pipeline integrity

*Topics CoveredPipeline Integrity ConceptPurpose of Pipeline Integrity ProgramsDifference between Natural Gas and Hazardous Liquid Pipelines - RegulationsThreats to Pipeline IntegrityRisk Assessment IssuesDirect Assessment - ECDA

*Pipeline Integrity AssessmentPipeline Integrity Assessment is a process which includes inspection of pipeline facilities, evaluating the indications resulting from the inspections, examining the pipe using a variety of techniques, evaluating the results of the examination, and characterizing the evaluation by defect type and severity and determining the resulting integrity of the pipeline through analysis

*Purpose of Pipeline Integrity ProgramsThe U.S. Department of Transportation (OPS) is proposing to change pipeline safety regulations to require operators of certain pipelines to validate the integrity of their pipelines in high consequence areas

*Regulations Related to Liquid Pipelines49 CFR Part 195 Pipeline Integrity Management in High Consequence areasCovered pipelines are categorized as follows:Category 1: pipelines existing on May 29, 2001 that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipelinesCategory 2: pipelines existing on May 29, 2001 that were owned or operated by an operator who owned or operated less than 500 or more miles of pipelinesCategory 3: pipelines constructed after May 29, 2001

*Programs and Practices to Manage Pipeline Integrity in Liquid PipelinesDevelop a written management program that addresses the risks on each segment of pipeline Category 1: March 31, 2002Category 2: February 18, 2003Category 3: 1 year after the pipeline begins operation

*Programs and Practices to Manage Pipeline Integrity in Liquid PipelinesInclude in the program an identification of each pipeline not later than:Category 1: December 31, 2001Category 2: November 18, 2002Category 3: date the pipeline begins operation

*Programs and Practices to Manage Pipeline Integrity in Liquid PipelinesInclude in the program a plan to carry out baseline assessments of the line pipe and this should include:1.The methods selected to assess the integrity of the pipeline by any of the following methods:Internal Inspection Tool ILIPressure testOther technology that the operator demonstrates can provide an equivalent understanding of the line pipe (notification to OPS must take place 90 days before conducting the assessment)

*Programs and Practices to Manage Pipeline Integrity in Liquid PipelinesA schedule for completing the integrity assessmentAn explanation of the assessment method selected and evaluation of risk factors considered in establishing the assessment scheduleComplete assessment, prior assessment and newly-identified areas deadlines have been set DA was completed after the liquid gas rule was ready

*Regulations Related to Gas Pipelines

*Regulatory IssuesDepartment of Transportation proposed rule (49 CFR Part 192) dated January 28, 2003 titled Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)

*Federal Regulation

*Regulatory IssuesThis proposed rule will satisfy Congressional mandates for RSPA/OPS to prescribe standards that establish criteria for identifying each gas pipeline facility located in a HCA and to prescribe standards requiring the periodic inspection of pipelines located in these areas

*Regulatory IssuesPipeline Integrity can be best assured by requiring each operator to:Implement a comprehensive IMPConduct a baseline assessment and periodic reassessments focused on identifying and characterizing applicable threatsMitigate significant defects discovered in this processMonitor the effectiveness of their programs so appropriate modifications can be recognized and implemented

*Regulatory IssuesAssessment MethodsInternal Inspection ILIPressure TestingDirect Assessment (data gathering, indirect examination, and post assessment evaluation)Any other method that can provide an equivalent understanding of the condition of line pipe

*Regulatory IssuesThe rule proposes to allow direct assessment as a supplemental assessment method on:Any covered pipeline sectionAs a primary assessment method on a covered pipeline where ILI and pressure testing are not possible or economically feasibleWhere the pipeline operates at low stressCan also be used to evaluate third party damage

*Regulatory IssuesAll three threats considered under direct assessment:External CorrosionInternal CorrosionSCC

*Regulatory IssuesAnother concept in the proposed rule is to use Confirmatory Direct Assessment to evaluate a segment for the presence of corrosion and third party damage

*Trade Group Associations On August 6, 2002, OPS issued a final rule on the definition of a high consequence area (HCA). Then on January 28, 2003, OPS issued a notice of proposed rulemaking regarding integrity management for natural gas transmission pipelines in high consequence areas (HCAs). AGA, along APGA and INGAA, have made significant strides in getting OPS to change their concepts initially reflected in these rulemakings. While a final rule for integrity management is not expected until later this year, operators of natural gas transmission lines are already faced with integrity requirements under the Pipeline Safety Improvement Act of 2002.

*ASME B31.8SManaging System Integrity of Gas PipelinesSpecifically design to provide the operator with the information necessary to develop and implement an effective integrity management programAppendix B Direct Assessment process

*Proposed IM Rule for Gas Transmission High Consequence AreasOperator Requirements for ComplianceRisk AssessmentIntegrity Assessment Methods for HCAsTime FramesResponding to Integrity Issues in HCAsRe-Assessments of HCAs

*High Consequence Areas (HCAS)IM Ruling Only Applies to HCAsOperator Must Identify All HCAsProposed Ruling Defines how to Identify HCAsMethod Revised Once and Could be Again Overly ComplicatedOne Year from Final Rule to Complete Task

*High Consequence Areas (HCAS)Class 3 or 4 Locations are HCAsSub-divided into High & Moderate Impact Zones using the Potential Impact Circle (PIC)Moderate is Outside an PICPIC has a Threshold Radius (TR) Based on a Calculated Potential Impact Radius (PIR).PIC Radius = 0.69*Dia*SQRT of PressureTR Extends for Certain Conditions

*High Consequence Areas (HCAS)Class 1 or 2 Locations - HCAs are Determined DifferentlyA corridor of 1000 ft (or larger) is used for a Cluster of 20+ Buildings Intended for PeopleCorridors of 300ft, 660 ft or 1000ft depending on Dia & Pressure used for Identified Sites.Identified Sites are Buildings or Outside Areas with Specific Definitions

*Operator Requirements for ComplianceWritten Program - Complete within 12 MonthsMust follow ASME B31.8S for ImplementationPrescriptive or Performance based OptionsRisk Analysis Required To Identify Threats & Rank HCAsMust have a Baseline PlanPlan Must Address the Identified Integrity ThreatsMust Justify Integrity Assessment Method(s)

*Operator Requirements for ComplianceMust Complete Assessments within Certain Time PeriodsMust Address Discovered Integrity IssuesMust Re-assess Everything on a Continual BasisOne or more HCAs Plan and Implementation RequiredMust Evaluate Plan PerformanceImplement Preventative & Mitigation MeasuresHave a QA and Communication ProcessKeep Records

*Risk AssessmentMust Conduct Based on ASME B31.8SPrescription or Performance BasedPerformance Based has to be RigorousBenefits of Performance Based Assessment areDeviate from the Prescriptive Rules in ASME B31.8SLonger Re-inspection IntervalsLonger Remediation TimescalesCan Use Direct Assessment Only (for Corrosion Caused Metal Loss and SCC)Risk Assessment Must be used for Prioritizing Integrity Assessments

*Integrity Assessment Methods for HCAsIn-Line Inspection (Internal inspection)Pressure TestDirect AssessmentECDAICDASCCDAConfirmatory Direct AssessmentOther Technology 180 Day Notification RequiredIf Used Requires a Specific Implementation Plan

*Integrity Assessment Methods for HCAsSpecial Rules Apply For Specific Threats e.g.Third Party DamageCyclic FatigueManufacturing or Construction DefectsLow Frequency ERW Pipe or Lap Welded PipeCorrosion Caused Metal Loss

*Integrity Threat ClassificationGas Pipeline incidents data has been analyzed and classified by the Pipeline Research Committee International (PRCI) into 22 root causes. One of the 22 causes was reported by operators by unknown (no rot cause or causes were identified. The remaining 21 threats have been grouped into (9) categories of related failure types

*Integrity Threat Classification A) Time DependentExternal CorrosionInternal corrosionStress Corrosion Cracking

*Integrity Threat ClassificationB) StableManufacturing Related DefectsDefective pipe seamDefective pipeWelding/Fabrication RelatedDefective pipe girth weldDefective fabrication weldWrinkle bend or buckleStripped threats/broken pipe/coupling failure

*Integrity Threat ClassificationEquipmentGasket O-ring failureControl/Relief equipment malfunctionSeal/pump packing failureMiscellaneous

*Integrity Threat ClassificationC) Time IndependentThird Party/Mechanical DamageIncorrect OperationsWeather related and outside forceCold weatherLightningHeavy rains or floodsEarth movements

*Time FramesInternal Inspection or Pressure TestStart with the Highest Risk HCAAll HCAs 100% Complete by December 2012Complete 50% of HCAs Based on Risk by December 2007Except for Class 3 or 4 Locations of Moderate Impact 100% Complete by December 2015

*Time FramesDirect AssessmentStart with the Highest Risk HCAAll HCAs Complete by December 2009Complete 50% of All HCAs Based on Risk by December 2006Except for Class 3 or 4 Locations of Moderate Impact 100% Complete by December 2012

*Responding to Integrity Issues in HCAsDiscovery of a Condition in an HCA 180 Days to Determine Threat to Integrity Except forImmediate Remediation ConditionsPredicted Failure Pressure < 1.1 x Established MOP at LocationAny Dent with a Stress Raiser Regardless of Size or OrientationAn Anomaly that Requires Immediate ActionMust Reduce Operating Pressure to a Safe LevelMust Follow ASME B31.8S, Section 7

*Responding to Integrity Issues in HCAs180 Day Remediation ConditionsPlain Dents > 6% of OD Regardless of OrientationPlain Dents > 2% of OD Affecting a Girth Weld or Seam WeldLonger Than 180 Day Remediation ConditionsOnly If Anomaly Cannot Grow to a Critical StageOnly If Internal Inspection used An Anomaly with a Predicted Failure Pressure > 1.1 x Established MOP at LocationAny Anomalous Condition Not Covered Above

*Re-Assessments of HCAsAs Frequently as Needed Operator DecidesBut No Longer Than 7 Years Unless A Confirmatory Direct Assessment is Carried OutVery Specific Rules ApplyOnly Available with Performance PlanInternal Inspection or Pressure Test - Maximum Periods are10 Years - Equal to or Greater Than 50% SMYS15 Years Equal to or Less Than 50% SMYSMaximum Periods must be Justifiable

*Re-Assessments of HCAsDirect Assessment Maximum Periods are5 Years for Remediation by Sampling10 Years for Remediation of All Anomalies

*Data GatheringIdentify Company Data Sources for IMP DevelopmentEvaluate Records and Procedures forPipeline Design and ConstructionPipeline OperationPipeline MaintenanceService HistoryPrior Integrity AssessmentsEvaluate systems already in place database, risk assessment, etc.Document Results

*HCA Identification Impact AssessmentApply Final Rule Definitions of HCAs to System to:Identify HCA Locations and ClassifyDetermine Potential Impact ZonesJustify Non-HCA LocationsDocument Results

*Threat Identification, Data Integration and Risk AssessmentReview Data from Phases 1 and 2 for HCA LocationsIdentify Threats Specific to HCAs, Identify Threats Specific to Non-HCAs,Justify Non-Applicable ThreatsCarry Out a Risk Assessment on HCA Segments to Determine:Likelihood of Failure, andConsequences of FailureDocument ResultsSpreadsheet Model or Vendor Software

*Develop BaselineAssessment PlanDecide on Integrity Assessment Method(s):In-Line InspectionPressure TestingDirect AssessmentMethod(s) Depend on:Nature of Identified ThreatsNumber and Location of HCAsCost Benefit ConsiderationsTechnically PossibleDevelop Plan(s) and ScheduleDocument Results

*Integrity Management ProgramA Typical IMP will have Sections:Threat Identification, Data Integration & Risk Assessment Current Results & JustificationsBaseline Assessment Plan for Line Pipe in HCAs Justification for Chosen Method(s), Direct Assessment Plan if Required, and Implementation TimescaleIntegrity Management of Facilities Other than Line Pipe in HCAs (May Not be Applicable)Process for Conducting Integrity Assessments Satisfies Requirement for Minimizing Safety and Environmental Risks

*Integrity Management ProgramA Typical IMP should also include:Review of Integrity Assessments Results by Qualified PersonnelCriteria for Remedial Action of Line Pipe in HCAs and Non-HCAsProcedure for Identifying Preventative & Mitigation Measures to Protect HCAsIntegrity Program Performance MeasuresProcedure for Continual Evaluation & Assessment of Pipeline Integrity in HCAs Including a Confirmatory Direct Assessment Plan if RequiredQuality Control Process

*Integrity Management ProgramA Typical IMP should also have a Communications PlanManagement of ChangeIntegrity Management Program Review ProcedureRecord KeepingRequired Notifications to the Office of Pipeline SafetyPersonnel Training

*Direct Assessment

*History of Direct AssessmentOriginally Proposed during Development of Congressional Bills on Pipeline SafetyProposed as an Alternative to ILI and Hydrostatic TestingTermed Direct Examination (Later Changed to Direct Assessment )INGAA Initiative to Develop Framework of ECDA Process (ICDA Followed)

*DA BackgroundIntegrity verification for high consequence areasIn-line inspectionHydrostatic testingDirect assessmentEach tool achieves comparable results and complementary resultsTools are selected based on operating conditionsAll tools are routinely used now

*Regulations and StandardsLiquid Rule 49 CFR 195 (Jan. 2002)API Standard 1160 (Nov. 2001)NPRM Gas Rule 49 CFR Part 192 (Jan. 2003)ASME B31.8S (Dec. 2001)NACE ECDA Standard RP0502-2002(2002)Pipeline External Corrosion Direct Assessment Methodology

*Regulations and Standards (Contd)Proposed NACE ICDA Standard TG 041(2003)Pipeline Internal Corrosion Direct Assessment MethodologyNACE SCC DA Standard TG 273 (In Progress)Pipeline SCC Direct Assessment Methodology

*Liquid Rule 49 CFR 195Acceptable Integrity Assessment Methods:Internal inspection tool or tools capable of detecting corrosion and deformation anomaliesPressure testingOther technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe.OPS notification required 90 days before assessment

*API Standard 1160Managing System Integrityfor Hazardous Liquid PipelinesAcceptable Integrity Assessment Methods:In-line inspection technologyHydrostatic Testing

*NPRM Gas Rule - 49 CFR Part 192Acceptable Integrity Assessment Methods:Internal inspection tool or tools capable of detecting corrosion and deformation anomalies as appropriatePressure testingDirected assessment method for external corrosion threats, internal corrosion threats, stress corrosion, and third party damage (if other assessment methods are not feasible)Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe.OPS notification required 180 days before assessment

*Supplement to ASME B31.8Managing System Integrity of Gas Pipelines

Acceptable Integrity Assessment Methods:(Dependent on integrity threats)In-line InspectionPressure TestingDirect AssessmentECDAICDAOther methodologies

*NACE Recommended PracticesNACE ECDA Standard RP0502-2002(2002)Pipeline External Corrosion Direct Assessment Methodology

Proposed NACE ICDA Standard TG 041(2003)Pipeline Internal Corrosion Direct Assessment Methodology

NACE SCC DA Standard TG 273 (In Progress)Pipeline SCC Direct Assessment Methodology

*What is Direct AssessmentA method of assessing pipeline integrity.Intended to be no less protective of public safety and environment than ILI or Hydrotest.

From direct examination.Bell hole inspections.

*Direct Assessment ProcessUtilize existing technologies in an integrated approach intended to map corrosion defectsUtilize prediction modeling to determine like and similarUse results to safely manage the pipeline system

*Direct Assessment ConceptTechnologies can be used as a diagnostic tool to assess pipeline integrity

Defect growth models can be used to determine safe operating conditions and to determine re-assessment or inspection frequency

*ECDA TechnologiesExisting technologiesTest station surveysClose-interval surveys (CIS)DC voltage gradientElectromagnetic inspectionBuried CouponsSoil ResistivityPreviously used as stand-alone assessmentsIntegration of data results in a predictive integrity model

*ApplicabilityExternal corrosion integrity verification for pipelines that cannot be inspected by ILI or pressure testCondition monitoring of pipelines inspected by ILI or pressure testedHave been inspected with other techniques as a means of establishing reassessment intervalsHave not been inspected by other means when future corrosion monitoring is of primary interestNot applicable to all pipelines

*Four Step ECDA ProcessPre-assessmentAssembly and review of pipeline dataIndirect examinationAbove-ground survey toolsDirect examinationExcavation, inspection, defect assessmentPost-assessmentValidation, prioritize repairs, re-inspection

*

Intervals

ReAssessment

Define

Intervals

Repair

Define

Validation Dig

(to be used in each DA region)

Post Assessment

Defects

Life of Remaining

-

Calculate Half

Examinations

From Direct

OK

More Digs

Done

Intervals

ReAssessment

Define

Intervals

Repair

Define

Validation Dig


Post Assessment

Defects

Life of Remaining

-

Calculate Half

Examinations

From Direct

OK

More Digs

Done

Intervals

ReAssessment

Define

Intervals

Repair

Define

Validation Dig

Examination

Further

Characterize

with Indirect

Exams

Primary

Examinations

Coating

Faults?

Secondary

Examinations

New Coating

Faults?

Select Areas for

Complementary

Examinations

Add Indirect

Techniques

Yes

No

No

Define DA

Regions,

Special

Concerns, and

Trouble Spots

Ensure DA

is

Applicable

Pipeline Data

Collection and

Review

ILI or

Pressure

Test

Indirect

Examinations

Select

Primary

and

Secondary

Tools

Pre

-

Assessment

Complementary

Technique Table

Data to

Support

Tool

Selection

Yes

No

Define DA

Regions,

Special

Concerns, and

Trouble Spots

Ensure DA

is

Applicable

Pipeline Data

Collection and

Review

ILI or

Pressure

Test

Indirect

Examinations

Select

Primary

and

Secondary

Tools

Pre

-

Assessment

Complementary

Technique Table

Data to

Support

Tool

Selection

Yes

No

Done

More Digs

OK

From Direct

Examinations

Calculate Half

-

Life of Remaining

Defects

Post Assessment


Prior

History

Estimate Maximum

Remaining Defect

Severity

Acceptable

Not

Acceptable

Post

-

Assessment

Direct Examinations


Confidence

Functions

Yes

Indirect

Examinations


from Pre

-

Assessment

Explain

through

digs

No

Yes

Direct

Examination

Further

Characterize

with Indirect

Exams

Primary

Examinations

Coating

Faults?

Secondary

Examinations

New Coating

Faults?

Select Areas for

Complementary

Examinations

Add Indirect

Techniques

Yes

No

No

Yes

Indirect

Examinations


from Pre

-

Assessment

Explain

through

digs

No

Yes

Direct

Estimate

Corrosion

Rates

Categorize and

Rank Coating Fault

Locations

Dig &

Measure

From Indirect

Exams

From Pre

-

Assessment

Prior

History

Estimate Maximum

Remaining Defect

Severity

Acceptable

Not

Acceptable

Post

-

Assessment

Direct Examinations


Confidence

Functions

Estimate

Corrosion

Rates

Categorize and

Rank Coating Fault

Locations

Dig &

Measure

From Indirect

Exams

From Pre

-

Assessment

Prior

History

*Pre-AssessmentData collectionECDA feasibility for pipelineIndirect inspection tool selectionECDA region identificationStep 1

*Pre-AssessmentData Collection (Table 1 of NACE Standard)Pipe relatedConstruction RelatedSoils/EnvironmentalCorrosion ProtectionPipeline OperationsStep 1

*Pre-AssessmentECDA feasibility AssessmentIndirect inspection tool feasibilityEstablish ECDA feasibility regionsDetermine which indirect methods are applicable to each regionStep 1

*What is a Region?Segment is a continuous length of pipeRegions are subsets of one segmentPipe with similar construction and environmental characteristicsSame survey toolsStep 1

*Where Might ECDA Not Be Applicable?As with all assessment tools, there are limitations to considerShielded coatingsRock ditchExtensive Pavement (Cost issue)Some CP configurationsExtensive Direct Connected AnodesStep 1

*Indirect ExaminationObjective: identify coating faults and areas where corrosion activity may have or may be occurringUtilizes a minimum of two complementary indirect techniques

Step 2

*Indirect TechniquesDirect CurrentMeasure structure potentialIdentify locations of high CP demand to small areaAlternating CurrentApply AC signalDetermine amount of current drain (i.e., grounding) and locationIdentify locations of high AC currentStep 2

*Indirect TechniquesDirect CurrentClose Interval Survey (CIS or CIPS)Direct Current Voltage Gradient (DCVG)Alternating CurrentACVG, Pearson SurveyAC Attenuation (PCM , EM , C-Scan)Step 2

*Indirect ExaminationObjective: identify coating faults and areas where corrosion activity may have or may be occurringUtilizes a minimum of two complementary indirect techniques

Step 2

*Direct ExaminationExcavate and collect data where corrosion most likelyCategorize indicationsImmediate action requiredScheduled action requiredSuitable for monitoringCharacterize coating and corrosion anomaliesEstablish corrosion severity for remaining strength analysisDetermine root-causeIn-process evaluation, re-categorization, guidelines on number of direct examinationsStep 3

*Number of Required DigsValidation ProcessTotal number of excavation depends on the results of the aboveground techniquesTypically 3-5/10 mile Section

Step 3

*Direct Examination DataCollect data at dig sitePipe to soil potentialsSoil resistivitySoil and water samplingUnder-film pHBacteriaPhotographic documentationStep 3

*Direct Examination DataCharacterize coating and corrosion anomaliesCoating conditionAdhesion, under film liquid, % bareCorrosion analysisCorrosion morphology classificationU/T mappingMPI analysis for SCCStep 3

*Direct ExaminationRemaining strength analysisASME B31GRSTRENGCorLASDnV RP-F10Step 3

*Direct ExaminationDetermine root-causeFor exampleLow CPInterferenceMICDisbonded coatingsStep 3

*Post AssessmentValidates ECDA ProcessProvides performance measures for integrity managementGrowth models are used to establish safe operationCorrosion Signature is developed and applied to entire segmentEstablishes reassessment intervalsStep 4

*Post AssessmentAssessment of ECDA EffectivenessComparison of ECDA indications with Control digsComparison of ILI to ECDA resultsRemaining Life CalculationsReassessment Intervals

*Post Assessment Assessment of ECDA EffectivenessComparison of ECDA Indications with Control Digs:ECDA 100% effective in locating areas where corrosion was taking place and where metal was exposedNo coating flaws and no corrosion was found at control digs

*Post AssessmentRemaining Life CalculationsNACE RP0502 Reassessment MethodologyThe establishment of the reassessment interval is based on establishing the remaining life of critical defects, establish a conservative growth rate, and utilize the following relationship:RL =C x SM (t/GR)

*Post AssessmentRemaining Life CalculationsWhen corrosion defects are found during the direct examinations, the maximum reassessment interval is calculated as one half the remaining life (RL).

*Post AssessmentRemaining Life CalculationsCC Technologies Reassessment Methodology is based on:Linear Polarization Resistance measurements are used to give instantaneous corrosion rates for each excavated site. The measured rate is a function of the soil characteristics and environment surrounding the pipe or segment being evaluated.

*Post AssessmentReassessment IntervalUsing the LPR technique, the maximum actual value obtained will be taken as the most conservative growth rate. The most significant external corrosion feature ILI indication that was field verified is then grown to 80% (Immediate action). Therefore the re-assessment interval will be less of this conservative value.

*ECDA Case Studies

*Survey Methodologies - Cathodic Protection LevelsClose-Interval SurveysMeasure pipe to soil potentials at close intervals to evaluate cathodic protection levelsLocate areas of active corrosionIdentify shorted casings, stray current interference, electrical shorts, CP shieldingInterrupt CP current to obtain polarized potentialsPipe to soil potentials measured at 5 foot intervals

*Survey MethodologiesCoating EvaluationsDCVG and ACVG:Locate and size holidays by measuring current flow in soil to pipeline coating holidaysInterrupt CP system using a fast cycle (DCVG)Use AC voltage signal applied to pipeline (ACVG)Measure potential difference between two electrodes

*Why These Survey Techniques?DCVG - Locate and size coating holidaysElectromagnetic - Evaluate overall coating condition on macro-levelSoil Resistivity - Soil corrosiveness at holiday locations to prioritize excavationsCIS - Determine CP levels at holiday sitesGPS - Pipe elevation for ICDA and pipeline mapping

*ECDA Site Selections

*Examples of Specific Anomalies Detected

* Coating Fault SiteCIS Showed a dip in potential-1.008v, -0.940v, -0.890v, -0.920vDCVG Showed Anomaly

*Corrosion Anomalies FoundIndirect techniques can detect areas of corrosion

*DiscoveriesThird party damageFiber optics lineDent and gougeValvesLeakingInhouse damage to pipeConcrete weights

*Third Party DamageLow CP potentials in CIS-0.840v (100mV of polarization)ACVG IndicationRequired Repair

*ECDA Site Selection

*ECDA Site SelectionFigure 15. E-9 628+40.5 holiday area. Figure 16. E-9 628+42.9 holiday area.

*ECDA Site Selection

*ECDA Site Selection PhotoFigure 24. E-11 Coating disbondment area. Figure 23. E-11 holiday as found.

*Challenges

*Distribution System Direct AssessmentMust rely on pipe exposure opportunitiesDevelop database of useful informationUtilize coupon technologies Utilize standard testing techniques

*Field Excavation Summary ReportImportant to establishing root cause of corrosionBuild databases on conditions contributing to corrosion and its mitigationDevelop risk-based predictive capability

*Availability of Trained PersonnelRequires experienced engineers and technicians for data collection and analysisRate limiting step is availability of trained personnelMinimum of 1 year of training for survey techniquesAn additional 6 months of training for recognition of quality dataA minimum of 3 years of analysis experience

*Information ManagementThere will be massive amounts of data from many systemsTimely processing is criticalUser friendly data management systems are keyOwner/Operator accessibility must be considered

*ProjectionsCost estimates to implement DA engineering on typical transmission system of 500 mile length with 10 anomalies/mileModel Development Cost Data review = $ 500/mileBase survey = $ 600/mileDiagnostic Survey = $200/anomaly = $2,000 Direct Examination = $500/anomaly = $5,000Modeling = $ 500/mileTotal Model Development Cost = $8,600/mileApplies to 50 miles = $430,000

*Projections (contd)Model Application CostData review = $ 500/mileBase survey = $ 600/mileDirect Examination = $500/anomaly = $2,500 (assumes 5 critical)Model Enhancement = $100/mileTotal Model Application Cost = $3,700/mileApplies to 450 miles = $1,660,000Total DA Engineering for 500 miles = $2.1 Million or $4,200/mile

*Discussion PointsECDA Process is generally underestimatedComplexityPre-Assessment RequirementsData managementDetails and accuracy can be overlookedTraining is an issueGenerally need a better understanding of dig measurements and data collection

*Discussion Points (contd)Need training on how to apply reassessment intervalsOthers?

*Lessons Learned To DateECDA is presently expensive but costs will decline with experienceFor some pipelines, other assessments will always be more cost effectiveAlignment of data is criticalECDA requires high attention to detailPre-assessment important

*SummaryFor liquid pipelines, the methods selected for the assessment of the pipeline integrity are: ILI, pressure test and other technology that the operator demonstrates can provide an equivalent understanding of the condition of the pipeline

*SummaryFor gas pipelines, the methods selected for the assessment of the pipeline integrity are: ILI, pressure test, direct assessment and other technology that the operator demonstrates can provide an equivalent understanding of the condition of the pipeline

*SummaryDirect assessment is based on the use and integration of existing technologiesDirect assessment will work if properly applied It will require data collection and management and a commitment to validation

*This document proposes to establish a rule to require operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact high consequence areas**This proposed rule will satisfy Congressional mandates for RSPA/OPS to prescribe standards that establish criteria for identifying each gas pipeline facility located in a HCA and to prescribe standards requiring the periodic inspection of pipelines located in these areas, including the circumstances under which an inspection can be conducted using an instrumented internal inspection device (smart pig) or an equally effective alternative inspection method.This proposed rule does not apply to gas gathering or to gas distribution lines*OPS believes it can be best assure pipeline integrity by requiring each operator to:Implement a comprehensive IMPConduct a baseline assessment and periodic reassessments focused on identifying and characterizing applicable threatsMitigate significant defects discovered in this processMonitor the effectiveness of their programs so appropriate modifications can be recognized and implementedThis approach also recognizes that improving integrity requires operators to gather and evaluate data on the performance trends resulting from their programs, and to make improvements and corrections based on this evaluation.*There are four acceptable assessment methods defined by this rule. They are: Internal Inspection (also known as in-line inspection, ILI and pig testing)Pressure testing;Direct assessment (a process that includes data gathering, indirect examination and/or analysis, direct examination, and post assessment evaluation; andAny other method that can provide an equivalent understanding of the condition of the line pipe.The rule indicates that because the primary function of internal inspection tools or pressure testing is to determine the condition the pipe is in, they determined that equivalent or greater safety can be provided by other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe.*The rule proposes to allow direct assessment as a supplemental assessment method on any covered pipeline segment and as a primary assessment method on covered pipeline where in-line inspection and pressure testing are not possible or economically feasible or where the pipeline operates at a low stress. None of the permitted assessment methods listed above is fully capable of characterizing all potential threats to pipeline integrity. Currently, direct assessment is only an acceptable inspection method for assessing external corrosion, internal corrosion and stress corrosion cracking. In addition, if no other assessment method is feasible, direct assessment may be used to evaluate third party damage. Operators choosing direct assessment technologies must undertake extra excavations and direct examinations during the period while direct assessment is being validated.*All three threats considered under direct assessment:External CorrosionInternal CorrosionSCCA NACE document has already been developed for ECDA. ICDA and SCC documents are in the process of revision and balloting.*This is a more streamlined assessment method that uses the steps involved in direct assessment to identify these significant threats to a pipelines integrity. RSPA/OPS is proposing that an operator use this method as an initial reassessment method within the required seven year reassessment interval, if the operator has, within the proposed limits, establish a longer reassessment interval for a particular segment. The follow up reassessment by pressure test, internal inspection or direct assessment would then be conducted at the established interval.**This standard was specifically designed to provide the operator with information necessary to develop and implement and effective integrity management program utilizing proven industry practices and processes.Appendix B provides information about the direct assessment process and specifies that direct assessment is one integrity assessment methodology that can be used within the integrity management program******Anomaly 6*

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