Boiler Tube Failures

BOILER TUBE FAILURES

“

Things Your Father May Not Have Told You”

STEPHEN M. McINTYRE

Division of Ashland Inc. One Drew Plaza

Boonton, New Jersey 07005

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

MECHANISMS

• Overheating

• Hydrogen Damage

• Caustic Gouging

• Oxygen Attack

• Thermal Fatigue

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

SHORT TERM OVERHEATING – Cont’d.

• Microstructure consists of bainite or martensite and ferrite

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

LONG TERM OVERHEATING - Cont’d

LONG TERM OVERHEATING - Cont’d

LONG TERM OVERHEATING - Cont’d

LONG TERM OVERHEATING - Cont’d

LONG TERM OVERHEATING - Cont’d

• 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

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

HYDROGEN DAMAGE – Cont’d

Concentrated Sodium Hydroxide Mechanism:

4NaOH + Fe

O

→

2NaFeO

+ Na

FeO

+ 2H

O

Fe + 2NaOH → Na

FeO

+ 2H

4H

_{+ Fe}

HYDROGEN DAMAGE – Cont’d

• Thick-lipped

• Brittle appearance

HYDROGEN DAMAGE – Cont’d

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

OXYGEN ATTACK

• Dissolved O₂ yields cathodic depolarization

• Reddish-brown hematite (Fe₂O₃) or “rust” deposits or tubercles

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

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 chemistry and lower pH)

FLOW ASSISTED CORROSION – Cont’d

• FAC affected by:

– Temperature – pH

– O₂ concentration

– Mass flow rate – Geometry

– Quality of fluid

FLOW ASSISTED CORROSION – Cont’d

Greatest potential for FAC occurs around 300 ºF

1.2 1.0 0.8 0.6 0.4 0.2 0.0 150 200 250 300 350 400 450 500 550 Temperature (0F) N o ra li z e d W e a r R a te 100

FLOW ASSISTED CORROSION – Cont’d

• 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 9.4 0 10 20 30 40 pH N o rm a li z e d W e a r R a te

FLOW ASSISTED CORROSION – Cont’d

• 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 0 10 20 30 40 50 60 70 80 90 100 Oxygen Concentration (ppb) N o ra li z e d W e a r R a te 0

FLOW ASSISTED CORROSION – Cont’d

• Normalized wear rate minimal below 10 ft/sec

FLOW ASSISTED CORROSION – Cont’d

• Geometry affects location of FAC, regardless of Reynold’s Number

• Changes in flow rate may not significantly reduce FAC

Wear at Low Re Numbers Wear at High Re Numbers Wear due to Secondary Flow at Medium Re Numbers

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,

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

Map of Tube Failures

Economizer side

East

5 10 15 20 25 30 35 40 45 50 55

Fire Box Side

Failed Scale detected Borescoped - Clean

Operating Conditions-Video Probe View

Notice iron oxide film has been compromised

Operating

Conditions-Visual Inspection

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

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.

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.

ID (waterside) surface of serrated-fin tube with localized accumulation of adherent, scab-like, rusty brown corrosion products.

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/gm Potassium 66.2 µg/gm Barium 221.8 µg/gm Copper <5.0 µg/gm Iron 63.7 µg/gm Magnesium (as Mg) 3257 µg/gm Calcium (as Ca)

119.2 µg/gm Silicon 344.2 µg/gm Sodium 132 µg/gm Chloride 9,039.7 µg/gm Sulfate

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

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

Failure

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

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

Corrective Actions &

Recommendations

• Improve boiler circulation

• Control intrusion of corrosive anions

• Maintain a buffering chemistry in the boiler

water

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

Corrective Actions & Recommendations

Monitor BFW Quality

Install Online Analyzers

– Cation Conductivity

Corrective Actions & Recommendations

Buffering Chemistry

• Coordinated Phosphate approach

• Phosphate ion will assist in buffering

corrosive environment beneath deposits

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 PO

and amines

• Periodic upsets in O

control

• Tubes: SA-214 (low carbon steel)

• 165 failed tubes in acrylic acid unit

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

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

Uncleaned Tubes (SEM-EDS)

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

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

CASE HISTORY #3

Under 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:

Laboratory Examination:

Visual Inspection

• Thick adherent oxide on hot

side

• Severe gouging

• Trace white deposits at

oxide tube interface

• No maricite layer

Laboratory Examination:

Visual Inspection

• Gouge along hot side away from failure

• No gray-white maricite layer observed

Laboratory Examination:

SEM-EDS

Laboratory Examination:

Microstructure

• Preferential attack at weld seam

• Weld not normalized

• In-situ spheroidization

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

Laboratory Examination:

Microstructure

• 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

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

Laboratory Examination:

Follow-up Tube Analysis (Cont’d)

Hot Side

Cold Side

Adjacent Tube:

Internal appearance after glass bead blasting

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

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

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

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