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Failure analysis of boiler tube at a petrochemical plant
Engineering Failure Analysis 106 (2019) 104146
Contents lists available at ScienceDirect
Engineering Failure Analysis journal homepage: www.elsevier.com/locate/engfailanal
Failure analysis of boiler tube at a petrochemical plant ⁎
R. Khadem Hosseinia, , Sh. Yareieeb a b
T
Corrosion Research Group, Research Institute of Petroleum Industry (RIPI), Tehran, Iran Research and Elite Club, Saghez Branch, Islamic Azad University, Saghez, Iran
A R T IC LE I N F O
ABS TRA CT
Keywords: Boiler tube Short-term overheating Finite element analysis Failure analysis
This research aims to assess the failure analysis of a boiler tube of a steam generation system at a petrochemical plant. To achieve this goal, firstly visual observation and thickness measurements were made to detect different features of failure. Secondly optical microscope and scanning electron microscope (SEM) were used observing the microstructures and also hardness measurements were carried out for metallurgical evaluation. Additionally, phase composition of deposits was studied by using X-ray diffraction (XRD). Also, the on-site water composition of the boiler was taken into consideration. Finally, Finite Element Analysis (FEA) was performed to model the condition of the tube before failure. Based on the results, “short-term overheating” was recognized as the root cause of the boiler tube failure.
1. Introduction In petrochemical plants, steam generation and its distribution system are inseparable parts consisted of internally pressurised components such as boiler and superheated steam tubes that generally operate at high temperatures [1]. The major problem in all boilers is the failure of boiler tubes that leads to forced outage of them. Several failure mechanisms are known [2]. The causes of failure range from those caused by high temperature to others associated with corrosion factors [3]. Corrosion in steam generator units, particularly in tubes, is mostly influenced by chemistry of water, tubing material susceptibility, operational conditions, and thermal and mechanical stresses. Phosphate corrosion and caustic corrosion are two detected mechanisms that occurred as a result of water treatment programs in boilers [4,5]. Low quality coal may contribute to coal-ash corrosion in coal-fired boiler tubes [6,7]. Stress corrosion cracking (SCC) can be a reason for failure when necessary condition including susceptible material like stainless steel 304 and stress exist. The residual stresses adjacent to weldments can be considered the source of stress [8]. Besides this fact, the high temperature damage is the most important failure mechanism in boiler tubes that can occur in different ways including oxidation, creep, microstructural changes as a result of overheating or interaction with the environment, thermal fatigue, low cycle fatigue or combinations of them [9]. Creep is the root cause of 30% of all tube failures in boilers and reformers by itself [10]. Overheating is another main reason for premature rupture of reheater and superheater tubes. This phenomenon may cause a reduction of strength because of a change in metallurgical structure and therefore lead to stress rupture [11]. Overheating can be either short-term [12,13] or long-term [14]. The short-term overheating takes place when tubes are exposed to high operating temperature, typically above the eutectoid transformation temperature of 727 °C, and it exhibits a thin-lipped longitudinal rupture with tube bulging, while long-term overheating is related to operating temperature above 454 °C, and can lead to tube bulging or thick-lipped ruptures [15]. Since the change in microstructure can occur due to high temperature in these failures [16], microstructural examination is used as an efficient method to recognize the type of overheating failure, as well as fracture morphology
⁎
Corresponding author. E-mail address: [email protected] (R.K. Hosseini).
https://doi.org/10.1016/j.engfailanal.2019.104146 Received 7 February 2019; Received in revised form 17 July 2019; Accepted 15 August 2019 Available online 17 August 2019 1350-6307/ © 2019 Published by Elsevier Ltd.
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Table 1 On-site measured control parameters of the steam drum water. pH
Conductivity μs cm−1
Sodium ppm
Chloride ppm
Phosphate ppm
9
11
2.2
trace
3.6
[17]. This study aimed to investigate the causes of boiler tube failure at a petrochemical plant. Toward this aim, macroscopic evaluation and hardness measurements of failed tube were compared to a sound tube. Microscopic examinations, including light microscope and scanning electron microscope (SEM), were carried out to observe the microstructure of failed tube samples. Also, phase composition of the deposit sample picked from the internal surface of the failed tube was studied by using X-ray diffraction. In addition to experimental evaluations, Finite element analysis as the numerical method was carried out to illustrate and deduce the failure mechanism and root cause. 2. Experimental procedures 2.1. Operational facts The studies were performed on a failed steam tube in a flue gas boiler working parallel with the other two boilers in the unit of waste heat recovery, with a mutual steam drum which produces high pressure steam for ammonia production plant by 220 ton per hour. Boiler design temperature and pressure of tubes were 325 °C and 11.7 MPa, respectively. The failed tube was located 4 m under the roof of combustion chamber and had been in service for more than 30 years. Inspection histories had not shown detectable damage before the failure. Because of problems with the instrumentation of controlling the level of the steam drum, boiler tubes have been exposed to water shortage and have caused tube failure, recently. Corrosion is monitored by controlling pH and conductivity and by measuring sodium, chloride and phosphate concentrations of steam drum water. Table 1 presents these parameters, as collected on site, in time of failure. 2.2. Visual observations Fig. 1 shows the cross section of the failed tube and sound tube. Although the examination of the failed tube surface indicates that the thickness of cross section differs in different sections, the sound tube has no noticeable change in thickness. As shown in Fig. 1a, the thickness of 13 points of the cross section of failed tube was measured by Sonatest A-Scan ultrasonic thickness gauge on the circumference of tube at 30° intervals given in Table 2, from "A" to "M". The results revealed that the least thickness was seen in the adjacent areas to the failure opening with 3.56 mm, and the largest one was in areas away from the failure opening with 5.11 mm. According to the specification, the nominal outer diameter and thickness of tubes were 63.5 mm and of 5.01 mm, respectively. Based on the 7 points measured thickness of cross section of the sound tube, "N", "O" and "Q" to "U" (Fig. 1b), the changes in thickness were in the range of 4.61 mm to 5.01 mm (Table 3). On the other hand, the failed tube was oval where the maximum and minimum outside diameters are 75.5 and 68.5 mm, respectively, with a 10% deviation from the circularity of the original size. Based on the standard of an equivalent grade of the tube, the difference in outside diameter readings in any one cross section shall not exceed 1.5% of the specified outside diameter [18]. The measured outside diameter of the sound tube was 64.0 mm to 64.5 mm which meets standard requirements. Besides the external examinations, the internal surface of tubes was observed. As shown in Fig. 2a, although the rust and thin blocky shaped black deposits were seen on the internal surface of the failed tube, this feature is not visible on the internal surface of the sound tube (Fig. 2b).
Fig. 1. The cross section of (a) the failed tube, and (b) the sound tube. 2
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Table 2 The wall thickness of cross section of the failed tube according to Fig. 1a. Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
A B C D
3.56 3.79 4.20 4.51
E F G H
4.70 4.95 5.11 4.99
I J K L
4.90 4.72 3.85 3.76
M
3.62
Table 3 The wall thickness of cross section of the sound tube according to Fig. 1b. Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
N O
4.61 4.65
P Q
– 4.93
R S
4.90 4.95
T U
4.97 5.01
Fig. 2. The internal surface of (a) the failed tube, (b) the sound tube.
2.3. Tube material characterization The chemical composition of the tube sample was analysed by using spark emission spectrophotometry with worldwide Analytical systems AG (model PMI–Master). Table 4 presents the chemical composition of the tube material that is consistent with the standard (DIN 17175–79) [19]. The results conform to the specifications for the steel grade ST.45.8. 2.4. Hardness measurement Hardness test was performed on the cross section of 13 points of the failed tube and 8 points of the sound tube, indicated in Fig. 1, by using Karl Frank 38,106 hardness tester and the Rockwell Type B (HRB) method [20]. According to Table 5, although the hardness of failed tube changed from 73.5 HRB to 94.5 HRB and also the nearest areas to the opening of the failed tube were the maximum, the hardness of the sound tube had no significant fluctuation. 2.5. Microscope analysis To perform microscopic analysis optical Olympus BH2-MJL microscope and TESCAN MIRA3 field emission gun scanning electron microscope (FEG–SEM) were used. Specimens were cut from the failed tube along the failure and away from the opening, at 180° apart along the circumference, to detect variations in microstructure on the circumference of the tube. Both longitudinal and transverse samples were examined, marked 1 to 4 as shown in Fig. 3. The samples were polished using a series of emery papers and finished with diamond polishing and then etched with 2% Nital etchant (2 ml HNO3 in 100 ml of ethanol). . Table 4 Chemical composition of the tube material compared to the standard (wt%). Elements
C
Mn
Si
S
P
Cr
Fe
Tube material DIN 17175-79 Gr. ST. 45.8
0.13 0.21
0.72 0.4–1.2
0.24 0.1–0.35
0.031 0.040
0.022 0.040
0.25 -
Balance Balance
3
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Table 5 Rockwell B hardness values of the cross section of the failed tube and sound tube according to Fig. 1. Point
Hardness (HRB)
Point
Hardness (HRB)
Point
Hardness (HRB)
A B C D E F G
94.5 93.0 88.5 87.0 80.5 77.5 73.5
H I J K L M N
76.5 79.5 83.0 87.0 90.5 93.0 73.0
O P Q R S T U
75.0 76.0 78.5 77.0 78.0 72.5 71.0
Fig. 3. Prepared samples from the adjacent and the opposite side of failure opening for microstructural analysis.
The optical micrographs of the specimens in the adjacent regions to the failure opening marked 1 and 2 corresponding to Fig. 4a and b, respectively. The microstructures contain martensite blocks (M) in the ferrite matrix (F) and also few carbides (C) near the grain boundaries. The microstructure of samples on the opposite side of the opening, namely 3 and 4, presented in Fig. 4c and d, respectively, were normal ferrite (F) and pearlite (P). There were no discontinuities or creep voids in any of the microstructures. Fig. 5 shows SEM images at different magnifications taken on the surface of cross section of the tube wall, namely 2 and 4, according to Fig. 3. As presented in Fig. 5 a-c, SEM micrographs of specimen 2, from the near area to the failure opening, reveal martensite islands (M) in a ferritic matrix (F) and also few carbides near grain boundaries (C). However, Fig. 5 d-f, showing SEM micrographs of specimen 4, from the opposite side of the opening, shows microstructures consisted of normal ferrite (F) and perlite (P). Layer of perlite is well visible in Fig. 5f. X-ray diffraction (XRD) analyses were applied to determine different phases of the deposit components. To do this, the deposit sample picked from the internal surface of the failed tube (Fig. 6a), was prepared on zero scattering foil and step-scanned in a STOE Stadi P diffractometer using unfiltered Cu Kα radiation. The step size was 0.02°/s in the range of 5°-120°. The voltage and current of the machine were 40 kV and 30 mA, respectively. The diffractogram of the deposit shown in Fig. 6b indicated that the analysed deposit consists of two main ferrous oxides; hematite (Fe2O3) and magnetite (Fe3O4). As shown in Fig. 6a, the deposit was magnetized, which can be due to the presence of magnetite phase. 3. Finite element analysis A 3D finite element model of the boiler tube was used to determine the effects of wall thinning and also temperature increase. Two models were made for this purpose. First, the model using initial dimensions of diameter and thickness and analysed in different temperatures. The outer diameter of tube is 63.5 mm and the nominal thickness is 5.1 mm. Second, in addition to different temperatures, tube wall thinning applies. According to actual wall thinning (see Table 2), tube is modelled considering different thickness as shown in Fig. 7. Physical and mechanical properties used in analyses are the function of temperature (see Table 6). Also, Poisson ratio is considered 0.3 and density is equal to 7850 kg/m3 [19]. Coupled thermomechanical analysis was used, to study the effect of pressure and temperature on stress simultaneously. Both sides of tubes were fixed in the longitudinal direction. The operational pressure is 110 bar. The domain of tubes was discretized using hexahedral elements of type 3D8RT.1 Elements Total number of first and second cases are 55,200 and 37,200, respectively. The result is shown in Figs. 8, 9 and Table 7. 4. Discussion Visual examination of cross section of failed tube revealed that the opening area had tinned by 30% (Fig. 1a, Table 2) compared to 1
An 8-node thermally coupled brick, trilinear displacement and temperature, reduced integration, hourglass control 4
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Fig. 4. The optical micrographs of the samples 1 to 4; (a) and (b) the specimens in the adjacent areas to the opening; (a) sample 1, (b) sample 2. (c) and (d) the specimens in the opposite side of the opening; (c) sample 3, (d) sample 4. F: ferrite, P: perlite M: martensite, and, C: carbide.
the opposite side of failure opening which can be related to short-term overheating. However, thickness of cross section of the sound tube varied less than 10% (Fig. 1b, Table 3). Also, in failed tube there was 10% ovality which can be another feature of short-term overheating. FEA confirmed these results when it shows tendency of the thinned wall tube to change to an oval shape as shown in Fig. 9. Although the optical and SEM micrographic examination revealed that the microstructures of samples adjacent to the opening consist of martensite blocks in ferrite matrix and few carbides, the microstructures of samples in opposite side of the failure region were composed of normal ferrite and pearlite which are expected microstructures corresponded to the chemical composition of the tube. There are some changes in hardness test results, too. In the failed tube, the region near to the failure has the maximum hardness which can be the consequence of the harder phase like the martensite instead of the pearlite in the microstructure. Hardness of the sound tube had no significant fluctuation. Thus, the microstructural changes and phase transformation are evident in the areas close to the failure region. The formation of martensite occurs when the temperature gets into the intercritical (A1 to A3) range, i.e. the phase transformation in the steels (above 723 °C), and then get cool rapidly. Therefore, this shows that the tube had experienced a localized overheating at the time of failure. The temperature at the failure region might have increased above 723 °C. It corresponds to the information reported by the plant inspection about the operation of tubes without water for a period of time that causes the temperature rises higher than operating temperature by intercritical range, and may approve the hypothesis of short-term overheating. There were no discontinuities or any creep voids in the microstructures of both failed tube and sound tube samples. Furthermore, in accordance with the standard requirements of water treatment for steam boilers, the key parameter which should be monitored is the molar ratio of Na to PO4 that should be 2.2:1 to 2.8:1, to prevent caustic cracking or phosphate corrosion [21]. Based on the on5
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
(caption on next page) 6
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Fig. 5. The SEM micrographs of the specimens 2 and 4, in the; (a), (b) and (c) adjacent to opening, and (d), (e) and (f) opposite side of it; F: ferrite, P: perlite M: martensite, and, C: carbide.
Fig. 6. XRD analysis of the internal deposit of the tube; (a) black magnetized deposit, and (b) the diffractogram of the deposit.
Fig. 7. Cross section of wall thinned tube model. Table 6 Physical and mechanical properties as the function of temperature. T (°C)
E (Gpa)
α (10–6/(°C)) between 20 °C and;
K (W/m·°C)
C (J/kg·°C)
Ys (MPa)
20 100 200 300 400 500 600
212 207 199 192 184 175 164
11.9 12.5 13.0 13.6 14.1 14.5 14.9
53.4 52.9 50.3 46.7 43.3 39.8 36.7
461 479 499 517 536 558 587
255 210 190 150 130 112 105
Fig. 8. Stress distribution of uniform case in (a) 300 °C and (b) 600 °C.
7
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Fig. 9. Tendency to deformation (scale factor 1:1000) and Stress distribution of wall thinned tube in (a) 300 °C and (b) 600 °C. (Locations of "A" to "D" in according to Fig. 7).
Table 7 Results of stress analysis and the effect of temperature and thinning on stress rising.
Uniform Case Wall Thinned Case
Temperature
Max. Stress
(°C)
(MPa)
300 600 300 600
61.15 62.03 89.28 91.42
Stress rising by increasing temperature (%)
Stress rising due to wall thinning in 300 °C (%)
Stress rising due to wall thinning in 600 °C (%)
1.44
46
47.3
2.4
site boiler water composition (Table 1), this ratio is equal to 2.6:1. So, it seems, these types of corrosion can't be considered as the failure mechanism in this case. According to the FEA results, two main factors of stress increase are high temperature and thinning. Increasing tube's skin temperature due to short-term overheating increases stress of tube. Temperature rising from 300 °C to 600 °C caused approximately 1 MPa stress increase in uniform case. This change for wall thinned case is about 2 MPa. Thinning caused two consequences. On one hand, thinning by decreasing nominal thickness leads to a non-uniform tube cross section and subsequently increases tube stress. As illustrated in Table 7, at two selected temperatures the maximum simulated stress of the uniform tube is about 62 MPa, whereas it is about 91 MPa in the thinned tube. On the other hand, wall thinning affects and increases the percentage of stress increase by temperature increasing from 300 °C to 600 °C, by 1.44 and 2.4% for uniform case and wall thinned tube, respectively. Anyhow, since calculated stress was lower than the tube's material yield stress either in uniform and thinned wall tube, a brittle fracture could be predicted. According to XRD analysis iron oxides including hematite (Fe2O3) and magnetite (Fe3O4) were the main constituents of deposit on the internal surface of the failed tube and so there was no evidence that corrosion has been led to failure. The blocky shape of the deposit that formed on the internal surface of the failed tube illustrated high stress in the failure area before opening occurred.
5. Conclusion This research was concerned with the root cause failure analysis of an overheated boiler tube. The failed tube had suffered shortterm overheating, as supported by partial phase transformation and the classic thin-lipped rupture characteristics. Metallographic studies showed distributed martensite as a brittle phase in ferritic matrix in the microstructure of the failed region, while in the microstructure of non-failed area only pearlite and ferrite were seen. These findings were confirmed by hardness measurement results as well. Also, FEA showed thinning and high temperature caused stress rising by short-term overheating. There was no evidence for creep damage or corrosion mechanisms in this study. Results showed that the accuracy of water flow is an important factor in Steam generation systems that should be monitored continuously.
Acknowledgments This work was financially supported by the Research Institute of Petroleum Industry (RIPI). 8
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
References [1] D.N. French, Metallurgical Failures in Fossil Fired Boilers, John Wiley and Sons Inc, New York, 2000. [2] R. Viswanathan, Damage Mechanisms and Life Assessment of High Temperature Components, ASM International Metals Park, OH, 1987. [3] Babak Haghighat-Shishavana, Hossein Firouzi-Nerbina, Masoud Nazarian-Samani, Pooria Ashtaria, Farzad Nasirpouria, Failure analysis of superheater tube ruptured in a power plant boiler: Main causes and preventive strategies, Eng. Fail. Anal. 98 (2019) 131–140, https://doi.org/10.1016/j.engfailanal.2019.01.016. [4] M.R. Khajavi, A.R. Abdolmaleki, N. Adibi, S. Mirfendereski, Failure analysis of bank front boiler tubes, Eng. Fail. Anal. 14 (2007) 731–738, https://doi.org/10. 1016/j.engfailanal.2005.10.017. [5] R.F. Daneshvar-Fatah, A. Mostafaei, R. Hosseinzadeh-Taghani, F. Nasirpouri, Caustic corrosion in a boiler waterside pipe: root cause and mechanism, Eng. Fail. Anal. 28 (2013) 69–77, https://doi.org/10.1016/j.engfailanal.2012.09.010. [6] M.M. Rahman, J. Purbolaksono, J. Ahmad, Root cause failure analysis of a division wall superheater tube of a coal-fired power station, Eng. Fail. Anal. 17 (2010) 1490–1494, https://doi.org/10.1016/j.engfailanal.2010.05.005. [7] H.M. Spring, A.L. Kohan, Boiler Operators' Guide, 2nd Edition, MC-Graw Hill, 1981. [8] A. Saad Abou-elazm, I. El Mahallawi, R. Abdel-karim, R. Rashad, Failure investigation of secondary super-heater tubes in a power boiler, Eng. Fail. Anal. 16 (2009) 433–448, https://doi.org/10.1016/j.engfailanal.2008.06.024. [9] I. Le May, T.L. da Silveria, S.K.P. Cheung-Mak, Uncertainties in the evaluation of high temperature damage in power stations and petrochemical plant, Int. J. Pres. Ves. Piping. 59 (1994) 335–343, https://doi.org/10.1016/0308-0161(94)90167-8. [10] D.R.H. Jones, Creep failures of overheated boiler, Superheater and reformer tubes, Eng. Fail. Anal. 28 (2004) 873–893, https://doi.org/10.1016/j.engfailanal. 2004.03.001. [11] F. Dehnavi, A. Eslami, F. Ashrafizadeh, A case study on failure of superhester tubes in an industrial power plant, Eng. Fail. Anal. 80 (2017) 368–377, https://doi. org/10.1016/j.engfailanal.2017.07.007. [12] J. Purbolaksono, J. Ahmad, L.C. Beng, A.Z. Rashid, A. Khinani, A.A. Ali, Failure analysis on a primary superheater tube of a power plant, Eng. Fail. Anal. 17 (2010) 158–167, https://doi.org/10.1016/j.engfailanal.2009.04.017. [13] Reza Khadem Hosseini, Root cause failure analysis of superheated steam tube at a petrochemical plant, Procedia Struct. Integrity 13 (2018) 232–237, https:// doi.org/10.1016/j.prostr.2018.12.039. [14] J.J. Perdomo, T.D. Spry, An overheat boiler tube failure, J. Fail. Anal. Prev. 5 (2005) 25–28, https://doi.org/10.1361/15477020522997. [15] R.D. Port, H.M. Herro, The NALCO Guide to Boiler Failure Analysis, Mc. GraweHill, New York, 1991. [16] G.R. Lobley, W.L. Al-Otaibi, Diagnosing boiler tube failures related to overheating, Adv. Mater. Res. 41-42 (2008) 175–181, https://doi.org/10.4028/www. scientific.net/AMR.41-42.175. [17] J. Purbolaksono, Y.W. Hong, S.S.M. Nor, H. Othman, B. Ahmad, Evaluation on reheater tube failure, Eng. Fail. Anal. 16 (2009) 533–537, https://doi.org/10. 1016/j.engfailanal.2008.06.008. [18] ASTM A530/A530M- 12, Standard specification for general requirements for specialized carbon and alloy steel pipe. [19] DIN 17175-79. Seamless Steel Tubes for Elevated Temperatures. [20] EN ISO 6508, Metallic materials – Rockwell hardness test, (2005). [21] BS 2486, Recommendations for treatment of water for steam boilers and water heaters, (1997).
9
Contents lists available at ScienceDirect
Engineering Failure Analysis journal homepage: www.elsevier.com/locate/engfailanal
Failure analysis of boiler tube at a petrochemical plant ⁎
R. Khadem Hosseinia, , Sh. Yareieeb a b
T
Corrosion Research Group, Research Institute of Petroleum Industry (RIPI), Tehran, Iran Research and Elite Club, Saghez Branch, Islamic Azad University, Saghez, Iran
A R T IC LE I N F O
ABS TRA CT
Keywords: Boiler tube Short-term overheating Finite element analysis Failure analysis
This research aims to assess the failure analysis of a boiler tube of a steam generation system at a petrochemical plant. To achieve this goal, firstly visual observation and thickness measurements were made to detect different features of failure. Secondly optical microscope and scanning electron microscope (SEM) were used observing the microstructures and also hardness measurements were carried out for metallurgical evaluation. Additionally, phase composition of deposits was studied by using X-ray diffraction (XRD). Also, the on-site water composition of the boiler was taken into consideration. Finally, Finite Element Analysis (FEA) was performed to model the condition of the tube before failure. Based on the results, “short-term overheating” was recognized as the root cause of the boiler tube failure.
1. Introduction In petrochemical plants, steam generation and its distribution system are inseparable parts consisted of internally pressurised components such as boiler and superheated steam tubes that generally operate at high temperatures [1]. The major problem in all boilers is the failure of boiler tubes that leads to forced outage of them. Several failure mechanisms are known [2]. The causes of failure range from those caused by high temperature to others associated with corrosion factors [3]. Corrosion in steam generator units, particularly in tubes, is mostly influenced by chemistry of water, tubing material susceptibility, operational conditions, and thermal and mechanical stresses. Phosphate corrosion and caustic corrosion are two detected mechanisms that occurred as a result of water treatment programs in boilers [4,5]. Low quality coal may contribute to coal-ash corrosion in coal-fired boiler tubes [6,7]. Stress corrosion cracking (SCC) can be a reason for failure when necessary condition including susceptible material like stainless steel 304 and stress exist. The residual stresses adjacent to weldments can be considered the source of stress [8]. Besides this fact, the high temperature damage is the most important failure mechanism in boiler tubes that can occur in different ways including oxidation, creep, microstructural changes as a result of overheating or interaction with the environment, thermal fatigue, low cycle fatigue or combinations of them [9]. Creep is the root cause of 30% of all tube failures in boilers and reformers by itself [10]. Overheating is another main reason for premature rupture of reheater and superheater tubes. This phenomenon may cause a reduction of strength because of a change in metallurgical structure and therefore lead to stress rupture [11]. Overheating can be either short-term [12,13] or long-term [14]. The short-term overheating takes place when tubes are exposed to high operating temperature, typically above the eutectoid transformation temperature of 727 °C, and it exhibits a thin-lipped longitudinal rupture with tube bulging, while long-term overheating is related to operating temperature above 454 °C, and can lead to tube bulging or thick-lipped ruptures [15]. Since the change in microstructure can occur due to high temperature in these failures [16], microstructural examination is used as an efficient method to recognize the type of overheating failure, as well as fracture morphology
⁎
Corresponding author. E-mail address: [email protected] (R.K. Hosseini).
https://doi.org/10.1016/j.engfailanal.2019.104146 Received 7 February 2019; Received in revised form 17 July 2019; Accepted 15 August 2019 Available online 17 August 2019 1350-6307/ © 2019 Published by Elsevier Ltd.
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Table 1 On-site measured control parameters of the steam drum water. pH
Conductivity μs cm−1
Sodium ppm
Chloride ppm
Phosphate ppm
9
11
2.2
trace
3.6
[17]. This study aimed to investigate the causes of boiler tube failure at a petrochemical plant. Toward this aim, macroscopic evaluation and hardness measurements of failed tube were compared to a sound tube. Microscopic examinations, including light microscope and scanning electron microscope (SEM), were carried out to observe the microstructure of failed tube samples. Also, phase composition of the deposit sample picked from the internal surface of the failed tube was studied by using X-ray diffraction. In addition to experimental evaluations, Finite element analysis as the numerical method was carried out to illustrate and deduce the failure mechanism and root cause. 2. Experimental procedures 2.1. Operational facts The studies were performed on a failed steam tube in a flue gas boiler working parallel with the other two boilers in the unit of waste heat recovery, with a mutual steam drum which produces high pressure steam for ammonia production plant by 220 ton per hour. Boiler design temperature and pressure of tubes were 325 °C and 11.7 MPa, respectively. The failed tube was located 4 m under the roof of combustion chamber and had been in service for more than 30 years. Inspection histories had not shown detectable damage before the failure. Because of problems with the instrumentation of controlling the level of the steam drum, boiler tubes have been exposed to water shortage and have caused tube failure, recently. Corrosion is monitored by controlling pH and conductivity and by measuring sodium, chloride and phosphate concentrations of steam drum water. Table 1 presents these parameters, as collected on site, in time of failure. 2.2. Visual observations Fig. 1 shows the cross section of the failed tube and sound tube. Although the examination of the failed tube surface indicates that the thickness of cross section differs in different sections, the sound tube has no noticeable change in thickness. As shown in Fig. 1a, the thickness of 13 points of the cross section of failed tube was measured by Sonatest A-Scan ultrasonic thickness gauge on the circumference of tube at 30° intervals given in Table 2, from "A" to "M". The results revealed that the least thickness was seen in the adjacent areas to the failure opening with 3.56 mm, and the largest one was in areas away from the failure opening with 5.11 mm. According to the specification, the nominal outer diameter and thickness of tubes were 63.5 mm and of 5.01 mm, respectively. Based on the 7 points measured thickness of cross section of the sound tube, "N", "O" and "Q" to "U" (Fig. 1b), the changes in thickness were in the range of 4.61 mm to 5.01 mm (Table 3). On the other hand, the failed tube was oval where the maximum and minimum outside diameters are 75.5 and 68.5 mm, respectively, with a 10% deviation from the circularity of the original size. Based on the standard of an equivalent grade of the tube, the difference in outside diameter readings in any one cross section shall not exceed 1.5% of the specified outside diameter [18]. The measured outside diameter of the sound tube was 64.0 mm to 64.5 mm which meets standard requirements. Besides the external examinations, the internal surface of tubes was observed. As shown in Fig. 2a, although the rust and thin blocky shaped black deposits were seen on the internal surface of the failed tube, this feature is not visible on the internal surface of the sound tube (Fig. 2b).
Fig. 1. The cross section of (a) the failed tube, and (b) the sound tube. 2
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Table 2 The wall thickness of cross section of the failed tube according to Fig. 1a. Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
A B C D
3.56 3.79 4.20 4.51
E F G H
4.70 4.95 5.11 4.99
I J K L
4.90 4.72 3.85 3.76
M
3.62
Table 3 The wall thickness of cross section of the sound tube according to Fig. 1b. Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
Point
Thickness (mm)
N O
4.61 4.65
P Q
– 4.93
R S
4.90 4.95
T U
4.97 5.01
Fig. 2. The internal surface of (a) the failed tube, (b) the sound tube.
2.3. Tube material characterization The chemical composition of the tube sample was analysed by using spark emission spectrophotometry with worldwide Analytical systems AG (model PMI–Master). Table 4 presents the chemical composition of the tube material that is consistent with the standard (DIN 17175–79) [19]. The results conform to the specifications for the steel grade ST.45.8. 2.4. Hardness measurement Hardness test was performed on the cross section of 13 points of the failed tube and 8 points of the sound tube, indicated in Fig. 1, by using Karl Frank 38,106 hardness tester and the Rockwell Type B (HRB) method [20]. According to Table 5, although the hardness of failed tube changed from 73.5 HRB to 94.5 HRB and also the nearest areas to the opening of the failed tube were the maximum, the hardness of the sound tube had no significant fluctuation. 2.5. Microscope analysis To perform microscopic analysis optical Olympus BH2-MJL microscope and TESCAN MIRA3 field emission gun scanning electron microscope (FEG–SEM) were used. Specimens were cut from the failed tube along the failure and away from the opening, at 180° apart along the circumference, to detect variations in microstructure on the circumference of the tube. Both longitudinal and transverse samples were examined, marked 1 to 4 as shown in Fig. 3. The samples were polished using a series of emery papers and finished with diamond polishing and then etched with 2% Nital etchant (2 ml HNO3 in 100 ml of ethanol). . Table 4 Chemical composition of the tube material compared to the standard (wt%). Elements
C
Mn
Si
S
P
Cr
Fe
Tube material DIN 17175-79 Gr. ST. 45.8
0.13 0.21
0.72 0.4–1.2
0.24 0.1–0.35
0.031 0.040
0.022 0.040
0.25 -
Balance Balance
3
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Table 5 Rockwell B hardness values of the cross section of the failed tube and sound tube according to Fig. 1. Point
Hardness (HRB)
Point
Hardness (HRB)
Point
Hardness (HRB)
A B C D E F G
94.5 93.0 88.5 87.0 80.5 77.5 73.5
H I J K L M N
76.5 79.5 83.0 87.0 90.5 93.0 73.0
O P Q R S T U
75.0 76.0 78.5 77.0 78.0 72.5 71.0
Fig. 3. Prepared samples from the adjacent and the opposite side of failure opening for microstructural analysis.
The optical micrographs of the specimens in the adjacent regions to the failure opening marked 1 and 2 corresponding to Fig. 4a and b, respectively. The microstructures contain martensite blocks (M) in the ferrite matrix (F) and also few carbides (C) near the grain boundaries. The microstructure of samples on the opposite side of the opening, namely 3 and 4, presented in Fig. 4c and d, respectively, were normal ferrite (F) and pearlite (P). There were no discontinuities or creep voids in any of the microstructures. Fig. 5 shows SEM images at different magnifications taken on the surface of cross section of the tube wall, namely 2 and 4, according to Fig. 3. As presented in Fig. 5 a-c, SEM micrographs of specimen 2, from the near area to the failure opening, reveal martensite islands (M) in a ferritic matrix (F) and also few carbides near grain boundaries (C). However, Fig. 5 d-f, showing SEM micrographs of specimen 4, from the opposite side of the opening, shows microstructures consisted of normal ferrite (F) and perlite (P). Layer of perlite is well visible in Fig. 5f. X-ray diffraction (XRD) analyses were applied to determine different phases of the deposit components. To do this, the deposit sample picked from the internal surface of the failed tube (Fig. 6a), was prepared on zero scattering foil and step-scanned in a STOE Stadi P diffractometer using unfiltered Cu Kα radiation. The step size was 0.02°/s in the range of 5°-120°. The voltage and current of the machine were 40 kV and 30 mA, respectively. The diffractogram of the deposit shown in Fig. 6b indicated that the analysed deposit consists of two main ferrous oxides; hematite (Fe2O3) and magnetite (Fe3O4). As shown in Fig. 6a, the deposit was magnetized, which can be due to the presence of magnetite phase. 3. Finite element analysis A 3D finite element model of the boiler tube was used to determine the effects of wall thinning and also temperature increase. Two models were made for this purpose. First, the model using initial dimensions of diameter and thickness and analysed in different temperatures. The outer diameter of tube is 63.5 mm and the nominal thickness is 5.1 mm. Second, in addition to different temperatures, tube wall thinning applies. According to actual wall thinning (see Table 2), tube is modelled considering different thickness as shown in Fig. 7. Physical and mechanical properties used in analyses are the function of temperature (see Table 6). Also, Poisson ratio is considered 0.3 and density is equal to 7850 kg/m3 [19]. Coupled thermomechanical analysis was used, to study the effect of pressure and temperature on stress simultaneously. Both sides of tubes were fixed in the longitudinal direction. The operational pressure is 110 bar. The domain of tubes was discretized using hexahedral elements of type 3D8RT.1 Elements Total number of first and second cases are 55,200 and 37,200, respectively. The result is shown in Figs. 8, 9 and Table 7. 4. Discussion Visual examination of cross section of failed tube revealed that the opening area had tinned by 30% (Fig. 1a, Table 2) compared to 1
An 8-node thermally coupled brick, trilinear displacement and temperature, reduced integration, hourglass control 4
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Fig. 4. The optical micrographs of the samples 1 to 4; (a) and (b) the specimens in the adjacent areas to the opening; (a) sample 1, (b) sample 2. (c) and (d) the specimens in the opposite side of the opening; (c) sample 3, (d) sample 4. F: ferrite, P: perlite M: martensite, and, C: carbide.
the opposite side of failure opening which can be related to short-term overheating. However, thickness of cross section of the sound tube varied less than 10% (Fig. 1b, Table 3). Also, in failed tube there was 10% ovality which can be another feature of short-term overheating. FEA confirmed these results when it shows tendency of the thinned wall tube to change to an oval shape as shown in Fig. 9. Although the optical and SEM micrographic examination revealed that the microstructures of samples adjacent to the opening consist of martensite blocks in ferrite matrix and few carbides, the microstructures of samples in opposite side of the failure region were composed of normal ferrite and pearlite which are expected microstructures corresponded to the chemical composition of the tube. There are some changes in hardness test results, too. In the failed tube, the region near to the failure has the maximum hardness which can be the consequence of the harder phase like the martensite instead of the pearlite in the microstructure. Hardness of the sound tube had no significant fluctuation. Thus, the microstructural changes and phase transformation are evident in the areas close to the failure region. The formation of martensite occurs when the temperature gets into the intercritical (A1 to A3) range, i.e. the phase transformation in the steels (above 723 °C), and then get cool rapidly. Therefore, this shows that the tube had experienced a localized overheating at the time of failure. The temperature at the failure region might have increased above 723 °C. It corresponds to the information reported by the plant inspection about the operation of tubes without water for a period of time that causes the temperature rises higher than operating temperature by intercritical range, and may approve the hypothesis of short-term overheating. There were no discontinuities or any creep voids in the microstructures of both failed tube and sound tube samples. Furthermore, in accordance with the standard requirements of water treatment for steam boilers, the key parameter which should be monitored is the molar ratio of Na to PO4 that should be 2.2:1 to 2.8:1, to prevent caustic cracking or phosphate corrosion [21]. Based on the on5
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
(caption on next page) 6
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Fig. 5. The SEM micrographs of the specimens 2 and 4, in the; (a), (b) and (c) adjacent to opening, and (d), (e) and (f) opposite side of it; F: ferrite, P: perlite M: martensite, and, C: carbide.
Fig. 6. XRD analysis of the internal deposit of the tube; (a) black magnetized deposit, and (b) the diffractogram of the deposit.
Fig. 7. Cross section of wall thinned tube model. Table 6 Physical and mechanical properties as the function of temperature. T (°C)
E (Gpa)
α (10–6/(°C)) between 20 °C and;
K (W/m·°C)
C (J/kg·°C)
Ys (MPa)
20 100 200 300 400 500 600
212 207 199 192 184 175 164
11.9 12.5 13.0 13.6 14.1 14.5 14.9
53.4 52.9 50.3 46.7 43.3 39.8 36.7
461 479 499 517 536 558 587
255 210 190 150 130 112 105
Fig. 8. Stress distribution of uniform case in (a) 300 °C and (b) 600 °C.
7
Engineering Failure Analysis 106 (2019) 104146
R.K. Hosseini and S. Yareiee
Fig. 9. Tendency to deformation (scale factor 1:1000) and Stress distribution of wall thinned tube in (a) 300 °C and (b) 600 °C. (Locations of "A" to "D" in according to Fig. 7).
Table 7 Results of stress analysis and the effect of temperature and thinning on stress rising.
Uniform Case Wall Thinned Case
Temperature
Max. Stress
(°C)
(MPa)
300 600 300 600
61.15 62.03 89.28 91.42
Stress rising by increasing temperature (%)
Stress rising due to wall thinning in 300 °C (%)
Stress rising due to wall thinning in 600 °C (%)
1.44
46
47.3
2.4
site boiler water composition (Table 1), this ratio is equal to 2.6:1. So, it seems, these types of corrosion can't be considered as the failure mechanism in this case. According to the FEA results, two main factors of stress increase are high temperature and thinning. Increasing tube's skin temperature due to short-term overheating increases stress of tube. Temperature rising from 300 °C to 600 °C caused approximately 1 MPa stress increase in uniform case. This change for wall thinned case is about 2 MPa. Thinning caused two consequences. On one hand, thinning by decreasing nominal thickness leads to a non-uniform tube cross section and subsequently increases tube stress. As illustrated in Table 7, at two selected temperatures the maximum simulated stress of the uniform tube is about 62 MPa, whereas it is about 91 MPa in the thinned tube. On the other hand, wall thinning affects and increases the percentage of stress increase by temperature increasing from 300 °C to 600 °C, by 1.44 and 2.4% for uniform case and wall thinned tube, respectively. Anyhow, since calculated stress was lower than the tube's material yield stress either in uniform and thinned wall tube, a brittle fracture could be predicted. According to XRD analysis iron oxides including hematite (Fe2O3) and magnetite (Fe3O4) were the main constituents of deposit on the internal surface of the failed tube and so there was no evidence that corrosion has been led to failure. The blocky shape of the deposit that formed on the internal surface of the failed tube illustrated high stress in the failure area before opening occurred.
5. Conclusion This research was concerned with the root cause failure analysis of an overheated boiler tube. The failed tube had suffered shortterm overheating, as supported by partial phase transformation and the classic thin-lipped rupture characteristics. Metallographic studies showed distributed martensite as a brittle phase in ferritic matrix in the microstructure of the failed region, while in the microstructure of non-failed area only pearlite and ferrite were seen. These findings were confirmed by hardness measurement results as well. Also, FEA showed thinning and high temperature caused stress rising by short-term overheating. There was no evidence for creep damage or corrosion mechanisms in this study. Results showed that the accuracy of water flow is an important factor in Steam generation systems that should be monitored continuously.
Acknowledgments This work was financially supported by the Research Institute of Petroleum Industry (RIPI). 8
Engineering Failure Analysis 106 (2019) 104146
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