Application for Special Permit
Modifying Compliance with 49 C.F.R § 192.611
(Class Location Change)
By
Florida Gas Transmission Company
Attachment C
Proposed Special Permit Conditions
FOR PUBLIC COMMENT
Revision: 2.0
Last Updated: 5/26/2020
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Table of Contents 1) Maximum Allowable Operating Pressure ....................................................................................... 4
2) Corrosion Control ............................................................................................................................ 4
3) Interference Currents Control .......................................................................................................... 5
4) Integrity Assessment Program ......................................................................................................... 6
5) Initial In-line Inspection .................................................................................................................. 6
6) Integrity Reassessment Intervals ..................................................................................................... 7
7) Stress Corrosion Cracking Assessment ........................................................................................... 7
8) HCA Assessments ........................................................................................................................... 9
9) Anomaly Evaluation and Remediation ............................................................................................ 9
a) General ......................................................................................................................................... 9
b) Response Time for ILI Results – Metal Loss ......................................................................... 10
i) Anomaly Response ................................................................................................................. 11
c) Response Time for ILI Results – Dents ..................................................................................... 12
i) Immediate response ................................................................................................................ 12
ii) Two-year response .............................................................................................................. 12
iii) Monitored response ............................................................................................................. 12
d) Engineering Critical Assessment for dents with an indication of metal loss or a stress riser 13
e) Response Time for ILI Results – Cracking ................................................................................ 14
i) Immediate response ................................................................................................................ 15
ii) One-year response (HCA) / Two-year response (non-HCA) .............................................. 15
iii) One-year response (HCA) / Two-year response (non-HCA) .............................................. 15
iv) One-year response (HCA) / Two-year response (non-HCA) .............................................. 15
v) Monitored response ............................................................................................................. 15
vi) Monitored response ............................................................................................................. 15
vii) Monitored response ............................................................................................................. 16
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f) Fracture mechanics modeling for failure stress and crack growth analysis ............................... 16
10) Girth Welds ................................................................................................................................ 17
11) Pipe Casings ............................................................................................................................... 18
i) Metallic Shorts ........................................................................................................................ 19
ii) Electrolytic Shorts ............................................................................................................... 19
iii) All Shorted Casings ............................................................................................................. 19
12) Pipe - Seam Evaluations ............................................................................................................. 19
13) Damage Prevention Program ...................................................................................................... 20
14) Mainline Valve – Monitoring and Remote Control for Leaks or Ruptures ............................... 21
15) O&M Manual – Special Permit Conditions ............................................................................... 21
16) Annual Report to PHMSA .......................................................................................................... 21
17) Special Permit Segment Specific Conditions ............................................................................. 22
a) Line-of-Sight Markers ................................................................................................................ 22
b) Data Integration ...................................................................................................................... 22
c) Pipe Properties Testing ............................................................................................................... 22
iii) Material Documentation Process ........................................................................................ 23
d) Pipeline System Flow Reversals ............................................................................................. 24
e) Environmental Assessments and Permits ................................................................................... 24
18) Documentation ........................................................................................................................... 24
19) Extension of Special Permit Segment ........................................................................................ 25
20) Certification ................................................................................................................................ 25
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I. Conditions1:
1) Maximum Allowable Operating Pressure: FGT proposes to continue operating the special
permit segments at or below the existing MAOP as follows: (pipeline name – class ID # –
MAOP):
a) FLBVW – 166334 – 1333 psig
b) FLBVW – 166338 – 1333 psig
c) FLBVW – 166340 – 1333 psig
d) FLBVW – 166347 – 1333 psig
e) FLBVW – 166349 – 1333 psig
f) FLBVW – 166350 – 1333 psig
g) FLBVW – 166352 – 1333 psig
h) FLMEE-26-27 – 166250 – 1322 psig
i) FLMEE-26-27 – 166256 – 1322 psig
j) FLMEE-26-27 – 166257 – 1322 psig
k) FLMEE-26-27 – 166267 – 1322 psig
l) FLMEF-26 – 166114 – 1322 psig
m) FLMEF-26 – 166129 – 1322 psig
2) Corrosion Control: FGT proposes to promptly address any corrosion control deficiencies in the
special permit segment that are indicated by the inspection and testing program required under
49 CFR 192.465.
a) Within six (6) months of identifying a deficiency, FGT must develop a remedial action plan,
apply for any necessary permits, and complete remedial action.
b) Unless non-systemic or location-specific causes of low cathodic protection levels are present
as described in Condition 2(c), where any annual test station reading (pipe-to-soil potential
measurement) indicates cathodic protection (CP) levels below the required levels in Appendix
D of 49 CFR Part 192, FGT must determine the extent of the area with inadequate cathodic
protection. Close interval surveys must be conducted in both directions from the test station
1 All special permit conditions that are applicable to the special permit inspection areas are also applicable to the special
permit segments. Special permit conditions that are applicable to the special permit segment are not applicable to the
special permit inspection area.
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with a low CP reading at a maximum interval of approximately three (3) feet, ending at the
nearest adjacent test stations with satisfactory readings. Close interval surveys must be
conducted, where practical based upon geographical, technical, or safety considerations. Close
interval surveys must be completed with the protective current interrupted unless it is
impractical to do so for technical or safety reasons. Remediation of areas with insufficient CP
levels must be performed in accordance with Condition 2(a). FGT must confirm restoration
of adequate CP by close interval survey over the entire area where low CP levels were
detected.
c) Close interval surveys are not required in instances where low potentials are a result of
electrical short to an adjacent foreign structure, rectifier malfunction, interruption of power
source, or interruption of CP current due to other non-systemic or location-specific causes. If
FGT identifies the potential cause of the low CP reading while conducting the close interval
surveys, additional survey points may be unnecessary to perform remediation. In these cases,
following the remedial measures, FGT must perform a close interval survey over the area
found to be deficient to confirm restoration of adequate cathodic protection.
3) Interference Currents Control: FGT proposes to address induced alternating current (AC) from
parallel electric transmission lines and other interference issues that may affect the pipeline such as
direct current (DC) in the special permit segments. An induced AC or DC program and remediation
plan to protect the pipeline from corrosion caused by stray currents must be in place within twenty-
four (24) months of the grant of this special permit. The program required to meet this Condition
3 must include:
a) Interference surveys for pipeline systems to detect the presence and level of any electrical stray
current. Interference surveys must be taken on periodic basis, including when there are current
flow increases over pipeline segment grounding design, from any co-located pipelines,
structures, or high voltage alternating current (HVAC) power lines, including from additional
generation, a voltage up rating, additional lines, new or enlarged power substations, new
pipelines or other structures;
b) Analysis of the results of the survey to determine the cause of the interference and whether the
level could cause significant corrosion (defined as 100 amps per meter squared for AC-induced
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corrosion), or if it impedes the safe operation of a pipeline, or that may cause a condition that
would adversely impact the environment or the public;
c) Remedial action is required when the interference is at a level that could cause significant
corrosion (defined as 100 amps per meter squared for AC-induced corrosion), or if it impedes
the safe operation of a pipeline, or that may cause a condition that would adversely impact the
environment or the public. Within six (6) months after completion of the survey, FGT must
develop a remediation plan, apply for necessary permits, and complete all remediation.
4) Integrity Assessment Program: FGT proposes to incorporate the special permit segments into a
documented integrity assessment program.
a) For segments covered under 49 CFR Part 192, Subpart O, the integrity assessment program
must conform to the requirements of Subpart O.
b) For segments not covered under 49 CFR Part 192, Subpart O, FGT must conduct assessments
and reassessments that are capable of identifying anomalies and defects associated with each
of the threats to which the pipeline segment is susceptible, as determined by FGT, using one
or more of the methods identified in 49 CFR 192.937(c).
5) Initial In-line Inspection:
a) FGT proposes to conduct initial instrumented in-line inspection (ILI) on the special permit
inspection areas within twenty-four (24) months after of the grant of this special permit. Initial
ILI assessments must include a high resolution magnetic flux leakage (HR-MFL) tool and a
high resolution (HR) deformation tool with deformation extended sensor arms. FGT may use
a prior ILI assessment as an initial assessment for the special permit inspection area if the
assessment met the Subpart O requirements for in-line inspection at the time of the assessment
within five (5) years prior to grant of this special permit.
b) When conducting in-line inspection, FGT must conform to API STD 1163, In-line Inspection
Systems Qualification Standard; ANSI/ASNT ILI-PQ-2005, In-line Inspection Personnel
Qualification and Certification; and NACE SP0102-2010, In-line Inspection of Pipelines.
Assessments may also be conducted using tethered or remotely controlled tools, not explicitly
discussed in NACE SP0102-2010, provided they conform to those sections of NACE SP0102-
2010 that are applicable.
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6) Integrity Reassessment Intervals: FGT proposes to schedule ILI reassessment dates for the
special permit inspection areas by adding the required time interval to the most recent assessment
year.
a) For segments covered under 49 CFR Part 192, Subpart O, reassessments must be conducted
in accordance with the FGT Integrity Management Plan under 49 CFR 192.939, but not to
exceed a seven (7) calendar year reassessment interval as defined in 49 CFR 192.939(a).
b) For segments not covered under 49 CFR Part 192, Subpart O, reassessments must occur every
ten (10) calendar years after initial assessment of a pipeline segment, or at a shorter
reassessment interval based upon the type of anomaly, operational, material, and
environmental conditions found on the pipeline segment, or as otherwise necessary to ensure
public safety.
7) Stress Corrosion Cracking Assessment: FGT proposes to evaluate the special permit segments
for stress corrosion cracking (SCC) as follows:
a) FGT must conduct an SCC threat assessment per the applicable edition of the American
Society of Mechanical Engineers Standard B31.8S, "Managing System Integrity of Gas
Pipelines” (ASME B31.8S) 2 Appendix A3, or NACE SP 0204-2008, "Stress Corrosion
Cracking (SCC) Direct Assessment Methodology”, Section 1.2.1.1 and 1.2.2. If the threat
assessment shows that the special permit segment does not meet any of the criteria for near
neutral or high pH SCC, then no further action is needed.
b) If the threat assessment required under Condition 7(a) indicates that the special permit
segment is susceptible to either near neutral or high pH SCC, FGT must perform a stress
corrosion cracking assessment on the special permit segment using an appropriate assessment
method for SCC (such as stress corrosion cracking direct assessment (SCCDA), a spike
hydrostatic pressure test, or ILI with a crack detection tool) no later than twenty-four (24)
months after of the grant of this special permit. The SCC assessment must address both high
pH SCC and near neutral pH SCC. An SCC assessment need not be performed if FGT has
performed an SCC assessment of the pipeline along the entire length of the special permit
segment less than four (4) years prior to the grant of this special permit.
2 The applicable edition incorporated by reference is listed in 49 CFR 192.7.
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i) If factors beyond FGT’s control prevent the completion of the SCCDA survey and
remediation within twenty-four (24) months, an SCC assessment and remediation must be
performed as soon as practicable and a letter justifying the delay and providing the
anticipated date of completion must be submitted to the appropriate PHMSA OPS Region
Director no later than one (1) month prior to the end of the twenty-four (24) months after
the grant of this special permit.
c) If the threat of SCC exists as determined in Condition 7(a) and when the special permit
segment is uncovered for any reason to comply with the special permit and integrity
management activities and the coating has been identified as poor during the pipeline
examination, then FGT must directly examine the pipe for SCC using an accepted industry
detection practice such as dry or wet magnetic particle tests. Examples of “poor coating”
include, but are not limited to, a coating that has become damaged and is losing adhesion to
the pipe which is shown by falling off the pipe and/or shields the cathodic protection. FGT
must keep coating records 3 at all excavation locations in the special permit segment to
demonstrate the coating condition.
d) If SCC4 activity is discovered by any means within the special permit inspection area in
similar pipe and pipe coating vintage (in accordance with 49 CFR 192.917(e)), or similar pipe
and pipe coating vintage within the special permit inspection area has had an in-service or
hydrostatic test SCC failure or leak; the special permit segment must be further assessed and
mitigated, using one of the following methods, within one (1) year of finding SCC:
i) Hydrostatic test program
A. The special permit segment shall be tested to a baseline pressure as specified in §§
192.619(a)(2) or 192.620(a)(2), whichever applies, for 8 hours, and pressure raised
(spiked) for a period of time in accordance with the current FGT Integrity Management
Plan specifications.
B. The SCC hydrostatic test program must be performed at a reassessment interval no
greater than seven (7) calendar years (but may be at a lesser interval in accordance with
3 The records must include, at a minimum, a description of the FGT’s detection procedures, records of finding, and
mitigation procedures implemented for the excavation.
4 “SCC” activity shall be defined as over both 10 percent wall thickness depth and 2-inches in length.
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the results of an engineering critical assessment) in the special permit segment, and
C. If pipe in a special permit segment leaks or ruptures during a hydrostatic test due to SCC,
a successful SCC hydrostatic test must be completed prior to returning the special permit
segment to operational service and all pipe in the special permit segment must be
replaced with new pipe within eighteen (18) months; or
ii) Crack detection tool assessment
A. SCC detection tool must be run in the special permit inspection area, and
B. All SCC activity found in the special permit segment must be remediated or replaced
within one (1) year of finding SCC; or
iii) Operating pressure must be lowered to 60% of the specified minimum yield strength
(SMYS); or
iv) All affected pipe must be replaced to meet 49 CFR 192.619 or 49 CFR 192.620 (whichever
applicable) in the special permit segment.
e) If any SCC activity is discovered in the special permit inspection area, FGT must submit an
SCC remediation plan to the appropriate PHMSA OPS Region Director with a copy to the
Director, PHMSA OPS Engineering and Research Division no later than sixty (60) days after
the finding of SCC. The plan must:
i) Meet Condition 7(c), including a SCC remediation/repair plan with SCC characterization
and timing, or
ii) Include a technical justification that shows that the threats for SCC in the special permit
segment are being addressed.
8) HCA Assessments: This special permit does not impact or defer any of FGT’s assessments for
HCAs under 49 CFR Part 192, Subpart O.
9) Anomaly Evaluation and Remediation:
a) General:
i) FGT must analyze the data obtained from the assessments required under Conditions 4, 5, 6,
and 7 to determine if a condition could adversely affect the safe operation of the pipeline.
ii) FGT must explicitly consider uncertainties in reported ILI assessment results (including, but
not limited to, tool tolerance, detection threshold, probability of detection, probability of
identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy,
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anomaly findings, and unity chart plots or equivalent for determining uncertainties and
verifying tool performance) in identifying and characterizing anomalies. Tool tolerance
validation must conform to API STD 1163, In-line Inspection Systems Qualification
Standard. FGT may use previously excavated and remediated anomalies to validate tool
tolerance.5
iii) Discovery of a condition occurs when FGT has adequate information to make the
determination required under Condition 9(a)(i). FGT must complete discovery promptly
after an assessment, but no later than one hundred-eighty (180) days after an assessment on
segments covered under 49 CFR Part 192, Subpart O or two hundred-forty (240) days on all
other segments, unless FGT can demonstrate that this timeline is impracticable.
b) Response Time for ILI Results – Metal Loss: The following is the required timing for
excavation and investigation of metal loss anomalies within a special permit segment or special
permit inspection area, based on ILI results. FGT must evaluate ILI data by using either the
ASME Standard B31G, "Manual for Determining the Remaining Strength of Corroded
Pipelines" (ASME B31G) 6 , the modified B31G(0.85dL), R-STRENG 7 , or an alternative
equivalent method for calculating the predicted failure pressure to determine anomaly
responses. Unless a special requirement for responding to certain conditions applies, as
provided in this Condition 9(b), FGT must follow the schedule in American Society of
Mechanical Engineers Standard B31.8S, "Managing System Integrity of Gas Pipelines” (ASME
B31.8S) 8 to respond to metal loss anomalies. Each imperfection or damage that requires
response under this Condition 9(b) or repair under FGT’s Standard Operating Procedures and
is verified by in-field examination must be repaired to support the current MAOP of the pipeline
segment, considering the design factor of the installed pipe.9
5 FGT may use multiple anomalies within the same excavation to validate tool tolerance.
6 The applicable edition incorporated by reference is listed in 49 CFR 192.7.
7 The applicable edition incorporated by reference is listed in 49 CFR 192.7.
8 The applicable edition incorporated by reference is listed in 49 CFR 192.7.
9 Anomaly response calculations are to be based off of the class location design factor of the pipe at the time of original
installation, not the design factor for the new class location.
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i) Anomaly Response:
A. Anomaly response shall be governed for conventional pipe (Class 1 design factor of
0.80, Class 2 of 0.67, Class 3 of 0.56) by the following table
Class Location Special Permit
Anomaly Investigation/Repair Criteria for
Special Permit Inspection Areas (SPIA)
Investigation/Repair
Criteria - Immediate
Investigation/Repair
Criteria - Monitored
SPIA
Location
Class
Location
Pipe
Operating
% SMYS
FPR Wall Loss FPR Wall Loss
Non HCA
& HCA 1 ≤ 80 % ≤ 1.39 ≥ 60 % > 1.39 < 60 %
Non HCA
& HCA
2 ≤ 67 % ≤ 1.67
≥ 60 % > 1.67 < 60 %
Non HCA
& HCA
3 ≤ 56 % ≤ 2.00
≥ 60 % > 2.00 < 60 %
Class Location Change
Non HCA
& HCA 1 to 2 ≤ 80 % ≤ 1.39 ≥ 50 % > 1.39 < 50 %
Non HCA
& HCA 2 to 3 ≤ 67 % ≤ 1.67 ≥ 50 % > 1.67 < 50 %
Non HCA
& HCA 1 to 3 ≤ 80 % ≤ 1.39 ≥ 40 % > 1.39 < 40 %
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c) Response Time for ILI Results – Dents: This is the required timing for excavation and
investigation of dent anomalies on the special permit segments or special permit inspection
areas, based on ILI results. Each imperfection or damage that requires response under this
Condition 9(c) or repair under FGT’s Standard Operating Procedures and is verified by in-field
examination must be repaired to support the current MAOP of the pipeline segment,
considering the design factor of the installed pipe. Anomalies on pipe segments covered under
49 CFR Part 192, Subpart O must addressed in accordance with 49 CFR 192.933. Other
anomalies must be addressed as follows:
i) Immediate response: Any dent anomaly within a special permit segment or special permit
inspection area that is located between the 8 o'clock and 4 o'clock positions (upper 2⁄3 of
the pipe) that has metal loss, cracking or a stress riser, unless an engineering critical
assessment of the dent in accordance with Condition 9(d) demonstrates that critical strain
levels are not exceeded.
ii) Two-year response: Any dent anomaly within a special permit segment or special permit
inspection area that is either:
A. a smooth dent located between the 8 o'clock and 4 o'clock positions (upper 2/3 of the
pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches
in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), unless
engineering analyses of the dent demonstrate critical strain levels are not exceeded;
or
B. a dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth
for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or
at a detected longitudinal or helical (spiral) seam weld, unless engineering analyses
of the dent and girth or seam weld demonstrate critical strain levels are not exceeded;
or
C. a dent located between the 4 o'clock position and the 8 o'clock position (bottom 1⁄3 of
the pipe) that has metal loss, cracking or a stress riser, unless an engineering critical
assessment of the dent in accordance with Condition 9(d) demonstrates that critical
strain levels are not exceeded.
iii) Monitored response: Any dent anomaly within a special permit segment or special
permit inspection area that is either:
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A. a dent with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches
in depth for a pipeline diameter less than NPS 12) located between the 4 o'clock
position and the 8 o'clock position (bottom 1⁄3 of the pipe); or
B. a dent located between the 8 o'clock and 4 o'clock positions (upper 2⁄3 of the pipe)
with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in
depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and engineering
analyses of the dent demonstrate critical strain levels are not exceeded; or
C. a dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth
for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or
at a detected longitudinal or helical (spiral) seam weld, and engineering analyses of
the dent and girth or seam weld demonstrate critical strain levels are not exceeded.
These analyses must consider weld properties; or
D. a dent that has metal loss, cracking or a stress riser and engineering critical assessment
of the dent in accordance with Condition 9(d) demonstrates that critical strain levels
are not exceeded.
d) Engineering Critical Assessment for dents with an indication of metal loss or a stress
riser: If FGT elects to use engineering critical assessment to evaluate a dent anomaly with
an indication of metal loss or a stress riser, FGT must use the process described in this
Condition 9(d). This process does not apply to dents with coincident cracking, as identified
through inline or visual inspection. Dents with coincident cracking must be remediated in
accordance with this Condition 9(d).
i) Engineering Critical Assessment. An engineering critical assessment is an analytical
procedure through which FGT must demonstrate that a dent anomaly with an indication
of metal loss or a stress riser does not jeopardize pipeline integrity. The engineering
critical assessment must:
A. Evaluate potential threats to the pipe segment in the vicinity of the dent, including
movement, loading and corrosion;
B. Identify and quantify all loads acting on the dent;
C. Review in-line inspection data for damage in the dent area and any associated weld
region;
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D. Perform pipeline curvature-based strain analysis, using inspection data from recent
in-line inspection with a high resolution deformation tool;
E. Compare dent profile between recent and previous in-line inspections to identify any
significant changes in dent depth and shape, if multiple in-line inspections with a high
resolution deformation tool have been conducted; and
F. Evaluate geometric strain level associated with the dent and any associated welds
using a technically appropriate methodology and calculate the plastic strain limit
damage factors or other technically appropriate damage factors to infer the possibility
of a crack. Dents with geometric strain levels that exceed 12% or that exceed the
critical strain must be remediated in accordance with Condition 9(c), as applicable.
The analysis must account for material property uncertainties and model inaccuracies
and tolerances.
ii) Analysis for Remaining Life. If FGT determines that the pipeline segment is susceptible
to cyclic fatigue or other loading conditions that could lead to fatigue, fatigue analysis
must be performed using a technically appropriate engineering methodology. The
analysis must account for model inaccuracies and tolerances. FGT must re-evaluate the
remaining life of the pipeline before 50% of the remaining life calculated by this analysis
has expired. FGT must determine and document if further pressure tests or use of other
methods are required at that time. FGT 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.
iii) Review. Analyses conducted in accordance with this section must be reviewed and
confirmed by a subject matter expert.
iv) When API 1183 [Assessment and Management of Pipeline Dents] is issued for
management of mechanical damage (currently under development), the requirements in
the standard will supersede the requirements in 9(d)(i,ii,iii).
e) Response Time for ILI Results – Cracking: The following is the required timing for
excavation and investigation of crack or crack-like anomalies within a special permit segment
or special permit inspection area, based on ILI results. Each imperfection or damage that
requires response under this Condition 9(e) or repair under the FGT Integrity Management
Plan and is verified by in-field examination must be repaired to support the current MAOP of
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the pipeline segment, considering the design factor of the installed pipe.
i) Immediate response: Any crack or crack-like anomaly within a special permit segment
or special permit inspection area that meets either: (1) crack depth is greater than 50%
of pipe wall thickness, as measured at the crack location; or (2) fracture mechanics
modeling per Condition 9(f) shows a failure stress pressure at the location of the
anomaly less than or equal to 1.1 times the MAOP.
ii) One-year response (HCA) / Two-year response (non-HCA): up to 80% of SMYS in
a Class 1, 2, or 3 location - Any crack or crack-like anomaly within a special permit
segment or special permit inspection area on pipe operating up to 80% of SMYS where
fracture mechanics modeling per Condition 9(f) shows a failure stress pressure at the
location of the anomaly less than 1.39 times the MAOP.
iii) One-year response (HCA) / Two-year response (non-HCA): up to 67% SMYS in a
Class 2 or 3 location - Any crack or crack-like anomaly within a special permit
segment or special permit inspection area on pipe operating up to 67% of SMYS where
fracture mechanics modeling per Condition 9(f) shows a failure stress pressure at the
location of the anomaly less than or equal to 1.50 times the MAOP.
iv) One-year response (HCA) / Two-year response (non-HCA): up to 56% SMYS in
Class 3 - Any crack or crack-like anomaly within a special permit segment or special
permit inspection area on pipe operating up to 56% (Class 3) of SMYS where fracture
mechanics modeling per Condition 9(f)) shows a failure stress pressure at the location of
the anomaly less than or equal to 1.50 times the MAOP.
v) Monitored response: up to 80% of SMYS in a Class 1, 2, or 3 location - Any crack
or crack-like anomaly within a special permit segment or special permit inspection
area on pipe operating up to 80% of SMYS where fracture mechanics modeling per
Condition 9(f) shows a failure stress pressure at the location of the anomaly greater than
1.39 times the MAOP.
vi) Monitored response: up to 67% SMYS in a Class 2 or 3 location - Any crack or
crack-like anomaly within a special permit segment or special permit inspection area
on pipe operating up to 67% of SMYS where fracture mechanics modeling per
Condition 9(f) shows a failure stress pressure at the location of the anomaly greater than
1.50 times the MAOP.
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vii) Monitored response: up to 56% SMYS in Class 3 - Any crack or crack-like anomaly
within a special permit segment or special permit inspection area on pipe operating up
to 56% (Class 3) of SMYS where fracture mechanics modeling per Condition 9(f)
shows a failure stress pressure at the location of the anomaly greater than 1.50 times the
MAOP.
f) Fracture mechanics modeling for failure stress and crack growth analysis: FGT
proposes to use the process described in this section where fracture mechanics modeling is
required by Condition 9(e).
i) Fracture Mechanics Modeling for Failure Stress Pressure. Failure stress pressure must be
determined using a technically proven fracture mechanics model appropriate to the failure
mode (ductile, brittle or both) and boundary condition used (pressure test, ILI, or other).
Examples of technically proven models include but are not limited to: for the brittle failure
mode, the Raju/Newman Model; for the ductile failure mode, Modified LnSec, API RP
579-1/ASME FFS-1, June 15, 2007, (API 579-1, Second Edition) – Level II or Level III,
CorLas™, and PAFFC. The analysis must account for model inaccuracies and tolerances
and use conservative assumptions for crack dimensions (length and depth) and failure
mode (ductile, brittle, or both) for the microstructure, location, and type of defect.
ii) Analysis for Flaw Growth and Remaining Life. If FGT determines that 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, such as SCC, an appropriate
engineering analysis methodology must be used. The above methodologies should account
for model inaccuracies and tolerances and be validated by a subject matter expert to
determine conservative predictions of flaw growth and remaining life at the maximum
allowable operating pressure.
A. 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).
B. FGT must re-evaluate the remaining life of the pipeline before 50% of the remaining life
calculated by this analysis has expired. FGT must determine and document if further
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pressure tests or use of other methods are required at that time. FGT 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.
iii) Review. Analyses conducted in accordance with this paragraph must be reviewed and
confirmed by a subject matter expert.
10) Girth Welds: FGT proposes to provide records to PHMSA to demonstrate the girth welds on the
special permit segments were nondestructively tested at the time of construction in accordance
with:
a) The Federal pipeline safety regulations at the time the pipelines were constructed or at least
1% of the girth welds in each special permit segment were non-destructively tested after
construction but prior to the application for this special permit provided at least two (2) girth
welds in the special permit segment were excavated and inspected.
b) If FGT cannot provide girth weld records to PHMSA to demonstrate either of the above in
Condition 10(a), FGT must complete one of the following:
i) Certify to PHMSA in writing that there have been no in-service leaks or breaks in the girth
welds within the entire special permit segment for the entire life of the pipeline;
ii) Perform a HR-MFL in-line inspection using a tool or tools capable of identifying girth weld
anomalies. If this technique is employed, FGT must develop a technical basis for evaluating
the serviceability of the girth welds based on HR-MFL data. The girth weld ILI inspection
plan, including ILI findings, technical determination for identifying weld anomalies and
confirmation excavations, must be submitted to the appropriate PHMSA OPS Regional
Director for approval 14 days prior to confirmation excavations; or
iii) Evaluate the terrain along the special permit segment for threats to girth weld integrity
from soil or settlement stresses and remediate all such integrity threats. Additionally,
excavate10, visually inspect, and nondestructively test at least two girth welds in the
special permit segment in accordance with the American Petroleum Institute Standard
1104, "Welding of Pipelines and Related Facilities" (API 1104) as follows:
10 FGT must evaluate for SCC any time the special permit segment is uncovered in accordance with Condition 7(b)
of this special permit.
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A. Using the edition of API 1104 current at the time the pipeline was constructed; or
B. Using the edition of API 1104 recognized in the Federal pipeline safety regulations at
the time the pipeline was constructed; or
C. Using the edition of API 1104 currently recognized in the Federal pipeline safety
regulations.
c) FGT proposes to complete any girth weld inspection and testing required under Condition
10(b) within twenty-four (24) months after the grant of this special permit. If any girth weld
in the special permit segments are found unacceptable in accordance with Condition 10(b),
FGT must repair the girth weld immediately and then prepare an inspection and remediation
plan for all remaining girth welds in the special permit segment based upon the repair findings
and the threat to the special permit segment. FGT must submit the inspection and remediation
plan for girth welds to the appropriate PHMSA OPS Region Director and remediate girth welds
in the special permit segment in accordance with the inspection and remediation plan within
sixty (60) days of finding girth welds that do not meet this Condition 10(c).
d) FGT proposes to complete any girth weld inspection and remediation required under Condition
10(c) within six (6) months after submitting the inspection and remediation plan to PHMSA.
If factors beyond FGT's control prevent the completion of these tasks within six (6) months, the
tasks must be completed as soon as practicable and a letter justifying the delay and providing
the anticipated date of completion must be submitted to the appropriate PHMSA OPS Region
Director no later than one (1) month prior to the end of the six (6) months interval after the
grant of this special permit. If FGT does not receive an objection letter from PHMSA within
thirty (30) days of notifying PHMSA, FGT can proceed with the extended girth weld inspection
and remediation interval.
11) Pipe Casings: FGT proposes to identify all shorted casings within the special permit segments no
later than twenty-four (24) months after the grant of this special permit and classify any shorted
casings as either having a "metallic short" (the carrier pipe and the casing are in metallic contact)
or an "electrolytic short" (the casing is filled with an electrolyte) using a commonly accepted
method such as the Panhandle Eastern, Pearson, DCVG, ACVG, AC Attenuation, or equivalent.
a) Where practical, FGT must clear shorted casings identified within the special permit segments
no later than twenty-four (24) months after the grant of this special permit as follows:
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i) Metallic Shorts: FGT must clear any metallic short on a casing in the special permit
segments.
ii) Electrolytic Shorts: FGT must remove the electrolyte from the casing/pipe annular space
on any casing in the special permit segments.
iii) All Shorted Casings: After the short has been cleared, FGT must install external corrosion
control test leads on both the carrier pipe and the casing in accordance with 49 CFR 192.471
to facilitate the future monitoring for shorted conditions. FGT may then choose to fill the
casing/pipe annular space with a high dielectric casing filler or other material which provides
a corrosion inhibiting environment provided an assessment and all repairs were completed.
b) If it is impractical for FGT to clear a shorted casing within the special permit segments, FGT
must monitor for the effects of shorted casings as part of the integrity assessment program
required by Conditions 4, 5, and 6 using an ILI tool or tools that have been demonstrated to
properly detect and assess corrosion over shorted locations. FGT must remediate any identified
corrosion in accordance with Condition 9.
12) Pipe - Seam Evaluations: FGT proposes to identify any pipeline in the special permit segments
that may be susceptible to pipe seam issues because of the vintage of the pipe, the manufacturer of
the pipe, or other issues. Once FGT has identified such issues, they must complete the following:
a) FGT proposes to perform an engineering analysis to determine if there are any pipe seam
threats on the pipe located in the special permit segment. This analysis must include the
documentation that the processes in (1) 'M Charts' in "Evaluating the Stability of
Manufacturing and Construction Defects in Natural Gas Pipelines" by Kiefner and Associates
updated April 26, 2007, under PHMSA Contract DTFAA-COSP02120 and (2) Figure 4.2,
'Framework for Evaluation with Path for the Segment Analyzed Highlighted' from TTO-5
"Low Frequency ERW and Lap Welded Longitudinal Seam Evaluation" by Michael Baker Jr.,
and Kiefner and Associates, et. al. under PHMSA Contract DTRS56-02-D-70036 were utilized
along with other relevant materials. If the engineering analysis shows that the pipe seam issues
on the pipe located in the special permit segment are not a threat to the integrity of the pipeline,
FGT does not have to complete Conditions 12(b) through 12(e). If there is a threat to the
integrity of the pipeline, then one or more of Conditions 12(b) through 12(e) must be
completed;
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b) If no 49 CFR Part 192, Subpart J hydrostatic test has been performed, FGT must hydrostatically
test the special permit segment to a minimum pressure of 100% of SMYS, in accordance with
49 CFR Part 192, Subpart J requirements for eight (8) continuous hours. This hydrostatic test
must be completed within twenty-four (24) months of issuance of this special permit. The
hydrostatic test must confirm there are no systemic issues with the weld seam or pipe. A root
cause analysis, including metallurgical examination of the failed pipe, must be performed for
any failure experienced during the test to verify that it is not indicative of a systemic issue.
The written results of this root cause analysis must be in provided to the appropriate PHMSA
OPS Region Director where the pipe is in service within sixty (60) days of the failure; or
c) If the pipeline in the special permit segment has experienced a seam leak or failure in the last
five (5) years and no hydrostatic test meeting the conditions in accordance with 49 CFR Part
192, Subpart J was performed after the seam leak or failure, then a hydrostatic test must be
performed within one (1) year after the grant of this special permit on the special permit
segment; and
d) If the pipeline in the special permit segment has any LF-ERW seam or EFW seam conditions
as noted in (i), (ii), or (iii) below, the special permit segment must be replaced:
i) Pipe constructed or manufactured prior to 1954 and has had any pipe seam leaks or ruptures
in the special permit inspection area, or
ii) Pipe has unknown manufacturing processes, or
iii) Pipe has known manufacturing or construction issues that are unresolved (such as
concentrated hard spots, hard heat-affected weld zones, selective seam corrosion, pipe
movement that has led to buckling, have had past leak and rupture issues, or any other
systemic issues).
e) If the pipeline in a special permit segment has a reduced longitudinal joint seam factor, below
1.0, as defined in 49 CFR 192.113 the special permit segment must be replaced.
13) Damage Prevention Program: FGT’s damage prevention program must incorporate the
applicable best practices of the Common Ground Alliance (CGA) within the special permit
segment.
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14) Mainline Valve – Monitoring and Remote Control for Leaks or Ruptures: FGT proposes
within one year of the Special Permit issuance to utilize Remote Operated Valves and/or Automatic
Control Valves for responding to an emergency in any Special Permit Segment.
15) O&M Manual – Special Permit Conditions: FGT proposes to amend applicable FGT Standard
Operating Procedures as required to incorporate conditions of this special permit to all applicable
special permit inspection areas.
16) Annual Report to PHMSA: Within one (1) year of the grant of this special permit and annually11
thereafter, FGT must report the following to the appropriate PHMSA OPS Region Director with
copies to the Deputy Associate Administrator, PHMSA Field Operations; Deputy Associate
Administrator, PHMSA Policy and Programs; Director, PHMSA Engineering and Research
Division; and Director, PHMSA Standards and Rulemaking Division:
a) The number of new residences, other structures intended for human occupancy and public
gathering areas built within the special permit segment during the previous year.
b) Any new integrity threats identified during the previous year and the results of any ILI or direct
assessments performed (including any un-remediated anomalies over 30% wall loss, cracking
found in the pipe body, weld seam or girth welds, and dents with metal loss, cracking or stress
riser) during the previous year in the special permit segment including their survey station,
failure pressure ratio, anomaly depth and length, class location and whether they are in an
HCA.
c) Any reportable incident, any leak normally indicated on the DOT Annual Report and all repairs
on the pipeline that occurred during the previous year in the special permit segments.
d) Any on-going damage prevention initiatives affecting the special permit segments and a
discussion of the success of the initiatives including corrosion control and SCC assessment
findings and remediation actions.
11 Annual reports must be received by PHMSA by the last day of the month in which the special permit is dated. For
example, the annual report for a special permit dated January 21, 2019, must be received by PHMSA no later than
January 31, each year beginning in 2020.
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e) Any mergers, acquisitions, transfer of assets, or other events affecting the regulatory
responsibility of the company operating the pipeline.
17) Special Permit Segment Specific Conditions: FGT proposes to comply with the following
requirements.
a) Line-of-Sight Markers: FGT proposes to install and maintain line-of-sight markings on the
pipeline in the special permit segments except in mountainous areas, agricultural areas,
wetlands, large water crossings such as lakes or other areas where line-of-sight signage is not
practical. Line-of-sight markers must be installed within twenty-four (24) months of issuance
of this special permit and replaced as necessary by FGT within thirty (30) days after
identification of line-of-sight marker removal.
b) Data Integration: FGT proposes to maintain data integration of all special permit condition
findings and remediations in the special permit segments that are required to implement
Conditions 1 – 14 of this special permit. Data integration may include the following
information, as needed: Pipe diameter, wall thickness, grade, and seam type; pipe coating;
MAOP; class location (including boundaries on aerial photography); high consequence areas
(HCAs) (including boundaries on aerial photography); hydrostatic test pressure including any
known test failures; casings; any in-service ruptures or leaks; ILI survey results including HR-
MFL, HR-geometry/caliper or deformation tools; close interval survey (CIS) surveys – most
recent; rectifier readings; cathodic protection test point survey readings; AC/DC interference
surveys; pipe coating surveys; pipe coating and anomaly evaluations from pipe excavations;
stress corrosion cracking (SCC) excavations and findings; and pipe exposures from
encroachments. Structures must be validated every three (3) years by obtaining new aerial
imagery or by ground patrol. Data integration must be updated on an annual basis. FGT must
conduct, at least, an annual review of integrity issues to be remediated.
c) Pipe Properties Testing: If FGT needs any of the following material properties to perform any
Condition in this special permit, and if the properties are not known or records are not available,
FGT must address missing properties as follows:
i) If pipe diameter or wall thickness is not known or records are not available, FGT must:
A. Use the same wall thickness values that are the basis for the current MAOP; or
B. Verify these properties based upon the material documentation process specified in
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Proposed Special Permit Conditions – For Public Comment Page 23 of 26
Condition 17(c)(iii)
ii) If SMYS or actual material yield is not known or records are not available, FGT must:
A. Use the same material properties that are the basis for the current MAOP;
B. Assume grade A pipe (30 ksi); or
C. Verify these properties based upon the material documentation process specified in
Condition 17(c)(iii)
iii) Material Documentation Process:
A. Develop and implement procedures for conducting non-destructive or destructive tests,
examinations, and assessments for any pipe in the special permit segments without pipe
diameter, wall thickness and yield strength records of this special permit.
B. A minimum of two (2) destructive or non-destructive test methods must be performed at
an excavation site. FGT must conduct one (1) non-destructive yield test assessment
using TD Williamson test procedures and ball indention methodology12, or equivalent,
and secondly, confirm that the pipe has not experienced unexpected yielding, considering
pressure test history. If non-destructive testing of pipe material properties show that the
pipe wall thickness is not within API 5L specification tolerances and the pipe grade is
under the strength requirements of API 5L by 3000 psi or more, then the yield strength
of that individual pipe shall be confirmed using destructive test methods or the special
permit segment pipe must be removed. Acceptance limits for the diameter tape
measurements shall be in accordance with PHMSA Advisory Bulletin ADB-09-01.
C. Assessments must be made for each unique combination of the following attributes: wall
thicknesses (within ten (10) percent of the smallest wall thickness in the population),
grade, manufacturing process, pipe manufacturing dates (within a two (2) year interval),
and construction dates (within a two (2) year interval).
D. The material properties determined from either destructive or non-destructive tests
required by this Condition 17(c)(iii) cannot be used to raise the original grade or
specification of the material, which must be based upon the applicable standard
referenced in 49 CFR 192.7.
12 Non-destructive assessment method and procedures must be submitted by FGT to the appropriate PHMSA OPS Region
Director and PHMSA OPS Director of Engineering and Research Division for review. If FGT does not receive an objection
letter from PHMSA within 30 days of notifying PHMSA, FGT can proceed with the non-destructive assessment.
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E. For a future special permit segment with missing MTRs or mill inspection reports, the
above methodology shall be applied or FGT may elect to remove pipe joints for
destructive testing.
d) Pipeline System Flow Reversals: For pipeline system flow reversals lasting longer than 90
days and where the MAOP for class location changes are exceeded under either 49 CFR
192.619(a)(1) or 192.61113 in a special permit segment, FGT must prepare a written plan that
corresponds to those applicable criteria identified in PHMSA Advisory Bulletin (ADB-2014-
04), “Guidance for Pipeline Flow Reversals, Product Changes and Conversion of Service”
issued on September 18, 2014 (79 FR 56121, Docket PHMSA-2014-0400). The written flow
reversal plan must be submitted to the appropriate PHMSA OPS Region Director with a copy
of the plan submitted to the Federal Docket for this special permit at www.regulations.gov. If
FGT does not receive an objection letter from PHMSA within ninety (90) days of notifying
PHMSA, FGT can proceed with the pipeline system flow reversal through the special permit
segment.
e) Environmental Assessments and Permits: FGT proposes to evaluate the potential
environmental consequences and affected resources of any land disturbances and water body
crossings needed to implement the special permit conditions for a special permit segment or a
special permit inspection area prior to the disturbance. If a land disturbance or water body
crossings is required, FGT must obtain and adhere to all applicable (Federal, state, and local)
environmental permit requirements when conducting the special permit conditions activity.
18) Documentation: FGT must maintain the following records for the special permit segments:
a) Documentation showing that the special permit segments were subject to a 49 CFR 192.505,
Subpart J, hydrostatic test for eight (8) continuous hours and at a minimum pressure of 1.25
times MAOP. If FGT does not have hydrostatic test documentation, then the special permit
segment must be hydrostatically tested to meet this requirement within twenty-four (24) months
of receipt of this special permit.
13 An example of exceedance of 49 CFR 192.619(a)(1) is a Grandfathered MAOP which has a design factor above 0.72. An
example of exceedance of 49 CFR 192.611 is a Class 1 to 3 location change.
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b) Documentation of compliance with all conditions of this special permit must be kept for the
life of this special permit.
19) Extension of Special Permit Segment: PHMSA may extend the special permit segments to
include additional segments of the [FLBVW, FLMEE-26-27, FLMEF-26] up to the limits of the
special permit inspection area pursuant to the following conditions. The special permit segment
extension need not be contiguous with the special permit segment. FGT must comply with the
following conditions:
a) Any extensions of the special permit segment must meet the following requirements prior to
the class location change or within twenty-four (24) months after the class location change:
i) All anomalies must be remediated in accordance with Condition 9.
b) Provide at least ninety (90) days advanced notice to the appropriate PHMSA OPS Region
Director and PHMSA Headquarters of a requested extension of the special permit segment
based on actual class location change and include a schedule of inspections and of any
anticipated remedial actions. If PHMSA Headquarters or the PHMSA OPS Region Director
makes a written objection before the effective date of the requested special permit segment
extension (ninety (90) days from receipt of the above notice), the requested special permit
extension does not become effective until a “no objection” response from PHMSA is received
by FGT.
c) Complete all other inspections and remediation of the proposed special permit segment
extension to the extent required by this modified special permit within twenty-four (24) months
of the Class location change.
d) Apply all the special permit conditions and limitations included herein to all future extensions.
20) Certification: A senior executive officer, vice president or higher, of FGT must certify in writing
the following:
a) FGT special permit inspection areas and special permit segments meet the conditions
described in this special permit;
b) The written manual of O&M procedures for the FGT pipelines [FLBVW, FLMEE-26-27,
FLMEF-26] has been updated to include all additional requirements of this special permit; and
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c) FGT has implemented all original conditions and the conditions of this modification as required
by this special permit.
d) FGT must send the certifications required in Condition 20(a) through (c) with completion date,
compliance documentation summary, and the required senior executive signature and date of
signature to the PHMSA OPS Associate Administrator with copies to the Deputy Associate
Administrator, PHMSA OPS Field Operations; appropriate PHMSA OPS Region Director;
Director, PHMSA OPS Standards and Rulemaking Division; and Director, PHMSA OPS
Engineering and Research Division; and to the Federal Register Docket (PHMSA-2020-
XXXX) at www.Regulations.gov within twenty-four (24) months of the issuance date of this
special permit.