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Stress corrosion failure of an X52 grade gas pipeline
Engineering Failure Analysis 46 (2014) 157–165
Contents lists available at ScienceDirect
Engineering Failure Analysis journal homepage: www.elsevier.com/locate/engfailanal
Stress corrosion failure of an X52 grade gas pipeline Bilal Saleem, Furqan Ahmed ⇑, Muhammad Asif Rafiq, Mohammad Ajmal, Liaqat Ali Metallurgical and Materials Engineering Department, University of Engineering and Technology, Lahore, Pakistan
a r t i c l e
i n f o
Article history: Received 2 July 2014 Received in revised form 26 August 2014 Accepted 27 August 2014 Available online 3 September 2014 Keywords: Gas pipeline Glass fiber reinforced coal–tar enamel High-pH corrosion Intergranular cracking Lowering/submerging of pipeline
a b s t r a c t In the present work, the failure investigation of a 45.72 cm (18 in.) diameter gas transmission pipeline (X-52 grade steel) has been described. The pipeline was shielded metal arc welded (SMAW) construction, and was welded in the form of spiral. The protective coating, applied on the pipeline, was made of glass fiber reinforced coal–tar enamel. The initial investigation showed that the failure of gas pipeline produced a big depression in the ground underneath. The produced depression was about 6.7 m deep, 4.6 m wide and 15 m long. The visual examination of the pipe revealed the absence of the protective coating from the surface of the pipeline near the ruptured area at many places from 4 o’clock to 7 o’clock positions. On closer examination, pitting was also found at different portions of the bare areas (where the coating was absent) of gas pipeline. Furthermore, the soil in which the pipeline was buried had pH of 9–10 that promoted corrosion on the surface of gas pipeline. The microscopic examination showed that the ruptured portions of the pipeline contained intergranular type cracks. Moreover, the stresses produced due to lowering/submerging of the pipeline seem to have contributed to this failure. The detailed study of this rupture suggested that the possible reason for this failure was stress corrosion cracking (SCC). Ó 2014 Elsevier Ltd. All rights reserved.
1. Introduction Pakistan has two main gas distributors: one that provides gas to the northern part of the country known as Sui Northern Gas pipeline (SNGPL) and the second that delivers gas to the southern portion is named as Sui Southern Gas pipeline (SSGC). This work deals with the failure investigation of a 45.72 cm (18 in.) diameter gas transmission pipeline that was located in the distribution region of SNGPL. The total service of the pipeline till failure was 25 years. The data review on the ages of pipelines in different countries around the world shows that the average age of the gas pipeline at the time of first high-pH stress corrosion failure was 22.9 years [1]. Stress corrosion cracking (SCC) occurs due to the combination of three factors; a susceptible material, localized tensile stress above threshold and exposure to corrosive environment. The first concept of SCC was reported after the metallographic and fractographic analyses of ruptured gas pipelines at Battelle in 1957 and Louisiana in 1965 [2]. It has been reported that there are two kinds of environments (developed between the coating and the outer pipeline surface) which are responsible to promote SCC on a gas pipeline [3,4]. These environments include; (i) the high pH alkaline environment (pH 9) responsible for SCC in USA, Austria, Iraq, Italy, Pakistan and Saudi Arabia, and (ii) nearly neutral pH that is found in the soils of Canada and Russia to causes SCC. The SCC that involves high-pH (9–10) solutions, contributes to intergranular cracking [5] and in case of stress corrosion cracking in lower-pH (6–7) environments, transgranular cracking occurs [6]. The studies have shown that the environments responsible for intergranular SCC (pH 9–10) contain high ⇑ Corresponding author. http://dx.doi.org/10.1016/j.engfailanal.2014.08.011 1350-6307/Ó 2014 Elsevier Ltd. All rights reserved.
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2 concentration of HCO 3 and CO3 ions in the vicinity of failures. Whereas in case of the solutions responsible for transgran ular SCC (pH 6–7), the concentration of CO2 3 ions is found negligible and the equilibrium is found between HCO3 ions and H2CO3 [7]. In order to protect the pipelines against corrosion, these are coated with an external coating. Moreover, a cathodic protection (CP) system is also installed to control the corrosion. It is well known that excessive cathodic (impressed) current produces hydrogen gas in the electrolytes in which the cathode are dipped [8,9]. This evolved hydrogen gas damages the protective coating (‘‘blowing off’’). With the increase in damage in the coating, the amount of current being drained from the system is increased [10]. The impressed current has to rise in order to maintain the required pipeline to soil potential. It has been reported by several researchers that the excessive use of cathodic protection for a buried gas pipe line increases the likelihood of SCC [11,12]. Most of the incidents of stress corrosion cracking (SCC) are reported to have occurred at the hoop stress level of 60% of specified minimum yield strength (SMYS). In all of these cases, there was either a secondary loading or a stress concentration due to a dent or local bending. Most of the SCC incidents have involved axial cracking. However, a few cases have also been reported where cracking had occurred transverse to the pipeline’s axis [2].
2. Description and history of failed pipeline 2.1. Location of the rupture The rupture of 45.72 cm (18 in.) diameter gas pipeline had occurred almost 4.0 km downstream to the cathodic protection (CP) station in the northern part of Pakistan.
2.2. Observations regarding site The failure had occurred over a pipeline length of 10.7 m, which is schematically shown in Fig. 1 and the photographs taken from the real fractured pipeline pieces are given in Fig. 2. Out of this 10.7 m length, 5.8 m long segment had opened along its spiral weld to form a plate (see Figs. 1B and 2a). Approximately 1.83 m long portion of the gas pipeline was detached from the ruptured end and blasted away to a distance of 300 m due to high gas pressure. The separated piece is shown in Fig. 1C/Fig. 2c, whereas the fractured ends upstream and downstream are labeled as ‘B’ and ‘D’, respectively in Fig. 1. The bent pipe sketched in Fig. 1D corresponds to the pipe shown in Fig. 2b. The failure of this pipeline had produced a large crater (almost 6.7 m deep, 4.6 m wide and 15 m long) on the ground which can be seen in Fig. 2b.
2.3. Mechanical and operating parameters of the gas pipeline The mechanical and operating parameters of this pipeline are given in Table 1.
2.4. Pipeline protection The failed pipe was coated with glass fiber reinforced coal–tar based enamel. Additionally, it was protected with cathodic protection (CP) system to protect it from corrosion. The CP system was functioning since the commissioning of this pipeline. Pipe to soil potential was checked every three months and adjustments were made, if needed, with respect to Cu/CuSO4 reference electrodes.
Fig. 1. Schematics of the fractured pipeline. B and D portions correspond to the fractures ends upstream and downstream, respectively. C portion corresponds to the pipeline piece which was blasted away after rupture.
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Fig. 2. Photographs taken from the real fractured pipeline pieces. (a) 5.8 m long segment of the pipe which had opened along its spiral weld to form a plate, (b) photograph of the site, showing failed pipes and the crater formation due to gas pressure, (c) central portion of the pipe that was blasted away after stress rupture.
Table 1 Mechanical and operating data of gas pipeline. Mechanical/operating data Steel grade Type of weld Diameter Wall thickness SYMS Operating pressure of gas Gas temperature Depth below ground level Type of coating
API 5L grade X-52 Spiral welded 45.72 cm (18 in.) 7.67 mm (0.302 in.) 359 MPa (52,000 psi) 7.37 MPa (1070 psi) 70 °C 2.13 m (7 ft) Reinforced coal–tar
3. Investigation of the rupture 3.1. Inspection of protective coating and the pipe surface Following the failure, the inspection team had arrived at the site and examined the ruptured pipeline. All the fractured pieces of the pipeline (labeled as B, C and D in Fig. 1) were available for inspection. The coating was almost completely absent from the pipe piece B due to flattening of the pipe. Pipe piece C was also showing no coating on its surface. In case of pipe D, coating was present at some locations and could be easily peeled off as can be seen in Fig. 3a. At some locations, sign of poor coating were present (see Fig. 3b). Under the coating and on the locations where coating was absent, rusty brownish surface could also be seen. The closer visual examination of the fractured ends revealed the presence of pitting and macro-cracks as shown in Fig. 3c. Pitting could also be seen at some other locations away from fractured ends.
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Fig. 3. (a) D portion of the ruptured pipeline showing damaged coating and rusty surface, (b) photograph of the pipeline showing the presence of poor adhesive coating, (c) fractured end of the pipe revealing macro-cracks and pitting.
In order to inspect the condition of the coating on the buried pipeline, two holes were dug. The schematic representation of these holes is shown in Fig. 4. The first hole (hole-A) was 61.0 m upstream to the rupture point. Top surface of the pipeline was 1.22 m deep from the soil level. The second hole (hole-B) was 21.3 m downstream to the rupture point and it was near the canal. The top surface of the pipeline in hole-B was 2.13 m deep from the soil level. The protective coating was found in poor condition, both in holes A and B, as can be seen in Fig. 5a and b. To check the presence of any electrolyte between coating and pipe surface, the coating was gently removed from the both excavated pipelines at 4 o’clock positions, and a layer of moisture was seen at the coating–pipeline interface as shown in Fig. 5c. The pH of this moisture/electrolyte was found between 9 and 10. A number soil samples were also collected from various locations (see Fig. 6) around the pipeline. All the samples were analyzed with XRD. The main constituents of the soil in the order of concentration were: (1) Quartz, (2) Muscovite and (3) Albite calcian. The pH values of all the soil samples were also measured using standard method and these were falling in between 9 and 10. It is found from the above observations that the coal–tar coating on the surface of the pipe had undergone deterioration and caused disbondment (Fig. 5). The high-pH ‘corrosive environment’ had also been present at pipe/coating interface. Furthermore, the soil chemistry indicates that a high-pH environment was present there for a considerable length of time which had caused corrosion pitting of the pipe surface (see Fig. 3c).
Fig. 4. Schematic representation of holes A and B. Hole-A was dug at 1.22 m depth while hole-B was made at 2.13 m depth.
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Fig. 5. (a) Poor condition of the coal–tar coating on the surface of the pipe found in hole-A, (b) damaged coating on the surface of the pipe found in hole-B, (c) presence of moisture/electrolytes at coating-pipeline interface. The disbonded coating can also be seen here.
Fig. 6. Schematic representations of soil collection points.
3.2. Analysis of cathodic protection of pipeline The ruptured segment of the 45.72 cm (18 in.) diameter pipeline was catholically protected by impressed current from rectifiers located 4.0 km upstream at CP station. The Transformer Rectifier (TR) unit was operating at 34 V and 27 A (High Silicon Anode Ground Bed). The pipeline to soil potential was 1.5 V at the CP station. It was reported by the staff at CP station that the downstream pipeline segment (under discussion) was drawing excessive current to adjust the potential for cathodic protection [13]. This high impressed current might have become responsible for the deterioration of the coating. 3.3. Source of additional stress In hole-B, which was dug 21.3 m downstream to the rupture point near the canal, 91 cm additional pipeline lowering was observed from the level of soil as compared to the normal depth (see Fig. 7). This lowering of pipeline was done to facilitate the safe passage of pipeline below the canal. This lowering/bending of the pipeline may have induced additional stresses on the pipe near the ruptured area.
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Fig. 7. Schematic representation of lowered/submerged pipeline under the canal. The pipe had produced additional stresses because of lowering and submerging.
3.4. Chemical analysis and calculation of carbon equivalent (CE) After the completion of on-site examination, it was decided to analyze the chemical composition of pipeline material to check whether it conforms to API 5L grade X-52 specification or not, and also to calculate its carbon equivalent. The spark emission spectrometer (METAL LAB 75-80, GNR Analytical Instruments, Italy) was used for chemical composition analysis of the pipeline steel. The analysis is given in Table 2. The chemical analysis shows that the steel composition is in accordance with X-52 pipe grade. According to American Petroleum Institute (API) specifications 5L [14], if carbon content is less than 0.12% then the following formula is used to calculate the carbon equivalent i.e. CE (Pcm) formula.
CE ¼ C þ
Si Mn Cu Ni Cr Mo V þ þ þ þ þ þ þ 5B 30 20 20 60 20 15 10
ð1Þ
According to above formula the CE of the pipeline material is 0.134 and the maximum limit is up to 0.25. Thus the CE (Pcm) of this material is within the allowable range. 3.5. Determination of mechanical properties The pipeline steel was also tensile tested as per API specifications 5L [14] to confirm whether the material complies with the API X-52 grade or not. In order to carry out tensile test, a number of samples were prepared and tested in a Universal Testing Machine (UTM) according to API standards/specifications [14]. In order to calculate elongation, following formula as per API specifications 5L [14] was used.
e ¼ 1944
A0:2
ð2Þ
U 0:9
where A = applicable area of tensile test specimen in ‘mm2’, U = specified minimum ultimate tensile strength in ‘MPa’, e = minimum elongation in 50 mm gauge length. The measured and the minimum required values of yield strength, tensile strength and percentage elongation (e) are given in Table 3. The comparison of mechanical properties indicates that pipeline material complies with API X52 specifications and is of reasonable quality. In the pressurized pipe, the Hoop stress is very important and can be calculated using following relation.
rhoop ¼
Pd 2t
ð3Þ
where gas pressure (P) = 7.37 MPa, diameter (d) = 45.72 cm, wall thickness (t) = 7.7 mm, hoop stress (r) = 220 MPa (61.2% of SMYS). Using the above formula, the hoop stress is 220 MPa which is about 61.2% of SMYS as against 72% maximum allowable.
Table 2 Chemical composition of pipeline steel. %C
%Si
%Mn
%Al
%P
%S
%Cu
%Ni
%Cr
%Ti
%Mo
0.070
0.334
1.066
0.32
0.009
0.019
0.007
0.0078
0.008
0.009
0.0013
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B. Saleem et al. / Engineering Failure Analysis 46 (2014) 157–165 Table 3 Measured and required yield strength, tensile strength and percentage elongations (e). Mechanical properties
Yield strength (MPa)
Tensile strength (MPa)
Percentage elongation (e)
Measured Required
375 359
425 455
24 23
3.6. Macroscopic examination Few samples were cut from the fractured ends of the pipeline and prepared for macroscopic examination. Macro-photograph of one of such samples is shown in Fig. 8a. Visible corrosion pitting can be seen on the surface of the pipe in this macrograph. This pitting had resulted from high-pH environment present in the surrounding soil. In the same macro-graph shown in Fig. 8a, branched cracking can also be seen. The photograph taken from the fractured surface of the same sample is presented in Fig. 8b and it shows that the pipe has undergone brittle fracture. 3.7. Microscopic examination Various samples were taken from crack initiation point for microstructural studies to identify the mode of rupture. The standard polishing procedures were followed to prepare the samples, both for optical and Scanning Electron Microscopy (SEM). The microstructure in Fig. 9 shows the presence of one of the corrosion pits. The deterioration and deformation of the steel microstructure can be seen around the pit, and the depth of this corrosion pit is 105 lm. The corrosion pits are responsible for a slight reduction in pipe wall thickness, and acted as stress raisers. The intergranular cracks with extensive branching [15,16] and the corrosion product inside the cracks can be seen in optical and SEM micrographs shown in Fig. 10a and b. Mainly three characteristics have been observed here: (a) intergranular cracking, (b) extensive crack branching, (c) corrosion products inside cracks. These three features are typically found in case of stress corrosion cracking [16], and intergranular type SCC is found mainly because of high-pH (9–10) environment [5]. 4. Findings of failure analysis It is a well-established fact that for stress corrosion cracking to occur in a pipeline, following three conditions must be satisfied. Corrosive environment. Material susceptible to SCC. Stress.
Fig. 8. (a) Macro-graph taken from the pipe surface at the fractured end. Corrosion pitting and branched cracking can be seen here. (b) Photograph taken from the fractured surface showing brittle fracture.
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Fig. 9. Micrograph of the corrosion pit, showing deterioration of the steel microstructure. The depth of this corrosion pit is 105 lm.
Fig. 10. (a) Optical micrograph showing intergranular cracking. The branching of the cracks can also be noted here. (b) SEM micrographs showing intergranular cracks. Corrosion products can also be seen inside these cracks.
4.1. Corrosive environment It is well known that potential adjustment is required as the coating deteriorates [14]. It was observed that the amount of impressed current was quite excessive in the segment where the rupture had occurred. So the coating (see Fig. 5a and b) may have started to damage in this particular segment a long ago. This has resulted in the seepage of moisture/electrolytes to the pipeline surface which can be seen in Fig. 5c. The content of the surrounding soil (high-pH) were also in contact with the
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naked areas of the pipe for a considerable length of time. The high-pH of the moisture/electrolyte and soil as mentioned earlier has contributed to SCC. The corrosion resulted in the formation of pits (see Figs. 3c and 8a) on the surface which in turn slightly reduced the wall thickness of the pipe and caused stress concentration. Therefore, the crack propagated under the combined action of ‘corrosion and stress’ until it attained a critical size, then catastrophically travelled and caused this rupture. 4.2. Material susceptible to SCC The results of the material testing i.e. chemical composition and mechanical properties as shown in Tables 2 and 3 indicate that pipeline material was of reasonable quality and almost similar to the specification of X52. However, it has been reported that X52 exhibited SCC several times in the presence of high-pH in various parts of the world [17]. Microscopic examination of the pipeline in the vicinity of the fractured area has clearly indicated the presence of corrosion pits (see Fig. 9). It can be seen in Fig. 10 that crack initiation point exhibits intergranular cracks with extensive branching. The corrosion product (i.e. dark etching areas) can also be seen within these cracks. These metallographic observations are similar to the reported incidents of SCC with high-pH [5,15,16]. 4.3. Stress The third prerequisite for the SCC, the hoop stress of 220 MPa (61.2% of SMYS) caused by pressurized gas was present in the pipeline. However, 91 cm extra lowering/submerging of the pipe line was also observed 21.3 m downstream (hole-B) to the rupture point. This lowering was extended till the bottom of the canal which was approximately 13.7 m further from hole-B. This simple lowering/submerging of the pipeline to get passage under the canal may have induced additional stresses in the pipeline at the fracture area and appeared to have contributed to the rupture. As a results of the above investigation and explanation, it can be concluded that the presence of the high-pH (9–10) moisture/electrolytes at the pipeline-coating interface and the stresses other than hoop stress, generated due to the lowering/ submerging of the pipeline (X52), are the possible causes of this stress corrosion cracking. 5. Conclusions Detailed investigation suggested that the probable cause of the rupture of X52 grade gas pipeline was SCC. The rupture had initiated/developed due to the decay/disbondment of the protective fiber reinforced coal–tar coating. The presence of moisture/electrolyte of high-pH (9–10) was observed at the interface of pipeline and coating. The additional stresses at the rupture area of the pipe line due to lowering/submerging of the pipeline likely to have contributed to this rupture. The Metallography revealed intergranular nature of fracture with branching and corrosion products inside cracks.
Acknowledgments Authors are deeply thankful to the SNGPL company Pakistan for providing the opportunity of conducting this failure analysis. We are also grateful to University of Engineering and Technology-Lahore and Pakistan council of Science and Industrial Research (PCSIR)-Lahore for utilizing their facilities and carry out the experimental work for this study. References [1] Wenk RL. Field investigation of stress–corrosion cracking. In: Proceedings of 5th symposium on line pipe research. Pipeline Research Committee, American Gas Association Catalog; 1997. p. 1–22 [no. 130174]. [2] Leis BN, Eiber RJ. Stress–corrosion cracking on gas transmission pipelines. In: Proceedings of first international business conference on onshore pipe lines history, causes, and mitigation, Berlin; 1997. Invited paper. [3] Villalba E, Atrens A. An evaluation of steels subjected to rock bolt SCC condition. Eng Failure Anal 2007;14:1351. [4] Manfredi C, Otegui JI. Failure by SCC in buried pipelines. Eng Failure Anal 2002;9:495. [5] Parkins RN, Fessler RR. Line pipe stress corrosion cracking-mechanisms and remedies. Corrosion 1986;86(March):8 [Paper number 320, NACE]. [6] Parkins RN, Blanchard Jr WK, Delanty BS. Transgranular stress corrosion cracking of high-pressure pipelines in contact with solutions of near neutral pH. Corrosion 1994;50:394. [7] Charles EA, Parkins RN. Generation of stress corrosion cracking environments at pipeline surfaces. Corrosion 1995;51:518. [8] Dey S, Mandhyan AK, Sondhi SK, Chattoraj I. Hydrogen entry into pipeline steel under freely corroding conditions in two corroding media. Corros Sci 2006;48:2676. [9] Shipilov SA, May IL. Structural integrity of aging buried pipelines having cathodic protection. Eng Failure Anal 2006;13:1159. [10] Liang P, Du CW, Li XG, Chen X, Liang Zl. Effect of hydrogen on the stress corrosion cracking behavior of X80 pipeline steel in Ku’erle soil simulated solution. Int J Miner Metall Mater 2009;16:407. [11] Kamimura K, Kishikawa H. Mechanism of cathodic disbanding of three-layer polyethylene-coated steel pipe. Corrosion 1998;54:979. [12] Yan MC, Weng YJ. Study on hydrogen absorption of pipeline steel under cathodic charging. Corros Sci 2006;48:432. [13] Private communication with SNGPL (Sui Northern Gas Pipelines Limited), Pakistan. [14] API (American Petroleum Institute) 5L specification for line pipe. 44th ed. Washington (DC): API Publishing Services; 2007. [15] Capelle J, Gilgert J, Dmytrakh I, Pluvinage G. Sensitivity of pipeline with steel API X52 to hydrogen embrittlement. Int J Hydrogen Energy 2008;33:7630. [16] Hasan F, Iqbal J, Ahmed F. Stress corrosion failure of a high-pressure gas pipeline. Eng Failure Anal 2007;14:801. [17] Stress Corrosion Cracking Studies. A report by DCVG (DC Voltage Gradient) Technology & Supply Limited, United Kingdom; 2006.
Contents lists available at ScienceDirect
Engineering Failure Analysis journal homepage: www.elsevier.com/locate/engfailanal
Stress corrosion failure of an X52 grade gas pipeline Bilal Saleem, Furqan Ahmed ⇑, Muhammad Asif Rafiq, Mohammad Ajmal, Liaqat Ali Metallurgical and Materials Engineering Department, University of Engineering and Technology, Lahore, Pakistan
a r t i c l e
i n f o
Article history: Received 2 July 2014 Received in revised form 26 August 2014 Accepted 27 August 2014 Available online 3 September 2014 Keywords: Gas pipeline Glass fiber reinforced coal–tar enamel High-pH corrosion Intergranular cracking Lowering/submerging of pipeline
a b s t r a c t In the present work, the failure investigation of a 45.72 cm (18 in.) diameter gas transmission pipeline (X-52 grade steel) has been described. The pipeline was shielded metal arc welded (SMAW) construction, and was welded in the form of spiral. The protective coating, applied on the pipeline, was made of glass fiber reinforced coal–tar enamel. The initial investigation showed that the failure of gas pipeline produced a big depression in the ground underneath. The produced depression was about 6.7 m deep, 4.6 m wide and 15 m long. The visual examination of the pipe revealed the absence of the protective coating from the surface of the pipeline near the ruptured area at many places from 4 o’clock to 7 o’clock positions. On closer examination, pitting was also found at different portions of the bare areas (where the coating was absent) of gas pipeline. Furthermore, the soil in which the pipeline was buried had pH of 9–10 that promoted corrosion on the surface of gas pipeline. The microscopic examination showed that the ruptured portions of the pipeline contained intergranular type cracks. Moreover, the stresses produced due to lowering/submerging of the pipeline seem to have contributed to this failure. The detailed study of this rupture suggested that the possible reason for this failure was stress corrosion cracking (SCC). Ó 2014 Elsevier Ltd. All rights reserved.
1. Introduction Pakistan has two main gas distributors: one that provides gas to the northern part of the country known as Sui Northern Gas pipeline (SNGPL) and the second that delivers gas to the southern portion is named as Sui Southern Gas pipeline (SSGC). This work deals with the failure investigation of a 45.72 cm (18 in.) diameter gas transmission pipeline that was located in the distribution region of SNGPL. The total service of the pipeline till failure was 25 years. The data review on the ages of pipelines in different countries around the world shows that the average age of the gas pipeline at the time of first high-pH stress corrosion failure was 22.9 years [1]. Stress corrosion cracking (SCC) occurs due to the combination of three factors; a susceptible material, localized tensile stress above threshold and exposure to corrosive environment. The first concept of SCC was reported after the metallographic and fractographic analyses of ruptured gas pipelines at Battelle in 1957 and Louisiana in 1965 [2]. It has been reported that there are two kinds of environments (developed between the coating and the outer pipeline surface) which are responsible to promote SCC on a gas pipeline [3,4]. These environments include; (i) the high pH alkaline environment (pH 9) responsible for SCC in USA, Austria, Iraq, Italy, Pakistan and Saudi Arabia, and (ii) nearly neutral pH that is found in the soils of Canada and Russia to causes SCC. The SCC that involves high-pH (9–10) solutions, contributes to intergranular cracking [5] and in case of stress corrosion cracking in lower-pH (6–7) environments, transgranular cracking occurs [6]. The studies have shown that the environments responsible for intergranular SCC (pH 9–10) contain high ⇑ Corresponding author. http://dx.doi.org/10.1016/j.engfailanal.2014.08.011 1350-6307/Ó 2014 Elsevier Ltd. All rights reserved.
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2 concentration of HCO 3 and CO3 ions in the vicinity of failures. Whereas in case of the solutions responsible for transgran ular SCC (pH 6–7), the concentration of CO2 3 ions is found negligible and the equilibrium is found between HCO3 ions and H2CO3 [7]. In order to protect the pipelines against corrosion, these are coated with an external coating. Moreover, a cathodic protection (CP) system is also installed to control the corrosion. It is well known that excessive cathodic (impressed) current produces hydrogen gas in the electrolytes in which the cathode are dipped [8,9]. This evolved hydrogen gas damages the protective coating (‘‘blowing off’’). With the increase in damage in the coating, the amount of current being drained from the system is increased [10]. The impressed current has to rise in order to maintain the required pipeline to soil potential. It has been reported by several researchers that the excessive use of cathodic protection for a buried gas pipe line increases the likelihood of SCC [11,12]. Most of the incidents of stress corrosion cracking (SCC) are reported to have occurred at the hoop stress level of 60% of specified minimum yield strength (SMYS). In all of these cases, there was either a secondary loading or a stress concentration due to a dent or local bending. Most of the SCC incidents have involved axial cracking. However, a few cases have also been reported where cracking had occurred transverse to the pipeline’s axis [2].
2. Description and history of failed pipeline 2.1. Location of the rupture The rupture of 45.72 cm (18 in.) diameter gas pipeline had occurred almost 4.0 km downstream to the cathodic protection (CP) station in the northern part of Pakistan.
2.2. Observations regarding site The failure had occurred over a pipeline length of 10.7 m, which is schematically shown in Fig. 1 and the photographs taken from the real fractured pipeline pieces are given in Fig. 2. Out of this 10.7 m length, 5.8 m long segment had opened along its spiral weld to form a plate (see Figs. 1B and 2a). Approximately 1.83 m long portion of the gas pipeline was detached from the ruptured end and blasted away to a distance of 300 m due to high gas pressure. The separated piece is shown in Fig. 1C/Fig. 2c, whereas the fractured ends upstream and downstream are labeled as ‘B’ and ‘D’, respectively in Fig. 1. The bent pipe sketched in Fig. 1D corresponds to the pipe shown in Fig. 2b. The failure of this pipeline had produced a large crater (almost 6.7 m deep, 4.6 m wide and 15 m long) on the ground which can be seen in Fig. 2b.
2.3. Mechanical and operating parameters of the gas pipeline The mechanical and operating parameters of this pipeline are given in Table 1.
2.4. Pipeline protection The failed pipe was coated with glass fiber reinforced coal–tar based enamel. Additionally, it was protected with cathodic protection (CP) system to protect it from corrosion. The CP system was functioning since the commissioning of this pipeline. Pipe to soil potential was checked every three months and adjustments were made, if needed, with respect to Cu/CuSO4 reference electrodes.
Fig. 1. Schematics of the fractured pipeline. B and D portions correspond to the fractures ends upstream and downstream, respectively. C portion corresponds to the pipeline piece which was blasted away after rupture.
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Fig. 2. Photographs taken from the real fractured pipeline pieces. (a) 5.8 m long segment of the pipe which had opened along its spiral weld to form a plate, (b) photograph of the site, showing failed pipes and the crater formation due to gas pressure, (c) central portion of the pipe that was blasted away after stress rupture.
Table 1 Mechanical and operating data of gas pipeline. Mechanical/operating data Steel grade Type of weld Diameter Wall thickness SYMS Operating pressure of gas Gas temperature Depth below ground level Type of coating
API 5L grade X-52 Spiral welded 45.72 cm (18 in.) 7.67 mm (0.302 in.) 359 MPa (52,000 psi) 7.37 MPa (1070 psi) 70 °C 2.13 m (7 ft) Reinforced coal–tar
3. Investigation of the rupture 3.1. Inspection of protective coating and the pipe surface Following the failure, the inspection team had arrived at the site and examined the ruptured pipeline. All the fractured pieces of the pipeline (labeled as B, C and D in Fig. 1) were available for inspection. The coating was almost completely absent from the pipe piece B due to flattening of the pipe. Pipe piece C was also showing no coating on its surface. In case of pipe D, coating was present at some locations and could be easily peeled off as can be seen in Fig. 3a. At some locations, sign of poor coating were present (see Fig. 3b). Under the coating and on the locations where coating was absent, rusty brownish surface could also be seen. The closer visual examination of the fractured ends revealed the presence of pitting and macro-cracks as shown in Fig. 3c. Pitting could also be seen at some other locations away from fractured ends.
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Fig. 3. (a) D portion of the ruptured pipeline showing damaged coating and rusty surface, (b) photograph of the pipeline showing the presence of poor adhesive coating, (c) fractured end of the pipe revealing macro-cracks and pitting.
In order to inspect the condition of the coating on the buried pipeline, two holes were dug. The schematic representation of these holes is shown in Fig. 4. The first hole (hole-A) was 61.0 m upstream to the rupture point. Top surface of the pipeline was 1.22 m deep from the soil level. The second hole (hole-B) was 21.3 m downstream to the rupture point and it was near the canal. The top surface of the pipeline in hole-B was 2.13 m deep from the soil level. The protective coating was found in poor condition, both in holes A and B, as can be seen in Fig. 5a and b. To check the presence of any electrolyte between coating and pipe surface, the coating was gently removed from the both excavated pipelines at 4 o’clock positions, and a layer of moisture was seen at the coating–pipeline interface as shown in Fig. 5c. The pH of this moisture/electrolyte was found between 9 and 10. A number soil samples were also collected from various locations (see Fig. 6) around the pipeline. All the samples were analyzed with XRD. The main constituents of the soil in the order of concentration were: (1) Quartz, (2) Muscovite and (3) Albite calcian. The pH values of all the soil samples were also measured using standard method and these were falling in between 9 and 10. It is found from the above observations that the coal–tar coating on the surface of the pipe had undergone deterioration and caused disbondment (Fig. 5). The high-pH ‘corrosive environment’ had also been present at pipe/coating interface. Furthermore, the soil chemistry indicates that a high-pH environment was present there for a considerable length of time which had caused corrosion pitting of the pipe surface (see Fig. 3c).
Fig. 4. Schematic representation of holes A and B. Hole-A was dug at 1.22 m depth while hole-B was made at 2.13 m depth.
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Fig. 5. (a) Poor condition of the coal–tar coating on the surface of the pipe found in hole-A, (b) damaged coating on the surface of the pipe found in hole-B, (c) presence of moisture/electrolytes at coating-pipeline interface. The disbonded coating can also be seen here.
Fig. 6. Schematic representations of soil collection points.
3.2. Analysis of cathodic protection of pipeline The ruptured segment of the 45.72 cm (18 in.) diameter pipeline was catholically protected by impressed current from rectifiers located 4.0 km upstream at CP station. The Transformer Rectifier (TR) unit was operating at 34 V and 27 A (High Silicon Anode Ground Bed). The pipeline to soil potential was 1.5 V at the CP station. It was reported by the staff at CP station that the downstream pipeline segment (under discussion) was drawing excessive current to adjust the potential for cathodic protection [13]. This high impressed current might have become responsible for the deterioration of the coating. 3.3. Source of additional stress In hole-B, which was dug 21.3 m downstream to the rupture point near the canal, 91 cm additional pipeline lowering was observed from the level of soil as compared to the normal depth (see Fig. 7). This lowering of pipeline was done to facilitate the safe passage of pipeline below the canal. This lowering/bending of the pipeline may have induced additional stresses on the pipe near the ruptured area.
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Fig. 7. Schematic representation of lowered/submerged pipeline under the canal. The pipe had produced additional stresses because of lowering and submerging.
3.4. Chemical analysis and calculation of carbon equivalent (CE) After the completion of on-site examination, it was decided to analyze the chemical composition of pipeline material to check whether it conforms to API 5L grade X-52 specification or not, and also to calculate its carbon equivalent. The spark emission spectrometer (METAL LAB 75-80, GNR Analytical Instruments, Italy) was used for chemical composition analysis of the pipeline steel. The analysis is given in Table 2. The chemical analysis shows that the steel composition is in accordance with X-52 pipe grade. According to American Petroleum Institute (API) specifications 5L [14], if carbon content is less than 0.12% then the following formula is used to calculate the carbon equivalent i.e. CE (Pcm) formula.
CE ¼ C þ
Si Mn Cu Ni Cr Mo V þ þ þ þ þ þ þ 5B 30 20 20 60 20 15 10
ð1Þ
According to above formula the CE of the pipeline material is 0.134 and the maximum limit is up to 0.25. Thus the CE (Pcm) of this material is within the allowable range. 3.5. Determination of mechanical properties The pipeline steel was also tensile tested as per API specifications 5L [14] to confirm whether the material complies with the API X-52 grade or not. In order to carry out tensile test, a number of samples were prepared and tested in a Universal Testing Machine (UTM) according to API standards/specifications [14]. In order to calculate elongation, following formula as per API specifications 5L [14] was used.
e ¼ 1944
A0:2
ð2Þ
U 0:9
where A = applicable area of tensile test specimen in ‘mm2’, U = specified minimum ultimate tensile strength in ‘MPa’, e = minimum elongation in 50 mm gauge length. The measured and the minimum required values of yield strength, tensile strength and percentage elongation (e) are given in Table 3. The comparison of mechanical properties indicates that pipeline material complies with API X52 specifications and is of reasonable quality. In the pressurized pipe, the Hoop stress is very important and can be calculated using following relation.
rhoop ¼
Pd 2t
ð3Þ
where gas pressure (P) = 7.37 MPa, diameter (d) = 45.72 cm, wall thickness (t) = 7.7 mm, hoop stress (r) = 220 MPa (61.2% of SMYS). Using the above formula, the hoop stress is 220 MPa which is about 61.2% of SMYS as against 72% maximum allowable.
Table 2 Chemical composition of pipeline steel. %C
%Si
%Mn
%Al
%P
%S
%Cu
%Ni
%Cr
%Ti
%Mo
0.070
0.334
1.066
0.32
0.009
0.019
0.007
0.0078
0.008
0.009
0.0013
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B. Saleem et al. / Engineering Failure Analysis 46 (2014) 157–165 Table 3 Measured and required yield strength, tensile strength and percentage elongations (e). Mechanical properties
Yield strength (MPa)
Tensile strength (MPa)
Percentage elongation (e)
Measured Required
375 359
425 455
24 23
3.6. Macroscopic examination Few samples were cut from the fractured ends of the pipeline and prepared for macroscopic examination. Macro-photograph of one of such samples is shown in Fig. 8a. Visible corrosion pitting can be seen on the surface of the pipe in this macrograph. This pitting had resulted from high-pH environment present in the surrounding soil. In the same macro-graph shown in Fig. 8a, branched cracking can also be seen. The photograph taken from the fractured surface of the same sample is presented in Fig. 8b and it shows that the pipe has undergone brittle fracture. 3.7. Microscopic examination Various samples were taken from crack initiation point for microstructural studies to identify the mode of rupture. The standard polishing procedures were followed to prepare the samples, both for optical and Scanning Electron Microscopy (SEM). The microstructure in Fig. 9 shows the presence of one of the corrosion pits. The deterioration and deformation of the steel microstructure can be seen around the pit, and the depth of this corrosion pit is 105 lm. The corrosion pits are responsible for a slight reduction in pipe wall thickness, and acted as stress raisers. The intergranular cracks with extensive branching [15,16] and the corrosion product inside the cracks can be seen in optical and SEM micrographs shown in Fig. 10a and b. Mainly three characteristics have been observed here: (a) intergranular cracking, (b) extensive crack branching, (c) corrosion products inside cracks. These three features are typically found in case of stress corrosion cracking [16], and intergranular type SCC is found mainly because of high-pH (9–10) environment [5]. 4. Findings of failure analysis It is a well-established fact that for stress corrosion cracking to occur in a pipeline, following three conditions must be satisfied. Corrosive environment. Material susceptible to SCC. Stress.
Fig. 8. (a) Macro-graph taken from the pipe surface at the fractured end. Corrosion pitting and branched cracking can be seen here. (b) Photograph taken from the fractured surface showing brittle fracture.
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Fig. 9. Micrograph of the corrosion pit, showing deterioration of the steel microstructure. The depth of this corrosion pit is 105 lm.
Fig. 10. (a) Optical micrograph showing intergranular cracking. The branching of the cracks can also be noted here. (b) SEM micrographs showing intergranular cracks. Corrosion products can also be seen inside these cracks.
4.1. Corrosive environment It is well known that potential adjustment is required as the coating deteriorates [14]. It was observed that the amount of impressed current was quite excessive in the segment where the rupture had occurred. So the coating (see Fig. 5a and b) may have started to damage in this particular segment a long ago. This has resulted in the seepage of moisture/electrolytes to the pipeline surface which can be seen in Fig. 5c. The content of the surrounding soil (high-pH) were also in contact with the
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naked areas of the pipe for a considerable length of time. The high-pH of the moisture/electrolyte and soil as mentioned earlier has contributed to SCC. The corrosion resulted in the formation of pits (see Figs. 3c and 8a) on the surface which in turn slightly reduced the wall thickness of the pipe and caused stress concentration. Therefore, the crack propagated under the combined action of ‘corrosion and stress’ until it attained a critical size, then catastrophically travelled and caused this rupture. 4.2. Material susceptible to SCC The results of the material testing i.e. chemical composition and mechanical properties as shown in Tables 2 and 3 indicate that pipeline material was of reasonable quality and almost similar to the specification of X52. However, it has been reported that X52 exhibited SCC several times in the presence of high-pH in various parts of the world [17]. Microscopic examination of the pipeline in the vicinity of the fractured area has clearly indicated the presence of corrosion pits (see Fig. 9). It can be seen in Fig. 10 that crack initiation point exhibits intergranular cracks with extensive branching. The corrosion product (i.e. dark etching areas) can also be seen within these cracks. These metallographic observations are similar to the reported incidents of SCC with high-pH [5,15,16]. 4.3. Stress The third prerequisite for the SCC, the hoop stress of 220 MPa (61.2% of SMYS) caused by pressurized gas was present in the pipeline. However, 91 cm extra lowering/submerging of the pipe line was also observed 21.3 m downstream (hole-B) to the rupture point. This lowering was extended till the bottom of the canal which was approximately 13.7 m further from hole-B. This simple lowering/submerging of the pipeline to get passage under the canal may have induced additional stresses in the pipeline at the fracture area and appeared to have contributed to the rupture. As a results of the above investigation and explanation, it can be concluded that the presence of the high-pH (9–10) moisture/electrolytes at the pipeline-coating interface and the stresses other than hoop stress, generated due to the lowering/ submerging of the pipeline (X52), are the possible causes of this stress corrosion cracking. 5. Conclusions Detailed investigation suggested that the probable cause of the rupture of X52 grade gas pipeline was SCC. The rupture had initiated/developed due to the decay/disbondment of the protective fiber reinforced coal–tar coating. The presence of moisture/electrolyte of high-pH (9–10) was observed at the interface of pipeline and coating. The additional stresses at the rupture area of the pipe line due to lowering/submerging of the pipeline likely to have contributed to this rupture. The Metallography revealed intergranular nature of fracture with branching and corrosion products inside cracks.
Acknowledgments Authors are deeply thankful to the SNGPL company Pakistan for providing the opportunity of conducting this failure analysis. We are also grateful to University of Engineering and Technology-Lahore and Pakistan council of Science and Industrial Research (PCSIR)-Lahore for utilizing their facilities and carry out the experimental work for this study. References [1] Wenk RL. Field investigation of stress–corrosion cracking. In: Proceedings of 5th symposium on line pipe research. Pipeline Research Committee, American Gas Association Catalog; 1997. p. 1–22 [no. 130174]. [2] Leis BN, Eiber RJ. Stress–corrosion cracking on gas transmission pipelines. In: Proceedings of first international business conference on onshore pipe lines history, causes, and mitigation, Berlin; 1997. Invited paper. [3] Villalba E, Atrens A. An evaluation of steels subjected to rock bolt SCC condition. Eng Failure Anal 2007;14:1351. [4] Manfredi C, Otegui JI. Failure by SCC in buried pipelines. Eng Failure Anal 2002;9:495. [5] Parkins RN, Fessler RR. Line pipe stress corrosion cracking-mechanisms and remedies. Corrosion 1986;86(March):8 [Paper number 320, NACE]. [6] Parkins RN, Blanchard Jr WK, Delanty BS. Transgranular stress corrosion cracking of high-pressure pipelines in contact with solutions of near neutral pH. Corrosion 1994;50:394. [7] Charles EA, Parkins RN. Generation of stress corrosion cracking environments at pipeline surfaces. Corrosion 1995;51:518. [8] Dey S, Mandhyan AK, Sondhi SK, Chattoraj I. Hydrogen entry into pipeline steel under freely corroding conditions in two corroding media. Corros Sci 2006;48:2676. [9] Shipilov SA, May IL. Structural integrity of aging buried pipelines having cathodic protection. Eng Failure Anal 2006;13:1159. [10] Liang P, Du CW, Li XG, Chen X, Liang Zl. Effect of hydrogen on the stress corrosion cracking behavior of X80 pipeline steel in Ku’erle soil simulated solution. Int J Miner Metall Mater 2009;16:407. [11] Kamimura K, Kishikawa H. Mechanism of cathodic disbanding of three-layer polyethylene-coated steel pipe. Corrosion 1998;54:979. [12] Yan MC, Weng YJ. Study on hydrogen absorption of pipeline steel under cathodic charging. Corros Sci 2006;48:432. [13] Private communication with SNGPL (Sui Northern Gas Pipelines Limited), Pakistan. [14] API (American Petroleum Institute) 5L specification for line pipe. 44th ed. Washington (DC): API Publishing Services; 2007. [15] Capelle J, Gilgert J, Dmytrakh I, Pluvinage G. Sensitivity of pipeline with steel API X52 to hydrogen embrittlement. Int J Hydrogen Energy 2008;33:7630. [16] Hasan F, Iqbal J, Ahmed F. Stress corrosion failure of a high-pressure gas pipeline. Eng Failure Anal 2007;14:801. [17] Stress Corrosion Cracking Studies. A report by DCVG (DC Voltage Gradient) Technology & Supply Limited, United Kingdom; 2006.