BASIC CONCEPTS BASIC CONCEPTS IN PIPELINE IN PIPELINE INTEGRITY INTEGRITY
MANAGEMENTMANAGEMENTAida Lopez-Garrity, P.Eng, MSc.Aida Lopez-Garrity, P.Eng, MSc.Kevin ParkerKevin Parker
CC TechnologiesCC TechnologiesPuebla, Mexico – November 11, 2003Puebla, Mexico – November 11, 2003
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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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Programs and Practices to Programs and Practices to Manage Pipeline Integrity Manage Pipeline Integrity
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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Programs and Practices to Programs and Practices to Manage Pipeline Integrity Manage Pipeline Integrity
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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Programs and Practices to Programs and Practices to Manage Pipeline Integrity Manage Pipeline Integrity
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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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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Regulatory IssuesRegulatory Issues
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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Regulatory IssuesRegulatory Issues
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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Regulatory IssuesRegulatory Issues
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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Regulatory IssuesRegulatory Issues
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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Regulatory IssuesRegulatory Issues
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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High Consequence Areas High Consequence Areas (HCA’S)(HCA’S)
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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High Consequence Areas High Consequence Areas (HCA’S)(HCA’S)
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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Integrity Threat Integrity Threat ClassificationClassification
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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Integrity Threat Integrity Threat ClassificationClassification
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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Integrity Threat Integrity Threat ClassificationClassification
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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Integrity Management Integrity Management ProgramProgram
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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Integrity Management Integrity Management ProgramProgram
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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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
Methodology”Methodology”
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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
Methodology”Methodology”
Proposed NACE ICDA Standard –TG 041Proposed NACE ICDA Standard –TG 041(2003)(2003)““Pipeline Internal Corrosion Direct Assessment Pipeline Internal Corrosion Direct Assessment
Methodology”Methodology”
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
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
Define DARegions,Special
Concerns, andTrouble Spots
Ensure DAis
Applicable
Pipeline DataCollection and
Review
ILI orPressure
Test
IndirectExaminations
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
IndirectExaminations
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
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
From DirectExaminations
Calculate Half-Life of Remaining
Defects
Post Assessment(to be used in each DA region)
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
Post AssessmentPost AssessmentRemaining Life Remaining Life
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
Post AssessmentPost AssessmentRemaining Life Remaining Life
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.
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
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
98
Corrosion Anomalies Corrosion Anomalies FoundFound
Indirect techniques can detect areas Indirect techniques can detect areas of corrosionof corrosion
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
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
ECDA Site SelectionECDA Site Selection
Figure 15. E-9 628+40.5 holiday area.
Figure 16. E-9 628+42.9 holiday area.
107
ECDA Site SelectionECDA Site Selection
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.
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