pipeline from the outermost edge of the first potential impact circle
that contains either an occupied site, five (5) or more buildings
intended for human occupancy, or a right-of-way for a designated
interstate, freeway, expressway, or other principal 4-lane arterial
roadway, to the outermost edge of the last contiguous potential impact
circle that contains either an occupied site, five (5) or more
buildings intended for human occupancy, or a right-of-way for a
designated interstate, freeway, expressway, or other principal 4-lane
arterial roadway.
    Modern pipe means any steel pipe that it is not legacy pipe,
regardless of the date of manufacture, and has a longitudinal joint
factor of 1.0 as defined in Sec.  192.113. Modern pipe refers to all
pipe that is not legacy pipe.
* * * * *
    Occupied site means each of the following areas:
    (1) An outside area or open structure that is occupied by five (5)
or more persons on at least 50 days in any twelve (12)-month period.
(The days need not be consecutive.) Examples include but are not
limited to, beaches, playgrounds, recreational facilities, camping
grounds, outdoor theaters, stadiums, recreational areas near a body of
water, or areas outside a rural building such as a religious facility;
or
    (2) A building that is occupied by five (5) or more persons on at
least five (5) days a week for ten (10) weeks in any twelve (12)-month
period. (The days and weeks need not be consecutive.) Examples include,
but are not limited to, religious facilities, office buildings,
community centers, general stores, 4-H facilities, or roller skating
rinks.
* * * * *
    Onshore production facility or onshore production operation means
wellbores, equipment, piping, and associated appurtenances confined to
the physical acts of extraction or recovery of gas from the earth and
the initial preparation for transportation. Preparation for
transportation does not necessarily mean the gas will meet ``pipeline
quality'' specifications as may be commonly understood or contained in
many contractual agreements. Piping as used in this definition may
include individual well flow lines, equipment piping, and transfer
lines between production operation equipment components. Production
facilities terminate at the furthermost downstream point where:
Measurement for the purposes of calculating minerals severance occurs;
or there is commingling of the flow stream from two or more wells.
* * * * *
    Significant seam cracking means cracks or crack-like flaws in the
longitudinal seam or heat affected zone of a seam weld where the
deepest crack is greater than or equal to 10% of wall thickness or the
total interacting length of the cracks is equal to or greater than 75%
of the critical length of a 50% through-wall flaw that would fail at a
failure pressure less than or equal to 110% of SMYS, as determined in
accordance with fracture mechanics failure pressure evaluation methods
(Sec. Sec.  192.624(c) and (d)) for the failure mode using conservative
Charpy energy values of the crack-related conditions.
    Significant stress corrosion cracking means a stress corrosion
cracking (SCC) cluster in which the deepest crack, in a series of
interacting cracks, is greater than 10% of the wall thickness and the
total interacting length of the cracks is equal to or greater than 75%
of the critical length of a 50% through-wall flaw that would fail at a
stress level of 110% of SMYS.
* * * * *
    Transmission line means a pipeline, other than a gathering line,
that: transports gas from a gathering line or storage facility to a
distribution center, storage facility, or large volume customer that is
not down-stream from a distribution center; has an MAOP of 20 percent
or more of SMYS; or transports gas within a storage field.
    Note: A large volume customer (factories, power plants, and
institutional users of gas) may receive similar volumes of gas as a
distribution center.
* * * * *
    Wrinkle bend. (1) Means a bend in the pipe that was formed in the
field during construction such that the inside radius of the bend has
one or more ripples with:
    (i) An amplitude greater than or equal to 1.5 times the wall
thickness of the pipe, measured from peak to valley of the ripple; or
    (ii) With ripples less than 1.5 times the wall thickness of the
pipe and with a wrinkle length (peak to peak) to wrinkle height (peak
to valley) ratio under 12.
[GRAPHIC] [TIFF OMITTED] TP08AP16.000

D = The outside diameter of the pipe, in. (mm),
h = The crest-to-trough height of the ripple, in. (mm), and
S = The maximum operating hoop stress, psi (S/145, MPa).

0
7. In Sec.  192.5, paragraph (d) is added to read as follows:

Sec.  192.5  Class locations.

* * * * *
    (d) Records for transmission pipelines documenting class locations
and demonstrating how an operator determined class locations in
accordance with this section must be retained for the life of the
pipeline.
0
8. Amend Sec.  192.7 by removing and reserving paragraph (b)(4) and
adding paragraphs (b)(10), (g)(2) through (4), (k), and (l).
    The additions read as follows:

Sec.  192.7  What documents are incorporated by reference partly or
wholly in this part?

* * * * *
    (b) * * *
    (10) API STD 1163-2005, ``In-Line Inspection Systems Qualification
Standard,'' 1st edition, August 2001, (API STD 1163), IBR approved for
Sec.  192.493.
* * * * *
    (g) * * *
    (2) NACE Standard Practice 0102-2010, ``Inline Inspection of
Pipelines,'' Revised 2010, (NACE SP0102), IBR approved for Sec. Sec.
192.150(a) and 192.493.
    (3) NACE Standard Practice 0204-2008, ``Stress Corrosion Cracking
Direct Assessment,'' Revised 2008, (NACE SP0204), Reaffirmed 2008, IBR
approved for Sec. Sec.  192.923(b)(3) and 192.929.
    (4) NACE Standard Practice 0206-2006, ``International Corrosion
Direct Assessment Methodology for Pipelines Carrying Normally Dry
Natural Gas,'' (NACE SP0206-2006), IBR approved for Sec. Sec.
192.923(b)(2), 192.927(b), and 192.927(c).
* * * * *
    (k) American Society for Nondestructive Testing (ASNT), P.O. Box
28518, 1711 Arlingate Lane, Columbus, OH 43228, phone<PHONE_NUMBER>,
https://www.asnt.org/.
    (1) ANSI/ASNT ILI-PQ-2010, ``In-line Inspection Personnel
Qualification and Certification,'' 2010, (ANSI/ASNT ILI-PQ-2010), IBR
approved for Sec.  192.493.
    (2) [Reserved]
    (l) Battelle Memorial Institute, 505 King Avenue, Columbus, OH
43201, phone<PHONE_NUMBER>, http://www.battelle.org/.
    (1) Battelle's Experience with ERW and Flash Welding Seam Failures:
Causes and Implications (Task 1.4), IBR approved for Sec.  192.624(c)
and (d).
    (2) Battelle Memorial Institute, ``Models for Predicting Failure
Stress Levels for Defects Affecting ERW and Flash-Welded Seams''
(Subtask 2.4), IBR approved for Sec.  192.624(c) and (d).
    (3) Battelle Final Report No. 13-021, ``Predicting Times to
Failures for ERW Seam Defects that Grow by Pressure Cycle Induced
Fatigue (Subtask 2.5), IBR approved for Sec.  192.624(c) and (d).
    (4) Battelle Memorial Institute, ``Final Summary Report and
recommendations for the Comprehensive Study to Understand Longitudinal
ERW Seam Failures--Phase 1'' (Task 4.5), IBR approved for Sec.
192.624(c) and (d).
0
9. Section 192.8 is revised to read as follows:

Sec.  192.8  How are onshore gathering lines and regulated onshore
gathering lines determined?

    (a) Each operator must determine and maintain records documenting
the beginning and endpoints of each gathering line it operates using
the definitions of onshore production facility (or onshore production
operation), gas processing facility, gas treatment facility, and
onshore gathering line as defined in Sec.  192.3 by [date 6 months
after effective date of the final rule] or before the pipeline is
placed into operation, whichever is later.
    (b) Each operator must determine and maintain records documenting
the beginning and endpoints of each regulated onshore gathering line it
operates as determined in Sec.  192.8(c) by [date 6 months after
effective date of the final rule] or before the pipeline is placed into
operation, whichever is later.
    (c) For purposes of part 191 of this chapter and Sec.  192.9,
``regulated onshore gathering line'' means:
    (1) Each onshore gathering line (or segment of onshore gathering
line) with a feature described in the second column that lies in an
area described in the third column; and
    (2) As applicable, additional lengths of line described in the
fourth column to provide a safety buffer:

----------------------------------------------------------------------------------------------------------------
                Type                           Feature                    Area                Safety buffer
----------------------------------------------------------------------------------------------------------------
A...................................  --Metallic and the MAOP   Area 1. Class 2, 3, or   None.
                                       produces a hoop stress    4 location (see Sec.
                                       of less than 20 percent   192.5).
                                       of SMYS. If the stress   Area 2. Class 1
                                       level is unknown, an      location with a
                                       operator must determine   nominal diameter of 8
                                       the stress level          inches or greater.
                                       according to the
                                       applicable provisions
                                       in subpart C of this
                                       part.
                                      --Non-metallic and the
                                       MAOP is more than 125
                                       psig (862 kPa).
B...................................  --Non-metallic and the    Area 1. Class 3, or 4    If the gathering line
                                       MAOP produces a hoop      location.                is in Area 2(b) or
                                       stress of less than 20   Area 2. An area within    2(c), the additional
                                       percent of SMYS. If the   a Class 2 location the   lengths of line extend
                                       stress level is           operator determines by   upstream and
                                       unknown, an operator      using any of the         downstream from the
                                       must determine the        following three          area to a point where
                                       stress level according    methods:.                the line is at least
                                       to the applicable        (a) A Class 2 location;   150 feet (45.7 m) from
                                       provisions in subpart C  (b) An area extending     the nearest dwelling
                                       of this part.             150 feet (45.7 m) on     in the area. However,
                                      --Non-metallic and thew    each side of the         if a cluster of
                                       MAOP is 125 psig (862     centerline of any        dwellings in Area 2(b)
                                       kPa) or less.             continuous 1 mile (1.6   or 2(c) qualifies a
                                                                 km) of pipeline and      line as Type B, the
                                                                 including more than 10   Type B classification
                                                                 but fewer than 46        ends 150 feet (45.7 m)
                                                                 dwellings; or.           from the nearest
                                                                (c) An area extending     dwelling in the
                                                                 150 feet (45.7 m) on     cluster.
                                                                 each side of the
                                                                 centerline of any
                                                                 continuous 1000 feet
                                                                 (305 m) of pipeline
                                                                 and including 5 or
                                                                 more dwellings..
----------------------------------------------------------------------------------------------------------------

0
10. In Sec.  192.9, paragraphs (c), (d), and (e) are revised and
paragraph (f) is added to read as follows:

Sec.  192.9  What requirements apply to gathering lines?

* * * * *
    (c) Type A, Area 1 lines. An operator of a Type A, Area 1 regulated
onshore gathering line must comply with the requirements of this part
applicable to transmission lines, except the requirements in Sec. Sec.
192.13, 192.150, 192.319, 192.461(f), 192.465(f), 192.473(c), 192.478,
192.710, 192.713, and in subpart O of this part. However, an operator
of a Type A, Area 1 regulated onshore gathering line in a Class 2
location may demonstrate compliance with subpart N by describing the
processes it uses to determine the qualification of persons performing
operations and maintenance tasks.
    (d) Type A, Area 2 and Type B lines. An operator of a Type A, Area
2 or Type B regulated onshore gathering line must comply with the
following requirements:
    (1) If a line is new, replaced, relocated, or otherwise changed,
the design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines;
    (2) If the pipeline is metallic, control corrosion according to
requirements of subpart I of this part applicable to transmission
lines;
    (3) Carry out a damage prevention program under Sec.  192.614;
    (4) Establish a public education program under Sec.  192.616;
    (5) Establish the MAOP of the line under Sec.  192.619;
    (6) Install and maintain line markers according to the requirements
for transmission lines in Sec.  192.707;
    (7) Conduct leakage surveys in accordance with Sec.  192.706 using
leak detection equipment and promptly repair hazardous leaks that are
discovered in accordance with Sec.  192.703(c); and
    (8) For a Type A, Area 2 regulated onshore gathering line only,
develop procedures, training, notifications, emergency plans and
implement as described in Sec.  192.615.
    (e) If a regulated onshore gathering line existing on [effective
date of the final rule] was not previously subject to this part, an
operator has until [date two years after effective date of the final
rule] to comply with the applicable requirements of this section,
unless the Administrator finds a later deadline is justified in a
particular case.
    (f) If, after [effective date of the final rule], a change in class
location or increase in dwelling density causes an onshore gathering
line to be a regulated onshore gathering line, the operator has one
year for Type A, Area 2 and Type B lines and two years for Type A, Area
1 lines after the line becomes a regulated onshore gathering line to
comply with this section.
0
11. In Sec.  192.13, paragraphs (a) and (b) are revised and paragraphs
(d) and (e) are added to read as follows:

Sec.  192.13  What general requirements apply to pipelines regulated
under this part?

    (a) No person may operate a segment of pipeline listed in the first
column that is readied for service after the date in the second column,
unless:
    (1) The pipeline has been designed, installed, constructed,
initially inspected, and initially tested in accordance with this part;
or
    (2) The pipeline qualifies for use under this part according to the
requirements in Sec.  192.14.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15 2007.
 this part did not apply until April 14,
 2006.
Regulated onshore gathering line to which   [date 1 year after effective
 this part did not apply until [effective    date of the final rule].
 date of the final rule].
All other pipelines.......................  March 12, 1971.
------------------------------------------------------------------------

    (b) No person may operate a segment of pipeline listed in the first
column that is replaced, relocated, or otherwise changed after the date
in the second column, unless the replacement, relocation or change has
been made according to the requirements in this part.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15, 2007.
 this part did not apply until April 14,
 2006.
Regulated onshore gathering line to which   [date 1 year after effective
 this part did not apply until [effective    date of the final rule].
 date of the final rule].
All other pipelines.......................  November 12, 1970.
------------------------------------------------------------------------

* * * * *
    (d) Each operator of an onshore gas transmission pipeline must
evaluate and mitigate, as necessary, risks to the public and
environment as an integral part of managing pipeline design,
construction, operation, maintenance, and integrity, including
management of change. Each operator of an onshore gas transmission
pipeline must develop and follow a management of change process, as
outlined in ASME/ANSI B31.8S, section 11, that addresses technical,
design, physical, environmental, procedural, operational, maintenance,
and organizational changes to the pipeline or processes, whether
permanent or temporary. A management of change process must include the
following: reason for change, authority for approving changes, analysis
of implications, acquisition of required work permits, documentation,
communication of change to affected parties, time limitations, and
qualification of staff.
    (e) Each operator must make and retain records that demonstrate
compliance with this part.
    (1) Operators of transmission pipelines must keep records for the
retention period specified in appendix A to part 192.
    (2) Records must be reliable, traceable, verifiable, and complete.
    (3) For pipeline material manufactured before [effective date of
the final rule] and for which records are not available, each operator
must re-establish pipeline material documentation in accordance with
the requirements of Sec.  192.607.
0
12. Section 192.67 is added to subpart A to read as follows:

Sec.  192.67  Records: Materials.

    Each operator of transmission pipelines must acquire and retain for
the life of the pipeline the original steel pipe manufacturing records
that document tests, inspections, and attributes required by the
manufacturing specification in effect at the time the pipe was
manufactured, including, but not limited to, yield strength, ultimate
tensile strength, and chemical composition of materials for pipe in
accordance with Sec.  192.55.
0
13. Section 192.127 is added to subpart B to read as follows:

Sec.  192.127  Records: Pipe design.

    Each operator of transmission pipelines must make and retain for
the life of the pipeline records documenting pipe design to withstand
anticipated external pressures and loads in accordance with Sec.
192.103 and determination of design pressure for steel pipe in
accordance with Sec.  192.105.
0
14. In Sec.  192.150, paragraph (a) is revised to read as follows:

Sec.  192.150  Passage of internal inspection devices.

    (a) Except as provided in paragraphs (b) and (c) of this section,
each new

transmission line and each replacement of line pipe, valve, fitting, or
other line component in a transmission line must be designed and
constructed to accommodate the passage of instrumented internal
inspection devices, in accordance with the requirements and
recommendations in NACE SP0102-2010, section 7 (incorporated by
reference, see Sec.  192.7).
* * * * *
0
15. Section 192.205 is added to subpart D to read as follows:

Sec.  192.205  Records: Pipeline components.

    Each operator of transmission pipelines must acquire and retain
records documenting the manufacturing standard and pressure rating to
which each valve was manufactured and tested in accordance with this
subpart. Flanges, fittings, branch connections, extruded outlets,
anchor forgings, and other components with material yield strength
grades of 42,000 psi or greater must have records documenting the
manufacturing specification in effect at the time of manufacture,
including, but not limited to, yield strength, ultimate tensile
strength, and chemical composition of materials.
0
16. In Sec.  192.227, paragraph (c) is added to read as follows:

Sec.  192.227  Qualification of welders and welding operators.

* * * * *
    (c) Records for transmission pipelines demonstrating each
individual welder qualification in accordance with this section must be
retained for the life of the pipeline.
0
17. In Sec.  192.285, paragraph (e) is added to read as follows:

Sec.  192.285  Plastic pipe: Qualifying persons to make joints.

* * * * *
    (e) For transmission pipelines, records demonstrating plastic pipe
joining qualifications in accordance with this section must be retained
for the life of the pipeline.
    18. In Sec.  192.319, paragraph (d) is added to read as follows:

Sec.  192.319  Installation of pipe in a ditch.

* * * * *
    (d) Promptly after a ditch for a steel onshore transmission line is
backfilled, but not later than three months after placing the pipeline
in service, the operator must perform an assessment to ensure integrity
of the coating using direct current voltage gradient (DCVG) or
alternating current voltage gradient (ACVG). The operator must repair
any coating damage classified as moderate or severe (voltage drop
greater than 35% for DCVG or 50 dB[mu]v for ACVG) in accordance with
section 4 of NACE SP0502 (incorporated by reference, see Sec.  192.7)
within six months of the assessment. Each operator of transmission
pipelines must make and retain for the life of the pipeline records
documenting the coating assessment findings and repairs.
0
19. In Sec.  192.452, the introductory text of paragraph (b) is revised
to read as follows:

Sec.  192.452  How does this subpart apply to converted pipelines and
regulated onshore gathering lines?

* * * * *
    (b) Regulated onshore gathering lines. For any regulated onshore
gathering line under Sec.  192.9 existing on [effective date of the
final rule], that was not previously subject to this part, and for any
onshore gathering line that becomes a regulated onshore gathering line
under Sec.  192.9 after April 14, 2006, because of a change in class
location or increase in dwelling density:
* * * * *
0
20. In Sec.  192.461, paragraph (a)(4) is revised and paragraph (f) is
added to read as follows:

Sec.  192.461  External corrosion control: Protective coating.

    (a) * * *
    (4) Have sufficient strength to resist damage due to handling
(including but not limited to transportation, installation, boring, and
backfilling) and soil stress; and
* * * * *
    (f) Promptly, but no later than three months after backfill of an
onshore transmission pipeline ditch following repair or replacement (if
the repair or replacement results in 1,000 feet or more of backfill
length along the pipeline), conduct surveys to assess any coating
damage to ensure integrity of the coating using direct current voltage
gradient (DCVG) or alternating current voltage gradient (ACVG).
Remediate any coating damage classified as moderate or severe (voltage
drop greater than 35% for DCVG or 50 dB[mu]v for ACVG) in accordance
with section 4 of NACE SP0502 (incorporated by reference, see Sec.
192.7) within six months of the assessment.
0
21. In Sec.  192.465, the section heading and paragraph (d) are revised
and paragraph (f) is added to read as follows:

Sec.  192.465  External corrosion control: Monitoring and remediation.

* * * * *
    (d) Each operator must promptly correct any deficiencies indicated
by the inspection and testing provided in paragraphs (a), (b) and (c)
of this section. Remedial action must be completed promptly, but no
later than the next monitoring interval in Sec.  192.465 or within one
year, whichever is less.
* * * * *
    (f) For onshore transmission lines, where any annual test station
reading (pipe-to-soil potential measurement) indicates cathodic
protection levels below the required levels in Appendix D of this part,
the operator must determine the extent of the area with inadequate
cathodic protection. Close interval surveys must be conducted in both
directions from the test station with a low cathodic protection (CP)
reading at a minimum of approximately five foot intervals. Close
interval surveys must be conducted, where practical based upon
geographical, technical, or safety reasons. Close interval surveys
required by this part must be completed with the protective current
interrupted unless it is impractical to do so for technical or safety
reasons. Remediation of areas with insufficient cathodic protection
levels or areas where protective current is found to be leaving the
pipeline must be performed in accordance with paragraph (d) of this
section. The operator must confirm restoration of adequate cathodic
protection by close interval survey over the entire area.
0
22. In Sec.  192.473, paragraph (c) is added to read as follows:

Sec.  192.473  External corrosion control: Interference currents.

* * * * *
    (c) For onshore gas transmission pipelines, the program required by
paragraph (a) of this section must include:
    (1) Interference surveys for a pipeline system to detect the
presence and level of any electrical stray current. Interference
surveys must be taken on a periodic basis including, when there are
current flow increases over pipeline segment grounding design, from any
co-located pipelines, structures, or high voltage alternating current
(HVAC) power lines, including from additional generation, a voltage up
rating, additional lines, new or enlarged power substations, new
pipelines or other structures;
    (2) Analysis of the results of the survey to determine the cause of
the interference and whether the level could impact the effectiveness
of cathodic protection; and
    (3) Implementation of remedial actions to protect the pipeline
segment from detrimental interference currents

promptly but no later than six months after completion of the survey.
0
23. Section 192.478 is added to read as follows:

Sec.  192.478  Internal corrosion control: Onshore transmission
monitoring and mitigation.

    (a) For onshore transmission pipelines, each operator must develop
and implement a monitoring and mitigation program to identify
potentially corrosive constituents in the gas being transported and
mitigate the corrosive effects. Potentially corrosive constituents
include but are not limited to: carbon dioxide, hydrogen sulfide,
sulfur, microbes, and free water, either by itself or in combination.
Each operator must evaluate the partial pressure of each corrosive
constituent by itself or in combination to evaluate the effect of the
corrosive constituents on the internal corrosion of the pipe and
implement mitigation measures.
    (b) The monitoring and mitigation program in paragraph (a) of this
section must include:
    (1) At points where gas with potentially corrosive contaminants
enters the pipeline, the use of gas-quality monitoring equipment to
determine the gas stream constituents;
    (2) Product sampling, inhibitor injections, in-line cleaning
pigging, separators or other technology to mitigate the potentially
corrosive gas stream constituents;
    (3) Evaluation twice each calendar year, at intervals not to exceed
7\1/2\ months, of gas stream and liquid quality samples and
implementation of adjustments and mitigative measures to ensure that
potentially corrosive gas stream constituents are effectively monitored
and mitigated.
    (c) If corrosive gas is being transported, coupons or other
suitable means must be used to determine the effectiveness of the steps
taken to minimize internal corrosion. Each coupon or other means of
monitoring internal corrosion must be checked at least twice each
calendar year, at intervals not exceeding 7\1/2\ months.
    (d) Each operator must review its monitoring and mitigation program
at least twice each calendar year, at intervals not to exceed 7\1/2\
months, based on the results of its gas stream sampling and internal
corrosion monitoring in (a) and (b) and implement adjustments in its
monitoring for and mitigation of the potential for internal corrosion
due to the presence of potentially corrosive gas stream constituents.
0
24. In Sec.  192.485, paragraph (c) is revised to read as follows:

Sec.  192.485  Remedial measures: Transmission lines.

* * * * *
    (c) Under paragraphs (a) and (b) of this section, the strength of
pipe based on actual remaining wall thickness may be determined by the
procedure in ASME/ANSI B31G (incorporated by reference, see Sec.
192.7) or the procedure in PRCI PR 3-805 (R-STRENG) (incorporated by
reference, see Sec.  192.7) for corrosion defects. Both procedures
apply to corroded regions that do not penetrate the pipe wall over 80
percent of the wall thickness and are subject to the limitations
prescribed in the procedures, including the appropriate use of class
location and pipe longitudinal seam factors in pressure calculations
for pipe defects. When determining the predicted failure pressure (PFP)
for gouges, scrapes, selective seam weld corrosion, and crack-related
defects, appropriate failure criteria must be used and justification of
the criteria must be documented. Pipe and material properties used in
remaining strength calculations and the pressure calculations made
under this paragraph must be documented in reliable, traceable,
verifiable, and complete records. If such records are not available,
pipe and material properties used in the remaining strength
calculations must be based on properties determined and documented in
accordance with Sec.  192.607.
0
25. Section 192.493 is added to subpart I to read as follows:

Sec.  192.493  In-line inspection of pipelines.

    When conducting in-line inspection of pipelines required by this
part, each operator must comply with the requirements and
recommendations of API STD 1163, In-line Inspection Systems
Qualification Standard; ANSI/ASNT ILI-PQ-2010, In-line Inspection
Personnel Qualification and Certification; and NACE SP0102-2010, In-
line Inspection of Pipelines (incorporated by reference, see Sec.
192.7). Assessments may also be conducted using tethered or remotely
controlled tools, not explicitly discussed in NACE SP0102-2010,
provided they comply with those sections of NACE SP0102-2010 that are
applicable.
0
26. In Sec.  192.503, paragraph (a)(1) is revised to read as follows:

Sec.  192.503  General requirements.

    (a) * * *
    (1) It has been tested in accordance with this subpart and Sec.
192.619, 192.620, or 192.624 to substantiate the maximum allowable
operating pressure; and
* * * * *
0
27. Section 192.506 is added to read as follows:

Sec.  192.506  Transmission lines: Spike hydrostatic pressure test for
existing steel pipe with integrity threats.

    (a) Each segment of an existing steel pipeline that is operated at
a hoop stress level of 30% of specified minimum yield strength or more
and has been found to have integrity threats that cannot be addressed
by other means such as in-line inspection or direct assessment must be
strength tested by a spike hydrostatic pressure test in accordance with
this section to substantiate the proposed maximum allowable operating
pressure.
    (b) The spike hydrostatic pressure test must use water as the test
medium.
    (c) The baseline test pressure without the additional spike test
pressure is the test pressure specified in Sec.  192.619(a)(2),
192.620(a)(2), or 192.624, whichever applies.
    (d) The test must be conducted by maintaining the pressure at or
above the baseline test pressure for at least 8 hours as specified in
Sec.  192.505(e).
    (e) After the test pressure stabilizes at the baseline pressure and
within the first two hours of the 8-hour test interval, the hydrostatic
pressure must be raised (spiked) to a minimum of the lesser of 1.50
times MAOP or 105% SMYS. This spike hydrostatic pressure test must be
held for at least 30 minutes.
    (f) If the integrity threat being addressed by the spike test is of
a time-dependent nature such as a cracking threat, the operator must
establish an appropriate retest interval and conduct periodic retests
at that interval using the same spike test pressure. The appropriate
retest interval and periodic tests for the time-dependent threat must
be determined in accordance with the methodology in Sec.  192.624(d).
    (g) Alternative technology or alternative technical evaluation
process. Operators may use alternative technology or an alternative
technical evaluation process that provides a sound engineering basis
for establishing a spike hydrostatic pressure test or equivalent. If an
operator elects to use alternative technology or an alternative
technical evaluation process, the operator must notify PHMSA at least
180 days in advance of use in accordance with Sec.  192.624(e). The
operator must submit the alternative technical evaluation to the
Associate Administrator of Pipeline Safety with the notification and
must obtain a ``no objection letter'' from the Associate Administrator
of Pipeline Safety prior to usage of alternative technology or an
alternative technical evaluation process.

The notification must include the following details:
    (1) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments;
    (2) Procedures and processes to conduct tests, examinations, and
assessments, perform evaluations, analyze defects and flaws, and
remediate defects discovered;
    (3) Data requirements including original design, maintenance and
operating history, anomaly or flaw characterization;
    (4) Assessment techniques and acceptance criteria;
    (5) Remediation methods for assessment findings;
    (6) Spike hydrostatic pressure test monitoring and acceptance
procedures, if used;
    (7) Procedures for remaining crack growth analysis and pipe segment
life analysis for the time interval for additional assessments, as
required; and
    (8) Evidence of a review of all procedures and assessments by a
subject matter expert(s) in both metallurgy and fracture mechanics.
0
28. In Sec.  192.517, the introductory text of paragraph (a) is revised
to read as follows:

Sec.  192.517  Records.

    (a) Each operator must make, and retain for the useful life of the
pipeline, a record of each test performed under Sec. Sec.  192.505,
192.506, and 192.507. The record must contain at least the following
information:
* * * * *
0
29. In Sec.  192.605, paragraph (b)(5) is revised to read as follows:

Sec.  192.605  Procedural manual for operations, maintenance, and
emergencies.

* * * * *
    (b) * * *
    (5) Operating pipeline controls and systems and operating and
maintaining pressure relieving or pressure limiting devices, including
those for starting up and shutting down any part of the pipeline, so
that the MAOP limit as prescribed by this part cannot be exceeded by
more than the margin (build-up) allowed for operation of pressure
relieving devices or pressure-limiting or control devices as specified
in Sec.  192.201, 192.620(e), 192.731, 192.739, or 192.743, whichever
applies.
* * * * *
0
30. Section 192.607 is added to read as follows:

Sec.  192.607  Verification of pipeline material: Onshore steel
transmission pipelines.

    (a) Applicable locations. Each operator must follow the
requirements of paragraphs (b) through (d) of this section for each
segment of onshore, steel, gas transmission pipeline installed before
[effective date of the final rule] that does not have reliable,
traceable, verifiable, and complete material documentation records for
line pipe, valves, flanges, and components and meets any of the
following conditions:
    (1) The pipeline is located in a High Consequence Area as defined
in Sec.  192.903; or
    (2) The pipeline is located in a class 3 or class 4 location.
    (b) Material documentation plan. Each operator must prepare a
material documentation plan to implement all actions required by this
section by [date 180 days after the effective date of the final rule].
    (c) Material documentation. Each operator must have reliable,
traceable, verifiable, and complete records documenting the following:
    (1) For line pipe and fittings, records must document diameter,
wall thickness, grade (yield strength and ultimate tensile strength),
chemical composition, seam type, coating type, and manufacturing
specification.
    (2) For valves, records must document either the applicable
standards to which the component was manufactured, the manufacturing
rating, or the pressure rating. For valves with pipe weld ends, records
must document the valve material grade and weld end bevel condition to
ensure compatibility with pipe end conditions;
    (3) For flanges, records must document either the applicable
standards to which the component was manufactured, the manufacturing
rating, or the pressure rating, and the material grade and weld end
bevel condition to ensure compatibility with pipe end conditions;
    (4) For components, records must document the applicable standards
to which the component was manufactured to ensure pressure rating
compatibility.
    (d) Verification of material properties. For any material
documentation records for line pipe, valves, flanges, and components
specified in paragraph (c) of this section that are not available, the
operator must take the following actions to determine and verify the
physical characteristics.
    (1) Develop and implement procedures for conducting non-destructive
or destructive tests, examinations, and assessments for line pipe at
all above ground locations.
    (2) Develop and implement procedures for conducting destructive
tests, examinations, and assessments for buried line pipe at all
excavations associated with replacements or relocations of pipe
segments that are removed from service.
    (3) Develop and implement procedures for conducting non-destructive
or destructive tests, examinations, and assessments for buried line
pipe at all excavations associated with anomaly direct examinations, in
situ evaluations, repairs, remediations, maintenance, or any other
reason for which the pipe segment is exposed, except for segments
exposed during excavation activities that are in compliance with Sec.
192.614, until completion of the minimum number of excavations as
follows:
    (i) The operator must define a separate population of undocumented
or inadequately documented pipeline segments for each unique
combination of the following attributes: wall thicknesses (within 10
percent of the smallest wall thickness in the population), grade,
manufacturing process, pipe manufacturing dates (within a two year
interval) and construction dates (within a two year interval).
    (ii) Assessments must be proportionally spaced throughout the
pipeline segment. Each length of the pipeline segment equal to 10
percent of the total length must contain 10 percent of the total number
of required excavations, e.g. a 200 mile population would require 15
excavations for each 20 miles. For each population defined according to
paragraph (d)(3)(i) of this section, the minimum number of excavations
at which line pipe must be tested to verify pipeline material
properties is the lesser of the following:
    (A) 150 excavations; or
    (B) If the segment is less than 150 miles, a number of excavations
equal to the population's pipeline mileage (i.e., one set of properties
per mile), rounded up to the nearest whole number. The mileage for this
calculation is the cumulative mileage of pipeline segments in the
population without reliable, traceable, verifiable, and complete
material documentation.
    (iii) At each excavation, tests for material properties must
determine diameter, wall thickness, yield strength, ultimate tensile
strength, Charpy v-notch toughness (where required for failure pressure
and crack growth analysis), chemical properties, seam type, coating
type, and must test for the presence of stress corrosion cracking, seam
cracking, or selective seam weld corrosion using ultrasonic inspection,
magnetic particle, liquid penetrant, or other appropriate non-
destructive examination techniques. Determination of material property
values must

conservatively account for measurement inaccuracy and uncertainty based
upon comparison with destructive test results using unity charts.
    (iv) If non-destructive tests are performed to determine strength
or chemical composition, the operator must use methods, tools,
procedures, and techniques that have been independently validated by
subject matter experts in metallurgy and fracture mechanics to produce
results that are accurate within 10% of the actual value with 95%
confidence for strength values, within 25% of the actual value with 85%
confidence for carbon percentage and within 20% of the actual value
with 90% confidence for manganese, chromium, molybdenum, and vanadium
percentage for the grade of steel being tested.
    (v) The minimum number of test locations at each excavation or
above-ground location is based on the number of joints of line pipe
exposed, as follows:
    (A) 10 joints or less: one set of tests for each joint.
    (B) 11 to 100 joints: one set of tests for each five joints, but
not less than 10 sets of tests.
    (C) Over 100 joints: one set of tests for each 10 joints, but not
less than 20 sets of tests.
    (vi) For non-destructive tests, at each test location, a set of
material properties tests must be conducted at a minimum of five places
in each circumferential quadrant of the pipe for a minimum total of 20
test readings at each pipe cylinder location.
    (vii) For destructive tests, at each test location, a set of
materials properties tests must be conducted on each circumferential
quadrant of a test pipe cylinder removed from each location, for a
minimum total of four tests at each location.
    (viii) If the results of all tests conducted in accordance with
paragraphs (d)(3)(i) and (ii) of this section verify that material
properties are consistent with all available information for each
population, then no additional excavations are necessary. However, if
the test results identify line pipe with properties that are not
consistent with existing expectations based on all available
information for each population, then the operator must perform tests
at additional excavations. The minimum number of excavations that must
be tested depends on the number of inconsistencies observed between as-
found tests and available operator records, in accordance with the
following table:

------------------------------------------------------------------------
Number of  excavations with  inconsistency
    between test  results and  existing       Minimum number of  total
   expectations  based on all  available      required  excavations for
     information for  each population        population.  The lesser of:
------------------------------------------------------------------------
0.........................................  150 (or pipeline mileage)
1.........................................  225 (or pipeline mileage
                                             times 1.5)
2.........................................  300 (or pipeline mileage
                                             times 2)
>2........................................  350 (or pipeline mileage
                                             times 2.3)
------------------------------------------------------------------------

    (ix) The tests conducted for a single excavation according to the
requirements of paragraphs (d)(3)(iii) through (vii) of this section
count as one sample under the sampling requirements of paragraphs
(d)(3)(i), (ii), and (viii) of this section.
    (4) For mainline pipeline components other than line pipe, the
operator must develop and implement procedures for establishing and
documenting the ANSI rating and material grade (to assure compatibility
with pipe ends).
    (i) Materials in compressor stations, meter stations, regulator
stations, separators, river crossing headers, mainline valve
assemblies, operator piping, or cross-connections with isolation valves
from the mainline pipeline are not required to be tested for chemical
and mechanical properties.
    (ii) Verification of mainline material properties is required for
non-line pipe components, including but not limited to, valves,
flanges, fittings, fabricated assemblies, and other pressure retaining
components appurtenances that are:
    (A) 2-inch nominal diameter and larger; or
    (B) Material grades greater than 42,000 psi (X-42); or
    (C) Appurtenances of any size that are directly installed on the
pipeline and cannot be isolated from mainline pipeline pressures.
    (iii) Procedures for establishing material properties for non-line
pipe components where records are inadequate must be based upon
documented manufacturing specifications. Where specifications are not
known, usage of manufacturer's stamped or tagged material pressure
ratings and material type may be used to establish pressure rating. The
operator must document the basis of the material properties established
using such procedures.
    (5) The material properties determined from the destructive or non-
destructive tests required by this section cannot be used to raise the
original grade or specification of the material, which must be based
upon the applicable standard referenced in Sec.  192.7.
    (6) If conditions make material verification by the above methods
impracticable or if the operator chooses to use ``other technology'' or
``new technology'' (alternative technical evaluation process plan), the
operator must notify PHMSA at least 180 days in advance of use in
accordance with paragraph Sec.  192.624(e) of this section. The
operator must submit the alternative technical evaluation process plan
to the Associate Administrator of Pipeline Safety with the notification
and must obtain a ``no objection letter'' from the Associate
Administrator of Pipeline Safety prior to usage of an alternative
evaluation process.
0
31. In Sec.  192.613, paragraph (c) is added to read as follows:

Sec.  192.613  Continuing surveillance.

* * * * *
    (c) Following an extreme weather event such as a hurricane or
flood, an earthquake, landslide, a natural disaster, or other similar
event that has the likelihood of damage to infrastructure, an operator
must inspect all potentially affected onshore transmission pipeline
facilities to detect conditions that could adversely affect the safe
operation of that pipeline.
    (1) Inspection method. An operator must consider the nature of the
event and the physical characteristics, operating conditions, location,
and prior history of the affected pipeline in determining the
appropriate method for performing the initial inspection to determine
damage and the need for the additional assessments required under the
introductory text of paragraph (c) in this section.
    (2) Time period. The inspection required under the introductory
text of paragraph (c) of this section must commence within 72 hours
after the cessation of the event, defined as the point in time when the
affected area can be safely accessed by the personnel and equipment,
including availability of personnel and equipment, required to perform
the inspection as determined under paragraph (c)(1) of this section,
whichever is sooner.
    (3) Remedial action. An operator must take appropriate remedial
action to ensure the safe operation of a pipeline based on the
information obtained as a result of performing the inspection required
under the introductory text of paragraph (c) in this section. Such

actions might include, but are not limited to:
    (i) Reducing the operating pressure or shutting down the pipeline;
    (ii) Modifying, repairing, or replacing any damaged pipeline
facilities;
    (iii) Preventing, mitigating, or eliminating any unsafe conditions
in the pipeline right-of-way;
    (iv) Performing additional patrols, surveys, tests, or inspections;
    (v) Implementing emergency response activities with Federal, State,
or local personnel; or
    (vi) Notifying affected communities of the steps that can be taken
to ensure public safety.
0
32. In Sec.  192.619, paragraphs (a)(2) through (4) are revised and
paragraphs (e) and (f) are added to read as follows:

Sec.  192.619  Maximum allowable operating pressure: Steel or plastic
pipelines.

    (a) * * *
    (2) The pressure obtained by dividing the pressure to which the
segment was tested after construction as follows:
    (i) For plastic pipe in all locations, the test pressure is divided
by a factor of 1.5.
    (ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more,
the test pressure is divided by a factor determined in accordance with
the following table:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Factors \1\, segment--
                                                     ---------------------------------------------------------------------------------------------------
                                                                                Installed after (Nov.
                   Class location                      Installed before (Nov.    11, 1970) and before       Installed after        Converted under Sec.
                                                             12, 1970)          [effective date of the   [effective date of the           192.14
                                                                                final rule]        final rule minus 1 day]
--------------------------------------------------------------------------------------------------------------------------------------------------------
1...................................................                      1.1                      1.1                     1.25                     1.25
2...................................................                     1.25                     1.25                     1.25                     1.25
3...................................................                      1.4                      1.5                      1.5                      1.5
4...................................................                      1.4                      1.5                      1.5                      1.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ For offshore segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For
  segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters,
  including a pipe riser, the factor is 1.5.

    (3) The highest actual operating pressure to which the segment was
subjected during the 5 years preceding the applicable date in the
second column. This pressure restriction applies unless the segment was
tested according to the requirements in paragraph (a)(2) of this
section after the applicable date in the third column or the segment
was uprated according to the requirements in subpart K of this part:

------------------------------------------------------------------------
       Pipeline segment              Pressure date          Test date
------------------------------------------------------------------------
--Onshore gathering line that   March 15, 2006, or      5 years
 first became subject to this    date line becomes       preceding
 part (other than Sec.           subject to this part,   applicable date
 192.612) after April 13, 2006   whichever is later.     in second
 but before [effective date of                           column.
 the final rule].
--Onshore gathering line that   [date one year after
 first became subject to this    effective date of the
 part (other than Sec.           final rule], or date
 192.612) on or after            line becomes subject
 [effective date of the final    to this part,
 rule].                          whichever is later.
--Onshore transmission line     March 15, 2006, or
 that was a gathering line not   date line becomes
 subject to this part before     subject to this part,
 March 15, 2006.                 whichever is later.
Offshore gathering lines......  July 1, 1976..........  July 1, 1971.
All other pipelines...........  July 1, 1970..........  July 1, 1965.
------------------------------------------------------------------------

    (4) The pressure determined by the operator to be the maximum safe
pressure after considering material records, including material
properties verified in accordance with Sec.  192.607, and the history
of the segment, particularly known corrosion and the actual operating
pressure.
* * * * *
    (e) Notwithstanding the requirements in paragraphs (a) through (d)
of this section, onshore steel transmission pipelines that meet the
criteria specified in Sec.  192.624(a) must establish and document the
maximum allowable operating pressure in accordance with Sec.  192.624
using one or more of the following:
    (1) Method 1: Pressure Test--Pressure test in accordance with Sec.
192.624(c)(1)(i) or spike hydrostatic pressure test in accordance with
Sec.  192.624(c)(1)(ii), as applicable;
    (2) Method 2: Pressure Reduction--Reduction in pipeline maximum
allowable operating pressure in accordance with Sec.  192.624(c)(2);
    (3) Method 3: Engineering Critical Assessment--Engineering
assessment and analysis activities in accordance with Sec.
192.624(c)(3);
    (4) Method 4: Pipe Replacement--Replacement of the pipeline segment
in accordance with Sec.  192.624(c)(4);
    (5) Method 5: Pressure Reduction for Segments with Small PIR and
Diameter--Reduction of maximum allowable operating pressure and other
preventive measures for pipeline segments with small PIRs and
diameters, in accordance with Sec.  192.624(c)(5); or
    (6) Method 6: Alternative Technology--Alternative procedure in
accordance with Sec.  192.624(c)(6).
    (f) Operators must maintain all records necessary to establish and
document the MAOP of each pipeline as long as the pipe or pipeline
remains in service. Records that establish the pipeline MAOP, include,
but are not limited to, design, construction, operation, maintenance,
inspection, testing, material strength, pipe wall thickness, seam type,
and other related data. Records must be reliable, traceable,
verifiable, and complete.
0
33. Section 192.624 is added to read as follows:

Sec.  192.624  Maximum allowable operating pressure verification:
Onshore steel transmission pipelines.

    (a) Applicable locations. The operator of a pipeline segment
meeting any of the following conditions must establish the maximum
allowable operating pressure using one or more of the methods specified
in Sec.  192.624(c)(1) through (6):

    (1) The pipeline segment has experienced a reportable in-service
incident, as defined in Sec.  191.3 of this chapter, since its most
recent successful subpart J pressure test, due to an original
manufacturing-related defect, a construction-, installation-, or
fabrication-related defect, or a cracking-related defect, including,
but not limited to, seam cracking, girth weld cracking, selective seam
weld corrosion, hard spot, or stress corrosion cracking and the
pipeline segment is located in one of the following locations:
    (i) A high consequence area as defined in Sec.  192.903;
    (ii) A class 3 or class 4 location; or
    (iii) A moderate consequence area as defined in Sec.  192.3 if the
pipe segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs'').
    (2) Pressure test records necessary to establish maximum allowable
operating pressure per subpart J for the pipeline segment, including,
but not limited to, records required by Sec.  192.517(a), are not
reliable, traceable, verifiable, and complete and the pipeline is
located in one of the following locations:
    (i) A high consequence area as defined in Sec.  192.903; or
    (ii) A class 3 or class 4 location
    (3) The pipeline segment maximum allowable operating pressure was
established in accordance with Sec.  192.619(c) before [effective date
of the final rule] and is located in one of the following areas:
    (i) A high consequence area as defined in Sec.  192.903;
    (ii) A class 3 or class 4 location; or
    (iii) A moderate consequence area as defined in Sec.  192.3 if the
pipe segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs'').
    (b) Completion date. For pipelines installed before [effective date
of the final rule], all actions required by this section must be
completed according to the following schedule:
    (1) The operator must develop and document a plan for completion of
all actions required by this section by [date 1 year after effective
date of the final rule].
    (2) The operator must complete all actions required by this section
on at least 50% of the mileage of locations that meet the conditions of
Sec.  192.624(a) by [date 8 years after effective date of the final
rule].
    (3) The operator must complete all actions required by this section
on 100% of the mileage of locations that meet the conditions of Sec.
192.624(a) by [date 15 years after effective date of the final rule].
    (4) If operational and environmental constraints limit the operator
from meeting the deadlines in Sec.  192.614(b)(2) and (3), the operator
may petition for an extension of the completion deadlines by up to one
year, upon submittal of a notification to the Associate Administrator
of the Office of Pipeline Safety in accordance with paragraph (e) of
this section. The notification must include an up-to-date plan for
completing all actions in accordance with paragraph (b)(1) of this
section, the reason for the requested extension, current status,
proposed completion date, remediation activities outstanding, and any
needed temporary safety measures to mitigate the impact on safety.
    (c) Maximum allowable operating pressure determination. The
operator of a pipeline segment meeting the criteria in paragraph (a) of
this section must establish its maximum allowable operating pressure
using one of the following methods:
    (1) Method 1: Pressure test.(i) Perform a pressure test in
accordance with Sec.  192.505(c). The maximum allowable operating
pressure will be equal to the test pressure divided by the greater of
either 1.25 or the applicable class location factor in Sec.
192.619(a)(2)(ii) or Sec.  192.620(a)(2)(ii).
    (ii) If the pipeline segment includes legacy pipe or was
constructed using legacy construction techniques or the pipeline has
experienced an incident, as defined by Sec.  191.3 of this chapter,
since its most recent successful subpart J pressure test, due to an
original manufacturing-related defect, a construction-, installation-,
or fabrication-related defect, or a crack or crack-like defect,
including, but not limited to, seam cracking, girth weld cracking,
selective seam weld corrosion, hard spot, or stress corrosion cracking,
then the operator must perform a spike pressure test in accordance with
Sec.  192.506. The maximum allowable operating pressure will be equal
to the test pressure specified in Sec.  192.506(c) divided by the
greater of 1.25 or the applicable class location factor in Sec.
192.619(a)(2)(ii) or Sec.  192.620(a)(2)(ii).
    (iii) If the operator has reason to believe any pipeline segment
may be susceptible to cracks or crack-like defects due to assessment,
leak, failure, or manufacturing vintage histories, or any other
available information about the pipeline, the operator must estimate
the remaining life of the pipeline in accordance with paragraph (d) of
this section.
    (2) Method 2: Pressure reduction. The pipeline maximum allowable
operating pressure will be no greater than the highest actual operating
pressure sustained by the pipeline during the 18 months preceding
[effective date of the final rule] divided by the greater of 1.25 or
the applicable class location factor in Sec.  192.619(a)(2)(ii) or
Sec.  192.620(a)(2)(ii). The highest actual sustained pressure must
have been reached for a minimum cumulative duration of 8 hours during a
continuous 30-day period. The value used as the highest actual
sustained operating pressure must account for differences between
discharge and upstream pressure on the pipeline by use of either the
lowest pressure value for the entire segment or using the operating
pressure gradient (i.e., the location-specific operating pressure at
each location).
    (i) Where the pipeline segment has had a class location change in
accordance with Sec.  192.611 and pipe material and pressure test
records are not available, the operator must reduce the pipeline
segment MAOP as follows:
    (A) For segments where a class location changed from 1 to 2, from 2
to 3, or from 3 to 4, reduce the pipeline maximum allowable operating
pressure to no greater than the highest actual operating pressure
sustained by the pipeline during the 18 months preceding [effective
date of the final rule], divided by 1.39 for class 1 to 2, 1.67 for
class 2 to 3, and 2.00 for class 3 to 4.
    (B) For segments where a class location changed from 1 to 3, reduce
the pipeline maximum allowable operating pressure to no greater than
the highest actual operating pressure sustained by the pipeline during
the 18 months preceding [effective date of the final rule], divided by
2.00.
    (ii) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph (d) of this section.
    (iii) Future uprating of the segment in accordance with subpart K
of this part is allowed if the maximum allowable operating pressure is
established using Method 2 described in paragraph (c)(2) of this
section.
    (iv) If an operator elects to use Method 2 described in paragraph
(c)(2) of this section, but desires to use a less conservative pressure
reduction factor, the operator must notify PHMSA in accordance with
paragraph (e) of this section no later than seven calendar days after
establishing the reduced maximum allowable operating pressure.

The notification must include the following details:
    (A) Descriptions of the operational constraints, special
circumstances, or other factors that preclude, or make it impractical,
to use the pressure reduction factor specified in Sec.  192.624(c)(2);
    (B) The fracture mechanics modeling for failure stress pressures
and cyclic fatigue crack growth analysis that complies with paragraph
(d) of this section;
    (C) Justification that establishing maximum allowable operating
pressure by another method allowed by this section is impractical;
    (D) Justification that the reduced maximum allowable operating
pressure determined by the operator is safe based on analysis of the
condition of the pipeline segment, including material records, material
properties verified in accordance Sec.  192.607, and the history of the
segment, particularly known corrosion and leakage, and the actual
operating pressure, and additional compensatory preventive and
mitigative measures taken or planned.
    (E) Planned duration for operating at the requested maximum
allowable operating pressure, long term remediation measures and
justification of this operating time interval, including fracture
mechanics modeling for failure stress pressures and cyclic fatigue
growth analysis and other validated forms of engineering analysis that
have been reviewed and confirmed by subject matter experts in
metallurgy and fracture mechanics.
    (3) Method 3: Engineering critical assessment. Conduct an
engineering critical assessment and analysis (ECA) to establish the
material condition of the segment and maximum allowable operating
pressure. An ECA is an analytical procedure, based on fracture
mechanics principles, relevant material properties (mechanical and
fracture resistance properties), operating history, operational
environment, in-service degradation, possible failure mechanisms,
initial and final defect sizes, and usage of future operating and
maintenance procedures to determine the maximum tolerable sizes for
imperfections. The ECA must assess: threats; loadings and operational
circumstances relevant to those threats including along the right-of
way; outcomes of the threat assessment; relevant mechanical and
fracture properties; in-service degradation or failure processes;
initial and final defect size relevance. The ECA must quantify the
coupled effects of any defect in the pipeline.
    (i) ECA analysis. (A) The ECA must integrate and analyze the
results of the material documentation program required by Sec.
192.607, if applicable, and the results of all tests, direct
examinations, destructive tests, and assessments performed in
accordance with this section, along with other pertinent information
related to pipeline integrity, including but not limited to close
interval surveys, coating surveys, and interference surveys required by
subpart I of this part, root cause analyses of prior incidents, prior
pressure test leaks and failures, other leaks, pipe inspections, and
prior integrity assessments, including those required by Sec.  192.710
and subpart O of this part.
    (B) The ECA must analyze any cracks or crack-like defects remaining
in the pipe, or that could remain in the pipe, to determine the
predicted failure pressure (PFP) of each defect. The ECA must use the
techniques and procedures in Battelle Final Reports (``Battelle's
Experience with ERW and Flash Weld Seam Failures: Causes and
Implications''--Task 1.4), Report No. 13-002 (``Models for Predicting
Failure Stress Levels for Defects Affecting ERW and Flash-Welded
Seams''--Subtask 2.4), Report No. 13-021 (``Predicting Times to Failure
for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue''--
Subtask 2.5) and (``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--Phase
1''--Task 4.5) (incorporated by reference, see Sec.  192.7) or other
technically proven methods including but not limited to API RP 579-1/
ASME FFS-1, June 5, 2007, (API 579-1, Second Edition)--Level II or
Level III, CorLasTM, or PAFFC. The ECA must use conservative
assumptions for crack dimensions (length and depth) and failure mode
(ductile, brittle, or both) for the microstructure, location, type of
defect, and operating conditions (which includes pressure cycling). If
actual material toughness is not known or not adequately documented by
reliable, traceable, verifiable, and complete records, then the
operator must determine a Charpy v-notch toughness based upon the
material documentation program specified in Sec.  192.607 or use
conservative values for Charpy v-notch toughness as follows: body
toughness of less than or equal to 5.0 ft-lb and seam toughness of less
than or equal to 1 ft-lb.
    (C) The ECA must analyze any metal loss defects not associated with
a dent including corrosion, gouges, scrapes or other metal loss defects
that could remain in the pipe to determine the predicted failure
pressure (PFP). ASME/ANSI B31G (incorporated by reference, see Sec.
192.7) or AGA Pipeline Research Committee Project PR-3-805
(``RSTRENG,'' incorporated by reference, see Sec.  192.7) must be used
for corrosion defects. Both procedures apply to corroded regions that
do not penetrate the pipe wall over 80 percent of the wall thickness
and are subject to the limitations prescribed in the equations
procedures. The ECA must use conservative assumptions for metal loss
dimensions (length, width, and depth). When determining PFP for gouges,
scrapes, selective seam weld corrosion, crack-related defects, or any
defect within a dent, appropriate failure criteria and justification of
the criteria must be used. If SMYS or actual material yield and
ultimate tensile strength is not known or not adequately documented by
reliable, traceable, verifiable, and complete records, then the
operator must assume grade A pipe or determine the material properties
based upon the material documentation program specified in Sec.
192.607.
    (D) The ECA must analyze interacting defects to conservatively
determine the most limiting PFP for interacting defects. Examples
include but are not limited to, cracks in or near locations with
corrosion metal loss, dents with gouges or other metal loss, or cracks
in or near dents or other deformation damage. The ECA must document all
evaluations and any assumptions used in the ECA process.
    (E) The maximum allowable operating pressure must be established at
the lowest PFP for any known or postulated defect, or interacting
defects, remaining in the pipe divided by the greater of 1.25 or the
applicable factor listed in Sec.  192.619(a)(2)(ii) or Sec.
192.620(a)(2)(ii).
    (ii) Use of prior pressure test. If pressure test records as
described in subpart J of this part and Sec.  192.624(c)(1) exist for
the segment, then an in-line inspection program is not required,
provided that the remaining life of the most severe defects that could
have survived the pressure test have been calculated and a re-
assessment interval has been established. The appropriate retest
interval and periodic tests for time-dependent threats must be
determined in accordance with the methodology in Sec.  192.624(d)
Fracture mechanics modeling for failure stress and crack growth
analysis.
    (iii) In-line inspection. If the segment does not have records for
a pressure test in accordance with subpart J of this part and Sec.
192.624(c)(1), the operator must develop and implement an inline
inspection (ILI) program using tools that can detect wall loss,
deformation from

dents, wrinkle bends, ovalities, expansion, seam defects including
cracking and selective seam weld corrosion, longitudinal,
circumferential and girth weld cracks, hard spot cracking, and stress
corrosion cracking. At a minimum, the operator must conduct an
assessment using high resolution magnetic flux leakage (MFL) tool, a
high resolution deformation tool, and either an electromagnetic
acoustic transducer (EMAT) or ultrasonic testing (UT) tool.
    (A) In lieu of the tools specified in paragraph Sec.
192.624(c)(3)(i), an operator may use ``other technology'' if it is
validated by a subject matter expert in metallurgy and fracture
mechanics to produce an equivalent understanding of the condition of
the pipe. If an operator elects to use ``other technology,'' it must
notify the Associate Administrator of Pipeline Safety, at least 180
days prior to use, in accordance with paragraph (e) of this section and
receive a ``no objection letter'' from the Associate Administrator of
Pipeline Safety prior to its usage. The ``other technology''
notification must have:
    (1) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments including characterization of
defect size crack assessments (length, depth, and volumetric); and
    (2) Procedures and processes to conduct tests, examinations, and
assessments, perform evaluations, analyze defects and remediate defects
discovered.
    (B) If the operator has information that indicates a pipeline
includes segments that might be susceptible to hard spots based on
assessment, leak, failure, manufacturing vintage history, or other
information, then the ILI program must include a tool that can detect
hard spots.
    (C) If the pipeline has had a reportable incident, as defined in
Sec.  192.3, attributed to a girth weld failure since its most recent
pressure test, then the ILI program must include a tool that can detect
girth weld defects unless the ECA analysis performed in accordance with
paragraph Sec.  192.624(c)(3)(iii) includes an engineering evaluation
program to analyze the susceptibility of girth weld failure due to
lateral stresses.
    (D) Inline inspection must be performed in accordance with Sec.
192.493.
    (E) All MFL and deformation tools used must have been validated to
characterize the size of defects within 10% of the actual dimensions
with 90% confidence. All EMAT or UT tools must have been validated to
characterize the size of cracks, both length and depth, within 20% of
the actual dimensions with 80% confidence, with like-similar analysis
from prior tool runs done to ensure the results are consistent with the
required corresponding hydrostatic test pressure for the segment being
evaluated.
    (F) Interpretation and evaluation of assessment results must meet
the requirements of Sec. Sec.  192.710, 192.713, and subpart O of this
part, and must conservatively account for the accuracy and reliability
of ILI, in-the-ditch examination methods and tools, and any other
assessment and examination results used to determine the actual sizes
of cracks, metal loss, deformation and other defect dimensions by
applying the most conservative limit of the tool tolerance
specification. ILI and in-the-ditch examination tools and procedures
for crack assessments (length, depth, and volumetric) must have
performance and evaluation standards confirmed for accuracy through
confirmation tests for the type defects and pipe material vintage being
evaluated. Inaccuracies must be accounted for in the procedures for
evaluations and fracture mechanics models for predicted failure
pressure determinations.
    (G) Anomalies detected by ILI assessments must be repaired in
accordance with applicable repair criteria in Sec. Sec.  192.713 and
192.933.
    (iv) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph Sec.  192.624(d).
    (4) Method 4: Pipe replacement. Replace the pipeline segment.
    (5) Method 5: Pressure reduction for segments with small potential
impact radius and diameter. Pipelines with a maximum allowable
operating pressure less than 30 percent of specified minimum yield
strength, a potential impact radius (PIR) less than or equal to 150
feet, nominal diameter equal to or less than 8-inches, and which cannot
be assessed using inline inspection or pressure test, may establish the
maximum allowable operating pressure as follows:
    (i) Reduce the pipeline maximum allowable operating pressure to no
greater than the highest actual operating pressure sustained by the
pipeline during 18 months preceding [effective date of the final rule],
divided by 1.1. The highest actual sustained pressure must have been
reached for a minimum cumulative duration of eight hours during one
continuous 30-day period. The reduced maximum allowable operating
pressure must account for differences between discharge and upstream
pressure on the pipeline by use of either the lowest value for the
entire segment or the operating pressure gradient (i.e., the location
specific operating pressure at each location);
    (ii) Conduct external corrosion direct assessment in accordance
with Sec.  192.925, and internal corrosion direct assessment in
accordance with Sec.  192.927;
    (iii) Develop and implement procedures for conducting non-
destructive tests, examinations, and assessments for cracks and crack-
like defects, including but not limited to stress corrosion cracking,
selective seam weld corrosion, girth weld cracks, and seam defects, for
pipe at all excavations associated with anomaly direct examinations, in
situ evaluations, repairs, remediations, maintenance, or any other
reason for which the pipe segment is exposed, except for segments
exposed during excavation activities that are in compliance with Sec.
192.614;
    (iv) Conduct monthly patrols in Class 1 and 2 locations, at an
interval not to exceed 45 days; weekly patrols in Class 3 locations not
to exceed 10 days; and semi-weekly patrols in Class 4 locations, at an
interval not to exceed six days, in accordance with Sec.  192.705;
    (v) Conduct monthly, instrumented leakage surveys in Class 1 and 2
locations, at intervals not to exceed 45 days; weekly leakage surveys
in Class 3 locations at intervals not to exceed 10 days; and semi-
weekly leakage surveys in Class 4 locations, at intervals not to exceed
six days, in accordance with Sec.  192.706; and
    (vi) Odorize gas transported in the segment, in accordance with
Sec.  192.625;
    (vii) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph Sec.  192.624(d).
    (viii) Under Method 5 described in paragraph (c)(5) of this
section, future uprating of the segment in accordance with subpart K of
this part is allowed.
    (6) Method 6: Alternative technology. Operators may use an
alternative technical evaluation process that provides a sound
engineering basis for establishing maximum allowable operating
pressure. If an operator elects to use alternative technology, the

operator must notify PHMSA at least 180 days in advance of use in
accordance with paragraph (e) of this section. The operator must submit
the alternative technical evaluation to PHMSA with the notification and
obtain a ``no objection letter'' from the Associate Administrator of
Pipeline Safety prior to usage of alternative technology. The
notification must include the following details:
    (i) Descriptions of the technology or technologies to be used for
tests, examinations, and assessments, establishment of material
properties, and analytical techniques, with like-similar analysis from
prior tool runs done to ensure the results are consistent with the
required corresponding hydrostatic test pressure for the segment being
evaluated.
    (ii) Procedures and processes to conduct tests, examinations, and
assessments, perform evaluations, analyze defects and flaws, and
remediate defects discovered;
    (iii) Methodology and criteria used to determine reassessment
period or need for a reassessment including references to applicable
regulations from this part and industry standards;
    (iv) Data requirements including original design, maintenance and
operating history, anomaly or flaw characterization;
    (v) Assessment techniques and acceptance criteria, including
anomaly detection confidence level, probability of detection, and
uncertainty of PFP quantified as a fraction of specified minimum yield
strength;
    (vi) If the operator has reason to believe any pipeline segment
contains or may be susceptible to cracks or crack-like defects due to
assessment, leak, failure, or manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph (d) of this section;
    (vii) Remediation methods with proven technical practice;
    (viii) Schedules for assessments and remediation;
    (ix) Operational monitoring procedures;
    (x) Methodology and criteria used to justify and establish the
maximum allowable operating pressure; and
    (xi) Documentation requirements for the operator's process,
including records to be generated.
    (d) Fracture mechanics modeling for failure stress and crack growth
analysis. (1) If the operator has reason to believe any pipeline
segment contains or may be susceptible to cracks or crack-like defects
due to assessment, leak, failure, or manufacturing vintage histories,
or any other available information about the pipeline, the operator
must perform fracture mechanics modeling for failure stress pressure
and crack growth analysis to determine the remaining life of the
pipeline at the maximum allowable operating pressure based on the
applicable test pressures in accordance with Sec.  192.506 including
the remaining crack flaw size in the pipeline segment, any pipe failure
or leak mechanisms identified during pressure testing, pipe
characteristics, material toughness, failure mechanism for the
microstructure(ductile and brittle or both), location and type of
defect, operating environment, and operating conditions including
pressure cycling. Fatigue analysis must be performed using a recognized
form of the Paris Law as specified in Battelle's Final Report No. 13-
021; Subtask 2.5 (incorporated by reference, see Sec.  192.7) or other
technically appropriate engineering methodology validated by a subject
matter expert in metallurgy and fracture mechanics to give conservative
predictions of flaw growth and remaining life. When assessing other
degradation processes, the analysis must be performed using recognized
rate equations whose applicability and validity is demonstrated for the
case being evaluated. For cases involving calculation of the critical
flaw size, conservative remaining life analysis must assess the
smallest critical sizes and use a lower-bound toughness. For cases
dealing with an estimating of the defect sizes that would survive a
hydro test pressure, conservative remaining life analysis that must
assess the largest surviving sizes and use upper-bound values of
material strength and toughness. The analysis must include a
sensitivity analysis to determine conservative estimates of time to
failure for cracks. Material strength and toughness values used must
reflect the local conditions for growth, and use data that is case
specific to estimate the range of strength and toughness for such
analysis. When the strength and toughness and limits on their ranges
are unknown, the analysis must assume material strength and fracture
toughness levels corresponding to the type of assessment being
performed, as follows:
    (i) For an assessment using a hydrostatic pressure test use a full
size equivalent Charpy upper-shelf energy level of 120 ft-lb and a flow
stress equal to the minimum specified ultimate tensile strength of the
base pipe material. The purpose of using the high level of Charpy
energy and flow stress (equal to the ultimate tensile strength) is for
an operator to calculate the largest defects that could have survived a
given level of hydrostatic test. The resulting maximum-size defects
lead to the shortened predicted times to failure,
    (ii) For ILI assessments unless actual ranges of values of strength
and toughness are known, the analysis must use the specified minimum
yield strength and the specified minimum ultimate tensile strength and
Charpy toughness valves lower than or equal to: 5.0 ft-lb for body
cracks; 1.0 ft-lb for ERW seam bond line defects such as cold weld,
lack of fusion, and selective seam weld corrosion defects.
    (iii) The sensitivity analysis to determine the time to failure for
a crack must include operating history, pressure tests, pipe geometry,
wall thickness, strength level, flow stress, and operating environment
for the pipe segment being assessed, including at a minimum the role of
the pressure-cycle spectrum.
    (2) If actual material toughness is not known or not adequately
documented for fracture mechanics modeling for failure stress pressure,
the operator must use a conservative Charpy energy value to determine
the toughness based upon the material documentation program specified
in Sec.  192.607; or use maximum Charpy energy values of 5.0 ft-lb for
body cracks; 1.0 ft-lb for cold weld, lack of fusion, and selective
seam weld corrosion defects as documented in Battelle Final Reports
(``Battelle's Experience with ERW and Flash Weld Seam Failures: Causes
and Implications''--Task 1.4), No. 13-002 (``Models for Predicting
Failure Stress Levels for Defects Affecting ERW and Flash-Welded
Seams''--Subtask 2.4), Report No. 13-021 (``Predicting Times to Failure
for ERW Seam Defects that Grow by Pressure-Cycle-Induced Fatigue''--
Subtask 2.5) and (``Final Summary Report and Recommendations for the
Comprehensive Study to Understand Longitudinal ERW Seam Failures--Phase
1''--Task 4.5) (incorporated by reference, see Sec.  192.7); or other
appropriate technology or technical publications that an operator
demonstrates can provide a conservative Charpy energy values of the
crack-related conditions of the line pipe.
    (3) The analysis must account for metallurgical properties at the
location being analyzed (such as in the properties of the parent pipe,
weld heat affected zone, or weld metal bond line), and must account for
the likely failure mode of anomalies (such as brittle fracture, ductile
fracture or both). If the likely failure mode is uncertain or unknown,
the analysis must analyze both failure modes and use the more
conservative result. Appropriate fracture

mechanics modeling for failure stress pressures in the brittle failure
mode is the Raju/Newman Model (Task 4.5) and for the ductile failure
mode is the Modified LnSec (Task 4.5) and Raju/Newman Models or other
proven-equivalent engineering fracture mechanics models for determining
conservative failure pressures may be used.
    (4) If the predicted remaining life of the pipeline calculated by
this analysis is 5 years or less, then the operator must perform a
pressure test in accordance with paragraph (c)(1) of this section or
reduce the maximum allowable operating pressure of the pipeline in
accordance with paragraph (c)(2) of this section to establish the
maximum allowable operating pressure within 1-year of analysis;
    (5) The operator must re-evaluate the remaining life of the
pipeline before 50% of the remaining life calculated by this analysis
has expired, but within 15 years. The operator must determine and
document if further pressure tests or use of other methods are required
at that time. The operator must continue to re-evaluate the remaining
life of the pipeline before 50% of the remaining life calculated in the
most recent evaluation has expired. If the analysis results show that a
50% remaining life reduction does not give a sufficient safety factor
based upon technical evaluations then a more conservative remaining
life safety factor must be used.
    (6) The analysis required by this paragraph (d) of this section
must be reviewed and confirmed by a subject matter expert in both
metallurgy and fracture mechanics.
    (e) Notifications. An operator must submit all notifications
required by this section to the Associate Administrator for Pipeline
Safety, by:
    (1) Sending the notification to the Office of Pipeline Safety,
Pipeline and Hazardous Material Safety Administration, U.S. Department
of Transportation, Information Resources Manager, PHP-10, 1200 New
Jersey Avenue SE., Washington, DC 20590-0001;
    (2) Sending the notification to the Information Resources Manager
by facsimile to<PHONE_NUMBER>; or
    (3) Sending the notification to the Information Resources Manager
by email to<EMAIL_ADDRESS>    (4) An operator must also send a copy to a State pipeline safety
authority when the pipeline is located in a State where PHMSA has an
interstate agent agreement, or an intrastate pipeline is regulated by
that State.
    (f) Records. Each operator must keep for the life of the pipeline
reliable, traceable, verifiable, and complete records of the
investigations, tests, analyses, assessments, repairs, replacements,
alterations, and other actions made in accordance with the requirements
of this section.
0
34. Section 192.710 is added to read as follows:

Sec.  192.710  Pipeline assessments.

    (a) Applicability. (1) This section applies to onshore transmission
pipeline segments that are located in:
    (i) A class 3 or class 4 location; or
    (ii) A moderate consequence area as defined in Sec.  192.3 if the
pipe segment can accommodate inspection by means of instrumented inline
inspection tools (i.e., ``smart pigs'').
    (2) This section does not apply to a pipeline segment located in a
high consequence area as defined in Sec.  192.903.
    (b) General. (1) An operator must perform initial assessments in
accordance with this section no later than [date 15 years after
effective date of the final rule] and periodic reassessments every 20
years thereafter, or a shorter reassessment internal based upon the
type anomaly, operational, material, and environmental conditions found
on the pipeline segment, or as otherwise necessary to ensure public
safety.
    (2) Prior assessment. An operator may use a prior assessment
conducted before [effective date of the final rule] as an initial
assessment for the segment, if the assessment meets the subpart O of
this part requirements for in-line inspection. If an operator uses this
prior assessment as its initial assessment, the operator must reassess
the pipeline segment according to the reassessment interval specified
in paragraph (b)(1) of this section.
    (3) MAOP verification. An operator may use an integrity assessment
to meet the requirements of this section if the pipeline segment
assessment is conducted in accordance with the integrity assessment
requirements of Sec.  192.624(c) for establishing MAOP.
    (c) Assessment method. The initial assessments and the
reassessments required by paragraph (b) of this section must be capable
of identifying anomalies and defects associated with each of the
threats to which the pipeline is susceptible and must be performed
using one or more of the following methods:
    (1) Internal inspection tool or tools capable of detecting
corrosion, deformation and mechanical damage (including dents, gouges
and grooves), material cracking and crack-like defects (including
stress corrosion cracking, selective seam weld corrosion,
environmentally assisted cracking, and girth weld cracks), hard spots,
and any other threats to which the segment is susceptible. When
performing an assessment using an in-line inspection tool, an operator
must comply with Sec.  192.493;
    (2) Pressure test conducted in accordance with subpart J of this
part. The use of pressure testing is appropriate for threats such as
internal corrosion, external corrosion, and other environmentally
assisted corrosion mechanisms, manufacturing and related defect
threats, including defective pipe and pipe seams, dents and other forms
of mechanical damage;
    (3) ``Spike'' hydrostatic pressure test in accordance with Sec.
192.506;
    (4) Excavation and in situ direct examination by means of visual
examination and direct measurement and recorded non-destructive
examination results and data needed to assess all threats, including
but not limited to, ultrasonic testing (UT), radiography, and magnetic
particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in appendix
F;
    (6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. Use of direct
assessment is allowed only if the line is not capable of inspection by
internal inspection tools and is not practical to assess (due to low
operating pressures and flows, lack of inspection technology, and
critical delivery areas such as hospitals and nursing homes) using the
methods specified in paragraphs (d)(1) through (5) of this section. An
operator must conduct the direct assessment in accordance with the
requirements listed in Sec.  192.923 and with the applicable
requirements specified in Sec. Sec.  192.925, 192.927 or 192.929; or
    (7) Other technology or technologies that an operator demonstrates
can provide an equivalent understanding of the line pipe for each of
the threats to which the pipeline is susceptible.
    (8) For segments with MAOP less than 30% of the SMYS, an operator
must assess for the threats of external and internal corrosion, as
follows:
    (i) External corrosion. An operator must take one of the following
actions to address external corrosion on a low stress segment:
    (A) Cathodically protected pipe. To address the threat of external
corrosion on cathodically protected pipe, an operator must perform an
indirect assessment (i.e. indirect examination

tool/method such as close interval survey, alternating current voltage
gradient, direct current voltage gradient, or equivalent) at least
every seven years on the segment. An operator must use the results of
each survey as part of an overall evaluation of the cathodic protection
and corrosion threat for the segment. This evaluation must consider, at
minimum, the leak repair and inspection records, corrosion monitoring
records, exposed pipe inspection records, and the pipeline environment.
    (B) Unprotected pipe or cathodically protected pipe where indirect
assessments are impractical. To address the threat of external
corrosion on unprotected pipe or cathodically protected pipe where
indirect assessments are impractical, an operator must--
    (1) Conduct leakage surveys as required by Sec.  192.706 at 4-month
intervals; and
    (2) Every 18 months, identify and remediate areas of active
corrosion by evaluating leak repair and inspection records, corrosion
monitoring records, exposed pipe inspection records, and the pipeline
environment.
    (ii) Internal corrosion. To address the threat of internal
corrosion on a low stress segment, an operator must--
    (A) Conduct a gas analysis for corrosive agents at least twice each
calendar year;
    (B) Conduct periodic testing of fluids removed from the segment. At
least once each calendar year test the fluids removed from each storage
field that may affect a segment; and
    (C) At least every seven (7) years, integrate data from the
analysis and testing required by paragraphs (c)(8)(ii)(A) and (B) of
this section with applicable internal corrosion leak records, incident
reports, safety-related condition reports, repair records, patrol
records, exposed pipe reports, and test records, and define and
implement appropriate remediation actions.
    (d) Data analysis. A person qualified by knowledge, training, and
experience must analyze the data obtained from an assessment performed
under paragraph (b) of this section to determine if a condition could
adversely affect the safe operation of the pipeline. In addition, an
operator must explicitly consider uncertainties in reported results
(including, but not limited to, tool tolerance, detection threshold,
probability of detection, probability of identification, sizing
accuracy, conservative anomaly interaction criteria, location accuracy,
anomaly findings, and unity chart plots or equivalent for determining
uncertainties and verifying tool performance) in identifying and
characterizing anomalies.
    (e) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information to determine that a condition exists.
An operator must promptly, but no later than 180 days after an
assessment, obtain sufficient information about a condition to make the
determination required under paragraph (d), unless the operator can
demonstrate that that 180-days is impracticable.
    (f) Remediation. An operator must comply with the requirements in
Sec.  192.713 if a condition that could adversely affect the safe
operation of a pipeline is discovered.
    (g) Consideration of information. An operator must consider all
available information about a pipeline in complying with the
requirements in paragraphs (a) through (f) of this section.
0
35. In Sec.  192.711, paragraph (b)(1) is revised to read as follows:

Sec.  192.711  Transmission lines: General requirements for repair
procedures.

* * * * *
    (b) * * *
    (1) Non integrity management repairs. Whenever an operator
discovers any condition that could adversely affect the safe operation
of a pipeline segment not covered under subpart O of this part, Gas
Transmission Pipeline Integrity Management, it must correct the
condition as prescribed in Sec.  192.713. However, if the condition is
of such a nature that it presents an immediate hazard to persons or
property, the operator must reduce the operating pressure to a level
not exceeding 80% of the operating pressure at the time the condition
was discovered and take additional immediate temporary measures in
accordance with paragraph (a) of this section to protect persons or
property. The operator must make permanent repairs as soon as feasible.
* * * * *
0
36. Section 192.713 is revised to read as follows:

Sec.  192.713  Transmission lines: Permanent field repair of
imperfections and damages.

    (a) This section applies to transmission lines. Line segments that
are located in high consequence areas, as defined in Sec.  192.903,
must also comply with applicable actions specified by the integrity
management requirements in subpart O of this part.
    (b) General. Each operator must, in repairing its pipeline systems,
ensure that the repairs are made in a safe manner and are made so as to
prevent damage to persons, property, or the environment. Operating
pressure must be at a safe level during repair operations.
    (c) Repair. Each imperfection or damage that impairs the
serviceability of pipe in a steel transmission line operating at or
above 40 percent of SMYS must be--
    (1) Removed by cutting out and replacing a cylindrical piece of
pipe; or
    (2) Repaired by a method that reliable engineering tests and
analyses show can permanently restore the serviceability of the pipe.
    (d) Remediation schedule. For pipelines not located in high
consequence areas, an operator must complete the remediation of a
condition according to the following schedule:
    (1) Immediate repair conditions. An operator must repair the
following conditions immediately upon discovery:
    (i) A calculation of the remaining strength of the pipe shows a
predicted failure pressure less than or equal to 1.1 times the maximum
allowable operating pressure at the location of the anomaly. Suitable
remaining strength calculation methods include, ASME/ANSI B31G;
RSTRENG; or an alternative equivalent method of remaining strength
calculation. These documents are incorporated by reference and
available at the addresses listed in Sec.  192.7(c). Pipe and material
properties used in remaining strength calculations must be documented
in reliable, traceable, verifiable, and complete records. If such
records are not available, pipe and material properties used in the
remaining strength calculations must be based on properties determined
and documented in accordance with Sec.  192.607.
    (ii) A dent that has any indication of metal loss, cracking or a
stress riser.
    (iii) Metal loss greater than 80% of nominal wall regardless of
dimensions.
    (iv) An indication of metal-loss affecting a detected longitudinal
seam, if that seam was formed by direct current or low-frequency or
high frequency electric resistance welding or by electric flash
welding.
    (v) Any indication of significant stress corrosion cracking (SCC).
    (vi) Any indication of significant selective seam weld corrosion
(SSWC).
    (vii) An indication or anomaly that in the judgment of the person
designated by the operator to evaluate the assessment results requires
immediate action.
    (2) Until the remediation of a condition specified in paragraph
(d)(1) of this section is complete, an operator must reduce the
operating pressure of the affected pipeline to the lower of:

    (i) A level that restores the safety margin commensurate with the
design factor for the Class Location in which the affected pipeline is
located, determined using ASME/ANSI B31G (``Manual for Determining the
Remaining Strength of Corroded Pipelines'' (1991) or AGA Pipeline
Research Committee Project PR-3-805 (``A Modified Criterion for
Evaluating the Remaining Strength of Corroded Pipe'' (December 1989))
(``RSTRENG,'' incorporated by reference, see Sec.  192.7) for corrosion
defects. Both procedures apply to corroded regions that do not
penetrate the pipe wall over 80 percent of the wall thickness and are
subject to the limitations prescribed in the equations procedures. When
determining the predicted failure pressure (PFP) for gouges, scrapes,
selective seam weld corrosion, crack-related defects, appropriate
failure criteria and justification of the criteria must be used. If
SMYS or actual material yield and ultimate tensile strength is not
known or not adequately documented by reliable, traceable, verifiable,
and complete records, then the operator must assume grade A pipe or
determine the material properties based upon the material documentation
program specified in Sec.  192.607; or
    (ii) 80% of pressure at the time of discovery, whichever is lower.
    (3) Two-year conditions. An operator must repair the following
conditions within two years of discovery:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock
positions (upper 2/3 of the pipe) with a depth greater than 6% of the
pipeline diameter (greater than 0.50 inches in depth for a pipeline
diameter less than nominal pipe size (NPS) 12).
    (ii) A dent with a depth greater than 2% of the pipeline's diameter
(0.250 inches in depth for a pipeline diameter less than NPS 12) that
affects pipe curvature at a girth weld or at a longitudinal or helical
(spiral) seam weld.
    (iii) A calculation of the remaining strength of the pipe shows a
predicted failure pressure ratio (FPR) at the location of the anomaly
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.
This calculation must adequately account for the uncertainty associated
with the accuracy of the tool used to perform the assessment.
    (iv) An area of corrosion with a predicted metal loss greater than
50% of nominal wall.
    (v) Predicted metal loss greater than 50% of nominal wall that is
located at a crossing of another pipeline, or is in an area with
widespread circumferential corrosion, or is in an area that could
affect a girth weld.
    (vi) A gouge or groove greater than 12.5% of nominal wall.
    (vii) Any indication of crack or crack-like defect other than an
immediate condition.
    (4) Monitored conditions. An operator does not have to schedule the
following conditions for remediation, but must record and monitor the
conditions during subsequent risk assessments and integrity assessments
for any change that may require remediation:
    (i) A dent with a depth greater than 6% of the pipeline diameter
(greater than 0.50 inches in depth for a pipeline diameter less than
NPS 12) located between the 4 o'clock position and the 8 o'clock
position (bottom 1/3 of the pipe).
    (ii) A dent located between the 8 o'clock and 4 o'clock positions
(upper 2/3 of the pipe) with a depth greater than 6% of the pipeline
diameter (greater than 0.50 inches in depth for a pipeline diameter
less than nominal pipe size (NPS) 12), and engineering analyses of the
dent demonstrate critical strain levels are not exceeded.
    (e) Other conditions. Unless another timeframe is specified in
paragraph (d) of this section, an operator must take appropriate
remedial action to correct any condition that could adversely affect
the safe operation of a pipeline system in accordance with the
criteria, schedules and methods defined in the operator's Operating and
Maintenance procedures.
    (f) In situ direct examination of crack defects. Whenever required
by this part, operators must perform direct examination of known
locations of cracks or crack-like defects using inverse wave field
extrapolation (IWEX), phased array, automated ultrasonic testing (AUT),
or equivalent technology that has been validated to detect tight cracks
(equal to or less than 0.008 inches). In-the-ditch examination tools
and procedures for crack assessments (length, depth, and volumetric)
must have performance and evaluation standards, including pipe or weld
surface cleanliness standards for the inspection, confirmed by subject
matter experts qualified by knowledge, training, and experience in
direct examination inspection and in metallurgy and fracture mechanics
for accuracy for the type of defects and pipe material being evaluated.
The procedures must account for inaccuracies in evaluations and
fracture mechanics models for failure pressure determinations.
0
37. Section 192.750 is added to read as follows:

Sec.  192.750  Launcher and receiver safety.

    Any launcher or receiver used after [date 6 months after effective
date of the final rule], must be equipped with a device capable of
safely relieving pressure in the barrel before removal or opening of
the launcher or receiver barrel closure or flange and insertion or
removal of in-line inspection tools, scrapers, or spheres. The operator
must use a suitable device to indicate that pressure has been relieved
in the barrel or must provide a means to prevent opening of the barrel
closure or flange, or prevent insertion or removal of in-line
inspection tools, scrapers, or spheres, if pressure has not been
relieved.
0
38. In Sec.  192.911, paragraph (k) is revised to read as follows:

Sec.  192.911  What are the elements of an integrity management
program?

* * * * *
    (k) A management of change process as required by Sec.  192.13(d).
* * * * *
0
39. In Sec.  192.917, paragraphs (a), (b), (c), (d), (e)(2), (e)(3),
and (e)(4) are revised to read as follows:

Sec.  192.917  How does an operator identify potential threats to
pipeline integrity and use the threat identification in its integrity
program?

    (a) Threat identification. An operator must identify and evaluate
all potential threats to each covered pipeline segment. Potential
threats that an operator must consider include, but are not limited to,
the threats listed in ASME/ANSI B31.8S (incorporated by reference, see
Sec.  192.7), section 2, which are grouped under the following four
threats:
    (1) Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;
    (2) Stable threats, such as manufacturing, welding/fabrication, or
equipment defects;
    (3) Time independent threats such as third party/mechanical damage,
incorrect operational procedure, weather related and outside force,
including consideration of seismicity, geology, and soil stability of
the area; and
    (4) Human error such as operational mishaps and design and
construction mistakes.
    (b) Data gathering and integration. To identify and evaluate the
potential threats to a covered pipeline segment, an operator must
gather, verify, validate, and integrate existing data and

information on the entire pipeline that could be relevant to the
covered segment. In performing data gathering and integration, an
operator must follow the requirements in ASME/ANSI B31.8S, section 4.
At a minimum, an operator must gather and evaluate the set of data
specified in paragraph (b)(1) of this section and appendix A to ASME/
ANSI B31.8S. The evaluation must analyze both the covered segment and
similar non-covered segments, and must:
    (1) Integrate information about pipeline attributes and other
relevant information, including, but not limited to:
    (i) Pipe diameter, wall thickness, grade, seam type and joint
factor;
    (ii) Manufacturer and manufacturing date, including manufacturing
data and records;
    (iii) Material properties including, but not limited to, diameter,
wall thickness, grade, seam type, hardness, toughness, hard spots, and
chemical composition;
    (iv) Equipment properties;
    (v) Year of installation;
    (vi) Bending method;
    (vii) Joining method, including process and inspection results;
    (viii) Depth of cover surveys including stream and river crossings,
navigable waterways, and beach approaches;
    (ix) Crossings, casings (including if shorted), and locations of
foreign line crossings and nearby high voltage power lines;
    (x) Hydrostatic or other pressure test history, including test
pressures and test leaks or failures, failure causes, and repairs;
    (xi) Pipe coating methods (both manufactured and field applied)
including method or process used to apply girth weld coating,
inspection reports, and coating repairs;
    (xii) Soil, backfill;
    (xiii) Construction inspection reports, including but not limited
to:
    (A) Girth weld non-destructive examinations;
    (B) Post backfill coating surveys;
    (C) Coating inspection (``jeeping'') reports;
    (xiv) Cathodic protection installed, including but not limited to
type and location;
    (xv) Coating type;
    (xvi) Gas quality;
    (xvii) Flow rate;
    (xviii) Normal maximum and minimum operating pressures, including
maximum allowable operating pressure (MAOP);
    (xix) Class location;
    (xx) Leak and failure history including any in-service ruptures or
leaks from incident reports, abnormal operations, safety related
conditions (both reported and unreported) and failure investigations
required by Sec.  192.617, and their identified causes and
consequences;
    (xxi) Coating condition;
    (xxii) CP system performance;
    (xxiii) Pipe wall temperature;
    (xxiv) Pipe operational and maintenance inspection reports,
including but not limited to:
    (A) Data gathered through integrity assessments required under this
part, including but not limited to in-line inspections, pressure tests,
direct assessment, guided wave ultrasonic testing, or other methods;
    (B) Close interval survey (CIS) and electrical survey results;
    (C) Cathodic protection (CP) rectifier readings;
    (D) CP test point survey readings and locations;
    (E) AC/DC and foreign structure interference surveys;
    (F) Pipe coating surveys, including surveys to detect coating
damage, disbonded coatings, or other conditions that compromise the
effectiveness of corrosion protection, including but not limited to
direct current voltage gradient or alternating current voltage gradient
inspections;
    (G) Results of examinations of exposed portions of buried pipelines
(e.g., pipe and pipe coating condition, see Sec.  192.459), including
the results of any non-destructive examinations of the pipe, seam or
girth weld, i.e. bell hole inspections;
    (H) Stress corrosion cracking (SCC) excavations and findings;
    (I) Selective seam weld corrosion (SSWC) excavations and findings;
    (J) Gas stream sampling and internal corrosion monitoring results,
including cleaning pig sampling results;
    (xxv) Outer Diameter/Inner Diameter corrosion monitoring;
    (xxvi) Operating pressure history and pressure fluctuations,
including analysis of effects of pressure cycling and instances of
exceeding MAOP by any amount;
    (xxvii) Performance of regulators, relief valves, pressure control
devices, or any other device to control or limit operating pressure to
less than MAOP;
    (xxviii) Encroachments and right-of-way activity, including but not
limited to, one-call data, pipe exposures resulting from encroachments,
and excavation activities due to development or planned development
along the pipeline;
    (xxix) Repairs;
    (xxx) Vandalism;
    (xxxi) External forces;
    (xxxii) Audits and reviews;
    (xxxiii) Industry experience for incident, leak and failure
history;
    (xxxiv) Aerial photography;
    (xxxv) Exposure to natural forces in the area of the pipeline,
including seismicity, geology, and soil stability of the area; and
    (xxxvi) Other pertinent information derived from operations and
maintenance activities and any additional tests, inspections, surveys,
patrols, or monitoring required under this part.
    (2) Use objective, traceable, verified, and validated information
and data as inputs, to the maximum extent practicable. If input is
obtained from subject matter experts (SMEs), the operator must employ
measures to adequately correct any bias in SME input. Bias control
measures may include training of SMEs and use of outside technical
experts (independent expert reviews) to assess quality of processes and
the judgment of SMEs. Operator must document the names of all SMEs and
information submitted by the SMEs for the life of the pipeline.
    (3) Identify and analyze spatial relationships among anomalous
information (e.g., corrosion coincident with foreign line crossings;
evidence of pipeline damage where overhead imaging shows evidence of
encroachment). Storing or recording the information in a common
location, including a geographic information system (GIS), alone, is
not sufficient; and
    (4) Analyze the data for interrelationships among pipeline
integrity threats, including combinations of applicable risk factors
that increase the likelihood of incidents or increase the potential
consequences of incidents.
    (c) Risk assessment. An operator must conduct a risk assessment
that analyzes the identified threats and potential consequences of an
incident for each covered segment. The risk assessment must include
evaluation of the effects of interacting threats, including the
potential for interactions of threats and anomalous conditions not
previously evaluated. An operator must ensure validity of the methods
used to conduct the risk assessment in light of incident, leak, and
failure history and other historical information. Validation must
ensure the risk assessment methods produce a risk characterization that
is consistent with the operator's and industry experience, including
evaluations of the cause of past incidents, as determined by root cause
analysis or other equivalent means, and include sensitivity analysis of
the

factors used to characterize both the probability of loss of pipeline
integrity and consequences of the postulated loss of pipeline
integrity. An operator must use the risk assessment to determine
additional preventive and mitigative measures needed (Sec.  192.935)
for each covered segment, and periodically evaluate the integrity of
each covered pipeline segment (Sec.  192.937(b)). The risk assessment
must:
    (1) Analyze how a potential failure could affect high consequence
areas, including the consequences of the entire worst-case incident
scenario from initial failure to incident termination;
    (2) Analyze the likelihood of failure due to each individual threat
or risk factor, and each unique combination of threats or risk factors
that interact or simultaneously contribute to risk at a common
location;
    (3) Lead to better understanding of the nature of the threat, the
failure mechanisms, the effectiveness of currently deployed risk
mitigation activities, and how to prevent, mitigate, or reduce those
risks;
    (4) Account for, and compensate for, uncertainties in the model and
the data used in the risk assessment; and
    (5) Evaluate the potential risk reduction associated with candidate
risk reduction activities such as preventive and mitigative measures
and reduced anomaly remediation and assessment intervals.
    (d) Plastic transmission pipeline. An operator of a plastic
transmission pipeline must assess the threats to each covered segment
using the information in sections 4 and 5 of ASME B31.8S, and consider
any threats unique to the integrity of plastic pipe such as poor joint
fusion practices, pipe with poor slow crack growth (SCG) resistance,
brittle pipe, circumferential cracking, hydrocarbon softening of the
pipe, internal and external loads, longitudinal or lateral loads,
proximity to elevated heat sources, and point loading.
    (e) * * *
    (2) Cyclic fatigue. An operator must evaluate whether cyclic
fatigue or other loading conditions (including ground movement,
suspension bridge condition) could lead to a failure of a deformation,
including a dent or gouge, crack, or other defect in the covered
segment. The evaluation must assume the presence of threats in the
covered segment that could be exacerbated by cyclic fatigue. An
operator must use the results from the evaluation together with the
criteria used to evaluate the significance of this threat to the
covered segment to prioritize the integrity baseline assessment or
reassessment. Fracture mechanics modeling for failure stress pressures
and cyclic fatigue crack growth analysis must be conducted in
accordance with Sec.  192.624(d) for cracks. Cyclic fatigue analysis
must be annually, not to exceed 15 months.
    (3) Manufacturing and construction defects. An operator must
analyze the covered segment to determine the risk of failure from
manufacturing and construction defects (including seam defects) in the
covered segment. The analysis must consider the results of prior
assessments on the covered segment. An operator may consider
manufacturing and construction related defects to be stable defects
only if the covered segment has been subjected to hydrostatic pressure
testing satisfying the criteria of subpart J of this part of at least
1.25 times MAOP, and the segment has not experienced an in-service
incident attributed to a manufacturing or construction defect since the
date of the pressure test. If any of the following changes occur in the
covered segment, an operator must prioritize the covered segment as a
high risk segment for the baseline assessment or a subsequent
reassessment, and must reconfirm or reestablish MAOP in accordance with
Sec.  192.624(c).
    (i) The segment has experienced an in-service incident, as
described in Sec.  192.624(a)(1);
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.
    (4) ERW pipe. If a covered pipeline segment contains low frequency
electric resistance welded pipe (ERW), lap welded pipe, pipe with seam
factor less than 1.0 as defined in Sec.  192.113, or other pipe that
satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3
and A4.4, and any covered or non-covered segment in the pipeline system
with such pipe has experienced seam failure (including, but not limited
to pipe body cracking, seam cracking and selective seam weld
corrosion), or operating pressure on the covered segment has increased
over the maximum operating pressure experienced during the preceding
five years (including abnormal operation as defined in Sec.
192.605(c)), or MAOP has been increased, an operator must select an
assessment technology or technologies with a proven application capable
of assessing seam integrity and seam corrosion anomalies. The operator
must prioritize the covered segment as a high risk segment for the
baseline assessment or a subsequent reassessment. Pipe with cracks must
be evaluated using fracture mechanics modeling for failure stress
pressures and cyclic fatigue crack growth analysis to estimate the
remaining life of the pipe in accordance with Sec.  192.624(c) and (d).
* * * * *
0
40. In Sec.  192.921, paragraph (a) is revised to read as follows:

Sec.  192.921  How is the baseline assessment to be conducted?

    (a) Assessment methods. An operator must assess the integrity of
the line pipe in each covered segment by applying one or more of the
following methods for each threat to which the covered segment is
susceptible. An operator must select the method or methods best suited
to address the threats identified to the covered segment (See Sec.
192.917). In addition, an operator may use an integrity assessment to
meet the requirements of this section if the pipeline segment
assessment is conducted in accordance with the integrity assessment
requirements of Sec.  192.624(c) for establishing MAOP.
    (1) Internal inspection tool or tools capable of detecting
corrosion, deformation and mechanical damage (including dents, gouges
and grooves), material cracking and crack-like defects (including
stress corrosion cracking, selective seam weld corrosion,
environmentally assisted cracking, and girth weld cracks), hard spots
with cracking, and any other threats to which the covered segment is
susceptible. When performing an assessment using an in-line inspection
tool, an operator must comply with Sec.  192.493. A person qualified by
knowledge, training, and experience must analyze the data obtained from
an internal inspection tool to determine if a condition could adversely
affect the safe operation of the pipeline. In addition, an operator
must explicitly consider uncertainties in reported results (including,
but not limited to, tool tolerance, detection threshold, probability of
detection, probability of identification, sizing accuracy, conservative
anomaly interaction criteria, location accuracy, anomaly findings, and
unity chart plots or equivalent for determining uncertainties and
verifying actual tool performance) in identifying and characterizing
anomalies;
    (2) Pressure test conducted in accordance with subpart J of this
part. An operator must use the test pressures specified in table 3 of
section 5 of ASME/ANSI B31.8S to justify an extended reassessment
interval in accordance with Sec.  192.939. The use of pressure testing
is appropriate for threats such as internal corrosion, external
corrosion, and other environmentally assisted corrosion mechanisms,
manufacturing and related defect threats, including defective pipe

and pipe seams, stress corrosion cracking, selective seam weld
corrosion, dents and other forms of mechanical damage;
    (3) ``Spike'' hydrostatic pressure test in accordance with Sec.
192.506. The use of spike hydrostatic pressure testing is appropriate
for threats such as 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;
    (4) Excavation and in situ direct examination by means of visual
examination, direct measurement, and recorded non-destructive
examination results and data needed to assess all threats, including
but not limited to, ultrasonic testing (UT), radiography, and magnetic
particle inspection (MPI);
    (5) Guided Wave Ultrasonic Testing (GWUT) conducted as described in
Appendix F;
    (6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. Use of direct
assessment is allowed only if the line is not capable of inspection by
internal inspection tools and is not practical to assess using the
methods specified in paragraphs (d)(1) through (5) of this section. An
operator must conduct the direct assessment in accordance with the
requirements listed in Sec.  192.923 and with the applicable
requirements specified in Sec.  192.925, 192.927, or 192.929; or
    (7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe for each of
the threats to which the pipeline is susceptible. An operator choosing
this option must notify the Office of Pipeline Safety (OPS) 180 days
before conducting the assessment, in accordance with Sec.  192.949 and
receive a ``no objection letter'' from the Associate Administrator of
Pipeline Safety. An operator must also notify the appropriate State or
local pipeline safety authority when a covered segment is located in a
State where OPS has an interstate agent agreement, or an intrastate
covered segment is regulated by that State.
* * * * *
0
41. In Sec.  192.923, paragraphs (b)(2) and (b)(3) are revised to read
as follows:

Sec.  192.923  How is direct assessment used and for what threats?

* * * * *
    (b) * * *
    (2) NACE SP0206-2006 and Sec.  192.927 if addressing internal
corrosion (ICDA).
    (3) NACE SP0204-2008 and Sec.  192.929 if addressing stress
corrosion cracking (SCCDA).
* * * * *
0
42. In Sec.  192.927, paragraphs (b) and (c) are revised to read as
follows:

Sec.  192.927  What are the requirements for using Internal Corrosion
Direct Assessment (ICDA)?

* * * * *
    (b) General requirements. An operator using direct assessment as an
assessment method to address internal corrosion in a covered pipeline
segment must follow the requirements in this section and in NACE
SP0206-2006 (incorporated by reference, see Sec.  192.7). The Dry Gas
(DG) Internal Corrosion Direct Assessment (ICDA) process described in
this section applies only for a segment of pipe transporting normally
dry natural gas (see definition Sec.  192.3), and not for a segment
with electrolyte normally present in the gas stream. If an operator
uses ICDA to assess a covered segment operating with electrolyte
present in the gas stream, the operator must develop a plan that
demonstrates how it will conduct ICDA in the segment to effectively
address internal corrosion, and must notify the Office of Pipeline
Safety (OPS) 180 days before conducting the assessment in accordance
with Sec.  192.921(a)(4) or Sec.  192.937(c)(4).
    (c) The ICDA plan. An operator must develop and follow an ICDA plan
that meets all requirements and recommendations contained in NACE