BOILER TUBE FAILURES
“Things Your Father May Not Have Told You”
STEPHEN M. McINTYRE
Ashland Water Technologies
Division of Ashland Inc.
One Drew Plaza
Boonton, New Jersey 07005
©2006, Ashland
INTRODUCTION
• Corrosion damage leads to untimely production
upsets, costly equipment failures and lost
opportunities
• Failure analysis an effective tool in establishing
true root cause of failure
• Root cause determination provides a path to
effective corrective actions
• Common corrosion mechanisms and case
histories presented
MECHANISMS
• Overheating
– Short Term
– Long Term
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•
•
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Hydrogen Damage
Caustic Gouging
Oxygen Attack
Thermal Fatigue
Flow Assisted Corrosion
CASE HISTORIES
• Thermal Oxidation Process Upsets in 650
psig HRSG
• Acrylic Acid Thermo Siphon Steam
Generator System
• Under Deposit Corrosion from Inadequate
Precleaning Procedures and Operational
Issues
SHORT TERM OVERHEATING
• Thin-lipped, longitudinal rupture
• Extensive tube bulging
• Large fish-mouth appearance
SHORT TERM OVERHEATING – Cont’d.
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Microstructure consists of bainite or martensite and ferrite
Indicates rapid cooling from above eutectoid temperature of 1340 ºF
SHORT TERM OVERHEATING – Cont’d
• Typical Causes:
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–
–
Low water level
Partial or complete pluggage of tubes
Rapid start-ups
Excessive load swings
Excessive heat input
LONG TERM OVERHEATING
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Little to moderate bulging
Little to moderate reduction in wall thickness
Typically accompanied by thermal oxidation
Found in superheaters, reheaters, waterwalls
LONG TERM OVERHEATING - Cont’d
Normal Pearlite and Ferrite Microstructure
LONG TERM OVERHEATING - Cont’d
In-situ spheroidization of iron carbides
LONG TERM OVERHEATING - Cont’d
Complete spheroidization of iron carbides
LONG TERM OVERHEATING - Cont’d
Graphitization
LONG TERM OVERHEATING - Cont’d
Creep Voids
LONG TERM OVERHEATING - Cont’d
• Typical causes:
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–
–
–
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Gradual accumulation of deposits or scale
Partially restricted steam or water flow
Excessive heat input from burners
Undesired channeling of fireside gases
Steam blanketing in horizontal or inclined tubes
Operation slightly above oxidation limits of given
tube steel (850 ºF for carbon steel)
OVERHEATING – Cont’d
Larson-Miller Parameter:
P = T (20 + Log t)
Where:
P = Larson-Miller parameter
T = Temperature of tube metal,
degrees Rankine, (ºF + 460)
t = Time for rupture, hours
HYDROGEN DAMAGE
• Typically occurs:
– Waterwall tubes above operating 1000 psig
– Beneath heavy deposits
– Where corrosion releases atomic hydrogen
HYDROGEN DAMAGE – Cont’d
Concentrated Sodium Hydroxide Mechanism:
4NaOH + Fe3O4 →
2NaFeO2 + Na2FeO2 + 2H2O
Fe + 2NaOH → Na2FeO2 + 2H
4H+ + Fe3C → CH4 + 3Fe
HYDROGEN DAMAGE – Cont’d
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Thick-lipped
Brittle appearance
Window sections (sometimes) blown out
HYDROGEN DAMAGE – Cont’d
Microstructure exhibits:
– Short discontinuous intergranular cracks
– Decarburization
CAUSTIC GOUGING
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Caustic concentrates - DNB or steam blanketing
NaOH beneath deposits destroys protective magnetite film
NaOH corrodes base metal
Also, evaporation along waterline with no deposits
OXYGEN ATTACK
• Dissolved O2 yields cathodic depolarization
• Reddish-brown hematite (Fe2O3) or “rust” deposits or
tubercles
• Hemispherical pitting beneath deposits
THERMAL FATIGUE
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Numerous cracks and crazing, oxide wedge
Caused by:
– Excessive cyclic thermal fluctuations
– Excessive thermal gradients and mechanical constraint
– DNB or rapidly fluctuating flows in waterwalls
– Low-amplitude vibrations of entire superheaters
FLOW ASSISTED CORROSION
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Localized thinning
Dissolution of protective
oxide and base metal
Occurs in single or
two phase water
Low pressure system
bends in evaporators,
risers and economizer tubes
Feedwater cycle (due to more volatile chemistry
and lower pH)
FLOW ASSISTED CORROSION – Cont’d
• FAC affected by:
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Temperature
pH
O2 concentration
Mass flow rate
Geometry
Quality of fluid
Alloys of construction
FLOW ASSISTED CORROSION – Cont’d
Noralized Wear Rate
1.2
1.0
0.8
0.6
0.4
0.2
0.0
100 150 200 250 300 350 400 450 500 550
Temperature (0F)
Greatest potential for FAC occurs around 300 ºF
FLOW ASSISTED CORROSION – Cont’d
Normalized Wear Rate
40
30
20
10
0
8.6
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•
8.8
9.0
pH
9.2
9.4
pH has significant effect on normalized wear rate of carbon steel
Nearly forty (40) fold reduction between pH 8.6 and 9.4
FLOW ASSISTED CORROSION – Cont’d
35
Noralized Wear Rate
30
25
20
15
10
5
0
0
10 20 30 40 50 60 70 80 90 100
Oxygen Concentration (ppb)
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•
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Dissolved oxygen has direct impact
FAC minimized above 30 ppb O2
FAC increases exponentially below 30 ppb O2
FLOW ASSISTED CORROSION – Cont’d
2.8
Noralized Wear Rate
2.6
2.4
2.0
1.8
1.6
1.4
1.2
1.0
10 20 30 40 50 60 70 80 90 100
Velocity (ft/sec)
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Normalized wear rate minimal below 10 ft/sec
Rate increases by 2.8 times at 100 ft/sec
FLOW ASSISTED CORROSION – Cont’d
Wear at
Low Re
Numbers
Wear due to
Secondary
Flow at
Medium Re
Numbers
Wear at
High Re
Numbers
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•
Geometry affects location of FAC, regardless of Reynold’s Number
Changes in flow rate may not significantly reduce FAC
FLOW ASSISTED CORROSION – Cont’d
• Most often found in “all-ferrous” metallurgy
• 0.1% addition of chromium can reduce FAC
• Trace levels of chromium in low carbon steels
(like SA-178 or SA-210) provide benefits,
even though chromium content not specified.
CASE HISTORY #1:
THERMAL OXIDIZER BOILER TUBE FAILURES
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Maleic Unit Thermal Oxidizer Boiler
650 psig
12 years old
All volatile treatment (AVT)
Fired by natural gas and waste solvent
streams
• SA-192 tube material (low carbon steel)
Map of Tube Failures
Economizer side
East
5
10
Failed
Scale detected
Borescoped - Clean
15
20
25
30
35
Fire Box Side
40
45
50
55
Operating Conditions-Video Probe View
Notice iron oxide film
has been compromised
Operating ConditionsVisual Inspection
Notice layered iron oxide chips
As-Received for Laboratory Examination
Figure 1: Top/right photo shows
the finned tube specimen as
received from row 17, which
exhibited a complete wall failure
at the external radius of the bend.
Bottom/left photo illustrates
the tube’s cross-section,
which revealed a layered,
brittle oxide layer that
measured 0.142″.
Magnified view of oxide layer shown in Figure 1 (bottom photo)
Magnification 5X
ID (waterside) surface of failed tube (smooth finned) as split, which
revealed heavy accumulation of reddish-black, scab-like deposit
and corrosion product. Visible gouging damage and failure also
observed.
Through-wall gouging
ID (waterside) surface after cleaning. Note severe, localized
gouging beneath deposits. Copper corrosion products also
observed near gouged areas.
Close up view of copper corrosion products observed near
gouged area of smooth finned tube.
Photomicrograph of copper corrosion products dispersed
throughout iron oxide matrix at ID surface.
Photomicrograph of tube metal microstructure at gouged area.
Microstructure consists of normal lamellar pearlite and ferrite.
Nital Etch
Magnification 855 X
ID (waterside) surface of serrated-fin tube with localized
accumulation of adherent, scab-like, rusty brown corrosion
products.
Note waterline marks
Chemical Analysis of water soluble components from the iron
oxide deposit at base metal interface of tube. CHN-S testing
performed on bulk dry deposit (not water extract).
Sulfate
9,039.7 µg/gm
Chloride
132 µg/gm
Sodium
344.2 µg/gm
Silicon
119.2 µg/gm
Calcium (as Ca)
3257 µg/gm
Magnesium (as Mg)
63.7 µg/gm
Iron
<5.0 µg/gm
Copper
221.8 µg/gm
Barium
66.2 µg/gm
Potassium
625.6 µg/gm
CHN-S Testing
Carbon
0.7%
Hydrogen
0.2%
Nitrogen
<1.0%
Sulfur
<1.0%
ID (waterside) surfaces of adjacent unfailed tubes exhibited thin,
non-magnetic, reddish deposit layer. DWD measured 5.2 g/ft2.
Remaining tubes were essentially free of corrosion and in excellent
condition.
Failure Mechanism
Thermal excesses and/or
inadequate flow led to
DNB/steam blanketing .
Failure Mechanism
Failure Mechanism
Thermal excesses and/or inadequate flow led
to DNB/steam blanketing .
•Scab-like deposits formed.
•Anions concentrated beneath iron deposits
and created a corrosive environment.
•Tubes thinned as a result of corrosion.
•Internal pressure overcame the thinned tube
wall.
Failure MechanismFailed Tube Orientation
Failure MechanismOperating Conditions
• Gas side temperature increases reduce mean time to failure
• Pressure fluctuations cause significant increase in steam
volume
• Potential exists for overheating due to steam stalling
• Boiler operated at maximum (and beyond) capacity
• Finned tubes installed 1 to 2 rows in front of design location
Failure MechanismOperating Conditions
• Thermal cycling disrupts iron oxide film
• Spalled iron oxide accumulates further down in tubes
• Boiler water penetrates chip scale
• Wick boiling concentrates boiler water solids to percent
levels
• Tube wall thinning results from over concentration of solids
and acid attack due to hydrolysis by Cl or SO4 anions
• Maximum allowable stress is exceeded due to thinning
Corrective Actions &
Recommendations
• Improve boiler circulation
• Control intrusion of corrosive anions
• Maintain a buffering chemistry in the boiler
water
• Modify boiler operation to avoid DNB
Corrective Actions & Recommendations
Improve Circulation
Points to be explored with the Boiler Manufacturer:
• Install baffles or orifices to improve flow to center tubes
• Install a central downcomer
• Ensure that finned tubes are situated appropriately
• Stagger tubes rather than positioning them in-line
Corrective Actions & Recommendations
Eliminate Corrosive Anions
• Identify sources of BFW contamination
– Analyze component streams
– Sentry sampler for low level metals analysis
– Eliminate or purify contaminated stream(s)
• Polish BFW components
– Makeup
– Condensate
• Consider chemical cleaning
Corrective Actions & Recommendations
Monitor BFW Quality
Install Online Analyzers
– Cation Conductivity
– pH
Corrective Actions & Recommendations
Buffering Chemistry
• Coordinated Phosphate approach
• Phosphate ion will assist in buffering
corrosive environment beneath deposits
• AVT maintained in salt coolers
CASE HISTORY #2:
SALT COOLER TUBE FAILURES
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Salt Cooler Thermo Siphon Steam Generator
Molten NaCl heat source
Operating pressure: 600 psig
15 years old
Coordinated PO4 and amines
Periodic upsets in O2 control
Tubes: SA-214 (low carbon steel)
165 failed tubes in acrylic acid unit
$50 MM in damages and “lost opportunities”
Cleaned Tubes (As Received)
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Localized pitting
Shallow corrosion
Maximum penetration (0.031”) 36% wall loss
Undercut pitting suggests an acid form of attack
Cleaned Tubes (As Received)
• Preferential attack of welded seam observed
• Specifically at expanded end
• Maximum penetration (0.029”) 34% wall loss
Uncleaned Tubes (As Received)
• Very thin, non-uniform black oxide and flash rust
• Oxide scale thickness ranged 0.0006 to 0.0010”
• DWD measured 4.9 g/ft2
Uncleaned Tubes (SEM-EDS)
Iron
Oxygen
Sulfur
Silicon
Calcium
Chlorine
78.8%
18.7%
0.74%
0.67%
0.57%
0.42%
Black oxide scale
Iron
Oxygen
Calcium
Phosphorus
Copper
Sulfur
69.6%
13.8%
9.70%
4.00%
2.30%
0.48%
Orange-brown and black oxide
scale corrosion products
Uncleaned Tubes (Stereoscopic View)
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•
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Bare shiny metal at localized pitting attack
“Shot blasted” appearance at freshly exposed metal
Note cracked and crazed pattern in oxide scale
Uncleaned Tubes (SEM-EDS)
Magnification 113 x
Magnification 177 x
Iron
84.8%
Oxygen
13.2%
Calcium
0.74%
Sulfur
0.35%
Phosphorus
0.34%
Silicon
0.27%
Chlorine
0.27%
Elemental Analysis at Pitted Area
Root Cause(s):
• Alloy substitution of plug in upstream unit
• H2SO4 “Black Acid” upstream process leaked into
condensate used for boiler feedwater
• No response to on-line conductivity warnings
• Contaminated condensate not dumped
• Boiler operated at pH 2-3 for several days
Corrective Actions:
• Water no longer considered a utility, but
rather a part of the process
• Best practice and process control measures
implemented
• “Re-educated” operators
• Automated “dump station” activated by low
feedwater pH
• No subsequent tube failures in four years
CASE HISTORY #3
Under Deposit Corrosion
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Cogeneration HRSG System
1800 psig High Pressure Evaporator Unit
Approximately 4000 hours (5.5 months)
Congruent phosphate, organic oxygen scavenger,
neutralizing amines
Tube material: SA-178 D (2 tubes received)
Failures occurred in first row, center section of the HP
evaporator, facing gas path
Organic acid process contamination in makeup
Misaligned duct burners also reported
Laboratory Examination:
Alloy Analysis:
Tube No. 13
Tube No. 81
SA-178 Gr. D
% Carbon
0.20
0.20
0.27 max.
% Manganese
1.26
1.31
1.00-1.50
% Phosphorus
0.011
0.012
0.030 max.
% Sulfur
0.003
0.003
0.015 max.
% Silicon
0.16
0.25
0.10 min.
Laboratory Examination:
Visual Inspection
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•
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Thick adherent oxide on hot
side
Severe gouging
Trace white deposits at
oxide tube interface
No maricite layer
Cracking
Laboratory Examination:
Visual Inspection
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•
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Gouge along hot side away from failure
No gray-white maricite layer observed
Dry grind to minimize loss of water soluble deposits
Laboratory Examination:
SEM-EDS
Analysis of deposits at
oxide-metal interface
Phosphorus
Manganese
Sodium
Iron
Silicon
Aluminum
Calcium
Oxygen
20.1%
18.3%
16.0%
11.6%
3.5%
1.0%
0.3%
29.0%
Laboratory Examination:
Microstructure
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Preferential attack at weld seam
Weld not normalized
In-situ spheroidization
No decarburization observed
Laboratory Examination:
Microstructure
• Several inches away (in
line) from failure
• Intergranular cracking
at gouged area
• Hydrogen induced
crack at ERW seam
• Characteristic of SCC in
carbon steel
Laboratory Examination:
Microstructure
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Numerous intergranular cracks
at gouged area
Cracking is typical of hydrogen
damage
Slight in-situ spheroidization
around entire circumference
Laboratory Examination:
Microstructure – (Separate tube)
•
Microstructure at gouged area exhibited iron carbide transformation
product, or Widmanstätten structure, indicating rapid cooling from
above eutectoid transformation temperature of 1340 ºF
Laboratory Examination:
Key Observations
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Severe gouging along hot side of tube
Heavy magnetite deposit (corrosion product)
Distinct maricite (NaFePO4) layer not observed
No evidence of Cl or SO4 observed at interface
Hydrogen induced cracking at gouge and ERW
Very high peak metal temperatures reached
Insufficient sample received to evaluate true internal cleanliness
Elemental deposit analysis alone does not identify specific corrosion
products
Attack more closely resembles caustic gouging and SCC
Requested adjacent unfailed tube and >24 hours to conduct lab
exam
Laboratory Examination:
Follow-up Tube Analysis
Hot Side
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Back Side
Adjacent tube received one month later
Distinct waterline marking along hot side
Reddish-black friable deposits
Internal DWD (g/ft2): 13.1 hot side, 9.1 back side
Laboratory Examination:
Follow-up Tube Analysis (Cont’d)
SEM-EDS Analysis of
reddish-black deposits
on ID surface of
adjacent tube
Iron
Manganese
Aluminum
Phosphorus
Calcium
Oxygen
83.6%
1.3%
0.5%
0.4%
0.3%
14.0%
Laboratory Examination:
Follow-up Tube Analysis (Cont’d)
Hot Side
Adjacent Tube:
Internal appearance after
glass bead blasting
Cold Side
Laboratory Examination:
Follow-up Tube Analysis (Cont’d)
Adjacent Tube:
Normal lamellar pearlite
and ferrite microstructure
observed around entire
circumference. No
evidence of cracking,
decarburization or any
other forms of degradation
observed throughout entire
tube.
Nital Etch
Magnification 500 x
Field Examination:
Follow-up Tube Analysis (Cont’d)
Video probe view of
identical tubes in adjacent
unfired HRSG unit.
No pre-cleaning performed.
Internal rust and non-protective
oxides will enhance wick boiling
and under deposit forms of
attack, especially in high heat
flux zones.
CASE HISTORY #3
Conclusions
• Failures do not always exhibit a single classic
mechanism
• Careful coordination required between laboratory
examination, field inspection, and operating records
• Failure attributed to under deposit corrosion
• Caustic corrosion and hydrogen induced SCC
primary corrosion mechanism(s)
CASE HISTORY #3
Leading Causes of Under Deposit Corrosion
• Localized Departure from Nucleate Boiling (DNB)
• Localized and very high heat flux from misaligned duct
burners
• BFW upsets from process contamination and
demineralizer control
• Pre-existing deposits from construction and outside
storage of tubes
• No pre-cleaning prior to commissioning
CASE HISTORY #3
Corrective Actions
• Changed treatment program from congruent
to equilibrium PO4 to offer improved buffering
against organic acid process contamination
• Improved demineralizer system to minimize
over runs
• Recommended precleaning tubes prior to
start up
©2006, Ashland