E2. Boiler Tube Failure Part 2

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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

7

#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

8

#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

9

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 rapid10 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


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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


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#9 Short Term Overheating - Features


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#9 Short Term Overheating: Mechanisms


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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 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


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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 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


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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


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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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THANK YOU!

E2. Boiler Tube Failure Part 2

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