metallurgical aspects of boiler tube failure
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METALLURGICAL ASPECTS OF
BOILER TUBE FAILURE
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ASME* APPROVED BOILER TUBING STEELSNumber Title of ASME* Specification
SA-178 Electric Resistance Welded Carbon Steel BoilerTubes
SA-192 Seamless Carbon Steel Boiler Tubes For High Pressure
Service
SA-209 Seamless Carbon Molybdenum Alloy Steel Boiler
And Supurheater Tubes
SA-210 Seamless Medium Carbon Steel Boiler And Supurheater
Tubes
SA-213 Seamless Ferritic And Austenitic Alloy-Steel Boiler,
Supurheater, And Heater Exchanger Tubes
SA-226 Electric-Resistance-Welded Carbon Steel Boiler And
Supurheater Tubes For High Pressure Service
SA-250 Electric-Resistance-Welded Carbon-Molybdenum
Alloy-Steel Boiler And Supurheater Tubes
*ASME Boiler and Pressure Vessel Code, Section I, Paragraph
PG-9 and Section II, Part II, Part A, Material Specifications for
Ferrous Materials.
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MINIMUM STRENGTHS ANDNOMINAL COMPOSITION
OF COMMONLY USED BOILER TUBE STEEL GRADES
Tube
steel
type
ASME
Specification
Grade Minimum
Tensile
Strength (MPa)
Minimum
Yield
Strength(MPa)
Nominal
Composition
Carbon Steel
ERW SA-178 A 324.3 179.4 0.15%C
C 41.4 225.3 0.35%C Max
Seamless SA-192 - 324.3 179.4 0.15%C
Seamless SA-210 A1 41.4 255.3 0.27%C Max
C 483 276 0.35%C MaxERW SA-226 - 324.3 179.4 0.15% C
Ferritic Alloy
ERW SA-250 T1 379.5 207 C0.5Mo
Seamless SA-209 T1 379.5 207 C-0.5Mo
T2 414 207 0.75Cr-0.5Mo
Seamless SA-213 T11 414 207 1.25Cr-0.5Mo
T12 414 207 1.00Cr-0.5Mo
T22 414 207 2.25Cr-1.0Mo
T91 586.5 414 9Cr-1Mo
Austenitic Stainless Alloy
Seamless SA-213 TP304H 517.5 207 18.Cr-8Ni
TP316H 517.5 207 16Cr-12Ni
TP321 517.5 207 2Mo
TP347 517.5 207 18Cr-10Ni-Ti
18Cr-10Ni-Cb
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Maximum Tube-Metal Temperatures Permitted By ASME
Code And Boiler Manufacturers
Tube steel
type
ASME
Specification
No.
ASME F
(0C)
Babcock
and Wilcox0F(
0C)
Combustion
Engineering0F(
0C)
Carbon steel SA-178 C 1000 (538) 950 (510) 850 (454)
Carbon steel SA-192 1000 (538) 950 (510) 850 (454)
Carbon steel SA-210 A1 1000 (538) 950 (510) 850 (454)
C-MO SA-290 T1 1000 (538) .. 900 (482)
C-MO SA-209 T1a 1000 (538) 975 (524) ..
C-MO SA-213T11 1200 (649) 1050 (566) 1025 (552)
SA-213T22 1200 (649) 1115 (602) 1075 (580)
Stainless SA-213 321H 1500 (816) 1400 (760) ..
Stainless SA-213 347H 1500 (816) .. 1300 (704)
Stainless SA-213 304H 1500 (816) 1400 (760) 1300 (704)
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SHORT-TERM OVERHEATING
TYPICAL LOCATIONS
Short-term overheating can occur in steam-cooled and water-cooledtubes at locations that:
Have become plugged by debris, scale, or condensate from
incomplete boil out.
Have exposure to high heat transfer rates from improper
firing of fuel burners.
Have experienced low coolant flow due to poor circulation or
upstream tube leak.
PROBABLE ROOT CAUSES.
Overheating is caused by either abnormal coolant flow or excessive
combustion gas temperature. Abnormal coolant flow can be caused by
a blockage in the tube circuit, loss of boiler water drum level, loss ofwater circulation, and incomplete boil out of steam-cooled tubes
during startup. Excessive combustion gas temperature can be
produced by over firing.
HIGH TEMPETATURE CREEP
TYPICAL LOCATIONS
High temperature creep can occur in steam-cooled tubes at locations
that:
Have become partially blocked by debris, scale, or deposits.
Have exposure to radiant heat or excessive gas temperature or
are just before the final outlet header.
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Are just before the change to a higher grade of steel or have
incorrect or lower grade of steel material.
Have high stresses due to welded attachments.
PROBABLE ROOT CAUSES.
High temperature creep is caused by insufficient boiler coolant
circulation, elevated boiler gas temperature, or inadequate tube
material properties.
CAUSTIC CORROSION
TYPICAL LOCATIONS.
Water cooled tubes can experience caustic corrosion at locations that:
Have flow descriptions such as welded joints with backing
rings or protrusions, bends, or deposits.
Have horizontal or inclined tubing.
Have high heat flux or flame impingement.
PROBABLE ROOT CAUSES.
When porous deposits build up in high heat input areas, sodium
hydroxide can concentrate within the deposit to a locally corrosive
level. An increase in the tube metal temperature due to the heattransfer resistance of the deposit supports the concentrating
mechanism.
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HYDROGEN DAMAGE
TYPICAL LOCATIONS.
Water-cooled carbon steel tubes can experience hydrogen damage at
locations that:
Have flow disruptions such as welded joints with backing
rings or protrusions, bends, or deposits.
Have horizontal or inclined tubing.
Have high heat flux.
PROBABLE ROOT CAUSES.
Hydrogen damage is caused by operation with low pH water
chemistry from ingress of acidic salts through condenser leakage,
contamination from chemical cleaning or malfunction of the chemical
control components, and concentration of the corrosive contaminants
within deposits on the internal tube wall.
PITTING(LOCALIZED CORROSION)
TYPICAL LOCATIONS.
Pitting can occur anywhere in the boiler including economizers,
supurheaters, reheaters, and water wall tubes. Locations where highlevels of oxygen can be present are likely to experience pitting.
PROBABLE ROOT CAUSES.
Pitting is caused by exposure of the tube to water with a high
concentrate oxygen. In economizer tubing, the cause of pitting is
likely to be high levels of oxygen in the feed-water entering the
economizers during boiler startup and low load operation periods.
In supurheater and reheater tubing, the cause of pitting is likely to be
collection of condensate in bends during outages.
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LOW TEMPERATURE CORROSION
TYPICAL LOCATIONS.
Low temperature corrosion can at locations in the economizer that:
have boiler tube metal temperatures below the acid dew
point, so that condensate will from on the metal.
have flue gas temperatures below the acid dew point, so that
condensate will from on the fly ash particle.
PROBABLE ROOT CAUSES.
Low temperature corrosion is caused by the formation andcondensation of sulfuric acid from the flue gases. The amount of
sulfer trioxide (SO3) formed in the combustion process is an important
factor since an increase in the SO3
concentration results in an increase
in the acid dew point temperature.
WATER WALL FIRE-SIDE
CORROSION.
TYPICAL LOCATIONS.
Water wall fire-side corrosion can occur at locations that:
have incomplete combustion conditions and a reducing
atmosphere at the water wall.
have corrosive ash deposits.
have steady or periodic flame impingement.
PROBABLE ROOT CAUSES
Water wall fire-side corrosion is caused by corrosive conditions in the
combustion zone which are due to inadequate oxygen supply, high
concentration of sulfure and increased chlorides in the fuel, improper
alignment of the fuel burners, and formation of molten ash on the
water wall tubes surface.
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HIGH TEMPERATURE COAL ASH
CORROSION
TYPICAL LOCATIONS.
High temperature coal ash corrosion can occur at locations insupurheaters and reheaters that:
have tube surface metal temperature between 5930C and
7040C (Maximum corrosion rates occur at 649
0C)
have slag type corrosive ash deposits that are strongly bonded
to the tube.
PROBABLE ROOT CAUSES.
Cool ash corrosion is caused by the formation of complex alkali-iron-
trisulfates in the ash deposits when the tube metal temperature is
between 11000F (593
0C) and 1300
0F (704
0C) Certain coals contain
constituents which from ash deposits that are corrosive in the molten
from.
FLY ASH EROSION
TYPICAL LOCATIONS.
Fly ash erosion can occur at locations that:
have gaps between the tube bank and the duct walls.
have gas by-pass channels where the velocity of the flue gas
can be much higher than that of the main flow
have protrusions or misalignment of tubing rows.
are adjacent to areas with large accumulations of ash.
PROBABLE ROOT CAUSES.
Fly ash erosion is caused by non-uniform or excessive gas flow which
accelerates a large volume of fly ash particles and directs them onto
the tube surface. Tube erosion is enhanced by distortion or
misalignment of tubing rows; fouling or plugging of gas passages by
ash buildups, which forces the flue gas to flow through smallerpassages at higher velocities. Changing fuel to one with higher ash
contents can result in more erosion and failures.
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VIBRATION FATIGUE
TYPICAL LOCATIONS.
Vibration fatigue can occur at locations that:
have welded tie type spacers between vertical water wall.
have welded or fixed attachment on horizontal steam cooled
tubes.
PROBABLE ROOT CAUSES.
Vibration fatigue is caused by tube vibration produced by gas-flow
induced forces. The vibration may be produced directly by the energy
in the energy in the flue gas or indirectly by vortex.
CORROSION FATIGUE
TYPICAL LOCATIONS.
Corrosion fatigue cracking can occur at locations that:
have difference in thermal expansion rates and directions
between joining boiler components. Cracking originates on
the external surface of steam-cooled terminal tubes at
headers.
have corrosion activity and strain from cyclic stresses or
residual stresses. Cracking originates on the internal surfaceof water-cooled tubes at welded attachments to structural
supports.
PROBABLE ROOT CAUSES.
Corrosion fatigue cracking is caused by cyclic stresses and corrosive
environmental conditions. Stresses may be due to differences in
thermal expansion between two joining components or to
concentration of stress from the formation of pits, notches, or othersurface irregularities.
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MAINTENANCE CLEARING DAMAGE
TYPICAL LOCATIONS
Maintenance clearing damage can occur at any locations that:
Requires hammering and chipping
Requires dynamiting Requires vacuum clearing
Requires high pressure grit or water blasting
Requires shotgum blasting.
PROBABLE ROOT CAUSES
Maintenance cleaning damage is caused by lack of quality control
during furnace cleaning. Maintenance clearing damage results when
excessive forces are applied during the process of removing ashaccumulations from the boiler. Heavy equipment and powerful tools
are employed to clean the furnace side of a boiler. Tube damage
results when the clearing equipment and tools are mishandled to
improperly applied.
CHEMICAL EXCURSION DAMAGE
TYPICAL LOCATIONS.Chemical excursion damage can occur at locations that:
have been inadvertently exposed to chemical cleaning
solutions.
have been inadvertently exposed to chemical clearing
solutions.
have been inadvertently exposed to corrosive chemicals
present in pant for normal water chemistry control.
PROBABLE ROOT CAUSES
Chemical excursion damage is caused lack of quality control when
using corrosive chemicals. Chemical damage results when chemical
cleaning agents are not adequately neutralized prior to operation or
are inadvertently injected into some portion of the boiler by
equipment malfunction or operator error. Acid or caustic excursions
during normal boiler operation can also cause general corrosion attack
and are the result of malfunction of water chemistry controls andwater treatment equipment.
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MATERIAL DEFECTS
TYPICAL LOCATIONS.
Material defects can occur at any location in the boiler but are morelikely to lead to failure at high temperature locations due to
interaction with the stress rupture failure mechanism.
PROBABLE ROOT CAUSES.
Material defects are caused by lack of quality control during tube
manufacture, fabrication, storage, and installation. Material defects
can be introduced during the making of the steel, fabrication of thetube and tube panels, erection of the boiler, or replacement of the
tube.
WELDING DEFECTS
TYPICAL LOCATIONS
Welding defects can occur at any location where tubing is joined
together or to structural members by the welding process.
PROABLE ROOT CAUSE.
Welding defects are caused by lack of quality control during the
welding process. Various type of welding defects can be introduced
due to deficiencies in the welding method. The most common types of
defects are excess penetration, porosity, inclusions, incomplete fusion,
undercut, and inadequate joint penetration. Defects result from poor
welding practice, improper joint preparation, improper electrode,
inadequate preheat, or rapid cooling.
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HIGH TEMPERATURE CREEP
FACTORS
TEMPERATURE
TIME
STRESS
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ACCELERATED CREEP RUPTURETEST
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FAILURE MECHANISM OF WATERWALL TUBES(LOCATION AND POSITION)
Water Wall Tube Locations And Typical Positions
Failure
Mechanism
Below
Burner
Level
At
Burner
Level
Above
Burner
Level
Typical Positions
Short-term
overheating
X X Horizontal or slightly inclined
tubes. Downstream from flow
disturbance, tube blockage, or
tube leak.
Caustic
Corrosion
X X High heat flux areas.
Horizontal tubes. Down
stream of weld, bend, or flow
disturbance.
Hydrogen
damage
X X High heat flux areas.
Horizontal tubes. . Down
stream of weld, bend, or flow
disturbance.
Water wall
Fire-side
Corrosion
X X X Tube that experience flame
impingement or have the
highest heat flux. Tubes in
walls close to burners.
Falling Slag
Erosion
X Tubes on sloping walls about
0.9 to 1.2m from bottom
opening.
Soot blower
Erosion
X Near furnace corners where
direct impingement can occur.
At soot blowers where nozzles
have been damaged.
Vibration
Fatigue
X Vertical screen tubes at
welded tie type spacers or at
welded attachments to tubesor supperts.
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FAILURE MECHANISM OF ECONOMISER TUBES(LOCATION AND POSITION)
Economiser Tube Locations And Typical Positions
Failure
Mechanism
Feed
Water
Inlet
Bends Fuel
Gas
Inlet
Typical Positions
Pitting
(LocalisedCorrosion)
X X X Horizontal tubing where
water can accumulateduring shutdowns. Feed
water inlet where
oxygenated water first
enters tubing.
Low
temperature
Corrosion
X At tubes containing water
or exposed to flue gas that
has a temperature below the
acid dew point.
Fly AshErosion
X XLeading tube or protrudingtube. Tubes adjacent to
walls or large
accumulations of fly ash.
Thermal
Fatigue
X At tube connections to feed
water inlet headers.
CorrosionFatigue
X X Horizontal or slightlyinclind tubes. Downstream
from flow disturbance, tube
blockage, or tube leak.
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FAILURE MECHANISM OF SUPERHEATER ANDREHEATER TUBES
(LOCATION AND POSITION)
Superheater or Reheater Locations And Typical Positions
Failure
Mechanism
Radiant
Circuits
Convection
Circuits
Typical Positions
Pitting
(Localised
Corrosion)
X X Low bends in pendant loops
where pluggage from scale,
debris, or condensate causes
low coolant flow.
High
Temperature
Corrosion
X X Upstream of Transition to
higher grade of tube
material. Leading tubes oroutlet tubes. Local areas or
outlet tubes. Local areas of
higher temperatures.
Pitting
(Localised
Corrosion)
X X Bottom of pendant loops and
low points of sagging
horizontal tubes.
Fly AshCorrosion
X At protrusions ormisalignment of tubing
rows. At walls or gas bypass
channels. Adjacent to largeash accumulations.
Corrosion
Fatigue
X At header-to-terminal tube
welds, especially at both
ends of header where
expansion is greatest.