An Approach To Pipeline Integrity Management
An Approach to Pipeline IntegrityManagementNACE Int’l Houston Section MeetingOctober 13, 2009Robert J. (Bob) Franco
Overview Pipeline assets 11-Element Operations Integrity Management System (OIMS)- Pipeline design and construction- Pipeline operations & integrity management Developing a pipeline integrity program Identifying integrity threats to an operating pipeline Adopting a ‘Failures are Preventable” mindset Objectives of the Facilities Integrity Management System (FIMS) FIMS implementation FIMS specific requirements for pipelines Pipeline Internal Corrosion Corrosion management 10 best practices Inspection tools ConclusionsPage 2
Upstream Production Pipeline Assets Onshore construction coststypically 1-2M/mile Transportation ofhazardous fluids – requiresprotection of Health, Safetyand the Environment Transportation of valuablesales products – mustminimize downtime Pipelines transport:Produced oilProduced gas (with H2S/CO2/water)Produced gas liquidsHeliumCO2Page 3
11-Element Operations Integrity Management SystemRigorous integrity management system provides framework for1. Management leadership,commitment andaccountability2. Risk assessment andmanagement3. Facilities design &construction – specs,codes, standards4. Information /documentation5. Personnel & training6. Operations &maintenance7. Management of change8. Third-party services9. Incident investigation &analysis10.Community awareness& emergencypreparedness11.Operations integrityassessment andimprovementPage 4
Developing a Pipeline Integrity ProgramOperation Integrity Management System (OIMS)1. Management leadership, commitment andaccountability2. Risk assessment and management3. Facilities design & construction – specs,codes, standards4. Information / documentation5. Personnel & training6.Operations & maintenance7. Management of change8. Third-party services9. Incident investigation & analysis10. Community awareness & emergency preparedness11. Operations integrity assessment and improvementFacilities Integrity Management System (FIMS) Identify integrity threats Design and execute a pipeline integrity program Steward and report program results Continuously improve the programPage 5
Threats to Operating Pipeline Integrity3rd Party DamageExternal CorrosionInternal CorrosionPipeline fire caused by backhoePage 6
Threats to Operating Pipeline Integrity – cont’dExternal StressCorrosion CrackingExternal Corrosion atERW SeamPage 7
Threats to Pipeline Integrity in Operation – cont’dUpheaval Buckling (Seismic)Thermal StressesCrack30”PipelinePage 8
Adopting a “Failures are Preventable” MindsetSAFETYINTEGRITYFatalityHigher quipment OutageAbnormalOperation EventsFirst AidAccelerated FailuresUnsafe ActFailures on DemandHazard Identification,Policies, ProcedureInjuries are grityProgramsPre-empted / Detected Failuresand Non-Critical Equipment FailureFailures are PreventablePage 9
FIMS Objectives & BenefitsWhat are we trying to accomplish with theFacilities Integrity Management System (FIMS)?Objectives Eliminate higher consequence facility incidents and improve overall facilityreliabilityIncorporate Best Practices into integrity management and ensure continuousimprovementBusiness Benefits Established a common global integrity management approachAligned organization to identify and address integrity issuesElevated awareness & understanding of global risk profileImproved management stewardship programGlobal “fleet management” approachMaintain positive reputation with publicPage 10
FIMS ImplementationPROGRAM DESIGNAssess Equipment CriticalityRisk-Based ApproachIdentify Maintenance Tasksand Inspection Activitiesthrough Risk-Based ProcessEquipment StrategiesPrepare FunctionalProgramsEquipment Integrity GuidesEquipmentspecific(pipelines, etc)PROGRAM EXECUTIONDevelop ExecutionProcedures / TimingMonitor Program StatusSchedule / Conduct OverallWork PlanMOC for Deferred ActivitiesPROGRAM REPORTINGReview and AssessProgram ResultsScheduled Reviews toConfirm Fitness-for-Service /Continuous ImprovementReport Non-ConformancesMaintain Facility IntegrityInventoryPage 11
Pipeline Integrity RequirementsFIMS Pipeline Integrity Requirements - Corrosion Pigging for solids control(weekly to monthly) Caliper pig for mechanical damage(5 year default) Process monitoring & MOC(Annually)- Temperature, pressure, fluid rates/volumes Fluids monitoring(Annually)- Full water analysis yearly- Includes chlorides, inhibitor residual, organic acidsDamaged pig Chemical treatment(Annually) Corrosion inspection (MFL or UT)(Min 5 yr default) Corrosion monitoring program(Annually)– Options include coupons, electric resistance probes,test spools, fluid sampling CP P/S potentials and interference checks (Annually)Brush BiDiCantilever BrushPit BossFIMS Pipeline Integrity Requirements - Other Right of way patrolsCrossings over navigable water waysWalking inspections; monitoring of exposed segmentsFirst responder communication with local authoritiesFrequencies shown here are typical, and must be individually developed for specific pipelinesby assessing risk and analyzing operating and monitoring dataPage 12
Internal Corrosion in Produced Oil & Gas PipelinesCorrosion Basics: Steel Water CorrosionOilfield Factors Add ComplexityOil Accelerating factors - salts, CO2, H2S, oxygen, organic andinorganic acids Inhibiting factors - liquid hydrocarbon, corrosion inhibitors Fluid flow regime effects – location of water, solids Formation of protective scales – carbonate, sulfideNeed to Account for These Factors in Predictions Accurate predictions require knowledge of fluid chemistry and flow conditions throughout field life Predictions are based primarily on laboratory testing and field experienceProblems Can Occur When Expected mitigating factors are not present; e.g. inadequate corrosion inhibition or cleaning Flow stream compositions and flow regimes are outside range from the design qualification Monitoring insufficient to detect changes in corrosionPage 13
Corrosion Management 10 Best Practices1. Operator has a Corrosion Monitoring Program Risk-based, considers tools, intervals, all degradation mechanisms2. Operator has a Corrosion Control Program Inhibition, CP, coatings surveillance types and intervals3. Operator has a Corrosion Inspection Program Risk-based, describes tools, intervals4. Programs have written objectives, performance measurements,and stewardship5. Programs have a performance assurance process - ext. auditsPage 14
Corrosion Management 10 Best Practices6. Resources and Organization Responsibilities and accountabilities, definition of resources required7. Corrosion Management Operational Requirements Planning & scheduling toolsRecord keepingPlanning & budgeting8. Corrosion Management of Change Process Review, approval, documentation9. Personnel Roles and Competencies Competency Assurance SystemTrainingDocumentation10. Self-Assessment and Improvement Operator assesses and reviews the effectiveness of his system regularlyPage 15
Pipeline Corrosion In-line Inspection (ILI) ToolsInspection Options Magnetic Flux Leakage (MFL) is primary tool- Accuracy /- 10% of wall thickness- Indirect method, requiring calibration andsizing models- Need supplemental ultrasonic (UT) proveup for validation digs- Accuracy an issue for measuring low wallloss and narrow axial corrosion Ultrasonic pigs can be used in liquid filledlines- Better accuracy than MFL for low wall loss- Subject to UT signal degradation withrough pipe surfaces Direct wall thickness measurementssometimes used- Requires good understanding of fluids,topography and corrosion mechanisms tosystematically select NDT locationsSensorsMagnets andBristlesIn-line Magnetic Flux Leakage (MFL) PigConfirming and mitigating externalcorrosion detected by ILIPage 16
Examples of Internal Corrosion Detected by ILIExample of top-of-line (TOL) 000Distance from Launch (m)OrientationExample of 360 and bottom of line (BOL) corrosionTOLBOLTOLPage 17
ConclusionsPipelines are an integral asset to upstream operationsPipeline integrity must consider all aspects of the design,construction, and operating phasesPipeline integrity requires adopting a:- “Failures are Preventable” mindset- Systematic program that accounts for integrity threatsA formalized Operations Integrity Management Systemdescribes management expectations of pipeline integrityA formalized Facilities Integrity Management Systemdescribes how to meet management expectations bydocumenting and stewarding integrity programs writtenby subject matter expertsAdoption of corrosion management best practices canimprove overall performance of pipeline operationPage 18
Steward and report program results . Threats to Operating Pipeline Integrity Pipeline fire caused by backhoe 3rd Party Damage External Corrosion Internal Corrosion. Page 7 Threats to Operating Pipeline Integrity – cont’d External Stress Corrosion Cracking .
Pipeline device hardware, Pipeline network, the Pipeline host hardware, the Pipeline application software and the Pipeline media disk storage systems. Each of these components is described below. Pipeline device hardware Pipeline device hardware has up to four independent channels with SDI I/O for capture and play out. The SDI
and Hazardous Liquid pipeline risk models. Operators establish risk models to address risk and improve safety within their respective pipeline systems. Pipeline risk models are a foundational part of the assessment of operational pipeline risk. Federal pipeline safety integrity management (IM) regulations require pipeline operators to use risk
Natural Gas Pipeline Safety Integrity Management - Federal: Title 49 Part 192 Subpart O - Gas Transmission Pipeline Integrity Management - Texas: TAC Title 16 Part 1 Chapter 8 Subchapter B Rule 8.101 Background: Texas was the first state in the nation to mandate a pipeline integrity managementprogram
PIPELINE INTEGRITY MANAGEMENT SYSTEM (PIMS) PIMS is a database system for managing subsea pipeline anomalies and inspection data with Integrity Management input, analysis and corrective action control. Subsea Asset managers do not have the time to filter through the mass of pipeline inspection data and reports to see where the anomalies are and the Integrity Manager doesn’t have time to .
Rather than introducing additional safety legislation for gas pipeline operators, further improvements in pipeline integrity are best facilitated by pipeline operators adopting an appropriate Safety Management System (SMS) including Pipeline Integrity Management Systems (PIMS). These systems are based on a "Plan-Do-Check-Act" approach which
Page 2 of 22 ODNR‐DSWR Pipeline Standard 12‐3‐13 Pipeline ‐ The pipeline and its related appurtenances. Pipeline Company ‐ The entity responsible for installing the pipeline, its successors, and assigns, on its own behalf and as operator of the company. Right‐of‐Way ‐ Includes the permanent and temporary easements that the pipeline company acquires
Page 2 of 22 ODNR‐DSWR Pipeline Standard 12‐3‐13 Pipeline ‐ The pipeline and its related appurtenances. Pipeline Company ‐ The entity responsible for installing the pipeline, its successors, and assigns, on its own behalf and as operator of the company. Right‐of‐Way ‐ Includes the permanent and temporary easements that the pipeline company acquires
and measured pile capacities. API-1993 provides potentially non-conservative results for shaft capacity in loose sands, and in loose-to-medium sands with high length (L) to diameter (D) ratios. Figures 1 and 2 illustrate these skewed trends, reproducing the database comparisons given by Jardine et al (2005) between calculated (Q c) and measured (Q m) shaft capacities. 2.2.2 Non-conservative .
