Pipeline Safety: Grant of Waiver; Alliance Pipeline L.P., 39145-39148 [06-6106]

Agencies

• Pipeline and Hazardous Materials Safety Administration
• DEPARTMENT OF TRANSPORTATION

[Federal Register Volume 71, Number 132 (Tuesday, July 11, 2006)]
[Notices]
[Pages 39145-39148]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-6106]


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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.

AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA); 
DOT.

ACTION: Grant of Waiver.

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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 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, fusion-bonded, 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

[[Page 39146]]

Station near Chicago, Illinois, at mile post 874.7. This segment of the 
APL pipeline, including the compressor stations, is referred to as the 
waiver area.
    (2) Provide relief from regulations which require that compressor 
station piping be subjected to Class 3 testing requirements by 
increasing the stress level in the compressor station piping from 50 
percent of SMYS, corresponding to 1814 psig, to 54 percent of SMYS, 
corresponding to 1961.4 psig. This request results in increasing the 
design factor for the station piping from 0.50 to 0.54.
    (3) Provide relief from regulations requiring all Class 1 locations 
to comply with strength test factor requirements. The minimum test 
pressure obtained in pipelines located in Class 1 locations was 2229 
psig. This resulted in a 1.15 test factor for operation at 1935.1 psig 
(80 percent of SMYS).
    (4) Provide relief from regulations requiring all Class 2 locations 
to comply with strength test factor and the design factor requirements. 
Two Class 2 locations totaling 966 linear feet (LF) are affected by 
this request and include a 379 LF section located downstream of mile 
post 764.6 and a 587 LF section located downstream of mile post 819.8. 
These two Class 2 locations will increase the design factor to 80 
percent of SMYS and operate up to the proposed MAOP of 1935.1 psig.
    (5) Allow use of the American Society of Mechanical Engineers 
(ASME) standard B31.8 requirement to hydrostatically test compressor 
station piping to 1.4 times the MAOP, in lieu of the regulatory 
requirements to test to 1.5 times the MAOP. As a result, piping in one 
of APL's compressor stations will be hydrostatically re-tested; 
however, the remaining six stations will not require additional station 
piping hydrostatic tests.
    (6) Relief from regulations governing compressor station design 
MAOP and overpressure protection set points, and be permitted to 
operate the system at the compressor stations at less than or equal to 
1961.4 psig. This corresponds to a compressor station MAOP of 54 
percent SMYS (81.07 percent of SMYS of the mainline pipe), which is 
26.3 psig above the proposed 1935.1 psig (80 percent of SMYS operating 
pressure). The overpressure protection set point exceeds the regulatory 
requirement of 75 percent of SMYS, but is less than 110 percent of the 
mainline MAOP of 1935.1 psig.

Pipeline System Analysis

    APL established feasibility criteria to assess the safety and 
reliability of the pipeline to operate at stress levels up to 80 
percent of SMYS. These criteria include:
     Developing operational commitments that would improve 
safety for any person residing, working, or vacationing near the United 
States portion of its pipeline, including approximately 15 miles of 
pipeline located in high consequence areas.
     Performing in-depth assessments of its existing pipeline 
equipment to ensure there is no impact on the reliability of the 
pipeline. APL performed reviews to verify that the equipment is capable 
of sustaining operations at increased pressures.
     Providing environmental benefits versus other delivery 
alternatives for the additional gas being provided.
     Creating economic benefits to natural gas suppliers and 
shippers.
     Creating incremental economic benefits to end use 
customers.
    APL also performed technical reviews and assessments of its 
pipeline and compressor stations facilities that currently operate at 
72 percent of SMYS and in the future will operate at 80 percent of 
SMYS. APL compared the threats associated with a pipeline operating at 
72 percent of SMYS with the threats associated with a pipeline 
operating at 80 percent of SMYS. APL analyzed the following nine 
threats: (1) Excavation damage; (2) external corrosion; (3) internal 
corrosion; (4) stress corrosion cracking; (5) pipe manufacturing; (6) 
construction; (7) equipment; (8) weather and outside factors; and (9) 
incorrect operations.
    In response to these technical reviews and assessments, APL 
proposed several programs to mitigate the increased risks to its 
pipeline. APL will implement preventive measures as part of its 
Integrity Management Program (IMP) to mitigate the threats imposed by 
excavation damage. APL also will develop an external corrosion 
mitigation plan to address the threat of external corrosion, and APL 
will rely on the integrity reassessment intervals of IMP to mitigate 
the threat of internal corrosion. To manage the threat of stress 
corrosion cracking, APL will implement magnetic particle examinations 
at any location(s) along its pipeline where damage to its fusion bond 
epoxy (FBE) coating is detected. APL also will perform external 
corrosion direct assessment (ECDA) in the Class 2 areas prior to 
increasing pressure with the exception of the pipeline segment located 
under the Mississippi River where ECDA is impractical.

Grant of Waiver

    On March 22, 2006, PHMSA published its notice of intent to consider 
the waiver and solicited comments from the public (71 FR 14572). We 
received two comments: One concerning ``open'' communications, and the 
other supporting the waiver.
     One commenter indicated that although APL has proven to be 
a good neighbor, he expressed reservations about APL's openness in 
communications.
     The other commenter supported the waiver because the 
benefits of granting the waiver will at least include (1) an increase 
in available natural gas pipeline capacity on APL's pipeline, thereby 
increasing the amount of natural gas that can be delivered to customer 
markets throughout the United States; (2) an improvement in fuel 
efficiency through a reduction in required fuel gas, which will lead to 
fuel cost savings; and (3) a reduction in capital expenditures by APL, 
particularly for expanding its facilities and building new pipelines.
    PHMSA reviewed the documentation submitted by APL prior to 
proposing action on the waiver petition. PHMSA also requested 
additional information as a part of its technical review. APL responded 
to information requests from PHMSA and other stakeholders to clarify 
technical details of the petition. APL's responses to our supplementary 
questions are available in docket PHMSA-2006-23387 at https://
dms.dot.gov. 
    PHMSA evaluated APL's studies that technically justified the waiver 
petition. PHMSA also recognized the superior materials used to 
construct the APL system and the full-scale testing sponsored by APL to 
verify the fracture control characteristics of the pipe material. APL 
proposed operational commitments, when combined with the PHMSA required 
safety criteria discussed later in this document, enhance the safety of 
the pipeline system and offset the risk of increasing the operating 
stress level from 72 percent to 80 percent of SMYS. APL's commitments 
and PHMSA's supplementary safety criteria require the APL system to be 
more rigorously monitored than other pipelines not covered by a similar 
waiver.
    PHMSA considered APL's waiver request and whether its proposal will 
yield an equivalent or greater degree of safety than that currently 
provided by the pipeline safety regulations. PHMSA also reviewed 
additional information provided by APL in response to a PHMSA 
information request. After reviewing all submitted information,

[[Page 39147]]

PHMSA also developed safety criteria that APL must comply with as a 
condition of the waiver. The criteria, listed below, together with the 
programs proposed by APL in the waiver petition, would be the basis for 
the life-cycle management of the APL pipeline subject to the waiver.
    PHMSA received positive comments and conducted a thorough technical 
review of APL's application for waiver, supporting documents, and 
comments received. In addition, PHMSA sought comments and received 
positive feedback from the impacted States along the pipeline and the 
Technical Pipeline Safety Standards Committee. PHMSA hereby grants 
APL's waiver request provided APL, or a successor operator, complies 
with the following supplemental safety criteria:

Pipe and Material Quality

    1. Fracture Control Plan: APL must implement an overall fracture 
control plan to address fracture initiation, propagation and Charpy 
arrest (stop) values. The fracture initiation, propagation and arrest 
plan must account for the entire range of temperatures, pressures and 
gas compositions that the pipeline will experience.
    2. Fittings: All pressure rated fittings and components (including 
flanges, valves, gaskets, pressure vessels and compressors) must be 
rated for a pressure 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.
    3. Station Design Factor: APL may use a design factor not exceeding 
0.54 for existing compressor and meter stations. New compressor and 
meter stations must be designed using a design factor of 0.50 per Sec.  
192.111.
    4. 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.
    5. Overpressure Protection: Mainline pipeline overpressure 
protection must be limited to a maximum of 104 percent of MAOP.

Supervisory Control and Data Acquisition (SCADA)

    6. SCADA System: APL must use a SCADA system to provide remote 
monitoring and control of the entire pipeline system.
    7. 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 
to remote control of mainline valves, APL may implement a leak 
detection system.
    8. SCADA Set Point Review: APL must implement a detailed procedure 
to establish and maintain accurate SCADA set points to ensure the 
pipeline is operating within acceptable design limits at all times.

Operations and Maintenance

    9. Leak Reporting: APL must notify the PHMSA Central Region Office 
as soon as practicable of any non-reportable leaks occurring on the 
pipeline covered by the waiver.
    10. Annual Reporting: Annually, following approval of the waiver, 
APL must report the following:
     The results of any ILI or direct assessments 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 within 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.
     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.
    11. Pipeline Inspection: The pipeline must be capable of passing 
ILI. All headers and other segments covered under the waiver that do 
not allow the passage of an internal inspection device must have a 
corrosion mitigation plan.
    12. Gas Quality Monitoring and Control: APL's gas quality 
monitoring and mitigation program must have the ability to restrict 
constituents that promote internal corrosion to not exceed the 
following limits:
     H2S (4 grains maximum);
     CO2 (3 percent maximum);
     H2O (less than or equal to 7 pounds per million 
standard cubic feet and no free water); and
     Other deleterious constituents that may impact the 
integrity of the pipeline must be minimized.
    13. Gas Quality Control Equipment: Filters/separators must be 
installed at locations where needed to comply with the above gas 
quality requirements and meet APL's gas tariff.
    14. Control of Liquids: Gas quality monitoring equipment must be 
installed to permit the operator to manage the introduction of 
contaminants and free liquids into the pipeline.
    15. Corrosion Mitigation Plan: APL must submit an external 
corrosion mitigation plan as summarized in its waiver petition, 
Appendix N.
    16. Initial Close Interval Survey: An initial baseline close 
interval survey (CIS) must be completed in concert with the baseline 
ILI indicated in criteria 24 and as indicated in the operational 
commitments of APL's waiver petition.
    17. Verification of Cathodic Protection: A CIS must be performed in 
concert with an 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.
    18. Pipeline Markers: APL must employ line-of-sight marking on the 
pipeline in the waiver area except in agricultural areas subject to the 
Federal Energy Regulatory Commission permits or environmental permits 
and local restrictions.
    19. Pipeline Patrolling: APL must patrol the pipeline 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.
    20. 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.
    21. Uprating Plan Review and Approval: The uprating (commissioning) 
plan must be submitted to the PHMSA Central Region Office for review 
and approval before increasing the pressure on the pipeline.
    22. Preliminary Criteria Reporting: A preliminary report describing 
the results, completion dates and status of actions required under 
supplemental safety criteria contained herein must be completed and 
submitted to PHMSA Headquarters and PHMSA Central Region Office prior 
to increasing the pressure on the pipeline system.
    23. Criteria Completion Reporting: A report describing results, 
completion dates and status of the outstanding criteria must be 
submitted to PHMSA

[[Page 39148]]

Headquarters and PHMSA Central Region Office within 180 days after 
completion of uprating.
    A final report must be submitted to PHMSA Headquarters and PHMSA 
Central Regional Office upon completion of the second ILI run for the 
pipeline.

Integrity Management

    24. Initial ILI: A baseline ILI must be performed in association 
with this waiver on the pipeline using a high-resolution inline 
inspection technology capable of detecting metal loss and mechanical 
damage. The results of the baseline ILI must be integrated with the 
baseline CIS as described in criteria number 16.
    25. Future ILI: A second high resolution MFL inspection must be 
performed on the pipe subject to the waiver following the baseline ILI 
and be completed 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.
    26. 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 plan or other acceptable integrity 
monitoring method.
    27. Damage Prevention Program: Common Ground Alliance's damage 
prevention best practices must be incorporated into APL's damage 
prevention program.
    28. Anomaly Evaluation and Repair: Anomaly evaluations and repairs 
must be performed based upon the following:
     For purposes of this criterion, the Failure Pressure Ratio 
(FPR) is an indication of the pipeline's remaining strength from an 
anomaly and is equal to the predicted failure pressure divided by the 
MAOP.
     Anomaly Response Time.
    [cir] Any anomaly with a FPR equal to or less than 1.1 must be 
treated as an ``immediate repair'' per subpart O.
    [cir] Any anomaly with a 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 that are not repaired 
must be reassessed according to subpart O and ASME Standard B31.8S 
requirements. Each anomaly not repaired must have a corrosion growth 
rate and an ILI tolerance assigned to it per the Gas IMP to determine 
the maximum re-inspection interval.
    b. APL must confirm that the remaining strength (R-STRENG) 
effective area method, R-STRENG-0.85dL, and B31G assessment methods are 
valid for the pipe diameter, wall thickness, grade, operating pressure, 
operating stress level, and operating temperature covered under this 
waiver. If the assessment methods are not valid, APL must submit a 
valid method to PHMSA Central Region Office. Until confirmation of the 
previously mentioned anomaly assessment calculations have been 
performed, APL must use the most conservative of the calculations for 
anomaly evaluation.
    c. Dents must be evaluated and repaired in accordance with 
Sec. Sec.  192.309(b)(ii) and 192.933(d)(l)(ii).
    29. 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 updated 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. 06-6106 Filed 7-6-06; 9:10 am]
BILLING CODE 4910-60-P