2012 FEPA Presentation: Charlie Hall


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  • As the pipeline ages, failures on the pipeline have become more frequent. Some years ago, the pipeline industry began to get extensive attention from regulators and legislators. Bellingham, WA incident Olympic Pipeline was implementing a new SCADA system and ignored a pipeline failure which pumped liquids into a stream. Some children playing with matches were killed when the water caught on fire. Some years later, an internal corrosion leak resulted in a group that had camped alongside a bridge to be killed. Gas leaked from the pipeline migrated over to a campfire and ignited. 12 people were involved in this incident. Congress legislated increased safety standards that resulted in the Pipeline Integrity Act.
  • Code of Federal Regulations Title 49 Part 192 Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines): Final rule
  • Note implementation deadline dates
  • Scope and Implementation: Develop and Follow a Written Integrity Management Plan Plan Contains All 16 Program Elements Specified in 192.911 HCA Identification, Baseline Assessment, Threat ID/Risk Assessment, DA Plan, Remediation, Continual Evaluation, Confirmatory DA, Preventative/Mitigative Measures, Performance Metrics, Recordkeeping, Management of Change, Quality Control, Communication Plan, Submittals to Regulators, Minimization of Environmental/Safety, Identification of New HCA’s Address the Risks on Each Covered Segment Collectively, a Set of Document(s) that Systematically Define, Control, and Implement Integrity Management Take Advantage of Existing Programs (e.g., O&M) Framework ( § 907) Minimal Process Detail Process for Implementing Each Program Element Describe How Relevant Decisions Will Be Made, By Whom, and Timeline Continual Incorporation of New Info Gained from Experience Evolve Into More Detailed and Comprehensive Program Continual Improvements Plans Certain Program Elements Described in Rule Refer to “Plans” Baseline Assessment Plan DA Plan (ECDA, ICDA, SCCDA) Performance Plan Communication Plan Why Have Written Plans? Accountability Compliance Record Portability (Asset Transfer) Consistent Implementation (Personnel Turnover) Progress (Performance) Standard Threat Analysis Prescriptive - 9 Categories 1. Internal Corrosion 2. External Corrosion 3. Stress Corrosion Cracking 4. Manufacturing-Related 5. Welding/Fabrication-Related 6. Equipment 7. Third Party/Mechanical Damage 8. Incorrect Operations 9. Weather-Related and Outside Force Data Gathering and Integration Minimum Data Per B31.8S, App A Past Incident History Corrosion Control Records Continuing Surveillance Records Patrolling Records Maintenance History Internal Inspection Records All Other Conditions Specific to Each Pipeline B31.8S Requires Systematic Effort Comprehensive Plan to Collect, Review & Analyze Data Validated and Documented Data and Assumptions Timely Consideration of New Information Data Integration Aimed At Putting Together Data from Different Sources for Better Understanding of Threats Combining Data from Integrity Assessments with Threat Assessment Requires ANALYSIS Continual Improvement “ Mature” Program is Not the End of Program Development Critical Self-Assessment Study Integrity Mgt Performance Identify Areas to Improve Risk Assessment Follow B31.8S, Section 5 Consider All Identified Threats Use Risk Assessment To: Prioritize Baseline Assessments Prioritize Reassessments Determine Additional Preventive and Mitigative Measures All Approaches Entail Identification of Relevant Threats for Each Covered Segment Characterization of Likelihood and Consequences of Pipeline Failure Likelihood and Consequences Combined to Calculate Risk References Standards Rule Invokes Industry Standards Documents (or Portions Thereof) Incorporated by Reference are Invoked in Subpart O as Though Set Out in Full in the CFR Re: 49 CFR 192.7 contains list NACE RP0502-2002 (ECDA) Entirety ASME B31.8S-2001 (IM) Specific (Most) Sections §§ 2, 4, 5, 6.2, 6.3, 6.4, 7, 9, 10, 11, 12, App A, App B.2
  • Three Baseline Assessment Tools Can be Applied: 1- Smart Pigging 2- Hydrostatic Testing 3- External Corrosion Direct Assessment
  • 2012 FEPA Presentation: Charlie Hall

    2. 2. Pipeline Integrity Actions• Incident Overview • Bellingham June 10, 1999 a gasoline pipeline ruptured Washington – Gasoline leaked into two creeks in the City of Bellingham, Washington and ignited – Fireball killed three persons, injured eight other persons – Caused significant property damage – Released approximately 1/4 million gallons of gasoline causing substantial environmental damage
    3. 3. El Paso Pipeline Incident August 19, 2000, 30-inch near Carlsbad, New Mexico.
    4. 4. El Paso Pipeline Incident
    5. 5. El Paso Pipeline Incident
    6. 6. Why Pipeline Integrity?•“deterioration of a material, usually a metal, that results from a reactionwith its environment”•Soil-side corrosion typically slow progressing•Corrosion rate influenced by geological formations – “corrosive zones”
    7. 7. Why Pipeline Integrity?
    8. 8. Why Pipeline Integrity?
    9. 9. Congressional Intervention
    10. 10. Pipeline Integrity Issued Integrity Management (IM) Regulations 12/15/2003 Require Industry To:  Conduct an Analysis of the Risks and Adopt a Written IM Program in High Consequence Areas (HCA’s) by 12/17/2004  Begin Baseline Assessments: 06/17/2004  Finish Baseline Assessments: 12/17/2012  Reassess Covered Pipeline Every 7 Years
    11. 11. Gas Integrity Management Program Scope and Implementation Remediation (901, 903, 907, 913) (933) HCA Identification Prevent/Mitigative (903, 905) (935) Threat Analysis Continual Evaluation (917) (937, 939, 941, 943) Baseline Assessment Performance (919, 921) Measures(947)Direct Assessment QA, Training, Comm. (923 through 921) (915, 945, 949, 951)
    12. 12. Baseline Assessment Tool SelectionBased Upon Threat Assessment Analysis Smart Pigging Historical Information (Need Further Investigation to Find Root Cause) Hydrostatic Testing (PHMSA Gold Standard – Disrupts Service / Introduces Water) External Corrosion Direct Assessment (Major Challenge for Acceptance – Industry Worked Out Process ECDA)
    13. 13. ECDA – Four Step Process Advantage “can locate areas where defects could form in the future rather than only areas were defects have already formed”
    14. 14. ECDA – Four Step Process 1. Pre-Assessment 2. Indirect Inspection 3. Direct Examinations 4. Post Assessments FAILURE TO FOLLOW PROCESS JEOPARDIZES PIPELINE SAFETY
    15. 15. ECDA – Four Step Process Pre-Assessment “Utilization of Operational and Historical Records to Assess Potential External Corrosion Locations and to Determine Feasibility of Applying ECDA” UNDERSTANDING PIPELINE THREATS AND THE NEED TO OVERCOME THE ACCEPTANCE THAT RECORDS REVIEW REQUIRED
    16. 16. ECDA – Four Step Process Pre-AssessmentIdentify and Address Corrosion Activity Past or Old Corrosion Damage (Finds Old Damage after CP Problem Corrected) Present Activity (Yes) Future Corrosion Risks (Identifies Problem Areas)Continuous Improvement Process (If AppliedCorrectly)
    17. 17. ECDA – Four Step Process Pre-Assessment ECDA Feasibility Assessment Integrate and Analyze Data Collected Coating Electrical Shielding (ECDA Feasibility NO) Backfill with Rock Content and Rock Ledges (Remain Problem) Ground Surface Hindrances, i.e. Pavements (Drilling/Traffic Control) Adjacent Buried Metallic Structures (Stray Current Influence) Inaccessible Areas (Difficult to Access – Casings Overcome) Situations That Prevent Aboveground Measurements in Reasonable Time-Frame (Planning and Execution)
    18. 18. ECDA – Four Step Process Pre-Assessment Data Collection Data Elements: Pipe-related, Construction Related, Soils/environmental, Corrosion Control, Operational Historical Records – Better Understanding Pipeline Sufficient Data – Missing Records Subject Matter Experts - Retirements Determine ECDA Feasibility – (Missing Data) Establish ECDA Regions Similar Physical Characteristics – Role of Environment Similar Past, Present, Future Corrosion Behaviors Utilizes Similar IIT Tools Select Indirect Inspection Tools
    19. 19. ECDA – Four Step Process Indirect Inspection CIS - Indicates CP Level DCVG/ACVG - Indicates Exposed Metal Soils - Indicate Environment Corrosivity Depth - Indicate Third Party Damage Risk PCM - Indicate Current Attenuation
    20. 20. ECDA – Four Step Process Indirect Inspection “Equipment and Practices Used to Take Measurements at Ground Surface Above or Near a Pipeline to Locate or Characterize Corrosion Activity, Coating Holidays, or Other Anomalies” Data Collection, Quality, Recognition, Current Interruption, Stray Current, Casings and AC Corrosion
    21. 21. ECDA – Four Step Process Indirect Inspection Locate and define severity of coating faults where corrosion may occur or be occurring Discovery Coating Condition More Severe Conduct at least two indirect inspection tools (IIT) the entire length of the ECDA Region Casings and AC Corrosion Align and compare results from IIT tools More Stray Current Than Expected Identify, classify, and report results for Direct Examination step
    22. 22. ECDA – Four Step Process Direct Examination “Inspections and Measurements Made On the Pipe Surface at Excavations as Part of External Corrosion Direct Assessment (ECDA)” Qualified Experienced Personnel
    23. 23. Data Integration Management Tools •INSERT INTEGRATED SURVEY GRAPH
    24. 24. ECDA – Four Step Process Direct Examination
    25. 25. ECDA – Four Step Process Direct Examination
    26. 26. ECDA – Four Step Process Post Assessment “Analysis of Indirect Inspections and Direct Examinations to Assess Pipeline Integrity, Prioritize Repairs, Redefine Reassessment Intervals and Assess the Overall Effectiveness of the ECDA Process”
    27. 27. ECDA – Four Step Process Direct Examination Process Validation Remaining Life Calculation Define Reassessment Interval Define Effectiveness Measures Continuous Improvement Reassess ECDA Feasibility