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#6 Hydrogen Damage
One of most disturbing tube failure mechanisms in HRSG and conventional boiler
Caused by the reaction of the iron carbide (FeC) in the tube microstructure with hydrogen – from under deposit corrosion process- which produces methane (CH4) at the grain boundaries of tube steel
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#6 Hydrogen Damages: Features
Thick Edged Brittle final fracture Often “window” opening
Multi layered deposits Major: magnetite
Microstructural decarburization
Source: B. Dooley, PPChem101Boiler and HRSG Tube Failure: Hydrogen Damage, PP Chem 2010 , 12(2)
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#6 Hydrogen Damages: Features
Source: B. Dooley, PPChem101-Boiler and HRSG Tube Failure: Hydrogen Damage, PP Chem 2010 , 12(2)
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#6 Hydrogen Damages: Features
Source: B. Dooley, PPChem101-Boiler and HRSG Tube Failure: Hydrogen Damage, PP Chem 2010 , 12(2)
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#6 Hydrogen Damages: Mechanisms
1. Excessive Deposition 2. Acidic Contamination
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#6 Hydrogen Damages: Location
HP & IP Evaporator
Water flow is disrupted Welded join Internal deposition Thermal hydraulic flow disruption - Local steam blanketing
Overheating of the tube
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#6 Hydrogen Damages Root Causes & Action to Confirm
Excessive deposits High iron in BFW and evaporator – increasing potential for concentration mechanism - Condenser tube leaks where Cl and SO4 enter the boiler
Selective tube sampling
Flow disruption Selective tube sampling
Gas side issue Tube 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 period High cation conductivity High chloride and / or sulfates
Major condenser leaks – one serious event pH depression in Boiler
Water treatment plant upset High cation conductivity
Errors in chemical cleaning process
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H2 Damages, Caustic Gouging & Acid PO4 Corrosion Characteristic
H2 Damage
Features of Failure • Gouged. thick deposit • Thick edged window opening
Caustic Gouging
Acid Phosphate Corrosion
• Gouged, thick deposit • Ductile, thin edged, pin hole
• Gouged, thick deposit • Ductile, thin edged, pin hole
Deposit
• Metal oxide
• Rich in caustic • Na-feroate , Naferoite
• Acid PO4 • 2-3 distinct layer • Maricite
Cycle Chemistry
Source of low pH exist
Source of high pH exist
DSP, MSP, or Na:PO4<3.0
Attack Rate
Very rapid10 mm/year
Rapid up to 2 mm/year
Rapid up to 2 mm/year
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#7 Oxygen Pitting
Localized dissolution of metal.
Relatively small amount of metal loss that initiate failure with catastrophic results
Type of pitting in Boiler Oxygen pitting Pitting caused by improper chemical cleaning Pitting caused by carry over of sodium sulfate
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#7 Oxygen Pitting: Features
Pit shape: broad, rounded
Pit distribution can be numerous or random
Corrosion product and deposit are present – primarily Fe2O3
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# 7 Oxygen Pitting: Features
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc., 1991
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#7 Oxygen Pitting: Mechanisms
1. Moisture 2. 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-drainable horizontal surfaces
Poor lay-up procedures
Can be found in Superheater and reheater tubes where condensate collects in bends
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#7 Oxygen Pitting Root Causes & Action to Confirm
Stagnant, oxygenated water with no protective environment due to improper layup Review the procedure Selective tube sampling Corrosion product analysis
#7 Oxygen Pitting Corrosion: Case History Case History Industry: Chemical process Location: Economizer Orientation: Horizontal Pressure: 41 bar Tube metallurgy: Carbon steel Treatment Program: Polymer & O2 Scav Time in Service: 7 years The reddish color & the presence of turbecles capping iron oxide-filled pits is typical of exposure of steel to water containing excessively high level of dissolved oxygen, Pitting & perforation of economizer tubes was a recurrent problem at this plant. Failures were occurring every 3 or 4 months. Excursions to high levels of oxygen was suspected but could not be documented. The boiler was operated 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 a synergistic interaction of a tensile stress and a specific corrodent to which the metal is sensitive
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#8 Stress Corrosion Cracking: Features
Thick-edged, brittle failure
May often involve the blow out of small “window-type” pieces
Little or no loss of wall thickness
Cracks Can initiate either inside or outside surfaces Can be oriented circumferentially or longitudinally May have significant branching
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#8 Stress Corrosion Cracking - Features
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 corrosive medium” i.e., a specific corrosive medium must be present for a given material
The presence of tensile stress Static tensile stress Tensile stresses which increase over time Tensile stresses which change at a low frequency over time
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#8 Stress Corrosion Cracking: Mechanisms
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: Mechanisms
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Stress Corrosion Cracking: Material & Corrodents
Austenitic Stainless Steel (300 series) Chlorides Sodium hydroxide Hydrogen sulfide
Carbon Steel Sodium hydroxide
Copper-based Alloys Ammonia
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#8 Stress Corrosion Cracking: Location
Potential for the highest concentration of contaminants Condensate can form during shutdown
High stress locations Bends, welds, tube attachment, supports, near weld, spacers; etc Especially where a change in thickness occur
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#8 Stress Corrosion Cracking Root Causes & Action to Confirm
Environmental Effects Chloride: Condenser in-leakage & chemical cleaning Caustic: Carry over
Stress Effects Residual stresses: fabrication/welding/heat treatment/bend Service stresses: especially at attachment & supports
Susceptible Material Effects
#8 Stress Corrosion Cracking: Case History Case History Industry: Petrochemical Location: Superheater, first stage Orientation: Vertical Pressure: 41 bar Tube metallurgy: 304 stainless steel Treatment Program: Phosphate Time in Service: 3 weeks The original tubes were CS that cracked after 9 months of service. SS tubes were specified to replace CS. Moderate bends were put to relieve the thermal expansion and contraction stress that had caused cracking in the CS tubes. SS failed because caustic stress corrosion cracking (lacked adequate devices for separation and load swings- carry over of ) boiler water. In addition , 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 above the design temperature for the tubing
In SH/RH tubing occur when the normal flow of cooling steam is blocked or partially blocked
Excessive temperatures and subsequent tube failures can occur 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 absent
Localized hardening near the rupture
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#9 Short Term Overheating - Features
Source: R.Port, The Nalco Guide to Boiler Failure Analysis, Mc Graw Hill, Inc., 1991
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#9 Short Term Overheating - Features
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 hotter sections of the water cooled tubing (evaporator)
Susceptible locations: Tubing nearest to the gas inlet, especially down stream of supplemental burner (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 temperature Visual examination of flame pattern Operating condition (gas temperature measurement; etc) Metallurgical analysis
Tube blockage Oxide from exfoliation tube material, chemical cleaning and /or improper repair Videoscope & metallurgical analysis to confirm
Start up with condensate filled tubes Thermocouple measurement Review start up procedure
#9 Short Term Overheating: Case History Case History Industry: Utility Location: Water wall, nose arch Orientation: Slanted Pressure: 124 bar Material: Carbon steel Treatment Program: Coordinated Phosphate Time in Service: 5 years Rupture occurred shortly after start-up. Microstructural evidence indicated that the tube metal near the rupture exceed 870 0C. No significant thermally formed oxide was found anywhere on the received section. The burst was caused by insufficient coolant flow on 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 for days, weeks, months or longer
Because steel loses much strength at elevated temperature, rupture caused by normal internal pressure becomes more likely as temperature rise
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#10 Long Overheating: Features
Thick-edged, brittle final failure
Bulging and plastic deformation
Scale Internal: Extensive, multilaminated & exfoliating External: Thick, laminated & often longitudinally cracked
May have “wastage flats”
Extensive sign of tube material degradation
Localized softening near the rupture is typical
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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 alloy Cause crack and exfoliated patches Cyclic thermal oxidation & spalling resulting wall thinning Process can continue until the entire wall is converted to oxide, creating a hole
Creep Rupture Plastic deformation during overheating Produce 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 a higher grade of material
Tubing nearest to the flue gas inlet, especially for supplementary-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 temperature Visual examination of flame pattern Operating condition (gas temperature measurement; etc) Metallurgical analysis
Tube blockage Oxide from exfoliation tube material, chemical cleaning and /or improper repair Videoscope & metallurgical analysis to confirm
Start up with condensate filled tubes Thermocouple measurement Review start up procedure
#10 Long Term Overheating: Example Case History Industry: Power Plant Location: Primary SH Inlet Pressure: 83 bar Orientation: Horizontal Treatment Program: Phosphate Time in Service: 20 years Creep rupture caused by prolong overheating at temperature above 570 0C. Coolant flow irregularities immediately downstream of a partially circumferential weld, along with internal deposition, which reduced heat transfer were contributing factors. Additionally, a switch from oil to coal firing likely changed fire-side heat input. The superheater had a history of boiler –water carryover 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 cause blockage of tubes
Excessive exfoliation can result in particulate erosion of turbine components, especially the nozzle block
May result in impacting the following: Plant availability
EPRI: Road Map for Analyzing BTF
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Determine the Extend of Damage Failure Mechanisms
Recommended Test
Corrosion Fatigue
Ultrasonic Testing UT) Selective Tube Sampling
Thermal/Mechanical Fatigue
Fluorescence magnetic partcle examination (WFMT) or Fluorescence penetrant (WFPT) Thermal stress analysis
Deposit
Selective tube sampling Deposit Weight Density (DWD)
FAC
Ultrasonic Testing (UT)
H2 Damage, Caustic & Acid Phosphate Corrosion
Ultrasonic Testing (UT) Selective Tube Sampling Boroscope Pressure Test after chemical cleaning
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Determine the Extend of Damage Failure Mechanisms
Recommended Test
Stress Corrosion Cracking
Fluorescence magnetic particle examination (WFMT) or Fluorescence penetrant (WFPT) Thermal stress analysis
Short & long term overheating
Radiography Tube removal Tube diameter measurement (wall thickness)
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Nalco SEA Recent 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=90:10 for air removal section
Boiler make-up: demineralized water from mixed bed
Condensate polisher: no
Two HRSG –HP Evaporator - tube failure in 1 week!
Important Events
November 2010 and confirmed
: Condenser in-leakage has identified
May 23-25, 2011 leakage become bigger
: Major ingress due to condenser in-
May 28-29, 2011 in condenser. Drum
: Plant shutdown. Plugged leak tubes inspection
May 30, 2011 : Plant is running back
Sept 8 – 22, 2011 inspection
Sept 18, 2011 : Tube failure of HP evaporator section.
Sept 22-23, 2011 HRSG tube failure.of HP Evap
Sept 25, 2011 : Plant is running back
: Major schedule shutdown. Drum
: Unscheduled plant shutdown due to
Deposit Sampling Analysis Result Elements/ Compounds Iron (Fe2O3) Copper (CuO) Phosporus (P2O5) Calcium (CaO) Magnesium (MgO) Sulfur (SO3) Silicon (SiO2) Zinc (Zn) Carbonate (CO2) Manganese (Mn) Sodium (Na2O) Loss at 925 0C Major compounds Minor compounds
Steam Drum – May ‘11 33 wt% 12 wt% 23 wt% 15 wt% 8 wt% 2wt% 4 wt% 1 wt% <1 wt% 1 wt% 1 wt% 2 wt% Magnetite-Fe3O4 Magnesium Iron Oxide (MgFe2O4)
Steam Drum – Sept ‘11 22 wt% 8 wt% 32 wt% 26 wt% 6 wt% 1 wt% 1 wt% <1 wt% 1 wt% 1 wt% 1 wt% Magnetite-Fe3O4 Ca PhosphateCa3PO4
HP Evap-Sept’11 (Sample #1) 50 wt% 15 wt% 14 wt% 8 wt% 5 wt% 2 wt% 1 wt% 1 wt% <1 wt%
HP Evap-Sept’11 (Sample #2) 90 wt% 3 wt% 2 wt% 1 wt% <1 wt%
1 wt% Magnetite-Fe3O4 Hematite-Fe2O3
Magnetite-Fe3O4 Iron Oxide - FeO Hematite-Fe2O3
Screen Analysis –Fracture/Appearance Excessive/ thick deposit
No tube bulging
Thick edge
Metal loss under deposit
Rectangular “Window”
Metal loss under deposit
Thick edge
Rectangular “Window”
Determine the Root Cause Major Root Cause Influences
Confirmation
Remarks
Influence of excessive deposits
Yes.
Flow disruption: deposits, DNB, bend/sharp changes in tube direction, locally high heat transfer; etc Influence of acidic contamination Condenser leaks – minor but occurring over an extend period Condenser leaks – major ingress, generally one serious event
Yes
Deposit in steam drum (boiler inspection May and September 2011) Heavy deposition in sampling tube (September 2011) Flow disruption only influenced by deposition
Water treatment plant up set leading to low pH condition Errors in chemical cleaning process
Yes. Yes. Yes. May 2011
pH of boiler dropped to ~8.5 on May 2011 Condenser leaks occurred November 2010 – 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 ppm
No. No.
No chemical cleaning conducted on 20102011.
Root Cause
Condenser in-leakage Increase chloride and sulfate level in BFW and boiler water Introduce hardness salts into BFW Introduce O2 into condensate and BFW
Deposition Hardness Iron Copper Phosphate
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 ?
Immediate Solution
Isolate the condenser and plug all the leaking tubes and tubes with high depth wastage. Ensure there is no cooling water in-leakage by checking condensate quality (cation conductivity, hardness, chloride; etc)
Selective tube sampling for deposit measurement. Inspection using fibre optic (boroscope) can provide useful information
Tube replacement for all tubing with hydrogen damage and/or significant wall loss be replaced
Check the efficacy of chemical cleaning
Long Term Solution
Chemical cleaning Proper 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 condenser leakage detection capability & control
Develop specific cycle chemistry targets, action levels and shutdown policies to maintain HRSG cleanliness.
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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
Case #2:Important Events
July 2011 program
: Change boiler chemical treatment
July – December 2011
15th December 2011 : Low pH Boiler water (~ 5.7)
18th December 2011 : 1st boiler tube failure (water wall)
24th December 2011 : 2nd boiler tube failure (water wall)
:Total iron in BFW > 10 ppb
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Screen Analysis: Location
Location of BTF: • Water Wall • Radiant heat transfer in front of buner • Highest temperature areas
Deposit Sampling Analysis Result
Screen Analysis –Fracture/Appearance
Screen Analysis –Fracture/Appearance
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Metallurgical Analysis Result (~3 weeks after the incident)
Confirm the Root Cause Major Root Cause Influences
Confirmation
Remarks
Influence of excessive deposits
Yes.
Flow disruption: deposits, DNB, bend/sharp changes in tube direction, locally high heat transfer; etc Influence of acidic contamination
Yes
Deposit in steam drum (Boiler inspection) Deposition in sampling tube High iron in BFW (>10 ppb) Flow disruption only influenced by deposition
Condenser leaks – minor but occurring over an extend period Condenser leaks – major ingress, generally one serious event Water treatment plant up set leading to low pH condition Errors in chemical cleaning process
Yes. ?
pH of Boiler dropped to <8.0 after start up in December 2011 Need to confirm by conducting condensate analysis by IC
No Yes No.
Contamination from pretreatment (possibly organic acids
Determine the Extend of Damage
Selective tube sampling
Chemical cleaning followed by boiler pressure test (1.5x than normal operation pressure)
Immediate Solution
Conducting proper chemical cleaning 1,8 tons of iron has removed from the boiler during cleaning DWD 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
Minimize deposit build up on boiler tubes by ensuring minimum corrosion product formation in BFW and transport into the boiler Total Iron < 10 ppb (ASME), EPRI < 2 ppb Total copper < 10 ppb (ASME), EPRI < 2 ppb
Use adequate chemistry related instrumentation and installation
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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