metallurgical aspects of boiler tube failure

7/27/2019 Metallurgical Aspects of Boiler Tube Failure

1/17

METALLURGICAL ASPECTS OF

BOILER TUBE FAILURE


2/17

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.


3/17

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


4/17

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)


5/17

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.


6/17

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.


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.


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.


7/17

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.


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.


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.


8/17

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.


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.


9/17

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.


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.


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.


10/17

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.


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.


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.


11/17

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.


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.


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.


12/17

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.


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.


13/17

HIGH TEMPERATURE CREEP

FACTORS

TEMPERATURE

TIME

STRESS


14/17

ACCELERATED CREEP RUPTURETEST


15/17

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.


16/17

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.


17/17

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.

metallurgical aspects of boiler tube failure

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