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

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

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

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

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

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

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

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)

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

Regulations Related to Gas Pipelines

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

Federal Regulation

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

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.

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.

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.

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.

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.

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.

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

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

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

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

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

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)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Direct Assessment

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)

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

Regulations and Standards Liquid Rule – 49 CFR 195 (Jan. 2002) API Standard 1160 (Nov. 2001) NPRM Gas Rule – 49 CFR Part 192 (Jan. 2003) ASME B31.8S (Dec. 2001) NACE ECDA Standard RP0502-2002 (2002) “Pipeline External Corrosion Direct Assessment Methodology”

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”

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

“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

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

“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

NACE Recommended Practices NACE ECDA Standard RP0502-2002 (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”

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.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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)

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).

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.

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.

ECDA Case Studies

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

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

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

ECDA Site Selections

ECDA Site Selections

ECDA Site Selections

Examples of Specific Anomalies Detected

Coating Fault Site CIS Showed a dip in potential DCVG Showed Anomaly -1.008v, -0.940v, -0.890v, -0.920v DCVG Showed Anomaly

Corrosion Anomalies Found Indirect techniques can detect areas of corrosion

Anomaly 6

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

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

ECDA Site Selection

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

ECDA Site Selection

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

Challenges

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

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

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

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

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

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

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

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

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

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

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

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

Thank You Questions and Discussion