New Rulemakings: What Can We Expect - Gary Krichau

NEW RULEMAKINGS – WHAT CAN WE EXPECT?

FINAL RULE
PIPELINE SAFETY: SAFETY OF GASTRANSMISSION PIPELINES, MAOP RECONFIRMATION
EXPANSIONOF ASSESSMENT REQUIREMENTS

FINAL RULE
Issued October 1, 2019
Federal Register Docket No.
PHMSA-2011-023

HISTORY
New rules have been in development since 2010.
[2010]
PG&E
San Bruno, CA
[2011]
ANPRM
MCA’s, MAOP,
Material
[2012]
Columbia
Sissonville, WV
[2016]
NPRM
[2019]
Final Rule

WHAT’S INTHE FINAL RULE?
• Expansion of Safety-RelatedCondition Reporting
• Moderate ConsequenceAreas
• New standards for ILI incorporated by reference
• Records: Material properties, Pipe design, Pipe components
• Spike hydrostatic pressure tests
• Verification of pipeline material properties and attributes
• MAOP reconfirmation
• Engineering critical assessment
• Analysis of predicted failure pressure
• Launcher and receiver safety
• Changes to IMP program notifications
• IMP – Identification of potential threats, Baseline assessments, Preventive and mitigative measures, reassessment
intervals

IN-LINE INSPECTION STANDARDS
192.7

INCORPORATED BY REFERENCE
• API Standard 1163
In-line Inspection Systems Qualifications
Second edition, April 2013, Reaffirmed August 2018
• ANSI/ANST ILI-PQ-2005 (2010)
In-line Inspection Personnel Qualification and Certification
Reapproved October 11, 2010
• NACE Standard Practice 0102-2010
In-line Inspection of Pipelines
Revised 2010-03-13

IMPACT
• All three standards reference each other
• API 1163 has been in use to qualify in-line inspection tool systems
• Describes risks to be investigated, choosing proper inspection technology,
maintaining operating conditions within performance specifications, and
confirmation of results
• Stringent documentation requirements
• ANST ILI-PQ has been in use to quality in-line inspection personnel
• Tools include geometry, axial magnetic flux, transverse magnetic flux, ultrasonic,
EMAT, and mapping technologies

IMPACT
• NACE 0102
• Tool selection
• Logistical guidelines for contracting in-line inspection vendors
• Inspection scheduling
• New construction – Planning for ILI surveys
• Multi-diameter line pipe, consistent wall thickness, valves, bends
• Pup joint installation every 1.2 miles (2 kilometers)
• GPS data from construction of welds
• Data analysis requirements
• Data management

IMPACT
• Procedure manual will need to include the requirements found in the three standards
• Ensure ILI systems are qualified
• More prescriptive ILI verification digs
• Ensure ILI analysts are qualified
• All aspects of the ILI project life cycle
• GIS requirements
• Documentation

RECORDS: MATERIAL PROPERTIES
• For pipelines installed after July 1, 2020, or if you have existing records
• Diameter
• SMYS
• Ultimate tensile strength
• Wall thickness
• Seam type
• Chemical composition (per APL 5L etc.)
• Life of facility record
• If material properties are required to reconfirm MAOP, subject to 192.624 and 192.607

IMPACT
• Existing processes for documenting and retaining the following:
• Diameter
• SMYS
• Wall thickness
• Seam type
• Need to revise processes and pipeline data to accommodate
• Chemical composition (per APL 5L etc.)
• Toughness will also be required for longitudinal seams and pipe body

MODERATE CONSEQUENCE AREAS
192.3

DEFINITION
Within the Potential Impact Radius of a pipeline, any area containing
• 5or more buildings intended for human occupancy
• Any portion of a paved surface including shoulders of a designated interstate, or
other freeway, or expressways, as well as any other principal arterial roadway
with 4or more lanes of traffic
• Is NOT already a high consequence area

IMPACT
• Adds moderate consequence areas to the existing high consequence areas
• Note that the only new code requirements defined thus far are for moderate
consequence areas within pipeline segments operating at 30% SMYS or higher
• MAOP Reconfirmation
• Integrity assessment

MAOP RECONFIRMATION – APPLICABILITY
• Two Categories
1. MAOP previously established by a subpart J pressure test without traceable, verifiable, complete
records within the following:
(Class 1: 1.1 x MAOP, Class 2: 1.25 x MAOP, Class 3: 1.5 x MAOP, correct duration, etc.)
• Any High Consequence Area
• All Class 3 locations and Class 4 locations
2. Grandfathered MAOP (five-year HighestActual Operating Pressure 1965-1970) AND the pipeline
MAOP is greater than or equal to 30% SMYS within the following:
• Any High Consequence Area
• All Class 3 locations and Class 4 locations
• Any Moderate Consequence Area

MAOP RECONFIRMATION – SIX METHODS
1. PressureTest per subpart J and Material Property Records per 192.607 if not
already on-hand
2. Pressure Reduction based on Highest Actual Operating Pressure
10/1/2014 – 10/1/2019
3. Engineering Critical Assessment per 192.632
4. Pipe Replacement
5. Pressure Reduction for Potential Impact Radius less than or equal to 150 feet
6. AlternativeTechnology with prior PHMSA approval

APPLICABLE PIPE
192.619 Maximum Allowable Operating Pressure – Steel or plastic pipelines
• (a)(1) Design pressure
• (a)(2)Test pressure
• (a)(3) Highest actual operating pressure 1965-1970
• (a)(4) By operator considering history
• (c) Grandfathered
• (d) Per 192.620 special permit

APPLICABLE PIPE
(a)(1) (a)(2) (a)(3) (a)(4) (c) (d) Other Total
Total 136,121 90,896 12,928 9,933 42,747 6,392 2,455 301,472
Incomplete 946 1591 334 158 630 0 45 3,704
%Total 45% 30% 4% 3% 14% 2% <1%
DOT Annual Report Data – 2018

APPLICABLE PIPE
• In theory, all pipe categorized under 192.619(a)(1),(2),(d)etc., which is
pressure tested pipe per subpart J, will NOT need to be reconfirmed
• All grandfather pipe (192.619(a)(3)(4),(c)) that is over 30% SMYS or is in a
moderate consequence area that is over 30% SMYS, will need to be
reconfirmed
• Any change in class location or identification of a new HCA or MCA could
require reconfirmation of MAOP within 4 years

APPLICABLE PIPE
(a)(1) (a)(2) (a)(3) (a)(4) (c) (d) Other Total
Total 136,121 90,896 12,928 9,933 42,747 6,392 2,455 301,472
Incomplete 946 1,591 334 158 630 0 45 3,704
%Total 45% 30% 4% 3% 14% 2% <1%
DOT Annual Report Data – 2018

MAOP RECONFIRMATION – DATES
• Procedures for MAOP reconfirmation by July 1, 2021
• Complete required actions on 50% of mileage by July 3, 2028
• Complete required actions on 100% of mileage by July 2, 2035

ENGINEERING CRITICAL ASSESSMENT
192.632

ECA REQUIREMENTS
• Must assess
• Threats; loadings and operational circumstances relevant to those threats
• Outcomes of threat assessments
• Relevant mechanical and fracture properties
• In-service degradation or failure processes
• Initial and final defect size relevance
• Effects of interaction of threats on any defects

ECA ANALYSIS
• Material properties
• Diameter
• Wall thickness
• Seam type
• Minimum yield strength
• Charpy v-notch toughness based on the lowest operational temperatures
• Predicted failure pressure per 192.712

ECA ANALYSIS
• Assessment to determine defects remaining in the pipe including prior pressure test
or in-line inspection
• In-line inspection tools must detect
• Wall loss
• Deformation from dents
• Wrinkle bends
• Ovalities
• Expansion
• Seam defects
• Cracking
• Selective seam weld corrosion
• Longitudinal, circumferential and girth weld cracks
• Hard spots
• Stress corrosion cracking

ECA ANALYSIS
• Operator must use unity plots or equivalent methodologies to validate the
performance of in-line inspection tools with statistical confidence
• Interpretation of results must meet
• 192.710 Assessment outside of HCAs
• 192.712 Analysis of predicted failure pressure
• Corrosion per ASME B31G
• Crack-like defects using technically proven fracture mechanics
• Charpy values if unknown
• No prior crack-like incidents: 13 / 4 foot-pounds for pipe body / seam
• Prior crack-like incidents: 5 / 1 foot-pounds for pipe body / seam
• HCAs: Subpart O

IMPACT
• Need to ensure existing processes include complete, traceable, verifiable, records
• Need to justify predicted failure pressures and pressure sentence plots, etc. used for
crack-like defects
• Potentially need to run material verification tools
• Potentially need to expand usage of EMAT tools
• Need run low field magnetic flux leakage tools for hard spots
• Ensure repair manuals include ovalities and explicit defect interaction rules

SUMMARY
Action
1. Understand final rule and summarize
2. Implement procedures by July 1, 2021
3. Complete MAOP reconfirmations by 2028 and
2035
SuggestedTiming
First quarter 2020
Plan to complete 2020
Plan to include within budget cycle

WHAT’S INTHE NEXT FINAL RULE(S)?
• Repair criteria for both HCA and non-HCA areas
• Extreme weather inspections
• Strengthening assessment requirements
• Corrosion control
• Management of change
• Remote control valves and automated shutoff valves
• Integrity Management clarifications
• Gathering lines

REVISION: REPAIR CRITERIA
SAME FOR HCA AND NON-HCA

REPAIR CRITERIA – PHMSA IS PROPOSING
• Immediate conditions
• 80% metal loss
• Corrosion near seam
• Selective Seam Corrosion (SSWC)/Significant SCC
• Scheduled conditions (HCAs within 1 year, Non-HCAs within 2 years)
• Areas of general corrosion > 50% wall thickness
• Metal loss calculation that shows a FPR : ≤ less than or equal to 1.25 for Class 1 locations, ≤ 1.39 for
Class 2 locations, ≤ 1.67 for Class 3 locations, and ≤ 2.00 for Class 4 locations.
• Additional dent criteria
• All other SCC and crack-like defects

REPAIR CRITERIA – GPAC COMMENTS
Allowing (but not require) engineering critical analysis (ECA) for the following dent-
related repair criteria (HCA and non-HCA):
• Dent with indication of metal loss, cracking, or stress riser
• Smooth topside dent > 6% diameter (or 0.50 in. deep for D<NPS12)
• Dent > 2% diameter (or >0.25 in. deep for D<NPS12) that affects pipe curvature at a girth weld or seam
weld
• Dents analyzed by ECA, but shown to not exceed critical strain levels would be Monitored Conditions;
PHMSA will consider language to accommodate alternative ECA methods such as FEA
ASME B31.8 paragraph 851 Critical Strains
• Dents in pipe body with strain >6%
• Dent over 2% OD on ductile seams or girth welds with strain >4% for dents

REPAIR CRITERIA – GPAC COMMENTS
Revise the immediate condition for dent anomalies with indications of metal loss,
cracking, or stress risers in non-HCAs as follows:
• Immediate Conditions –Topside dents that exceed critical strain levels
• 2-year Scheduled Conditions – Bottom-side dents that exceed critical strain levels
• Monitored Conditions – Dents that do not exceed critical strain levels are monitored
ASME B31.8 paragraph 851 Critical Strains
• Dents in pipe body with strain >6%
• Dent over 2% OD on ductile seams or girth welds with strain >4% for dents

REVISION: CORROSION CONTROL
192 SUBPART I

CORROSION CONTROL – PHMSA IS PROPOSING
• 192.319 Installation of Pipe in a Ditch
Perform coating survey within 3 months of installation of new pipe and repair within 6 months
• 192.461 External Corrosion Control: Protective coating
Perform coating survey within 6 months of pipe replacements 1000’ or more and repair within 6
months
• 192.465 External Corrosion Control: Monitoring and Remediation
For any annual pipe-to-soils readings not meeting criteria, in addition to prompt remedial action, the
operator must perform a close-interval survey (5’ interval) from the upstream and downstream test
points of the area of concern to verify remediation has been achieved
• 192.473 External Corrosion Control: Interference Currents
The corrosion control program shall include interference surveys for the presence of stray currents
from collocated pipelines and HVAC power lines. Any remedial actions identified must be remediated
within 6 months.

CORROSION CONTROL – GPAC COMMENTS
• 192.319 Installation of Pipe in a Ditch
Perform coating survey within 3 months of installation of new pipe and repair within 6 months
• Raise the repair threshold from “moderate” to “severe” indications
• Modify the applicability of this requirement to segments > 1000’ to be consistent with 192.461
• Lengthen the assessment & remediation timeframe to 6 months after the pipeline is placed in service
(192.319) and provide allowance for delayed permitting
• 192.461 External Corrosion Control: Protective coating
Perform coating survey within 6 months of pipe replacements 1000’ or more and repair within 6 months
• Modify records requirement as follows: “… make and retain for the life of the pipeline records
documenting the coating indirect assessment findings and repairs remedial actions”
• Providing flexibility for technology unless objected to by PHMSA

• 192.465 External Corrosion Control: Monitoring and Remediation
For any annual pipe-to-soils readings not meeting criteria, in addition to prompt remedial action, the
operator must perform a close-interval survey (5’ interval) from the upstream and downstream test
points of the area of concern to verify remediation has been achieved
• Clarify that the new requirements in paragraph 192.465(d) only apply to gas transmission pipelines
• Address comments on timeframe to require a remedial action plan and apply for any necessary
permits within 6 months and complete remedial action within 1 calendar year, not to exceed 15
months, or as soon as practicable after obtaining necessary permits
• Address situations where CIS may not be an effective response to require that operators investigate
and mitigate any non-systemic or location-specific causes, and that close interval surveys would only
be required to address systemic causes.

• 192.473 External Corrosion Control: Interference Currents
The corrosion control program shall include interference surveys for the presence of stray currents from
collocated pipelines and HVAC power lines. Any remedial actions identified must be remediated within 6
months.
• Clarify that surveys are only required for lines subject to stray currents
• Clarify that remedial action is required when the interference is at a level that could cause significant
corrosion (defined as 100 amps per meter squared, or if it impedes the safe operating pressure of a
pipeline, or that may cause a condition that would adversely affect the environment or the public)
• Update the timeframe for remediation to require a remediation procedure and application for
necessary permits within 6 months and complete remediation within 12 months, with allowance for
delayed permitting

IMPACT
• Revise construction procedures and/or standards to include assessment and remediation
of coating damage during construction
• Revise operating procedures to perform follow-up CIS when criteria is not met in certain
cases
• Revise operating procedures to assess and monitor for stray currents for co-locations with
HVAC power lines
• Records to demonstrate compliance
• Timing?

MORE INFORMATION
Agency/Docket Number: PHMSA-2011-0023
https://www.federalregister.gov/documents/2019/10/01/2019-20306/pipeline-safety-safety-of-gas-
transmission-pipelines-maop-reconfirmation-expansion-of-assessment
Gas PipelineAdvisory Committee (GPAC)
https://www.phmsa.dot.gov/standards-rulemaking/pipeline/pipeline-advisory-committees

THANKYOU
Gary Krichau
Director of Corrosion and Pipeline Integrity
402-398-7274 office
Gary.Krichau@nngco.com

New Rulemakings: What Can We Expect - Gary Krichau

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