PHMSA MEGA Rule

July 1, 2020
• Operators must prepare and follow procedures (per §§ 192.13(c) and 192.605) addressing
applicable regulations without timeframes explicitly defined in the Final Rule (§§ 191.23,
191.25, 192.3, 192.5, 192.7, 192.9, 192.18, 192.67, 192.127, 192.150, 192.205, 192.493,
192.506, 192.517, 192.607 (if material verification is being used per § 192.712), 192.619,
192.632, 192.710, 192.712, 192.805, 192.909, 192.917, 192.921, 192.933, 192.935,
192.937, 192.939, 192.949 (removed and replaced with 192.18), and Appendix F to Part
192.
• Operators must begin to identify, schedule (according to a risk-based prioritization), and
perform assessments required by § 192.710 (see FAQ-12 regarding MCA identification).

July 1, 2021
• Operators must begin retaining records for each individual welder qualification at the
time of construction for a minimum of 5 years following construction, per § 192.227.
• For transmission pipe installed after July 1, 2021, operators must begin retaining records
for each person’s plastic pipe joining qualifications at the time of construction for a
minimum of 5 years following construction, per § 192.285.
• If subject to § 192.624, operators must develop and document procedures for completing
all actions required by this section (see FAQ-12 regarding MCA identification). These
procedures must include:
o A process for reconfirming MAOP for any pipelines that meet a condition of
§ 192.624(a)
o A process for performing a spike test or material verification per §§ 192.506 and
192.607, if applicable
o A process for performing an engineering critical assessment (ECA) for MAOP
reconfirmation per § 192.632, if implemented
• Operators must modify their launchers and receivers that will be used after this date to
meet the conditions of §192.750.
March 15, 2022
• Operators must submit a revised Annual Report (PHMSA F 7100.2-1) that reflect this
rulemaking.
July 3, 2028
• Operators must complete all actions required by § 192.624 on at least 50% of the pipeline
mileage subject to MAOP reconfirmation.
July 3, 2034
• Operators must complete all originally identified assessments required by § 192.710.
July 2, 2035
• Operators must complete all actions required by § 192.624 on 100% of the pipeline
mileage subject to MAOP reconfirmation.

Yes. While the new rule focuses on the safety of onshore gas transmission lines, new
requirements apply to regulated gas gathering lines. Section § 192.9 identifies the safety
requirements applicable to regulated gas gathering lines. Sections §§ 192.9(b), 192.9(c), and
192.9(d) identify code sections that do not apply to gas gathering lines. Operators of regulated
gas gathering lines should review the following code sections, revised in this rulemaking, to see how they apply to their systems: §§ 191.23, 191.25, 192.3, 192.5, 192.7, 192.18, 192.67,
192.127, 192.205, 192.227, 192.517, 192.619(a), 192.619(f), 192.750, and 192.805.

PHMSA described the qualifications of a “subject matter expert” in the Preamble of the Final
Rule at 84 FR 52206: PHMSA expects a qualified subject matter expert to be an individual with
formal or on-the-job technical training in the technical or operational area being analyzed,
evaluated, or assessed. The operator must be able to document that the individual is
appropriately knowledgeable and experienced in the subject being assessed.

The intent of § 192.712 is to require operators to conduct rigorous failure pressure analyses that
are properly documented, for review and evaluation by qualified experts. Subject matter experts
don’t necessarily need to perform the analyses, but they must review and confirm the analyses

Records required by 192.227(c) must be retained for a minimum of five years after the end of
construction. PHMSA considers the end of construction to be prior to an operator placing a gas,
as defined by §§ 192.1(a) and 192.3, into the pipeline, making it an in-service pipeline, and
operating that pipeline. Per § 192.227(c), “construction” activities include the installation of
pipe—be it for new construction, replacement, relocation, or repair. These construction activities
would also include the installation or replacement of components with pipe attached.

Operators can report new data requirements on the revised incident form (Form PHMSA F
7100.2) starting July 1, 2021. However, operators can view this revised form currently on the
docket (PHMSA-2019-0225). Section 191.15 requires each operator of a transmission or a
gathering pipeline system to submit DOT Form PHMSA F 7100.2 as soon as practicable, but not
more than 30 days after detecting an incident required to be reported under § 191.5 of Part 191.
The form has been modified to collect information and data the pipeline operator must obtain as
part of the Final Rule, including a record(s) of the maximum allowable operating pressure
(MAOP) reconfirmation method used for the pipeline segment that experienced the incident, and
whether the incident occurred in a moderate consequence area (MCA). Operators must identify
MCAs to determine if the new requirements under §§ 192.624(a) and 192.710(a) apply to them.

The revised annual report form (Form PHMSA F 7100.2-1) for gas transmission pipelines has
been modified to collect MCA and MAOP reconfirmation information. Operators will be able to
start using the annual report form on July 1, 2021. Operators, however, can view this revised
form currently on the docket (PHMSA-2019-0225). PHMSA will require operators to use the
revised annual report form beginning Calendar Year 2021, due no later than March 15, 2022.
The Final Rule does not require modifications of the annual report for gas distribution; therefore,
that report remains unchanged.

No. The notification guidance in § 192.18(a) and (b) applies to all sections of Part 192. The
sections specifically identified in § 192.18(c) require that the operator provide notification to
PHMSA at least 90 days prior to using other technologies or methodologies. These sections
include as follows: §§ 192.506(b), 192.607(e)(4), 192.607(e)(5), 192.624(c)(2)(iii),
192.624(c)(6), 192.632(b)(3), 192.710(c)(7), 192.712(d)(3)(iv), 192.712(e)(2)(i)(E),
192.921(a)(7), or 192.937(c)(7). Operators are also required to notify PHMSA of changes to
their Operator Qualification and Integrity Management plans per § 192.805(i) and § 192.909 (b),
respectively

No, operators may proceed with using other technologies if they submitted a notification per §
192.18 and PHMSA did not respond within 90 days. After 90 days following notification
submission, an operator does not have to wait for a written approval or a “no objection letter”
from PHMSA to proceed with using “other technology.” An operator seeking a written “no
objection letter” from PHMSA prior to implementing the alternative technology per § 192.18(c)
should include a specific request for the written response in its § 192.18 notification.

To identify applicable roadways, PHMSA expects operators to use all information available
including but not limited to the following: www.thenationalmap.gov, www.fhwa.dot.gov, and
other federal and state highway mapping data; aerial imagery; pipeline patrols and surveys
(ground and aerial); and, pipeline route maps. When identifying an MCA, PHMSA expects
operators to capture the area between the outermost edge of the paved surfaces, including all
medians. Entrance and exit ramps to access-controlled roadways should be included in the MCA
analysis. There is no comprehensive GIS-based source of roadways as defined in the Federal
Highway Administration’s (FHWA) Highway Functional Classification Concepts, Criteria and
Procedures, Section 3.1 (see:
https://www.fhwa.dot.gov/planning/processes/statewide/related/highway_functional_classificatio
ns/fcauab.pdf). However, Section 4 of the FHWA document includes recommendations and
guidance on how to obtain GIS-based roadway inventory data at a state level. PHMSA does not
intend to develop a single source of data for operators to use to determine if an MCA exists on
their pipeline system.

The new rule, which went into effect July 1, 2020, requires operators to develop procedures per §
192.605(b)(1) to determine the location of MCAs on their pipeline system and to incorporate
these procedures into their manual for maintenance and normal operations. Operators must then
implement those procedures to complete the initial identification of MCAs by July 1, 2021 and
record those MCAs in the revised incident and annual reports after this date. (See FAQ-6 and
FAQ-7.)
PHMSA anticipates that some operators will incorporate an MCA identification process into
existing HCA and class identification procedures, while other operators might prepare a separate
procedure for identifying MCAs. MCAs are used to determine a pipeline segment’s applicability
under §§ 192.624 and 192.710.
Operators must begin performing assessments according to a risk-based prioritization schedule
starting July 1, 2020, the effective date of the rule, and complete all assessments no later than
July 3, 2034, per § 192.710(b). Operators must also begin performing MAOP reconfirmations
on July 1, 2021, to complete all actions required by the schedules in § 192.624(b)(1) and (2).
An assessment performed prior to July 1, 2020, the effective date of the rule, that meets the
conditions outlined in § 192.710(b)(3) may be used as an assessment. Operators who use a prior
assessment for a pipeline segment located in an MCA must conduct ongoing reassessments of
that segment within 10 years as per § 192.710(b)(2)—not 14 years as would be the case for an
initial assessment under § 192.710(b)(1).

Yes. Operators must identify, document and track all MCAs—regardless of piggability and
operating stress—for annual and incident report data collection.

PHMSA expects that operators will re-evaluate their MCAs once per calendar year, not to
exceed a period of 15 months, consistent with current HCA and class location change studies
(per §§ 192.905 and 192.609). PHMSA also expects that operators will add any newly identified
MCAs to their § 192.710 assessment schedule within one year of the discovery date. This
expectation is consistent with current Gas IMP FAQ-19, FAQ-20, and FAQ-179, posted on the
PHMSA’s Technical Resources site at https://www.phmsa.dot.gov/pipeline/gas-transmissionintegrity-management/gas-transmission-integrity-management-faqs.

No. A spike test is not required for all pipelines that are hydrotested or re-hydrotested and are
operating at 30% or more of SMYS. The hydrostatic spike pressure testing requirements in
§ 192.506 applies only when conducted as required by §§ 192.710 and 192.921.
A spike test is appropriate and should be considered for time-dependent threats, such as the
following: stress corrosion cracking; selective seam weld corrosion; manufacturing and related
defects, including defective pipe and pipe seams; and, other forms of defect or damage involving
cracks or crack-like defects, such as those listed in §§ 192.710(c)(3), 192.917(e)(6) and
192.937(c)(3).
If an operator decides to spike test a transmission pipeline operated at a hoop stress greater than
30% SMYS, the test must be conducted according to the spike-test procedures listed in §
192.506

Yes. While pipeline operators must verify material properties per § 192.607 where explicitly
referenced in Part 192, PHMSA also allows the voluntary use of § 192.607 (per § 192.619(a)(4)) for material property verification outside of HCAs, MCAs, and Class 3 and Class 4 locations in
order to determine key Subpart C – Pipe Design attributes. Operators of pipeline segments that
do not meet the applicability of § 192.624 may, and in fact are encouraged to, conduct and use
the results of a properly conducted testing program such as those outlined in §192.607 to ensure
the safe operation of the pipeline regardless of location. That said, operators must consider the
newly determined material property results regardless of pipeline location when they analyze
predicted failure pressures for anomalies, develop appropriate repair procedures, conduct
engineering critical assessments, or fulfill other requirements under Part 192.

No. The opportunistic gathering of data on unknown material properties does not need to meet
the MAOP reconfirmation schedule outlined in § 192.624(b), except when the selected MAOP
reconfirmation method requires material properties testing to reconfirm the MAOP. The
timeframe for opportunistic data collection may vary, based on the length of the pipeline, amount
of pipe with missing material properties, number of opportunities, and testing results. (See
§ 192.607 for a complete description.) Also, § 192.712 requires the operator to know the pipe
material properties when conducting the analysis of predicted failure pressure for anomalies or
defect evaluations.

When determining the vintage of two potentially similar pipeline segments (e.g., same diameter,
wall thickness, grade, and seam type), operators must consider the following: If the difference
between either the manufacturing date of the two segments or the construction date of the two
segments is greater than 2 years, the two segments cannot be considered similar and must be
placed in separate populations per the mandate in § 192.607(e)(1). In the first example, the two
pipe segments would be in the same population. In the second example, the operator would not
be able to place the two pipe segments in the same population unless additional records
demonstrate traceability to another population of pipe.

Operators should only split populations based on known attributes and they should have separate
populations of pipe segments where attributes are unknown. Operators that can document pipe
material properties but are missing the manufacturing or construction date attributes would not
need to conduct an expanded sampling program to determine material properties. When material
attributes are unknown, operators must use manufacturing and construction dates noted in
§ 192.607(e)(1) and FAQ-18 to delineate the boundaries of the material properties sampling
program.

Per § 192.607, operators must implement a sampling program for each unique pipe population
group with unknown pipe attributes. Operators can initially group pipe segments with no known
material properties information into a single population. When performing material properties
testing on pipe from the unknown population group, operators must add newly verified samples
into matching pipe populations or create new pipe population groups, as applicable.

Yes. In-line inspection data may be used to delineate various pipe population groups for
subsequent sampling of multiple segments for material property verification. Operators must
define processes they plan to implement the requirements of MAOP reconfirmation and material
verification, and report whether they are using an alternative sampling approach under §
192.607(e)(5). This alternate sampling method must also be reported per § 192.18.

Yes. Depending on the in-line inspection tool capabilities, operators can determine certain
material properties and attributes with the required confidence levels. Any verification of
material properties and attributes using nondestructive methods or inspection tools must meet the
requirements in § 192.607(d).

No process currently exists to compile pipe material property information. Material properties
can vary greatly during the manufacturing process. PHMSA expects operators to verify pipe
material used within their system.

Operators must address each activity listed in § 192.607(c) in their procedures for safely
conducting nondestructive or destructive tests, examinations, and assessments to verify the
material properties. The listed activities include: anomaly direct examinations, in situ
evaluations, repairs, remediations, maintenance, and excavations associated with replacements or
relocations of pipeline segments that are removed from service. Operators’ procedures should
establish specific criteria for identifying when these pipeline exposures are safe “opportunities”
for material verification and identify any criteria that would render an exposure inappropriate for
material verification, such as confined space concerns or unstable excavations. In most cases, an
operator should be able to conduct material properties tests after completing an immediate repair.
PHMSA does not expect operators to perform material properties verification for unknown pipe
properties on pipeline segments exposed during excavation activities per § 192.614 Damage
Prevention Program. However, material verification performed during a one-call excavation
must be performed per §192.607.

After making the area safe, an operator must perform testing to verify pipeline material
properties and attributes per § 192.607 if the pipeline segment experiencing the leak meets
applicability per §§ 192.624 Maximum allowable operating pressure reconfirmation: Onshore
steel transmission pipelines, or per 192.712 Analysis of Predicted Failure Pressure.

Operators must verify diameter, wall thickness, seam type, and grade (e.g., yield strength,
ultimate tensile strength, or pressure rating for valves and flanges, etc.), and Charpy v-notch
toughness values (if needed), if these items are unknown and are necessary for MAOP
reconfirmation (per § 192.624), an engineering critical assessment (per § 192.632), or failure
pressure analysis (per § 192.712), as specified by those regulations.

Other material properties and attributes might be required to be documented (e.g. Subpart I,
Subpart O).

Operators must reduce the operating pressure and MAOP per § 192.619 and may need to
perform MAOP Exceedance reporting per §§ 191.23(a)(10) and 191.25(b).

PHMSA expects operators to define the term “not consistent” in their material verification
procedures as it relates to pipe properties, and to detail how they will establish an expanded
sampling program in response to such information. The regulation requires operators to maintain
material records for line pipe, such as pipe wall thicknesses, grades, and manufacturing process
(seam types). Pipeline material records and class location information are used to determine and
support the pipeline MAOP. Any operator who discovers pipe properties that differ from those
used to determine the pipeline’s MAOP should consider such properties to be “not consistent”
with available information or assumptions for operations and maintenance. The operator
material sampling programs must be modified to comply with the requirements of §
192.607(e)(4).

Yes. Operators may take advantage of all pipeline excavations and exposures to collect material
properties regardless of pipeline location. If operators plan to use material and attribute
information collected from pipe segments outside of HCA, MCA, and Class 3 and 4 areas to
fulfill the requirements of §§ 192.624 and 192.712, they must adopt and follow procedures for
implementing § 192.607(e) in those areas as well. Any acquired material properties and attribute
data will aid the operators’ efforts to safely conduct MAOP reconfirmation, pipeline
assessments, anomaly evaluations, analysis of failure pressure, and repairs for all pipeline
segment irrespective of Class Location or HCA/MCA designation.

If the sampling procedures mandated by § 192.607(e) are used outside of HCA, MCA, or Class 3
or 4 areas, the operator must also include procedures to delineate the geographic limits of the
sampled segments and how that pipe material and attribute information will be applied to meet
the additional regulatory requirements for HCA, MCA, and Class 3 and 4 areas.

The Preamble of the rule at 84 FR 52218, excerpted below, states PHMSA’s expectations
relative to “TVC” records.

Traceable records are those which can be clearly linked to original information about a pipeline
segment or facility. Traceable records might include pipe mill records, which include
mechanical and chemical properties; purchase requisition; or as-built documentation indicating
minimum pipe yield strength, seam type, wall thickness and diameter. Careful attention should
be given to records transcribed from original documents as they may contain errors. Information
from a transcribed document, in many cases, should be verified with complementary or
supporting documents.

Verifiable records are those in which information is confirmed by other complementary, but
separate, documentation. Verifiable records might include contract specifications for a pressure
test of a pipeline segment complemented by pressure charts or field logs. Another example might
include a purchase order to a pipe mill with pipe specifications verified by a metallurgical test of
a coupon pulled from the same pipeline segment. In general, the only acceptable use of an
affidavit would be as a complementary document, prepared and signed at the time of the test or
inspection by a qualified individual who observed the test or inspection being performed.

Complete records are those in which the record is finalized as evidenced by a signature, date or
other appropriate marking such as a corporate stamp or seal. For example, a complete pressure
testing record should identify a specific segment of pipe, who conducted the test, the duration of
the test, the test medium, temperatures, accurate pressure readings, and elevation information as
applicable. An incomplete record might reflect that the pressure test was initiated, failed and
restarted without conclusive indication of a successful test. A record that cannot be specifically
linked to an individual pipeline segment is not a complete record for that segment. Incomplete or
partial records are not an adequate basis for establishing MAOP or MOP. If records are
unknown or unknowable, a more conservative approach is indicated.

For example, a mill test report must be traceable, verifiable, and complete, which is a typical
record for pipelines. For the mill test report to be traceable it would need to be dated in the
same time frame as construction or have some other link relating the mill record to the material
installed in the pipeline, such as a work order or project identification. For the mill test report
to be verified, it would need to be confirmed by the purchase or project specification for the
pipeline or the alignment sheet with consistent information. Such an example would be verified
by independent records. For the mill test report to be complete, it must be signed, stamped, or
otherwise authenticated as a genuine and true record of the material by the source of the record
or information, in this example it could be the pipe mill, supplier, or testing lab.

Another common record is a pressure test record, which must be traceable, verifiable, and
complete. For the pressure test record to be traceable, it would need to identify a specific and
unique segment of pipe that was tested (such as mileposts, survey stations, etc.) or have some
other link relating the pressure test to the physical location of the test segment, such as a work
order, project identification, or alignment sheet. For the pressure test record to be verified, it
would need to be confirmed by the purchase or project specification for the pipeline or the
alignment sheet with consistent information. Such an example would be verified by independent
records. For the pressure test record to be complete, it should identify a specific segment of
pipe, who conducted the test, the duration of the test, the test medium, temperatures, accurate
pressure readings, elevation information, and any other information required by § 192.517, as

applicable. An incomplete record might reflect that the pressure test was initiated, failed and
restarted without conclusive indication of a successful test.

If operators do not have traceable, verifiable and complete records to establish MAOP for
segments listed in § 192.624(a), they must reconfirm the segments’ MAOP. Therefore, operators
should review all existing records, particularly those reflecting pipe replacements, relocations,
repairs, or other changes to verify that those modifications have been integrated into their MAOP
records. Operators, for example, should compare records of historical repairs, leaks, ruptures,
incidents, and in-line inspection data (wall thickness, coating, seam type, joint length, fittings,
etc.) against their MAOP records. If the records are incomplete or otherwise inadequate, the
operator must reconfirm MAOP for those segments.

PHMSA requires operators of onshore gas transmission pipelines that do not meet the
applicability criteria of § 192.624(a) to comply with the other MAOP and design requirements of
Part 192, such as § § 192.603(b), 192.605,192.609, 192.611, 192.619, 192.620, 192.195,
192.201, and 192.739. These code sections all require knowledge of a documented MAOP and
the materials of which the pipeline is constructed. Operators who do not have proper records
should follow the sections of Part 192 that address pressure testing and/or materials confirmation
based on the type of documents that are not available.

Yes. An operator performing a pressure reduction based on “Method 2” of § 192.624(c)(2) is
reconfirming the pipeline’s MAOP by creating a safety margin by which the pipeline is
operating. The pressure reduction creates and establishes a new MAOP. The recordkeeping
requirements of § 192.619(f) will apply to the MAOP reconfirmation records that document the
pressure reduction (i.e., 5-year operating pressures, application of reduction factors, etc.). Note,
however, that operators who need traceable, verifiable, and complete records of material
properties and attributes to comply with elements of §§ 192.624, 192.632, or 192.712 (for
anomaly repairs, an Engineering Critical Assessment, use of another MAOP reconfirmation
method, or the calculation of predicted failure pressures, for example) would still need to obtain
those records per the opportunistic method described in § 192.607.

This statement means the 8-hour period does not need to be continuous; it can be made up of
shorter periods that over the course of 30-days amount to at least 8 hours above a certain
pressure. Per §§ 192.624(c)(2) and (c)(5)(i), the value used as the highest actual sustained
operating pressure must account for differences between upstream and downstream pressure on
the pipeline by use of either the lowest maximum pressure value for the entire pipeline segment
or using the operating pressure gradient along the entire pipeline segment (i.e., the locationspecific operating pressure at each location) that is protected from over-pressuring (see
§§ 192.199 and 192.201).

When a change in class location occurs on a pipeline segment, operators must confirm or revise
the MAOP for that segment within 24 months from the date the classification changed, per §§
192.609 and 192.611, not in accordance with MAOP reconfirmation requirements established in
§ 192.624(b)(2). When an HCA or MCA on a pipeline segment is added or changed, that area
will need to comply with § 192.624(a). If this occurs, the operator must reconfirm the MAOP
per § 192.624(b)(2). Operators must ensure that the MAOP records for these new segments are
traceable, verifiable, and complete.

No. The MAOP of the legacy pipeline segment (+72% SMYS) must still be revised per
§§ 192.611(a)(1)(i), 192.611(a)(2), 192.611(a)(3), and 192.619(a), as applicable for the Class
location change and the in-service pipeline. To meet these requirements, the operator must use
material properties per § 192.105 (or acquire them per § 192.607), and have a hydrotest
performed per § 192.619(a)(2). A legacy pipeline with an MAOP above 72% SMYS cannot
have a class location change, such as from a Class 1 to a Class 2 location, without either
lowering the MAOP to at or below 72% SMYS or replacing the pipe with materials suitable for a
Class 2 or Class 3 location design factor and pressure test. However, if the pipeline is operating
at a corresponding hoop stress (at or below 72% SMYS) that is commensurate with the present
class location, the existing legacy MAOP can be maintained, assuming the legacy MAOP is
documented (per §§ 192.603(b) and 192.605(b)(3)) and material properties, pipe design and pipe
component records are traceable, verifiable, and complete

Yes. Line pipe and non-line pipe within compressor, meter, and pressure-limiting stations,
including bypasses (up to the station emergency shutdown or isolation valves), are subject to §
192.624 and must be incorporated into the operator’s MAOP reconfirmation program. PHMSA
expects the operator to examine or assess the pressure rating for all above-ground components.
For buried components, PHMSA expects operators to implement a sampling program similar to
that required for line pipe per § 192.607(e). Under § 192.607(f), testing of components for
chemical and mechanical properties is not required.

No. However, the destruction or loss of such records would prevent the pipeline from operating
in the future under Parts 192 or 195 (see conversion of service requirements under §§ 192.14 and
195.5).

It depends on the circumstances:

For Non-HCAs Pipeline Segments: Operators must follow § 192.503 general requirements,
including test medium, when conducting future pressure tests in non-HCA segments. If the nonHCA segment requires a spike hydrostatic pressure test the threat, the operator must follow
192.710(c)(3) and 192.506.

For HCAs Pipeline segments subject to Subpart O: Operators must follow § 192.917(e)(3)
requirements to address manufacturing and construction defects. After July 1, 2020, operators
must conduct a hydrostatic pressure test to at least 1.25 of the MAOP to comply with §
192.917(e)(3).

If prior pressure tests (before July 1, 2020) utilized a medium other than water to address
manufacturing or construction threats, the operator may continue to rely on those prior tests to
demonstrate stability of manufacturing or construction defects under § 192.917(e)(3) if none of
the specified events listed in 192.917(e)(3)(i through iii) have occurred. If these events have
occurred after the prior pressure test, the HCA pipeline segment must be re-pressure tested using
water.

Failure or fracture mechanics models that may be used are listed in the Preamble of this final rule
at 84 FR 52236. All failure models used for the engineering critical assessment (ECA) analysis
must be used within each model’s technical parameters for the defect type and the pipe or weld
material properties. An operator that wants to use a method which is not listed must use a
technically proven fracture mechanics model appropriate to the failure mode (ductile, brittle or
both), material properties (pipe and weld properties), and boundary condition used (pressure test,
ILI).

Examples of technically proven models for calculating predicted failure pressures include the
following:
• For the brittle failure mode, the Newman-Raju Model1 and PipeAssess PI™ software;2
and
• For the ductile failure mode, Modified Log-Secant Model,3 API RP 579-14 – Level II or
Level III, CorLas™ software,5 PAFFC Model,6 and PipeAssess PI™ software.

Following an ECA using an appropriate fracture mechanics model, an operator must remediate
crack-like anomalies per §§ 192.632, 192.712(d) through (g), and 192.713.

Yes. An operator must obtain Charpy v-notch values if these are needed and are unknown.
Section 192.712(e)(2) provides that “the analyses performed in accordance with this section must
utilize pipe and material properties that are documented in traceable, verifiable, and complete
records.” If documented data required for any analysis is not available, an operator must obtain

1 Newman, J.C., and Raju; “Stress Intensity Factors for Cracks in Three Dimensional Finite Bodies Subjected to
Tension and Bending Loads;” Computational Methods in the Mechanics of Fracture; Elsevier; 1986; pp. 311-334.
2 Interim Report for Phase II – Task 5 of the Comprehensive Study to Understand Longitudinal ERW Seam Failures,
“Summary Report for an Integrity Management Software Tool,” May 2017.
https://primis.phmsa.dot.gov/matrix/FilGet.rdm?fil=11469.
3 ASTM International, ASTM STP 536, “Failure Stress Levels of Flaws in Pressurized Cylinders,” 1973.
4 American Petroleum Institute and American Society of Mechanical Engineers, API 579-1/ASME FFS-1, “FitnessFor-Service,” Second Edition, June 2007.
5 NACE International, NACE Corrosion 96 Paper 255, “Effect of Stress Corrosion Cracking on Integrity and
Remaining Life of Natural Gas Pipelines,” March 1996.
6 Pipeline Research Council International, Inc., Topical Report NG-18 No. 193, “Development and Validation of a
Ductile Flaw Growth Analysis for Gas Transmission Line Pipe,” June 1991.

the undocumented data through § 192.607. Until documented material properties are available,
the operator must use conservative assumptions as defined in §§ 192.712(d) and (e).

Each segment of pipeline that becomes unsafe must be replaced, repaired, or removed from
service per § 192.703(b) and (c). Operators must take remedial measures for anomalies in
MCAs per § 192.710(f), which in turn reference the applicable remediation sections of
§§ 192.485, 192.711, and 192.713. Response timeframes for MCAs will be included in “Safety
of Gas Transmission Pipelines: Repair Criteria, Integrity Management Improvements, Cathodic
Protection, Management of Change, and Other Related Amendments (PHMSA-2011-0023) Final
Rule.”

Section § 192.710(b)(2) states that periodic assessments must be performed “at least once every
10 years, with intervals not to exceed 126 months.” PHMSA intends the maximum reassessment
interval by an allowable reassessment method to be 10 calendar years. This is consistent with
the Subpart O reassessment interval per § 192.939.

A pipeline segment containing HCAs must be reassessed at least once every seven calendar years
per § 192.939. If that same pipeline segment also contains MCAs, those areas must be
reassessed at least once every 10 calendar years per § 192.710(b)(2). (See FAQ-43.) If operators
elect to reduce the reassessment interval for the MCAs to coincide with the shorter reassessment
interval required by adjacent HCAs in that same pipeline segment, PHMSA expects their plans,
procedures and records to reflect that decision. If an ILI assessment is used for a pipeline which
contains both MCAs and HCAs, then the schedule for evaluation of an MCA coincides with the
HCA assessment interval (7 years).