Pipeline Safety: Grant of Waiver; Rockies Express Pipeline, 39141-39145 [06-6105]
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Federal Register / Vol. 71, No. 132 / Tuesday, July 11, 2006 / Notices
Dated: July 5, 2006.
Murray Bloom,
Acting Secretary, Maritime Administration.
[FR Doc. E6–10756 Filed 7–10–06; 8:45 am]
BILLING CODE 4910–81–P
DEPARTMENT OF TRANSPORTATION
National Highway Traffic Safety
Administration
[Docket No. NHTSA 2006–24707; Notice 2]
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Pilkington Glass of Canada Ltd., Grant
of Petition for Decision of
Inconsequential Noncompliance
Pilkington Glass of Canada Ltd.
(Pilkington) has determined that certain
aftermarket windshields that it
manufactured in 2005 and 2006 do not
comply with S6.2 and S6.3 of 49 CFR
571.205, Federal Motor Vehicle Safety
Standard (FMVSS) No. 205, ‘‘Glazing
Materials.’’ Pursuant to 49 U.S.C.
30118(d) and 30120(h), Pilkington has
petitioned for a determination that this
noncompliance is inconsequential to
motor vehicle safety and has filed an
appropriate report pursuant to 49 CFR
part 573, ‘‘Defect and Noncompliance
Reports.’’ Notice of receipt of a petition
was published, with a 30-day comment
period, on May 19, 2006, in the Federal
Register (71 FR 29214). NHTSA
received no comments.
Affected are a total of approximately
760 aftermarket number GW1549GBY
windshields manufactured between
September 9, 2005 and March 31, 2006.
Pilkington explains that the exact
number of noncompliant windshields is
unknown, but that 8.1 percent of the
windshields that remain in the
company’s possession are
noncompliant, and applying that
percentage to the 9,383 windshields that
have been distributed produces a result
of approximately 760 windshields. S6.2
and S6.3 of FMVSS No. 205 require that
each windshield be marked with certain
information including a manufacturer’s
model number and manufacturer’s code
mark. The affected windshields are
marked with either an illegible model
number or an illegible manufacturer’s
code. Pilkington has corrected the
problem that caused these errors so that
they will not be repeated in future
production.
Pilkington believes that the
noncompliance is inconsequential to
motor vehicle safety and that no
corrective action is warranted. The
petitioner states that the windshields
are clearly inscribed ‘‘Pilkington’’ and
‘‘Made in Canada,’’ which would allow
a distributor or consumer to clearly
identify the manufacturer. Pilkington
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further states that consumers do not
need the illegible information to operate
their vehicles safely, and ‘‘repair shops
typically do not use the model number
in deciding upon the size or model of
the replacement glass. Instead, [they]
generally use various manuals and web
sites * * * such as * * * National Auto
Glass Specifications.’’ Pilkington also
states that it has taken action to prevent
additional sales of these windshields by
notifying wholesalers and distributors to
return windshields with the
noncompliant markings.
NHTSA agrees with Pilkington that
the noncompliance is inconsequential to
motor vehicle safety. The manufacturer
can be identified by the words
‘‘Pilkington’’ and ‘‘Made in Canada,’’
which are inscribed on the windshield.
To identify the proper replacement
glass, a repair facility would presumably
follow the typical practice of using
references such as the National Auto
Glass Specifications web site and
manuals. Therefore this noncompliance
does not present a safety problem in
terms of replacement or recall. The
windshields meet all other FMVSS
requirements.
In consideration of the foregoing,
NHTSA has decided that the petitioner
has met its burden of persuasion that
the noncompliance described is
inconsequential to motor vehicle safety.
Accordingly, Pilkington’s petition is
granted and the petitioner is exempted
from the obligation of providing
notification of, and a remedy for, the
noncompliance.
Authority: (49 U.S.C. 30118, 30120;
delegations of authority at CFR 1.50 and
501.8)
Issued on July 5, 2006.
Daniel C. Smith,
Associate Administrator for Enforcement.
[FR Doc. E6–10763 Filed 7–10–06; 8:45 am]
BILLING CODE 4910–59–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
[Docket No. PHMSA–2006–23998; Notice 2]
Pipeline Safety: Grant of Waiver;
Rockies Express Pipeline
Pipeline and Hazardous
Materials Safety Administration
(PHMSA); DOT.
ACTION: Grant of waiver.
AGENCY:
SUMMARY: PHMSA is granting Rockies
Express Pipeline, L.L.C. (Rockies
Express) a waiver of compliance from
the pipeline safety regulation that
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39141
prescribes the design factor to be used
in the design formula for steel pipe.
This waiver allows the Rockies Express
pipeline to operate at hoop stresses up
to 80 percent of the specified minimum
yield strength (SMYS) in Class 1
locations. The waiver also grants
Rockies Express relief from equipment
requirements for pressure relieving and
limiting stations.
Before granting the waiver, PHMSA
performed a thorough technical review
of Rockies Express’s application and
supporting documents. PHMSA
requested and received supplementary
information pertaining to numerous
technical aspects of its metallurgy,
pipeline design, and engineering
practices. These materials are available
in the docket PHMSA–2006–23998 at
https://dms.dot.gov. PHMSA also sought
comments from the public and received
positive feedback from the impacted
States along the pipeline and the
Technical Pipeline Safety Standards
Committee.
The waiver is subject to and
conditional upon supplemental safety
criteria set forth in this notice. The
supplemental safety criteria address the
life cycle management of the subject
pipeline and require Rockies Express to
adhere to maintenance, inspection,
monitoring, control, and reporting
standards exceeding existing regulatory
requirements.
SUPPLEMENTARY INFORMATION:
Background
Rockies Express is a joint
development of Kinder Morgan Energy
Partners, L.P. and Sempra Pipelines &
Storage, a subsidiary of Sempra Energy.
Rockies Express is obtaining
regulatory approvals to construct a new
1,323-mile interstate natural gas
pipeline. When it is complete, the 42inch diameter pipeline will transport
natural gas from basins in Colorado and
Wyoming to markets in the upper
Midwest and Eastern United States. The
pipeline will cross portions of
Wyoming, Colorado, Nebraska,
Missouri, Illinois, Indiana, and Ohio.
Rockies Express plans to construct the
pipeline in three phases. The first or
western segment of the pipeline will be
approximately 710 miles long. It will
start at the hub in Cheyenne, Wyoming
and extend to an interconnection with
the Panhandle Eastern Pipe Line
Company in Audrain County, Missouri.
Four additional compressor stations will
be installed at the Cheyenne Hub to
support operations. The second or
central segment of the pipeline will be
approximately 425 miles long and
extend from the terminus of the western
segment of the pipeline in Audrain
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County, Missouri to the hub in Lebanon,
Ohio. The final or eastern segment of
the pipeline will be approximately 188
miles long and extend from the Lebanon
Hub terminus to a point at or near
Clarington, Ohio.
Rockies Express’ Waiver Requests
Rockies Express requests a waiver of
compliance from the following
regulatory requirements:
49 CFR 192.111—Design Factor (F) for
Steel Pipe; and
49 CFR 192.201—Required Capacity of
Pressure Relieving and Limiting
Stations.
The design factors are found in the
following table:
Class location
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1
2
3
4
Design factor
(F)
................................................
................................................
................................................
................................................
0.72
0.60
0.50
0.40
The waiver request is for
approximately 1,323 miles of 42-inch
diameter pipe located within the United
States. The waiver will allow Rockies
Express to:
(1) Operate its new pipeline at hoop
stresses up to 80 percent of SMYS in
Class 1 locations, and at a maximum
allowable operating pressure (MAOP) of
1,480 pounds per square inch gauge.
(2) Operate each pressure relief
station installed to protect pipelines in
Class 1 locations at pressures that may
not exceed the MAOP plus 4 percent, or
the pressure that produces a hoop stress
of 83 percent of SMYS, whichever is
lower at that time.
The pipe to be used for the Rockies
Express pipeline will be either a
longitudinal seam submerged arc
welded pipe or a helical seam
submerged arc welded pipe. The pipe
also will be API Grades X80 and X70,
and high-strength and high-toughness
steel pipe, suitable for high-pressure gas
transmission service. The Rockies
Express pipeline will be 42 inches in
diameter, coated externally with fusionbonded epoxy (FBE), and be protected
by an impressed current cathodic
protection (CP) system. The field weld
joints will be externally coated with
field applied FBE.
All welds on the Rockies Express
pipeline will be nondestructively tested.
If any weld imperfections are
discovered, they will be repaired or
removed prior to putting the line in
service. The Rockies Express pipeline
also will be hydrostatically tested to a
minimum of 100 percent of SMYS. Prior
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to commissioning the pipeline for gas
service, it will be surveyed with a multichannel geometry-smart-tool capable of
detecting anomalies including dents and
buckles. Approximately 90 percent of
the Rockies Express pipeline will be
located in Class 1 areas in a common
right-of-way with other pipelines.
Further, Kinder Morgan will install
variable resistance bonds between the
various pipelines and metallic
structures sharing the right-of-way to
eliminate stray electrical currents, and
to equalize the voltage potentials
between Rockies Express and other
underground metallic structures.
Kinder Morgan conducted a risk
analysis for Rockies Express and
compared the risks associated with
using a 0.80 design criteria to using a
0.72 design criteria. The risk analysis
considered risks in the following nine
areas: (1) Stress corrosion cracking; (2)
manufacturing defects; (3) weather/
outside factors; (4) welding and
fabrication defects; (5) equipment
failure; (6) equipment impact or thirdparty damage; (7) external corrosion; (8)
internal corrosion; and (9) incorrect
operation.
From the risk analysis results Kinder
Morgan determined that there was no
significant increase in the overall risk
associated with using the 0.80 design
criteria for this type of pipe. Moreover,
according to Kinder Morgan, only in the
areas of external corrosion, internal
corrosion, and incorrect operation did
the risk analysis show a slightly higher
degree of risk associated with using a
0.80 design factor. A pipe wall designed
with a 0.80 design factor results in a
slightly higher risk factor because it is
manufactured with a thinner wall pipe
than the pipe designed with a 0.72
design factor; therefore, the pipe
designed with a 0.80 design factor
operates at higher stress levels.
Consequently, the factor of safety
between the MAOP and the pipe’s
SMYS is reduced. Rockies Express
indicated that they will employ several
control and prevention programs to
mitigate these increased risks.
Grant of Waiver
PHMSA considered Rockies Express’
waiver request and whether its proposal
will yield an equivalent or greater
degree of safety than the current
regulations. PHMSA published a notice
of intent to consider the waiver and
solicited comments on March 22, 2006
(71 FR 14573). No comments were
received.
Based on the Rockies Express’
application for waiver for its new
pipeline and PHMSA’s extensive
technical analysis and favorable
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feedback from the impacted States and
the Technical Pipeline Safety Standards
Committee, PHMSA hereby grants
Rockies Express’ waiver request with
the following supplemental safety
criteria:
Pipe and Material Quality
1. Steel Properties: The skelp/plate
must be micro alloyed, fine grain, fully
killed steel with calcium treatment and
continuous casting.
2. Manufacturing Standards: The pipe
must be manufactured according to
American Petroleum Institute (API)
standard 5L, product specification level
(PSL) 2, and supplementary
requirements (SR) for maximum
operating pressures and minimum
operating temperatures. Pipe carbon
equivalents must be at or below 0.25
based on the material chemistry
parameter (Pcm) formula.
3. Fracture Control: The API standard
5L and other standards address steel
pipe toughness properties needed to
resist initiation and propagation, and
arrest (stop) a pipeline failure caused by
a fracture. Rockies Express must
institute an overall fracture control plan
addressing steel pipe properties
necessary to resist and arrest this
condition within 6 pipe joints. The plan
must include acceptable Charpy Impact
and Drop Weight Tear Test values,
which are measures of a steel pipeline’s
toughness and resistance to fracture.
The fracture control plan must also be
in accordance with API standard 5L,
Appendix F and must include the
following tests:
• (a) SR 5A—Fracture Toughness
Testing for Shear Area: Test results must
be at least 80 percent of the minimum
average shear area for all heats with a
minimum result of 80 percent shear area
for any single test;
• (b) SR 5B—Fracture Toughness
Testing for Absorbed Energy; and
• (c) SR 6—Fracture Toughness
Testing by Drop Weight Tear Test: Test
results must be at least 80 percent of the
average shear area for all heats with a
minimum result of 60 percent of the
shear area for any single test.
The above fracture initiation,
propagation and arrest plan must
account for the entire range of pipeline
operating temperatures, pressures and
gas compositions planned for the
pipeline diameter, grade, and operating
stress level associated with this wavier.
4. Steel Plate Quality Control: The
steel mill and/or pipe rolling mill must
incorporate a comprehensive plate/coil
mill and pipe mill inspection program
to check for defects and inclusions that
could affect the pipe quality. This
program must include a plate (body and
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all ends) ultrasonic testing (UT)
inspection program to check for
imperfections such as laminations.
An inspection protocol for centerline
segregation evaluation using a test
method referred to as slab macroetching must be employed to check for
inclusions that may form as the steel
plate cools after it has been cast. A
minimum of one macro-etch test must
be performed from the first heat
(manufacturing run) of each sequence
(approximately 4 heats) and graded on
the Mannesmann scale or equivalent.
Test results with a Mannesmann scale
rating of one or two out of a possible
five are acceptable.
5. Pipe Seam Quality Control: A
quality assurance program must be
instituted for pipe weld seams. The pipe
weld seam tests must meet the
minimum requirements for tensile
strength in API standard 5L for the
appropriate pipe grade properties.
A pipe weld seam hardness test using
the Vickers hardness testing of a crosssection from the weld seam must be
performed on one length of pipe from
each heat. The maximum weld seam
and heat affected zone hardness must be
a maximum of 280 Vickers hardness.
The hardness tests must include a
minimum of 3 readings for each heat
affected zone, 3 readings in the weld
metal, and 2 readings in each section of
pipe base metal for a total of 13
readings.
The pipe weld seam must be 100
percent ultrasonically tested after
expansion and hydrostatic testing per
APL standard 5L.
6. Puncture Resistance: Steel pipe will
be puncture resistant to 35 ton.
Puncture resistance will be calculated
based on industry established
calculations such as the Pipeline
Research Council International’s
‘‘Reliability Based Prevention of
Mechanical Damage to Pipelines’’
calculation method.
7. Mill Hydrostatic Test: The pipe
must be subjected to a mill hydrostatic
test pressure of 95 percent SMYS or
greater for 10 seconds.
8. Pipe Coating: The application of a
corrosion resistant coating to the steel
pipe must be subject to a coating
application quality control program.
The program must address pipe surface
cleanliness standards, blast cleaning,
application temperature control,
adhesion, cathodic disbondment,
moisture permeation, bending,
minimum coating thickness, coating
imperfections, and coating repair.
9. Field Coating: A field girth weld
joint coating application specification
and quality standards to ensure pipe
surface cleanliness, application
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temperature control, adhesion quality,
cathodic disbondment, moisture
permeation, bending, minimum coating
thickness, holiday detection, and repair
quality must be implemented in field
conditions. Field joint coatings must be
non-shielding to CP. Field coating
applicators must use valid coating
procedures and be trained to use these
procedures.
10. Coatings for Trenchless
Installation: Coatings used for
directional bore, slick bore, and other
trenchless installation methods must
resist abrasions and other damages that
may occur due to rocks and other
obstructions encountered in this
installation technique.
11. Bends Quality: Certification
records of factory induction bends and/
or factory weld bends must be obtained
and retained. All bends, flanges, and
fittings must have carbon equivalents
(CE) below 0.42 or a pre-heat procedure
prior to welding for CE above 0.42.
12. Fittings: All pressure rated fittings
and components (including flanges,
valves, gaskets, pressure vessels, and
compressors) must be rated for a
pressure rating commensurate with the
MAOP and class location of the
pipeline. Designed fittings (including
tees, elbows and caps) must have the
same design factors as the adjacent pipe
class location.
13. Design Factor—Stations:
Compressor and meter stations must be
designed using a design factor of 0.50 in
accordance with § 192.111.
14. Temperature Control: The
compressor station discharge
temperature must be limited to 120°
Fahrenheit or a temperature below the
maximum long-term operating
temperature for the pipe coating.
15. Overpressure Protection Control:
Mainline pipeline overpressure
protection must be limited to a
maximum of 104 percent MAOP.
16. Welding Procedures: Automated
or manual welding procedure
documentation must be submitted to the
appropriate PHMSA regional office. The
PHMSA’s regional office must be
notified within 14 days before welding
procedure qualification activities.
17. Depth of Cover: The soil cover
must be a minimum of 36 inches except
in areas where threats from chisel
plowing or other activities require the
top of the pipeline to be installed one
foot below the deepest penetration.
Construction
18. Construction Quality: A
construction quality assurance plan to
ensure quality standards and controls
must be maintained throughout the
construction phase with respect to:
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Inspection, pipe hauling and stringing,
field bending, welding, non-destructive
examination (NDE) of girth welds, field
joint coating, pipeline coating integrity
tests, lowering of the pipeline in the
ditch, padding materials to protect the
pipeline, backfilling, alternating current
(AC) interference mitigation and CP
systems. All girth welds must be nondestructively examined by radiography
or alternative means. The NDE examiner
must have all required certifications that
are current.
19. Interference Currents Control:
Control of induced AC from parallel
electric transmission lines and other
interference issues that may affect the
pipeline must be incorporated into the
design of the pipeline and addressed
during the construction phase. Issues
identified and not originally addressed
in the design phase must be brought to
PHMSA’s attention. An induced AC
program to protect the pipeline from
corrosion caused by stray currents must
be in place within six months after
placing the pipeline in service.
Pre-In Service Hydrostatic Pressure Test
20. Test Level: The pre-in service
hydrostatic test must be to a pressure
producing a hoop stress on 0.8 designed
class 1 pipe of at least 100 percent
SMYS and 1.25 X MAOP.
21. Assessment of Test Failures: Any
pipe failure occurring during the pre-in
service hydrostatic test must undergo a
root cause failure analysis to include a
metallurgical examination of the failed
pipe. The results of this examination
must preclude a systemic pipeline
material issue and the results must be
reported to PHMSA headquarters and
the appropriate PHMSA regional office.
Supervisory Control and Data
Acquisition (SCADA)
22. SCADA System Capabilities: A
SCADA system to provide remote
monitoring and control of the entire
pipeline system must be employed.
23. Mainline Valve Control: Mainline
valves that reside on either side of
pipeline segment containing a High
Consequence Area (HCA) where
personnel response time to the valve
exceeds one (1) hour must be remotely
controlled by the SCADA system. The
SCADA system must be capable of
opening and closing the valve and
monitoring the valve position, upstream
pressure and downstream pressure. As
an alternative, a leak detection system
for mainline valve control is acceptable.
24. SCADA Procedures: A detailed
procedure for establishing and
maintaining accurate SCADA set points
must be established to ensure the
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pipeline operates within acceptable
design limits at all times.
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Operations and Maintenance
25. Leak Reporting: Rockies Express
must notify the appropriate PHMSA
regional office within 24 hours of any
non-reportable leaks occurring on the
pipeline.
26. Annual Reporting: Following
approval of the waiver, Rockies Express
must annually report the following:
• The results of any in-line inspection
(ILI) or direct assessment results
performed within the waiver area
during the previous year;
• Any new integrity threats identified
within the waiver area during the
previous year;
• Any encroachment in the waiver
area, including the number of new
residences or public gathering areas;
• Any reportable incidents associated
with the waiver area that occurred
during the previous year;
• Any leaks on the pipeline in the
waiver area that occurred during the
previous year;
• A list of all repairs on the pipeline
in the waiver area made during the
previous year;
• On-going damage prevention
initiatives on the pipeline in the waiver
area and a discussion of their success;
and
• Any company mergers,
acquisitions, transfers of assets, or other
events affecting the regulatory
responsibility of the company operating
the pipeline to which this waiver
applies.
27. Pipeline Inspection: The pipeline
must be capable of passing ILI. All
headers and other segments covered
under this waiver that do not allow the
passage of an ILI device must have a
corrosion mitigation plan.
28. Gas Quality Monitoring and
Control: An acceptable gas quality
monitoring and mitigation program
must be instituted to not exceed the
following limits:
a. H2S (4 grains maximum);
b. CO2 (3 percent maximum);
c. H2O (less than or equal to 7 pounds
per million standard cubic feet and no
free water); and
d. Other deleterious constituents that
may impact the integrity of the pipeline
must be instituted.
Filters/separators must be installed at
locations where gas is received into the
pipeline to minimize the entry of
contaminants and to protect the
integrity of downstream pipeline
segments.
Gas quality monitoring equipment
must be installed to permit the operator
to manage the introduction of
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contaminants and free liquids into the
pipeline.
29. Cathodic Protection: The initial
CP system must be operational within
12 months of placing the pipeline in
service.
30. Interference Current Surveys:
Interference surveys must be performed
within six months of placing the
pipeline in service to ensure compliance
with applicable NACE International
(NACE) standards (Recommended
Practice (RP) 0169 and RP 0177) for
interference current levels.
31. Corrosion Surveys: Corrosion
surveys of the affected pipeline must be
completed within six months of placing
the respective CP system(s) in operation
to ensure CP (in accordance with the
NACE standard RP 0169, paragraphs 6.2
and 6.3), test stations, AC interference
mitigation, and AC grounding programs
(NACE standard RP 0177) are being
implemented along the pipeline.
32. Verification of Cathodic
Protection: A close interval survey (CIS)
must be performed in concert with ILI
in accordance with subpart O
reassessment intervals for all HCA
pipeline mileage. If any annual test
point readings fall below subpart I
requirements, remediation must be
performed and must include a CIS on
either side of the affected test point to
ensure corrosion control.
33. Pipeline Markers: Rockies Express
must employ line-of-sight markings on
the pipeline in the waiver area except in
agricultural areas, subject to Federal
Energy Regulatory Commission permits
or environmental permits and local
restrictions.
34. Pipeline Patrolling: Pipeline
patrolling must be conducted at least
monthly to inspect for excavation
activities, ground movement, wash-outs,
leakage, and/or other activities and
conditions affecting the safe operation
of the pipeline.
35. Monitoring of Ground Movement:
An effective monitoring/mitigation plan
must be in place to monitor for and
mitigate issues of unstable soil and
ground movement.
Integrity Management
36. Review of Risk Assessment
Calculations: A copy of the C–FER
PIRAMID risk analysis report regarding
the pipe subject to this waiver must be
submitted to PHMSA Headquarters.
37. Initial ILI: A baseline ILI must be
performed in association with the
construction of the pipeline using a
high-resolution Magnetic Flux Leakage
(MFL) tool within three years of placing
a pipeline segment in service. A
geometry tool must be launched either
prior to placing the pipeline in service,
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or no later than six months after placing
the pipeline in service.
38. Future ILI: A second highresolution MFL inspection must be
performed and completed on the pipe
subject to this waiver within the first
reassessment interval required by
subpart O, regardless of HCA
classification. Future ILI must be
performed on a frequency consistent
with subpart O for the entire pipeline
covered by this waiver.
39. Direct Assessment Plan: Headers,
mainline valve bypasses, and other
sections covered by this waiver that
cannot accommodate ILI tools must be
part of a Direct Assessment (DA) plan or
other acceptable integrity monitoring
method.
40. Initial CIS: A CIS must be
performed on the pipeline within one
year of completion of the installation of
CP systems. The CIS results must be
integrated with the baseline ILI to
determine whether further action is
needed.
41. Damage Prevention Program:
Common Ground Alliance’s damage
prevention best practices must be
incorporated into the Rockies Express
damage prevention program.
42. Class 2 and 3 Pipe: Pipe installed
in Class 2 and Class 3 locations must
use stress factors of 0.60 and 0.50 as
required in § 192.111. Pipe in road and
railroad crossings must meet the
requirements of § 192.111.
43. Anomaly Evaluation and Repair:
Anomaly evaluations and repairs must
be performed based upon the following:
• Anomaly Response Time
Æ Any anomaly with a failure
pressure ratio (FPR) equal to or less than
1.1 must be treated as an ‘‘immediate’’
per subpart O.
Æ Any anomaly with an FPR equal to
or less than 1.25 must be remediated
within 12 months per subpart O.
Æ Any anomaly with an FPR greater
than 1.25 must have a remediation
schedule per subpart O.
• Anomaly Repair Criteria
Æ Segments operating at MAOP equal
to 80 percent stress level—any anomaly
evaluated and found to have an FPR
equal to or less than 1.25 must be
repaired.
Æ Segments operating at MAOP equal
to 66 percent stress level—any anomaly
evaluated and found to have an FPR
equal to or less than 1.50 must be
repaired.
Æ Segments operating at MAOP equal
to 56 percent stress level—any anomaly
evaluated and found to have an FPR
equal to or less than 1.80 must be
repaired.
a. All other pipe segments with
anomalies not repaired must be
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reassessed according to subpart O and
the American Society of Mechanical
Engineers (ASME) standard B31.8S
requirements. Each anomaly not
repaired must have a corrosion growth
rate and ILI tool tolerance assigned to it
per the Gas Integrity Management
Program (IMP) to determine the
maximum re-inspection interval.
b. Rockies Express must confirm the
remaining strength (R–STRENG)
effective area method, R–STRENG—
0.85dL, and ASME standard B31G
assessment methods are valid for their
pipe diameter, wall thickness, grade,
operating pressure, operating stress
level, and operating temperature. If it is
not valid, Rockies Express must confirm
a valid evaluation method to PHMSA.
Until confirmation of the previously
mentioned anomaly assessment
calculations has been performed,
Rockies Express must use the most
conservative of the calculations for
anomaly evaluation.
c. Dents must be evaluated and
repaired per § 192.309(b)(ii) and
§ 192.933(d)(l)(ii).
44. Preliminary Criteria Reporting: A
preliminary report describing the
results, completion dates and status of
the supplementary requirements must
be completed for the western and
eastern segments of the pipeline and
submitted to PHMSA Headquarters and
the appropriate PHMSA regional office
prior to commencing construction of
each segment.
45. Criteria Completion Reporting: A
report describing results, completion
dates and status of the outstanding
supplementary requirements must be
submitted to PHMSA Headquarters and
the appropriate regional office within
180 days after completion of the western
pipeline segment. A similar report must
be completed within 180 days of
completion of the eastern segment and
submitted to PHMSA Headquarters and
the appropriate PHMSA regional office.
A follow-up report must be submitted
for the western and eastern segments
after the baseline ILI run has been
performed with assessment and
integration of the results. A final report
must be submitted upon completion of
the second ILI run for the western and
eastern segments. These reports must be
submitted to PHMSA Headquarters and
the appropriate PHMSA regional office.
46. Potential Impact Radius
Calculation Updates: If the pipeline
operating pressures and gas quality are
determined to be outside the parameters
of the C–FER Study, a new study with
the uprated parameters must be
incorporated into the IMP.
If at anytime PHMSA determines the
effect of the waiver is inconsistent with
VerDate Aug<31>2005
16:49 Jul 10, 2006
Jkt 208001
pipeline safety, PHMSA will revoke the
waiver at its sole discretion.
Authority: 49 U.S.C. 60118 (c) and 49 CFR
1.53.
Issued in Washington, DC, on July 5, 2006.
Theodore L. Willke,
Deputy Associate Administrator for Pipeline
Safety.
[FR Doc. 06–6105 Filed 7–6–06; 9:10 am]
BILLING CODE 4910–60–P
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials
Safety Administration
[Docket No. PHMSA–2006–23387; Notice 2]
Pipeline Safety: Grant of Waiver;
Alliance Pipeline L.P.
Pipeline and Hazardous
Materials Safety Administration
(PHMSA); DOT.
ACTION: Grant of Waiver.
AGENCY:
SUMMARY: PHMSA is granting Alliance
Pipeline L.P. (APL) a waiver of
compliance from certain PHMSA
regulations for the United States portion
of its pipeline system. This waiver
increases the maximum allowable
operating pressure (MAOP) for its
pipeline. It also increases the design
factor for its compressor station piping,
grants relief from the hydrostatic testing
requirements for its compressor station
piping, and grants relief from equipment
requirements for pressure relieving and
limiting stations.
Before granting the waiver, PHMSA
performed a thorough technical review
of APL’s application for waiver and
supporting documents. PHMSA
requested and received supplementary
information pertaining to numerous
technical aspects of APL’s design,
engineering, operations, and
maintenance practices. PHMSA also
sought comments from the public and
received positive feedback from the
impacted States along the pipeline and
the Technical Pipeline Safety Standards
Committee.
The waiver is subject to and
conditional upon supplemental safety
criteria set forth in this notice. The
supplemental safety criteria address the
life cycle management of the subject
pipeline and require the operator to
adhere to maintenance, inspection,
monitoring, control, and reporting
standards exceeding existing regulatory
requirements.
SUPPLEMENTARY INFORMATION:
Background
The United States portion of APL’s
system was commissioned in 2000 and
PO 00000
Frm 00097
Fmt 4703
Sfmt 4703
39145
consists of approximately 888 miles of
transmission pipeline in North Dakota,
Minnesota, Iowa, and Illinois. APL
transports natural gas from the
Canadian/United States border near
Minot, North Dakota to the Aux Sable
Delivery Meter Station near Chicago,
Illinois where natural gas liquids such
as ethane, butane, propane, and other
liquids are separated out from the gas
stream. The natural gas is then
transported about 13 miles to various
metering facilities. The APL system
includes seven compressor stations.
The APL system is constructed from
36-inch, Grade X70 high pressure steel
pipe with three wall thicknesses: 0.622
inches, 0.746 inches, and 0.895 inches.
The pipelines are mechanically welded,
coated with multi-layered, fusionbonded, non-shielding epoxy, and are
protected by an impressed current
cathodic protection system.
During construction of the APL
pipeline, all girth welds were subjected
to volumetric inspection to verify weld
quality. Further, in 2005, APL inspected
the pipeline using a high-resolution
Magnetic Flux Leakage (MFL) in-line
inspection (ILI) tool. The operator used
this technology to look for anomalies
that could impact the integrity and
safety of the pipeline. No anomalies
were found.
APL’s Waiver Requests
APL requests a waiver of compliance
from the following regulatory
requirements:
49 CFR 192.111—Design Factor (F) for
Steel Pipe;
49 CFR 192.201—Required Capacity of
Pressure Relieving and Limiting
Stations;
49 CFR 192.505—Strength Test
Requirements for Steel Pipeline to
Operate at a Hoop Stress of 30
percent or more of SMYS; and
49 CFR 192.619—Maximum Allowable
Operating Pressure: Steel or Plastic
Pipelines.
The waiver request is for
approximately 874.7 miles of 36-inch
diameter pipe located in the United
States between the Canadian border at
Milepost 0.0 and the inlet of Aux Sable
Deliver Meter Station near Chicago,
Illinois at Milepost 874.7. In the
document, we refer to this segment as
the area of waiver.
The waiver application involves six
specific requests:
(1) Increase the stress level from 72
percent of SMYS, corresponding to 1740
psig, to 80 percent of SMYS,
corresponding to 1935.1 psig from the
Canadian border at Milepost 0.0 to the
inlet of the Aux Sable Delivery Meter
E:\FR\FM\11JYN1.SGM
11JYN1
]]>Agencies
[Federal Register Volume 71, Number 132 (Tuesday, July 11, 2006)]
[Notices]
[Pages 39141-39145]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-6105]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Pipeline and Hazardous Materials Safety Administration
[Docket No. PHMSA-2006-23998; Notice 2]
Pipeline Safety: Grant of Waiver; Rockies Express Pipeline
AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA);
DOT.
ACTION: Grant of waiver.
-----------------------------------------------------------------------
SUMMARY: PHMSA is granting Rockies Express Pipeline, L.L.C. (Rockies
Express) a waiver of compliance from the pipeline safety regulation
that prescribes the design factor to be used in the design formula for
steel pipe. This waiver allows the Rockies Express pipeline to operate
at hoop stresses up to 80 percent of the specified minimum yield
strength (SMYS) in Class 1 locations. The waiver also grants Rockies
Express relief from equipment requirements for pressure relieving and
limiting stations.
Before granting the waiver, PHMSA performed a thorough technical
review of Rockies Express's application and supporting documents. PHMSA
requested and received supplementary information pertaining to numerous
technical aspects of its metallurgy, pipeline design, and engineering
practices. These materials are available in the docket PHMSA-2006-23998
at https://dms.dot.gov. PHMSA also sought comments from the public and
received positive feedback from the impacted States along the pipeline
and the Technical Pipeline Safety Standards Committee.
The waiver is subject to and conditional upon supplemental safety
criteria set forth in this notice. The supplemental safety criteria
address the life cycle management of the subject pipeline and require
Rockies Express to adhere to maintenance, inspection, monitoring,
control, and reporting standards exceeding existing regulatory
requirements.
SUPPLEMENTARY INFORMATION:
Background
Rockies Express is a joint development of Kinder Morgan Energy
Partners, L.P. and Sempra Pipelines & Storage, a subsidiary of Sempra
Energy.
Rockies Express is obtaining regulatory approvals to construct a
new 1,323-mile interstate natural gas pipeline. When it is complete,
the 42-inch diameter pipeline will transport natural gas from basins in
Colorado and Wyoming to markets in the upper Midwest and Eastern United
States. The pipeline will cross portions of Wyoming, Colorado,
Nebraska, Missouri, Illinois, Indiana, and Ohio.
Rockies Express plans to construct the pipeline in three phases.
The first or western segment of the pipeline will be approximately 710
miles long. It will start at the hub in Cheyenne, Wyoming and extend to
an interconnection with the Panhandle Eastern Pipe Line Company in
Audrain County, Missouri. Four additional compressor stations will be
installed at the Cheyenne Hub to support operations. The second or
central segment of the pipeline will be approximately 425 miles long
and extend from the terminus of the western segment of the pipeline in
Audrain
[[Page 39142]]
County, Missouri to the hub in Lebanon, Ohio. The final or eastern
segment of the pipeline will be approximately 188 miles long and extend
from the Lebanon Hub terminus to a point at or near Clarington, Ohio.
Rockies Express' Waiver Requests
Rockies Express requests a waiver of compliance from the following
regulatory requirements:
49 CFR 192.111--Design Factor (F) for Steel Pipe; and
49 CFR 192.201--Required Capacity of Pressure Relieving and Limiting
Stations.
The design factors are found in the following table:
------------------------------------------------------------------------
Design
Class location factor (F)
------------------------------------------------------------------------
1.......................................................... 0.72
2.......................................................... 0.60
3.......................................................... 0.50
4.......................................................... 0.40
------------------------------------------------------------------------
The waiver request is for approximately 1,323 miles of 42-inch
diameter pipe located within the United States. The waiver will allow
Rockies Express to:
(1) Operate its new pipeline at hoop stresses up to 80 percent of
SMYS in Class 1 locations, and at a maximum allowable operating
pressure (MAOP) of 1,480 pounds per square inch gauge.
(2) Operate each pressure relief station installed to protect
pipelines in Class 1 locations at pressures that may not exceed the
MAOP plus 4 percent, or the pressure that produces a hoop stress of 83
percent of SMYS, whichever is lower at that time.
The pipe to be used for the Rockies Express pipeline will be either
a longitudinal seam submerged arc welded pipe or a helical seam
submerged arc welded pipe. The pipe also will be API Grades X80 and
X70, and high-strength and high-toughness steel pipe, suitable for
high-pressure gas transmission service. The Rockies Express pipeline
will be 42 inches in diameter, coated externally with fusion-bonded
epoxy (FBE), and be protected by an impressed current cathodic
protection (CP) system. The field weld joints will be externally coated
with field applied FBE.
All welds on the Rockies Express pipeline will be nondestructively
tested. If any weld imperfections are discovered, they will be repaired
or removed prior to putting the line in service. The Rockies Express
pipeline also will be hydrostatically tested to a minimum of 100
percent of SMYS. Prior to commissioning the pipeline for gas service,
it will be surveyed with a multi-channel geometry-smart-tool capable of
detecting anomalies including dents and buckles. Approximately 90
percent of the Rockies Express pipeline will be located in Class 1
areas in a common right-of-way with other pipelines. Further, Kinder
Morgan will install variable resistance bonds between the various
pipelines and metallic structures sharing the right-of-way to eliminate
stray electrical currents, and to equalize the voltage potentials
between Rockies Express and other underground metallic structures.
Kinder Morgan conducted a risk analysis for Rockies Express and
compared the risks associated with using a 0.80 design criteria to
using a 0.72 design criteria. The risk analysis considered risks in the
following nine areas: (1) Stress corrosion cracking; (2) manufacturing
defects; (3) weather/outside factors; (4) welding and fabrication
defects; (5) equipment failure; (6) equipment impact or third-party
damage; (7) external corrosion; (8) internal corrosion; and (9)
incorrect operation.
From the risk analysis results Kinder Morgan determined that there
was no significant increase in the overall risk associated with using
the 0.80 design criteria for this type of pipe. Moreover, according to
Kinder Morgan, only in the areas of external corrosion, internal
corrosion, and incorrect operation did the risk analysis show a
slightly higher degree of risk associated with using a 0.80 design
factor. A pipe wall designed with a 0.80 design factor results in a
slightly higher risk factor because it is manufactured with a thinner
wall pipe than the pipe designed with a 0.72 design factor; therefore,
the pipe designed with a 0.80 design factor operates at higher stress
levels. Consequently, the factor of safety between the MAOP and the
pipe's SMYS is reduced. Rockies Express indicated that they will employ
several control and prevention programs to mitigate these increased
risks.
Grant of Waiver
PHMSA considered Rockies Express' waiver request and whether its
proposal will yield an equivalent or greater degree of safety than the
current regulations. PHMSA published a notice of intent to consider the
waiver and solicited comments on March 22, 2006 (71 FR 14573). No
comments were received.
Based on the Rockies Express' application for waiver for its new
pipeline and PHMSA's extensive technical analysis and favorable
feedback from the impacted States and the Technical Pipeline Safety
Standards Committee, PHMSA hereby grants Rockies Express' waiver
request with the following supplemental safety criteria:
Pipe and Material Quality
1. Steel Properties: The skelp/plate must be micro alloyed, fine
grain, fully killed steel with calcium treatment and continuous
casting.
2. Manufacturing Standards: The pipe must be manufactured according
to American Petroleum Institute (API) standard 5L, product
specification level (PSL) 2, and supplementary requirements (SR) for
maximum operating pressures and minimum operating temperatures. Pipe
carbon equivalents must be at or below 0.25 based on the material
chemistry parameter (Pcm) formula.
3. Fracture Control: The API standard 5L and other standards
address steel pipe toughness properties needed to resist initiation and
propagation, and arrest (stop) a pipeline failure caused by a fracture.
Rockies Express must institute an overall fracture control plan
addressing steel pipe properties necessary to resist and arrest this
condition within 6 pipe joints. The plan must include acceptable Charpy
Impact and Drop Weight Tear Test values, which are measures of a steel
pipeline's toughness and resistance to fracture.
The fracture control plan must also be in accordance with API
standard 5L, Appendix F and must include the following tests:
(a) SR 5A--Fracture Toughness Testing for Shear Area: Test
results must be at least 80 percent of the minimum average shear area
for all heats with a minimum result of 80 percent shear area for any
single test;
(b) SR 5B--Fracture Toughness Testing for Absorbed Energy;
and
(c) SR 6--Fracture Toughness Testing by Drop Weight Tear
Test: Test results must be at least 80 percent of the average shear
area for all heats with a minimum result of 60 percent of the shear
area for any single test.
The above fracture initiation, propagation and arrest plan must
account for the entire range of pipeline operating temperatures,
pressures and gas compositions planned for the pipeline diameter,
grade, and operating stress level associated with this wavier.
4. Steel Plate Quality Control: The steel mill and/or pipe rolling
mill must incorporate a comprehensive plate/coil mill and pipe mill
inspection program to check for defects and inclusions that could
affect the pipe quality. This program must include a plate (body and
[[Page 39143]]
all ends) ultrasonic testing (UT) inspection program to check for
imperfections such as laminations.
An inspection protocol for centerline segregation evaluation using
a test method referred to as slab macro-etching must be employed to
check for inclusions that may form as the steel plate cools after it
has been cast. A minimum of one macro-etch test must be performed from
the first heat (manufacturing run) of each sequence (approximately 4
heats) and graded on the Mannesmann scale or equivalent. Test results
with a Mannesmann scale rating of one or two out of a possible five are
acceptable.
5. Pipe Seam Quality Control: A quality assurance program must be
instituted for pipe weld seams. The pipe weld seam tests must meet the
minimum requirements for tensile strength in API standard 5L for the
appropriate pipe grade properties.
A pipe weld seam hardness test using the Vickers hardness testing
of a cross-section from the weld seam must be performed on one length
of pipe from each heat. The maximum weld seam and heat affected zone
hardness must be a maximum of 280 Vickers hardness. The hardness tests
must include a minimum of 3 readings for each heat affected zone, 3
readings in the weld metal, and 2 readings in each section of pipe base
metal for a total of 13 readings.
The pipe weld seam must be 100 percent ultrasonically tested after
expansion and hydrostatic testing per APL standard 5L.
6. Puncture Resistance: Steel pipe will be puncture resistant to 35
ton. Puncture resistance will be calculated based on industry
established calculations such as the Pipeline Research Council
International's ``Reliability Based Prevention of Mechanical Damage to
Pipelines'' calculation method.
7. Mill Hydrostatic Test: The pipe must be subjected to a mill
hydrostatic test pressure of 95 percent SMYS or greater for 10 seconds.
8. Pipe Coating: The application of a corrosion resistant coating
to the steel pipe must be subject to a coating application quality
control program. The program must address pipe surface cleanliness
standards, blast cleaning, application temperature control, adhesion,
cathodic disbondment, moisture permeation, bending, minimum coating
thickness, coating imperfections, and coating repair.
9. Field Coating: A field girth weld joint coating application
specification and quality standards to ensure pipe surface cleanliness,
application temperature control, adhesion quality, cathodic
disbondment, moisture permeation, bending, minimum coating thickness,
holiday detection, and repair quality must be implemented in field
conditions. Field joint coatings must be non-shielding to CP. Field
coating applicators must use valid coating procedures and be trained to
use these procedures.
10. Coatings for Trenchless Installation: Coatings used for
directional bore, slick bore, and other trenchless installation methods
must resist abrasions and other damages that may occur due to rocks and
other obstructions encountered in this installation technique.
11. Bends Quality: Certification records of factory induction bends
and/or factory weld bends must be obtained and retained. All bends,
flanges, and fittings must have carbon equivalents (CE) below 0.42 or a
pre-heat procedure prior to welding for CE above 0.42.
12. Fittings: All pressure rated fittings and components (including
flanges, valves, gaskets, pressure vessels, and compressors) must be
rated for a pressure rating commensurate with the MAOP and class
location of the pipeline. Designed fittings (including tees, elbows and
caps) must have the same design factors as the adjacent pipe class
location.
13. Design Factor--Stations: Compressor and meter stations must be
designed using a design factor of 0.50 in accordance with Sec.
192.111.
14. Temperature Control: The compressor station discharge
temperature must be limited to 120[deg] Fahrenheit or a temperature
below the maximum long-term operating temperature for the pipe coating.
15. Overpressure Protection Control: Mainline pipeline overpressure
protection must be limited to a maximum of 104 percent MAOP.
16. Welding Procedures: Automated or manual welding procedure
documentation must be submitted to the appropriate PHMSA regional
office. The PHMSA's regional office must be notified within 14 days
before welding procedure qualification activities.
17. Depth of Cover: The soil cover must be a minimum of 36 inches
except in areas where threats from chisel plowing or other activities
require the top of the pipeline to be installed one foot below the
deepest penetration.
Construction
18. Construction Quality: A construction quality assurance plan to
ensure quality standards and controls must be maintained throughout the
construction phase with respect to: Inspection, pipe hauling and
stringing, field bending, welding, non-destructive examination (NDE) of
girth welds, field joint coating, pipeline coating integrity tests,
lowering of the pipeline in the ditch, padding materials to protect the
pipeline, backfilling, alternating current (AC) interference mitigation
and CP systems. All girth welds must be non-destructively examined by
radiography or alternative means. The NDE examiner must have all
required certifications that are current.
19. Interference Currents Control: Control of induced AC from
parallel electric transmission lines and other interference issues that
may affect the pipeline must be incorporated into the design of the
pipeline and addressed during the construction phase. Issues identified
and not originally addressed in the design phase must be brought to
PHMSA's attention. An induced AC program to protect the pipeline from
corrosion caused by stray currents must be in place within six months
after placing the pipeline in service.
Pre-In Service Hydrostatic Pressure Test
20. Test Level: The pre-in service hydrostatic test must be to a
pressure producing a hoop stress on 0.8 designed class 1 pipe of at
least 100 percent SMYS and 1.25 X MAOP.
21. Assessment of Test Failures: Any pipe failure occurring during
the pre-in service hydrostatic test must undergo a root cause failure
analysis to include a metallurgical examination of the failed pipe. The
results of this examination must preclude a systemic pipeline material
issue and the results must be reported to PHMSA headquarters and the
appropriate PHMSA regional office.
Supervisory Control and Data Acquisition (SCADA)
22. SCADA System Capabilities: A SCADA system to provide remote
monitoring and control of the entire pipeline system must be employed.
23. Mainline Valve Control: Mainline valves that reside on either
side of pipeline segment containing a High Consequence Area (HCA) where
personnel response time to the valve exceeds one (1) hour must be
remotely controlled by the SCADA system. The SCADA system must be
capable of opening and closing the valve and monitoring the valve
position, upstream pressure and downstream pressure. As an alternative,
a leak detection system for mainline valve control is acceptable.
24. SCADA Procedures: A detailed procedure for establishing and
maintaining accurate SCADA set points must be established to ensure the
[[Page 39144]]
pipeline operates within acceptable design limits at all times.
Operations and Maintenance
25. Leak Reporting: Rockies Express must notify the appropriate
PHMSA regional office within 24 hours of any non-reportable leaks
occurring on the pipeline.
26. Annual Reporting: Following approval of the waiver, Rockies
Express must annually report the following:
The results of any in-line inspection (ILI) or direct
assessment results performed within the waiver area during the previous
year;
Any new integrity threats identified within the waiver
area during the previous year;
Any encroachment in the waiver area, including the number
of new residences or public gathering areas;
Any reportable incidents associated with the waiver area
that occurred during the previous year;
Any leaks on the pipeline in the waiver area that occurred
during the previous year;
A list of all repairs on the pipeline in the waiver area
made during the previous year;
On-going damage prevention initiatives on the pipeline in
the waiver area and a discussion of their success; and
Any company mergers, acquisitions, transfers of assets, or
other events affecting the regulatory responsibility of the company
operating the pipeline to which this waiver applies.
27. Pipeline Inspection: The pipeline must be capable of passing
ILI. All headers and other segments covered under this waiver that do
not allow the passage of an ILI device must have a corrosion mitigation
plan.
28. Gas Quality Monitoring and Control: An acceptable gas quality
monitoring and mitigation program must be instituted to not exceed the
following limits:
a. H2S (4 grains maximum);
b. CO2 (3 percent maximum);
c. H2O (less than or equal to 7 pounds per million
standard cubic feet and no free water); and
d. Other deleterious constituents that may impact the integrity of
the pipeline must be instituted.
Filters/separators must be installed at locations where gas is
received into the pipeline to minimize the entry of contaminants and to
protect the integrity of downstream pipeline segments.
Gas quality monitoring equipment must be installed to permit the
operator to manage the introduction of contaminants and free liquids
into the pipeline.
29. Cathodic Protection: The initial CP system must be operational
within 12 months of placing the pipeline in service.
30. Interference Current Surveys: Interference surveys must be
performed within six months of placing the pipeline in service to
ensure compliance with applicable NACE International (NACE) standards
(Recommended Practice (RP) 0169 and RP 0177) for interference current
levels.
31. Corrosion Surveys: Corrosion surveys of the affected pipeline
must be completed within six months of placing the respective CP
system(s) in operation to ensure CP (in accordance with the NACE
standard RP 0169, paragraphs 6.2 and 6.3), test stations, AC
interference mitigation, and AC grounding programs (NACE standard RP
0177) are being implemented along the pipeline.
32. Verification of Cathodic Protection: A close interval survey
(CIS) must be performed in concert with ILI in accordance with subpart
O reassessment intervals for all HCA pipeline mileage. If any annual
test point readings fall below subpart I requirements, remediation must
be performed and must include a CIS on either side of the affected test
point to ensure corrosion control.
33. Pipeline Markers: Rockies Express must employ line-of-sight
markings on the pipeline in the waiver area except in agricultural
areas, subject to Federal Energy Regulatory Commission permits or
environmental permits and local restrictions.
34. Pipeline Patrolling: Pipeline patrolling must be conducted at
least monthly to inspect for excavation activities, ground movement,
wash-outs, leakage, and/or other activities and conditions affecting
the safe operation of the pipeline.
35. Monitoring of Ground Movement: An effective monitoring/
mitigation plan must be in place to monitor for and mitigate issues of
unstable soil and ground movement.
Integrity Management
36. Review of Risk Assessment Calculations: A copy of the C-FER
PIRAMID risk analysis report regarding the pipe subject to this waiver
must be submitted to PHMSA Headquarters.
37. Initial ILI: A baseline ILI must be performed in association
with the construction of the pipeline using a high-resolution Magnetic
Flux Leakage (MFL) tool within three years of placing a pipeline
segment in service. A geometry tool must be launched either prior to
placing the pipeline in service, or no later than six months after
placing the pipeline in service.
38. Future ILI: A second high-resolution MFL inspection must be
performed and completed on the pipe subject to this waiver within the
first reassessment interval required by subpart O, regardless of HCA
classification. Future ILI must be performed on a frequency consistent
with subpart O for the entire pipeline covered by this waiver.
39. Direct Assessment Plan: Headers, mainline valve bypasses, and
other sections covered by this waiver that cannot accommodate ILI tools
must be part of a Direct Assessment (DA) plan or other acceptable
integrity monitoring method.
40. Initial CIS: A CIS must be performed on the pipeline within one
year of completion of the installation of CP systems. The CIS results
must be integrated with the baseline ILI to determine whether further
action is needed.
41. Damage Prevention Program: Common Ground Alliance's damage
prevention best practices must be incorporated into the Rockies Express
damage prevention program.
42. Class 2 and 3 Pipe: Pipe installed in Class 2 and Class 3
locations must use stress factors of 0.60 and 0.50 as required in Sec.
192.111. Pipe in road and railroad crossings must meet the requirements
of Sec. 192.111.
43. Anomaly Evaluation and Repair: Anomaly evaluations and repairs
must be performed based upon the following:
Anomaly Response Time
[cir] Any anomaly with a failure pressure ratio (FPR) equal to or
less than 1.1 must be treated as an ``immediate'' per subpart O.
[cir] Any anomaly with an FPR equal to or less than 1.25 must be
remediated within 12 months per subpart O.
[cir] Any anomaly with an FPR greater than 1.25 must have a
remediation schedule per subpart O.
Anomaly Repair Criteria
[cir] Segments operating at MAOP equal to 80 percent stress level--
any anomaly evaluated and found to have an FPR equal to or less than
1.25 must be repaired.
[cir] Segments operating at MAOP equal to 66 percent stress level--
any anomaly evaluated and found to have an FPR equal to or less than
1.50 must be repaired.
[cir] Segments operating at MAOP equal to 56 percent stress level--
any anomaly evaluated and found to have an FPR equal to or less than
1.80 must be repaired.
a. All other pipe segments with anomalies not repaired must be
[[Page 39145]]
reassessed according to subpart O and the American Society of
Mechanical Engineers (ASME) standard B31.8S requirements. Each anomaly
not repaired must have a corrosion growth rate and ILI tool tolerance
assigned to it per the Gas Integrity Management Program (IMP) to
determine the maximum re-inspection interval.
b. Rockies Express must confirm the remaining strength (R-STRENG)
effective area method, R-STRENG--0.85dL, and ASME standard B31G
assessment methods are valid for their pipe diameter, wall thickness,
grade, operating pressure, operating stress level, and operating
temperature. If it is not valid, Rockies Express must confirm a valid
evaluation method to PHMSA. Until confirmation of the previously
mentioned anomaly assessment calculations has been performed, Rockies
Express must use the most conservative of the calculations for anomaly
evaluation.
c. Dents must be evaluated and repaired per Sec. 192.309(b)(ii)
and Sec. 192.933(d)(l)(ii).
44. Preliminary Criteria Reporting: A preliminary report describing
the results, completion dates and status of the supplementary
requirements must be completed for the western and eastern segments of
the pipeline and submitted to PHMSA Headquarters and the appropriate
PHMSA regional office prior to commencing construction of each segment.
45. Criteria Completion Reporting: A report describing results,
completion dates and status of the outstanding supplementary
requirements must be submitted to PHMSA Headquarters and the
appropriate regional office within 180 days after completion of the
western pipeline segment. A similar report must be completed within 180
days of completion of the eastern segment and submitted to PHMSA
Headquarters and the appropriate PHMSA regional office.
A follow-up report must be submitted for the western and eastern
segments after the baseline ILI run has been performed with assessment
and integration of the results. A final report must be submitted upon
completion of the second ILI run for the western and eastern segments.
These reports must be submitted to PHMSA Headquarters and the
appropriate PHMSA regional office.
46. Potential Impact Radius Calculation Updates: If the pipeline
operating pressures and gas quality are determined to be outside the
parameters of the C-FER Study, a new study with the uprated parameters
must be incorporated into the IMP.
If at anytime PHMSA determines the effect of the waiver is
inconsistent with pipeline safety, PHMSA will revoke the waiver at its
sole discretion.
Authority: 49 U.S.C. 60118 (c) and 49 CFR 1.53.
Issued in Washington, DC, on July 5, 2006.
Theodore L. Willke,
Deputy Associate Administrator for Pipeline Safety.
[FR Doc. 06-6105 Filed 7-6-06; 9:10 am]
BILLING CODE 4910-60-P
