CORROSION OF BOILER TUBES SOME CASE STUDIES 1

ABSTRACT CORROSION OF BOILER TUBES SOME CASE STUDIES 1 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 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 4 th 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 o C.

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/cm 2 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 3 rd 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 H 2 SO 4 ) 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 H 2 SO 4 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 SO 3 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 S. No. Deposits Description of Tube Parameters (weight %) Sample V Si Cr Fe Mn Cu Ni Zn Al Ca 1 External Flame Impingement Zone (fire side) 2 External Flame Impingement Zone (wall side) 3 External Non Flame Impingement Zone (fire side) 4 External Non Flame Impingement Zone (wall side) 5 Internal Flame Impingement Zone 6 Internal Non Flame Impingement Zone 0.5 < 0.1 < 0.1 62.5 - - - - - - 1.5 < 0.1 < 0.1 62.5 0.4 - - - - - 1.2 0.2 < 0.1 57.8 - - - - - - 0.5 < 0.1 < 0.1 58.7 0.4 - - - - - - - - 24.5 0.8 27.8 11. 2 3.3 < 0.1 0.5 - - - 41.2 0.6 19.3 5.8 2.2 < 0.1 0.5

Table 2. Operational and Design Parameters of Boiler Unit # 63 Maximum continuous evaporation, kg/hr Maximum design pressure, Bar ga. Pressure at super heater outlet, Bar ga. Super heater steam temperature o C Feed water temp. at economizer inlet o C Air Temperature: Air heater inlet o C Air heater outlet o C Flue Gas Temperature: Furnace exist temperature o C Primary superheater inlet temperature o C Air heater inlet temperature Air heater outlet temperature o C Feed Water: Feed water inlet temperature o C Feed water pressure after regulator Bar ga Feed water temperature entering boiler drum o C Steam: Steam drum pressure Bar ga. Secondary superheater outlet pressure bar ga. Secondary superheater outlet temperature o C Design 730,000 113.0 93.08 515 o C 235 o C 72 o C 315 o C 750 o C 820 o C 360 o C 146 o C 235 o C 1 o C 312 o C 100.18 93.08 515 o C Operation 92 512 224 - - - - 337 105 224 102 301 390 o C 92 504 o C Figure 1. Photograph of fire side water wall tubes in as received conditions

cps 50 Fe 40 30 20 O 10 Fe V Fe 0 Si S Cr Mn 0 5 10 15 20 Energy (kev) 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

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

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

Figure 17. Inner section of ruptured superheater tube # 63 (Outlet) 3 rd 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 cps 20 Fe 15 10 V O Al 5 S Cu Si Ca K V Mn Fe Ni Cu Cu 0 0 5 10 15 20 Energy (kev) Figure 29. EDX profile of the outside scale deposits formed on bank generation tube # 9

cps 60 Fe 50 40 30 20 O 10 0 Fe Al Mg Si S K K V Mn Fe 0 5 10 15 20 Energy (kev) 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

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