DOT Pipeline Compliance News - December 2010 Issue

December 2010 Issue

In This Issue

DOT Pipeline Compliance Workshop – January 17-19, 2011

Join us January 17 – 19 in Houston at our new office and dedicated training facility for an informative, lively, and interactive workshop on DOT Pipeline Compliance and OPA Planning for DOT Pipelines. This workshop has been attended by hundreds of pipeline personnel, with excellent feedback. The workshop provides an overview of the DOT pipeline regulations, and is appropriate for people who are new to pipeline regulations, who could use a refresher, or anyone who needs to know the latest information in these areas.

PROGRAM SCHEDULE:

Day 1 (January 17): Gas Pipeline Regulations (49CFR192)
The workshop will include an introduction to DOT/OPS pipeline compliance; State and Federal program variations; roles and responsibilities; design, construction, operations, maintenance, and emergency response requirements; how to monitor rulemaking activity and stay current with your compliance program; operator qualification, public awareness; with a specific emphasis on the gas integrity management regulations. Each attendee will receive general training materials which include the applicable DOT 49 CFR 192 regulations for gas pipelines (cd-rom), inspection checklists, and speaker’s PowerPoint presentation handouts.

Day 2 (January 18): Special Topics
Back by popular demand! RCP is conducting a special workshop day to discuss topics that many of our clients have expressed an interest in. The workshop topics will include: Control Room Management, Public Awareness Program Effectiveness Evaluations, and Revised Reporting Requirements.

Day 3 (January 19): Liquid Pipeline Regulations (49CFR195)
The workshop will include an introduction to DOT/OPS pipeline compliance; State and Federal program variations, roles and responsibilities; design, construction, operations, maintenance, and emergency response requirements; spill response planning requirements; how to monitor rulemaking activity and stay current with your compliance program; operator qualification and public awareness. Each attendee will receive general training materials which include the applicable DOT 49 CFR 195 regulations for hazardous liquid pipelines (cd-rom), inspection checklists, and speaker’s PowerPoint presentation handouts.

To register, or for additional information, click here.

PHMSA Final Rule on Updates to Pipeline and LNG Reporting Requirements

Docket No. PHMSA–2008–0291; Amdt. Nos. 191–21; 192–115; 193–23; and 195–95]
RIN 2137–AE33

The Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Final Rule revising the Pipeline Safety Regulations with updates to natural gas and hazardous liquid Pipelines, and Liquefied Natural Gas (LNG) facilities reporting requirements. (See related article in the July 2009 edition of the DOT Pipeline Compliance Newsletter.)

Operators will be required to use the new annual report forms in 2011 to report data for 2010. The information required to complete the new LNG incident report form is related to the occurrence of an incident and is collected during investigation of the event, not over time. In order to develop the on-line system, PHMSA is delaying the submission of the 2010 annual reports for gas transmission, LNG and hazardous liquids. The gas transmission and LNG annual reports will not be required to be submitted until June 15th and the hazardous liquid annual report will not be required to be submitted until August 15, 2011. PHMSA is also delaying the implementation of the OPID registry requirements until January 1, 2012.

In addition to editorial, reference and definition revisions for clarification to the Final Rule, Instructions and Forms, changes from the Notice of Proposed Rulemaking (NPRM) and this Final Rule include:

PHMSA is withdrawing the proposed safety-related condition report and associated changes to §§ 191.25 and 195.56 at this time.
PHMSA has accepted the suggestion to conform the treatment of incidents in Part 191 to that of accidents in Part 195; therefore, this final rule defines a gas pipeline incident as “a release of gas from a pipeline, or of LNG, liquefied petroleum gas, refrigerant gas, or gas from an LNG facility, and that results in one or more of the following consequences:”.
PHMSA has revised the definition of an incident in § 191.3 to clarify that actuation of an emergency shutdown system at an LNG facility that results from causes other than an actual emergency does not constitute an incident. This will eliminate the need to submit incident reports for shutdowns that result from maintenance, inadvertent actuations and signals, and any other emergency shutdown that does not result from an actual emergency. PHMSA has also deleted rollovers as an incident criterion.
PHMSA has not included in this final rule the proposed new criterion concerning fires or explosions not intentionally set by the operator. PHMSA is persuaded by the comments that it did not adequately consider the effect of this new criterion and the resulting burden.
This final rule requires reporting of releases that meet or exceed “3 million cubic feet” (i.e., 3,000 Mcf). PHMSA has revised the final rule to clarify that reporting under the volume threshold is only required for “unintended” releases that exceed the specified amount.
PHMSA has revised the final rule to make clear that the cost of gas lost is not to be included in the calculation of property damages for comparison with the $50,000 criterion.
PHMSA has revised the final rule to eliminate the requirement to request an alternate reporting method 60 days in advance of each required submission. The final rule provides that operators may apply for use of alternate submission methods and that approvals of such requests may be indefinite or until a date specified by PHMSA, eliminating the need to apply separately for each required submission.
As suggested by commenters, PHMSA has revised §§ 191.5 and 195.52 to allow operators the option of submitting online reports of certain incidents to the NRC (NRC).
PHMSA made changes to some of the criteria for notification:
- PHMSA has increased the dollar threshold from $5 million to $10 million and has limited its applicability to projects not involving line section pipe.
- PHMSA has also modified the reporting criterion for rehabilitation, replacement, modification, upgrade, uprate or other update to exclude changes that must be made on an emergency basis from the requirement for 60-day prior reporting. The final rule requires that operators notify PHMSA of emergency projects as soon as practicable.
PHMSA is withdrawing the changes proposed in the NPRM to §§ 191.27 and 195.57, and is also withdrawing the proposed forms related to these requirements.
PHMSA considers that a change in personnel, which could affect ‘‘contact information,’’ is too fine a level of detail to require notification. Therefore, PHMSA has not adopted this requirement into the regulations. PHMSA will consider modifying the National Operator Registry to make it available for operators to report voluntarily changes in contact information.
PHMSA has modified the proposed revision to the hazardous liquid pipeline annual report form and has revised this final rule to require reporting by state only for those parts of the form that indicate such reporting is required.
PHMSA has revised the Annual Report for both the Gas Transmission and Gathering Pipelines and Hazardous Liquid Pipelines forms to allow reporting to one decimal place and has indicated that rounding to the nearest mile is allowed.
PHMSA has revised Part C to require reporting of the total volume of gas transported under the reporting OPID during the reporting year for operators who do not operate their transmission lines as part of a distribution pipeline system. And has also revised this part to eliminate the need to report volume transported for operators who operate transmission pipelines as part of a distribution pipeline system.

This final rule is effective January 1, 2011.

For a copy of the Final Rule, contact Jessica Roger.

Pipeline Safety: Control Room Management/Human Factors PHMSA-2007-27954

On September 17, 2010, PHMSA published a Control Room Management/Human Factors notice of proposed rulemaking (NPRM) proposing to expedite the program implementation deadlines to August 1, 2011, for most of the requirements, except for certain provisions regarding adequate information and alarm management, which would have a program implementation deadline of August 1, 2012. PHMSA has received a request to extend the comment period in order to have more time to evaluate the NPRM. PHMSA has concurred in part with this request and has extended the comment period from November 16, 2010, to December 3, 2010.

Control Room Management Services

RCP is able to provide pipeline operators with fully compliant, customized Control Room Management Programs that take advantage of any existing processes that are currently in place and develop new processes that are tailored to your organization’s ability to successfully implement.

RCP also has the expertise to conduct readiness assessments as well as compliance analysis of your existing Control Room Management programs. This independent analysis will take into consideration what others within the industry are doing as a benchmark as well as what the final regulations require.

For more information on how RCP can help with your Control Room Management Program, contact Jessica Roger.

Online Reporting Now Available for Low Consequence Liquid Pipeline Incidents

Cheryl Trench of Allegro Energy Consulting has informed us that PHMSA’s online system for filing a Form PHMSA F 7000-1 for low consequence accidents from liquids pipelines will be available for data entry on November 19. This shortened release report is analogous to the “one-page” report that existed from 2002-2009. The system will not allow you to report an event as a “low consequence accident” if it involves: death or personal injury requiring hospitalization; or fire or explosion; or a release of 5 barrels or more; or property damage greater than $50,000: or pollution of a body of water. While the low consequence events are reported in less detail than more severe accidents, the new form requires more detail on location, consequences and causes than was the case before the implementation of the revised form in January 2010. The regulations on release reporting (Part 195.50, Part 195.52 and Part 195.54) are unchanged by the availability of the online filing functionality for this subset of accidents.

You can find the current form on the PHMSA website; only the shaded questions are required for low consequence accidents. You may also want to consult the instructions.

Final Rule on Greenhouse Gas Emissions Reporting for Petroleum and Natural Gas Systems

EPA-HQ-OAR-2009-0923; FRL-9226-1; RIN 2060-AP99

The Environmental Protection Agency (EPA) has promulgated a regulation (SubPart W of 40 CFR Part 98) to require monitoring and reporting of greenhouse gas emissions from petroleum and natural gas systems. This action adds this source category to the list of source categories already required to report greenhouse gas emissions. This action applies to sources with carbon dioxide equivalent emissions above certain threshold levels as described in this regulation. This action does not require control of greenhouse gases. The affected source categories are:

Offshore petroleum and natural gas production. Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes secondary platform structures connected to the platform structure via walkways, storage tanks associated with the platform structure, and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and, exploration that is not conducted on production platforms.
Onshore petroleum and natural gas production. Onshore petroleum and natural gas production means all equipment on a well pad or associated with a well pad (including compressors, generators, or storage facilities), and portable non-self-propelled equipment on a well pad or associated with a well pad (including well drilling and completion equipment, workover equipment, gravity separation equipment, auxiliary non-transportation-related equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels and all enhanced oil recovery (EOR) operations using CO2, and all petroleum and natural gas production located on islands, artificial islands, or structures connected by a causeway to land, an island, or artificial island.
Onshore natural gas processing. Natural gas processing means facilities that separate and recovers natural gas liquids (NGLs) and/or other non-methane gases and liquids from a stream of produced natural gas using equipment performing one or more of the following processes: oil and condensate removal, water removal, separation of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or other processes, and also the capture of CO2 separated from natural gas streams. This segment also includes all residue gas compression equipment owned or operated by the natural gas processing facility, whether inside or outside the processing facility fence. This source category does not include reporting of emissions from gathering lines and boosting stations. This source category includes: (1)all processing facilities that fractionate and (2) those that do not fractionate with throughput of 25 MMscf per day or greater.
Onshore natural gas transmission compression. Onshore natural gas transmission compression includes any stationary combination of compressors that move natural gas at elevated pressure from production fields or natural gas processing facilities, in transmission pipelines, to natural gas distribution pipelines, or into storage. In addition, transmission compressor stations may include equipment for liquids separation, natural gas dehydration, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression operated by natural gas processing facilities are included in the onshore natural gas processing segment and are excluded from this segment. This source category also does not include reporting of emissions from gathering lines and boosting stations-these sources are currently not covered by subpart W.
Underground natural gas storage. Underground natural gas storage includes subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility that inject natural gas into and remove natural gas from the underground reservoirs.
Liquefied natural gas (LNG) storage. LNG storage includes onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied natural gas.
LNG import and export facilities. LNG import equipment includes all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States.
Natural gas distribution. Natural gas distribution includes the distribution pipelines (not interstate transmission pipelines or intrastate transmission pipelines) and metering and regulating equipment at city gate stations, and excluding customer meters, that physically deliver natural gas to end users and is operated by a Local Distribution Company (LDC) that is regulated as a separate operating company by a public utility commission or that is operated as an independent municipally-owned distribution system. This segment excludes customer meters and infrastructure and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and “farm taps” upstream of the local distribution company inlet-these sources are not covered by subpart W.

The final rule is effective on December 30, 2010.

Editor’s note: If your air emissions compliance personnel aren’t already familiar with this topic, they have a lot of reading to do!

Greenhouse Gas Reporting Assistance

Do you need help in determining if the GHG Final Rule applies to you? Do you know what to report and when? RCP can help you get the answers. Contact Jessica Roger for more information.

[Docket No. PHMSA–2010–0354]

The Pipeline and Hazardous Materials Safety Administration (PHMSA) invites comments on an information collection under Office of Management and Budget (OMB) Control No. 2137–0578, titled ‘‘Reporting Safety- Related Conditions on Gas, Hazardous Liquid, and Carbon Dioxide Pipelines and Liquefied Natural Gas Facilities.’’ PHMSA is preparing to request approval from OMB for a renewal of the current information collection.

Submit comments on or before January 28, 2011 to the E–Gov Website; Fax: (202) 493–2251; or Mail: Docket Management Facility; U.S. DOT, 1200 New Jersey Avenue, SE., West Building, Room W12–140, Washington, DC 20590–0001. Identify the docket number, PHMSA–2010–0354, at the beginning of your comments.

Pipeline Safety: UIP Information Collection Activities

[Docket No. PHMSA–2010–0355]

The Pipeline and Hazardous Materials Safety Administration (PHMSA) invites comments on an information collection under Office of Management and Budget (OMB) Control No. 2137–0618, titled ‘‘Pipeline Safety: Periodic Underwater Inspection.’’ PHMSA is preparing to request approval from OMB for a renewal of the current information collection.

Submit comments on or before February 7, 2011 to the E–Gov Website; Fax: (202) 493–2251; or Mail: Docket Management Facility; U.S. DOT, 1200 New Jersey Avenue, SE., West Building, Room W12–140, Washington, DC 20590–0001. Identify the docket number, PHMSA–2010–0355, at the beginning of your comments.

RCP’s Web-Based Compliance Management Systems

CP’s Compliance Management System (CMS) is an invaluable tool for managing all aspects of regulatory workflow. Some examples of how our clients are using the CMS include:

O&M Scheduling and Data Acquisition;
Cathodic Protection Inspection and Data Management;
One-Call Screening and Ticket Management;
Repair / Replacement Programs;
Operator Qualification Administration and Workflow Integration;
Leak Life Cycle Management;
Environmental, Health and Safety Compliance;
Audit Action Item Tracking; and
Customer Data Management.

DIMP Integration

For gas distribution operators looking for a powerful tool to implement DIMP, the RCP CMS integrates O&M data captured from field personnel along with inherent system attributes to provide real-time risk analysis, performance reporting, as well as track additional and accelerated actions taken to mitigate risks.

Key Features

GIS integrated workflow management
Custom tailored e-mail notifications and reporting
Runs on any web-enabled device, no software to download
Powerful reporting and custom query functionality
Multiple security and user privilege settings
Document storage and control (ex. procedures, maps, images, and completion documentation)
Automatic recurrence setting for routine tasks (example: leak surveys, CP surveys, etc.)
Create work orders for unscheduled / unplanned activities (ex. release reporting)

To request a demonstration or to request more information, please contact Jessica Roger.

Pipeline Safety: Random Drug Testing Rate

[Docket ID PHMSA-2010-0323]

Operators of gas, hazardous liquid, and carbon dioxide pipelines and operators of liquefied natural gas facilities must select and test a percentage of covered employees for random drug testing. Pursuant to 49 CFR 199.105(c)(2), (3), and (4), the PHMSA Administrator’s decision on whether to change the minimum annual random drug testing rate is based on the reported random drug test positive rate for the pipeline industry. The data considered by the Administrator comes from operators’ annual submissions of Management Information System (MIS) reports required by 49 CFR 199.119(a). If the reported random drug test positive rate is less than one percent, the Administrator may continue the minimum random drug testing rate at 25 percent. In 2009, the random drug test positive rate was less than one percent. Therefore, the minimum random drug testing rate will remain at 25 percent for calendar year 2011.

Reminder: On January 19, 2010, PHMSA published an Advisory Bulletin (75 FR 2926) implementing the annual collection of contractor MIS drug and alcohol testing data. (See related article in the February 2010 edition of the DOT Pipeline Compliance Newsletter.) All applicable § 199.119 (drug testing) and § 199.229 (alcohol testing) MIS reporting operators are responsible for the submission of all contractor MIS reports to PHMSA, as well as their own, by March 15, 2011. Contractors with employees in safety-sensitive positions who performed, as defined in § 199.3 of 49 CFR part 199, covered functions, must submit these reports only through the auspices of each operator for whom these covered employees performed those covered functions (i.e., maintenance, operations or emergency response).

For further information contact Stanley Kastanas, Program Manager, Substance Abuse Prevention Program, PHMSA, U.S. Department of Transportation, telephone 202-550-0629 or e-mail.

Pipeline Safety: Technical Pipeline Safety Advisory Committee Meeting

[Docket No. PHMSA-2009-0203]

The Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC) will meet via conference call on Monday, December 13, 2010, 1 p.m. to 4 p.m. EST. The committee will consider and vote on a proposed rule titled: “Pipeline Safety: Applying Safety Regulation to All Rural Onshore Hazardous Liquid Low-Stress Lines” published on June 22, 2010 (75 FR 35366). This rulemaking would apply the Federal pipeline safety regulations to the remaining unregulated rural onshore hazardous liquid low-stress pipelines, as required by current law. The meeting agenda will include the committee’s discussion and vote on the proposed rule, and on the associated regulatory analysis and environmental assessment.

The meeting attendees should register in advance by clicking here. PHMSA will post any new information including meeting presentations on the PHMSA/Office of Pipeline Safety Web page about 15 days before the meeting takes place.

For information about the meeting, contact Cheryl Whetsel by phone at 202-366-4431 or by e-mail. For technical contents about the proposed rule contact Mike Israni by phone at 202-366-4595 or by e-mail.

Members of the public may attend and make a statement during the advisory committee meetings. For a better chance to speak at the meetings, please contact Cheryl Whetsel by December 1, 2010.

PHMSA Migrates NPMS Database to PODS

PHMSA has completed the migration of the 510,917-mile National Pipeline Mapping System (NPMS) Database to PODS (Pipeline Open Data Standard). This large dataset is visible to the general public via the Public View \ application on www.npms.phmsa.dot.gov.

By utilizing the PODS Data Model, PHMSA is now able to track attributes in a pipe-centric, rather than operator-centric, manner. This enables PHMSA to research changes to a pipe segment through the years, differentiate operator performance from pipeline performance, detect changes between an operator’s current submission and previous NPMS submissions, and to query the database for either the current derived layer, or for historic data.

Bill Byrd signature
W. R. (Bill) Byrd, PE
President
RCP Inc.

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