Part 255 Transmission and Distribution of Gas

(a) Each operator shall inspect each service regulator when it is installed, at the time of periodic meter change, and at the time a service which has been inactive for a period of two years or more is reactivated to service. (b) An operator may elect to inspect service regulator…

(a) Each transmission line valve must be inspected and partially operated at intervals not exceeding 15 months, but at least once each calendar year. (b) Each operator must take prompt remedial action to correct any valve found inoperable. (c) The location of all valves in transm…

(a) Each valve, the use of which may be necessary for the safe shutdown or sectionalization of a distribution system, must be inspected and partially operated at intervals not exceeding 15 months, but at least once each calendar year. Included are the principal shut-off valves at…

(a) Except as provided in subdivision (b) of this section, buried high-pressure service line valves or exposed exterior high-pressure service line valves shall be inspected in conjunction with the service regulator inspection required under section 255.744 of this Part. (b) Burie…

(a) Each vault housing pressure-regulating and pressure-limiting equipment, and having a volumetric internal content of 200 cubic feet (5.66 cubic meters) or more, must be inspected at intervals not exceeding 15 months, but at least once each calendar year, to determine that it i…

Each operator shall take the following minimum steps to minimize the danger of accidental ignition of gas in any structure or area where the presence of gas constitutes a hazard of fire or explosion. (a) When a hazardous amount of gas is being vented into open air, each potential…

(a) Each cast iron caulked bell and spigot joint that is subject to pressures of 25 psig (172 kPa) or more must be sealed with a material or device which: (1) does not reduce the flexibility of the joint; (2) permanently bonds, either chemically, mechanically or both, with the be…

When an operator has knowledge that the support for a segment of a buried cast iron pipeline is disturbed, the following actions must be taken. (a) That segment of the pipeline must be protected, as necessary, against damage during the disturbance by: (1) vibrations from heavy co…

(a) When any cast iron pipe, eight inches or less in nominal diameter, has been or will be exposed and undermined by an excavation 36 inches (914 millimeters) or greater in width, the purpose of which is for work other than normal gas operation and maintenance work being performe…

(a) If an excavation is made parallel to any cast iron gas main, eight inches or less in nominal diameter, and said excavation is not adequately shored to protect the cast iron main against movement, the cast iron main must be replaced where more than half the pipe diameter lies …

Each operator must maintain equipment used in joining plastic pipe in accordance with the manufacturer’s recommended practices or with written procedures that have been proven by test and experience to produce acceptable joints.

(a) For purposes of determining the start of an onshore gathering line under this Part, a production facility is comprised of wellhead assemblies, including traps or separators, heaters, control valves, and flow lines of less than 100 feet (30.5 meters) in length between the well…

(a) Each operator shall report all accidents where gas facilities may be involved, which cause injury or death to any person or damage to property, or could cause concern because of coverage by news media. (b) All incidents involving carbon monoxide (CO) that result in an investi…

Each operator shall submit a list during January of each year indicating the names, addresses, and home and business telephone numbers of responsible officials who may be contacted in the event of an emergency. The list shall also be submitted to all municipalities within which t…

(a) Any notification of a gas leak or gas odor, or any notification of damage to facilities by contractors or other outside sources shall constitute the need for prompt action. (b) Each operator shall be responsible for the leak investigation, classification, and repair of each l…

(a) A gas leak record, identified by number, shall be used to depict the entire history of a leak from the time of discovery through the follow-up inspection. (b) The record shall contain information as to the nature of the repair and follow-up results. (c) Leaks shall only be cl…

Each instrument utilized for leakage surveys and investigations must be tested against a known sample or in accordance with the manufacturer's recommended instructions as follows: (a) after any repair or replacement of parts other than normal maintenance; (b) once every three mon…

(a) A type 1 leak is one which, due to its location and/or relative magnitude, constitutes a potentially hazardous condition to the public or buildings. (b) A type 1 leak requires an immediate effort to protect life and property. (c) Continuous action shall be thereafter taken un…

(a) A type 2A leak does not present an immediately hazardous condition to the public or buildings, but is of a nature that requires frequent surveillance and scheduled repair. (b) Type 2A leaks shall be repaired within a period not to exceed six months. (c) Type 2A leaks shall be…

(a) A type 2 leak does not present an immediate hazardous condition to the public or buildings, but is of a nature requiring scheduled repair. (b) Type 2 leaks shall be repaired within a period not to exceed one year, except that leaks classified under paragraph (d)(5) of this se…

(a) A type 3 leak is not immediately hazardous at the time of detection and can be reasonably expected to remain that way. (b) A type 3 leak is any leak not classified as type 1, 2A or 2. (c) Type 3 leaks shall be reevaluated during the next required leakage survey or annually, w…

(a) Each operator shall, upon completing a type 1, type 2A or type 2 leak repair to its underground facilities, conduct a follow-up inspection at least 14 days after but within 30 days of the repair to validate said repair. (b) Follow-up inspections are not required for leak repa…

Whenever an operator conducts an annual leakage survey of all mains, or a portion of the mains, in its distribution system, any sustained reading of four percent or less gas-in-air on a CGI at an isolated test point outside the curbline or shoulder of the road can be considered a…

(a) Any major interruption of service furnished by any pipeline, or the failure of any major equipment, or any other interruption or failure of such facilities which could cause public concern because of coverage by news media, is to be immediately reported through the Gas Emerge…

(a) Each operator shall appropriately record each report received by it as to a gas leak or emergency on a suitably numbered service record. (b) A daily log shall be kept and maintained on file recording the receipt and handling of each such report and shall contain the following…

(a) Each operator shall establish procedures to analyze each failure or accident for the purpose of determining its cause and to minimize the possibility of a recurrence. This plan shall include a procedure to select samples of the failed facility or equipment for laboratory exam…

Each operator shall submit a copy of the annual report sent to the Office of Pipeline Safety, United States Department of Transportation not later than March 15th of each year.

Each operator shall submit a report on the existence of any of the applicable safety-related conditions involving facilities in service in accordance with sections 23 and 25 of title 49, Code of Federal Regulations, part 191, Transportation of Natural and Other Gas by Pipeline; A…

(a) Except as specified in subdivision (b) of this section, each gathering line shall be designed, constructed, tested, operated and maintained as specified in subdivision (e) of this section. (b) Gathering lines or any portion thereof located within the following areas shall be …

Sections 255.901 through 255.951 of this Part prescribe minimum requirements for an integrity management program on any gas transmission pipeline covered under this Part. For gas transmission pipelines constructed of plastic, only the requirements in sections 255.917, 255.921, 25…

The following definitions apply to sections 255.901 through 255.951 of this Part: (a) Assessment is the use of testing techniques as allowed in sections 255.901 through 255.951 of this Part to ascertain the condition of a covered pipeline segment. (b) Confirmatory direct assessme…

To determine which segments of an operator's transmission pipeline system are covered by sections 255.901 through 255.951 of this Part, an operator must identify the high consequence areas. An operator must use methods defined in section 255.903(f)(1) or (2) of this Part to ident…

No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in section 255.911 of this Part and that addresses the risks on each covered transmission pipeline se…

An operator must document any change to its program and the reasons for the change before implementing the change. An operator must notify the department and OPS, in accordance with section 255.949 of this Part, of any change to the program that may substantially affect the progr…

An operator's initial integrity management program begins with a framework (see section 255.907 of this Part) and evolves into a more detailed and comprehensive integrity management program, as information is gained and incorporated into the program. An operator must make continu…

ASME/ANSI B31.8S (as described in section 10.3 of this Title) provides the essential features of a performance-based or a prescriptive integrity management program. An operator that uses a performance-based approach that satisfies the requirements for exceptional performance in s…

The integrity management program must provide that each supervisor whose responsibilities relate to the integrity management program possesses and maintains a thorough knowledge of the integrity management program and of the elements for which the supervisor is responsible. The p…

Integrity and use of the threat identification in an integrity program. An operator must identify and evaluate all potential threats to each covered pipeline segment. Potential threats that an operator must consider include, but are not limited to, the threats listed in ASME/ANSI…

An operator must include each of the following elements in its written baseline assessment plan: (a) Identification of the potential threats to each covered pipeline segment and the information supporting the threat identification. (See section 255.917 of this Part.) (b) The meth…