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Corrosive wear failure analysis in a natural gas pipeline
Wear 263 (2007) 567–571
Case study
Corrosive wear failure analysis in a natural gas pipeline M.A.L. Hern´andez-Rodr´ıguez ∗ , D. Mart´ınez-Delgado, R. Gonz´alez, A. P´erez Unzueta, R.D. Mercado-Sol´ıs, J. Rodr´ıguez Facultad de Ingenier´ya Mecanica y Electrica, Universidad Autonoma de Nuevo Leon, Av. Universidad S/N, San Nicolas de los Garza, Nuevo Leon 66450, Mexico Received 2 September 2006; received in revised form 9 January 2007; accepted 11 January 2007 Available online 23 May 2007
Abstract Corrosive wear failure in gas pipelines can potentially cause substantial human and economic losses. This work presents the failure analysis of an API 5L X52 steel grade section of a pipeline used in an underground transportation, which is located next to a natural gas extraction plant. A T-shape section of this line, failed by perforation under unknown circumstances. Chemical and mechanical characterization of the steel pipe section was performed. Optical microscopy, electron microscopy and energy disperse spectroscopy were performed near the failure origin site in order to identify the composition of the corrosion products. Based on the microscopic and visual analyses, a corrosive wear sequence was identified as follows: the scales adhered to the inner wall of the pipe were easily loosened and detached in certain sites due to the turbulent gas stream. This resulted in the exposure of the fresh steel surface to the highly corrosive environment that prevails inside the pipeline. The unprotected areas acted as preferential sites for pitting corrosion of the steel until the final failure of the pipe was produced. © 2007 Published by Elsevier B.V. Keywords: Corrosive wear; Gas pipelines; Failure analysis; Erosion–corrosion
1. Introduction The ever increasing demand for energy has prompted companies to look for non-renewable resources in remote places. This necessity has stimulated the development of an adequate infrastructure to carry natural gas from extraction fields to storage sites and from these to treatment plants and distribution facilities and, ultimately, to urban and industrial consumption areas. This distribution is achieved using a complex pipeline network which requires the highest level of reliability in order to ensure a safe delivery of the product to the end users. Natural gas pipeline sections located near to the extraction wells are more susceptible to fail. This fact is due to the high concentration of corrosive agents carried in the gas stream, such as CO2 , H2 S, calcium and chlorine compounds which promote the deterioration of the steel pipe, mainly due to erosion–corrosion ∗ Corresponding autor at: Facultad de Ingenier´ ya Mecanica y Electrica, Universidad Autonoma de Nuevo Leon, Av. Universidad S/N, San Nicolas de los Garza, Nuevo Leon 66450, Mexico. Tel.: +52 81 14920375; fax: +52 81 10523321. E-mail address: [email protected] (M.A.L. Hern´andezRodr´ıguez).
0043-1648/$ – see front matter © 2007 Published by Elsevier B.V. doi:10.1016/j.wear.2007.01.123
[1–3]. In addition to the contaminants, the presence of salt water usually encountered inside the pipeline aggravates the corrosion process. Process variables, such as flow rate, pressure and pipeline design interact to create a synergistic effect of corrosion and erosive wear of the pipe. Corrosion products are first deposited on the internal gas pipeline surface in the form of scales. These products, which are mainly CaCO3 and FeCO3 , initially, act as a protective barrier to prevent the corrosion of the steel surface [4,5]. Once the scales have grown to a certain thickness, they become highly brittle and are easily removed by the mechanical forces of the gas stream in localized zones. Thus, the newly exposed areas become highly susceptible to a galvanic corrosion process aggravated by the attraction of chlorine ions into these areas [6]. This develops localized pits due to pitting corrosion until the final failure of the pipe is produced. In this work, a failure analysis of an API 5L X52 steel grade pipeline T-shape section is presented. This pipeline section, which failed under unknown circumstances, was part of a transportation pipeline network located near to a natural gas extraction plant in northern Mexico. Optical microscopy, electron microscopy and energy disperse spectroscopy were performed to characterize the failure and to identify the composition of the corrosion products. Based on the microscopic analyses
568
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
and observations, a corrosive wear sequence is proposed in this paper. 2. Analytical techniques The pipe section corresponding to the failure was characterized by chemical composition to ensure that the pipeline corresponded to the above-mentioned API grade. The microstructure was revealed by immersion etching in Nital 2%. The affected zone was dry cut and visual analysis was performed to describe the different areas of the failure. The residues adhered to the internal pipeline surface were carefully removed with a scalpel in order to analyze them by energy dispersive spectroscopy (EDS) and X-ray diffraction (XRD). 2.1. Visual inspection Fig. 1a shows a schematic representation and an actual picture of the segment of the gas pipeline analyzed in this work. This segment includes a T-shape section to help decrease the turbulence of the gas stream caused by the 90◦ flow diversion. A steel cap is welded to one end of the T-shape vertical section of the pipe (Fig. 1a). The failure was observed in the steel cap
as a perforation through the wall thickness of the pipe (Fig. 1b) which was the cause of the gas leak. In addition, the visual inspection of the steel cap revealed the presence of several pits of various levels of advancement in the inner wall surface. The areas where pits were found did not exhibit the scales that were observed in other parts of the T-shape section. This may be due to the detachment of scales by mechanical forces generated by a high turbulent stream. Fig. 2a shows a picture of the inner side of the vertical part of the T-shape section. In these walls, adhered scales were observed with globular morphology along with minimal attacks by pitting corrosion. The inner side of horizontal part of the T-shape section is shown in Fig. 2b. In the interior part of the horizontal pipe at the position typically called 6:00 h, traces of condensates originated by the precipitation of humidity and contaminants of the gas stream were observed. In addition, a severe damage due to several pits located in the same part was noticed. 2.2. Gas pipeline material analysis Table 1 shows the chemical composition results of the pipeline section, identified as M1. Carbon and sulphur analysis were performed by combustion and infrared detection
Fig. 1. (a) Pipe line section with a T-shape geometry, (b) metallic cap 76.2 mm diameter and (c) pitted zone.
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
569
Fig. 3. Microstructure performed near to the failure zone, showing pearlite bands phase in the ferrite matrix, 100×.
Fig. 2. (a) Photograph of the internal wall of vertical part of the T-shape section showing the presence of scales adhered. (b) Photograph of the internal section of the horizontal part of the T-shape section showing the extent of damage (pits) due to erosion–corrosion.
respectively according to ASTM E1019. In addition, X-ray fluorescence (XRF) was performed to evaluate the remaining elements according to ASTM E1085. Hardness measurements were taken on the surface of the pipe resulting on an average of 84 HRB.
Fig. 4. Metallographic micrograph before etching of a cross-section near to the perforation of the cap, 100×.
2.4. Electron microscopy and XRD 2.3. Optical microscopy Fig. 3 shows a metallographic micrograph of the metal base near to the metallic cap that illustrates a typical ferritic and pearlitic microstructure of an API 5L X52 steel grade. Fig. 4 shows an as-polished metallographic micrograph of a crosssection near to the perforation of the cap. In Fig. 4, the interface between the metal matrix and corrosion products where a pit around 0.3 mm of diameter is observed. The corrosion products were analyzed by scanning electron microscope (SEM) and X-ray diffractometer (XRD).
Corrosion products were collected from the internal gas pipeline walls and from pitting zones in close proximity to the failure area to be analyzed by SEM and XRD. The products were sorted according to their location: inner pipe walls and metallic cap residues. Fig. 5a shows the typical corrosion products found adhered to the inner pipe walls, while the energy dispersive spectrometer analysis (EDS) shows the elements content. When the pitting areas were analyzed by SEM–EDS chlorine was detected, as is shown in Fig. 5b. Those products adhered to the gas pipe walls were mainly FeCO3 , according XRD analysis as shown in Fig. 6.
Table 1 Chemical composition (wt.%) gas pipeline steel Sample
C
S
Mn
P
Si
Cr
Ni
Mo
Cu
V
Nb
Ti
W
Fe
M1
0.18
<0.01
0.94
0.009
0.23
0.07
0.12
0.03
0.206
0.003
<0.001
0.019
<0.006
Balance
570
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
Fig. 5. Analysis of the residues encountered in the internal wall of the pipe: (a) CaCO3 residues; (b) chlorine residues inside a pit.
3. Failure discussion
Fig. 6. X-ray analysis of the sample showing the presence of FeCO3 and chlorine residues.
Carbonic acid (H2 CO3 ) is usually found in the gas stream as a result of the combination of CO2 and natural gas. In addition, the presence of the calcium and iron ions promote the formation of CaCO3 and FeCO3 (siderite) [7]. The chemical composition of the condensed water found inside of the pipe line (pH 7.5, TDS 4520 mg/l, Ca 866 mg/l, alkalinity 296 mg/l as CaCO3 ), shows a Langalier saturation index [8] of 1 which, along with the presence of Ca observed in the EDX analysis (Fig. 5a), confirms the trend to form the precipitates of CaCO3 shown as scales in the visual inspection (Fig. 2a). On the other hand, the scales that exhibited sulphur content (Fig. 5a) can be related with the presence of H2 S, which promotes the formation of iron sulphide (Fex Sx ). In the visual inspection, the fragility of these scales was evidenced. Scales adherence depends on the temperature, CO2 and H2 S gas concentration, pH, flow rate and pipeline design [9,10]. These scales layers have an uneven and random growth until
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
the gas turbulence detach them by erosion–corrosion mechanism [1] resulting a susceptible area with a large cathode and anode relationship which in turn, originate the most favorable stage for pitting corrosion attack. This erosion–corrosion cycle was repeated in all T-shape section being the metallic cap where the high turbulence accelerated the localized corrosion [7]. This phenomenon formed several pits until one of them perforated the pipeline causing the failure. In the horizontal part of the T-shape section traces of scales in the inferior part (6:00 h position) inside of the pipe were evidenced. These traces are due to the detachment of scales resulting on a severe localized attack by pitting corrosion (Fig. 2b), specifically located on the traces of the condensed water and contaminants contended in the natural gas stream. 4. Conclusions A corrosive wear mechanism was found to be the main cause of failure of the T-shape section of gas extraction pipeline system under analysis. A corrosive wear sequence was identified as follows: a constant formation of scales (CaCO3 , FeCO3 and Hx Sx ) on the interior walls were originated by the reaction of contaminants, such as CO2 , H2 S and calcium compounds contended in the humidity of the gas stream. These adhered fragile scales were easily loosened and detached in certain sites due to the turbulent gas stream resulting in the exposure of the fresh steel surface to the highly corrosive environment that prevails inside the pipeline. The unprotected areas along with a high turbulent system promoted by diversion flow in the metallic cap, established the preferential conditions for localized corro-
571
sion until one of the pits perforated the pipe producing the final failure. Acknowledgement The authors acknowledge the tests performed by Universidad de Guadalajara, during this work. References [1] J.R. Shadley, S.A. Shirazi, E. Dayalan, M. Ismail, E.F. Rybicki, Erosion–corrosion of a carbon steel elbow in a carbon dioxide environment, Corrosion 52 (9) (1996). [2] J. Postlethwaite, S. Nesic, Erosion–corrosion in single and multiphase flow, in: R.W. Revie (Ed.), Uhlig’s Corrosion Handbook, second ed., John Wiley & Sons, 2000, pp. 249–272. [3] E.S. Venkatesh, Erosion damage in oil and gas wells, in: Proceeding of Rocky Mountain Meeting of SPE, Billings, MT, May, 1986. [4] L.E. Newton, R.H. Hausler (Eds.), CO2 Corrosion in oil and Gas Production, NACE, 1984 (selected papers, abstracts and references). [5] C.A. Palacios, J.R. Shadley, CO2 Corrosion of N-80 steel at 71 ◦ C in a two-phase flow system, Corrosion 49 (8) (1993). [6] M.G. Fontana, N.D. Greene, Eight forms of corrosion, in: Corrosion Engineering, second ed., Mc Graw Hill, 1978, pp. 51–54. [7] N. Sridhar, D.S. Dunn, A.M. Anderko, M.M. Lencka, H.U. Schutt, Effects of water and gas compositions on internal corrosion of gas pipelinesmodeling and experimental studies, Corrosion 57 (3) (2001). [8] R. Baboian (Ed.), NACE Corrosion Engineer’s Reference Book, third ed., NACE Press, 2002. [9] J.S. Smith, J.D.A. Miller, Nature of sulfides and their corrosive effect on ferrous metals: a review, Br. Corros. J. 10 (3) (1975) 136–143. [10] F.F. Lyle, H.U. Schutt, CO2 /H2 S corrosion under wet gas pipeline conditions in the presence of bicarbonate, chloride, and oxygen, CORROSION/98, Paper No. 11, Houston, TX, NACE, 1998.
Case study
Corrosive wear failure analysis in a natural gas pipeline M.A.L. Hern´andez-Rodr´ıguez ∗ , D. Mart´ınez-Delgado, R. Gonz´alez, A. P´erez Unzueta, R.D. Mercado-Sol´ıs, J. Rodr´ıguez Facultad de Ingenier´ya Mecanica y Electrica, Universidad Autonoma de Nuevo Leon, Av. Universidad S/N, San Nicolas de los Garza, Nuevo Leon 66450, Mexico Received 2 September 2006; received in revised form 9 January 2007; accepted 11 January 2007 Available online 23 May 2007
Abstract Corrosive wear failure in gas pipelines can potentially cause substantial human and economic losses. This work presents the failure analysis of an API 5L X52 steel grade section of a pipeline used in an underground transportation, which is located next to a natural gas extraction plant. A T-shape section of this line, failed by perforation under unknown circumstances. Chemical and mechanical characterization of the steel pipe section was performed. Optical microscopy, electron microscopy and energy disperse spectroscopy were performed near the failure origin site in order to identify the composition of the corrosion products. Based on the microscopic and visual analyses, a corrosive wear sequence was identified as follows: the scales adhered to the inner wall of the pipe were easily loosened and detached in certain sites due to the turbulent gas stream. This resulted in the exposure of the fresh steel surface to the highly corrosive environment that prevails inside the pipeline. The unprotected areas acted as preferential sites for pitting corrosion of the steel until the final failure of the pipe was produced. © 2007 Published by Elsevier B.V. Keywords: Corrosive wear; Gas pipelines; Failure analysis; Erosion–corrosion
1. Introduction The ever increasing demand for energy has prompted companies to look for non-renewable resources in remote places. This necessity has stimulated the development of an adequate infrastructure to carry natural gas from extraction fields to storage sites and from these to treatment plants and distribution facilities and, ultimately, to urban and industrial consumption areas. This distribution is achieved using a complex pipeline network which requires the highest level of reliability in order to ensure a safe delivery of the product to the end users. Natural gas pipeline sections located near to the extraction wells are more susceptible to fail. This fact is due to the high concentration of corrosive agents carried in the gas stream, such as CO2 , H2 S, calcium and chlorine compounds which promote the deterioration of the steel pipe, mainly due to erosion–corrosion ∗ Corresponding autor at: Facultad de Ingenier´ ya Mecanica y Electrica, Universidad Autonoma de Nuevo Leon, Av. Universidad S/N, San Nicolas de los Garza, Nuevo Leon 66450, Mexico. Tel.: +52 81 14920375; fax: +52 81 10523321. E-mail address: [email protected] (M.A.L. Hern´andezRodr´ıguez).
0043-1648/$ – see front matter © 2007 Published by Elsevier B.V. doi:10.1016/j.wear.2007.01.123
[1–3]. In addition to the contaminants, the presence of salt water usually encountered inside the pipeline aggravates the corrosion process. Process variables, such as flow rate, pressure and pipeline design interact to create a synergistic effect of corrosion and erosive wear of the pipe. Corrosion products are first deposited on the internal gas pipeline surface in the form of scales. These products, which are mainly CaCO3 and FeCO3 , initially, act as a protective barrier to prevent the corrosion of the steel surface [4,5]. Once the scales have grown to a certain thickness, they become highly brittle and are easily removed by the mechanical forces of the gas stream in localized zones. Thus, the newly exposed areas become highly susceptible to a galvanic corrosion process aggravated by the attraction of chlorine ions into these areas [6]. This develops localized pits due to pitting corrosion until the final failure of the pipe is produced. In this work, a failure analysis of an API 5L X52 steel grade pipeline T-shape section is presented. This pipeline section, which failed under unknown circumstances, was part of a transportation pipeline network located near to a natural gas extraction plant in northern Mexico. Optical microscopy, electron microscopy and energy disperse spectroscopy were performed to characterize the failure and to identify the composition of the corrosion products. Based on the microscopic analyses
568
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
and observations, a corrosive wear sequence is proposed in this paper. 2. Analytical techniques The pipe section corresponding to the failure was characterized by chemical composition to ensure that the pipeline corresponded to the above-mentioned API grade. The microstructure was revealed by immersion etching in Nital 2%. The affected zone was dry cut and visual analysis was performed to describe the different areas of the failure. The residues adhered to the internal pipeline surface were carefully removed with a scalpel in order to analyze them by energy dispersive spectroscopy (EDS) and X-ray diffraction (XRD). 2.1. Visual inspection Fig. 1a shows a schematic representation and an actual picture of the segment of the gas pipeline analyzed in this work. This segment includes a T-shape section to help decrease the turbulence of the gas stream caused by the 90◦ flow diversion. A steel cap is welded to one end of the T-shape vertical section of the pipe (Fig. 1a). The failure was observed in the steel cap
as a perforation through the wall thickness of the pipe (Fig. 1b) which was the cause of the gas leak. In addition, the visual inspection of the steel cap revealed the presence of several pits of various levels of advancement in the inner wall surface. The areas where pits were found did not exhibit the scales that were observed in other parts of the T-shape section. This may be due to the detachment of scales by mechanical forces generated by a high turbulent stream. Fig. 2a shows a picture of the inner side of the vertical part of the T-shape section. In these walls, adhered scales were observed with globular morphology along with minimal attacks by pitting corrosion. The inner side of horizontal part of the T-shape section is shown in Fig. 2b. In the interior part of the horizontal pipe at the position typically called 6:00 h, traces of condensates originated by the precipitation of humidity and contaminants of the gas stream were observed. In addition, a severe damage due to several pits located in the same part was noticed. 2.2. Gas pipeline material analysis Table 1 shows the chemical composition results of the pipeline section, identified as M1. Carbon and sulphur analysis were performed by combustion and infrared detection
Fig. 1. (a) Pipe line section with a T-shape geometry, (b) metallic cap 76.2 mm diameter and (c) pitted zone.
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
569
Fig. 3. Microstructure performed near to the failure zone, showing pearlite bands phase in the ferrite matrix, 100×.
Fig. 2. (a) Photograph of the internal wall of vertical part of the T-shape section showing the presence of scales adhered. (b) Photograph of the internal section of the horizontal part of the T-shape section showing the extent of damage (pits) due to erosion–corrosion.
respectively according to ASTM E1019. In addition, X-ray fluorescence (XRF) was performed to evaluate the remaining elements according to ASTM E1085. Hardness measurements were taken on the surface of the pipe resulting on an average of 84 HRB.
Fig. 4. Metallographic micrograph before etching of a cross-section near to the perforation of the cap, 100×.
2.4. Electron microscopy and XRD 2.3. Optical microscopy Fig. 3 shows a metallographic micrograph of the metal base near to the metallic cap that illustrates a typical ferritic and pearlitic microstructure of an API 5L X52 steel grade. Fig. 4 shows an as-polished metallographic micrograph of a crosssection near to the perforation of the cap. In Fig. 4, the interface between the metal matrix and corrosion products where a pit around 0.3 mm of diameter is observed. The corrosion products were analyzed by scanning electron microscope (SEM) and X-ray diffractometer (XRD).
Corrosion products were collected from the internal gas pipeline walls and from pitting zones in close proximity to the failure area to be analyzed by SEM and XRD. The products were sorted according to their location: inner pipe walls and metallic cap residues. Fig. 5a shows the typical corrosion products found adhered to the inner pipe walls, while the energy dispersive spectrometer analysis (EDS) shows the elements content. When the pitting areas were analyzed by SEM–EDS chlorine was detected, as is shown in Fig. 5b. Those products adhered to the gas pipe walls were mainly FeCO3 , according XRD analysis as shown in Fig. 6.
Table 1 Chemical composition (wt.%) gas pipeline steel Sample
C
S
Mn
P
Si
Cr
Ni
Mo
Cu
V
Nb
Ti
W
Fe
M1
0.18
<0.01
0.94
0.009
0.23
0.07
0.12
0.03
0.206
0.003
<0.001
0.019
<0.006
Balance
570
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
Fig. 5. Analysis of the residues encountered in the internal wall of the pipe: (a) CaCO3 residues; (b) chlorine residues inside a pit.
3. Failure discussion
Fig. 6. X-ray analysis of the sample showing the presence of FeCO3 and chlorine residues.
Carbonic acid (H2 CO3 ) is usually found in the gas stream as a result of the combination of CO2 and natural gas. In addition, the presence of the calcium and iron ions promote the formation of CaCO3 and FeCO3 (siderite) [7]. The chemical composition of the condensed water found inside of the pipe line (pH 7.5, TDS 4520 mg/l, Ca 866 mg/l, alkalinity 296 mg/l as CaCO3 ), shows a Langalier saturation index [8] of 1 which, along with the presence of Ca observed in the EDX analysis (Fig. 5a), confirms the trend to form the precipitates of CaCO3 shown as scales in the visual inspection (Fig. 2a). On the other hand, the scales that exhibited sulphur content (Fig. 5a) can be related with the presence of H2 S, which promotes the formation of iron sulphide (Fex Sx ). In the visual inspection, the fragility of these scales was evidenced. Scales adherence depends on the temperature, CO2 and H2 S gas concentration, pH, flow rate and pipeline design [9,10]. These scales layers have an uneven and random growth until
M.A.L. Hern´andez-Rodr´ıguez et al. / Wear 263 (2007) 567–571
the gas turbulence detach them by erosion–corrosion mechanism [1] resulting a susceptible area with a large cathode and anode relationship which in turn, originate the most favorable stage for pitting corrosion attack. This erosion–corrosion cycle was repeated in all T-shape section being the metallic cap where the high turbulence accelerated the localized corrosion [7]. This phenomenon formed several pits until one of them perforated the pipeline causing the failure. In the horizontal part of the T-shape section traces of scales in the inferior part (6:00 h position) inside of the pipe were evidenced. These traces are due to the detachment of scales resulting on a severe localized attack by pitting corrosion (Fig. 2b), specifically located on the traces of the condensed water and contaminants contended in the natural gas stream. 4. Conclusions A corrosive wear mechanism was found to be the main cause of failure of the T-shape section of gas extraction pipeline system under analysis. A corrosive wear sequence was identified as follows: a constant formation of scales (CaCO3 , FeCO3 and Hx Sx ) on the interior walls were originated by the reaction of contaminants, such as CO2 , H2 S and calcium compounds contended in the humidity of the gas stream. These adhered fragile scales were easily loosened and detached in certain sites due to the turbulent gas stream resulting in the exposure of the fresh steel surface to the highly corrosive environment that prevails inside the pipeline. The unprotected areas along with a high turbulent system promoted by diversion flow in the metallic cap, established the preferential conditions for localized corro-
571
sion until one of the pits perforated the pipe producing the final failure. Acknowledgement The authors acknowledge the tests performed by Universidad de Guadalajara, during this work. References [1] J.R. Shadley, S.A. Shirazi, E. Dayalan, M. Ismail, E.F. Rybicki, Erosion–corrosion of a carbon steel elbow in a carbon dioxide environment, Corrosion 52 (9) (1996). [2] J. Postlethwaite, S. Nesic, Erosion–corrosion in single and multiphase flow, in: R.W. Revie (Ed.), Uhlig’s Corrosion Handbook, second ed., John Wiley & Sons, 2000, pp. 249–272. [3] E.S. Venkatesh, Erosion damage in oil and gas wells, in: Proceeding of Rocky Mountain Meeting of SPE, Billings, MT, May, 1986. [4] L.E. Newton, R.H. Hausler (Eds.), CO2 Corrosion in oil and Gas Production, NACE, 1984 (selected papers, abstracts and references). [5] C.A. Palacios, J.R. Shadley, CO2 Corrosion of N-80 steel at 71 ◦ C in a two-phase flow system, Corrosion 49 (8) (1993). [6] M.G. Fontana, N.D. Greene, Eight forms of corrosion, in: Corrosion Engineering, second ed., Mc Graw Hill, 1978, pp. 51–54. [7] N. Sridhar, D.S. Dunn, A.M. Anderko, M.M. Lencka, H.U. Schutt, Effects of water and gas compositions on internal corrosion of gas pipelinesmodeling and experimental studies, Corrosion 57 (3) (2001). [8] R. Baboian (Ed.), NACE Corrosion Engineer’s Reference Book, third ed., NACE Press, 2002. [9] J.S. Smith, J.D.A. Miller, Nature of sulfides and their corrosive effect on ferrous metals: a review, Br. Corros. J. 10 (3) (1975) 136–143. [10] F.F. Lyle, H.U. Schutt, CO2 /H2 S corrosion under wet gas pipeline conditions in the presence of bicarbonate, chloride, and oxygen, CORROSION/98, Paper No. 11, Houston, TX, NACE, 1998.