Boiler Tube Failures

BOILER TUBE FAILURES“Things Your Father May Not Have Told You”

STEPHEN M. McINTYREAshland 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

• 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.

• 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:– Low water level– Partial or complete pluggage of tubes– Rapid start-ups– Excessive load swings– Excessive heat input

LONG TERM OVERHEATING

• 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


In-situ spheroidization of iron carbides


Complete spheroidization of iron carbides


Graphitization


Creep Voids


• Typical causes:– 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 parameterT = 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


• Thick-lipped• Brittle appearance• Window sections (sometimes) blown out


Microstructure exhibits:– Short discontinuous intergranular cracks– Decarburization

CAUSTIC GOUGING

• 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

• 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

• 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 chemistryand lower pH)

FLOW ASSISTED CORROSION – Cont’d

• FAC affected by:– Temperature– pH– O2 concentration– Mass flow rate– Geometry– Quality of fluid– Alloys of construction


Greatest potential for FAC occurs around 300 ºF

1.2

1.0

0.8

0.6

0.4

0.2

0.0150 200 250 300 350 400 450 500 550

Temperature (0F)

Nor

aliz

ed W

ear R

ate

100


• pH has significant effect on normalized wear rate of carbon steel• Nearly forty (40) fold reduction between pH 8.6 and 9.4

8.6 8.8 9.0 9.2 9.40

10

20

30

40

pH

Nor

mal

ized

Wea

r Rat

e


• Dissolved oxygen has direct impact• FAC minimized above 30 ppb O2• FAC increases exponentially below 30 ppb O2

35

30

25

20

15

10

5

010 20 30 40 50 60 70 80 90 100

Oxygen Concentration (ppb)

Nor

aliz

ed W

ear R

ate

0

FLOW ASSISTED CORROSION – Cont’d2.8

2.6

2.4

2.0

1.8

1.6

1.4

1.2

1.010 20 30 40 50 60 70 80 90 100

Velocity (ft/sec)

Nor

aliz

ed W

ear R

ate

• Normalized wear rate minimal below 10 ft/sec• Rate increases by 2.8 times at 100 ft/sec


• Geometry affects location of FAC, regardless of Reynold’s Number• Changes in flow rate may not significantly reduce FAC

Wear atLow Re

Numbers

Wear atHigh Re

Numbers

Wear due toSecondary

Flow atMedium ReNumbers


• 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

• 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 15 20 25 30 35 40 45 50 55Fire Box Side

FailedScale detectedBorescoped - Clean

Operating Conditions-Video Probe View

Notice iron oxide film has been compromised

Operating Conditions-Visual 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).

<1.0%Sulfur

<1.0%Nitrogen

0.2%Hydrogen

0.7%Carbon

CHN-S Testing

625.6 µg/gmPotassium

66.2 µg/gmBarium

221.8 µg/gmCopper

<5.0 µg/gmIron

63.7 µg/gmMagnesium (as Mg)

3257 µg/gmCalcium (as Ca)

119.2 µg/gmSilicon

344.2 µg/gmSodium

132 µg/gmChloride

9,039.7 µg/gmSulfate

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 Mechanism-Failed Tube Orientation

Failure Mechanism-Operating 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 Mechanism-Operating 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 & RecommendationsMonitor BFW Quality

Install Online Analyzers– Cation Conductivity

– pH

Corrective Actions & RecommendationsBuffering 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

• 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)

• 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)

Black oxide scale Orange-brown and black oxide scale corrosion products

Iron 78.8%Oxygen 18.7%Sulfur 0.74%Silicon 0.67%Calcium 0.57%Chlorine 0.42%

Iron 69.6%Oxygen 13.8%Calcium 9.70%Phosphorus 4.00%Copper 2.30%Sulfur 0.48%

Uncleaned Tubes (Stereoscopic View)

• 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 #3Under Deposit Corrosion

• 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:

0.10 min.0.250.16% Silicon

0.015 max.0.0030.003% Sulfur

0.030 max.0.0120.011% Phosphorus

1.00-1.501.311.26% Manganese

0.27 max.0.200.20% Carbon

SA-178 Gr. DTube No. 81Tube No. 13

Laboratory Examination:Visual Inspection

• Thick adherent oxide on hot side

• Severe gouging• Trace white deposits at

oxide tube interface• No maricite layer

Cracking

Laboratory Examination:Visual Inspection

• 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 20.1%Manganese 18.3%Sodium 16.0%Iron 11.6%Silicon 3.5%Aluminum 1.0%Calcium 0.3%Oxygen 29.0%

Laboratory Examination:Microstructure

• Preferential attack at weld seam• Weld not normalized• In-situ spheroidization• No decarburization observed


• Several inches away (in line) from failure

• Intergranular cracking at gouged area

• Hydrogen induced crack at ERW seam

• Characteristic of SCC in carbon steel


• 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

• 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

• 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

Hot Side Back Side

Laboratory Examination:Follow-up Tube Analysis (Cont’d)

Iron 83.6%Manganese 1.3%Aluminum 0.5%Phosphorus 0.4%Calcium 0.3%Oxygen 14.0%

SEM-EDS Analysis of reddish-black deposits on ID surface of adjacent tube


Hot Side

Cold SideAdjacent Tube:

Internal appearance after glass bead blasting


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 EtchMagnification 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 #3Conclusions

• 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 #3Leading 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 #3Corrective 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

Boiler Tube Failures

Documents

Transcript of Boiler Tube Failures