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

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

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

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

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

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

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

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

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

10. Regulations Related to Gas Pipelines

11. Regulatory Issues
Department of Transportation proposed rule (49 CFR Part 192) dated January 28, 2003 titled “Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines)
This document proposes to establish a rule to require operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact high consequence areas

12. Federal Regulation

13. Regulatory Issues
This proposed rule will satisfy Congressional mandates for RSPA/OPS to prescribe standards that establish criteria for identifying each gas pipeline facility located in a HCA and to prescribe standards requiring the periodic inspection of pipelines located in these areas
This proposed rule will satisfy Congressional mandates for RSPA/OPS to prescribe standards that establish criteria for identifying each gas pipeline facility located in a HCA and to prescribe standards requiring the periodic inspection of pipelines located in these areas, including the circumstances under which an inspection can be conducted using an instrumented internal inspection device (smart pig) or an equally effective alternative inspection method.
This proposed rule does not apply to gas gathering or to gas distribution lines

14. Regulatory Issues
Pipeline Integrity can be best assured by requiring each operator to:
Implement a comprehensive IMP
Conduct a baseline assessment and periodic reassessments focused on identifying and characterizing applicable threats
Mitigate significant defects discovered in this process
Monitor the effectiveness of their programs so appropriate modifications can be recognized and implemented
OPS believes it can be best assure pipeline integrity by requiring each operator to:
Implement a comprehensive IMP
Conduct a baseline assessment and periodic reassessments focused on identifying and characterizing applicable threats
Mitigate significant defects discovered in this process
Monitor the effectiveness of their programs so appropriate modifications can be recognized and implemented
This approach also recognizes that improving integrity requires operators to gather and evaluate data on the performance trends resulting from their programs, and to make improvements and corrections based on this evaluation.

15. Regulatory Issues Assessment Methods Internal Inspection ILI
Pressure Testing
Direct Assessment (data gathering, indirect examination, and post assessment evaluation)
Any other method that can provide an equivalent understanding of the condition of line pipe
There are four acceptable assessment methods defined by this rule. They are:
Internal Inspection (also known as in-line inspection, ILI and pig testing)
Pressure testing;
Direct assessment (a process that includes data gathering, indirect examination and/or analysis, direct examination, and post assessment evaluation; and
Any other method that can provide an equivalent understanding of the condition of the line pipe.
The rule indicates that because the primary function of internal inspection tools or pressure testing is to determine the condition the pipe is in, they determined that equivalent or greater safety can be provided by other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe.

16. Regulatory Issues
The rule proposes to allow direct assessment as a supplemental assessment method on:
Any covered pipeline section
As a primary assessment method on a covered pipeline where ILI and pressure testing are not possible or economically feasible
Where the pipeline operates at low stress
Can also be used to evaluate third party damage
The rule proposes to allow direct assessment as a supplemental assessment method on any covered pipeline segment and as a primary assessment method on covered pipeline where in-line inspection and pressure testing are not possible or economically feasible or where the pipeline operates at a low stress. None of the permitted assessment methods listed above is fully capable of characterizing all potential threats to pipeline integrity. Currently, direct assessment is only an acceptable inspection method for assessing external corrosion, internal corrosion and stress corrosion cracking. In addition, if no other assessment method is feasible, direct assessment may be used to evaluate third party damage. Operators choosing direct assessment technologies must undertake extra excavations and direct examinations during the period while direct assessment is being validated.

17. Regulatory Issues
All three threats considered under direct assessment:
External Corrosion
Internal Corrosion
SCC
All three threats considered under direct assessment:
External Corrosion
Internal Corrosion
SCC
A NACE document has already been developed for ECDA. ICDA and SCC documents are in the process of revision and balloting.

18. Regulatory Issues
Another concept in the proposed rule is to use Confirmatory Direct Assessment to evaluate a segment for the presence of corrosion and third party damage
This is a more streamlined assessment method that uses the steps involved in direct assessment to identify these significant threats to a pipeline’s integrity. RSPA/OPS is proposing that an operator use this method as an initial reassessment method within the required seven year reassessment interval, if the operator has, within the proposed limits, establish a longer reassessment interval for a particular segment. The follow up reassessment by pressure test, internal inspection or direct assessment would then be conducted at the established interval.

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

20. ASME B31.8S Managing System Integrity of Gas Pipelines
Specifically design to provide the operator with the information necessary to develop and implement an effective integrity management program
Appendix B – Direct Assessment process
This standard was specifically designed to provide the operator with information necessary to develop and implement and effective integrity management program utilizing proven industry practices and processes.
Appendix B provides information about the direct assessment process and specifies that direct assessment is one integrity assessment methodology that can be used within the integrity management program

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

48. Direct Assessment

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

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

51. Regulations and Standards
Liquid Rule – 49 CFR (Jan. 2002)
API Standard (Nov. 2001)
NPRM Gas Rule – 49 CFR Part (Jan. 2003)
ASME B31.8S (Dec. 2001)
NACE ECDA Standard RP (2002)
“Pipeline External Corrosion Direct Assessment Methodology”

52. Regulations and Standards (Cont’d)
Proposed NACE ICDA Standard –TG 041 (2003)
“Pipeline Internal Corrosion Direct Assessment Methodology”
NACE SCC DA Standard –TG 273 (In Progress)
“Pipeline SCC Direct Assessment Methodology”

53. Liquid Rule – 49 CFR 195 Acceptable Integrity Assessment Methods:
Internal inspection tool or tools capable of detecting corrosion and deformation anomalies
Pressure testing
Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe.
OPS notification required 90 days before assessment

54. “Managing System Integrity for Hazardous Liquid Pipelines”
API Standard 1160
“Managing System Integrity
for Hazardous Liquid Pipelines”
Acceptable Integrity Assessment Methods:
In-line inspection technology
Hydrostatic Testing

55. NPRM Gas Rule - 49 CFR Part 192
Acceptable Integrity Assessment Methods:
Internal inspection tool or tools capable of detecting corrosion and deformation anomalies as appropriate
Pressure testing
Directed assessment method for external corrosion threats, internal corrosion threats, stress corrosion, and third party damage (if other assessment methods are not feasible)
Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe.
OPS notification required 180 days before assessment

56. “Managing System Integrity of Gas Pipelines”
Supplement to ASME B31.8
“Managing System Integrity of Gas Pipelines”
Acceptable Integrity Assessment Methods:
(Dependent on integrity threats)
In-line Inspection
Pressure Testing
Direct Assessment
ECDA
ICDA
Other methodologies

57. NACE Recommended Practices
NACE ECDA Standard RP (2002)
“Pipeline External Corrosion Direct Assessment Methodology”
Proposed NACE ICDA Standard –TG 041 (2003)
“Pipeline Internal Corrosion Direct Assessment Methodology”
NACE SCC DA Standard –TG 273 (In Progress)
“Pipeline SCC Direct Assessment Methodology”

58. What is Direct Assessment
A method of assessing pipeline integrity.
Intended to be no less protective of public safety and environment than ILI or Hydrotest.
From “direct examination.”
Bell hole inspections.

59. Direct Assessment Process
Utilize existing technologies in an integrated approach intended to map corrosion defects
Utilize prediction modeling to determine “like and similar”
Use results to safely manage the pipeline system

60. Direct Assessment Concept
Technologies can be used as a diagnostic tool to assess pipeline integrity
Defect growth models can be used to determine “safe” operating conditions and to determine re-assessment or inspection frequency

61. ECDA Technologies Existing technologies
Test station surveys
Close-interval surveys (CIS)
DC voltage gradient
Electromagnetic inspection
Buried Coupons
Soil Resistivity
Previously used as stand-alone assessments
Integration of data results in a predictive integrity model

62. Applicability
External corrosion integrity verification for pipelines that cannot be inspected by ILI or pressure test
Condition monitoring of pipelines inspected by ILI or pressure tested
Have been inspected with other techniques as a means of establishing reassessment intervals
Have not been inspected by other means when future corrosion monitoring is of primary interest
Not applicable to all pipelines

63. Four Step ECDA Process Pre-assessment
Assembly and review of pipeline data
Indirect examination
Above-ground survey tools
Direct examination
Excavation, inspection, defect assessment
Post-assessment
Validation, prioritize repairs, re-inspection

65. Pre-Assessment Data collection ECDA feasibility for pipeline
Indirect inspection tool selection
ECDA region identification
Step 1

66. Pre-Assessment Data Collection (Table 1 of NACE Standard) Pipe related
Construction Related
Soils/Environmental
Corrosion Protection
Pipeline Operations
Step 1

67. Pre-Assessment ECDA feasibility Assessment
Indirect inspection tool feasibility
Establish ECDA feasibility regions
Determine which indirect methods are applicable to each region
Step 1

68. What is a Region? Segment is a continuous length of pipe
Regions are subsets of one segment
Pipe with similar construction and environmental characteristics
Same survey tools
Step 1

69. Where Might ECDA Not Be Applicable?
As with all assessment tools, there are limitations to consider
Shielded coatings
Rock ditch
Extensive Pavement (Cost issue)
Some CP configurations
Extensive Direct Connected Anodes
Step 1

70. Indirect Examination
Objective: identify coating faults and areas where corrosion activity may have or may be occurring
Utilizes a minimum of two complementary indirect techniques
Step 2

71. Indirect Techniques Direct Current Alternating Current
Measure structure potential
Identify locations of high CP demand to small area
Alternating Current
Apply AC signal
Determine amount of current drain (i.e., grounding) and location
Identify locations of high AC current
Step 2

72. Indirect Techniques Direct Current Alternating Current
Close Interval Survey (CIS or CIPS)
Direct Current Voltage Gradient (DCVG)
Alternating Current
ACVG, Pearson Survey
AC Attenuation (PCM , EM , C-Scan)
Step 2

73. Indirect Examination
Objective: identify coating faults and areas where corrosion activity may have or may be occurring
Utilizes a minimum of two complementary indirect techniques
Step 2

74. Direct Examination
Excavate and collect data where corrosion most likely
Categorize indications
Immediate action required
Scheduled action required
Suitable for monitoring
Characterize coating and corrosion anomalies
Establish corrosion severity for remaining strength analysis
Determine root-cause
In-process evaluation, re-categorization, guidelines on number of direct examinations
Step 3

75. Number of Required Digs Validation Process
Total number of excavation depends on the results of the aboveground techniques
Typically 3-5/10 mile Section
Step 3

76. Direct Examination Data
Collect data at dig site
Pipe to soil potentials
Soil resistivity
Soil and water sampling
Under-film pH
Bacteria
Photographic documentation
Step 3

77. Direct Examination Data
Characterize coating and corrosion anomalies
Coating condition
Adhesion, under film liquid, % bare
Corrosion analysis
Corrosion morphology classification
U/T mapping
MPI analysis for SCC
Step 3

78. Direct Examination Remaining strength analysis ASME B31G RSTRENG
CorLAS
DnV RP-F10
Step 3

79. Direct Examination Determine root-cause For example Low CP
Interference
MIC
Disbonded coatings
Step 3

80. Post Assessment Validates ECDA Process
Provides performance measures for integrity management
Growth models are used to establish safe operation
Corrosion “Signature” is developed and applied to entire segment
Establishes reassessment intervals
Step 4

81. Post Assessment Assessment of ECDA Effectiveness
Comparison of ECDA indications with Control digs
Comparison of ILI to ECDA results
Remaining Life Calculations
Reassessment Intervals

82. Post Assessment Assessment of ECDA Effectiveness
Comparison of ECDA Indications with Control Digs:
ECDA 100% effective in locating areas where corrosion was taking place and where metal was exposed
No coating flaws and no corrosion was found at control digs

83. Post Assessment Remaining Life Calculations
NACE RP0502 Reassessment Methodology
The establishment of the reassessment interval is based on establishing the remaining life of critical defects, establish a conservative growth rate, and utilize the following relationship:
RL =C x SM (t/GR)

84. Post Assessment Remaining Life Calculations
When corrosion defects are found during the direct examinations, the maximum reassessment interval is calculated as one half the remaining life (RL).

85. Post Assessment Remaining Life Calculations
CC Technologies Reassessment Methodology is based on:
Linear Polarization Resistance measurements are used to give instantaneous corrosion rates for each excavated site. The measured rate is a function of the soil characteristics and environment surrounding the pipe or segment being evaluated.

86. Post Assessment Reassessment Interval
Using the LPR technique, the maximum actual value obtained will be taken as the most conservative growth rate. The most significant external corrosion feature ILI indication that was field verified is then grown to 80% (Immediate action). Therefore the re-assessment interval will be less ½ of this conservative value.

87. ECDA Case Studies

88. Survey Methodologies - Cathodic Protection Levels
Close-Interval Surveys
Measure pipe to soil potentials at close intervals to evaluate cathodic protection levels
Locate areas of active corrosion
Identify shorted casings, stray current interference, electrical shorts, CP shielding
Interrupt CP current to obtain polarized potentials
Pipe to soil potentials measured at 5 foot intervals

89. Survey Methodologies Coating Evaluations
DCVG and ACVG:
Locate and “size” holidays by measuring current flow in soil to pipeline coating holidays
Interrupt CP system using a fast cycle (DCVG)
Use AC voltage signal applied to pipeline (ACVG)
Measure potential difference between two electrodes

90. Why These Survey Techniques?
DCVG - Locate and size coating holidays
Electromagnetic - Evaluate overall coating condition on macro-level
Soil Resistivity - Soil corrosiveness at holiday locations to prioritize excavations
CIS - Determine CP levels at holiday sites
GPS - Pipe elevation for ICDA and pipeline mapping

91. ECDA Site Selections

92. ECDA Site Selections

93. ECDA Site Selections

94. Examples of Specific Anomalies Detected

95. Coating Fault Site CIS Showed a dip in potential DCVG Showed Anomaly
-1.008v, v, v, v
DCVG Showed Anomaly

98. Corrosion Anomalies Found
Indirect techniques can detect areas of corrosion

99. Anomaly 6

101. Discoveries Third party damage Valves Inhouse damage to pipe
Fiber optics line
Dent and gouge
Valves
Leaking
Inhouse damage to pipe
Concrete weights

102. Third Party Damage Low CP potentials in CIS ACVG Indication
-0.840v (100mV of polarization)
ACVG Indication
Required Repair

105. ECDA Site Selection

106. ECDA Site Selection Figure 15. E-9 628+40.5 holiday area.

107. ECDA Site Selection

108. ECDA Site Selection Photo
Figure 23. E-11 holiday as found.
Figure 24. E-11 Coating disbondment area.

109. Challenges

110. Distribution System Direct Assessment
Must rely on pipe exposure opportunities
Develop database of useful information
Utilize coupon technologies
Utilize standard testing techniques

111. Field Excavation Summary Report
Important to establishing root cause of corrosion
Build databases on conditions contributing to corrosion and its mitigation
Develop risk-based predictive capability

112. Availability of Trained Personnel
Requires experienced engineers and technicians for data collection and analysis
Rate limiting step is availability of trained personnel
Minimum of 1 year of training for survey techniques
An additional 6 months of training for recognition of quality data
A minimum of 3 years of analysis experience

113. Information Management
There will be massive amounts of data from many systems
Timely processing is critical
User friendly data management systems are key
Owner/Operator accessibility must be considered

114. Projections
Cost estimates to implement DA engineering on typical transmission system of 500 mile length with 10 anomalies/mile
Model Development Cost
Data review = $ 500/mile
Base survey = $ 600/mile
Diagnostic Survey = $200/anomaly = $2,000
Direct Examination = $500/anomaly = $5,000
Modeling = $ 500/mile
Total Model Development Cost = $8,600/mile
Applies to 50 miles = $430,000

115. Projections (cont’d) Model Application Cost
Data review = $ 500/mile
Base survey = $ 600/mile
Direct Examination = $500/anomaly = $2,500 (assumes 5 critical)
Model Enhancement = $100/mile
Total Model Application Cost = $3,700/mile
Applies to 450 miles = $1,660,000
Total DA Engineering for 500 miles = $2.1 Million or $4,200/mile

116. Discussion Points ECDA Process is generally underestimated”
Complexity
Pre-Assessment Requirements
Data management
Details and accuracy can be overlooked
Training is an issue
Generally need a better understanding of dig measurements and data collection

117. Discussion Points (cont’d)
Need training on how to apply reassessment intervals
Others?

118. Lessons Learned To Date
ECDA is presently expensive but costs will decline with experience
For some pipelines, other assessments will always be more cost effective
Alignment of data is critical
ECDA requires high attention to detail
Pre-assessment important

119. Summary
For liquid pipelines, the methods selected for the assessment of the pipeline integrity are: ILI, pressure test and other technology that the operator demonstrates can provide an equivalent understanding of the condition of the pipeline

120. Summary
For gas pipelines, the methods selected for the assessment of the pipeline integrity are: ILI, pressure test, direct assessment and other technology that the operator demonstrates can provide an equivalent understanding of the condition of the pipeline

121. Summary
Direct assessment is based on the use and integration of existing technologies
Direct assessment will work if properly applied
It will require data collection and management and a commitment to validation

122. Thank You
Questions and Discussion