Techniques that have been traditionally used for obtaining such in-service information include in-line inspection (ILI) and the hydrostatic test. These techniques have previously been favored since the interpretation of their impact on structural integrity has been perceived to be relatively straightforward. However, these approaches are not always practicable and therefore alternatives are sometimes necessary. Abstract
A ROBUST APPROACH TO PIPELINE INTEGRITY MANAGEMENT USING DIRECT ASSESSMENT BASED ON STRUCTURAL RELIABILITY ANALYSIS Andrew Francis, Tim Illson, M A McCallum & M McQueen Advantica Loughborough UK PH: +44 1509 282719 Fax: +44 1509 283118 [email protected]Abstract The basic objective of a pipeline integrity management system is to ensure that the load applied to the pipeline remains lower than the resistance to that load. This is customarily achieved by implementing measures at the start of life that ensure that a ‘safety margin’ exits at that time, and then periodically collecting information, during life, in order to ensure that the margin is not lost. Techniques that have been traditionally used for obtaining such in-service information include in-line inspection (ILI) and the hydrostatic test. These techniques have previously been favored since the interpretation of their impact on structural integrity has been perceived to be relatively straightforward. However, these approaches are not always practicable and therefore alternatives are sometimes necessary. For external corrosion, valuable information can be obtained using surface measurement techniques such as Close Interval Survey (CIS), Direct Current Voltage Gradient (DCVG) and other so-called Direct Assessment (DA) techniques. For internal corrosion, equivalent surface measurement techniques do not exist and therefore alternative sources of information are required. To this end Advantica have developed a (DA) technique based on predictive multiphase flow modeling that, combined with knowledge of the pipeline topography, can be used to determine the likely sites of water ‘hold-up’ and hence internal corrosion. However, both above ground measurement techniques and predictive modeling are subject to uncertainty and therefore do not always locate the presence of corrosion. Moreover, it is possible that the presence of corrosion may be identified erroneously. In order to account for this uncertainty, Advantica have developed a new technique, based on Structural Reliability Analysis, for robustly interpreting the
Transcript
A ROBUST APPROACH TO PIPELINE INTEGRITY MANAGEMENT USING DIRECTASSESSMENT BASED ON STRUCTURAL RELIABILITY ANALYSIS
Andrew Francis, Tim Illson, M A McCallum & M McQueenAdvantica
The basic objective of a pipeline integrity management system is to ensure thatthe load applied to the pipeline remains lower than the resistance to that load.This is customarily achieved by implementing measures at the start of life thatensure that a ‘safety margin’ exits at that time, and then periodically collectinginformation, during life, in order to ensure that the margin is not lost.
Techniques that have been traditionally used for obtaining such in-serviceinformation include in-line inspection (ILI) and the hydrostatic test. Thesetechniques have previously been favored since the interpretation of their impacton structural integrity has been perceived to be relatively straightforward.However, these approaches are not always practicable and therefore alternativesare sometimes necessary.
For external corrosion, valuable information can be obtained using surfacemeasurement techniques such as Close Interval Survey (CIS), Direct CurrentVoltage Gradient (DCVG) and other so-called Direct Assessment (DA)techniques.
For internal corrosion, equivalent surface measurement techniques do not existand therefore alternative sources of information are required. To this endAdvantica have developed a (DA) technique based on predictive multiphase flowmodeling that, combined with knowledge of the pipeline topography, can be usedto determine the likely sites of water ‘hold-up’ and hence internal corrosion.
However, both above ground measurement techniques and predictive modelingare subject to uncertainty and therefore do not always locate the presence ofcorrosion. Moreover, it is possible that the presence of corrosion may beidentified erroneously.
In order to account for this uncertainty, Advantica have developed a newtechnique, based on Structural Reliability Analysis, for robustly interpreting the
impact of results from above ground surveys and predictive modeling on thestructural reliability levels.This paper describes the development and application of these techniques forthe purpose of integrity management.Case studies involving both external and internal corrosion are presented which,clearly demonstrate the application, and emphasize the value of the technique asa basis for integrity management.
INTRODUCTIONExternal Corrosion Direct Assessment (ECDA) has been defined as “a structuredprocess that is intended to improve safety by assessing and reducing the impactof external corrosion on pipeline integrity. By identifying and addressing corrosionactivity and repairing corrosion defects and remediating the cause, ECDAproactively seeks to prevent external corrosion defects from growing to a sizelarge enough to impact on structural integrity” [1].It is widely accepted that the process consisting of four steps. These are
• Pre-Assessment• Indirect Inspection• Direct Examination• Post Assessment
The purpose of the pre-assessment is to obtain an indication of the level ofintegrity that currently exists on the pipeline system. This may vary from locationto location and therefore this pre-assessment can be regarded as part of abroader process that is used to identify segments and rank these in terms of risk.However, this generally involves the consideration of other causes of failure. Thisrisk-ranking phase is beyond the scope of this paper and the process describedherein is based on the assumption that the identification of pipeline segmentshas been undertaken. The pre-assessment is thus limited to the assessment ofintegrity for given segments.The approach adopted is use Structural Reliability Analysis [2-7] taking accountof existing information in order to establish a prior view of the probability of failureof a given segment. Such information would include basic pipeline physicalparameters such as operating pressure, material grade, wall thickness anddiameter. Additionally, pipeline age and coating time would usually be known andtaken into account. Other relevant information would include results of previousabove ground surveys and records excavations and repairs. However, these arenot always available and assumed levels of corrosion may be used based oncomparisons with similar systems of a similar age. Appropriate conservatism isintroduced when such assumptions are required.The results of the SRA are used as a basis for deciding on the requirements ofthe next three stages.
For segments for which the current knowledge of the integrity is considered to beinsufficient indirect assessment is undertaken to acquire further information.This involves the use of above ground surveys such as Close Interval Survey(CIS) and Direct Current Voltage Gradient (DCVG). The purpose of the latter isdetect coating damage, whilst CIS is used to detect the presence of activecorrosion. An important factor associated with both of these (and other) aboveground survey techniques is that they are not 100% reliable. Sometimes they failto detect the damage, i.e. the Probability of Detection (PoD) is less than 1 andsometimes they indicate damage when damage is not present, i.e. the Probabilityof False Indication (PfI) is greater than zero. Direct measurements atexcavation sites are used to take account of this unreliability and to improve theknowledge of defect sizes.Excavations are mainly undertaken at sites at which the surveys indicate coatingdamage is likely to be present. The observations made at these sites provideinformation for use in the post assessment.When corrosion is found at these sites, the size of the damage is used to updatethe prior distribution of defect depth. The discovery of coating damage and/oractive corrosion maintains (but does not change) the prior belief of level of thereliability (PoD & PfI) of the surveys. When coating damage and/or activecorrosion is not found at these sites then the prior value of the PfI may bechanged as a result of Bayesian Updating.A small number of excavations are made at sites at which damage has not beenindicated. (Note that in practice these are made at sites at which other remedialwork is required, e.g. installation of test posts) When no damage is found atthese sites, this maintains (but does not change) the prior belief of level of thereliability (PoD & PfI) of the surveys. When coating damage and/or activecorrosion is found, the prior value of the PoD may be changed as a result ofBayesian Updating.The outcome of the above process is used in the post assessment to updatethe expected number of sites at which active corrosion is expected and todetermine the posterior probability of failure using the updated defect sizedistribution.Depending on the value of the posterior failure probability, the integrity of thesegment is either declared acceptable or more excavations are undertakenfollowed by further analysis.The above text has provided a brief outline of a rigorous process for managingthe threat due to external corrosion. However, the approach may also be appliedto manage the threat due to internal corrosion. Stages 1,3 and 4 apply equally tointernal corrosion, but of course above ground survey techniques (stage 2) arenot applicable and an alternative indirect measurement technique is thereforerequired.To this end hydraulic modelling has been identified as a technique forpredicting the likely locations of internal corrosion damage. Based on locations of
‘low points’ inclination and length of slopes, temperature, water content and flowrate, hydraulic modeling is used to determine the positions at which water is likelyto ‘drop out’ and hence promote corrosion. Data required for this purpose andindeed the modeling technique are subject to uncertainty and this is addressed inan analogous manner to that used for above ground surveys.A detailed description based on a recent case study is provided below of the useof direct assessment for managing the threats due to both external and internalcorrosion. A number of segments were identified. However, in the interests ofbrevity the analysis of only two of these is presented here. The relevant physicaldetails of these are given in Table 1.
PRE ASSESSMENTThe pre-assessment primarily involves the use of SRA to determine an initialestimate of the probability of failure based on information that is available prior tothe undertaking of any direct and indirect examinations. The initial failureprobability is computed using ‘prior’ distributions and is referred to as the priorfailure probability.SRA is essentially a process for combining pipeline physical properties anddamage data taking, taking account of uncertainty in order to determine thefailure probability. The process is described in detail in [2-7]. However, for thepresent publication the focus is on the inputs and outputs rather than the processitself.In addition to the expected number of internal and external corrosion defects, theparameters that determine the structural integrity are pressure, P , yieldstrength, yσ , ultimate strength, uσ , diameter, D , wall thickness, w , defectdepth, a , and defect length, l . Details of the limit state function are given in [2-7].Each of the parameters is subject to uncertainty that needs to be taken intoaccount by the SRA. The data required for this purpose is generally provided bya range of different sources. However, within this publication, the focus isrestricted to the parameters that are of direct relevance to the method, namelydefect depth and defect length. The treatment of other parameters is discussedin [2-7].Frequency of Occurrence of External Corrosion DefectsNo previously reported corrosion damage was available. Consequently,information gathered from similar systems (in the UK) was used and, based onthe age of the pipeline, the prior expected number of coating defect sites permile, CDEN , was found to be 11.88.
Furthermore, information gathered from the UK Transmission system indicatesthat the proportion of sites with coating defects that will have active corrosion, α ,is about 1%. The pipelines for which this observation were made have similarcoating and are of similar age to the system under consideration and, assumingno marked difference between levels of protection, it was considered reasonable
to assume this statistic applies here. The expected number of sites with activecorrosion, activeEN , was thus assumed to be 0.1188 per mile.
Depth of External Corrosion DefectsNo initial data describing the uncertainty in this external corrosion defect depthwere available and therefore recourse to another data source was necessary. Tothis end data that have been collected over a period of in excess of 25 yearsfrom investigations of the UK Transmission system were used. A statisticalanalysis of these data revealed that the defect depth can be described by aWeibull distribution with a shape parameter α and a scale parameter
nttK )( 0−=β where t denotes the time since commissioning and 0t denotes thetime that elapsed before the defects were introduced. Values of K,α and n werefound to be 2.3328, 0.0244 and 0.65 respectively.
For the Weibull distribution used, the mean defect depth, aµ is given by
)/11( αβµ +Γ=a
where Γ denotes the Gamma Function. Assuming a 40-year life to date, and that00 =t , gives value for β of 0.268 and hence a mean defect depth of 0.237.
Length of External Corrosion DefectsThe defect length is also a time dependent quantity. However, the effect ofgrowth of this quantity is far less significant than the growth of defect depth. Ingeneral it can be assumed that the length is governed by the length of thecoating defect and provided that no further loss of coating occurs the defectlength can be assumed to remain constant with time.No initial data describing the uncertainty in this quantity were available for thepipeline and recourse to another data source was necessary. Using the samesource as for depth, statistical analysis of the data revealed that the defect lengthis described by a Weibull distribution with shape parameter 0.8752=α and scaleparameter 12.5=β inches. This gives a means value of 5.5 inches.
Frequency of Occurrence of Internal Corrosion DefectsBased on the number of inlet points on the pipeline and the potential range offlow rates nine potential hold-up sites were identified implying a prior incidentfrequency of 1.125 per mile.Depth of Internal Corrosion DefectsFor internal corrosion to occur, there must be liquid water present. This water caneither be introduced at a point of entry or condense out of the gas due to lowambient temperatures. For the present study only the latter is considered.In the USA, gas generally contains 7lbs/mmscf giving a dew point of 27oF at 600psi. Thus water will condense upon the pipe wall once it reaches thistemperature. The number of days per year during which corrosion can occur is
considered to be equal to the number of days, ET , for which the ambienttemperature falls below 27oF
An analysis of NOAA data reveals that the uncertainty in ET can be representedby a Lognormal distribution with mean,
ETµ , equal to 27 days and a standard
deviation, ET
σ , of 13 days.
On the days that corrosion will occur, the corrosion growth rate, a , is related toCO2 partial pressure that is related is to the operating pressure. An analysis ofpartial pressure variations that occurred on the pipeline, resulted in a growth ratethat can be represented by a Normal distribution with a mean, aµ , of 1.009mm/yrand a standard deviation, aσ , of 0.009.
Assuming that the growth rate, although subject to uncertainty, remains constantover time, the updated growth rate is given by
365ETaa = ,
and it follows that, for given ET , the distribution of growth rate is given by
=
Ea
EE T
apT
Tap 365365)|( .
Hence, the prior distribution of growth rate, )(apa
, is given by
∫∞
=0
)(365365)( EEE
aE
adTTp
Tap
Tap
The distribution of defect depth at time t (>0) is thus given by
)/(1)( tapt
apa
= .
After a life to date of 40 years, this results in a distribution with mean, µ , value of2.538mm and a standard deviation, σ of 1.202mm.
Length of Internal Corrosion DefectsIn general it can be assumed that the length is governed by the length of thehold-up and can be assumed to remain constant with time.A Lognormal distribution with mean, µ , equal to 6 inches and a coefficient ofvariation of 25% was considered to be an appropriate prior distribution.
Prior Failure probabilitiesTables 2 and 3 show the probabilities of failure, during the year 2004, due toexternal and internal corrosion respectivelyFigures 1 and 2 show the leak, rupture and total prior failure probability due toexternal corrosion between 2004 and 2020.Figure 3 and 4 show the leak, rupture and total prior failure probability due tointernal corrosion between 2004 and 2020.For both external and internal corrosion, based on Advantica’s experience ofconducting similar studies on onshore pipelines, these prior failure probabilitiesare considered to be unacceptable.The information gathered from the indirect assessments, d i r e c tmeasurements and hydraulic modeling was therefore necessary to justifycontinued safe operation of these pipeline segmentsThe following sections summarize the findings of data gathering exercises and ademonstration of the updating of the failure probabilities is given subsequently.
INDIRECT EXAMINATIONSSeveral above ground survey techniques were adopted including pipeline currentmapper and soil resistivity measurements. However, in the interests of brevityonly the effects of of CIS and DCVG are reported here.
Close Interval Survey(CIS)
The CIS was performed over the entire 8-mile segment. To facilitate this survey,a total of 4 current interrupters were installed.
The criteria used to rank the effectiveness of the of the CP system is:
Type I – ON & OFF potentials >–850mv (i.e. more positive): Probable ActiveCorrosionType II – ON < -850mv, OFF > -850mv: Possible Active CorrosionType III – ON & OFF < -850mv: Probable Inactive Corrosion
The main findings from the survey, are summarized as:
First Segment – Predominantly Type II indications, with the exception of a smallarea, where Type I conditions exist.
Second Segment – Type III indications only.
Direct Current Voltage Gradient
Based on the results from the correlated CIS and PCM surveys, approximately 4miles were surveyed using DCVG.
The survey produced 189 indications, summarized as:• 5 (indications) >35%IR• 56 15 – 35%IR• 128 <15%IR
Hydraulic Modelling
An internally developed pipeline simulation program called Netflo was used forhydraulic modelling. The modeling addressed the condensation of water fromnominally dry gas and the transportation of wet gas from well inlets.
Netflo uses values of physical and inlet parameters to predict flow patterns andwater accumulation.
The following pipeline physical parameters were used :
• Pressure – 600 psig• Temperature – 65oF• Low flow rate – 17 mmscfd• Normal flow rate – 31 mmscfd• High flow rate – 60 mmscfd
The topography of the pipeline was derived from a GPS survey. Essentially, theGPS co-ordinates and elevation were converted into a topographic profile for usewithin Netflo.
Heat transfer coefficients were derived from the burial depth of the pipeline usingthe equation:
=
−
DHD
kh soilsoil 2cosh
21
Where: hsoil = heat transfer coefficient due to burial
Ksoil = thermal conductivity of soilD = outside diameter of buried pipeH = distance between top of soil and centre of pipe
A thermal conductivity of 0.75 W/mK was used for the soil. This would be typicalof moist clay. A winter ambient air temperature of 43oF was used for themodeling to reflect a severe case for water condensation.
The hydraulic modelling indicated that there were numerous locations within thepipeline segment where the condensed water from nominally dry gas couldaccumulate at the flow rates used. From an internal corrosion perspective themost important accumulation sites are those closest to the inlets and these wereidentified.The two pipeline segments contains a number of tap points where potentially wetgas from wells entered the line. The hydraulic modelling thus identified the firstaccumulation points downstream of well inlets.
DIRECT EXAMINATIONS ECDAECDAFrom an assessment of the results from stage 2, the severities of the indicationswere classified in order to prioritize which indications should be excavated forfurther analysis. The indications can be summarized as follows:
• 26 Anomalies - Type II & Minor• 102 Anomalies - Type III & Minor• 9 Anomalies - Type II & Moderate• 47 Anomalies - Type III & Moderate• 5 Anomalies - Type III & Severe
A total of 9 sites were selected for direct examination. An additional 5excavations were also performed at locations where there were no indications ofcoating anomalies from the above ground surveys. This was carried out todetermine both the accuracy and reliability of the survey techniques.
ICDAA number of sites (see Table 4) were selected for excavation, based on theresults of the hydraulic modelling. Inspection at each of these sites wasundertaken using a guided wave ultrasonic tool (GUL).No significant internal corrosion was found at any of the excavation sites
POST ASSESSMENT
Updating Expected Number of Coating Defects SitesFor DCVG, prior values of the probability of detection and probability of falseindication were assumed to be 0.9 and 0.1, respectively.
The number of DCVG indications, DCVGN , found was 204.
Following the survey, 9 excavations were undertaken at sites where the DCVGsurvey indicated coating defects and 5 excavations were undertaken at siteswhere the DCVG survey did not indicate coating defects. The methodologydescribed in [8] was used with this information to update the probability ofdetection, the probability of false indications and subsequently the expectednumber of coating damage sites.Coating damage was found at each of the 9 sites at which damage wasexpected; based on Bayesian updating, this observation reduced the value of PfIfrom 0.1 to 0.082.No coating defects were found at the 5 sites at which damage was not expected;based on Bayesian updating, this observation increased the value of the PoDfrom 0.9 to 0.91
Based on the above value of DCVGN and the updated values of PfI and PoD, theexpected number of coating damage sites per mile increased from 11.88 to18.78.
Updating Expected Number of Active External Corrosion Sites,Assuming 1% that active corrosion is present at 1% of the sites at which coatingdamage is present, the expected frequency of occurrence of sites having activecorrosion is 0.1878 per mile.For CIS, prior values of the probability of detection and probability of falseindication were assumed to be 0.88 and 0.1, respectivelySince there were no active corrosion sites indicated, the probability of falseindication cannot be updated.No active corrosion was found at any of the 14 excavation sites at which activecorrosion was not expected; base on Bayesian updating, this observationincreased the probability of detection from 0.88 to 0.89.Using this outcome, the expected number of active corrosion sites per milechanges from 0.1878 to 0.176.
Updating External Corrosion Defect Depth DistributionThe measurements of defect depth size made at the sites of bell-holeexcavations, allows an updating of the defect depth distribution ),( Tap to beundertaken, where T is the time of the excavation relative to some referencetime. Using Bayesian updating techniques, this resulted in an expected value ofβ of 0.0020 inches, compared to a prior value of 0.268 inches.
It is immediately apparent that the updating has a significant effect on the priordistribution. The mean value of the prior distribution is 0.237 inches and themean value of the updated distribution is 0.0018 inches. This highlights theconservatism of the initial assumption. It should be noted that the mean value ofthe observed data is 0.0016 inches. It can readily be deduced that if one furtherexcavation were to be undertaken then it would need to have a depth in excessof 2.4 inches in order to increase the observed mean to the prior value of themean. Based on the current distribution, such a defect is incredible. On thecontrary more excavations will reduce the mean value still further, since thisdistribution is slightly more onerous than the observed data. It thus follows thatprovided acceptable failure probabilities are obtained based on the existingdistribution, no further excavations are necessary.
Updating External Corrosion Defect Length DistributionThe measurements of defect length size at the sites of bell-hole excavations,allows an updating of the defect length distribution. Using Bayesian updatingtechniques, this resulted in an expected value of β of 0.77 inches, compared toa prior value of 5.12 inches.It is immediately apparent that the updating has a significant effect on the priordistribution. The mean value of the prior distribution is 5.5 inches and the meanvalue of the updated distribution is 0.82 inches. This highlights the conservatismof the initial assumption. It should also be noted that the mean value of theobserved data is 0.56 inches. It can be readily deduced that if one furtherexcavation were to be undertaken then it would need to have a length in excessof 54 inches in order to increase the observed mean to the prior mean. Based onthe current distribution the likelihood of such a defect is incredible. On thecontrary more excavations are likely to reduce the mean value of the updateddistribution, since this is more onerous than the observed data. It thus followsthat provided acceptable failure probabilities are obtained based on the existingprior, no further excavations are necessary.
Updating Internal Corrosion Defect Depth DistributionThe measurements of defect depth size for internal indications at the calibrationdig sites, allows an updating of the distribution of days on which the temperatureis below 27oF.
Using Bayes Theorem, the posterior distribution of ET can be obtained using
∫∞
=
0
)()|(
)()|()|(
EEEob
EEobobE
dTTpTap
TpTapaTp
where the prior distribution )( ETp represented is by a Lognormal distribution withmean,
ETµ , equal to 27 days and a standard deviation,
ETσ , of 13 days (see
above).
Using the results of the calibration digs, resulted in an updated mean value ET
µ of1.39 days.This information allows us to update our view on the defect depth distribution.The updated distribution is Lognormal with mean, µ , equal to 0.126mm and astandard deviation, σ , equal to 0.002mm. These compare with prior values of2.538mm and 1.202mm, respectively.
Updating Internal Corrosion Defect Length Distribution
Using the results of the excavations, this gives an expected value of µ of 0.49inches, compared to a prior value of 6 inches
Updated Probability of FailureSRA was used to determine the probabilities of failure based on the updateddistributions.The updated failure probabilities in the year 2004 for external corrosion areshown in Table 5. When compared with the prior failure probabilities in Table 2, itis immediately obvious that using the information gathered from the aboveground surveys and the excavations, the probability of failure due to externalcorrosion is reduced to negligible values. Immediately following updating it is thusappropriate to state that the failure due to external corrosion in 2004 is incredible.Figures 5 and 6 show the effect that the updating has on the probability of failuredue to external corrosion in the period from 2004 to 2020. The markedimprovement for ‘earlier years is clearly visible. Furthermore, it is seen that thetotal probability of failure due to external corrosion remains acceptably low untilaround 2015. The implications of this outcome are that it is not strictly necessaryto undertake a further assessment for a period of about 10 years.Moreover, if the probability of a rupture alone is considered, (more severeconsequences) it is noted that the probability remains acceptable for the whole ofthe time period considered.When considering the above outcome, it is worth noting that if a hydrostatic testor an in-line inspection are the adopted mitigation measures, CFR Parts 192 &195 requires these to be undertaken every 5 years unless a reliable engineeringjustification can be made to extend this period.Based on the above the ECDA methodology has demonstrated that the overallprobability of failure due to external corrosion remains negligible for around 11years and more significantly that the probability of a rupture occurring remains
acceptable low until after 2020. The implications of this outcome are that it wouldbe prudent to undertake a further assessment in about 11 years time. As aninitial ‘benchmark’, it is worth noting that if hydrostatic or in-line inspection are theadopted mitigation measures, CFR Parts 192 & 195 requires these to beundertaken every 5 years unless a reliable engineering justification can be madeto extend this period.The updated failure probabilities in the year 2004 for internal corrosion are shownin Table 6. When compared with the prior failure probabilities in Table 3, it isimmediately obvious that using the information gathered from the indirectexamination and the excavations, the probability of failure due to internalcorrosion is reduced to negligible values. Immediately following updating it is thusappropriate to state that the failure due to internal corrosion in 2004 is incredible.When the updated failure probability for internal corrosion is calculated in thetime period 2004 to 2020 it is found that using the ICDA methodology, thelikelihood of failure is incredible.
CONCLUSIONSA rigorous methodology for determining the integrity of pipeline systems usingExternal and Internal Corrosion Direct Assessment techniques based onStructural Reliability Analysis and Bayesian Updating has been described.The application of the technique to a North American pipeline system has beendescribed in detail.External CorrosionThe results of the pre-assessment showed that the prior failure probabilities wereunacceptable and identified a requirement for a number of above ground surveysto be conducted during the indirect Inspection stage, including, Pipeline CurrentMapper, Close Interval Survey and Direct Current Voltage Gradient.Based on a consideration of the results of the indirect inspection stage, 9 siteswere identified for excavations during the direct examination stage.During the direct examination stage no locations of active corrosion weredetected.The results obtained from indirect inspections and direct examination were usedto update the prior failure probabilities. The updated probabilities were found tobe significantly lower than the prior probabilities.Based on a consideration of the results it was concluded that no furtherexcavations were necessary and that the ECDA study would be necessary for atleast a further 11 years.
Internal Corrosion
The results of the pre-assessment showed that the prior failure probabilities wereunacceptable and identified a requirement for Advantica to use the NetFlosoftware to highlight excavation sites.During the indirect inspection stage, a total of 9 hold-ups were indicated.During the direct examination stage, no locations of active internal corrosion orinactive internal corrosion were detected.The results obtained from the indirect inspections and direct examination wereused to update the prior failure probabilities. The updated probabilities werefound to be significantly lower than the prior probabilities and indicated that thelikelihood of failure due to internal corrosion is incredible.The objective of the ICDA study was to assure the integrity of the pipeline bydetermining sites where internal corrosion could occur, inspecting these areasand using the results to assess whether internal corrosion was a credible threatto pipeline integrity.
No significant internal corrosion was discovered in any of the sites inspected.The ICDA concept is that inspection at the sites where water would firstaccumulate gives implies information about the rest of the pipeline. If these siteshave not corroded then other locations that have a lower probability ofaccumulating water should also be free of corrosion. Therefore, the lack ofcorrosion in the sites inspected implies that the pipeline should be essentiallyfree of internal corrosion that would threaten its integrity.The secondary implication is that the pipeline inlet gas has been effectively dryover the history of the pipeline. If wet gas had entered the pipeline then corrosionwould have been found at some of the excavation sites.
REFERENCES
1. NACE Recommended Practice RP0502-2002, Pipeline External CorrosionDirect Assessment.
2. Francis, A., Edwards, A.M., Espiner, R.J., & Senior, G., “Applying StructuralReliability Methods to Ageing Pipelines”, Paper C571/011/99, IMechEConference on Ageing Pipelines, Newcastle, UK, October 1999
3. Francis, A, Edwards, A.M. & Espiner, R.J., “A Fundamental Consideration ofthe Deterioration Processes Affecting Offshore Pipelines using StructuralReliability Analysis”, Paper OMAE00-5042, ETCE/OMAE 2000 Joint Conference,New Orleans, USA, February 2000
4. Edwards, A.M., “The application of Structural Reliability Analysis TowardsDeveloping Pipeline Integrity Management Programs”, AGA OperationsConference, May 7-9, 2000, Denver Colorado
5. Francis, A., Edwards, A.M., Espiner, R.J., & Senior, G., “An AssessmentProcedure to Justify Operation of Gas Transmission Pipelines at Design Factorsup to 0.8”, Paper PIPE90, Pipeline Technology Conference, Brugge, Belgium,May 2000.
6. Francis, A., Espiner, R.J., Edwards, A.M. & Hay, R.J., ‘A Consideration of DataRequirements for Structural Reliability Based Assessments of Onshore Pipelines’5th International Conference on Engineering Structural Integrity Assessment,Churchill College, Cambridge, UK September 2000
7. Francis, A., McCallum, M., Gardiner, M. & Michie, R., ‘A FundamentalInvestigation of the Effects of The Hydrostatic Pressure Test on the StructuralIntegrity of Pipelines using Structural Reliability Analysis’, 20th InternationalConference on Offshore Mechanics and Artic Engineering, Rio de Janeiro, Brazil,June 2001.8. Francis, A., Gardiner, M., Goodfellow, A., McCallum, M, Senior, G. &Greenwood, B, ‘A Systematic Risk and Reliability-Based Approach to IntegrityManagement of Piggable and Non-Piggable Pipelines’, Pipeline Integrity andSafety Conference, Houston, Texas, September 2001.’
