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Wear 263 (2007) 567–571

Case study

Corrosive wear failure analysis in a natural gas pipeline

M.A.L. Hernandez-Rodrıguez ∗, D. Martınez-Delgado, R. Gonzalez,A. Perez Unzueta, R.D. Mercado-Solıs, J. Rodrıguez

Facultad de Ingenierya 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 2007Available 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 ofan API 5L X52 steel grade section of a pipeline used in an underground transportation, which is located next to a natural gas extraction plant. AT-shape section of this line, failed by perforation under unknown circumstances. Chemical and mechanical characterization of the steel pipe sectionwas performed. Optical microscopy, electron microscopy and energy disperse spectroscopy were performed near the failure origin site in orderto identify the composition of the corrosion products. Based on the microscopic and visual analyses, a corrosive wear sequence was identified asfollows: the scales adhered to the inner wall of the pipe were easily loosened and detached in certain sites due to the turbulent gas stream. Thisresulted in the exposure of the fresh steel surface to the highly corrosive environment that prevails inside the pipeline. The unprotected areas actedas 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 com-panies to look for non-renewable resources in remote places.This necessity has stimulated the development of an adequateinfrastructure to carry natural gas from extraction fields to stor-age sites and from these to treatment plants and distributionfacilities and, ultimately, to urban and industrial consumptionareas. This distribution is achieved using a complex pipelinenetwork which requires the highest level of reliability in orderto ensure a safe delivery of the product to the end users. Nat-ural gas pipeline sections located near to the extraction wellsare more susceptible to fail. This fact is due to the high con-centration of corrosive agents carried in the gas stream, such asCO2, H2S, calcium and chlorine compounds which promote thedeterioration of the steel pipe, mainly due to erosion–corrosion

∗ Corresponding autor at: Facultad de Ingenierya Mecanica y Electrica, Uni-versidad Autonoma de Nuevo Leon, Av. Universidad S/N, San Nicolas de losGarza, Nuevo Leon 66450, Mexico.Tel.: +52 81 14920375; fax: +52 81 10523321.

E-mail address: mhernandez@gama.fime.uanl.mx (M.A.L. Hernandez-Rodrıguez).

[1–3]. In addition to the contaminants, the presence of salt waterusually encountered inside the pipeline aggravates the corro-sion process. Process variables, such as flow rate, pressure andpipeline design interact to create a synergistic effect of corro-sion and erosive wear of the pipe. Corrosion products are firstdeposited on the internal gas pipeline surface in the form ofscales. These products, which are mainly CaCO3 and FeCO3,initially, act as a protective barrier to prevent the corrosion ofthe steel surface [4,5]. Once the scales have grown to a certainthickness, they become highly brittle and are easily removedby the mechanical forces of the gas stream in localized zones.Thus, the newly exposed areas become highly susceptible toa galvanic corrosion process aggravated by the attraction ofchlorine ions into these areas [6]. This develops localized pitsdue to pitting corrosion until the final failure of the pipe isproduced. In this work, a failure analysis of an API 5L X52steel grade pipeline T-shape section is presented. This pipelinesection, which failed under unknown circumstances, was partof a transportation pipeline network located near to a naturalgas extraction plant in northern Mexico. Optical microscopy,electron microscopy and energy disperse spectroscopy were per-formed to characterize the failure and to identify the compositionof the corrosion products. Based on the microscopic analyses

0043-1648/$ – see front matter © 2007 Published by Elsevier B.V.doi:10.1016/j.wear.2007.01.123

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and observations, a corrosive wear sequence is proposed inthis paper.

2. Analytical techniques

The pipe section corresponding to the failure was char-acterized by chemical composition to ensure that thepipeline corresponded to the above-mentioned API grade. Themicrostructure was revealed by immersion etching in Nital 2%.The affected zone was dry cut and visual analysis was per-formed to describe the different areas of the failure. The residuesadhered to the internal pipeline surface were carefully removedwith a scalpel in order to analyze them by energy dispersivespectroscopy (EDS) and X-ray diffraction (XRD).

2.1. Visual inspection

Fig. 1a shows a schematic representation and an actual pic-ture of the segment of the gas pipeline analyzed in this work.This segment includes a T-shape section to help decrease theturbulence of the gas stream caused by the 90◦ flow diversion.A steel cap is welded to one end of the T-shape vertical sectionof 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 visualinspection of the steel cap revealed the presence of several pitsof various levels of advancement in the inner wall surface. Theareas where pits were found did not exhibit the scales that wereobserved in other parts of the T-shape section. This may be dueto the detachment of scales by mechanical forces generated bya high turbulent stream.

Fig. 2a shows a picture of the inner side of the vertical part ofthe T-shape section. In these walls, adhered scales were observedwith globular morphology along with minimal attacks by pittingcorrosion. The inner side of horizontal part of the T-shape sec-tion is shown in Fig. 2b. In the interior part of the horizontal pipeat the position typically called 6:00 h, traces of condensates orig-inated by the precipitation of humidity and contaminants of thegas stream were observed. In addition, a severe damage due toseveral pits located in the same part was noticed.

2.2. Gas pipeline material analysis

Table 1 shows the chemical composition results of thepipeline section, identified as M1. Carbon and sulphur anal-ysis 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.

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Fig. 2. (a) Photograph of the internal wall of vertical part of the T-shape sectionshowing the presence of scales adhered. (b) Photograph of the internal sectionof 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-rayfluorescence (XRF) was performed to evaluate the remainingelements according to ASTM E1085. Hardness measurementswere taken on the surface of the pipe resulting on an average of84 HRB.

2.3. Optical microscopy

Fig. 3 shows a metallographic micrograph of the metal basenear to the metallic cap that illustrates a typical ferritic andpearlitic microstructure of an API 5L X52 steel grade. Fig. 4shows an as-polished metallographic micrograph of a cross-section near to the perforation of the cap. In Fig. 4, the interfacebetween the metal matrix and corrosion products where a pitaround 0.3 mm of diameter is observed. The corrosion prod-ucts were analyzed by scanning electron microscope (SEM) andX-ray diffractometer (XRD).

Fig. 3. Microstructure performed near to the failure zone, showing pearlite bandsphase in the ferrite matrix, 100×.

Fig. 4. Metallographic micrograph before etching of a cross-section near to theperforation of the cap, 100×.

2.4. Electron microscopy and XRD

Corrosion products were collected from the internal gaspipeline walls and from pitting zones in close proximity to thefailure area to be analyzed by SEM and XRD. The products weresorted according to their location: inner pipe walls and metal-lic cap residues. Fig. 5a shows the typical corrosion productsfound adhered to the inner pipe walls, while the energy disper-sive spectrometer analysis (EDS) shows the elements content.When the pitting areas were analyzed by SEM–EDS chlorinewas detected, as is shown in Fig. 5b. Those products adhered tothe gas pipe walls were mainly FeCO3, according XRD analysisas shown in Fig. 6.

Table 1Chemical 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

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Fig. 5. Analysis of the residues encountered in the internal wall of the pipe: (a) CaCO3 residues; (b) chlorine residues inside a pit.

Fig. 6. X-ray analysis of the sample showing the presence of FeCO3 and chlorineresidues.

3. Failure discussion

Carbonic acid (H2CO3) is usually found in the gas stream asa result of the combination of CO2 and natural gas. In addition,the presence of the calcium and iron ions promote the formationof CaCO3 and FeCO3 (siderite) [7]. The chemical compositionof 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 thepresence of Ca observed in the EDX analysis (Fig. 5a), confirmsthe trend to form the precipitates of CaCO3 shown as scales inthe visual inspection (Fig. 2a). On the other hand, the scalesthat exhibited sulphur content (Fig. 5a) can be related with thepresence of H2S, which promotes the formation of iron sulphide(FexSx).

In the visual inspection, the fragility of these scales was evi-denced. Scales adherence depends on the temperature, CO2 andH2S gas concentration, pH, flow rate and pipeline design [9,10].These scales layers have an uneven and random growth until

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the gas turbulence detach them by erosion–corrosion mecha-nism [1] resulting a susceptible area with a large cathode andanode relationship which in turn, originate the most favorablestage for pitting corrosion attack. This erosion–corrosion cyclewas repeated in all T-shape section being the metallic cap wherethe high turbulence accelerated the localized corrosion [7]. Thisphenomenon formed several pits until one of them perforatedthe pipeline causing the failure.

In the horizontal part of the T-shape section traces of scalesin the inferior part (6:00 h position) inside of the pipe were evi-denced. These traces are due to the detachment of scales resultingon a severe localized attack by pitting corrosion (Fig. 2b),specifically located on the traces of the condensed water andcontaminants contended in the natural gas stream.

4. Conclusions

A corrosive wear mechanism was found to be the main causeof failure of the T-shape section of gas extraction pipeline sys-tem under analysis. A corrosive wear sequence was identifiedas follows: a constant formation of scales (CaCO3, FeCO3 andHxSx) on the interior walls were originated by the reaction ofcontaminants, such as CO2, H2S and calcium compounds con-tended in the humidity of the gas stream. These adhered fragilescales were easily loosened and detached in certain sites due tothe turbulent gas stream resulting in the exposure of the freshsteel surface to the highly corrosive environment that prevailsinside the pipeline. The unprotected areas along with a highturbulent system promoted by diversion flow in the metalliccap, established the preferential conditions for localized corro-

sion until one of the pits perforated the pipe producing the finalfailure.

Acknowledgement

The authors acknowledge the tests performed by Universidadde Guadalajara, during this work.

References

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[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 onferrous metals: a review, Br. Corros. J. 10 (3) (1975) 136–143.

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