BASIC CONCEPTS IN PIPELINE INTEGRITY MANAGEMENT

1. BASIC CONCEPTS IN PIPELINE INTEGRITY MANAGEMENT Aida Lopez-Garrity, P.Eng, MSc. Kevin Parker CC Technologies Puebla, Mexico – November 11, 2003

2. Topics Covered • Pipeline Integrity Concept • Purpose of Pipeline Integrity Programs • Difference between Natural Gas and Hazardous Liquid Pipelines - Regulations • Threats to Pipeline Integrity • Risk Assessment Issues • Direct Assessment - ECDA

3. Pipeline Integrity Assessment • Pipeline Integrity Assessment is a process which includes inspection of pipeline facilities, evaluating the indications resulting from the inspections, examining the pipe using a variety of techniques, evaluating the results of the examination, and characterizing the evaluation by defect type and severity and determining the resulting integrity of the pipeline through analysis

4. Purpose of Pipeline Integrity Programs • The U.S. Department of Transportation (OPS) is proposing to change pipeline safety regulations to require operators of certain pipelines to validate the integrity of their pipelines in high consequence areas

5. Regulations Related to Liquid Pipelines • 49 CFR Part 195 “Pipeline Integrity Management in High Consequence areas” • Covered pipelines are categorized as follows: • Category 1: pipelines existing on May 29, 2001 that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipelines • Category 2: pipelines existing on May 29, 2001 that were owned or operated by an operator who owned or operated less than 500 or more miles of pipelines • Category 3: pipelines constructed after May 29, 2001

6. Programs and Practices to Manage Pipeline Integrity in Liquid Pipelines • Develop a written management program that addresses the risks on each segment of pipeline • Category 1: March 31, 2002 • Category 2: February 18, 2003 • Category 3: 1 year after the pipeline begins operation

7. Programs and Practices to Manage Pipeline Integrity in Liquid Pipelines • Include in the program an identification of each pipeline not later than: • Category 1: December 31, 2001 • Category 2: November 18, 2002 • Category 3: date the pipeline begins operation

8. Programs and Practices to Manage Pipeline Integrity in Liquid Pipelines • Include in the program a plan to carry out baseline assessments of the line pipe and this should include: 1. The methods selected to assess the integrity of the pipeline by any of the following methods: • Internal Inspection Tool ILI • Pressure test • Other technology that the operator demonstrates can provide an equivalent understanding of the line pipe (notification to OPS must take place 90 days before conducting the assessment)

9. Programs and Practices to Manage Pipeline Integrity in Liquid Pipelines • A schedule for completing the integrity assessment • An explanation of the assessment method selected and evaluation of risk factors considered in establishing the assessment schedule • Complete assessment, prior assessment and newly-identified areas deadlines have been set • DA was completed after the liquid gas rule was ready

10. Regulations Related to Gas Pipelines

11. Regulatory Issues • Department of Transportation proposed rule (49 CFR Part 192) dated January 28, 2003 titled “Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)

12. Federal Regulation

13. Regulatory Issues • This proposed rule will satisfy Congressional mandates for RSPA/OPS to prescribe standards that establish criteria for identifying each gas pipeline facility located in a HCA and to prescribe standards requiring the periodic inspection of pipelines located in these areas

14. Regulatory Issues • Pipeline Integrity can be best assured by requiring each operator to: • Implement a comprehensive IMP • Conduct a baseline assessment and periodic reassessments focused on identifying and characterizing applicable threats • Mitigate significant defects discovered in this process • Monitor the effectiveness of their programs so appropriate modifications can be recognized and implemented

15. Regulatory Issues • Assessment Methods • Internal Inspection ILI • Pressure Testing • Direct Assessment (data gathering, indirect examination, and post assessment evaluation) • Any other method that can provide an equivalent understanding of the condition of line pipe

16. Regulatory Issues • The rule proposes to allow direct assessment as a supplemental assessment method on: • Any covered pipeline section • As a primary assessment method on a covered pipeline where ILI and pressure testing are not possible or economically feasible • Where the pipeline operates at low stress • Can also be used to evaluate third party damage

17. Regulatory Issues • All three threats considered under direct assessment: • External Corrosion • Internal Corrosion • SCC

18. Regulatory Issues • Another concept in the proposed rule is to use Confirmatory Direct Assessment to evaluate a segment for the presence of corrosion and third party damage

19. Trade Group Associations • On August 6, 2002, OPS issued a final rule on the definition of a high consequence area (HCA). Then on January 28, 2003, OPS issued a notice of proposed rulemaking regarding integrity management for natural gas transmission pipelines in high consequence areas (HCAs). AGA, along APGA and INGAA, have made significant strides in getting OPS to change their concepts initially reflected in these rulemakings. While a final rule for integrity management is not expected until later this year, operators of natural gas transmission lines are already faced with integrity requirements under the Pipeline Safety Improvement Act of 2002.

20. ASME B31.8S • Managing System Integrity of Gas Pipelines • Specifically design to provide the operator with the information necessary to develop and implement an effective integrity management program • Appendix B – Direct Assessment process

21. Proposed IM Rule for Gas Transmission • High Consequence Areas • Operator Requirements for Compliance • Risk Assessment • Integrity Assessment Methods for HCA’s • Time Frames • Responding to Integrity Issues in HCA’s • Re-Assessments of HCA’s

22. High Consequence Areas (HCA’S) • IM Ruling Only Applies to HCA’s • Operator Must Identify All HCA’s • Proposed Ruling Defines how to Identify HCA’s • Method Revised Once and Could be Again – Overly Complicated • One Year from Final Rule to Complete Task

23. High Consequence Areas (HCA’S) • Class 3 or 4 Locations are HCA’s • Sub-divided into High & Moderate Impact Zones using the Potential Impact Circle (PIC) • Moderate is Outside an PIC • PIC has a Threshold Radius (TR) Based on a Calculated Potential Impact Radius (PIR). • PIC Radius = 0.69*Dia*SQRT of Pressure • TR Extends for Certain Conditions

24. High Consequence Areas (HCA’S) • Class 1 or 2 Locations - HCA’s are Determined Differently • A corridor of 1000 ft (or larger) is used for a Cluster of 20+ Buildings Intended for People • Corridors of 300ft, 660 ft or 1000ft depending on Dia & Pressure used for “Identified Sites”. • Identified Sites are Buildings or Outside Areas with Specific Definitions

25. Operator Requirements for Compliance • Written Program - Complete within 12 Months • Must follow ASME B31.8S for Implementation • Prescriptive or Performance based Options • Risk Analysis Required – To Identify Threats & Rank HCA’s • Must have a Baseline Plan • Plan Must Address the Identified Integrity Threats • Must Justify Integrity Assessment Method(s)

26. Operator Requirements for Compliance • Must Complete Assessments within Certain Time Periods • Must Address Discovered Integrity Issues • Must Re-assess Everything on a Continual Basis • One or more HCA’s – Plan and Implementation Required • Must Evaluate Plan Performance • Implement Preventative & Mitigation Measures • Have a QA and Communication Process • Keep Records

27. Risk Assessment • Must Conduct Based on ASME B31.8S • Prescription or Performance Based • Performance Based has to be Rigorous • Benefits of Performance Based Assessment are • Deviate from the Prescriptive Rules in ASME B31.8S • Longer Re-inspection Intervals • Longer Remediation Timescales • Can Use Direct Assessment Only (for Corrosion Caused Metal Loss and SCC) • Risk Assessment Must be used for Prioritizing Integrity Assessments

28. Integrity Assessment Methods for HCA’s • In-Line Inspection (Internal inspection) • Pressure Test • Direct Assessment • ECDA • ICDA • SCCDA • Confirmatory Direct Assessment • Other Technology – 180 Day Notification Required If Used Requires a Specific Implementation Plan

29. Integrity Assessment Methods for HCA’s • Special Rules Apply For Specific Threats e.g. • Third Party Damage • Cyclic Fatigue • Manufacturing or Construction Defects • Low Frequency ERW Pipe or Lap Welded Pipe • Corrosion Caused Metal Loss

30. Integrity Threat Classification • Gas Pipeline incidents data has been analyzed and classified by the Pipeline Research Committee International (PRCI) into 22 root causes. One of the 22 causes was reported by operators by “unknown” (no rot cause or causes were identified. The remaining 21 threats have been grouped into (9) categories of related failure types

31. Integrity Threat Classification • A) Time Dependent • External Corrosion • Internal corrosion • Stress Corrosion Cracking

32. Integrity Threat Classification • B) Stable • Manufacturing Related Defects • Defective pipe seam • Defective pipe • Welding/Fabrication Related • Defective pipe girth weld • Defective fabrication weld • Wrinkle bend or buckle • Stripped threats/broken pipe/coupling failure

33. Integrity Threat Classification • Equipment • Gasket O-ring failure • Control/Relief equipment malfunction • Seal/pump packing failure • Miscellaneous

34. Integrity Threat Classification • C) Time Independent • Third Party/Mechanical Damage • Incorrect Operations • Weather related and outside force • Cold weather • Lightning • Heavy rains or floods • Earth movements

35. Time Frames • Internal Inspection or Pressure Test • Start with the Highest Risk HCA • All HCA’s 100% Complete by December 2012 • Complete 50% of HCA’s Based on Risk by December 2007 • Except for Class 3 or 4 Locations of Moderate Impact – 100% Complete by December 2015

36. Time Frames • Direct Assessment • Start with the Highest Risk HCA • All HCA’s Complete by December 2009 • Complete 50% of All HCA’s Based on Risk by December 2006 • Except for Class 3 or 4 Locations of Moderate Impact – 100% Complete by December 2012

37. Responding to Integrity Issues in HCA’s • Discovery of a Condition in an HCA – 180 Days to Determine Threat to Integrity Except for • Immediate Remediation Conditions • Predicted Failure Pressure < 1.1 x Established MOP at Location • Any Dent with a Stress Raiser Regardless of Size or Orientation • An Anomaly that Requires Immediate Action • Must Reduce Operating Pressure to a Safe Level • Must Follow ASME B31.8S, Section 7

38. Responding to Integrity Issues in HCA’s • 180 Day Remediation Conditions • Plain Dents > 6% of OD Regardless of Orientation • Plain Dents > 2% of OD Affecting a Girth Weld or Seam Weld • Longer Than 180 Day Remediation Conditions • Only If Anomaly Cannot Grow to a Critical Stage • Only If Internal Inspection used – • An Anomaly with a Predicted Failure Pressure > 1.1 x Established MOP at Location • Any Anomalous Condition Not Covered Above

39. Re-Assessments of HCA’s • As Frequently as Needed – Operator Decides • But No Longer Than 7 Years Unless A Confirmatory Direct Assessment is Carried Out • Very Specific Rules Apply • Only Available with Performance Plan • Internal Inspection or Pressure Test - Maximum Periods are • 10 Years - Equal to or Greater Than 50% SMYS • 15 Years Equal to or Less Than 50% SMYS • Maximum Periods must be Justifiable

40. Re-Assessments of HCA’s • Direct Assessment – Maximum Periods are • 5 Years for Remediation by Sampling • 10 Years for Remediation of All Anomalies

41. Data Gathering • Identify Company Data Sources for IMP Development • Evaluate Records and Procedures for • Pipeline Design and Construction • Pipeline Operation • Pipeline Maintenance • Service History • Prior Integrity Assessments • Evaluate systems already in place – database, risk assessment, etc. • Document Results

42. HCA Identification Impact Assessment • Apply Final Rule Definitions of HCA’s to System to: • Identify HCA Locations and Classify • Determine Potential Impact Zones • Justify Non-HCA Locations • Document Results

43. Threat Identification, Data Integration and Risk Assessment • Review Data from Phases 1 and 2 for HCA Locations • Identify Threats Specific to HCA’s, • Identify Threats Specific to Non-HCA’s, • Justify Non-Applicable Threats • Carry Out a Risk Assessment on HCA Segments to Determine: • Likelihood of Failure, and • Consequences of Failure • Document Results Spreadsheet Model or Vendor Software

44. Develop BaselineAssessment Plan • Decide on Integrity Assessment Method(s): • In-Line Inspection • Pressure Testing • Direct Assessment • Method(s) Depend on: • Nature of Identified Threats • Number and Location of HCA’s • Cost – Benefit Considerations • Technically Possible • Develop Plan(s) and Schedule • Document Results

45. Integrity Management Program • A Typical IMP will have Sections: • Threat Identification, Data Integration & Risk Assessment – Current Results & Justifications • Baseline Assessment Plan for Line Pipe in HCA’s – Justification for Chosen Method(s), Direct Assessment Plan if Required, and Implementation Timescale • Integrity Management of Facilities Other than Line Pipe in HCA’s (May Not be Applicable) • Process for Conducting Integrity Assessments – Satisfies Requirement for Minimizing Safety and Environmental Risks

46. Integrity Management Program • A Typical IMP should also include: • Review of Integrity Assessments Results by Qualified Personnel • Criteria for Remedial Action of Line Pipe in HCA’s and Non-HCA’s • Procedure for Identifying Preventative & Mitigation Measures to Protect HCA’s • Integrity Program Performance Measures • Procedure for Continual Evaluation & Assessment of Pipeline Integrity in HCA’s – Including a Confirmatory Direct Assessment Plan if Required • Quality Control Process

47. Integrity Management Program • A Typical IMP should also have a Communications Plan • Management of Change • Integrity Management Program Review Procedure • Record Keeping • Required Notifications to the Office of Pipeline Safety • Personnel Training

48. Direct Assessment

49. History of Direct Assessment • Originally Proposed during Development of Congressional Bills on Pipeline Safety • Proposed as an Alternative to ILI and Hydrostatic Testing • Termed Direct Examination (Later Changed to Direct Assessment ) • INGAA Initiative to Develop Framework of ECDA Process (ICDA Followed)

50. DA Background • Integrity verification for high consequence areas • In-line inspection • Hydrostatic testing • Direct assessment • Each tool achieves comparable results and complementary results • Tools are selected based on operating conditions • All tools are routinely used now