlorides) in the fuel and the operating
temperature of flue gas metal surfaces determine the likelihood and severity of corrosion.
Corrosion can be very subtle at the surface; however, wall loss over time is accumulative. For
example, in Figure 11-2, what appears to be out-of-round in the tube is not out-of-round.
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11-2
Figure 11-2
In this tube, what appears to be out-of-round is actually accumulative wall loss from
corrosion
11.2 Cycling’s Influence on Dew-Point Corrosion Damage
Continued low-load operation can produce dew-point corrosion, depending on the temperature
and sulfur content of the fuel.
11.3 Location
Low-temperature corrosion or dew-point corrosion can occur at locations in the economizer with
boiler tube metal temperatures below the acid dew point (so that condensate forms on the metal)
or with flue gas temperature below the acid dew point (so that condensate forms on the fly ash
particle). The obvious locations are openings to the furnace; support penetrations through the
roof; and leaks around the superheater, reheater, economizer penetrations, and, of course, the air
preheater.
All heaters and boilers that burn fuels containing sulfur have the potential for sulfuric-acid dewpoint corrosion in the economizer sections and stacks. The acid dew point is usually taken to
mean sulfuric acid.
Stainless steel feedwater heaters on HRSGs can be at risk for stress-corrosion cracking (SCC) if
the atmosphere of the combustion turbine includes chlorine. Drift from cooling towers that use
chlorine-based biocides can blow into the combustion turbine, potentially leading to damage in
the feedwater heaters. Oceanside HRSGs are other potential installations for similar damage
because of their locations. When the inlet water temperature is below the dew point of
hydrochloric acid—about 130°F (54°C)—hydrochloric acid–induced SCC can develop. Ferrite
steels do not suffer SCC from hydrochloric acid.
Figure 11-3 shows the locations in a boiler where low-temperature corrosion or dew-point
corrosion can occur.
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11-3
LTC = low-temperature corrosion
Figure 11-3
Common locations of low-temperature or dew-point corrosion in the boiler
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11-4
HRSGs that have austenitic stainless steel feedwater heaters can suffer chloride-induced SCC
from the gas side (OD) when the temperature of the inlet water is below the dew point of
hydrochloric acid.
11.4 External Appearance
Sulfuric-acid corrosion on economizers or other carbon steel components will have general
wastage, perhaps with broad, shallow pits, depending on the way the sulfuric acid condenses. For
the feedwater heaters in HRSGs and situations of SCC, the general appearance will be somewhat
crazed; the leaks will be crack-like fissures.
Figure 11-4 shows tubes with dew-point corrosion, the appearance of which can take many
forms. What is common is wall loss in the tube under attack. Figure 11-5 shows corrosion on an
economizer inlet header, and Figure 11-6 shows a failure from corrosion.
Figure 11-4
One of the many appearances of dew-point corrosion
Figure 11-5
Economizer inlet header corrosion
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11-5
Figure 11-6
A tube that has failed because of corrosion
11.5 Causes
Low-temperature corrosion is caused by the formation and condensation of sulfuric acid from the
flue gases. The amount of sulfur trioxide formed in the combustion process is an important factor
because an increase in the S0₃ concentration results in an increase in the acid dew-point
temperature. Low-temperature corrosion is a more significant problem in oil-fired boilers than in
coal-fired boilers due to the vanadium in the oil ash deposits and the smaller quantity of ash
constituents.
The root causes of low-temperature corrosion can be verified by determining the acid dew-point
temperature, defined as the temperature at which the combustion gases are saturated with sulfuric
acid. The acid dew point varies directly with the amount of S0₃ in the flue gas. The metal and
gas temperatures in the economizer can be measured to ascertain that they are above the acid
dew point obtained during the various phases of boiler operation.
Sulfur and chlorine species in fuel will form sulfur trioxide and hydrogen chloride within the
combustion products. At sufficiently low temperatures, sulfuric acid and the water vapor in the
flue gas will condense as sulfuric acid and hydrochloric acid and promote rapid corrosion by
these acidic species. At lower temperatures, hydrochloric acid can condense and promote
corrosion of carbon steels and SCC of stainless steels.
11.6 Prevention/Correction
Maintain the metallic surfaces at the back end of the boilers and fired heaters above the
temperature of sulfuric-acid dew-point corrosion. For HRSGs, avoid using austenitic stainless
steels in the feedwater heaters if the environment is likely to contain chlorine.
Similar damage occurs in oil-fired boilers when the units are water-washed to remove ash and
the final rinse does not neutralize the acid salts. Sodium carbonate or washing soda should be
added to the final rinse as a basic solution to neutralize the acidic ash constituents.
In the case of dew-point corrosion or cold corrosion, raising the temperature of the flue gases
will stop the process cold. If this is not possible, an aggressive material upgrade will be required
to re-establish reliability (see Figure 11-7).
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11-6
Figure 11-7
Raising the temperature of the flue gases will halt dew-point corrosion or cold corrosion
It is important to eliminate the source of corrosion. Once secure, repairs can be planned.
11.7 Repairs
Replacements are the preferred repairs. However, other repairs might be selected based on the
plant’s accepted risk profile.
11.8 Inspection Techniques
Ultrasonic measurement of wall thickness will monitor the wastage in economizer tubes. SCC of
stainless steels can be found using borescopic and liquid penetrant inspection.
11.9 Inspection Case Histories
Figure 11-8 presents three case histories indicating damage from low-temperature corrosion.
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11-7
Figure 11-8
Inspection reports indicating damage from low-temperature corrosion: fireside corrosion
on a waterwall (first report) and acid dew-point corrosion in economizer tubes (second and
third reports)
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11-8
Figure 11-8 (continued)
Inspection reports indicating damage from low-temperature corrosion: fireside corrosion
on a waterwall (first report) and acid dew-point corrosion in economizer tubes (second and
third reports)
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11-9
Figure 11-8 (continued)
Inspection reports indicating damage from low-temperature corrosion: fireside corrosion
on a waterwall (first report) and acid dew-point corrosion in economizer tubes (second and
third reports)
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11-10
Figure 11-8 (continued)
Inspection reports indicating damage from low-temperature corrosion: fireside corrosion
on a waterwall (first report) and acid dew-point corrosion in economizer tubes (second and
third reports)
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12
INSPECTION OF THE ECONOMIZER
12.1 Cycling Effects on the Economizer
Low-cycle fatigue is the impingement of cold water on hot surfaces at quick shutdown and
restart. Cycling involves increases and decreases in temperatures, which produce major thermal
stress on pressure boundaries. Cycling operation has a major impact on water-touched boiler
tubes, mostly because of the cyclic stresses and strains and the many stress concentration
locations in the component.
Figure 12-1 shows an economizer arrangement.
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Figure 12-1
An economizer arrangement
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12-2
12.2 Inspection Guidelines for the Economizer
An inspection of the economizer before debris removal should consist of the following:
•
•
•
•
•
While inspecting the boiler for slag buildup (lane pluggage), it is important to record the
percent of free area and the depth to which the buildup extends within the bundle.
Record general areas of possible tube erosion for a more detailed inspection after debris has
been removed. When plugging is observed (Figure 12-2 shows an example), higher gas
velocities will be experienced in the open areas.
These open areas will be the most likely location for fly ash erosion. Mark them specifically
for further scrutiny once the cleanup is complete.
For bundles, identify gas lanes with spacing greater than 6 in. (152.4 mm). As illustrated by
Figure 12-3, excessive lane spacing results in gases taking the path of least resistance. Sketch
fly ash and bridging. Estimate percent free, area lost, and areas of bridging between tubes
within the bundle.
For flow baffles, indicate plugging that results in the flow area of mesh being reduced >50%
and worn or eroded screen locations >4 in.2 (2580.6 mm2). Sketch the configuration,
including dimensions and the angles of baffles. Inspecting the flow patterns before the baffle
is removed allows the determination of appropriate baffle repairs and the result of sootblower
and fly erosion. Figure 12-4 is a rare view of the cross-section of an economizer with the
convection pass wall removed, and Figure 12-5 shows an eroded circular flow baffle that is
sacrificial; it must be replaced when eroded through.
Figure 12-2
Ash has blocked various gas lanes, restricting flow
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Figure 12-3
Excessive lane spacing results in gases taking the path of least resistance
Figure 12-4
An economizer with the convection pass wall removed
Figure 12-5
An eroded circular flow baffle
Figure 12-6 shows the locations in a boiler where ash corrosion is common.
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Figure 12-6
Common areas of ash erosion in a boiler
An inspection of the economizer after debris removal should consist of the following:
•
•
•
•
•
•
•
•
•
Intense inspection of the first 10 elements from the sidewalls and the sidewalls themselves
The front and rear bends the entire depth (labeled A in Figure 12-7)
Spacer bars and hangers (labeled B in Figure 12-7)
Alignment lugs (labeled B in Figure 12-7)
Around any baffles (labeled C in Figure 12-7)
All economizer bends (labeled A in Figure 12-7)
Headers (labeled D in Figure 12-7)
In front of baffles (labeled C in Figure 12-7)
Along tube fins (all)
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Figure 12-7
Economizer inspection sites after debris removal
Look for the following in overheated economizer tubes:
•
•
•
•
•
•
•
•
Excessive sagging of tubes.
A blackened appearance (see Figure 12-8). (It is not necessarily a symptom of overheat;
however, all overheated tubes are typically black in appearance.)
Elephant hide.
Bulging.
Burnt shields.
Tube, element.
The cause of overheat.
Tube outside diameter.
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12-6
Figure 12-8
Blackened appearance
Figure 12-9 shows a tube on which the protective tube shield has been eroded through. This is a
very significant problem because the erosion will be accelerated by the eroded shield, causing
more erosion than if the tube had been unshielded.
Figure 12-9
An eroded-through protective tube shield
To inspect for fly ash erosion of tubes or fins, examine the tube and the element length of the
eroded area. When examining tubes by ultrasonic thickness and wall wastage exceeding 20% is
found, it is important to address the cause to prevent further loss.
To inspect for misalignment, look for the following, recording the bundle, tube, and element:
•
•
•
Misalignment into gas lanes >1 1/4 diameter (see Figure 12-10)
Erosion
Rubbing
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Figure 12-10
Misalignment can cause accelerated erosion and high-pressure drop over the area
Misalignment can cause accelerated erosion and a high-pressure drop over the area, forcing the
gases into lower-pressure regions (see Figure 12-10). A previous repair, hardware failures, or
differential expansion can cause misalignment. Correct the misalignment by installing new or by
using existing alignment hardware. Cane spacers work effectively in this application.
Figure 12-11 shows a pad weld at risk for developing a leak. Inspect existing pad welds for
cracking, erosion, or improper metal. Pad welds should be up and down stringers, not horizontal,
for lowest stress. Proper metal can be checked with a magnet—the higher grades of stainless are
nonmagnetic. Extremely heavy or misapplied pad welding should be cut out and replaced with a
new section of tubing. If the pad weld is done correctly and the problem is not severe, it can be
ground and rewelded.
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Figure 12-11
Pad welds made in this manner are at risk of developing leaks
For economizer tube shields, inspect for the following:
•
•
•
•
•
•
•
Shields eroded through.
Burnt.
Missing shield (see Figure 12-12). It is important to measure the tube for wall thickness
(using ultrasonic methods). The tube should then be repaired according to the plant’s criteria
and reinstalled.
Looseness and redirection of flow.
Tube wall loss >20%.
Displaced shields.
Holes.
Figure 12-12
A tube shield that has been eroded through
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In gas lanes, measure distances from center to center. Inspect for the following, recording any
issues by bundle, tube, and element:
•
•
•
•
Debris
Shields lodged
Blockage that is redirecting gas flow (see Figure 12-13)
Erosion caused by misdirected gas flow
Figure 12-13
A dislodged harmonic baffle is blocking the gas lanes
In economizer tube bends, inspect for polishing and erosion (rear bends). Record the tube,
element, and tube wall loss greater than 20%.
In convection pass sidewalls and ring headers, inspect for missing refractory. Figure 12-14
shows a rare view of the economizer tube loops with the rear convection pass wall removed.
Figure 12-14
Economizer tube loops with the rear convection pass wall removed
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12-10
When inspecting for fly ash erosion or retract in the economizer, record the tube that erosion is
adjacent to, the element, the wall tube number, the blower number, and the length of the eroded
area. Spot-examine the wall thickness with ultrasonic methods for wall loss in excess of 20%.
Figure 12-15 shows erosion in a header.
Figure 12-15
Common header erosion
It can be difficult to gain access for a proper economizer inspection. At a certain age, the tubes
and elements must be inspected from top to bottom, possibly requiring serious activities that will
impact a plant’s timeframes and budgets. The thicknesses of ringed fins are the most difficult
features to assess because of the lack of clearance between fins (see Figure 12-16).
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12-11
Figure 12-16
Ringed fins are difficult to assess
For the gas baffles in the economizer, inspect the following:
Holes in mesh >4 in.2 (2580.6 mm2).
Missing angles.
Baffle dimensions (including height, width, and angle).
Any missing or cracked refractory, steel plate, and angles.
Tubing under and in front of the baffle for erosion.
Vertical baffles should be tightly installed; inspect the attachments. If erosion exists, inspect
adjacent tubes for gouging and erosion.
• Hangers tubes. Record bowing, rubbing, cracked welds, missing pins, erosion, and the hanger
and element numbers.
In all cases, if a baffle requires repair, record the height, width, angle, and material. Figure 12-17
depicts the likely areas for fly ash erosion in the baffle system. A small area of the baffle can
cause a large problem with fly ash and retract erosion (see Figure 12-18).
•
•
•
•
•
•
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12-12
Figure 12-17
The likely areas for fly ash erosion in the baffle system
Figure 12-18
A small area of the baffle can cause a large problem with fly ash and retract erosion
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12-13
For the economizer inlet and intermediate outlet headers, inspect for the following, recording the
tube and element numbers for any indications:
•
•
•
Fly ash erosion (spot-examine thickness with ultrasonic methods)
Low-temperature corrosion
Nipple cracking/erosion (see Figures 12-19 and 12-20)
Figure 12-19
Header erosion at a nipple
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Figure 12-20
Corrosion on a header nipple
For the left and right convection wall peg fins, inspect the peg fins, especially at corners, for the
following:
•
•
•
•
Missing fins (see Figure 12-21)
Cracked fins
Broken fins
Adjacent tube, elevation
Figure 12-21
Missing convection pass peg fin (This will cause a breakdown in refractory on the cold
side.)
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12-15
For the front and rear wall-to-element support brackets, inspect for the following:
•
Broken
•
Cracked
•
Missing support lugs
•
Clips
•
Straps
It is very important that each support lug be in place and doing its job—these lugs provide
element support and alignment. When a support lug is disengaged (see Figure 12-22), it transfers
the load to the remaining lugs, overloading the engaged lugs over time. The elements that are not
engaged have additional stress on them due to the lack of support. In Figure 12-23, a support lug
has become disengaged from the convection pass wall.
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Figure 12-22
A disengaged support lug
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12-17
Figure 12-23
A support lug disengaged from the convection pass wall
Figure 12-24 shows a support failure that is allowing the element to sag. This sagging combined
with the tube droop will probably produce a tube leak. If you are aware that this is occuring,
short-stroke the retract so that it just misses the tube.
Figure 12-24
The sagging element could droop to a point where the retractable sootblower might
engage it
Additional support systems include stainless steel hangers, as seen in Figure 12-25. They also
include various other types, depending on the individual manufacturer.
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Figure 12-25
A broken stainless steel support system in failure
Figure 12-26 shows the locations in an economizer where sootblower erosion is common.
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Figure 12-26
Common locations of sootblower erosion in the economizer
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In Figure 12-27, erosion can be seen on the extended fins of the economizer. If the fin is eroded,
it is likely that the underlying tube is also eroded. To address erosion in economizer tubes,
perform the following:
•
•
•
•
•
•
Record the retract number when identifying the erosion. Sootblowing in combination with
ash will erode the tubes around a sootblower. Condensate should be removed from the
sootblower system regularly. The blowing pressures should be at a minimum to achieve
effective results, and the blowing frequency might need to be adjusted.
The eroded sections will require shielding, pad welding, or replacement, according to
remaining wall. Install shielding once a tube section is replaced to prevent future erosion.
Polishing.
Record wall loss if it is greater than 20%.
Record the tube and element length of the eroded area.
Spot-examine the wall thickness with ultrasonic methods for wall loss greater than 20%. In
Figure 12-28, for example, it is important that the tube be measured for wall thickness. The
tube should then be repaired according to the plant’s criteria, and the tube shield should be
reinstalled. In Figure 12-29, a shield has been eroded through. This shield must be removed
and the tube thickness examined.
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12-21
Figure 12-27
Erosion on the extended fins of an economizer
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12-22
Figure 12-28
The wall thickness of the tube must be measured ultrasonically
Figure 12-29
A shield eroded through
The basic degradation mechanism associated with sootblower erosion is the removal of the
protective oxide film from a boiler tube. Clean metal exposures in the high-temperature furnace
gas atmosphere are re-oxidized, consuming a little tube metal through each oxidation cycle.
After alternating oxidation and scale removal cycles, failure occurs when the tube’s metal
thickness is reduced to the point where it can no longer contain the internal steam pressure within
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12-23
the boiler tube. Typical steam escaping from the rupture will wash neighboring tubes, causing
them to fail. Tubes subject to sootblower erosion will have little to no ash on the tube surface.
Figure 12-30 shows the areas in an economizer most likely to sustain retractable sootblower
erosion.
Figure 12-30
Likely areas of retractable sootblower erosion
Tensile overload failures due to severe external wall thinning should be expected soon for the
tube indicated in Figure 12-31. The wall thinning observed is a result of high-velocity ash
erosion from a combination of the fly ash redirected due to the economizer support rod and
center tube sheet. As obstructions (such as the support rod) block the flow of the fly ash, the
velocity of the gas passing through the open lane increases. High velocities create low-pressure
regions on the trailing side of the tube, resulting in concentrated fly ash erosion. The pitting
observed is a direct impact of the eroding media—in this case, high-velocity fly ash. Poor tube
alignment is a contributor to ash erosion down in the bank (see Figure 12-31). At any junction,
ash erosion is likely. The ash stream is redirected and will actually be magnified in severity (see
Figure 12-32).
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12-24
Figure 12-31
Poor tube alignment is a contributor to ash erosion down in the bank
Figure 12-32
Ash erosion is likely at any junction
In the economizer’s rear bends, inspect for the following:
•
•
•
Polishing
Fly ash erosion (spot-examine thickness ultrasonically)
Low-temperature corrosion
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12-25
Record any wall loss greater than 20%, and record the tube number, element, blower number,
and length of the eroded area.
Figure 12-33 provides a rare view of the return bends of the economizer when the backwall is
removed.
Figure 12-33
The return bends of the ecomomizer
At every junction in the economizer, there is a likelihood of abrasion or rubbing (see
Figure 12-34).
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12-26
Figure 12-34
The likelihood of abrasion exists at every economizer junction
For existing shielding, inspect for the following (all shielding meeting any of these criteria
should be removed and replaced):
•
•
•
•
•
•
•
•
Erosion (holes).
Bent shielding.
Loose shielding.
Missing shields (if missing, examine by ultrasonic method).
Overheated shield conditions. See Figure 12-35 for an example of protective shielding that
has overheated and warped, which can cause more damage than if the tubes had been
unshielded.
Erosion and attachments for toboggan shields.
Incorrect installation: shielding should allow for tube expansion.
Broken strap conditions.
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12-27
Figure 12-35
Protective shielding that has overheated and warped
In Figure 12-36, the return-bend shields are concentrating the erosion on the tube. Shielding and
baffle techniques can successfully control erosion (see Figure 12-37). However, be aware that
too much baffling can actually increase erosion.
Figure 12-36
Return-bend shields that concentrate erosion on the tube
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12-28
Figure 12-37
Shielding and baffle techniques can control erosion
Figure 12-38 is a cutaway view of an inlet header and stub tube. Boiler startups and shutdowns
result in significant transient thermal stresses as a result of the steam temperature changes in the
thick-walled headers. Changes in boiler load have the effect of further increasing the temperature
difference between the individual tube legs and the bulk header temperature.
Figure 12-38
Inlet header and stub tube
As the boiler load increases, the firing rate must increase to maintain pressure. During this
transient, the boiler is temporarily over-fired to compensate for the combined effect of increasing
steam flow and decreasing pressure. As a result, there is a temporary upset in steam temperature
from individual tube outlet legs relative to the bulk header temperature. During load decreases,
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12-29
the opposite occurs; the firing rate decreases slightly faster than steam flow in the superheater,
with a resulting decrease in tube outlet temperatures relative to the header bulk temperature. As a
consequence of the through-wall temperature differences and the temperature differences
between individual outlet legs and the bulk header steam temperature, the header experiences
localized stresses much greater than the stress associated with steam pressure. Further, during
increasing and decreasing load changes, the reversal of the through-wall temperature differences
and the reversal of individual tube leg steam temperatures relative to the header cause reversal of
corresponding stresses at the bore hole penetrations. These increased and reversing stresses of
boiler startups and shutdowns result in significant transient thermal stresses from the steam
temperature changes in the thick-walled headers.
Figures 12-39 through 12-44 show ligament and circumferential cracks at headers and radial
cracks. Cracks are oriented along the axis of the bore hole and propagate along the bore and
across ligaments between adjacent holes. If not detected in their early stages, these cracks will
eventually propagate through the tube stub-to-header welds, resulting in steam leaks. Bore hole
cracking combined with general creep of the header can lead to more catastrophic stub weld
failure. Header ligament cracking is a result of injection of cold feedwater during boiler startup;
ligament cracking is a result of boiler top-up with cold feedwater during shutdown. Stub-toheader cracking is a result of temperature differentials between economizer tubes during low
flow and boiler shutdown.
Figure 12-39
Ligament cracks
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Figure 12-40
Circumferential crack on tube to stub at header
Figure 12-41
Borescope inspection reveals ligament cracks oriented in a radial location
Figure 12-42
A crack in a header tee
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Figure 12-43
Three radial cracks
Figure 12-44
Circumferential cracking
The major cause of header end-of-life in the United States is creep fatigue. This results in
ligament and bore hole cracking. Two or three of the hottest or highest-stressed areas should be
inspected. It is important that the base metal of the header be examined for cracking. Inspect for
the following:
•
Fatigue cracking as a result of water hammer during startup on steaming economizers
•
Quench cracking of inlet tees as a result of injection of cold feedwater on startup (see Figure
12-45)
•
Thermally induced bending as a result of stratification of water flow during low-load
operation or off-load boiler top-up (top-to-bottom temperature differential)
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Figure 12-45
Quench cracking of tube bore holes as a result of cold feedwater injected on startup
Perform wet fluorescent magnetic particle inspection (WFMT) of all major header welds,
including at the following:
•
•
•
•
•
Outlet nozzle.
Torque plates.
Support lugs and plates.
Circumferential girth.
Stub-to-header area. Initially, 100% of the tube stub-to-header welds should be inspected by
WFMT. After the baseline inspection, WFMT inspections can be limited to 10–25% of the
tube stub-to-header welds. Figure 12-46 show tube-to-header welds.
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12-33
Figure 12-46
Tube-to-header welds
Perform ultrasonic angle beam/shear wave examination of major welds. This is particularly
important if the header has any long seam welds.
To examine the header for creep damage, metallographic replication should be performed.
Typically, six to twelve replicas are taken on the header tube stubs, header circumferential or
longitudinal pipe welds, and nozzle-to-header welds. Typically, replicas are for the areas of
highest temperature or stress.
Inspect headers for droop; check support brackets for cracking and deformation. Look for
internal or external erosion/corrosion of outlet stubs.
12.3 Inspection Case Histories of Economizers
Figure 12-47 presents four examples of inspection reports indicating cycling-related problems in
boiler economizers.
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12-34
Figure 12-47
Inspection reports indicating cycling-related problems in the economizer: fly ash erosion
(first and third reports), sootblower erosion (second report), and thermal fatigue cracking
(fourth report)
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12-35
Figure 12-47 (continued)
Inspection reports indicating cycling-related problems in the economizer: fly ash erosion
(first and third reports), sootblower erosion (second report), and thermal fatigue cracking
(fourth report)
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12-36
Figure 12-47 (continued)
Inspection reports indicating cycling-related problems in the economizer: fly ash erosion
(first and third reports), sootblower erosion (second report), and thermal fatigue cracking
(fourth report)
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12-37
Figure 12-47 (continued)
Inspection reports indicating cycling-related problems in the economizer: fly ash erosion
(first and third reports), sootblower erosion (second report), and thermal fatigue cracking
(fourth report)
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13
INSPECTION OF THE WATERWALL SLOPE/HOPPER/
COUTANT
13.1 Cycling Effects on Waterwalls (All Areas)
Many boilers have suffered tube cracking in the lower furnace area after a period of on-off
cycling operation. Generally, tube leaks have occurred after about 400 cycles. The longitudinal
cracks form on the casing-side internal tube surface and propagate through the wall, resulting in
leaks (see Figure 13-1). The failure mechanism is corrosion fatigue, and the cause of the problem
is a combination of thermal cycling and water chemistry at highly stressed areas. When the boiler
is shut down and bottled up for the off-line period, the entire furnace is at or near saturation
temperature. Figure 13-2 shows the lower-slope tube arrangement.
Figure 13-1
Note the ID crack opposite the rupture
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Figure 13-2
Lower-slope tube arrangement
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13-2
During the idle period, the boiler water cools off, with subcooled water collecting in the lower
section of the furnace tubes. There is then a temperature gradient from the lower to the upper
furnace. When flow in the furnace is initiated after the shutdown period, the hot water displaces
the cold water, resulting in a thermal cycle. The greater the temperature difference, the greater
the shock.
13.2 Inspection Guidelines for the Waterwall Slope/Hopper/Coutant
Inspect lower waterwalls for excessive slag buildup and unusual slag patterns (for example, in
color or texture) before deslagging or cleaning the furnace. Record the thickness, length, and
width of the buildup and the elevation.
Inspect the beginning and ending elevations of bowed or misaligned tubes or panels. Report the
tubes involved, and note the severity and length of displacement. Dented or suppressed tubes are
a much different issue than crushed tubes (see Figure 13-3).
Figure 13-3
A dented/suppressed tube
If large slag falls are a problem, check the structural members and lugs below in the lower dead
air space.
The furnace slope wall must be analyzed to ensure its reliability under other mechanical loads, if
applicable, such as positive and negative furnace pressures, deadweight loads, wind loads,
earthquake loads, and reactive loads that exist between the furnace wall and the rigid buckstay
system.
The hopper bottom or coutant can be deflected, causing gas leaks into the lower dead air spaces
(see Figure 13-4).
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13-3
Figure 13-4
A deflected hopper bottom/coutant
Look for the following symptoms of overheating in waterwall tubes:
•
•
•
•
•
Blackened or red color
Elephant hide–type cracking
Liquid-phase corrosion
Bulging (an example is shown in Figure 13-5)
Bowing (record tube bow >one diameter) and rubbing (tube to tube)
Figure 13-5
Bulged tubes are clear evidence of an overheated tube
For membranes, verify proper membrane terminations. All membrane terminations must end in a
3/8-in.-minimum (9.6-mm-minimum) radius to allow the stresses to radiate from the center,
thereby reducing stress at any individual location. Also, inspect for crack propagation
(transverse, longitudinal, at tube), length, tube (between, on), and elevation. Figure 13-6 shows a
membrane crack that can be arrested using the keyhole method.
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13-4
Figure 13-6
Membrane crack that can be arrested using the keyhole method
Around sootblowers, inspect for the following:
•
•
•
•
•
Erosion (spot-examine thicknesses ultrasonically)
Areas worn flat
Pitting
Membrane (cracks, width >3/4 in. [19.1 mm])
Circumferential tube cracking (severity), tube, length, location, retract or sootblower, wall
loss >20%
Figure 13-7 shows a sootblower wall opening.
Figure 13-7
Sootblower wall opening
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13-5
To inspect for fireside corrosion, check for tubes that are worn flat, are pitted, or have an
alligator-hide surface. Figure 13-8 shows the typical appearance on tubes. Spot-examine
thicknesses with ultrasonic methods. When tube wall loss exceeds 20%, note the tube, elevation,
and panel (type and material).
Figure 13-8
The typical effect of fireside corrosion on tubes
Figure 13-9 shows several tubes that have been pad-welded. Inspect previous pad welds for the
following:
•
•
•
•
•
Cracks
Heavy horizontal weave (weld technique)
Undercut or excessive reinforcement
Steam cuts
Tube, elevation, and length
Figure 13-9
Tubes that have been pad-welded
Inspect waterwall tubes for circumferential cracking, recording the tube number, elevation, and
severity of any cracking. Circumferential tube cracking (an example appears in Figure 13-10) is
usually a sign of other problems.
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13-6
Figure 13-10
Circumferential tube cracking
Figure 13-11 shows a crack in a seal skirt attachment (a DMW), and Figure 13-12 is a slagcovered tube.
Figure 13-11
A crack in a seal skirt attachment
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Figure 13-12
Slag-covered tube
For shotgun dents or gouges in waterwall tubes, inspect the depth and wall thickness, and record
the elevation and tube numbers. A shotgun dent in a vertical (see Figure 13-13) is a result of a
missed shot somewhere else. This, however, does not make the dent without problems.
Figure 13-13
A shotgun dent in a vertical
Inspect butt welds for cracks, undercut exceeding >1/32 in. (0.03 mm); note tube and elevation.
Perform a close arch elevation inspection. The butt welds pictured in Figure 13-14 are of such
poor quality that an intense inspection should be conducted.
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13-8
Figure 13-14
Poor butt welds requiring intense inspection
Around observation ports, inspect for the following:
•
•
•
Tubes worn flat
Tubes pitted
Erosion (spot-examine thickness ultrasonically)
Inspect slope-to-sidewall membrane seals for the following:
• Membrane anomalies: cracking, excessive (>0.75 in. [19.1 mm]) width, and termination
• Gaps or separations
• Gouges
• Erosion
The lower slope-to-sidewall seal must be intact. If failed, moisture will leak into the dead air
space, mix with the ash, and corrode the slope tubes. Figure 13-15 shows thinning in sidewall
tubes adjacent to slope tubes.
Figure 13-15
Thinning in sidewall tubes adjacent to slope tubes
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Inspect tubes for dents and gouges. If gouges are found, record the depth, width, and length of
each as well as the distance from the top bend or throat. For dents discovered, record any that
might be restricting flow. Include location information—the wall, tube, thickness, and elevation.
Figure 13-16 shows a slope tube that has been impacted by more than 10%.
Figure 13-16
Slope tube impacted more than 10%
13.3 Inspection Case Histories for the Waterwall Slope/Hopper/Coutant
Figure 13-17 presents three example inspection reports indicating cycling-related damage in the
waterwall slope/hopper/coutant.
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Figure 13-17
Inspection reports indicating a crushed front waterwall tube (first report), a coutant tube
crushed by slag fall (second report), and sootblower erosion (third report)
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13-11
Figure 13-17 (continued)
Inspection reports indicating a crushed front waterwall tube (first report), a coutant tube
crushed by slag fall (second report), and sootblower erosion (third report)
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Figure 13-17 (continued)
Inspection reports indicating a crushed front waterwall tube (first report), a coutant tube
crushed by slag fall (second report), and sootblower erosion (third report)
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14
INSPECTION OF FURNACE WATERWALLS
14.1 Cycling Effects on Waterwalls (All Areas)
Figure 14-1 shows the location of the waterwall tubes. An increase in slagging here is usually an
effect of cycling operation. With more slag, there is additional sootblower operation to clean the
increase in slag. With the increase in sootblower operation, there are additional slope impacts.
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14-1
Figure 14-1
The location of the waterwall tubes
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14-2
With the up-and-down nature of cycling, there is an increase in the thermal expansion and
contraction of the materials of the boiler. This increases stress and opens the door for corrosion
fatigue. Thermal fatigue could easily result if water is used for deslagging.
Last, with variations in combustion and temperatures, fuel ash corrosion must be considered as a
possibility. This would be especially true in an older (>20 years) boiler.
14.2 Inspection Guidelines for Waterwalls
Inspect waterwalls for excessive slag buildup (see Figure 14-2, where slag is spalling) and
unusual slag patterns (in color, texture, and so on) before deslagging or cleaning the furnace.
Record the thickness, length, width of the buildup, and elevation.
Figure 14-2
Slag spalling off tubes during an outage
For bowing, record the beginning and ending elevations of bowed or misaligned tubes or panels,
the tubes involved, and the severity of displacement. Figure 14-3 shows a severely bowed
waterwall panel.
Figure 14-3
A severely bowed waterwall panel
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The cause of large bowed panels in a furnace wall can be short-term overheat or structural steel
failure resulting from improper restraint or furnace pressure excursion. If membranes are intact
and the bowed area is not causing problems, the area should be corrected by restoring the
structural integrity or compensating for the differential expansion or other problems. Bowed
areas are more susceptible to increased sootblower erosion.
Inspect waterwall tubes for the following signs of overheating:
•
•
•
•
•
•
Blackened or red color (Figure 14-4 shows an example)
Elephant hide–type cracking
Liquid-phase corrosion
Bulging (see Figures 14-5 and 14-6)
Bowing: record tube bows of more than one diameter
Rubbing (tube to tube)
Figure 14-4
A clear sign of overheating: a blackened, circumferentially cracked appearance
Figure 14-5
An obvious bulge
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14-4
Figure 14-6
Multiple bulges reveal multiple events of DNB
A tube can become overheated through the following properties and mechanisms:
•
•
•
•
•
•
•
Wrong materials used in the tube’s fabrication.
Operating problems (over-firing or uneven firing).
Flame impingement.
High-intensity light. In Figure 14-7, for example, the high-intensity light shown can produce
enough energy to overheat an adjacent waterwall tube.
Waterside plugging, fouling, or deposits.
Loss of boiler coolant or low water level.
Stress due to welded attachments or wall thinning.
Figure 14-7
High-intensity light capable of overheating an adjacent waterwall tube
If overheating takes place, tube replacement is necessary. To correct the problem, the cause must
be addressed.
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For membranes, inspect the following:
•
Membrane welds. Proper membrane terminations have a minimum radius of 3/8 in.
(9.5 mm).
•
Crack propagation (transverse, longitudinal, at tube), length, tube (between and on), and
elevation.
•
Incomplete membrane welds.
A membrane that exceeds the cooling limitation to tubes will burn back to where the cooling
effect of the tube protects it (see Figure 14-8).
Figure 14-8
A membrane that exceeds the cooling limitation to tubes
Membrane cracking can occur at the following locations:
•
•
•
•
•
•
•
Access doors
Sootblowers
Observation ports
Wall openings
Tube to tube
Burners
Sidewalls in the lower dead air space
Slotted membranes must be properly terminated with a keyhole at the end of the slot. Cracking
can also occur in fin and stud plates as well as membranes if welded to a furnace wall tube.
Figure 14-9 shows a classic example of a propagating membrane-to-tube crack.
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Figure 14-9
A crack propagating from membrane to tube
If cracking is found, it must be ground out and penetrant-tested to ensure that the crack has not
gone to the tube. Remove any cracked material from the tubing, and install new material.
Around sootblowers, inspect for the following:
•
Erosion (spot-examine thickness with ultrasonic methods) (see Figure 14-10) and areas worn
flat. Figure 14-11 shows extensive sootblower erosion. It appears that the tube was
previously repaired by pad welding, indicating that the blower was never readjusted to solve
the original problem. Figure 14-12 shows what can go wrong around a sootblower opening.
•
Pitting.
•
Membrane (cracks, width >3/4 in. [19.1 mm]).
•
Circumferential tube cracking (note severity, tube, length, and location).
•
Retract or sootblower wall loss >20%.
Figure 14-10
Severe erosion
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14-7
Figure 14-11
Extensive sootblower erosion in a pad-welded tube
Figure 14-12
A good example of what can go wrong around a sootblower opening
Sootblower erosion can be caused by the following:
•
•
•
•
•
Incorrect rotation or alignment
Water condensing in steam
Damaged nozzles
Incorrect blowing pressure
Incorrect draining of the blower system prior to blowing
Sootblower pre-blow erodes behind the tube rather than in front (see Figure 14-13). Be careful to
check all sootblower tubes behind the offsets.
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14-8
Figure 14-13
Pre-blow erodes behind the tube
Around burners, inspect for the following:
•
•
•
•
Erosion (spot-examine thickness with ultrasonic methods) and flats. In Figure 14-14, coal
particles have eroded tubes adjacent to burners.
Pitting.
Membrane (cracks, width >3/4 in. [19.1 mm]).
Circumferential tube cracking (record severity, tube, length, and location).
Figure 14-14
Coal particles erode tubes adjacent to burners
For waterwalls, corrosion cracks are predominantly circumferential and, to a lesser extent, axial.
The overall appearance on the waterwalls is one of circumferential grooving. The alligator-hide
morphology of superheaters and reheaters and the circumferential cracking on waterwalls in
coal-fired boilers are caused by a similar mechanism. The liquid ash layer develops, and the
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slush can hold only a certain weight of ash. When the weight is excessive, the slag is shed,
exposing a bare, uninsulated tube to the heat flux of the fireball. The temperatures will spike on
waterwalls by perhaps 100°F, and the cracking is then similar to thermal fatigue. The mechanism
for the steam-cooled tubes is similar, except that the temperature spike is probably less;
therefore, the thermal fatigue damage is less severe.
Corrosion can manifest in many ways and offer varying appearances (such as that shown in
Figures 14-15 and 14-16). In all cases, regardless of appearance, there will be wall loss.
Figure 14-15
One appearance of corrosion
Figure 14-16
Severe corrosion on a waterwall
Inspect for the following indications of fireside corrosion:
•
Tubes that are corroded thin
•
Pitted (spot-examine thickness ultrasonically)
•
Alligator hide–like appearance
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Record the tube, elevation, panel (type and material), and tube wall loss exceeding 20%.
Locations of fireside corrosion include the burner and windbox zone. Problems might be helped
by fuel nozzle adjustments or coal and air distribution adjustment.
Inspect previous pad welds for the following, recording the tube, elevation, and length:
•
•
•
•
•
Cracks
Horizontal weave (weld technique)
Undercut
Excessive reinforcement
Steam cuts
For circumferential tube cracking, record the tube number, elevation, and severity of cracking. It
appears as a type of tight parallel cracking (also called elephant hide) and is usually caused by
thermal fatigue, sootblower quenching, or stress. Figure 14-17 shows a tube with cracking
apparent after ash was removed.
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Figure 14-17
Cracking visible after ash removal
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14-12
The conditions causing the cracks should be remedied. The cracking should be monitored and
identified as slight, medium, or heavy. Heavy cracking in a tube wall should be replaced.
Inspect for tube shotgun dents or gouges (see Figure 14-18), and record their depth, surrounding
wall thickness, and elevation. Shotgun dents and gouges are usually due to deslagging, tool
marks, or scaffolds. Unless there is an actual wall loss in the tube or a significant (>10%)
restriction in the ID of the tube, we suggest that no repairs be made. These dents and gouges look
far worse than they really are. Keep in mind that flow restriction is the real concern for a dented
tube.
Figure 14-18
Multiple shot gunshot impacts
In butt welds, inspect for cracks and undercut exceeding 1/32 in. (0.8 mm). Record the tube and
elevation. A visible crack, such as that shown in Figure 14-19, is never a good sign. It is
important to understand the nature and cause of the crack when considering next actions.
Figure 14-19
A visible crack is never a good sign
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14-13
Inspect for the following around observation ports:
•
•
•
•
•
•
•
Tubes worn flat
Pitting
Erosion (spot-examine thickness ultrasonically)
Corrosion
Membrane crack terminations (contour)
Pad welds (proper metal) and technique
Circumferential tube cracks
Record the length, elevation, and tube wall loss exceeding 20%.
The area at the top of the slope is subject to slag falls. This area will gradually thin over time,
with the thinning usually symmetric and difficult to visualize. It is best to use ultrasonic
examination to measure this area. Failures will result if tubes that have been collapsed are not
removed.
Inspect for erosion (and abrasion), which usually takes the form of gouging (Figure 14-20
presents an example) and is caused by slag falls sliding down the walls and slope. (The effect is
worse at the sidewalls.) This occurs usually at about 4 ft (1.2 m) up from and to the center of the
slope nose. This area should be examined visually and then ultrasonically thickness-scanned at or
around the nose, 2 ft (0.6 m) up from the nose, and 4 ft (1.2 m) up from the nose. Inspect by
ultrasonic method every five tubes. Scan every tube when readings fall below the plant’s criteria.
Figure 14-20
A gash in a vertical tube
The methodology for quench crack inspection on all waterwalls is as follows. All wall tubes in
all corners should be inspected from 3 ft (0.9 m) above the highest known blowing area to 3 ft
(0.9 m) below the lowest known blowing area every fifth tube. The tubes should be ground for
visual inspection and ultrasonic verification of crack depth. Tubing found with cracks below the
desired minimum wall should be examined every 12 in. (304.8 mm) upstream and downstream
until an acceptable tube wall is found. The tubes that do not meet these technical requirements
should be replaced. Ultrasonic thickness readings should be recorded in most areas that are to be
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inspected, regardless of the action taken. These thickness readings will allow the plant to chart
the progression of future quench cracking and identify locations that are more likely to require
future inspection and possible replacement. This will allow the plant to move from a shotgun
approach to a more refined, surgical approach to future inspection and repairs. The benefit will
be future reductions in inspection and repair costs.
Figures 14-21 and 14-22 show tubes cracked by water lances. The tube failure depicted in Figure
14-23 was due to splashing from the ash pit to the underside of tubing. The weld contour was
much too sharp, causing sensitivity and failure.
Figure 14-21
A tube cracked by a water lance
Figure 14-22
Another tube cracked by a water lance
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Figure 14-23
A tube failure resulting from splashing from the ash pit
Excessive pad welds do not hold up well in quench-cracked areas. The increased thickness of the
welded area causes higher tube temperature and increased quench damage.
Figure 14-24 shows an example of fretting, which, along with abrasion, can lead to tube failure.
Figure 14-25 shows an OD crack in a boiler tube.
Figure 14-24
Fretting can lead to a tube failure
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14-16
Figure 14-25
An OD crack in a boiler tube
Historically, the type of pad weld shown in Figure 14-26 has proven to be a failure risk. When
similar pad welds are encountered and the logistics are right, they should be replaced. At a
minimum, they should be ground to the original tube contour and checked for cracks.
Figure 14-26
Replace this type of pad weld when possible
In existing pad welds, inspect for the following and record all location information (the tube,
wall, elevation, and length):
•
•
•
•
•
Weld cracks
Horizontal weave (weld technique)
Undercut
Excessive reinforcement
Incorrect weld rod material (carbon-to-carbon and stainless-to-stainless are correct)
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14-17
There are other issues related to work quality that should be inspected for and addressed. For
example, in Figure 14-27, a neighboring tube was accidentally cut—a common occurrence.
These cuts should be feathered and the wall loss replaced. In Figure 14-28 is a window weld cut
rectangular. Window welds are Code-permissible but discouraged. The rectangular weld creates
unacceptable stress in the repair and tube; instead, a football-shaped weld would have been
correct.
Figure 14-27
Accidental cutting of a neighbor tube
Figure 14-28
A rectangular window weld creating unacceptable stress in the repair and tube
14.3 Inspection Case Histories of Furnace Waterwalls
Figure 14-29 presents 15 examples of inspection reports indicating cycling-related damage on
furnace waterwalls.
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14-18
Figure 14-29
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-19
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-20
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-21
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-23
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-24
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-25
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-26
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-27
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-28
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-29
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-30
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-31
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-32
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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14-33
Figure 14-29 (continued)
Inspection reports indicating sootblower erosion (1 and 3), gouging from past
maintenance work (2), cracked membrane (4), thermal fatigue or cracking from quenching
(5, 6, and 14), a failed attachment clip (7), gas injector erosion (8), impact gouge damage
(9), a thermal fatigue–cracked weld (10), an explosion-produced hole (11), a tube crushed
by fly ash erosion (12), slag fall damage (13), and thermal fatigue cracking in a
supercritical waterwall (15)
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15
INSPECTION OF REAR-WALL HANGER TUBES
15.1 Cycling Effects on Rear-Wall Hanger Tubes
Figure 15-1 shows the location of the rear-wall hanger tubes. They support the weight of the rear
furnace wall, carry a large load, and are therefore usually very thick.
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Figure 15-1
Location of the rear-wall hanger tubes
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15-2
15.2 Inspection Guidelines for Rear-Wall Hanger Tubes
Inspect tubes for erosion as they bend from the slope up vertical, at the roof , and at the base of
the rear waterwall screen tubes (see Figure 15-2 for likely locations). It is common for erosion to
take place in the retract paths. Tubes should be shielded if this is a problem. Repair by pad
welding or shielding when wall loss meets the specified criteria.
Figure 15-2
Likely locations of erosion and abrasion in rear-wall hanger tubes
Slag on the arch causes erosion at the bend between the arch and vertical tubes. Check for wall
thickness and pad-weld or shield accordingly. Shielding should extend 12 in. (304.8 mm) above
the bend. In Figure 15-3, erosion from sliding slag has thinned a tube.
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15-3
Figure 15-3
Tube thinning from sliding-slag erosion
Inspect rear wall hanger tubes for cracking, corrosion (see Figure 15-4), burned and displaced
shields, and abrasion (see Figure 15-5).
Figure 15-4
A severely corroded tube
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15-4
Figure 15-5
Abrasion between restraint and tube
Inspect tubes for the following signs of overheating:
•
•
•
•
•
•
Blackened or red color (see Figure 15-6)
Elephant hide–type cracking
Liquid-phase corrosion
Bulging
Bowing (record tube bow of more than one diameter)
Rubbing (tube to tube)
Figure 15-6
Black color and cracks indicate possible overheat
If there is an arch floor refractory baffle, sketch missing locations, including length, and estimate
the weight of refractory needed for repair. Inspect any exposed tubes for jackhammer scars or fly
ash erosion. Figure 15-7 shows erosion at the intersection of tubing and refractory.
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15-5
Figure 15-7
Erosion at the intersection of tubing and refractory
Cracking can exist if welded tie vibration restraints are installed. Any tubes affected should be
repaired. Stainless steel U-bolts can be installed as additional vibration restraints.
Inspect the arch floor refractory baffle for retract erosion on both the left and right sides. If tubes
are worn flat, record wall loss of more than 20%.
Inspect previous pad welds. Record cracks, horizontal weave (weld technique), undercut,
excessive reinforcement, and weld rod material.
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15-6
For existing tube shields, inspect for the following:
•
•
•
Shields that are eroded (stainless steel)
Missing (if missing, examine the tube ultrasonically)
Loose or turned shield
In high heat areas above 1600°F (871°C), the stainless tube shields must be installed tight to the
tube. This is usually accomplished by power brushing. If the shield is not fit tightly, it will look
like Figure 15-8 within about the first hour of operations. In Figure 15-8, the gaps between
shields are extremely dangerous because ash will be concentrated in the gaps, accelerating ash
erosion. In Figure 15-9, the tube shield has overheated and expanded, bowing away from the
tube it is supposed to protect. This is the result of applying a new shield over a dirty tube—the
dirtier the tube, the less cooling effect it provides.
Figure 15-8
Dangerous gaps between shields
Figure 15-9
An overheated shield bowing away from the very tube it is supposed to protect
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15-7
For flex ties, lugs, and alignment brackets, inspect for the following:
•
•
•
Crack components
Missing clips
Gouging on tubing
If broken lugs exist, record the depth and tube wall loss in excess of 20%. Figure 15-10 shows a
broken alignment lug. These are usually made of stainless steel. If so, this might be a DMW.
Figure 15-10
A broken alignment lug
In Figure 15-11, the alignment bars have been overheated, causing distortions. One of two things
has happened: the temperature of the flue gases exceeded the alignment bar capacity, or the
wrong material was used in the alignment system.
Figure 15-11
Distortion caused by overheated alignment bars
Figure 15-12 shows an example of excessive attachment. Any remnants left welded to a tube act
as a fin transferring energy to the tube. These should always be removed by grinding.
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15-8
Figure 15-12
Remove any remnants of an attachment
Look for improper pad welds characterized by any of the following:
•
•
•
•
•
Weld cracks
Horizontal weave (weld technique)
Undercut
Excessive reinforcement (see Figure 15-13)
Incorrect weld rod material (the correct materials are carbon to carbon and stainless to
stainless)
Record all location information (the tube, wall, elevation, and length).
Figure 15-13
Excessive, poorly applied pad welds
In tubes, inspect for the following, recording the length, elevation, and tube wall loss for loss
exceeding 20%:
•
•
•
•
Areas worn flat
Pitting
Erosion (spot-examine thickness ultrasonically)
Corrosion
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15-9
•
•
•
Membrane cracks terminations (contour)
Pad welds (proper metal and technique)
Circumferential cracks
15.3 Inspection Case Histories for Rear-Wall Hanger Tubes
Figure 15-14 presents three examples of inspection reports indicating cycling-related damage in
rear-wall hanger tubes.
Figure 15-14
Inspection reports indicating fly ash erosion at a deflection arch intersection (first report),
thermal fatigue in refractory (second report), and damage in wall hanger tubes (third
report)
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15-10
Figure 15-14 (continued)
Inspection reports indicating fly ash erosion at a deflection arch intersection (first report),
thermal fatigue in refractory (second report), and damage in wall hanger tubes (third
report)
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15-11
Figure 15-14 (continued)
Inspection reports indicating fly ash erosion at a deflection arch intersection (first report),
thermal fatigue in refractory (second report), and damage in wall hanger tubes (third
report)
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16
INSPECTION OF CONVECTION PASS WALLS/HEAT
RECOVERY AREA
Figure 16-1 shows the locations of the convection pass tubes.
Figure 16-1
Locations of the convection pass tubes
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16-1
16.1 Inspection Guidelines for Back/Convection Pass Walls
Inspect for the following, paying particular attention to the corners of the heat recovery area:
•
Missing membrane or peg fins (see Figure 16-2)
•
•
•
•
•
•
•
Tubes worn flat
Pitting
Erosion (spot-examine the thickness ultrasonically)
Corrosion
Membrane crack terminations (contour)
Pad welds (proper metal and technique used)
Circumferential tube cracks
Figure 16-2
Refractory is exposed with the peg fin missing
As seen in Figure 16-3, the left and right rear corners are likely locations for increased fly ash
erosion.
Figure 16-3
The rear corners are likely locations for increased fly ash erosion
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16-2
In existing tube shields, inspect for the following:
•
•
•
Eroded shields
Missing shields (if missing, examine the tube ultrasonically)
Deformed, loose, or turned shields that allow gaps between the shield and tube
Inspect the beginning and ending elevations of bowed or misaligned tubes (the tubes involved).
Note the severity of displacement.
In existing pad welds, inspect for the following:
•
•
•
•
•
Cracks (see Figure 16-4)
Horizontal weave (weld technique)
Undercuts
Excessive membrane
Incorrect rod material
Figure 16-4
A crack in the weld
Inspect for tubes that have been worn flat or that are pitted—both indications of erosion. If the
wall loss is suspected to be less than 20%, spot-check ultrasonically. Pay particular attention to
the bent tube openings in the heat recovery area for erosion. Repair all erosion according to the
remaining wall criteria. Inspect the superheat center wall–to-penthouse seal, and record all leaks
and cracks in the seal. Figure 16-5 depicts fly ash erosion at the header-to-tube connection.
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16-3
Figure 16-5
Fly ash erosion at the header-to-tube connection
At access doors, inspect for membrane cracks, tube erosion, and tube-to-casing gouges. Any tube
out of plane with the wall will experience fly ash erosion. Figure 16-6 shows this at tubes that
offset around access doors.
Figure 16-6
Tubes in the convection pass that, if out of alignment, will catch fly ash and become
thinned by erosion
For the retract blower, inspect for the following:
•
Erosion and corrosion wherever tubes are eroded flat (spot-examine ultrasonically if
necessary).
•
Corrosion under the blower from a leaking poppet valve.
•
•
•
Membrane or peg fin tears.
Erosion and dropped tubes in roof tubes.
Dew-point corrosion in the lower convection pass area. This will appear as pitting and
corrosive attack to tubing or enclosure walls.
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16-4
Inspect the heat recovery area/superheat center wall headers for the following:
•
•
•
•
Erosion
Corrosion
Bowing
Nipple cracks
Compensate for header erosion with finger bars and refractory. Because of the thickness of
headers, repairs require special consideration. Heat-treating and stress relief are usually required.
Consultation with the engineering and/or welding quality assurance/quality control departments
is recommended.
Figure 16-7 shows a Babcock & Wilcox– (B&W-) type boiler heat recovery area rear-wall
header splice. It is common for these splices to crack on startup. This is typical in B&W boilers
only.
Figure 16-7
Convection pass header coupler in B&W units have had cracking in this location
Check for membrane tears in tubes close to headers (such tears might be due to differential
expansion). If membrane tears exist, install steel reinforcing bars to relieve the stress. In some
B&W units, the section between rear convection pass wall headers cracks and tears up the
convection pass rear wall (see Figure 16-8). Any tube in the convection pass walls that is out of
plane (bowed into the gas lane) will erode quickly from fly ash erosion (see Figure 16-9). Check
nipple welds wherever bowed tubes exist.
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16-5
Figure 16-8
In some B&W units, the section between rear convection pass wall headers cracks and
tears up the rear wall
Figure 16-9
Tubes in the convection pass walls that are bowed into the gas lane will erode quickly
Polished tubes are not always thin enough to require action. However, polished tubes should be
treated with suspicion because some activity is occurring in the polished area. Figure 16-10
shows polished tubes that measured above minimum wall thickness.
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16-6
Figure 16-10
Polished tubes that measured above minimum wall thickness
16.2 Inspection Case Histories for Back/Convection Pass Walls
Figure 16-11 presents two examples of inspection reports indicating cycling-related damage in
back/convection pass walls.
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16-7
Figure 16-11
Inspection reports indicating fly ash erosion on a back pass wall (first report) and lowtemperature corrosion on a convection pass wall (second report)
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16-8
Figure 16-11 (continued)
Inspection reports indicating fly ash erosion on a back pass wall (first report) and lowtemperature corrosion on a convection pass wall (second report)
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16-9
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17
INSPECTION OF THE SUPERHEATER/REHEATER
PENDANTS AND PLATENS
Figure 17-1 shows the locations of the superheat and reheat pendants.
Figure 17-1
Locations of the superheat and reheat pendants
17.1 Cycling Effects on the Superheater/Reheater Pendants and Platens
On cold starts, condensation is present in superheater/reheater loops during the initial startup.
Condensate is also significant during hot starts. When condensation occurs, water droplets are
generated as a mist in the saturated steam. Due to latent heat transfer, the tubes experience an
immediate concentrated heat flux that then cools down the tube wall to saturation temperature.
Later, the outlet header is likely flooded with water.
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17-1
Water quenching in superheaters causes tubing to shrink at varying rates and locations,
producing high stresses on tube and header welds. The outlet headers are shocked (thick walls).
Water quenching during hot startups must be assumed as it can be the cause of tube failure in
very few startups.
17.2 Inspection Guidelines for Superheater/Reheater Pendants and Platens
Inspect at the superheat and reheat lower loops (see Figure 17-2).
Figure 17-2
Superheat and reheat lower loops
Inspect for the following signs of overheating in the tubes:
•
•
•
•
•
•
Blackened or red color
Elephant hide–type cracking
Liquid-phase corrosion
Bulging
Bowing (record any tube bow of more than one diameter)
Rubbing (tube to tube)
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17-2
However, not all overheated tubes are visible. Many can be covered up with ash and slag, as in
Figure 17-3. If tube overheat (bow) is suspected, it might be necessary to have the tube cleaned
for a closer look.
Figure 17-3
An overheated tube concealed by ash and slag
For any shotgun dents, inspect the depth, surrounding wall thickness, tube, and elevation.
Shotgun dents are usually due to deslagging, tool marks, or scaffolds. Unless there is an actual
wall loss in the tube or a significant (greater than 10%) restriction in the ID of the tube, we
suggest that no repairs be made. These look far worse than they really are. For example,
Figure 17-4 shows a location with many dents caused by shotgun blast. If you look carefully,
you can see that the dents are quite shallow—a fact that allows the plant to take no action on the
tube. However, in Figure 17-5, the tube shown has too much steam flow restriction; it must be
replaced. The rest of the tube circuit should be examined for signs of overheating.
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17-3
Figure 17-4
Many shallow dents caused by shotgun blast
Figure 17-5
A tube with excessive restriction of steam flow
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17-4
In pad welds (for thickness restoration), examine the following, noting the tube, pendant, and
elevation:
•
•
•
•
•
•
•
Horizontal weave (weld technique)
Undercuts
Excessive membrane
Rod material
Heavy or magnetic
Crack severity
Tube wall loss >20%
The weld displayed in Figure 17-6 is more likely to present problems than a weld made through
the proper technique. If conditions present themselves, the weld—although it is a lower
priority—should be removed.
Figure 17-6
A weld that is more likely to be problematic than one made by the proper technique
Inspect for tubes that have been worn (including worn flat) or pitted by erosion. Record the tube,
pendant, and elevation. If wall loss is suspected to be less than 20%, spot-check the wall
ultrasonically. Figure 17-7 shows a tube eroded by wet steam, which can be aggressive.
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17-5
Figure 17-7
Wet steam erosion can be aggressive
Inspect shields for the following, recording the tube, assembly, and elevation:
•
•
•
•
•
•
•
Shields eroded through
Burnt shields
Missing (examine thickness by ultrasonic method)
Loose shields and redirection of flow
Tube wall loss >20%
Displaced shields
Holes
Burned and deformed shields will redirect sootblower and fly ash into areas not easily seen by
the boiler inspector (see Figure 17-8). These must be replaced after a thorough inspection of the
tube below the shield.
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17-6
Figure 17-8
Burned and deformed shields redirect sootblower and fly ash
In bowed or misaligned tubes or assemblies, inspect the beginning and ending elevations. Note
the tubes involved, the severity of displacement, and any evidence of overheating. Poor
alignment or bowing (see Figure 17-9 for an example) is usually attributed to overheating. It is
important to know why the tube bowed so that the root cause can be addressed. The replacement
of the tube will be determined by whether the subject tube is thinned past the minimum wall
thickness.
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17-7
Figure 17-9
Poor alignment or bowing is usually attributed to overheating
Check tubes for the following signs of overheating:
•
•
•
•
•
•
Blackened or red color
Elephant hide–type cracking or bark-like appearance (see Figure 17-10)
Liquid-phase corrosion
Bulging
Bowing (record tube bow of more than one diameter)
Rubbing (tube to tube)
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17-8
Figure 17-10
A bark-type surface on tubes sometimes indicates overheating
On alignment bars, inspect for the following, recording the tube, element, elevation, and tube
wall loss in excess of 20%:
•
•
Missing or damaged clips
Cracked alignment devices
•
Disengaged (see Figure 17-11 for an example of bowed, disengaged flex ties)
•
•
•
Gouging
Binding abrading clips
Erosion
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17-9
Figure 17-11
These flex ties are not engaged due to excessive bowing
Figure 17-12 shows a broken alignment bar. To craft a solution, the plant must first understand
why the bar broke. In Figure 17-13, poor alignment is resulting in slag and ash being trapped in a
bundle of tubes.
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17-10
Figure 17-12
A broken alignment bar
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17-11
Figure 17-13
Slag and ash trapped in a misaligned bundle of tubes
Corrosion takes many different forms, such as that pictured in Figure 17-14. Liquid-phase
corrosion is shown in Figure 17-15. In all cases, the corrosion will reduce the wall thickness.
Inspect for the following signs of corrosion, recording the tube, element, elevation, and tube
material:
•
•
•
•
Flats (spot-examine thickness ultrasonically)
Pitting
Alligator hide
Wall loss exceeding 20%
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17-12
Figure 17-14
One of the many forms of corrosion
Figure 17-15
Corrosion in this area is usually liquid-phase corrosion
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17-13
Tube-to-tube DMWs should be inspected for cracks due to carbon migration at weld boundaries.
Record the length and propagation (direction). Cracks form primarily from the OD, so that NDE
(that is, visual, magnetic particle, liquid penetrant, and ultrasonic thickness measurements) must
be used. In Figure 17-16, which shows a DMW crack running from the OD toward the ID, the
crack visible at the OD provides little useful information about the remaining life.
Figure 17-16
A DMW crack visible at the OD that provides little if any information on the remaining
useful life
The most reliable method for controlling DMW failures is to proactively replace the welds
before they fail. Taking total starts into consideration, a window of opportunity can be calculated
(see Figure 17-17).
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17-14
Figure 17-17
Replace DMWs before they fail
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17-15
At vertical tubes (see Figure 17-18), inspect tubes for the following signs of overheating:
•
•
•
•
•
•
Blackened or red color
Elephant hide–type cracking
Liquid-phase corrosion
Bulging
Bowing (record tube bow of more than one diameter
Rubbing (tube to tube)
•
Slag deposits
Figure 17-18
Inspect vertical tubes
When a tube is found overheated, the examiner should look at the entire circuit for additional
damage (see Figure 17-19).
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17-16
Figure 17-19
The entire circuit of an overheated tube should be inspected for other damage
Inspect vertical tubes for signs of erosion—tubes that are worn (including worn flat) and pitting.
If wall loss is suspected to be less than 20%, spot-check ultrasonically. Record the tube, pendant,
length, and elevation.
In Figure 17-20, a shield and tube underneath it have eroded. Replace the shield after repairs are
made to the tube.
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17-17
Figure 17-20
Erosion in a shield and underlying tube
Inspect pad welds for the following:
•
•
•
•
•
Cracks
Horizontal weave (weld technique)
Undercuts
Excessive membrane
Incorrect rod material
Figure 17-21 shows a weld with a significant amount of coarse contrast in the weld weave. It
should be replaced as soon as practical. In Figure 17-22, erosion has taken place in more than
one cycle. Repeating the same repair over and over is not the best practice. Instead, find the root
cause and fix it.
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17-18
Figure 17-21
Unacceptable coarse contrast in the weld weave
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17-19
Figure 17-22
Erosion has occurred in more than one cycle
Inspect the beginning and ending elevations of bowed or misaligned vertical tubes. Record the
tubes involved and the severity of displacement. A bowed tube, such as the one shown in Figure
17-23, is a target for retractable sootblower wash.
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17-20
Figure 17-23
A bowed tube is a target for retractable sootblower wash
Inspect for evidence of rubbing or fretting. Rubbing is aggravated by cycling (see Figure 17-24).
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17-21
Figure 17-24
Cycling aggravates rubbing
Inspect vertical tubes for corrosion-caused wall loss in excess of 20%. Typically, erosion is
found at misaligned tubes. Spot-examine thickness with ultrasonic methods. Record the tube,
pendant, length, and elevation. Figure 17-25 shows extreme sootblower erosion. Keep in mind
that any tube penetrating the roof is subject to fly ash erosion (see Figure 17-26).
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17-22
Figure 17-25
Extreme sootblower erosion
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17-23
Figure 17-26
Tubes penetrating the roof are subject to fly ash erosion
Locations in which a tube arrangement presents a target to the retractable sootblower will usually
produce erosion (see Figure 17-27). For retract wash, inspect washed tubes (thickness-examine
with ultrasonic methods) and wall loss of more than 20% of the tube. Record the pendant, length,
elevation, and retract number. In Figure 17-28, retract erosion was found behind a wrapper tube
on the individual vertical tubes.
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17-24
Figure 17-27
Where a tube arrangement presents a target to the retractable sootblower, erosion usually
occurs
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17-25
Figure 17-28
Retract erosion behind a wrapper tube on the individual vertical tubes
Ash corrosion can be found anywhere in the area depicted in Figure 17-29.
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17-26
Figure 17-29
Ash corrosion can be found anywhere in this area
Crushed tubes follow the same rules as dented tubes. If more than 10% of the cross-section is
reduced, the tubes involved must be replaced. See Figure 17-30 for an example.
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17-27
Figure 17-30
Crushed tubes follow the same rules as dented tubes
A gap in a shield provides a focused stream of ash to cut the tube between the two gapping
shields (see Figure 17-31). Install a bridge or cover shield that will cover the gap and seal it.
Figure 17-31
A gap in a shield provides a focused stream of ash
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17-28
18
INSPECTION OF HORIZONTAL AND VERTICAL
WRAPPER TUBES
18.1 Inspection Guidelines for Horizontal and Vertical Wrapper Tubes
Figures 18-1 and 18-2 show horizontal and vertical wrapper tubes. Inspect them for erosion,
which is probably a result of retractable sootblower accelerated erosion, and record. Redirected
erosion, whether it be retract or fly ash, can be severe in its ability to thin the tubes involved, as
seen in Figure 18-3.
Figure 18-1
Horizontal and vertical wrapper tubes
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18-1
Figure 18-2
Retractable sootblower accelerated erosion is the probable cause in this area
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18-2
Figure 18-3
Redirected erosion can severely thin tubes
Inspect for tube-to-tube rubbing in horizontal and vertical wrapper tubes. Rubbing and abrasion
occur when two physical elements touch each other (see Figure 18-4). A broken support lug can
abrade the adjacent tube (see Figure 18-5). Crossovers or scissors tubes are likely to rub each
other, and increased cycling will exacerbate the problem (see Figure 18-6). For any rubbing
discovered, record the tube, pendant, length, and elevation.
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18-3
Figure 18-4
A broken support lug can abrade the adjacent tube
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18-4
Figure 18-5
Rubbing/abrasion between physical elements
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18-5
Figure 18-6
Crossovers or scissors tubes are likely to rub each other
Record any tubes bowed more than one tube diameter. In Figure 18-7, bowing has caused one
side of a panel to become disengaged from the other.
Figure 18-7
A panel disengaged by tube bowing
In tube ties and support lugs, looked for cracked or missing components and gouging (depth).
Record tube wall loss of more than 20% and the tube, pendant, and elevation. Figures 18-8 and
18-9 are examples of alignment and support devices. In Figure 18-9, abrasion at a rigid
mechanical alignment lug is difficult to access because of the complexity of the connections. In
many cases, the alignment lug must be disengaged to gain access.
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18-6
Figure 18-8
Broken alignment hardware
Figure 18-9
Hard-to-access abrasion at a rigid mechanical alignment lug
The more complex a junction of tubing, the greater the likelihood of abrasion and erosion (see
Figure 18-10).
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18-7
Figure 18-10
A complex junction of tubing
Handcuffs provide fertile ground for abrasion and sootblower erosion (see Figure 18-11). In
handcuff alignment brackets, inspect for the following, recording the tube, element, elevation,
and tube wall loss exceeding 20%:
•
•
•
•
•
•
Missing
Cracked
Disengaged
Gouging
Binding cuffs
Erosion
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18-8
Figure 18-11
Handcuffs provide fertile ground for abrasion and sootblower erosion
Inspect horizontal and vertical wrapper tubes for cracking and exfoliation. Record the tube,
element, and elevation.
The tube shields are at retract blowers. Inspect for the following:
•
•
•
•
Shields eroded through
Burnt shields (see Figure 18-12)
Missing shields (ultrasonically examine tube thickness)
Loose shields
Record tube wall loss of more than 20% and the tube, pendant, and elevation.
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18-9
Figure 18-12
Distorted/burned tube shields may redirect erosion flow, increasing the likelihood of tube
thinning
Record any dents from shotgun deslagging. The outside tube is especially vulnerable. The tube
shown in Figure 18-13 has extreme shotgun dents. If the tube involved is stainless steel and older
than 15 years, replacement is suggested.
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18-10
Figure 18-13
A tube with extreme shotgun dents
Inspect for slag buildup on elements. Slag will accumulate at the scissor tubes and any bowed
tubes. As can be seen in Figure 18-14, slag-covered tubes can cover underlying corrosion or
erosion. Record the amount of slag found and the pendant, tubes involved, and elevation.
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18-11
Figure 18-14
Slag-covered tubes can cover underlying corrosion or erosion
Inspect the DMWs at the tube material changes for cracking. Record the element, tube, and
elevation.
Inspect old pad welds for cracking, magnetic attraction (from improper material), and weld size.
Note the tube, element, length, and elevation. Pay particular attention to any stainless tubes
because they are more prone to cracking. The pad-welded area in Figure 18-15 has been welded
more than once. This indicates that a better solution is required.
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18-12
Figure 18-15
This pad-welded area has been welded more than onceInspect for the following
indications of overheating in horizontal and vertical wrapper tubes:
•
•
•
•
Blackened or red color
Elephant hide–type cracking
Liquid-phase corrosion
Bulging
Record the tube, element, length, and elevation, and measure the tube outside diameter.
Perform a close inspection of the front and rear tubes for fireside corrosion. Record flat areas.
Spot-examine thickness ultrasonically in areas with pitting or alligator hide–like appearance.
Record wall loss exceeding 20% and the tube, element, elevation, and tube material.
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18-13
Examine for retract wash (erosion). Redirected retract erosion can cause severe thickness
reduction in odd locations (see Figure 18-16). Tubes are generally worn flat or pitted. Identify
which retract. Record tube wall loss exceeding 20% (spot-examine thickness with an ultrasonic
method) and the tube, element, and elevation.
Figure 18-16
Redirected retract erosion can cause severe thickness reduction in odd locations
In handcuff alignment brackets, inspect for the following problems, recording the tube, elevation,
and tube wall loss exceeding 20%:
•
•
•
•
•
•
Missing
Cracked
Disengaged
Gouging
Binding cuffs
Erosion
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18-14
Examine for the following alignment problems:
•
•
•
•
•
•
Clearance to arch (if at loop; record)
Bowing (more than one tube diameter)
Rubbing into adjacent elements (see Figure 18-17)
Tube, element, length, elevation, and tube wall loss >20%
Excessive fouling and debris (record and sketch)
Blockage of gas lanes and buildup of ash on tubes and under elements (at arch floor); heavy
or peculiar slag deposit on tubes
Figure 18-17
Yoke tubes are prime locations for erosion from sootblowers and abrasion from tube-totube rubbing
Inspect platen alignment tubes. Figure 18-18 shows wrapper alignment tubes that are subject to
abrasion and sootblower erosion.
Figure 18-18
Wrapper alignment tubes subject to abrasion and sootblower erosion
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18-15
In roof tubes, check penetrations through the ceiling for tube-to-tube rubbing and inspect for
burnt or missing gas seals/heat shields and missing peg fins. Record any missing refractory.
Examine for wall loss exceeding 20% and roof droop of more than one tube’s diameter.
Condensate in any horizontal tubes will cause internal corrosion due to exposure to oxygen
during outages (see Figure 18-19).
Figure 18-19
Condensate in horizontal tubes will cause internal corrosion
Inspect existing shields for the following, recording the element number, tube, and elevation:
•
•
•
•
Eroded shields
Burnt shields
Missing shields (if missing, examine tube thickness ultrasonically)
Displaced shields
On some designs (see Figure 18-20), a knuckle tube is used to hold division panels in left to right
locations. Major abrasion can be found here. Figure 18-21 shows that a single circuit can be
overheated. Bowing as extreme as that shown in Figure 18-22 indicates that tube replacements
are required.
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18-16
Figure 18-20
A knuckle tube holding division panels in left to right locations
Figure 18-21
A single circuit can be overheated
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18-17
Figure 18-22
Extreme bowing requiring replacement
18.2 Inspection Case Histories for Horizontal and Vertical Wrapper Tubes
Figure 18-23 presents five examples of inspection reports indicating cycling-related damage in
wrapper tubes.
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18-18
Figure 18-23
Inspection reports indicating fretting/rubbing in a wrapper tube (first report), a tube
gouged by abrasion (second report), a crack in a superheat platen (third report), thermal
fatigue in a superheater pendant (fourth report), and sootblower erosion (fifth report)
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18-19
Figure 18-23 (continued)
Inspection reports indicating fretting/rubbing in a wrapper tube (first report), a tube
gouged by abrasion (second report), a crack in a superheat platen (third report), thermal
fatigue in a superheater pendant (fourth report), and sootblower erosion (fifth report)
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18-20
Figure 18-23 (continued)
Inspection reports indicating fretting/rubbing in a wrapper tube (first report), a tube
gouged by abrasion (second report), a crack in a superheat platen (third report), thermal
fatigue in a superheater pendant (fourth report), and sootblower erosion (fifth report)
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18-21
Figure 18-23 (continued)
Inspection reports indicating fretting/rubbing in a wrapper tube (first report), a tube
gouged by abrasion (second report), a crack in a superheat platen (third report), thermal
fatigue in a superheater pendant (fourth report), and sootblower erosion (fifth report)
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18-22
Figure 18-23 (continued)
Inspection reports indicating fretting/rubbing in a wrapper tube (first report), a tube
gouged by abrasion (second report), a crack in a superheat platen (third report), thermal
fatigue in a superheater pendant (fourth report), and sootblower erosion (fifth report)
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18-23
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19
INSPECTION OF THE HORIZONTAL SUPERHEATER
AND REHEATER
19.1 Cycling Effects on the Horizontal Superheater and Reheater
Cycling-accentuated problems can result in distortion of the assembly, cracks at attachments or
supports, and, ultimately, tube leaks. Cycling and load changes cause in-plane and out-of-plane
distortion of superheater/reheat assemblies, the damaging effects of excessive sootblower
operation, and the stresses induced by various thermal loadings. All of these compound to reduce
component reliability.
Water can accumulate during extended outages in low horizontal areas not capable of draining.
These areas over time will corrode, thin, and fail. In these areas, inspection is typically
ineffective.
19.2 Inspection Guidelines for Horizontal Superheaters and Reheaters
Inspect for fly ash erosion, typically found at misaligned tubes. Record tube wall loss of more
than 20% (spot-examine thickness ultrasonically), the tube, assembly, length, and elevation.
Figure 19-1 shows a likely location for fly ash erosion.
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19-1
Figure 19-1
The rear of the areas is a likely location for fly ash erosion
On convection pass sidewalls, inspect for missing refractory and fly ash erosion. Record the tube
number that erosion is occurring adjacent to and the wall number. Figure 19-2 shows a flat area
created by fly ash erosion.
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19-2
Figure 19-2
A flat area created by fly ash erosion
Look for retract wash. Record washed tubes (spot-examine tube thickness ultrasonically), and
inspect for pitting and bowing. In horizontal and vertical support tubes, record wall loss
exceeding 20% and the tube, assembly, length, elevation, and retract number.
The tube shields are at retract blowers. Inspect them for the following:
•
•
•
•
•
•
•
Shields eroded through
Burnt
Missing (examine tube thickness ultrasonically)
Loose shields and redirected flow
Tube wall loss >20%
Displaced shields
Holes
Record the tube, assembly, and elevation. Figures 19-3 through 19-5 are images of tube shield
problems.
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19-3
Figure 19-3
Be sure to check the underlying tube for wall loss before the shield is replaced
Figure 19-4
A shield eroded through can be a target for accelerated erosion
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19-4
Figure 19-5
Distorted tube shields must be removed and inspected before a final repair is selected
Inspect old pad welds for cracking, magnetic attraction (from improper material), and size.
Include the tube, element, length, and elevation. Pay particular attention to any stainless tubes
because they are more prone to cracking. Not all pad welds are sites of future leaks, but each one
should be carefully inspected (see Figure 19-6).
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19-5
Figure 19-6
Inspect all pad welds carefully
Check for the following signs of tube overheating:
• Blackened or red color
• Elephant hide–type cracking
• Liquid-phase corrosion
• Bulging
Bowing (see Figure 19-7) is probably overheat. If overheat has been corrected and the bow is not
creating flow problems, it can go uncorrected. Record tube bow of more than one diameter and
any tube-to-tube rubbing.
Figure 19-7
Bowing is likely caused by overheating
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19-6
Inspect for the following signs of abrasion:
•
•
•
Rubbing (fretting tube-to- tube) (see Figures 19-8 and 19-9)
Missing
Cracked
Figure 19-8
A convection pass wall tube that has been rubbed by an adjacent element
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19-7
Figure 19-9
A disengaged support bracket abrading the return bend
Inspect tube ties/supports for the following, recording the tube number, assembly, and row:
•
•
•
•
Cracks
Missing components
Gouging (record its depth) and tube wall loss exceeding 20%
Bowing
Figure 19-10 shows erosion, abrasion, and corrosion.
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19-8
Figure 19-10
Erosion, abrasion, and corrosion
Corrosion can exist where ash and water (during outage) combine to produce an acidic condition,
corroding tubes (see Figure 19-11). Inspect closely for fireside corrosion in front and rear tubes.
Inspect for the following:
•
•
•
•
Flats (spot-examine thickness ultrasonically)
Pitting
Alligator hide
Wall loss >20%, tube, element, elevation, and tube material
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19-9
Figure 19-11
Corrosion from an acidic combination of ash and water
Inspect for alignment problems, such as tubes bowed more than one tube diameter and rubbing
into adjacent assemblies. Record the tube, length, number, and tube wall loss >20%. In Figure
19-12, a disengaged hanger is allowing the element to droop into the crawl space.
Figure 19-12
A disengaged hanger allowing the element to droop into the crawl space
Debris acts like a baffle, redirecting gas flows (see Figure 19-13). Removing it is not just a
matter of good housekeeping. For excessive fouling and debris, record and sketch lockage of gas
lanes and ash buildup on tubes. Inspect gas lanes, and measure distances from center to center.
Record debris (shields lodged and any blockage redirecting gas flow) and the relevant bundle,
tube, and element.
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19-10
Figure 19-13
Debris acts like a baffle, redirecting gas flows
Roof tubes might not be accessible. Check penetrations through the roof for tube-to-tube
rubbing, missing refractory, burnt or missing gas seals (high crown), heat shields, missing peg
fins (peg fins act as a heat shield to protect the high crown seal areas [see Figure 19-14]), tube
wall loss or more than 20%, and roof droop of more than one tube diameter. In Figure 19-15,
tubes drooping down into the furnace indicate that tube ties are broken in the penthouse area.
Figure 19-14
Peg fins act as a heat shield to protect the high crown seal areas
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19-11
Figure 19-15
Tubes drooping down into the furnace indicate that tube ties are broken in the penthouse
area
Inspect for differential thermal fatigue cracking. Inspect propagation and record the length, tube,
and element. Thermal fatigue cracking cannot be assessed by the width of the crack at the
surface (see Figure 19-16).
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19-12
Figure 19-16
Thermal fatigue cracking cannot be assessed by the width of crack at the surface
Inspect gas lanes. Measure distances (from center to center). Record debris (shields lodged and
any blockage redirecting gas flow) and the bundle, tube, and element.
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19-13
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(EPRI, www.epri.com) conducts research and
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including
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in
emerging
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Together…Shaping the Future of Electricity
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