Gas Pipeline Safety

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Gas Pipeline Safety

• Ed Steele
• Chief, Gas Pipeline Safety Section
• Public Utilities Commission

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Gathering Lines
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Gathering Lines

• Final Rule Issued
• April 14, 2006
• Amendment 192-102
• Adopts a consensus standard (in part) to
  distinguish onshore gathering lines from other
  gas pipelines and production operations.
• Consensus Standard
• API Recommended Practice 80
• Guidelines for the Definition of Onshore Gas
  Gathering Lines

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API Recommended Practice 80

• Defines onshore gas gathering lines through a
  series of definitions, description and diagrams
  intended to represent the varied and complex
  nature of production and gathering in the U.S.

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Gathering Lines

• Regulation based on risk the line poses to the
  public
• Based on pressure and proximity to people
• Operator must use API RP 80 to determine if an
  onshore pipeline is an onshore gathering line
  subject to the following limitation

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Gathering Lines

• The beginning of gathering may not extend beyond
  the furthermost downstream point in a production
  operation
• Does not include equipment that can be used in
  either production or transportation (separators
  or dehydrators) unless that equipment is involved
  in the process of production and preparation for
  transportation or delivery of hydrocarbon gas

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Gathering Lines

• The endpoint of gathering may not extend beyond
  the first downstream natural gas processing plant
• If the endpoint of gathering is determined by
  commingling of gas from separate production
  fields, the fields may be no more than 50 miles
  apart
• The endpoint of gathering may not extend beyond
  the further most downstream compressor used to
  increase gathering line pressure for delivery to
  another pipeline

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API Recommended Practice 80

• Production Operation means piping and equipment
  used for production and preparation for
  transportation or delivery of hydrocarbon gas
  and/or liquids and includes the following
  processes
• (a) Extraction and recovery, lifting,
  stabilization, treatment, separation, production
  processing, storage, and measurement of
  hydrocarbon gas and/or liquids

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Gathering Lines

• Two types of gathering lines
• Type A
• Type B

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Jurisdictional Gathering Lines

• Type A
• Metallic and gt20 SMYS
• Nonmetallic and gt125 psig
• Class 2, 3 and 4 locations

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Jurisdictional Gathering Lines

• Type B
• Metallic and lt20 SMYS
• Class 3 and 4 locations
• Also in class 2 locations using 3 different
  methods
• Class 2 location
• Area extending 150 feet on each side of
  continuous 1 mile segment of pipeline including
  more than 10 or less than 46 dwellings
• Area extending 150 feet on each side of
  continuous 1000 feet of pipeline including 5 or
  more dwellings

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Jurisdictional Gathering Lines

• Type A
• All parts of code that apply to transmission
  lines
• Type B
• If line is new, replaced, relocated or changed,
  must be designed and tested in compliance with
  code
• Metallic line Corrosion control requirements
• Damage Prevention
• Public Education
• MAOP
• Line Markers

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Jurisdictional Gathering Lines

• All new lines must comply on the date line goes
  into service
• Existing line not previously subject to Part 192
• Corrosion Control April 15, 2007
• Damage Prevention Program October 15, 2007
• MAOP October 15, 2007
• Line Markers April 15, 2008
• All Other Type A Requirements April 15, 2007
• Class Location Changes or increase in dwelling
  density
• 1 year for Type B
• 2 year for Type A

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Gathering Seminar

• November 28, 2006
• Marietta, Ohio
• Dewitt Burdeaux
• Time and location to be determined

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Minimum Gas Service Standards
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Minimum Gas Service Standards

• Nothing has changed from the last rehearing on
  these rules
• OCC had filed for rehearing and the Commission
  stayed with the original entry
• The Commission waited until the rehearing
  timeframe had expired before moving forward

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Minimum Gas Service Standards

• PUCOs Legal Department has not sent the rules
  over to JCARR to date
• Working on finalizing forms
• Once the forms are finalized, the rules will be
  submitted to JCARR to go through their process

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JCARR
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JCARR

• Joint Committee on Agency Rule Review
• 119.032 of Ohio Revised Code
• Requires all state agencies to conduct a review
  (every 5 years) of their rules (OAC) and to
  determine whether
• Continue rules without change
• Amend their rules
• Rescind their rules

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JCARR

• Section 119.032(c), Revised Code requires
  Commission to determine
• The rules should be continued, be amended, or be
  rescinded, taking into consideration the purpose,
  the scope, and intent of the statute
• The rules need amendment or rescission to give
  more flexibility at the local level
• Rules need amendment or rescission to eliminate
  unnecessary paperwork

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JCARR

• Agency proposes changes to rules
• Submitted to JCARR. JCARR has jurisdiction over
  these rules for 65 days. In the last 30 days,
  JCARR has a meeting where rule is on the agenda.
  
• JCARR does not approve the rules, only recommend
  that they go forward or additional changes be
  made.
• Once JCARR loses its jurisdiction, there is a 10
  day waiting period. Then rules become effective.

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JCARR

• Formally, PUCO was allowed to incorporate by
  reference all federal pipeline safety regulations
  (Part 192).
• A few years ago, there were a few court decisions
  that limited the PUCOs ability to adopt these
  rules by incorporation.

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JCARR

• In addition, each time the Federal Regulations
  (Part 192) are changed
• PUCO must do a rulemaking to adopt those changes
  and go through the JCARR process
• PUCO plans on doing this on a semi-annual to
  annual basis
• Unless there is a major rulemaking that we need
  to adopt sooner

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Public Awareness

• API 1162

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Public Awareness

• Final Rule published May 19, 2005 (June 16, 2005)
• Incorporates by reference the guidelines of the
  American Petroleum Institute (API) Recommended
  Practice 1162 (RP 1162)
• Operators must develop and implement public
  awareness programs

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Public Awareness

• Pipeline Safety Improvement Act of 2002
• Requires operators to evaluate and, where needed,
  improve their pipeline safety awareness programs

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API 1162

• Industry consensus standard provides guidance and
  recommendations, including
• Intended audiences
• The kinds of information to be communicated
• Frequencies and methodologies for communicating
  the information
• Evaluation of the programs for effectiveness

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Public Awareness

• All pipeline system operators must follow the
  baseline, and where appropriate, the supplemental
  requirements of API 1162
• All operators had to comply with this by June 20,
  2006

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Public Awareness

• Under the regulations, operators of gas and
  hazardous liquid pipeline facilities must carry
  out continuing programs to educate the public on
   
• the use of a One-Call notification system prior
  to excavation, and other damage prevention
  activities
• the possible hazards associated with unintended
  releases from the pipeline facility
• the physical indications that such a release may
  have occurred
• what steps should be taken for public safety in
  the event of a pipeline release and
• how to report such an event.

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Public Awareness

• Operators must include in their programs
  activities to advise affected municipalities,
  school districts, businesses, and residents of
  pipeline locations. Of significance is the
  requirement that operators must review their
  programs for effectiveness and enhance the
  programs as necessary.

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Public Awareness

• On June 16, 2006, PHMSA issued an Advisory
  Bulletin to tell certain pipeline operators how
  to submit their written public awareness programs
  for review.
• The 2002 PSIA requires pipeline operators to
  submit these programs for review.
• PHMSA has implemented a Clearinghouse for
  reviewing operator submissions.

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Public Awareness OGA Plan

• Ohio Gas Association members
• Collaborative effort
• Hired Devaney and Associates
• Developed a plan for all Ohio Gas Association
  members
• Plan has been reviewed by members of the Pipeline
  and Hazardous Materials Safety Association (PHMSA)

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Public Awareness OGA Plan

• No issues were identified by PHMSA Central Region
• No issues have been identified by PUCO
• PUCO was involved in process from the beginning
• Thorough plan, collaborative effort, strong
  message
• OGA Collaborative Plan has been discussed across
  NAPSR and PHMSA as a model plan

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Public Awareness OGA Plan

• No other association has gone as far as Ohio Gas
  Association has with all aspects of Public
  Awareness
• As long as member companies customize template,
  they should be in compliance with requirement

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Public Awareness OGA Plan

• Ohio has agreed to participate in the PHMSA
  centralized review process
• Team made up of PHMSA staff, state pipeline
  safety programs, PHMSA contractor
• If deviations from baseline elements are found,
  the review team will refer the issues to state
  pipeline safety agency (PUCO)

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Public Awareness

• During the first half of the public awareness
  program submittal period, PHMSA received 276
  programs covering 375 operators. This represents
  about 14 of the operators expected to submit
  programs.

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Public Awareness Plan

• File your plan ASAP
• Deadline October 7
• No penalty for filing early

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Public Awareness

• All states are participating except for
• Connecticut
• DC
• Illinois
• Maryland
• Montana
• South Dakota
• Virginia
• Wyoming

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Statewide Riser Investigation

• 05-463-GA-COI

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Riser Investigation

• April 6, 2005 Riser case opened
• April 13, 2005 Entry issued and set up workshop
• May 12, 2005 Riser failure form issued
• June 29, 2005 Request for proposal issued
• August 3, 2005 Riser Removal protocol workshop
• September 8, 2005 Docketed Riser Removal
  Protocols
• October 14, 2005 Non-leaking risers removed from
  4 largest LDCs
• May 2006 Testing Completed
• June 2006 Lab Report Completed
• June 30, 2006 Consultant Report Completed

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Riser Investigation

• Commission hired
• University of Akrons Polymer Engineering
  Department as Commissions consultant
• Akron Rubber Development Laboratory (ARDL) as the
  Commissions testing laboratory

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Riser Investigation

• ARDL has completed their report and submitted it
  to Commission staff
• University of Akron has completed their report
  and submitted it to Commission staff
• Staff is finalizing report that will be docketed
  along with ARDL and University of Akrons reports

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Timeframe

• Final report is expected to be filed by end of
  October 2006
• Commission will consider staffs report and make
  final ruling on how we proceed

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Ohio Revised Code

• 4901.16. Penalty for divulging information.Except
  in his report to the public utilities commission
  or when called on to testify in any court or
  proceeding of the public utilities commission, no
  employee or agent referred to in section 4905.13
  of the Revised Code shall divulge any information
  acquired by him in respect to the transaction,
  property, or business of any public utility,
  while acting or claiming to act as such employee
  or agent. Whoever violates this section shall be
  disqualified from acting as agent, or acting in
  any other capacity under the appointment or
  employment of the commission.   

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Final Report

• Will be docketed
• Everyone on service list should be served by our
  docketing department
• I will notify Ohio Gas Association

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Updates to OQ
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OQ

• PHMSA is considering three changes to regulations
  
• Training
• Reevaluation intervals
• New construction

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OQ

• Training
• an OQ program would have to include training in
  particular circumstances. These circumstances
  are
• an individual has never performed an assigned
  covered task
• there has been substantial change to a covered
  task
• ensure training in damage prevention for
  individuals performing excavation for the
  operator

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OQ

• Reevaluation Intervals
• Considering requiring an operator to set maximum
  intervals for reevaluation for every task
• Intervals would not exceed five years

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OQ

• New Construction
• require an operator to have a process to verify
  the integrity of new construction
• using accepted quality control practices during
  construction
• new construction tasks in OQ programs
• using integrity verification methods
• pressure testing
• nondestructive testing

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OQ

• Non-regulatory
• Other clarifications, possibly by advisory
  bulletin, would enhance an operators
  understanding of the requirements
• Emergency response
• Abnormal operating conditions

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Advisory Bulletin on Excavation Activities

• January 17, 2006
• PHMSA issued advisory bulletin
• Reinforcing the need for safe excavation
  practices
• Recommends that pipeline operators integrate the
  OQ regulations into
• Marking
• Trenching
• Backfilling
• Reminds operators that excavation is considered a
  covered task under the OQ regulations
• Requires that pipeline operators and contractors
  be qualified to perform pipeline excavation
  activities

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NAPSR Issues
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NAPSR

• NASPR Administrative Manager
• Pipeline Safety Law Reauthorization
• Distribution Integrity Management
• Future Issues

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NAPSR

• Administrative Manager
• Funding provided by PHMSA through a grant
• NAPSR has drafted a job description, employment
  contract and advertised for the position
• Applications were due July 1, 2006
• Final decision to be made by November 1, 2006

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NAPSR

• Pipeline Safety Reauthorization
• Remove the 7 year reassessment interval for
  integrity management out of statutory language.
• Civil enforcement authority of damage prevention
  for the states.
• Grants for research and development to improve
  damage prevention such as research on locating
  technology and the one call communication
  process.
• Locating and siting authority for pipelines.

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NAPSR

• Pipeline Safety Reauthorization
• Permit streamlining
• Some level of security authority
• Limited safety requirements for small LP/Master
  Meter operators
• Ability to charge fee for the review of LNG
  facility designs
• Providing clarity on direct sales lateral issue

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NAPSR

• Pipeline Safety Reauthorization
• Administrations Proposed Bill Language Forwarded
  to Congress in early June
• Introduced As HR 5678
• House Transportation And Infrastructure Committee
  HR 5782

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NAPSR

• Distribution Integrity Management
• NAPSR participated in DIMP committees
• NAPSR working on teams developing guidance
  material with GPTC

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NAPSR Future Issues

• Inside Meters
• Illinois fined an operator for not inspecting
  inside meters
• Has been an issue in Ohio
• Look for enforcement to increase in future

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811

• The Federal Communications Commission (FCC)
  released an order on March 14, 2005
• Designated the 811 dialing code as a nationwide
  number to be used by state one-call notification
  systems for providing advanced notice of
  excavation activities to underground facility
• Operators implement the Pipeline Safety Act which
  provides for the establishment of a nationwide
  toll-free abbreviated dialing arrangement to be
  used by state one-call notification systems

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811

• Commission opened docket (05-1306-AU-COI) to
  address any issues that may exist for one-call
  centers in Ohio on October 25, 2005
• November 4, 2005, the Commission issued an entry
  by which it invited interested parties to file
  comments and/or reply comments addressing any
  technical, operational, cost, or compensation
  issues pertaining to 811 implementation, along
  with recommendations regarding what, if any,
  steps the Commission should take in order to
  ensure that they are resolved in a timely manner
• Whether and how it may be possible for both Ohio
  one-call centers to receive 811 calls from the
  same area

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811

• Nearly all of the initial and reply comments
  expressed support for the idea that the
  Commission should designate one of the existing
  Ohio one-call centers, namely the Ohio Utilities
  Protection Service (OUPS), as the sole 811
  one-call system provider in Ohio
• Nearly all of the local exchange telephone
  companies who filed comments expressed the view
  that it is not feasible to have two separate
  one-call centers make simultaneous use of the
  811dialing code in the same area

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811

• May 4, 2006, the Commission held public workshop
  on this issue and collected information.
• The Ohio Commission is in the process of working
  with the industry in determining the best method
  for the implementation of 8-1-1.  Although no
  carrier has yet to file a tariff proposal or cost
  study it is likely that all carriers will incur
  some level of cost in implementing 8-1-1.  As to
  how the cost may be recovered and by whom, will
  be determined by the Ohio Commission later this
  year.

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Distribution Integrity Management Regulations
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Timeline

• Inspector Generals Report - July 2004
• American Gas Foundation (AGF) Report - December
  2004
• Allegro Report (For OPS/PHMSA) - 2004
• DIMP Committee Report - December 2005
• GPTC/DIMP Standard Work - 2006
• NPRM - Fall of 2006
• Public Meeting - Early 2007

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Inspector Generals Report

• July 20, 2004 report to US House of Rep.
• Gas Distribution Lines make up 85 of the 2.1
  million miles of natural gas pipelines in the
  United States.
• Natural gas distribution pipelines over the last
  10 years have experienced over 4 times the number
  of fatalities and 3.5 times the number of
  injuries when compared to hazardous liquid and
  transmission pipelines.

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Inspector Generals Report

• Distribution
• 174 fatalities
• 662 injuries

• Transmission and Hazardous Liquids
• 43 fatalities
• 178 injuries

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Inspector Generals Strategy

• Three Elements of DOTs IG Plan
• Understanding the infrastructure
• Identifying and characterizing the threats
• Determining how best to manage the known risks
  (prevention and mitigation issues)

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American Gas Foundation Report

• Looked at three major areas
• Natural Gas Distribution Industry Safety
  Performance
• Current Regulations and Industry Practices that
  address threats to the natural gas distribution
  infrastructure
• Differences between Gas Transmission and Gas
  Distribution Infrastructure

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American Gas Foundation Report- Findings

• Key differences noted between distribution and
  transmission infrastructure
• Type of infrastructure
• System operating pressures
• Materials of construction
• Typical failure mechanisms
• Inspection methods
• Class locations
• Connection to customers

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American Gas Foundation Report- Findings

• Visual inspection of piping is more prevalent in
  distribution than transmission systems
• Many operators actively participate in damage
  prevention organizations
• Some one call programs allow exemptions from one
  call membership and not all include
  fines/penalties for offenders

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American Gas Foundation Report- Findings

• Current pipeline regulations address threats to
  distribution infrastructure
• Operators employ prevention and mitigation
  practices in excess of those required by law
• Downward trend in incident fatalities and
  injuries (1990-2002)
• Major cause of incidents is outside force damage
  third party damage

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Allegro Report

• Completed in 2004 for OPS/PHMSA
• Evaluated five years of incident data (1999-2003)
• Attempted to reclassify them into the new cause
  categories listed in the current incident
  reporting forms
• 67 incidents were outside force damage
• 38 excavation and mechanical damage
• 11 vehicle damage (contributed to 25 of fatal
  incidents)

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OPS/PHMSA Creates DIMP Committee

• Building on AGF Report, DIGIT Committee, State
  and Industry Initiatives
• Involve all stakeholders
• Assure flexibility to the maximum extent
  practicable
• Identify strategies to implement selected
  integrity management options

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Team Structure

• Executive Steering Team
• Coordinating Team
• Task Teams
• Strategic Options
• Risk Control
• Data
• Outside Force

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• Strategic Options - Identify options to implement
  for distribution system safety
• Risk Control - Evaluate the effectiveness and
  applicability of the current regulations as well
  a reviewing current risk control practices in
  government and industry
• Data - Assemble existing information to identify
  the type, significance, and trends for threats
  affecting distribution pipelines
• Outside Force - Review Common Ground Alliance
  database and related information to identify
  practices being used to prevent outside force
  damage and the extent of the applications

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Implementation Options to be Considered

• Structured Nation-Wide Education Program
• National/local advertising campaign similar
  to call-before you-dig
• Model State Legislation
• Prepare draft language that could be
  incorporated by States into legislation
  addressing distribution pipeline safety issues.

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Implementation Options to be Considered

• National Consensus Standard or Guidelines
• National Consensus Standard or other guidance
  document detailing specific practices for
  improving distribution pipeline safety under
  different circumstances.
• Guidance Document for Adoption by States
• Similar to above except made mandatory. States
  could adopt in whole or in part based on local
  needs.

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Implementation Options to be Considered

• Simple Flexible Federal Regulation
• Regulation requiring that each operator have an
  integrity plan that reflects (a) knowledge of
  infrastructure, (b) consideration of applicable
  threats, (c) activities to reduce risk, and (d)
  process for monitoring performance.
• Prescriptive Federal Regulation
• Regulation similar to the integrity management
  rule for gas transmission pipelines

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Implementation Options to be Considered

• Development of Innovative Safety Technology
• Support research and development of techniques
  to assess the integrity of small-diameter,
  networked pipeline systems of varying materials.

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DIMP Report

• Finalized in December 2005
• The DIMP report recommends the following
• A high-level flexible federal regulation
• Implementation guidance
• Nationwide education program for implementation
  of 811 for One Call programs
• Continued research and development

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DIMP Report

• Differences between gas distribution and
  transmission systems make it impractical to
  establish prescriptive requirements that would be
  appropriate in all cases
• The report recommended that an operators
  distribution integrity management program consist
  of seven key elements

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7 Key Elements of a Distribution Integrity Plan

• Develop and implement a written integrity
  management plan
• Know its infrastructure
• Identify threats
• Assess and prioritize risks
• Identify and implement mitigation measures
• Measure performance, monitor results, and
  evaluate the effectiveness of it programs
• Periodically report a limited set of performance
  measure to its regulator

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Excavation Damage

• Most significant single threat to distribution
  system integrity
• Recommended 9 key elements for an effective
  damage prevention program
• Not all states have this type of program
• Federal legislation needed to support development
  by all states
• Single greatest opportunity to distribution
  safety improvements

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9 Elements to an Effective Damage Prevention Plan

• Enhanced communication between operators and
  excavators
• Fostering support and partnership of all
  stakeholders in all phases
• Operators use of performance measures for
  persons performing locating of pipelines and
  pipeline construction
• Partnership in employee training

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9 Elements to an Effective Damage Prevention Plan
(contd)

• Partnership in public education
• Enforcement agencies role as partner and
  facilitator to help resolve issues
• Fair and consistent enforcement of the law
• Use of technology to improve all parts of the
  process
• Analysis of data to continually evaluate/improve
  program effectiveness

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Other Notables

• EFVs should not be federally mandated
• The management of gas leaks is fundamental to
  successful management of distribution risk and a
  vital risk control practice
• Distribution pipeline systems are relatively safe
• Incidents occur but have been reduced
• There is room for improvement

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GPTC/DIMP- Implementation Guidance

• In order to address DIMP recommendations, PHMSA
  asked GPTC to begin writing guidance material
• GPTC combined with stakeholder groups represented
  in the DIMP phase one group to begin writing
  guidance
• Meetings held in April, June, and August 2006
• Five subgroups working to address the seven key
  elements

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GPTC/DIMP- Implementation Guidance

• Final draft to be given to GPTC Members during
  their November meeting
• Hope to have in the next edition of the GPTC
  manual that will be available the middle of 2007

93
NPRM/Public Meetings

• NPRM is expected sometime in October
• PHMSA is planning a public meeting sometime
  during the first of the year
• Final rule planned by the end of 2007

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OPS/PHMSA Website

• http//ops.dot.gov

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Further Information

• Ed Steele
• at
• 614-644-8983
• or
• ed.steele_at_puc.state.oh.us