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FAILURE ANALYSIS OF HRSG TUBES

EXAMPLE REPORT

Modified from Original Report – Electronic Copy –

Casey Julich-Trojan, B.Eng. Metallurgist

Shane Turcott, P.Eng., M.A.Sc. Principal Metallurgist

It broke. Understand why. Solve the problem. [email protected], (289) 895-8363

Failure Analysis of HRSG Tubes Page 1 of 14

FAILURE ANALYSIS OF HRSG TUBES 1.0 INTRODUCTION AAAAAAAA had experienced failure of two superheater tubes in a heat recovery steam generator (HRSG). Both failures had occurred at the superheater tubes’ inlets just below the header (locations marked in Appendix A). The superheater tubes comprised of two inch diameter, finned ASME SA213 T11 low alloy steel and had been installed in 1989 (~29 years of service). Steel Image was requested to determine the nature and details of failure. 2.0 EXAMINATION Figure 1 displays the two tube segments submitted for analysis. For the ease of reference within this report, the tubes were allocated as Tubes #1 and #2. Tube #1 was cut open and a portion of the tube was found to comprise of flow assisted corrosion (FAC) damage (Figure 2). These FAC features comprised of a swept pattern on one side of the tube which exhibited ‘wave’ patterns (Figure 3). The most thinned section, likely where the leak site had been (or close to), had been damaged during the cutting/removal operation. The leak site on Tube #2 had been better preserved (Figure 4). One side of the tube had experienced severed wall thinning and, in this thinned region, cracks had formed. The features downstream the leak site were consistent with FAC and similar to Tube #1 (Figure 5). As the leak site of Tube #2 was better preserved than Tube #1, the destructive analysis focused on Tube #2. The leak site of Tube #2 was located within the region of severe thinning and wall breach had been completed by the formation of transverse cracks (Figure 6). Within this region, the wall had thinned from the nominal wall thickness of 0.120 inches to just under 0.020 inches. This accounted for 80% wall loss. The transverse cracks were aligned with the fins. These cracks had likely formed after, and as a result of, wall thinning. The cracks’

SUMMARY

Leaking of the two HRSG superheater tubes had occurred due to flow assisted corrosion (FAC). The flow from the header into the two inlet tubes had created either impingement flow or turbulence that had resulted in FAC and accelerated wall loss at specific sites along the tubes. This had lead to wall loss accounting for 80% of the original wall thickness, then leading to cracking and leaking.



surfaces exhibited an erosion pattern consistent with water content within the steam (remaining water content in the steam is required for FAC). Flow assisted corrosion (FAC) occurs when moist steam accelerates the rate of wall loss. Sites that experience FAC tend to be areas of turbulence or impingement which impacting water droplets cause erosion of the protective oxide layer, causing accelerated wall loss. In this case, steam flow from the header into the superheater inlet tubes had created the conditions leading to FAC. FAC is sometimes coupled with more complex corrosion mechanisms (i.e. from improper water treatment) and therefore, further analysis of the corrosion products were needed to rule out other contributing mechanisms. Energy dispersive spectroscopy (EDS) analysis of the internal surface of Tube #2 within the leak region found the product to comprise predominantly of iron oxide (Figure 7). No foreign corrosion agents were detected. The top layer of the scale was consistent with the scale expected to form from exposure to properly treated water/steam. Several cross-sections were taken through the leak region and at remote sites of Tube #2. Figure 8 compares the wall thickness of a remote site with the leak site. As noted before, FAC had caused severe wall loss and the remaining wall thickness had accounted for only 20% of the original nominal thickness. Cracking, as a result of the FAC damage and wall thinning, corresponded to the external fins. Optical examination and EDS analysis found the internal scale in cross-section to comprise of iron oxide scale (Figures 9 and 10). Water treatments are designed to selectively grow such oxides which provide protection to the underlying steel. Therefore, the damage was not consistent with issues in water treatment or a complex chemical attack. Instead, the damage appeared solely related to the FAC which, due to the water droplet erosion, wears away this protective layer and accelerates the rate of corrosion. Chemical analysis of Tube #2 was performed in accordance with ASTM E415. Table 1 lists the obtained results. The tube almost conformed to ASME SA213 T11 compositional requirements yet the sulphur was higher than the permitted maximum. This non-conformance would not have contributed to this failure. Table 1: Chemical Analysis Results

Sample Composition (wt%)

C Mn Si S P Cr Mo Ni ASTM A213

T11 0.05-0.15

0.30-0.60

0.50-1.00

0.025 Max

0.025 Max

1.00-1.50

0.44-0.65

--

HRSG Tube 0.11 0.52 0.47 0.039 0.018 1.21 0.48 0.08 *Chemical analysis performed in accordance with ASTM E1019, E1097 (modified) and E1479



The tube’s core metallurgy of the remaining material was in relatively good condition. The core microstructure of Tube #2, within the leak region, exhibited only the onset of thermal damage in the form of minimal pearlite spheroidization (Figure 11). Using the rating chart in Appendix B, spheroidization was rated as Level B which was not concerning nor close to life-limiting. No creep voids were observed. Considering its nearly three decades of service, the core metallurgy of the tube was in relatively good condition. 3.0 CONCLUSIONS Leaking of the two HRSG superheater tubes had occurred due to flow assisted corrosion (FAC). The flow from the header into the two inlet tubes had created the conditions leading to FAC and accelerated wall loss. This had caused localized wall loss accounting for up to 80% of the original wall thickness. Once significant thinning had occurred, cracks had formed, breaching the tubes’ walls and causing leaking. Flow assisted corrosion (FAC) requires the combination of (a) water within the steam and (b) flow directed into the tube’s walls from either flow impingement or turbulence. The water droplets impacting into the protective oxide scale causes its erosion and accelerates wall loss. In this case, the steam flow from the superheater header into the tubes’ inlets created the conditions causing FAC. FAC damaged would likely be limited to areas of impingement flow or, more likely, high turbulence beneath the header. As the steam becomes superheated and dries, FAC is no longer a concern. Other than the wall loss acceleration from FAC, no other complex corrosion mechanism were detected or suspected. No issues with water treatment or the introduction of other foreign corrosion agents had contributed to wall loss. Ultimately, failure was associated solely due to flow dynamics at the superheater tube inlets. No quality issues with the original tube material were observed that would have contributed to failure. Tube #2 exhibited a higher sulphur content and permitted by ASME SA213 T11 yet this would not have contributed to the damage sustained. Besides the FAC damage, no other life-limiting damage mechanisms were observed. Due to the external finning, inspection to assess for FAC and wall loss during shutdowns may not be possible. If this site were readily accessible during shutdowns, AAAAAA may consider replacing the initial inlet tube section, perhaps a foot in length, using tube material without fins. If the associated loss in superheater efficiency could be justified, it would allow for thickness measurements during future shutdowns.



Figure 1: Photograph displaying the submitted segments of the two failed tubes.

Figure 2: Photographs displaying the damage within Tube #1. The damage exhibited

a ‘swept’ pattern and waves consistent with flow assisted corrosion.

Damage (flow assisted

corrosion)

Damage

Tube #1

Tube #2

Most thinned site damaged during cutting removal

Tube #1



Figure 3: Photographs and macrographs of Tube #1 displaying the (b) damage

sustained by the flame cutting at the most thinned site and (c) the wave patterns indicative of flow assisted corrosion (FAC).

a) Tube #1

b) Most Severe Damage, 5x

Wave pattern consistent with FAC

c) Near Severe Damage, 10x

Melted from flame cutting



Figure 4: Photographs illustrating the damage on Tube #2. One site had experienced

severe wall thinning causing wall breach.

a) Tube #2, OD

b) Tube #2, ID

Wall penetration



Figure 5: Photographs of Tube #2 illustrating the swept, wave pattern beneath the most

severe damage, consistent with flow assisted corrosion. Other sites around the tube had suffered no wall loss (also consistent with FAC).

Flow assisted corrosion

Tube #2



Figure 6: Macrographs of Tube #2 displaying the cracks within the FAC thinned region.

The crack surface exhibited erosion patterns confirming that the steam included water content (needed for FAC). The cracking would have occurred after severe FAC wall thinning.

b) Tube #2, ID

b) Wall Breach, 5x

c) Wall Breach, 20x

Water erosion patterns (illustrates the erosive nature

of the steam/water)



keV0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00

Co

un

ts[x

1.E

+3

]

0.0

5.0

10.0

15.0

20.0

001

C

Cr

O

CrFe

Fe

NaMg

Al

Si P SS

K KCa

Ca Cr Cr

Fe

FeCa

keV0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00

Co

un

ts[x

1.E

+3

]

0.0

5.0

10.0

15.0

20.0001

C

Cr

O

CrFe

Fe

Na Si P SS

Cr Cr

Fe

Fe

Figure 7: EDS analysis of the corroded surface of Tube #2, within the vicinity of

wall loss and leaking, found the corrosion product to consist predominantly of iron oxide. No foreign corrosion agents were detected. The wall loss appeared to have occurred predominantly due to FAC rather than a complex corrosion/chemical attack. SE1, 15kV.

Water erosion patterns

(water in steam)



Figure 8: Macrographs taken of Tube #2 through (a) a remote site and (b) a leak site.

The leak site had suffered localized wall loss accounting for 80% of the original wall thickness. Etched using 3% nital.

a) Remote, 10x

b) Leak Site, 10x

Wall Breach (crack at fin)

~0.020 inches



Figure 9: Micrographs displaying the corroded surface of Tube #2 in cross-section. The

surface comprised of oxide scale expected to form from treated water/steam exposure. No obvious, aggressive chemical attack was observed. Etched using 3% nital.

keV0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00

Co

un

ts[x

1.E

+3

]

0.0

1.0

2.0

3.0

4.0

5.0

6.0

004

C

O

Fe

Fe

Si

Fe

Fe

keV0.00 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00 9.00 10.00

Co

un

ts[x

1.E

+3

]

0.0

2.0

4.0

6.0

8.0

10.0

12.0

001

MoC

CrO

CrFeFe

SiMo

Mo

S

S

Cr Cr

Fe

Fe

Figure 10: SEM images and EDS spectra of the internal scale within the leak region of

Tube #2. The scale comprised of iron oxide expected for properly treated water/steam exposure. No foreign corrosion agents were detected. SE1, 15kV.

a) Tube #2, ID Surface, 100x

a) ID Surface, Loc 1, 500x

b) ID Surface, Loc 2, 1000x

Oxide scale



Figure 11: Micrographs displaying the core microstructure of Tube #2 within the leak

region. The microstructure exhibited only the onset of thermal degradation in the form of Level B spheroidization (rating chart in Appendix C). No creep damage was observed. Overall, the core metallurgy of the tube was in good condition. Etched using 3% nital.

a) Tube #2, Core, 400x

b) Tube #2, Core, 1000x

Minimal spheroidization (Level B)



APPENDIX A – LOCATION OF FAILURES

Leak Sites



APPENDIX B: LEVEL CLASSIFICATIONS OF SPHERIODIZATION

Spheroidization of carbon and alloy steels is a long-term degradation mode that occurs gradually over years and decades of service (depending upon the temperature of operation). Eventually spheroidization will result in strength reduction of the steel. Advanced Levels E-F spheroidization damage often precedes creep void/crack formation. The schematics below illustrate the six stages of spheroidization.

FAILURE ANALYSIS OF HRSG TUBES - steelimage.com · It broke. Understand why. Solve the problem....

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