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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#6 Hydrogen Damages: Features
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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: Features
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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
Root Causes & Action to Confirm
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
Root Causes & Action to Confirm
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
Root Causes & Action to Confirm
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)
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,
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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Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,1991
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#9 Short Term Overheating: Mechanisms
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,
1991
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#9 Short Term Overheating: Mechanisms
Source: EPRI, Heat Recovery Steam Generator Tube Failure Manual , 2002
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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
Root Causes & Action to Confirm
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.
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,1991
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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
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,1991
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#10 Long Term Overheating - Features
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,1991
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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
Source: EPRI, Heat Recovery Steam Generator Tube Failure Manual , 2002
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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
Root Causes & Action to Confirm
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.
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,
1991
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Short Term vs Long Term Overheating
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc.,
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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Determine the Extend of Damage
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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Determine the Extend of Damage
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
Screen Analysis Fracture/Appearance
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Screen Analysis Fracture/Appearance
Screen Analysis Fracture/Appearance
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Screen Analysis Fracture/Appearance
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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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Determine the Extend of Damage
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!