DOT Pipeline Compliance News - November 2019 Issue

November 2019 Issue

In This Issue

PHMSA Natural Gas Transmission & Gathering Incident Report Form Changes F 7100.2

[Docket No. PHMSA-2011-0023-0471]

PHMSA has made several important modifications to the incident report form and instructions for reporting Natural Gas Transmission and Gathering releases. The following changes have occurred:

Major Changes:

PHMSA asks what time the release met report criteria (A.4) and when the operator identified the failure. These times may be the same, but often an operator is aware of an event before any report criteria have been met.
PHMSA now requires more details on the operational status of the pipeline at the time of the incident. For example, did the event occur during routine start-up or normal operations?
Additional information is being collected on release consequences. The number of injuries that did not require overnight hospitalization, but did require treatment, whether at a hospital or onsite by EMTs is now required. Also, the number of private/business buildings that were affected by the event, damaged, evacuated, or had gas service interrupted, will be collected in the form.
Additional information on when and how MAOP was first established are now required as well as the estimated gas flow through the pipe at the time of the release.
Additional information on Stray Current Corrosion is now being collected.
Additional questions will be required on underground facilities located within a foot of the line where the incident occurred and if it occurred in a water crossing 100 feet or greater in length.
A new section with several questions regarding vehicular damage not related to excavation is included requiring information on the driver, vehicle, speeds, etc. for Other Outside Force Damages.
Part J is now a separate section that includes information regarding in-line inspections. The list of ILI tools has been updated to reflect current technologies. Other data now collected include the propulsion method for the tool, the resolution of the tool (if applicable), and the type of anomalies the tool was attuned to detect. In addition, the most recent tool run year and the previous tool run year will be required. Direct Assessment questions also include updated choices for the types of assessments recently performed.
Part K is an entirely new section and allows an operator to choose additional contributing factors. Each factor is a sub cause from the other parts of the report form. For instance, if a piece of equipment was incorrectly installed and then subsequently overpressured and caused a release, both of these factors can be indicated on the form. Any additional factors involved in the release selected in Part K will need to be explained in the Narrative section of the form.

Minor Changes include:

Additional information is requested on the time zones and daylight savings status for the incident location
Additional questions regarding communication and involvement of local, state, and/or federal responders, including the time the communications occurred
Information regarding plastic pipe and the specifications of plastic pipe or plastic pipe fusions
Additional information on girth welds involved in the event, including any changes in pipe wall thickness and other pipe specifications for both sides of the weld
Minor changes to the answers for the item involved in the event
The manufacture year will now be collected for all items involved
When computing the cost of the release, the cost per square foot of gas is now required, in addition to the calculations of the cost of gas released during the event
Requires information on gas odorization
Exemptions to One-Call Centers if a release was due to third party excavation damage

Instruction Changes:

When calculating volumes released, gas consumed by fire should be included in the unintentional gas estimates. Intentional and controlled gas release volumes should also include any gas released by ESDs and relief devices, even if the release occurs in anticipation of repairs some time after the event occurred.
The operator’s initial indication of the failure is now asked, rather than how the incident was identified. This change in wording follows PHMSA’s attempt to determine when an operator is first aware of a potential event and at what time they were alerted to the issue (questions A.12 and A.13). In the instructions, PHMSA notes that an operator may be aware of a possible situation before any report criteria are met or before the operator has positively identified the failure.
Please note that Part J and K are new and include detailed instructions on the choices available and how to answer each question.

PHMSA ID’s Great Lakes as an Ecological Resource in NPMS

PHMSA recently updated its National Pipeline Mapping System (NPMS) by reclassifying the Great Lakes region as an unusually sensitive area (USA) ecological resource. A USA is a subset of the high consequence areas hazardous liquid pipeline operators are required to identify as part of their integrity management programs. Pipeline operators will now be able to use this GIS data to help with their integrity management planning, including determining whether a leak from their infrastructure could affect these ecological resource areas.

The Great Lakes USA data includes Lake Ontario, Lake Erie, Lake Huron (including Lake St. Clair), Lake Michigan, and Lake Superior, and the connecting channels (Saint Mary’s River, Saint Clair River, Detroit River, Niagara River, and Saint Lawrence River to the Canadian Border).

For more information on the Great Lakes USA data, visit the NPMS website.

Pipeline Research & Development Forum

February 19-20, 2020

The Pipeline and Hazardous Materials Safety Administration will hold their next Pipeline R&D Forum on February 19-20, 2020 in Arlington, VA. The forum allows public, government and industry pipeline stakeholders to develop recommendations on the technical gaps and challenges for future research. It also reduces duplication of programs, factors ongoing research efforts, leverages resources and broadens synergies. The national research agenda coming out of these events is aligned with the needs of the pipeline safety mission, makes use of the best available knowledge and expertise, and considers stakeholder perspectives. Specifically, the forum:

1. Identifies key pipeline technical challenges facing industry and government;

2. Disseminates information on current research efforts; and

3. Identifies new research that can help to meet known challenges.

Additional information can be found on PHMSA’s Public Meetings website.

NTSB Issues Findings and Recommendations from Merrimack Valley Incident

The National Transportation Safety Board (NTSB) conducted a public meeting on September 24^th and issued their findings and recommendations related to the Columbia Gas of Massachusetts’ overpressurization incident. The incident that occurred on September 13, 2018 involved high-pressure natural gas accidentally released into a low-pressure gas distribution system in the northeast region of the Merrimack Valley. One person was killed and 22 individuals, including three firefighters, were transported to local hospitals due to injuries. The fires and explosions damaged 131 structures, including at least 5 homes that were destroyed in the city of Lawrence and the towns of Andover and North Andover. Most of the damage occurred from fires ignited by natural gas-fueled appliances; several of the homes were destroyed by natural gas-fueled explosions.

An abstract of the final report, which includes the findings, probable cause, and all safety recommendations, is available here.

The urgent safety recommendations issued earlier in the investigation are available here.

NTSB Recommendations:

To PHMSA:

Revise Title 49 Code of Federal Regulations Part 192 to require overpressure protection for low-pressure natural gas distribution systems that cannot be defeated by a single operator error or equipment failure.
Issue an alert to all low-pressure natural gas distribution system operators of the possibility of a failure of overpressure protection; and the alert should recommend that operators use a failure modes and effects analysis or equivalent structured and systematic method to identify potential failures and take action to mitigate those identified failures.

To the States of Alabama, Alaska, Arizona, Arkansas, California, Colorado, Connecticut, Florida, Georgia, Idaho, Illinois, Iowa, Kentucky, Louisiana, Maine, Maryland, Minnesota, Mississippi, Missouri, Montana, Nebraska, Nevada, New York, North Carolina, Pennsylvania, South Carolina, South Dakota, Texas, Utah, Virginia, and Wyoming:

Remove the exemption so that all future natural gas infrastructure projects require licensed professional engineer approval and stamping.

To the Commonwealth of Massachusetts Executive Office of Public Safety and Security:

Develop guidance that includes a component for effective communications when deploying mutual aid resources within the first hours of a multi-jurisdictional incident.

To NiSource, Inc.:

Review your protocols and training for responding to large-scale emergency events, including providing timely information to emergency responders, appropriately assigning NiSource emergency response duties, performing multi-jurisdictional training exercises, and participating cooperatively with municipal emergency management agencies.

Petition for Reconsideration Submitted for Recent Gas Transmission Regulation

Four trade associations jointly submitted a Petition for Reconsideration to PHMSA for the recently published final rule Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments. There are two issues in the new regulation that The Associations found to be in conflict with approved language voted on by the Gas Piping Advisory Committee.

The Associations request that PHMSA revise § 192.624(a)(1) to adopt the GPAC-endorsed language indicating that § 192.624(a)(1) does not apply where an operator has “records necessary to establish maximum allowable operating pressure in accordance with § 192.619(a)(2)”, pressure test records. Without the specific reference to § 192.619(a)(2), it is unclear whether an operator must reconfirm MAOP when a pipeline segment already has a traceable, verifiable, and complete pressure test record.
The Associations request reconsideration of § 192.5(d), which codifies the requirement for pipeline operators to have records documenting the current class location of each pipeline segment. Section 192.5(d) does not limit the recordkeeping requirement to transmission pipelines. This deviates from the intent and scope of the NPRM, which stated that the recordkeeping requirements for establishing class location only applied to transmission pipelines, not distribution or gathering pipelines.

For a copy of the petition for reconsideration, click here.

Gas Mega-Rule Support
Are you ready for the recently published and pending gas transmission and gathering regulations? RCP has been heavily involved throughout this rulemaking process and is ready to assist operators as they get prepared. Whether it’s a deep dive into MAOP records reconfirmation, assessing where your Moderate Consequence Areas exist, reviewing existing pipeline integrity programs, developing action plans to get into compliance, or simply providing training to your team on what’s coming, RCP can help. Visit www.rcp.com or contact Jessica Foley for more information.

Advisory Committee Meetings

PHMSA will hold a joint public meeting of the Gas Pipeline Advisory Committee (GPAC) and the Liquid Pipeline Advisory Committee (LPAC) on November 14, 2019, from 8:30 a.m. to 5.00 p.m. ET. The meeting will be held at the Intercontinental Washington DC—The Wharf, 801 Wharf Street SW, Washington, DC 20024. The committees will discuss a variety of topics to update committee members on both gas and liquid pipeline applicable safety program and policy issues, such as:

Pipeline safety public awareness,
reauthorization of the pipeline safety program,
a regulatory agenda update,
a discussion of safety management systems within the pipeline industry,
an update on the Voluntary Information Sharing Working Group, and
an update on pipeline safety’s research and development program.

The meeting will be open to the public. Members of the public will be provided an opportunity to make a statement during the meeting. Registration is available on the PHMSA meeting page, which will also contain the agenda and any additional information for the meeting. Presentations will be available on the meeting website and posted on the E-Gov website under docket number PHMSA-2016-0136 within 30 days following the meeting. The proceeding will be recorded and a record of the proceeding will also be made available to the public on the E-Gov website.

California Code of Regulations: Title 19. Public Safety, Division 1. State Fire Marshal Chapter 14. Hazardous Liquid Pipeline Safety, Article 7: §2100 – §2120 10.1.2019

New Requirements for Pipelines near Environmentally & Ecologically Sensitive Areas in the Coast Zones of California

The state of California Fire Marshal’s office is proposing to adopt new requirements for pipelines located within a ½ mile of environmentally and ecologically sensitive areas in coastal zones. Pipelines in these sensitive areas, including low stress and gravity fed lines, will be required by January 1, 2022 to be fitted with the best available technology to reduce the volume of Hazardous Liquids released in a spill to protect state waters and wildlife. Such technologies will include, but not be limited to, leak detection systems, automatic shutoff systems, remotely controlled block valves, and any combination thereof. A dataset of the areas where pipelines will need to conform to Article 7 of CA state law will be available January 1, 2020, on the National Oceanic and Atmospheric Administration’s website.

New and replacement pipelines will be required, as of January 1, 2020 to utilize the best in current technologies to reduce the negative consequences of pipeline releases based on risk analyses conducted by each operator. Operators of existing pipelines will be required to submit a risk analysis and implementation plan by July 1, 2020 to retrofit existing pipelines in these sensitive coastal areas with the best mitigating technologies. Operators will be able to prioritize the retrofitting of pipelines based on risk and potential impacts. Once the pipelines have been updated, the technologies in place will be tested and a report submitted within 90 days to the State Fire Marshal for review. In addition, any plan for retrofitting new technologies will also require details on the training of personnel in the use and operation of each technology.

Operators may submit risk analysis cases that show a given pipeline near these sensitive coastal areas could not impact the coastal zone to exempt that pipeline from the requirements in this regulation. In addition, operators may also submit analyses and data that show a given pipeline is already using the most effective current technologies for a deferral for provisions in this Article. All submissions must be completed by February 1, 2020.

If a pipeline release impacts a coastal zone, operators are required to provide a report within 90 days to the State Fire Marshal that includes an evaluation and failure analysis of the factors included in the risk analysis submitted for the requirements of this Article, whether the pipeline was exempt or not. The report will also require an evaluation of the technologies’ performance and identify how the operator will address any issues thereof. Operators must also submit a new risk analysis and implementation plan for that pipeline which will be required within 12 months of the release.

All operators will be required to perform and update their risk assessments and resubmit them to the State Fire Marshal once every 5 years for review. All records associated with this Article’s provisions, risk analysis, implementation plan, testing results, training requirements, and other support documents, shall be kept for the life of the pipeline. Any other supplementary records used for review during inspections shall be kept for 6 years or three inspection cycles, whichever is longer.

Underwater Inspection Procedures & Inspection Interval Risk Model Updates

2019 has been a busy hurricane season. For many operators with assets in the Gulf of Mexico and its inlets subject to 49 CFR 192.612 and 195.413 there have been only a couple of named storms near those assets. However, some operators did receive requests from the off shore regulators to evaluate the impact on their pipelines from some of the season’s early storms. Now with hurricane season ending, it is a good time to make plans to evaluate the potential risk changes for shallow water pipelines. RCP’s Underwater Inspection Interval Risk Model analyzes key operator information and the latest storm data tabulated by the National Hurricane Center, as well as National Oceanic and Atmospheric Administration charts, and state game and fisheries department maps of navigational channels, shipping lanes, anchorage areas and commercial fishing locations to reassess previous risk rankings and inspection interval timelines.

For more information on RCP’s Underwater Inspection Procedure or Inspection Interval Risk Model, contact Jessica Foley.

API RP 1181 Pipeline Operational Status Determination, First Edition

API has recently published the first edition of API RP 1181. This document provides guidance for operations, inspection, and maintenance activities based on the operational status of a pipeline. This establishes four statuses:

precommissioned,
active/in-service,
idled, and
abandoned;

and gives operations, inspections, and maintenance recommendations for various pipeline operational statuses; explains pipeline status documentation requirements; and gives recommendations regarding safe transition between pipeline statuses.

For the purposes of this document, the word “pipeline” refers to transmission and regulated gathering pipelines and pipeline systems, although the principles may be applied to nonregulated gathering and flow lines. Regulations, permits, and easement requirements may supersede the guidance given in this document.

This RP can be ordered here.

TRRC Hires Pipeline Safety Inspectors

According to the Railroad Commission of Texas (TRRC), Texas is employing a record-high 69 pipeline inspectors, up from 63 in fiscal year 2018. Those inspectors completed more than 4,800 pipeline safety inspections and issued more than 2,500 citations for violations in fiscal year 2019, which ended on Aug. 31. The increase was possible due to financial support from the Texas Legislature and should position Texas to keep pace with its growing pipeline infrastructure from shale drilling, said Stephanie Weldman, director of the agency’s pipeline safety section. Full story on the TRRC website.

Oklahoma Administrative Code Title 165 Updates

On October 14, 2019, Oklahoma Corporation Commission (OKCC) issued revisions to Oklahoma Administrative Code Title 165. These changes included requiring Operators to provide Excavators with additional information as outlined in Title 165, Section 20. In addition, Section 25 concerning underground storage tanks was updated to provide new and additional requirements around vapor and water monitoring along with the documentation and the availability of records. Another update included revising Section 26 to include requirements for taking aboveground tanks out of and returning them to service.

For a copy of updates to OKCC Title 165 Section 20, 25, or 26 contact Jessica Foley.

CGA Annual DIRT Report

The Common Ground Alliance (CGA) released their annual report which provides a summary and analysis of the events submitted into CGA’s Damage Information Reporting Tool (DIRT) which analyzes damage and near-miss events from excavation activities related to buried facilities. The complete report for 2018 is available for download on the CGAWebsite.

In addition, CGA is providing access to an interactive dashboard that allows users to filter the data more granularly by factors contributing to damages. Visit DIRT Report for 2018 Interactive Analysis to review the dashboard.

We would welcome the opportunity to discuss our services with you.

Sincerely,

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

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