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2005 Gas Safety Seminar2005 Gas Safety Seminar

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WELCOME WELCOME

IntroductionsGoals of this seminarInformal meetingAny problems with lodging or conference room talk with me or one of the inspectors

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IntroductionsIntroductionsPaul Metro – Chief Gas Safety DivisionBob Biggard – Gas Safety InspectorBill Derr – Gas Safety InspectorRalph Graeser – Gas Safety InspectorSteve Hurbanek – Gas Safety InspectorMike Nguyen – Gas Safety InspectorPete Stanley – Gas Safety InspectorMike Hoffman – Director of Transportation and Safety

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Seminar GoalsSeminar Goals

EducateDiscussUnite the ideas of Integrity Management, Damage Prevention, Corrosion Control, and Security to form the base of a dynamic gas safety program

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Informal MeetingInformal Meeting

Open and informal discussionsIts ok to disagree or ask questionsWe want to hear all sides of the issues

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Need AssistanceNeed Assistance

Talk to one of the gas safety inspectors and they will assist you

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AgendaAgendaWednesday, October 5, 2005

8:30 – 9:00 Registration

9:00 – 9:30 KEYNOTE SPEAKERCommissioner Kim Pizzingrilli (PA PUC)

Introductions / IMP Review & RegulationsPaul Metro (Chief, Gas Safety Division, PA PUC)

9:30 – 10:30 Integrity Management ProgramClyde Myers (Office of Pipeline Safety Eastern Region)

10:30 – 10:45 BREAK

10:45 – 12:00 DIMP John Jolly / Michael Jones(Philadelphia Gas Works)

12:00 – 1:00 LUNCH

1:00 – 2:00 Damage Prevention / IMP / DIMPBill Kiger (Pennsylvania One Call)

2:00 – 2:15 BREAK

2:15 – 3:00 Fiber to the Premise Project – FTTPVerizon

3:00 – 3:30 Damage Prevention Gerry Barnett (Labor & Industry)

Thursday, October 6, 2005

9:00 – 10:00 Corrosion Ralph Graeser / Stephen Hurbanek (Gas Safety Inspectors, PA PUC)

10:00 – 10:15 BREAK

10:15 – 11:15 Corrosion / IMPGeorge Lomax (Heath Consultants)

11:15 – 12:00 Antiterrorism Task Force David Newcomer (Supervisor, PA PUC)

12:00 LUNCH

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Commissioner PizzingrilliCommissioner Pizzingrilli

IMP Review and Regulations

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Origins of IMPOrigins of IMP

High-consequence, high-profile accidents– Bellingham 1999– Carlsbad 2000

OPS response included new rules for integrity management of transmission pipelines (liquid and gas)Understand threats/risksKnow effect on high consequence areasPeriodically inspect (Assess) pipeline conditionRemediate identified anomaliesImplement preventive & mitigative measures

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LegislationLegislationHigh profile pipeline incidents led to several versions of senate and house bills over a couple of years

Congress passed the “Pipeline Safety Improvement Act of 2002 (PSIA2002)” in December 2002 after which the President signed it into law as Public Law No. 107-355 on December 17, 2002.

Contains many items… of which Integrity Management for Gas Transmission Pipelines is a major one. (Note: Already required for liquid pipelines)

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LegislationLegislationItems related to Integrity Management for Gas Transmission Pipelines:

– Requires Risk Analyses and Integrity Management Programs for Operators of Gas Transmission Pipelines in High Consequence Areas (HCAs)

– 10 years to perform baseline assessments of pipelines starting 12/17/02

– Reassessments every 7 years or more frequently

– Much, much more

– Requires the Department of Transportation/Office of Pipeline Services (DOT/OPS) to develop integrity management rulemaking within 1 year.

– Many other items included in the PSIA2002

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Integrity Management Rule for GasIntegrity Management Rule for GasTransmission PipelinesTransmission Pipelines

In December 2003, DOT/OPS issued the final rule on “Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)” It was effective January, 2004.

Several revisions since. Most recent effective May 2004.

The rule is incorporated in the Code of Federal Regulations CFR Part 192 as a new Subpart 0.

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Integrity Management Rule Integrity Management Rule TimelineTimeline

12/17/02 10 Year Window Started12/16/03 Integrity Management Rule (revisions since)6/17/04 Begin Baseline Assessment Process8/31/04 Performance Measure Report thru 6/17/0412/17/04 Integrity Management Program Due12/17/07 Complete Highest ranked 50% of mileage12/17/09 Reassessments begin12/17/12 Complete next 50 %

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Natural Gas Integrity Management: Flowchart

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Elements Required in an Integrity Elements Required in an Integrity Management ProgramManagement Program

Identify all OPS Transmission Pipelines located within High Consequence Areas (HCAs)Conduct Risk Assessment and rank pipelinesIdentify ThreatsDetermine Appropriate Method to Assess ThreatsDevelop a Baseline Assessment PlanAssessment methodsData Management and Integration

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Elements Required in an Elements Required in an Integrity Management ProgramIntegrity Management Program

Preventive and Mitigative MeasuresManagement of Change (MOC)Quality Assurance / Quality ControlCommunications PlanPerformance MeasuresTraining/Certification for Employees and ContractorsDocumentationContinuous ImprovementOthers

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Who in your utility will be affected Who in your utility will be affected by Integrity Management?by Integrity Management?

Engineering and DesignConstructionMaintenanceOperationsDamage PreventionAnd those who supervise themOther support organizations: procurement, contracting,Environmental,That’s just about everybody!

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Identify Transmission LinesIdentify Transmission Lines

Pipelines that operate at high pressures that produce high stress levels (where the Maximum Allowable Operating Pressure (MAOP) produces a stress level 20% or greater of the Specified Minimum Yield Strength (SMYS))Pipelines in Storage FieldsPipelines that deliver gas to Large Volume Customers or Distribution Centers even if below 20% SMYS.

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Identify High Consequence Areas Identify High Consequence Areas ((HCAsHCAs))

HCAs are high populated areas and identified sites in close proximity to transmission pipelines. Identified sites include facilities with persons who are mobility-impaired, confined, or hard to evacuate, and places where people gather for recreational and other purposes (20 or more people for 50 or more days per year). For facilities with mobility impaired, confined, or hard-to-evacuate persons and places where people gather, the corridor of protection from the pipeline is 300 feet, 660 feet or 1000 feet depending on the pipeline's diameter and operating pressure.Use of national data basesContacting public safety officialsThousands of HCAs

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Perform Risk AssessmentPerform Risk Assessment

Use of a risk model – PIRIMIDData gathering; input extensive and time consumingVery conservative assumptions due to missing data on older pipelinesRank HCA segments

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Identify Threats on HCA SegmentsIdentify Threats on HCA Segmentsand Methods of Assessmentand Methods of Assessment

Per rule – ASME B31.8 S threats. Identify which threats exist... Materials, construction, operation, mechanical, corrosion, other

Identify acceptable methods of threat assessment

In Line Inspection, hydrotesting, External Corrosion Direct Assessment, Internal Corrosion Direct Assessment, other

Not all methods can assess all threats, must be flexible

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Baseline Assessment PlanBaseline Assessment Plan

Schedule 10 Year Program consists ofRisk rankingThreat identificationMethod of assessment of threatsMany considerations when selecting assessment methodwhen more than one method is acceptableCostCustomer impactPermitting impactsWorkforceScheduling

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InIn--LineLine--Inspection (ILI) Inspection (ILI) Assessment MethodAssessment MethodAlso know as Smart Pigging or Also know as Smart Pigging or Internal InspectionInternal Inspection

Tools that run internally in a pipeline – magnetic flux or ultrasonic Detects: Metal loss (Corrosion, gouges, some cracks?)Can differentiate internal vs. externalProvides: Snapshot of pipe conditionDoes not detect: Most cracks and coating anomaliesAnomalies confirmed by digsDetermine action required

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In Line Inspection ProcessIn Line Inspection Process8 - 10 months planningPre-assessment – is retrofit requiredRetrofit pipelineFull opening valves, bends, launchers, receivers, filters, separators, etc.Some permanent; some temporaryPerform Smart Pig Inspection of Pipeline

• Clean pipeline (dry or chemical 4 - 5 runs)• Caliper pig inspection (1 run)• Gauge pig inspection (1 run)• Smart pig inspection (1 run)

Immediate Indications of defectsReportUp to 180 days after inspectionDirect Assessment – including verification digsPost Assessment – determine reassessment interval, scheduled digs

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Other IMP ElementsOther IMP ElementsData Integration and Management

• Massive Effort - old hard copy as well as electronic• New software system• Re-format existing data• Fill in missing data• Make data updates easier

Interface with risk model and company-wide data systems including future GISPreventative and Mitigative MeasuresMust implement measures beyond minimum code requirements for threats that are identifiedManagement of Change (MOC)

• Significant impact• Hundreds of existing procedures impacted• Process to integrate everything touching pipeline integrity

Quality Assurance

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Other IMP ElementsOther IMP ElementsCommunications PlanLandowners, public, governmentalPerformance MeasuresSemi Annual reporting of certain measuresTraining/Certification for Employees and Contractors

• Challenge to determine what is certification and then to certify

• Industry is putting together some recommended practices

• Company responsible even if using expert contractors

Documentation

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ReferenceReferenceIntegrity Management in the Real WorldNARUC MeetingAugust 30, 2004John DaggPipeline Integrity ManagerSouthern California Gas CompanyA Sempra Energy UtilityDistribution Integrity Management – The Current WorkMary McDanielRailroad Commission of Texas