OVERHEATING AND FUEL ASH CORROSION FAILURE OF BOILER TUBES IN SWCC POWER PLANTS - Some Case Studies 1

Transcription

1 OVERHEATING AND FUEL ASH CORROSION FAILURE OF BOILER TUBES IN SWCC POWER PLANTS - Some Case Studies 1 ABSTRACT Nausha Asrar, Anees U. Malik and Shahreer Ahmed Research and Development Center Saline water Conversion Corporation P.O.Box 8328, Al-Jubail, Kingdom of Saudi Arabia. Dhib Al-Subaii Al-Khobar Power and Desalination Plant, Al-Khobar And Izdein M. Said Al-Khafji Power and Desalination Plant, SWCC Results of investigations of the failure of boiler tubes of SWCC power plants at Al- Khafji and Al-Khobar are presented. Cause and mechanisms of failure are discussed and recommendation for prevention of reoccurrence of such failures are provided. Case - I Failed boiler tubes of Al-Khobar plant were received. The tubes had circumferential cracks and blown up portions. All the failures were detected on the fire-side surfaces of the tubes. Presence of sulfur in the oil ash deposits on the fire-side of the tubes appears to be the main cause of failure of boiler tubes. The cracking of the tube at the weldment was due to the combined effect of S-induced corrosion and welding stresses. Circumferential fissures initiated by the molten ash were enhanced greatly due to welding stresses and resulted in the cracking of tube at the weldment. It is recommended to avoid high sulfur in the fuel and to maintain a low metal temperature (below 480 o C) in the boiler. Case - II Superheater tubes of boiler # 100 ad 200 of Al-Khafji plant were found ruptured. The rupturing and hole formation in the superheater tubes is the result of long term overheating of the tubes. Thinning of tube walls occurred due to localized deposits and 1 Presented in Second Acquired Experience Symposium on Desalination Plants O&M, SWCC, Al-Jubail, Sept.29-Oct.3,

2 overheating problems. For avoiding reoccurrence of such failures it is recommended to carry out regular inspection of scale deposition on the steam/water side surface and measurement of deterioration in the boiler tube thickness. If the amount of the deposits has crossed the allowable limit, cleaning of the tubes should be carried out immediately. INTRODUCTION The failure of industrial boilers has been a prominent feature in fossil fuel fired power plants. The contribution of one or several factors appear to be responsible for failures, culminating in the partial or complete shutdown of the plant. The use of high sulfur or/and vanadium-containing fuel, exceeding the design limit of temperature and pressure during operation, and poor maintenance are some of the factors which have a detrimental effect on the performance of materials of construction. A survey of the literature [1-8] pertaining to the performance of steam boilers during the last 30 years shows that abundant cases have been referred to, concerned with the failure of boilers due to fuel ash corrosion, overheating, hydrogen attack, carburization and decarburization, corrosion fatigue cracking, stress corrosion cracking, caustic embrittlement, erosion, etc. Oil ash corrosion which is quite common in utility boilers is originated from the vanadium present in the oil. Vanadium reacts with sodium, sulfur, and chlorine during combustion to produce low melting point ash compositions. These molten ash deposits on the boiler tube surfaces dissolve protective oxides and scales, causing accelerated tube wastage [3]. Corrosion problems in boiler tubes arisen due to overheating are quite common. This mode of failure is predominantly found in superheaters, reheaters, and water wall tubes, and in the result of operating conditions in which tube metal temperature exceeds the design limits for periods ranging from days to years. The phenomenon of overheating is manifested by the presence of significant deposits, which impart a reduction in water flow and excessive fire-side heat input. Due to this rise in temperature, steel loses its strength, causing rupture or bulging of the tube due to internal pressure. In a recent investigation [9], three case studies in two 1800 psig boilers are described. The failures have been attributed to accelerated corrosion, hydrogen attack and overheating. In another study, corrosion of stainless superheater tubes occurred due to carburization resulting in intergranular wastage of steel near the exposed surface [10]. Use of fuel oil high in S, V, and asphalt content in a plant, after 1412

3 about 12 years service, resulted in deposition of carbon coke and soot particles on the tube surface and introduced a carburization process in the steel matrix [11]. Gabrielle [12] overviewed the water related tube failures in industrial boilers. The causes of the majority of failures are attributed to the upset in water quality and/or steam purity. The mechanisms of failures due to overheating (short term and long term), water-side corrosion, general surface attack, stress-assisted corrosion, caustic embrittlement, hydrogen damage, and chelant corrosion have been discussed in detail. This paper presents the results of two separate investigations carried out to determine the causes of failure of boiler tubes of Al-Khobar and Al-Khafji Power and Desalination Plants. The main aim of this investigation is to acquaint the operation and maintenance personnel with the different corrosion modes involved in failures, and to suggest some measures for preventing the recurrence of such failures. CASE - I : SULFUR INDUCED CORROSION AND STRESS ENHANCED CORROSION GENERAL DESCRIPTION Failed tubes, designated as A and B of Al-Khobar plant were from the tertiary superheater area. All the tubes were first examined by nacked eyes and then under a stereo microscope and the failed area were marked by arrow (Fig. 1 a. and b). Following were the as received conditions of the above tubes. Tube A. : This tube (OD 45 mm thickness 6 mm) was cracked circumferentially at the HAZ of the weld and was found in two pieces. The fire-side surface was covered with a brown color adherent oxide scale while the steam side surface was covered with black oxide scale (Fig. 1 b). Tube B : In tube B (OD 45 mm, thickness 6 mm) a ~ 30 mm long ~ 20 mm wide burst was found. Thickness of the lip of the burst was same as the thickness of the tube wall. This indicates that this area of the tube had blown up without bulging of the tube. 1413

4 In addition to this burst, large number of circumferential cracks, originating at the fireside surface of the tube and going deep into metal matrix, were also observed. Material Analysis Materials of A and B tubes were analyzed with the help of EDAX and their carbon level was determined by Carbon-sulfur analyzer. The composition of Tube A was found similar to 1¼ Cr 0.5 Mo steel (ASTM grade A213 T12) and tube B as 2½ Cr 1.0 Mo steel (ASTM grade A 213 T22). Microstructural and Elemental Analyses A small cross-section of the failed area was taken from the failed zone of the tube and mounted in conductive resins. Mounted specimens were abraded, polished, etched, dried and their metallographic studies were carried out under the metallurgical microscope. Metallographs of the tube A revealed that on fire-side surface of the tube thickness of oxide scale is not uniform and the corrosion is intergranular in nature (Fig.3 On fireside surface of the tube B, many grooves starting from the surface and going deep into the matrix were revealed by optical metallography. One of the grooves showing corrosion product within the canal of the groove is shown in the Figure 4. On the fireside surface the oxide scale were very fragile in nature and, therefore, were broken during polishing of the sample. In order to understand the chemistry of oxide scales, metal matrix and inclusions found inside the cracks, EDAX and EPMA techniques were used. Figure 5 is the characteristic EPMA composition profile of the oxide scale formed on the fireside surface of the boiler tube A. In these images sulfur is recognized in the innermost layer of the oxide scale. Corrosion product present in the grooves of the fireside surface of the tube-b was analyzed by EPMA. Figure 6 shows presence of sulfur at the growing tip of the grooves. DISCUSSION 1414

5 Bunker-C oil is used for fuel in power plants. During the distillation process, virtually all the metallic compounds and a large part of the sulfur are concentrated in the residual fuel oil. The fuel oil constituents that are reported to have the maximum effect on oil ash corrosion are vanadium, sodium, sulfur and chlorine. According to chemical analysis of deposits, formed on superheater tubes (Table - 1), sulfur content increases when vanadium content is reduced in the deposits [13]. Our EDX analysis and EPMA results showing no vanadium and considerable amount of sulfur in the corrosion product is in consistent with the findings of Tomozuchi et. al., [13]. Microscopic studies of the corroded areas of the boiler tubes have revealed selective corrosion of the grain boundaries of the tubes (Fig. 3). Chemical analysis of the corrosion products indicates that sulfur is one of the major causes of the failure of the fire-side surfaces of the boiler tubes. Sulfur-Induced Corrosion Sulfur typically is found as sodium sulfate in fuel ash. At high temperature it dissociates according to the following reaction [14]. Na 2 SO 4 Na 2 O + SO 3 The reaction products will alter the basicity of the molten ash deposits. Sulfur reacts with sodium in the melt altering the concentration of Na 2 O, and thereby changing the corrosion rates. The melting of deposits depends on the Na + S/V ratio and it ranges from o C. Observation of the corroded parts through optical microscope has revealed grooving and selective corrosion of the grain-boundaries. EPMA results show presence of only sulfur beneath the oxide scales. These results indicate that the failure of the boiler tubes is due to sulfur induced corrosion and, therefore, the tube metal temperature must have raised above 480 o C. As the intergranular corrosion of the fireside surface of the tubes 1415

6 increases the mechanical properties of the tube metal deteriorates. Under these circumstances if the temperature and pressure of the tube elevate abnormally due to some reason, the tube will burst. Figure 6 is the EPMA sulfur print of the grooving. Existence of abundant sulfur at the tip of the groove proves that the reaction by alkali sulfate compounds play an important role in the grooving corrosion. During this corrosion the end of the corroded part grows deep into the metal matrix. Stress Enhanced Corrosion In the case of tube A it appears that the weldment was not stress relieved. When corrosive conditions are prevalent, the current flow between the anodic and cathodic half cells (stressed and unstressed regions respectively) is greatly enhanced. The welding stresses of tube A, therefore, might have enhanced the growth of the fissures caused by sulfur induced corrosion and this resulted into the cracking of the tube at the weldment. CASE - II : LONG TERM OVERHEATING GENERAL DESCRIPTION The strength of carbon steel remain nearly constant up to about 454 o C. Above this temperature, steel begins to loose its strength rapidly. If the tube metal temperate is gradually increased beyond this temperature, it will plastically deform and then rupture. The approximate time to rupture is a function of the hoop stress (related to internal pressure and tube dimension) and the temperature. The localized nature of the overheating is a consequence of the fact that deposits do not form uniformly along the time. The deposits, occur in locations of high heat flux. Deposits may also favor areas where physical drop out of suspended solids is more likely, such as weld backing rings or sloped tubes. These deposits insulate the metal from the cooling effects of the water, resulting in reduced heat transfer into the water and increased metal temperatures. 1416

7 As the local regions develop hot spots, bulging of the tube occurs which results into the rupturing of the tube (Fig. 7). IDENTIFICATION Overheating failures caused by the insulating effect of deposits can invariably be recognized by the formation of blisters in the tube. These blisters represent a localized area of the tube that underwent creep deformation. Presence of thick, brittle, dark oxide layers on both internal and external surfaces indicate the occurrence of long-term overheating. Reduction in wall thickness and increase in OD of the tube (Fig 8) show the extent of oxide scale formation and bulging of the tube. Bulging usually causes spalling of deposits at the bulged site, which reduces the thickness of the wall tube. Due to prolonged thermal oxidation and thinning of the tube wall a hole appeared on the fireside (Fig. 7a). Superheater tubes shown in Figure 7b, were ruptured longitudinally due to high pressure and thinning of the tube wall. Here the broad mouth of the rupture indicates that the ruptured tubes remained in the furnace for long period during which its lip were heavily oxidized at high temperature and corrosion products were eroded due to flow of steam. Presence of S and V has been identified by EDAX in the oxide scales on the fireside surface of these tubes (Fig. 9 and 10). DISCUSSION Long-term overheating is a chronic problem. It is the result of long-term deposition and/or long-term system operating problem. Heavy deposition on steam and fireside surfaces of water wall or superheater tubes insulates the tube wall from the cooling effect of water or steam. Deposits on superheater tubes caused by carryover and/or contaminated water can produce overheating. Heavy deposition on the steam-side surfaces of the failed tubes is expected also due to its slant orientation. Other probable sources of overheating could be overfiring, incorrect flame pattern, restricted coolant flow. In order to avoid this problem, headers, U-bends, long horizontal runs and the hottest areas should be inspected for evidence of obstruction, scales, deposits and other foreign materials. Sometimes, excess deposits are removed by chemical or mechanical 1417

8 cleaning. Also firing procedures, and furnace temperature near the overheated areas should be checked. CONCLUSIONS 1. Presence of sulfur in the oil ash deposited on the fireside surfaces of the tube appears to be the main cause of the failure of the boiler tubes at Al-Khobar Power Plant. 2. The mode of failure is intergranular corrosion attack induced by molten ash deposits when the tube metal temperature was raised above normal working temperature, i.e., 480 o C. 3. Cracking of the tube A of Al-Khobar plant at the weldment is due to the combined effect of sulfur-induced corrosion and welding stresses. Circumferential fissures initiated by the molten ash were enhanced greatly due to the welding stresses and resulting into the cracking of the tube at the weldment. 4. Rupturing of superheater tubes of boiler # 100 and 200 at Al-Khafji plant and hole formation in the superheater tube of boiler # 200 are the results of long-term overheating of the tubes. 5. Thinning of the tube walls is due to localized deposits and overheating problem. 6. Ruptured tubes of boiler # 100 and # 200 remained unattended in failed condition for a long period due to which most of its lip portion were burned. RECOMMENDATIONS 1. Periodic analysis of the fuel ash deposits on boiler tubes is recommended for determining the amount of sodium, sulfur and vanadium which are responsible for corrosion. 2. The use of high sulfur in the fuel and increase in the tube metal temperature should be avoided. 1418

9 3. SWCC should establish its specification for the maximum amount of the sulfur and vanadium in the fuel oil and stable zone of gas and metal temperature. 4. All the operation parameters of the boiler should be strictly maintained and monitored properly. 5. Scale deposition on the steam/water side surface and thickness of the boiler tubes should be inspected as soon as possible. If the amount of the deposits has crossed the allowable limit, cleaning of the tubes should be carried out at the earliest. REFERENCES 1. Reid, W. T. External Corrosion and Deposits - Boilers and Gas Turbines. New York :Elsvier, Stringer, J. High Temperature Problems in the Electric Power Industry and their Solutions, in High Temperature Corrosion. Ed., R. A. Rapp. Houston : National Association of Corrosion Engineers, 1983, p French, D. N. Liquid Ash Corrosion Problems in Fossil Fuel Boilers, Porc, Electrochem Soc., (1983), 83-85, p Corrosion in Fossil Fuel Power Plants, in Metal Handbook, Vol. 13 ed. B. C. Syratt, Metals, Park, Ohio : American Society for Metals, 1987, p Porta R. D. and H. M. Herro, The Nalco Guide to Boiler Failure Analysis. New York : McGrawll Hill, Dooley, R B. Boiler Tube Failures - A Perspective and Vision, Proceedings International Conference on Boiler Tube Failures in Fossil Plants, Palo Alto, California : EPRI, Calannino J., Prevent Boiler Tube Failure Part I : Fire-side Mechanisms, Chemical Engg. Progress, October, 1993, p Calannino, J. Prevent Boiler Tube Failures Part II : Waterside Mechanisms, Chemical Engg. Progress, November 1993, p Hendrix, D. E., Hydrogen Attack on waterwall Tubes in High Pressure Boilers, Materials performance, (1995), 32(8), p

10 10. Lopez-Lopz, D., Wong-Noreno, and L. Martinez, Usual Superheater Tube Wastage Associated with Carburization, Materials Performance, (1994), 33(12), p Paul, L. D. and R. R. Seeley, Oil Ash Corrosion - a Review of Utility Boiler, Corrosion, (1991), 47, p Gabrielli, F. An Overview of Water-Related Tube Failure in Industrial Boilers, Materials Performance, (1988), 27(6), p T. Kawamura and Yoshio Harada, Control of Gasside Corrosion in Oil Fired Boilers, Mitsubishi Tech. Bulletin, No. 139, May, L. D. Paul and R. R. Seelay, Oil Ash Corrosion - A Review of Utility Boiler Experience, Corrosion, Feb. 1991, p Table 1. Chemical Analysis of Deposits Formed on Superheater Tubes (At steam temperature 571 o C) [Ref. 13] Fuel/Sulfur (%) V 2 O 5 (ppm) ph 1g/ 100 ml H 2 O Acid Insol. Matt (%) Total C as C (%) Total S as SO 3 (%) Total Fe as Fe 2 O 3 (%) Total V as V 2 O 5 (%) Total Ni as NiO (%) Total Na as Na 2 O (%) Total Ca as CaO (%) Total Mg as MgO (%) SO 3 + V 2 O 5 + Na 2 O (%)

11 Figure 1. Boiler tube - A of Al-Khobar plant showing crack at the weldment Figure 2. As received boiler tube-b with circumferential cracks and failure opening 1421

12 -. Figure 3. Magnified view of Fig.6 showing intergranular corrosion by molten ash (X800) 1422

13 Figure 4. Optical micrograph of cross section of grooving of tube-b (X l00) 1423

14 @ Figure 5. EPMA micrograph and composition profile of oxide scale formed on fireside surface of the boiler tube-a Figure 6. EPMA picture and composition profile of cross section of grooving on the tire-side surface of the boiler tube - B 1424

15 * \ Figure 7(a). Superheater tube of boiler #200 showing hole and portion of ruptured (b) superheater tubes of boiler # 100 and # 200. The tubes have experienced longterm overheating. Tubes in (b) remained in the furnace for very long period after rupturing and burned its lips considerably. 1425

16 Figure 8. As received condition of the boiler tube-c 1426

17 Figure 9 EPMA micrograhp and composition profile of oxide scale formed on fireside surface of the boiler tube-d 1427

18 f\ Figure 10. EDAX result of the oxide scale formed on the fireside surface of the raptured superheater tube of unit #