CORROSION OF BOILER TUBES SOME CASE STUDIES1

Anees U. Malik, Ismail Andijani, Mohammad Mobin,

Fahd Al-Muaili and Mohammad Al-Hajri

Saline Water Desalination Research Institute Saline Water Conversion Corporation (SWCC)

P O Box 8328, Al-Jubail- 31951 Kingdom of Saudi Arabia Email: rdc@swcc.gov.sa

ABSTRACT Failure of boiler tubes by corrosion attack has been a familiar phenomenon in power

plants resulting in unscheduled plant shut down, in consequence, there are heavy losses

in industrial production and disruptions to civil amenities. The failure of boiler tubes

appears in the form of bending, bulging, cracking, wearing or rupture, causing leakage

of the tubes. The failure can be caused by one or more modes such as overheating,

stress corrosion cracking (SCC), hydrogen embrittlement, creep, flame impingement,

sulfide attack, weld attack, dew point corrosion, etc.

In this presentation, information related to boiler tube failures are given in the form of

some case studies. The case studies are comprised of failures occurred due to SCC,

overheating, flame impingement and creep. The description of the failure, possible

causes and mechanism(s) will be presented followed by conclusions and

recommendations.

INTRODUCTION The failure of industrial boiler has been a prominent feature in fossil fuel power plants.

The contribution of one or several factors appears to be responsible for failures,

culminating in the partial or complete shut down of the plant resulting in heavy losses

in industrial production and disruption to civil amenities. The use of inferior tube

materials, use of high sulfur or/and vanadium containing fuels, exceeding the design

limit of temperature and pressure during operation, poor maintenance and aging are

some of the factors which have a detrimental effect on the performance of materials of

construction. The failure of boiler tubes appeared in the form of bending, bulging,

1 Published in the Proceeding of 4th SWCC Acquired Experience Symposium held at Jeddah in 2005, pp. 739-763.

wearing or rupture, decarburization, carburization causing leakage of the tubes. The

failure can be caused by one or more modes such as overheating, SCC, hydrogen

embrittlement, creep, flame impingement, sulfide attack, weld attack, dew point attack,

hot corrosion, etc.

In the present paper, information related to boiler tube failures are given in the form of

five cases studies.

CASE - I :

Flame Impingement of Water Wall Tubes - Shoaiba Phase- II

During unit reliability operation by Shoaiba plant engineers, flame impingement test

was conducted on water wall tubes for a few hours and it was found that flame touched

the rear wall of the furnace. It was decided by the Plant management to send some

tubes to R&D Center for investigating the effect of flame impingement on water wall

tubes.

Physical Inspection

Out of the 6 tubes provided for analysis, 3 tubes (# 1 to 3) were from flame

impingement area, 2 tubes (#4 and 5) from non-flame impingement area and one tube

(#6) was unused tube for comparison purposes (Fig. 1). The tubes were in services

since August 2000 at variable boiler load conditions. All the tubes were electrical

resistance welded seam (ERWS), however, the location of the seam was not visible by

naked eye. The position of the seam in the tube was located by grinding, polishing and

deep etching of the tube.

The original thickness of the tube was 6.2 mm and the material composition

corresponded to SA 178C.

Steam side (internal surface) of the tubes (#1 to 5) contains very thin adherent dark grey

colored scales. The results of analysis steam side scales indicate high concentrations of

Cu (19-28%) and Ni (6 to 11%) along with Zn, P, Ca and Al in significant

concentrations (Table 1).

There is much higher concentration of Cu and Ni in steam side scales in tubes from

flame impingement zone. All these compounds are contaminated with magnetite scales.

The analysis of fire side (external) scales shows the presence of S and V. The source

appears to be fuel (Table 1, Fig.2).

Microstructural Studies

The microstructures of the cross-sections of unused, non-flame impingement zone and

flame impingement zone tubes were studied. The microstructures of the cross-sections

of all the tubes were observed at the seam area. In general, the microstructures of the

seam areas show contour shaped structures in which contours in opposite directions can

be seen along a vertical axis. Some typical microstructures are discussed below:

(i) Unused Tube (#6): Contour type with well defined central line structure is

pearlitic-ferritic type with no decarburization layer (Fig. 3).

(ii) Non-Flame Impingement Zone Tube (#4 and 5) : Diffused line along the opposite

contours with no decarburization (Fig. 4).

(iii) Flame Impingement Zone Tubes (# 1 to 3): There are following cases:

(a) When the seam is not facing flame directly, there is a contour structure but no

evidence of decarburization (Fig. 5).

(b) When the seam is directly facing the flame (#1), refinement of the grains

along the vertical axis can be seen with a well-defined decarburized layer

(Fig. 6). This tube appears to be most affected by flame impingement.

In all the tubes, there is reduction in wall thickness (5 to 8%) after operation.

Conclusions

1. No decarburization was found in the unused tube and non-impingement zone

tubes. However, in flame impingement zone tubes, a well-defined decarburized

layer is present in area between the opposite contours.

2. A clear decarburization layer is probably only when the seam of the boiler tube is

directly facing the flames.

CASE - II :

Creep Failure of Boiler Reheater Tubes in a Power Plant

R&D Center received 2 reheater boiler tubes (#3 and 4) for analysis. The boilers were

commissioned about 24 years ago and had been in operation for more than 150,000 hrs.

Following were the salient features of the boiler tubes:

• Tube material : Medium carbon steel SA 192

• Nature of the tube : Seamless

• Outer diameter : 57.15 mm

• Nominal thickness : 3.4 mm

• Working pressure : 345 psig

Metallography

Photograph of the reheater tubes # 3 and 4 is shown in as received condition (Fig. 7).

External surface appeared reddish brown.

Steam Side Scales

The steam side scales contain dark grey magnetite. The inner surface is covered with

small and big pits with hematite stringers (Figs. 8 and 9). Tubes are shown after

cleaning (Fig. 10).

Microstructural Studies

The microstructures of the boiler tubes (#3 and 4) were studied by observing the

structures of cross-sections through a photometallurgical microscope. The main

observations were as follows:

(i) Cross-section of boiler unit # 3, steam side: Ferritic-pearlitic structure, there is

dispersion of carbides and accumulation at grain boundaries (Fig. 11).

(ii) Cross-section of boiler unit #3, fire side: Carbides are dispersed in ferrite matrix

and precipitated at the grain boundaries (Fig. 12).

(iii) Cross-section of boiler unit # 4, steam side: Pearlitic structure. Dispersion of

carbides in the matrix, precipitation of carbide at the grain boundaries and

spheroidization of carbides. Presence of voids is also indicated.

(iv) Cross-section of boiler unit # 4, fire side: Pearlitic structure. Huge dispersion of

carbides, spheroidization and accumulation of carbide at the grain boundaries

(Fig. 13).

Discussion

Microstructural studies reveal the following features:

(i) Structure is ferritic-pearlitic

(ii) Dispersion of carbides in the ferritic matrix

(iii) Accumulation of carbides at the grain boundaries

(iv) Spheropidization of carbides

(v) Presence of voids in some cases

The afore-mentioned observations provide strong evidence for a creep induced failure

of type II which appeared to be dominant during current operation of the boiler.

No cracking or leakage was found in the tube which indicates that stage III creep has

not yet reached, so tubes can be used for some more time.

Scale density and scale thickness values of the boiler tubes are high but still they can be

operated without cleaning.

Conclusion

The results of metallographic studies point out the involvement of creep type II

behavior in reheater tubes from boiler unit # 3 and 4.

Recommendation

As the reheater tubes from boiler unit # 3and 4 appear to be under deterioration due to

the influence of creep type II behavior. Therefore, the replacement of the tubes shall be

required in near future. A better tube material like a low alloy steel shall be a better

choice at the operating boiler temperature above 500 oC.

CASE - III :

Failure of High Temperature Superheater Tube of Boiler # 63, Al-Jubail Plant

The boiler # 63 had been in operation for more than 15 years. It was found that

superheater tube # 67 had failed at 2 locations. The failed portions were from the same

pendant.

The first portion of the failure was found at the bottom of the first loop near the

upstream side of the first bend (Fig. 14). This portion was sent to ANSALDO for

investigation.

The second portion of the failure was found at the bottom portion of the third loop

upstream of the weld point (Fig. 15). This portion of the tube consisting of outlet and

inlet tubes were sent to R&D Center for investigation. The pipe sheared at the bottom

portion. From the photograph, it is observed that the failure of the tube occurred by

rupture at the bottom portion of the third loop upstream side of the weld joint (Fig. 16).

Specifications of the unit # 63 boiler are given in Table 2.

SEM Studies

The inner section of the ruptured tube outlet and inlet are marked 1 to 5 indicating

different locations. (Fig. 17).

The fractography of the tube sample at locations 1 and 3 was carried out by SEM.

Whilst at location 1 (expanded portion) there are clear indications of intergranular

cracking originated from the outside surface (Fig. 18), the cracks at location 3

(protruded portion) are intergranular as well as transgranular (Fig. 19). The cracks at

location 5 (inlet of tube) are transgranular (Fig. 20). All cracks showed multiple

direction of propagation which are typically arising out of stresses in the scales and the

metal at high temperature.

Quantification of the Scales

The quantification of scale densities carried out near fracture surface of the tubes, as

determined by acid dissolution technique was found to be 483 and 219 mg/cm2 for

superheater inlet and outlet tubes (both third loop), respectively. The scale densities

seem to exceed the limits set by Otker Jonas for chemical cleaning of the boiler tubes.

Discussion

The presence of thick scale deposition in the fractured boiler tubes would result in

overheating leading to fracture under operating pressure-temperature conditions. The

presence of trans and intergranular fracture in SEM further proves the consequences of

thick scale deposition over steam side.

Conclusions

(i) Optical and SEM studies and quantification of the scale densities indicate the

cause of superheater tube is overheating.

(ii) Overheating of the tube at the bottom of 3rd loop near the upstream side is due to

heavy scale deposition.

Recommendations

(i) In view of abnormal deposition of scales at various locations of superheater

tubes, chemical cleaning of all high temperature superheater tubes be carried out

to avoid failure in future.

(ii) Periodic evaluation of superheater tubes for its scale density and tube life should

be planned in every maintenance schedule in consultation with R&D Center.

CASE - IV :

Failure Analysis of Failed Generation Bank Tube in Boiler # 4, Madina-Yanbu Plant Medina-Yanbu plant has 5 identical boilers and the manufacturer is MHI. Boiler No. 4

has failure at the generation bank tube zone. The boiler had been in service for approx

23 years. T&I report indicated rupture of the tube # 9 and leakage in the tube # 2 (at 6

O’clock position).

Figure 21shows drawing of the boiler front indicating the location of generation bank

tubes.

Physical Examination

Figure 22 shows ruptured generation bank tube in as received condition. Figure 23

shows inside water drum at the end of ruptured generation bank tube and Figure 24

shows broken away refractory laying between bank tubes and rear wall tubes. Pits and

tube thinning were noticed near the ruptured side indicating localized corrosion and

metal loss (Fig. 25). The pits are indicative of corrosion and thinning indicates partial

dissolution of metal due to corrosion near the rupture.

After removal of internal and external scales, the photograph of internal surface shows

presence of small pits (Fig. 26). The corrosion inside the tube could be the result of

dissolved oxygen in water which was further confirmed by heavy corrosion inside the

water drum (Fig. 23).

Microstructural Studies

Cross-sections of the ruptured tube samples were selected for microstructural studies.

Sample at the end of rupture shows transgranular crack propagation (Figs.27 and 28).

Presence of S, V, Ca and K in the fire side scales (EDX analysis) indicates that fuel oil

containing these impurities (Fig. 29). Due to rupture, there is contamination of S and V

in the scales from the outside combustion gases ( Fig. 30).

Discussion

Hydrojetting is carried out during shut down by using alkali (10% NaOH) to remove

heavy external deposits on the tube. The S-containing deposits are acidic in nature

forming aqueous solution of acid (mainly H2SO4) and salts by reacting with alkali.

During hydrojetting of the boiler tubes, low pH liquid (pH~2) is formed as affluent

where most of the liquid is drained off, some liquid remained adsorbed on the

refractories. The acidic liquid adsorbed by the refractories attacked the adjacent

metallic tubing. With time this gradually thinned down the metal and ultimately due to

high pressure (70 mm Hg) inside the tube, rupture of the tube occurred.

During the start of shut down period, the combustion gas contaminated with S also

condensed as H2SO4 at the dew point temperature and initiated dew point corrosion. V

compounds present in the combustion gases react with scale/corrosion products in

presence of oxygen forming low melting vanadates which undergo flushing reaction

resulting in accelerated or hot corrosion of metal. The thinning of the wall tube by

residual adsorbed acid along with combination of dew point and hot corrosion resulted

in rupture of the tube.

Conclusion

The rupture of the boiler tube occurred as a result of combination of 3 processes

namely, (i) thinning of wall tube by residual adsorbed acid attack (ii) dew point

corrosion and (iii) hot corrosion.

Recommendations

(i) Inspection of rest of the generation bank tubes, which are vulnerable to attack by

acid adsorbed at the refractories should be checked for corrosion.

(ii) During hydrojetting, pH of the washing affluent of the boiler tubes at different

locations should be monitored and should not be below 7.5.

(iii) It is advised to keep the S and V contamination level in the fuel oil to minimum

by using appropriate additive.

CASE - V :

Failure Investigations of Boiler Tubes, Al-Khafji Plant

Two pieces of wall tubes of rolled area of water drum from boiler # 200 were received

for investigation by the R&D Center.

The specifications of the boiler tube and operation parameters were as follows:

Nature of the failure : Cracks on wall tubes just above expanded and

flared

Area at water drum

Boiler No. : # 200

Years in service : About 13 years

Drum pressure : 20 bars

Tube orientation : Vertical

Wall tube material : ASTM 178A

Tube dimension : 60.8 mm x 3.2 mm

No. of failed tubes : 8, 2 received for investigation

Physical Inspection

Figures 31 shows photograph of the wall tubes in as received condition. In the thick

walled fracture, the cracks appeared to be originating from outside.

Microstructural Studies

The cross-sections of the samples reveal branching associated with the cracks. The

cracks are continuous, intergranular, transgranular or mixed type, running through the

wall tubes (Fig. 32 and 33).

EDAX Studies

EDAX of the cracked area revealed presence of elements like S, V, Cl, Fe, Ni, Mo and

Cu (Fig. 34).

Discussion

Presence of intergranular and transgranular multi-branch cracks and occurrence of thick

walled fracture indicate failure caused by stress corrosion cracking (SCC). There are

two principal causes that govern SCC in the boiler environment. First, the metal in the

affected region must be stressed to a sufficiently higher level. Second, concentration of

a specific corrodent at the stressed metal site must occur. Both the above mentioned

factors are observed to play a role ion SCC of the tube.

Just above the failure site a hole was detected in the super heater inlet header tube. In

order to take out the tubes from the drum, huge amount of green fluid was found while

removing the refractory insulation. It is quite possible that steam leaked from the

superheater and might have condensed at the bottom of the furnace. The condensate

dissolved the soot containing sulfur and vanadium and through the ceramic, led it

seeped down to the outer surface of the drum. Due to dissolution of S and V from soot

and SO3 gas from the combustion gases, condensate must be very corrosive.

Boiler wall tubes are joined to the water drum by expanding and flaring the tubes in the

drum plate hole. It seems during fabrication the tube ends were not stress relieved and

when these tubes with enough residual stresses came into contact with corrosive

condensate, a synergic interaction of tensile stress and a corrodent occurred and

resulted into SCC.

Conclusions

Corrosive condensate formed by the condensation of leaked out steam from superheater

tubes, initiated SCC of wall tubes fixed in the water drum.

Recommendations

(1) The boiler components should be stress free this can be done by altering

operational parameters or redesigning the affected components.

(2) Residual stresses can be relieved by proper annealing.

(3) Presence of corrodent in boiler tube auxiliaries which is responsible for SCC, can

be avoided by keeping internal surfaces sufficiently free of deposits, preventing

in-leakage of condensers, heat exchangers and process steam.

Table 1. Chemical Composition of External and Internal Deposits

Parameters (weight %) S. No. Deposits Description of Tube

Sample V Si Cr Fe Mn Cu Ni Zn Al Ca1 External Flame Impingement

Zone (fire side) 0.5 < 0.1 < 0.1 62.5 - - - - - -

2 External Flame Impingement Zone (wall side) 1.5 < 0.1 < 0.1 62.5 0.4 - - - - -

3 External Non Flame Impingement Zone (fire side) 1.2 0.2 < 0.1 57.8 - - - - - -

4 External Non Flame Impingement Zone (wall side) 0.5 < 0.1 < 0.1 58.7 0.4 - - - - -

5 Internal Flame Impingement Zone - - - 24.5 0.8 27.8 11.

2 3.3 < 0.1 0.5

6 Internal Non Flame Impingement Zone - - - 41.2 0.6 19.3 5.8 2.2 < 0.1 0.5

Table 2. Operational and Design Parameters of Boiler Unit # 63

Design Operation Maximum continuous evaporation, kg/hr Maximum design pressure, Bar ga. Pressure at super heater outlet, Bar ga. Super heater steam temperature oC Feed water temp. at economizer inlet oC

730,000 113.0 93.08 515 oC 235 oC

92 512 224

Air Temperature: Air heater inlet oC Air heater outlet oC

72 oC 315 oC

- -

Flue Gas Temperature: Furnace exist temperature oC Primary superheater inlet temperature oC Air heater inlet temperature Air heater outlet temperature oC

750 oC 820 oC 360 oC 146 oC

- - 337 105

Feed Water: Feed water inlet temperature oC Feed water pressure after regulator Bar ga Feed water temperature entering boiler drum oC

235 oC 1 oC 312 oC

224 102 301

Steam: Steam drum pressure Bar ga. Secondary superheater outlet pressure bar ga. Secondary superheater outlet temperature oC

100.18 93.08 515 oC

390 oC 92 504 oC

Figure 1. Photograph of fire side water wall tubes in as received conditions

Figure 2. EDX profile of external deposits (fire side) collected from the boiler tubes from non flame impingement zone

Figure 3. Microstructure at the center of the weld seam in the unused tube x 100

0 5 10 15 20Energy (keV)

0

10

20

30

40

50

cps

O

Fe

Si S

V

Cr Mn

Fe

Fe

Figure 4. Microstructure at the center of the weld seam in the tube # 4 from non flame impingement zone X 100

Figure 5. Microstructure at the center of the weld seam in the

tube # 3 from flame impingement zone X 100

Figure 6a. Photomicrograph of boiler tube (#1) showing refined grains with evidence of decarburization (fire side) X 100

Figure 6b. Photomicrograph of boiler tube (#1) showing refined

grains with evidence of decarburization (steam side) X100

Figure 7. Photograph of the reheater tubes, Ghazlan Unit # 3

and #4- as in received condition

Figure 8. Photograph of the splitted reheater tube Unit # 3 showing steam side – magnified view

Figure 9. Photograph of the splitted reheater tube Unit # 4 showing steam side – magnified view

Figure 10. Photograph showing (a) reheater tube Unit # 3 (steam side) after cleaning (b) reheater tube Unit # 4 (steam side) after cleaning

(b)

(a)

Figure 11. Photograph of a cross-section of reheater tube Unit # 3 showing steam side scales X 200

Figure 12. Photomicrograph of a cross-section of reheater tube Unit # 3 showing fire side scales X 200

Figure 13. Photomicrograph of a cross-section of reheater tube Unit # 4 showing central portion X200

Figure 14. Photograph showing longitudinal open crack at the bottom of I loop upstream side of the I bend of Boiler # 3

Figure 15. Photograph showing ruptured and sheared tube at the bottom of the 3rd loop upstream side of boiler # 63

Figure 16. Inlet and outlet portions of the ruptured tube at the bottom of the 3rd loop upstream of boiler # 63, HTSH Pendent 67 – As received condition

Figure 17. Inner section of ruptured superheater tube # 63

(Outlet) 3rd loop (HTSH Pendent # 67)

Figure 18. SEM fractograph of the tube (sample location #

1) (I.G.C.)

Figure 19. SEM fractograph of the tube (sample location # 3) (T.G.C.)

Figure 20. SEM fractograph of the tube (sample location # 5) (T.G.C.)

Figure 21. Schematic drawing of the boiler front indicating the

location of generation bank tubes

Figure 22 Ruptured generation bank tube # 9 in as received condition showing front view.

Figure 23. Pictures of ruptured generation bank tube # 9 (end shown inside water drum)

Figure 24. Pictures of broken away refractory installed on the area between generation bank tubes and rear well tubes

Figure 25. Picture of the portion of ruptured generation

tube showing localized attack and metal loss

Figure 26. Photograph of the ruptured tube after removal of the scales (external side) showing pitting and thinning of the tube

Figure 27. Photomicrograph of a cross-section of boiler tube #

9 at a location where the rupture zone ends

Figure 28. SEM photograph of sample #2 showing a deep transgranular crack

Figure 29. EDX profile of the outside scale deposits formed on bank generation tube # 9

0 5 10 15 20Energy (keV)

0

5

10

15

20

cps

O

Cu

Al

Si

S

KCa

V

V

Mn

Fe

Fe

Ni

Cu

Cu

Figure 30. EDX profile of the scales formed at the steam side (inner) of generation bank tube # 9

Figure 31. As received cracked samples of boiler

wall tube taken out from the water drum

0 5 10 15 20Energy (keV)

0

10

20

30

40

50

60cps

O

FeMg

Al

Si

S

K

K VMn

Fe

Fe

Figure 32. Micrograph of the cross-section of the stress corrosion cracks in the boiler tubes shown in Fig. 41. X 200

Figure 33. Micrograph showing intergranular mode of SCC X400

Figure 34. Energy dispersive X-ray analysis (EDAX) of the cross-section of the cracks showing presence of S, V and Cl at the crack