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A Regulator’s View on Approaches to MIC Threat and Failure Assessment
Presentation by: Jenny Been, National Energy Board
Forum on Assessment of Microbiologically Influenced Corrosion
(MIC) Threats and Failures: Approaches and Challenges
Thursday, Feb 7, 2019 from 8:45AM - 11:30AM
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Disclaimer
The views, judgments, opinions and recommendations expressed in this session do not necessarily reflect those of the National Energy Board, its Chair or Members, nor is the Board obligated to adopt any of them.
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A Regulator’s View on Approaches to MIC Threat and Failure Assessment
• OPR S40 Integrity Management Program
o A company shall develop, implement and maintain an integrity management program that anticipates, prevents, manages and mitigates conditions that could adversely affect safety or the environment during the design, construction, operation, maintenance or abandonment of a pipeline.
• The pipeline company is accountable to implement an adequate and effective IMP
o Follow standards such as CSA Z662
• The regulator must have the confidence in the company’s ability and commitment to do so
o May use Information Requests to clarify, demonstrate, justify, etc.
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NEB Regulated Pipelines
Comparison of Length of Regulated Pipelines
NEB 71,000 km
AER 415,000 km
PHMSA 816,000 km
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2176
162
692
2002 to 2009
Other Incident Causes
Internal Corrosion
External Corrosion
PHMSA Incident Data – Hazardous Liquid Pipelines
2832439
278
2010 to present
Other Incident Causes
Internal Corrosion
External Corrosion
692
14565
ExternalCorrosion
MIC Transmission
439
192
41
InternalCorrosion
MIC Transmission
278
38 20
ExternalCorrosion
MIC Transmission
Overall: 4.8% MIC
Transmission:
2.1% MIC
Overall: 6.5% MIC
Transmission:
1.7% MIC
6
867
150
70
2010 to present
Other Incident Causes
Internal Corrosion
External Corrosion
762
159
108
2002 to 2009
Other Incident Causes
Internal Corrosion
External Corrosion
PHMSA Incident Data – Gas Pipelines
108
5 3
ExternalCorrosion
MIC Transmission
150
61
5
InternalCorrosion
MIC Transmission
70
4 4
ExternalCorrosion
MIC Transmission
159
73
23
InternalCorrosion
MIC Transmission
Overall: 7.6% MIC Transmission: 2.5% MIC
Overall: 6.0% MIC Transmission: 0.8% MIC
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0
20
40
60
Total ILI HCA Coated Asphalt /Coal Tar
Tape Other Leak Rupture
Hazardous Liquid Pipelines
External Corrosion 2001-2009 External Corrosion 2010-present
Internal Corrosion 2010-present
0
5
10
15
20
25
Total ILI HCA Coated Asphalt /Coal Tar
Tape Other Leak Rupture
Gas Transmission Pipelines
External Corrosion 2001-2009 Internal Corrosion 2001-2009
External Corrosion 2010-present Internal Corrosion 2010-present
PHMSA Incident Data
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NEB Incident Data
Canada
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• MIC failures have been most strongly associated with clay soils and tape coating
• However, MIC failures have been recorded in different soil types with many types of coating
NEB Incident Data with MIC as the main or as a contributing cause
0
2
4
6
8
10
Total ILI Class 1 Asphalt Tape Leak Rupture
Gas Transmission Pipelines
External Corrosion 2002-present
• No reported incidents on liquid lines
• No reported internal corrosion incidents
• The role of MIC may not be known and may not be reported
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Where can we expect MIC?
The conclusion that MIC has taken place should be based on the preponderance of circumstantial evidence (NACE TM0106-2016)
• Gathering and aligning data
• Coating condition
• Type of coating, field or plant applied, age of coating, soil type and conditions, excavation data on the line
• Above-ground inspections (e.g. DCVG, ACVG)
• Anaerobic/aerobic conditions, water table (elevation profile), soil type
• In-situ monitoring of the environment at pipe depth, e.g. NOVAProbe (soil resistivity, ORP, T, pH)
• Rely still largely on In-Line Inspections
“Indirect” Assessment:
NOVAProbe
• Portable probe for
characterizing the
environment at pipe depth
– Soil resistivity (R)
• Soil moisture, how dry?
– Oxidation Reduction Potential
(ORP)
• Oxygen levels
• Anaerobic conditions
– Temperature
– pHInserting Probe in soil
IPC2004-0371
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2009 Rupture of the NGTL Peace River Mainline (PRML)
• 481 km, 20-inch dia (7.14 mm wall) gas pipeline in NW AB, Class 1
• Built in 1968, field coated with PVC tape
• 1973-2009: experienced 16 leaks and 6 ruptures
• External corrosion as the predominant failure mechanism
• Operated under the jurisdiction of the ERCB (now AER) until 2009, when it moved to the jurisdiction of the NEB
• ILI and excavation program in place
• Rupture in silty soil with some clay present; considerable water at pipe depth
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• Extensive corrosion with localized areas of deep corrosion (complex corrosion geometries)
• Corrosion deposit analysis indicated the presence of iron oxide, iron carbonate, and iron sulphide (mackinawite)
• The presence of MIC thought to be primarily the result of SRB
• Supported by the presence of sulphate rich soil
• MIC was a contributing factor to the external corrosion and the rupture of PRML
• Average corrosion rates were of the order of 0.2 mm/y, where MIC may accelerate pitting rates up to 0.7 mm/y
• Increasing the CP to -1000 mV ON potential was ineffective in the presence of the disbonded shielding coating
• ILI process improvements prioritized areas of external corrosion for coating repair (2004, 2006, 2007)
2009 Rupture of the NGTL PRML
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• Undersizing of the complex corrosion by the MFL tool
• A field investigation was not triggered
• A new set of field investigation criteria for complex corrosion was developed
• The new criteria were validated with a pressure test
• NEB imposed a more conservative criterion for depth of 70% wall thickness or deeper
2009 Rupture of the NGTL PRML
Characteristic 2007 MFL Prediction 2009 Measurement
Depth 71% wall thickness 95% wall thickness
Failure Pressure 8310 kPa (1.47 MOP) 5540 kPa (0.98 MOP)
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Management system causes of the rupture
• Operational control deficiencies within the IMP, including ineffective external coating, cathodic protection, and in-line inspection
• Inadequate criteria for field investigation by not accounting for the unforeseen tool limitation of sizing complex corrosion
NEB made recommendations to all companies regulated under its jurisdiction to consider the occurrence of complex corrosion and implement the appropriate complex corrosion field investigation criteria
2009 Rupture of the NGTL PRML
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Conclusions
• The pipeline company is accountable to implement an adequate and effective IMP
• The regulator must have the confidence in the company’s ability and commitment to do so
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Challenges
• Difficulty of locating MIC using ECDA methodology, monitoring local conditions, and relating these conditions to the severity of corrosion
• Development of In-line inspection technology that reliably detects pinhole and pitting corrosion, complex corrosion
• Setting appropriate and conservative field investigation criteria