Transcript HCAs & Pipeline Assessment Intervals Is There a Need for

HCAs & Pipeline Assessment Intervals
Is There a Need for Change?
Richard B. Kuprewicz
President, Accufacts Inc.
For Pipeline Safety Trust New Orleans Conference 11/20 & 11/21/08
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Is There A Need For Change?
 The Answer is yes!
 Different yes for many sides/factions in this room
 Will briefly present
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Short regulatory perspective
Summary on integrity inspections
Weaknesses in present approach
Recommended changes
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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
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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”
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Captures ~ 43% of liquid transmission pipeline mileage or ~ 73,000 miles
 Gas Transmission Integrity Management
 PSIA of 2002
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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)
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Maximum Reassessment Interval ranging from 7 to 20 yrs based on stress levels
 HCA determined essentially by C-fer empirical correlation sweep
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Captures about 7% of gas transmission pipeline mileage or ~ 19,000 miles
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Anomalies Requiring Immediate Repair
 Liquid Transmission Pipelines
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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
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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
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 Other Conditions that may need to be scheduled
 E.g., anomaly in or near a casing, crossing, or near another pipeline
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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
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From PHMSA web site http://primis.phmsa.dot.gov/iim/index.htm
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From PHMSA web site http://primis.phmsa.dot.gov/gasimp/PerformanceMeasures.htm
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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
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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
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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
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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
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On Setting Regulatory Reassessment Intervals
 For corrosion
 Address the different risks of selective vs. general corrosion
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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)
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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!
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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