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Engineering Failure Analysis 15 (2008) 182–187

Short communication

Failure of carbon steel tubes in a fluidized bed combustor

V. Kain, K. Chandra *, B.P. Sharma

Materials Science Division, Bhabha Atomic Research Centre, Mumbai 400 085, India

Received 5 May 2006; accepted 5 December 2006Available online 1 February 2007

Abstract

Plain carbon steels are used in power plants for transfer of heat from the flue gases/fluidized bed to water. In the presentstudy, the failure of a few super heater tubes at localized regions in an atmospheric fluidized bed combustor was studied.The main reason of the failure was attributed to high oxidation at these localized regions and spalling off of the oxides dueto high operating temperature and high velocity of the alumina and silica particles in the fluidized bed. Obvious designchanges and/or bandaging with a stainless steel sleeve at the affected regions coming in direct path of the fuel nozzle wererecommended in this case.� 2006 Elsevier Ltd. All rights reserved.

Keywords: Metallurgical failure analysis; Power plant; Boiler tube; Oxidation; Erosion

1. Introduction

Thermal power plants use fluidized bed combustion (FBC) technology to obtain superheated steam. FBCplants [1] are more flexible than conventional plants in that they can be fired on coal, oil and biomass, amongother fuels. Fluidized beds suspend solid fuels on upward-blowing jets of air during the combustion process.This results in a turbulent mixing of gas and solids and the tumbling action, much like a bubbling fluid, pro-vides for more effective chemical reactions and heat transfer. FBC reduces the amount of sulfur emitted in theform of SOx emissions. Limestone is generally used to precipitate out sulfate during combustion, which alsoallows more efficient heat transfer from the boiler to the water pipes used to transfer the heat energy. Theheated precipitate coming in direct contact with the pipes (heating by conduction) increases its efficiency.The fluidized beds have important advantages [2] over conventional pulverized coal boilers like (a) excellentheat transfer, (b) good combustion efficiency, (c) low emission of contaminants and (d) good fuel flexibility.Since this allows coal plants to burn at lower temperatures, less NOx is also emitted. FBC boilers can burnfuels other than coal, and the lower temperatures of combustion (800 �C) have other added benefits as well.

FBC systems fit into essentially two major groups, atmospheric systems (AFBC) and pressurized systems(PFBC), and two minor subgroups, bubbling or circulating fluidized bed. In the present study, failures of

1350-6307/$ - see front matter � 2006 Elsevier Ltd. All rights reserved.

doi:10.1016/j.engfailanal.2006.12.009

* Corresponding author. Tel.: +91 22 25595402.E-mail address: kchandra@apsara.barc.gov.in (K. Chandra).

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superheater tubes in an atmospheric fluidized bed combustion (AFBC) were studied. The fluidized bed was abubbling type bed. This fluidized combustion bed used coal that was low in sulfur and therefore did not use asorbent to control sulfur levels. In this fluidized combustion bed particles of alumina and silica were used formore effective heat and mass transfer. The boiler had a capacity of 45 TPH @ 30 kg/cm2. The failed tubes wereof size OD 44.5 mm and thickness 5.0 mm. The failure had occurred after around two months of operationwhereas the normal expected life in this particular plant is around one year at the prevailing operating con-ditions. The tube material is carbon steel grade SA213-T22, which is a 2.25 Cr-1 Mo type steel with around0.1% (maximum) carbon. The maximum temperature in the combustion bed in this plant is reported to be880–930 �C. The maximum steam temperature is 400 �C inside the super heater tubes. The composition ofthe bed is reported to be 35% minimum alumina and the remaining silica. The size of alumina and silica par-ticles used was 0.6–2.65 mm. The fuel enters the bed at a pressure of 1000 mm (water column) and at the airnozzle the pressure is 600 mm (water column). The bed height is maintained at 600 mm (water column).

2. Failure analysis

2.1. Visual examination

The affected (leaky) tubes in the plant are shown in Fig. 1. The physical appearance of the tube (visualexamination at magnifications up to X20) revealed heavy oxide formation on the OD surfaces of the tube.The tube had suffered from corrosion/oxidation which finally led to the failure. The final failure was evidentas a big hole/rupture of diameter �10 mm. The corrosion had taken place from the OD side and it showed as adepression on the OD surface at the failed region. These features are shown in Fig. 2. The thickness of the tubehad decreased to less than 0.4 mm at the location of failure from the original thickness of 5 mm.

Fig. 1. The failure of the super heater tubes at localized regions leading to tube rupture.

Fig. 2. Visual examination showing (a) thinning from the OD side and (b) the failed region of the tube and the affected region along withthe remaining unaffected region.

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2.2. Stereo microscopic examination

The area around the failed region (from the OD side) was examined under a stereo (video) microscope, andthe micrographs are shown in Fig. 3. The thick oxides (brownish-red in color) formed on the surface of thetube at and around the hole are visible in Fig. 3a. The stereo microscopic examination also revealed thatthe oxide formed on the surface of the tube near the hole had got spalled off which is evident in Fig. 3b. Thisfigure shows the regions close to the hole that do not have an oxide cover and the regions that are covered withoxide. Examination of the OD surface of the tube away from the failed region confirmed that the oxides werepresent all along the length of the tube.

2.3. Microstructure and microhardness

Samples were cut from the failed region of the tube as-well-as from the region away from the failed area.The cross-sections of these samples were mounted, polished to diamond finish and etched in a 2% nital solu-tion. The etched samples were examined under an optical microscope and the microstructures are shown inFig. 4. There was no difference in the microstructures of the samples at the area of failed region and at an areaaway from it. The microstructure consisted of the typical structure of carbon steel i.e. a mixture of ferrite andpearlite phases as shown in Fig. 4. The average grain size was quite fine, around 10 lm. However, the amountof pearlite was quite less in the area close to the ID surface at the failed region, which is evident in Fig. 4b. Themicrohardness was also measured on both the samples of the failed region as well as on the sample away fromit. The test was carried out at a load of 300 g-force and a dwell time of 10 s. The microhardness values were in

Fig. 3. Stereo microscopic examination revealing (a) oxide at nearby regions of the hole, (b) oxide coverage starting some distance awayfrom the punctured region.

Fig. 4. The microstructure of cross-section of the tube sample near the failed region (a) at the mid thickness section, and (b) close to the IDsurface showing lesser pearlite phase.

Fig. 5. SEM micrographs showing (a) bare metal surfaces with scratches (stringers), (b) the scratches and coverage of the metal surfaceswith oxide and (c) thick oxide still present on the regions slightly away from the punctured regions.

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the range of 175–180 HV for both the samples; however the hardness values were slightly less (160–165 HV) inthe area close to the ID surface at the failed region. These observations on microstructure and hardness con-firm that the material of the tube conforms to the SA213-T22 and were not defective.

2.4. Scanning electron microscopic examination

One sample was cut from the failed region of the tube containing the hole (the punctured region) and itsOD surface was examined under the SEM. The SEM micrographs are shown in Fig. 5a and b. Two distinctfeatures were revealed under the SEM: (1) the region very close to the hole showed stringer type marks at loca-tions where the oxide had got spalled off and the bare metal could be seen (2) while the other region at somedistance away from the hole had shown coverage with surface oxide which was intact. Fig. 5c shows the areaslightly away from the hole showing thick oxide on the surface, a part of which had fallen off.

These observations indicate that the failure of the tube had occurred due to heavy oxidation on the ODsurfaces of the tube. These oxides continuously get detached (spall off) from the metal and thus fresh surfacesget exposed to the fluidized bed combustion environment when excessive oxidation takes place. This excessiveoxidation finally leads to thinning and failure of the tube. Fig. 5a and b show the scratch (stringer) type marksat and near the failed regions. These could be due to direct impingement of the combustion gases (along withalumina/silica particles) at the surfaces that are affected (oxides spalled off, exposing base material). At theselocations, erosion due to such a direct impingement could also be leading to spalling off of oxides.

3. Discussion

The failures were in localized regions only on a few super heater tubes. All these tubes were located near thecoal nozzle. It was confirmed from the power plant that these tubes take the direct blast of combustion gases,being just in front of the coal nozzle. In such a case, the main combustion at the location of these tubes wouldbring down partial pressure of oxygen. Such localized regions where the partial pressure of oxygen is lower

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would undergo more corrosion [3,4] due to other factors e.g. higher partial pressure of sulfur at such localizedregions. The thick (sulfide) corrosion products spall off leading to exposure of bare material to this environ-ment and again cause faster corrosion. This cycle of corrosion and spalling off oxides leads to thinning of thetube at localized regions.

Alumina and silica particles of size 0.6–2.65 mm were used in the fluidized bed in this power plant. The ste-reo and SEM examination of the OD surfaces of the failed regions of the tubes did not reveal any indication ofdamage (erosion) due to particles of this size range. This shows that the main degradation of the tube basematerial is due to corrosion and not by erosion of the base material due to alumina and silica particles.

Oxidation corrosion of steels takes place due to the high affinity of oxygen to react with steel to form oxi-des. The kinetics of oxidation process is high at high temperatures. However, oxidation is more favored inoxidizing environments. The OD sides of the tubes are exposed to such an environment in fluidized bedsand therefore undergo oxidation corrosion. From the ID side of the tubes, the oxidation corrosion is notobserved as the water/steam present on the ID side allows formation of adherent oxides on steel surfaces.In the event of turbulent flow inside the tubes, the flow assisted corrosion [5] takes places from ID side ofthe tubes and results in heavy thinning of the tubes. The failed sample from plant clearly showed thinningfrom the OD side of the tubes and as indicated above, it was due to oxidation corrosion.

In the fluidized bed environments, it is reported that there are different wastage – temperature behavior [2]observed in four separate temperature regions. In each region, a different erosion–corrosion regime operates.There are various wastage mechanisms, i.e. (a) oxide chipping, (b) development of a compact and adherentoxide scale, (c) oxide and metal removal, and (d) fracture and spalling within the oxide layer and at thescale/metal interface. In a laboratory fluidized bed (FB) facility in the temperature range from 100 to600 �C, tests were carried out [2] on pin specimens in air using alumina particles of 560 lm average size atimpact velocities from 1.5 to 4.5 m/s. The last mechanism was found to be responsible for high wastage ratesobserved at temperatures above about 450 �C and impact velocities above 3.5 m/s.

In the present case of failure, the localized heavy oxidation had occurred due to high temperature at thoselocalized regions that are in the direct path of coal nozzle. At these locations, the velocity of alumina/silicaparticles is also the highest. This combination of higher velocity and higher temperature at locations directlyin the path of coal nozzle contributed to higher localized oxidation of the superheater tubes. Obviously, chang-ing these conditions (changing the direction of coal nozzle so that no tubes are in the direct path; reducingvelocity of combustion gases so that the velocity of alumina/silica particles is lower than 3–3.5 m/s; reducingthe maximum temperature at regions just ahead of the coal nozzle) would help minimize the localized oxida-tion problems. However, all these remedial actions have a direct impact on the efficiency and output of thefluidized bed. Therefore, a decision keeping these implications in mind has to be taken by the plant.

The 2.25Cr–1Mo steel (SA213-T22) has exceptionally high creep properties, but is limited for applicationsto 595 �C from creep strength point of view and to 580 �C because of possible oxidation at higher tempera-tures [3]. The 9Cr–1Mo (SA213-T91) steel has good oxidation resistance and can be used up to 650 �C andis a cheaper substitute for austenitic stainless steels which show good oxidation resistance up to 815 �C.The air oxidation rates of steel can be classified as excessive/moderate/satisfactory and as a function of tem-perature and alloy composition can be obtained from air corrosion – temperature nomographic chart [6].

In case of the present fluidized bed, the failures are confined to a small zone (in a limited number of tubesthat face the coal nozzle directly). This could be attributed to higher temperatures due to combustion in thislocalized region and/or removal of oxides by erosion from the combustion gases. The oxygen potential alsoreduces at the point of combustion and is reported to lead to higher oxidation rates at such locations. Thisis reported [3,4] to be due to increase in formation of sulfur containing scales that are not adherent and spalloff readily. There was no sulfur containing scale observed on the failure sample examined by us as all the scalehad spalled off from this region. This failure analysis has established the reason to be erosion (spalling) of theoxides that are formed at such locations by the direct impact of the combustion gases. This is shown by thealmost bare metallic surfaces at the failed region whereas other nearby surfaces were covered with protectiveoxides. Therefore, the immediate remedy should be to avoid/minimize direct impact of the combustion gases/bed particles onto the tube regions of interest (failure). This can be done by redesigning the coal nozzle loca-tion such that tubes do not come in direct way of combustion. Under the same conditions of operation, amaterial change to stainless steel (at the location of interest; e.g. use of SS sleeves) is a logical remedy.

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3.1. Remedial action

The following actions were suggested to delay/avoid the failures:

Long term solution:

1. The regions that are usually affected in the super heater tubes should be covered with a sleeve of austeniticstainless steel (SS 310). These stainless steel sleeves can be tag welded or clamped onto the super heatertubes to cover the prone areas. This is usually referred to as ‘‘Bandaging’’ of stainless steel strips ontothe prone regions. This can be easily done in the plant without the need for making changes in the designof the combustion bed or material of construction of the super heater tubes.

2. The super heater tubes made from 9Cr–1 Mo (e.g. SA 213-T91) steel may be used instead of the materialcurrently used (2.25Cr–1 Mo). This material has a much higher resistance against corrosion/oxidation/ero-sion at high temperatures. Otherwise tubes made from stainless steels e.g. SS 304L/SS347 may be used atsuch locations but this requires engineering details that may not be easy to implement.

3. The location of the coal nozzle may be changed in a way so as to avoid a direct impact of the combustionon to the super heater tubes. This is to ensure that no tubes are in the direct path of the coal nozzle.

Solution for implementation in the short term:

1. The velocity of the alumina–silica particles may be reduced (to a maximum velocity of 3–3.5 m/s). From acorrosion point of view, reducing the velocity will reduce the corrosion (oxidation–erosion) rates. However,the plant reports velocities of 1.5–4.5 m/s at the currently operating conditions. Any reduction in velocity,even if feasible, may reduce the efficiency of the fluidized (combustion) bed and this factor should always beconsidered while taking such an action.

2. Passing more air at the locations where failure occurs could also help in reducing the corrosion rate. Thiswill counter lowering of oxygen potential at such locations. However, the rate of flushing with air has to bewell controlled otherwise faster corrosion could take place.

4. Conclusion

The failure of carbon steel tubes used as superheater tubes in a fluidized bed combustor was analyzed. Thereason of the failure was excessive oxidation and spalling off (erosion) of oxides at localized regions of thetubes from the OD side that were in direct path of the fuel nozzle of the fluidized bed combustor. Simpledesign changes in the first case and/or bandaging with a stainless steel sleeve at the regions that are in directpath of the fuel nozzle were recommended.

References

[1] Oakey JE, Pinder LW, Vanstone R, Henderson M, Osgerby S. Review of status of advanced materials for power generation. ReportNo. COAL R224. DTI/Pub URN 02/1509. National Physical Laboratory. UK; 2003.

[2] Chacon-Nava JG, Stott FH, Martinez-Villafane A, Almeraya Calderon, Gonzalez Rodriguez. The erosion–corrosion performance ofSA213-T22 steel in low velocity conditions. ASM J Mater Perf Eng 2001;10(6):699–704.

[3] Stringer J. Corrosion of superheaters and high-temperature air heaters. ASM metals handbook, vol. 13. p. 998–9.[4] Wright IG. Hot corrosion in coal and oil-fired boilers. ASM metals handbook, vol. 13. p. 995–6.[5] Smith CL, Shah VN, Kao T, Apostolakis G. Incorporating aging effects into probabilistic risk assessment – a feasibility study utilizing

reliability physics models. NUREG/CR-5632, USNRC; 2001.[6] Fontana MG. Corrosion engineering. McGraw-Hill; 1987 [p. 525].