U.S. DOT Pipeline and Hazardous Materials

Safety Administration

William (Bill) Lowry, PE Community Liaison

Community Assistance & Technical Services (CATS)

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

Name Change

Effective: January 1, 2017

Office of Pipeline Safety Community Liaisons

Community Liaison Services Program

Manager Karen Lynch

Eastern Region

Southern Region

Karen Gentile

Ian Woods

Arthur Buff

James Kelly

Central Region

Angela Pickett

Sean Quinlan

Western Region

Dave Mulligan

Tom Finch

Southwest Region

Bill Lowry

Jay Prothro

For more information: http://primis.phmsa.dot.gov/comm/CATS.htm

Today’s Agenda

• PHMSA Update

• Inspection Policies and Procedures

• PHMSA Rulemaking

• PHMSA Advisory Bulletins

PHMSA Update

PHMSA Organization Chart

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Rosanne Goodwill

Alan Mayberry

Bill Schoonover

Howard (Mac) McMillan

Everett Lott

Tami Perriello

Kim Curry

PHMSA’s FY2015 IT Portfolio

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PHMSA Regional Offices

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

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

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…..

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

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: – https://www.youtube.com/playlis

t?list=PL4wHDsuQ-uKm7Mz20uvkeagVu2u_Cro6o

– Public Workshop Feb 2014 – Search PHMSA + SMS

Copyright 2012 – E.I DuPont

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1986 1990 1994 1998 2002 2006 2010 2014

Index (1988 = 1)

Calendar Year

Pipeline Safety with Context Measures (1988-2015)

Natural Gas Consumption

Petroleum ProductConsumption

Pipeline Mileage

U.S. Population (Millions)

Major Hazardous LiquidSpills

Incidents with Death orInjury

Categories of Incident Reports

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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

Serious Incidents

All System Types Hazardous Liquid and Carbon Dioxide

data as-of 2/6/2017

Significant Incidents All System Types

Hazardous Liquid and Carbon Dioxide

data as-of 2/6/2017

Hazardous Liquid and Carbon Dioxide Significant Incidents

CY 2016 Leading Causes: Material/Weld/Equipment Failure Corrosion Other

data as-of 2/6/2017

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Cited Regulation Types (2016)

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* Excluded withdrawn violations

Most Cited Regulations – Hazardous Liquids (2010 - 2016)

Most Cited Corrosion Regulations - Hazardous Liquids (2010 – 2016)

* Excluded withdrawn violations

$265,500

$81,700

$349,800

$147,400

$49,600

$44,700

$253,400

$145,000

$114,900

$431,700

$186,800

$0 $100,000 $200,000 $300,000 $400,000 $500,000

Cathodic Protection Adequacy [195.571]

Corrosion Control Record Retention Period[195.589(c)]

Timely Correction of Corrosion ControlDeficiencies [195.573(e)]

Atmospheric Corrosion Control InspectionFrequency [195.583(a)]

Rectifiers and other devices performance check[195.573(c)]

Examine Exposed Portions of Buried Pipe[195.569]

External Corrosion Control Testing Frequency[195.573(a)(1)]

Take adequate steps to mitigate internal corrosion[195.579(a)]

Cathodic Protection Inspection on Breakout tanks[195.573(d)]

Clean and coat pipeline exposed to the atmosphere[195.581(a)]

Alleviate Interference Currents [195.577(a)]

Violation Section (195)

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13

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05101520253035

Cathodic Protection Adequacy [195.571]

Corrosion Control Record Retention Period[195.589(c)]

Timely Correction of Corrosion Control Deficiencies[195.573(e)]

Atmospheric Corrosion Control InspectionFrequency [195.583(a)]

Rectifiers and other devices performance check[195.573(c)]

Examine Exposed Portions of Buried Pipe [195.569]

External Corrosion Control Testing Frequency[195.573(a)(1)]

Take adequate steps to mitigate internal corrosion[195.579(a)]

Cathodic Protection Inspection on Breakout tanks[195.573(d)]

Clean and coat pipeline exposed to the atmosphere[195.581(a)]

Alleviate Interference Currents [195.577(a)]

Most Cited Regulation (HL Corrosion Control: 2010 - 2016)

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Inspection Policies and Procedures

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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.

Data Management Policy Forms and instructions are publicly-available at: http://www.phmsa.dot.gov/pipeline/library/forms Operator information, reports, notifications, etc

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.

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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.

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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.

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.

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.

Integrated Inspection

Refocus Inspection Priorities Based on Lessons Learned

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• 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

Rulemaking

Congressional Mandates and Recommendations

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• 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-14-667 Larger, high pressure gathering lines • GAO-13-577 Guidance on Risk Based Reassessment Intervals • GAO -13 -168 Data and Guidance on Incident Response • GAO-12-388 Data Collection Gathering Pipelines

• Office of Inspector General (OIG) Report (AV-2012-140) • #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

https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-15-014

https://www.ntsb.gov/_layouts/ntsb.recsearch/Recommendation.aspx?Rec=P-15-014

Changes since 2010 • Legislation

– 2011 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 - 35

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• 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

Reauthorization: Protection Our Infrastructure of Pipelines and Enhancing Safety Act of 2016

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 - 37

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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)

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

Future Rulemakings Underway

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The timeline for all future rulemaking is pending

Departmental determinations on implementing and maintaining compliance with the applicable

Executive Orders and Memorandums.

Hazardous Liquid IM Rule

• Set to publish and then pulled back as new

administration took office

• Publish by the end of 2017?

Hazardous Liquid IM Rule

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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, 2010. • Congress issues Pipeline Safety Act of 2011 on January 3, 2012. • 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 conditions, and put resources in areas for most impact.

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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

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Mandates and Recommendations Addressed or Completed in the Rule

• NTSB Recommendations: – P-12-03 – Crack Assessments

– P-12-04 – Discovery of Condition

– P-15-22 - Improve Data Integration

• GAO Recommendations: – GAO-12-388 – Reporting of unregulated gathering lines

– GAO-14-667 – Collecting data on unregulated gathering lines

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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))

5. Modifying the IM repair criteria including extending repair timing

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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

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Gravity Pipelines (§ 195.13)

• 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)

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Gathering Lines (§ 195.15)

• 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)

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Inspections Following Extreme Weather Events

or Disasters (§ 195.414)

• 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.

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Periodic Assessment of Pipelines (§195.416)

• 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.

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Modifying Repair Criteria (§ 195.452)

• 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 less-injurious 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.

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Expanding Use of Leak Detection Systems (§§ 195.134 / 195.444)

• 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.

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Using ILI Tools in All HCAs (§ 195.452)

• 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.

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Clarification of Other Requirements (§ 195.452)

• 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. 29 2011 PSA). (Begins on publication date with full implementation 3 years after publication date)

– Continued next slide…

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Clarification of Other Requirements (§ 195.452)

• 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.

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Safety Data Sheets (§ 195.65)

• 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.

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IM Assessments for Certain Underwater Hazardous Liquid Pipeline Facilities in HCAs

(§ 195.454)

• 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…

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IM Assessments for Certain Underwater Hazardous Liquid Pipeline Facilities in HCAs

(§ 195.454)

• 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.

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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)

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.

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.

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-16-06 (OMB Memorandum M-16-06).

Inflation Adjustment of Maximum

Civil Penalties (effective 04/27/2017)

(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

Underground Storage Facilities for Natural Gas

https://primis.phmsa.dot.gov/ung/index.htm

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 4th

PHMSA Safety Advisory Bulletins 2016 – 2017 (to date)

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)

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)

ADB–2016–01

• Potential for Damage to Pipeline Facilities Caused by Severe Flooding.

• Similar to ADB-2015-01 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

ADB 2016-01 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

ADB 2016-01 • ADB 2016-01 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

ADB–2016–02 • 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

ADB–2016–02 • 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.

ADB–2016–03

• 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.

ADB–2016–04 • 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.

ADB–2016–04

• 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–2016–04

ADB–2016–04 • 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.

ADB-2016-05 • 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.

ADB-2016-05 • The process and requirements for pipeline abandonment

are captured in §§ 192.727 and 195.402(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.

ADB–2016–06

• 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.

ADB–2016–06 • 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

ADB-2016-07 • 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

ADB-2016-07 • 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.

Advisory Bulletin 2017-01 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.

ADB-2017-01 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.

ADB-2017-01 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

ADB 2017-02 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 § 192.915.

• PHMSA recognized inconsistencies in how the requirements of § 192.915 have been implemented by operators and issued ADB 2017-02 to remind operators of their responsibility to include the training and qualification requirements for IM personnel as required by § 192.915 and ASME B31.8S.

• This Advisory Bulletin satisfies NTSB Rec. P-15-14.

Miscellaneous

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 2016.

• 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.

http://www.phmsa.dot.gov/pipeline/regs/technical-advisory-comm/voluntary-information-sharing-

system-working-group

VISS Team Next Meeting

• Administrative Meeting held April 18th • Face to Face meeting in DC June 8-9th • 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

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.

https://primis.phmsa.dot.gov/rmwg/index.htm

BSEE draft PRA Guide document

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

• https://www.bsee.gov/what-we-do/offshore-regulatory-programs/probabilistic-risk-assessment-analysis

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

PHMSA Website Locations for Regulatory Status Interpretations (Search by date or regulation)

http://www.phmsa.dot.gov/pipeline/regs/interps

Special Permits and State Waivers http://www.phmsa.dot.gov/pipeline/regs/special-permits

Rulemakings (tabular with links to detail)

http://www.phmsa.dot.gov/pipeline/regs/rulemaking

Advisory Bulletins (tabular with links to detail) http://www.phmsa.dot.gov/pipeline/regs/advisory-bulletin

https://www.transportation.gov/regulations/report-on-significant-rulemakings

The Significant Rulemakings Report

….

Additional PHMSA Website Locations

Pipeline Technical Resources https://primis.phmsa.dot.gov/ptr.htm

Meetings

http://primis.phmsa.dot.gov/meetings/

Electronic Reading Room http://www.phmsa.dot.gov/foia/e-reading-room

Stakeholder Communications

http://primis.phmsa.dot.gov/comm/

PSA 2011 Reports and Studies https://www.phmsa.dot.gov/pipeline/psa/related-reports-and-studies

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

101

https://primis.phmsa.dot.gov/ptr.htm

https://primis.phmsa.dot.gov/iim/index.htm

Louisiana PERI Kickoff Meeting

Thursday, August 31, 2017

Louisiana State Police Training Academy Auditorium

8181 Independence Blvd. Baton Rouge, Louisiana 70806

Thank you.

William (Bill) Lowry, PE Community Liaison bill.lowry@dot.gov

http://phmsa.dot.gov/pipeline