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phmsa office of pipeline safety

PHMSA Updates . Presented to:California State Fire Marshal's 2011 Pipeline Safety WorkshopMay 26, 2011By Tom FinchCATS Manager, Western RegionUSDOT/PHMSA/Office of Pipeline Safety (OPS) . PHMSA HQ . Administrator Cynthia Quarterman (Political Appointee)Chief Counsel

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phmsa office of pipeline safety

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    1. PHMSAOffice of Pipeline Safety

    3. PHMSA HQ Administrator Cynthia Quarterman (Political Appointee) Chief Counsel Biz Scott (Political Appointee) Deputy Administrator Tim Butters Jeff Wiese - Associate Administrator of Pipeline Safety Alan Mayberry - OPS Deputy Associate Administrator of Regional Operations Linda Daugherty - OPS Deputy Associate Administrator of Policy John Hess - Director of Emergency Support and Security Chris Hoidal Director of Western Region (Lakewood, Colorado)

    4. PHMSA Regions

    5. Western Region Offices Western Region Office 12300 West Dakota Avenue, Suite 110 Lakewood, CO 80228 Satellite offices in: Cheyenne, WY (1 engineer) Billings, MT (1 engineer) Helena, MT (1 engineer) Ontario, CA (3 engineers, one just hired) Anchorage, AK (6 engineers)

    6. Objectives of Past Rulemaking The past Administration focused on resolving many of our rulemaking mandates from Congress and the Pipeline Safety Reauthorizations of 2002 and 2006 (PIPES Act). NTSB recommendations addressed. Recurring special permits requests are now codified into regulations. Collecting better data to aid agency decisions.

    7. Final Key Rulemakings Final Rules Issued: _ Standards for Increasing the Maximum Allowable Operating Pressure (MAOP) for Gas Transmission Pipelines (Effective 12/22/08) Low Stress Hazardous Liquid Pipelines Phase 1 (Effective 07/03/08) Safety Orders (Effective 02/17/09) Distribution Integrity Management (DIMP) (Effective 02/02/10) Control Room Mgmt. (Prevention Through People) (Effective 02/01/10) Standards Update API 1104 and API 5L (Incorporated 04/14/09) One Rule - Updates to Pipeline and Liquefied Natural Gas Reporting Requirements (Effective 01/01/2011) Low Stress Hazardous Liquid Pipelines Phase 2 - Applying Safety Regulations to All Rural Onshore Hazardous Liquid Low-Stress Lines (Effective 10/01/2011) Final Rules MAOP issued October 17, effective Dec 22 Low stress rule June 3, 2008, effective July 3, 2008 Safety Orders IFR March 2008, Final Rule issued January 16 DIMP NPRM June 25 2008 CRM September 12/2008Final Rules MAOP issued October 17, effective Dec 22 Low stress rule June 3, 2008, effective July 3, 2008 Safety Orders IFR March 2008, Final Rule issued January 16 DIMP NPRM June 25 2008 CRM September 12/2008

    8. Alternate MAOP Rule Allows for an increase of maximum allowable operating pressure (MAOP) over that currently allowed (up to 80% of Specified Minimum Yield Strength in Class 1 areas) Applies to gas transmission lines. Also, was being requested by one hazardous liquid operator for a hazardous liquid pipeline from Canada to Texas Increases energy capacity while maintaining safety Requires additional design and construction considerations Requires higher level of maintenance and assessment Requires 180 day notice to Region about intent to use alternate MAOP level PHMSA published in the Federal Register today (Part V 73 FR 62148;October 17, 2008) a Final Rule that amends the pipeline safety regulations to prescribe safety requirements for the operation of certain gas transmission pipelines at pressures based on higher operating stress levels. The result is an increase of maximum allowable operating pressure (MAOP) over that currently allowed in the regulations. Improvements in pipeline technology assessment methodology, maintenance practices, and management processes over the past twenty-five years have significantly reduced the risk of failure in pipelines and necessitate updating the standards that govern the MAOP. This rule will generate significant public benefits by reducing the number and consequences of potential incidents and boosting the potential capacity and efficiency of pipeline infrastructure, while promoting rigorous life-cycle maintenance and investment in improved pipe technology. 80% SMYS lots of strings NOPR 3/12/08 (73 FR 13167) No more waivers Special Permits Rockies Express approved Columbia Gulf, Gulf Crossing, Boardwalk & Florida Gas pendingPHMSA published in the Federal Register today (Part V 73 FR 62148;October 17, 2008) a Final Rule that amends the pipeline safety regulations to prescribe safety requirements for the operation of certain gas transmission pipelines at pressures based on higher operating stress levels. The result is an increase of maximum allowable operating pressure (MAOP) over that currently allowed in the regulations. Improvements in pipeline technology assessment methodology, maintenance practices, and management processes over the past twenty-five years have significantly reduced the risk of failure in pipelines and necessitate updating the standards that govern the MAOP. This rule will generate significant public benefits by reducing the number and consequences of potential incidents and boosting the potential capacity and efficiency of pipeline infrastructure, while promoting rigorous life-cycle maintenance and investment in improved pipe technology. 80% SMYS lots of strings NOPR 3/12/08 (73 FR 13167) No more waivers Special Permits Rockies Express approved Columbia Gulf, Gulf Crossing, Boardwalk & Florida Gas pending

    9. Timeline Special permits were granted on a case by case basis Proposed rule developed to codify Special Permit conditions Notice of Proposed Rulemaking (NPRM) published March 12, 2008 Final rule published October 17, 2008 Final rule was effective 60 days from date of publicationDecember 22, 2008

    10. Comparisonof Material and Construction Control

    11. Comparison of Damage Prevention & Emergency Response

    12. Comparison of Corrosion Control

    13. ComparisonOther Requirements

    14. Accidents High Profile & Recent High Profile Corrosion Accidents in Alaska in 2006 Recent Accidents in April, May, June, September, December, 2010, and January 2011

    15. High Profile Corrosion Accident in Alaska March 2, 2006 and August 6, 2006 Internal corrosion caused a 5,000 barrel crude oil spill onto the Arctic Tundra on March 2nd. Issued a CAO on a 34 diameter, low stress crude oil transmission pipeline NOT regulated by DOT. Following mandated smart pigging and a second leak discovered on August 6th, the operator shut down their entire Prudhoe Bay crude oil system until interim safety could be assured. Full line replacement occurred. This spill catapulted rulemaking on low stress pipelines in USA areas, i.e. The Low Stress Liquid Gathering Rule to the head of the rulemaking list.

    16. Another High Profile Accident in Alaska Alyeska Pump Station (PS) 9 May 25, 2010 Overfilled Breakout Tank at PS 9 5000 BBLs spilled out vents and into containment area. Failed Unit Power System (UPS) prevented communications, tank monitoring and valve control. Tank appears to be damaged. Issued a CAO requiring full time monitoring at PS9 and staffing by OQ personnel at site. Verification that pipeline could operate without PS 9 relief.

    17. Photo of Pump Station 9 Spill

    18. Another High Profile Accident Salt Lake City, June 12, 2010 Approx 750 BBL of crude spill into Salt Lake City creeks and small lakes on June 11/12, 2010. Power company built substation immediately adjacent to pipeline. Fence post directly on top of pipeline. Fault current burned dime sized hole in pipeline.

    19. Damaged Pipe - Salt Lake City, June 12, 2010

    20. Pipeline SpillApril 5, 2010 Unknown crude oil line spills 2000 BBL near Mt View, Wyoming CAO issued 4/28/2010 to take out of service until O&M, OQ, and ILI conducted. Tank allowed to come back into service.

    21. SpillCheyenne, WY - June 14, 2010 30,000 BBL breakout tank overfills in Cheyenne, Wyoming. High alarms did not work. Spilled 50 BBLs into containment.

    22. San Bruno, CA - September 9, 2010

    23. Salt Lake City, Utah December 1, 2010

    24. Salt Lake City, Utah December 1, 2010

    25. A Focus on AC induced current and fault current protection 195.575 Which facilities must I electrically isolate and what inspections, tests, and safeguards are required? (a) You must electrically isolate each buried or submerged pipeline from other metallic structures, unless you electrically interconnect and cathodically protect the pipeline and the other structures as a single unit. (b) You must install one or more insulating devices where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control. (c) You must inspect and electrically test each electrical isolation to assure the isolation is adequate. (d) If you install an insulating device in an area where a combustible atmosphere is reasonable to foresee, you must take precautions to prevent arcing. (e) If a pipeline is in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, you must protect the pipeline against damage from fault currents or lightning and take protective measures at insulating devices. (f) Any unusual risk of lightning, you must protect the pipeline against damage from fault currents or lightning and take protective measures at insulating devices.

    26. A Focus on AC induced current and fault current protection 195.577 What must I do to alleviate interference currents? (a) For pipelines exposed to stray currents, you must have a program to identify, test for, and minimize the detrimental effects of such currents. (b) You must design and install each impressed current or galvanic anode system to minimize any adverse effects on existing adjacent metallic structures.

    27. A Focus on AC induced current and fault current protection 192.467 External corrosion control: Electrical isolation. (a) Each buried or submerged pipeline must be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit. (b) One or more insulating devices must be installed where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control. (c) Except for unprotected copper inserted in a ferrous pipe, each pipeline must be electrically isolated from metallic casings that are a part of the underground system. However, if isolation is not achieved because it is impractical, other measures must be taken to minimize corrosion of the pipeline inside the casing. (d) Inspection and electrical tests must be made to assure that electrical isolation is adequate. (e) An insulating device may not be installed in an area where a combustible atmosphere is anticipated unless precautions are taken to prevent arcing. (f) Where a pipeline is located in close proximity to electrical transmission tower footings, ground cables or counterpoise, or in other areas where fault currents or unusual risk of lightning may be anticipated, it must be provided with protection against damage due to fault currents or lightning, and protective measures must also be taken at insulating devices.

    28. Pipeline Accidents & Incidents w/Death or Major Injury (1988-2010)

    29. Questions? Thank You! Tom Finch U.S. Department of Transportation (US DOT) Pipeline & Hazardous Materials Safety Administration (PHMSA) Western Region CATS Manager e-mail: thomas.finch@dot.gov Tel: 720-963-3175 Cell: 303-807-7200 Fax: 720-963-3161

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