Accepted Manuscript

A case study on failure of superheater tubes in an industrial power

plant

F. Dehnavi, A. Eslami, F. Ashrafizadeh

PII: S1350-6307(16)30205-9
DOI: doi: 10.1016/j.engfailanal.2017.07.007
Reference: EFA 3225
To appear in: Engineering Failure Analysis
Received date: 16 April 2016
Revised date: 28 June 2017
Accepted date: 5 July 2017

Please cite this article as: F. Dehnavi, A. Eslami, F. Ashrafizadeh , A case study on failure
of superheater tubes in an industrial power plant, Engineering Failure Analysis (2017),
doi: 10.1016/j.engfailanal.2017.07.007

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 ACCEPTED MANUSCRIPT

A case study on failure of superheater tubes in an

industrial power plant

F. Dehnavi a, A. Eslami a, *, F. Ashrafizadeh a

Department of Materials Engineering, Isfahan University of Technology, Isfahan 8415683111, Iran

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ABSTRACT

A failure analysis investigation was carried out on the secondary Superheater tubes of a boiler

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unit in a steam power plant. The tubes, made of DIN-16CrMo4 steel, failed by bulging and
rupture only after about three years of operation. Metallurgical investigations revealed that
microstructural degradation had mainly occurred at the external (fireside) tube surface. Long-
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term overheating was identified as the root cause of the premature failure.

Keywords: Superheater; Rupture; Overheating; Microstructural degradation.

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Highlights

 Detailed investigation on rupture of several superheater tubes was performed.

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 Most severe failure occurred on the external surface of the tubes.

 Long-term overheating was identified as the root cause of failure.
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 Oxidation in hot flue-gas atmosphere and fly-ash erosion accelerated the tube rupture.
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1. Introduction
The primary function of a boiler is to generate steam for the turbine to produce electricity. The
steam is heated in a convective superheater at higher temperatures prior to delivery to the

*
Corresponding author: Abdoulmajid Eslami, Email: m.eslami@cc.iut.ac.ir,

Phone: +98 313 391 5706, Fax: +983133912752

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turbine. Steam superheaters are widely used in steam generators and heat-recovery steam
generators (HRSGs). Their purpose is to raise steam temperature from saturation conditions to
the desired final temperature, which can be as high as 540 °C in some cases. Steam pressure in
such operations typically ranges 10-100 bar. Superheated steam improves the thermal efficiency
and overall power output. In addition, it produces little or no moisture, depending on the pressure
ratio, at the steam turbine exit; moisture in the last few stages of a steam turbine can damage the
turbine blades. Superheaters are constructed from seamless alloy steel tubes. Tube sizes normally
vary from 32-64 mm. There are different designs for superheaters depending on gas/steam

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parameters and space availability; they can be of convective or radiant design or a combination
of these in packaged boilers. Convective superheaters are the earliest type of superheater, located

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above or behind banks of water tubes; they are protected from direct flame or fire. Radiant
superheaters are exposed to the heat source and are placed at upper parts of the combustion

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chamber. Convective superheater bank tubes are suspended in the flue gas path in the boiler.
Such complex situation of high temperature, stress, time and aggressive environment can result

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in abrupt rupture of tubes. Failure of superheater tubes can occur by different mechanisms, such
as creep, overheating, oxidation, stress rupture, thermal fatigue, ash/high temperature corrosion,
and erosion. More often, two or several of these mechanisms contribute to failure [1-3].
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One of the causes of premature rupture of superheater and reheater tubes is overheating.
Overheating means rise in tube temperature above the design limits, whether several hundred
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degrees for a brief period (short-term overheating), or slight over temperature during extended
time (long-term overheating or high temperature creep). Overheating is mainly caused by
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inadequate cooling of the tubes due to loss of internal steam, thickening of oxide, or thermo-
mechanical treatments during production and installation of the tubes. In addition, overheating
may lead to reduction of strength via change in metallurgical structure during service and
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thereby, stress rupture. Short-term mode of overheating makes severe local bulging and
considerable reduction in tube-wall thickness due to softening of the material at elevated
temperatures before actual failure, while creep-ruptured tubes often have little wall thinning and
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slight bulging [4-6].

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General oxidation or scaling can also lead to premature failure of superheater tubes. Grain-
boundary oxidation may produce a notch effect that can limit the effective life of the
components. The presence of water vapor and carbon dioxide in air and to a greater extent in
atmospheres derived from the combustion of fossil fuels has been found to increase the reaction
rate of steels noticeably. In addition, fireside surfaces of superheater and reheater tubes are
susceptible to “ash corrosion”; an accelerated attack due to fluxing of the protective oxide scale
from the metal surface by low melting-point alkali sulfate compounds [7-10].

Creep-resistant low-alloy steels usually contain molybdenum for enhanced creep strength, along
with chromium for improved corrosion resistance. These Cr-Mo steels are extensively used at
elevated temperatures in boilers and superheater tubes. Thermal exposure over time is one of the

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main service conditions affecting the mechanical properties of the low-alloy steels due to
changes in the metallurgical structure. These metallurgical changes include spheroidization,
decarburization/carburization, embrittlement and increase in the grain size. Spheroidization of
the carbides in steel occurs since spheroidized microstructures are one of the most stable states
found in steels. The spheroidization of carbides, in general, reduces strength and increases
ductility. The thermal exposure of Cr-Mo ferritic steels also contributes to complex aging
phenomena, which is governed by complicated carbide precipitation processes that occur in the
steel [11-15].

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A review of the literature indicates that although there are many publications on the subject,

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specific papers on metallurgical degradation that occurs during long term overheating of steel
tubes in the combustion gas are scarce. In this study, a comprehensive microstructural

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investigation on failure of convective superheater tubes of a boiler is presented. Detailed
examination including visual observation, optical microscopy and electron-probe microanalysis

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of the virgin tube and damaged tube is carried out in this regard, and root cause of the failure is
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2. Experimental procedure
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As schematically shown in Fig. 1 the convective superheater in this study consists of three rows
of tubes†. Rupture was reported after about 26000 h (3 years) in the upper face of tubes on the
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top row of convective superheater. The operational parameters for the failed convective
superheater is given in Table 1. According to the operational records, three types of gases (i.e.
natural gas, blast furnace gas, and occasionally the cock gas) were used as the fuel in the
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investigated boiler.

Two O-ring-section samples were cut from the damaged tube; one from the rupture region
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(section A-A’ in Fig. 2) and the other (section B-B’) from the bulged region at the end of tube
length (section B-B’ in Fig. 2). Four locations of the A-A’ and B-B’ ring-sections were
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considered for comparison as shown in Fig. 3. Also, in order to study the microstructure of the
virgin tube and damaged tube, specimen surfaces were examined by optical microscope and
Scanning Electron Microscope (SEM) equipped with Energy Dispersive X-ray spectrometer
(EDS). Samples were polished and etched in 2% nital solution prior to examination of the
surface. The thickness of the tube near and away from the failed regions was measured using a
digital micrometer. For each location of B-B’ section, Vickers micro-hardness was measured
using Koopa Haresh micro-hardness tester and an applied load of 200 gf (1.962 N) for 20
seconds. Chemical composition of the tube sections was determined using an optical emission

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Each row also consists of 56 tubes itself, which are connected to the outlet header.

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spectrometer (Metalscan, ARUN). X-Ray Diffraction (XRD) analysis was also performed on
scales and deposits using Philips X’pert system in order to identify different phases.

3. Results and discussion

3.1. Visual examination
Typical camera image of the ruptured tube is shown in Fig. 2a. Failure has occurred at the
position of 12 o’clock, as schematically is shown in Fig. 3. The important role of hoop stresses

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can be seen from fracture happening parallel to the tube axis. The tube is mainly damaged from

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its external surface (fireside of the tube). Visual appearance of one end of the tube at 12 o’clock
position exhibits longitudinal thick-lipped ‘‘fish-mouth” rupture commonly observed in cases of

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creep-induced failure of superheater and reformer tubes [15]. In mid-region of the tube,
secondary rupture cracks are observed at 12 o’clock position. Close to the end of the tube length,
swelling is also evident at the 12 o’clock position. Fig. 4 shows different regions of the failed

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tube and their cross section profiles. The cross section of the tube is distorted in the form of
diametrical expansion; indicating creep failure [3, 12, 15]. In the end region of the tube length,
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white deposits were detected on the external surface at opposite face (6 o’clock position). Heavy
scaling was observed at both the external and internal surfaces of the tube (Fig. 4). The scales on
the external surface were very thick and full of cracks; the scales spalled-off at the rupture zone.
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No obvious evidence of other types of corrosion (such as pitting or erosion-corrosion by steam)

was observed on the internal and external surfaces of the tube.
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Wall thinning has occurred all around the tube due to metal oxidation, but thinning at the failed
face (12 o’clock position) of the tube was relatively more severe. As can be seen in Fig. 4, the
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tube cross section has been deformed in such a way that wall has thinned down at the damaged
face. Another important issue is that wall thickness reduction at some areas of the failed face has
taken place from the external surface, too; so this side of the tube is flattened (Fig. 4). Flattening
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must have been caused by fly-ash erosion and also oxidation in hot oxidizing flue-gas.
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3.2. Chemical and microstructural analysis

Chemical composition of the tube material, compared with its GB standard is shown in Table 2.
The tube material can be categorized as low alloy chromium-molybdenum steel, with its
chemical composition close to GB 35CrMoV standard [16]. The chromium-molybdenum heat
resistant steels are widely used in the oil and gas industries and in fossil fuel and nuclear power
plants [11].

Microstructure of the virgin tube compared to the failed tube is shown in Fig. 5. As can be seen
from Fig. 5a, the microstructure of the virgin tube consists of ferrite and pearlite colonies. The
microstructure of the failed tube consists of ferritic grains with carbide particles (Fig. 5b). The

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carbide precipitates are mainly formed along the grain boundaries. Table 3 shows the
composition of the carbide precipitates. The failure temperature of the tube can be approximated
by microstructural evidence; i.e. spheroidization in ferritic structures would usually occur at tube
metal temperatures around 600 °C [4, 15]. Long-time exposure of ferritic steels to temperatures
just below 600 °C makes no transformation to austenite, but it would cause pearlite dissolution
and carbide spheroidization. This is due to lower interfacial free energy of spherical carbide
boundaries with ferrite compared to plate-form carbide-ferrite boundaries.

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Decarburization on external surface of the damaged tube was also observed. As it is shown in
Figures 6 and 7, the damaged face (12 o’clock position) of the tube is free from carbide particles

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on its external surface, while at 6 o’clock position spheroidized carbides on both external and
internal walls are formed (see Fig. 8). This indicates that the damaged face of the tube should

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have been exposed to slightly higher temperature compared to its opposite face. The positions of
3 and 9 o’clock have similar microstructures as that of 6 o’clock, except for that the number and
size of the carbides is different. In fact, the 3 and 9 o’clock positions have larger size and lower

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number of carbides in comparison to the 6 o’clock position.
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Microstructure of 12 o’clock position showed individual cavities and microcracks formed via
void coalescence; presence of such features is an indication of creep failure. In addition, the
deformed cross section of the failed tube (as discussed in section 3.1) confirms occurrence of
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creep failure. Some of the microcracks were initiated from the external surface going towards the
inner parts of the tube wall. These cracks were almost perpendicular to the direction of hoop
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stress; indicating it as the main stress responsible for the creep. Growth of such vertical
microcracks reduced the metal strength and caused tube rupture. General transition of creep signs
from fireside surface towards the bulk of the tube, at the rupture zone, is shown in Fig. 6,
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showing three zones throughout the tube wall thickness, each zone having a dominant
characteristic of creep. At the outer region of the tube wall thickness, there are vertical
intergranular cracks as a result of creep void coalescence, filled with oxidation products.
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Consequently, a second zone, where creep void growth is dominant, can be recognized (Fig. 6a).
In deeper sites, there are individual voids along the grain boundaries as the initial stage of the
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creep; this stage is shown in Fig. 6b. SEM images showing voids growth and coalescence are
presented in Fig. 6c and d. From Fig. 6a, it can be seen that farther from rupture edge, the
concentration of defects such as creep voids, microcracks and oxide notches is gradually
reducing. At the bulged zone, only a chain of creep micro-voids exists at the grain boundaries on
the external surface of the tube (Fig. 7a). No evidence of creep at the internal surface of tube was
observed (see Fig. 7b). Existence of voids and micro-cracks beneath the oxide layer on the
steamside surface (see Fig. 7b) should not be due to creep occurring at this zone. Such features
usually originate because of internal oxidation of Cr–Mo steels, particularly within the low
oxygen partial pressure environment of the steam [9].

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Oxide scales were present on both the external and internal surfaces of the failed tube. The scales
were double-layered. XRD analysis of the oxide scales (shown in Fig. 8) indicated that the outer
oxide layer on both sides of the tube consists of hematite (Fe2O3). Results of EDS analysis in
Table 4 revealed that scales on both sides consist predominantly of iron oxides with some
enrichment of chromium and molybdenum elements. Based on Fe to O ratio, inner scales consist
of magnetite (Fe3O4). The inner region of scales has higher contents of Cr and Mo than the base
metal adjacent to it. This makes more protection by inner layer of scale compared to the outer
layer where chromium is lower. Considerable amounts of sulfur were identified at the external

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surface of the tube within the oxide scales. The sulfur should be from the fuel used in the boiler,
and could cause accelerated oxidation [7-10].

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Numerous notches and microcracks were formed as a result of oxidation at tube external

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circumference. (see Fig. 9). Oxide notches are well-known crack initiators in the steam generator
systems [9]. The number and depth of microcracks on the external surface of the failed tube at 12
o’clock position were higher than other locations. As mentioned earlier, presence of the

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cracks/microcracks filled with thick oxide layers indicates considerable ingress of oxygen into
the sub-surface. The oxides had compositions similar to that presented in Table 4.
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As shown in Fig. 10, some voids and longitudinal cracks have formed between layers of
steamside scales in cross sectional view. At the beginning of exfoliation, voids exist separately
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from each other. With time, the voids should have linked and have caused the separation of outer
layer from the inner layer. Finally, the outer layer is exfoliated; a phenomenon that can be even
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seen by naked eye at these locations. In the sequence of exfoliation, the voids would act as
barriers of heat transfer [14], causing overheating.
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Some white deposits were also observed on the oxide scales on the external tube surface of 6
o’clock position at the end region of the tube length. XRD analysis of the deposits showed the
presence of alkali sulphates (K3Na(SO4)2 and KNaSO4) and Sulfur in the form of S8. (see Fig.
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11). Such minerals should have also formed from the boiler fuel gas. Alkali sulfates in coal ash
are often the primary species for the hot corrosion of superheater tubes. The presence of such
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compounds can initiate hot corrosion by salt fluxing and sulfidation. This type of attack creates
molten flux at service temperature; it removes protective oxide scale, exposing more base metal.
Type and severity of corrosion is a function of a number of variables, including the history of the
alloy, operating temperature and gas composition, particularly its SO2 content. In some cases,
small holes become evident in the protective reaction product barrier, where the molten deposits
begin to penetrate. In sulfidation, an increase in the amount of sulfide particles becomes evident
in the alloy beneath the protective oxide layer [10, 17]. In this study, since there were no
microstructural evidences of hot corrosion on rupture sites, hot corrosion should not have played
a significant role in the failure of the tubes.

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3.3. Micro-hardness profiles

Average microhardness of the virgin tube was 170 HV. Microhardness of the failed tube material
was measured at various tube angles in the B-B’ section (location of swelling). The profile of
micro-hardness of the failed tube when moving from the fireside towards the steamside is shown
in Fig. 12. As can be seen from this figure, the hardness has dropped (from its original value of
170 HV) at all locations of the failed tube. The loss in hardness of the failed tube is due to
microstructural changes of the tubes in service, i.e.: dissolution of pearlite and even carbides. As
can be seen in Fig. 12, at 3, 9 o’clock positions, the measured hardness is slightly lower (127

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HV) compared to that at the 6 o’clock position (150 HV). The lower hardness should be due to

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lower amounts of coagulated carbides at these locations (compare Fig. 7a and Fig. 9). The
hardness value of 12 o’clock position was 138 HV. Based on carbide content, it is expected that

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the hardness value of 12 o’clock position to be lower than the hardness at 3 and 9 o’clock
regions. However, this inconsistency could be explained by the work-hardening due to plastic
deformation of metal occurring at the rupture edge (the 12 o’clock position).

3.4. Failure mechanism

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The studied tubes located on top row of superheater package, were in direct contact with hot,
oxidizing flue-gas stream; so they were very susceptible to overheating and oxidation.
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Accumulation of oxide scales on the steamside surface of hot tube, with lower thermal
conductivity in comparison to the bare steel could have caused further increase in temperature of
tube. There are a number of published algorithms for estimating the metal temperature based on
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thickness of the oxide scale. For low alloy steels with 1-3% chromium content, the following
empirical equation has been suggested [13]:
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log 𝑋 = 2.1761 × 10−4 𝑇 (20 + log 𝑡) − 7.25 (1)

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Where in Equation (1) the scale thickness is in mils (1 mm = 40 mils), the absolute temperature
in Rankine (R) and the operational time is in hours, shown by X, T and t, in the Equation
respectively. Using Eq. (1), for an operation time of 26000 hours, and average scale thickness of
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approximately 200 µm, the temperature was calculated approximately 630°C. This temperature
exceeds the temperature of 600°C, which has been reported in literature for carbide
spheroidization in ferritic steels [4, 15]. Therefore, it could be stated that the failed tubes should
have experienced overheating. While overheating was introduced as the primary cause of
premature failure, it should be noted that other issues such as wall thinning due to oxidation and
fly-ash erosion, have caused exceeding hoop stress. Loss of strength due to decarburization,
pearlite elimination, and creep micro-voids coalescence should have facilitated premature
rupture of the failed tube.

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4. Conclusions
1. Severe microstructural degradation occurred at the fireside surface of upper face (i.e. the
12 o’clock position) of superheater tubes; this involved decarburization, pearlite
dissolution, carbide spheroidisation and formation of creep voids and microcracks.

2. Long-term overheating (high temperature creep) was identified as the primary cause of
premature failure of the superheater tubes. Scale thickening on steamside surface of the
tube increased the tube service temperature. On the other hand, formation of thick scale

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on fireside surface caused metal consumption, tube wall thinning and an increase in hoop

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stress.”

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3. Wall thinning due to oxidation, and loss of strength due to microstructural degradation, led
to final rupture of the superheater tubes under the exceeding hoop stress.

Acknowledgements
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The authors would like to thank Isfahan University of Technology for its financial support and
provision of laboratory equipment.
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Tables:

Table 1
Operational parameters of the failed boiler bank tube
Parameters Range
Steam temperature (480 – 520) °C
Steam pressure 100 kg/cm2 (10 MPa)
Geometry of the tube Outer diameter: 32 mm; Thickness: 4 mm
≈ 900°C

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Flue gas temperature

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Table 2

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Comparison of the chemical composition of the failed tube with GB standard
Element (wt.%)
Item
C Si Mn Cr Mo Ni V Cu P S Fe

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Steel tube 0.31 0.24 0.70 1.37 0.20 <0.11 0.20 <0.09 <0.035 <0.019 Bal.

0.3 0.17 0.4 1 0.2 0.1

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GB 35CrMoV - - - - - <0.3 - <0.3 <0.035 <0.035 Bal.
0.38 0.37 0.7 1.3 0.3 0.2
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Table 3
Chemical composition (wt. %) of scattered carbides determined by EDS analysis
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Element Cr Mo Mn C Fe
22.4 1.8 4.2 46.7 Bal.
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Table 4
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Chemical composition of oxide scale at steamside and fireside surfaces of the failed tube (wt. %)
Element C O S Cr Fe Mo
wt. % 5.6 24.2 1.4 3.0 62.4 3.4
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Figures:

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Fig. 1. Schematic of the convective superheater setup.
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Fig. 2. Camera images of the failed tube in the as-received condition.

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Fig. 3. Schematic of the O-ring section of the failed tube.

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Fig. 4. Various regions of the failed tube and their cross section profiles: distorted cross section of the
tube in the form of diametrical expansion and flattening of fireside surface (both on 12 o’clock position),
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heavy scaling at both the external and internal surfaces of the tube and wall thinning.
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Fig. 5. Optical micrograph of (a) ferrite-pearlite microstructure of virgin tube, (b) general microstructure
of failed tube.
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Fig. 6. SEM micrographs of areas adjacent to rupture lips (12 o’clock position of section A-A’) showing

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general transition of creep signs throughout the tube thickness; (a) two stages of creep across the tube
wall, intergranular cracks at/near fireside surface as a result of void coalescence, and zone of creep void
growth beneath it, (b) lack of carbides showing decarburization in the mid-wall thickness and creep

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microvoids at grain boundaries, (c) creep voids growth at higher magnification, (d) creep voids
coalescence.
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Fig. 7. (a) SEM micrograph at the area of tube-wall swelling (12 o’clock position of section B-B’);
decarburization of regions adjacent to fireside surface and presence of chain of creep micro-voids at grain
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boundaries in this zone, (b) SEM image of 3, 9 and 12 o’clock regions of both sections showing carbide
particles in the matrix of steamside surface and almost uniform/ adherent oxide scale on it. Some voids
and microcracks as a result of internal oxidation are present beneath the oxide layer.
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Fig. 8. XRD pattern of spalled scales from both surfaces.

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Fig. 9. SEM image of 6 o’clock regions of both sections showing carbide particles in the matrix of
fireside surface, and oxide notches under two-layered scale on outer wall.

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Fig. 10. Rupture edge showing thickness reduction, a large number of macro/micro cracks filled with
oxidation products on fireside, thick defectful oxide scale and many microcracks on steamside surface of
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the tube.

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Fig. 11. XRD pattern of white deposits accumulated on outer surface at end-length region of the failed
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pos12 pos3 pos6 pos9
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180
170
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Micro-hardness (HV30)

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150
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0 600 1200 1800 2400 3000

Distance from fireside surface (µm)

Fig. 12. micro-hardness profiles taken in radial direction at different clock angles of section B-B’.

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