Gas Integrity Management Rule Protocols

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Gas Integrity Management RuleProtocols

• 49 CFR 192
• Pipeline Integrity Management
• January 2005
• Welcome

2
Natural Gas Transmission PipelineIntegrity
Management Oversight Program

• Atlanta, Georgia
• January 2005
• OPS NAPSR
• Welcome You

3
Welcome and Opening Remarks

• Jeff Wiese
• OPS Program Development Director

4
Welcome

• Acknowledgements
• Introductions
• Administrative Announcements
• Safety and Comfort Directions
• Web Cast Instruction
• QA
• Agenda Review

5
Acknowledgements

• NAPSR
• OPS Key Partner in Pipeline Safety
• Major contributors to the shape and direction of
  IMP oversight
• Our alignment works for everyone concerned

6
Acknowledgements

• Industry
• INGAA, AGA, SGA, MEA, NEA
• Actively involved and not shy
• BGE, Duke, El Paso, PGE
• Essential reality check
• Standards Committees
• Particularly ASME NACE

7
Administrative Announcements

• Slides webcast will be available online
• http//primis.rspa.dot.gov/gasimp
• Attendance lists will NOT be available
• Playing strictly to the agenda

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Safety Comfort

• Emergency Direction
• Restrooms
• Cell Phones Pagers

9
Web Cast

• We web casting to allow participation by a larger
  audience please register
• Causes us to use very plain text for
  presentations
• For help or to submit questions
  GASIMP_at_RSPA.DOT.GOV

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Q A Sessions

• QA Session at End of Each Day
• Via e-mail (GASIMP_at_RSPA.dot.gov)
• 3x5 cards (attendees)
• Questions from the floor (attendees)
• Please identify yourself each time you speak

11
Agenda Review

• Starting promptly _at_ 830a ET
• Agenda available online ET
• Ambitious schedule, so well be following the
  agenda as closely as possible
• Audience door closing is cue
• Introduction of OPS DAA

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Gas Integrity ManagementPublic Workshop

• Relationship of Gas IMP to
• OPS Strategy
• Ted Willke
• Deputy Associate Administrator
• Office of Pipeline Safety
• Atlanta Georgia
• January 19, 2005

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OPS Strategic Focus

• Improve the safety of the nations pipelines
• Provide the basis for increased public confidence
  in pipeline safety

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Recent OPS Strategic Activities (1)

• Worked to restore our credibility by
• Addressing Congressional mandates resolving
  NTSB issues
• Improving the knowledge and skill of our
  technical and inspection staff
• Strengthening our internal management practices
  and data
• Strengthened our relationship with the states,
  our key safety partners

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Recent OPS Strategic Activities (2)

• Promulgated new regulations to ensure
• The pipeline is in better condition
• The operator implements management practices that
  improve safety
• The people responsible for safety are better able
  to perform their responsibilities

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Three Major Pillars of Our Go-Forward Strategy

• Risk and integrity management
• Shared knowledge and responsibility
• Expanding our role in a changing world

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Key Strategies

• Risk and Integrity Management
• Better problem identification and understanding
• Improved standards and regulations
• More efficient and consistent inspection and
  enforcement
• More risk-based allocation of resources
• Better performance evaluation

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Key Strategies

• Shared knowledge and responsibility
• Better preparation and training
• Better technologies
• Better informed stakeholders

19
Key Strategies

• Expanding our role
• Support for national energy policy
• Protecting national infrastructure
• Expanded support for local officials

20
Gas IMP is a Significant Element in Implementing
our Strategy

• Largest OPS regulatory action
• Unprecedented effort by industry
• Cooperation with NAPSR from the outset
• Numerous National Consensus Standards
• Development and demonstration of needed new
  technologies processes

21
Getting to Where We are has Required Broad
Cooperation

• Industry has stepped forward
• The states have participated to an unprecedented
  degree
• The OPS staff has grown to meet the challenge

22
Welcome and Opening Remarks

• Jeff Wiese
• OPS Program Development Director

23
Integrity Management Goals

• Accelerate assessments of pipelines in High
  Consequence Areas (HCAs)
• Promote rigorous, systematic management of
  pipeline integrity
• Enhance governmental oversight of company
  integrity plans and programs
• Increase confidence in pipeline safety

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Integrity Management Objectives

• IMP oversight objectives
• Clearly communicated regulatory expectations
• Nationally consistent oversight program
• Quality of results through well trained
  inspection workforce
• Program development process has been, and will
  continue to be, extremely transparent
• Oversight procedures and support are available
  via the internet http//primis.rspa.dot.gov/iim

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Clear Regulatory Expectations

• Communicating requirements
• Operators should use
• http//primis.rspa.dot.gov/gasimp
• FAQs, inspection protocols, flow charts, key
  documents, timelines, etc.
• Public Meetings 05/2004 today
• Interacting with industry
• Pilot inspections
• Feedback on FAQs and protocols
• Technical studies and research

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Nationally Consistent Oversight

• HQ/Field partnership for program development
• Standardized inspection protocols
• Detailed field guidance for inspectors
• Field testing and reset meetings
• Aggressive training schedule for Federal and
  State inspectors
• IT solutions team collaboration

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Quality of Results

• National consistent approach
• Federal-State, HQ-field team approach for balance
  (11/2003)
• Feedback to operator after audit
• Structured, but evolving enforcement
• NOPV for serious issues
• NOA to foster continuous improvement

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What Have We Accomplished?

• Designed systematic approach to oversight
• Designed and developed the Integrity Management
  Website and IMP Team collaboration application
• Conducted initial public meeting focused on the
  rule in May 2004
• Developed FAQs to address public and industry
  questions

29
What Have We Accomplished?

• Developed inspection protocols and guidance for
  inspectors
• Pilot tested, adjusted, and publicly disseminated
  the inspection protocols
• Developed training for our Federal-State team

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Gas IM Inspection Focus

• Organizational commitment
• Quality of management processes
• Personnel qualifications
• Clearly documented implementation basis
• Continual improvement of program

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Gas IM Inspections

• Initial IMP inspections will be focused on IM
  Programs
• Ultimately IMP inspections may be integrated with
  other inspections
• Inspection integration
• Spectrum of performance data
• More complete picture of operator performance

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Gas IM Learning Curve

• Goal safer and more efficiently managed
  pipeline integrity
• Experience collection and analysis
• Lessons learned extracted/shared
• Data collection - significant effort
• Requires regular communication public,
  industry, regulators, and vendor communities . . .

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Gas Integrity Management Oversight Program
Development

• Zach Barrett
• Introduction
• January 2005

34
Gas Integrity Management

• Public Web Site
• Resource/Communication Tool
• http//primis.rspa.dot.gov/gasimp/

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Operator Resources

• Gas Integrity Management Web Site
• Key Documents
• Performance Reporting
• Fact Sheet
• Flowchart of Rule
• Register and View Meetings

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Operator Resources

• Gas Integrity Management Web Site
• Key Documents
• Performance Reporting
• Fact Sheet
• Flowchart of Rule
• Register and View Meetings

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Performance Reporting

• OPS Has Issued an Advisory Bulletin for Reports
  Due February 28, 2005
• Gas Transmission Operators were also Mailed a
  Copy
• Reports are to Cover Period From January 1 to
  December 31, 2004

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Operator Resources

• Gas Integrity Management Web Site
• Key Documents
• Performance Reporting
• Fact Sheet
• Flowchart of Rule
• Register and View Meetings

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Operator Resources

• Gas Integrity Management Web Site
• Key Documents
• Performance Reporting
• Fact Sheet
• Flowchart of Rule
• Register and View Meetings

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Operator Resources

• Gas Integrity Management Web Site
• Key Documents
• Performance Reporting
• Fact Sheet
• Flowchart of Rule
• Register and View Meetings

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Operator Resources

• Gas Integrity Management Web Site
• OPS Communications (Links)
• Notifications
• Question or Comment
• Frequently Asked Questions (FAQs)
• Inspection Protocols

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Operator Resources

• Gas Integrity Management Web Site
• OPS Communications (Links)
• Notifications
• Question or Comment
• Frequently Asked Questions (FAQs)
• Inspection Protocols

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Notifications

• Notifications Are Required For
• Substantial Change to IM Program
• Use of Other Assessment Technology
• Can Not Meet Schedule for Evaluation and
  Remediation

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Operator Resources

• Gas Integrity Management Web Site
• OPS Communications (Links)
• Notifications
• Question or Comment
• Frequently Asked Questions (FAQs)
• Inspection Protocols

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Operator Resources

• Gas Integrity Management Web Site
• OPS Communications (Links)
• Notifications
• Question or Comment
• Frequently Asked Questions (FAQs)
• Inspection Protocols

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Operator Resources

• Gas Integrity Management Web Site
• OPS Communications (Links)
• Notifications
• Question or Comment
• Frequently Asked Questions (FAQs)
• Inspection Protocols

64
Inspection Protocol Development

• What are Inspection Protocols?
• The Inspection Protocols are a series of
  questions designed to guide pipeline safety
  inspectors in an investigative approach toward
  assessing pipeline operator compliance with the
  Gas Integrity Management Regulations

65
Inspection Protocol Development

• OPS Developed an Integrity Management Inspection
  Approach Focusing on
• Operator Processes for Managing Integrity
• Operator Process Implementation
• This is the Basis of the Inspection Protocols

66
Inspection Protocol Development

• Development Team - Established by OPS and the
  National Association of Pipeline Safety
  Representatives (NAPSR) November 6, 2003

67
Inspection Protocol Development

• Eight (8) Senior Federal Inspectors all with
  Integrity Management Experience representing the
  five (5) OPS Regions
• Five (5) Senior State Inspectors two (2) with
  Integrity Management Experience
• Ohio, New York, Nevada, Alabama, and Louisiana

68
Inspection Protocol Development

• Goals Inspection Protocol Development
• Protocol questions must be tightly aligned with
  the gas integrity regulations and referenced
  industry standards
• Clearly state compliance goal in each protocol
  question

69
Inspection Protocol Development

• Protocol Goals Cont
• Do not repeat protocols
• Support Primary Protocols with supplemental
  questions
• Protocol order should facilitate efficient
  completion of inspection

70
Inspection Protocol Development

• Draft Protocols Developed through Team Meetings
  and Posted on Gas Integrity Management Public Web
  Site - End of March 2004

71
Inspection Protocol Development

• Pilot Testing of Draft Protocols with volunteer
  pipeline operators July and August 2004 - Duke,
  El Paso, Pacific Gas Electric and Baltimore Gas
  Electric

72
Pilot Issues

• Consequence Factors in Risk Assessment (Protocol
  C.3.c)
• Risk includes consequence factors
• Required by B31.8S
• HCA Identification process is a simple
  consequence screen
• Consequence factors needed to discriminate the
  relative risk between covered segments

73
Pilot Issues

• Pressure Reduction for Immediate Repair
  Conditions (FAQ-229)
• Safety Margin is Required
• 0.72 x Predicted Failure Pressure
• Account for defect growth until repair made (up
  to one year)
• Operators may justify less safety margin Based on
  Corrosion Growth Rate

74
Pilot Issues

• New Threats (e.g., Near-Neutral SCC) (Protocol
  C.1)
• Rule Requires ALL Threats be Identified
• B31.8S, 2.2 Requires that all threats shall be
  considered

75
Pilot Issues

• Tolerance for PICs (FAQ-174)
• Following factors must be accounted for
• P/L Location Data Accuracy
• Building/Identified Site Location Accuracy
• GIS Accuracy

76
Pilot Issues

• Multiple BAPs for Each Business Entity (FAQ-38)
• Multiple BAPs are allowed, based on legal
  business entities
• Operators may aggregate all businesses into a
  single BAP at their discretion

77
Pilot Issues

• 5-Year Operating Pressure Benchmark for Stable
  MC Defects (FAQ-231)
• 5-Year benchmark determined based on 5 years
  preceding HCA Identification
• NOT a rolling 5-year

78
Pilot Issues

• Required Digs for ICDA (Protocol D.08.b.iii)
• Changed Protocol to Clarify the 2 Minimum
  Required Digs
• One in HCA at low point near beginning of ICDA
  Region
• Second in HCA near the end of the ICDA Region
  (defined as the liquid hold-up point predicted by
  the ICDA Model)

79
Pilot Issues

• Detailed Processes Required for Integrity
  Management Activities in which Operators are
  Actively Engaged (FAQ 140)
• Rule allows process development to begin with a
  Framework
• Detailed Procedures Necessary for Successful
  Implementation

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Protocol Development

• Final Protocols
• Made Publicly Available Oct. 04
• Result of Extensive, Detailed Reviews
• Incorporate Lessons Learned from Pilot Visits
• Very Tightly Tied to Rule Requirements

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Protocol Presentations

• Presented by members of the Gas IM Development
  Team
• Footer in each slide
• References to source of requirements
• FAQs

85
Tomorrow

• Federal and State Training
• Inspection Format
• Enforcement Process

86
Gas Integrity Management Rule Protocols

• Jeff Gilliam
• 49 CFR 192.903 and 905
• High Consequence Area Identification
• Protocol A
• January 2005

87
Key Elements High Consequence Area
Identification

• A.1 Program Requirements
• A.2 Potential Impact Radius (PIR)
• A.3 Identified Sites
• A.4 Identify HCAs/Class Location
• (Method 1)
• A.5 Identify HCAs/PIR (Method 2)
• A.6 Newly Identified HCAs

88
A.1 Program Requirements

• A.1 Program Requirements Processes in Place to
  Identify HCAs Using Methods 1 and/or 2
• a. Documented Processes
• b. Document the Method Used
• c. Document Covered Segment Locations
• d. HCAs identified by 12/17/2004

89
A.1.a Documentation of Methods

• 2 Methods for HCA Identification
• Operator May Use Either, or Both
• Documented Descriptions of How HCA Identification
  is Implemented
• Roles and Responsibilities
• Assurance that All of the Pipeline Has Been
  Evaluated for HCAs.

90
A.1.b Methods Used

• Documentation Specifies
• Which Methods (or Combination of Methods) Are
  Used
• Which Pipeline Segments Were Evaluated by Which
  Method
• OPS Has No Preference

91
A.1.c System Maps Segment Documentation

• Maps or Other Suitably Detailed Documentation
• Use of GIS or Similar Mapping Software
• Demonstrate System
• Overlay of HCAs With Pipeline System
• If Mapping Software is Not Used
• Describe and Demonstrate Process
• Inaccuracies

92
A.1.d Completion of HCA Identification

• Completion of HCA Identification by December
  17, 2004

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A.2 - Potential Impact Radius

• A.2 Potential Impact Radius - Meets Requirements
  of 192.903
• a. Verify the Correct Formula is Used
• b. Axial Extension of PIC

94
A.2.a Use of Potential Impact Radius Formula

• Use Most Limiting MAOP in the Segment
• Flammable Gases Other Than Natural Gas
• Use B31.8S to Derive the PIR Equation
• For Nonflammable Gases, the Entire Pipeline May
  be Treated as an HCA
• OPS Has Further Studies Underway

95
A.2.b Axial Extension of Potential Impact Radius
HCA Includes the Area Extending Axially Along the
Length of the Pipeline - Outermost Edge of 1st
PIC to the Outermost Edge of the Last PIC.
96
A.3 - Identified Sites

• A.3 Identified Sites - Verify Program Includes
  Sources Listed in 905(b)
• a. Identified Sites Must Include
• i. Outside Areas or Open Structures occupied
  by 20 People
• ii. Buildings Occupied by 20 People
• iii. Facilities With People of Limited
  Mobility

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A.3 - Identified Sites

• A.3.b. Use the Following Sources
• Routine OM Activities, AND
• Input from Public Officials
• In the Absence of Public Official Input, the
  Operator Must Use 1 of the Following
• 1. Visible Markings Such as Signs, or
• 2. Facility Licensing or Registration Data, or
• 3. Official Lists or Maps

98
A.3.b Sources of information for Identified
Sites

• Reasonable or Good Faith Effort
• Guidance in 7/17/2003 Advisory Bulletin

99
A.4 - Identification Using Class Locations
(Method 1)

• A.4.a Class Locations (Method 1)
• Class 3 and 4 Piping Locations
• Use of Existing Class Location Data and
  Identified Sites
• Operators of Pipelines Operating Below 30 SMYS -
  192.935(d) Applies

100
A.4 - Identification Using Class Locations
(Method 1)
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A.4 - Identification Using Class Locations
(Method 1)

• A.4 Using Class Locations (Method 1) Class 1
  2 Locations With PIR gt 660 Feet
• b. PIC Contains 20 Buildings
• i. May Prorate for PIRs gt 660 Feet
• Until 12/17/2006
• c. PIC Contains Identified Site

102
A.5.a - Identification Using Potential Impact
Radius (Method 2)

• A.5 Identification Using PIR (Method 2)
• a. PIC Contains 20 Buildings
• i. For PIRs gt 660 Feet, May Prorate Building
  Count
• 1. Until 12/17/06
• b. PIC Contains Identified Site

103
A.6 - Identification and Assessment of Newly
Identified HCAs

• A.6 Identification and Assessment of Newly
  Identified HCAs
• New or Revised HCA Segments Due to Changing
  Pipeline Conditions
• Operators are Expected to Remain Cognizant of
  Changes
• Newly-Identified HCA Incorporated into the IMP
  Within 1 Year

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A.6.a - Identification and Assessment of Newly
Identified HCAs
A.6 Identification and Assessment of Newly
Identified HCAs a. Operators Program Includes
Processes for New Information 1. Changes in
Pipeline MAOP, 2. Pipeline Modifications, 3.
Changes in the Commodity Transported in the
Pipeline, - continued on next slide
105
A.6.a - Identification and Assessment of Newly
Identified HCAs
4. Identification of New Construction, 5. Change
in the Use of Existing Buildings, 6. Installation
of New Pipeline, 7. Change in Class
Location, 8. Pipeline Reroutes 9. Corrections
to Location Data, 10. Field Design Changes -
continued on next slide
106
A.6.a - Identification and Assessment of Newly
Identified HCAs

• New and Changing HCAs Should be Identified by the
  Operator
• Operators are Responsible for Monitoring
  Conditions Near Their Pipelines
• Operator Should Capture Changes in its HCA
  Identification Maps or System
• Changing Conditions Should be Evaluated At Least
  Annually

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Protocol Area A Identification of HCAs
Conclusion Thank you for your attention
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Gas Integrity Management Rule Protocols

• Don Moore
• Threat IdentificationData Gathering and
  Integration and Risk Assessment - Inspection
  Protocol C
• 49 CFR 192.917
• January 2005

109
Protocol C Structure

• C.1 - Threat Identification
• C.2 - Data Collection Integration
• C.3 - Risk Assessment
• C.4 - Risk Assessment Validation
• C.5 - Plastic Pipe

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C.1 Threat Identification

• Consider and Evaluate
• Nine Major Threat Categories
• Cyclic Fatigue
• All Other Potential Threats
• Interactive Threats
• Justify Elimination of Threats from Consideration

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C.1.a - Threat Categories

• 9 Categories
• 1. Internal Corrosion
• 2. External Corrosion
• 3. Stress Corrosion Cracking
• 4. Manufacturing-Related
• 5. Welding/Fabrication-Related

112
C.1.a - Threat Categories

• 9 Categories (Contd)
• 6. Equipment
• 7. Third Party/Mechanical Damage
• 8. Incorrect Operations
• 9. Weather-Related and Outside Force

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C.1.a Guidance for Evaluation of Specific
Threats

• Third Party Damage
• Manufacturing Construction Defects (Including
  Seam Defects)

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C.1.a - Specific Threats Third Party Damage

• Two Evaluations
• Segment Susceptible to Immediate Failure Due to
  TPD?
• Does Segment Have Residual Damage?

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C.1.a - Specific ThreatsThird Party Damage

• If Segment Susceptible to Future Damage
• Comprehensive Additional Damage Prevention
  Measures (192.935)
• Virtually All Pipelines Are Susceptible

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C.1.a - Specific Threats Third Party Damage

• Integrate Data to Determine if Segment Shows
  Evidence of Residual TPD Defects
• Excavate Locations With Dent indications from ILI
  or
• Conduct Integrity Assessment
• Repair Conditions per 192.933

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C.1.a - Specific ThreatsManufacturing/Constructi
on Defects

• Pipe Tested to Subpart J
• Stable if
• Pressure Tested per Subpart J, AND
• Not Subject to Interacting Threats
• Considered Susceptible if Failure Has Been
  Experienced

118
C.1.a - Specific Threats Manufacturing/Constructi
on Defects

• Pipe NOT Tested to Subpart J
• Defects Stable if
• Operating Pressure ? Benchmark (5-Year Max
  Preceding HCA Identification) AND
• MAOP Not Increased AND
• Cyclic Fatigue Stresses Not Increased AND
• Not Susceptible to Interacting Threats

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C.1.b Threat Identification

• Applies to Performance Based Programs Only

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C.2.a Data Gathering Integration

• Gather / Evaluate Data from Entire Pipeline
  Relevant to Covered Segments
• Comprehensive Data Plan

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C.2.b C.2.c - Required Data

• Gather and Evaluate Data for Entire Pipeline
• Must Follow B31.8S, Section 4
• Min. Data Set (B31.8S, App. A)
• Data Sources (B31.8S, Table 2)
• Additional Data Required for Performance-Based
  Approach

122
C.2.b - Required Data Sources

• 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

123
C.2.d - Treatment of Missing or Suspect Data

• No exclusion of a Threat Because of Lack of Data
• Conservative Assumptions
• Impact of Uncertain Data
• If Significant, Obtain Additional Data

124
C.2.e - New Information Incorporated

• Measures to Incorporate New Information
• Timely
• Effective
• Protocol K

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C.2.f - Data Integration

• Data Elements Analyzed
• Common Spatial Reference System
• Integration of ILI or ECDA Results

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C.3 - Risk Assessment

• Follow B31.8S, Section 5
• Consider All Identified Threats
• C.3.a - Use Risk Assessment To
• Prioritize Baseline Assessments
• Prioritize Reassessments
• Evaluate Additional Preventive and Mitigative
  Measures

127
C.3.b - Risk Assessment Approaches

• 4 Options
• Subject Matter Experts (SMEs)
• Relative Risk Ranking Models
• Scenario-Based Models
• Probabilistic Models

128
C.3.c - Risk Assessment Required Characteristics

• All Approaches Require
• Identification of Relevant Threats
• Likelihood
• Consequences
• Likelihood and Consequences Combined to Calculate
  Overall Risk

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C.3.c Risk Assessment Required Characteristics

• Logical Structure
• Incorporates Failure Experience
• Integrates Inspection Results
• Appropriate Weighting of Risk Factors
• Pipeline Subdivisions Sufficient to Represent
  Risk Appropriately

130
C.3.d Risk Assessment Revisions

• Risk Updated to Account for
• Integrity Assessments
• Preventive and Mitigative Measures
• Inaccuracies Identified by Maintenance or Other
  Activities
• Integrate w/ Day-to-Day Processes
• Continuous Improvement of Risk Model

131
C.4 Risk Assessment Validation

• Validation Process to Ensure Risk Assessment
  Results Are
• Logical
• Consistent

132
C.5 - Plastic Pipelines

• Assess Threats per B31.8S, Sections 4 5
• Consider Threats Unique to the Integrity of
  Plastic Pipe

133
Protocol Area C - Threat Identification Data
Gathering and Integration and Risk Assessment
Protocols
Conclusion Thank you for your attention
134
Gas Integrity Management Rule Protocols

• Allan Beshore
• 49 CFR 192.919 and 921
• Baseline Assessment Plan
• Protocol B
• January 2005

135
Key Elements Baseline Assessment Plan

• Identify Potential Threats
• Specify Assessment Methods
• Risk-Prioritized Schedule
• DA Plans (If Applicable)
• Procedure to Minimize Environmental and Safety
  Risks

136
Key Elements Baseline Assessment Plan

• Operators With Multiple Operating Entities May
  Either
• Have Separate Baseline Assessment Plans for Each
  Entity, OR
• Combine All Assets into a Single Baseline
  Assessment Plan

137
Protocols for Baseline Assessment Plans

• B.1 Assessment Methods
• B.2 Prioritized Schedule
• B.3 Use of Prior Assessments
• B.4 Newly Identified HCAs / Newly Installed
  Pipe
• B.5 Consideration of Environmental and
  Safety Risks, and
• B.6 Changes

138
B.1 Assessment Methods

• Baseline Assessment Plan Includes All Covered
  Segments
• Assessment Method(s) for Each Covered Segment
• May Need More Than One
• Assessment Method that is Best Suited for the
  Specified Threats

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B.1 Assessment Methods

• Actual Pipeline Defects (e.g., Corrosion)
• Threats From Future Event
• Addressed Using PM Measures
• Assess for Damage from Previous Events
• As Needed Based on Threat Identification Data
  Integration

140
B.1 Assessment Methods

• Operators Must Assess for TPD
• If a Threat from Residual TPD has Been Identified
• Treatment of TPD Threats is Also Addressed in
  Protocol C.

141
B.1 Assessment Methods

• DA is Acceptable Method for EC, IC, and SCC
  Threats Only
• ECDA - Be Vigilant to Identify / Investigate
  Potential TPD
• DA Plans Cover Data Integration
• DA Plan Specifics Addressed in Protocol D

142
B.1.a - Assessment Method Inline Inspection

• Internal Inspection Tools Selection Per ASME
  B31.8S, Section 6.2
• Include Evaluation of Reliability of ILI Method

143
B.1.b Assessment Method Pressure Test

• Pressure Test Per Subpart J
• Use of a Spike Test, Alone, is "Other Technology
• Spike Test Can be Very Effective to Assess
  Certain Threats
• (e.g., Seam Defects or SCC)

144
B.1.c Assessment Method Other Technology

• IMP Must Require Notification to OPS and
  Applicable State and Local Officials to Use
  Other Technology
• Notify 180 Days Before Conducting the Assessment
• Pressure Reduction is Not an Acceptable
  Assessment Method

145
B.1.d Assessment Method ERW Pipe

• If Susceptible to Seam Failure (LF ERW or Lap
  Welded Pipe)
• Method(s) Able to Find Seam Anomalies
• Must Prioritize as High Risk
• Seam Defects May be Stable (i.e., Not
  Susceptible) Seam Assessment Not Required (See
  Protocol C)

146
B.1.e Assessment Method Plastic Pipe

• If Plastic Pipe is Susceptible to Failure from
  Causes Other Than Third-Party Damage
• Use Alternate Assessment Method to Address the
  Identified Threats

147
B.2 Assessment Schedule

• Baseline Assessment Plan by December 17, 2004
• Include Risk Based Schedule
• Considers Applicable Risk Factors

148
B.2.a Assessment Schedule All Segments

• Baseline Assessment Plan Schedule Includes All
  Covered Segments Not Already Assessed

149
B.2.b Assessment Schedule Risk Prioritized

• Prioritize Covered Segments Based on
• Potential Threats
• Applicable Risk Analysis
• Utilize Risk Ranking

150
B.2.c Assessment Schedule High Risk Segments

• High-Risk Segments Means Overall High-Risk
  Prioritized in Top 50
• Manufacturing/Construction Defects
• LF ERW or Lap Welded Pipe
• Only If They Are Not Stable

151
B.2.d Assessment Schedule Deadlines

• 50 Complete 12/17/2007
• Begin w/ Highest Risk Segments
• Priority May Consider Practical Scheduling
  Operational Issues
• Count Cumulative Miles of Covered Segments (Not
  Total Miles Assessed)
• 100 Complete 12/17/2012
• - continued on next slide

152
B.2.d Assessment Schedule Deadlines -
continuation

• 50 Complete 12/17/2007 (cont.)
• States May Have State-Specific 50 Progress
  Deadlines

153
B.2.e Assessment Schedule Implementation

• Review the Operators Implementation to Date
• Schedule Performance
• Assessment Method Actually Used
• Completion Date of Assessment is Recorded
• Discovery Clock Starts

154
B.3 Prior Assessments

• Prior Assessments Are Those that Were Completed
  Prior to December 17, 2002
• B.3.a - Threats Identified per 192.919(a)
• B.3.b - Assessment Methods Used Meet 192.921(a)
• B.3.c - Remedial Actions Have Been Carried Out to
  Address Conditions Listed in Section 192.933
• - continued on next slide

155
B.3 Prior Assessments - continuation

• Operators Can Count Prior Assessments Toward the
  50 Progress Milestone
• Prior Assessment May be Credited Even if it Did
  Not Assess All Threats
• Perform a New Assessment for Other Threat(s)

156
B.4 New HCAs/Pipe

• Operator Updates the Baseline Assessment Plan
  for
• Newly Identified HCAs
• Newly Installed Pipe

157
B.4.a New HCAs/Pipe One Year Requirement

• Incorporate Into the Baseline Assessment Plan
  Within 1 Year AND
• Assessments Have Been Appropriately Scheduled
  and/or Completed

158
B.4.b B.4.c Assessments for New HCAs / Piping

• Baseline Assessments Completed Within 10 Years of
  Identification
• For Newly Identified HCAs,
• For Newly Installed Pipe Determined to be a
  Covered Segment

159
B.4.d New HCAs/Pipe Threats to New Sections

• Threats to These Pipeline Sections Must be
  Identified

160
B.4.e New HCAs/Pipe Assessment Methods for New
or Idled Sections

• Assessment Methods Must be Appropriate for the
  Threats
• Operators May Defer Activities Required by the
  Rule for Out-of-Service Pipe
• Deferred Activities Must be Completed When that
  Pipeline is Returned to Service

161
B.5 Environmental and Safety Risks

• Address Requirements for Conducting the Baseline
  Assessments in a Manner that Minimizes
  Environmental and Safety Risks
• Existing Procedures May be Referenced if Adequate

162
B.5.a Environmental and Safety Risks
Implementation

• Implement Precautions to -
• Protect Workers and Members of the Public
• Environment

163
B.6 Updating the Baseline Assessment Plan

• Verify that the Operator Keeps the Baseline
  Assessment Plan Up-to-Date With Respect to New
  Information
• Also Refer to Protocol K

164
B.6.a Updating the Baseline Assessment Plan
Process

• Requirements to Keep the Baseline Assessment Plan
  Up-to-date
• Address Newly Arising Information, Applicable
  Threats, and Risks
• Address Changes to the Segment Prioritization or
  Assessment Method as Applicable

165
B.6.b Updating the BAP Implementation

• For Changes to BAP, document
• Reason for Change
• Authority for Approving Change
• Analysis of Implications
• Communication of Changes to Affected Parties
• ASME B31.8S, Section 11(a)

166
B.6.b Updating the Baseline Assessment Plan
OPS Positions

• Notify OPS Only for Changes that
• Substantially Affect the Programs
  Implementation, OR
• Significantly Modify the Program or
  Implementation Schedule
• Keep Copies of the Revisions of the Baseline
  Assessment Plan

167
Protocol Area B Baseline Assessment Plan
Conclusion Thank you for your attention
168
Gas Integrity Management Rule Protocols

• Clyde Myers
• 49 CFR 192.923, 925, 927, 929 931
• Direct Assessment Plan
• Protocols D.1 through D.5
• January 2005

169
Direct Assessment

• DA Plan
• DA Applies to EC, IC, and SCC Threats Only
• Standards Incorporated By Reference
• ASME B31.8S 6.4, A-3, B-1, B-2
• NACE RP-0502-2002
• If conflict, the More Stringent Requirement
  Applies

170
External Corrosion Direct Assessment

• D.1 ECDA Programmatic Requirements
• ECDA Must Apply 4-Step Process
• D.2 - Pre-Assessment
• D.3 - Indirect Examination
• D.4 - Direct Examinations
• D.5 - Post Assessment

171
D.1.a - ECDA Programmatic Requirements

• ECDA Plan must describe its process
• Objectives
• Implementation
• Decisions
• Timeline
• Data Integration and Analysis
• Continual Improvement

172
D.1.b - Restrictive Criteria For 1st ECDA on
Segment

• Pre-Assessment
• Collect More Critical Data,
• More ECDA Regions
• Use More Than Two Tools
• Indirect Examination
• More Stringent Criteria for Categorizing
  Indications
• Direct Examination
• Additional Excavations Data

173
D.1.c - ECDA Third Party Damage

• Process to Address Coating Indications
• Integrate Data to Identify Potential TPD, Such
  as
• One-Call
• ROW Data
• Third Party Encroachments
• Foreign Lines

174
D.1.c - ECDA Residual Third Party Damage

• Matches of ECDA Coating Faults With Suspected
  Third Party Activity
• Basis for Decisions and Actions Taken

175
D.2 - ECDA Preassessment

• Comply With NACE RP-0502, 3
• ECDA Feasibility
• ID ECDA Regions
• Select Indirect Tools
• Complementary

176
D.2.a Identify Data Needs

• Pre-Assessment Data Intensive
• Historical, Current, Physical
• Must Consider Following Data
• Pipe-Related
• Construction Related
• Soils/Environmental
• Corrosion Control
• Operational

177
D.2.b Feasibility Assessment

• ECDA Feasibility Assessment
• Integrate Analyze Data to Determine
• 2 Indirect Tools
• ECDA Regions
• Locations Where Tool Use Not Feasible
• Disbonded Coating
• Rock Backfill
• Rebar in Pavement

178
D.2.c - Indirect Tool Selection

• Indirect Tool Selection
• Minimum of 2 Tools for Each Region Basis
• Detect Corrosion or Coating Holidays
• NACE RP-0502 Table 2 Appendix A
• Reliable for Expected Conditions

179
D.2.d Identify ECDA Regions

• Identify Regions
• Physical Characteristics
• Corrosion History
• Expected Future Corrosion
• Same Indirect Inspection Tools
• A Region Need Not Be Contiguous

180
D.2.d - ECDA Regions
ECDA 1
ECDA 2
ECDA 3
ECDA 4
ECDA 5
CIS EM
CIS/DCVG
CIS/DCVG
River
Sandy-Loam Med Resist No History
Sandy Well Drained Low Resist No History
Sandy Well Drained Med. Resist. Some Problems
Loam Poor Drainage High Resist Many Problems
181
D.2.d - ECDA Region Changes

• Regions May be Modified Consistent With Region
  Criteria
• Based on Indirect Inspection
• e.g., Tools Not Performing Consistently
  Throughout Region
• Based on Direct Examination
• e.g., Improved Knowledge of Soil Conditions

182
D.3 - ECDAIndirect Examination

• Locate Indications of Coating Faults Corrosion
  Activity
• Identify Severity of Indications
• Identify Excavation Priorities

183
D.3.a Conduct Indirect Examinations

• 2 Indirect Examination Tools
• Over Each ECDA Region
• Follow Industry Tool SOPs
• Establish Spacing of Readings
• Reduced Spacing in Suspect Areas
• Document Data from Indirect Examinations

184
D.3.b Identify Indications

• Align and Compare Data
• Consider Spatial Errors
• Compare Results of Tools for Consistency
• Unresolved Discrepancies Classified as More
  Severe
• Identify Indications

185
D.3.b Classify Indication Severity

• Establish Classification Criteria
• Capabilities of Tools
• Unique Conditions of Region
• Presence of Active Corrosion
• Expertise Level of Analysts

186
D.3.b Classify Indication Severity

• Table 3 of NACE 0502
• Severe Moderate Minor
• Active Corrosion is Severe
• If Indeterminate, Indications Must be Classified
  as Severe

187
D.3.b ECDA Process Pre-Assessment Check

• Compare Indirect Results With
• Pre-assessment Results
• Prior History
• If Inconsistent, Re-evaluate
• ECDA Feasibility
• ECDA Region criteria
• Tool Selection

188
D.3.b Establish Excavation Priorities

• Prioritize Direct Exam of Each Indication
• Example Criteria RP-0502 Table 4
• Urgency of Excavation
• Immediate Action Required
• Scheduled Action Required
• Suitable for Monitoring

189
D.3.b - Clarification Regarding Immediate
Indication Terminology

• Immediate Indication Terminology
• Compared to 192.933

190
D.4 - ECDADirect Examinations

• Required Excavations Data Collection
• Assess Corrosion Activity
• Measure Pipe Surface Conditions
• Measure Immediate Surrounding Environment Data
• Defect Size and Growth Rate
• Remediate Defects Determine Root Cause
• Verify Classifications Excavation Priorities

191
Minimum Excavations

• NACE RP-0502-2002, 5.10
• No. of Regions in the Segment
• No. of Immediate Indications
• Scheduled Indications
• Defect Found at Scheduled Indication More Severe
  Than Defect at Immediate
• Monitored Indications
• First Application of ECDA

192
D.4.a - ECDADirect Examinations

• Minimum Requirements For
• Consistent Data Collection
• Recordkeeping in Each Region
• Types of Data
• Conditions Encountered
• Corrosion Activity Expected
• Availability Quality of Prior Data

193
D.4.a - ECDADirect Examinations (cont.)

• Remove Coating, Clean Pipe
• Identify/Map Corrosion
• Measure Document All Significant Defects
• Depth and Morphology Measurements
• Magnetic Particle for Cracks
• UT for Internal Defects

194
D.4.b - ECDADirect Examinations

• Remaining Strength Evaluation
• RSTRENG, ASME B31G
• SOPs Must Include Criteria
• Defects Exceed Allowable Limits
• Similar Defects May Exist in the Region
• Suitability of ECDA Process Based on Root Cause

195
D.4.b - ECDADirect Examinations

• If Remaining Strength or Pf is less than (MAOP)
  X (SF)
• Repair or Replace or Lower MAOP
• Consider Alternative Method for Assessing Region
  With Remaining Strength Concerns

196
D.4.c, d - ECDADirect Examinations

• Root Cause Analysis
• Identify Underlying Root Cause for Each
  Significant Corrosion Area
• Formal Root Cause Analysis
• Remediation Activities
• Mitigate or Preclude Future Corrosion

197
D.4.e - ECDADirect Examinations

• Perform an In-process Evaluation
• Evaluate Criteria Used to
• Classify Severity of Indications
• Establish Priorities of Excavations
• On 1st Use, Classification and Prioritization
  Criteria May Not Be Relaxed

198
D.4.f, g Changes in Plan Time Frames

• Establish Basis for Changing
• Classifications of Severity
• Priorities for Excavation Required
• Establish Implement
• Internal Notifications of Changes
• Time Frame for Direct Examinations

199
D.4.h Process for Defects other than EC

• Process for Defects Discovered Other Than
  External Corrosion
• i.e., ILI or Subpart J Test Methods for
• Mechanical Damage
• Stress Corrosion Cracking
• Seam Weld Issues

200
D.5 - Post Assessment Objectives

• Determine Reassessment Intervals
• Assess Overall Effectiveness of the ECDA Process

201
D.5.a - Reassessment Intervals

• Based on Worst Defect Found at a Scheduled
  Indication
• Half of Calculated Remaining Life
• Corrosion Growth Rates
• Measured Data, OR
• Default Rate of 16 mil/yr (App D)

202
D.5.b Reassessment Interval Limits

• Intervals Must Not Exceed 192.939
• 10 Years if Above 50 SMYS
• 15 Years if Between 30 50 SMYS,
• 20 Years if Below 30 SMYS
• Direct Examination Results May Affect
  Re-Assessment Interval

203
D.5.c Assessment of ECDA Effectiveness

• Process Validation Dig(s)
• One Additional Direct Exam to Validate ECDA
  Process (2 If 1st Use of DA)
• 1 At a Scheduled Indication,
• 1 Where No Indication Was Found
• Re-Evaluate if Defects More Severe Than Expected

204
D.5.c Assessment of ECDA Effectiveness

• Performance Measures
• Long Term Effectiveness of ECDA
• Controlling External Corrosion
• RP-0502 Suggests Measures
• Number of Reclassifications
• Trend the Number of Immediate and Scheduled
  Indications

205
D.5.d ECDA Post Assessment

• Improve ECDA by Incorporating Feedback Throughout
  Process

206
Protocol Area D.1 through D.5 External Corrosion
Direct Assessment
Conclusion Thank you for your attention
207
Gas Integrity Management Rule Protocols

• Clyde Myers
• 49 CFR 192.927
• Internal Corrosion Direct Assessment
• Protocols D.6 through D.10
• January 2005

208
Internal Corrosion Direct Assessment (ICDA)

• 49 CFR 192.927
• ASME B31.8S

209
Internal Corrosion Direct Assessment

• D.6 Dry Gas ICDA Programmatic Requirements
• D.7 Dry Gas ICDA Pre-Assessment
• D.8 Dry Gas ICDA Direct Examination
• D.9 Dry Gas ICDA Post-Assessment
• D.10 Wet Gas ICDA Programmatic Requirements

210
D.6.a - Dry Gas (DG) ICDAPlan

• DG ICDA Plan per 192.927(c)
• Pre-Assessment
• ICDA Region Identification
• Identification of Locations for Excavation and
  Direct Examination
• Post Assessment

211
D.6.b - DG ICDAPlan Requirements

• DG ICDA Plan Requirements
• Criteria for Key Decisions
• DG ICDA Feasibility
• DG ICDA Region Identification
• Conditions Requiring Excavation
• Implementing Each DG ICDA Step

212
D.6.c d - DG ICDA

• DG ICDA Plan Requirements
• More Restrictive Criteria 1st Use
• DG ICDA Analysis Applied to Entire Pipeline
• If Corrosion is Found
• Remediate Per 933, and
• Evaluate All Segments (Covered and Non-Covered
  Segments) With Similar Characteristics

213
D.7.a - DG ICDA Pre-Assessment

• Gather and Integrate Data
• Facility Historical Data
• Information to Support Flow Model
• Gas Input and Withdrawal Points
• Low Points (Drips, Traps, etc.)
• Elevation Inclines
• Flow Rates
• Cleaning Pig Data

214
D.7.b - DG ICDA Pre-Assessment Data Analysis

• Integrated Data Analysis
• Determine DG ICDA Feasibility
• Identify DG ICDA Regions
• Support Use of a Flow Model
• Identify Where Liquids Are Entrained and
  Accumulate

215
D.7.c - DG ICDA - Identify Excavation Locations

• Flow Model GRI 02-0057 Must Consider Changes In
• Diameter, Gas Inputs and Withdrawals, Gas
  Velocity, Pressure and Temperature
• Identify Points of Water Accumulation
• Use of Other Flow Models
• Flow Model Not Needed if 100 of Region is
  Examined

216
D.8.a - DG ICDA Identify Excavation Locations

• Site Selection and Direct Exam
• Integrate Critical Inclination Angle With
  Pipeline Inclination Profile
• Locate Likely IC Sites, Electrolyte Predicted

217
D.8.b - DG ICDADirect Examination

• Direct Examination Using UT, Radiography, or
  Other Techniques
• A Min. 2 Locations/DG ICDA Region
• 1st at Low Point Nearest Beginning
• 2nd Downstream Near End

218
DG ICDA - Identify Excavation Locations
DG ICDA Region
Flow
Critical Angle of Inclination
First Low Point In ICDA Region
219
D.8.c - DG ICDADirect Examination

• If Corrosion Exists
• Evaluate Severity Remediate
• Perform Additional Excavations or Use Alternative
  Assessment for Internal Corrosion
• Evaluate Similar Pipe (Both Covered and
  Non-Covered)

220
D.9.a - DG ICDA Post Assessment

• Post Assessment Evaluation and Monitoring-
  Objectives
• Evaluate Effectiveness of DG ICDA
• Reassessment Intervals

221
DG ICDA Post Assessment
Direct Exam Location
Location of Additional Dig For Post Assessment
Critical Angle of Inclination
222
D.9.b - DG ICDA Post Assessment

• Post Assessment Monitoring Where IC Has Been
  Identified
• Continual Monitoring Required
• Frequency of Monitoring Based on Results of All
  Integrity Assessments
• Risk Factors of Segment

223
D.10 - ICDA for Wet Gas

• If Operator Elects ICDA for Wet Gas the Operator
  Must
• Develop a Plan to Effectively Address Internal
  Corrosion
• Provide Notifications to OPS 180 Days Prior

224
Protocol Area D.6 D.10 Internal Corrosion
Direct Assessment
Conclusion Thank you for your attention
225
Gas Integrity Management Rule Protocols

• Clyde Myers
• 49 CFR 192.929
• Stress Corrosion Cracking Direct Assessment
• Protocols D.11 and D.12
• January 2005

226
SCCDA

• High pH SCC
• SCCDA Plan Must Meet B31.8S Appendix A3
• D.11 SCCDA Data Gathering Evaluation
• D.12 SCCDA Assessment, Examination, Threat
  Remediation

227
SCCDA

• Near-Neutral pH SCC
• Plans Reviewed on a Case-by-Case Basis

228
SCCDA Plan (High pH)

• SCCDA Plan Must Address
• Data Gathering, Integration (D.11)
• Data Collected at All Excavations Meeting SCC
  Likelihood Criteria
• Including Non-Covered Segments
• Assessment, Examination, Threat Remediation
  (D.12)

229
D.11.a - SCCDA Data Gathering Integration

• Systematic Process to Collect, Integrate, and
  Evaluate Data
• Evaluate Identify SCC Segments
• Prioritize Assessments

230
D.11.a - SCCDA Data Gathering Integration

• Minimum Data Set (Appendix A3)
• Age of Pipe,
• SMYS,
• Operating Temperature,
• Distance From Compressor Station,
• Coating Type,
• Past Hydro Information,
• If Data is Missing
• Use Conservative Assumptions

231
Screening Criteria for High-pH SCC
Susceptibility

• Segment Experienced in Service or Hydro Test SCC
  Leak or Rupture, OR
• Susceptible to High pH SCC if Segment Meets All
  Criteria
• Stress gt 60 SMYS
• Historic Temp gt 100F
• lt 20 Miles Downstream of Compressor
• gt 10 Years Old
• Coating Other Than Fusion Bonded Epoxy

232
D.12.a - SCCDA Assessment Method

• Assessment Method Required
• Bell Hole, or
• Hydro Test Program
• Written Inspection, Examination, and Evaluation
  Plan

233
D.12.b Factors in Selecting Dig Sites

• Bell Hole Examination Evaluation
• Identify Criteria for Dig Site Selection
• History of SCC in Area
• Mechanical Damage, Dents, Soils/Moisture, Steep
  Slopes
• Coating Anomalies
• General Corrosion
• Other Integrity Threats Present in Segment
• Greatest Stress, Pressure Fluctuations, and
  Highest Temperatures

234
D.12.b - Bell Hole Assessment Method

• Direct Examination for SCC
• Including Areas of Coating Disbondment
• Magnetic Particle Inspection

235
D.12.b - Bell Hole Assessment Method

• If No SCC Indication
• Define Re-Evaluation Interval
• Mitigate SCC Indications
• Hydro Test Valve Section for SCC
• E