Pipeline Safety: Grant of Special Permit; TransCanada Pipelines Limited, 72815-72819 [E7-24776]
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Federal Register / Vol. 72, No. 245 / Friday, December 21, 2007 / Notices
Environmental Process: In accordance
with NEPA, SAFETEA–LU section 6002
and FTA’s section 5309 New Starts
requirements, the project’s
environmental process has been divided
into three general phases: (1) Scoping;
(2) Alternatives Analysis/ EIS, selection
of the Locally Preferred Alternative
(LPA); selection of the Preferred
Alternative and (3) Final EIS.
III. Alternatives
The Feasibility Study conducted in
2005 recommended Bus Rapid Transit
(BRT) along University Parkway and
University Avenue with a detour off
University Avenue to serve Brigham
Young University (BYU). Because
population and employment densities
have changed in the study area since
2005, the AA/EIS will evaluate a wide
range of fixed guideway alternatives
including light rail and Bus Rapid
Transit. Bus Rapid Transit includes
exclusive transit lanes (either centerrunning or side-running) and queue
jump lanes. The preliminary
alternatives will be narrowed to a
locally preferred alternative based on
updated ridership forecasts. The locally
preferred alternative and a No-Action
alternative will be evaluated in detail in
the EIS resulting in the selection of a
Preferred Alternative.
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IV. Probable Effects
NEPA requires FTA and UTA to
evaluate the significant impacts of the
alternatives selected for study in the
AA/EIS. Primary issues identified thus
far include additional right-of-way
takes, business impacts, potential
impacts to historic properties, and
traffic and accessibility impacts. The
impacts will be evaluated for both the
construction period and for the longterm period of operation. Measures to
mitigate adverse impacts will be
developed.
V. FTA Procedures
The regulation implementing NEPA,
as well as provisions of the Safe,
Accountable, Flexible, Efficient
Transportation Equity Act: A Legacy for
Users (SAFETEA–LU), call for public
involvement in the NEPA process.
Section 6002 of SAFETEA–LU requires
that the lead agencies (FTA, UTA, and
MAG) do the following: (1) Extend an
invitation to other Federal and nonFederal agencies and Native American
tribes that may have an interest in the
proposed project to become
‘‘participating agencies;’’ (2) provide an
opportunity for involvement by
participating agencies and the public to
help define the purpose and need for a
proposed project, as well as the range of
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18:37 Dec 20, 2007
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alternatives for consideration in the EIS;
and (3) establish a plan for coordinating
public and agency participation in, and
comment on, the environmental review
process. An invitation to become a
participating or cooperating agency,
with scoping materials appended, will
be extended to other Federal and nonFederal agencies and Native American
tribes that may have an interest in the
proposed project. It is possible that the
lead agencies will not be able to identify
all Federal and non-Federal agencies
and Native American tribes that may
have such an interest. Any Federal or
non-Federal agency or Native American
tribe interested in the proposed project
that does not receive an invitation to
become a participating agency should
notify Pat Rothacher, Utah Transit
Authority, at 3600 South 700 West, Salt
Lake City, UT 84119 or
prothacher@rideuta.com.
UTA is seeking federal assistance
from the FTA to fund the proposed
project under 49 United States Code
5309 and will, therefore, be subject to
regulations (49 Code of Federal
Regulations (CFR) Part 611) related to
New Starts projects.
The AA/EIS will be prepared in
accordance with NEPA and its
implementing regulation issued by the
Council on Environmental Quality (40
CFR Parts 1500–1508) and with the
FTA/Federal Highway Administration
regulations ‘‘Environmental Impact and
Related Procedures’’ (23 CFR part 771).
In accordance with 23 CFR 771.105(a)
and 771.133, FTA will comply with all
Federal environmental laws,
regulations, and executive orders
applicable to the proposed project
during the environmental review
process. These requirements include,
but are not limited to, the
environmental and public hearing
provisions of Federal transit laws (49
U.S.C. 5301 (e), 5323 (b), and 5324); the
project-level air quality conformity
regulation of the U.S. Environmental
Protection Agency (EPA) (40 CFR Part
93); The section 404 (b)(1) guidelines of
EPA (40 CFR Part 230); the regulation
implementing section 106 of the
National Historic Preservation Act (36
CFR Part 800); the regulation
implementing section 7 of the
Endangered Species Act (50 CFR Part
402); section 4(f) of the Department of
Transportation Act (23 CFR 771.135);
and Executive Orders 12898 on
environmental justice, 11988 on
floodplain management, and 11990 on
wetlands.
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Issued on: December 14, 2007.
Charmaine Knighton,
Deputy Regional Administrator, Region VIII.
[FR Doc. E7–24861 Filed 12–20–07; 8:45 am]
BILLING CODE 4910–57–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
[Docket No. PHMSA–2006–24058]
Pipeline Safety: Grant of Special
Permit; TransCanada Pipelines Limited
Pipeline and Hazardous
Materials Safety Administration
(PHMSA); DOT.
ACTION: Notice; Grant of Special Permit.
AGENCY:
SUMMARY: The Pipeline and Hazardous
Materials Safety Administration
(PHMSA) is granting TransCanada
Pipelines Limited (TransCanada) a
special permit waiving compliance from
the Federal pipeline safety regulation in
49 CFR 192.611 for two pipeline
segments in the Portland Natural Gas
Transmission System, described below
under ‘‘Pipeline System Affected.’’ The
regulation requires natural gas pipeline
operators to confirm or revise the
maximum allowable operating pressure
of a pipeline after a change in class
location.
FOR FURTHER INFORMATION CONTACT:
Alan Mayberry at (202) 366–5124, or by
e-mail at Alan.Mayberry @dot.gov; or
Wayne Lemoi at (404) 832–1160 or by
e-mail at Wayne.Lemoi@dot.gov.
SUPPLEMENTARY INFORMATION:
Special Permit Request
Pipeline Operator: TransCanada
petitioned PHMSA on April 8, 2005, for
a special permit to waive compliance
from the Federal pipeline safety
regulation in 49 CFR § 192.611 for two
pipeline segments of the Portland
Natural Gas Transmission System
(PNGTS) 24-inch mainline operated by
TransCanada and described below
under ‘‘Pipeline System Affected.’’ The
regulation requires natural gas pipeline
operators to confirm or revise the
maximum allowable operating pressure
(MAOP) of a pipeline after a change in
class location.
Pipeline System Affected: This special
permit request covers two segments of a
single 24-inch pipeline known as the
PNGTS pipeline in and near the town of
North Windham, Maine. Special permit
segment 1 includes 615 feet that
changed from a Class 1 location to a
Class 3 location on March 1, 2004, and
an additional 2,298 feet that
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TransCanada anticipates will change
from a Class 1 location to a Class 3
location for a total of 2,913 feet. Special
permit segment 2 is just upstream of
special permit segment 1 and includes
4,766 feet anticipated by TransCanada
to change from a Class 1 location to a
Class 3 location. Anticipated class
location change for both special permit
segments is due to residential and
commercial development anticipated by
TransCanada. The two ‘‘special permit
segments’’ are defined as follows:
• Special Permit Segment 1: 2,913
feet, mile post (MP) 132.20 to MP 132.75
• Special Permit Segment 2: 4,766
feet, MP 130.88 to MP 131.78
A special permit inspection area is
defined as the area within 220 yards of
each side of a pipeline centerline along
the entire length of the special permit
segment and along the pipeline up to 25
miles upstream and downstream of the
special permit segment. The ‘‘special
permit inspection area’’ for this special
permit consists of the area within 220
yards of each side of the PNGTS
pipeline centerline along the entire
length of the pipeline from 25 miles
upstream of special permit segment 2 to
approximately 10 miles downstream of
special permit segment 1 and is
inclusive of both special permit
segments.
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Public Notice
On September 7, 2006, PHMSA
published a notice of the TransCanada
request in the Federal Register (71 FR
52871) inviting interested persons to
comment on the request. On February 8,
2007, PHMSA posted another notice in
the Federal Register (72 FR 6042)
informing the public that we have
changed the name granting a waiver to
a special permit. We did not receive any
public comments for or against this
special permit request. We also
requested and received supplemental
information from TransCanada. The
special permit petition, Federal Register
notice, supplemental information from
TransCanada and all other documents
pertinent to this special permit request
are available for review by the public in
Docket Number PHMSA–2006–24058 in
the Federal Docket Management System
(FDMS) located on the internet at
www.Regulations.gov.
Special Permit Analysis
Background: On June 29, 2004,
PHMSA published in the Federal
Register (69 FR 38948) the criteria it
uses for the consideration of class
location change special permits. First,
certain threshold requirements must be
met for a pipeline section to be further
evaluated for a class location change
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special permit. Second, the age and
manufacturing process of the pipe;
system design and construction;
environmental, operating and
maintenance histories; and integrity
management program (IMP) elements
are evaluated as significant criteria.
These significant criteria are presented
in matrix form and can be reviewed in
the FDMS, Docket Number PHMSARSPA–2004–17401. Third, such special
permits will only then be granted when
pipe conditions and active integrity
management provides a level of safety
greater than or equal to a pipe
replacement or pressure reduction.
Threshold Requirements: Each of the
threshold requirements published by
PHMSA in the June 29, 2004 FR notice
is discussed below for the TransCanada
special permit petition.
(1) No pipeline segments in a class
location changing to Class 4 location
will be considered. This special permit
request is for two pipeline segments in
class locations that have changed or are
anticipated to change from Class 1 to
Class 3. This requirement has been met
for both PNGTS special permit
segments.
(2) No bare pipe will be considered.
Both special permit segments of the
PNGTS pipeline are coated with Fusion
Bond Epoxy (FBE), meeting this
requirement.
(3) No pipe containing wrinkle bends
will be considered. There are no wrinkle
bends in the special permit segments.
This requirement has been met for both
PNGTS special permit segments.
(4) No pipe segments operating above
72 percent of the specified minimum
yield strength (SMYS) will be
considered for a Class 3 special permit.
The PNGTS pipeline operates at or
below 72 percent SMYS. This
requirement has been met for both
PNGTS special permit segments.
(5) Records must be produced that
show a hydrostatic test to at least 1.25
× MAOP. The PNGTS pipeline has been
hydrostatically tested to 1,846 pounds
per square inch gauge (psig), 1.28 ×
MAOP. This requirement has been met
for both PNGTS special permit
segments.
(6) In-line inspection (ILI) must have
been performed with no significant
anomalies identified that indicate
systemic problems. The PNGTS pipeline
has been ILI inspected with no
significant anomalies in the special
permit segments, thus meeting this
requirement.
(7) The special permit inspection area
must be inspected according to the
operator’s IMP and periodically
inspected with an in-line inspection
technique. This special permit will
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include conditions requiring
TransCanada to perform additional
inspections in the special permit
inspection area on a frequency
consistent with the integrity
management regulations contained in 49
CFR Part 192, Subpart O. The special
permit conditions will also require
TransCanada to incorporate both special
permit segments in its written IMP as
‘‘covered segments’’ in a ‘‘high
consequence area (HCA)’’ per 49 CFR
192.903.
Criteria Matrix: The original and
supplemental data submitted by
TransCanada for the special permit
segments have been compared to the
class location change special permit
criteria matrix. The data falls within the
‘‘probable acceptance’’ column of the
criteria matrix for all criteria except for
a change, from a Class 1 location to a
Class 3 location, which falls within the
‘‘possible acceptance’’ column of the
criteria matrix, and the ILI Time Frame
Requirement which falls within the
‘‘possible acceptance’’ column of the
criteria matrix.
(1) Pipe design and construction,
including pipe manufacture, material,
design stress and weld radiography: the
pipe of both special permit segments
was manufactured in 1998–1999 of
American Petroleum Institute
Specification 5L, Specification for Line
Pipe (API 5L), X–70 steel, using a 72
percent SMYS design factor per
§ 192.111, with documented 100 percent
circumferential field weld radiographic
inspection. The pipe coating is millapplied FBE with field-applied FBE on
circumferential welds. All of these
factors fall within the ‘‘probable
acceptance’’ column of the criteria
matrix.
(2) Pressure testing: both special
permit segments were pressure tested in
1998 to 1,846 psig corresponding to 128
percent MAOP and 92 percent SMYS.
No test failures occurred. These factors
fall within the ‘‘probable acceptance’’
column of the criteria matrix.
(3) Environmental considerations: the
depth of cover is given as 48 inches for
both special permit segments, exceeding
the requirements of § 192.327(a). Both
special permit segments are located in
stable terrain that does not contain any
major slopes. These factors fall within
the ‘‘probable acceptance’’ column of
the criteria matrix.
(4) Operational considerations:
according to TransCanada, there were
no leaks or failures in the two special
permit segments of the pipeline. The
pipeline transports only dry gas with
light pressure fluctuations. Cathodic
protection (CP) was operational in the
fall of 1999 on both pipeline special
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permit segments, which was within 9
months of the in-service date of the
pipeline. A baseline close interval
survey (CIS) of the entire PNGTS
pipeline was performed during the
summer of 2000. No low potentials or
CP anomalies were identified in the
special permit segments. No safety
related condition reports (SRCR) have
been issued for the special permit
segments. These factors fall within the
‘‘probable acceptance’’ column of the
criteria matrix.
(5) Integrity management program:
special permit segment 1 is currently
within an HCA, while special permit
segment 2 is anticipated by
TransCanada to become an HCA in its
entirety due to anticipated
development. The entire PNGTS
pipeline (including both special permit
segments) transports odorized gas.
Leakage surveys using leak detection
equipment are performed annually on
the entire pipeline including the special
permit segments. PNGTS performed an
ILI on November 1, 2002, which was
more than two years but less than five
years prior to the special permit
application date, placing this criterion
in the ‘‘possible acceptance’’ column of
the criteria matrix. Two minor (less than
4 percent) anomalies identified in the
2002 ILI were excavated in 2005; no
active corrosion was found. A high
resolution magnetic flux leakage (MFL)
ILI is scheduled for 2009 on the pipeline
sections including the special permit
segments. A baseline CIS was performed
in 2002 on the entire PNGTS pipeline
system. TransCanada annually performs
a CIS of 15–20 percent of the system and
proposes to perform a CIS on the special
permit segments annually. TransCanada
has not identified any coating or
corrosion issues. TransCanada proposes
to perform a direct current voltage
gradient (DCVG) survey on both special
permit segments and 1,000 feet
upstream and downstream of the special
permit segments. TransCanada also
proposes to perform weekly aerial
patrols and quarterly ground road
crossing patrols, including leakage
surveys, using leak detection equipment
in the proposed special permit
segments. TransCanada additionally
proposes to install buried excavation
warning tape over the pipeline
comprising the special permit segments.
All of these factors, with the exception
of the ILI time frame criterion, fall
within the ‘‘probable acceptance’’
column. The ILI time frame falls within
the ‘‘possible acceptance’’ column
because it was several months outside
the two year requirement prior to the
special permit application.
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Special Permit Findings
PHMSA finds that granting this
special permit is not inconsistent with
pipeline safety and will provide a level
of safety equal to or greater than pipe
replacement or pressure reduction. We
do so because the special permit
analysis shows the following:
(1) The special permit segments meet
six of the seven threshold requirements.
The seventh threshold requirement, that
the special permit inspection area be
inspected according to the operator’s
IMP and periodically inspected with an
in-line inspection technique, will be
addressed in the special permit
conditions. The special permit
conditions will also include annual
inspection requirements of the special
permit inspection area and both special
permit segments on a frequency
consistent with 49 CFR 192, Subpart O;
the Integrity Management regulations.
(2) The special permit segments fall in
the ‘‘probable acceptance’’ column of
the criteria matrix for all criteria except
for class location change and ILI time
frame. The class location change for
both special permit segments is from a
Class 1 location to a Class 3 location,
which places this parameter in the
‘‘possible acceptance’’ column. The last
ILI that was performed on the entire
PNGTS pipeline containing the special
permit segments was on November 1,
2002, which is longer than two but less
than five years preceding the special
permit petition. This places the ILI time
frame parameter in the ‘‘possible
acceptance’’ column.
(3) The special permit conditions will
require TransCanada to implement
enhanced IMP actions for the entire
special permit inspection area.
Special Permit Grant
PHMSA grants a special permit of
compliance from 49 CFR 192.611 to
TransCanada Pipelines Limited for two
pipeline segments defined below in or
near North Windham, Maine in the
Portland Natural Gas Transmission
System. The special permit segments are
where the class locations along the
pipeline have changed or are
anticipated to change in the future from
a Class 1 location to a Class 3 location.
As of July 1, 2007, only 615 feet of
special permit segment 1 has actually
changed to Class 3 location. PHMSA is
nevertheless granting this special permit
for both the actual and the anticipated
class location change along both special
permit segments because the additional
integrity management program actions
required by this special permit for the
entire special permit inspection area
will enhance the safety of operation of
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the PNGTS pipeline. This special permit
applies to the pipeline special permit
segments defined as follows:
• Special permit segment 1: 2,913
feet, mile post (MP) 132.20 to MP 132.75
• Special permit segment 2: 4,766
feet, MP 130.88 to MP 131.78
A special permit inspection area is
defined as the area within 220 yards of
each side of a pipeline centerline along
the entire length of the special permit
segment and along the pipeline up to 25
miles upstream and downstream of the
special permit segment. The ‘‘special
permit inspection area’’ for this special
permit consists of the area within 220
yards of each side of the PNGTS
pipeline centerline along the entire
length of the pipeline from 25 miles
upstream of special permit segment 2 to
approximately 10 miles downstream of
special permit segment 1 and inclusive
of both special permit segments.
Special Permit Conditions
This special permit is granted with
the following conditions:
(1) TransCanada must continue to
operate the special permit segments at
or below the existing MAOP.
(2) TransCanada must incorporate
both special permit segment 1 and
special permit segment 2 into its written
IMP as ‘‘covered segments’’ in an HCA
as defined in 49 CFR Subpart O,
§ 192.903, except for the reporting
requirements contained in 49 CFR
192.945. The special permit segments
included in this special permit need not
be included in TransCanada’s IMP
baseline assessment plan.
(3) TransCanada must perform a CIS
of the entire length of the special permit
inspection area not later than one year
after the grant of special permit and
remediate any areas of inadequate
cathodic protection. A CIS and
remediation need not be performed on
the special permit inspection area if a
CIS and remediation have been
performed within 6 years of the grant of
special permit. If factors beyond
TransCanada’s control prevent the
completion of the CIS and remediation
within one year, a CIS and remediation
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
Director, PHMSA Eastern Region not
later than one year of the grant of
special permit.
(4) TransCanada must perform
ongoing CIS of both special permit
segment 1 and special permit segment 2
at the applicable reassessment
interval(s) for a ‘‘covered segment’’
determined in accordance with 49 CFR
192.939.
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(5) TransCanada must perform a
Direct Current Voltage Gradient (DCVG)
survey of both special permit segment 1
and special permit segment 2 not later
than one year after the grant of special
permit to verify the pipeline coating
conditions and to remediate any
integrity issues in the special permit
segments. If factors beyond
TransCanada’s control prevent the
completion of the DCVG and
remediation within one year, a DCVG
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 Director, PHMSA
Eastern Region not later than one year
of the grant of special permit.
(6) TransCanada must evaluate the
potential for stress corrosion cracking
(SCC), according to 49 CFR 192.929
within one year after the grant of special
permit. If the potential for SCC is
identified, TransCanada must perform a
stress corrosion cracking direct
assessment (SCCDA) of the special
permit inspection area in accordance
with 49 CFR 192.929.
(7) TransCanada must submit the CIS,
DCVG and SCCDA findings including
remediation actions in a written report
to the Director, PHMSA Eastern Region
not later than two years after the grant
of special permit.
(8) TransCanada must amend
applicable sections of its operations and
maintenance (O&M) manual(s) to
incorporate the inspection and
reassessment intervals by ILI along the
entire length of the special permit
inspection area at a frequency
consistent with 49 CFR § 192, Subpart
O.
(9) TransCanada must amend
applicable sections of its O&M
manual(s) to incorporate the inspection
and reassessment intervals by CIS of
both special permit segment 1 and
special permit segment 2 at a frequency
consistent with 49 CFR Part 192,
Subpart O.
(10) The assessments of the special
permit segments and the special permit
inspection area using ILI must conform
to the required maximum reassessment
intervals specified in 49 CFR 192.939.
(11) TransCanada must schedule
future reassessment dates for the special
permit inspection area according to 49
CFR § 192.939 by adding the required
time interval to the previous assessment
date.
(12) TransCanada must ensure their
damage prevention program
incorporates the applicable best
practices of the Common Ground
Alliance (CGA) within the special
permit inspection area.
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18:37 Dec 20, 2007
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(13) TransCanada must give sufficient
notice to the Director, PHMSA Eastern
Region to enable observation of any or
all special permit related activities in
the special permit inspection area.
(14) TransCanada must determine and
provide certification that all inspections
and activities associated with this
special permit will not impact or defer
any of the operator’s assessments for
HCAs under 49 CFR part § 192, subpart
O, particularly those associated with the
most significant 50 percent.
(15) Within three months following
approval of this special permit and
annually thereafter, TransCanada must
report the following to the Director,
PHMSA Eastern Region:
(a) The economic benefits of the
special permit to TransCanada. This
should address both the costs avoided
from not replacing the pipe and the
added costs of the inspection program
(required for the initial report only).
(b) In the first annual report, fully
describe how the public benefits from
energy availability. This should address
the benefits of avoided disruptions as a
consequence of pipe replacement and
the benefits of maintaining system
capacity. Subsequent reports must
indicate any changes to this initial
assessment.
(c) The number of new residences,
other structures intended for human
occupancy and public gathering areas
built within the special permit
inspection area.
(d) Any new integrity threats
identified during the previous year and
the results of any in-line inspections or
direct assessments performed during the
previous year in the special permit
inspection area.
(e) 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 inspection area.
(f) On-going damage prevention
initiatives affecting the special permit
inspection area and a discussion on the
success of the initiatives.
(g) Any mergers, acquisitions, transfer
of assets, or other events affecting the
regulatory responsibility of the company
operating the pipeline.
(16) At least one CP pipe-to-soil test
station must be located within each
HCA with a maximum spacing between
test stations of one-half mile within an
HCA. In cases where obstructions or
restricted areas prevent test station
placement, the test station must be
placed in the closest practical location.
This requirement applies to any HCA
within the special permit inspection
area.
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(17) If any annual test station readings
within the special permit inspection
area fall below 49 CFR part 192, subpart
I requirements, remediation must occur
within six months and include a CIS on
each side of the affected test station to
the next test station and identified
corrosion system modifications to
ensure corrosion control. If factors
beyond TransCanada’s control prevent
the completion of remediation within
six months, remediation 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 Director, PHMSA
Eastern Region not later than one year
after the grant of special permit.
(18) Anomaly Evaluation and Repair:
(a) General: TransCanada shall
account for ILI tool tolerance and
corrosion growth rates in scheduled
response times and repairs.
(b) Dents: TransCanada shall repair
dents in the special permit segments
and special permit inspection area in
accordance with 49 CFR § 192.933.
(c) Repair Criteria: Repair criteria
applies to anomalies located within the
special permit inspection area when
they have been excavated and
investigated in accordance with 49 CFR
192.485 and 192.933 as follows:
(i) Special permit segments—repair
any anomaly with a failure pressure
ratio (FPR) less than or equal to 1.39 for
pipe operating at a stress level up to 72
percent of SMYS and any anomaly
greater than 50 percent of pipe wall
thickness.
(ii) Special permit inspection area—
the response time must be in accordance
with 49 CFR § 192, subpart O, the
applicable edition of the American
Society of Mechanical Engineers
Standard B31.8S, Managing System
Integrity of Gas Pipelines (ASME
B31.8S) and TransCanada’s IMP.
(d) Response Time for ILI Results: The
following guidelines provide the
required timing for excavation and
investigation of anomalies based on ILI
results. Reassessment by ILI will ‘‘reset’’
the timing for anomalies not already
investigated and/or repaired.
TransCanada must evaluate ILI data by
using either the ASME Standard B31G,
Manual for Determining the Remaining
Strength of Corroded Pipelines (ASME
B31G), or the Modified B31G (0.85dL)
for calculating the predicted failure
pressure ratio to determine anomaly
responses.
(i) Special permit segment:
—Immediate response: FPR equal to or
less than 1.1 or anomalies equal to
and greater than 80 percent of pipe
wall thickness;
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—1-year response: pipe operating at a
stress level up to 72 percent of
SMYS—FPR equal to or less than 1.39
and anomalies equal to or greater than
60 percent of pipe wall thickness;
—Scheduled reponse: pipe operating at
a stress level up to 72 percent of
SMYS—FPR greater than 1.39 and
anomalies less than 60 percent of pipe
wall thickness.
(ii) Special permit inspection area:
The response time must be in
accordance with 49 CFR § 192, subpart
O, ASME B31.8S (applicable edition)
and TransCanada’s IMP.
(19) PHMSA may extend either or
both of the original special permit
segments to include contiguous
segments of pipeline up to the limits of
the special permit inspection area
pursuant to the following conditions.
TransCanada must:
(a) Provide at least 90 days advance
written notice to the Director, PHMSA
Eastern Region and PHMSA
Headquarters of a requested extension of
either or both of special permit segment
1 and special permit segment 2 based on
an actual class location change and
include a schedule of inspections and of
any anticipated remedial actions. If
PHMSA Headquarters makes a written
objection before the effective date of the
requested special permit segment (90
days from receipt of the above notice),
the requested special permit segment
extension does not become effective.
(b) Complete all inspections and
remediation of the proposed special
permit segment extension to the extent
required of the original special permit
segment.
(c) Apply all the special permit
conditions and limitations included
herein to all future extensions.
Special Permit Limitations
PHMSA has the sole authority to
make all determinations on whether
TransCanada has complied with the
specified conditions. Should
TransCanada fail to comply with any
conditions of this special permit, or
should PHMSA determine this special
permit is no longer appropriate or that
this special permit is inconsistent with
pipeline safety, PHMSA may revoke this
special permit and require TransCanada
to comply with the regulatory
requirements of 49 CFR 192.611.
mstockstill on PROD1PC66 with NOTICES
Authority: 49 U.S.C. 60118 (c)(1) and 49
CFR 1.53.
Issued in Washington, DC on December 17,
2007.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. E7–24776 Filed 12–20–07; 8:45 am]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Surface Transportation Board
[STB Finance Docket No. 35087]
Canadian National Railway Company
and Grand Trunk Corporation—
Control—EJ&E West Company
AGENCY:
Surface Transportation Board,
DOT.
Notice of Intent To Prepare an
Environmental Impact Statement (EIS);
Notice of Initiation of the Scoping
Process, Including Notice of Availability
of Draft Scope of Study for
Environmental Impact Statement;
Request for Comments on Draft Scope;
and Notice of Open-House Meetings.
ACTION:
SUMMARY: On October 30, 2007,
Canadian National Railway Corporation
(CNR) and Grand Trunk Corporation
(GTC), a noncarrier holding company
through which CNR controls its U.S. rail
subsidiaries, filed an application with
the Surface Transportation Board
(Board) seeking the Board’s approval of
the acquisition of control of EJ&E West
Company (EJ&EW), a wholly owned
noncarrier subsidiary of Elgin, Joliet and
Eastern Railway Company (EJ&E). In
this document, the action before the
Board will be referred to as the proposal
or the proposed acquisition and CNR
and GTC will be referred to collectively
as CN or as Applicants.
CN is one of Canada’s two major
railroads. It extends from Halifax, Nova
Scotia, to Vancouver and Prince Rupert,
British Columbia. EJ&E is a Class II
railroad that currently operates over 198
miles of track in northeastern Illinois
and northwestern Indiana, consisting
primarily of an arc of roughly 190 miles
around Chicago, IL, extending from
Waukegan, IL, southwards to Joliet, IL,
then eastward to Gary, IN, and then
northwest to South Chicago along Lake
Michigan. EJ&E provides rail service to
approximately 100 customers, including
steel mills, coal utilities, plastics and
chemical producers, steel processors,
distribution centers, and scrap
processors.
72819
Applicants’ proposed acquisition of
the EJ&E would shift rail traffic
currently moving over CN’s rail lines
inside the EJ&E arc in Chicago to the
EJ&E, which traverses the suburbs
generally to the west and south of
Chicago. Rail traffic on CNR lines inside
the EJ&E arc would generally decrease.
The decreases in rail traffic would be
offset by increases in the number of
trains operating on the EJ&E rail line
outside of Chicago (approximately 15–
27 more trains would operate on various
segments of the EJ&E). Applicants also
proposed to construct six new rail
connections and approximately 19 miles
of new sidings/double tracking.
Applicants give three primary reasons
for seeking approval of the proposed
acquisition: Improved rail operations in
the Chicago area; availability to EJ&E’s
Kirk Yard in Gary, Indiana, and other
smaller facilities in Joliet, Illinois, and
Whiting, Indiana; and improved service
to companies dealing in steel,
chemicals, and petrochemicals, as well
as Chicago area utilities.
To thoroughly assess the potential
environmental impacts that may result
from the proposed acquisition, the
Board, through its Section of
Environmental Analysis (SEA), will
prepare an Environmental Impact
Statement (EIS). The purpose of this
Notice is to give all interested persons
the opportunity to actively participate
in the forthcoming environmental
review, the first step of which is
‘‘scoping.’’ Scoping is an open process
for determining the range of issues that
should be examined and assessed in the
EIS. In addition to announcing that the
Board will prepare an EIS for this
proceeding, this Notice also announces
the availability of a draft scope of study,
requests comments on the draft scope of
study, and presents the schedule of
Open-House meetings to be held in the
project area.
Scoping
Open House meetings will be held at the
dates and locations listed below. Each
location will have an afternoon and an
evening session at the following times:
The afternoon Open House is scheduled
from 1p.m. to 4 p.m. and the evening
Open House is scheduled from 6 p.m. to
8 p.m. There is no need to attend more
than one meeting, but all are welcome
to attend as many meetings as desired.
DATES, TIMES, AND LOCATIONS:
Date
Location
January 8, 2008 ..................................................................
Crown Plaza, Salon A/C Room, 510 E. Route 83, Mundelein, IL 60060, 847–949–
5100.
Makray Memorial Golf Club, Grand Ballroom, 1010 S. NW., Highway, Barrington, IL
60010, 847–381–6500.
January 9, 2008 ..................................................................
VerDate Aug<31>2005
18:37 Dec 20, 2007
Jkt 214001
PO 00000
Frm 00155
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21DEN1
]]>Agencies
[Federal Register Volume 72, Number 245 (Friday, December 21, 2007)]
[Notices]
[Pages 72815-72819]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E7-24776]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
[Docket No. PHMSA-2006-24058]
Pipeline Safety: Grant of Special Permit; TransCanada Pipelines
Limited
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA);
DOT.
ACTION: Notice; Grant of Special Permit.
-----------------------------------------------------------------------
SUMMARY: The Pipeline and Hazardous Materials Safety Administration
(PHMSA) is granting TransCanada Pipelines Limited (TransCanada) a
special permit waiving compliance from the Federal pipeline safety
regulation in 49 CFR 192.611 for two pipeline segments in the Portland
Natural Gas Transmission System, described below under ``Pipeline
System Affected.'' The regulation requires natural gas pipeline
operators to confirm or revise the maximum allowable operating pressure
of a pipeline after a change in class location.
FOR FURTHER INFORMATION CONTACT: Alan Mayberry at (202) 366-5124, or by
e-mail at Alan.Mayberry @dot.gov; or Wayne Lemoi at (404) 832-1160 or
by e-mail at Wayne.Lemoi@dot.gov.
SUPPLEMENTARY INFORMATION:
Special Permit Request
Pipeline Operator: TransCanada petitioned PHMSA on April 8, 2005,
for a special permit to waive compliance from the Federal pipeline
safety regulation in 49 CFR Sec. 192.611 for two pipeline segments of
the Portland Natural Gas Transmission System (PNGTS) 24-inch mainline
operated by TransCanada and described below under ``Pipeline System
Affected.'' The regulation requires natural gas pipeline operators to
confirm or revise the maximum allowable operating pressure (MAOP) of a
pipeline after a change in class location.
Pipeline System Affected: This special permit request covers two
segments of a single 24-inch pipeline known as the PNGTS pipeline in
and near the town of North Windham, Maine. Special permit segment 1
includes 615 feet that changed from a Class 1 location to a Class 3
location on March 1, 2004, and an additional 2,298 feet that
[[Page 72816]]
TransCanada anticipates will change from a Class 1 location to a Class
3 location for a total of 2,913 feet. Special permit segment 2 is just
upstream of special permit segment 1 and includes 4,766 feet
anticipated by TransCanada to change from a Class 1 location to a Class
3 location. Anticipated class location change for both special permit
segments is due to residential and commercial development anticipated
by TransCanada. The two ``special permit segments'' are defined as
follows:
Special Permit Segment 1: 2,913 feet, mile post (MP)
132.20 to MP 132.75
Special Permit Segment 2: 4,766 feet, MP 130.88 to MP
131.78
A special permit inspection area is defined as the area within 220
yards of each side of a pipeline centerline along the entire length of
the special permit segment and along the pipeline up to 25 miles
upstream and downstream of the special permit segment. The ``special
permit inspection area'' for this special permit consists of the area
within 220 yards of each side of the PNGTS pipeline centerline along
the entire length of the pipeline from 25 miles upstream of special
permit segment 2 to approximately 10 miles downstream of special permit
segment 1 and is inclusive of both special permit segments.
Public Notice
On September 7, 2006, PHMSA published a notice of the TransCanada
request in the Federal Register (71 FR 52871) inviting interested
persons to comment on the request. On February 8, 2007, PHMSA posted
another notice in the Federal Register (72 FR 6042) informing the
public that we have changed the name granting a waiver to a special
permit. We did not receive any public comments for or against this
special permit request. We also requested and received supplemental
information from TransCanada. The special permit petition, Federal
Register notice, supplemental information from TransCanada and all
other documents pertinent to this special permit request are available
for review by the public in Docket Number PHMSA-2006-24058 in the
Federal Docket Management System (FDMS) located on the internet at
www.Regulations.gov.
Special Permit Analysis
Background: On June 29, 2004, PHMSA published in the Federal
Register (69 FR 38948) the criteria it uses for the consideration of
class location change special permits. First, certain threshold
requirements must be met for a pipeline section to be further evaluated
for a class location change special permit. Second, the age and
manufacturing process of the pipe; system design and construction;
environmental, operating and maintenance histories; and integrity
management program (IMP) elements are evaluated as significant
criteria. These significant criteria are presented in matrix form and
can be reviewed in the FDMS, Docket Number PHMSA-RSPA-2004-17401.
Third, such special permits will only then be granted when pipe
conditions and active integrity management provides a level of safety
greater than or equal to a pipe replacement or pressure reduction.
Threshold Requirements: Each of the threshold requirements
published by PHMSA in the June 29, 2004 FR notice is discussed below
for the TransCanada special permit petition.
(1) No pipeline segments in a class location changing to Class 4
location will be considered. This special permit request is for two
pipeline segments in class locations that have changed or are
anticipated to change from Class 1 to Class 3. This requirement has
been met for both PNGTS special permit segments.
(2) No bare pipe will be considered. Both special permit segments
of the PNGTS pipeline are coated with Fusion Bond Epoxy (FBE), meeting
this requirement.
(3) No pipe containing wrinkle bends will be considered. There are
no wrinkle bends in the special permit segments. This requirement has
been met for both PNGTS special permit segments.
(4) No pipe segments operating above 72 percent of the specified
minimum yield strength (SMYS) will be considered for a Class 3 special
permit. The PNGTS pipeline operates at or below 72 percent SMYS. This
requirement has been met for both PNGTS special permit segments.
(5) Records must be produced that show a hydrostatic test to at
least 1.25 x MAOP. The PNGTS pipeline has been hydrostatically tested
to 1,846 pounds per square inch gauge (psig), 1.28 x MAOP. This
requirement has been met for both PNGTS special permit segments.
(6) In-line inspection (ILI) must have been performed with no
significant anomalies identified that indicate systemic problems. The
PNGTS pipeline has been ILI inspected with no significant anomalies in
the special permit segments, thus meeting this requirement.
(7) The special permit inspection area must be inspected according
to the operator's IMP and periodically inspected with an in-line
inspection technique. This special permit will include conditions
requiring TransCanada to perform additional inspections in the special
permit inspection area on a frequency consistent with the integrity
management regulations contained in 49 CFR Part 192, Subpart O. The
special permit conditions will also require TransCanada to incorporate
both special permit segments in its written IMP as ``covered segments''
in a ``high consequence area (HCA)'' per 49 CFR 192.903.
Criteria Matrix: The original and supplemental data submitted by
TransCanada for the special permit segments have been compared to the
class location change special permit criteria matrix. The data falls
within the ``probable acceptance'' column of the criteria matrix for
all criteria except for a change, from a Class 1 location to a Class 3
location, which falls within the ``possible acceptance'' column of the
criteria matrix, and the ILI Time Frame Requirement which falls within
the ``possible acceptance'' column of the criteria matrix.
(1) Pipe design and construction, including pipe manufacture,
material, design stress and weld radiography: the pipe of both special
permit segments was manufactured in 1998-1999 of American Petroleum
Institute Specification 5L, Specification for Line Pipe (API 5L), X-70
steel, using a 72 percent SMYS design factor per Sec. 192.111, with
documented 100 percent circumferential field weld radiographic
inspection. The pipe coating is mill-applied FBE with field-applied FBE
on circumferential welds. All of these factors fall within the
``probable acceptance'' column of the criteria matrix.
(2) Pressure testing: both special permit segments were pressure
tested in 1998 to 1,846 psig corresponding to 128 percent MAOP and 92
percent SMYS. No test failures occurred. These factors fall within the
``probable acceptance'' column of the criteria matrix.
(3) Environmental considerations: the depth of cover is given as 48
inches for both special permit segments, exceeding the requirements of
Sec. 192.327(a). Both special permit segments are located in stable
terrain that does not contain any major slopes. These factors fall
within the ``probable acceptance'' column of the criteria matrix.
(4) Operational considerations: according to TransCanada, there
were no leaks or failures in the two special permit segments of the
pipeline. The pipeline transports only dry gas with light pressure
fluctuations. Cathodic protection (CP) was operational in the fall of
1999 on both pipeline special
[[Page 72817]]
permit segments, which was within 9 months of the in-service date of
the pipeline. A baseline close interval survey (CIS) of the entire
PNGTS pipeline was performed during the summer of 2000. No low
potentials or CP anomalies were identified in the special permit
segments. No safety related condition reports (SRCR) have been issued
for the special permit segments. These factors fall within the
``probable acceptance'' column of the criteria matrix.
(5) Integrity management program: special permit segment 1 is
currently within an HCA, while special permit segment 2 is anticipated
by TransCanada to become an HCA in its entirety due to anticipated
development. The entire PNGTS pipeline (including both special permit
segments) transports odorized gas. Leakage surveys using leak detection
equipment are performed annually on the entire pipeline including the
special permit segments. PNGTS performed an ILI on November 1, 2002,
which was more than two years but less than five years prior to the
special permit application date, placing this criterion in the
``possible acceptance'' column of the criteria matrix. Two minor (less
than 4 percent) anomalies identified in the 2002 ILI were excavated in
2005; no active corrosion was found. A high resolution magnetic flux
leakage (MFL) ILI is scheduled for 2009 on the pipeline sections
including the special permit segments. A baseline CIS was performed in
2002 on the entire PNGTS pipeline system. TransCanada annually performs
a CIS of 15-20 percent of the system and proposes to perform a CIS on
the special permit segments annually. TransCanada has not identified
any coating or corrosion issues. TransCanada proposes to perform a
direct current voltage gradient (DCVG) survey on both special permit
segments and 1,000 feet upstream and downstream of the special permit
segments. TransCanada also proposes to perform weekly aerial patrols
and quarterly ground road crossing patrols, including leakage surveys,
using leak detection equipment in the proposed special permit segments.
TransCanada additionally proposes to install buried excavation warning
tape over the pipeline comprising the special permit segments. All of
these factors, with the exception of the ILI time frame criterion, fall
within the ``probable acceptance'' column. The ILI time frame falls
within the ``possible acceptance'' column because it was several months
outside the two year requirement prior to the special permit
application.
Special Permit Findings
PHMSA finds that granting this special permit is not inconsistent
with pipeline safety and will provide a level of safety equal to or
greater than pipe replacement or pressure reduction. We do so because
the special permit analysis shows the following:
(1) The special permit segments meet six of the seven threshold
requirements. The seventh threshold requirement, that the special
permit inspection area be inspected according to the operator's IMP and
periodically inspected with an in-line inspection technique, will be
addressed in the special permit conditions. The special permit
conditions will also include annual inspection requirements of the
special permit inspection area and both special permit segments on a
frequency consistent with 49 CFR 192, Subpart O; the Integrity
Management regulations.
(2) The special permit segments fall in the ``probable acceptance''
column of the criteria matrix for all criteria except for class
location change and ILI time frame. The class location change for both
special permit segments is from a Class 1 location to a Class 3
location, which places this parameter in the ``possible acceptance''
column. The last ILI that was performed on the entire PNGTS pipeline
containing the special permit segments was on November 1, 2002, which
is longer than two but less than five years preceding the special
permit petition. This places the ILI time frame parameter in the
``possible acceptance'' column.
(3) The special permit conditions will require TransCanada to
implement enhanced IMP actions for the entire special permit inspection
area.
Special Permit Grant
PHMSA grants a special permit of compliance from 49 CFR 192.611 to
TransCanada Pipelines Limited for two pipeline segments defined below
in or near North Windham, Maine in the Portland Natural Gas
Transmission System. The special permit segments are where the class
locations along the pipeline have changed or are anticipated to change
in the future from a Class 1 location to a Class 3 location. As of July
1, 2007, only 615 feet of special permit segment 1 has actually changed
to Class 3 location. PHMSA is nevertheless granting this special permit
for both the actual and the anticipated class location change along
both special permit segments because the additional integrity
management program actions required by this special permit for the
entire special permit inspection area will enhance the safety of
operation of the PNGTS pipeline. This special permit applies to the
pipeline special permit segments defined as follows:
Special permit segment 1: 2,913 feet, mile post (MP)
132.20 to MP 132.75
Special permit segment 2: 4,766 feet, MP 130.88 to MP
131.78
A special permit inspection area is defined as the area within 220
yards of each side of a pipeline centerline along the entire length of
the special permit segment and along the pipeline up to 25 miles
upstream and downstream of the special permit segment. The ``special
permit inspection area'' for this special permit consists of the area
within 220 yards of each side of the PNGTS pipeline centerline along
the entire length of the pipeline from 25 miles upstream of special
permit segment 2 to approximately 10 miles downstream of special permit
segment 1 and inclusive of both special permit segments.
Special Permit Conditions
This special permit is granted with the following conditions:
(1) TransCanada must continue to operate the special permit
segments at or below the existing MAOP.
(2) TransCanada must incorporate both special permit segment 1 and
special permit segment 2 into its written IMP as ``covered segments''
in an HCA as defined in 49 CFR Subpart O, Sec. 192.903, except for the
reporting requirements contained in 49 CFR 192.945. The special permit
segments included in this special permit need not be included in
TransCanada's IMP baseline assessment plan.
(3) TransCanada must perform a CIS of the entire length of the
special permit inspection area not later than one year after the grant
of special permit and remediate any areas of inadequate cathodic
protection. A CIS and remediation need not be performed on the special
permit inspection area if a CIS and remediation have been performed
within 6 years of the grant of special permit. If factors beyond
TransCanada's control prevent the completion of the CIS and remediation
within one year, a CIS and remediation 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 Director, PHMSA
Eastern Region not later than one year of the grant of special permit.
(4) TransCanada must perform ongoing CIS of both special permit
segment 1 and special permit segment 2 at the applicable reassessment
interval(s) for a ``covered segment'' determined in accordance with 49
CFR 192.939.
[[Page 72818]]
(5) TransCanada must perform a Direct Current Voltage Gradient
(DCVG) survey of both special permit segment 1 and special permit
segment 2 not later than one year after the grant of special permit to
verify the pipeline coating conditions and to remediate any integrity
issues in the special permit segments. If factors beyond TransCanada's
control prevent the completion of the DCVG and remediation within one
year, a DCVG 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 Director, PHMSA Eastern Region not
later than one year of the grant of special permit.
(6) TransCanada must evaluate the potential for stress corrosion
cracking (SCC), according to 49 CFR 192.929 within one year after the
grant of special permit. If the potential for SCC is identified,
TransCanada must perform a stress corrosion cracking direct assessment
(SCCDA) of the special permit inspection area in accordance with 49 CFR
192.929.
(7) TransCanada must submit the CIS, DCVG and SCCDA findings
including remediation actions in a written report to the Director,
PHMSA Eastern Region not later than two years after the grant of
special permit.
(8) TransCanada must amend applicable sections of its operations
and maintenance (O&M) manual(s) to incorporate the inspection and
reassessment intervals by ILI along the entire length of the special
permit inspection area at a frequency consistent with 49 CFR Sec. 192,
Subpart O.
(9) TransCanada must amend applicable sections of its O&M manual(s)
to incorporate the inspection and reassessment intervals by CIS of both
special permit segment 1 and special permit segment 2 at a frequency
consistent with 49 CFR Part 192, Subpart O.
(10) The assessments of the special permit segments and the special
permit inspection area using ILI must conform to the required maximum
reassessment intervals specified in 49 CFR 192.939.
(11) TransCanada must schedule future reassessment dates for the
special permit inspection area according to 49 CFR Sec. 192.939 by
adding the required time interval to the previous assessment date.
(12) TransCanada must ensure their damage prevention program
incorporates the applicable best practices of the Common Ground
Alliance (CGA) within the special permit inspection area.
(13) TransCanada must give sufficient notice to the Director, PHMSA
Eastern Region to enable observation of any or all special permit
related activities in the special permit inspection area.
(14) TransCanada must determine and provide certification that all
inspections and activities associated with this special permit will not
impact or defer any of the operator's assessments for HCAs under 49 CFR
part Sec. 192, subpart O, particularly those associated with the most
significant 50 percent.
(15) Within three months following approval of this special permit
and annually thereafter, TransCanada must report the following to the
Director, PHMSA Eastern Region:
(a) The economic benefits of the special permit to TransCanada.
This should address both the costs avoided from not replacing the pipe
and the added costs of the inspection program (required for the initial
report only).
(b) In the first annual report, fully describe how the public
benefits from energy availability. This should address the benefits of
avoided disruptions as a consequence of pipe replacement and the
benefits of maintaining system capacity. Subsequent reports must
indicate any changes to this initial assessment.
(c) The number of new residences, other structures intended for
human occupancy and public gathering areas built within the special
permit inspection area.
(d) Any new integrity threats identified during the previous year
and the results of any in-line inspections or direct assessments
performed during the previous year in the special permit inspection
area.
(e) 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 inspection area.
(f) On-going damage prevention initiatives affecting the special
permit inspection area and a discussion on the success of the
initiatives.
(g) Any mergers, acquisitions, transfer of assets, or other events
affecting the regulatory responsibility of the company operating the
pipeline.
(16) At least one CP pipe-to-soil test station must be located
within each HCA with a maximum spacing between test stations of one-
half mile within an HCA. In cases where obstructions or restricted
areas prevent test station placement, the test station must be placed
in the closest practical location. This requirement applies to any HCA
within the special permit inspection area.
(17) If any annual test station readings within the special permit
inspection area fall below 49 CFR part 192, subpart I requirements,
remediation must occur within six months and include a CIS on each side
of the affected test station to the next test station and identified
corrosion system modifications to ensure corrosion control. If factors
beyond TransCanada's control prevent the completion of remediation
within six months, remediation 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 Director, PHMSA Eastern Region not
later than one year after the grant of special permit.
(18) Anomaly Evaluation and Repair:
(a) General: TransCanada shall account for ILI tool tolerance and
corrosion growth rates in scheduled response times and repairs.
(b) Dents: TransCanada shall repair dents in the special permit
segments and special permit inspection area in accordance with 49 CFR
Sec. 192.933.
(c) Repair Criteria: Repair criteria applies to anomalies located
within the special permit inspection area when they have been excavated
and investigated in accordance with 49 CFR 192.485 and 192.933 as
follows:
(i) Special permit segments--repair any anomaly with a failure
pressure ratio (FPR) less than or equal to 1.39 for pipe operating at a
stress level up to 72 percent of SMYS and any anomaly greater than 50
percent of pipe wall thickness.
(ii) Special permit inspection area--the response time must be in
accordance with 49 CFR Sec. 192, subpart O, the applicable edition of
the American Society of Mechanical Engineers Standard B31.8S, Managing
System Integrity of Gas Pipelines (ASME B31.8S) and TransCanada's IMP.
(d) Response Time for ILI Results: The following guidelines provide
the required timing for excavation and investigation of anomalies based
on ILI results. Reassessment by ILI will ``reset'' the timing for
anomalies not already investigated and/or repaired. TransCanada must
evaluate ILI data by using either the ASME Standard B31G, Manual for
Determining the Remaining Strength of Corroded Pipelines (ASME B31G),
or the Modified B31G (0.85dL) for calculating the predicted failure
pressure ratio to determine anomaly responses.
(i) Special permit segment:
--Immediate response: FPR equal to or less than 1.1 or anomalies equal
to and greater than 80 percent of pipe wall thickness;
[[Page 72819]]
--1-year response: pipe operating at a stress level up to 72 percent of
SMYS--FPR equal to or less than 1.39 and anomalies equal to or greater
than 60 percent of pipe wall thickness;
--Scheduled reponse: pipe operating at a stress level up to 72 percent
of SMYS--FPR greater than 1.39 and anomalies less than 60 percent of
pipe wall thickness.
(ii) Special permit inspection area: The response time must be in
accordance with 49 CFR Sec. 192, subpart O, ASME B31.8S (applicable
edition) and TransCanada's IMP.
(19) PHMSA may extend either or both of the original special permit
segments to include contiguous segments of pipeline up to the limits of
the special permit inspection area pursuant to the following
conditions. TransCanada must:
(a) Provide at least 90 days advance written notice to the
Director, PHMSA Eastern Region and PHMSA Headquarters of a requested
extension of either or both of special permit segment 1 and special
permit segment 2 based on an actual class location change and include a
schedule of inspections and of any anticipated remedial actions. If
PHMSA Headquarters makes a written objection before the effective date
of the requested special permit segment (90 days from receipt of the
above notice), the requested special permit segment extension does not
become effective.
(b) Complete all inspections and remediation of the proposed
special permit segment extension to the extent required of the original
special permit segment.
(c) Apply all the special permit conditions and limitations
included herein to all future extensions.
Special Permit Limitations
PHMSA has the sole authority to make all determinations on whether
TransCanada has complied with the specified conditions. Should
TransCanada fail to comply with any conditions of this special permit,
or should PHMSA determine this special permit is no longer appropriate
or that this special permit is inconsistent with pipeline safety, PHMSA
may revoke this special permit and require TransCanada to comply with
the regulatory requirements of 49 CFR 192.611.
Authority: 49 U.S.C. 60118 (c)(1) and 49 CFR 1.53.
Issued in Washington, DC on December 17, 2007.
Jeffrey D. Wiese,
Associate Administrator for Pipeline Safety.
[FR Doc. E7-24776 Filed 12-20-07; 8:45 am]
BILLING CODE 4910-60-P
