Application for Special Permit

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

PHMSA-2020-0044 – Florida Gas Transmission Company

Proposed Special Permit Conditions – For Public Comment Page 2 of 26

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



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



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.



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



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.



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.



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.



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,



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.




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.



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 %



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:



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;



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



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.



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



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.



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:



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;



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.



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.



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



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.



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.

http://www.regulations.gov/



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



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.

http://www.regulations.gov/

Documents

Application for Special Permit