SP0206-2006 and that implements all four steps of the DG-ICDA process
including pre-assessment, indirect inspection, detailed examination,
and post-assessment. The plan must identify where all ICDA Regions with
covered segments are located in the transmission system. An ICDA Region
is a continuous length of pipe (including weld joints) uninterrupted by
any significant change in water or flow characteristics that includes
similar physical characteristics or operating history. An ICDA Region
extends from the location where liquid may first enter the pipeline and
encompasses the entire area along the pipeline where internal corrosion
may occur until a new input introduces the possibility of water
entering the pipeline. In cases where a single covered segment is
partially located in two or more ICDA regions, the four-step ICDA
process must be completed for each ICDA region in which the covered
segment is partially located in order to complete the assessment of the
covered segment.
    (1) Preassessment. An operator must comply with the requirements
and recommendations in NACE SP0206-2006 in conducting the preassessment
step of the ICDA process.
    (2) Indirect Inspection. An operator must comply with the
requirements and recommendations in NACE SP0206-2006, and the following
additional requirements, in conducting the Indirect Inspection step of
the ICDA process. Operators must explicitly document the results of its
feasibility assessment as required by NACE SP0206-2006, Section 3.3; if
any condition that precludes the successful application of ICDA
applies, then ICDA may not be used, and another assessment method must
be selected. When performing the indirect inspection, the operator must
use pipeline specific data, exclusively. The use of assumed pipeline or
operational data is prohibited. When calculating the critical
inclination angle of liquid holdup and the inclination profile of the
pipeline, the operator must consider the accuracy, reliability, and
uncertainty of data used to make those calculations, including but not
limited to gas flow velocity (including during upset conditions),
pipeline elevation profile survey data (including specific profile at
features with inclinations such as road crossing, river crossings,
drains, valves, drips, etc.), topographical data, depth of cover, etc.
The operator must select locations for direct examination, and
establish the extent of pipe exposure needed (i.e., the size of the
bell hole), to explicitly account for these uncertainties and their
cumulative effect on the precise location of predicted liquid dropout.
    (3) Detailed examination. An operator must comply with the
requirements and recommendations in NACE SP0206-2006 in conducting the
detailed examination step of the ICDA process. In addition, on the
first use of ICDA for a covered segment, an operator must identify a
minimum of two locations for excavation within each covered segment
associated with the ICDA Region and must perform a detailed examination
for internal corrosion at each location using ultrasonic thickness
measurements, radiography, or other generally accepted measurement
techniques. One location must be the low point (e.g., sags, drips,
valves, manifolds, dead-legs, traps) within the covered segment nearest
to the beginning of the ICDA Region. The second location must be
further downstream, within a covered segment, near the end of the ICDA
Region. If corrosion is found at any location, the operator must--
    (i) Evaluate the severity of the defect (remaining strength) and
remediate the defect in accordance with Sec.  192.933, if the condition
is in a covered segment,

or in accordance with Sec. Sec.  192.485 and 192.713 if the condition
is not in a covered segment;
    (ii) Expand the detailed examination program, whenever internal
corrosion is discovered, to determine all locations that have internal
corrosion within the ICDA region, and accurately characterize the
nature, extent, and root cause of the internal corrosion. In cases
where the internal corrosion was identified within the ICDA region but
outside the covered segment, the expanded detailed examination program
must also include at least two detailed examinations within each
covered segment associated with the ICDA region, at the location within
the covered segment(s) most likely to have internal corrosion. One
location must be the low point (e.g., sags, drips, valves, manifolds,
dead-legs, traps) within the covered segment nearest to the beginning
of the ICDA Region. The second location must be further downstream,
within the covered segment. In instances of first use of ICDA for a
covered segment, where these locations have already been examined per
paragraph (c)(3) of this section, two additional detailed examinations
must be conducted within the covered segment; and
    (iii) Expand the detailed examination program to evaluate the
potential for internal corrosion in all pipeline segments (both covered
and non-covered) in the operator's pipeline system with similar
characteristics to the ICDA region in which the corrosion was found and
remediate identified instances of internal corrosion in accordance with
Sec.  192.933 or Sec.  192.713, as appropriate.
    (4) Post-assessment evaluation and monitoring. An operator must
comply with the requirements and recommendations in NACE SP0206-2006 in
performing the post assessment step of the ICDA process. In addition to
the post-assessment requirements and recommendations in NACE SP0206-
2006, the evaluation and monitoring process must also include--
    (i) Evaluating the effectiveness of ICDA as an assessment method
for addressing internal corrosion and determining whether a covered
segment should be reassessed at more frequent intervals than those
specified in Sec.  192.939. An operator must carry out this evaluation
within a year of conducting an ICDA;
    (ii) Validation of the flow modeling calculations by comparison of
actual locations of discovered internal corrosion with locations
predicted by the model (if the flow model cannot be validated, then
ICDA is not feasible for the segment); and
    (iii) Continually monitoring each ICDA region which contains a
covered segment where internal corrosion has been identified by using
techniques such as coupons or UT sensors or electronic probes, and by
periodically drawing off liquids at low points and chemically analyzing
the liquids for the presence of corrosion products. An operator must
base the frequency of the monitoring and liquid analysis on results
from all integrity assessments that have been conducted in accordance
with the requirements of this subpart, and risk factors specific to the
ICDA region. At a minimum, the monitoring frequency must be two times
each calendar year, but at intervals not exceeding 7\1/2\ months. If an
operator finds any evidence of corrosion products in the ICDA region,
the operator must take prompt action in accordance with one of the two
following required actions and remediate the conditions the operator
finds in accordance with Sec.  192.933.
    (A) Conduct excavations of, and detailed examinations at, locations
downstream from where the electrolyte might have entered the pipe to
investigate and accurately characterize the nature, extent, and root
cause of the corrosion, including the monitoring and mitigation
requirements of Sec.  192.478; or
    (B) Assess the covered segment using ILI tools capable of detecting
internal corrosion.
    (5) Other requirements--The ICDA plan must also include the
following:
    (i) Criteria an operator will apply in making key decisions (e.g.,
ICDA feasibility, definition of ICDA Regions and Sub-regions,
conditions requiring excavation) in implementing each stage of the ICDA
process;
    (ii) Provisions that analysis be carried out on the entire pipeline
in which covered segments are present, except that application of the
remediation criteria of Sec.  192.933 may be limited to covered
segments.
0
43. Section 192.929 is revised to read as follows:

Sec.  192.929  What are the requirements for using direct assessment
for stress corrosion cracking (SCCDA)?

    (a) Definition. Stress corrosion cracking direct assessment (SCCDA)
is a process to assess a covered pipe segment for the presence of SCC
by systematically gathering and analyzing excavation data for pipe
having similar operational characteristics and residing in a similar
physical environment.
    (b) General requirements. An operator using direct assessment as an
integrity assessment method to address stress corrosion cracking in a
covered pipeline segment must develop and follow an SCCDA plan that
meets all requirements and recommendations contained in NACE SP0204-
2008 and that implements all four steps of the SCCDA process including
pre-assessment, indirect inspection, detailed examination and post-
assessment. As specified in NACE SP0204-2008, Section 1.1.7, SCCDA is
complementary with other inspection methods such as in-line inspection
(ILI) or hydrostatic testing and is not necessarily an alternative or
replacement for these methods in all instances. In addition, the plan
must provide for--
    (1) Data gathering and integration. An operator's plan must provide
for a systematic process to collect and evaluate data for all covered
segments to identify whether the conditions for SCC are present and to
prioritize the covered segments for assessment in accordance with NACE
SP0204-2008, sections 3 and 4, and table 1. This process must also
include gathering and evaluating data related to SCC at all sites an
operator excavates during the conduct of its pipeline operations (both
within and outside covered segments) where the criteria in NACE SP0204-
2008 indicate the potential for SCC. This data gathering process must
be conducted in accordance with NACE SP0204-2008, section 5.3, and must
include, at minimum, all data listed in NACE SP0204-2008, table 2.
Further, the following factors must be analyzed as part of this
evaluation:
    (i) The effects of a carbonate-bicarbonate environment, including
the implications of any factors that promote the production of a
carbonate-bicarbonate environment such as soil temperature, moisture,
the presence or generation of carbon dioxide, and/or Cathodic
Protection (CP).
    (ii) The effects of cyclic loading conditions on the susceptibility
and propagation of SCC in both high-pH and near-neutral-pH
environments.
    (iii) The effects of variations in applied CP such as
overprotection, CP loss for extended periods, and high negative
potentials.
    (iv) The effects of coatings that shield CP when disbonded from the
pipe.
    (v) Other factors which affect the mechanistic properties
associated with SCC including but not limited to historical and
present-day operating pressures, high tensile residual stresses,
flowing product temperatures, and the presence of sulfides.
    (2) Indirect inspection. In addition to the requirements and
recommendations of NACE SP0204-2008, section 4, the

plan's procedures for indirect inspection must include provisions for
conducting at least two above ground surveys using complementary
measurement tools most appropriate for the pipeline segment based on
the data gathering and integration step.
    (3) Direct examination. In addition to the requirements and
recommendations of NACE SP0204-2008, the plan's procedures for direct
examination must provide for conducting a minimum of three direct
examinations within the SCC segment at locations determined to be the
most likely for SCC to occur.
    (4) Remediation and mitigation. If any indication of SCC is
discovered in a segment, an operator must mitigate the threat in
accordance with one of the following applicable methods:
    (i) Removing the pipe with SCC, remediating the pipe with a Type B
sleeve, hydrostatic testing in accordance with (b)(4)(ii), below, or by
grinding out the SCC defect and repairing the pipe. If grinding is used
for repair, the repair procedure must include: Nondestructive testing
for any remaining cracks or other defects; measuring remaining wall
thickness; and the remaining strength of the pipe at the repair
location must be determined using ASME/ANSI B31G or RSTRENG and must be
sufficient to meet the design requirements of subpart C of this part.
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) Significant SCC must be mitigated using a hydrostatic testing
program to a minimum test pressure equal to 105 percent of the
specified minimum yield strength of the pipe for 30 minutes immediately
followed by a pressure test in accordance with Sec.  192.506, but not
lower than 1.25 times MAOP. The test pressure for the entire sequence
must be continuously maintained for at least 8 hours, in accordance
with Sec.  192.506 and must be above the minimum test factors in Sec.
192.619(a)(2)(ii) or 192.620(a)(2)(ii), but not lower than 1.25 times
maximum allowable operating pressure. Any test failures due to SCC must
be repaired by replacement of the pipe segment, and the segment re-
tested until the pipe passes the complete test without leakage. Pipe
segments that have SCC present, but that pass the pressure test, may be
repaired by grinding in accordance with paragraph (b)(4)(i) of this
section.
    (5) Post assessment. In addition to the requirements and
recommendations of NACE SP0204-2008, sections 6.3, periodic
reassessment, and 6.4, effectiveness of SCCDA, the operator's
procedures for post assessment must include development of a
reassessment plan based on the susceptibility of the operator's pipe to
SCC as well as on the mechanistic behavior of identified cracking.
Reassessment intervals must comply with Sec.  192.939. Factors that
must be considered include, but are not limited to:
    (i) Evaluation of discovered crack clusters during the direct
examination step in accordance with NACE RP0204-2008, sections <IP_ADDRESS>,
5.4, and 5.5;
    (ii) Conditions conducive to creation of the carbonate-bicarbonate
environment;
    (iii) Conditions in the application (or loss) of CP that can create
or exacerbate SCC;
    (iv) Operating temperature and pressure conditions including
operating stress levels on the pipe;
    (v) Cyclic loading conditions;
    (vi) Mechanistic conditions that influence crack initiation and
growth rates;
    (vii) The effects of interacting crack clusters;
    (viii) The presence of sulfides; and.
    (ix) Disbonded coatings that shield CP from the pipe.
0
44. In Sec.  192.933, paragraphs (a)(1), (b), (d)(1) are revised and
paragraphs (d)(2)(iii) through (vii) are added to read as follows:

Sec.  192.933  What actions must be taken to address integrity issues?

    (a) * * *
    (1) Temporary pressure reduction. If an operator is unable to
respond within the time limits for certain conditions specified in this
section, the operator must temporarily reduce the operating pressure of
the pipeline or take other action that ensures the safety of the
covered segment. An operator must determine any temporary reduction in
operating pressure required by this section using ASME/ANSI B31G
(incorporated by reference, see Sec.  192.7) or AGA Pipeline Research
Council International, PR-3-805 (R-STRENG) (incorporated by reference,
see Sec.  192.7) to determine the safe operating pressure that restores
the safety margin commensurate with the design factor for the Class
Location in which the affected pipeline is located, or reduce the
operating pressure to a level not exceeding 80 percent of the operating
pressure at the time the condition was discovered. 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. An operator must
notify PHMSA in accordance with Sec.  192.949 if it cannot meet the
schedule for evaluation and remediation required under paragraph (c) of
this section and cannot provide safety through temporary reduction in
operating pressure or other action. An operator must also notify a
State pipeline safety authority when either a covered segment is
located in a State where PHMSA has an interstate agent agreement, or an
intrastate covered segment is regulated by that State.
* * * * *
    (b) Discovery of condition. Discovery of a condition occurs when an
operator has adequate information about a condition to determine that
the condition presents a potential threat to the integrity of the
pipeline. For the purposes of this section, a condition that presents a
potential threat includes, but is not limited to, those conditions that
require remediation or monitoring listed under paragraphs (d)(1)
through (3) of this section. An operator must promptly, but no later
than 180 days after conducting an integrity assessment, obtain
sufficient information about a condition to make that determination,
unless the operator demonstrates that the 180-day period is
impracticable. In cases where a determination is not made within the
180-day period the operator must notify OPS, in accordance with Sec.
192.949, and provide an expected date when adequate information will
become available.
* * * * *
    (d) * * *
    (1) Immediate repair conditions. An operator's evaluation and
remediation schedule must follow ASME/ANSI B31.8S, section 7 in
providing for immediate repair conditions. To maintain safety, an
operator must temporarily reduce operating pressure in accordance with
paragraph (a) of this section or shut down the pipeline until the
operator completes the repair of these conditions. An operator must
treat the following conditions as immediate repair conditions:
    (i) 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 for any
class location. Suitable

remaining strength calculation methods include ASME/ANSI B31G
(incorporated by reference, see Sec.  192.7), PRCI PR-3-805 (R-STRENG)
(incorporated by reference, see Sec.  192.7); or an alternative method
of remaining strength calculation that will provide an equally
conservative result. 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) An indication or anomaly that in the judgment of the person
designated by the operator to evaluate the assessment results requires
immediate action.
    (iv) Metal loss greater than 80% of nominal wall regardless of
dimensions.
    (v) An indication of metal-loss affecting a detected longitudinal
seam, if that seam was formed by direct current, low-frequency, or high
frequency electric resistance welding or by electric flash welding.
    (vi) Any indication of significant stress corrosion cracking (SCC).
    (vii) Any indication of significant selective seam weld corrosion
(SSWC).
    (2) * * *.
    (iii) A calculation of the remaining strength of the pipe shows a
predicted failure pressure ratio 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.
    (iv) An area of general 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.
* * * * *
0
45. In Sec.  192.935, paragraphs (a), (b)(2), and (d)(3) are revised
and paragraphs (f) and (g) are added to read as follows:

Sec.  192.935  What additional preventive and mitigative measures must
an operator take?

    (a) General requirements. An operator must take additional measures
beyond those already required by part 192 to prevent a pipeline failure
and to mitigate the consequences of a pipeline failure in a high
consequence area. Such additional measures must be based on the risk
analyses required by Sec.  192.917, and must include, but are not
limited to: Correction of the root causes of past incidents to prevent
recurrence; establishing and implementing adequate operations and
maintenance processes that could increase safety; establishing and
deploying adequate resources for successful execution of preventive and
mitigative measures; installing automatic shut-off valves or remote
control valves; installing pressure transmitters on both sides of
automatic shut-off valves and remote control valves that communicate
with the pipeline control center; installing computerized monitoring
and leak detection systems; replacing pipe segments with pipe of
heavier wall thickness or higher strength; conducting additional right-
of-way patrols; conducting hydrostatic tests in areas where material
has quality issues or lost records; tests to determine material
mechanical and chemical properties for unknown properties that are
needed to assure integrity or substantiate MAOP evaluations including
material property tests from removed pipe that is representative of the
in-service pipeline; re-coating of damaged, poorly performing or
disbonded coatings; applying additional depth-of-cover survey at roads,
streams and rivers; remediating inadequate depth-of-cover; providing
additional training to personnel on response procedures, conducting
drills with local emergency responders; and implementing additional
inspection and maintenance programs.
    (b) * * *
    (2) Outside force damage. If an operator determines that outside
force (e.g., earth movement, loading, longitudinal, or lateral forces,
seismicity of the area, floods, unstable suspension bridge) is a threat
to the integrity of a covered segment, the operator must take measures
to minimize the consequences to the covered segment from outside force
damage. These measures include, but are not limited to, increasing the
frequency of aerial, foot or other methods of patrols, adding external
protection, reducing external stress, relocating the line, or
geospatial, GIS, and deformation in-line inspections.
* * * * *
    (d) * * *
    (3) Perform semi-annual, instrumented leak surveys (quarterly for
unprotected pipelines or cathodically protected pipe where indirect
assessments, i.e. indirect examination tool/method such as close
interval survey, alternating current voltage gradient, direct current
voltage gradient, or equivalent, are impractical).
* * * * *
    (f) Internal corrosion. As an operator gains information about
internal corrosion, it must enhance its internal corrosion management
program, as required under subpart I of this part, with respect to a
covered segment to prevent and minimize the consequences of a release
due to internal corrosion. At a minimum, as part of this enhancement,
operators must--
    (1) Monitor for, and mitigate the presence of, deleterious gas
stream constituents.
    (2) At points where gas with potentially deleterious contaminants
enters the pipeline, use filter separators or separators and continuous
gas quality monitoring equipment.
    (3) At least once per quarter, use gas quality monitoring equipment
that includes, but is not limited to, a moisture analyzer,
chromatograph, carbon dioxide sampling, and hydrogen sulfide sampling.
    (4) Use cleaning pigs and sample accumulated liquids and solids,
including tests for microbiologically induced corrosion.
    (5) Use inhibitors when corrosive gas or corrosive liquids are
present.
    (6) Address potentially corrosive gas stream constituents as
specified in Sec.  192.478(a), where the volumes exceed these amounts
over a 24-hour interval in the pipeline as follows:
    (i) Limit carbon dioxide to three percent by volume;
    (ii) Allow no free water and otherwise limit water to seven pounds
per million cubic feet of gas; and
    (iii) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet
(16 ppm) of gas. If the hydrogen sulfide concentration is greater than
0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging
and inhibitor injection program to address deleterious gas stream
constituents, including follow-up sampling and quality testing of
liquids at receipt points.
    (7) Review the program at least semi-annually based on the gas
stream experience and implement adjustments to monitor for, and
mitigate the presence of, deleterious gas stream constituents.
    (g) External corrosion. As an operator gains information about
external corrosion, it must enhance its external corrosion management
program, as required under subpart I of this part, with respect to a
covered segment to

prevent and minimize the consequences of a release due to external
corrosion. At a minimum, as part of this enhancement, operators must--
    (1) Control electrical interference currents that can adversely
affect cathodic protection as follows:
    (i) As frequently as needed (such as when new or uprated high
voltage alternating current power lines greater than or equal to 69 kVA
or electrical substations are co-located near the pipeline), but not to
exceed every seven years, perform the following:
    (A) Conduct an interference survey (at times when voltages are at
the highest values for a time period of at least 24-hours) to detect
the presence and level of any electrical current that could impact
external corrosion where interference is suspected;
    (B) Analyze the results of the survey to identify locations where
interference currents are greater than or equal to 20 Amps per meter
squared; and
    (C) Take any remedial action needed within six months after
completing the survey to protect the pipeline segment from deleterious
current. Remedial action means the implementation of measures
including, but not limited to, additional grounding along the pipeline
to reduce interference currents. Any location with interference
currents greater than 50 Amps per meter squared must be remediated. If
any AC interference between 20 and 50 Amps per meter squared is not
remediated, the operator must provide and document an engineering
justification.
    (2) Confirm the adequacy of external corrosion control through
indirect assessment as follows:
    (i) Periodically (as frequently as needed but at intervals not to
exceed seven years) assess the adequacy of the cathodic protection
through an indirect method such as close-interval survey, and the
integrity of the coating using direct current voltage gradient (DCVG)
or alternating current voltage gradient (ACVG).
    (ii) Remediate any damaged coating with a voltage drop classified
as moderate or severe (IR drop greater than 35% for DCVG or 50
dB[micro]v for ACVG) under section 4 of NACE RP0502-2008 (incorporated
by reference, see Sec.  192.7).
    (iii) Integrate the results of the indirect assessment required
under paragraph (g)(2)(i) of this section with the results of the most
recent integrity assessment required by this subpart and promptly take
any needed remedial actions no later than 6 months after assessment
finding.
    (iv) Perform periodic assessments as follows:
    (A) Conduct periodic close interval surveys with current
interrupted to confirm voltage drops in association with integrity
assessments under sections Sec. Sec.  192.921 and 192.937 of this
subpart.
    (B) Locate pipe-to-soil test stations at half-mile intervals within
each covered segment, ensuring at least one station is within each high
consequence area, if practicable.
    (C) Integrate the results with those of the baseline and periodic
assessments for integrity done under sections Sec. Sec.  192.921 and
192.937 of this subpart.
    (3) Control external corrosion through cathodic protection as
follows:
    (i) If an annual test station reading indicates cathodic protection
below the level of protection required in subpart I of this part,
complete assessment and remedial action, as required in Sec.
192.465(f), within 6 months of the failed reading or notify each PHMSA
pipeline safety regional office where the pipeline is in service and
demonstrate that the integrity of the pipeline is not compromised if
the repair takes longer than 6 months. An operator must also notify 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; and
    (ii) Remediate insufficient cathodic protection levels or areas
where protective current is found to be leaving the pipeline in
accordance with paragraph (g)(3)(i) of this section, including use of
indirect assessments or direct examination of the coating in areas of
low CP readings unless the reason for the failed reading is determined
to be a short to an adjacent foreign structure, rectifier connection or
power input problem that can be remediated and restoration of adequate
cathodic protection can be verified. The operator must confirm
restoration of adequate corrosion control by a close interval survey on
both sides of the affected test stations to the adjacent test stations.
0
46. In Sec.  192.937, paragraphs (b) and (c) are revised to read as
follows:

Sec.  192.937  What is a continual process of evaluation and assessment
to maintain a pipeline's integrity?

* * * * *
    (b) Evaluation. An operator must conduct a periodic evaluation as
frequently as needed to assure the integrity of each covered segment.
The periodic evaluation must be based on a data integration and risk
assessment of the entire pipeline as specified in Sec.  192.917, which
incorporates an analysis of updated pipeline design, construction,
operation, maintenance, and integrity information. For plastic
transmission pipelines, the periodic evaluation is based on the threat
analysis specified in Sec.  192.917(d). For all other transmission
pipelines, the evaluation must consider the past and present integrity
assessment results, data integration and risk assessment information
(Sec.  192.917), and decisions about remediation (Sec.  192.933). The
evaluation must identify the threats specific to each covered segment,
including interacting threats and the risk represented by these
threats, and identify additional preventive and mitigative measures
(Sec.  192.935) to avert or reduce risks.
    (c) 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). 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,
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
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.
    (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 time dependent threats such as internal corrosion,
external corrosion, and other environmentally assisted corrosion
mechanisms and for manufacturing and related defect threats, including
defective pipe and pipe seams.
    (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). An operator must explicitly consider
uncertainties in in situ direct examination results (including, but not
limited to, tool tolerance, detection threshold, probability of
detection, probability of identification, sizing accuracy, and usage
unity chart plots or equivalent for determining uncertainties and
verifying performance on the type defects being evaluated) in
identifying and characterizing anomalies.
    (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 (c)(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;
    (7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. 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.
    (8) Confirmatory direct assessment when used on a covered segment
that is scheduled for reassessment at a period longer than seven years.
An operator using this reassessment method must comply with Sec.
192.931.
0
47. In Sec.  192.939, the introductory text of paragraph (a) is revised
to read as follows:

Sec.  192.939  What are the required reassessment intervals?

* * * * *
    (a) Pipelines operating at or above 30% SMYS. An operator must
establish a reassessment interval for each covered segment operating at
or above 30% SMYS in accordance with the requirements of this section.
The maximum reassessment interval by an allowable reassessment method
is seven calendar years. Operators may request a six month extension of
the seven-calendar year reassessment interval if the operator submits
written notice to OPS, in accordance with Sec.  192.949, with
sufficient justification of the need for the extension. If an operator
establishes a reassessment interval that is greater than seven calendar
years, the operator must, within the seven-calendar year period,
conduct a confirmatory direct assessment on the covered segment, and
then conduct the follow-up reassessment at the interval the operator
has established. A reassessment carried out using confirmatory direct
assessment must be done in accordance with Sec.  192.931. The table
that follows this section sets forth the maximum allowed reassessment
intervals.
* * * * *
0
48. In Sec.  192.941, paragraphs (b)(1) and the introductory text to
(b)(2) are revised to read as follows:

Sec.  192.941  What is a low stress reassessment?

* * * * *
    (b) * * *
    (1) Cathodically protected pipe. To address the threat of external
corrosion on cathodically protected pipe in a covered segment, 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 covered segment. An operator must use the
results of each indirect assessment as part of an overall evaluation of
the cathodic protection and corrosion threat for the covered segment.
This evaluation must consider, at minimum, the leak repair and
inspection records, corrosion monitoring records, exposed pipe
inspection records, and the pipeline environment.
    (2) Unprotected pipe or cathodically protected pipe where indirect
assessments are impractical. If an indirect assessment is impractical
on the covered segment an operator must--
* * * * *
0
49. Appendix A to part 192 is revised to read as follows:

Appendix A to Part 192--Records Retention Schedule for Transmission
Pipelines

    Appendix A summarizes the part 192 records retention
requirements. As required by Sec.  192.13(e), records must be
readily retrievable and must be reliable, traceable, verifiable, and
complete.

----------------------------------------------------------------------------------------------------------------
                                                                Summary of records
                                                                requirement (Note:
                                                              referenced code section
          Code section                 Section title         specifies  requirements.         Retention time
                                                             This summary provided for
                                                                convenience only.)
----------------------------------------------------------------------------------------------------------------
                                               Subpart A--General
----------------------------------------------------------------------------------------------------------------
Sec.   192.5(d).................  Class locations........  Records that demonstrate how  Life of pipeline.
                                                            an operator determined
                                                            class locations and the
                                                            actual class locations.
Sec.   192.13(e)................  What general             Records that demonstrate      As specified in this
                                   requirements apply to    compliance with this part.    appendix.
                                   pipelines regulated      At a minimum, operators
                                   under this part?.        must prepare and maintain
                                                            the records specified in
                                                            appendix A to part 192.

Sec.   192.14(b)................  Conversion to service    Records of investigations,    Life of pipeline.
                                   subject to this part.    tests, repairs,
                                                            replacements, and
                                                            alterations made under the
                                                            requirements of Sec.
                                                            192.14(a).
Sec.   192.16(d)................  Customer notification..  Records of a copy of the      3 years.
                                                            notice currently in use and
                                                            evidence that notices have
                                                            been sent to customers.
----------------------------------------------------------------------------------------------------------------
                                              Subpart B--Materials
----------------------------------------------------------------------------------------------------------------
Sec.   192.67...................  Records: Materials and   Records for steel pipe        Life of pipeline.
                                   pipe.                    manufacturing tests,
                                                            inspections, and attributes.
----------------------------------------------------------------------------------------------------------------
                                             Subpart C--Pipe Design
----------------------------------------------------------------------------------------------------------------
Sec.   192.112..................  Additional design        Records for alternative MAOP  Life of pipeline.
                                   requirements for steel   demonstrating compliance
                                   pipe using alternative   with this section.
                                   maximum allowable
                                   operating pressure.
Sec.   192.127..................  Records: Pipe Design     Design records for external   Life of pipeline.
                                   for External Loads and   loads and internal pressure.
                                   Internal Pressures.
----------------------------------------------------------------------------------------------------------------
                                    Subpart D--Design of Pipeline Components
----------------------------------------------------------------------------------------------------------------
Sec.   192.144..................  Qualifying metallic      Records indicating            Life of pipeline.
                                   components.              manufacturer and pressure
                                                            ratings of metallic
                                                            components.
Sec.   192.150..................  Passage of internal      Records of each new           Life of pipeline.
                                   inspection devices.      transmission line
                                                            replacement of pipe,
                                                            valves, fittings, or other
                                                            line component showing that
                                                            the replacement is
                                                            constructed to accommodate
                                                            internal inspection devices
                                                            as required by Sec.
                                                            192.150.
Sec.   192.153..................  Components fabricated    Records of strength tests...  Life of pipeline.
                                   by welding.
Sec.   192.205..................  Records: Pipeline        Records documenting the       Life of pipeline.
                                   components.              manufacturing standard,
                                                            tests, and pressure rating
                                                            to which valves, flanges,
                                                            fittings, branch
                                                            connections, extruded
                                                            outlets, anchor forgings,
                                                            tap connections, and other
                                                            components were
                                                            manufactured and tested in
                                                            accordance with this
                                                            subpart.
----------------------------------------------------------------------------------------------------------------
                                    Subpart E--Welding of Steel in Pipelines
----------------------------------------------------------------------------------------------------------------
Sec.   192.225(b)...............  Welding procedures.....  Records of welding            Life of pipeline.
                                                            procedures, including
                                                            results of qualifying
                                                            procedure tests.
Sec.   192.227(c)...............  Qualification of         Records demonstrating welder  Life of pipeline.
                                   welders and welding      qualification.
                                   operators.
Sec.   192.243(f)...............  Nondestructive testing.  Records showing by milepost,  Life of pipeline.
                                                            engineering station, or by
                                                            geographic feature, the
                                                            number of girth welds made,
                                                            the number nondestructively
                                                            tested, the number
                                                            rejected, and the
                                                            disposition of the rejects.
----------------------------------------------------------------------------------------------------------------
                              Subpart F--Joining of Materials Other Than by Welding
----------------------------------------------------------------------------------------------------------------
Sec.   192.283..................  Plastic pipe:            Records of joining            Life of pipeline.
                                   Qualifying joining       procedures, including
                                   procedures.              results of qualifying
                                                            procedure tests.
Sec.   192.285(e)...............  Plastic pipe:            Records demonstrating         Life of pipeline.
                                   Qualifying persons to    plastic pipe joining
                                   make joints.             qualifications.
----------------------------------------------------------------------------------------------------------------
                  Subpart G--General Construction Requirements for Transmission Lines and Mains
----------------------------------------------------------------------------------------------------------------
Sec.   192.303..................  Compliance with          Records of written            Life of pipeline.
                                   specifications or        specifications or standards
                                   standards.               that apply to each
                                                            transmission line or main.
Sec.   192.305..................  Inspection: General....  Transmission line or main     Life of pipeline.
                                                            inspections.
Sec.   192.307..................  Inspection of materials  Pipe and component materials  Life of pipeline.
                                                            inspections.
Sec.   192.319(d)...............  Installation of pipe in  Records documenting the       Life of pipeline.
                                   a ditch.                 coating assessment findings
                                                            and repairs.
Sec.   192.328..................  Additional construction  Records for alternative MAOP  Life of pipeline.
                                   requirements for steel   demonstrating compliance
                                   pipe using alternative   with this section
                                   maximum allowable        including: quality
                                   operating pressure.      assurance, girth weld non-
                                                            destructive examinations,
                                                            depth of cover, initial
                                                            strength testing (pressure
                                                            tests and root cause
                                                            analysis of failed pipe),
                                                            and impacts of interference
                                                            currents.
----------------------------------------------------------------------------------------------------------------

                        Subpart H--Customer Meters, Service Regulators, and Service Lines
----------------------------------------------------------------------------------------------------------------
Sec.   192.383..................  Excess flow valve        Number of excess flow valves  Life of pipeline.
                                   installation.            installed, as reported as
                                                            part of annual report.
----------------------------------------------------------------------------------------------------------------
                                  Subpart I--Requirements for Corrosion Control
----------------------------------------------------------------------------------------------------------------
Sec.   192.452(a)...............  How does this subpart    Records demonstrating         Life of pipeline.
                                   apply to converted       compliance by the
                                   pipelines and            applicable deadlines.
                                   regulated onshore
                                   gathering lines?.
Sec.   192.459..................  Exposed buried pipe      Records of examinations for   Life of pipeline.
                                   inspection.              evidence of external
                                                            corrosion whenever any
                                                            portion of a buried
                                                            pipeline is exposed.
Sec.   192.461..................  External corrosion       Records of protective         Life of pipeline.
                                   control: Protective      coating type, coating
                                   coating.                 installation and
                                                            procedures, surveys, and
                                                            remediation of coating
                                                            defects.
Sec.   192.465(a)...............  External corrosion       Records of pipe to soil       Life of pipeline.
                                   control: Monitoring.     measurements.
Sec.   192.465(b)...............  External corrosion       Records of rectifier          5 years.
                                   control: Monitoring--    inspections.
                                   rectifiers.
Sec.   192.465(c)...............  External corrosion       Records of inspections of     5 years.
                                   control: Monitoring--    each reverse current
                                   stray current/           switch, each diode, and
                                   interference             each interference bond
                                   mitigation and           whose failure would
                                   critical interference    jeopardize structure
                                   bonds.                   protection.
Sec.   192.465(e)...............  External corrosion       Records of re-evaluation of   Life of pipeline.
                                   control: Monitoring--    cathodically unprotected
                                   active corrosion zones.  pipelines.
Sec.   192.467(d)...............  External corrosion       Records of inspection and     Life of pipeline.
                                   control: Electrical      electrical tests made to
                                   isolation.               assure that electrical
                                                            isolation is adequate.
Sec.   192.473..................  External corrosion       Records of surveys,           Life of pipeline.
                                   control: Interference    analysis, and remediation
                                   currents.                of interference currents.
Sec.   192.475..................  Internal pipe            Records demonstrating         Life of pipeline.
                                   inspection.              whenever any pipe is
                                                            removed from a pipeline for
                                                            any reason, the internal
                                                            surface was inspected for
                                                            evidence of corrosion.
Sec.   192.476(d)...............  Internal corrosion       Records demonstrating         Life of pipeline.
                                   control: Design and      compliance with this
                                   construction of          section.
                                   transmission line.
Sec.   192.477..................  Coupons or other means   Records demonstrating the     Life of pipeline.
                                   for monitoring           effectiveness of each
                                   internal corrosion.      coupon or other means of
                                                            monitoring procedures used
                                                            to minimize internal
                                                            corrosion.
Sec.   192.478..................  Internal corrosion       Records demonstrating         Life of pipeline.
                                   control: Onshore         compliance with this
                                   transmission             section for internal
                                   monitoring and           monitoring and mitigation
                                   mitigation.              program.
Sec.   192.478(b)(3)............  Gas and Liquid Samples.  Records showing evaluation    Life of pipeline.
                                                            twice each calendar year of
                                                            gas stream and liquid
                                                            quality samples.
Sec.   192.481(a)...............  Atmospheric corrosion    Records of inspection of      5 years.
                                   control: Monitoring.     each pipeline or portion of
                                                            pipeline that is exposed to
                                                            the atmosphere for evidence
                                                            of atmospheric corrosion.
Sec.   192.485(c)...............  Remedial measures:       Pipe and material properties  Life of pipeline.
                                   Transmission lines.      used in remaining strength
                                                            calculations and remaining
                                                            strength calculations must
                                                            be documented in reliable,
                                                            traceable, verifiable, and
                                                            complete records.
Sec.   192.491(a) and (b).......  Corrosion control        Records or maps showing the   Life of pipeline.
                                   records.                 location of cathodically
                                                            protected piping, cathodic
                                                            protection facilities,
                                                            galvanic anodes, and
                                                            neighboring structures
                                                            bonded to the cathodic
                                                            protection system.
Sec.   192.491(c)...............  Corrosion control        Records of each test,         5 years.
                                   records.                 survey, or inspection
                                                            required by subpart I in
                                                            sufficient detail to
                                                            demonstrate the adequacy of
                                                            corrosion control measures
                                                            or that a corrosive
                                                            condition does not exist.
                                                           Records related to Sec.       Life of pipeline.
                                                            Sec.   192.465(a) and (e)
                                                            and 192.475(b) must be
                                                            retained for as long as the
                                                            pipeline remains in service.
----------------------------------------------------------------------------------------------------------------
                                          Subpart J--Test Requirements
----------------------------------------------------------------------------------------------------------------
Sec.   192.517(a)...............  Records................  Records of each test          Life of pipeline.
                                                            performed under Sec.  Sec.
                                                             192.505, 192.506, and
                                                            192.507.
Sec.   192.517(b)...............  Records................  Records of each test          5 years.
                                                            required by Sec.  Sec.
                                                            192.509, 192.511, and
                                                            192.513.
----------------------------------------------------------------------------------------------------------------

                                               Subpart K--Uprating
----------------------------------------------------------------------------------------------------------------
Sec.   192.553(b)...............  General requirements...  Records of each               Life of pipeline.
                                                            investigation required by
                                                            subpart K, of all work
                                                            performed, and of each
                                                            pressure test conducted, in
                                                            connection with uprating of
                                                            a segment of pipeline.
----------------------------------------------------------------------------------------------------------------
                                              Subpart L--Operations
----------------------------------------------------------------------------------------------------------------
Sec.   192.603(b)...............  General provisions.....  Records necessary to          Life of pipeline.
                                                            administer the procedures
                                                            established under Sec.
                                                            192.605 for operations,
                                                            maintenance, and
                                                            emergencies including class
                                                            location and changes in
                                                            Sec.  Sec.   192.5,
                                                            192.609, and 192.611.
Sec.   192.605..................  Procedural manual for    Records for O&M Manual--      5 years.
                                   operations,              review and update once per
                                   maintenance, and         calendar year, not to
                                   emergencies.             exceed 15 months.
Sec.   192.605..................  Procedural manual for    Records for Emergency Plan--  5 years.
                                   operations,              review and update once per
                                   maintenance, and         calendar year, not to
                                   emergencies.             exceed 15 months.
Sec.   192.605..................  Procedural manual for    Records for Operator          5 years.
                                   operations,              Qualification Plan--review
                                   maintenance, and         and update once per
                                   emergencies.             calendar year, not to
                                                            exceed 15 months.
Sec.   192.605(b)(12)...........  Procedural manual for    Records for Control Room      5 years.
                                   operations,              Management (CRM)--review
                                   maintenance, and         and update once per
                                   emergencies.             calendar year, not to
                                                            exceed 15 months.
Sec.   192.605(c)...............  Procedural manual for    For gas transmission          Life of pipeline.
                                   operations,              operators, a record of the
                                   maintenance, and         abnormal operations.
                                   emergencies.
Sec.   192.607(c)...............  Verification of          Traceable, verifiable, and    Life of pipeline.
                                   Pipeline Material:       complete records that
                                   Onshore steel            demonstrate and
                                   transmission pipelines.  authenticate data and
                                                            information regarding the
                                                            properties outlined in Sec.
                                                              192.607(c)(1) through (4).
Sec.   192.609..................  Change in class          Records for class location    Life of pipeline.
                                   location: Required       studies required by this
                                   study.                   section.
Sec.   192.611..................  Change in class          Records for revisions of      Life of pipeline.
                                   location: Confirmation   maximum allowable operating
                                   or revision of maximum   pressure due to class
                                   allowable operating      location changes to confirm
                                   pressure.                to Sec.   192.611.
Sec.   192.612..................  Underwater inspection    Records of Underwater         5 years.
                                   and reburial of          inspection in Gulf of
                                   pipelines in the Gulf    Mexico--periodic, as
                                   of Mexico and its        indicated in operators O&M
                                   inlets.                  Manual.
Sec.   192.613(a)...............  Continuing surveillance  Records of continuing         5 years.
                                                            surveillance findings.
Sec.   192.613(b)...............  Continuing surveillance  Records of remedial actions.  Life of pipeline.
Sec.   192.613(c)(1)............  Continuing surveillance  Records of inspections        5 years.
                                                            performed following extreme
                                                            events.
Sec.   192.613(c)(3)............  Continuing surveillance  Records of remedial actions.  Life of pipeline.
Sec.   192.614..................  Damage prevention        Damage Prevention/One Call    5 years (or as
                                   program.                 records.                      indicated by state one
                                                                                call, whichever is
                                                                                longer).
Sec.   192.614..................  Damage prevention        Records of Damage Prevention  5 years.
                                   program.                 meetings with Emergency
                                                            Responder/Public Officials.
Sec.   192.615..................  Emergency plans........  Records of training.........  5 years.
Sec.   192.615..................  Emergency plans........  Records of each review that   5 years.
                                                            procedures were effectively
                                                            followed after each
                                                            emergency.
Sec.   192.616..................  Public awareness.......  Records showing Public        5 years.
                                                            Education Activities.
Sec.   192.617..................  Investigation of         Procedures for analyzing      Life of pipeline.
                                   failures.                accidents and failures as
                                                            described in Sec.   192.617
                                                            to determine the causes of
                                                            the failure and minimizing
                                                            the possibility of a
                                                            recurrence. Records of
                                                            accident/failure reports.
Sec.   192.619..................  Maximum allowable        Traceable, verifiable, and    Life of pipeline.
                                   operating pressure:      complete records that
                                   Steel or plastic         demonstrate and
                                   pipelines.               authenticate data and
                                                            information regarding the
                                                            maximum allowable operating
                                                            pressures outlined in Sec.
                                                             192.619(a) through (d).
Sec.   192.620(c)(7)............  Alternative maximum      Records demonstrating         Life of pipeline.
                                   allowable operating      compliance with paragraphs
                                   pressure for certain     Sec.   192.620(b), (c)(6),
                                   steel pipelines.         and (d).
Sec.   192.624(f)...............  Maximum allowable        Reliable, traceable,          Life of pipeline.
                                   operating pressure       verifiable, and complete
                                   verification: Onshore    records of the
                                   steel transmission       investigations, tests,
                                   pipelines.               analyses, assessments,
                                                            repairs, replacements,
                                                            alterations, and other
                                                            actions made under the
                                                            requirements of Sec.
                                                            192.624.
Sec.   192.625..................  Odorization of gas.....  Records of Odorometer         5 years.
                                                            Readings--periodic, as
                                                            indicated in operators O&M
                                                            Manual.

Sec.   192.631(a)...............  Control room management  Records of control room       Life of pipeline.
                                                            management procedures that
                                                            implement the requirements
                                                            of this section.
Sec.   192.631(j)...............  Control room management  (1) Records that demonstrate  1 year, or the last 2
                                                            compliance with the           periodic tests or
                                                            requirements of this          validations, whichever
                                                            section; and.                 is longer.
                                                           (2) Documentation to
                                                            demonstrate that any
                                                            deviation from the
                                                            procedures required by this
                                                            section was necessary for
                                                            the safe operation of a
                                                            pipeline facility.
----------------------------------------------------------------------------------------------------------------
                                             Subpart M--Maintenance
----------------------------------------------------------------------------------------------------------------
Sec.   192.703(c)...............  General................  Records of hazardous and non- Life of pipeline.
                                                            hazardous leaks.
Sec.   192.705..................  Transmission lines:      Records of periodic right-of- 5 years.
                                   Patrolling.              way patrols--frequency
                                                            dependent on class location.
Sec.   192.706..................  Transmission lines:      Records of periodic leakage   5 years.
                                   Leakage surveys.         surveys--frequency
                                                            dependent on class location.
Sec.   192.709(a)...............  Transmission lines:      Records for the date,         Life of pipeline.
                                   Record keeping.          location, and description
                                                            of each repair made to pipe
                                                            (including pipe-to-pipe
                                                            connections).
Sec.   192.709(b) and (c).......  Transmission lines:      (b) Records of the date,      5 years.*
                                   Record keeping.          location, and description
                                                            of each repair made to
                                                            parts of the pipeline
                                                            system other than pipe must
                                                            be retained for at least 5
                                                            years.
                                                           (c) A record of each patrol,  .......................
                                                            survey, inspection, test,
                                                            and repair required by
                                                            subparts L and M of this
                                                            part must be retained for
                                                            at least 5 years or until
                                                            the next patrol, survey,
                                                            inspection, or test is
                                                            completed, whichever is
                                                            longer.*
Sec.   192.710..................  Pipeline assessments...  Records of pipeline           Life of pipeline.
                                                            assessments in class 3 or
                                                            class 4 locations and
                                                            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'').
Sec.   192.713(c)...............  Transmission lines:      Records of each repair made   Life of pipeline.
                                   Permanent field repair   to transmission lines must
                                   of imperfections and     be documented.
                                   damages.
Sec.   192.713(d)...............  Transmission lines:      Repair and remediation        Life of pipeline.
                                   Permanent field repair   schedules, pressure
                                   of imperfections and     reductions and remaining
                                   damages.                 strength calculations must
                                                            be documented.
Sec.   192.731..................  Compressor stations:     Records of inspections and    5 years.
                                   Inspection and testing   tests of pressure relieving
                                   of relief devices.       and other remote control
                                                            shutdown devices.
Sec.   192.736..................  Compressor stations:     Records of inspections and    5 years.
                                   Gas detection.           tests of gas detection
                                                            systems--periodic, as
                                                            indicated in operators O&M
                                                            Manual.
Sec.   192.739..................  Pressure limiting and    Records of inspections and    5 years.
                                   regulating stations:     tests of pressure relief
                                   Inspection and testing.  devices and pressure
                                                            regulating stations and
                                                            equipment.
Sec.   192.743..................  Pressure limiting and    Records of capacity           5 years.
                                   regulating stations:     calculations or
                                   Capacity of relief       verifications for pressure
                                   devices.                 relief devices (except
                                                            rupture discs).
Sec.   192.745..................  Valve maintenance:       Records of inspections of     5 years.
                                   Transmission lines.      emergency valves.
Sec.   192.749..................  Vault maintenance......  Records of inspections of     5 years.
                                                            vaults containing pressure
                                                            regulating or pressure
                                                            limiting equipment.
----------------------------------------------------------------------------------------------------------------
                                 Subpart N--Qualification of Pipeline Personnel
----------------------------------------------------------------------------------------------------------------
Sec.   192.807..................  Operator qualification   Records that demonstrate      5 years.**
                                   recordkeeping.           compliance with subpart N
                                                            of this part Records
                                                            supporting an individual's
                                                            current qualification shall
                                                            be maintained while the
                                                            individual is performing
                                                            the covered task.**
                                                           Records of prior
                                                            qualification and records
                                                            of individuals no longer
                                                            performing covered tasks
                                                            shall be retained for a
                                                            period of five years..
----------------------------------------------------------------------------------------------------------------
                                Subpart O--Gas Transmission Integrity Management
----------------------------------------------------------------------------------------------------------------
Sec.   192.947..................  Integrity management...  Records that demonstrate      Life of pipeline.
                                                            compliance with all of the
                                                            requirements of subpart O
                                                            of this part.
----------------------------------------------------------------------------------------------------------------

0
50. Appendix D to part 192 is revised to read as follows:

Appendix D to Part 192--Criteria for Cathodic Protection and
Determination of Measurements

    I. Criteria for cathodic protection--
    A. Steel, cast iron, and ductile iron structures.
    (1) A negative (cathodic) voltage across the structure
electrolyte boundary of at least 0.85 volt, with reference to a
saturated copper-copper sulfate reference electrode, often referred
to as a half cell. Determination of this voltage must be made in
accordance with sections II and IV of this appendix.
    (2) A minimum negative (cathodic) polarization voltage shift of
100 millivolts. This polarization voltage shift must be determined
in accordance with sections III and IV of this appendix.
    B. Aluminum structures.
    (1) Except as provided in paragraphs B(2) and (3) of this
section, a minimum negative (cathodic) polarization voltage shift of
100 millivolts. This polarization voltage shift must be determined
in accordance with sections III and IV of this appendix.
    (2) Notwithstanding the minimum criteria in paragraph B(1) of
this section, if aluminum is cathodically protected at voltages in
excess of 1.20 volts as measured with reference to a copper-copper
sulfate reference electrode, in accordance with section II of this
appendix, the aluminum may suffer corrosion resulting from the
build-up of alkali on the metal surface. A voltage in excess of 1.20
volts may not be used unless previous test results indicate no
appreciable corrosion will occur in the particular environment.
    (3) Since aluminum may suffer from corrosion under high pH
conditions, and since application of cathodic protection tends to
increase the pH at the metal surface, careful investigation or
testing must be made before applying cathodic protection to stop
pitting attack on aluminum structures in environments with a natural
pH in excess of 8.
    C. Copper structures. A minimum negative (cathodic) polarization
voltage shift of 100 millivolts. This polarization voltage shift
must be determined in accordance with sections III and IV of this
appendix.
    D. Metals of different anodic potentials. A negative (cathodic)
voltage, measured in accordance with section IV of this appendix,
equal to that required for the most anodic metal in the system must
be maintained. If amphoteric structures are involved that could be
damaged by high alkalinity covered by paragraphs B(2) and (3) of
this section, they must be electrically isolated with insulating
flanges, or the equivalent.
    II. Interpretation of voltage measurement. Structure-to-
electrolyte potential measurements must be made utilizing
measurement techniques that will minimize voltage (IR) drops other
than those across the structure electrolyte boundary. All voltage
(IR) drops other than those across the structure electrolyte
boundary will be differentiated, such that the resulting measurement
accurately reflects the structure-to-electrolyte potential.
    III. Determination of polarization voltage shift. The
polarization voltage shift must be determined by interrupting the
protective current and measuring the polarization decay. When the
current is initially interrupted, an immediate voltage shift occurs
often referred to as an instant off potential. The voltage reading
after the immediate shift must be used as the base reading from
which to measure polarization decay in paragraphs A(2), B(1), and C
of section I of this appendix.
    IV. Reference electrodes (half cells).
    A. Except as provided in paragraphs B and C of this section,
negative (cathodic) voltage must be measured between the structure
surface and a saturated copper-copper sulfate reference electrode
contacting the electrolyte.
    B. Other standard reference electrodes may be substituted for
the saturated copper-copper sulfate electrode. Two commonly used
reference electrodes are listed below along with their voltage
equivalent to -0.85 volt as referred to a saturated copper-copper
sulfate reference electrode:
    (1) Saturated KCL calomel half cell:-0.78 volt.
    (2) Silver-silver chloride reference electrode used in sea
water: -0.80 volt.
    C. In addition to the standard reference electrode, an alternate
metallic material or structure may be used in place of the saturated
copper-copper sulfate reference electrode if its potential stability
is assured and if its voltage equivalent referred to a saturated
copper-copper sulfate reference electrode is established.

0
51. In appendix E, Tables E.II.1 and E.II.3 are revised to read as
follows:

Appendix E to Part 192--Guidance on Determining High Consequence Areas
and on Carrying out Requirements in the Integrity Management Rule

* * * * *

II. Guidance on Assessment Methods and Additional Preventive and
Mitigative Measures for Transmission Pipelines

* * * * *

 Table E.II.1--Preventive and Mitigative Measures for Transmission Pipelines Operating Below 30% SMYS not in an
                                    HCA but in a Class 3 or Class 4 Location
----------------------------------------------------------------------------------------------------------------
                                             Existing part 192 requirements           (Column 4)  Additional (to
                                    ------------------------------------------------    part 192 requirements)
         (Column 1) Threat                                                            preventive and mitigative
                                       (Column 2)  Primary    (Column 3)  Secondary            measures
----------------------------------------------------------------------------------------------------------------
External Corrosion.................  455--(Gen. Post 1971),  603--(Gen Operation)..  For Cathodically Protected
                                      457--(Gen. Pre--1971).                          Transmission Pipeline:
                                     459--(Examination),     613--(Surveillance)...   Perform semi-
                                      461--(Ext. coating).                            annual leak surveys.
                                     463--(CP), 465--        ......................  For Unprotected
                                      (Monitoring).                                   Transmission Pipelines or
                                                                                for Cathodically Protected
                                                                                Pipe where indirect
                                                                                assessments (i.e.,
                                                                                indirect examination tool/
                                                                                method such as close
                                                                                interval survey,
                                                                                alternating current
                                                                                voltage gradient, direct
                                                                                current voltage gradient,
                                                                                or equivalent) are
                                                                                impractical:
                                     467--(Elect
                                      isolation), 469--Test
                                      stations).
                                     471--(Test leads),
                                      473--(Interference).
                                     479--(Atmospheric),
                                      481--(Atmospheric).
                                     485--(Remedial), 705--
                                      (Patrol).
                                     706-- (Leak survey),
                                      711--(Repair--gen.).
                                     717--(Repair--perm.)..  ......................   Perform quarterly
                                                                                leak surveys.
Internal Corrosion.................  475--(Gen IC), 477--    53(a)--(Materials)....  Perform semi-annual leak
                                      (IC monitoring).                                surveys.

                                     485--(Remedial), 705--  603--(Gen Oper'n).....
                                      (Patrol).
                                     706--(Leak survey),     613--(Surveillance)...
                                      711 (Repair--gen.).
                                     717--(Repair--perm.)..
3rd Party Damage...................  103--(Gen. Design),     ......................   Participation in
                                      111--(Design factor).                           state one-call system.
                                     317--(Hazard prot),     615--(Emerg. Plan)....   Use of qualified
                                      327--(Cover).                                   operator employees and
                                                                                contractors to perform
                                                                                marking and locating of
                                                                                buried structures and in
                                                                                direct supervision of
                                                                                excavation work.
                                     614--(Dam. Prevent),    ......................  AND
                                      616--(Public
                                      education).
                                     705--(Patrol), 707--                             Either monitoring
                                      (Line markers).                                 of excavations near
                                                                                operator's transmission
                                                                                pipelines in class 3 and 4
                                                                                locations. Any indications
                                                                                of unreported construction
                                                                                activity would require a
                                                                                follow up investigation to
                                                                                determine if mechanical
                                                                                damage occurred.
                                     711--(Repair--gen.),
                                      717--(Repair--perm.).
----------------------------------------------------------------------------------------------------------------

* * * * *

     Table E.II.3--Preventive and Mitigative Measures Addressing Time Dependent and Independent Threats for
                           Transmission Pipelines That Operate Below 30% SMYS, in HCAs
----------------------------------------------------------------------------------------------------------------
                                           Existing part 192 requirements             Additional (to part 192
              Threat               ----------------------------------------------  requirements)  preventive and
                                           Primary               Secondary              mitigative measures
----------------------------------------------------------------------------------------------------------------
External Corrosion................  455--(Gen. Post 1971)  .....................  For Cathodically Protected
                                                                                Transmission Pipelines
                                    457--(Gen. Pre-1971).  .....................   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 7
                                                                                years. Results are to be
                                                                                utilized as part of an
                                                                                overall evaluation of the CP
                                                                                system and corrosion threat
                                                                                for the covered segment.
                                                                                Evaluation shall include
                                                                                consideration of leak repair
                                                                                and inspection records,
                                                                                corrosion monitoring records,
                                                                                exposed pipe inspection
                                                                                records, and the pipeline
                                                                                environment.
                                    459--(Examination)...
                                    461--(Ext. coating)..
                                    463--(CP)............
                                    465--(Monitoring)....  603--(Gen. Operation)
                                    467--(Elect            613--(Surveillance)..
                                     isolation).
                                    469--(Test stations).
                                    471--(Test leads)....  .....................  For Unprotected Transmission.
                                                                                Pipelines or for Cathodically
                                                                                Protected Pipe where Indirect
                                                                                Assessments are Impracticable
                                    473--(Interference)..
                                    479--(Atmospheric)...  .....................   Conduct quarterly
                                                                                leak surveys AND
                                    481--(Atmospheric)...  .....................   Every 1\1/2\ years,
                                                                                determine areas of active
                                                                                corrosion by evaluation of
                                                                                leak repair and inspection
                                                                                records, corrosion monitoring
                                                                                records, exposed pipe
                                                                                inspection records, and the
                                                                                pipeline environment.
                                    485--(Remedial)......
                                    705--(Patrol)........
                                    706--(Leak survey)...
                                    711--(Repair--gen.)..
                                    717--(Repair--perm.).
Internal Corrosion................  475--(Gen. IC).......  .....................   Obtain and review gas
                                                                                analysis data each calendar
                                                                                year for corrosive agents
                                                                                from transmission pipelines
                                                                                in HCA,
                                    477--(IC monitoring).  .....................   Periodic testing of
                                                                                fluid removed from pipelines.
                                                                                Specifically, once each year
                                                                                from each storage field that
                                                                                may affect transmission
                                                                                pipelines in HCA, AND
                                    485--(Remedial)......  53(a)--(Materials)...   At least every 7
                                                                                years, integrate data
                                                                                obtained with applicable
                                                                                internal corrosion leak
                                                                                records, incident reports,
                                                                                safety related condition
                                                                                reports, repair records,
                                                                                patrol records, exposed pipe
                                                                                reports, and test records.
                                    705--(Patrol)........  603--(Gen. Oper.)....
                                    706--(Leak survey)...  613--(Surveil.)......
                                    711--(Repair--gen.)..

                                    717--(Repair--perm.).
3rd Party Damage..................  103--(Gen. Design)...  615-- (Emerg. Plan)..   Participation in
                                                                                state one-call system,
                                    111--(Design factor).  .....................   Use of qualified
                                                                                operator employees and
                                                                                contractors to perform
                                                                                marking and locating of
                                                                                buried structures and in
                                                                                direct supervision of
                                                                                excavation work, AND
                                    317--(Hazard prot.)..  .....................   Either monitoring of
                                                                                excavations near operator's
                                                                                transmission pipelines, or bi-
                                                                                monthly patrol of
                                                                                transmission pipelines in
                                                                                HCAs or class 3 and 4
                                                                                locations. Any indications of
                                                                                unreported construction
                                                                                activity would require a
                                                                                follow up investigation to
                                                                                determine if mechanical
                                                                                damage occurred.
                                    327--(Cover).........
                                    614--(Dam. Prevent)..
                                    616--(Public educat.)
                                    705--(Patrol)........
                                    707--(Line markers)..
                                    711--(Repair--gen.)..
                                    717--(Repair--perm.).
----------------------------------------------------------------------------------------------------------------

0
52. Appendix F to part 192 is added to read as follows:

Appendix F to Part 192--Criteria for Conducting Integrity Assessments
Using Guided Wave Ultrasonic Testing (GWUT)

    This appendix defines criteria which must be properly
implemented for use of Guided Wave Ultrasonic Testing (GWUT) as an
integrity assessment method. Any application of GWUT that does not
conform to these criteria is considered ``other technology'' as
described by Sec. Sec.  192.710(c)(7), 192.921(a)(7), and
192.937(c)(7), for which OPS must be notified 180 days prior to use
in accordance with Sec.  192.921(a)(7) or 192.937(c)(7). GWUT in the
``Go-No Go'' mode means that all indications (wall loss anomalies)
above the testing threshold (a maximum of 5% of cross sectional area
(CSA) sensitivity) be directly examined, in-line tool inspected,
pressure tested or replaced prior to completing the integrity
assessment on the cased carrier pipe.
    I. Equipment and software: Generation. The equipment and the
computer software used are critical to the success of the
inspection. Guided Ultrasonics LTD (GUL) Wavemaker G3 or G4 with
software version 3 or higher, or equipment and software with
equivalent capabilities and sensitivities, must be used.
    II. Inspection range. The inspection range and sensitivity are
set by the signal to noise (S/N) ratio but must still keep the
maximum threshold sensitivity at 5% cross sectional area (CSA). A
signal that has an amplitude that is at least twice the noise level
can be reliably interpreted. The greater the S/N ratio the easier it
is to identify and interpret signals from small changes. The signal
to noise ratio is dependent on several variables such as surface
roughness, coating, coating condition, associated pipe fittings
(T's, elbows, flanges), soil compaction, and environment. Each of
these affects the propagation of sound waves and influences the
range of the test. It may be necessary to inspect from both ends of
the pipeline segment to achieve a full inspection. In general the
inspection range can approach 60 to 100 feet for a 5% CSA, depending
on field conditions.
    III. Complete pipe inspection. To ensure that the entire
pipeline segment is assessed there should be at least a 2 to 1
signal to noise ratio across the entire pipeline segment that is
inspected. This may require multiple GWUT shots. Double ended
inspections are expected. These two inspections are to be overlaid
to show the minimum 2 to 1 S/N ratio is met in the middle. If
possible, show the same near or midpoint feature from both sides and
show an approximate 5% distance overlap.
    IV. Sensitivity.
    A. The detection sensitivity threshold determines the ability to
identify a cross sectional change. The maximum threshold sensitivity
cannot be greater than 5% of the cross sectional area (CSA).
    B. The locations and estimated CSA of all metal loss features in
excess of the detection threshold must be determined and documented.
    C. All defect indications in the ``Go-No Go'' mode above the 5%
testing threshold must be directly examined, in-line inspected,
pressure tested, or replaced prior to completing the integrity
assessment.
    V. Wave frequency. Because a single wave frequency may not
detect certain defects, a minimum of three frequencies must be run
for each inspection to determine the best frequency for
characterizing indications. The frequencies used for the inspections
must be documented and must be in the range specified by the
manufacturer of the equipment.
    VI. Signal or wave type: Torsional and longitudinal. Both
torsional and longitudinal waves must be used and use must be
documented.
    VII. Distance amplitude correction (DAC) curve and weld
calibration.
    A. The Distance Amplitude Correction curve accounts for coating,
pipe diameter, pipe wall and environmental conditions at the
assessment location. The DAC curve must be set for each inspection
as part of establishing the effective range of a GWUT inspection.
    B. DAC curves provide a means for evaluating the cross sectional
area change of reflections at various distances in the test range by
assessing signal to noise ratio. A DAC curve is a means of taking
apparent attenuation into account along the time base of a test
signal. It is a line of equal sensitivity along the trace which
allows the amplitudes of signals at different axial distances from
the collar to be compared.
    VIII. Dead zone. The dead zone is the area adjacent to the
collar in which the transmitted signal blinds the received signal,
making it impossible to obtain reliable results. Because the entire
line must be inspected, inspection procedures must account for the
dead zone by requiring the movement of the collar for additional
inspections. An alternate method of obtaining valid readings in the
dead zone is to use B-scan ultrasonic equipment and visual
examination of the external surface. The length of the dead zone and
the near field for each inspection must be documented.
    IX. Near field effects. The near field is the region beyond the
dead zone where the receiving amplifiers are increasing in power,
before the wave is properly established. Because the entire line
must be inspected, inspection procedures must account for the near
field by requiring the movement of the collar for additional
inspections. An alternate method of obtaining valid readings in the
near field is to use B-scan ultrasonic equipment and visual
examination of the external surface. The length of the dead zone and
the near field for each inspection must be documented.
    X. Coating type.
    A. Coatings can have the effect of attenuating the signal. Their
thickness and condition are the primary factors that affect the rate
of signal attenuation. Due to their variability, coatings make it
difficult to predict the effective inspection distance.
    B. Several coating types may affect the GWUT results to the
point that they may reduce the expected inspection distance. For

example, concrete coated pipe may be problematic when well bonded
due to the attenuation effects. If an inspection is done and the
required sensitivity is not achieved for the entire length of the
cased pipe, then another type of assessment method must be utilized.
    XI. End seal. Operators must remove the end seal from the casing
at each GWUT test location to facilitate visual inspection.
Operators must remove debris and water from the casing at the end
seals. Any corrosion material observed must be removed, collected
and reviewed by the operator's corrosion technician. The end seal
does not interfere with the accuracy of the GWUT inspection but may
have a dampening effect on the range.
    XII. Weld calibration to set DAC curve. Accessible welds, along
or outside the pipe segment to be inspected, must be used to set the
DAC curve. A weld or welds in the access hole (secondary area) may
be used if welds along the pipe segment are not accessible. In order
to use these welds in the secondary area, sufficient distance must
be allowed to account for the dead zone and near field. There must
not be a weld between the transducer collar and the calibration
weld. A conservative estimate of the predicted amplitude for the
weld is 25% CSA (cross sectional area) and can be used if welds are
not accessible. Calibrations (setting of the DAC curve) should be on
pipe with similar properties such as wall thickness and coating. If
the actual weld cap height is different from the assumed weld cap
height, the estimated CSA may be inaccurate and adjustments to the
DAC curve may be required. Alternative means of calibration can be
used if justified by sound engineering analysis and evaluation.
    XIII. Validation of operator training.
    A. There is no industry standard for qualifying GWUT service
providers. Pipeline operators must require all guided wave service
providers to have equipment-specific training and experience for all
GWUT equipment operators which includes training for:
    (1) Equipment operation;
    (2) Field data collection; and
    (3) Data interpretation on cased and buried pipe.
    B. Only individuals who have been qualified by the manufacturer
or an independently assessed evaluation procedure similar to ISO
9712 (Sections: 5 Responsibilities; 6 Levels of Qualification; 7
Eligibility; and 10 Certification), as specified above, may operate
the equipment.
    C. A Senior level GWUT equipment operator with pipeline specific
experience must provide onsite oversight of the inspection and
approve the final reports. A senior level GWUT equipment operator
must have additional training and experience, including but not
limited to training specific to cased and buried pipe, with a
quality control program which conforms to section 12 of ASME B31.8S.
    D. Training and experience minimums for senior level GWUT
equipment operators:
    (1) Equipment Manufacturer's minimum qualification for equipment
operation and data collection with specific endorsements for casings
and buried pipe
    (2) Training, qualification and experience in testing procedures
and frequency determination
    (3) Training, qualification and experience in conversion of
guided wave data into pipe features and estimated metal loss
(estimated cross-sectional area loss and circumferential extent)
    (4) Equipment Manufacturer's minimum qualification with specific
endorsements for data interpretation of anomaly features for pipe
within casings and buried pipe.
    XIV. Equipment: Traceable from vendor to inspection company. The
operator must maintain documentation of the version of the GWUT
software used and the serial number of the other equipment such as
collars, cables, etc., in the report.
    XV. Calibration onsite. The GWUT equipment must be calibrated
for performance in accordance with the manufacturer's requirements
and specifications, including the frequency of calibrations. A
diagnostic check and system check must be performed on-site each
time the equipment is relocated. If on-site diagnostics show a
discrepancy with the manufacturer's requirements and specifications,
testing must cease until the equipment can be restored to
manufacturer's specifications.
    XVI. Use on shorted casings (direct or electrolytic). GWUT may
not be used to assess shorted casings. GWUT operators must have
operations and maintenance procedures (see Sec.  192.605) to address
the effect of shorted casings on the GWUT signal. The equipment
operator must clear any evidence of interference, other than some
slight dampening of the GWUT signal from the shorted casing,
according to their operating and maintenance procedures. All shorted
casings found while conducting GWUT inspections must be addressed by
the operator's standard operating procedures.
    XVII. Direct examination of all indications above the detection
sensitivity threshold.
    The use of GWUT in the ``Go-No Go'' mode requires that all
indications (wall loss anomalies) above the testing threshold (5% of
CSA sensitivity) be directly examined (or replaced) prior to
completing the integrity assessment on the cased carrier pipe. If
this cannot be accomplished then alternative methods of assessment
(such as hydrostatic pressure tests or ILI) must be utilized.
    XVIII. Timing of direct examination of all indications above the
detection sensitivity threshold. Operators must either replace or
conduct direct examinations of all indications identified above the
detection sensitivity threshold according to the table below.
Operators must conduct leak surveys and reduce operating pressure as
specified until the pipe is replaced or direct examinations are
completed.

----------------------------------------------------------------------------------------------------------------
                                      Required response to GWUT indications
-----------------------------------------------------------------------------------------------------------------
                                      Operating pressure   Operating pressure over 30
          GWUT Criterion            less than or equal to   and less than or equal to   Operating pressure over
                                           30% SMYS                 50% SMYS                    50% SMYS
----------------------------------------------------------------------------------------------------------------
Over the detection sensitivity      Replace or direct      Replace or direct           Replace or direct
 threshold (maximum of 5% CSA).      examination within     examination within 6        examination within 6
                                     12 months, and         months, instrumented leak   months, instrumented
                                     instrumented leak      survey once every 30        leak survey once every
                                     survey once every 30   calendar days, and          30 calendar days, and
                                     calendar days.         maintain MAOP below the     reduce MAOP to 80% of
                                                            operating pressure at       operating pressure at
                                                            time of discovery.          time of discovery.
----------------------------------------------------------------------------------------------------------------

    Issued in Washington, DC, on March 17, 2016, under authority
delegated in 49 CFR part 1.97(a).
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. 2016-06382 Filed 4-7-16; 8:45 am]
 BILLING CODE 4910-60-P