HCAs & Pipeline Assessment Intervals Is There a Need for Change?

1. HCAs & Pipeline Assessment IntervalsIs There a Need for Change? Richard B. Kuprewicz President, Accufacts Inc. For Pipeline Safety Trust New Orleans Conference 11/20 & 11/21/08

2. Is There A Need For Change? • The Answer is yes! • Different yes for many sides/factions in this room • Will briefly present • Short regulatory perspective • Summary on integrity inspections • Weaknesses in present approach • Recommended changes

3. Current Federal Regulations • Liquid Integrity Management (49CFR195.452) • Phased (via Large / Small Operator) Regulation in 5/29/2001 & 2/15/2002 • 7 year Baseline assessment • Large operator 50% by 9/30/2004, all by 3/31/08 • Small operator 50% by 8/16/2005, all by 2/17/2009 • ~ 5 year maximum reassessment interval • HCA determined by “could affect” • Captures ~ 43% of liquid transmission pipeline mileage or ~ 73,000 miles • Gas Transmission Integrity Management • PSIA of 2002 • 10 year Baseline Assessment • 50% inspected by 12/17/2007, 100% by 12/17/2012 • 7 year reassessments • PHMSA Regulation in 2003 (49CFR192 subpart O) • Maximum Reassessment Interval ranging from 7 to 20 yrs based on stress levels • HCA determined essentially by C-fer empirical correlation sweep • Captures about 7% of gas transmission pipeline mileage or ~ 19,000 miles

4. Anomalies Requiring Immediate Repair • Liquid Transmission Pipelines • Metal Loss > 80% nominal wall thickness • Remaining strength calc burst pressure at anomaly < MOP • Dent on top of pipe with stress concentrator • Dent on top of pipe > 6% pipe diameter • Anomaly in evaluator’s judgment requires immediate repair • Gas Transmission Pipelines • Remaining strength calc failure pressure at anomaly < 1.1 x MAOP • Dent on top of pipe with stress concentrator • Anomaly in evaluator’s judgment requires immediate repair

5. Liquid - Schedule Repairs • 60 – Day Conditions • Top dent > 3% diameter • Bottom dent with stress concentrator • 180 – Day Conditions • Dent > 2% diameter affecting curvature at girth/longitudinal seam • Top of pipeline dent > 2% diameter • Bottom of pipe dent > 6% diameter • Calc showing operating pressure less than MOP at anomaly • Metal loss > 50% of nominal wall • Predicted metal loss >50% of nominal wall at another pipe crossing, widespread circumference or could affect girth weld • Confirmed crack indication • Corrosion of or along a longitudinal seam • Gouge or groove > 12.5% of nominal wall thickness • Other Conditions that may need to be scheduled • E.g., anomaly in or near a casing, crossing, or near another pipeline

6. Gas - Schedule Repairs • 1 – Year Conditions • Dent on top of pipe > 6% diameter • Dent > 2% diameter affecting pipe curvature at girth or at longitudinal welds • Monitored Conditions Not Requiring Repair • Bottom Dent > 6% of diameter • Top Dent > 6% of diameter not exceeding critical strain levels • Dent > 2% diameter affecting curvature at girth or longitudinal welds but not exceeding critical strain levels

7. From PHMSA web site http://primis.phmsa.dot.gov/iim/index.htm

8. From PHMSA web site http://primis.phmsa.dot.gov/gasimp/PerformanceMeasures.htm

9. Changes Needed In Current IM Approach • U.S. Regs lead the world in area of Integrity Management (IM) • Some areas build off technology developed in other countries • U.S. approach is “Model One” - first of its kind • U.S. has more transmission mileage than other top fifteen countries combined! • Since inception of IM rule through 2007 - Tens of thousands of repairs have occurred on U.S. pipelines • Liquid Pipelines ~ 26,000 repairs in HCAs, another ~ 59,000 outside HCAs • Gas Transmission ~ 2,500 repairs in HCAs, non HCA repairs not required to be reported • Utilize Learning Curve from First Cycle of IM Assessments • Be aware history doesn’t define the future • Always room for improvement • Need public report repairs by anomaly cause • Limitations / traps in consensus standards • Reward those doing the right thing

10. On Setting Regulatory Reassessment Intervals • For corrosion • Address the different risks of selective vs. general corrosion • Selective corrosion can easily substantially exceed 12 mils/yr • Burst calculations models moot if assuming wrong corrosion rate! • PHMSA knows the difference between general and selective corrosion • Respect that PHMSA may be prevented from disclosing corrosion rates in certain cases • Other time-dependent anomalies need to be addressed • Move to newer stronger pipe (X-70, X-80, X-100, X120) • Delayed third party damage failure much more likely • Stress loading (i.e., land movement) complications • Reassessment interval changes must be based on sound science and sound assumptions • Are field realities in sync with assumptions in consensus standards? • Given uncertainties of present technology, a safety margin is still required for re-inspection intervals • Illusionary more “bad” inspections (whether mileage or frequency) are not better than fewer good inspections matching the risks!

11. On Addressing HCAs and Public Confidence • Expand HCAs • Increase the pipeline miles prudently inspected/re-inspected • For Liquids • Address other sensitive areas beyond current HCAs definitions of: • commercial navigable waterways, • populated areas, • unusually sensitive area • Capture High Impact and Risk Areas • E.g., sensitive parklands / protected areas • For Gas • Address the “exotics” where C-fer zone is way too small • More Public Transparency Required • PHMSA must report damage database by anomaly type • Mandate reporting of all pipe repairs, even beyond HCAs, by type of damage