fired heaters and boilers inspection

7/28/2019 Fired Heaters and Boilers Inspection

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N. Al-Khirdaji, AZTech Sr. Consultant

3.2 Fired Boilers and heaters

Inspection Advanced Inspection

API 573 Inspection of fired heaters and boilers

u e nes or e nspec on o

installed fired heaters

FTIS Furnace tube inspection system (Quest TuTec)

Pressure Systems RiskRISK

Probability of failure consequence of failure

Susceptibilityfactor

Severityfactor

Internal corrosionExternal corrosion

FatigueStress Corrosion Cracking

Third party damageSabotage/pilferage

Loss of ground support

Risk to lifeDamage to asset

Loss of productionCost of failure

Environmental effectsPublic image


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Boiler Inspection

A boiler inspector is a professionally trained and

examination of boilers.

While every boiler should be professionally inspectedannually, there is more than one type of inspectionmade by an inspector.

Jurisdictions and insurance companies recommend that,

externally, while not under pressure.

An external inspection while the boiler is under pressure issuggested midway between the annual inspections.

Boiler Inspection

An internal boiler inspection consists of all watersideareas of the vessel steam, blow-off, and waterconnections), and fireside conditions, as well asdearators, superheaters, and economizers.

While evidence of internal corrosion and scale, leaks,overheating, and flame impingement are noted anddocumented in the boiler inspector's report, the rootcause may require additional resources.

ot t e owner operator an t e water treatment consu tantare this resource, playing an active role at this inspection,and in any subsequent adjustments made tot he boilermanagement program.


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UT Inspection of Boiler Tubes

EMAT Guided WaveBoiler, Heater &Furnace Tube Applications

100% High Speed Flaw Detection in Tubes

Chromium Depletion Detection

Tube Imbrittlement Detection

Corrosion Detection caused by Flame

Impingement

U-Bend Inspection for Corrosion and Wall loss


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Inspection and Assessment of Critical

Boiler Components Steam Drum Assessment: Inspection and testing focuses on detecting

.

The preferred nondestructive examination (NDE) method iswet fluorescent magnetic particle testing (WFMT). BecauseWFMT uses fluorescent particles that are examined underultraviolet light, it is more sensitive than dry powder typemagnetic particle testing (MT) and it is faster than liquid dyepenetrant testing (PT) methods.

WFMT should include the ma or welds selected attachmentwelds, and at least some of the ligaments.

If locations of corrosion are found, then ultrasonic thicknesstesting (UT) may be performed to assess thinning due to metalloss.

In rare instances, metallographic replication may be performed


Boiler Components Headers Boilers designed for temperatures above 900F (482C) can

have superheater outlet headers that are subject to creep thep as c e orma on s ra n o e ea er rom ong- ermexposure to temperature and stress.

For high-temperature headers, tests can include metallographicreplication and ultrasonic angle beam shear wave inspectionsof higher stress weld locations.

Industrial boilers are more typically designed for temperaturesless that 900F (482C) thus failure is not normally related to

.

Lower temperature headers are subject to corrosion or possibleerosion.

Additionally, cycles of thermal expansion and mechanicalloading may lead to fatigue damage.


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Boiler Components Headers Assessment: The nondestructive examination (NDE) methodshould include testing of the welds by magnetic particle testing(MT) or by wet fluorescent magnetic particle testing (WFMT).

In addition, it is advisable to perform internal inspection with avideo probe to assess waterside cleanliness, to note anybuildup of deposits or maintenance debris that could obstructflow, and to determine if corrosion is a problem.

Inspected headers should include some of the water circuit.

If a location of corrosion is seen, then ultrasonic thickness

testing (UT) to quantify remaining wall thickness is advisable.


Boiler Components Tubing By far, the greatest number of forced outages in all types of

boilers are caused by tube failures.

Failure mechanisms vary greatly from long term to short term.

Superheater tubes operating at sufficient temperature can faillong term (over many years) due to normal life expenditure.For these tubes with predicted finite life, the NOTIS test andremaining life analysis software (Babcock & Wilcox) wouldbe useful.

Most tubes in the industrial boiler do not have a finite life due

o e r empera ure o opera on un er norma con ons. Tubes are more likely to fail because of abnormal deterioration

such as water/steam-side deposition retarding heat transfer,flow obstructions, tube corrosion [inside diameter (ID) and/oroutside diameter (OD)], fatigue, and tube erosion.


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Boiler Components Tubing Assessment: Tubing is one of the components where visual examination isof great importance because many tube damage mechanisms lead to visual

, , , .

The primary nondestructive examination (NDE) method for obtaining dataused in tube assessment is contact ultrasonic thickness testing (UTT) fortube thickness measurements. Contact UTT is done on accessible tubesurfaces by placing the ultrasonic transducer onto the tube using a couplant,a gel or fluid that transmits from the ultrasonic transducer sound into thetube. Variations on standard contact UTT have been developed due toaccess limitations. Examples include:

Internal rotating inspection system (IRIS)-based techniques in which

rotating mirror to scan tubes from the IDespecially in the areaadjacent to drums.

Laser-Optic Tube Inspection System (LOTIS) technology is capable ofvery accurately mapping and quantifying internal tube damages such asPitting, Corrosion, Erosion, Open Surface Cracking, Bulging, Denting,etc.


Boiler Components Piping Main Steam For lower temperature systems, the piping is subject

to the same damage as noted for the boiler headers.,

become damaged from excessive or cyclical system loads.

Assessment: The nondestructive examination (NDE) method ofchoice for testing of external weld surfaces is wet flourescentmagnetic particle testing (WFMT). Magnetic particle testing (MT)and penetrant testing (PT) methods are sometimes used if lighting orpipe geometry make WFMT impractical.

Non-drainable sections, such as sagging horizontal runs, are subject

.internal video probe and/or ultrasonic thickness testing (UTT)measurements.

Volumetric inspection (i.e., ultrasonic shear wave) of selectedpiping welds may be included in the NDE. However, concerns forweld integrity related to the growth of subsurface cracks is aproblem associated with creep of high temperature piping and is nota concern on most industrial installations.


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Boiler Components Piping Feedwater A piping system often overlooked is feedwater piping.Depending upon the operating parameters of the feedwater system,

, ,corrosion or flow assisted corrosion (FAC). This is also referred toas erosion-corrosion. If susceptible, the pipe may experiencematerial loss from internal surfaces near bends, pumps, injectionpoints, and flow transitions.

Ingress of air into the system can lead to corrosion and pitting.

Out-of-service corrosion can occur if the boiler is idle for longperiods.

ssessmen : nterna v sua nspect on w t a v eo pro e srecommended if access allows. NDE can include MT, PT, or

WFMT at selected welds. UTT should be done in any locationwhere FAC is suspected to ensure there is not significant piping wallloss


Boiler Components Deaerators

Overlooked for many years in condition assessment,

have been known to fail catastrophically in bothindustrial and utility plants.The damage mechanism is corrosion of shell welds,which occurs on the inside diameter (ID) surfaces.

Assessment: Deaerators welds should have a

. All internal welds and selected external attachment

welds should be tested by wet fluorescent magneticparticle testing (WFMT).


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Boiler Inspection/Maintenance Checklist

Description CommentMaintenance Frequency

Daily Weekly Monthly Annually

inspection

equipment is operating and that safety systems are

in place.

X

Check

lubricating all

components

Compare temperatures with tests performed after

annual cleaning. X

Check steam

pressure

Is the variation in steam pressure as expected under

different loads? Wet steam may be produced if the

pressure drops too fast.

X

Check unstable

water level

Unstable levels can be a sign of contaminates in

feedwater, overloading of boiler, or equipment X

.

Check burner Check for proper control and cleanliness. X

Check motor

Conditiontemperatures

Check for proper function.

X

Check oi l fi lters Check and clean/replace oil f il ters and s trainersX

Boiler blowdown Verify the bottom, surface and water column blow

downs are occurring and are effective. X



Dail Weekl Monthl Annuall

Check all relief valves Check for leaks. X

Check water level

control

Stop feedwater pump and allow control to stop fuel flow

to burner. Do not allow water level to drop below

recommended level.

X

Check pilot and

Burner assemblies

Clean pilot and burner following manufacturer's

guidelines. Examine for mineral or corrosion buildup.X

Check boiler

Operating

characteristics

Stop fuel flow and observe

flame failure. Start boiler and observe

characteristics of flame.

X

Inspect system Look for: leaks, defective valves and traps, corroded

for water or steamleaks

piping, and condition of insulation. X

Inspect all linkages

on combustion air

dampers and fuel

valves

Check for proper setting and t ightness.

X

Inspect boiler for

air leaks

Check damper seals.X


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Description Comment

Maintenance Frequency


Flue gases Measure and compare last months readings for flue gas

composition over entire firing range.X

air supply

to make sure openings are adequate and clean.X

Check fuel

system

Check pressure gauge, pumps, filters and t ransfer

lines. Clean filters as required.X

Check belts

and packing

glands

Check belts for proper tension. Check packing

glands for compression leakage. X

Check for air

leaks

Check for air leaks around access openings and

flame scanner assembly.X

Check all

blower belts

Check for tightness and minimum sl ippage.X

Check all gaskets Check gaskets for tight sealing. Replace if they do

not provide a tight seal.X

Inspect boiler

insulation

Inspect all boiler insulation and casings for hot spotsX

Steam control

valves

Calibrate steam control valves as specified by

manufacturer.X

Pressure

reducing or

regulating valves

Check for proper operation.

X




Clean waterside

surfaces

Follow manufacturer's recommendation on cleaning

and preparing waterside surfaces.X

Cl ean Fol low manufact urer's recommendat ion on cleani ng

fireside and preparing fireside surfaces.

Inspect & Repair

Refractories

on fireside

Use recommended material and procedures.

X

Relief valve Remove and recondition or replace relief valves. X

Feedwater

system

Clean and recondition feedwater pumps. Clean

condensate receivers and deaeration system.X

Fuel system Clean and recondi tion system pumps, fi lters, pilot , oi l

preheaters, oil storage tanks, and other system

components.

X

Electricalsystems Clean all electrical t erminals. Check electroniccontrols and replace any defective parts. X

Hydraulic And

Pneumatic

valves

Check operation and repair as necessary.

X

Flue gases Make adjus tment s t o ensure opt imal fl ue gas

composition.

Record composition, firing position, and temperature.

X

Eddy

current test

As required, conduct eddy current test to assess tube

wall thickness.X


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Material Aging and Degradation

Materials aging and degradation typically increaseas a function of increasing temperature and time inservice.

As essential equipment ages, the plant operatorand owner must determine if they can continue tooperate it safely and reliably to avoid injuries to

plant personnel and to the public, damage to theenvironment and business losses.

Fitness for service assessment can be used to

evaluate equipment and piping systems, and makedecisions based on sound, established engineering

principles.

Material Degradation Mechanisms Material degradation mechanisms include:

General corrosion,

Loca ze corros on,

Erosion-corrosion (conjoint corrosion).

Pitting and crevice corrosion,

Hydrogen attack,

Embrittlement,

Stress corrosion cracking,

, High-temperature creep, and

Mechanical distortion.

These degradation mechanisms affect mechanicalintegrity


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Deterioration / Degradation

Macroscopic damage such as dents or gouges,

u g ng, e orma on.

General or localized wall thinning and pitting.

Material flaws, cracks, and welding defects.

Degradation of material properties due to

c anges n e ma er a m cros ruc ure.

Corrosion -1 Corrosion is caused by electro-chemical processes

in which a metal reacts with its environment toform an oxide or compound by the formation ofcells comprising:

an anode (the deteriorating metal),

a cathode (adjacent metal),

a conducting solution (acid / salts).

It can occur both internally and externally topipelines, vessels, plant, machinery, structures andsupports.


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Corrosion - 2

The materials selection philosophy aspect of thedesign phase of all plant and structures should takeinto account the:

anticipated service conditions (pressure,temperature and atmosphere), and

the contents of the system in order to eitherminimize corrosion or to make adequateallowances for it in the form of additional

.

The initial corrosion on some metals creates animpervious coating which prevents furthercorrosion taking place.

General Corrosion

Corrosion or degradation of material exposed to

the air and its pollutants rather than immersed in aAtmospheric

Corrosion of metals generally over the entireGeneral

Caused by an externally induced electrical currentStray-

current

Corrosion that occurs when a metal or alloy is

electrically coupled to another metal or

conducting non-metal in the same electrolyte

Galvanic

liquid

General/Uniform

Corrosion: Corrosive

attack dominated by

uniform thinning due to

even regular loss of metal

from the corrosion

surface.

Other forms

Carburization

Sulfidation Corrosion by direct reaction of

exposed metals to oxidizing

agents at elevated temperatures

Oxidation

High-

temperature

Corrosion of metals due to molten or fused saltsMolten salt

The predominant standardutilized for general

corrosion assessment is

ASTM G31


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Localized Corrosion

Occurs on metallic surfaces coated with thin

Extremely localized corrosion marked by thePitting

Corrosion in narrow openings or spaces in metal to

metal or non-metal to metal component sitesCrevice

organ c m, yp ca y . mm c ,

characterized by the appearance of fine

filaments in semi-random directions from one

or more sources

Filiform

Localized Corrosion: all

or most of the metal

loss occurs at discrete

Cases where biological organisms are the sole causeor an accelerating factor in the localized

corrosion

Localizemicro

biological

Environmentally Influenced Corrosion

Occurs when the corrosion rate of the grain

boundary areas of an alloy exceeds that of

the grain interiors

Intergranular

Metallurgically influenced

corrosion: form of

attack where metallurgy

plays a significant role

A form of corrosion characterized by thepreferential removal of one constituent of

an alloy leaving behind an altered residual

structure

Dealloying


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Mechanically Assisted Degradation

Removal of surface material by the action of

Occurs on a metal surface in contact with a

Combined wear and corrosion between

contacting surfaces when motion between

the surfaces is restricted to very small

amplitude oscillations

Fretting

numerous individual impacts of solid or

liquid particles

Erosion

Mechanically assisted

degradation: form of

attack where velocity,

abrasion,

Occurs in metals as a result of the combined

action of a cyclic stress and a corrosive

environment

Fatigue

qu , pressure erent a s generate gas or

vapor bubbles which upon encountering

high-pressure zones, collapse and causeexplosive shocks to the surface

av tat on

Water drop

impingement

hydrodynamics etc.

play a major role

Environmentally Induced Cracking

Service failures in engineering materials that

Brittle failure of a normally ductile metal

when coated with a thin film of a liquid

metaland subse uentl stressed in

Liquid metal

embrittlement

Results from the combined action of

hydrogen and residual or tensile stress

Hydrogen

damage

occur by slow environmentally induced

crack propagation

Stress cracking

Environmentally induced

cracking: forms of

cracking that are

produced in the presence

of stress.

occurs below the melting point of the solid in

certain liquid metal embrittlement

couples

Solid metal

embrittlement

tension(Stress Corrosion Cracking)


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Corrosion of Membrane Tubes

Crevice Corrosion

occurs within crevices and other shieldedareas on metal surfaces exposed tocorrosives.

This type of attack is usually associated

caused by holes, gasket surfaces, lap joints,surface deposits, and crevices under boltand rivet heads.


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Crevice Corrosion Example

Gasket (crevice) corrosion on a large stainless steel pipe flange.

Erosion-Corrosion

the presence of a moving corrosive fluid, leading to

the accelerated loss of material.

Flow velocity is an important

environmental factor. Its effect

is especially pronounced in

chemical processing, petroleum,

marine, and power plants, which

handle fluids of all kinds.


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Erosion-corrosion

This form of corrosion is deterioration of metal caused

electrochemical attack.

Erosion is caused by relative motion between the

corrosive processing medium and the metal surface.

The electrochemical attack is caused by the surface

- -

vis the corrosive fluid.

The protective film on the metal surface is swept

away by rapid movement of the processing fluid.

Erosion-corrosion

In Power Plant Piping Major failures have occurred in piping due to single-

- - .

Significant variables include: temperature of water or

steam, pH, oxygen content of fluid, quality of steam,

flow velocity, quality of oxide layer on inner surface

of the pipe, chemical composition of the steel pipe.

-water, elbows, tees, etc., in wet steam.


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Erosion-corrosion

In Power Plant Piping - 2Factors mitigating erosion-corrosion:

pH (>9.0 is best),

Oxygen content (50 ppb),

Piping design/layout changes to improve flowgeometries.

-.resistant to single-phase erosion-corrosion

while austenitics are resistant to wet steam).

Erosion Failure of Superheater TubeThe fish-mouth type rupture occurred after 15 years of service.

1) Visual Examination

The preliminary visual examination revealed a distinct ridge or

of the bend near the tangent point and

on the side opposite from direction of

gas flow.

step, which had been sculpted into the tubing wall. This ridgeis physical evidence of the effects of erosion.

2) Dimensional Analysis

Wall thickness measurements indicated that there had been almost no wall loss a short

distance away from the rupture. In contrast, wall thickness measurements taken in the

immediate vicinity of the rupture revealed significant and highly localized wastage

corresponding to a 91% loss of original wall thickness.


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Susceptibility of Stainless Steels to

SCC Copson CurveNot all stainless steels are equally

susceptible to SCC.

Copson determined that a direct

relationship exists between the time to

failure and the nickel content.

The stainless steel nickel content with

the most potential is 8%, which is the

same content of the workhorse of the

, .

Improvements in time to failure come

from selecting an alloy with very lownickel, such as TP 439, or very high

nickel, such as the 6% molybdenum

containing alloys or alloy 20. The high

nickel alternative can be very expensive.

Critical Crevice Temperature and Maximum Chloride

Levels Versus PREN of Various Stainless Steels

Crevice corrosion is commonly

measured by the ASTM G 48 test.

A hi her CCT indicates more corrosion

resistance

Kovach and Redmond developed

relationships between the PREN and

the G 48 critical crevice temperature

(CCT) and plotted the relationships.

This Figure is a modified version to be

used as a tool for comparing alloys and

determining maximum chloride levels


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Fatigue

Fatigue only takes place if the load is alternating.

,

alternating stresses can be registered:

1. Mechanical stresses due to change in pressure or to

changing system stresses.

2. Thermal stresses due to temperature differences through

the component wall thickness. These stresses become only

significant when the wall thickness is larger than 45 mm.

3. Stratification due to temperature differences on twoopposite spots on the component.

Creep Failure Bulged TubesBoiler superheater and firedheater tubes frequently fail

,combination of the two.Other failure modes includeerosion-corrosion, metaldusting, vibration, and locallife-limiting conditions such

,scale/coke build-up, etc.

Tube swelling is evidencethat significant consumptionof creep life has taken place.


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Creep Rupture of Superheater TubeThe failed superheater tubing contained a relatively thick-lipped, fish-mouth typerupture. The rupture was located on the hot side of the tubing, adjacent to a butt

weld. The tubing from which the sample was taken was specified to be 2.125" OD x

"

Based on the results of the destructive examination, it was established that the SH

tube had failed due to the effects of advanced creep-rupture damage, which was the

result of long-term overheating.

. , - , - .

The SH tube also contained a circumferential fracture that had resulted in the

complete separation of the tubing at the location of the tube-to-tube butt weld.

However, the results of the destructive examination demonstrated that this fracture

was the result of consequential damage and was not the primary failure site.

Creep Rupture of Superheater Tube

Key Findings of Analysis:1. As with some of the previous overheating failures, there were

longitudinal grooves running adjacent to and parallel with the rupture.These grooves were determined to be the secondary effects of creeprupture damage.

2. Examination of the inner surface revealed a relatively thick layer ofpartially exfoliated steamside scale along both sides of the element,with evidence of longitudinal grooving within the scale layer. Thisgrooving resulted when the steamside scale fractured as the tubingswelled.

3. Measurements of the outer diameter and inner diameter indicated thatthere had been a significant amount of swelling, both at a locationimmediately adjacent to the rupture and at a location far removed fromthe rupture. The tubing near the rupture had swelled approximately3%, while the tubing far removed from the rupture had swelledapproximately 2%.


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Idealized Creep Curve and Corresponding

Microstructural Damage

Stress Corrosion CrackingStress corrosion cracking (SCC) is the formation of brittle

cracks in a normally sound material through the simultaneous

Three factors must be present simultaneously for SCC to occur.

StressMaterial

ac on o a ens e s ress an a oca ze corros ve env ronmen

Examples include:

Steel: SCC in caustic (high

Environment

SCC, .

SS and Al alloys: SCC insolutions containing chlorides.

Ti-alloys: SCC in nitric acidor methanol.Corroding media;

Temperature


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Stress Corrosion Cracking

The three components necessary for stress-corrosion cracking

1. susceptible material,

2. contaminant to which the subject material is vulnerable and,

3. a tensile stress.

Stress Corrosion Cracking (SCC)

Transgranular Cracking in TP

304N Feedwater Heater Tubing


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With regard to possible contaminants, either caustics orchlorides can produce cracking with the microstructuralea ures o serve n e a e s a n ess u e. oug

chloride-induced SCC is common in stainless steelcomponents, caustic SCC can occur over a substantiallybroader range of temperatures and should not be dismissedwithout careful consideration of all possible sources ofcontamination.

Even a relatively small amount of a caustic, such as sodium, inthe ori inal source water can be a ressive when concentrated.

With regard to the tensile stress component of the damage,possible sources of stress include local residual stressesassociated with tube manufacturing (i.e. rotary straightening ofthe tube), bending, or with welding (i.e. welded attachments).


If one tube fails due to SCC it is very likely, given the natureof the damage, that a number of tubes will have been affected.

If the unit is returned to service before all significant damageis identified, then failures will continue to occur.

Therefore, tubing should be inspected using the appropriateNDE techniques to detect badly cracked tubes forreplacement.

poss e sources o contam nat on s ou e rev ewein an effort to identify the contaminant and to determinehow the contaminant entered the damaged area so that therisk of similar problems can be eliminated during futureoperation.


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Flow Accelerated Corrosion (FAC) FAC is a chemical/corrosion process involving the dissolution

of the protective oxide layer along the ID surface of a

componen .

The partial or complete removal of the protective oxide results

in a rapid thinning of the component wall, until eventually the

remaining wall thickness is insufficient to contain the internal

pressure and rupture occurs.

The FAC failure shown in the photograph

occurred in an economizer nipple tube.

Flow Accelerated Corrosion (FAC)

FAC typically occurs in the temperature range of , ,

mostly commonly found in economizer tubing, lowpressure evaporator tubing, and drum internals.

In addition, the propensity for forming FAC damageis greater in areas of high turbulence, such as would

be found at a nipple connection.

n ncrease n ur u ence resu s n an ncrease n e masstransport of ferrous ions away from the oxide/fluidinterface, which increases the diffusion gradient.

This results in a more rapid rate of diffusion of ionsthrough the oxide layer and into the flowing fluid.


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1. The key evidence indicating single phase FAC as the cause of the failure was a

series of overlapping elongated pits.

This type of pitting often is referred to as horseshoe-shaped pitting.

The obvious orientation to the pitting is a reflection of the influence of the fluid

flow on the pattern of ID attack.

2. Aside from the evidence of FAC, there was no indication of any other damage

mode. Specifically, there was no evidence of a shallow cold worked layer along the

ID surface of the tube, indicating that the wastage was not due to erosion-corrosion,

in which particle impact is responsible for the removal of the protective oxide film.


Modifications addressing temperature and/or turbulencetypically are not feasible and, therefore, the primary approachto solving problems with FAC is to address the issue of waterchemistry.

The feedwater pH must be carefully controlled and, if possible,oxygen scavengers such as hydrazine should not be employed.

If changing the water chemistry is not an option, then anotherapproach might be to use tubing materials that are more

.

Steels with a higher level of residual chromium and/ormolybdenum (e.g. SA-213, T11) tend to form a more protectiveoxide layer and, therefore, often are highly resistant to attack byFAC.


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Short Term Elevated Temperature

Tensile StrengthFor all materials used in boiler construction, the strength decreases as

tem erature increases. This Table lists the short-term tensile stren th for

Test Temperature, oFTensile Strength, psi

SA192 SA213 TP321H

80 55,000 84,000

300 59,000 68,000

500 59 500 62 500

SA192 and SA213 TP321H that illustrates this point.

700 52,600 60,000

900 41,000 56,000

1100 20,000 49,300

1300 9,900 38,000

1500 5,600 23,000

Short Term Overheating Failures

The simplest explanation for all "short-term"

when the tube metal temperature rises so that the hoopstress from the internal steam pressure equals the tensilestrength at elevated temperature, rupture occurs.

For example, in a super-heater of SA192 tubes, with adesigned metal temperature of 800oF, theASME Boiler andPressure Vessel Code gives the allowable stress at 800oF as

9,000 psi. If the tube-metal temperature should rise to atemperature of around 1300oF, the hoop stress would beequal to or slightly greater than the tensile strength at1300oF, and failure would occur in a few minutes.


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The balance between heat flow and fluid flow can be upsetfrom either side; too much heat flow or too little fluid flow.

In a waterwall tube, steam forms as discrete bubbles, nucleateboiling. When the bubble is large enough, the bubble is swept away by the

moving fluid, and the cycle repeats.

At too high a heat flux or too low a fluid flow, steam-bubble formationis too fast for removal by the moving fluid. Several bubbles join toform a steam blanket, a departure from nucleate boiling, DNB. Heattrans er t roug t e steam an et s poor steam s an exce entinsulator) and tube-metal temperatures rapidly rise and failure occurs

quickly. In a superheater or reheater, DNB cannot occur as only steam

super heating takes place, no boiling. However, short-termoverheating failures do occur but usually during start-up.


Boiler operational problems that can lead to these short-termhigh-temperature failures include, among others:1. Flame impingement from misaligned or worn burners that leads to the

formation of a steam blanket, as the local heat flux is too great for thefluid flow through the tube.

2. Blockage of a superheater tube with condensate or foreign materialthat prevents steam flow. These problems are more frequent duringstart-up.

3. Reduced flow in either a water or steam circuit that leads to inadequate. , ,

dents from slag falls or ruptured tubes, and partial blockage fromdebris or other foreign matter are some of the more obvious causes.

4. Foreign objects, broken attemperation- spray nozzles, for example, inheaders that partially block a superheater or reheater tube.


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Regardless of the location within the boiler that these failuresoccur, the appearance is similar.

There is a wide-open burst with the failure edge drawn to a nearknife-edge condition, and

the length of the opening four or five tube diameters.

These failures display considerable ductility; the thinning at thefailure lip may be more than 90% of the original wall at theinstant of rupture.

indicate the peak temperature at the time of failure.

For ferritic steels there is a transformation from ferrite and ironcarbide or pearlite, to ferrite and austenite. This temperature isreferred to as the lower-critical transformation temperature andoccurs at 1340oF or higher, depending on the exact alloycomposition.

Boiler Tube Corrosion MechanismsExample

fired heaters and boilers inspection

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