Boiler Tube Failures

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

• • • • •

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

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: – – – – – –

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

• • •

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

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 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 chemistry and lower pH)

FLOW ASSISTED CORROSION – Cont’d

• FAC affected by: – – – – – – –

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

• •

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)

• • •

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)

• •

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

• •

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 • • • • •

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