E2. Boiler Tube Failure Part 2

8/10/2019 E2. Boiler Tube Failure Part 2

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#6 Hydrogen Damage

One of most disturbing tube failure mechanisms in HRSGand conventional boiler

Caused by the reaction of the iron carbide (FeC) in the tubemicrostructure with hydrogen from under deposit

corrosion process- which produces methane (CH 4) at thegrain boundaries of tube steel

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#6 Hydrogen Damages: Features

Thick EdgedBrittle final fractureOften window opening

Multi layered depositsMajor: magnetite

Microstructural decarburization

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Source: B. Dooley , PPChem101-Boiler and HRSG Tube Failure:Hydrogen Damage, PP Chem2010 , 12(2)


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Source: B. Dooley , PPChem101-Boiler and HRSG Tube Failure: Hydrogen Damage, PP Chem 2010 , 12(2)


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Source: B. Dooley , PPChem101-Boiler and HRSG Tube Failure: Hydrogen Damage, PP Chem 2010 , 12(2)


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#6 Hydrogen Damages: Mechanisms

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1. Excessive Deposition2. Acidic Contamination


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#6 Hydrogen Damages: Location

HP & IP Evaporator

Water flow is disruptedWelded joinInternal depositionThermal hydraulic flow disruption

- Local steam blanketingOverheating of the tube

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#6 Hydrogen Damages

Root Causes & Action to Confirm

Excessive depositsHigh iron in BFW and evaporator increasing potential for concentrationmechanism

- Condenser tube leaks where Cl and SO 4 enter the boilerSelective tube sampling

Flow disruptionSelective tube sampling

Gas side issueTube heat flux & temperature measurement

Influence of acidic contamination

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#6 Hydrogen Damages


Minor condenser leaks over an extended periodHigh cation conductivityHigh chloride and / or sulfates

Major condenser leaks one serious eventpH depression in Boiler

Water treatment plant upsetHigh cation conductivity

Errors in chemical cleaning process

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H2 Damages, Caustic Gouging & Acid PO 4 Corrosion

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Characteristic H 2 Damage Caustic Gouging Acid Phosphate

Corrosion

Features of Failure Gouged. thick

deposit Thick edged window opening

Gouged, thick

deposit Ductile, thinedged, pin hole

Gouged, thick

deposit Ductile, thinedged, pin hole

Deposit Metal oxide Rich in caustic Na-feroate , Na-

feroite

Acid PO4 2-3 distinct layer Maricite

Cycle Chemistry Source of low pHexist

Source of high pHexist

DSP, MSP, orNa:PO 4


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#7 Oxygen Pitting

Localized dissolution of metal.Relatively small amount of metal loss that initiate failurewith catastrophic results

Type of pitting in BoilerOxygen pittingPitting caused by improper chemical cleaningPitting caused by carry over of sodium sulfate

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#7 Oxygen Pitting: Features

Pit shape: broad, rounded

Pit distribution can be numerousor random

Corrosion product and depositare present primarily Fe 2O 3

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# 7 Oxygen Pitting: Features

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Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc., 1991


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#7 Oxygen Pitting: Mechanisms

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1. Moisture2. Oxygen

Source: EPRI, Heat Recovery Steam Generator Tube Failure Manual , 2002


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#7 Oxygen Pitting: Location

Prevalent in economizer

Any wet surface, especially no-drainablehorizontal surfaces

Poor lay-up procedures

Can be found in Superheater and reheatertubes where condensate collects in bends

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#7 Oxygen Pitting


Stagnant, oxygenated water with no protective environmentdue to improper layup

Review the procedureSelective tube samplingCorrosion product analysis

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#7 Oxygen Pitting Corrosion: Case History

Case History

Industry: Chemical processLocation: EconomizerOrientation: HorizontalPressure: 41 barTube metallurgy: Carbon steelTreatment Program: Polymer & O2 ScavTime in Service: 7 years

The reddish color & the presence of turbeclescapping iron oxide-filled pits is typical of exposureof steel to water containing excessively high levelof dissolved oxygen, Pitting & perforation ofeconomizer tubes was a recurrent problem at thisplant. Failures were occurring every 3 or 4 months.Excursions to high levels of oxygen was suspectedbut could not be documented. The boiler wasoperated continuously.

Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,

1991


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#8 Stress Corrosion Cracking

Metal failure resulting from asynergistic interaction of atensile stress and a specificcorrodent to which the metal issensitive

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#8 Stress Corrosion Cracking: Features

Thick-edged, brittle failure

May often involve the blow out of small window -typepieces

Little or no loss of wall thickness

CracksCan initiate either inside or outside surfacesCan be oriented circumferentially or longitudinallyMay have significant branching

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#8 Stress Corrosion Cracking - Features

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Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc., 1991


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#8 Stress Corrosion Cracking: Mechanisms

Can occur if 2 (two) conditions exist:

The existence of a critical system of material and corrosivemedium i.e., a specific corrosive medium must be presentfor a given material

The presence of tensile stressStatic tensile stressTensile stresses which increase over timeTensile stresses which change at a low frequency over time

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#8 Stress Corrosion Cracking: Mechanisms22

Source: H.G. Seipp, Damage in Water/Steam Cycle-Often Matter of Solubility, PP Chem 2005 (7)

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#8 Stress Corrosion Cracking: Mechanisms23

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Stress Corrosion Cracking:

Material & Corrodents

Austenitic Stainless Steel (300 series)ChloridesSodium hydroxide

Hydrogen sulfide

Carbon SteelSodium hydroxide

Copper-based Alloys Ammonia

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#8 Stress Corrosion Cracking: Location

Potential for the highest concentration of contaminantsCondensate can form during shutdown

High stress locationsBends, welds, tube attachment, supports, near weld, spacers; etcEspecially where a change in thickness occur

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#8 Stress Corrosion Cracking


Environmental EffectsChloride: Condenser in-leakage & chemical cleaningCaustic: Carry over

Stress EffectsResidual stresses: fabrication/welding/heat treatment/bendService stresses: especially at attachment & supports

Susceptible Material Effects

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#8 Stress Corrosion Cracking: Case History

Case History

Industry: PetrochemicalLocation: Superheater, first stageOrientation: VerticalPressure: 41 barTube metallurgy: 304 stainless steelTreatment Program: PhosphateTime in Service: 3 weeks

The original tubes were CS that cracked after 9months of service. SS tubes were specified toreplace CS. Moderate bends were put to relievethe thermal expansion and contraction stress thathad caused cracking in the CS tubes.SS failed because caustic stress corrosioncracking (lacked adequate devices for separationand load swings- carry over of ) boiler water. Inaddition , the bends provided high residual stress(no stress-reilef-annealed apply on the bend)


1991

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#9 Short Term Overheating

Occur when the tube metal temperatures are well abovethe design temperature for the tubing

In SH/RH tubing occur when the normal flow of coolingsteam is blocked or partially blocked

Excessive temperatures and subsequent tube failures canoccur in very short period of time

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#9 Short Term Overheating: Features

Thin-edged, ductile final failures

Longitudinal fish mouth or rupture

Tube bulging is often

Scale not necessarily thick or can be absentLocalized hardening near the rupture

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#9 Short Term Overheating - Features

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Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,1991

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#9 Short Term Overheating - Features

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#9 Short Term Overheating: Mechanisms


1991

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#9 Short Term Overheating: Mechanisms


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#9 Short Term Overheating: Location

Can occur in steam-cooled tubing (SH/RH) or the hottersections of the water cooled tubing (evaporator)

Susceptible locations:Tubing nearest to the gas inlet, especially down stream of supplementalburner (most common leading row SH)Tubing down steam of bends;etc- where potential blockage is exit

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#9 Short Term Overheating


Excessive gas temperatureVisual examination of flame patternOperating condition (gas temperature measurement; etc)Metallurgical analysis

Tube blockageOxide from exfoliation tube material, chemical cleaning and /or improperrepairVideoscope & metallurgical analysis to confirm

Start up with condensate filled tubesThermocouple measurementReview start up procedure


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#9 Short Term Overheating: Case History

Case History

Industry: UtilityLocation: Water wall, nose archOrientation: SlantedPressure: 124 barMaterial: Carbon steelTreatment Program: Coordinated Phosphate

Time in Service: 5 years

Rupture occurred shortly after start-up.Microstructural evidence indicated that the tubemetal near the rupture exceed 870 0C. Nosignificant thermally formed oxide was foundanywhere on the received section.The burst was caused by insufficient coolant flowon start-up.


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#10 Long Term Overheating

Occur when metal temperature exceed design limits fordays, weeks, months or longer

Because steel loses much strength at elevatedtemperature, rupture caused by normal internal pressure

becomes more likely as temperature rise


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#10 Long Term Overheating - Features


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#10 Long Term Overheating - Features


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#10 Long Term Overheating: Mechanisms

Thermal Oxidation (metal burning)Excessive if temperatures > certain value for each alloyCause crack and exfoliated patchesCyclic thermal oxidation & spalling resulting wall thinningProcess can continue until the entire wall is converted to oxide,

creating a hole

Creep RupturePlastic deformation during overheatingProduce thick-lipped rupture

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#10 Long Term Overheating : Mechanisms


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#10 Long Term Overheating: Location

Near the material changes just before the change to ahigher grade of material

Tubing nearest to the flue gas inlet, especially forsupplementary-fired units

Final leg of tubing just before the outlet header

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#10 Long Term Overheating


Excessive gas temperatureVisual examination of flame patternOperating condition (gas temperature measurement; etc)Metallurgical analysis

Tube blockageOxide from exfoliation tube material, chemical cleaning and /or improperrepairVideoscope & metallurgical analysis to confirm

Start up with condensate filled tubesThermocouple measurementReview start up procedure


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#10 Long Term Overheating: Example

Case History

Industry: Power PlantLocation: Primary SH InletPressure: 83 barOrientation: HorizontalTreatment Program: PhosphateTime in Service: 20 years

Creep rupture caused by prolong overheating attemper a ture above 570 0C. Coolant flowirregularities immediately downstream of a partiallycircumferential weld, along with internal deposition,which reduced heat transfer were contributingfactors. Additionally, a switch from oil to coal firing

likely changed fire-side heat input.

The superheater had a history of boiler watercarryover and load swing were common.


1991

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Short Term vs Long Term Overheating


1991

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#11 Exfoliation: Location

Superheater and Reheater Tubes

Results of long term overheating of tubes

Significant impact is the type and quality of the tube metal

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#11 Exfoliation: Results

Exfoliated particles will collect in bends and can causeblockage of tubes

Excessive exfoliation can result in particulate erosion ofturbine components, especially the nozzle block

May result in impacting the following:Plant availability

EPRI R d M f A l i BTF


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EPRI: Road Map for Analyzing BTF

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Determine the Extend of Damage

Failure Mechanisms Recommended TestCorrosion Fatigue Ultrasonic Testing UT)

Selective Tube Sampling

Thermal/Mechanical Fatigue Fluorescence magnetic partcleexamination (WFMT) or Fluorescencepenetrant (WFPT)Thermal stress analysis

Deposit Selective tube samplingDeposit Weight Density (DWD)

FAC Ultrasonic Testing (UT)

H2 Damage, Caustic & AcidPhosphate Corrosion Ultrasonic Testing (UT)Selective Tube SamplingBoroscopePressure Test after chemical cleaning

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Failure Mechanisms Recommended TestStress Corrosion Cracking Fluorescence magnetic particle

examination (WFMT) or Fluorescencepenetrant (WFPT)Thermal stress analysis

Short & long term overheating RadiographyTube removalTube diameter measurement (wallthickness)

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Nalco SEARecent Case of Boiler Tube Failure

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Case #1: HRSG Tube Failure

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Case #1: Plant Data

Combined Cycle Power Plant, 110 MW Thailand

HRSG, Multiple Pressure (HP:62 bar, LP: 5 bar), Capacity:67 tons/hr (HP), 11 tons/hr (LP)

Condensing steam turbine

Surface condenser with admiralty tubes and Cu:Ni=90:10for air removal section

Boiler make-up: demineralized water from mixed bed

Condensate polisher: no


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Two HRSG HP

Evaporator - tube failure in1 week!


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Important EventsNovember 2010 : Condenser in-leakage has identifiedand confirmed

May 23-25, 2011 : Major ingress due to condenser in-leakage become bigger

May 28-29, 2011 : Plant shutdown. Plugged leak tubesin condenser. Drum inspection

May 30, 2011 : Plant is running back

Sept 8 22, 2011 : Major schedule shutdown. Druminspection

Sept 18, 2011 : Tube failure of HP evaporator section.

Sept 22-23, 2011 : Unscheduled plant shutdown due toHRSG tube failure.of HP Evap

Sept 25, 2011 : Plant is running back


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Deposit Sampling Analysis Result

Elements/

Compounds

Steam Drum

May 11

Steam Drum

Sept 11

HP Evap-Sept11

(Sample #1)

HP Evap-Sept11

(Sample #2)Iron (Fe2O3) 33 wt% 22 wt% 50 wt% 90 wt%Copper (CuO) 12 wt% 8 wt% 15 wt% -Phosporus (P2O5) 23 wt% 32 wt% 14 wt% 3 wt%Calcium (CaO) 15 wt% 26 wt% 8 wt% 2 wt%Magnesium (MgO) 8 wt% 6 wt% 5 wt% 1 wt%

Sulfur (SO3) 2wt% - 2 wt% -Silicon (SiO2) 4 wt% 1 wt% 1 wt% -Zinc (Zn) 1 wt% 1 wt% 1 wt% -Carbonate (CO2)


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Screen Analysis Fracture/Appearance

Excessive/thick deposit

Metal lossunderdeposit

RectangularWindow

No tubebulging

Thick edge


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Metal lossunderdeposit

RectangularWindow

Thick edge


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Determine the Root CauseMajor Root Cause Influences Confirmation Remarks

Influence of excessive deposits Yes. Deposit in steam drum (boiler inspectionMay and September 2011)

Heavy deposition in sampling tube(September 2011)

Flow disruption: deposits, DNB, bend/sharpchanges in tube direction, locally high heattransfer; etc

Yes Flow disruption only influenced bydeposition

Influence of acidic contamination Yes. pH of boiler dropped to ~8.5 on May 2011Condenser leaks minor but occurring overan extend period

Yes. Condenser leaks occurred November 2010 May 2011

Condenser leaks major ingress, generallyone serious event

Yes.May 2011

pH of boiler dropped to ~8.5 Hardness in condensate went up >0.5

ppm Chloride concentration in HP evaporator

went up > 10 ppmWater treatment plant up set leading tolow pH condition

No.

Errors in chemical cleaning process No. No chemical cleaning conducted on 2010-2011.


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Root Cause

Condenser in-leakageIncrease chloride and sulfate level in BFW and boiler waterIntroduce hardness salts into BFWIntroduce O2 into condensate and BFW

DepositionHardnessIronCopperPhosphate


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Ultrasonic test not applicable for finned tube

Visual inspection by using fiber optic (boroscope/videoscope) - not applicable

Selective tube sampling ?Chemical cleaning & pressure test ?


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Immediate Solution

Isolate the condenser and plug all the leaking tubesand tubes with high depth wastage. Ensure there isno cooling water in-leakage by checking condensatequality (cation conductivity, hardness, chloride; etc)

Selective tube sampling for deposit measurement.Inspection using fibre optic (boroscope) can provideuseful information

Tube replacement for all tubing with hydrogendamage and/or significant wall loss be replaced

Check the efficacy of chemical cleaning


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Long Term Solution

Chemical cleaningProper chemical cleaning method/procedure.

Pressure test 1.5x than normal operating pressure

Replace all tube failed in pressure test

Improving integrity of surface condenser

Install on-line instrumentation to improve condenserleakage detection capability & control

Develop specific cycle chemistry targets, actionlevels and shutdown policies to maintain HRSGcleanliness.

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Case #2: Coal Fired Boiler Tube Failure (BTF)

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Case #2: Plant Data

Cogeneration Plant (Coal Fired) for Paper Mill

3x35 MW + 1x65 MW Indonesia

Boiler #6, 300 tons/hr, 100 bar

Condensing steam turbine

Surface condenser with admiralty tubes

Boiler make-up: demineralized water from mixed bed

Condensate polisher: yes, for process condensate


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Case #2:Important Events

July 2011 : Change boiler chemical treatmentprogram

July December 2011 :Total iron in BFW > 10 ppb

15th

December 2011 : Low pH Boiler water (~ 5.7)18 th December 2011 : 1 st boiler tube failure (water wall)

24 th December 2011 : 2 nd boiler tube failure (water wall)

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Screen Analysis: Location

Location of BTF:

Water Wall

Radiant heat transfer infront of buner

Highest temperature areas


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Deposit Sampling Analysis Result



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M t ll i l A l i R lt73


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Metallurgical Analysis Result

(~3 weeks after the incident)

C fi h R C


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Confirm the Root Cause

Major Root Cause Influences Confirmation Remarks

Influence of excessive deposits Yes. Deposit in steam drum (Boilerinspection)

Deposition in sampling tube High iron in BFW (>10 ppb)

Flow disruption: deposits, DNB, bend/sharpchanges in tube direction, locally high heat

transfer; etc

Yes Flow disruption only influenced bydeposition

Influence of acidic contamination Yes. pH of Boiler dropped to


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Selective tube samplingChemical cleaning followed by boiler pressure test (1.5xthan normal operation pressure)

I di t S l ti


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Immediate Solution

Conducting proper chemical cleaning1,8 tons of iron has removed from the boiler during cleaningDWD test after cleaning = clean

Followed by boiler pressure test (1.5x than normal)Some tubes were failed during pressure test

Replacing all the tubes with significant metal losses

Long Term Solution


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Long Term Solution

Minimize deposit build up on boiler tubes by ensuringminimum corrosion product formation in BFW and transportinto the boiler

Total Iron < 10 ppb (ASME), EPRI < 2 ppbTotal copper < 10 ppb (ASME), EPRI < 2 ppb

Use adequate chemistry related instrumentation andinstallation

Preventing acidic contamination into the boiler system

Preventing upset of the water treatment plant- UF-RO-Ion Exchange for all boilers to minimize TOC intrusion- Use appropriate on-line instrumentation to monitor performance of plant

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THANK YOU!

Documents

E2. Boiler Tube Failure Part 2