corrosive wear failure analysis in a natural gas pipeline

corrosive wear failure analysis in a natural gas pipeline 文库 Corrosive wear failure analysis in a natural gas pipeline Wear 263 (2007) 567–571Case studyCorrosive wear failure analysis in a natural gas pipelineM.A.L. Hern′ andez-Rodr′ ?guez?, D. Mart′ ?nez-Delgado, R. Gonz′ alez,A. P′ erez Unzueta, R.D. Mercado-Sol′ ?s, J. Rodr′ ?guezFacultad de Ingenier′ ya Mecanica y Electrica, Universidad Autonoma de Nuevo Leon, Av. Universidad S/N,San Nicolas de los Garza, Nuevo Leon 66450, MexicoReceived 2 September 2006; received in revised form 9 January 2007; accepted 11 January 2007Available online 23 May 2007AbstractCorrosive 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-shapesectionofthisline,failedbyperforationunderunknowncircumstances.Chemicalandmechanicalcharacterizationofthesteelpipesectionwas 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–corrosion1. IntroductionThe 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 Ingenier′ ya 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. Hern′ andez-Rodr′ ?guez).[1–3].Inadditiontothecontaminants,thepresenceofsaltwaterusually 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 CaCO3and 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 文库 文库 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,electronmicroscopyandenergydispersespectroscopywereper-formedtocharacterizethefailureandtoidentifythecompositionof the corrosion products. Based on the microscopic analyses0043-1648/$ – see front matter ? 2007 Published by Elsevier B.V.doi:10.1016/j.wear.2007.01.123 568M.A.L. Hern′ andez-Rodr′ ?guez et al. / Wear 263 (2007) 567–571and observations, a corrosive wear sequence is proposed inthis paper.2. Analytical techniquesThe 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-formedtodescribethedifferentareasofthefailure.Theresiduesadhered to the internal removedwith a scalpel in order to analyze them by energy pipeline surface were carefully dispersivespectroscopy (EDS) and X-ray diffraction (XRD).2.1. Visual inspectionFig. 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 capas 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 oftheT-shapesection.Inthesewalls,adheredscaleswereobservedwithglobularmorphologyalongwithminimalattacksbypittingcorrosion. The inner side of horizontal part of the T-shape sec-tionisshowninFig.2b.Intheinteriorpartofthehorizontalpipeatthepositiontypicallycalled6:00h,tracesofcondensatesorig-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 analysisTable 1 shows the chemical composition results of thepipeline section, identified as M1. Carbon and sulphur anal-ysis were performed by combustion and infrared detectionFig. 1. (a) Pipe line section with a T-shape geometry, (b) metallic cap 76.2mm diameter and (c) pitted zone. M.A.L. Hern′ andez-Rodr′ ?guez et al. / Wear 263 (2007) 567–571569Fig. 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 microscopyFig. 3 shows a metallographic micrograph of 文库 文库 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 0.3mm of diameter is observed. The corrosion prod-uctswereanalyzedbyscanningelectronmicroscope(SEM)andX-ray diffractometer (XRD).Fig.3. Microstructureperformedneartothefailurezone,showingpearlitebandsphase 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 XRDCorrosion products were collected from the internal gaspipeline walls and from pitting zones in close proximity to thefailureareatobeanalyzedbySEMandXRD.Theproductsweresorted 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 (EDS) shows the elements content.When the pitting areas were analyzed by SEM–analysisEDS chlorinewas detected, as is shown in Fig. 5b. Those products adhered tothegaspipewallsweremainlyFeCO3,accordingXRDanalysisas shown in Fig. 6.Table 1Chemical composition (wt.%) gas pipeline steelSampleCSMnPSiCrNiMoCuVNbTiWFeM10.18<0.010.940.0090.230.070.120.030.2060.003<0.0010.019<0.006Balance 570M.A.L. Hern′ andez-Rodr′ ?guez et al. / Wear 263 (2007) 567–571Fig. 5. Analysis of the residues encountered in the internal wall of the pipe: (a) CaCO3residues; (b) chlorine residues inside a pit.Fig.6. X-rayanalysisofthesampleshowingthepresenceofFeCO3andchlorineresidues.3. Failure discussionCarbonic acid (H2CO3) is usually found in the gas stream asa result of the combination of CO2and natural gas. In addition,the presence of the calcium and iron ions promote the formationof CaCO3and FeCO3(siderite) [7]. The chemical compositionof the condensed water found inside of the pipe line (pH 7.5,TDS 4520mg/l, Ca 866mg/l, alkalinity 296mg/l as CaCO3),showsaLangaliersaturationindex[8]of1which,alongwiththepresenceofCaobservedintheEDXanalysis(Fig.5a),confirmsthe trend to form the precipitates of CaCO3shown as scales inthe visual inspection (Fig. 2a). On the other hand, the scalesthat exhibited sulphur content (Fig. 5a) can be related with thepresenceofH2S,whichpromotestheformationofironsulphide(FexSx).In the visual inspection, the fragility of these scales was evi-denced. Scales adherence depends on the temperature, CO2andH2S 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′ ?guez et al. / Wear 263 (2007) 567–571571the 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 (6:00h position) inside of the pipe were 文库 文库 evi-denced.Thesetracesareduetothedetachmentofscalesresultingon 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. ConclusionsA 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, FeCO3andHxSx) 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.AcknowledgementTheauthorsacknowledgethetestsperformedbyUniversidadde Guadalajara, during this work.References[1] J.R. Shadley, S.A. Shirazi, E. Dayalan, M. Ismail, E.F. Rybicki,Erosion–corrosionofacarbonsteelelbowinacarbondioxideenvironment,Corrosion 52 (9) (1996).[2] J.Postlethwaite,S.Nesic,Erosion–corrosioninsingleandmultiphaseflow,in:R.W.Revie(Ed.),U hlig’sCorrosionHandbook,seconded.,JohnWiley& Sons, 2000, pp. 249–272.[3] E.S. Venkatesh, Erosion damage in oil and gas wells, in: Proceeding ofRocky Mountain Meeting of SPE, Billings, MT, May, 1986.[4] L.E. Newton, R.H. Hausler (Eds.), CO2Corrosion in oil and Gas Produc-tion, NACE, 1984 (selected papers, abstracts and references).[5] C.A. Palacios, J.R. Shadley, CO2Corrosion of N-80 steel at 71?C in atwo-phase flow system, Corrosion 49 (8) (1993).[6] M.G. Fontana, N.D. Greene, Eight forms of corrosion, in: Corrosion Engi-neering, second ed., Mc Graw Hill, 1978, pp. 51–54.[7] N. Sridhar, D.S. Dunn, A.M. Anderko, M.M. Lencka, H.U. Schutt, Effectsof water and gas compositions on internal corrosion of gas pipelines-modeling 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 onferrous metals: a review, Br. Corros. J. 10 (3) (1975) 136–143.[10] F.F. Lyle, H.U. Schutt, CO2/H2S corrosion under wet gas pipelineconditions in the presence of bicarbonate, chloride, and oxygen, COR-ROSION/98, Paper No. 11, Houston, TX, NACE, 1998. 文库