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2012 FEPA Presentation: Charlie Hall
1. INTEGRITY MANAGEMENT
10 YEARS EXTERNAL
CORROSION DIRECT
ASSESSMENT (ECDA)
Charlie Hall
2. Pipeline Integrity Actions
• Incident Overview • Bellingham
June 10, 1999 a gasoline pipeline
ruptured
Washington
– Gasoline leaked into two creeks
in the City of Bellingham,
Washington and ignited
– Fireball killed three persons,
injured eight other persons
– Caused significant property
damage
– Released approximately 1/4
million gallons of gasoline
causing substantial
environmental damage
3. El Paso Pipeline Incident
August 19, 2000, 30-inch near Carlsbad, New Mexico.
6. Why Pipeline Integrity?
•“deterioration of a material, usually a metal, that results from a reaction
with its environment”
•Soil-side corrosion typically slow progressing
•Corrosion rate influenced by geological formations – “corrosive zones”
10. Pipeline Integrity
Issued Integrity Management (IM) Regulations
12/15/2003
Require Industry To:
Conduct an Analysis of the Risks and Adopt a
Written IM Program in High Consequence Areas
(HCA’s) by 12/17/2004
Begin Baseline Assessments: 06/17/2004
Finish Baseline Assessments: 12/17/2012
Reassess Covered Pipeline Every 7 Years
11. Gas Integrity Management Program
Scope and
Implementation Remediation
(901, 903, 907, 913) (933)
HCA Identification Prevent/Mitigative
(903, 905) (935)
Threat Analysis Continual Evaluation
(917) (937, 939, 941, 943)
Baseline Assessment Performance
(919, 921) Measures(947)
Direct Assessment QA, Training, Comm.
(923 through 921) (915, 945, 949, 951)
12. Baseline Assessment Tool Selection
Based Upon Threat Assessment Analysis
Smart Pigging Historical Information (Need
Further Investigation to Find Root Cause)
Hydrostatic Testing (PHMSA Gold Standard –
Disrupts Service / Introduces Water)
External Corrosion Direct Assessment (Major
Challenge for Acceptance – Industry Worked Out
Process ECDA)
13. ECDA – Four Step Process
Advantage
“can locate areas where defects could form in
the future rather than only areas were defects
have already formed”
14. ECDA – Four Step Process
1. Pre-Assessment
2. Indirect Inspection
3. Direct Examinations
4. Post Assessments
FAILURE TO FOLLOW PROCESS
JEOPARDIZES PIPELINE SAFETY
15. ECDA – Four Step Process
Pre-Assessment
“Utilization of Operational and Historical
Records to Assess Potential External
Corrosion Locations and to Determine
Feasibility of Applying ECDA”
UNDERSTANDING PIPELINE THREATS
AND THE NEED TO OVERCOME THE
ACCEPTANCE THAT RECORDS REVIEW
REQUIRED
16. ECDA – Four Step Process
Pre-Assessment
Identify and Address Corrosion Activity
Past or Old Corrosion Damage (Finds Old
Damage after CP Problem Corrected)
Present Activity (Yes)
Future Corrosion Risks (Identifies Problem
Areas)
Continuous Improvement Process (If Applied
Correctly)
17. ECDA – Four Step Process
Pre-Assessment
ECDA Feasibility Assessment
Integrate and Analyze Data Collected
Coating Electrical Shielding (ECDA Feasibility NO)
Backfill with Rock Content and Rock Ledges (Remain
Problem)
Ground Surface Hindrances, i.e. Pavements (Drilling/Traffic
Control)
Adjacent Buried Metallic Structures (Stray Current Influence)
Inaccessible Areas (Difficult to Access – Casings Overcome)
Situations That Prevent Aboveground Measurements in
Reasonable Time-Frame (Planning and Execution)
18. ECDA – Four Step Process
Pre-Assessment
Data Collection
Data Elements: Pipe-related, Construction Related,
Soils/environmental, Corrosion Control, Operational
Historical Records – Better Understanding Pipeline
Sufficient Data – Missing Records
Subject Matter Experts - Retirements
Determine ECDA Feasibility – (Missing Data)
Establish ECDA Regions
Similar Physical Characteristics – Role of Environment
Similar Past, Present, Future Corrosion Behaviors
Utilizes Similar IIT Tools
Select Indirect Inspection Tools
19. ECDA – Four Step Process
Indirect Inspection
CIS - Indicates CP Level
DCVG/ACVG - Indicates Exposed Metal
Soils - Indicate Environment Corrosivity
Depth - Indicate Third Party Damage Risk
PCM - Indicate Current Attenuation
20. ECDA – Four Step Process
Indirect Inspection
“Equipment and Practices Used to Take
Measurements at Ground Surface Above or
Near a Pipeline to Locate or Characterize
Corrosion Activity, Coating Holidays, or Other
Anomalies”
Data Collection, Quality, Recognition,
Current Interruption, Stray Current, Casings
and AC Corrosion
21. ECDA – Four Step Process
Indirect Inspection
Locate and define severity of coating faults where
corrosion may occur or be occurring Discovery
Coating Condition More Severe
Conduct at least two indirect inspection tools (IIT) the
entire length of the ECDA Region Casings and AC
Corrosion
Align and compare results from IIT tools More Stray
Current Than Expected
Identify, classify, and report results for Direct
Examination step
22. ECDA – Four Step Process
Direct Examination
“Inspections and Measurements Made On the
Pipe Surface at Excavations as Part of
External Corrosion Direct Assessment
(ECDA)”
Qualified Experienced Personnel
26. ECDA – Four Step Process
Post Assessment
“Analysis of Indirect Inspections and Direct
Examinations to Assess Pipeline Integrity,
Prioritize Repairs, Redefine Reassessment
Intervals and Assess the Overall Effectiveness
of the ECDA Process”
27. ECDA – Four Step Process
Direct Examination
Process Validation
Remaining Life Calculation
Define Reassessment Interval
Define Effectiveness Measures
Continuous Improvement
Reassess ECDA Feasibility
As the pipeline ages, failures on the pipeline have become more frequent. Some years ago, the pipeline industry began to get extensive attention from regulators and legislators. Bellingham, WA incident Olympic Pipeline was implementing a new SCADA system and ignored a pipeline failure which pumped liquids into a stream. Some children playing with matches were killed when the water caught on fire. Some years later, an internal corrosion leak resulted in a group that had camped alongside a bridge to be killed. Gas leaked from the pipeline migrated over to a campfire and ignited. 12 people were involved in this incident. Congress legislated increased safety standards that resulted in the Pipeline Integrity Act.
Code of Federal Regulations Title 49 Part 192 Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines): Final rule
Note implementation deadline dates
Scope and Implementation: Develop and Follow a Written Integrity Management Plan Plan Contains All 16 Program Elements Specified in 192.911 HCA Identification, Baseline Assessment, Threat ID/Risk Assessment, DA Plan, Remediation, Continual Evaluation, Confirmatory DA, Preventative/Mitigative Measures, Performance Metrics, Recordkeeping, Management of Change, Quality Control, Communication Plan, Submittals to Regulators, Minimization of Environmental/Safety, Identification of New HCA’s Address the Risks on Each Covered Segment Collectively, a Set of Document(s) that Systematically Define, Control, and Implement Integrity Management Take Advantage of Existing Programs (e.g., O&M) Framework ( § 907) Minimal Process Detail Process for Implementing Each Program Element Describe How Relevant Decisions Will Be Made, By Whom, and Timeline Continual Incorporation of New Info Gained from Experience Evolve Into More Detailed and Comprehensive Program Continual Improvements Plans Certain Program Elements Described in Rule Refer to “Plans” Baseline Assessment Plan DA Plan (ECDA, ICDA, SCCDA) Performance Plan Communication Plan Why Have Written Plans? Accountability Compliance Record Portability (Asset Transfer) Consistent Implementation (Personnel Turnover) Progress (Performance) Standard Threat Analysis Prescriptive - 9 Categories 1. Internal Corrosion 2. External Corrosion 3. Stress Corrosion Cracking 4. Manufacturing-Related 5. Welding/Fabrication-Related 6. Equipment 7. Third Party/Mechanical Damage 8. Incorrect Operations 9. Weather-Related and Outside Force Data Gathering and Integration 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 B31.8S Requires Systematic Effort Comprehensive Plan to Collect, Review & Analyze Data Validated and Documented Data and Assumptions Timely Consideration of New Information Data Integration Aimed At Putting Together Data from Different Sources for Better Understanding of Threats Combining Data from Integrity Assessments with Threat Assessment Requires ANALYSIS Continual Improvement “ Mature” Program is Not the End of Program Development Critical Self-Assessment Study Integrity Mgt Performance Identify Areas to Improve Risk Assessment Follow B31.8S, Section 5 Consider All Identified Threats Use Risk Assessment To: Prioritize Baseline Assessments Prioritize Reassessments Determine Additional Preventive and Mitigative Measures All Approaches Entail Identification of Relevant Threats for Each Covered Segment Characterization of Likelihood and Consequences of Pipeline Failure Likelihood and Consequences Combined to Calculate Risk References Standards Rule Invokes Industry Standards Documents (or Portions Thereof) Incorporated by Reference are Invoked in Subpart O as Though Set Out in Full in the CFR Re: 49 CFR 192.7 contains list NACE RP0502-2002 (ECDA) Entirety ASME B31.8S-2001 (IM) Specific (Most) Sections §§ 2, 4, 5, 6.2, 6.3, 6.4, 7, 9, 10, 11, 12, App A, App B.2
Three Baseline Assessment Tools Can be Applied: 1- Smart Pigging 2- Hydrostatic Testing 3- External Corrosion Direct Assessment