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Gas Integrity Management Rule Protocols

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Title: Gas Integrity Management Rule Protocols


1
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

8
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

10
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

12
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

13
OPS Strategic Focus
  • Improve the safety of the nations pipelines
  • Provide the basis for increased public confidence
    in pipeline safety

14
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

15
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

16
Three Major Pillars of Our Go-Forward Strategy
  • Risk and integrity management
  • Shared knowledge and responsibility
  • Expanding our role in a changing world

17
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

18
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

24
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

25
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

26
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

27
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

28
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

30
Gas IM Inspection Focus
  • Organizational commitment
  • Quality of management processes
  • Personnel qualifications
  • Clearly documented implementation basis
  • Continual improvement of program

31
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

32
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 . . .

33
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/

35
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36
Operator Resources
  • Gas Integrity Management Web Site
  • Key Documents
  • Performance Reporting
  • Fact Sheet
  • Flowchart of Rule
  • Register and View Meetings

37
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38
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39
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40
Operator Resources
  • Gas Integrity Management Web Site
  • Key Documents
  • Performance Reporting
  • Fact Sheet
  • Flowchart of Rule
  • Register and View Meetings

41
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42
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43
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

44
Operator Resources
  • Gas Integrity Management Web Site
  • Key Documents
  • Performance Reporting
  • Fact Sheet
  • Flowchart of Rule
  • Register and View Meetings

45
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46
Operator Resources
  • Gas Integrity Management Web Site
  • Key Documents
  • Performance Reporting
  • Fact Sheet
  • Flowchart of Rule
  • Register and View Meetings

47
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48
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49
Operator Resources
  • Gas Integrity Management Web Site
  • Key Documents
  • Performance Reporting
  • Fact Sheet
  • Flowchart of Rule
  • Register and View Meetings

50
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51
Operator Resources
  • Gas Integrity Management Web Site
  • OPS Communications (Links)
  • Notifications
  • Question or Comment
  • Frequently Asked Questions (FAQs)
  • Inspection Protocols

52
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53
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54
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55
Operator Resources
  • Gas Integrity Management Web Site
  • OPS Communications (Links)
  • Notifications
  • Question or Comment
  • Frequently Asked Questions (FAQs)
  • Inspection Protocols

56
Notifications
  • Notifications Are Required For
  • Substantial Change to IM Program
  • Use of Other Assessment Technology
  • Can Not Meet Schedule for Evaluation and
    Remediation

57
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58
Operator Resources
  • Gas Integrity Management Web Site
  • OPS Communications (Links)
  • Notifications
  • Question or Comment
  • Frequently Asked Questions (FAQs)
  • Inspection Protocols

59
(No Transcript)
60
Operator Resources
  • Gas Integrity Management Web Site
  • OPS Communications (Links)
  • Notifications
  • Question or Comment
  • Frequently Asked Questions (FAQs)
  • Inspection Protocols

61
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62
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63
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

80
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

81
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82
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83
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84
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

93
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

97
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)
101
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

104
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

107
Protocol Area A Identification of HCAs
Conclusion Thank you for your attention
108
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

110
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

111
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

113
C.1.a Guidance for Evaluation of Specific
Threats
  • Third Party Damage
  • Manufacturing Construction Defects (Including
    Seam Defects)

114
C.1.a - Specific Threats Third Party Damage
  • Two Evaluations
  • Segment Susceptible to Immediate Failure Due to
    TPD?
  • Does Segment Have Residual Damage?

115
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

116
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

117
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

119
C.1.b Threat Identification
  • Applies to Performance Based Programs Only

120
C.2.a Data Gathering Integration
  • Gather / Evaluate Data from Entire Pipeline
    Relevant to Covered Segments
  • Comprehensive Data Plan

121
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

125
C.2.f - Data Integration
  • Data Elements Analyzed
  • Common Spatial Reference System
  • Integration of ILI or ECDA Results

126
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

129
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

139
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
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