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PHMSA Office of Pipeline Safety

PHMSA Office of Pipeline Safety . 2010 Pipeline Safety Seminar. Pipeline and Hazardous Materials Safety Administration Community Assistance and Technical Services Elizabeth Komiskey Harold Winnie June 22, 2010. Meeting Challenges Facing the Industry. Control Rooms

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PHMSA Office of Pipeline Safety

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  1. PHMSAOffice of Pipeline Safety

  2. 2010 Pipeline Safety Seminar Pipeline and Hazardous Materials Safety Administration Community Assistance and Technical Services Elizabeth Komiskey Harold Winnie June 22, 2010

  3. Meeting Challenges Facing the Industry • Control Rooms • Public Awareness - Effectiveness • DIMP • Incident Report Forms

  4. Control Room ManagementRegulations Implementation 06-14-2010

  5. Operators and Controllers *- Limited Inclusion refers to Fatigue Management and Compliance Deviation

  6. Pipeline CRM Risk Matrix--- Risk derived from monitor and control ---Red indicates highest risk, Yellow indicates lower risk --- Full Inclusion --- Limited to Fatigue Mgt Matrix coding principally represents the combination of frequency and consequence of pipeline upset conditions and failures, where CRM may be a contributing factor 06-14-2010

  7. 49CFR : 192.631 & 195.446 • a) General • b) Roles and Responsibilities • c) Provide Adequate Information • d) Fatigue Mitigation • e) Alarm Management • f) Change Management • g) Operating Experience • h) Training • i) Compliance Validation • j) Compliance and Deviation 06-14-2010

  8. Inspections Fatigue Management 06-14-2010

  9. Key Milestones for CRM RegulationsImplementation Timetable • Final Rule Published : Dec-2009 → Public Workshop : Nov-2010 • Hours of Service Criteria Finalized : 1Q11 • Shift Schedules Criteria Finalized: 1Q11 • FAQ’s Finalized : 1Q11 • Inspection Enforcement Guidance : 2Q11 • Inspector Training Material : 2Q11 • Operator Procedures/Programs Established : Aug-2011 → Program Inspections : Sep-2011 to Feb-2013 • Operator Procedures/Programs in Service : Feb-2013 → Implementation Inspections Begin : Mar-2013

  10. CRM Public Workshop • 1 Full Day • November 17, 2010 • Houston • Preliminary Inspection Material • FAQ’s, Discussed and Solicited • Stakeholder Participation 06-14-2010

  11. Public Awareness

  12. What has PHMSA done? • Formed a Public Awareness Program Enforcement Guidance Team • Create Enforcement Guidance for Public Awareness Programs • Developed draft enforcement guidance and will maintain the “final” guidance in response to new regulations and Advisory Bulletins.

  13. What is PHMSA doing? PHMSA formed an ad hoc committee to focus on program effectiveness (4-year review) evaluations: • Operator self-evaluations • Results (including documentation) • PAP improvements identified and/or implemented

  14. Action Plan • Focused inspection questions based on overall enforcement guidance • Develop FAQs • Develop a training plan • Develop prioritization strategy • Implement a pilot program • Timeline

  15. Public Meeting June 30, 2010 Hotel Intercontinental 2222 W. Loop-South Houston, Texas 77027 (on your own for lunch)

  16. Public Meeting Go to: www.phmsa.dot.gov/pipeline Click on “Stakeholder Communications” Click on “Public Meetings” Click on “More information . . .” Check June 30, 2010 Registration & Agenda is there

  17. Effectiveness of Public Awareness Programs

  18. Effectiveness Evaluation • When is it Due? • API RP 1162 in section 8.5? • PHMSA FAQ’s? • http://primis.phmsa.dot.gov/comm/publications/Public_Awareness_FAQs_05-11-2006.pdf?nocache=1572

  19. Program Evaluation • Assessment of Program Implementation • Measuring Program Effectiveness

  20. Measuring Program Effectiveness

  21. Outreach: Percentage of Each Intended Audience Reached with Desired Messages • Number of Inquiries by Phone to Operator • Input Received Via Feedback Postcards (reply or bounce-back cards) • Events or meetings • Sent by mail • Operator’s canvassing of the right-of-wayS • Number of officials or emergency responders who attend pipeline training or emergency response exercises

  22. Desired Behaviors by the Intended Stakeholder Audience • Excavators Using • Number of notifications received from the One-Call Center • Assessment of first responder behaviors, • Response to pipeline-related calls, • Post-incident assessment of actions • Assessment of actual incidents should recognize • Appropriateness of public stakeholders’ responses • Actual incident was correctly identified • Reported and personal safety actions undertaken • Consistent with public awareness communication.

  23. Key Take A Ways • Effectiveness Evaluation June 20, 2010 • Continuous Improvement • Surveys • Reply Cards • Seven Seconds

  24. DIMP

  25. DIMP Timeline • Pipeline Inspection, Enforcement, and Protection Act of 2006 (PIPES) … DIMP mandate • NPRM … June 25, 2008 • Comment Period ended … October 23, 2008 • TPSSC Vote … December 12, 2008 • Final Rule Publish … December 4, 2009 (Effective Date… February 12, 2010) • Comment Period for Reporting of Compression Couplings … February 4, 2010 • Operators Write and Implement DIMP Plan … Aug. 12, 2011

  26. What Operators Must Do for DIMP to have Value? • Develop an approach that is specific to the threats your systems faces as well as the unique aspects of your facilities, operating locations, and data available for use. • Focus on risk, driven by data. • Identify data gaps. Promote accurate and effective data collection, analysis and use. • Review current processes and procedures for leak reporting, new installs, maintenance & operations, pipe exposures, damage prevention, and public awareness. • Identify and implement additional/accelerated actions to mitigate threats, and integrating these with your current programs. …operators must seek not simply to meet minimum compliance but strive to improve the integrity of their pipeline system!

  27. What Principles Underlie DIMP? • DIMP requires operators to: • Know Their Infrastructure • Identify Threats • Evaluate and Rank Risks • Identify and Implement Measures to Address Risks • Measure Performance, Monitor Results, and Evaluate Effectiveness • Periodically Evaluate and Improve Program • Report Results • In combination with the GPTC Guidance provides direction to operators and allows the regulator to investigate internal operator risk management practices

  28. Final Rule Requirements • Develop and Implement Written Plan Within 18 months of Final Rule • EFV’s must be installed on new and replaced service lines serving single-family residences • Report compression coupling failures • Maintain IMP records for 10 years • Alternate Inspection Interval (Optional) • Simpler but similar requirements for master meter and small liquefied petroleum gas (LPG) operators • Performance Measures & Annual Report

  29. Reporting Coupling Failure

  30. Reporting Coupling Failure • Public comment period on inclusion of reporting of metallic compression coupling failures which result in hazardous leaks • Data to be reported includes: • Required information is failure-specific – more than number of failures. Reported on the annual report • Period to file comments extended to February 4, 2010

  31. Performance Measure and Annual Report Performance measures must include: • Number of hazardous leaks either eliminated or repaired categorized by cause • Number of excavation damages • Number of excavation tickets (based on One-call tickets) • Total number of leaks either eliminated or repaired, categorized by cause • Number of hazardous leaks either eliminated or repaired categorized by material • Any additional measures the operator determines are needed to evaluate the effectiveness of the operator’s IM program in controlling each identified threat. …annual report forms are in revision, to be posted on PHMSA’s web site.

  32. DIMP Guidance GPTC Guidelines APGA (SHRIMP) Simple Handy Rule based Integrity Management Plan Guidance for MMO’s, LPG, and Small Operators Local Workshops and Seminars 37

  33. Excess Flow Valve (EFV) • New or replaced service lines serving single-family residences • Must install an EFV service line (90 days after FR), Unless (1) Operating at 10 psig or less (2) Contaminants in the gas stream (3) EFV could interfere with necessary operation or maintenance activities (4) An EFV is not commercially available

  34. Deviation from required periodic inspections under this part ? • Propose to reduce the frequency of periodic inspections on the basis of the: • Engineering analysis • Risk assessment • Demonstrate that the reduced frequency will not significantly increase risk • Submit proposal to responsible agency for APPROVAL

  35. Select Additional/Accelerated Actions • For each threat SHRIMP will offer a pick list of possible additional/accelerated actions • These come from GPTC, with additions by the SHRIMP advisors • Based on answers to the threat assessment questions some A/As may be recommended and others not offered • Example: If CP levels are good, upgrading CP may not be offered as an A/A Action

  36. Key Takeaways • Final Rule Effective Date 2-12-2010 • When Do I Need to Have My Program Implemented 8-12-2011 • What Should I Include in My Program • What about Small Operators • What about LPG and Master Meters

  37. New Incident Forms Effective January 2010 new forms are to be used. Form RSPA F 7100.1 Distribution Form RSPA F 7100.2 Transmission and Gathering

  38. What is an incident • "Incident" means any of the following events: • (1) An event that involves a release of gas from a pipeline or of liquefied natural gas or gas from an LNG Facility and • (i) A death, or personal injury necessitating in-patient hospitalization; or • (ii) Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more. • (2) An event that results in an emergency shutdown of an LNG facility. • (3) An event that is significant, in the judgment of the operator, even though it did not meet the criteria of paragraphs (1) or (2).

  39. Additional Considerations • Items to be considered when determining if an event may be significant include the following. • (1) Rupture, Explosion, Fire. • (2) Loss of service. • (3) Involvement of local emergency response personnel. • (4) Evacuation of people in the area. • (5) Major Traffic Reroutes/Closures • (6) Degree of media involvement.

  40. Within two (2) hours or as soon as practical following the discovery of any reportable incident, an operator shall notify the NATIONAL REPORTING CENTER NRC (800-424-8802) IUB

  41. What should be provided • For the telephonic report • (1) Names of operator and person making report and their telephone numbers. • (2) The location of the incident. • (3) The time of the incident. • (4) The number of fatalities and personal injuries, if any. • (5) All other significant facts that are known by the operator that are relevant to the cause of the incident or extent of the damages.

  42. REQUIRED WRITTEN REPORTS Each gas distribution system operator shall file Form PHMSA F 7100.1, and each gas transmission or gathering system operator shall file Form PHMSA F 7100.2 for an incident that meets the criteria in 49 CFR §191.3 as soon as practicable but not more than 30 days after discovery of the incident.

  43. SECONDARY IGNITION • Damage from secondary ignition need not be reported unless the damage to facilities subject to Part 191 exceeds $50,000. • Secondary ignition is a gas fire where the origin is unrelated to the gas facilities, such as electrical fires, arson, etc.

  44. REPORTING ONLINE • ONLINE http://opsweb.phmsa.dot.gov/ • If you submit your report online, PLEASE DO NOT MAIL OR FAX the completed report to DOT as this may result in duplicate entries. • Submit a copy of your report directly to the Iowa Utility Board in addition to submitting to DOT/PHMSA.

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