NTSB Safety Recommendation P-11-017

NTSB safety recommendation P-11-017.

TO THE PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION: Require that all natural gas transmission pipelines be configured so as to accommodate in-line inspection tools, with priority given to older pipelines. (Safety Recommendation P-11-17 was superseded by Safety Recommendation P-15-18)

Priority: CLASS II

Overall Status: Closed - Superseded

Issued Date: 2011-09-26

Adopted Date: 2011-09-12

Overall Date Closed: 2015-02-10

Synopsis: On September 9, 2010, about 6:11 p.m. Pacific daylight time,1 a 30-inch-diameter underground natural gas transmission pipeline (which is identified by the company as Line 132), owned and operated by Pacific Gas and Electric Company (PG&E), ruptured in a residential area in San Bruno, California. The accident killed eight people, injured many more, and caused substantial property damage. The rupture on Line 132 occurred near mile point 39.28, at the intersection of Earl Avenue and Glenview Drive in San Bruno. About 47.6 million standard cubic feet of natural gas were released as a result of the rupture. The released natural gas was ignited after the rupture; the subsequent explosion created a crater about 72 feet long by 26 feet wide, and the resulting fire destroyed 38 homes and damaged 70. A ruptured pipe segment about 28 feet long was found about 100 feet away from the crater.

Probable Cause: The National Transportation Safety Board determines that the probable cause of the accident was the Pacific Gas and Electric Company's (PG&E) (1) inadequate quality assurance and quality control in 1956 during its Line 132 relocation project, which allowed the installation of a substandard and poorly welded pipe section with a visible seam weld flaw that, over time grew to a critical size, causing the pipeline to rupture during a pressure increase stemming from poorly planned electrical work at the Milpitas Terminal; and (2) inadequate pipeline integrity management program, which failed to detect and repair or remove the defective pipe section.

Ntsbnumber: DCA10MP008

Report Number: PAR-11-01

Addressee Name: PHMSA

Addressee Status: Closed - Superseded

Addressee Date Closed: 2015-02-10

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2011-12-07

Communication Type: NPRM Response

Communication Contents: Notation 8360: The National Transportation Safety Board (NTSB) has reviewed the Pipeline and Hazardous Materials Safety Administration (PHMSA) Advance Notice of Proposed Rulemaking (ANPRM), “Pipeline Safety: Safety of Gas Transmission Pipelines,” that was published in the Federal Register on August 25, 2011. PHMSA is considering whether changes to the regulations governing the safety of gas transmission pipelines are needed, and is inviting comments on 14 specific topic areas in 2 broad categories—integrity management-related requirements and nonintegrity management requirements. In the area of integrity management, PHMSA is seeking comments and information about revising the definition of high consequence areas (HCA), including more prescriptive language, and placing additional restrictions on the use of specific pipeline assessment methods. In the nonintegrity management area, PHMSA is seeking information and comments about strengthening or expanding requirements for the spacing of mainline valves; installation of remotely operated or automatically operated valves; and corrosion control of steel pipelines, gas gathering lines, and underground gas storage facilities. The NTSB believes that the regulations for gas transmission pipelines can and should be improved and supports the overall intent of the ANPRM. However, the publication of the ANPRM 5 days before the NTSB public meeting on the Pacific Gas and Electric Company (PG&E) natural gas transmission pipeline rupture in San Bruno, California, precluded any mention in the ANPRM of the safety recommendations the NTSB adopted at the public meeting held on August 30, 2011, and issued on September 26, 2011. As a result of the Board Meeting, the NTSB issued 13 safety recommendations (P-11-8 through P-11-20) to PHMSA to improve the safety of natural gas transmission pipelines. The NTSB believes PHMSA should seek comments and information related to its safety recommendations to PHMSA issued as a result of the San Bruno investigation to take certain regulatory actions. In the ANPRM, PHMSA is also seeking information that would be relevant to Safety Recommendation P-93-9 the NTSB issued as a result of its accident investigation of an explosion and fire of a natural gas pipeline from a salt dome storage cavern in Brenham, Texas, on April 7, 1992. The accident resulted in 3 fatalities and 21 injuries. Safety Recommendation P-93-9 was classified “Closed—Unacceptable Action” on July 27, 1998, after a rulemaking proceeding to regulate underground gas storage was terminated in 1997. The NTSB supports PHMSA’s intention to reconsider regulating underground gas storage and is pleased PHMSA is revisiting this issue by seeking information and comment in this ANPRM. In support of our position, the NTSB is providing the following table listing the NTSB’s responses (that is, previously issued safety recommendations) to certain specific questions posed by PHMSA in the ANPRM: PHMSA’s ANPRM Questions NTSB’s Responses (Safety Recommendations) K.1. Should PHMSA develop Federal standards governing the safety of underground gas storage facilities? If so, should they be voluntary? If so, what portions of the facilities should be addressed in these standards? Develop safety requirements for storage of highly volatile liquids and natural gas in underground facilities, including a requirement that all pipeline operators perform safety analyses of new and existing underground geologic storage systems to identify potential failures, determine the likelihood that each failure will occur, and assess the feasibility of reducing the risk; require that operators incorporate all feasible improvements. (P-93-9) K.6. What standards are used for emergency shutdowns, emergency shutdown stations, gas monitors, local emergency response communications, public communications, and O&M Procedures? Require operators of natural gas transmission and distribution pipelines and hazardous liquid pipelines to provide system-specific information about their pipeline systems to the emergency response agencies of the communities and jurisdictions in which those pipelines are located. This information should include pipe diameter, operating pressure, product transported, and potential impact radius. (P-11-8) L.1. Are there standards used by the pipeline industry to guide management processes including management of change? Do standards governing the management of change process include requirements for IM procedures, O&M manuals, facility drawings, emergency response plans and procedures, and documents required to be maintained for the life of the pipeline? Require operators of natural gas transmission and distribution pipelines and hazardous liquid pipelines to ensure that their control room operators immediately and directly notify the 911 emergency call center(s) for the communities and jurisdictions in which those pipelines are located when a possible rupture of any pipeline is indicated. (P-11-9) PHMSA’s ANPRM Questions NTSB’s Responses (Safety Recommendations) B.4. What measures, if any, should operators be required explicitly to implement? Should they apply to all HCAs, or is there some reasonable basis for tailoring explicit mandates to particular HCAs? Should additional preventative and mitigative measures include any or all of the following: Additional line markers (line-of-sight); depth of cover surveys; close interval surveys for cathodic protection (CP) verification; coating surveys and recoating to help maintain CP current to pipe; additional right-of-way patrols; shorter ILI run intervals; additional gas quality monitoring, sampling, and in-line inspection tool runs; and improved standards for marking pipelines for operator construction and maintenance and one-calls? Require that all operators of natural gas transmission and distribution pipelines equip their supervisory control and data acquisition systems with tools to assist in recognizing and pinpointing the location of leaks, including line breaks; such tools could include a real-time leak detection system and appropriately spaced flow and pressure transmitters along covered transmission lines. (P-11-10) Amend Title 49 Code of Federal Regulations 192.935(c) to directly require that automatic shutoff valves or remote control valves in high consequence areas and in class 3 and 4 locations be installed and spaced at intervals that consider the factors listed in that regulation. (P-11-11) M.4. Are there any standards that exist that PHMSA could adopt or from which PHMSA could adapt concepts for Quality Management System (QMS)? Amend Title 49 Code of Federal Regulations 199.105 and 49 Code of Federal Regulations 199.225 to eliminate operator discretion with regard to testing of covered employees. The revised language should require drug and alcohol testing of each employee whose performance either contributed to the accident or cannot be completely discounted as a contributing factor to the accident. (P-11-12) Issue immediate guidance clarifying the need to conduct postaccident drug and alcohol testing of all potentially involved personnel despite uncertainty about the circumstances of the accident. (P-11-13) N.2. Should PHMSA repeal the MAOP exemption for pre-1970 pipelines? Should pre-1970 pipelines that operate above 72% SMYS be allowed to continue to be operated at these levels without increased safety evaluations such as periodic pressure tests, in-line inspections, coating examination, CP surveys, and expanded requirements on interference currents and depth of cover maintenance? N.3. Should PHMSA take any other actions with respect to exempt pipelines? Amend Title 49 Code of Federal Regulations 192.619 to delete the grandfather clause and require that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test. (P-

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2014-01-03

Communication Type: Official Correspondence

Communication Contents: We recognize that implementing this recommendation will not be an easy task, and we are pleased that, with the assistance of academia and industry, PHMSA has begun efforts to do so. Pending completion of the recommended action, Safety Recommendation P-11-17 remains classified OPEN—ACCEPTABLE RESPONSE.

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2015-04-08

Communication Type: Official Correspondence

Communication Contents: We appreciate receiving your update regarding actions to address Safety Recommendation P 11-17. However, please note that Safety Recommendation P-11-17 was classified CLOSED--SUPERSEDED by Safety Recommendation P 15-18 on January 27, 2015, in our safety study titled Integrity Management of Gas Transmission Pipelines in High Consequence Areas. We look forward to learning of your plans for addressing Safety Recommendation P-15-18, which is classified "Open-Await Response."

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2012-04-24

Communication Type: Official Correspondence

Communication Contents: The NTSB is encouraged that the U.S. Secretary of Transportation is committed to this issue and that PHMSA initiated regulatory action with its August 25, 2011, issuance of an ANPRM, Pipeline Safety: Safety of Gas Transmission Pipelines, which includes action regarding Integrity Management Programs (IMP). Accordingly, pending publication of a final rule that satisfies the recommendation, Safety Recommendation P-11-17 is classified OPEN—ACCEPTABLE RESPONSE.

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2015-02-10

Communication Type: Official Correspondence

Communication Contents: -From the Safety Study "Integrity Management of Gas Transmission Pipelines in High Consequence Areas." (SS-15-01, Notation 8565A, adopted January 27, 2015) 49 CFR § 192.150 states that with some exceptions, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line must be designed and constructed to accommodate the passage of instrumented ILI devices. Furthermore, justification of excluding the use of ILI as an integrity assessment tool must be provided by the operator. With the advancement of ILI tools and technology, such as the introduction of robotic devices, it is expected that more and more pipelines will become “piggable,” or able to accommodate ILI tools. INGAA and its members recognize that ILI is the most predictive and preferred tool, and have invested heavily in making their pipeline systems piggable by both making more of the pipeline system conducive to ILI and improving the capability of tools (INGAA 2012). The NTSB concludes that improvements in ILI tools allow for the inspection of gas transmission pipelines that were previously uninspectable by ILI. While it is up to the operators to choose the most appropriate method for their pipelines, it is clear that ILI is the best choice as an integrity assessment tool. The NTSB supersedes recommendation P-11-17 to PHMSA, which required that all natural gas transmission pipelines be configured so as to accommodate in-line inspection tools, with priority given to older pipelines with the following recommendation: The NTSB recommends that PHMSA require that all natural gas transmission pipelines be capable of being in-line inspected by either reconfiguring the pipeline to accommodate ILI tools or by the use of new technology that permits the inspection of previously uninspectable pipelines; priority should be given to the highest risk transmission pipelines that considers age, internal pressure, pipe diameter, and class location. The NTSB recommends that AGA and INGAA work together to develop and implement a strategy for increasing the use of ILI tools as appropriate, with an emphasis on intrastate pipelines. The NTSB further recommends that PHMSA revise Form F7100.1, Annual Report Form, to collect information on the mileage of both HCA and non-HCA pipelines that can accommodate ILI tools. Require that all natural gas transmission pipelines be capable of being in-line inspected by either reconfiguring the pipeline to accommodate in line inspection tools or by the use of new technology that permits the inspection of previously uninspectable pipelines; priority should be given to the highest risk transmission pipelines that considers age, internal pressure, pipe diameter, and class location. (Supersedes Safety Recommendation P-11-17, which is now classified CLOSED--SUPERSEDED) (P-15-18)

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2013-08-29

Communication Type: Official Correspondence

Communication Contents: -From Cynthia L. Quarterman, Administrator: Forty percent of the Nation’s natural gas transmission pipelines are currently unpiggable; therefore, requiring that all natural gas transmission pipelines be made piggable entails a major rulemaking to include an in-depth cost/benefit analysis. Many of these pipelines may need to be modified or the in-line inspection technology must be improved. PHMSA is evaluating recently submitted gas transmission annual report data to better understand the potential impact of such a requirement. PHMSA is also researching pipe inspection technologies. Beginning in 2004 and with $7.4M investment to date, PHMSA’s Pipeline Safety Research Program partnered with other Federal agencies, academics, and the Northeast Gas Association to develop, demonstrate, and deploy two robotic inspection technologies for unpiggable natural gas pipelines. The first tool was commercialized in 2011 for 6-inch to 8-inch pipe diameters. The second tool for 20-inch to 26-inch diameters will be commercial before spring 2013 and easily capable of detecting before failure the types of corrosion defects found in the Columbia Gas Transmission Corporation pipeline at Sissonville, WV. These robotic solutions will greatly enhance the pipeline industry’s ability to inspect unpiggable pipelines. Visual and magnetic flux leakage sensors for corrosion detection can now be passed through plug valves and many other line configurations that make pipelines unpiggable. PHMSA is now entertaining new research that will integrate other sensors that detect crack-like defects onto these robotic solutions, expanding their inspection capabilities much further.

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2015-01-22

Communication Type: Official Correspondence

Communication Contents: -From Timothy P. Butters, Acting Administrator: In 2012, PHMSA modified its Gas Transmission Annual Report forms to obtain better data on how many miles of gas transmission pipelines accommodate ILI tools and are piggable and how many are difficult to internally inspect. PHMSA received this data in 2013 and continues to analyze it. Of the 301,993 miles of gas transmission pipelines in the Nation, 113,632 (40 percent) of that mileage do not accommodate ILI tools. PHMSA's Pipeline Safety Research and Development Program is developing and deploying new inspection technologies for difficult-to-inspect natural gas pipelines. Our prior investments ($7.4M to date from 2004) have yielded very promising new, commercialized robotic technologies that are able to pig certain previously difficult-to-inspect portions of lines. PHMSA is now entertaining new research proposals that will integrate these robotic solutions with sensors that detect crack-like defects, which will further expand their inspection capabilities and improve their ability to detect seam cracks and defects. PHMSA continues to advocate for natural gas transmission pipeline operators to respond to former Secretary LaHood's '"Call to Action" to repair, replace, or rehabilitate high risk pipe. To date, 38 states have pipe replacement initiatives underway and other states are evaluating their abilities to provide relief to operators and the public for similar replacement initiatives. Further, there are some limitations on PHMSA's statutory authority to apply new design standards to existing infrastructure, and PHMSA has initiated a cost/benefit analysis to determine how to best address this recommendation. As mentioned above, approximately 40 percent of the Nation's natural gas transmission pipelines are difficult to inspect; therefore, requiring that all natural gas transmission pipelines be made piggable entails a major rulemaking. Cost/benefit is critical to informing action as many of these pipelines may need to be modified or existing in-line inspection technology must be improved.

Addressee Acronym: PHMSA

Addressee Organization Type: G-Federal Government

Communication Date: 2011-12-14

Communication Type: Official Correspondence

Communication Contents: -From Cynthia L. Quarterman, Administrator: PHMSA regulations were changed in 2004 to require that most new gas transmission pipelines be piggable. In March 2010, Secretary LaHood issued a call to action to accelerate the repair, replacement or rehabilitation of the highest risk pipe. PHMSA is hopeful that natural gas transmission pipeline operators will respond to that call to action by ensuring the integrity of older pipelines. PHMSA has already initiated an Advanced Notice of Proposed Rulemaking to consider whether the IMP rule should be expanded to include more pipelines for integrity assessment and to address assessment methods (including application of inline inspections). Since significant portions of the Nation’s natural gas transmission pipelines are not now piggable, requiring that all natural gas transmission pipelines be made piggable will entail a major rulemaking that must analyze the costs that it would entail. To ensure their piggability many may need to be replaced or the in line inspection technology must be improved. As mentioned earlier, PHMSA is requesting OMB approval for an information collection that will help us more precisely understand the implications of such a requirement. PHMSA also intends to continue to invest significant research and development attention on this problem. Our prior investments have yielded very promising new robotic technology that has effectively made portions of this infrastructure previously considered unpiggable accessible to new types of pigs. We are optimistic that a combination of information, research, and rulemaking will help us drive attainment of this laudable, but ambitious goal.