[Federal Register Volume 71, Number 132 (Tuesday, July 11, 2006)]
[Notices]
[Pages 39141-39145]
From the Federal Register Online via the Government Publishing 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 http://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