section must reconfirm its MAOP using one of the following methods:
    (1) Method 1: Pressure test. Perform a pressure test and verify
material properties records in accordance with Sec.  192.607 and the
following requirements:
    (i) Pressure test. Perform a pressure test in accordance with
subpart J of this part. The MAOP must be equal to the test pressure
divided by the greater of either 1.25 or the applicable class location
factor in Sec.  192.619(a)(2)(ii).
    (ii) Material properties records. Determine if the following
material properties records are documented in traceable, verifiable,
and complete records: Diameter, wall thickness, seam type, and grade
(minimum yield strength, ultimate tensile strength).
    (iii) Material properties verification. If any of the records
required by paragraph (c)(1)(ii) of this section are not documented in
traceable, verifiable, and complete records, the operator must obtain
the missing records in accordance with Sec.  192.607. An operator must
test the pipe materials cut out from the test manifold sites at the
time the pressure test is conducted. If there is a failure during the
pressure test, the operator must test any removed pipe from the
pressure test failure in accordance with Sec.  192.607.
    (2) Method 2: Pressure Reduction. Reduce pressure, as necessary,
and limit MAOP to no greater than the highest actual operating pressure
sustained by the pipeline during the 5 years preceding October 1, 2019,
divided by the greater of 1.25 or the applicable class location factor
in Sec.  192.619(a)(2)(ii). The highest actual sustained pressure must
have been reached for a minimum cumulative duration of 8 hours during a
continuous 30-day period. The value used as the highest actual
sustained operating pressure must account for differences between
upstream and downstream pressure on the pipeline by use of either the
lowest maximum pressure value for the entire pipeline segment or using
the operating pressure gradient along the entire pipeline segment
(i.e., the location-specific operating pressure at each location).
    (i) Where the pipeline segment has had a class location change in
accordance with Sec.  192.611, and records documenting diameter, wall
thickness, seam type, grade (minimum yield strength and ultimate
tensile strength), and pressure tests are not documented in traceable,
verifiable, and complete records, the operator must reduce the pipeline
segment MAOP as follows:
    (A) For pipeline segments where a class location changed from Class
1 to Class 2, from Class 2 to Class 3, or from Class 3 to Class 4,
reduce the pipeline MAOP to no greater than the highest actual
operating pressure sustained by the pipeline during the 5 years
preceding October 1, 2019, divided by 1.39 for Class 1 to Class 2, 1.67
for Class 2 to Class 3, and 2.00 for Class 3 to Class 4.
    (B) For pipeline segments where a class location changed from Class
1 to Class 3, reduce the pipeline MAOP to no greater than the highest
actual operating pressure sustained by the pipeline during the 5 years
preceding October 1, 2019, divided by 2.00.
    (ii) Future uprating of the pipeline segment in accordance with
subpart K is allowed if the MAOP is established using Method 2.
    (iii) If an operator elects to use Method 2, but desires to use a
less conservative pressure reduction factor or longer look-back period,
the operator must notify PHMSA in accordance with Sec.  192.18 no later
than 7 calendar days after establishing the reduced MAOP. The
notification must include the following details:
    (A) Descriptions of the operational constraints, special
circumstances, or other factors that preclude, or make it impractical,
to use the pressure reduction factor specified in Sec.  192.624(c)(2);
    (B) The fracture mechanics modeling for failure stress pressures
and cyclic fatigue crack growth analysis that complies with Sec.
192.712;
    (C) Justification that establishing MAOP by another method allowed
by this section is impractical;
    (D) Justification that the reduced MAOP determined by the operator
is safe based on analysis of the condition of the pipeline segment,
including material properties records, material properties verified in
accordance Sec.  192.607, and the history of the pipeline segment,
particularly known corrosion and leakage, and the actual operating
pressure, and additional compensatory preventive and mitigative
measures taken or planned; and
    (E) Planned duration for operating at the requested MAOP, long-term
remediation measures and justification of this operating time interval,
including fracture mechanics modeling for failure stress pressures and
cyclic fatigue growth analysis and other validated forms of engineering
analysis that have been reviewed and confirmed by subject matter
experts.
    (3) Method 3: Engineering Critical Assessment (ECA). Conduct an ECA
in accordance with Sec.  192.632.
    (4) Method 4: Pipe Replacement. Replace the pipeline segment in
accordance with this part.
    (5) Method 5: Pressure Reduction for Pipeline Segments with Small
Potential Impact Radius. Pipelines with a potential impact radius (PIR)
less than or equal to 150 feet may establish the MAOP as follows:
    (i) Reduce the MAOP to no greater than the highest actual operating
pressure sustained by the pipeline during 5 years preceding October 1,
2019, divided by 1.1. The highest actual sustained pressure must have
been reached for a minimum cumulative duration of 8 hours during one
continuous 30-day period. The reduced MAOP must account for differences
between discharge and upstream pressure on the pipeline by use of
either the lowest value for the entire pipeline segment or the
operating pressure gradient (i.e., the location specific operating
pressure at each location);
    (ii) Conduct patrols in accordance with Sec.  192.705 paragraphs
(a) and (c) and conduct instrumented leakage surveys in accordance with
Sec.  192.706 at intervals not to exceed those in the following table 1
to Sec.  192.624(c)(5)(ii):

                   Table 1 to Sec.   192.624(c)(5)(ii)
------------------------------------------------------------------------
       Class locations               Patrols           Leakage surveys
------------------------------------------------------------------------
(A) Class 1 and Class 2.....  3 \1/2\ months, but   3 \1/2\ months, but
                               at least four times   at least four times
                               each calendar year.   each calendar year.
(B) Class 3 and Class 4.....  3 months, but at      3 months, but at
                               least six times       least six times
                               each calendar year.   each calendar year.
------------------------------------------------------------------------

    (iii) Under Method 5, future uprating of the pipeline segment in
accordance with subpart K is allowed.
    (6) Method 6: Alternative Technology. Operators may use an
alternative technical evaluation process that provides a documented
engineering analysis for establishing MAOP. If an operator elects to
use alternative technology, the operator must notify PHMSA in advance
in accordance with Sec.  192.18. The notification must include
descriptions of the following details:
    (i) The technology or technologies to be used for tests,
examinations, and assessments; the method for establishing material
properties; and analytical techniques with similar analysis from prior
tool runs done to ensure the results are consistent with the required
corresponding hydrostatic test pressure for the pipeline segment being
evaluated;
    (ii) Procedures and processes to conduct tests, examinations,
assessments and evaluations, analyze defects and flaws, and remediate
defects discovered;
    (iii) Pipeline segment data, including original design, maintenance
and operating history, anomaly or flaw characterization;
    (iv) Assessment techniques and acceptance criteria, including
anomaly detection confidence level, probability of detection, and
uncertainty of the predicted failure pressure quantified as a fraction
of specified minimum yield strength;
    (v) If any pipeline segment contains cracking or may be susceptible
to cracking or crack-like defects found through or identified by
assessments, leaks, failures, manufacturing vintage histories, or any
other available information about the pipeline, the operator must
estimate the remaining life of the pipeline in accordance with
paragraph Sec.  192.712;
    (vi) Operational monitoring procedures;
    (vii) Methodology and criteria used to justify and establish the
MAOP; and
    (vii) Documentation of the operator's process and procedures used
to implement the use of the alternative technology, including any
records generated through its use.
    (d) Records. An operator must retain records of investigations,
tests, analyses, assessments, repairs, replacements, alterations, and
other actions taken in accordance with the requirements of this section
for the life of the pipeline.

0
23. Section 192.632 is added to read as follows:

Sec.  192.632   Engineering Critical Assessment for Maximum Allowable
Operating Pressure Reconfirmation: Onshore steel transmission
pipelines.

    When an operator conducts an MAOP reconfirmation in accordance with
Sec.  192.624(c)(3) ``Method 3'' using an ECA to establish the material
strength and MAOP of the pipeline segment, the ECA must comply with the
requirements of this section. The ECA must assess: Threats; loadings
and operational circumstances relevant to those threats, including
along the pipeline right-of way; outcomes of the threat assessment;
relevant mechanical and fracture properties; in-service degradation or
failure processes; and initial and final defect size relevance. The ECA
must quantify the interacting effects of threats on any defect in the
pipeline.
    (a) ECA Analysis. (1) The material properties required to perform
an ECA analysis in accordance with this paragraph are as follows:
Diameter, wall thickness, seam type, grade (minimum yield strength and
ultimate tensile strength), and Charpy v-notch toughness values based
upon the lowest operational temperatures, if applicable. If any
material properties required to perform an ECA for any pipeline segment
in accordance with this paragraph are not documented in traceable,
verifiable and complete records, an operator must use conservative
assumptions and include the pipeline segment in its program to verify
the undocumented information in accordance with Sec.  192.607. The ECA
must integrate, analyze, and account for the material properties, the
results of all tests, direct examinations, destructive tests, and
assessments performed in accordance with this section, along with other
pertinent information related to pipeline integrity, including close
interval surveys, coating surveys, interference surveys required by
subpart I of this part, cause analyses of prior incidents, prior
pressure test leaks and failures, other leaks, pipe inspections, and
prior integrity assessments, including those required by Sec. Sec.
192.617, 192.710, and subpart O of this part.
    (2) The ECA must analyze and determine the predicted failure
pressure for the defect being assessed using procedures that implement
the appropriate failure criteria and justification as follows:
    (i) The ECA must analyze any cracks or crack-like defects remaining
in the pipe, or that could remain in the pipe, to determine the
predicted failure pressure of each defect in accordance with Sec.
192.712.
    (ii) The ECA must analyze any metal loss defects not associated
with a dent, including corrosion, gouges, scrapes or other metal loss
defects that could remain in the pipe, to determine the predicted
failure pressure. ASME/ANSI B31G (incorporated by reference, see Sec.
192.7) or R-STRENG (incorporated by reference, see Sec.  192.7) must be
used for corrosion defects. Both procedures and their analysis apply to
corroded regions that do not penetrate the pipe wall over 80 percent of
the wall thickness and are subject to the limitations prescribed in the
equations' procedures. The ECA must use conservative assumptions for
metal loss dimensions (length, width, and depth).
    (iii) When determining the predicted failure pressure for gouges,
scrapes, selective seam weld corrosion, crack-related defects, or any
defect within a dent, appropriate failure criteria and justification of
the criteria must be used and documented.
    (iv) If SMYS or actual material yield and ultimate tensile strength
is not known or not documented by traceable, verifiable, and complete
records, then the operator must assume 30,000 p.s.i. or determine the
material properties using Sec.  192.607.
    (3) The ECA must analyze the interaction of defects to
conservatively determine the most limiting predicted failure pressure.
Examples include, but are not limited to, cracks in or near locations
with corrosion metal loss, dents with gouges or other metal loss, or
cracks in or near dents or other deformation damage. The ECA must
document all evaluations and any assumptions used in the ECA process.
    (4) The MAOP must be established at the lowest predicted failure
pressure for any known or postulated defect, or interacting defects,
remaining in the pipe divided by the greater of 1.25 or the applicable
factor listed in Sec.  192.619(a)(2)(ii).
    (b) Assessment to determine defects remaining in the pipe. An
operator must utilize previous pressure tests or develop and implement
an assessment program to determine the size of defects remaining in the
pipe to be analyzed in accordance with paragraph (a) of this section.
    (1) An operator may use a previous pressure test that complied with
subpart J to determine the defects remaining in the pipe if records for
a pressure test meeting the requirements of subpart J of this part
exist for the pipeline segment. The operator must calculate the largest
defect that could have survived the pressure test. The operator must
predict how much the defects have grown since the date of the pressure
test in

accordance with Sec.  192.712. The ECA must analyze the predicted size
of the largest defect that could have survived the pressure test that
could remain in the pipe at the time the ECA is performed. The operator
must calculate the remaining life of the most severe defects that could
have survived the pressure test and establish a re-assessment interval
in accordance with the methodology in Sec.  192.712.
    (2) Operators may use an inline inspection program in accordance
with paragraph (c) of this section.
    (3) Operators may use ``other technology'' if it is validated by a
subject matter expert to produce an equivalent understanding of the
condition of the pipe equal to or greater than pressure testing or an
inline inspection program. If an operator elects to use ``other
technology'' in the ECA, it must notify PHMSA in advance of using the
other technology in accordance with Sec.  192.18. The ``other
technology'' notification must have:
    (i) Descriptions of the technology or technologies to be used for
all tests, examinations, and assessments, including characterization of
defect size used in the crack assessments (length, depth, and
volumetric); and
    (ii) Procedures and processes to conduct tests, examinations,
assessments and evaluations, analyze defects, and remediate defects
discovered.
    (c) In-line inspection. An inline inspection (ILI) program to
determine the defects remaining the pipe for the ECA analysis must be
performed using tools that can detect wall loss, deformation from
dents, wrinkle bends, ovalities, expansion, seam defects, including
cracking and selective seam weld corrosion, longitudinal,
circumferential and girth weld cracks, hard spot cracking, and stress
corrosion cracking.
    (1) If a pipeline has segments that might be susceptible to hard
spots based on assessment, leak, failure, manufacturing vintage
history, or other information, then the ILI program must include a tool
that can detect hard spots.
    (2) If the pipeline has had a reportable incident, as defined in
Sec.  191.3, attributed to a girth weld failure since its most recent
pressure test, then the ILI program must include a tool that can detect
girth weld defects unless the ECA analysis performed in accordance with
this section includes an engineering evaluation program to analyze and
account for the susceptibility of girth weld failure due to lateral
stresses.
    (3) Inline inspection must be performed in accordance with Sec.
192.493.
    (4) An operator must use unity plots or equivalent methodologies to
validate the performance of the ILI tools in identifying and sizing
actionable manufacturing and construction related anomalies. Enough
data points must be used to validate tool performance at the same or
better statistical confidence level provided in the tool
specifications. The operator must have a process for identifying
defects outside the tool performance specifications and following up
with the ILI vendor to conduct additional in-field examinations,
reanalyze ILI data, or both.
    (5) Interpretation and evaluation of assessment results must meet
the requirements of Sec. Sec.  192.710, 192.713, and subpart O of this
part, and must conservatively account for the accuracy and reliability
of ILI, in-the-ditch examination methods and tools, and any other
assessment and examination results used to determine the actual sizes
of cracks, metal loss, deformation and other defect dimensions by
applying the most conservative limit of the tool tolerance
specification. ILI and in-the-ditch examination tools and procedures
for crack assessments (length and depth) must have performance and
evaluation standards confirmed for accuracy through confirmation tests
for the defect types and pipe material vintage being evaluated.
Inaccuracies must be accounted for in the procedures for evaluations
and fracture mechanics models for predicted failure pressure
determinations.
    (6) Anomalies detected by ILI assessments must be remediated in
accordance with applicable criteria in Sec. Sec.  192.713 and 192.933.
    (d) Defect remaining life. If any pipeline segment contains
cracking or may be susceptible to cracking or crack-like defects found
through or identified by assessments, leaks, failures, manufacturing
vintage histories, or any other available information about the
pipeline, the operator must estimate the remaining life of the pipeline
in accordance with Sec.  192.712.
    (e) Records. An operator must retain records of investigations,
tests, analyses, assessments, repairs, replacements, alterations, and
other actions taken in accordance with the requirements of this section
for the life of the pipeline.

0
24. Section 192.710 is added to read as follows:

Sec.  192.710   Transmission lines: Assessments outside of high
consequence areas.

    (a) Applicability: This section applies to onshore steel
transmission pipeline segments with a maximum allowable operating
pressure of greater than or equal to 30% of the specified minimum yield
strength and are located in:
    (1) A Class 3 or Class 4 location; or
    (2) A moderate consequence area as defined in Sec.  192.3, if the
pipeline segment can accommodate inspection by means of an instrumented
inline inspection tool (i.e., ``smart pig'').
    (3) This section does not apply to a pipeline segment located in a
high consequence area as defined in Sec.  192.903.
    (b) General--(1) Initial assessment. An operator must perform
initial assessments in accordance with this section based on a risk-
based prioritization schedule and complete initial assessment for all
applicable pipeline segments no later than July 3, 2034, or as soon as
practicable but not to exceed 10 years after the pipeline segment first
meets the conditions of Sec.  192.710(a) (e.g., due to a change in
class location or the area becomes a moderate consequence area),
whichever is later.
    (2) Periodic reassessment. An operator must perform periodic
reassessments at least once every 10 years, with intervals not to
exceed 126 months, or a shorter reassessment interval based upon the
type of anomaly, operational, material, and environmental conditions
found on the pipeline segment, or as necessary to ensure public safety.
    (3) Prior assessment. An operator may use a prior assessment
conducted before July 1, 2020 as an initial assessment for the pipeline
segment, if the assessment met the subpart O requirements of part 192
for in-line inspection at the time of the assessment. If an operator
uses this prior assessment as its initial assessment, the operator must
reassess the pipeline segment according to the reassessment interval
specified in paragraph (b)(2) of this section calculated from the date
of the prior assessment.
    (4) MAOP verification. An integrity assessment conducted in
accordance with the requirements of Sec.  192.624(c) for establishing
MAOP may be used as an initial assessment or reassessment under this
section.
    (c) Assessment method. The initial assessments and the
reassessments required by paragraph (b) of this section must be capable
of identifying anomalies and defects associated with each of the
threats to which the pipeline segment is susceptible and must be
performed using one or more of the following methods:
    (1) Internal inspection. Internal inspection tool or tools capable
of detecting those threats to which the

pipeline is susceptible, such as corrosion, deformation and mechanical
damage (e.g., dents, gouges and grooves), material cracking and crack-
like defects (e.g., stress corrosion cracking, selective seam weld
corrosion, environmentally assisted cracking, and girth weld cracks),
hard spots with cracking, and any other threats to which the covered
segment is susceptible. When performing an assessment using an in-line
inspection tool, an operator must comply with Sec.  192.493;
    (2) Pressure test. Pressure test conducted in accordance with
subpart J of this part. The use of subpart J pressure testing is
appropriate for threats such as internal corrosion, external corrosion,
and other environmentally assisted corrosion mechanisms; manufacturing
and related defect threats, including defective pipe and pipe seams;
and stress corrosion cracking, selective seam weld corrosion, dents and
other forms of mechanical damage;
    (3) Spike hydrostatic pressure test. A spike hydrostatic pressure
test conducted in accordance with Sec.  192.506. A spike hydrostatic
pressure test is appropriate for time-dependent 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) Direct examination. 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
applicable threats. Based upon the threat assessed, examples of
appropriate non-destructive examination methods include ultrasonic
testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave
Field Extrapolation (IWEX), radiography, and magnetic particle
inspection (MPI);
    (5) Guided Wave Ultrasonic Testing. Guided Wave Ultrasonic Testing
(GWUT) as described in Appendix F;
    (6) Direct assessment. Direct assessment to address threats of
external corrosion, internal corrosion, and stress corrosion cracking.
The use of use of direct assessment to address threats of external
corrosion, internal corrosion, and stress corrosion cracking is allowed
only if appropriate for the threat and pipeline segment being assessed.
Use of direct assessment for threats other than the threat for which
the direct assessment method is suitable is not allowed. An operator
must conduct the direct assessment in accordance with the requirements
listed in Sec.  192.923 and with the applicable requirements specified
in Sec. Sec.  192.925, 192.927 and 192.929; or
    (7) Other technology. Other technology that an operator
demonstrates can provide an equivalent understanding of the condition
of the line pipe for each of the threats to which the pipeline is
susceptible. An operator must notify PHMSA in advance of using the
other technology in accordance with Sec.  192.18.
    (d) Data analysis. An operator must analyze and account for the
data obtained from an assessment performed under paragraph (c) of this
section to determine if a condition could adversely affect the safe
operation of the pipeline using personnel qualified by knowledge,
training, and experience. In addition, when analyzing inline inspection
data, an operator must account for uncertainties in reported results
(e.g., tool tolerance, detection threshold, probability of detection,
probability of identification, sizing accuracy, conservative anomaly
interaction criteria, location accuracy, anomaly findings, and unity
chart plots or equivalent for determining uncertainties and verifying
actual tool performance) in identifying and characterizing anomalies.
    (e) 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. 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 180 days is impracticable.
    (f) Remediation. An operator must comply with the requirements in
Sec. Sec.  192.485, 192.711, and 192.713, where applicable, if a
condition that could adversely affect the safe operation of a pipeline
is discovered.
    (g) Analysis of information. An operator must analyze and account
for all available relevant information about a pipeline in complying
with the requirements in paragraphs (a) through (f) of this section.

0
25. Section 192.712 is added to read as follows:

Sec.  192.712   Analysis of predicted failure pressure.

    (a) Applicability. Whenever required by this part, operators of
onshore steel transmission pipelines must analyze anomalies or defects
to determine the predicted failure pressure at the location of the
anomaly or defect, and the remaining life of the pipeline segment at
the location of the anomaly or defect, in accordance with this section.
    (b) Corrosion metal loss. When analyzing corrosion metal loss under
this section, an operator must use a suitable remaining strength
calculation method including, ASME/ANSI B31G (incorporated by
reference, see Sec.  192.7); R-STRENG (incorporated by reference, see
Sec.  192.7); or an alternative equivalent method of remaining strength
calculation that will provide an equally conservative result.
    (c) [Reserved]
    (d) Cracks and crack-like defects--(1) Crack analysis models. When
analyzing cracks and crack-like defects under this section, an operator
must determine predicted failure pressure, failure stress pressure, and
crack growth using a technically proven fracture mechanics model
appropriate to the failure mode (ductile, brittle or both), material
properties (pipe and weld properties), and boundary condition used
(pressure test, ILI, or other).
    (2) Analysis for crack growth and remaining life. If the pipeline
segment is susceptible to cyclic fatigue or other loading conditions
that could lead to fatigue crack growth, fatigue analysis must be
performed using an applicable fatigue crack growth law (for example,
Paris Law) or other technically appropriate engineering methodology.
For other degradation processes that can cause crack growth,
appropriate engineering analysis must be used. The above methodologies
must be validated by a subject matter expert to determine conservative
predictions of flaw growth and remaining life at the maximum allowable
operating pressure. The operator must calculate the remaining life of
the pipeline by determining the amount of time required for the crack
to grow to a size that would fail at maximum allowable operating
pressure.
    (i) When calculating crack size that would fail at MAOP, and the
material toughness is not documented in traceable, verifiable, and
complete records, the same Charpy v-notch toughness value established
in paragraph (e)(2) of this section must be used.
    (ii) Initial and final flaw size must be determined using a
fracture mechanics model appropriate to the failure mode (ductile,
brittle or both) and boundary condition used (pressure test, ILI, or
other).
    (iii) An operator must re-evaluate the remaining life of the
pipeline before 50% of the remaining life calculated by this analysis
has expired. The operator must determine and document if further
pressure tests or use of other assessment

methods are required at that time. The operator must continue to re-
evaluate the remaining life of the pipeline before 50% of the remaining
life calculated in the most recent evaluation has expired.
    (3) Cracks that survive pressure testing. For cases in which the
operator does not have in-line inspection crack anomaly data and is
analyzing potential crack defects that could have survived a pressure
test, the operator must calculate the largest potential crack defect
sizes using the methods in paragraph (d)(1) of this section. If pipe
material toughness is not documented in traceable, verifiable, and
complete records, the operator must use one of the following for Charpy
v-notch toughness values based upon minimum operational temperature and
equivalent to a full-size specimen value:
    (i) Charpy v-notch toughness values from comparable pipe with known
properties of the same vintage and from the same steel and pipe
manufacturer;
    (ii) A conservative Charpy v-notch toughness value to determine the
toughness based upon the material properties verification process
specified in Sec.  192.607;
    (iii) A full size equivalent Charpy v-notch upper-shelf toughness
level of 120 ft.-lbs.; or
    (iv) Other appropriate values that an operator demonstrates can
provide conservative Charpy v-notch toughness values of the crack-
related conditions of the pipeline segment. Operators using an assumed
Charpy v-notch toughness value must notify PHMSA in accordance with
Sec.  192.18.
    (e) Data. In performing the analyses of predicted or assumed
anomalies or defects in accordance with this section, an operator must
use data as follows.
    (1) An operator must explicitly analyze and account for
uncertainties in reported assessment results (including 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 the type and dimensions
of anomalies or defects used in the analyses, unless the defect
dimensions have been verified using in situ direct measurements.
    (2) The analyses performed in accordance with this section must
utilize pipe and material properties that are documented in traceable,
verifiable, and complete records. If documented data required for any
analysis is not available, an operator must obtain the undocumented
data through Sec.  192.607. Until documented material properties are
available, the operator shall use conservative assumptions as follows:
    (i) Material toughness. An operator must use one of the following
for material toughness:
    (A) Charpy v-notch toughness values from comparable pipe with known
properties of the same vintage and from the same steel and pipe
manufacturer;
    (B) A conservative Charpy v-notch toughness value to determine the
toughness based upon the ongoing material properties verification
process specified in Sec.  192.607;
    (C) If the pipeline segment does not have a history of reportable
incidents caused by cracking or crack-like defects, maximum Charpy v-
notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-
lbs. for cold weld, lack of fusion, and selective seam weld corrosion
defects;
    (D) If the pipeline segment has a history of reportable incidents
caused by cracking or crack-like defects, maximum Charpy v-notch
toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-lbs. for
cold weld, lack of fusion, and selective seam weld corrosion; or
    (E) Other appropriate values that an operator demonstrates can
provide conservative Charpy v-notch toughness values of crack-related
conditions of the pipeline segment. Operators using an assumed Charpy
v-notch toughness value must notify PHMSA in advance in accordance with
Sec.  192.18 and include in the notification the bases for
demonstrating that the Charpy v-notch toughness values proposed are
appropriate and conservative for use in analysis of crack-related
conditions.
    (ii) Material strength. An operator must assume one of the
following for material strength:
    (A) Grade A pipe (30,000 psi), or
    (B) The specified minimum yield strength that is the basis for the
current maximum allowable operating pressure.
    (iii) Pipe dimensions and other data. Until pipe wall thickness,
diameter, or other data are determined and documented in accordance
with Sec.  192.607, the operator must use values upon which the current
MAOP is based.
    (f) Review. Analyses conducted in accordance with this section must
be reviewed and confirmed by a subject matter expert.
    (g) Records. An operator must keep for the life of the pipeline
records of the investigations, analyses, and other actions taken in
accordance with the requirements of this section. Records must document
justifications, deviations, and determinations made for the following,
as applicable:
    (1) The technical approach used for the analysis;
    (2) All data used and analyzed;
    (3) Pipe and weld properties;
    (4) Procedures used;
    (5) Evaluation methodology used;
    (6) Models used;
    (7) Direct in situ examination data;
    (8) In-line inspection tool run information evaluated, including
any multiple in-line inspection tool runs;
    (9) Pressure test data and results;
    (10) In-the-ditch assessments;
    (11) All measurement tool, assessment, and evaluation accuracy
specifications and tolerances used in technical and operational
results;
    (12) All finite element analysis results;
    (13) The number of pressure cycles to failure, the equivalent
number of annual pressure cycles, and the pressure cycle counting
method;
    (14) The predicted fatigue life and predicted failure pressure from
the required fatigue life models and fracture mechanics evaluation
methods;
    (15) Safety factors used for fatigue life and/or predicted failure
pressure calculations;
    (16) Reassessment time interval and safety factors;
    (17) The date of the review;
    (18) Confirmation of the results by qualified technical subject
matter experts; and
    (19) Approval by responsible operator management personnel.

0
26. Section 192.750 is added to read as follows:

Sec.  192.750  Launcher and receiver safety.

    Any launcher or receiver used after July 1, 2021, must be equipped
with a device capable of safely relieving pressure in the barrel before
removal or opening of the launcher or receiver barrel closure or flange
and insertion or removal of in-line inspection tools, scrapers, or
spheres. An operator must use a device to either: Indicate that
pressure has been relieved in the barrel; or alternatively prevent
opening of the barrel closure or flange when pressurized, or insertion
or removal of in-line devices (e.g. inspection tools, scrapers, or
spheres), if pressure has not been relieved.

0
27. In Sec.  192.805, paragraph (i) is revised to read as follows:

Sec.  192.805  Qualification Program.

* * * * *
    (i) After December 16, 2004, notify the Administrator or a state
agency participating under 49 U.S.C. Chapter 601 if an operator
significantly modifies the program after the administrator or state
agency has verified that it complies

with this section. Notifications to PHMSA must be submitted in
accordance with Sec.  192.18.

0
28. In Sec.  192.909, paragraph (b) is revised to read as follows:

Sec.  192.909  How can an operator change its integrity management
program?

* * * * *
    (b) Notification. An operator must notify OPS, in accordance with
Sec.  192.18, of any change to the program that may substantially
affect the program's implementation or may significantly modify the
program or schedule for carrying out the program elements. An operator
must provide notification within 30 days after adopting this type of
change into its program.

0
29. In Sec.  192.917, paragraphs (a)(3) and (e)(2) through (4) are
revised, and paragraph (e)(6) is added to read as follows:

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

    (a) * * *
    (3) Time independent threats such as third party damage, mechanical
damage, incorrect operational procedure, weather related and outside
force damage to include consideration of seismicity, geology, and soil
stability of the area; and
* * * * *
    (e) * * *
    (2) Cyclic fatigue. An operator must analyze and account for
whether cyclic fatigue or other loading conditions (including ground
movement, and suspension bridge condition) could lead to a failure of a
deformation, including a dent or gouge, crack, or other defect in the
covered segment. The analysis must assume the presence of threats in
the covered segment that could be exacerbated by cyclic fatigue. An
operator must use the results from the analysis together with the
criteria used to determine the significance of the threat(s) to the
covered segment to prioritize the integrity baseline assessment or
reassessment. Failure stress pressure and crack growth analysis of
cracks and crack-like defects must be conducted in accordance with
Sec.  192.712. An operator must monitor operating pressure cycles and
periodically, but at least every 7 calendar years, with intervals not
to exceed 90 months, determine if the cyclic fatigue analysis remains
valid or if the cyclic fatigue analysis must be revised based on
changes to operating pressure cycles or other loading conditions.
    (3) Manufacturing and construction defects. An operator must
analyze the covered segment to determine and account for the risk of
failure from manufacturing and construction defects (including seam
defects) in the covered segment. The analysis must account for the
results of prior assessments on the covered segment. An operator may
consider manufacturing and construction related defects to be stable
defects only if the covered segment has been subjected to hydrostatic
pressure testing satisfying the criteria of subpart J of at least 1.25
times MAOP, and the covered segment has not experienced a reportable
incident attributed to a manufacturing or construction defect since the
date of the most recent subpart J pressure test. If any of the
following changes occur in the covered segment, an operator must
prioritize the covered segment as a high-risk segment for the baseline
assessment or a subsequent reassessment.
    (i) The pipeline segment has experienced a reportable incident, as
defined in Sec.  191.3, since its most recent successful subpart J
pressure test, due to an original manufacturing-related defect, or a
construction-, installation-, or fabrication-related defect;
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.
    (4) Electric Resistance Welded (ERW) pipe. If a covered pipeline
segment contains low frequency ERW pipe, lap welded pipe, pipe with
longitudinal joint factor less than 1.0 as defined in Sec.  192.113, or
other pipe that satisfies the conditions specified in ASME/ANSI B31.8S,
Appendices A4.3 and A4.4, and any covered or non-covered segment in the
pipeline system with such pipe has experienced seam failure (including
seam cracking and selective seam weld corrosion), or operating pressure
on the covered segment has increased over the maximum operating
pressure experienced during the preceding 5 years (including abnormal
operation as defined in Sec.  192.605(c)), or MAOP has been increased,
an operator must select an assessment technology or technologies with a
proven application capable of assessing seam integrity and seam
corrosion anomalies. The operator must prioritize the covered segment
as a high-risk segment for the baseline assessment or a subsequent
reassessment. Pipe with seam cracks must be evaluated using fracture
mechanics modeling for failure stress pressures and cyclic fatigue
crack growth analysis to estimate the remaining life of the pipe in
accordance with Sec.  192.712.
* * * * *
    (6) Cracks. If an operator identifies any crack or crack-like
defect (e.g., stress corrosion cracking or other environmentally
assisted cracking, seam defects, selective seam weld corrosion, girth
weld cracks, hook cracks, and fatigue cracks) on a covered pipeline
segment that could adversely affect the integrity of the pipeline, the
operator must evaluate, and remediate, as necessary, all pipeline
segments (both covered and non-covered) with similar characteristics
associated with the crack or crack-like defect. Similar characteristics
may include operating and maintenance histories, material properties,
and environmental characteristics. An operator must establish a
schedule for evaluating, and remediating, as necessary, the similar
pipeline segments that is consistent with the operator's established
operating and maintenance procedures under this part for testing and
repair.

0
30. In Sec.  192.921, revise paragraph (a) and add paragraph (i) to
read as follows:

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

    (a) Assessment methods. An operator must assess the integrity of
the line pipe in each covered segment by applying one or more of the
following methods for each threat to which the covered segment is
susceptible. An operator must select the method or methods best suited
to address the threats identified to the covered segment (See Sec.
192.917).
    (1) Internal inspection tool or tools capable of detecting those
threats to which the pipeline is susceptible. The use of internal
inspection tools is appropriate for threats such as corrosion,
deformation and mechanical damage (including dents, gouges and
grooves), material cracking and crack-like defects (e.g., stress
corrosion cracking, selective seam weld corrosion, environmentally
assisted cracking, and girth weld cracks), hard spots with cracking,
and any other threats to which the covered segment is susceptible. When
performing an assessment using an in-line inspection tool, an operator
must comply with Sec.  192.493. In addition, an operator must analyze
and account for uncertainties in reported results (e.g., tool
tolerance, detection threshold, probability of detection, probability
of identification, sizing accuracy, conservative anomaly interaction
criteria, location accuracy, anomaly findings, and unity chart plots or
equivalent for determining uncertainties and verifying actual tool

performance) in identifying and characterizing anomalies;
    (2) Pressure test conducted in accordance with subpart J of this
part. The use of subpart J pressure testing is appropriate for threats
such as internal corrosion; external corrosion and other
environmentally assisted corrosion mechanisms; manufacturing and
related defects threats, including defective pipe and pipe seams;
stress corrosion cracking; selective seam weld corrosion; dents; and
other forms of mechanical damage. An operator must use the test
pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S
(incorporated by reference, see Sec.  192.7) to justify an extended
reassessment interval in accordance with Sec.  192.939.
    (3) Spike hydrostatic pressure test conducted in accordance with
Sec.  192.506. The use of spike hydrostatic pressure testing is
appropriate for time-dependent 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. Based upon
the threat assessed, examples of appropriate non-destructive
examination methods include ultrasonic testing (UT), phased array
ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX),
radiography, and magnetic particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in Appendix
F. The use of GWUT is appropriate for internal and external pipe wall
loss;
    (6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. The use of direct
assessment to address threats of external corrosion, internal
corrosion, and stress corrosion cracking is allowed only if appropriate
for the threat and the pipeline segment being assessed. Use of direct
assessment for threats other than the threat for which the direct
assessment method is suitable is not allowed. An operator must conduct
the direct assessment in accordance with the requirements listed in
Sec.  192.923 and with the applicable requirements specified in
Sec. Sec.  192.925, 192.927 and 192.929; or
    (7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe for each of
the threats to which the pipeline is susceptible. An operator must
notify PHMSA in advance of using the other technology in accordance
with Sec.  192.18.
* * * * *
    (i) Baseline assessments for pipeline segments with a reconfirmed
MAOP. An integrity assessment conducted in accordance with the
requirements of Sec.  192.624(c) may be used as a baseline assessment
under this section.

0
31. In Sec.  192.933, paragraphs (a)(1) and (2) are revised 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); R-STRENG (incorporated by
reference, see Sec.  192.7); or by reducing the operating pressure to a
level not exceeding 80 percent of the level at the time the condition
was discovered. An operator must notify PHMSA in accordance with Sec.
192.18 if it cannot meet the schedule for evaluation and remediation
required under paragraph (c) of this section and cannot provide safety
through a temporary reduction in operating pressure or through another
action.
    (2) Long-term pressure reduction. When a pressure reduction exceeds
365 days, an operator must notify PHMSA under Sec.  192.18 and explain
the reasons for the remediation delay. This notice must include a
technical justification that the continued pressure reduction will not
jeopardize the integrity of the pipeline.
* * * * *

0
32. In Sec.  192.935, paragraph (b)(2) is revised to read as follows:

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

* * * * *
    (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 increasing the frequency of aerial, foot
or other methods of patrols; adding external protection; reducing
external stress; relocating the line; or inline inspections with
geospatial and deformation tools.
* * * * *

0
33. In Sec.  192.937, revise paragraph (c) and add paragraph (d) to
read as follows:

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

* * * * *
    (c) Assessment methods. In conducting the integrity reassessment,
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 on the covered segment (see Sec.  192.917).
    (1) Internal inspection tools. When performing an assessment using
an in-line inspection tool, an operator must comply with the following
requirements:
    (i) Perform the in-line inspection in accordance with Sec.
192.493;
    (ii) Select a tool or combination of tools capable of detecting the
threats to which the pipeline segment is susceptible such as corrosion,
deformation and mechanical damage (e.g. dents, gouges and grooves),
material cracking and crack-like defects (e.g. stress corrosion
cracking, selective seam weld corrosion, environmentally assisted
cracking, and girth weld cracks), hard spots with cracking, and any
other threats to which the covered segment is susceptible; and
    (iii) Analyze and account for uncertainties in reported results
(e.g., tool tolerance, detection threshold, probability of detection,
probability of identification, sizing accuracy, conservative anomaly
interaction criteria, location accuracy, anomaly findings, and unity
chart plots or equivalent for determining uncertainties and verifying
actual tool performance) in identifying and characterizing anomalies.
    (2) Pressure test conducted in accordance with subpart J of this
part. The use of pressure testing is appropriate for threats such as:
Internal corrosion; external corrosion and other environmentally
assisted corrosion mechanisms; manufacturing and related defects
threats, including defective pipe and pipe seams; stress corrosion
cracking; selective seam weld corrosion; dents; and other forms of
mechanical damage. An operator must use the test

pressures specified in table 3 of section 5 of ASME/ANSI B31.8S
(incorporated by reference, see Sec.  192.7) to justify an extended
reassessment interval in accordance with Sec.  192.939.
    (3) Spike hydrostatic pressure test in accordance with Sec.
192.506. The use of spike hydrostatic pressure testing is appropriate
for time-dependent 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. Based upon
the threat assessed, examples of appropriate non-destructive
examination methods include ultrasonic testing (UT), phased array
ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX),
radiography, or magnetic particle inspection (MPI);
    (5) Guided wave ultrasonic testing (GWUT) as described in Appendix
F. The use of GWUT is appropriate for internal and external pipe wall
loss;
    (6) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. The use of direct
assessment to address threats of external corrosion, internal
corrosion, and stress corrosion cracking is allowed only if appropriate
for the threat and pipeline segment being assessed. Use of direct
assessment for threats other than the threat for which the direct
assessment method is suitable is not allowed. An operator must conduct
the direct assessment in accordance with the requirements listed in
Sec.  192.923 and with the applicable requirements specified in
Sec. Sec.  192.925, 192.927, and 192.929;
    (7) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe for each of
the threats to which the pipeline is susceptible. An operator must
notify PHMSA in advance of using the other technology in accordance
with Sec.  192.18; or
    (8) Confirmatory direct assessment when used on a covered segment
that is scheduled for reassessment at a period longer than 7 calendar
years. An operator using this reassessment method must comply with
Sec.  192.931.
    (d) MAOP reconfirmation assessments. An integrity assessment
conducted in accordance with the requirements of Sec.  192.624(c) may
be used as a reassessment under this section.

0
34. In Sec.  192.939, paragraphs (a) introductory text, (b)
introductory text, and (b)(1) are 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 7 calendar years. Operators may request a 6-month extension of the
7-calendar-year reassessment interval if the operator submits written
notice to OPS, in accordance with Sec.  192.18, with sufficient
justification of the need for the extension. If an operator establishes
a reassessment interval that is greater than 7 calendar years, the
operator must, within the 7-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.
* * * * *
    (b) Pipelines Operating below 30% SMYS. An operator must establish
a reassessment interval for each covered segment operating below 30%
SMYS in accordance with the requirements of this section. The maximum
reassessment interval by an allowable reassessment method is 7 calendar
years. Operators may request a 6-month extension of the 7-calendar-year
reassessment interval if the operator submits written notice to OPS in
accordance with Sec.  192.18. The notice must include sufficient
justification of the need for the extension. An operator must establish
reassessment by at least one of the following--
    (1) Reassessment by pressure test, internal inspection or other
equivalent technology following the requirements in paragraph (a)(1) of
this section except that the stress level referenced in paragraph
(a)(1)(ii) of this section would be adjusted to reflect the lower
operating stress level. If an established interval is more than 7
calendar years, an operator must conduct by the seventh calendar year
of the interval either a confirmatory direct assessment in accordance
with Sec.  192.931, or a low stress reassessment in accordance with
Sec.  192.941.
* * * * *

Sec.  192.949  [Removed and Reserved]

0
35. Remove and reserve Sec.  192.949.

0
36. Appendix F 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 90 days prior to use in accordance with Sec. 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 carrier pipe.
    I. Equipment and Software: Generation. The equipment and the
computer software used are critical to the success of the inspection.
Computer software for the inspection equipment must be reviewed and
updated, as required, on an annual basis, with intervals not to exceed
15 months, to support sensors, enhance functionality, and resolve any
technical or operational issues identified.
    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. 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).
    The locations and estimated CSA of all metal loss features in
excess of the detection threshold must be determined and documented.
    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. 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. 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. 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. 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 pipe, then
another type of assessment method must be utilized.
    XI. End Seal. When assessing cased carrier pipe with GWUT,
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 pipeline 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 pipeline 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 a
documented engineering analysis and evaluation.
    XIII. Validation of Operator Training. 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:
    A. Equipment operation,
    B. field data collection, and
    C. data interpretation on cased and buried pipe.
    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. 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 training specific to
cased and buried pipe, with a quality control program which that
conforms to Section 12 of ASME B31.8S (for availability, see Sec.
192.7).
    XIV. Training and Experience Minimums for Senior Level GWUT
Equipment Operators:
     Equipment Manufacturer's minimum qualification for
equipment operation and data collection with specific endorsements for
casings and buried pipe
     Training, qualification and experience in testing
procedures and frequency determination
     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)
     Equipment Manufacturer's minimum qualification with
specific endorsements for data interpretation of anomaly features for
pipe within casings and buried pipe.
    XV. Equipment: Traceable from vendor to inspection company. An
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.
    XVI. 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 to a different casing or pipeline segment. 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.
    XVII. 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.
    XVIII. 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
or other GWUT application. If this cannot be accomplished, then
alternative methods of assessment (such as hydrostatic pressure tests
or ILI) must be utilized.
    XIV. 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 September 16, 2019, under authority
delegated in 49 CFR part 1.97.
Howard R. Elliott,
Administrator.
[FR Doc. 2019-20306 Filed 9-30-19; 8:45 am]
 BILLING CODE 4910-60-P