U.S. DOT Pipeline and Hazardous Materials Safety Administration. William (Bill) Lowry, PE Community Liaison

Transcription

1 U.S. DOT Pipeline and Hazardous Materials Safety Administration William (Bill) Lowry, PE Community Liaison

2 Community Assistance & Technical Services (CATS) Name Change Effective: January 1, 2017 Community Liaison (CL) Why? More appropriately aligns with current roles and responsibilities Better articulates role to various stakeholders Stakeholders can more clearly interface with the agency staff CATS acronym was too long and difficult to explain

3 Office of Pipeline Safety Community Liaisons Community Liaison Services Program Manager Karen Lynch Eastern Region Southern Region Central Region Western Region Southwest Region Karen Gentile Arthur Buff Angela Pickett Dave Mulligan Bill Lowry Ian Woods James Kelly Sean Quinlan Tom Finch Jay Prothro For more information:

4 PHMSA Update Today s Agenda Inspection Policies and Procedures PHMSA Rulemaking PHMSA Advisory Bulletins

5 PHMSA Update

6 PHMSA Organization Chart Howard (Mac) McMillan Rosanne Goodwill - - Kim Curry Alan Mayberry Bill Schoonover Everett Lott Tami Perriello

7 PHMSA Regional Offices PHMSA s FY2015 IT Portfolio 7

8 Underlying Principles It is the responsibility of the operator to understand and manage the risks associated with their pipelines PHMSA s primary role - establish minimum safety standards (defined in the regulations by required risk control practices) and verify the operators perform to these standards PHMSA strives to impact operator performance beyond mere compliance with the regulations Focus is on PERFORMANCE

9 Executive Orders & Memos Many relate to Pipeline Infrastructure Promoting Energy Independence and Economic Growth - immediately review existing regulations that potentially burden "burden" means to unnecessarily obstruct, delay, curtail, or otherwise impose significant costs on the siting, permitting, production, utilization, transmission, or delivery of energy resources. Elimination of at least two prior regulations for every one new regulation that is issued Alleviate unnecessary regulatory burdens placed on the American people Streamline and expedite, in a manner consistent with law, environmental reviews and approvals for all infrastructure projects

10 PHMSA Approaches to Promote Improved Performance (1/2) Conduct physical and programmatic inspections (management systems, procedures, and processes) Clarify expectations through range of public communications (regulations, published protocols, guidance documents including ADBs, public meetings, enforcement transparency, outreach, education) Facilitate/promote adoption of a Safety Management System..

11 PHMSA Approaches to Promote Improved Performance (2/2) Participate in consensus standards development Promote public awareness, damage prevention programs and equip emergency responders Conduct accident and safety investigations Communicate directly with operators on their challenges

12 Pipeline Operators, No Matter Their Size, Can Benefit From a PSMS PSMS is centered around Safety Leadership at ALL levels and Management Commitment. PSMS fosters and requires continual improvement. Learn from other industries: t?list=pl4whdsuqukm7mz20uvkeagvu2u_cro6o Public Workshop Feb 2014 Search PHMSA + SMS Copyright 2012 E.I DuPont

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14 Index (1988 = 1) Pipeline Safety with Context Measures ( ) Natural Gas Consumption Petroleum Product Consumption 1.0 Pipeline Mileage U.S. Population (Millions) 0.4 Major Hazardous Liquid Spills Incidents with Death or Injury Calendar Year

15 1 5 Categories of Incident Reports All Reported everything operators report Serious fatality or injury requiring in-patient hospitalization, but Fire First excluded. Fire First are gas distribution incidents with a cause of Other Outside Force Damage and sub-cause of Nearby Industrial, Man-made, or Other Fire/Explosion Significant include any of the following, but Fire First excluded: 1. Fatality or injury requiring in-patient hospitalization 2. $50,000 or more in total costs, measured in 1984 dollars 3. Highly volatile liquid (HVL) releases of 5 barrels or more 4. Non-HVL liquid releases of 50 barrels or more 5. Liquid releases resulting in an unintentional fire or explosion

16 data as-of 2/6/2017 All System Types Serious Incidents Hazardous Liquid and Carbon Dioxide

17 data as-of 2/6/2017 All System Types Significant Incidents Hazardous Liquid and Carbon Dioxide

18 Hazardous Liquid and Carbon Dioxide Significant Incidents CY 2016 Leading Causes: Material/Weld/Equipment Failure Corrosion Other data as-of 2/6/2017

19 Cited Regulation Types (2016) 19

20 Most Cited Regulations Hazardous Liquids ( ) * Excluded withdrawn violations

21 Most Cited Corrosion Regulations - Hazardous Liquids ( ) Violation Most Cited Section Regulation (195) (HL Corrosion Control: ) $0 $100,000 $200,000 $300,000 $400,000 $500, Cathodic Protection Cathodic Protection Adequacy [ ] Adequacy [ ] $265, Corrosion Corrosion Control Control Record Record Retention Retention Period Period [ (c)] [ (c)] $81, Timely Correction Timely of Correction Corrosion of Control Corrosion Deficiencies Control Deficiencies [ (e)] [ (e)] $349, Atmospheric Atmospheric Corrosion Corrosion Control Control Inspection Inspection Frequency Frequency [ (a)] [ (a)] $147, Rectifiers and and other other devices devices performance check check [ (c)] $49, Examine Exposed Portions of Buried Pipe Examine Exposed Portions of Buried Pipe [ ] [ ] $44, External External Corrosion Corrosion Control Control Testing Testing Frequency Frequency [ (a)(1)] $253, Take adequate steps to mitigate internal corrosion [ (a)] $145, Cathodic Protection Inspection on on Breakout tanks [ (d)] $114,900 9 Clean and coat pipeline exposed to the atmosphere [ (a)] $431, Alleviate Alleviate Interference Interference Currents Currents [ (a)] [ (a)] $186,800 * Excluded withdrawn violations

22 Inspection Policies and Procedures

23 The Heterogeneous Regulatory Environment we are in. Hundreds of pipeline operators; thousands of systems Sizes range from mega-corporations to mom and pop Multiple product mixes. Varying pipeline ages and materials Pipelines traverse long distances with different operating environments (geography, soil, weather, etc.) Pipelines can be impacted by outsiders (public, excavators, farmers, etc.) Pipelines criss-cross the country, involving every state.

24 Data Management Policy Forms and instructions are publicly-available at: Operator information, reports, notifications, etc

25 Inspection Scheduling Policy Risk Ranking Index Model (RRIM) calculates a risk score for each Unit in an Inspection System. The average risk score for all Units is the Inspection System (IS) risk score

26 Inspection Scheduling Policy Factors include: Pipeline mileage Accidents Type of pipe Bare or poorly coated pipe Enforcement history HCA data Previous inspection How long since, Findings.

27 Integrated Inspection Strategy for performing risk-informed regulatory inspections that determines the inspection scope and allocates inspection resources based on pipeline risks. Allows for the combination of previous discrete inspections types, e.g. OQ, CRM, Standard, to be combined into one unified inspection. 27

28 Integrated Inspection The II process utilizes the Inspection Assistant to leverage prior inspection knowledge, concerns and coverage while allowing flexibility in determining the scope of the inspection while still ensuring that the core, high risk elements are always addressed.

29 Integrated Inspection II provides for a formalized process to gather both historical information regarding the operator, the pipeline system attributes, and previous enforcement using PHMSA s existing databases like the Pipeline Data Mart, NPMS, and SMART, as well as real time data and by using a screening process it allows for identification of risk drivers that may have occurred recently.

30 Refocus Inspection Priorities Based on Lessons Learned Focus on Change (Data is quickly dated) - New operator or new employees - Change in operating conditions flow reversal. - Change in assets, e.g. pump stations, commodities. - Change in environmental condition ground movement, flooding, nearby construction - Spend more time validating the accuracy of the ILIs push for more varied anomaly digs 30

31 Rulemaking

32 Congressional Mandates and Recommendations Reauthorizations Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 NTSB Safety Recommendations 37 Open Acceptable Action 1 Open Unacceptable Action (require all personnel involved in integrity management programs to meet minimum professional qualification criteria) - request to change to Open Acceptable Response Advisory Bulletin General Accountability Office (GAO) Audits being addressed in HL and GT NPRMs GAO Larger, high pressure gathering lines GAO Guidance on Risk Based Reassessment Intervals GAO Data and Guidance on Incident Response GAO Data Collection Gathering Pipelines Office of Inspector General (OIG) Report (AV ) #5 Update Integrity Management requirements for non-linear assets- R&D in progress #8 Create database of physical characteristics, accidents and inspections - NPMS Information Collection expansion with OMB 32

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35 Legislation Changes since Pipeline Safety, Regulatory Certainty and Job Creation Act Grandfather clause, Integrity Management Expansion, Leak Detection, Dilbit Study 2016 PIPES Act Emergency Orders, Integrity Assessments (certain pipelines), Great Lakes as HCA, LNG, Storage -

36 Reauthorization: Protection Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 Signed June 22, 2016; reauthorizes OPS through FY 2019; Aggressive timetable Contains 19 mandates for OPS consisting of regulations, studies, and other actions including: Convene a working group to consider development of information sharing system Make public the status of our final rules that meet specific criteria Issue or update regulations for Underground Storage, LNG, Safety Data Sheets, Hazardous Materials Identification Numbers, Unusually Sensitive Areas Conduct post-inspection briefing with the operator Review staff resource management Report on lost and unaccounted for gas Permits OPS to issue emergency order without prior notice for unsafe condition and to withhold payments to underperforming States Studies and Reports on Inspection Report Information, Damage Prevention Tech, Pipeline Safety Regulatory Databases, Propane Gas, and Natural Gas Leak Reporting Instructs audits of integrity management, workforce management, pipeline safety technical assistance grants, corrosion, research and development, and odorization 36

37 Changes since 2010 Non Regulatory Actions Advisory Bulletins Lessons learned from Marshall, MI Spill Response Plans Public Workshops Pipeline Risk Management/Risk Modeling Pipeline Seam Valves and Leak Detection Spill Drill Engagement Focus

38 Rulemaking Docket Safety of On-Shore Hazardous Liquid Pipelines (Final) Set to publish and then pulled back as new administration took office Safety of Gas Transmission and Gathering Pipelines (Final) Proposed rule being reviewed with GPAC Plastic Pipe (NPRM) Rupture Detection and Valves (Pre- NPRM)

39 Proposed - Pipeline Rupture Detection and Mitigation Rule Establish and define rupture detection and response time metrics including the integration of Automatic Shutoff Valves (ASV) and Remote Control Valve (RCV) placement, with the objective of improving overall incident response Rule responds to requirements of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (The Act): Section 4: ASV/RCV or equivalent technology be installed on newly constructed or entirely replaced natural gas and hazardous liquid transmission pipelines 2 years after the act was issued Section 8: Require operators of hazardous liquid pipeline facilities to use leak detection systems and establish standards for their use. The Act also mandated two studies of leak detection and response, one by the GAO, and one by PHMSA. Also - Two NTSB Recommendations related to valves and leak detection

40 Future Rulemakings Underway The timeline for all future rulemaking is pending Departmental determinations on implementing and maintaining compliance with the applicable Executive Orders and Memorandums

41 Hazardous Liquid IM Rule Set to publish and then pulled back as new administration took office Publish by the end of 2017?

42 Hazardous Liquid IM Rule

43 Brief History on HL Rule Incident near Marshall, MI, on July 25, 2010, spills over 1,000,000 gallons of crude oil into the Kalamazoo River. Hazardous Liquid (HL) ANPRM issued on October 18, Congress issues Pipeline Safety Act of 2011 on January 3, Shortly after, NTSB issues Marshall, MI, investigation report and recommendations for revising the HL regulations. GAO also issues a recommendation. NPRM published October 13, 2015; approx. 70 comments received. Liquid Pipeline Advisory Committee (LPAC) on February 1, 2016; found rule to be technically feasible, reasonable, cost-effective, & practicable with minor edits. Rule addresses mandates/recommendations, closes some safety gaps, ensure operators are detecting and remediating unsafe 43 conditions, and put resources in areas for most impact. 43

44 Mandates and Recommendations Addressed or Completed in the Rule Pipeline Safety Act of 2011: 5(f) Expand Integrity Management (IM) or IM principles to non-hcas 8 Leak Detection 12 Oil Flow Lines, data collection 14 Biofuels 21 Hazardous Liquid (HL) Gathering Lines 29 Seismicity PIPES 2016 Act: 14 Safety Data Sheets 25 IM Requirements for HL Pipeline Facilities located in Inland Waters 44 44

45 Mandates and Recommendations Addressed or Completed in the Rule NTSB Recommendations: P Crack Assessments P Discovery of Condition P Improve Data Integration GAO Recommendations: GAO Reporting of unregulated gathering lines GAO Collecting data on unregulated gathering lines 45 45

46 Summary of Final Rule With this final rule, PHMSA is revising Part 195: 1. Establishing reporting requirements for gravity pipelines 2. Extending reporting requirements to gathering lines (annual, safety related condition report (SRCR), incident) 3. Requiring inspections of pipelines affected by extreme weather and disasters 4. Requiring periodic assessment of onshore, piggable transmission pipelines that are not covered by present Integrity Management (IM) requirements (Non-High Consequence Areas (HCAs)) Modifying the IM repair criteria including extending repair timing 46

47 Summary of Final Rule With this final rule, PHMSA is revising Part 195: 6. Requiring leak detection systems on all new and existing non-hca hazardous liquid transmission pipelines 7. Requiring use of ILI tools for all HCAs within 20 years 8. Clarifying other IM requirements, including: Requiring integration of pipeline information Periodic verification of the identification of HCA segments 9. Requiring operators provide material safety data sheets (MSDS) to first responders within 6 hours of reporting a spill 10. Requiring operators conduct ILI and other surveys of certain onshore underwater pipelines every 12 months 47 47

48 Gravity Pipelines ( ) ISSUE: Gravity lines are exempted under current code. PHMSA cannot gather any data concerning their safety. PHMSA believes these lines pose same safety risk as low-stress lines currently covered under the code. BASIS: Other pipelines that operate at low pressure and for short distances such as gravity-fed lines are subject to Federal regulation. PHMSA needs data to determine whether gravity lines need to be similarly regulated. SOLUTION: PHMSA will collect: OpID Registry information Annual reporting information (1 year after effective date) Accident reporting information (6 months after effective date) Safety-related condition reporting (6 months after effective date) 48

49 Gathering Lines ( ) ISSUE: Most rural gathering lines currently exempted from any code requirements. Only rural lines that are 6-8 in dia, >20% SMYS, located within ¼ mile of Unusually Sensitive Areas are regulated. BASIS: Congress (Sec 21 of 2011 Act) and NTSB have had questions about the safety of hazardous liquid gathering lines. SOLUTION: PHMSA will collect: OpID Registry information Annual reporting information (1 year after effective date) Accident reporting information (6 months after effective date) Safety-related condition reporting (6 months after effective date) 49

50 Inspections Following Extreme Weather Events or Disasters ( ) ISSUE: There are no current requirements for post-event inspections of pipelines after natural disasters or other extreme weather events. BASIS: Timely inspection will ensure detection and remediation of any unsafe conditions created by unusual events. SOLUTION: PHMSA is requiring: Operators perform an initial inspection of facilities for conditions that could adversely affect the safe operation of those facilities following an event carrying the likelihood of damage to infrastructure. The initial inspection must commence within 72 hours after the cessation of the event, defined as the point when personnel and equipment are available and can safely access the area. Operators must take remedial actions to ensure the safe operation of the pipeline following these events. 50

51 Periodic Assessment of Pipelines ( ) ISSUE: Lines outside HCAs do not currently have a regulatory requirement for assessment. BASIS: Such a requirement would ensure operators obtain information necessary for prompt detection and remediation of corrosion and other deformation anomalies in all locations, not just in HCAs. SOLUTION: Consistent with the requirements of IM for HCAs, onshore, piggable transmission lines in non-hcas will be assessed at least once every 10 years. 51

52 Modifying Repair Criteria ( ) ISSUE: Current repair criteria does not reflect proper prioritizing of abnormal pipeline conditions found in the field. BASIS: Inspection experience identified weaknesses in repair decisions in response to ILI data. SOLUTION: In HCAs, PHMSA will: Modify the repair criteria to include additional anomalies under immediate repair condition. Modify the repair schedule to allow operators more time to address lessinjurious conditions and focus resources on immediate conditions (eliminate 60-day & 180-day categories and establish a 9-month category). Require operators explicitly consider tool tolerance for repair decisions. Collect ILI data from HCAs and non-hca segments for repair decisions. 52

53 Expanding Use of Leak Detection Systems ( / ) ISSUE: Operators are currently required to have a leak detection system, but the requirements are not clear. This proposal restructures the existing requirement to ensure that all pipelines are designed to include a leak detection system and operate and maintain per specified standards. BASIS: Recent pipeline incidents, such as those in Marshall, Michigan, and Salt Lake City, Utah, suggest an adequate means for identifying leaks is of high importance. SOLUTION: All existing non-hca hazardous liquid transmission pipelines will have a leak detection system within 5 years after the rule s effective date. All new non-hca hazardous liquid transmission pipelines will have a leak detection system within 1 year after the rule s effective date. 53

54 Using ILI Tools in All HCAs ( ) ISSUE: Not all pipelines in HCAs can accommodate passage of ILI tools, and there is no regulatory requirement for them to do so. BASIS: Increased use of ILI methods ( pigging ) will further promote public and environmental safety in these high risk areas (HCAs). NTSB highly supportive of making lines piggable; specific recommendations made on GT lines. SOLUTION: PHMSA will require all HCA pipelines to be capable of accommodating ILI tools within 20 years. Commensurate with statutory language, operators with lines where the basic construction cannot be modified to accommodate ILI tools can request a waiver. 54

55 Clarification of Other Requirements ( ) ISSUE: Operators currently are not fully integrating pipeline data across all data sources. Additionally, periodic verification of HCAs is lacking among some operators. SOLUTION: PHMSA is revising the IM requirements to: Specify additional pipeline attributes for operators to analyze when evaluating the integrity of pipelines in HCAs (including seismicity; Sec PSA). (Begins on publication date with full implementation 3 years after publication date) Continued next slide 55

56 Clarification of Other Requirements ( ) Integrate all sources of information, including spatial relationships, when determining pipeline integrity. (Begins on publication date with full implementation 3 years after publication date) Require operators to have a written IM plan prior to operation. Require annual HCA segment identification/verification. Clarify the applicability of IM to pipeline facilities, not just line pipe. 56

57 Safety Data Sheets ( ) ISSUE: Material Safety Data Sheets are documents that give detailed information about the nature of chemicals, such as their potential properties and hazards. They are designed for workers who may be exposed to hazardous materials. BASIS: Self-executing congressional mandate from PIPES 2016 Act, Section 14. SOLUTION: Following a spill, operators must provide safety data sheets on any spilled hazardous liquid to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of reporting the accident

58 IM Assessments for Certain Underwater Hazardous Liquid Pipeline Facilities in HCAs ( ) ISSUE: Following the Marshall, MI, incident, lawmakers became increasingly concerned with pipelines operating within the Great Lakes. BASIS: Self-executing congressional mandate from PIPES 2016 Act, Section 25. SOLUTION 58 58

59 IM Assessments for Certain Underwater Hazardous Liquid Pipeline Facilities in HCAs ( ) 59 SOLUTION: Applies to onshore underwater hazardous liquid pipeline facilities located in an HCA where any portion of which is located at depths greater than 150 feet under the surface of the water. Operators must assess lines using ILI appropriate for the integrity threats to the pipeline at least once every 12 months, and; Complete other integrity assessments on a schedule based on the risk that the pipeline facility poses to the HCA in which the pipeline facility is located. 59

60 Recently Published Rules Excavation Enforcement (7/15/2015) Inflation Adjustment of Maximum Civil Penalties Final Rule (06/30/2016) Safety of Underground Natural Gas Storage Facilities IFR (12/19/2016) Operator Qualification, Cost Recovery, Accident and Incident Notification, and Other Pipeline Safety Changes (1/23/2017)

61 Excavation Enforcement Criteria and procedures to determine the adequacy of State pipeline excavation damage prevention law enforcement programs. The Federal requirements PHMSA will enforce in States with inadequate excavation damage prevention law enforcement programs. The adjudication process for administrative enforcement proceedings against excavators where Federal authority is exercised.

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63 Inflation Adjustment of Maximum Civil Penalties Final Rule On April 27, PHMSA published in the Federal Register a Final Rule revising references in its regulations to the maximum civil penalties for violations of Federal pipeline safety laws, or any PHMSA regulations or orders issued thereunder. Under the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015, Federal agencies are required to adjust their civil monetary penalties effective January 15, 2017, and annually thereafter, to account for changes in inflation.

64 Inflation Adjustment of Maximum Civil Penalties Final Rule PHMSA originally published an Interim Final Rule on June 30, 2016, (81 FR 42564). The interim final rule stated that PHMSA is revising references in its regulations to the maximum civil penalties for violations of Federal pipeline safety laws, or any PHMSA regulations or orders issued thereunder, in accordance with OMB guidance Implementation of the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015, M (OMB Memorandum M-16-06).

65 Inflation Adjustment of Maximum Civil Penalties (effective 04/27/2017)

66 Underground Storage Facilities for Natural Gas (Interim Final Rule) Rule requires operators of underground storage facilities for natural gas to comply with minimum safety standards, including compliance with: o API RP 1171, Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs o API RP 1170, Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage o Annual and Incident reporting requirements ~400 interstate and intrastate US underground natural gas storage facilities are operating with more than four trillion cubic feet of natural gas working capacity

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68 Operator Qualification, Cost Recovery and Other Pipeline Safety Proposed Changes NPRM published 7/10/15; comment period ended 9/8/2015 This rule will address reauthorization issues related to: Operator Qualification for new construction CRM Incident Reporting Cost Recovery for some new construction inspections Farm Taps Assessment methods for HL lines Renewal process for special permits API 1104 and in-service welding PAC meeting June 1-3, 2016 Published January 23, 2017 Effective 60 days to April 4 th

69 PHMSA Safety Advisory Bulletins (to date)

70 Advisory Bulletins Potential for Damage Caused by Severe Flooding (01/19/2016) Underground Storage Facilities for Natural Gas (02/5/2016) Dangers of Abnormal Snow and Ice Build-up on Gas Distribution Systems. (02/11/2016) Corrosion Protection Under Insulation (06/21/2016)

71 Advisory Bulletins Clarification of Terms Relating to Pipeline Operational Status (08/16/2016) Safeguarding and Securing Pipelines from Unauthorized Access (12/09/2016) HCA Identification Methods for GT Pipelines (12/13/2016) Deactivation of Threats in IMP (3/16/2017) Guidance on Training and Qualifications for IMP (4/10/2017)

72 ADB Potential for Damage to Pipeline Facilities Caused by Severe Flooding. Similar to ADB as these events continue to occur titled Potential for Damage to Pipeline Facilities Caused by Flooding, River Scour, and River Channel Migration Several ADBs on this topic, and please review them all if applicable to your operations

73 ADB Events referenced include: July 1, 2011, ExxonMobil Pipeline Company experienced a pipeline failure near Laurel, Montana 63,000 gallons of crude oil spilled into the Yellowstone River July 15, 2011, NuStar Pipeline Operating Partnership, L.P. reported a 4,200 gallon (100 barrels) anhydrous ammonia spill in the Missouri River in Nebraska August 13, 2011, Enterprise Products Operating, LLC discovered a release of 28,350 gallons (675 barrels) of natural gasoline in the Missouri River in Iowa January 17, 2015, a breach in the Bridger Pipeline Company s Poplar System resulted in another spill into the Yellowstone River near the town of Glendive, Montana, releasing an estimated 28,434 gallons of crude oil into the river and impacting local water supplies

74 ADB ADB reiterates those actions that an operator should take prior to, during, and following abnormal events. As shown in these events, river bottom scour and channel migration may occur due to seasonal flooding, increased stream velocities, and manmade and natural river bank restrictions. Additionally, the safety of valves, regulators, relief sets, pressure sensors, and other facilities normally above ground or above water can be jeopardized when covered by water

75 ADB To Owners and Operators of Underground Pipeline and Storage Facilities regarding the Safe Operation of Underground Storage Facilities for Natural Gas Operators of underground storage facilities used for the storage of natural gas, as defined in 49 CFR Part 192, should review their O,M & ER activities to ensure the integrity of underground storage facilities are properly maintained

76 ADB In addition, operator s O&M processes and procedures should be reviewed and updated at least annually, unless operational inspections for integrity warrant shorter review periods. O&M processes and procedures should include data collection and integration, risk assessments, monitoring, operational limits, mitigation measures, and record keeping for any underground storage facility threat that could impact public safety, operating personnel, or the environment due to leakage, failure, or abnormal operating conditions whether above ground or underground.

77 ADB Subject: Owners and Operators of Petroleum Gas and Natural Gas Facilities in Areas Subject to Heavy Snowfall or Abnormally Icy Weather. Dangers of Abnormal Snow and Ice Build-up on Gas Distribution Systems.

78 ADB Subject - Ineffective Protection, Detection, and Mitigation of Corrosion Resulting From Insulated Coatings on Buried Pipelines PHMSA failure investigation of the Plains Pipeline May 19, 2015, accident in Santa Barbara, CA Operators are reminded to review their pipeline operations to ensure that pipeline segments that are both buried and insulated have effective coating and corrosion-control systems to protect against cathodic protection shielding, conduct in-line inspections for all threats, and ensure in-line inspection tool findings are accurate, verified, and conducted for all pipeline threats.

79 ADB The need for coatings and CP systems to be designed, installed, and maintained so as not to foster an environment of shielding and moisture that can lead to excessive external corrosion growth rates and pipe steel cracking such as stress corrosion cracking Coatings for buried, insulated pipelines that may result in cathodic protection shielding yet still comply with 49 CFR Part 192, Subpart I or 49 CFR Part 195, Subpart H. Inadequate corrosion prevention may be addressed through any one or more methods, or a combination of methods described in ADB

80 ADB Employ ILI data analysis techniques to account for the potential growth of Corrosion Under Insulation, including interaction criteria for anomaly assessment ILI data, subsequent analysis of the data, and pipeline excavations should: Confirm the accuracy of the ILI data to characterize the extent and depth of the external corrosion and ILI tolerances and unity charts Follow the ILI guidelines of API Standard 1163 Use additional or more frequent reassessment intervals and confirmations Assess and mitigate operational and environmental conditions in shielded and insulated coatings that lead to excessive corrosion growth rates, pipe steel cracking, and all other threats.

81 ADB Subject: Clarification of Terms Relating to Pipeline Operational Status PHMSA regulations do not recognize an idle status for a hazardous liquid or gas pipelines. The regulations consider pipelines to be either active and fully subject to all parts of the safety regulations or abandoned.

82 ADB The process and requirements for pipeline abandonment are captured in and (c)(10) for gas and hazardous liquid pipelines, respectively. Pipelines abandoned after the effective date of the regulations must comply with requirements to purge all combustibles and seal any facilities left in place. The last owner or operator of abandoned offshore facilities and abandoned onshore facilities that cross over, under, or through commercially navigable waterways must file a report with PHMSA. PHMSA regulations define the term abandoned to mean permanently removed from service.

83 ADB PHMSA issued this ADB in coordination with TSA to remind all pipeline owners and operators of the importance of safeguarding and securing their pipeline facilities and monitoring their SCADA systems for abnormal operations and/or indications of unauthorized access or interference with safe pipeline operations. Additionally, this Advisory Bulletin is to remind the public of the dangers associated with tampering with pipeline system facilities.

84 ADB Subject: Safeguarding and Securing Pipelines from Unauthorized Access Pipeline Safety and Security If you see something, Say something Relationships with Law Enforcement Increased Security and Patrols Protection of Facilities SCADA System Monitoring Incident And Accident Reporting

85 ADB Subject: High Consequence Area Identification Methods Inform owners and operators of gas transmission pipelines that PHMSA has developed guidance on the identification and periodic verification of HCAs, including the application of a buffer zone to the PIR, and information regarding the accuracy of class locations This advisory bulletin addresses NTSB Recommendation P-15-06

86 ADB PHMSA recommends operators frequently and consistently review their data including class location data for potential inaccuracies or limitations, and add a buffer zone to the calculated PIR to help ensure proper HCA identification. The purpose and usage of buildings, open structures, and outside areas can shift over time, changing the number of identified sites in a PIR, and therefore, whether an area is an HCA. PHMSA believes that if operators review class location and PIR data on an annual basis as a part of their IM programs, the accuracy of HCA determinations will be greatly improved.

87 Advisory Bulletin on Deactivation of Threats in IMP ADB to inform owners and operators of gas transmission pipelines that PHMSA has developed guidance on threat identification and establishment of minimum criteria for deactivation of threats. Provides guidance regarding documenting their rationale of analyses, justifications, determinations, and decisions related to threat deactivation. This Advisory Bulletin satisfies NTSB Rec. P-15-9.

88 ADB Deactivation of Threats The threats identified in ASME B31.8S 2004 may be considered active or inactive, but are never permanently eliminated ASME B31.8S 2004, Appendix A, identifies the information an operator must collect and analyze for threats, which must demonstrate an individual threat is not acting on the pipe before an operator can properly declare the threat inactive for each assessment period.

89 ADB Deactivation of Threats Time-Dependent Threats - External Corrosion, Internal Corrosion, Stress Corrosion Cracking Static or Stable Threats Manufacturing, Construction, Equipment Time Independent Threats - Third-Party Damage, Incorrect Operations, Weather- Related and Outside Forces Cyclic Fatigue

90 ADB Guidance on Training and Qualifications for IM Programs PHMSA published the gas transmission pipeline integrity management (IM) rule on 12/15/2003 Established requirements for supervisory and other personnel with IM program functions in PHMSA recognized inconsistencies in how the requirements of have been implemented by operators and issued ADB to remind operators of their responsibility to include the training and qualification requirements for IM personnel as required by and ASME B31.8S. This Advisory Bulletin satisfies NTSB Rec. P

91 Miscellaneous

92 VISS (ILI Data Sharing) Committee PHMSA s Voluntary Information-sharing System (VIS) Working Group is mandated by law, section 10 of the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of Provide recommendations on the development of a voluntary information-sharing system to encourage collaborative efforts to improve inspection information feedback and information sharing with the purpose of improving gas transmission and hazardous liquid pipeline facility integrity risk analysis.

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94 VISS Team Next Meeting Administrative Meeting held April 18 th Face to Face meeting in DC June 8-9 th Provide information to Committee on processes and data utilized in ILI Identify sub-committees that could support missions Look to expand pipeline technical expertise on committee

95 Risk Modeling Work Group The PHMSA Pipeline Risk Modeling Work Group was formed as a follow up to the September 2015 Pipeline Risk Modeling Methodologies Public Workshop. The purpose of the group is to provide technical, integrity management and operational input to PHMSA to aid in the development of a pipeline system risk modeling technical guidance document.

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97 BSEE draft PRA Guide document BSEE has posted their draft Probablistic Risk Assessment Guide document on their website

98 RMWG Path Forward Continue with development of Guidance Document Hold a couple of more meetings - Relative risk models and summary/conclusory meeting Public Meeting to discuss document

99 PHMSA Website Locations for Regulatory Status Interpretations (Search by date or regulation) Special Permits and State Waivers Rulemakings (tabular with links to detail) Advisory Bulletins (tabular with links to detail) The Significant Rulemakings Report.

100 Additional PHMSA Website Locations Pipeline Technical Resources Meetings Electronic Reading Room Stakeholder Communications PSA 2011 Reports and Studies

101 101 Additional PHMSA Websites Pipeline Technical Resources Alternative MAOP Cased Crossings & Guided Wave Ultrasonics (GWUT) Class Location Special Permits Control Room Management (CRM) Gas Distribution Integrity Management Program (DIMP) Gas Transmission Integrity Management (GT IM) Hazardous Liquid Integrity Management (HL IM) High Volume Excess Flow Valves (EFV) Low Strength Pipe Operator Qualification (OQ) Pipeline Construction Research & Development (R&D) Public Meetings Regulations & Interpretations

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103 Louisiana PERI Kickoff Meeting Thursday, August 31, 2017 Louisiana State Police Training Academy Auditorium 8181 Independence Blvd. Baton Rouge, Louisiana 70806

104 Thank you. William (Bill) Lowry, PE Community Liaison