Paper No.

32

CORROSION 96The NACE International Annual Conference and Exposition

C02 CORROSION IN WET GAS SYSTEMS

P.A. AttwoodPetroleum Development Oman

P.O. BOX81Muscat, Sultanate of Oman

Kees van Gelder and C.D. Charnley

Petroleum Development OmanP.O. BOX81

Muscat, Sultanate of Oman

ABSTRACT

The failure of a pipeline used to transport wet C02 containing gas has highlightedthe limitations that both intelligent surveys and ultrasonic testing (UT) inspection canhave for the detection of internal grooving type corrosion. These limitations arepresented, together with the inspection, testing and assessment programme that wassubsequently introduced to evaluate the condition of other associated production facilitiesoperating under similar conditions. Measures adopted to prevent the reoccurrence of suchC02 induced corrosion damage are discussed. In addition, the use of a corrosion rateprediction tool enabled the risk ranking of the facilities under threat of C02 inducedcorrosion to be rapidly undertaken and therefore enable an inspection and assessmentpriority ranking to be made. A comparison is therefore made of the predicted levels ofcorrosion with those actually observed in practice.

Keywords: carbon dioxide, grooving, hydrotest, corrosion rate prediction, wet gas

INTRODUCTION

On 22 March 94 a rupture occurred on 25.4 cm (inch) diameter buried pipelineused to transport approximately 1.5 MMsm3/d of wet gas (containing 0.8 mol% C02)from Yibal A station to Yibal D station. The pipeline, which had been installed in 1988,possessed a nominal wall thickness of 4.78 mm and was operating well within its agreed

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operating envelope (maximum allowable operating pressure of 9100 kPa) at a pressure of

5700 kPa. The failure was located 20 metres downstream of the pig launcher in the first

joint after the bend entering the buried section. The force of the rupture was sufficient to

propel a 2 metre section of the pipeline some 70 metres away and to cause significantdamage to the pig launcher pipework. Figure 1 provides a schematic illustration of thelocation of the failure. Inspection of the failed section of the line revealed that the failurewas caused by bottom of line C02 corrosion. It appeared that corrosion damage hadinitiated at a number of discreet locations in the 6 o’clock position which progressivelydeveloped into a series of channels or grooves running parallel with the length of the linefor a significant distance. The channels, for the majority of their length, appeared to

penetrate through approximately 80% of the full wall thickness (between 0.8 and 1 mm ofremaining wall thickness was measured near the rupture initiation site). A ductile crackinitiated at the centre of the failed section and propagated along the corrosion groove for adistance of approximately 1 metre in either direction. No other influencing factors werefound (operating conditions, impact damage, mechanical defect, location of weld seam).

A prior intelligent survey conducted in October 1993 indicated the presence of

some anomalies on the log which were interpreted in the flawlist as internal isolated pits

(max. 40% wall loss) which did not interact nor affect the maximum allowable operating

pressure of the line. The extent of corrosion, based on the intelligent survey data, was

most severe near the pig launcher (where rupture subsequently occurred), while other

affected sections were randomly distributed along the length of the pipeline. Based on the

log, it was concluded that only 9 areas were affected, consisting of 1 to 2 joints in each

case.

In January 1994 dig-ups were undertaken at the areas coinciding with theintelligent survey reported anomalies and subsequent manual ultrasonic testing (UT)inspection using a D-meter type thickness probe in these locations appeared to confirmthe flawlist (i.e. 40°/0 wall loss). Both the intelligent survey and UT inspection techniques,however, were calibrated for pitting defects and not for grooves such as led to the failure.Consequently, the full severity of the defect was not acknowledged at the time. Ironically,the UT checks were undertaken in the location where the pipe later ruptured.

The subsequent failure analysis further revealed that large quantities of water (upto 5 m3 per day) were transported by the Yibal A-D line since the Yibal A-station finalstage compression knock-out vessel had been taken out of service in 1989 (notably, thereason for this was that severe corrosion damage had been observed on the vessel inquestion). The study also revealed that almost all of the other gas lines and relatedfacilities transported water saturated gas (only water knock out vessels were employed tolimit water carry through) and were therefore assumed to be operating in the wet modewith the associated risk of severe internal corrosion. At the time no corrosion inhibitorwas applied in this line or any other handling wet gas.

32/2

Based upon the measured wall thickness loss at the rupture site (80% of 4.78mm), and assuming that corrosion initiated after 1989, the observed penetration rate wasestimated at 0.7 mm/y.

LATERAL IMPLICATIONS

A lateral impact study was undertaken to establish the extent of the problem aswet gas with similar corrosive properties to that being transported in the failed line wasalso transported in the Yibal A-B-C grid distribution system (Figure 2) and two otherfields (Fahud and Qarn Alam) with varying levels of C02, flow rates and pressure. Thisexercise was greatly assisted by the recent availability of a corrosion management system,Pacer-CM. This computer based system has been designed to provide the corrosionengineer with a means of storing, analyzing and reporting all corrosion related activities.Pacer-CM enables all the fixed information (wall thickness, design code, diameter, etc.)of any piece of equipment to be stored in user specified Equipment Record Cards (ERC),The ERC concept is therefore used to provide an easily retrieved reference for the designand construction parameters for all equipment subjected to a corrosion risk. Using thissystem the full range of facilities for the three fields which were exposed to a similarcorrosion risk as that which had been posed by the failed pipeline could be rapidlycompiled. In summary, the following facilities were identified:

Description Number

L

a. all inter-station HP wet gas 36 inter-station HP wet gas lineslines

b. all station HP wet gas lines 28 stations

c. all gas well lines 22

d. all gas injection lines 10

e. all gas lift lines -1000 ranging from 0.1 to 6 km in length(732 operating Aug. ’94)

f. well casing and tubing on all gas lifted wells

The scale of the problem lead to the development of a risk assessment ranking

which was based upon a corrosion rate prediction model. The oldest and best knownmodel is the de Waard - Milliams nomograml, first published in 1975 and continuallyrevised since. In order to calculate predicted corrosion rates for the pipeline and pipingsystems a spreadsheet programme, Wetgas6A, was used. This programme predicts theC02 corrosion rates using three different models. In general, a modified form of the deWaard - Milliams modelz provides a conservative, worst case estimate of the corrosionrate, the IFE (Institute For Energy research, Norway) models,o provides much morerealistic predictions but, since it is an semi-empirical correlation model, has certainlimitations, while the Limited Corrosion Rate (LCR) models serves as a check on the IFE

model: corrosion rates predicted by any model fundamentally cannot exceed the ratepredicted by the LCR model.

The predicted rates used in the study were based on the lower values of either theIFE prediction or the LCR model, whichever was lowest (this was usually the IFEmodel). A major drawback of all models available today is that, although the effects ofthe presence FeC03 scales are taken into account, the effects of scale formation kineticsare not included. Particularly in systems where water only occurs by condensation (whichis relevant for the majority of the wet gas lines included in this study) the effects ofscaling kinetics can be quite important and can result in corrosion rates significantlylower than the ones predicted by the models used in Wetgas6A. When free water alsoenters the pipeline, in addition to condensed water, the IFE model has been observed toprovide the best fit.

Wetgas6A also has a flow regime prediction model built in the spreadsheet toprovide an assessment of the flow regime, i.e., fully stratified, stratified-wavy, mistannular or slug flow (Table 1). These flow regimes are largely determined by the

superficial gas (Vsg) and liquid (Vsl) velocities in the pipeline.

For the purpose of this study, lines where the flow model predicted stratified,stratified-wavy flow, or mist-annular tlow near the boundary with stratified-wavy flow,were deemed most critical because of the high probability of rupture due to groovingcorrosion.

PREDICTED CORROSION RATES

Calculations using the Wetgas6A corrosion prediction model indicate a maximumlevel of corrosion for the Yibal A-D pipeline of 2-2.5 mm/y assuming continuous andcomplete water wetting of the pipe wall. Corrosion coupons (located 4 m away from thefailure) indicated 0.2 mm/y average wall thickness loss (not penetration rate). Themeasured wall thickness loss at the rupture site (80°/0 of 4.78 mm), initiated a penetrationrate of 0.7 mm/y.

The parameters used in the Wetgas6A calculations, for each of the 3 areas, areshown in Table 2. The results of the corrosion rate calculations for pipelines in the Yibalarea are summarized in Table 3. The detailed calculation result predict high corrosionrates throughout the Yibal area. For two lines (20.32 cm (8 inch) Yibal A to B - A76, and25.4 cm (1O inch) Yibal B to C - A77) the effect of free water and gas velocity (Vsg) wasinvestigated in more detail: This demonstrated first, that for these lines the presence offree water does not significantly affect the predicted maximum corrosion rate, however itdoes alter the corrosion rate profile over the length of the line; and second, in general thepredicted corrosion rate increases with increasing Vsg It should be noted that for the 25.4cm (1O inch) Yibal A to D - A81 line, which ruptured in service, the predicted corrosionrate (Vcorr) is high, and that also for the 25.4 cm (1O inch) Yibal B to C - A77 line, which

ruptured during hydrotesting, Vcorr is high for the high flow case.

The results of the corrosion rate calculations using Wetgas6A for the Fahud areaare summarised in Table 4. When compared to Yibal, the Fahud area lines show moderate

(though by no means negligible) predicted corrosion rates (Vcorr). Corrosion rates arepredicted to be lowest in the lines with low gas velocity (Vsg) e.g. 20.3 cm diameter (8inch) Fahud D to MLPS - A45 and 20.3 cm diameter (8 inch) Fahud D to E - A46). In thelow flow cases the corrosion rate profile tends to show a decline of Vcorr to the minimum

value after only a short distance (200 - 300m) from the inlet.

The results of the corrosion rate calculations using Wetgas6A for the Qarn Alamarea are summarised in Table 5. With the exception of the lines coming from SaihNihayda, predicted corrosion rates are relatively low (gas velocities (Vsg) are low in

these lines). The 15.24 cm (6 inch) Saih Rawl to Saih Nihayda - A70 line has the highestpredicted corrosion rates (Vcorr), which were found to subsequently be in line with thetindings in the field.

The differences in the corrosion rates between the three areas can be related to thedifference in C02 partial pressure. Superficial gas velocity and flow regime play a rolebut not sufficient to become visible in the observed time-average corrosion rates. Thescatter in the observed time-average corrosion rates within each area is very large. Itshould be noted, though, that when determining time-average corrosion rates it isassumed that corrosion started at the start of the observation period (in this case, at start-up of the line) which is not necessarily a worst case assumption. If corrosion started laterthan start-up of the line the actual corrosion rate would have been higher than the time-average value over the whole period.

As a consequence to the above evaluation, lines in Yibal were given highestpriority for inspectiotiassessment followed by selected lines in Fahud and Qarn Alamwhich exhibited the highest corrosion rates.

HOW THE CONSEQUENCES OF FAILURE WERE REDUCED

The actions taken were aimed at reducing the consequences of a failure topersonnel, to the facilities and to medium term oil deferment.

Restricted access procedures were put in place on the wet gas system systems as follows:-

a. Very High Risk Facilities:

i. these were shut down immediately.

32/5

b. High Risk Facilities:

i. these were shut down if there was no or little impact on production.otherwise they continued to operate,

ii. no work was to take place within 50 metres of such facilities,...111. authority was to be granted only for essential operational work,

iv. all non-essential work including construction was stopped,

v. routine pigging operations were suspended,

vi. access within 50 metres was restricted.

c. Medium Risk Facilities:

i. these continued to operateii. only operational essential work was permitted...111. authorization was required by area coordinator

iv. visits and access were minimized

d. Low Risk Facilities:

i. these continued to operateii. normal authorization of work and access continued to apply

The inspection necessary to prove the integrity of the facility was classified as

essential. However for UT inspection on-plott *), depressurised sections of station wet gaspiping were first tested to give confidence that the additional testing on the same systemor station could take place on line. The schedule took advantage of planned shutdowns toreduce oil deferment, however some additional shutdowns were necessary.

For high risk pipeline excavation, a shutdown was required in view of theunknown stresses which could be caused (settling, thermal expansion) and subsequent UTinspection was only to be carried out on shutdown lines until the risk could bedowngraded.

HOW THE PROBABILITY OF FAILURE WAS REDUCED:- TEST ANDMITIGATION STRATEGIES

Pipelines

The method used for immediate risk reduction was injection of corrosion inhibitorintroduced either continuously or batch wise.

1(1)On-plot refers to facilities located within a station boundary where design code ASME/ANSI 1331.3applies

32/6

The methods used for proving the integrity of a pipeline were:-

a. automated UT scanning of known defects if intelligent survey data wasavailable

b. hydrotest if no intelligent data was data available or if results were suspectc. install temporary line if calculated loss of revenue during hydrotest exceeded

cost for temporary line or if defect verification would exceed this costd. abandon line (as opposed to suspending at pressure) if not required.e. intelligent survey, only for lines at medium or low risk due to

implementation timing

The decision logic was generally as follows:-

For lines which had a recent (3 years) intelligent inspection the accuracy ofinspections was verified via excavations and automated UT scans of the most severe andtypical defects. For most lines in this category this had already been done during the1993-1994 sleeving campaign.

For lines which had older information or not sufficient defect verification, the

approach was to select a number of representative defects and automated UT scan those,followed by a defect assessment.

For lines which were not piggable or had not had a recent inspection, intelligentinspection was not considered as a short term action in view of the lead time, analternative method was used. However, if it was initially classified as medium risk, thenan intelligent inspection was planned and implemented during the next intelligent surveycontract.

Alternative methods included either hydrotesting or replacing by a temporaryabove ground line (flowline design). The decision to replace a line in this way was basedon present risk category of existing line and a cost comparison with alternativeassessment methods.

On some old tape wrap coated lines, the cathodic protection system was turned offto mitigate the likelihood of stress corrosion cracking. This policy has not yet been fullydefined and requires further investigation.

Pipelines: -Defect Assessment

The design code ASME/ANSI B3 1.8 was used to assess pipeline defects wherethe depth and longitudinal length were known, The assessment was based on the presentdefect size, expected future growth, required operating envelope and the interval to thenext inspection or replacement. Defects which fell inside the code were accepted, whilstother defects required repair.

32/7

A fitness for purpose analysis was performed for lines that were hydrotested.These lines may contain defects outside the above design code but the hydrotest provedthe absence of defects that could lead to rupture in the medium term, as per the projectobjectives.

The basis for hydrotesting is to establish the strength and leak tightness

capabilities of a facility at a pressure above the normal operating pressure. Typically newpipelines are tested to 125% of the maximum operating pressure.

For this investigation into wet gas corrosion, the primary intent was to minimizethe potential for rupture during a period of time that would be required to implement longterm integrity solutions, such as gas drying or use of corrosion resistant alloys

(approximately 2 years), which means, for many of the systems

a. replacement due to the high cost of retrofitting scraper trapsb. modifying piping to accommodate inspection tools

The time frame for which a pipeline can operate at a given test pressure is based

on a model which uses fracture mechanics. It establishes a minimum wall thickness forpressure containment while providing margins for continued internal and externalcorrosion growth. Basic input parameters are the pipe specifications (size, thickness andgrade), operating pressures and the projected corrosion growth rates.

Pipe specifications were readily available for most major pipeline systems, but forsome, this information had to be assumed. The process for establishing a test pressureinvolved the following steps:-

a. calculating the wall thickness required to contain operating pressures.b. establishing external corrosion growth based on coating condition.c. establishing internal corrosion growth rate based on historical

maximums and inhibition efficiencies.d. establishing time period for which the system must operate.e. calculating hydrotest pressure that will prove the required wall

thickness considering the above requirements.

The expected annual corrosion rate is multiplied by the number of years the line isrequired before further assessment. From a knowledge of the maximum allowableoperating pressure. a test pressure is selected on the graph (Figure 3) to the left of thevertical line (which is the limit for leak before break - rupture). This method does nottherefore prevent leaks,

The limitations to this approach are established by the maximum pressure apipeline and its components (fittings, flanges, etc.) can be subjected to. The maximum a

Q91Q

pipe can be subject to is normally 100% of its specified minimum yield strength and forthe components 150°/0 of the maximum operating pressure.

Since 1991, the defects identified by internal intelligent surveys in PDO pipelineshave been classified as follows:-

Grade 1 Anomaly indications indicative of 15 to 30% body wall penetrationsGrade 2 Anomaly indications indicative of 30 to 40% body wall penetrationsGrade 3 Anomaly indications indicative of 40 to 50’?40body wall penetrations

Grade 4 Anomaly indications indicative of 50 to 60% body wall penetrations

Grade 5 Anomaly indications indicative of 60’?ZOplus body wall penetrations

Stations

The strategy used for reducing the probability of failure in the stations was basedon ultrasonic testing at selected test sites, and is given below:-

a. UT InspectionThis was done in two stages, the first was aimed at reducing the evaluated riskfrom high to medium and at testing the bulk of the stations piping (90Y0completion). After the second stage all planned UT was complete and additionaltesting included bottom scanning (between the 5 and 7 o’clock position on theline) had been carried out in suspect areas. The risk category remained mediumupon completion.

b. RepairsRepair work was planned and implemented immediately when serious defectswere identified in the above process.

c. Corrosion InhibitionContinuous corrosion inhibition was applied by direct injection into thecompressor discharge lines and was aimed at penetrating into all the gashandling system.

d. Buried SectionsBuried on-plot wet gas lines have been identified on many stations. These havenot been ultrasonically tested as they would have required shutdowns to exposeand test them. The cost of the testing and associated oil deferment would be morethan the cost of replacement in most cases, and in addition, the lines would haveto be dug up every few years for regular inspections.

32/9

Stations: -Defect Assessment

A spreadsheet programme was used which enabled the defects to be evaluated inaccordance with the on-plot piping design code ASME/ANSI B3 1.3. Using thisprogramme the defects were categorized into three groups as follows, each withdefined follow-up action:-

TDefect Descrip.

Group

A Serious

FB Major

c Minor

1

Definition Action

Major corrosion and integrity Requiresproblem (wall thickness less than immediateor close to minimum required by replacement

ASME/ANSI B3 1.3)

Major corrosion problem (>20Y0 Monitor defectwall thickness loss) growth (every

6 months)

Minor (<20’?40wall thickness loss) Monitor defectgrowth (every

12 months)

a pre-

Gas Lift Lines

General. There were approximately 1000 gas lift lines (732 were on line at endAug. 94) associated with wet gas handling, these include both active and inactive lines.The facility specifics are:

Piue Size Length &

2 to 3-inch O.D. 0.1 to 6.0 km new to 30 years

The overall plan was to reduce the risk of rupture in gas lift lines which couldresult from internal C02 corrosion. The initial step was to select a test method whichwould provide evidence that this condition did exist. Historically the primary problem hasbeen external corrosion.

Test Methods. Test methods considered for these facilities included hydrotesting,manual ultrasonic testing (UT) and cut-outs. The methods selected were UT and cut-outs.Although, early into the programme UT was discontinued due to noted inaccuracies indefect detection. Manual UT can confidently be used to identify pitting on piping with adiameter of 10 cm (4 inch) or more, however using it to assess whether the pitting hasjoined up to form grooves is difficult. Defining the occurrence of grooving corrosion onstations has not been possible unless confirmed by automated UT, except at Fahud Bwhere it was clear cut. In areas of concentrated major pitting, the trend is for the pitting tojoin up and form grooves.

32/1 O

Hydrotesting was not suitable for the testing of gas lift lines, as the test pressureneeded to prove the minimum wall thickness as required by the piping code wasconsiderably higher than the flange rating, and proven life by hydrotesting was in theorder of months rather than years.

Promamme. The cut-out programme consisted of selecting sections of gas liftlines to be removed in the Fahud, Qarn Alam and Yibal areas. The specific plan was todetermine, based on the sample, if evidence existed that would indicate the presence ofgrooving corrosion which could result in rupture. If no such indications were present, nofurther work would be done due to the small probability of rupture. If indications werepresent, a more detailed investigation would be required using statistical modeling andevaluation.

RESULTS

A summary of results is as follows:-

a. Carbon dioxide grooving corrosion was confirmed on 6 pipelines in Yibal and2 in Qarn Alam, in station piping at Yibal A and Fahud B and in gas lift linesat Yibal, Fahud and Qarn Alam.

b. Major and minor internal pipe damage caused by carbon dioxide corrosionwas found throughout the investigated wet gas system.

c. At some locations the remaining wall thickness was less than the minimumrequired by the pipe code such that confidence could no longer be guaranteedin the integrity of the piping.

d. The results indicate grooving corrosion in the gas lift systems along with areasof internal and external pitting. Preliminary assessment, based on ANSI 31.8,indicates that all the detected grooving corrosion is within safe operatinglimits. Only one external pit (91 % wall thickness loss) was outside the designcode in the Fahud area.

e. Buried lines have been identified on many stations that required replacementabove ground. More stations need to be checked.

f. Generally there was good qualitative correlation between the corrosion foundin the field and corrosion rates predicted by the corrosion model Wetgas6A,although actual field corrosion rates, where calculated, were lower than thosepredicted.

32111

il. Stress corrosion cracking has been found in two government gas well linesand highlighted as a potentially serious problem in old tape wrapped lines.

h. Wind blown sand built up on pipeline facilities has been identified as a majorproblem contributing to external corrosion (not by erosion), in Yibal theproblem is serious.

i. 4 pipelines have been abandoned and replaced by temporary lines.

j 1 pipeline has been abandoned without replacement, 2 others have beenproposed for immediate replacement.

k. A medium term corrosion inhibition programme has been implemented

1. 17 pipelines have been identified for replacement pending furtherinvestigations

CONCLUSIONS

The failure of a pipeline used to transport wet gas has highlighted the limitationsof both intelligent surveys and UT inspection for the detection of internal grooving typecorrosion. Although re-examination of the intelligent survey raw data does (according tothe survey vendors), however, reveal possible bottom of line corrosion and/or grooving,but this is not evident in the initial flawlist supplied to evaluate the condition of the line.The use of a corrosion rate prediction tool enabled the risk ranking of the facilities underthreat of C02 induced corrosion to be rapidly undertaken and therefore enable aninspection and assessment priority ranking to be made.

As a consequence to this failure a major review and inspection/assessment ofPetroleum Development Oman’s wet gas handling facilities were undertaken. The resultsclearly showed that the problem was not just restricted to the pipeline facilities in thelocality of the failure. In order to circumvent such problems in the future an extensivecampaign of inhibition, inspection, hydrotesting and line replacement has been

undertaken.

REFERENCES

1. C. de Waard, D.E. Milliams, “Prediction of Carbonic Acid Corrosion in Natural GasPipelines”, First International Conference on the Internal and External Protection ofPipes, paper no. F1, (University of Durham, UK, 1975).

2. C. de Waard, U. Lotz, D.E. Milliams, “Predictive Model for C02 CorrosionEngineering in Wet Gas Pipelines”, CORROSION/91, paper no. 577, (Houston, TX:NACE International, 1991).

3. A. Dugstad, K. Videm, “Kjeller Sweet Corrosion-II. Final report”, IFE/KR/F-90/008KSC-11-59, Institutt For Energiteknikk, Norway, 1990.

4. C. de Waard, U. Lotz, A. Dugstad, “Influence of Liquid Flow Velocity on C02Corrosion: A Semi-empirical model”, CORROSION/95, paper no. 128, (Houston. TX:NACE International, 1995).

5. B.F.M. Potts, “Mechanistic Models for the Prediction of C02 Corrosion Rates UnderMulti-phase Flow Conditions”, CORROSION/95, paper no. 137, (Houston, TX: NACE

International, 1995).

32/1 3

TABLE 1

FLOW REGIMES FOR GIVEN SUPERFICIAL GAS VELOCITIES

Ft-=

1low v~g (up toapprox. 6 rds)

Flow Re~ime

Liquids in the linebecome virtually

stagnant

Stratified flow

regimes and the low

Vsg end of the mist-annular flow regime.

high Vsg (6 to20 mls)

Vsg >20 m’s

Mist - annular flow

Mist - annular flow

Action

Corrosion tends to be more localised (pitting followedby so-called “mesa attack”) which tends to cause leaksrather than ruptures.

This is expected to produce conditions conducive to thegrooving type corrosion which can result in a piperupture as observed in the failed Yibal A-D pipeline

Corrosion will occur around the full circumference ofthe pipe inner diameter which, for the pipeline sizes andwall thicknesses included in the task force study, tendsto result in pipeline leaks rather than ruptures.

Liquid droplet impingement starts to play a role in thecorrosion process and erosion-corrosion can occur. Sincethe type of attack under erosion-corrosion conditions isvery erratic and dependent on sometimes small flowdisturbances both leaks and ruptures must be expectedunder such a flow re~ime.

TABLE 2

PARAMETERS USED TO DETERMINE C02 INDUCED CORROSION RATES

Area Pressure (bar) Temperature ~C) C02 Content Superficial gas velocity

(mole%) (m/s)

Yibal 56 40-60 0.8 1-6

Fahud 48 50 0.64 1.1-7earn Alam 60 50 0.28 -1.0 0.5 -2.4

32/1 4

TABLE 3

YIBAL AREA WET GAS PIPELINES; PREDICTED CORROS1ON RATES EX WETGAS-6

2.5

2

1.5

1

0.5

PREDICTED CORROSION RATE AS FUNCTION OF Vsg

■ MAXIMUM RATE

MINIMUM RATE

o0 1

■

■

■

H

,-

■

II

6’2 3

Vsg (m/s)

4 5

3?115

TABLE 4

FAHUD AREA WET GAS PIPELINES; PREDICTED CORROSION RATES EX WETGAS-6

A40,..,.,..,,.,,.,,.,,,,,A41,,.,,.,,.,,,,,,,,,,,,,A43

A44

A45

A46,,,,,,,,,.,,,,,,,,,,,,A50,.,,.,,.,,.,,.,,.,,.,,A55,,,,,.,,,,,,,,,,..,,.,

-

MLPS TO FAH-B,,,,.,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,FAH-C TO MLPS,,,,,.,,,,,,,.,,.,,.,.,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,FAH-D TO FAH-F,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,",.,.,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,

FAH-D.FN6R TO MLPS

FAH-D TO MLPS

FAH-D TO FAH-E,,,,.,,.,,,,,,,,,,,.,,..,.,,.,,.,,,,,,,.,,.,,.,,.,,,..,..,..,.,,.,,.,,..,,,,..,,,,..FAH-F TO FAH-D,,.,,.,,.,,,,.,,,,,.,,.,..,,.,,..,.,,.,,,,,.,,,,,,,,,,.,,,,,,,,,,,,,,,,.,,.,,.,,.,,.,,.,,,,.,,.,,.,,,,,,,,,,,

NAT-W TO NATIH

ET=(kdMMsm3

4.581 0,,,.,,.,,.,,.,,.,,.,,.,,. ,,,.,,,,,,,,,,,,,,,”,,.,,,,,,,,,,,,,,,,,,,,,,,,,,

PREDICTED CORROSION

MAXIMUM RATE I

FLOW REGIME PREDICTED Vcorr (mm/y)

PREDICTED

MAXIMUM MINIMUM

,,,.,,.,,.,,..,..,..,.,..,..,..,,.,,.,,.,,.,,.,,-,,.,,.,,.,,..,..,..,.,,.,..,,.,,.,,.,,.,,.,,,.,,,,,.,,.,,.,,.,,..,..,..,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,.,,.,,.,,,,..,.,,.,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,,ANNULAR DISP. 1.17 0.8.. ,.,..,..,,.,,.,,.,,.,,,.,,.,,.,,.,,.,,..,.,,..,.,,.,,.,,.,,.,..,,.,.,,.,,,.,,,,,.,,.,,,,,,,,.,,,,,.,,,,,,,,,,,,,..,.,,.,,..,,.,,.,,,,,,,,,,,,,,,,,,,,,,,,,,,,ANNULAR DISP. 1.2 0.98..,..,.,..,..,,.,,.,,.,,.,..,..,..,,.,,.,,,,,,.,,.,,., .,,.,,.,,.,,.,,.,,.,,.,,.,,.,,.,,.,,.,,.,,,,,.,,,,,,.,,.,,.,,,,,,,.,,,,,.,,,,.,,,,.,,,.,,,,,,,,,,,,,,,,,,,,,,,,,

RATE AS FUNCTION OF Vsg

W=

MINIMUM RATE

■I

,

1 2

t I I

3 4 5

Vsg (m/s)

6

■

7

32/1 6

TABLE 5

QARN ALAM AREA WET GAS PIPELINES; PREDICTED CORROSION RATES EX WETGAS-6

rYm LINE Vsg FREE FLOW REGIME PREDICTED Vcorr (mm/y)

No. (m/s) WATER PREDICTED

(kdMMsm3) MAXIMUM MINIMIJM

PREDICTED CORROSION RATE AS FUNCTION OF Vsg

2.5

w

1- 1.5

s

o

0

■ MAXIMUM RATE

I MINIMUM RATE

0.5 1 1.5 2

■

2.5

Vsg (m/s)

32/1 7

1.43m. . .u.uem

Launcherdisplacement

1 .25m ~- due to rupture

20 m

\

A0914/ \

/

------ .- .0.-. 0 .000.- ------- --- ● -*-*-* 0.-.-.-

[

-*-.

Yibal A-D pig

Pipeline details:

launcher

Nominal diameter

Wall thickness

Material

Design

Design

Design

Length

pressure

temperature

code

10 inch

4.8 mm

AP15L X60

9100 kPa

82 deg C

ANSI B 31.8

2.2 km

FIGURE 1- Location of pipeline rupture

Ground level0 ------ ----

2.5 m

w

‘\Rupture location

A77 10“

RM B-Cl

“i8“

c 4---.-

1 8“

RM C-Cl

“-””e

RM

A79 6“

Al tiuw

Station

HP Wet

— -.

Gas Line

Remote Manifold

B ‘AM-(’”” ‘a’) F D

A74 8“

A73 q2“ A81 1o“

A86 10“(Abandoned)1o“

77. 6“ Temp.

RMA-DI

8“

8“

RMD-DI

House

GGP -

2.5

—

-.

—

—

o–

0

■ 1,1 MAOP = 62,4 bar■

1,5 MAOP = 85.5 bar

+ 2.0 MAOP = 114 bar

.:, 3.0 MAOP = 171 bar am..,,..”””””””--”----”” ““” ‘

/m,,,,. ..---”-

,/ ‘./”

10 20 30 40 50 60 70 80 90 100

Pit axial length (mm)

FIGURE 3- Additional wall thickness available above that required for pressure containment