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Rebuilding the World's Pipeline Infrastructure
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Rebuilding the World's Pipeline Infrastructure

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Slides from a presentation by Bill Hoff, Director, Engineering Group, Gulf Interstate Engineering Company and Edward J. Wiegele, President, Professional Services, Willbros Engineers (U.S.), LLC at the ...

Slides from a presentation by Bill Hoff, Director, Engineering Group, Gulf Interstate Engineering Company and Edward J. Wiegele, President, Professional Services, Willbros Engineers (U.S.), LLC at the 2012 International Pipeline & Offshore Contractors Association Convention in Istanbul.

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    Rebuilding the World's Pipeline Infrastructure Rebuilding the World's Pipeline Infrastructure Presentation Transcript

    • Rebuilding the World’s Pipeline Infrastructure William J. Hoff Edward J. WiegeleGroup Director , Engineering Services President, Professional ServicesGulf Interstate Engineering Company Willbros Engineers (U.S.) LLC
    • William J. Hoff
    • US Pipeline Infrastructure 3
    • International Pipelines Beyond North America Source: Pipeline & Gas Journals Mid-Year International Pipeline Report 10,166 mi South & Central America and Caribbean 1,980 mi Western Europe & EU Countries 8,318 mi Middle East 8,523 mi Africa 17,039 mi Former Soviet Union-Eastern Europe 35,546 mi Asia Pacific Region 81,572 mi Total 4
    • Natural Gas Pipeline Safety Act: 1968 Regulations Effective Date: 1970Source: Oil Pipeline Characteristics and Risk Factors:Illustrations from the Decade of Construction, 2001 5
    • Timeline of Key Events Timeline Event 1968 ● US Passes Natural Gas Pipeline Safety Act  Pipeline Safety Provisions Become Law 1970 ● Gas Pipeline Safety Regulations Developed  Effective Date for All Gas Operators 1979 ● US Passes Hazardous Liquid Pipeline Safety Act  For All US Liquid Operators Dec 1, 2000 ● Liquids IMP Rule – 49 CFR 195.452  Industry Reference API 1162 Dec 15, 2003 ● Gas IMP Rule – 49 CFR 192 Subpart O Industry References: ASME B31.8SWhy is this • Requirements / Standards are being adopted by other countriesImportant? • Opportunities exist to assist Operators in Integrity Management • Long term need for these Services 6
    • Background to Understanding US RegulationsIncidents Leading to Pipeline Integrity Regulations Olympic Pipeline • Bellingham Washington - June 1999 • Gasoline Pipeline Rupture • Fatalities: 3 young boys El Paso Pipeline • Carlsbad, New Mexico - August 2000 • Natural Gas Pipeline Rupture • Fatalities: 12 7
    • Olympic Pipeline Accident – Bellingham, WA 8
    • Olympic Pipeline Accident – Bellingham, WACherry Point ● Performing Software Upgrade on SCADARefinery ComputersPipeline ● Switched Delivery PointsRupture ● Notice pressure rise – considered normal Water Treatment Plan (actually due valve closure) ● SCADA becomes unresponsive ● Electrician takes down pump station manually Whatcom Creek ● Pressure surge backs up the line, surge relief valve fails to open ● Pressure surge causes rupture at water treatment plant (unknown) Valve Fails ● Deleted software upgrade, rebooted SCADA, to Open and restarted pipeline ● Pipeline is restarted ● Additional product is released at rupture site Renton Station 9
    • Olympic Pipeline Accident – Bellingham, WA Event Tie to IMP RuleCherry PointRefinery SCADA Upgrade - Personal Knowledge & TrainingPipeline - Management of ChangeRupture - Quality Assurance Water Treatment Plan Pressure Rise - Personal Knowledge & Training & Restart of P/L Damage at Water - Threat ID – 3rd Party Damage Treatment Plant - Preventive & Mitigative Measures Whatcom Creek Smart Pig Run - Assessment Methods - Conducting Assessments - Remediation Valve Fails - Personal Knowledge & Training to Open Pipeline Rupture - Minimize Enviro / Safety Risks - Personal Knowledge & Training Relief Valve - Management of Change Failure - Personal Knowledge & Training Renton Station 10
    • El Paso Pipeline – Carlsbad, NM Accident 11
    • El Paso Pipeline – Carlsbad, NM Accident ● 12 Fatalities ● Cause: Internal CorrosionAddl Ties to IMP Rule● Threat: Internal Corrosion● Cyclic Fatigue: Suspension Bridge 12
    • Similar Requirements for Gas & Liquids PipelinesHazardous Liquid Pipelines Natural Gas Pipelines• 49 CFR 195.452 • 49 CFR 192 Subpart O• Applicable to High Consequence Areas • Applicable to High Consequence Areas• Industry Standard: API 1162 • Industry Standard: ASME B31.8S• Required Elements • Required Elements – Identify High Consequence Areas – Identify High Consequence Areas – Identify Threats – Identify Threats – Perform Risk Analysis – Perform Risk Analysis – Prepare Assessment Plan – Prepare Assessment Plan – Perform Remediation – Perform Remediation – Perform Continual Evaluation – Perform Continual Evaluation – Maintain Performance Metrics – Maintain Performance Metrics – Implement Preventive & Mitigative Measures – Implement Preventive & Mitigative Measures – Utilize Management of Change – Utilize Management of Change – Develop Quality Assurance Program – Develop Quality Assurance Program – Record Keeping – Record Keeping – Develop Communications Plan – Develop Communications Plan 13
    • Key Differences Between Gas & Liquids Pipelines Hazardous Liquid Pipelines Natural Gas Pipelines• Maximum 5 Year Assessment Cycle • Maximum 7 Year Assessment Cycle• Product Characteristics • Product Characteristics – Liquid run off based on terrain – Local well defined Impact Area – Potential migration in rivers and streams – No run off, vertical dispersion – Potential groundwater contamination – No impact to groundwater• High Consequence Area Definition • High Consequence Area Definition – Commercially Navigable Waterway – Method 1: Class Location – High Population Area – Method 2: Potential Impact Radius – Other Populated Areas – Both Methods Include: Identified Sites – Usually Sensitive Areas• Remediation Conditions • Remediation Conditions – Immediate – Immediate – 60 Days – 1 Year – 180 Days – Monitor• Other Considerations • Other Considerations – Runoff Modeling, Potential to Impact – BTU Content Affects Impact Radius 14
    • Discussion of Natural Gas Pipeline Integrity RuleFiltering Criteria Gas Transmission Pipelines ● Is the pipeline system subject to 49 CFR 192? ● Does it have Transmission Pipe per 192.3? ● Have High Consequence Areas been identified on the system? 15
    • Gas Integrity Management ProgramRequired Program Elements a) Identification of HCAs b) Baseline Assessment Plan c) Threat Identification d) Direct Assessment Plan e) Remediation f) Continual Evaluation & Assessment g) Confirmatory Direct Assessment h) Preventive & Mitigative Measures i) Performance Plan j) Record Keeping k) Management of Change l) Quality Assurance m) Communications Plan n) Procedure to provide risk analysis & IMP to Regulators upon request o) Minimizing environmental / safety risks p) Identification of new HCAs 16
    • Identification of High Consequence Areas HCA Methods Typically Used● 1. Class Location Reduces Length● 2. Potential Impact Circle (PIC)● Both Include “Identified Sites” 17
    • High Consequence Areas – PIR Method PIR  0.69 pd 2PIR = Radius of a Circular Area in Feet Surrounding the Point of Failure p = Maximum Allowable Operating Pressure (MAOP) in the pipeline segment in pounds per square inch d = Nominal Diameter of the Pipeline in Inches. 18
    • High Consequence Area – More than 20 Buildings Potential Impact Circle with more than 20 Buildings 19
    • Identified Sites(a) An Outside Area or Open Structure that is occupied by twenty (20) or more persons on at least 50 days in any twelve (12)-month period. (The days need not be consecutive.)  Beaches  Outdoor Theaters  Playgrounds  Stadiums  Recreational Facilities  Recreational Areas near water  Camping Grounds  Areas Outside a Religious Facilityb) (b) A Building that is occupied by twenty (20) or more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)-month period. (The days and weeks need not be consecutive.)  Religious Facilities  General Stores  Office Buildings  Roller Skating Rinks  Community Centers  4-H Facilitiesc) A Facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate  Hospitals  Day-Care Facilities  Prisons  Retirement Facilities  Schools  Assisted-Living Facilities 20
    • HCA – Identified Site Identified Site PIR PIR PIR PIR 21
    • HCA – Identified Site Potential Impact Radius PIR  0.69 pd 2 p = 1200 psi d = 20-inch PIR  0.69 (1200)20 2 PIR  478 feetPIR = Radius of a Circular Area in Feet Surrounding the Point of Failure Identified Site p = Maximum Allowable Operating Pressure (MAOP) in the pipeline segment in pounds per square inch d = Nominal Diameter of the Pipeline in Inches. 22
    • Steps to a Baseline Assessment Plan Activity Purpose PlanThreat Identification Addresses All Threats & Evaluation (9 Categories) Selects AppropriateAssessment Method Assessment Method Baseline Selection for Each Identified Assessment Plan Threat Prioritized Risk Analysis Risk Ranking & Prioritization of Assessments 23
    • Threat Identification Prescriptive Approach Performance Based Approach 9 Categories 21 Specific Threats. (a) Time Dependent (a) Time Dependent1 (1) External Corrosion (1) External Corrosion (2) Internal Corrosion 1 (2) Internal Corrosion2 (3) Stress Corrosion Cracking 2 (3) Stress Corrosion Cracking3 3 (b) Static or Resident (b) Static or Resident4 (1) Manufacturing Related Defects (1) Manufacturing Related Defects 4  Defective Pipe Seam  Defective Pipe Seam  Defective Pipe 5  Defective Pipe5 (2) Welding / Fabrication Related (2) Welding / Fabrication Related  Defective Pipe Girth Weld 6  Defective Pipe Girth Weld  Defective Fabrication Weld 7  Defective Fabrication Weld  Wrinkle Bend or Buckle 8  Wrinkle Bend or Buckle  Stripped Threads / Broken Pipe / 9  Stripped Threads / Broken Pipe / Coupling Failure Coupling Failure6 (3) Equipment Failures (3) Equipment Failures  Gasket O-ring failure 10  Gasket O-ring failure  Control / Relief Equipment Malfunction 11  Control / Relief Equipment Malfunction  Seal / Pump Packing Failure 12  Seal / Pump Packing Failure  Miscellaneous 13  Miscellaneous (c) Time Independent (c) Time Independent (1) Third Party / Mechanical Damage 14 (1) Third Party / Mechanical Damage7  Damage by 1st, 2nd,or 3rd Parties 15  Damage by 1st, 2nd,or 3rd Parties  Previously Damaged Pipe 16  Previously Damaged Pipe.  Vandalism  Vandalism8 (2) Incorrect Operations – Human Error 17 (2) Incorrect Operations – Human Error  Incorrect Operations  Incorrect Operations9 (3) Weather Related and Outside Force 18 (3) Weather Related and Outside Force  Cold Weather 19  Cold Weather  Lightning 20  Lightning  Heavy Rains or Floods 21  Heavy Rains or Floods  Earth Movements  Earth Movements 24
    • Assessment Method Selection • Inline Inspection – Metal Loss Tools – Crack Detection Tools – Caliper / Geometry Tools • Pressure Test – 49 CFR 192 Subpart J Pressure Test – Spike Test • Direct Assessment – External Corrosion Direct Assessment – Internal Corrosion Direct Assessment – Stress Corrosion Cracking Direct Assessment • Other Approved Technology 25
    • Risk Analysis & PrioritizationSingle Threat: Most CommonRiski = Pi x CiPipeline Segment:Consider All 9 Threat Categories 9Risk = (P1 x C1 )  (P2 x C 2 ) . (P9 x C9 ) i 1where: P = Probability of failure C = Consequence of failure1 to 9 = Threat Category 26
    • Baseline Assessment Plan Risk Analysis and HCA Assessment Method Assessment Method Prioritization Method Selection SelectionRisk Risk Section HCA HCA HCA Assessment Assessment Assessment AssessmentRank Score Pipeline Section Length Method ID Miles 1 Date 2 Date 1 4956 River Road to Griffin Tap 8.7 PIR 105 3.5 ECDA Jan 2012 ICDA Jan 2012 2 3013 Brookside Station to Valve 25 9.8 PIR 65 2.4 ECDA Mar 2012 ICDA Mar 2012 3 2835 Valve 27 to Raven Station 8.3 PIR 78 1.2 Press Test Aug 2012 Spike Test Aug 2012 4 2530 Fairview Station to South River Valve 7.2 PIR 21 2.1 ILI - MFL Nov 2012 Caliper Nov 2012 5 2298 Preston Tap to Valve 20 6.9 PIR 107 0.9 ECDA 1st Qtr 2013 ICDA 1st Qtr 2013 6 1756 Larkin Street Trap to Valve 13 8.4 PIR 86 1.6 ILI - MFL 2nd Qtr 2013 Caliper 2nd Qtr 2013 7 1406 Valve 11 to Edgebrook tap 5.6 PIR 92 0.7 ILI - MFL 2nd Qtr 2013 Caliper 2nd 2013 27
    • Pipeline Integrity Management Trends Gas Transmission Integrity ManagementAssessment Miles per Year HCA Repairs per Year 28
    • Opportunities• Remediation• Pipeline Retrofitting for Inline Inspection Tools• Direct Assessment• Hydrostatic Testing• Pipeline Replacement• Automatic Shut Off / Remote Control Valves• Preventative and Mitigative Measures 29
    • Recent Pipeline Integrity DevelopmentsPacific Gas and Electric San Bruno, CA - September 2010 Natural Gas Pipeline Rupture Fatalities: 8National Transportation Safety Board (NTSB)Probable Cause Inadequate Quality Assurance during a pipeline relocation Inadequate Pipeline Integrity Management Program • Incomplete and inaccurate pipeline information • Did not consider the design & materials in risk assessment • Failed to consider welded seam cracks in risk assessment • Assessment method was unable to detect welded seam defects • Integrity Program reviews were superficial - No Improvements made 30
    • New PHMSA Advisory BulletinsJanuary 10, 2011Establish MAOP using Record Evidence• Perform detailed Threat and Risk Analysis• Use accurate data especially to determine MAOP• Use Risk Analysis: Assessment Selection Preventive & Mitigative MeasuresMay 7, 2012Verification of Records• New annual reporting requirements for Gas Operators (2013)• Report progress toward verification of records• Records must be “Traceable, Verifiable, and Complete” 31
    • PODS – IPLOCA Work GroupFormed to:Develop Industry Standards DataStandards for New Pipeline Construction● Data structure specifically designed for Design & Construction● Improved data management over entire life cycle● Common format for data and metadata● Material tracking and traceability● As-built survey / progress tracking during construction● Common database deliverable to Operator● Ability to assure data is “Traceable, Verifiable, and Complete” 32
    • Opportunities• Pipeline Data Gathering• Records Validation• MAOP Validation• Geographic Information System Development• Field Verification 33
    • Edward J. Wiegele
    • Chief Reasons for Accidents 35
    • What is Pipeline Integrity Management & Maintenance?• Program design• Program execution (assessments/reviews)• Follow-on engineering & construction • Engineering activities include: • IMP design & O&M manual development • Risk analysis • System integrity validation and assessment • ILI program design and implementation • Construction activities include: • GIS Services, database design and analysis • Pipeline rehabilitation • Data collection and as-builting • Pipeline take up and relay • Establishing operating plans to • Hydrostatic testing keep pipelines in good working order • Anomaly digs (investigation and repair work) • Leveraging technology to • Maintenance work monitor and assess conditions real time • Call out and emergency work 36
    • Why is this important?• With the stringent regulations in US, the market for pipeline construction on existing pipelines and facilities is expanding at a rapid rate• In global markets where there are few regulations related to integrity, the existing infrastructure will need attention• This market will grow world wide, and if the incident rate increases it will accelerate 37
    • Work to Re-Build the Pipeline InfrastructureRe-building a pipeline system requires consideration of more elements than a new construction project Pipeline GIS Mapping and Records Engineering System Risk Project Assessments Management Pipeline Integrity Assessments Budget Controls Operations / Project Maintenance Elements ROW / Permitting Repairs Commissioning Procurement & Startup Construction Logistics Management 38
    • Challenges to gaining clear, timely visibility into pipeline integrityTraditional pipeline integrity analysisprocess Disparate systems and data Dated views of assets Uneven field data updates No single version of the truth Repairs not tracked 39
    • Meeting Business Goals Can Be Difficult 40
    • Assessment Method – ILI Tools Metal Loss Tools Transverse Field (TFI) MFL – Compression Wave Ultrasonics – Circumferential Field for NarrowMFL Axial Field – Indirect Liquid Coupled Direct Measure- Axial Oriented Metal Loss Measurement ment Crack Detection ToolsShear Wave Ultrasonics – Elastic Wave – Wheel Coupled Emat – Gas Only Liquid Coupled For Gas or Liquid 41
    • External Corrosion Direct Assessment 42
    • Assessing Unpiggable Pipelines through Direct AssessmentThe Direct Assessment Process is suitable for ECDA, ICDA and SCCDA. Datais mined or created at each step is also being provided back to GIS database tofurther enhance and provide an integrity driven deliverable for future riskcalculations.1) Pre-Assessment: incorporating various field and operation data gathering, data integration, and analysis and validating that DA is an acceptable assessment method2) Indirect Inspection: combination of above ground tools and calculations to flag possible corrosion sites (calls), based on the evaluation or extrapolation of the data acquired during Pre-Assessment3) Direct Examination: excavation and direct assessment to confirm corrosion at the identified sites, and remediation as defined in regulation4) Post Assessment: determine if direct assessment sites are representative of the conditions of the pipeline, and what activities needs to be conducted moving forward based on the findings from the previous steps 43
    • Pipeline Integrity Process – Where To Take Action• There is a defined process to determine the location of the integrity work which is influenced by and dependent on: • Assessment of the operating conditions of the line • GIS/integrity management data analysis • Results from ILI or Direct Assessments • Field verification digs • Environmental conditions around the line • Probability of failure • Consequence of failure • Accuracy of data and imagery • Population density 44
    • Construction work is extensive• One company in the US plans to spend $1B USD/year for 10 years on an 8000 mile system • Making lines piggable • Hydrostatic testing • Anomaly repairs from ILI runs and ECDA work • Pipeline replacements • Additional valves to improve shut down response times • New controls systems • Improvements to corrosion control systems• This type of work extended around the world represents a tremendous amount of activity well into the future 45
    • Digs and Repairs• The following is an example of an actual process for construction activities that are required following integrity assessments where a pipeline is in need of attention• Costs to assess and repair represent a significant cost advantage over replacement of the pipeline and are preferred by most operators• Repairs are less disruptive to the environment• Proper assessment methods provide accurate dig and repair locations 46
    • Excavation 47
    • Evaluation of Pipe 48
    • Integrity ManagementNon-Destructive Evaluation (NDE) 49
    • Coat and Jeep and Backfill – on to next dig 50
    • Integrity Field Repair Methods 51
    • Hydrotesting and Pipeline Replacements • Strength testing is an option vs. replacement • Smaller distances but multiple locations • Take up and relay or offset and relay • Interconnections and service disruptions are a significant issue • Coordination with Owner company operations critical
    • Tracking the Work - Correcting the Data Centerline Adjustment Blue is where the centerline was moved based on surveys and the Red line is where theoriginal centerline existed from the digitization process from the maps. The heavy set blue line is attributed to the PCM survey and was utilized to further adjust the extends of the pipeline segment. 53
    • Technology ensures improved visibility of condition of pipeline assets The operators need secure and intuitive enterprise wide access to “one version of the truth”.Access to accurate and Comply with Safety current information Confidently validate and Regulatory from anywhere “at-risk” Locations Laws 54
    • Current State of Enterprise Integrity Data Cloud Delivery Model Server GIS Department Enterprise PublicGeoEye Proprietary. © 2012GeoEye, Inc. All Rights Reserved User Types 55
    • Future State of Enterprise Integrity Data Cloud Delivery Model Server GIS Department Engineering OperationsGeoEye Proprietary. © 2012GeoEye, Inc. All Rights Reserved User Types 56
    • Integrity Information Needs to be in the Hands of Operators and Service ProvidersAccess from laptops,  tablets, smart  phones and other  portable devices. GeoEye Proprietary. © 2012 GeoEye, Inc. All Rights Reserved 57
    • Confidently Validate “at-risk” Locations 58
    • Confidently Validate “at-risk” Locations Access to current  imagery shows pipeline  proximity to critical  infrastructure 59
    • Safety and Compliance Benefits Access up to date,reliable information Avoid fines and penalties Avoid cost and negative PR 60
    • Questions?