Diagnosing Boiler Tube Failures Related to Overheating

Transcription

1 Advanced Materials Research Online: ISSN: , Vols , pp doi: / Trans Tech Publications, Switzerland Diagnosing Boiler Tube Failures Related to Overheating Graham R. Lobley a, Waleed L. Al-Otaibi b Saudi Aramco, Consulting Services Department, Dhahran 31311, Saudi Arabia Fax: a graham.lobley@aramco.com, b waleed.otaibi.1@aramco.com Keywords: short-term overheating, long-term overheating, fuel ash corrosion, carbide spheroidization, graphitization, phase transformation Abstract. Unexpected tube failure is the major factor causing unreliability in utility boilers. The first step in analyzing tube failures is to identify the active damage mechanisms. Three tube damage mechanisms related to overheating are presented and possible root causes are discussed to resolve these tube failures. Damage mechanisms can be recognized by metallurgical evaluation, comprising a combination of both visual and microexamination, complemented by chemical analyses of tube or fireside deposits, as appropriate. Characterizing the degree of microstructural degradation can also help to confirm and separate various potential high temperature tube damage modes, such as long or short term overheating, as well fuel ash attack. Carbon steel is the standard tube material for high pressure boilers (typically up to 625 psig steam) and has a normal design temperature limit of about 440 ºC. However, microstructural changes occurring as a result of higher temperature exposures in service can include carbide spheroidization, graphitization and other transformations. Metallography is powerful tool for evaluating overheated failures and also for fire damage assessment. Evaluating overheated steel microstructures utilizes the principles of steel heat treatment and application of the iron-iron carbide equilibrium diagram. Introduction Boiler tube failures are the major cause of unscheduled shutdowns in the conventional fossil-fired utility plant, perhaps accounting for between 2 to 3% availability loss in the US [1]. Saudi Aramco operates around 80 utility boilers company-wide, producing high pressure steam (mainly at 625 psig) for important plant applications. Approximately 39 % of boiler tube failures are related to overheating (Figure 1). This is based on Saudi Aramco experience, with a sample of 101 failure cases. Fig.1: Boiler Tubes Common Damage Mechanisms All rights reserved. No part of contents of this paper may be reproduced or transmitted in any form or by any means without the written permission of Trans Tech Publications, (# , Pennsylvania State University, University Park, USA-19/09/16,04:48:04)

2 176 Structural Integrity and Failure, 2008 Low carbon steel is specified for these subcritical steam boiler tubes, except superheaters: the bank (generating) tubes are roll-expanded into the steam and mud drums and the waterwall tubes within the firebox are welded together (Figure 2) [2]. Though seamless tubes are often preferred, many electric resistance welded (ERW) tubes are also utilized in boilers. Solving boiler tube failures is ideally performed as an interdisciplinary team effort, to engage design, materials, process and operations engineers. Though this team approach is strongly recommended, the key first step is to correctly identify the damage mechanism by appropriate metallurgical failure analysis. This involves a discovery phase which should gather and review relevant operating history and circumstances associated with tube failure. The importance of gathering relevant background information about the system s design and operational history cannot be over-emphasized, as this simplifies the failure analysis process [3]. This is followed by laboratory examination and evaluation, starting with photography and nondestructive examination, then deposit or scale sampling (fireside or tubeside, as appropriate), finally destructive evaluation to document microstructure and characterize the failure in more detail. Though this microexamination step is relatively time-consuming, it is essential to assess possible microstructural degradation related to overheating damage and also to characterize cracking and fracture morphology. A key reference noted that although the skilled observer can detect and diagnose many failures based solely upon visual inspection, often there is no substitute for laboratory investigations [4]. Fig.2: boiler schematic [2] Case 1: Short-term Overheating Overheating can result in several tube damage mechanisms, including both short or long term overheating and fireside corrosion. The different mechanisms have definite macroscopic and microstructural damage characteristics. Regarding short-term overheating, three different degrees of short-term overheating can be defined, depending on the presence and extent of any metallurgical phase transformation observed [1]. Examination. In the current case, a single waterwall tube failed by overheating, leading to a characteristic wide rupture normally called a fish-mouth rupture (Figure 3). The tube failure in SA178A carbon steel occurred after 22 years service in a gas plant. The boiler had been chemically cleaned about two years prior to the failure. Examination revealed a gaping wide longitudinal split along the tube center line at the hot side. Thinned fracture edges indicated a thin-lipped failure. The tubeside showed little evidence of internal deposits and no pitting or general corrosion. Microstructural examination and hardness testing revealed that partial transformation had occurred during the rapid overheating event (Figure 4). The partially transformed microstructure had an average hardness of 193 HV, versus the

3 Advanced Materials Research Vols cold side average of 114 HV. The microstructure was hardened due to partial transformation to low carbon martensite/bainite. Discussion. The fractured tube had suffered intercritical short-term overheating, as supported by partial phase transformation and the classic thin-lipped fish-mouth rupture characteristics. Following heating into the intercritical (A1 to A3) range, hardening occurs via rapid quenching by the flow of steam and water released by the burst. Regarding root causes of rapid overheating failures, starvation (low flow) is the most probable in this case, since a malfunction of a drum water level control switch was reported by plant inspection. Malfunction of the level control could have caused starvation and failure in one of the tubes. When a rapid overheating event occurs, failure is most likely to occur at one tube location only, resulting in rapid depressurization. Conversely, longterm overheating normally affects several tubes resulting in local bulging and creep failure [4]. Fig. 3: thin-lip, fish-mouth rupture of boiler tube Fig. 4: microstructure at rupture, showing partial transformation, x500 Recommendations. Though no more background information about the failed level switch was provided, it was recommended to periodically check the functionality of level control switches and involve instrumentation specialists to assess reliability and integrity of the switches installed. Case 2: Long-term Overheating Several adjacent boiler screen tubes developed localized bulging, after about 23 years service. The boiler was last chemically cleaned about 5 years before the tube failures. Due to the design configuration, some of the tube failures were located at regions of locally higher heat flux. Examination. Small bulges located on the hot side of the tubes were surrounded by areas showing red-coloured oxides. The tube failures showed longitudinal type ruptures, with multiple parallel secondary cracks and thick-lip type ruptures (Figure 5). Two tubes were sectioned for microstructure examination and additional chemical tests, comprising scale density index, X-ray fluorescence analysis and X-ray diffraction tests. The tubeside deposit included around 40 wt% copper, with 3.3% phosphorus, 3.2% calcium and 1.3% barium. The tube scale was approximately 2.5 mm thick on the hotside, with a measured scale density index of 2218g/m 2. Microstructural examination of hot and cold sides of the tube revealed dramatic differences, with significant microstructural changes as a result of localized high heat exposure on the hot side. On the cold side, the microstructure comprised a normalized fine-grained lamellar pearlite, dispersed in a ferritic matrix. This normalized structure is typical of new tubes, or tubes that have not been overheated in service. At the hot side, the microstructure showed both carbide spheroidization and localized graphitization (Figure 6). Discussion Prolonged exposure of carbon and low alloy steel components to temperatures exceeding 427 C can result in several kinds of material microstructural degradation, including carbide coarsening and/or spheroidization and occasionally graphitization [5]. At higher

4 178 Structural Integrity and Failure, 2008 temperatures, the lamellar or platelet shape of carbide within the pearlite becomes unstable and gradually changes to a spheroidal shape. The internal energy of the carbide is reduced by changing its shape to a sphere. The excess surface energy is the driving force for the change and the process that leads to the new shape is termed spheroidization [6]. The spheroidized iron carbide itself is also unstable and subsequently transforms to graphite and ferrite. Spheroidal graphite particles form during this further microstructural change in a process termed graphitization. Graphitization generally results from the decomposition of pearlite (iron plus iron carbide) into the equilibrium structure of iron plus graphite. When graphitization forms as randomly dispersed nodules, it is mechanically relatively benign [5]. However, when alignment of graphite nodules occurs into planar or chain-like form, this significantly weakens the material, creating the potential for brittle failure along these zones of weakness [5]. Fig. 5: tube showing localized bulging at hot side (right) Fig. 6: microstructure at hot side showing full carbide spheroidization and a graphite nodule, x400 The changes to the shape of iron-carbide leading to spheroidization, and its decomposition into graphite, graphitization, are competing processes. At temperatures above about 540 o C, graphite appears after carbide spheroidization. At lower temperatures, graphitization occurs before the steel is fully spheroidized; that is, the pearlite colonies are still sharply defined, but graphite particles are clearly visible [6]. Since the boiler tube microstructure on the hot side comprised primarily fully spheroidized iron carbides with a few isolated graphite nodules, it is concluded that the tube was overheated for a prolonged period at temperatures exceeding 540 o C. Tubes that are prone to long-term overheating often contain significant internal deposits, experience reduced coolant flow, excessive fire-side heat input, or are near or opposite burners [4]. Slanted tubes, such as nose arches, are prone to long-term overheating due to steam channeling. Failures usually occur in relatively broad areas and often many tubes are either ruptured or bulged [4]. The measured scale density index of 2218g/m 2 at the tube hotside greatly exceeds the normal limits for chemical cleaning to be scheduled. Based on the scaling limits set in an internal practice, when the scale density index exceeds 1000 g/m 2, the boiler should be chemically cleaned before further operation. Scale analyses revealed high levels of copper as well as significant amounts of calcium, barium and magnesium. The former suggests corrosion of heat exchange equipment in the boiler feedwater circuit and the latter possible ingress of raw water into the boiler water system. A recently published case of long-term boiler tube overheating [7], after just 6 months of operation, reported over 6 mm thickness of internal calcium carbonate scale. The root cause was attributed to water treatment problems, during a period when raw water was used in the boiler. Sources of significant deposits must be identified and eliminated [4]. Factors creating deposits can include improper water treatment, system contamination, improper boiler operation, and/or excessive heat input [4]. In the present case, the source of the reported barium was difficult to

5 Advanced Materials Research Vols explain. However, boiler makeup water has subsequently been changed from an original mixture of condensate, distillate and reverse osmosis (RO) water, to entirely RO water, which achieves better and more consistent water quality. Recommendations: were made to perform immediate chemical cleaning of the boiler and optimize water treatment program and operation. Case 3: Fuel Ash Corrosion A fuel oil-fired boiler experienced an emergency shutdown due to tube failure. Inspection revealed that several tubes were in poor condition and 12 bank and bank side wall tubes were subsequently plugged. Tube damage reported by plant inspection included rupture, erosion and bulging, the latter on several tubes. Subsequently, a sample section from a plugged tube was submitted for laboratory evaluation. The purpose was to assess the effectiveness of the existing fuel additive program, which is based on adding powdered magnesia to the fuel oil. The program should prevent possible fuel ash attack, by raising the melting point of the harmful, fusible deposits that can form on the fireside surfaces of tubes in some circumstances. The boiler tubes are specified as carbon steel to SA192. The tube dimensions are 2.6 inch internal diameter, with a nominal tube wall thickness of 4.0 mm (0.157 inch). Examination The tube bank wall section showed fairly heavy fireside deposits upon receipt (Figure 7). XRF elemental analysis on the external fireside deposits revealed high % levels of detrimental elements (vanadium 12.3 wt%, sulfur 10.7 wt% and sodium 1.3 wt%), as well as magnesium (8.1 wt%). X-ray diffraction analysis revealed the presence of 30% sodium vanadium oxide (NaV 6 O 15 ) and 35% magnesium sulphate (Epsomite MgSO 4.7H 2 O). The remaining deposits were then removed in inhibited acid, to examine the external surface condition of the tube. Figure 8 shows an area of intense localized attack on the fireside of the tube. This pock-marked type damage is typical of fuel ash corrosion [9]. The material was locally severely thinned by fuel ash corrosion to below inch (general wall thickness 0.170/0.180 inch). The thinned area was sectioned and microsections were then taken through the thinned area (Figure 9) and on the cold side (Figure 10). The microstructure in the thinned area had been completely modified, showing both spheroidization of the iron carbide phase and limited graphitization, observed as isolated black graphite nodules. This microstructural degradation indicated that the tube had operated at a high local temperatures (Figure 8). Fig.7 bank wall tube as received Fig. 8 intense fuel ash attack evident after cleaning

6 180 Structural Integrity and Failure, 2008 Fig. 9: Spheroidization and graphitization at hot side, x750 Fig. 10: Original pearlitic microstructure at opposite side, x750 Discussion. The majority of company boilers are fired on fuel gas or C2/C3 hydrocarbons; only about 19% of boilers are dual-fired, i.e. fuel oil/fuel gas. Arabian Gulf residual fuel oils are classed as low vanadium (V), low sodium (Na), with typically ppm V, ppm Na and 2.5% S [1]. For these low V, Na residual oils, fireside corrosion is considered to be controlled principally by the formation of liquid alkali sulphates, with small amounts of vanadates [4]. The nominal fuel oil composition at the specific plant is 50 ppm V, 20 ppm Na and 3.5% S. However, with yield improvement programs specifying vacuum residual (typically 120 ppm V) and possible Na excursions due to caustic carryover issues, it is possible that the fuel oil may have increased V and Na levels above the nominal figures. In the present case, in the deposits where fuel ash attack occurred, 12.3 wt% V and 1.3 wt% Na were detected by XRF elemental analysis, so there is a dramatic increase in V and Na at the damaged site. Tube supports for fired heaters are specified in API 650 [10]. If the metal temperature exceeds about 650 C and the combined V plus Na exceed 100 ppm, then either high alloy hardware (50Cr-50 NiCb minimum) or a castable refractory cover are required. This standard specifically recognizes the dangers of relatively low V and Na for tube supports, which are not internally cooled. The intense local external wastage on the tube fireside surface was diagnosed as fuel ash corrosion damage. The fuel additive program is either partially effective or the damage predates implementation of the program. Microstructural degradation confirmed local long-term overheating, which is a factor promoting fireside corrosion damage in residual fuels. Carbon and alloy steels develop corrosion resistance from the formation of protective oxide scales, primarily based on magnetite [8]. Processes that either remove the protective oxides or prevent their formation promote rapid corrosion wastage. The actual cause of this wastage is the rapid oxidation of clean, unprotected steel. Constituents within the oil ash form low-melting-point mixtures [4]. These low-meltingpoint species dissolve the protective iron oxide on the surface of the boiler tube and bring the bare metal into contact with oxygen. The action of these liquids is like a brazing flux dissolving and preventing the formation of a protective oxide film. In oil-fired boilers, mixtures of vanadium pentoxide and sodium oxide or vanadium pentoxide and sodium sulphate are the problem. The exact melting point depends on the relative amounts of sodium and vanadium oxides, but the minimum melting point can be as low as about 550 o C [4]. The extent of microstructural degradation is determined by the degree of overheating above the normal design temperature limit of 440 ºC. Plain low carbon steels such as SA192 and SA178 used for boiler tubes are specified in the normalized heat treatment condition. Normalization produces a fine-grained network of ferrite containing islands of lamellar pearlite. Based on the observed microstructure comprising spheroidized pearlite and isolated graphite nodules, it inferred that the boiler tube was locally exposed to temperatures exceeding 540 ºC, probably up to 600 ºC. With the presence of vanadium and sodium oxides and sulphates, fuel ash corrosion can occur at these estimated metal exposure temperatures (up to 600 ºC). The presence of magnesium compounds should however inhibit this hot corrosion. Although the fuel additive program seems to have been working fairly well, problems with sootblower reliability have promoted accumulations

7 Advanced Materials Research Vols of thick ash deposits. Separate investigators also expressed concern that the boiler tubes may be corroding under these ash deposits. External ash deposits not only impair the overall thermal efficiency of the boiler, but also promote overheating of tubes. If the ash is not removed by soot blowers it accumulates on the boiler tubes, primarily in the main bank tubes. Recommendations. The principal recommendation is to improve reliability of sootblowers and ensure full cleaning of fireside ash deposits at each shutdown. It is also recommended to monitor tube wall thickness at selected locations during shutdown (every two years) and carefully inspect for signs of fireside corrosion, focusing on locations prone or subject to overheating or known to have had heavy accumulations of fireside ash deposits. Summary Correctly diagnosing boiler tube failures due to overheating can be challenging at several levels. First, collecting appropriate samples is sometimes difficult and the available relevant background information is often incomplete. Second, laboratory evaluation requires skilled interpretation of microstructural degradation and chemical analysis data. A key factor in understanding overheating failure modes is metallographic interpretation of degraded microstructures, which requires understanding of ferrous heat treatment principles and application of the iron-iron carbide equilibrium phase diagram. Ideally, a small team of discipline specialists and operations personnel should work together to identify potential root cause factors. References [1] R. B. Dooley, W. P. McNaughton, Boiler Tube Failures: Theory and Practice, EPRI, Palo Alto, CA, [2] Saudi Aramco internal course material. [3] M. J. Esmacher, Avoiding Potential Problems in Diagnosing Boiler Tube Failure Mechanisms, 1998 International Water Conference, Pittsburgh, Pennsylvania, USA. [4] H. Herro, R. D. Port, Nalco Guide to Boiler Failure Analysis, ASM, 1991 [5] J. R Foulds, R. Viswanathan, Graphitization of Steels in Elevated-Temperature Service, Journal of Materials Engineering and Performance, Vol.10, No. 4, August 2001, ASM, pp (9). [6] D. N. French, Microstructural Degradation, January 1991 National Board Bulletin, ASME. [7] J. J. Perdomo, T. D. Spry, An Overheat Boiler Tube Failure, Journal of Failure Analysis & Prevention, Vol 5(2), April 2005, ASM. [8] D. N. French, Fuel Ash Corrosion, Fall 1992 National Board Bulletin, ASME [9] Boiler Tube Analysis, Babcock & Wilcox. [10] API 560, Fired Heaters for General Refinery Services-Fourth Edition 2007.