Pipeline Integrity Management

BASIC CONCEPTS BASIC CONCEPTS IN PIPELINE IN PIPELINE INTEGRITY INTEGRITY

MANAGEMENTMANAGEMENT

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Topics CoveredTopics Covered

Pipeline Integrity ConceptPipeline Integrity Concept Purpose of Pipeline Integrity ProgramsPurpose of Pipeline Integrity Programs Difference between Natural Gas and Difference between Natural Gas and

Hazardous Liquid Pipelines - Hazardous Liquid Pipelines - RegulationsRegulations

Threats to Pipeline IntegrityThreats to Pipeline Integrity Risk Assessment IssuesRisk Assessment Issues Direct Assessment - ECDADirect Assessment - ECDA

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Pipeline Integrity Pipeline Integrity AssessmentAssessment

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

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Purpose of Pipeline Purpose of Pipeline Integrity ProgramsIntegrity Programs

The U.S. Department of The U.S. Department of Transportation (OPS) is proposing to Transportation (OPS) is proposing to change pipeline safety regulations to change pipeline safety regulations to require operators of certain require operators of certain pipelines to validate the integrity of pipelines to validate the integrity of their pipelines in high consequence their pipelines in high consequence areasareas

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Regulations Related to Regulations Related to Liquid PipelinesLiquid Pipelines

49 CFR Part 195 “Pipeline Integrity 49 CFR Part 195 “Pipeline Integrity Management in High Consequence areas”Management in High Consequence areas”

Covered pipelines are categorized as follows:Covered pipelines are categorized as follows: Category 1: pipelines existing on May 29, 2001 Category 1: pipelines existing on May 29, 2001

that were owned or operated by an operator who that were owned or operated by an operator who owned or operated a total of 500 or more miles of owned or operated a total of 500 or more miles of pipelinespipelines

Category 2: pipelines existing on May 29, 2001 Category 2: pipelines existing on May 29, 2001 that were owned or operated by an operator who that were owned or operated by an operator who owned or operated less than 500 or more miles of owned or operated less than 500 or more miles of pipelinespipelines

Category 3: pipelines constructed after May 29, Category 3: pipelines constructed after May 29, 20012001

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Programs and Practices to Programs and Practices to Manage Pipeline Integrity Manage Pipeline Integrity

in Liquid Pipelinesin Liquid Pipelines Develop a written management Develop a written management

program that addresses the risks on program that addresses the risks on each segment of pipeline each segment of pipeline Category 1: March 31, 2002Category 1: March 31, 2002 Category 2: February 18, 2003Category 2: February 18, 2003 Category 3: 1 year after the pipeline Category 3: 1 year after the pipeline

begins operationbegins operation

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in Liquid Pipelinesin Liquid Pipelines Include in the program an Include in the program an

identification of each pipeline not identification of each pipeline not later than:later than: Category 1: December 31, 2001Category 1: December 31, 2001 Category 2: November 18, 2002Category 2: November 18, 2002 Category 3: date the pipeline begins Category 3: date the pipeline begins

operationoperation

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in Liquid Pipelinesin Liquid Pipelines Include in the program a plan to carry Include in the program a plan to carry

out baseline assessments of the line out baseline assessments of the line pipe and this should include:pipe and this should include:

1.1. The methods selected to assess the The methods selected to assess the integrity of the pipeline by any of the integrity of the pipeline by any of the following methods:following methods:

Internal Inspection Tool ILIInternal Inspection Tool ILI Pressure testPressure test Other technology that the operator demonstrates can Other technology that the operator demonstrates can

provide an equivalent understanding of the line pipe provide an equivalent understanding of the line pipe (notification to OPS must take place 90 days before (notification to OPS must take place 90 days before conducting the assessment)conducting the assessment)

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in Liquid Pipelinesin Liquid Pipelines2.2. A schedule for completing the integrity A schedule for completing the integrity

assessmentassessment

3.3. An explanation of the assessment method An explanation of the assessment method selected and evaluation of risk factors selected and evaluation of risk factors considered in establishing the assessment considered in establishing the assessment scheduleschedule

Complete assessment, prior assessment Complete assessment, prior assessment and newly-identified areas deadlines have and newly-identified areas deadlines have been set been set

DA was completed after the liquid gas DA was completed after the liquid gas rule was readyrule was ready

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Regulations Related to Gas Regulations Related to Gas PipelinesPipelines

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Regulatory IssuesRegulatory Issues

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

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Federal RegulationFederal Regulation

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

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Regulatory IssuesRegulatory Issues Pipeline Integrity can be best assured by Pipeline Integrity can be best assured by

requiring each operator to:requiring each operator to: Implement a comprehensive IMPImplement a comprehensive IMP Conduct a baseline assessment and periodic Conduct a baseline assessment and periodic

reassessments focused on identifying and reassessments focused on identifying and characterizing applicable threatscharacterizing applicable threats

Mitigate significant defects discovered in this Mitigate significant defects discovered in this processprocess

Monitor the effectiveness of their programs so Monitor the effectiveness of their programs so appropriate modifications can be recognized appropriate modifications can be recognized and implementedand implemented

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Assessment MethodsAssessment Methods Internal Inspection ILIInternal Inspection ILI Pressure TestingPressure Testing Direct Assessment (data gathering, Direct Assessment (data gathering,

indirect examination, and post indirect examination, and post assessment evaluation)assessment evaluation)

Any other method that can provide an Any other method that can provide an equivalent understanding of the equivalent understanding of the condition of line pipecondition of line pipe

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The rule proposes to allow direct The rule proposes to allow direct assessment as a supplemental assessment assessment as a supplemental assessment method on:method on: Any covered pipeline sectionAny covered pipeline section As a primary assessment method on a covered As a primary assessment method on a covered

pipeline where ILI and pressure testing are pipeline where ILI and pressure testing are not possible or economically feasiblenot possible or economically feasible

Where the pipeline operates at low stressWhere the pipeline operates at low stress Can also be used to evaluate third party Can also be used to evaluate third party

damagedamage

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All three threats considered under All three threats considered under direct assessment:direct assessment: External CorrosionExternal Corrosion Internal CorrosionInternal Corrosion SCCSCC

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

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Trade Group Trade Group Associations Associations

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

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ASME B31.8SASME B31.8S

Managing System Integrity of Gas Managing System Integrity of Gas PipelinesPipelines

Specifically design to provide the Specifically design to provide the operator with the information operator with the information necessary to develop and implement necessary to develop and implement an effective integrity management an effective integrity management programprogram

Appendix B – Direct Assessment Appendix B – Direct Assessment processprocess

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Proposed IM Rule for Proposed IM Rule for Gas Transmission Gas Transmission

High Consequence AreasHigh Consequence Areas Operator Requirements for ComplianceOperator Requirements for Compliance Risk AssessmentRisk Assessment Integrity Assessment Methods for HCA’sIntegrity Assessment Methods for HCA’s Time FramesTime Frames Responding to Integrity Issues in HCA’sResponding to Integrity Issues in HCA’s Re-Assessments of HCA’sRe-Assessments of HCA’s

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High Consequence Areas High Consequence Areas (HCA’S)(HCA’S)

IM Ruling Only Applies to HCA’sIM Ruling Only Applies to HCA’s Operator Must Identify All HCA’sOperator Must Identify All HCA’s Proposed Ruling Defines how to Proposed Ruling Defines how to

Identify HCA’sIdentify HCA’s Method Revised Once and Could be Method Revised Once and Could be

Again – Overly ComplicatedAgain – Overly Complicated One Year from Final Rule to One Year from Final Rule to

Complete TaskComplete Task

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Class 3 or 4 Locations are HCA’sClass 3 or 4 Locations are HCA’s Sub-divided into High & Moderate Impact Sub-divided into High & Moderate Impact

Zones using the Potential Impact Circle Zones using the Potential Impact Circle (PIC)(PIC)

Moderate is Outside an PICModerate is Outside an PIC PIC has a Threshold Radius (TR) Based on PIC has a Threshold Radius (TR) Based on

a Calculated Potential Impact Radius (PIR).a Calculated Potential Impact Radius (PIR). PIC Radius = 0.69*Dia*SQRT of PressurePIC Radius = 0.69*Dia*SQRT of Pressure TR Extends for Certain ConditionsTR Extends for Certain Conditions

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Class 1 or 2 Locations - HCA’s are Class 1 or 2 Locations - HCA’s are Determined DifferentlyDetermined Differently

A corridor of 1000 ft (or larger) is used for A corridor of 1000 ft (or larger) is used for a Cluster of 20+ Buildings Intended for a Cluster of 20+ Buildings Intended for PeoplePeople

Corridors of 300ft, 660 ft or 1000ft Corridors of 300ft, 660 ft or 1000ft depending on Dia & Pressure used for depending on Dia & Pressure used for “Identified Sites”.“Identified Sites”.

Identified Sites are Buildings or Outside Identified Sites are Buildings or Outside Areas with Specific DefinitionsAreas with Specific Definitions

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Operator Requirements Operator Requirements for Compliancefor Compliance

Written Program - Complete within 12 MonthsWritten Program - Complete within 12 Months Must follow ASME B31.8S for ImplementationMust follow ASME B31.8S for Implementation Prescriptive or Performance based OptionsPrescriptive or Performance based Options Risk Analysis Required – To Identify Threats & Risk Analysis Required – To Identify Threats &

Rank HCA’sRank HCA’s Must have a Baseline PlanMust have a Baseline Plan Plan Must Address the Identified Integrity Plan Must Address the Identified Integrity

ThreatsThreats Must Justify Integrity Assessment Method(s)Must Justify Integrity Assessment Method(s)

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Operator Requirements Operator Requirements for Compliancefor Compliance

Must Complete Assessments within Certain Must Complete Assessments within Certain Time PeriodsTime Periods

Must Address Discovered Integrity IssuesMust Address Discovered Integrity Issues Must Re-assess Everything on a Continual Must Re-assess Everything on a Continual

BasisBasis One or more HCA’s – Plan and Implementation One or more HCA’s – Plan and Implementation

RequiredRequired Must Evaluate Plan PerformanceMust Evaluate Plan Performance Implement Preventative & Mitigation MeasuresImplement Preventative & Mitigation Measures Have a QA and Communication ProcessHave a QA and Communication Process Keep RecordsKeep Records

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Risk AssessmentRisk Assessment Must Conduct Based on ASME B31.8SMust Conduct Based on ASME B31.8S Prescription or Performance BasedPrescription or Performance Based Performance Based has to be RigorousPerformance Based has to be Rigorous Benefits of Performance Based Assessment areBenefits of Performance Based Assessment are

Deviate from the Prescriptive Rules in ASME B31.8SDeviate from the Prescriptive Rules in ASME B31.8S Longer Re-inspection IntervalsLonger Re-inspection Intervals Longer Remediation TimescalesLonger Remediation Timescales Can Use Direct Assessment Only (for Corrosion Can Use Direct Assessment Only (for Corrosion

Caused Metal Loss and SCC)Caused Metal Loss and SCC) Risk Assessment Must be used for Prioritizing Risk Assessment Must be used for Prioritizing

Integrity AssessmentsIntegrity Assessments

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Integrity Assessment Integrity Assessment Methods for HCA’sMethods for HCA’s

In-Line Inspection (Internal In-Line Inspection (Internal inspection)inspection)

Pressure TestPressure Test Direct AssessmentDirect Assessment

ECDAECDA ICDAICDA SCCDASCCDA Confirmatory Direct AssessmentConfirmatory Direct Assessment Other Technology – 180 Day Notification Other Technology – 180 Day Notification

RequiredRequired

If Used Requires a Specific Implementation Plan

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Integrity Assessment Integrity Assessment Methods for HCA’sMethods for HCA’s

Special Rules Apply For Specific Special Rules Apply For Specific Threats e.g.Threats e.g. Third Party DamageThird Party Damage Cyclic FatigueCyclic Fatigue Manufacturing or Construction DefectsManufacturing or Construction Defects Low Frequency ERW Pipe or Lap Low Frequency ERW Pipe or Lap

Welded PipeWelded Pipe Corrosion Caused Metal LossCorrosion Caused Metal Loss

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Integrity Threat Integrity Threat ClassificationClassification

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

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Integrity Threat Integrity Threat Classification Classification

A) Time DependentA) Time Dependent External CorrosionExternal Corrosion Internal corrosionInternal corrosion Stress Corrosion CrackingStress Corrosion Cracking

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B) StableB) Stable Manufacturing Related DefectsManufacturing Related Defects

Defective pipe seamDefective pipe seam Defective pipeDefective pipe

Welding/Fabrication RelatedWelding/Fabrication Related Defective pipe girth weldDefective pipe girth weld Defective fabrication weldDefective fabrication weld Wrinkle bend or buckleWrinkle bend or buckle Stripped threats/broken pipe/coupling Stripped threats/broken pipe/coupling

failurefailure

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EquipmentEquipment Gasket O-ring failureGasket O-ring failure Control/Relief equipment malfunctionControl/Relief equipment malfunction Seal/pump packing failureSeal/pump packing failure MiscellaneousMiscellaneous

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C) Time IndependentC) Time Independent Third Party/Mechanical DamageThird Party/Mechanical Damage

Incorrect OperationsIncorrect Operations Weather related and outside forceWeather related and outside force

Cold weatherCold weather LightningLightning Heavy rains or floodsHeavy rains or floods Earth movementsEarth movements

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Time FramesTime Frames

Internal Inspection or Pressure TestInternal Inspection or Pressure Test Start with the Highest Risk HCAStart with the Highest Risk HCA All HCA’s 100% Complete by December All HCA’s 100% Complete by December

20122012 Complete 50% of HCA’s Based on Risk Complete 50% of HCA’s Based on Risk

by December 2007by December 2007 Except for Class 3 or 4 Locations of Except for Class 3 or 4 Locations of

Moderate Impact – 100% Complete by Moderate Impact – 100% Complete by December 2015December 2015

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Time FramesTime Frames

Direct AssessmentDirect Assessment Start with the Highest Risk HCAStart with the Highest Risk HCA All HCA’s Complete by December 2009All HCA’s Complete by December 2009 Complete 50% of All HCA’s Based on Complete 50% of All HCA’s Based on

Risk by December 2006Risk by December 2006 Except for Class 3 or 4 Locations of Except for Class 3 or 4 Locations of

Moderate Impact – 100% Complete by Moderate Impact – 100% Complete by December 2012December 2012

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Responding to Integrity Responding to Integrity Issues in HCA’sIssues in HCA’s

Discovery of a Condition in an HCA – 180 Discovery of a Condition in an HCA – 180 Days to Determine Threat to Integrity Except Days to Determine Threat to Integrity Except forfor

Immediate Remediation ConditionsImmediate Remediation Conditions Predicted Failure Pressure < 1.1 x Established Predicted Failure Pressure < 1.1 x Established

MOP at LocationMOP at Location Any Dent with a Stress Raiser Regardless of Size Any Dent with a Stress Raiser Regardless of Size

or Orientationor Orientation An Anomaly that Requires Immediate ActionAn Anomaly that Requires Immediate Action Must Reduce Operating Pressure to a Safe LevelMust Reduce Operating Pressure to a Safe Level Must Follow ASME B31.8S, Section 7Must Follow ASME B31.8S, Section 7

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Responding to Integrity Responding to Integrity Issues in HCA’sIssues in HCA’s

180 Day Remediation Conditions180 Day Remediation Conditions Plain Dents > 6% of OD Regardless of OrientationPlain Dents > 6% of OD Regardless of Orientation Plain Dents > 2% of OD Affecting a Girth Weld or Plain Dents > 2% of OD Affecting a Girth Weld or

Seam WeldSeam Weld Longer Than 180 Day Remediation ConditionsLonger Than 180 Day Remediation Conditions

Only If Anomaly Cannot Grow to a Critical StageOnly If Anomaly Cannot Grow to a Critical Stage Only If Internal Inspection used –Only If Internal Inspection used –

An Anomaly with a Predicted Failure Pressure > 1.1 x An Anomaly with a Predicted Failure Pressure > 1.1 x Established MOP at LocationEstablished MOP at Location

Any Anomalous Condition Not Covered AboveAny Anomalous Condition Not Covered Above

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Re-Assessments of HCA’sRe-Assessments of HCA’s As Frequently as Needed – Operator DecidesAs Frequently as Needed – Operator Decides But No Longer Than 7 Years Unless A But No Longer Than 7 Years Unless A

Confirmatory Direct Assessment is Carried Confirmatory Direct Assessment is Carried OutOut Very Specific Rules ApplyVery Specific Rules Apply Only Available with Performance PlanOnly Available with Performance Plan

Internal Inspection or Pressure Test - Internal Inspection or Pressure Test - Maximum Periods areMaximum Periods are 10 Years - Equal to or Greater Than 50% SMYS10 Years - Equal to or Greater Than 50% SMYS 15 Years Equal to or Less Than 50% SMYS15 Years Equal to or Less Than 50% SMYS

Maximum Periods must be JustifiableMaximum Periods must be Justifiable

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Re-Assessments of HCA’sRe-Assessments of HCA’s

Direct Assessment – Maximum Direct Assessment – Maximum Periods arePeriods are 5 Years for Remediation by Sampling5 Years for Remediation by Sampling 10 Years for Remediation of All 10 Years for Remediation of All

AnomaliesAnomalies

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Data GatheringData Gathering Identify Company Data Sources for IMP Identify Company Data Sources for IMP

DevelopmentDevelopment Evaluate Records and Procedures forEvaluate Records and Procedures for

Pipeline Design and ConstructionPipeline Design and Construction Pipeline OperationPipeline Operation Pipeline MaintenancePipeline Maintenance Service HistoryService History Prior Integrity AssessmentsPrior Integrity Assessments

Evaluate systems already in place – Evaluate systems already in place – database, risk assessment, etc.database, risk assessment, etc.

Document ResultsDocument Results

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HCA Identification HCA Identification Impact AssessmentImpact Assessment

Apply Final Rule Definitions of Apply Final Rule Definitions of HCA’s to System to:HCA’s to System to: Identify HCA Locations and ClassifyIdentify HCA Locations and Classify Determine Potential Impact ZonesDetermine Potential Impact Zones Justify Non-HCA LocationsJustify Non-HCA Locations Document ResultsDocument Results

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Threat Identification, Threat Identification, Data Integration and Data Integration and

Risk AssessmentRisk Assessment Review Data from Phases 1 and 2 for HCA Review Data from Phases 1 and 2 for HCA LocationsLocations

Identify Threats Specific to HCA’s, Identify Threats Specific to HCA’s, Identify Threats Specific to Non-HCA’s,Identify Threats Specific to Non-HCA’s, Justify Non-Applicable ThreatsJustify Non-Applicable Threats Carry Out a Risk Assessment on HCA Carry Out a Risk Assessment on HCA

Segments to Determine:Segments to Determine: Likelihood of Failure, andLikelihood of Failure, and Consequences of FailureConsequences of Failure

Document ResultsDocument ResultsSpreadsheet Model or Vendor Software

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Develop BaselineDevelop BaselineAssessment PlanAssessment Plan

Decide on Integrity Assessment Method(s):Decide on Integrity Assessment Method(s): In-Line InspectionIn-Line Inspection Pressure TestingPressure Testing Direct AssessmentDirect Assessment

Method(s) Depend on:Method(s) Depend on: Nature of Identified ThreatsNature of Identified Threats Number and Location of HCA’sNumber and Location of HCA’s Cost – Benefit ConsiderationsCost – Benefit Considerations Technically PossibleTechnically Possible

Develop Plan(s) and ScheduleDevelop Plan(s) and Schedule Document ResultsDocument Results

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Integrity Management Integrity Management ProgramProgram

A Typical IMP will have Sections:A Typical IMP will have Sections: Threat Identification, Data Integration & Risk Threat Identification, Data Integration & Risk

Assessment – Current Results & JustificationsAssessment – Current Results & Justifications Baseline Assessment Plan for Line Pipe in Baseline Assessment Plan for Line Pipe in

HCA’s – Justification for Chosen Method(s), HCA’s – Justification for Chosen Method(s), Direct Assessment Plan if Required, and Direct Assessment Plan if Required, and Implementation TimescaleImplementation Timescale

Integrity Management of Facilities Other than Integrity Management of Facilities Other than Line Pipe in HCA’s (May Not be Applicable)Line Pipe in HCA’s (May Not be Applicable)

Process for Conducting Integrity Assessments Process for Conducting Integrity Assessments – Satisfies Requirement for Minimizing Safety – Satisfies Requirement for Minimizing Safety and Environmental Risksand Environmental Risks

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A Typical IMP should also include:A Typical IMP should also include: Review of Integrity Assessments Results by Review of Integrity Assessments Results by

Qualified PersonnelQualified Personnel Criteria for Remedial Action of Line Pipe in Criteria for Remedial Action of Line Pipe in

HCA’s and Non-HCA’sHCA’s and Non-HCA’s Procedure for Identifying Preventative & Procedure for Identifying Preventative &

Mitigation Measures to Protect HCA’sMitigation Measures to Protect HCA’s Integrity Program Performance MeasuresIntegrity Program Performance Measures Procedure for Continual Evaluation & Procedure for Continual Evaluation &

Assessment of Pipeline Integrity in HCA’s – Assessment of Pipeline Integrity in HCA’s – Including a Confirmatory Direct Assessment Including a Confirmatory Direct Assessment Plan if RequiredPlan if Required

Quality Control ProcessQuality Control Process

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A Typical IMP should also have a A Typical IMP should also have a Communications PlanCommunications Plan Management of ChangeManagement of Change Integrity Management Program Review Integrity Management Program Review

ProcedureProcedure Record KeepingRecord Keeping Required Notifications to the Office of Pipeline Required Notifications to the Office of Pipeline

SafetySafety Personnel TrainingPersonnel Training

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Direct AssessmentDirect Assessment

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History of Direct History of Direct AssessmentAssessment

Originally Proposed during Originally Proposed during Development of Congressional Bills on Development of Congressional Bills on Pipeline SafetyPipeline Safety

Proposed as an Alternative to ILI and Proposed as an Alternative to ILI and Hydrostatic TestingHydrostatic Testing Termed Direct Examination (Later Termed Direct Examination (Later

Changed to Direct Assessment )Changed to Direct Assessment ) INGAA Initiative to Develop Framework INGAA Initiative to Develop Framework

of ECDA Process (ICDA Followed)of ECDA Process (ICDA Followed)

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DA BackgroundDA Background

Integrity verification for high consequence Integrity verification for high consequence areasareas In-line inspectionIn-line inspection Hydrostatic testingHydrostatic testing Direct assessmentDirect assessment

Each tool achieves comparable results and Each tool achieves comparable results and complementary resultscomplementary results

Tools are selected based on operating Tools are selected based on operating conditionsconditions

All tools are routinely used nowAll tools are routinely used now

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Regulations and StandardsRegulations and Standards

Liquid Rule – 49 CFR 195 Liquid Rule – 49 CFR 195 (Jan. 2002)(Jan. 2002) API Standard 1160 API Standard 1160 (Nov. 2001)(Nov. 2001) NPRM Gas Rule – 49 CFR Part 192 NPRM Gas Rule – 49 CFR Part 192

(Jan. 2003)(Jan. 2003) ASME B31.8S ASME B31.8S (Dec. 2001)(Dec. 2001) NACE ECDA Standard RP0502-2002NACE ECDA Standard RP0502-2002

(2002)(2002)““Pipeline External Corrosion Direct Assessment Pipeline External Corrosion Direct Assessment

Methodology”Methodology”

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Regulations and Standards Regulations and Standards (Cont’d)(Cont’d)

Proposed NACE ICDA Standard –TG Proposed NACE ICDA Standard –TG 041041 (2003)(2003)““Pipeline Internal Corrosion Direct Pipeline Internal Corrosion Direct

Assessment Methodology”Assessment Methodology”

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


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Liquid Rule – 49 CFR 195Liquid Rule – 49 CFR 195

Acceptable Integrity Assessment Methods:Acceptable Integrity Assessment Methods: Internal inspection tool or tools capable of Internal inspection tool or tools capable of

detecting corrosion and deformation anomaliesdetecting corrosion and deformation anomalies Pressure testingPressure testing Other technology that the operator Other technology that the operator

demonstrates can provide an equivalent demonstrates can provide an equivalent understanding of the condition of the line pipe.understanding of the condition of the line pipe. OPS notification required 90 days before OPS notification required 90 days before

assessmentassessment

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API Standard 1160API Standard 1160

““Managing System IntegrityManaging System Integrity

for Hazardous Liquid Pipelines”for Hazardous Liquid Pipelines”

Acceptable Integrity Assessment Methods:•In-line inspection technology

•Hydrostatic Testing

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NPRM Gas Rule - 49 NPRM Gas Rule - 49 CFR Part 192CFR Part 192

Acceptable Integrity Assessment Acceptable Integrity Assessment Methods:Methods:

Internal inspection tool or tools capable of detecting Internal inspection tool or tools capable of detecting corrosion and deformation anomalies as appropriatecorrosion and deformation anomalies as appropriate

Pressure testingPressure testing Directed assessment method for external corrosion threats, Directed assessment method for external corrosion threats,

internal corrosion threats, stress corrosion, and third party internal corrosion threats, stress corrosion, and third party damage (if other assessment methods are not feasible)damage (if other assessment methods are not feasible)

Other technology that the operator demonstrates can Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the provide an equivalent understanding of the condition of the line pipe.line pipe. OPS notification required 180 days before assessmentOPS notification required 180 days before assessment

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Supplement to ASME B31.8Supplement to ASME B31.8

““Managing System Integrity of Gas Pipelines”Managing System Integrity of Gas Pipelines”

Acceptable Integrity Assessment Methods:(Dependent on integrity threats)

•In-line Inspection

•Pressure Testing

•Direct Assessment

–ECDA

–ICDA

•Other methodologies

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NACE Recommended NACE Recommended PracticesPractices

NACE ECDA Standard RP0502-2002NACE ECDA Standard RP0502-2002(2002)(2002)““Pipeline External Corrosion Direct Assessment Pipeline External Corrosion Direct Assessment


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


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

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What is Direct AssessmentWhat is Direct Assessment

A method of assessing pipeline A method of assessing pipeline integrity.integrity. Intended to be no less protective of Intended to be no less protective of

public safety and environment than ILI public safety and environment than ILI or Hydrotest.or Hydrotest.

From “direct examination.”From “direct examination.” Bell hole inspections.Bell hole inspections.

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Direct Assessment ProcessDirect Assessment Process

Utilize existing technologies Utilize existing technologies in an integrated approach in an integrated approach intended to map corrosion intended to map corrosion defectsdefects

Utilize prediction modeling Utilize prediction modeling to determine “like and to determine “like and similar”similar”

Use results to safely manage Use results to safely manage the pipeline systemthe pipeline system

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Direct Assessment ConceptDirect Assessment Concept

Technologies can be used as a Technologies can be used as a diagnostic tool to assess pipeline diagnostic tool to assess pipeline integrityintegrity

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

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ECDA TechnologiesECDA Technologies Existing technologiesExisting technologies

Test station surveysTest station surveys Close-interval surveys (CIS)Close-interval surveys (CIS) DC voltage gradientDC voltage gradient Electromagnetic inspectionElectromagnetic inspection Buried CouponsBuried Coupons Soil ResistivitySoil Resistivity

Previously used as stand-alone Previously used as stand-alone assessmentsassessments

Integration of data results in a Integration of data results in a predictive integrity modelpredictive integrity model

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ApplicabilityApplicability External corrosion integrity verification External corrosion integrity verification

for pipelines that cannot be inspected by for pipelines that cannot be inspected by ILI or pressure testILI or pressure test

Condition monitoring of pipelines Condition monitoring of pipelines inspected by ILI or pressure testedinspected by ILI or pressure tested

Have been inspected with other Have been inspected with other techniques as a means of establishing techniques as a means of establishing reassessment intervalsreassessment intervals

Have not been inspected by other means Have not been inspected by other means when future corrosion monitoring is of when future corrosion monitoring is of primary interestprimary interest

Not applicable to all pipelinesNot applicable to all pipelines

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Four Step ECDA ProcessFour Step ECDA Process

1.1. Pre-assessmentPre-assessment Assembly and review of pipeline dataAssembly and review of pipeline data

2.2. Indirect examinationIndirect examination Above-ground survey toolsAbove-ground survey tools

3.3. Direct examinationDirect examination Excavation, inspection, defect Excavation, inspection, defect

assessmentassessment4.4. Post-assessmentPost-assessment

Validation, prioritize repairs, re-Validation, prioritize repairs, re-inspectioninspection

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EstimateCorrosion

Rates

Categorize andRank Coating Fault

Locations

Dig &Measure

From IndirectExams

From Pre-Assessment

PriorHistory

Estimate MaximumRemaining Defect

Severity

Acceptable

NotAcceptable

Post-Assessment

Direct Examinations(to be used in each DA region)

ConfidenceFunctions

EstimateCorrosion

Rates

Categorize andRank Coating Fault

Locations

Dig &Measure

From IndirectExams

From Pre-Assessment

PriorHistoryPrior

History

Estimate MaximumRemaining Defect

Severity

Acceptable

NotAcceptable

Post-Assessment

Direct Examinations(to be used in each DA region)

ConfidenceFunctions

Yes

IndirectExaminations

(to be used in each DA region)

from Pre-Assessment

Explainthrough

digs

No

Yes

DirectExamination

FurtherCharacterizewith Indirect

Exams

PrimaryExaminations

CoatingFaults?

SecondaryExaminations

New CoatingFaults?

Select Areas forComplementary

Examinations

Add IndirectTechniques

Yes

No

No

Yes


(to be used in each DA region)

from Pre-Assessment

Explainthrough

digs

No

Yes

DirectExamination

FurtherCharacterizewith Indirect

Exams

PrimaryExaminations

CoatingFaults?

SecondaryExaminations

New CoatingFaults?

Select Areas forComplementary

Examinations

Add IndirectTechniques

Yes

No

No

Define DARegions,Special

Concerns, andTrouble Spots

Ensure DAis

Applicable

Pipeline DataCollection and

Review

ILI orPressure

Test


SelectPrimary

andSecondary

Tools

Pre-Assessment

ComplementaryTechnique Table

Data toSupport

ToolSelectionYes

No

Define DARegions,Special

Concerns, andTrouble Spots

Ensure DAis

Applicable

Pipeline DataCollection and

Review

ILI orPressure

Test


SelectPrimary

andSecondary

Tools

Pre-Assessment

ComplementaryTechnique Table

Data toSupport

ToolSelectionYes

No

Done

More Digs

OK

From DirectExaminations

Calculate Half-Life of Remaining

Defects

Post Assessment(to be used in each DA region)

Validation Dig

DefineRepair

Intervals

DefineReAssessment

Intervals

Done

More Digs

OK



Defects


Validation Dig

DefineRepair

Intervals

DefineReAssessment

Intervals

Done

More Digs

OK



Defects


Validation Dig

DefineRepair

Intervals

DefineReAssessment

Intervals

65

Pre-AssessmentPre-Assessment

Data collectionData collection ECDA feasibility for pipelineECDA feasibility for pipeline Indirect inspection tool selectionIndirect inspection tool selection ECDA region identificationECDA region identification

Step 1Step 1

66

Pre-AssessmentPre-Assessment

Data Collection (Table 1 of NACE Data Collection (Table 1 of NACE Standard)Standard) Pipe relatedPipe related Construction RelatedConstruction Related Soils/EnvironmentalSoils/Environmental Corrosion ProtectionCorrosion Protection Pipeline OperationsPipeline Operations

Step 1Step 1

67

Pre-AssessmentPre-Assessment ECDA feasibility AssessmentECDA feasibility Assessment

Indirect inspection tool feasibilityIndirect inspection tool feasibility Establish ECDA feasibility regionsEstablish ECDA feasibility regions

Determine which indirect methods Determine which indirect methods are applicable to each regionare applicable to each region

Step 1Step 1

68

What is a Region?What is a Region?

Segment is a continuous length of pipeSegment is a continuous length of pipe Regions are subsets of one segmentRegions are subsets of one segment

Pipe with similar construction and Pipe with similar construction and environmental characteristicsenvironmental characteristics

Same survey toolsSame survey tools

Step 1Step 1

69

Where Might ECDA Not Where Might ECDA Not Be Applicable?Be Applicable?

As with all assessment tools, there are As with all assessment tools, there are limitations to considerlimitations to consider Shielded coatingsShielded coatings Rock ditchRock ditch Extensive Pavement (Cost issue)Extensive Pavement (Cost issue) Some CP configurationsSome CP configurations

Extensive Direct Connected AnodesExtensive Direct Connected AnodesStep 1Step 1

70

Indirect ExaminationIndirect Examination

Objective: identify coating faults and Objective: identify coating faults and areas where corrosion activity may have areas where corrosion activity may have or may be occurringor may be occurring

Utilizes a minimum of two complementary Utilizes a minimum of two complementary indirect techniquesindirect techniques

Step 2Step 2

71

Indirect TechniquesIndirect Techniques

Direct CurrentDirect Current Measure structure potentialMeasure structure potential Identify locations of high CP demand to Identify locations of high CP demand to

small areasmall area Alternating CurrentAlternating Current

Apply AC signalApply AC signal Determine amount of current drain (i.e., Determine amount of current drain (i.e.,

grounding) and locationgrounding) and location Identify locations of high AC currentIdentify locations of high AC current

Step 2Step 2

72

Indirect TechniquesIndirect Techniques

Direct CurrentDirect Current Close Interval Survey (CIS or CIPS)Close Interval Survey (CIS or CIPS) Direct Current Voltage Gradient (DCVG)Direct Current Voltage Gradient (DCVG)

Alternating CurrentAlternating Current ACVG, Pearson SurveyACVG, Pearson Survey AC Attenuation (PCM , EM , C-Scan)AC Attenuation (PCM , EM , C-Scan)

Step 2Step 2

73

Indirect ExaminationIndirect Examination

Objective: identify coating faults and Objective: identify coating faults and areas where corrosion activity may have areas where corrosion activity may have or may be occurringor may be occurring

Utilizes a minimum of two complementary Utilizes a minimum of two complementary indirect techniquesindirect techniques

Step 2Step 2

74

Direct ExaminationDirect Examination Excavate and collect data where corrosion Excavate and collect data where corrosion

most likelymost likely Categorize indicationsCategorize indications

Immediate action requiredImmediate action required Scheduled action requiredScheduled action required Suitable for monitoringSuitable for monitoring

Characterize coating and corrosion anomaliesCharacterize coating and corrosion anomalies Establish corrosion severity for remaining Establish corrosion severity for remaining

strength analysisstrength analysis Determine root-causeDetermine root-cause In-process evaluation, re-categorization, In-process evaluation, re-categorization,

guidelines on number of direct examinationsguidelines on number of direct examinationsStep 3Step 3

75

Number of Required DigsNumber of Required DigsValidation ProcessValidation Process

Total number of excavation depends on Total number of excavation depends on the results of the aboveground the results of the aboveground techniquestechniques

Typically 3-5/10 mile Section Typically 3-5/10 mile Section

Step 3Step 3

76

Direct Examination DataDirect Examination Data

Collect data at dig siteCollect data at dig site Pipe to soil potentialsPipe to soil potentials Soil resistivitySoil resistivity Soil and water samplingSoil and water sampling Under-film pHUnder-film pH BacteriaBacteria Photographic documentationPhotographic documentation

Step 3Step 3

77

Direct Examination DataDirect Examination Data

Characterize coating and corrosion Characterize coating and corrosion anomaliesanomalies Coating conditionCoating condition

Adhesion, under film liquid, % bareAdhesion, under film liquid, % bare Corrosion analysisCorrosion analysis

Corrosion morphology classificationCorrosion morphology classification U/T mappingU/T mapping MPI analysis for SCCMPI analysis for SCC

Step 3Step 3

78

Direct ExaminationDirect Examination Remaining strength analysisRemaining strength analysis

ASME B31GASME B31G RSTRENGRSTRENG CorLASCorLAS DnV RP-F10DnV RP-F10

Step 3Step 3

79

Direct ExaminationDirect Examination

Determine root-causeDetermine root-cause For exampleFor example

Low CPLow CP InterferenceInterference MICMIC Disbonded coatingsDisbonded coatings

Step 3Step 3

80

Post AssessmentPost Assessment

Validates ECDA ProcessValidates ECDA Process Provides performance measures for Provides performance measures for

integrity managementintegrity management Growth models are used to establish Growth models are used to establish

safe operationsafe operation Corrosion “Signature” is developed Corrosion “Signature” is developed

and applied to entire segmentand applied to entire segment Establishes reassessment intervalsEstablishes reassessment intervalsStep 4Step 4

81

Post AssessmentPost Assessment

Assessment of ECDA EffectivenessAssessment of ECDA Effectiveness Comparison of ECDA indications with Comparison of ECDA indications with

Control digsControl digs Comparison of ILI to ECDA resultsComparison of ILI to ECDA results

Remaining Life CalculationsRemaining Life Calculations Reassessment IntervalsReassessment Intervals

82

Post AssessmentPost Assessment Assessment of ECDA Assessment of ECDA

EffectivenessEffectiveness Comparison of ECDA Indications Comparison of ECDA Indications

with Control Digs:with Control Digs: ECDA 100% effective in locating areas ECDA 100% effective in locating areas

where corrosion was taking place and where corrosion was taking place and where metal was exposedwhere metal was exposed

No coating flaws and no corrosion was No coating flaws and no corrosion was found at control digsfound at control digs

83

Post AssessmentPost AssessmentRemaining Life Remaining Life

CalculationsCalculations NACE RP0502 Reassessment NACE RP0502 Reassessment

MethodologyMethodology The establishment of the reassessment The establishment of the reassessment

interval is based on establishing the interval is based on establishing the remaining life of critical defects, remaining life of critical defects, establish a conservative growth rate, establish a conservative growth rate, and utilize the following relationship:and utilize the following relationship:

RL =C x SM (t/GR)RL =C x SM (t/GR)

84


CalculationsCalculations When corrosion defects are found When corrosion defects are found

during the direct examinations, the during the direct examinations, the maximum reassessment interval is maximum reassessment interval is calculated as one half the remaining calculated as one half the remaining life (RL).life (RL).

85


CalculationsCalculations CC Technologies Reassessment CC Technologies Reassessment

Methodology is based on:Methodology is based on: Linear Polarization Resistance Linear Polarization Resistance

measurements are used to give measurements are used to give instantaneous corrosion rates for each instantaneous corrosion rates for each excavated site. The measured rate is a excavated site. The measured rate is a function of the soil characteristics and function of the soil characteristics and environment surrounding the pipe or environment surrounding the pipe or segment being evaluated. segment being evaluated.

86

Post AssessmentPost AssessmentReassessment IntervalReassessment Interval

Using the LPR technique, the maximum Using the LPR technique, the maximum actual value obtained will be taken as the actual value obtained will be taken as the most conservative growth rate. The most most conservative growth rate. The most significant external corrosion feature ILI significant external corrosion feature ILI indication that was field verified is then indication that was field verified is then grown to 80% (Immediate action). grown to 80% (Immediate action). Therefore the re-assessment interval will Therefore the re-assessment interval will be less ½ of this conservative value.be less ½ of this conservative value.

87

ECDA Case StudiesECDA Case Studies

88

Survey Methodologies - Survey Methodologies - Cathodic Protection Cathodic Protection

LevelsLevels Close-Interval SurveysClose-Interval Surveys

Measure pipe to soil potentials at close Measure pipe to soil potentials at close intervals to evaluate cathodic protection levelsintervals to evaluate cathodic protection levels

Locate areas of active corrosionLocate areas of active corrosion Identify shorted casings, stray current Identify shorted casings, stray current

interference, electrical shorts, CP shieldinginterference, electrical shorts, CP shielding Interrupt CP current to obtain polarized Interrupt CP current to obtain polarized

potentialspotentials Pipe to soil potentials measured at 5 foot Pipe to soil potentials measured at 5 foot

intervalsintervals

89

Survey MethodologiesSurvey MethodologiesCoating EvaluationsCoating Evaluations

DCVG and ACVGDCVG and ACVG:: Locate and “size” holidays by measuring Locate and “size” holidays by measuring

current flow in soil to pipeline coating holidayscurrent flow in soil to pipeline coating holidays Interrupt CP system using a fast cycle (DCVG)Interrupt CP system using a fast cycle (DCVG) Use AC voltage signal applied to pipeline Use AC voltage signal applied to pipeline

(ACVG)(ACVG) Measure potential difference between two Measure potential difference between two

electrodeselectrodes

90

Why These Survey Why These Survey Techniques?Techniques?

DCVG - Locate and size coating holidaysDCVG - Locate and size coating holidays Electromagnetic - Evaluate overall coating Electromagnetic - Evaluate overall coating

condition on macro-levelcondition on macro-level Soil Resistivity - Soil corrosiveness at Soil Resistivity - Soil corrosiveness at

holiday locations to prioritize excavationsholiday locations to prioritize excavations CIS - Determine CP levels at holiday sitesCIS - Determine CP levels at holiday sites GPS - Pipe elevation for ICDA and pipeline GPS - Pipe elevation for ICDA and pipeline

mappingmapping

91

ECDA Site SelectionsECDA Site Selections

92


93


94

Examples of Specific Examples of Specific Anomalies DetectedAnomalies Detected

95

Coating Fault SiteCoating Fault Site

CIS Showed a dip in potentialCIS Showed a dip in potential -1.008v, -0.940v, -0.890v, -0.920v-1.008v, -0.940v, -0.890v, -0.920v

DCVG Showed Anomaly DCVG Showed Anomaly

96

97

98

Corrosion Anomalies Corrosion Anomalies FoundFound

Indirect techniques can detect areas Indirect techniques can detect areas of corrosionof corrosion

99

100

101

DiscoveriesDiscoveries

Third party damageThird party damage Fiber optics lineFiber optics line Dent and gougeDent and gouge

ValvesValves LeakingLeaking

Inhouse damage to pipeInhouse damage to pipe Concrete weightsConcrete weights

102

Third Party DamageThird Party Damage

Low CP potentials in CISLow CP potentials in CIS -0.840v (100mV of polarization)-0.840v (100mV of polarization)

ACVG IndicationACVG Indication Required Repair Required Repair

103

104

105

ECDA Site SelectionECDA Site Selection

Scale: 1.0 Inch = 100 FeetDistance (Feet)

51000 51100 51200 51300 51400 51500 51600 51700 51800 51900 52000 52100 52200 52300 52400 52500

Pip

e-t

o-S

oil

Po

ten

tial (

V-v

s-C

SE

)

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

Ele

vatio

n P

rofil

e (

Fe

et)

200

250

300

350

400

450

500

Pip

e D

ep

th (

Inch

es)

20

40

60

80

100

120

PC

M (

mV

)

0

500

1000

1500

2000

DC

VG

Ho

lida

y (%

IR)

0

20

40

60

80

100

So

il R

esi

stiv

ity (

Oh

m-c

m)

0

1e+5

2e+5

3e+5

4e+5

5e+5

I 182 I 183I 184 I 185

Cre

ek

Section 5 - 2nd Block Valve to IPC Region 3Gas Flow

Latitude:

33.232684 N

Longitute:

94.146778 W

Latitude:

33.232636 N

Longitute:

94.146955 W

Latitude:

33.232552 N

Longitute:

94.147253 W

Latitude:

33.232299 N

Longitute:

94.148162 W

Latitude:

33.231803 N

Longitute:

94.149786 W

106


Figure 15. E-9 628+40.5 holiday area.

Figure 16. E-9 628+42.9 holiday area.

107


Scale: 1.0 Inch = 100 FeetDistance (Feet)

72000 72100 72200 72300 72400 72500 72600 72700 72800 72900 73000 73100 73200 73300 73400 73500

Pip

e-t

o-S

oil

Po

ten

tial (

V-v

s-C

SE

)

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

Ele

vatio

n P

rofil

e (

Fe

et)

200

250

300

350

400

450

500

Pip

e D

ep

th (

Inch

es)

20

40

60

80

100

120

PC

M (

mV

)

0

500

1000

1500

2000

DC

VG

Ho

lida

y (%

IR)

0

20

40

60

80

100

So

il R

esi

stiv

ity (

Oh

m-c

m)

0

1e+5

2e+5

3e+5

4e+5

5e+5

I 229 I 230 I 231 I 232I 233

Section 5 - 2nd Block Valve to IPC Region 3Gas Flow

Latitude:

33.249886 N

Longitute:

94.082442 W

Latitude:

33.249795 N

Longitute:

94.082657 W

Latitude:

33.249665 N

Longitute:

94.083025 W

Latitude:

33.249559 N

Longitute:

94.083281 W

Latitude:

33.249014 N

Longitute:

94.084696 W

108

ECDA Site Selection ECDA Site Selection PhotoPhoto

Figure 24. E-11 Coating disbondment

area.

Figure 23. E-11 holiday as found.

109

ChallengesChallenges

110

Distribution System Distribution System Direct AssessmentDirect Assessment

Must rely on pipe exposure Must rely on pipe exposure opportunitiesopportunities

Develop database of useful Develop database of useful informationinformation

Utilize coupon technologies Utilize coupon technologies Utilize standard testing techniquesUtilize standard testing techniques

111

Field Excavation Field Excavation Summary ReportSummary Report

Important to establishing root cause Important to establishing root cause of corrosionof corrosion

Build databases on conditions Build databases on conditions contributing to corrosion and its contributing to corrosion and its mitigationmitigation

Develop risk-based predictive Develop risk-based predictive capabilitycapability

112

Availability of Trained Availability of Trained PersonnelPersonnel

Requires experienced engineers and Requires experienced engineers and technicians for data collection and technicians for data collection and analysisanalysis

Rate limiting step is availability of Rate limiting step is availability of trained personneltrained personnel Minimum of 1 year of training for survey Minimum of 1 year of training for survey

techniquestechniques An additional 6 months of training for An additional 6 months of training for

recognition of quality datarecognition of quality data A minimum of 3 years of analysis A minimum of 3 years of analysis

experience experience

113

Information Information ManagementManagement

There will be massive amounts of There will be massive amounts of data from many systemsdata from many systems Timely processing is criticalTimely processing is critical User friendly data management systems User friendly data management systems

are keyare key Owner/Operator accessibility must be Owner/Operator accessibility must be

consideredconsidered

114

ProjectionsProjections Cost estimates to implement DA engineering Cost estimates to implement DA engineering

on typical transmission system of 500 mile on typical transmission system of 500 mile length with 10 anomalies/milelength with 10 anomalies/mile

Model Development Cost Model Development Cost Data review = $ 500/mileData review = $ 500/mile Base survey = $ 600/mileBase survey = $ 600/mile Diagnostic Survey = $200/anomaly = $2,000 Diagnostic Survey = $200/anomaly = $2,000 Direct Examination = $500/anomaly = $5,000Direct Examination = $500/anomaly = $5,000 Modeling = $ 500/mileModeling = $ 500/mile

Total Model Development Cost = $8,600/mileTotal Model Development Cost = $8,600/mile Applies to 50 miles = $430,000Applies to 50 miles = $430,000

115

Projections (cont’d)Projections (cont’d) Model Application CostModel Application Cost

Data review = $ 500/mileData review = $ 500/mile Base survey = $ 600/mileBase survey = $ 600/mile Direct Examination = $500/anomaly = $2,500 Direct Examination = $500/anomaly = $2,500

(assumes 5 critical)(assumes 5 critical) Model Enhancement = $100/mileModel Enhancement = $100/mile

Total Model Application Cost = Total Model Application Cost = $3,700/mile$3,700/mile

Applies to 450 miles = $1,660,000Applies to 450 miles = $1,660,000 Total DA Engineering for 500 miles = $2.1 Total DA Engineering for 500 miles = $2.1

Million or $4,200/mileMillion or $4,200/mile

116

Discussion PointsDiscussion Points

ECDA Process is generally ECDA Process is generally underestimated”underestimated” ComplexityComplexity Pre-Assessment RequirementsPre-Assessment Requirements Data managementData management

Details and accuracy can be overlookedDetails and accuracy can be overlooked Training is an issueTraining is an issue Generally need a better understanding Generally need a better understanding

of dig measurements and data of dig measurements and data collectioncollection

117

Discussion Points Discussion Points (cont’d)(cont’d)

Need training on how to apply Need training on how to apply reassessment intervalsreassessment intervals

Others?Others?

118

Lessons Learned To Lessons Learned To DateDate

ECDA is presently expensive but costs ECDA is presently expensive but costs will decline with experiencewill decline with experience For some pipelines, other assessments will For some pipelines, other assessments will

always be more cost effectivealways be more cost effective Alignment of data is criticalAlignment of data is critical ECDA requires high attention to detailECDA requires high attention to detail Pre-assessment importantPre-assessment important

119

SummarySummary For liquid pipelines, the methods For liquid pipelines, the methods

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

120

SummarySummary

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

121

SummarySummary

Direct assessment is based on the Direct assessment is based on the use and integration of existing use and integration of existing technologiestechnologies

Direct assessment will work if Direct assessment will work if properly applied properly applied

It will require data collection and It will require data collection and management and a commitment to management and a commitment to validationvalidation

122

Thank You

Questions and Discussion

Pipeline Integrity Management

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