Failure of crude oil pipeline due to microbiologically induced corrosion

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Failure of crude oil pipeline due tomicrobiologically induced corrosion

S. S. Al-Jaroudi*1, A. Ul-Hamid2 and M. M. Al-Gahtani1

A 25?5 km long and 28 in. diameter underground pipeline used for transporting wet sour Arab Light

grade crude oil failed after 3 years of service. The pipeline was operated at 40% of permissible flow

velocity and capacity and protected under a corrosion inhibitor programme. The failure occurred

due to corrosion of the lower surface of the pipeline resulting in pinholes within a period of one month.

Eight corrosion damaged areas were detected over the entire length of the pipeline. Ultrasonic non-

destructive inspection and close potential surveys were conducted on the failed pipeline. Various

sections of the corrosion products were metallurgically evaluated using scanning electron

microscopy coupled with energy dispersive X-ray spectroscopy. The corrosion product was

identified using photometric and potentiometric analysis combined with X-ray diffraction. Crude oil

and water samples obtained from the pipeline were also analysed. The material of the pipeline was

identified as AISI grade C1018. Ultrasound testing revealed localised pitting at failed locations, while

close potential surveys ruled out external corrosion. Experimental results indicated that the failure

was caused by extensive microbiologically induced corrosion at the internal surface of the pipeline.

Sulphate reducing bacteria present in the crude oil, along with below standard flow velocity of the

latter, is thought to be responsible for the observed microbiologically induced corrosion.

Replacement with a 20 in. diameter pipeline was suggested as a permanent solution to the

corrosion problem, whereas a number of short-term measures were also recommended.

Keywords: MIC, SRB, Corrosion, Pipeline, Sour, Crude

IntroductionCrude oil pipelines form a wide transportation networkthat transfers the crude oil from one facility to another fortreatment. Damage induced by pipeline corrosion disruptsthe transport process, adds to direct cost and can alsoresult in unfavourable events, such as fires and explosionsthat disturb the environment’s ecology. For these reasons,it is essential to prevent, identify and remedy corrosionrelated failures of transmission crude oil pipelines.

Microbiologically induced corrosion (MIC) refersto corrosion caused by biological organisms. Microbiologically induced corrosion can occur in any aqueousenvironment and is a common problem in oil and gasindustry facilities due to the omnipresent nature ofmicrobes and corrosive by-products in the pipelines. Thesulphate reducing bacteria (SRB) present in the crude oilform a specialised group of microbes that use sulphate asthe electron acceptor for their respiration and generate H2Sas a terminal product.1 The ubiquity of these bacteria leadsto a variety of imposing industrial, economic andecological effects due to their ability to generate large

quantities of H2S. Corrosion of industrial equipment hasbeen ascribed to MIC in several studies.2,3 Sulphatereducing bacteria are the main cause of MIC, whichresults in increased corrosion rate, pitting and stresscorrosion cracking.4–8 Furthermore, SRB promote corro-sion by hydrogen utilisation and catholic depolarisation onmetal surfaces. In addition, they produce H2S, whichdirectly attacks the surface.9–14 More than 77% of thecorrosion in the oil producing wells in the USA is inducedby SRB.15 The mechanism of corrosion induced by SRBhas been heavily investigated.5,16–26

The mechanisms of metal corrosion in the presence ofSRB are complex. In an anaerobic environment, SRBuses sulphate as the electron acceptor and reduces it to asulphide. The following reactions may occur during thisprocess18

Anodic reaction 4Fe?4Fe2zz8e{

Water dissociation 8H2O?8Hzz8OH{

Cathodic reaction 8Hzz8e{?8H adsð ÞBacterial consumption SO2{

4 z8H?S2{z4H2O

Corrosion products Fe2zzS2{?FeS

Overall reaction4FezSO2{

4 z4H2O?

3Fe(OH)2zFeSz2OH{

This overall process is described as cathodic depolarisation.

1Saudi Aramco, Tanajib Lab, Dhahran, Saudi Arabia2Center of Research Excellence in Corrosion, Research Institute, KingFahd University of Petroleum and Minerals, Dhahran 31261, Saudi Arabia

*Corresponding author, email [email protected]

� 2011 Institute of Materials, Minerals and MiningPublished by Maney on behalf of the Institute

Received 8 September 2009; accepted 20 January 2010568 Corrosion Engineering, Science and Technology 2011 VOL 46 NO 4 DOI 10.1179/147842210X12695149033819

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Based on this theory, SRB consume the atomic hydrogenaccumulated at the cathode by a hydrogenase enzyme. Ithas been suggested that the corrosion rates increase dueto the cathodic reduction of H2S

H2Sz2e{?H2zS2{

and the anodic reaction is accelerated by the formation ofiron sulphide27,28

FezS2{?FeSz2e{

The presence of micro-organisms on a metal surfaceoften leads to highly localised changes in the concen-tration of the electrolyte constituents, pH and oxygenconcentration and can result in localised corrosion,depending on the passive film formation and repairingcapabilities of the underlying alloy.29–35 Sulphatereducing bacteria are very important micro-organismsfrom environmental and industrial standpoints. Theanaerobic corrosion of metals is enhanced by theactivities of SRB and is a universal industrial problemwhere aqueous process fluids contact equipment.Corrosion of steel by SRB has been known for manyyears, and various mechanisms have been postulated.The ratio of corroded Fe/iron sulphide is found to varyfrom 0?1 : 1 to almost 50 : 1.36 The anaerobic corrosionof Fe due to SRB is characterised by a coating on themetal surface consisting of black compounds contain-ing corrosion products. The nature of this blackcorrosion product appears to be most important indetermining the corrosion mechanism.37

In the present study, the crude oil pipeline wasdesigned for 322 thousand barrels per day (Tbpd)with a flow velocity of 1?58 m s–1. In practice, thepipeline was operated at a low flow velocity of 0?54–0?69 m s–1, which is below the minimum velocityrequired as per its design specifications for productionrate ranges between 110 to 140 Tbpd, which isapproximately 35–45% of the expected productionrate. The pipeline had been monitored under corro-sion inhibitor programme using Cortron AR505. Thechemical composition of the corrosion inhibitor islisted in Table 1. The injection rate of corrosioninhibitor used for crude oil at the leading end of thepipeline was set during the start-up of the facility at5% water cut and 21 ppm by volume treatment rate.The required injection rate since the plant start-upvaried between 19?7 and 29?6 L/day, based on a crudeproduction rate of 100–150 Tbpd. Actual consump-tion rate during service varied from 7?2 to 30. Thispaper states the pipeline history and inspectionoutlines, identifies the cause of failure and provides

recommendations to prevent future failure along witha mitigation strategy.

ExperimentalClose interval potential survey, instrument scraping andmanual ultrasonic scan were applied to the failedpipeline to investigate the possible causes of thepipeline’s corrosion damaged area. Various chemicalanalyses were undertaken for the sour crude and itsformation water. Corrosion products were washed withtoluene at ambient temperature and then petroleumether to remove the adhered crude oil. The samples weredried at room temperature under nitrogen gas atatmospheric pressure. For cross-section analysis, asample was polished with Cooper Nicholson roundhandle needle file 5 K9. A scanning electron microscope(model JEOL JSM-6490LA) attached with an energydispersive X-ray spectrometer (model JEOL EX-54165JMU) was used to metallurgically evaluate varioussections of failed pipeline for corrosion products.Imaging was performed in secondary electron imagingmode at an accelerating voltage of 20 kV.

A portion of the dried sample was ground to a powderand analysed by X-ray diffraction (XRD) to determineits chemical composition. The identification of thecrystalline phases was achieved using X-PertHighScore Plus programme. The semiquantification ofXRD data was done using the Rietveld method. Afurther dried portion was digested in HCl. On the aciddigest portion, a photometric technique was used todetermine the sulphate content. Further portions of the

Table 1 Chemical composition of water base corrosion inhibitor

Ingredient Amount, wt-%

Fatty acid, tall oil, polymers, ethoxylated 1–10Alkyl pyridine benzyl chloride quaternary 1–10Nonylphenol, branched, ethoxylated 1–102-Ethylhexanol, ethoxylated, phosphated potassium salt 1–10Phosphate ester 1–10Amines, tallow alkyl, ethoxylated 1–10Methanol 1–10Cocobenzyldimethylammonium chloride ,1Ethanediol ,1

1 Optical picture showing contamination of typical sam-

ple with crude oil

Al-Jaroudi et al. Failure of crude oil pipeline due to MIC

Corrosion Engineering, Science and Technology 2011 VOL 46 NO 4 569

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deposits were analysed for carbonate by a coulometricmethod and for sulphide by a potentiometric method.

Results and discussion

Visual inspectionThe optical macrograph in Fig. 1 shows a corrosiondeposit sample covered with crude oil.

Microstructural characterisationTypical morphology of the outer surface of the corrosiondeposit scraped from the internal surface of the failedpipeline is shown at low magnifications in Fig. 2a and b.The energy dispersive spectroscopy (EDS) spectrum(Fig. 2c) obtained from this corrosion product showeda predominant presence of Fe and S. The same location isshown at a slightly higher magnification in Fig. 3a and b

where a crystal of iron sulphide is visible. The EDSspectrum acquired from the crystal showing high Fe andS contents is also shown in Fig. 3c. Microbiologicallyinduced corrosion activity often causes the formation ofbiofilms, iron sulphide precipitation and cavity genera-tion at the Fe and steel surfaces.38,39 Furthermore, theSEM image in Fig. 4a shows a relatively fine sphericalstructure of iron sulphide formed due to bacterialmetabolism and associated with severe corrosion.40 TheEDS spectrum in Fig. 4b indicates predominant presenceof Fe and S. In addition, Fig. 5a and b shows flakydeposits that formed part of the corrosion deposit. TheirEDS in Fig. 5c indicates high counts of oxygen alongwith Fe and S. This confirms the presence of iron oxide inthe corrosion product.41

Elemental distribution of C, O, S and Fe was obtainedin a typical cross-section of corrosion deposit using X-ray

2 (a, b) Backscattered electron SEM image showing the morphology of the outer surface of the corrosion deposit formed

at the inner surface of the pipeline. (c) Corresponding EDX spectrum showing predominance of iron and sulfur within

the corrosion product


570 Corrosion Engineering, Science and Technology 2011 VOL 46 NO 4

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a

b

3 (a, b) Backscatter electron SEM image of the outer surface layer of the corrosion deposit showing iron sulfide crystal

inside a cavity. (c) Corresponding EDX spectrum obtained from the crystal showing high Fe and S concentration



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mapping. This allowed a better understanding of thedistinctive features of the corrosion product formed withtime. Figure 6 shows cross-section micrograph along withits X-ray mapping of the deposits. The internal part of thelayer seems to be denser and more compact, and mappingdata show enrichment in Fe and S. The EDS analysisobtained from this region also depicted high counts of Sand Fe suggesting that inner layer is primarily composedof iron sulphide. Extensive EDS analysis of the corrosion

product has shown iron sulphide as the major constituentof the corrosion deposit, with iron oxide and other scaleproducts as minor phases.

The inner layer of the corroded surfaces had pyriteaggregates, as depicted in Fig. 7a. The EDS spectrum inFig 7b, taken from one of these aggregates, showedhigh counts of sulphur with relatively low counts of Fe.This confirms the presence of pyrite within thecorrosion product formed closer to the pipeline’s inner

4 (a) Backscattered SEM image of the outer surface of the deposit showing spherical morphology of iron sulfide. (b)

Corresponding EDS spectrum obtained from the region shown in (a)



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5 (a, b) Backscattered SEM image of the outer surface of the deposit showing flaky structure. (c) EDS spectrum

obtained from the flakes show relatively high O peak along with predominant Fe and S



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surface. In addition, Fig. 8 shows the presence of anetwork of pyrite as has been reported in otherstudies.42 Presence of the pyrite aggregates in the innerlayer might resemble pyritic pseudomorphs of micro-organisms.43 Pyrite, in the presence of SRB, isconsidered the end product where iron monosulphides,such as mackinawite and greigite, are transformed intodisulphides.42

Close interval potential surveyThe close potential survey for failed pipeline wasconducted, and the potential on the line was found tobe between 1242 and 2000 mV, which exceeds theminimum 1100 mV potential required. The Close

Interval Potential Survey results indicated that theexternal surfaces of the pipeline were well protected.Thus, external corrosion was ruled out as a possiblecause of the corrosion damaged areas.

Manual ultrasound inspectionsInitially, ultrasound scan inspection was conducted atthe first three damaged locations and revealed localisedcorrosion pitting at the 6 o’clock position. Furthermore,10 locations from the base run were selected to beexcavated to measure the influence of corrosion. Theanalysis results indicated pitting and corrosion atlocalised regions where the damage had occurred.

6 Backscattered and X-ray mapping images for C, O, Fe and S taken from cross-section of corrosion deposit: inner sur-

face shows enrichment in Fe and S



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Instrument scraping findingsInstrument scraping run was undertaken to deliver acomprehensive and detailed assessment. The resultsof test runs undertaken after 1 and 3 years of pipelineservice are shown in Table 2. All metal loss is due tointernal corrosion. The reported internal corrosionmagnitude after 1 year is negligible compared to thatof 3 years into service. Thus, the severe internalcorrosion detected within the pipeline occurred

7 (a) Backscattered SEM image of the inner surface of corrosion deposit illustrating the morphology of pyrite aggregate.

(b) EDS spectrum obtained from pyrite aggregate in Fig. 7a

Table 2 Instrument scraping test results

Metal loss, % 1 year into service 3 years into service

.60 0 1641–60 0 53Total 0 69



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within the last 2 years of service. Immediate repairsof these damaged regions were undertaken.

Crude samples analysisThe analysis results of crude oil samples collected fromboth ends of the failed pipeline are shown in Table 3.

Water samples analysisWater samples collected from the failed pipeline duringscraping were analysed. The analysis results are shownin Table 4. Low pH of water sample with high level ofchloride and sulphide renders the media highly corrosivecausing pitting in carbon steel, especially if the internalsurface of the line is not protected with the corrosioninhibitor due to its insufficient injection rate. Thisgenerates the possibility of having direct chemicalconversion of the H2S, originally present in the crudeoil, to corrosion products besides the microbial corro-sion. On the other hand, the counts per millilitre ofgeneral aerobic bacteria of the sample were determinedto be 100, which is considered a low value, and itspresence is insignificant.

Photometric and potentiometric analysis ofcorrosion productsA weighed portion of the deposits was digested in mixedacids using a microwave digestion technique. The resultingsolution was then filtered to remove any acid insolublematerial, which was determined gravimetrically. The resultsindicated that 0?41% was insoluble in normal mineralacids. The material insoluble in acid is believed to be silica(sand). The acid soluble portion of the sample wasanalysed for sulphate using a photometric technique andfor both carbonate and sulphide by coulometric andpotentiometric techniques respectively. The results indicatethat the sample contained 30?2% sulphide but no sulphateor carbonate. The results indicate the presence of ironsulphide compounds as major phases.

X-ray diffraction analysis of corrosion productsX-ray diffraction was used to identify the phases presentin the corrosion products, as shown in Fig. 9. Therelative approximate values, normalised to 100%, arelisted in Table 5. The results show that the sampleconsists of corrosion products of iron sulphides [greigite(Fe3S4), mackinawite (FeS), pyrrhotite (Fe7S8) andpyrite (FeS2)] and iron oxides {magnetite (Fe3O4) andlepidocrocite [FeO(OH)]}.

X-ray diffraction analysis of the carbon steel corrosionproducts showed the presence of significant amounts ofgreigite (Fe3S4) and mackinawite (FeS). These com-pounds are characteristic of MIC, and they areconsidered as fingerprints for corrosion induced bySRB.44–47 Furthermore, research has suggested thatgreigite and mackinawite are indicator products ofMIC activity.48 Furthermore, greigite and mackinawiteare very common metastable iron sulphide produced bybiologically induced mineralisation. They are consideredas precursors in the formation of pyrite in highlyreducing environments through a series of solid statetransformations.49,50 Greigite causes the bacteria to beoriented in magnetic fields. In the presence of thesemagnetotactic bacteria, it forms from non-magneticmackinawite (tetragonal FeS) and possibly from cubicFeS. These precursors apparently transform into greigiteby rearrangement of Fe atoms over time.51 The highcontent of iron sulphide compounds in the corrosionproducts was verified by the determination of the totalsulphide in the corrosion products, which was 30?2 wt-%.

From literature, it is well known that the initialcorrosion product formed is mackinawite film FeS, anFe-rich iron sulphide that forms a poorly protectivelayer on the metal surface.52 The latter then getsconverted to Fe3S4 when Fe II concentration is low,which supports the presence of the formation of thebiofilm, and finally to FeS2. The magnetite Fe3O4 forms

8 Backscattered SEM image of inner surface of corrosion

deposit showing pyrite network structure

Table 4 Analysis results of water sample collectedduring pipeline scraping

Parameter Result

Total dissolved solids 188 600 mg L21

General aerobic bacteria 100 counts mL21

Residual corrosion inhibitor 156 mg L21

H2S 659 mg L21

pH 5.56

Table 3 Crude analysis results of failed pipeline

Parameter

Sample location

Start ofpipeline

End ofpipeline

Hydrogen sulphide(H2S), ppm

2982 1606

BS&W*, % 16.1 2.2Sulphate reducingbacteria, colonies cc21

100 2.56103

*Basic Sediment and Water.

Table 5 Crystalline phase constitution of corrosionproducts using XRD

Compound Amount, wt-%

Greigite (Fe3S4) 44Mackinawite (FeS) 15Pyrrhotite (Fe7S8) 7Pyrite (FeS2) 2Magnetite (Fe3O4) 28Lepidocrocite [FeO(OH)] 4



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as a result of oxidation of the FeS2 in the presence ofmoisture. It has been reported that the corrosion rate ofmild steel in the presence of iron sulphide increases withiron sulphide concentration.53

Mackinawite FeS formed by reaction of HS ions witheither Fe metal of Fe2z (Ref. 54)

HS{zFe?FeSz1=2H2

The reaction describing greigite formation from mack-inawite via Fe loss can be written as55

FeSzHS{z1=2O2zHz?Fe3S4zH2O

Transformation from greigite to pyrite can be expressedin terms of Fe loss56

Fe3S4z2Hz?2FeS2zFe2zzH2

Pyrite can be oxidised to form magnetite57

2FeS2z2O2?Fe3O4z3S2

Mode of failureThe morphology and phase constitution of corrosionproducts as determined by XRD and SEM respectivelyclearly showed the evidence for MIC within the failedpipeline. The MIC was responsible for severe corrosioninside the pipeline resulting in pinhole damage. Thecause of MIC is the presence of the SRB micro-organisms. The presence of iron oxide in the form ofhigh oxidation state of Fe [Fe3O4 and FeO(OH)] andhigh corrosivity of the water associated with crude oilindicates chemical corrosion, where the source may be

(a)

(b)

9 a X-ray diffraction pattern obtained from corrosion product of pipeline and b standard XRD patterns of identified com-

pounds in corrosion product



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the producing wells. Analysis of the corrosion productsupported MIC as being the predominant corrosionmechanism.

Cause of failureThe main contributing factor to the high internalcorrosion rate is the low flow velocity within failedpipeline. Excessive amount of water drops out due to theprevailing low flow velocity, which is below the specifiedengineering design. Under the low flow and high watercut conditions, the wet/sour service and bacteriacorrosion activities become severe. For instance, thecorrosion rate of steel in brine aqueous solutionsaturated with H2S had been reported as an averagefrom 2?5 to 4?5 mm/year.58 Furthermore, it was foundthat the corrosion rate of steel in the sea mud with SRBcould be as high as 10 times of that in the sea mudwithout SRB.59 No practical amount of on-streamscraping frequency will remove the water fast enoughin the pipeline (i.e. water will immediately drop out rightbehind the on-stream scraper to fill the line again). Themain internal corrosion mitigation approach to thepipeline internal corrosion problem is to increase itsprevailing low flow velocity.

ConclusionBased upon the results obtained, it could be concludedthat the crude oil pipeline failed due to a combination ofMIC and chemical corrosion, the former corrosion typebeing the predominant contributor. Sulphate reducingbacteria is responsible for MIC, which becomes severe inthe presence of low flow and high water cut conditionsthat prevailed in the pipeline.

RecommendationsAs a permanent solution to the low flow velocity andhigh water cut, replacement with a new 20 in. diameterpipeline was recommended. In the meantime, variousshort term measures were suggested to mitigate theinternal corrosion progress within the existing pipeline,as listed below.1. Maintain maximum sustainable flow rate in the

pipeline.2. Ensure continuous operation of corrosion monitor-

ing system.3. Utilise brush scrapers during the on-stream weekly

scraping.4. Increase the corrosion inhibitor concentration with

a biocide enhanced inhibitor.5. Install corrosion coupon to measure sessile SRB

activities.6. Install corrosion monitoring system to monitor the

corrosion rate.7. Conduct an instrument scraping run after six

months to measure the effectiveness of theaddressed recommendations which are being pro-posed.

8. Inspect the pipeline lateral lines and other non-scrapable piping by ultrasound scanning to evalu-ate their integrity.

9. Perform the pipeline batch treatment in conjunc-tion with routine scraping operations. Chemicalinjection can be set to the pump maximum as thescraper is being readied for launch. Increased

efficiency of cleaning may be realised by sendinga second scraper through the line several hoursafter the first scraper has left the line. In thismanner, the second scraper may benefit from anypotential surfactant qualities of the biocideenhanced corrosion inhibitor.

10. Increase the current injection dosage of the corro-sion inhibiter to maintain a high degree of pipelineprotection in the presence of high corrosive media.

11. Avoid, eliminate or chemically treat areas that holdwater and microbes such as dead legs, tow flowareas and storage to mitigate the effects of MICand other forms of corrosion.

12. Monitor the level of the corrosive species such assulphide, chloride and acidity in the water asso-ciated with the crude to prevent any potential forcorrosion.

Acknowledgements

The authors wish to acknowledge the support of SaudiAramco, Saudi Arabia. The second author appreciatesthe support extended by the Center of ResearchExcellence in Corrosion, Research Institute, KingFahd University of Petroleum and Minerals.

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Failure of crude oil pipeline due to microbiologically induced corrosion

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