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Ted Christensen, PE
Direct Assessment ECDA – Program Development
Objective:
1. Why is there an ECDA plan ?2. What are acceptable methods of
an ECDA plan ?3. Does it make a difference ?
Requirements
“Pipeline Safety Improvement Act of 2002”
Signed into law on December 17, 2002
The law has 25 sections
“RISK ANALYSIS AND INTEGRITY
MANAGEMENT PROGRAMS FOR GAS
PIPELINES”
Requirements
Each operator who owns or operates a gas transmission line in a high consequence area must adopt an integrity management plan that -
• Identify the high consequence areas (HCA’s)
• Perform risk assessment to prioritize HCA’s
• Perform baseline assessment
• Has integrity management plan (14 required sections)
Requirements • December 17, 2002 - Pipeline Safety Improvement Act of 2002
signed into Law• December 17, 2002 – Operators may begin base line assessment
(grandfather)• January 28, 2003 – DOT issues proposed rule• December 12, 2003 – DOT issues regulation • June 17, 2004 - Operators must start base line assessment• December 17, 2004 – Operators must complete risk analysis and
adopt an integrity management plan (24 months)• December 17, 2007 – Operators must complete baseline assessment
for 50% of facilities, must be the highest priority (5 years)• December 17, 2012 – Operators must complete base line
assessment for 100% of facilities (10 years)
Requirements
There are 4 acceptable methods defined by the rule for the baseline assessment:
1. Internal inspection (ILI)2. Pressure testing3. Direct assessment4. Other methods
Direct Assessment • Types of Direct Assessment
• External Corrosion Direct Assessment (ECDA)• Internal Corrosion Direct Assessment (ICDA)
• Stress Corrosion Direct Assessment (SCCDA)
ECDA External Corrosion Direct Assessment
A four part process that combines pre-assessment, indirect inspections, direct examinations, and post assessment to evaluate the impact of external corrosion on the integrity of a pipeline
Regulation DOT 192.925 - What are the requirements for using External Corrosion Direct Assessment (ECDA)?
Must follow the requirements in
ASME/ANSI B31.8S - section 6.4
NACE RP 0502-2010
Regulation The operator must develop and implement a plan that
has procedures addressing:
(1) Preassessment(2) Indirect examinations(3) Direct examinations(4) Post assessment and continuing evaluation
The 4 required steps
(1) Pre-assessment
(2) Indirect examinations(3) Direct examinations(4) Post assessment and continuing
evaluation
Preassessment • NACE RP 0502-2010 section 3• ASME B31.8S section 6.4
Apply a more restrictive criteria for first time use of ECDA in HCA section
Use of two different, but complimentary tools (must be listed in NACE RP 0502-2010 appendix
A or the operator must prove technique)
Preassessment (cont.)
NACE RP 0502-2010 Section 3Preassessment - • Data collection (3.2)• Assessment of ECDA feasible (3.3)• Selection of indirect inspection tools (3.4)• Identification of ECDA regions (3.5)Requires -
• Sufficient data collected, integrated, and analysis• Comprehensive and thorough fashion
Preassessment (Data collection)
As a minimum, the pipeline operator shall include data from the following five categories, as shown in Table 1
1. Pipe-related (6)
2. Construction-related (11)
3. Soil/environment (5)
4. Corrosion Control (10)
5. Operational (11)
A Total of 43 Data Elements
Preassessment (Data collection)
Table 1: ECDA Data Elements (PIPE-RELATED)
Data Elements Indirect Inspection ToolSelection
ECDA Region definition Use and Interpretation of Results
PIPE -RELATEDMaterial (steel, cast iron, etc.)and grade
ECDA not appropriate fornonferrous materials.
Special considerations should begiven to locations wheredissimilar metals are joined.
Can create local corrosion cells whenexposed to the environment.
Diameter May reduce detectioncapability of direct inspectiontools.
Influences CP current flow andinterpretation of results
Wall thickness Impacts critical defect size and remaininglife predictions
Year Manufactured Older pipe materials typically have lowertoughness levels, which reduces criticaldefect size and remaining life predictions.
Seam Type Locations with pre-1970 lowfrequency electric resistancewelded (ERW0 or flash weldedpipe with increased selectiveseam corrosion susceptibility mayrequire separate ECDA regions.
Older pipe typically has lower weld seamtoughness that reduces critical defect size.Pre-1970 ERW or flash-welded pipe seamsmay be subjected to higher corrosion ratesthan the base metal.
Bare pipe Limits ECDA application.Fewer available tools – SeeAppendix A.
Segments with bare pipe incoated pipelines should be inseparate ECDA regions.
See ECDA methods provided in AppendixA.
Preassessment (Data collection)
• If there is insufficient data for a ECDA region, and you cannot support the preassessment step, ECDA shall not be used for that segment
• Much of the data needed for the ECDA preassessment step is also used in the risk assessment phase of a pipeline integrity management program
Preassessment (Assessment of ECDA feasible)
The following conditions may make it difficult to apply ECDA• Coatings that cause electrical shielding• Backfill with significant rock content or rock ledges• Pavement, frozen ground and reinforced concrete• Adjacent buried metallic structures• Inaccessible areas
If indirect inspection methods are not practical, the ECDA process may not be applied.
Preassessment (Selection of indirect inspection tools)
• DOT 192.925 (b) (1) (ii)“If an operator utilizes an indirect inspection method that is not discussed in appendix A of NACE RP0502-2010, the operator must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of the data for the inspection method”
Preassessment (Selection of indirect inspection tools)
Selection of Indirect Inspection Tools
Minimum of two indirect inspection tools • Detect corrosion activity and/or coating holidays
• Endeavor to use complimentary tools• The strength of one tool compensates for the limitations of the
other tool
• Table 2: ECDA Tool Selection Matrix
• Appendix A: Indirect Inspection Methods
Preassessment (Selection of indirect inspection tools)
NACE RP0502-2010 appendix AIndirect Inspection methods
• Close -interval surveys (CIS)• AC current attenuation surveys• DCVG and ACVG surveys• Pearson surveys• Cell-to-cell surveys
Preassessment (Selection of indirect inspection tools)
• Table 2: ECDA Tool Selection Matrix (Partial)
Preassessment (Identification of ECDA regions)
An ECDA region is a portion of a pipeline segment that has • Similar physical characteristics• Similar corrosion history• Expected corrosion conditions• Uses the same indirect inspection tools
Preassessment (Identification of ECDA regions)
• Table 1 - ECDA Data Elements and Table 2 - ECDA Tool Selection Matrix may be used as guidance in establishing ECDA regions
• The definitions of ECDA regions may be modified based on the results of the indirect and direct inspection steps
• A single ECDA region does NOT have to be contiguous (either side of a river)
Preassessment (Summary)
• Data is gathered and reviewed(More information may be needed)
• Establish if ECDA is appropriate(Could be used for some HCA segments but not for others)
• Indirect inspection tools are identified(Different tools for different HCA segments)
• Regions are identified (Regions may change after indirect and direct examination)
Document your data, data sources, assumptions and decision making process
The 4 required steps
(1) Preassessment
(2) Indirect examinations
(3) Direct examinations(4) Post assessment and continuing
evaluation
Indirect examinations
NACE RP0502-2010 Section 4 To define the severity of coating faults, other anomalies and areas at which corrosion activity may have occurred or may be occurring
1. Requires the use of at least two inspection tools over the entire length of the ECDA region
2. Align and compare the data from the two inspection tools3. May require more than two inspection tools in a ECDA
region
Indirect examinations • The boundaries of the ECDA region should be clearly
marked• When ECDA is applied for the first time, consider spot
checking, repeating inspections or other means to ensure consistent data
• The distance selected must be such that the inspection tool can detect and locate corrosion activity
• The indirect inspections should be conducted as close together as in time as practical (Change of season, installation or abandonment of facilities)
• GPS shots should be taken on above ground locations (even if outside of region)
Indirect examinations After the indirect inspection data is taken, indications shall be identified and aligned for comparison
• Must define criteria for identifying indications• Coated lines: Should be sufficient to locate coating
faults regardless of corrosion activity at the fault• Poorly coated or bare lines: Should be sufficient to
locate anodic regions• Must consider spatial errors
Indirect examinations
Indirect examinations
After identifying and aligning indications, a classification system must be defined and applied • Classification is the process of estimating the likelihood of corrosion activity at each indication under typical year-round conditions• Severe - highest likelihood of corrosion• Moderate - possible corrosion activity• Minor - inactive or lowest likelihood of corrosion
Indirect examinations • The criteria for classifying the severity
• capabilities of the indirect inspection tool• unique conditions within the ECDA region
• When ECDA is used for the first time• Make the classification system as stringent as possible
• When it cannot be determined whether corrosions is active, an indication should be considered severe
Indirect examinations • Table 3: Example Severity Classification
Tool/Environment Minor Moderate SevereCIS, aerated moist
soilSmall dips with onand off potentialsabove CP criteria
Medium dips or offpotentials below CP
criteria
Large dips or on andoff potentials bellow
CP criteriaDCVG survey,
similar conditionsLow voltage drop:
cathodic conditions atindications when CP
is on and off
Medium voltage dropand/or neutralconditions at
indications when CPis off
High voltage dropand/or anodic
conditions when CP ison or off
ACVG or Pearsonsurvey, similar
conditions
Low voltage drop Medium voltage drop High voltage drop
Electromagnetic Low signal loss Medium signal loss High signal lossAC current
attenuation surveySmall increase in
attenuation per unitlength
Medium increase inattenuation per unit
length
Large increase inattenuation per unit
length
Indirect examinations If two or more indirect inspection tools indicate a significant different set of locations at which corrosion activity may exist-• Explained by the inherent capabilities of tools?• Specific and localized pipeline features?
or• Preliminary direct examinations• Additional indirect examinations
Indirect examinations • If discrepancies cannot be resolved
• ECDA feasibility should be reassessed
• For initial ECDA applications, any location at which discrepancies cannot be resolved, the location shall be categorized as severe
Indirect examinations • After discrepancies have been resolved, the results of the indirect examination shall be compared with the results of the preassessment and prior history of each ECDA region• If the results are not consistent
• Reassess ECDA feasibility• Reassess ECDA region definition
Indirect examinations
•NOTE: 192.933 (b) states - ...to determine that the condition presents a potential threat to the integrity of the pipeline…..An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about the condition to make that determination.
Indirect examinations (Summary)
• Mark regions and conduct surveys• Align and compare results• Define classification system
• Must be as stringent as practical if ECDA is used for the first time
• Compare results• May need to do a preliminary direct exam• ECDA may not be feasible• If using ECDA for first time, unresolved discrepancies
must be classified as severe• Must be consistent with pre-assessment and region
definitions
The 4 required steps (1) Preassessment(2) Indirect examinations
(3) Direct examinations
(4) Post assessment and continuing evaluation
Direct examinations
NACE RP0502-2010 Section 5
The objectives of the Direct Examination Step is to determine which indications from the indirect inspections are most severe and collect data to assess corrosion activity
Direct examinations • The six phases involved
• Prioritization of indication found during the indirect inspections
• Excavation and data collection at areas where corrosion activity is most likely
• Measurements of coating damage and corrosion defects
• Evaluation of remaining strength• Root cause analysis• A process evaluation
Direct examinations (Prioritization)
Table 4: Example Prioritization of Indirect Inspection Indications
Immediate Action Required Scheduled Action RequiredStable for
Monitoring Severe indications in close proximity
regardless of prior corrosion Individual severe indications or groups
of moderate indications in regions ofmoderate prior corrosion
Moderate indications in locations inregions of severe prior corrosion
All remaining severindications;
All remaining moderateindications in regions ofmoderate prior corrosion
Groups of minor indications inregions of severe priorcorrosion
Allremainingindications
Direct examinations • DOT 192.993 (c) Schedule for evaluation and remediation
• Must follow schedule in ASME B31.8S Section 7 Figure 4• Based on MAOP Above 50%/ Above 30% but not exceeding 50% / Not
exceeding 30%• Table is Pf/MAOP vs Response Time (years)
Direct examinations (Measurements)
• Excavations based on the priority categories• Define minimum requirements for consistent data collection• NACE RP 0502-2002 Appendix A/B/C contains typical
data measurements and related activities• Gather information on
• Environment soils/water/MIC
• Coating type/condition/thickness/adhesion• Corrosion product/defects/measurements
Direct examinations (Remaining strength)
• Evaluate or calculate the remaining strength at locations where corrosion defects are found• ASME B31G• RSTRENG• DNV Standard RP-F101
Direct examinations (Root cause analysis)
• Must identify any root cause of all significant corrosion
• If a root cause is uncovered for which ECDA is not well suited, an alternative method of assessing the integrity should be considered• Shielding by disbonded coatings• biological corrosion
Direct examinations (Process evaluation)
The purpose is to evaluate the criteria used to categorize the repair criteria and severity criteria • If existing corrosion is less severe than prioritized, you may modify
the criteria and then reprioritize all indications
• If existing corrosion is more severe than prioritized, you must modify the criteria and reprioritize all indications
• Any indication for which a comparable direct examination measurement shows more serious conditions than the indirect inspection data, indications shall be moved to a more severe
category
Direct examinations (Summary)
• Prioritization of indication
• Excavation and data collection
• Measurements of coating damage and corrosion
defects
• Evaluation of remaining strength
• Root cause analysis
• A process evaluation
The 4 required Steps (1) Preassessment(2) Indirect examinations(3) Direct examinations
(4) Post assessment and continuing evaluation
Post assessment and continuing evaluation
NACE RP0502-2010 Section 6
The objective of the Post-Assessment Step is to define reassessment intervals and assess the overall effectiveness of the ECDA process
Post assessment and continuing evaluation
Reassessment intervals based on • All immediate indications have been addressed during
direct examination• All monitored indications are expected to experience
insignificant growth• Remaining life calculations• Must not exceed DOT 192.939
Post assessment and continuing evaluation
DOT 192.939• Pipelines operating at or above 50% SMYS
• Direct Assessment every 10 years• Confirmatory Direct Assessment every 7 years
• Pipelines operating at or above 30% SMYS, up to 50% SMYS• Direct Assessment every 15 years• Confirmatory Direct Assessment every 7 years
• Pipelines operating below 30% SMYS• Direct Assessment every 25 years• Confirmatory Direct Assessment every 7 years
Post assessment and continuing evaluation
Remaining life calculations• If no corrosion defects are found, no remaining life
calculations are needed, the remaining life can be taken as the same for a new pipeline
• The maximum remaining flaw size shall be taken as the same size as the most severe indication • Root cause shows most severe indication is unique, use next
most severe indication• Substitute based on more sophisticated method
• Use values and methods provided in Appendix D in the absence of measured corrosion rate data
Post assessment and continuing evaluation
Remaining Life = C x SM x t/GR
• C = Calibration factor of 0.85• SM = Safety margin = Failure pressure ratio minus MAOP ratio,
• Failure pressure ratio = calculated failure pressure / yield pressure• MAOP ratio = MAOP / yield pressure
• t = nominal wall thickness (mm or in)• GR = Growth Rate 0.4 mm/y (16mpy)
Post assessment and continuing evaluation
Remaining life example:• 20 inch OD / .375 wt / x-52 / fp = 1700 psig
• Yield = (2 x wt x SMYS)/OD = (2 x .375 x 52,000) / 20 = 1950 psig• MAOP = Yield x CF = 1950 x .50 = 975 psig• Failure pressure ratio = fp/yield = 1700/1950 = .872• MAOP ratio = MAOP/yield = 975/1950 = .500• Safety margin = .875 - .500 = .375• t/GR = .375/.016 = 23.44 years
RL = 0.85 x 0.375 x 23.44 years = 7.47 years
Post assessment and continuing evaluation
• When corrosion defects are found during the direct examinations, the maximum reassessment interval for each ECDA region shall be taken as one-half the calculated remaining life
• Different ECDA regions may have different reassessment intervals based on variations in expected growth rates between ECDA regions
Post assessment and continuing evaluation
Assessment of ECDA effectiveness• At least one additional direct assessment location at a randomly
selected location shall be conducted to provide additional conformation that the ECDA process is working
• For initial ECDA applications, at least two additional direct exams will be performed• One which is classified as scheduled (monitor)• One in location where no indication exist
Post assessment and continuing evaluation
Activity for which feedback should be considered1. Identification and classification of indirect inspection results2. Data collected from direct examinations3. Remaining strength analysis4. Root cause analysis5. Remediation activities6. In-process evaluation7. Direct examinations used for process validation8. Criteria for monitoring long term ECDA effectiveness9. Scheduled monitoring and period reassessment
Records NACE RP0502-2010 Section 7
The ECDA records that document in a clear, concise, workable manner all 4 steps in the ECDA process
ECDA Process Summary • Pre-assessment
• Data / ECDA feasibility / Selection of tools / identification of regions
• Indirect examinations• Conduct surveys / align and compare results / define classification system /
compare results
• Direct examinations• Prioritization / data collection / remaining strength / root cause analysis /
process evaluation
• Post assessment and continuing evaluation• Remaining life / re-assessment / effectiveness / improvement
Common Question Does ECDA really work?
YES, BUT…..
• It will not work in all HCA segments
• The results of the indirect inspections may lead you to utilize IIL or pressure testing
• All four steps in the ECDA process must be completed thoroughly and documented
Areas of Concern • Coatings that shield
• Tapes / extruded poly• Field joints - cold and hot applied tapes / heat shrink sleeves
• Deep pipelines - HDD• Poorly coated pipelines - number of indications
• Casings• Remaining life calculations - 16 mils/year• Surface conditions - pavement• Sacrificial Anodes - On/Off CIS / Coating fault indications
Summary Documentation, Documentation, Documentation
Detail procedures
Share information
Expect to revise your procedures
ECDA is only one part of your company’s Pipeline Integrity Management Program
Resources • Federal Register December 15, 2003 Vol. 68, No. 240.
Docket No. RSPA-00-7666 DOT Subpart O Pipeline Integrity Management 192.901 - 192.947
• NACE Standard PR0502-2010 Pipeline External Corrosion Direct Assessment Methodology
• ASME/ANSI B31.8S Managing System Integrity Of Gas Pipelines
Conclusion
•Why is the an ECDA plan ?•What are acceptable methods of
an ECDA plan ?•Does it make a difference ?
Thank You!
QUESTIONS ?
Ted Christensen, PEMercer Technical Services
816-820-2898