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Direct Assessment Basics

Direct Assessment Basics. Richard Lopez Office of Pipeline Safety Southwest Region. Why Direct Assessment?. Alternative to ILI or Hydro Test When Not Feasible or Practical Many Gas Transmission Pipelines are “Not Piggable”

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Direct Assessment Basics

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  1. Direct Assessment Basics Richard Lopez Office of Pipeline Safety Southwest Region

  2. Why Direct Assessment? • Alternative to ILI or Hydro Test When Not Feasible or Practical • Many Gas Transmission Pipelines are “Not Piggable” • The Cost to Make Them Piggable can be Prohibitive (from $1M to $8M per mile)

  3. Why Direct Assessment? • ILI or Hydro-testing Could Cause Customer Supply Interruptions • LDC Laterals Often Sole Source Supply • Pipeline Safety Improvement Act 2002 – Section 23 • TPSSC Equivalency Recommendation

  4. Factors Impeding Piggability • Telescopic Connections • Small Diameter Pipelines • Short Pipelines • Sharp Radius Bends

  5. Factors Impeding Piggability • Less than Full Opening Valves • No Alternate Supply if Pig is “Hung Up” • Low Pressure & Low Flow Conditions • Scheduling and Coordination is an Anti-trust Issue

  6. Features in Common with ILI • Indirect Examinations • Validation/Excavation/Direct Exam • Integrate & Analyze Data • Identify & Address Data Gaps • Identify Remediation Needs • Determine Re-assessment Intervals

  7. Factors Impeding Hydro-Test • Service Interruptions • Sole Source Supplies • Concerns of Causing Pipeline Damage • Dewatering Concerns/Difficult to Dry

  8. Factors Impeding Hydro-Test • Dewatering Concerns/Difficult to Dry • Growth of Sub-critical Defects • Water Availability & Disposal • No Characterization of Future Risk

  9. DA Basics - Overview • Distinct Assessment Process for each Applicable Threat (i.e., EC, IC, & SCC) • Scope of DA as an IM Assessment is more Limited than either ILI or Hydro

  10. DA Basics - Overview • May be the Assessment Method of Choice (esp. for Non-piggable Lines and Low-Stress Gas Lines that cannot be Hydro Tested) • Involves Integration of Risk Factor Data to Identify Potential Threats

  11. Keys to Successful DA • Expertise, Skill, Experience • Follow NACE Standards • Document Justifications for Not Implementing “Should” and “May” Recommendations in the Standards • Documents Reasons for Program Decisions and Options Selected

  12. Keys to Successful DA (cont.) • Data Management • Collection, Integration, Analysis • Data Quality • Understand Limitations of DA • Provide Detailed Procedures for All Process Steps

  13. Today’s Discussion will Focus on ECDA • NACE RP0502 has been Issued • ECDA Process is More Mature than ICDA or SCCDA • Overview of NACE RP0502 Process for ECDA

  14. Limitations of ECDA • ECDA Can Not Deal With: • Lines Susceptible to Seam Failure • Near-neutral pH SCC • Fatigue Failures in Liquid Lines • Internal Corrosion • Plastic Pipe • Pipe in Shielded Areas

  15. Limitations of ECDA • ECDA has Limited Applicability to: • Mechanical Damage (Only to the Degree that Coating is also Damaged)

  16. 4 Step ECDA Process of NACE RP0502 • Pre-assessment • Indirect Assessment • Direct Physical Examination • Post-assessment

  17. Pre-assessment • Process Similar to Risk Assessment • Assemble and Analyze Risk Factor Data

  18. Pre-assessment • Purpose: • Determine Whether ECDA Process is Appropriate and Define “ECDA Regions” • Select Appropriate Indirect Inspection Tools (e.g., CIS, DCVG, PCM, C-SCAN) • Complementary Primary and Secondary Tools are Required • Identify Inspection Expectations

  19. Pre-assessment • Data Collection (Table 1 of NACE Standard) • Pipe Related • Construction Related • Soils/Environmental • Corrosion Protection • Pipeline Operations

  20. Pre-assessment • ECDA Indirect Insp. Tool Feasibility • Complementary Tools – Evaluate pipe with different technologies (see table 2 of NACE RP0502)

  21. Pre-assessment • Feasibility Influenced by: • Degree of Shielding (Coating type, Terrain) • Accessibility (Pavement, Water Crossings, Casings)

  22. Pre-assessment • Establish ECDA feasibility regions • Determine which indirect methods are applicable to each region • Tools may vary from region to region

  23. Pre-assessment • What is a Region? • Segment is a Continuous Length of Pipe • Regions are Subsets of One Segment • Characterized by Common Attributes • Pipe with Similar Construction and Environmental Characteristics • Use of Same Indirect Inspection Tools Throughout the Region is Appropriate

  24. Indirect Inspection • Close Interval Survey (CIS) • Direct Current Voltage Gradient (DCVG) • C-Scan • Pipeline Current Mapper (PCM) • Alternating Current Voltage Gradient (ACVG) (PCM with A-Frame)

  25. Indirect Inspection • Pearson • Ultrasonic • Waveform • Soil Resistivity, Pipe Depth

  26. Indirect Inspection • Direct Current • Measure Structure Potential • Identify Locations of High CP Demand to Small Area

  27. Indirect Inspection • Alternating Current • Apply AC signal • Determine Amount of Current Drain (i.e., Grounding) and Location • Identify Locations of High AC Current

  28. Indirect Inspection • Types of Direct Current Tools • Close Interval Survey (CIS or CIPS) • Direct Current Voltage Gradient (DCVG) • Types of Alternating Current Tools • Alternating Current Voltage Gradient (ACVG) • Pearson Survey • AC Attenuation (PCM, EM, C-Scan)

  29. Indirect Inspection • Purpose: • Locate Areas Where Coating Damage May Exist • Evaluate Whether Corrosion Activity is Present • Apply Primary and Secondary Tools

  30. Indirect Inspection • Timing Such That Conditions are Same • Overlay and Evaluate Data for Clarity, Quality, and Consistency • Distance Correlation Should be Good

  31. Indirect Inspection via CIS • May Detect Large Coating Holidays • Measure Pipe to Soil Potential at Regular Intervals (2.5 – 5 ft. Desirable) • Protection criteria • -850mV polarized potential • 100mV polarization

  32. Indirect Inspection via CIS • Secondary Interpretation • Change in potential profile • Amount of IR drop (Low or High) • ON and OFF Readings are Desirable

  33. Indirect Inspection via DCVG • Measures Voltage Gradient in Soil • CP Current Greatest Where Coating is Damaged

  34. Indirect Inspection via DCVG • Interrupt Rectifier to Determine ∆V • One Electrode • Two Electrodes • Parallel or perpendicular to ROW • Coating Holiday Size Indicated by % ∆V • Triangulation Used to Locate Holiday

  35. Indirect Inspection via ACVG • Impose AC current • Measure Gradient Between 2 Electrodes Spaced ~1m Apart • Gradient Corresponds to Current Flow

  36. Direct Physical Examination • Establish “Priority Categories” from Indirect Inspection • Excavations for Direct Examination

  37. Direct Physical Examination • Purpose: • Confirm Presence of Corrosion Activity • Determine Need for Repair or Mitigation • Evaluate Likely Corrosion Growth Rate • Support Adjustments to Excavation Scope • Evaluate Need for Other Technology

  38. Direct Physical Examination • Categorize Indications • Immediate Action Required • Schedule for Action Required • Suitable for Monitoring • Excavate and Collect Data Where Corrosion is Most Likely

  39. Direct Physical Examination • Characterize Coating and Corrosion Anomalies • Establish Corrosion Severity for Remaining Strength Analysis • Determine Root Cause

  40. Direct Physical Examination • In-process Evaluation, Re-categorization, Guidelines on Number of Direct Examinations • All “Immediate” Must be Excavated • Prioritize “Scheduled” & “Monitored” • If >20% Wall Loss Found, Examine at Least 1 More (2 More for 1st ECDA)

  41. Direct Physical Examination • If No Indications • At Least 1, and 2 for 1st ECDA • Choose More Corrosive Region

  42. Direct Physical Examination • Dig a Bell Hole • Visual Inspection • Coating Condition • Ultrasonic Testing • Radiography • Soil Chemistry and Resistivity

  43. Direct Physical Examination • Collect Data at Dig Site • Pipe to Soil Potentials • Soil Resistivity • Soil and Water Sampling • Under-film pH • Bacteria & SCC Related Data • Photographic Documentation

  44. Direct Physical Examination • Characterize Coating and Corrosion Anomalies • Coating Condition • Adhesion, Under Film Liquid, % Bare • Corrosion Analysis • Corrosion Morphology Classification • Damage Mapping • MPI Analysis for SCC

  45. Direct Physical Examination • Remaining Strength Analysis • ASME B31G • RSTRENG

  46. Direct Physical Examination • Determine Root Cause • For Example • Low CP • Interference • MIC • Disbonded Coatings • Construction Practices • 3rd Party Damage

  47. Post-Assessment • Evaluates Composite Set of Data and Assessment Results • Sets Re-inspection Intervals • Validates ECDA Process

  48. Post-Assessment • Remaining Life - Maximum Flaw • Maximum Remaining Flaw Size Taken Same as Most Severe that was Found • Second Maximum if Unique • If No Corrosion Defects, Same as New • Other (e.g., Statistical)

  49. Post-Assessment • Remaining Life Growth Rate • Measured Corrosion Rate • Maximum Depth / Burial Time • 16mpy (80% C.I. for Corrosion Tests) • 0.3mm/y if at Least 40mV CP Demonstrated

  50. Post-Assessment • Linear Polarization Resistance (LPR) • Probe or Existing Buried Coupon • Coupon Retrieval • Assess ECDA Effectiveness

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