Engineering Failure Analysis 18 (2011) 963–970
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Engineering Failure Analysis
journal homepage: www.elsevier.com/locate/engfailanal
Failure analysis of stress corrosion cracking occurred in a gas
transmission steel pipeline
E. Sadeghi Meresht a, T. Shahrabi Farahani a,⇑, J. Neshati b
a
b
Materials Engineering Department, Faculty of Engineering, Tarbiat modares University, P.O. Box 14115-143, Tehran, Iran
Research Institute of Petroleum Industry (RIPI), P.O. Box 14665-137, Tehran, Iran
a r t i c l e
i n f o
Article history:
Received 10 August 2010
Received in revised form 30 October 2010
Accepted 28 November 2010
Available online 7 December 2010
Keywords:
API 5L X60
Stress corrosion cracking
Pipeline
Intergranular
a b s t r a c t
In January 2010, stress corrosion cracking was occurred in a high-pressure gas pipeline
steel in northern regions of Iran, after almost 40 years since its installation. In this study,
failure mechanisms were determined based on available documents and metallographic
studies conducted on this pipeline. The results showed that the applied polyethylene tape
coating on the external surface of the pipeline became opened and disbonded in the corroded area causing external surface of buried pipeline to be exposed to wet soil around
it. As a result of the chemical interactions and formation of carbonate/bicarbonate solution
and with the presence of tensile stresses, stress corrosion cracking occurred in the longitudinal direction and at the outer surface of the pipe. In addition, mechanisms and morphology of cracks propagation due to stress corrosion cracking to internal side of the pipe wall
were studied.
Ó 2010 Elsevier Ltd. All rights reserved.
1. Introduction
Stress corrosion cracking in oil and gas transmission pipelines used in oil and gas industries is a highly important issue,
because always the leakage or rupture and failure of the pipelines can pose a potential threat to humans and environment. As
a result, corrosion and defects detection of pipelines is essential [1].
Generally, buried pipelines in soil with more than 5 years of life, experience different types of corrosion and metallurgical
defects’ especially cracks. The source of these cracks can be defects that randomly exist and come to existence due to construction or demolition processes of carbon steel pipeline. Combination of stress (such as Hoop stress or residual stress) with
natural soil environment which contains different amounts of moisture and oxygen, promote the initiation of cracking and
accelerates its growth in the thickness of the pipe.
In the pipeline during operation, the cracks can grow from primary sizes to critical sizes leading to leakage (especially in
the pipelines with small wall thickness) or a sudden failure (particularly in the pipelines with large wall thickness). Stress
corrosion cracking on the external surface of pipeline steel has occurred in many countries (such as Australia, Iran, the United States, Canada, and Pakistan), it has been followed by catastrophic events [2,3].
In this case study, the causes of stress corrosion cracking of API 5L X60 steel gas pipeline that was installed in the northern
regions of Iran, has been studied. Chemical analysis of alloy steel pipeline above in comparison with the standard API SPEC 5L
Grade X60 is given in Table 1 [4]. The mechanical properties of the steel discussed in this article using an Instron servo
hydraulic machine evaluated by tensile tests and the results are listed in Table 2. Tensile and yield strengths values are located in the range of standard API 5L X60. Macro hardness tests were performed to clarify the hardness of base metal on
three points to achieve reproducibility. The hardness Vickers tests results are shown in Table 3.
⇑ Corresponding author. Tel.: +98 21 82883378; fax: +98 21 88005040.
E-mail address: tshahrabi34@modares.ac.ir (T. Shahrabi Farahani).
1350-6307/$ - see front matter Ó 2010 Elsevier Ltd. All rights reserved.
doi:10.1016/j.engfailanal.2010.11.014
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E. Sadeghi Meresht et al. / Engineering Failure Analysis 18 (2011) 963–970
Table 1
Chemical composition of steel pipeline suffers stress corrosion cracking in comparison with API SPEC 5L Grade X60.
Specimen
API 5L X60
[4]
Fe
C
Si
Mn
P
S
Cr
Ni
Mo
Cu
V
Ti
Co
Al
Sn
As
Base
–
0.12
Max
0.22
0.3
–
1.2
Max
1.4
0.029
Max
0.03
0.016
Max
0.03
0.01
–
0.01
–
0.01
–
0.03
–
0.061
–
0.002
–
0.007
–
0.017
–
0.002
–
0.005
–
Table 2
Tensile properties of steel pipeline suffer stress corrosion cracking in comparison with API SPEC 5L Grade X60.
Property
Valuea
API 5L X60 [4]
a
Yield strength
Ultimate tensile strength
Circumferential
Longitudinal
Circumferential
Longitudinal
428 (MPa)
62,075 (psi)
Min: 413 (MPa) or 60,000 (psi)
431 (MPa)
62,510 (psi)
522 (MPa)
75,709 (psi)
Min: 517 (MPa) or 75,000 (psi)
518 (MPa)
75,129 (psi)
Under ambient condition (23 °C and 65% relative humidity) with a crosshead speed of 1 mm/min.
2. History of pipeline failure
2.1. Visual inspections
A part of gas transmission pipelines, with diameters of 40 in., suffering from stress corrosion cracking, was in a distance of
3 km downstream from the closest compressor station where the gas temperature was relatively higher than the stable levels further downstream. The pipeline’s cracked zone was at 6 o’clock position. With the help of visual inspection, 59 cracks
observed clearly on the surface area of 50 cm and 20 cm, in the longitudinal direction on the outer surface of the pipeline.
The largest crack length was about 20 mm and the smallest crack length was about 0.1 mm (Fig. 1). All cracks were shallow
and thus with no leaks and failure. Deepest crack was around 2.4 mm and also the external surface of pipeline contained
considerably small to largely wide shallow pits. Some of these pits were even placed in the crack propagation path and some
of these paths were ended to these pits.
Also, field studies indicated that the applied polyethylene tape coating became loose and overlapped, i.e., opened and
disbonded in the corroded area on the outer surface of the pipe. In the cracked region, the coating had lost its adhesion
to the outer surface of the pipe, so it was easily dug.
2.2. Corrosion products analysis
When the coating was completely removed, the external surface of the pipe was covered with a lot of rust red/brown/
black. In addition, small-sized white and yellow powder deposits were observed on the surface of the tube (Fig. 2). These
deposits were collected carefully from the surface of pipe and analyzed by X-ray scattering (Table 4).
Table 3
The hardness Vickers tests results of base metal.
HV value
Point 1
Point 2
Point 3
Applied force (kg f)
Hardness region
Value (HV)
Mean value (HV)
232
230
234
230
3
Base metal
Fig. 1. The longitudinal cracks with different sizes on the external surface of the steel pipeline in a 40 in. gas pipeline failed near a compressor station.
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Fig. 2. The presence of small-sized white and yellow powder deposits under the coating on the external surface of the steel pipeline (50).
Table 4
Elemental analysis (XRF) and structural analysis (XRD) of the corrosion products
formed on the outer surface of the pipe.
Analyzing method
Results
XRF
XRD
Fe, Si, S, Al, Ca, P, Mn, Ni, Cl, O
FeO, Fe3O4, FeCO3
Table 5
Chemical analysis and structural analysis (XRD) of soil samples around the pipeline.
Sample number XRD
Soil chemical analysis
pH (in ambient temperature)
Cl (wt.%) SO2 (wt.%) CO2 (wt.%) HCO
3 (wt.%)
4
3
1
2
3
4
5
CaCO3, SiO2
CaCO3, SiO2
Ca(OH)2, CaO and a small amount of: SiO, Ca3SiO5
CaCO3, SiO2
Ca(OH)2 and a small amount of: SiO2, Ca3SiO5
0.1P
0.1P
0.1P
0.1P
0.1P
0.1P
0.1P
0.1P
0.1P
0.1P
59
48
10
37
2
3.1
2.8
0.4
3.6
0.1
9.4
12.2
11.7
9
12.3
2.3. Analysis of soil adjacent to pipeline
The soil samples adjacent to the cracked area was also analyzed by X-ray scattering (Table 5). The presence of carbonate–
bicarbonate ðCO23 —HCO
3 Þ in the analysis shows the presence of an environment with high pH presence in the vicinity of the
cracked region for a long time.
It should be mentioned, although, a lot of red/brown/black rust was observed on the outer surface of the pipe, there was
no sign of pitting corrosion or weight loss. In fact, the pipe wall thickness dimensions had not change.
2.4. Mechanical and service parameters of the pipeline
Various parameters related to this pipeline are summarized in Table 6. Stress corrosion cracks had been identified after
almost 40 years. During the year before the diagnosis of stress corrosion cracking, operating pressure was lower than the
maximum allowable operating pressure. It is also important to note that the thermal history of the pipeline during the past
years consistently was lower than the allowable limit. The pH of the electrolyte trapped in the gap beneath the disbonded
coating was measured using Litmus paper. pH values were between 8 and 10.
2.5. Protection of pipeline
The damaged pipeline began to operate with the coal-tar based coating, which was replaced by polyethylene tape coating
in 1999. It is reported that this replacement was due to very slight damage which applied to the coal-tar based coating. The
pipeline was cathodic protected by impressed current method for the mitigation of corrosion. Pipe to soil potential measurements (with respect to Cu/CuSO4 reference electrodes), was performed every six months, if required, it should be balanced to
the minimum amount of pipe to soil potentials (0.85 V pipe to soil potential with respect to Cu/CuSO4 reference). It should
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Table 6
Mechanical and service parameters of the pipeline.
Property
API standard
Diameter of pipe
Wall thickness
Grade of steel
Internal gas pressure (at the time of diagnostic the cracks)
Hydraulic pressure (line tested at)
Temperature of gas
Depth below ground level
Type of coating
40 in.
0.5 in.
API 5L X60 60,000 psi min yield
925 psig
1050 psig
32–47 °C
2 diameters
At first coal-tar based which was replaced by polyethylene tape coating from 1999
Table 7
Applied potential for cathodic protection of steel pipelines, with respect to Cu/CuSO4 reference
electrode in the recent third readings.
a
Reading time
Potential range (V)a
First half of 2008 (July)
Second half of 2008 (January)
First half of 2009 (July)
1.5, 1.7
1.11, 1.5
0.9, 1.09
The more distance from the compressor station, the more decreases in potential values.
be mentioned that the part of the pipeline which suffered stress corrosion cracking always had more negative potential than
the standard 0.85 V to the reference electrode of Cu/CuSO4 reference. The recent third reading of the pipeline potentials are
given in Table 7.
2.6. Microstructure
Microstructure of steel pipelines is ferritic–pearlitic structure, in which pearlite grains are dispersed in ferritic base which
consists of lighter ferrites and darker pearlites (Fig. 3). The presence of so many inclusions such as MnS parallel to the longitudinal direction of pipe, were also observed. These inclusions are considered as preferred locations for initiation of surface
cracks or propagation of pre-existing defects [5–7].
2.7. Metallography of cracks
Metallographic samples containing macroscopic cracks and pits were prepared from circumferential sections of the pipe.
After the polishing and etching (2% Nital etchant), the specimen was cleaned using ultrasonic in a 5% EDTA solution for 5 min
and observed using the SEM Phillip XL-30. Furthermore, no article morphologies and crack growth and corrosion mechanisms were studied. Fig. 4 shows that the majority of cracks were initiated at the end of pits, and have been propagated
in the pipe wall thickness. Type of cracks propagation mode was intergranular and branched. On the other hand, main crack’s
path is singular and from the sides and bottom, the secondary small cracks have propagated, that some of these cracks were
not clearly identifiable. Stress corrosion cracks had initiated at ferritic grain boundaries and had grown to a size of several
grains. If only grain boundaries corrosion had occurred, all grain boundaries were subjected to attacks, but because it had
not, grain boundaries corrosion did not happen, but instead intergranular stress corrosion cracks occurred [8].
Micrographs obtained in the Figs. 3–5 shows that (1) In general, cracks growth has been intergranular, (2) cracks have
many fine branches, and (3) corrosion products were observed inside the cracks. These three characteristics caused clearly
by stress corrosion cracks suggest that the pipeline failure was due to stress corrosion cracking [9]. Because the cracks were
Fig. 3. The optical microscopic image of the stress corrosion cracking (200).
E. Sadeghi Meresht et al. / Engineering Failure Analysis 18 (2011) 963–970
Fig. 4. Growth of cracks at the end of pits.
Fig. 5. SEM image (BSE) of the intergranular stress corrosion cracking (240).
Fig. 6. SEM image (SE) of the presence of corrosion products inside the cracks and the corrosion products analysis of point ‘‘A’’.
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Fig. 7. (a) SEM image (BSE) of a macrocrack and (b) results of various zones quantitative analysis.
shallow, it was difficult to break and open these sections in order to perform different analyses such as SEM and EDAX of
corrosion products found on the surface of cracks. So only the largest cracks were broken and opened by doing surface bending [5]. EDAX analysis was carried out from two points (Fig. 7a). Point B is from the tip of crack and point C is from the edge of
the crack. The analyses results show that in point B, corrosion products contain primarily elements such as Carbon, Oxygen,
Silicate, Sulfur and Aluminum. Analysis of corrosion products at point C, which was in the vicinity of the surrounding wet
soil, showed also the same particles in point B. But the amount of sulfur in this section had been slightly increased which
indicates, at this point, the severity of corrosion caused by SRB might be higher than point B (Fig. 7b). EDAX analysis of corrosion products trapped in the crack and its secondary branches resulted in Carbon, Oxygen, Silicate and Sulfur (Fig. 7b).
High amount of Mn in some parts inside the cracks in the EDAX analysis, indicates the presence of MnS inclusions (point A
in Fig. 6a). Micrograph shows some hydrogen voids in the microstructure, which may be created by cathodic protection and
existence of acidic pH conditions in the tip of crack (Fig. 6b).
3. Discussion
The values listed in Tables 1 and 2 shows that the pipe material is in accordance with API 5L Standard. History of pipeline
temperature and pressure shows that stress corrosion cracking occurs in the conditions where temperature and pressure
were working lower than the allowable limits. So obviously, the growth of cracks is due to the defects that had grown up
in the working life of the pipeline. Also long-term placement of pipelines in underground had caused oxide layer to form
on the surface and sides of cracks after many years. The cracks formed in the working conditions in the cross-section, were
opened at the beginning, and became narrower gradually to the crack tip. Thickness of corrosion products approaching the
crack tip decreases, but the size of this thickness is not accurately determined.
Macro hardness Vickers tests of base metals show low hardness in base material that allows one to discard susceptibility
to hydrogen embrittlement, possibly generated by cathodic overprotection.
Scanning electron microscopy can give us the image of secondary electrons (SE) and backscatter electron image (BSE).
Because in the backscatter electron image, heavier particles scattering back more electrons and produce lighter images than
the lighter particles, it can provide more information about the composition of oxide layers. Because of higher content of
oxide layers, this layer seems darker to the steel background. This event may happen more at the fresh crack tip [8].
Characteristics found in this study, is in accordance with the characteristics of stress corrosion cracking with high pH.
Considering the results, the features cannot be found in any other specific mechanism for these phenomena. Defects caused
by stress corrosion cracking, have unique characteristics that occur rarely in other corrosion mechanisms.
E. Sadeghi Meresht et al. / Engineering Failure Analysis 18 (2011) 963–970
969
In our case, these characteristics are the following:
(1) Colonies of intergranular and branched stress corrosion cracks on the pipeline surface.
(2) Considerable concentration of carbonate/bicarbonate in the soil.
(3) Layers of red/brown/black lining surface containing cracks.
The black film covering the fracture surfaces probably consists of magnetite, which is thermodynamically the most likely
corrosion product under the existing electrochemical, temperature and pH conditions. Magnetite is a protective film, but
brittle. If this layer is damaged due to localized plastic strain, allowed to contact the environment to the metal surface at
the tip of the crack. As a result, this localized dissolution leads to initiation and crack propagation of stress corrosion cracks
[7,9].
Yellow powder deposits on the surface of the pipe are probably due to the presence of iron carbonate (FeCO3) that the
corrosion products analysis by XRD and XRF, confirms the presence of this compound. Presence of this compound in
corrosion products indicates the existence of carbonate/bicarbonate environment which is viewed as the most important
factor in stress corrosion cracking at the external pipeline surface [9]. Previous studies show that the environment of carbonate/bicarbonate may result from the cathodic protection reactions. More generally, hydrogen evolution in the trapped water
between the pipeline surface and coating damaged zones, due to cathodic protection current can causes the formation of
hydroxyl ions from electrochemical reactions.
The soil carbon dioxide can react with hydroxyl ions and according to the following reactions, carbonate and bicarbonate
ions will be formed:
CO2 þ OH ! HCO3
HCO3 þ OH ! CO2
3 þ H2 O
Regarding details of the system, different amounts of hydroxyl ions, carbonate and/or bicarbonate can be formed. As a result
of iron ions react with carbonate ions, iron carbonate is formed. The small-sized white powder deposits, is probably related
to crystals of carbonate and sodium bicarbonate deposits.
It should be noted that the CP currents are shielded from the steel by the coating and, thus, are often insufficient to prevent SCC. SCC occurs in the presence of bicarbonate and carbonic solution at locations where the coating may totally shield the pipe from CP. In our case it seems that cathodic protection plays an Insignificant role in
occurrence of high-pH SCC because the range of higher susceptibility electrochemical potentials is almost between
675 and 825 mV (Cu/CuSO4)[10] and CP in the recent third readings of the pipeline potential were higher than
900 mV.
However, the occurrence of stress corrosion cracking is under the influence of different factors such as levels of stress,
temperature and stress fluctuations, pH environment, the potential, and microstructure, initiation of stress corrosion cracks
basically depends on the beginning of the destruction of coating. That is why the new coatings such as polyethylene tape,
Fusion epoxy bonded, and urethane based compounds show better behavior than the old coal-tar based coatings [11,12].
In our case, the coal-tar based coating was replaced by polyethylene tape coating in 1999. The coal-tar based coatings have
had many disadvantages compared to the polyethylene tape coatings such as low resistance of coating to disbonding and the
lower ability to pass current through the coating and thereby protect the disbonded regions [13,14]. Based on previous studies, majority of the stress corrosion cracking failures was associated with coal-tar based coatings and therefore it is possible
that after the recoating, the cracks that initiated during existence of primary coating were dormant for some time, and then
reinitiated during existence of secondary coating.
Most failures occurred by stress corrosion cracking, occur at 6 o’clock position or near the bottom of pipe. Some possible
reasons for this behavior are as follows [15]:
– Because of presence of more defects near the bottom of the pipe in the coatings.
– The bottom of the pipe is usually anodic in comparison to the top because of oxygen-concentration gradients in the soil.
– The water in the soil or under the coating flows toward the bottom of the bitch or the bottom of the pipe.
4. Conclusions
The existence of active defects on external surface steel pipeline immersed in CO2
3 =HCO3 environments indicates its possible susceptibility to SCC failures in such aggressive media. In this study, SEM fractographs of the pipe above showed the
combination of microcleavage, intergranular and branched stress corrosion cracks with high-pH.
In view of the above, the following recommendations are made to prevent the recurrence of similar failures caused by
stress corrosion cracking of the pipelines.
(1) Diagnosis the place of the cracks by destructive and non-destructive tests, to prevent them from growing up.
(2) The prevention or reduction of the growth of stress corrosion cracks, to prevent them from reaching the critical size.
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In general, prevention of SCC requires elimination of one of the three conditions – tensile stress, a critical environment or
a susceptible alloy. Also changing the environment, electrochemical potential, level of stress and temperature, using inhibitors (organic or inorganic inhibitors) and new coatings are considered as other ways of preventing stress corrosion cracking.
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