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The Code of Federal Regulations is a codification of the general and permanent rules published in the Federal Register by the Executive departments and agencies of the Federal Government. The Code is divided into 50 titles which represent broad areas subject to Federal regulation. Each title is divided into chapters which usually bear the name of the issuing agency. Each chapter is further subdivided into parts covering specific regulatory areas.
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Title 49—
In the volume containing parts 100-185, see § 172.101 for the Hazardous Materials Table. The Federal Motor Vehicle Safety Standards appear in part 571.
Redesignation tables for chapter III—Federal Motor Carrier Safety Administration, Department of Transportation and chapter XII—Transportation Security Administration, Department of Transportation appear in the Finding Aids section of the fifth and ninth volumes.
For this volume, Susannah C. Hurley was Chief Editor. The Code of Federal Regulations publication program is under the direction of Michael L. White, assisted by Ann Worley.
(This book contains parts 186 to 199)
Other regulations issued by the Department of Transportation appear in 14 CFR chapters I and II, 23 CFR, 33 CFR chapters I and IV, 44 CFR chapter IV, 46 CFR chapters I through III, 48 CFR chapter 12, and 49 CFR chapters I through VI.
33 U.S.C. 1321; 49 U.S.C. 5101-5127, 60101
(a) This part prescribes procedures used by the Pipeline and Hazardous Materials Safety Administration in carrying out duties regarding pipeline safety under 49 U.S.C. 60101
(b) This subpart defines certain terms and prescribes procedures that are applicable to each proceeding described in this part.
As used in this part:
(a) Each order, notice, or other document required to be served under this part shall be served personally, by registered or certified mail, overnight courier, or electronic transmission by facsimile or other electronic means that includes reliable acknowledgement of actual receipt.
(b) Service upon a person's duly authorized representative or agent constitutes service upon that person.
(c) Service by registered or certified mail or overnight courier is complete upon mailing. Service by electronic transmission is complete upon transmission and acknowledgement of receipt. An official receipt for the mailing from the U.S. Postal Service or overnight courier, or a facsimile or other electronic transmission confirmation, constitutes prima facie evidence of service.
(a) The Administrator, PHMSA, the Chief Counsel, PHMSA, or the official designated by the Administrator, PHMSA, to preside over a hearing convened in accordance with this part, may sign and issue subpoenas individually on their own initiative or, upon request and adequate showing by any person participating in the proceeding that the information sought will materially advance the proceeding.
(b) A subpoena may require the attendance of a witness, or the production of documentary or other tangible evidence in the possession or under the control of person served, or both.
(c) A subpoena may be served personally by any person who is not an interested person and is not less than 18 years of age, or by certified or registered mail.
(d) Service of a subpoena upon the person named therein shall be made by delivering a copy of the subpoena to such person and by tendering the fees for one day's attendance and mileage as specified by paragraph (g) of this section. When a subpoena is issued at the instance of any officer or agency of the United States, fees and mileage need not be tendered at the time of service. Delivery of a copy of a subpoena and tender of the fees to a natural person may be made by handing them to the person, leaving them at the person's office with the person in charge thereof, leaving them at the person's dwelling place or usual place of abode with some person of suitable age and discretion then residing therein, by mailing them by registered or certified mail to the person at the last known address, or by any method whereby actual notice is given to the person and the fees are made available prior to the return date.
(e) When the person to be served is not a natural person, delivery of a copy of the subpoena and tender of the fees may be effected by handing them to a designated agent or representative for service, or to any officer, director, or
(f) The original subpoena bearing a certificate of service shall be filed with the official having responsibility for the proceeding in connection with which the subpoena was issued.
(g) A subpoenaed witness shall be paid the same fees and mileage as would be paid to a witness in a proceeding in the district courts of the United States. The witness fees and mileage shall be paid by the person at whose instance the subpoena was issued.
(h) Notwithstanding the provisions of paragraph (g) of this section, and upon request, the witness fees and mileage may be paid by the PHMSA if the official who issued the subpoena determines on the basis of good cause shown, that:
(1) The presence of the subpoenaed witness will materially advance the proceeding; and
(2) The person at whose instance the subpoena was issued would suffer a serious hardship if required to pay the witness fees and mileage.
(i) Any person to whom a subpoena is directed may, prior to the time specified therein for compliance, but in no event more than 10 days after the date of service of such subpoena, apply to the official who issued the subpoena, or if the person is unavailable, to the Administrator, PHMSA to quash or modify the subpoena. The application shall contain a brief statement of the reasons relied upon in support of the action sought therein. The Administrator, PHMSA, or this issuing official, as the case may be, may:
(1) Deny the application;
(2) Quash or modify the subpoena; or
(3) Condition a grant or denial of the application to quash or modify the subpoena upon the satisfaction of certain just and reasonable requirements. The denial may be summary.
(j) Upon refusal to obey a subpoena served upon any person under the provisions of this section, the PHMSA may request the Attorney General to seek the aid of the U. S. District Court for any District in which the person is found to compel that person, after notice, to appear and give testimony, or to appear and produce the subpoenaed documents before the PHMSA, or both.
(a) In circumstances where a rule contained in parts 192, 193 and 195 of this chapter authorizes the Administrator to make a finding or approval, an operator may petition the Administrator for such a finding or approval.
(b) Each petition must refer to the rule authorizing the action sought and contain information or arguments that justify the action. Unless otherwise specified, no public proceeding is held on a petition before it is granted or denied. After a petition is received, the Administrator or participating state agency notifies the petitioner of the disposition of the petition or, if the request requires more extensive consideration or additional information or comments are requested and delay is expected, of the date by which action will be taken.
(1) For operators seeking a finding or approval involving intrastate pipeline transportation, petitions must be sent to:
(i) The State agency certified to participate under 49 U.S.C. 60105.
(ii) Where there is no state agency certified to participate, the Administrator, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE, Washington, DC 20590.
(2) For operators seeking a finding or approval involving interstate pipeline transportation, petitions must be sent to the Administrator, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE, Washington, DC 20590.
(c) All petitions must be received at least 90 days prior to the date by which the operator requests the finding or approval to be made.
(d) The Administrator will make all findings or approvals of petitions initiated under this section. A participating
(a)
(2) PHMSA's Office of the Chief Counsel (OCC) is available to answer questions concerning Federal pipeline safety law, 49 U.S.C. 60101
(b)
(2) A written interpretation regarding Federal pipeline safety law, 49 U.S.C 60101
(a) This subpart describes the enforcement authority and sanctions exercised by the Associate Administrator, OPS for achieving and maintaining pipeline safety. It also prescribes the procedures governing the exercise of that authority and the imposition of those sanctions.
(b) A person who is the subject of action pursuant to this subpart may be represented by legal counsel at all stages of the proceeding.
(a) Officers, employees, or agents authorized by the Associate Administrator for Pipeline Safety, PHMSA, upon presenting appropriate credentials, are authorized to enter upon, inspect, and examine, at reasonable times and in a reasonable manner, the records and properties of persons to the extent such records and properties are relevant to determining the compliance of such persons with the requirements of 49 U.S.C. 60101
(b) Inspections are ordinarily conducted pursuant to one of the following:
(1) Routine scheduling by the Regional Director of the Region in which the facility is located;
(2) A complaint received from a member of the public;
(3) Information obtained from a previous inspection;
(4) Report from a State Agency participating in the Federal Program under 49 U.S.C. 60105;
(5) Pipeline accident or incident; or
(6) Whenever deemed appropriate by the Administrator, PHMSA or his designee.
(c) If, after an inspection, the Associate Administrator, OPS believes that further information is needed to determine appropriate action, the Associate Administrator, OPS may send the owner or operator a “Request for Specific Information” to be answered within 45 days after receipt of the letter.
(d) To the extent necessary to carry out the responsibilities under 49 U.S.C. 60101
(e) If a representative of the DOT investigates an incident involving a pipeline facility, OPS may request that the operator make available to the representative all records and information that pertain to the incident in any way, including integrity management plans and test results, and that the operator afford all reasonable assistance in the investigation.
(f) When the information obtained from an inspection or from other appropriate sources indicates that further OPS action is warranted, the OPS may issue a warning letter under § 190.205 or initiate one or more of the enforcement proceedings prescribed in §§ 190.207 through 190.235.
Upon determining that a probable violation of 49 U.S.C. 60101
(a) Except as otherwise provided by this subpart, a Regional Director begins an enforcement proceeding by serving a notice of probable violation on a person charging that person with a probable violation of 49 U.S.C. 60101
(b) A notice of probable violation issued under this section shall include:
(1) Statement of the provisions of the laws, regulations or orders which the respondent is alleged to have violated and a statement of the evidence upon which the allegations are based;
(2) Notice of response options available to the respondent under § 190.209;
(3) If a civil penalty is proposed under § 190.221, the amount of the proposed civil penalty and the maximum civil penalty for which respondent is liable under law; and
(4) If a compliance order is proposed under § 190.217, a statement of the remedial action being sought in the form of a proposed compliance order.
(c) The Associate Administrator, OPS may amend a notice of probable violation at any time prior to issuance of a final order under § 190.213. If an amendment includes any new material allegations of fact or proposes an increased civil penalty amount or new or additional remedial action under
Within 30 days of receipt of a notice of probable violation, the respondent shall respond to the Regional Director who issued the notice in the following way:
(a) When the notice contains a proposed civil penalty—
(1) Pay the proposed civil penalty as provided in § 190.227 and close the case with prejudice to the respondent;
(2) Submit written explanations, information or other materials in answer to the allegations or in mitigation of the proposed civil penalty; or
(3) Request a hearing under § 190.211.
(b) When the notice contains a proposed compliance order—
(1) Agree to the proposed compliance order;
(2) Request the execution of a consent order under § 190.219;
(3) Object to the proposed compliance order and submit written explanations, information or other materials in answer to the allegations in the notice of probable violation; or
(4) Request a hearing under § 190.211.
(c) Failure of the respondent to respond in accordance with paragraph (a) of this section or, when applicable, paragraph (c) of this section, constitutes a waiver of the right to contest the allegations in the notice of probable violation and authorizes the Associate Administrator, OPS, without further notice to the respondent, to find facts to be as alleged in the notice of probable violation and to issue a final order under § 190.213.
(d) All materials submitted by operators in response to enforcement actions may be placed on publicly accessible Web sites. A Respondent that seeks confidential treatment under 5 U.S.C. 552(b) for any portion of its responsive materials must provide a second copy of such materials along with the complete original document. A Respondent may redact the portions it believes qualify for confidential treatment in the second copy but must provide an explanation for each redaction.
(a) A request for a hearing provided for in this part must be accompanied by a statement of the issues that the respondent intends to raise at the hearing. The issues may relate to the allegations in the notice, the proposed corrective action (including a proposed amendment, a proposed compliance order, or a proposed hazardous facility order), or the proposed civil penalty amount. A respondent's failure to specify an issue may result in waiver of the respondent's right to raise that issue at the hearing. The respondent's request must also indicate whether or not the respondent will be represented by counsel at the hearing.
(b) A telephone hearing will be held if the amount of the proposed civil penalty or the cost of the proposed corrective action is less than $10,000, unless the respondent submits a written request for an in-person hearing. Hearings are held in a location agreed upon by the presiding official, OPS and the respondent.
(c) An attorney from the Office of the Chief Counsel, Pipeline and Hazardous Materials Safety Administration, serves as the presiding official at the hearing.
(d) The hearing is conducted informally without strict adherence to rules of evidence. The respondent may submit any relevant information and material and call witnesses on the respondent's behalf. The respondent may also examine the evidence and witnesses presented by the government. No detailed record of a hearing is prepared.
(e) Upon request by respondent, and whenever practicable, the material in the case file pertinent to the issues to be determined is provided to the respondent 30 days before the hearing. The respondent may respond to or rebut this material at the hearing.
(f) During the hearing, the respondent may offer any facts, statements,
(g) At the close of the respondent's presentation, the presiding official may present or allow the presentation of any OPS rebuttal information. The respondent may then respond to that information.
(h) After the evidence in the case has been presented, the presiding official shall permit argument on the issues under consideration.
(i) The respondent may also request an opportunity to submit further written materal for inclusion in the case file. The presiding official shall allow a reasonable time for the submission of the material and shall specify the date by which it must be submitted. If the material is not submitted within the time prescribed, the case shall proceed to final action without the material.
(j) After submission of all materials during and after the hearing, the presiding official shall prepare a written recommendation as to final action in the case. This recommendation, along with any material submitted during and after the hearing, shall be included in the case file which is forwarded to the Associate Administrator, OPS for final administrative action.
(a) After a hearing under § 190.211 or, if no hearing has been held, after expiration of the 30 day response period prescribed in § 190.209, the case file of an enforcement proceeding commenced under § 190.207 is forwarded to the Associate Administrator, OPS for issuance of a final order.
(b) The case file of an enforcement proceeding commenced under § 190.207 includes:
(1) The inspection reports and any other evidence of alleged violations;
(2) A copy of the notice of probable violation issued under § 190.207;
(3) Material submitted by the respondent in accord with § 190.209 in response to the notice of probable violation;
(4) The Regional Director's evaluation of response material submitted by the respondent and recommendation for final action to be taken under this section; and
(5) In cases involving a § 190.211 hearing, any material submitted during and after the hearing and the presiding official's recommendation for final action to be taken under this section.
(c) Based on a review of a case file described in paragraph (b) of this section, the Associate Administrator, OPS shall issue a final order that includes—
(1) A statement of findings and determinations on all material issues, including a determination as to whether each alleged violation has been proved;
(2) If a civil penalty is assessed, the amount of the penalty and the procedures for payment of the penalty, provided that the assessed civil penalty may not exceed the penalty proposed in the notice of probable violation; and
(3) If a compliance order is issued, a statement of the actions required to be taken by the respondent and the time by which such actions must be accomplished.
(d) Except as provided by § 190.215, an order issued under this section regarding an enforcement proceeding is considered final administrative action on that enforcement proceeding.
(e) It is the policy of the Associate Administrator, OPS to issue a final order under this section expeditiously. In cases where a substantial delay is expected, notice of that fact and the date by which it is expected that action will be taken is provided to the respondent upon request and whenever practicable.
(a) A respondent may petition the Associate Administrator, OPS for reconsideration of a final order issued under § 190.213. It is requested, but not required, that three copies be submitted. The petition must be received no later than 20 days after service of the final order upon the respondent. Petitions received after that time will not be considered. The petition must
(b) If the respondent requests the consideration of additional facts or arguments, the respondent must submit the reasons they were not presented prior to issuance of the final order.
(c) The Associate Administrator, OPS does not consider repetitious information, arguments, or petitions.
(d) The filing of a petition under this section stays the payment of any civil penalty assessed. However, unless the Associate Administrator, OPS otherwise provides, the order, including any required corrective action, is not stayed.
(e) The Associate Administrator, OPS may grant or deny, in whole or in part, any petition for reconsideration without further proceedings. In the event the Associate Administrator, OPS reconsiders a final order, a final decision on reconsideration may be issued without further proceedings, or, in the alternative, additional information, data, and comment may be requested by the Associate Administrator, OPS as deemed appropriate.
(f) It is the policy of the Associate Administrator, OPS to issue notice of the action taken on a petition for reconsideration expeditiously. In cases where a substantial delay is expected, notice of that fact and the date by which it is expected that action will be taken is provided to the respondent upon request and whenever practicable.
When the Associate Administrator, OPS has reason to believe that a person is engaging in conduct which involves a violation of the 49 U.S.C. 60101
(a) At any time before the issuance of a compliance order under § 190.213 the Associate Administrator, OPS and the respondent may agree to dispose of the case by joint execution of a consent order. Upon such joint execution, the consent order shall be considered a final order under § 190.213.
(b) A consent order executed under paragraph (a) of this section shall include:
(1) An admission by the respondent of all jurisdictional facts;
(2) An express waiver of further procedural steps and of all right to seek judicial review or otherwise challenge or contest the validity of that order;
(3) An acknowledgement that the notice of probable violation may be used to construe the terms of the consent order; and
(4) A statement of the actions required of the respondent and the time by which such actions shall be accomplished.
When the Associate Administrator, OPS has reason to believe that a person has committed an act which is a violation of any provision of the 49 U.S.C. 60101
(a) Any person who is determined to have violated a provision of 49 U.S.C. 60101
(b) Any person who knowingly violates a regulation or order under this subchapter applicable to offshore gas gathering lines issued under the authority of 49 U.S.C. 5101
(c) Any person who is determined to have violated any standard or order under 49 U.S.C. 60103 shall be subjected to a civil penalty of not to exceed $50,000, which penalty shall be in addition to any other penalties to which such person may be subject under paragraph (a) of this section.
(d) Any person who is determined to have violated any standard or order under 49 U.S.C. 60129 shall be subject to a civil penalty not to exceed $1,000, which shall be in addition to any other penalties to which such person may be subject under paragraph (a) of this section.
(e) No person shall be subject to a civil penalty under this section for the violation of any requirement of this subchapter and an order issued under § 190.217, § 190.219 or § 190.233 if both violations are based on the same act.
In determining the amount of a civil penalty under this part,
(a) The Associate Administrator, OPS shall consider:
(1) The nature, circumstances and gravity of the violation, including adverse impact on the environment;
(2) The degree of the respondent's culpability;
(3) The respondent's history of prior offenses;
(4) The respondent's ability to pay;
(5) Any good faith by the respondent in attempting to achieve compliance;
(6) The effect on the respondent's ability to continue in business; and
(b) The Associate Administrator, OPS may consider:
(1) The economic benefit gained from violation, if readily ascertainable, without any reduction because of subsequent damages; and
(2) Such other matters as justice may require.
(a) Except for payments exceeding $10,000, payment of a civil penalty proposed or assessed under this subpart may be made by certified check or money order (containing the CPF Number for the case), payable to “U.S. Department of Transportation,” to the Federal Aviation Administration, Mike Monroney Aeronautical Center, Financial Operations Division (AMZ-341), P.O. Box 25770, Oklahoma City, OK 73125, or by wire transfer through the Federal Reserve Communications System (Fedwire) to the account of the U.S. Treasury. Payments exceeding $10,000 must be made by wire transfer.
(b) Payment of a civil penalty assessed in a final order issued under § 190.213 or affirmed in a decision on a petition for reconsideration must be made within 20 days after receipt of the final order or decision. Failure to do so will result in the initiation of collection action, including the accrual of interest and penalties, in accordance with 31 U.S.C. 3717 and 49 CFR part 89.
(a) Any person who willfully and knowingly violates a provision of 49 U.S.C. 60101
(b) Any person who willfully violates a regulation or order under this subchapter issued under the authority of 49 U.S.C. 5101
(c) Any person who willfully and knowingly injures or destroys, or attempts to injure or destroy, any interstate transmission facility, any interstate pipeline facility, or any intrastate pipeline facility used in interstate or foreign commerce or in any activity affecting interstate or foreign commerce (as those terms are defined in 49 U.S.C. 60101
(d) Any person who willfully and knowingly defaces, damages, removes, destroys any pipeline sign, right-of-way marker, or marine buoy required by 49 U.S.C. 60101
(e) Any person who willfully and knowingly engages in excavation activity without first using an available one-call notification system to establish the location of underground facilities in the excavation area; or without considering location information or markings established by a pipeline facility operator; and
(1) Subsequently damages a pipeline facility resulting in death, serious bodily harm, or property damage exceeding $50,000;
(2) Subsequently damages a pipeline facility and knows or has reason to know of the damage but fails to promptly report the damage to the operator and to the appropriate authorities; or
(3) Subsequently damages a hazardous liquid pipeline facility that results in the release of more than 50 barrels of product; shall, upon conviction, be subject for each offense to a fine of not more than $5,000, imprisonment for a term not to exceed 5 years, or both.
(f) No person shall be subject to criminal penalties under paragraph (a) of this section for violation of any regulation and the violation of any order issued under § 190.217, § 190.219 or § 190.229 if both violations are based on the same act.
If an employee of the Pipeline and Hazardous Materials Safety Administration becomes aware of any actual or possible activity subject to criminal penalties under § 190.229, the employee reports it to the Office of the Chief Counsel, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Washington, DC 20590. The Chief Counsel refers the report to OPS for investigation. Upon completion of the investigation and if appropriate, the Chief Counsel refers the report to the Department of Justice for criminal prosecution of the offender.
(a) Except as provided by paragraph (b) of this section, if the Associate Administrator, OPS finds, after reasonable notice and opportunity for hearing in accord with paragraph (c) of this section and § 190.211(a), a particular pipeline facility to be hazardous to life, property, or the environment, the Associate Administrator, OPS shall issue an order pursuant to this section requiring the owner or operator of the facility to take corrective action. Corrective action may include suspended or restricted use of the facility, physical inspection, testing, repair, replacement, or other appropriate action.
(b) The Associate Administrator, OPS may waive the requirement for notice and opportunity for hearing under paragraph (a) of this section before issuing an order pursuant to this section when the Associate Administrator, OPS determines that the failure to do so would result in the likelihood of serious harm to life, property, or the environment. However, the Associate Administrator, OPS shall provide an opportunity for a hearing as soon as is
(c) Notice and hearing:
(1) Written notice that OPS intends to issue an order under this section shall be served upon the owner or operator of an alleged hazardous facility in accordance with § 190.5. The notice shall allege the existence of a hazardous facility and state the facts and circumstances supporting the issuance of a corrective action order. The notice shall also provide the owner or operator with the opportunity for a hearing and shall identify a time and location where a hearing may be held.
(2) An owner or operator that elects to exercise its opportunity for a hearing under this section must notify the Associate Administrator, OPS of that election in writing within 10 days of service of the notice provided under paragraph (c)(1) of this section, or under paragraph (b) of this section when applicable. The absence of such written notification waives an owner or operator's opportunity for a hearing and allows the Associate Administrator, OPS to issue a corrective action order in accordance with paragraphs (d) through (h) of this section.
(3) A hearing under this section shall be presided over by an attorney from the Office of Chief Counsel, Pipeline and Hazardous Materials Safety Administration, acting as Presiding Official, and conducted without strict adherence to formal rules of evidence. The Presiding Official presents the allegations contained in the notice issued under this section. The owner or operator of the alleged hazardous facility may submit any relevant information or materials, call witnesses, and present arguments on the issue of whether or not a corrective action order should be issued.
(4) Within 48 hours after conclusion of a hearing under this section, the Presiding Official shall submit a recommendation to the Associate Administrator, OPS as to whether or not a corrective action order is required. Upon receipt of the recommendation, the Associate Administrator, OPS shall proceed in accordance with paragraphs (d) through (h) of this section. If the Associate Administrator, OPS finds the facility is or would be hazardous to life, property, or the environment, the Associate Administrator, OPS shall issue a corrective action order in accordance with this section. If the Associate Administrator, OPS does not find the facility is or would be hazardous to life, property, or the environment, the Associate Administrator shall withdraw the allegation of the existence of a hazardous facility contained in the notice, and promptly notify the owner or operator in writing by service as prescribed in § 190.5.
(d) The Associate Administrator, OPS may find a pipeline facility to be hazardous under paragraph (a) of this section:
(1) If under the facts and circumstances the Associate Administrator, OPS determines the particular facility is hazardous to life, property, or the environment; or
(2) If the pipeline facility or a component thereof has been constructed or operated with any equipment, material, or technique which the Associate Administrator, OPS determines is hazardous to life, property, or the environment, unless the operator involved demonstrates to the satisfaction of the Associate Administrator, OPS that, under the particular facts and circumstances involved, such equipment, material, or technique is not hazardous.
(e) In making a determination under paragraph (d) of this section, the Associate Administrator, OPS shall consider, if relevant:
(1) The characteristics of the pipe and other equipment used in the pipeline facility involved, including its age, manufacturer, physical properties (including its resistance to corrosion and deterioration), and the method of its manufacture, construction or assembly;
(2) The nature of the materials transported by such facility (including their corrosive and deteriorative qualities),
(3) The characteristics of the geographical areas in which the pipeline facility is located, in particular the climatic and geologic conditions (including soil characteristics) associated with such areas, and the population density and population and growth patterns of such areas;
(4) Any recommendation of the National Transportation Safety Board issued in connection with any investigation conducted by the Board; and
(5) Such other factors as the Associate Administrator, OPS may consider appropriate.
(f) A corrective action order shall contain the following information:
(1) A finding that the pipeline facility is hazardous to life, property, or the environment.
(2) The relevant facts which form the basis of that finding.
(3) The legal basis for the order.
(4) The nature and description of any particular corrective action required of the respondent.
(5) The date by which the required corrective action must be taken or completed and, where appropriate, the duration of the order.
(6) If the opportunity for a hearing was waived pursuant to paragraph (b) of this section, a statement that an opportunity for a hearing will be available at a particular time and location after issuance of the order.
(g) The Associate Administrator, OPS shall rescind or suspend a corrective action order whenever the Associate Administrator, OPS determines that the facility is no longer hazardous to life, property, or the environment. When appropriate, however, such a rescission or suspension may be accompanied by a notice of probable violation issued under § 190.207.
(h) At any time after a corrective action order issued under this section has become effective, the Associate Administrator, OPS may request the Attorney General to bring an action for appropriate relief in accordance with § 190.235.
(i) Upon petition by the Attorney General, the District Courts of the United States shall have jurisdiction to enforce orders issued under this section by appropriate means.
Whenever it appears to the Associate Administrator, OPS that a person has engaged, is engaged, or is about to engage in any act or practice constituting a violation of any provision of 49 U.S.C. 60101
(a) A Regional Director begins a proceeding to determine whether an operator's plans or procedures required under parts 192, 193, 195, and 199 of this subchapter are inadequate to assure safe operation of a pipeline facility by issuing a notice of amendment. The notice shall provide an opportunity for a hearing under § 190.211 of this part and shall specify the alleged inadequacies and the proposed action for revision of the plans or procedures. The notice shall allow the operator 30 days after receipt of the notice to submit written comments or request a hearing. After considering all material presented in writing or at the hearing, the Associate Administrator, OPS shall determine whether the plans or procedures are inadequate as alleged and order the required amendment if they are inadequate, or withdraw the notice if they are not. In determining the adequacy of an operator's plans or procedures, the Associate Administrator, OPS shall consider:
(1) Relevant available pipeline safety data;
(2) Whether the plans or procedures are appropriate for the particular type of pipeline transportation or facility, and for the location of the facility;
(3) The reasonableness of the plans or procedures; and
(4) The extent to which the plans or procedures contribute to public safety.
(b) The amendment of an operator's plans or procedures prescribed in paragraph (a) of this section is in addition to, and may be used in conjunction with, the appropriate enforcement actions prescribed in this subpart.
(a) When may PHMSA issue a safety order? If the Associate Administrator, OPS finds, after notice and an opportunity for hearing under paragraph (b) of this section, that a particular pipeline facility has a condition or conditions that pose a pipeline integrity risk to public safety, property, or the environment, the Associate Administrator may issue an order requiring the operator of the facility to take necessary corrective action. Such action may include physical inspection, testing, repair or other appropriate action to remedy the identified risk condition.
(b) How is an operator notified of the proposed issuance of a safety order and what are its response options? (1)
(2)
(3)
(4)
(5)
(6)
(c) How is the determination made that a pipeline facility has a condition that poses an integrity risk? The Associate Administrator, OPS may find a pipeline facility to have a condition that poses a pipeline integrity risk to public safety, property, or the environment under paragraph (a) of this section:
(1) If under the facts and circumstances the Associate Administrator determines the particular facility has such a condition; or
(2) If the pipeline facility or a component thereof has been constructed or operated with any equipment, material, or technique with a history of being susceptible to failure when used in pipeline service, unless the operator involved demonstrates that such equipment, material, or technique is not susceptible to failure given the manner it is being used for a particular facility.
(d) What factors must PHMSA consider in making a determination that a risk condition is present? In making a determination under paragraph (c) of this section, the Associate Administrator, OPS shall consider, if relevant:
(1) The characteristics of the pipe and other equipment used in the pipeline facility involved, including its age, manufacturer, physical properties (including its resistance to corrosion and deterioration), and the method of its manufacture, construction or assembly;
(2) The nature of the materials transported by such facility (including their corrosive and deteriorative qualities), the sequence in which such materials are transported, and the pressure required for such transportation;
(3) The characteristics of the geographical areas where the pipeline facility is located, in particular the climatic and geologic conditions (including soil characteristics) associated with such areas;
(4) For hazardous liquid pipelines, the proximity of the pipeline to an unusually sensitive area;
(5) The population density and growth patterns of the area in which the pipeline facility is located;
(6) Any relevant recommendation of the National Transportation Safety Board issued in connection with any investigation conducted by the Board;
(7) The likelihood that the condition will impair the serviceability of the pipeline;
(8) The likelihood that the condition will worsen over time; and
(9) The likelihood that the condition is present or could develop on other areas of the pipeline.
(e) What information will be included in a safety order? A safety order shall contain the following:
(1) A finding that the pipeline facility has a condition that poses a pipeline integrity risk to public safety, property, or the environment;
(2) The relevant facts which form the basis of that finding;
(3) The legal basis for the order;
(4) The nature and description of any particular corrective actions to be required of the operator; and
(5) The date(s) by which the required corrective actions must be taken or completed and, where appropriate, the duration of the order.
(f) Can PHMSA take other enforcement actions on the affected facilities? Nothing in this section precludes PHMSA from issuing a Notice of Probable Violation under § 190.207 or taking other enforcement action if noncompliance is identified at the facilities that are the subject of a safety order proceeding.
This subpart prescribes general rulemaking procedures for the issue, amendment, and repeal of Pipeline Safety Program regulations of the Pipeline and Hazardous Materials Safety Administration of the Department of Transportation.
For the purposes of this subpart,
(a) Information and data considered relevant by the Administrator relating to rulemaking actions, including notices of proposed rulemaking; comments received in response to notices; petitions for rulemaking and reconsideration; denials of petitions for rulemaking and reconsideration; records of additional rulemaking proceedings under § 190.325; and final regulations are maintained by the Pipeline and Hazardous Materials Safety Administration at 1200 New Jersey Avenue, SE, Washington, D.C. 20590-0001.
(b) Once a public docket is established, docketed material may be accessed at
Records of the Pipeline and Hazardous Materials Safety Administration relating to rulemaking proceedings are available for inspection as provided in section 552(b) of title 5, United States Code, and part 7 of the Regulations of the Office of the Secretary of Transportation (part 7 of this title).
Petitions for extension of time to comment submitted under § 190.319, petitions for hearings submitted under § 190.327, petitions for rulemaking submitted under § 190.331, and petitions for reconsideration submitted under § 190.335 must be submitted to: Administrator, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue, SE, Washington, D.C. 20590-0001.
Unless the Administrator, for good cause, finds that notice is impracticable, unnecessary, or contrary to the public interest, and incorporates that finding and a brief statement of the reasons for it in the rule, a notice of proposed rulemaking is issued and interested persons are invited to participate in the rulemaking proceedings with respect to each substantive rule.
The Administrator initiates rulemaking on his or her own motion; however, in so doing, the Administrator may use discretion to consider the recommendations of other agencies of the United States or of other interested persons including those of any technical advisory body established by statute for that purpose.
(a) Each notice of proposed rulemaking is published in the
(b) Each notice, whether published in the
(1) A statement of the time, place, and nature of the proposed rulemaking proceeding;
(2) A reference to the authority under which it is issued;
(3) A description of the subjects and issues involved or the substance and terms of the proposed regulation;
(4) A statement of the time within which written comments must be submitted; and
(5) A statement of how and to what extent interested persons may participate in the proceeding.
(a) Any interested person may participate in rulemaking proceedings by submitting comments in writing containing information, views or arguments in accordance with instructions for participation in the rulemaking document.
(b) The Administrator may invite any interested person to participate in the rulemaking proceedings described in § 190.325.
(c) For the purposes of this subpart, an interested person includes any Federal or State government agency or any political subdivision of a State.
A petition for extension of the time to submit comments must be received not later than 10 days before expiration of the time stated in the notice. It is requested, but not required, that three copies be submitted. The filing of the petition does not automatically extend the time for petitioner's comments. A petition is granted only if the petitioner shows good cause for the extension, and if the extension is consistent with the public interest. If an extension is granted, it is granted to all persons, and it is published in the
All written comments must be in English. It is requested, but not required, that five copies be submitted. Any interested person should submit as part of written comments all material considered relevant to any statement of fact. Incorporation of material by reference should be avoided; however, where necessary, such incorporated material shall be identified by document title and page.
All timely comments and the recommendations of any technical advisory body established by statute for the purpose of reviewing the proposed rule concerned are considered before final action is taken on a rulemaking proposal. Late filed comments are considered so far as practicable.
The Administrator may initiate any further rulemaking proceedings that the Administrator finds necessary or desirable. For example, interested persons may be invited to make oral arguments, to participate in conferences between the Administrator or the Administrator's representative and interested persons, at which minutes of the conference are kept, to appear at informal hearings presided over by officials designated by the Administrator at which a transcript of minutes are kept, or participate in any other proceeding to assure informed administrative action and to protect the public interest.
(a) If a notice of proposed rulemaking does not provide for a hearing, any interested person may petition the Administrator for an informal hearing. The petition must be received by the Administrator not later than 20 days before expiration of the time stated in the notice. The filing of the petition does not automatically result in the scheduling of a hearing. A petition is granted only if the petitioner shows good cause for a hearing. If a petition for a hearing is granted, notice of the hearing is published in the
(b) Sections 556 and 557 of title 5, United States Code, do not apply to hearings held under this part. Unless otherwise specified, hearings held under this part are informal, nonadversary fact-finding proceedings, at which there are no formal pleadings or adverse parties. Any regulation issued in a case in which an informal hearing is held is not necessarily based exclusively on the record of the hearing.
(c) The Administrator designates a representative to conduct any hearing held under this subpart. The Chief Counsel designates a member of his or her staff to serve as legal officer at the hearing.
Final rules are prepared by representatives of the Office of Pipeline Safety and the Office of the Chief Counsel. The regulation is then submitted to the Administrator for consideration. If the Administrator adopts the regulation, it is published in the
(a) Any interested person may petition the Associate Administrator for Pipeline Safety to establish, amend, or repeal a substantive regulation, or may petition the Chief Counsel to establish, amend, or repeal a procedural regulation.
(b) Each petition filed under this section must—
(1) Summarize the proposed action and explain its purpose;
(2) State the text of the proposed rule or amendment, or specify the rule proposed to be repealed;
(3) Explain the petitioner's interest in the proposed action and the interest of any party the petitioner represents; and
(4) Provide information and arguments that support the proposed action, including relevant technical, scientific or other data as available to the petitioner, and any specific known cases that illustrate the need for the proposed action.
(c) If the potential impact of the proposed action is substantial, and information and data related to that impact are available to the petitioner, the Associate Administrator or the Chief Counsel may request the petitioner to provide—
(1) The costs and benefits to society and identifiable groups within society, quantifiable and otherwise;
(2) The direct effects (including preemption effects) of the proposed action on States, on the relationship between the Federal Government and the States, and on the distribution of power and responsibilities among the various levels of government;
(3) The regulatory burden on small businesses, small organizations and small governmental jurisdictions;
(4) The recordkeeping and reporting requirements and to whom they would apply; and
(5) Impacts on the quality of the natural and social environments.
(d) The Associate Administrator or Chief Counsel may return a petition that does not comply with the requirements of this section, accompanied by a written statement indicating the deficiencies in the petition.
(a)
(b)
(c)
(d)
(a) Except as provided in § 190.339(d), any interested person may petition the Associate Administrator for reconsideration of any regulation issued under this subpart, or may petition the Chief Counsel for reconsideration of any procedural regulation issued under this subpart and contained in this subpart. It is requested, but not required, that three copies be submitted. The petition must be received not later than 30 days after publication of the rule in the
(b) If the petitioner requests the consideration of additional facts, the petitioner must state the reason they were not presented to the Associate Administrator or the Chief Counsel within the prescribed time.
(c) The Associate Administrator or the Chief Counsel does not consider repetitious petitions.
(d) Unless the Associate Administrator or the Chief Counsel otherwise provides, the filing of a petition under this section does not stay the effectiveness of the rule.
(a) The Associate Administrator or the Chief Counsel may grant or deny, in whole or in part, any petition for reconsideration without further proceedings, except where a grant of the petition would result in issuance of a new final rule. In the event that the Associate Administrator or the Chief Counsel determines to reconsider any regulation, a final decision on reconsideration may be issued without further proceedings, or an opportunity to submit comment or information and data as deemed appropriate, may be provided. Whenever the Associate Administrator or the Chief Counsel determines that a petition should be granted or denied, the Office of the Chief Counsel prepares a notice of the grant or denial of a petition for reconsideration, for issuance to the petitioner, and the Associate Administrator or the Chief Counsel issues it to the petitioner. The Associate Administrator or the Chief Counsel may consolidate petitions relating to the same rules.
(b) It is the policy of the Associate Administrator or the Chief Counsel to issue notice of the action taken on a petition for reconsideration within 90 days after the date on which the regulation in question is published in the
(a) Any interested person may appeal a denial of the Associate Administrator or the Chief Counsel, issued under § 190.333 or § 190.337, to the Administrator.
(b) An appeal must be received within 20 days of service of written notice to petitioner of the Associate Administrator's or the Chief Counsel's decision, or within 20 days from the date of publication of the decision in the
(c) It is requested, but not required, that three copies of the appeal be submitted to the Administrator.
(d) Unless the Administrator otherwise provides, the filing of an appeal under this section does not stay the effectiveness of any rule.
(a) Where practicable, the Administrator will use direct final rulemaking to issue the following types of rules:
(1) Minor, substantive changes to regulations;
(2) Incorporation by reference of the latest edition of technical or industry standards;
(3) Extensions of compliance dates; and
(4) Other noncontroversial rules where the Administrator determines that use of direct final rulemaking is in the public interest, and that a regulation is unlikely to result in adverse comment.
(b) The direct final rule will state an effective date. The direct final rule will also state that unless an adverse comment or notice of intent to file an adverse comment is received within the specified comment period, generally 60 days after publication of the direct final rule in the
(c) For purposes of this section, an adverse comment is one which explains why the rule would be inappropriate, including a challenge to the rule's underlying premise or approach, or would be ineffective or unacceptable without a change. Comments that are frivolous or insubstantial will not be considered adverse under this procedure. A comment recommending a rule change in addition to the rule will not be considered an adverse comment, unless the commenter states why the rule would be ineffective without the additional change.
(d) Only parties who filed comments to a direct final rule issued under this section may petition under § 190.335 for reconsideration of that direct final rule.
(e) If an adverse comment or notice of intent to file an adverse comment is received, a timely document will be published in the
(a) What is a special permit? A special permit is an order by which PHMSA waives compliance with one or more of the Federal pipeline safety regulations under the standards set forth in 49 U.S.C. 60118(c) and subject to conditions set forth in the order. A special permit is issued to a pipeline operator
(b) How do I apply for a special permit? Applications for special permits must be submitted at least 120 days before the requested effective date using any of the following methods:
(1) Direct fax to PHMSA at: 202-366-4566; or
(2) Mail, express mail, or overnight courier to the Associate Administrator for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., East Building, Washington, DC 20590.
(c) What information must be contained in the application? Applications must contain the following information:
(1) The name, mailing address, and telephone number of the applicant and whether the applicant is an operator;
(2) A detailed description of the pipeline facilities for which the special permit is sought, including:
(i) The beginning and ending points of the pipeline mileage to be covered and the Counties and States in which it is located;
(ii) Whether the pipeline is interstate or intrastate and a general description of the right-of-way including proximity of the affected segments to populated areas and unusually sensitive areas;
(iii) Relevant pipeline design and construction information including the year of installation, the material, grade, diameter, wall thickness, and coating type; and
(iv) Relevant operating information including operating pressure, leak history, and most recent testing or assessment results;
(3) A list of the specific regulation(s) from which the applicant seeks relief;
(4) An explanation of the unique circumstances that the applicant believes make the applicability of that regulation or standard (or portion thereof) unnecessary or inappropriate for its facility;
(5) A description of any measures or activities the applicant proposes to undertake as an alternative to compliance with the relevant regulation, including an explanation of how such measures will mitigate any safety or environmental risks;
(6) A description of any positive or negative impacts on affected stakeholders and a statement indicating how operating the pipeline pursuant to a special permit would be in the public interest;
(7) A certification that operation of the applicant's pipeline under the requested special permit would not be inconsistent with pipeline safety;
(8) If the application is for a renewal of a previously granted waiver or special permit, a copy of the original grant of the waiver or permit; and
(9) Any other information PHMSA may need to process the application including environmental analysis where necessary.
(d) How does PHMSA handle special permit applications? (1)
(2)
(e) Can a special permit be requested on an emergency basis? Yes. PHMSA may grant an application for an emergency special permit without notice
(f) How do I apply for an emergency special permit? Applications for emergency special permits may be submitted to PHMSA using any of the following methods:
(1) Direct fax to the Crisis Management Center at: 202-366-3768;
(2) Direct e-mail to PHMSA at:
(3) Express mail/overnight courier to the Associate Administrator for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., East Building, Washington, DC 20590.
(g) What must be contained in an application for an emergency special permit? In addition to the information required under paragraph (c) of this section, applications for emergency special permits must include:
(1) An explanation of the actual or impending emergency and how the applicant is affected;
(2) A citation of the regulations that are implicated and the specific reasons the permit is necessary to address the emergency (e.g., lack of accessibility, damaged equipment, insufficient manpower);
(3) A statement indicating how operating the pipeline pursuant to an emergency special permit is in the public interest (e.g., continuity of service, service restoration);
(4) A description of any proposed alternatives to compliance with the regulation (e.g., additional inspections and tests, shortened reassessment intervals); and
(5) A description of any measures to be taken after the emergency situation or permit expires—whichever comes first—to confirm long-term operational reliability of the pipeline facility.
If PHMSA determines that handling of the application on an emergency basis is not warranted, PHMSA will notify the applicant and process the application under normal special permit procedures of this section.
(h) In what circumstances will PHMSA revoke, suspend, or modify a special permit?
(1) PHMSA may revoke, suspend, or modify a special permit on a finding that:
(i) Intervening changes in Federal law mandate revocation, suspension, or modification of the special permit;
(ii) Based on a material change in conditions or circumstances, continued adherence to the terms of the special permit would be inconsistent with safety;
(iii) The application contained inaccurate or incomplete information, and the special permit would not have been granted had the application been accurate and complete;
(iv) The application contained deliberately inaccurate or incomplete information; or
(v) The holder has failed to comply with any material term or condition of the special permit.
(2) Except as provided in paragraph (h)(3) of this section, before a special permit is modified, suspended or revoked, PHMSA will notify the holder in writing of the proposed action and the reasons for it, and provide an opportunity to show cause why the proposed action should not be taken.
(i) The holder may file a written response that shows cause why the proposed action should not be taken within 30 days of receipt of notice of the proposed action.
(ii) After considering the holder's written response, or after 30 days have passed without response since receipt of the notice, PHMSA will notify the holder in writing of the final decision with a brief statement of reasons.
(3) If necessary to avoid a risk of significant harm to persons, property, or the environment, PHMSA may in the notification declare the proposed action immediately effective.
(4) Unless otherwise specified, the terms and conditions of a corrective action order, compliance order, or other order applicable to a pipeline facility covered by a special permit will take precedence over the terms of the special permit.
(5) A special permit holder may seek reconsideration of a decision under paragraph (h) of this section as provided in paragraph (i) of this section.
(i) Can a denial of a request for a special permit or a revocation of an existing special permit be appealed? Reconsideration of the denial of an application for a special permit or a revocation of an existing special permit may be sought by petition to the Associate Administrator. Petitions for reconsideration must be received by PHMSA within 20 calendar days of the notice of the grant or denial and must contain a brief statement of the issue and an explanation of why the petitioner believes that the decision being appealed is not in the public interest. The Associate Administrator may grant or deny, in whole or in part, any petition for reconsideration without further proceedings. The Associate Administrator's decision is the final administrative action.
(j) Are documents related to an application for a special permit available for public inspection? Documents related to an application, including the application itself, are available for public inspection on regulations.gov or the Docket Operations Facility to the extent such documents do not include information exempt from public disclosure under 5 U.S.C. 552(b). Applicants may request confidential treatment under part 7 of this title.
49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, and 60124; and 49 CFR 1.53.
(a) This part prescribes requirements for the reporting of incidents, safety-related conditions, and annual pipeline summary data by operators of gas pipeline facilities located in the United States or Puerto Rico, including pipelines within the limits of the Outer Continental Shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331).
(b) This part does not apply to—
(1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are produced or where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream;
(2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters
(3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator; or
(4) Onshore gathering of gas outside of the following areas:
(i) An area within the limits of any incorporated or unincorporated city, town, or village.
(ii) Any designated residential or commercial area such as a subdivision, business or shopping center, or community development.
As used in this part and the PHMSA Forms referenced in this part—
(1) An event that involves a release of gas from a pipeline or of liquefied natural gas or gas from an LNG facility and
(i) A death, or personal injury necessitating in-patient hospitalization; or
(ii) Estimated property damage, including cost of gas lost, of the operator or others, or both, of $50,000 or more.
(2) An event that results in an emergency shutdown of an LNG facility.
(3) An event that is significant, in the judgement of the operator, even though it did not meet the criteria of paragraphs (1) or (2).
(a) At the earliest practicable moment following discovery, each operator shall give notice in accordance with paragraph (b) of this section of each incident as defined in § 191.3.
(b) Each notice required by paragraph (a) of this section shall be made by telephone to 800-424-8802 (in Washington, DC, 267-2675) and shall include the following information.
(1) Names of operator and person making report and their telephone numbers.
(2) The location of the incident.
(3) The time of the incident.
(4) The number of fatalities and personal injuries, if any.
(5) All other significant facts that are known by the operator that are relevant to the cause of the incident or extent of the damages.
Each written report required by this part must be made to Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, the Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. However, incident and annual reports for intrastate pipeline transportation subject to the jurisdiction of a State agency pursuant to a certification under section 5(a) of the Natural Gas Pipeline Safety Act of 1968 may be submitted in duplicate to that State agency if the regulations of that agency require submission of these reports and provide for further transmittal of one copy within 10 days of receipt for incident reports and not later than March 15 for annual reports to the Information Resources Manager. Safety-related condition reports required by § 191.23 for intrastate pipeline transportation must be submitted concurrently to that State agency, and if that agency acts as an agent of the Secretary with respect to interstate transmission facilities, safety-related condition reports for these facilities must be submitted concurrently to that agency.
(a) Except as provided in paragraph (c) of this section, each operator of a distribution pipeline system shall submit Department of Transportation Form RSPA F 7100.1 as soon as practicable but not more than 30 days after detection of an incident required to be reported under § 191.5.
(b) When additional relevant information is obtained after the report is submitted under paragraph (a) of this section, the operator shall make supplementary reports as deemed necessary with a clear reference by date and subject to the original report.
(c) The incident report required by this section need not be submitted with respect to master meter systems or LNG facilities.
(a) Except as provided in paragraph (b) of this section, each operator of a distribution pipeline system shall submit an annual report for that system on Department of Transportation Form RSPA F 7100.1-1. This report must be submitted each year, not later than March 15, for the preceding calendar year.
(b) The annual report required by this section need not be submitted with respect to:
(1) Petroleum gas systems which serve fewer than 100 customers from a single source;
(2) Master meter systems; or
(3) LNG facilities.
Each operator, primarily engaged in gas distribution, who also operates gas transmission or gathering pipelines shall submit separate reports for these pipelines as required by §§ 191.15 and 191.17. Each operator, primarily engaged in gas transmission or gathering, who also operates gas distribution pipelines shall submit separate reports for these pipelines as required by §§ 191.9 and 191.11.
(a) Except as provided in paragraph (c) of this section, each operator of a transmission or a gathering pipeline system shall submit Department of Transportation Form RSPA F 7100.2 as soon as practicable but not more than 30 days after detection of an incident required to be reported under § 191.5.
(b) Where additional related information is obtained after a report is submitted under paragraph (a) of this section, the operator shall make a supplemental report as soon as practicable with a clear reference by date and subject to the original report.
(c) The incident report required by paragraph (a) of this section need not be submitted with respect to LNG facilities.
(a) Except as provided in paragraph (b) of this section, each operator of a transmission or a gathering pipeline system shall submit an annual report for that system on Department of Transportation Form RSPA 7100.2-1. This report must be submitted each year, not later than March 15, for the preceding calendar year.
(b) The annual report required by paragraph (a) of this section need not be submitted with respect to LNG facilities.
Copies of the prescribed report forms are available without charge upon request from the address given in § 191.7. Additional copies in this prescribed format may be reproduced and used if in the same size and kind of paper. In addition, the information required by these forms may be submitted by any other means that is acceptable to the Administrator.
This section displays the control number assigned by the Office of Management and Budget (OMB) to the gas pipeline information collection requirements of the Office of Pipeline Safety pursuant to the Paperwork Reduction Act of 1980, Public Law 96-511. It is the intent of this section to comply with the requirements of section 3507(f) of the Paperwork Reduction Act which requires that agencies display a current control number assigned by the Director of OMB for each agency information collection requirement.
(a) Except as provided in paragraph (b) of this section, each operator shall report in accordance with § 191.25 the existence of any of the following safety-related conditions involving facilities in service:
(1) In the case of a pipeline (other than an LNG facility) that operates at a hoop stress of 20 percent or more of its specified minimum yield strength,
(2) Unintended movement or abnormal loading by environmental causes, such as an earthquake, landslide, or flood, that impairs the serviceability of a pipeline or the structural integrity or reliability of an LNG facility that contains, controls, or processes gas or LNG.
(3) Any crack or other material defect that impairs the structural integrity or reliability of an LNG facility that contains, controls, or processes gas or LNG.
(4) Any material defect or physical damage that impairs the serviceability of a pipeline that operates at a hoop stress of 20 percent or more of its specified minimum yield strength.
(5) Any malfunction or operating error that causes the pressure of a pipeline or LNG facility that contains or processes gas or LNG to rise above its maximum allowable operating pressure (or working pressure for LNG facilities) plus the build-up allowed for operation of pressure limiting or control devices.
(6) A leak in a pipeline or LNG facility that contains or processes gas or LNG that constitutes an emergency.
(7) Inner tank leakage, ineffective insulation, or frost heave that impairs the structural integrity of an LNG storage tank.
(8) Any safety-related condition that could lead to an imminent hazard and causes (either directly or indirectly by remedial action of the operator), for purposes other than abandonment, a 20 percent or more reduction in operating pressure or shutdown of operation of a pipeline or an LNG facility that contains or processes gas or LNG.
(b) A report is not required for any safety-related condition that—
(1) Exists on a master meter system or a customer-owned service line;
(2) Is an incident or results in an incident before the deadline for filing the safety-related condition report;
(3) Exists on a pipeline (other than an LNG facility) that is more than 220 yards (200 meters) from any building intended for human occupancy or outdoor place of assembly, except that reports are required for conditions within the right-of-way of an active railroad, paved road, street, or highway; or
(4) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report, except that reports are required for conditions under paragraph (a)(1) of this section other than localized corrosion pitting on an effectively coated and cathodically protected pipeline.
(a) Each report of a safety-related condition under § 191.23(a) must be filed (received by the Associate Administrator, OPS) in writing within five working days (not including Saturday, Sunday, or Federal Holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reports may be transmitted by facsimile at (202) 366-7128.
(b) The report must be headed “Safety-Related Condition Report” and provide the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person submitting the report.
(4) Name, job title, and business telephone number of person who determined that the condition exists.
(5) Date condition was discovered and date condition was first determined to exist.
(6) Location of condition, with reference to the State (and town, city, or county) or offshore site, and as appropriate, nearest street address, offshore platform, survey station number, milepost, landmark, or name of pipeline.
(7) Description of the condition, including circumstances leading to its discovery, any significant effects of the
(8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned follow-up or future corrective action, including the anticipated schedule for starting and concluding such action.
(a) Each operator shall, within 60 days after completion of the inspection of all its underwater pipelines subject to § 192.612(a), report the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person submitting the report.
(4) Total length of pipeline inspected.
(5) Length and date of installation of each exposed pipeline segment, and location, including, if available, the location according to the Minerals Management Service or state offshore area and block number tract.
(6) Length and date of installation of each pipeline segment, if different from a pipeline segment identified under paragraph (a)(5) of this section, that is a hazard to navigation, and the location, including, if available, the location according to the Minerals Management Service or state offshore area and block number tract.
(b) The report shall be mailed to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue SE., Washington, DC 20590-0001.
49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, and 60118; and 49 CFR 1.53.
Nomenclature changes to part 192 appear at 71 FR 33406, June 9, 2006.
(a) This part prescribes minimum safety requirements for pipeline facilities and the transportation of gas, including pipeline facilities and the transportation of gas within the limits of the outer continental shelf as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331).
(b) This part does not apply to—
(1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are
(2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters without first connecting to a transporting operator's facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS may petition the Administrator, or designee, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9;
(3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator;
(4) Onshore gathering of gas—
(i) Through a pipeline that operates at less than 0 psig (0 kPa);
(ii) Through a pipeline that is not a regulated onshore gathering line (as determined in § 192.8); and
(iii) Within inlets of the Gulf of Mexico, except for the requirements in § 192.612; or
(5) Any pipeline system that transports only petroleum gas or petroleum gas/air mixtures to—
(i) Fewer than 10 customers, if no portion of the system is located in a public place; or
(ii) A single customer, if the system is located entirely on the customer's premises (no matter if a portion of the system is located in a public place).
As used in this part:
(1) For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification; or
(2) For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with § 192.107(b).
A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.
(a) This section classifies pipeline locations for purposes of this part. The following criteria apply to classifications under this section.
(1) A “class location unit” is an onshore area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1- mile (1.6 kilometers) length of pipeline.
(2) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy.
(b) Except as provided in paragraph (c) of this section, pipeline locations are classified as follows:
(1) A Class 1 location is:
(i) An offshore area; or
(ii) Any class location unit that has 10 or fewer buildings intended for human occupancy.
(2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy.
(3) A Class 3 location is:
(i) Any class location unit that has 46 or more buildings intended for human occupancy; or
(ii) An area where the pipeline lies within 100 yards (91 meters) of either a building or a small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) that is occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need not be consecutive.)
(4) A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent.
(c) The length of Class locations 2, 3, and 4 may be adjusted as follows:
(1) A Class 4 location ends 220 yards (200 meters) from the nearest building with four or more stories above ground.
(2) When a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends 220 yards (200 meters) from the nearest building in the cluster.
(a) Any documents or portions thereof incorporated by reference in this part are included in this part as though set out in full. When only a portion of a document is referenced, the remainder is not incorporated in this part.
(b) All incorporated materials are available for inspection in the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., Washington, DC, 20590-0001, or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030 or go to:
(c) The full titles of documents incorporated by reference, in whole or in part, are provided herein. The numbers in parentheses indicate applicable editions. For each incorporated document, citations of all affected sections are provided. Earlier editions of currently listed documents or editions of documents listed in previous editions of 49 CFR part 192 may be used for materials and components designed, manufactured, or installed in accordance with these earlier documents at the time they were listed. The user must refer to the appropriate previous edition of
(1)
A. Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX 77098.
B. American Petroleum Institute (API), 1220 L Street, NW., Washington, DC 20005.
C. American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, West Conshohocken, PA 19428.
D. ASME International (ASME), Three Park Avenue, New York, NY 10016-5990.
E. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park Street, NE., Vienna, VA 22180.
F. National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O. Box 9101, Quincy, MA 02269-9101.
G. Plastics Pipe Institute, Inc. (PPI), 1825 Connecticut Avenue, NW., Suite 680, Washington, DC 20009.
H. NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084.
I. Gas Technology Institute (GTI), 1700 South Mount Prospect Road, Des Plaines, IL 60018.
(2)
(a) An operator must use API RP 80 (incorporated by reference, see § 192.7), to determine if an onshore pipeline (or part of a connected series of pipelines) is an onshore gathering line. The determination is subject to the limitations listed below. After making this determination, an operator must determine if the onshore gathering line is a regulated onshore gathering line under paragraph (b) of this section.
(1) The beginning of gathering, under section 2.2(a)(1) of API RP 80, may not extend beyond the furthermost downstream point in a production operation as defined in section 2.3 of API RP 80. This furthermost downstream point does not include equipment that can be used in either production or transportation, such as separators or dehydrators, unless that equipment is involved in the processes of “production and preparation for transportation or delivery of hydrocarbon gas” within the meaning of “production operation.”
(2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 80, may not extend beyond the first downstream natural gas processing plant, unless the operator can demonstrate, using sound engineering principles, that gathering extends to a further downstream plant.
(3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API RP 80, is determined by the commingling of gas from separate production fields, the fields may not be more than 50 miles from each other, unless the Administrator finds a longer separation distance is justified in a particular case (see 49 CFR § 190.9).
(4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 80, may not extend beyond the furthermost downstream compressor used to increase gathering line pressure for delivery to another pipeline.
(b) For purposes of § 192.9, “regulated onshore gathering line” means:
(1) Each onshore gathering line (or segment of onshore gathering line) with a feature described in the second column that lies in an area described in the third column; and
(2) As applicable, additional lengths of line described in the fourth column to provide a safety buffer:
(a)
(b)
(c)
(d)
(1) If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial testing must be in accordance with requirements of this part applicable to transmission lines;
(2) If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines;
(3) Carry out a damage prevention program under § 192.614;
(4) Establish a public education program under § 192.616;
(5) Establish the MAOP of the line under § 192.619; and
(6) Install and maintain line markers according to the requirements for transmission lines in § 192.707.
(e)
(1) An operator of a new, replaced, relocated, or otherwise changed line must be in compliance with the applicable requirements of this section by the date the line goes into service, unless an exception in § 192.13 applies.
(2) If a regulated onshore gathering line existing on April 14, 2006 was not previously subject to this part, an operator has until the date stated in the second column to comply with the applicable requirement for the line listed in the first column, unless the Administrator finds a later deadline is justified in a particular case:
(3) If, after April 14, 2006, a change in class location or increase in dwelling density causes an onshore gathering line to be a regulated onshore gathering line, the operator has 1 year for Type B lines and 2 years for Type A lines after the line becomes a regulated onshore gathering line to comply with this section.
Operators of transportation pipelines on the Outer Continental Shelf (as defined in the Outer Continental Shelf Lands Act; 43 U.S.C. 1331) must identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 1998 to identify the transfer points. If it is not practicable to durably mark a transfer point and the transfer point is located above water, the operator must depict the transfer point on a schematic located near the transfer point. If a transfer point is located subsea, then the operator must identify the transfer point on a schematic which must be maintained at the nearest upstream facility and provided to PHMSA upon request. For those cases in which adjoining operators have not agreed on a transfer point by September 15, 1998 the Regional Director and the MMS Regional Supervisor will make a joint determination of the transfer point.
(a) Each plant that supplies petroleum gas by pipeline to a natural gas distribution system must meet the requirements of this part and ANSI/NFPA 58 and 59.
(b) Each pipeline system subject to this part that transports only petroleum gas or petroleum gas/air mixtures must meet the requirements of this part and of ANSI/NFPA 58 and 59.
(c) In the event of a conflict between this part and ANSI/NFPA 58 and 59, ANSI/NFPA 58 and 59 prevail.
(a) No person may operate a segment of pipeline listed in the first column that is readied for service after the date in the second column, unless:
(1) The pipeline has been designed, installed, constructed, initially inspected, and initially tested in accordance with this part; or
(2) The pipeline qualifies for use under this part according to the requirements in § 192.14.
(b) No person may operate a segment of pipeline listed in the first column that is replaced, relocated, or otherwise changed after the date in the second column, unless the replacement, relocation or change has been made according to the requirements in this part.
(c) Each operator shall maintain, modify as appropriate, and follow the plans, procedures, and programs that it is required to establish under this part.
(a) A steel pipeline previously used in service not subject to this part qualifies for use under this part if the operator prepares and follows a written procedure to carry out the following requirements:
(1) The design, construction, operation, and maintenance history of the pipeline must be reviewed and, where sufficient historical records are not available, appropriate tests must be performed to determine if the pipeline is in a satisfactory condition for safe operation.
(2) The pipeline right-of-way, all aboveground segments of the pipeline, and appropriately selected underground segments must be visually inspected for physical defects and operating conditions which reasonably could be expected to impair the strength or tightness of the pipeline.
(3) All known unsafe defects and conditions must be corrected in accordance with this part.
(4) The pipeline must be tested in accordance with subpart J of this part to substantiate the maximum allowable operating pressure permitted by subpart L of this part.
(b) Each operator must keep for the life of the pipeline a record of the investigations, tests, repairs, replacements, and alterations made under the requirements of paragraph (a) of this section.
(a) As used in this part:
(b) In this part:
(1) Words importing the singular include the plural;
(2) Words importing the plural include the singular; and
(3) Words importing the masculine gender include the feminine.
(a) This section applies to each operator of a service line who does not maintain the customer's buried piping up to entry of the first building downstream, or, if the customer's buried piping does not enter a building, up to the principal gas utilization equipment or the first fence (or wall) that surrounds that equipment. For the purpose of this section, “customer's buried piping” does not include branch lines that serve yard lanterns, pool heaters, or other types of secondary equipment. Also, “maintain” means monitor for corrosion according to § 192.465 if the customer's buried piping is metallic, survey for leaks according to § 192.723, and if an unsafe condition is found, shut off the flow of gas, advise the customer of the need to repair the unsafe condition, or repair the unsafe condition.
(b) Each operator shall notify each customer once in writing of the following information:
(1) The operator does not maintain the customer's buried piping.
(2) If the customer's buried piping is not maintained, it may be subject to the potential hazards of corrosion and leakage.
(3) Buried gas piping should be—
(i) Periodically inspected for leaks;
(ii) Periodically inspected for corrosion if the piping is metallic; and
(iii) Repaired if any unsafe condition is discovered.
(4) When excavating near buried gas piping, the piping should be located in advance, and the excavation done by hand.
(5) The operator (if applicable), plumbing contractors, and heating contractors can assist in locating, inspecting, and repairing the customer's buried piping.
(c) Each operator shall notify each customer not later than August 14, 1996, or 90 days after the customer first receives gas at a particular location, whichever is later. However, operators of master meter systems may continuously post a general notice in a prominent location frequented by customers.
(d) Each operator must make the following records available for inspection by the Administrator or a State agency
(1) A copy of the notice currently in use; and
(2) Evidence that notices have been sent to customers within the previous 3 years.
This subpart prescribes minimum requirements for the selection and qualification of pipe and components for use in pipelines.
Materials for pipe and components must be:
(a) Able to maintain the structural integrity of the pipeline under temperature and other environmental conditions that may be anticipated;
(b) Chemically compatible with any gas that they transport and with any other material in the pipeline with which they are in contact; and
(c) Qualified in accordance with the applicable requirements of this subpart.
(a) New steel pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification;
(2) It meets the requirements of—
(i) Section II of appendix B to this part; or
(ii) If it was manufactured before November 12, 1970, either section II or III of appendix B to this part; or
(3) It is used in accordance with paragraph (c) or (d) of this section.
(b) Used steel pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification and it meets the requirements of paragraph II-C of appendix B to this part;
(2) It meets the requirements of:
(i) Section II of appendix B to this part; or
(ii) If it was manufactured before November 12, 1970, either section II or III of appendix B to this part;
(3) It has been used in an existing line of the same or higher pressure and meets the requirements of paragraph II-C of appendix B to this part; or
(4) It is used in accordance with paragraph (c) of this section.
(c) New or used steel pipe may be used at a pressure resulting in a hoop stress of less than 6,000 p.s.i. (41 MPa) where no close coiling or close bending is to be done, if visual examination indicates that the pipe is in good condition and that it is free of split seams and other defects that would cause leakage. If it is to be welded, steel pipe that has not been manufactured to a listed specification must also pass the weldability tests prescribed in paragraph II-B of appendix B to this part.
(d) Steel pipe that has not been previously used may be used as replacement pipe in a segment of pipeline if it has been manufactured prior to November 12, 1970, in accordance with the same specification as the pipe used in constructing that segment of pipeline.
(e) New steel pipe that has been cold expanded must comply with the mandatory provisions of API Specification 5L.
(a) New plastic pipe is qualified for use under this part if:
(1) It is manufactured in accordance with a listed specification; and
(2) It is resistant to chemicals with which contact may be anticipated.
(b) Used plastic pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification;
(2) It is resistant to chemicals with which contact may be anticipated;
(3) It has been used only in natural gas service;
(4) Its dimensions are still within the tolerances of the specification to which it was manufactured; and
(5) It is free of visible defects.
(c) For the purpose of paragraphs (a)(1) and (b)(1) of this section, where pipe of a diameter included in a listed specification is impractical to use, pipe of a diameter between the sizes included in a listed specification may be used if it:
(1) Meets the strength and design criteria required of pipe included in that listed specification; and
(2) Is manufactured from plastic compounds which meet the criteria for material required of pipe included in that listed specification.
(a) Except as provided in paragraph (d) of this section, each valve, fitting, length of pipe, and other component must be marked—
(1) As prescribed in the specification or standard to which it was manufactured, except that thermoplastic fittings must be marked in accordance with ASTM D 2513; or
(2) To indicate size, material, manufacturer, pressure rating, and temperature rating, and as appropriate, type, grade, and model.
(b) Surfaces of pipe and components that are subject to stress from internal pressure may not be field die stamped.
(c) If any item is marked by die stamping, the die must have blunt or rounded edges that will minimize stress concentrations.
(d) Paragraph (a) of this section does not apply to items manufactured before November 12, 1970, that meet all of the following:
(1) The item is identifiable as to type, manufacturer, and model.
(2) Specifications or standards giving pressure, temperature, and other appropriate criteria for the use of items are readily available.
In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of 70 to 1, or more, that is transported by railroad unless:
(a) The transportation is performed in accordance with API RP 5L1.
(b) In the case of pipe transported before November 12, 1970, the pipe is tested in accordance with subpart J of this part to at least 1.25 times the maximum allowable operating pressure if it is to be installed in a class 1 location and to at least 1.5 times the maximum allowable operating pressure if it is to be installed in a class 2, 3, or 4 location. Notwithstanding any shorter time period permitted under subpart J of this part, the test pressure must be maintained for at least 8 hours.
This subpart prescribes the minimum requirements for the design of pipe.
Pipe must be designed with sufficient wall thickness, or must be installed with adequate protection, to withstand anticipated external pressures and loads that will be imposed on the pipe after installation.
(a) The design pressure for steel pipe is determined in accordance with the following formula:
(b) If steel pipe that has been subjected to cold expansion to meet the SMYS is subsequently heated, other than by welding or stress relieving as a part of welding, the design pressure is limited to 75 percent of the pressure determined under paragraph (a) of this section if the temperature of the pipe exceeds 900 °F (482 °C) at any time or is held above 600 °F (316 °C) for more than 1 hour.
(a) For pipe that is manufactured in accordance with a specification listed in section I of appendix B of this part, the yield strength to be used in the design formula in § 192.105 is the SMYS stated in the listed specification, if that value is known.
(b) For pipe that is manufactured in accordance with a specification not listed in section I of appendix B to this part or whose specification or tensile properties are unknown, the yield strength to be used in the design formula in § 192.105 is one of the following:
(1) If the pipe is tensile tested in accordance with section II-D of appendix B to this part, the lower of the following:
(i) 80 percent of the average yield strength determined by the tensile tests.
(ii) The lowest yield strength determined by the tensile tests.
(2) If the pipe is not tensile tested as provided in paragraph (b)(1) of this section, 24,000 p.s.i. (165 MPa).
(a) If the nominal wall thickness for steel pipe is not known, it is determined by measuring the thickness of each piece of pipe at quarter points on one end.
(b) However, if the pipe is of uniform grade, size, and thickness and there are more than 10 lengths, only 10 percent of the individual lengths, but not less than 10 lengths, need be measured. The thickness of the lengths that are not measured must be verified by applying a gauge set to the minimum thickness found by the measurement. The nominal wall thickness to be used in the design formula in § 192.105 is the next wall thickness found in commercial specifications that is below the average of all the measurements taken. However, the nominal wall thickness used may not be more than 1.14 times the smallest measurement taken on pipe less than 20 inches (508 millimeters) in outside diameter, nor more than 1.11 times the smallest measurement taken on pipe 20 inches (508 millimeters) or more in outside diameter.
(a) Except as otherwise provided in paragraphs (b), (c), and (d) of this section, the design factor to be used in the design formula in § 192.105 is determined in accordance with the following table:
(b) A design factor of 0.60 or less must be used in the design formula in § 192.105 for steel pipe in Class 1 locations that:
(1) Crosses the right-of-way of an unimproved public road, without a casing;
(2) Crosses without a casing, or makes a parallel encroachment on, the right-of-way of either a hard surfaced road, a highway, a public street, or a railroad;
(3) Is supported by a vehicular, pedestrian, railroad, or pipeline bridge; or
(4) Is used in a fabricated assembly, (including separators, mainline valve assemblies, cross-connections, and
(c) For Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in § 192.105 for uncased steel pipe that crosses the right-of-way of a hard surfaced road, a highway, a public street, or a railroad.
(d) For Class 1 and Class 2 locations, a design factor of 0.50, or less, must be used in the design formula in § 192.105 for—
(1) Steel pipe in a compressor station, regulating station, or measuring station; and
(2) Steel pipe, including a pipe riser, on a platform located offshore or in inland navigable waters.
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure (MAOP) calculated under § 192.620, a segment must meet the following additional design requirements. Records for alternative MAOP must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
The longitudinal joint factor to be used in the design formula in § 192.105 is determined in accordance with the following table:
The temperature derating factor to be used in the design formula in § 192.105 is determined as follows:
Subject to the limitations of § 192.123, the design pressure for plastic pipe is
= 0.40 for nominal pipe size (IPS or CTS) 4-inch or less, SDR-11 or greater (
(a) Except as provided in paragraph (e) and paragraph (f) of this section, the design pressure may not exceed a gauge pressure of 100 psig (689 kPa) for plastic pipe used in:
(1) Distribution systems; or
(2) Classes 3 and 4 locations.
(b) Plastic pipe may not be used where operating temperatures of the pipe will be:
(1) Below −20°F (−20°C), or −40°F (−40°C) if all pipe and pipeline components whose operating temperature will be below −29°C (−20°F) have a temperature rating by the manufacturer consistent with that operating temperature; or
(2) Above the following applicable temperatures:
(i) For thermoplastic pipe, the temperature at which the HDB used in the design formula under § 192.121 is determined.
(ii) For reinforced thermosetting plastic pipe, 150°F (66°C).
(c) The wall thickness for thermoplastic pipe may not be less than 0.062 inches (1.57 millimeters).
(d) The wall thickness for reinforced thermosetting plastic pipe may not be less than that listed in the following table:
(e) The design pressure for thermoplastic pipe produced after July 14, 2004 may exceed a gauge pressure of 100 psig (689 kPa) provided that:
(1) The design pressure does not exceed 125 psig (862 kPa);
(2) The material is a PE2406 or a PE3408 as specified within ASTM D2513 (incorporated by reference,
(3) The pipe size is nominal pipe size (IPS) 12 or less; and
(4) The design pressure is determined in accordance with the design equation defined in § 192.121.
(f) The design pressure for polyamide-11 (PA-11) pipe produced after January 23, 2009 may exceed a gauge pressure of 100 psig (689 kPa) provided that:
(1) The design pressure does not exceed 200 psig (1379 kPa);
(2) The pipe size is nominal pipe size (IPS or CTS) 4-inch or less; and
(3) The pipe has a standard dimension ratio of SDR-11 or greater (
(a) Copper pipe used in mains must have a minimum wall thickness of 0.065 inches (1.65 millimeters) and must be hard drawn.
(b) Copper pipe used in service lines must have wall thickness not less than that indicated in the following table:
(c) Copper pipe used in mains and service lines may not be used at pressures in excess of 100 p.s.i. (689 kPa) gage.
(d) Copper pipe that does not have an internal corrosion resistant lining may not be used to carry gas that has an average hydrogen sulfide content of more than 0.3 grains/100 ft
This subpart prescribes minimum requirements for the design and installation of pipeline components and facilities. In addition, it prescribes requirements relating to protection against accidental overpressuring.
(a) Each component of a pipeline must be able to withstand operating pressures and other anticipated loadings without impairment of its serviceability with unit stresses equivalent to those allowed for comparable material in pipe in the same location and kind of service. However, if design based upon unit stresses is impractical for a particular component, design may be based upon a pressure rating established by the manufacturer by pressure testing that component or a prototype of the component.
(b) The design and installation of pipeline components and facilities must meet applicable requirements for corrosion control found in subpart I of this part.
Notwithstanding any requirement of this subpart which incorporates by reference an edition of a document listed in § 192.7 or Appendix B of this part, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this part if—
(a) It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component; and
(b) The edition of the document under which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in § 192.7 or appendix B of this part:
(1) Pressure testing;
(2) Materials; and
(3) Pressure and temperature ratings.
(a) Except for cast iron and plastic valves, each valve must meet the minimum requirements of API 6D (incorporated by reference,
(b) Each cast iron and plastic valve must comply with the following:
(1) The valve must have a maximum service pressure rating for temperatures that equal or exceed the maximum service temperature.
(2) The valve must be tested as part of the manufacturing, as follows:
(i) With the valve in the fully open position, the shell must be tested with no leakage to a pressure at least 1.5 times the maximum service rating.
(ii) After the shell test, the seat must be tested to a pressure not less than 1.5 times the maximum service pressure rating. Except for swing check valves, test pressure during the seat test must be applied successively on each side of the closed valve with the opposite side open. No visible leakage is permitted.
(iii) After the last pressure test is completed, the valve must be operated through its full travel to demonstrate freedom from interference.
(c) Each valve must be able to meet the anticipated operating conditions.
(d) No valve having shell components made of ductile iron may be used at pressures exceeding 80 percent of the pressure ratings for comparable steel valves at their listed temperature. However, a valve having shell components made of ductile iron may be used at pressures up to 80 percent of the pressure ratings for comparable steel valves at their listed temperature, if:
(1) The temperature-adjusted service pressure does not exceed 1,000 p.s.i. (7 Mpa) gage; and
(2) Welding is not used on any ductile iron component in the fabrication of the valve shells or their assembly.
(e) No valve having pressure containing parts made of ductile iron may be used in the gas pipe components of compressor stations.
(a) Each flange or flange accessory (other than cast iron) must meet the minimum requirements of ASME/ANSI B16.5, MSS SP-44, or the equivalent.
(b) Each flange assembly must be able to withstand the maximum pressure at which the pipeline is to be operated and to maintain its physical and chemical properties at any temperature to which it is anticipated that it might be subjected in service.
(c) Each flange on a flanged joint in cast iron pipe must conform in dimensions, drilling, face and gasket design to ASME/ANSI B16.1 and be cast integrally with the pipe, valve, or fitting.
(a) The minimum metal thickness of threaded fittings may not be less than specified for the pressures and temperatures in the applicable standards referenced in this part, or their equivalent.
(b) Each steel butt-welding fitting must have pressure and temperature ratings based on stresses for pipe of the same or equivalent material. The actual bursting strength of the fitting must at least equal the computed bursting strength of pipe of the designated material and wall thickness, as determined by a prototype that was tested to at least the pressure required for the pipeline to which it is being added.
(a) Except as provided in paragraphs (b) and (c) of this section, 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 internal inspection devices.
(b) This section does not apply to: (1) Manifolds;
(2) Station piping such as at compressor stations, meter stations, or regulator stations;
(3) Piping associated with storage facilities, other than a continuous run of transmission line between a compressor station and storage facilities;
(4) Cross-overs;
(5) Sizes of pipe for which an instrumented internal inspection device is not commercially available;
(6) Transmission lines, operated in conjunction with a distribution system which are installed in Class 4 locations;
(7) Offshore transmission lines, except transmission lines 10
(i) Platform space or configuration is incompatible with launching or retrieving instrumented internal inspection devices; or
(ii) If the design includes taps for lateral connections, the operator can demonstrate, based on investigation or experience, that there is no reasonably practical alternative under the design circumstances to the use of a tap that will obstruct the passage of instrumented internal inspection devices; and
(8) Other piping that, under § 190.9 of this chapter, the Administrator finds in a particular case would be impracticable to design and construct to accommodate the passage of instrumented internal inspection devices.
(c) An operator encountering emergencies, construction time constraints or other unforeseen construction problems need not construct a new or replacement segment of a transmission line to meet paragraph (a) of this section, if the operator determines and documents why an impracticability prohibits compliance with paragraph (a) of this section. Within 30 days after discovering the emergency or construction problem the operator must petition, under § 190.9 of this chapter, for approval that design and construction to accommodate passage of instrumented internal inspection devices would be impracticable. If the petition is denied, within 1 year after the date of the notice of the denial, the operator must modify that segment to allow passage of instrumented internal inspection devices.
(a) Each mechanical fitting used to make a hot tap must be designed for at least the operating pressure of the pipeline.
(b) Where a ductile iron pipe is tapped, the extent of full-thread engagement and the need for the use of outside-sealing service connections, tapping saddles, or other fixtures must be determined by service conditions.
(c) Where a threaded tap is made in cast iron or ductile iron pipe, the diameter of the tapped hole may not be more than 25 percent of the nominal diameter of the pipe unless the pipe is reinforced, except that
(1) Existing taps may be used for replacement service, if they are free of cracks and have good threads; and
(2) A 1
(a) Except for branch connections and assemblies of standard pipe and fittings joined by circumferential welds, the design pressure of each component fabricated by welding, whose strength cannot be determined, must be established in accordance with paragraph UG-101 of section VIII, Division 1, of the ASME Boiler and Pressure Vessel Code.
(b) Each prefabricated unit that uses plate and longitudinal seams must be designed, constructed, and tested in accordance with section I, section VIII, Division 1, or section VIII, Division 2 of the ASME Boiler and Pressure Vessel Code, except for the following:
(1) Regularly manufactured butt-welding fittings.
(2) Pipe that has been produced and tested under a specification listed in appendix B to this part.
(3) Partial assemblies such as split rings or collars.
(4) Prefabricated units that the manufacturer certifies have been tested to at least twice the maximum pressure to which they will be subjected under the anticipated operating conditions.
(c) Orange-peel bull plugs and orange-peel swages may not be used on pipelines that are to operate at a hoop stress of 20 percent or more of the SMYS of the pipe.
(d) Except for flat closures designed in accordance with section VIII of the ASME Boiler and Pressure Code, flat
Each welded branch connection made to pipe in the form of a single connection, or in a header or manifold as a series of connections, must be designed to ensure that the strength of the pipeline system is not reduced, taking into account the stresses in the remaining pipe wall due to the opening in the pipe or header, the shear stresses produced by the pressure acting on the area of the branch opening, and any external loadings due to thermal movement, weight, and vibration.
Each extruded outlet must be suitable for anticipated service conditions and must be at least equal to the design strength of the pipe and other fittings in the pipeline to which it is attached.
Each pipeline must be designed with enough flexibility to prevent thermal expansion or contraction from causing excessive stresses in the pipe or components, excessive bending or unusual loads at joints, or undesirable forces or moments at points of connection to equipment, or at anchorage or guide points.
(a) Each pipeline and its associated equipment must have enough anchors or supports to:
(1) Prevent undue strain on connected equipment;
(2) Resist longitudinal forces caused by a bend or offset in the pipe; and
(3) Prevent or damp out excessive vibration.
(b) Each exposed pipeline must have enough supports or anchors to protect the exposed pipe joints from the maximum end force caused by internal pressure and any additional forces caused by temperature expansion or contraction or by the weight of the pipe and its contents.
(c) Each support or anchor on an exposed pipeline must be made of durable, noncombustible material and must be designed and installed as follows:
(1) Free expansion and contraction of the pipeline between supports or anchors may not be restricted.
(2) Provision must be made for the service conditions involved.
(3) Movement of the pipeline may not cause disengagement of the support equipment.
(d) Each support on an exposed pipeline operated at a stress level of 50 percent or more of SMYS must comply with the following:
(1) A structural support may not be welded directly to the pipe.
(2) The support must be provided by a member that completely encircles the pipe.
(3) If an encircling member is welded to a pipe, the weld must be continuous and cover the entire circumference.
(e) Each underground pipeline that is connected to a relatively unyielding line or other fixed object must have enough flexibility to provide for possible movement, or it must have an anchor that will limit the movement of the pipeline.
(f) Except for offshore pipelines, each underground pipeline that is being connected to new branches must have a firm foundation for both the header and the branch to prevent detrimental lateral and vertical movement.
(a)
(b)
(1) Pipe more than 2 inches (51 millimeters) in diameter that is carrying gas under pressure; or
(2) Gas handling equipment other than gas utilization equipment used for domestic purposes.
(c)
(d)
(e)
(a) Where entrained vapors in gas may liquefy under the anticipated pressure and temperature conditions, the compressor must be protected against the introduction of those liquids in quantities that could cause damage.
(b) Each liquid separator used to remove entrained liquids at a compressor station must:
(1) Have a manually operable means of removing these liquids.
(2) Where slugs of liquid could be carried into the compressors, have either automatic liquid removal facilities, an automatic compressor shutdown device, or a high liquid level alarm; and
(3) Be manufactured in accordance with section VIII of the ASME Boiler and Pressure Vessel Code, except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4, or less.
(a) Except for unattended field compressor stations of 1,000 horsepower (746 kilowatts) or less, each compressor station must have an emergency shutdown system that meets the following:
(1) It must be able to block gas out of the station and blow down the station piping.
(2) It must discharge gas from the blowdown piping at a location where the gas will not create a hazard.
(3) It must provide means for the shutdown of gas compressing equipment, gas fires, and electrical facilities in the vicinity of gas headers and in the compressor building, except that:
(i) Electrical circuits that supply emergency lighting required to assist station personnel in evacuating the compressor building and the area in the vicinity of the gas headers must remain energized; and
(ii) Electrical circuits needed to protect equipment from damage may remain energized.
(4) It must be operable from at least two locations, each of which is:
(i) Outside the gas area of the station;
(ii) Near the exit gates, if the station is fenced, or near emergency exits, if not fenced; and
(iii) Not more than 500 feet (153 meters) from the limits of the station.
(b) If a compressor station supplies gas directly to a distribution system with no other adequate source of gas available, the emergency shutdown system must be designed so that it will not function at the wrong time and cause an unintended outage on the distribution system.
(c) On a platform located offshore or in inland navigable waters, the emergency shutdown system must be designed and installed to actuate automatically by each of the following events:
(1) In the case of an unattended compressor station:
(i) When the gas pressure equals the maximum allowable operating pressure plus 15 percent; or
(ii) When an uncontrolled fire occurs on the platform; and
(2) In the case of a compressor station in a building:
(i) When an uncontrolled fire occurs in the building; or
(ii) When the concentration of gas in air reaches 50 percent or more of the lower explosive limit in a building which has a source of ignition.
(a) Each compressor station must have pressure relief or other suitable protective devices of sufficient capacity and sensitivity to ensure that the maximum allowable operating pressure of the station piping and equipment is not exceeded by more than 10 percent.
(b) Each vent line that exhausts gas from the pressure relief valves of a compressor station must extend to a location where the gas may be discharged without hazard.
(a) Each compressor station must have adequate fire protection facilities. If fire pumps are a part of these facilities, their operation may not be affected by the emergency shutdown system.
(b) Each compressor station prime mover, other than an electrical induction or synchronous motor, must have an automatic device to shut down the unit before the speed of either the prime mover or the driven unit exceeds a maximum safe speed.
(c) Each compressor unit in a compressor station must have a shutdown or alarm device that operates in the event of inadequate cooling or lubrication of the unit.
(d) Each compressor station gas engine that operates with pressure gas injection must be equipped so that stoppage of the engine automatically shuts off the fuel and vents the engine distribution manifold.
(e) Each muffler for a gas engine in a compressor station must have vent slots or holes in the baffles of each compartment to prevent gas from being trapped in the muffler.
Each compressor station building must be ventilated to ensure that employees are not endangered by the accumulation of gas in rooms, sumps, attics, pits, or other enclosed places.
(a) Each pipe-type and bottle-type holder must be designed so as to prevent the accumulation of liquids in the holder, in connecting pipe, or in auxiliary equipment, that might cause corrosion or interfere with the safe operation of the holder.
(b) Each pipe-type or bottle-type holder must have minimum clearance from other holders in accordance with the following formula:
(a) Each bottle-type holder must be—
(1) Located on a site entirely surrounded by fencing that prevents access by unauthorized persons and with
(2) Designed using the design factors set forth in § 192.111; and
(3) Buried with a minimum cover in accordance with § 192.327.
(b) Each bottle-type holder manufactured from steel that is not weldable under field conditions must comply with the following:
(1) A bottle-type holder made from alloy steel must meet the chemical and tensile requirements for the various grades of steel in ASTM A 372/A 372M.
(2) The actual yield-tensile ratio of the steel may not exceed 0.85.
(3) Welding may not be performed on the holder after it has been heat treated or stress relieved, except that copper wires may be attached to the small diameter portion of the bottle end closure for cathodic protection if a localized thermit welding process is used.
(4) The holder must be given a mill hydrostatic test at a pressure that produces a hoop stress at least equal to 85 percent of the SMYS.
(5) The holder, connection pipe, and components must be leak tested after installation as required by subpart J of this part.
(a) Each transmission line, other than offshore segments, must have sectionalizing block valves spaced as follows, unless in a particular case the Administrator finds that alternative spacing would provide an equivalent level of safety:
(1) Each point on the pipeline in a Class 4 location must be within 2
(2) Each point on the pipeline in a Class 3 location must be within 4 miles (6.4 kilometers) of a valve.
(3) Each point on the pipeline in a Class 2 location must be within 7
(4) Each point on the pipeline in a Class 1 location must be within 10 miles (16 kilometers) of a valve.
(b) Each sectionalizing block valve on a transmission line, other than offshore segments, must comply with the following:
(1) The valve and the operating device to open or close the valve must be readily accessible and protected from tampering and damage.
(2) The valve must be supported to prevent settling of the valve or movement of the pipe to which it is attached.
(c) Each section of a transmission line, other than offshore segments, between main line valves must have a blowdown valve with enough capacity to allow the transmission line to be blown down as rapidly as practicable. Each blowdown discharge must be located so the gas can be blown to the atmosphere without hazard and, if the transmission line is adjacent to an overhead electric line, so that the gas is directed away from the electrical conductors.
(d) Offshore segments of transmission lines must be equipped with valves or other components to shut off the flow of gas to an offshore platform in an emergency.
(a) Each high-pressure distribution system must have valves spaced so as to reduce the time to shut down a section of main in an emergency. The valve spacing is determined by the operating pressure, the size of the mains, and the local physical conditions.
(b) Each regulator station controlling the flow or pressure of gas in a distribution system must have a valve installed on the inlet piping at a distance from the regulator station sufficient to permit the operation of the valve during an emergency that might preclude access to the station.
(c) Each valve on a main installed for operating or emergency purposes must comply with the following:
(1) The valve must be placed in a readily accessible location so as to facilitate its operation in an emergency.
(2) The operating stem or mechanism must be readily accessible.
(3) If the valve is installed in a buried box or enclosure, the box or enclosure must be installed so as to avoid transmitting external loads to the main.
(a) Each underground vault or pit for valves, pressure relieving, pressure limiting, or pressure regulating stations, must be able to meet the loads which may be imposed upon it, and to protect installed equipment.
(b) There must be enough working space so that all of the equipment required in the vault or pit can be properly installed, operated, and maintained.
(c) Each pipe entering, or within, a regulator vault or pit must be steel for sizes 10 inch (254 millimeters), and less, except that control and gage piping may be copper. Where pipe extends through the vault or pit structure, provision must be made to prevent the passage of gases or liquids through the opening and to avert strains in the pipe.
Each vault must be located in an accessible location and, so far as practical, away from:
(a) Street intersections or points where traffic is heavy or dense;
(b) Points of minimum elevation, catch basins, or places where the access cover will be in the course of surface waters; and
(c) Water, electric, steam, or other facilities.
Each underground vault or closed top pit containing either a pressure regulating or reducing station, or a pressure limiting or relieving station, must be sealed, vented or ventilated as follows:
(a) When the internal volume exceeds 200 cubic feet (5.7 cubic meters):
(1) The vault or pit must be ventilated with two ducts, each having at least the ventilating effect of a pipe 4 inches (102 millimeters) in diameter;
(2) The ventilation must be enough to minimize the formation of combustible atmosphere in the vault or pit; and
(3) The ducts must be high enough above grade to disperse any gas-air mixtures that might be discharged.
(b) When the internal volume is more than 75 cubic feet (2.1 cubic meters) but less than 200 cubic feet (5.7 cubic meters):
(1) If the vault or pit is sealed, each opening must have a tight fitting cover without open holes through which an explosive mixture might be ignited, and there must be a means for testing the internal atmosphere before removing the cover;
(2) If the vault or pit is vented, there must be a means of preventing external sources of ignition from reaching the vault atmosphere; or
(3) If the vault or pit is ventilated, paragraph (a) or (c) of this section applies.
(c) If a vault or pit covered by paragraph (b) of this section is ventilated by openings in the covers or gratings and the ratio of the internal volume, in cubic feet, to the effective ventilating area of the cover or grating, in square feet, is less than 20 to 1, no additional ventilation is required.
(a) Each vault must be designed so as to minimize the entrance of water.
(b) A vault containing gas piping may not be connected by means of a drain connection to any other underground structure.
(c) Electrical equipment in vaults must conform to the applicable requirements of Class 1, Group D, of the National Electrical Code, ANSI/NFPA 70.
(a) Thermosetting fittings for plastic pipe must conform to ASTM D 2517.
(b) Thermoplastic fittings for plastic pipe must conform to ASTM D 2513.
Each valve installed in plastic pipe must be designed so as to protect the plastic material against excessive torsional or shearing loads when the valve or shutoff is operated, and from any other secondary stresses that might be exerted through the valve or its enclosure.
(a)
(b)
(1) Have pressure regulation devices capable of meeting the pressure, load, and other service conditions that will be experienced in normal operation of the system, and that could be activated in the event of failure of some portion of the system; and
(2) Be designed so as to prevent accidental overpressuring.
(a) If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less and a service regulator having the following characteristics is used, no other pressure limiting device is required:
(1) A regulator capable of reducing distribution line pressure to pressures recommended for household appliances.
(2) A single port valve with proper orifice for the maximum gas pressure at the regulator inlet.
(3) A valve seat made of resilient material designed to withstand abrasion of the gas, impurities in gas, cutting by the valve, and to resist permanent deformation when it is pressed against the valve port.
(4) Pipe connections to the regulator not exceeding 2 inches (51 millimeters) in diameter.
(5) A regulator that, under normal operating conditions, is able to regulate the downstream pressure within the necessary limits of accuracy and to limit the build-up of pressure under no-flow conditions to prevent a pressure that would cause the unsafe operation of any connected and properly adjusted gas utilization equipment.
(6) A self-contained service regulator with no external static or control lines.
(b) If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator that does not have all of the characteristics listed in paragraph (a) of this section is used, or if the gas contains materials that seriously interfere with the operation of service regulators, there must be suitable protective devices to prevent unsafe overpressuring of the customer's appliances if the service regulator fails.
(c) If the maximum actual operating pressure of the distribution system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods must be used to regulate and limit, to the maximum safe value, the pressure of gas delivered to the customer:
(1) A service regulator having the characteristics listed in paragraph (a) of this section, and another regulator located upstream from the service regulator. The upstream regulator may not be set to maintain a pressure higher than 60 p.s.i. (414 kPa) gage. A device must be installed between the upstream regulator and the service regulator to limit the pressure on the inlet of the service regulator to 60 p.s.i. (414 kPa) gage or less in case the upstream regulator fails to function properly.
(2) A service regulator and a monitoring regulator set to limit, to a maximum safe value, the pressure of the gas delivered to the customer.
(3) A service regulator with a relief valve vented to the outside atmosphere, with the relief valve set to open so that the pressure of gas going to the customer does not exceed a maximum safe value. The relief valve may either be built into the service regulator or it may be a separate unit installed downstream from the service regulator. This combination may be used alone only in those cases where the inlet pressure on the service regulator does not exceed the manufacturer's safe working pressure rating of the service regulator, and may not be used where the inlet pressure on the service regulator exceeds 125 p.s.i. (862 kPa) gage. For higher inlet pressures, the methods in paragraph (c) (1) or (2) of this section must be used.
(4) A service regulator and an automatic shutoff device that closes upon a rise in pressure downstream from the regulator and remains closed until manually reset.
Except for rupture discs, each pressure relief or pressure limiting device must:
(a) Be constructed of materials such that the operation of the device will not be impaired by corrosion;
(b) Have valves and valve seats that are designed not to stick in a position that will make the device inoperative;
(c) Be designed and installed so that it can be readily operated to determine if the valve is free, can be tested to determine the pressure at which it will operate, and can be tested for leakage when in the closed position;
(d) Have support made of noncombustible material;
(e) Have discharge stacks, vents, or outlet ports designed to prevent accumulation of water, ice, or snow, located where gas can be discharged into the atmosphere without undue hazard;
(f) Be designed and installed so that the size of the openings, pipe, and fittings located between the system to be protected and the pressure relieving device, and the size of the vent line, are adequate to prevent hammering of the valve and to prevent impairment of relief capacity;
(g) Where installed at a district regulator station to protect a pipeline system from overpressuring, be designed and installed to prevent any single incident such as an explosion in a vault or damage by a vehicle from affecting the operation of both the overpressure protective device and the district regulator; and
(h) Except for a valve that will isolate the system under protection from its source of pressure, be designed to prevent unauthorized operation of any stop valve that will make the pressure relief valve or pressure limiting device inoperative.
(a) Each pressure relief station or pressure limiting station or group of those stations installed to protect a pipeline must have enough capacity, and must be set to operate, to insure the following:
(1) In a low pressure distribution system, the pressure may not cause the unsafe operation of any connected and properly adjusted gas utilization equipment.
(2) In pipelines other than a low pressure distribution system:
(i) If the maximum allowable operating pressure is 60 p.s.i. (414 kPa) gage or more, the pressure may not exceed the maximum allowable operating pressure plus 10 percent, or the pressure that produces a hoop stress of 75 percent of SMYS, whichever is lower;
(ii) If the maximum allowable operating pressure is 12 p.s.i. (83 kPa) gage or more, but less than 60 p.s.i. (414 kPa) gage, the pressure may not exceed the
(iii) If the maximum allowable operating pressure is less than 12 p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable operating pressure plus 50 percent.
(b) When more than one pressure regulating or compressor station feeds into a pipeline, relief valves or other protective devices must be installed at each station to ensure that the complete failure of the largest capacity regulator or compressor, or any single run of lesser capacity regulators or compressors in that station, will not impose pressures on any part of the pipeline or distribution system in excess of those for which it was designed, or against which it was protected, whichever is lower.
(c) Relief valves or other pressure limiting devices must be installed at or near each regulator station in a low-pressure distribution system, with a capacity to limit the maximum pressure in the main to a pressure that will not exceed the safe operating pressure for any connected and properly adjusted gas utilization equipment.
(a)
(b)
(1) Each takeoff connection and attaching boss, fitting, or adapter must be made of suitable material, be able to withstand the maximum service pressure and temperature of the pipe or equipment to which it is attached, and be designed to satisfactorily withstand all stresses without failure by fatigue.
(2) Except for takeoff lines that can be isolated from sources of pressure by other valving, a shutoff valve must be installed in each takeoff line as near as practicable to the point of takeoff. Blowdown valves must be installed where necessary.
(3) Brass or copper material may not be used for metal temperatures greater than 400° F (204°C).
(4) Pipe or components that may contain liquids must be protected by heating or other means from damage due to freezing.
(5) Pipe or components in which liquids may accumulate must have drains or drips.
(6) Pipe or components subject to clogging from solids or deposits must have suitable connections for cleaning.
(7) The arrangement of pipe, components, and supports must provide safety under anticipated operating stresses.
(8) Each joint between sections of pipe, and between pipe and valves or fittings, must be made in a manner suitable for the anticipated pressure and temperature condition. Slip type expansion joints may not be used. Expansion must be allowed for by providing flexibility within the system itself.
(9) Each control line must be protected from anticipated causes of damage and must be designed and installed to prevent damage to any one control line from making both the regulator and the over-pressure protective device inoperative.
(a) This subpart prescribes minimum requirements for welding steel materials in pipelines.
(b) This subpart does not apply to welding that occurs during the manufacture of steel pipe or steel pipeline components.
(a) Welding must be performed by a qualified welder in accordance with welding procedures qualified under section 5 of API 1104 (incorporated by reference,
(b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used.
(a) Except as provided in paragraph (b) of this section, each welder must be qualified in accordance with section 6 of API 1104 (incorporated by reference, see § 192.7) or section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference, see § 192.7). However, a welder qualified under an earlier edition than listed in § 192.7 of this part may weld but may not requalify under that earlier edition.
(b) A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of Appendix C of this part. Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of this part as a requirement of the qualifying test.
(a) No welder whose qualification is based on nondestructive testing may weld compressor station pipe and components.
(b) No welder may weld with a particular welding process unless, within the preceding 6 calendar months, he has engaged in welding with that process.
(c) A welder qualified under § 192.227(a)—
(1) May not weld on pipe to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS unless within the preceding 6 calendar months the welder has had one weld tested and found acceptable under the sections 6 or 9 of API Standard 1104 (incorporated by reference,
(2) May not weld on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS unless the welder is tested in accordance with paragraph (c)(1) of this section or requalifies under paragraph (d)(1) or (d)(2) of this section.
(d) A welder qualified under § 192.227(b) may not weld unless—
(1) Within the preceding 15 calendar months, but at least once each calendar year, the welder has requalified under § 192.227(b); or
(2) Within the preceding 7
(i) A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or
(ii) For welders who work only on service lines 2 inches (51 millimeters) or smaller in diameter, two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part.
The welding operation must be protected from weather conditions that would impair the quality of the completed weld.
(a) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 30 percent or more of SMYS may not deflect the pipe more than 3°.
(b) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of less than 30 percent, but more than 10 percent, of SMYS may not deflect the pipe more than 12
(c) A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of 10 percent or less of SMYS may not deflect the pipe more than 90°.
Before beginning any welding, the welding surfaces must be clean and free of any material that may be detrimental to the weld, and the pipe or component must be aligned to provide the most favorable condition for depositing the root bead. This alignment must be preserved while the root bead is being deposited.
(a) Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that:
(1) The welding is performed in accordance with the welding procedure; and
(2) The weld is acceptable under paragraph (c) of this section.
(b) The welds on a pipeline to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS must be nondestructively tested in accordance with § 192.243, except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if:
(1) The pipe has a nominal diameter of less than 6 inches (152 millimeters); or
(2) The pipeline is to be operated at a pressure that produces a hoop stress of less than 40 percent of SMYS and the welds are so limited in number that nondestructive testing is impractical.
(c) The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in Section 9 of API Standard 1104 (incorporated by reference,
(a) Nondestructive testing of welds must be performed by any process, other than trepanning, that will clearly indicate defects that may affect the integrity of the weld.
(b) Nondestructive testing of welds must be performed:
(1) In accordance with written procedures; and
(2) By persons who have been trained and qualified in the established procedures and with the equipment employed in testing.
(c) Procedures must be established for the proper interpretation of each nondestructive test of a weld to ensure the acceptability of the weld under § 192.241(c).
(d) When nondestructive testing is required under § 192.241(b), the following percentages of each day's field butt welds, selected at random by the operator, must be nondestructively tested over their entire circumference:
(1) In Class 1 locations, except offshore, at least 10 percent.
(2) In Class 2 locations, at least 15 percent.
(3) In Class 3 and Class 4 locations, at crossings of major or navigable rivers, offshore, and within railroad or public highway rights-of-way, including tunnels, bridges, and overhead road crossings, 100 percent unless impracticable, in which case at least 90 percent. Nondestructive testing must be impracticable for each girth weld not tested.
(4) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent.
(e) Except for a welder whose work is isolated from the principal welding activity, a sample of each welder's work for each day must be nondestructively tested, when nondestructive testing is required under § 192.241(b).
(f) When nondestructive testing is required under § 192.241(b), each operator must retain, for the life of the pipeline, a record showing by milepost, engineering station, or by geographic feature, the number of girth welds made, the number nondestructively tested, the number rejected, and the disposition of the rejects.
(a) Each weld that is unacceptable under § 192.241(c) must be removed or repaired. Except for welds on an offshore pipeline being installed from a pipeline vessel, a weld must be removed if it has a crack that is more than 8 percent of the weld length.
(b) Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability.
(c) Repair of a crack, or of any defect in a previously repaired area must be in accordance with written weld repair procedures that have been qualified under § 192.225. Repair procedures must provide that the minimum mechanical properties specified for the welding procedure used to make the original weld are met upon completion of the final weld repair.
(a) This subpart prescribes minimum requirements for joining materials in pipelines, other than by welding.
(b) This subpart does not apply to joining during the manufacture of pipe or pipeline components.
(a) The pipeline must be designed and installed so that each joint will sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping or by anticipated external or internal loading.
(b) Each joint must be made in accordance with written procedures that have been proven by test or experience to produce strong gastight joints.
(c) Each joint must be inspected to insure compliance with this subpart.
(a) Each caulked bell and spigot joint in cast iron pipe must be sealed with mechanical leak clamps.
(b) Each mechanical joint in cast iron pipe must have a gasket made of a resilient material as the sealing medium. Each gasket must be suitably confined and retained under compression by a separate gland or follower ring.
(c) Cast iron pipe may not be joined by threaded joints.
(d) Cast iron pipe may not be joined by brazing.
(a) Ductile iron pipe may not be joined by threaded joints.
(b) Ductile iron pipe may not be joined by brazing.
Copper pipe may not be threaded except that copper pipe used for joining screw fittings or valves may be threaded if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe listed in Table C1 of ASME/ANSI B16.5.
(a)
(b)
(1) The mating surfaces of the joint must be clean, dry, and free of material which might be deterimental to the joint.
(2) The solvent cement must conform to ASTM Designation D 2513.
(3) The joint may not be heated to accelerate the setting of the cement.
(c)
(1) A butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the piping, compresses the heated ends together, and holds the pipe in proper alignment while the plastic hardens.
(2) A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the joint uniformly and simultaneously to essentially the same temperature.
(3) An electrofusion joint must be joined utilizing the equipment and techniques of the fittings manufacturer or equipment and techniques shown, by testing joints to the requirements of § 192.283(a)(1)(iii), to be at least equivalent to those of the fittings manufacturer.
(4) Heat may not be applied with a torch or other open flame.
(d)
(1) The adhesive must conform to ASTM Designation D 2517.
(2) The materials and adhesive must be compatible with each other.
(e)
(1) The gasket material in the coupling must be compatible with the plastic.
(2) A rigid internal tubular stiffener, other than a split tubular stiffener, must be used in conjunction with the coupling.
(a)
(1) The burst test requirements of—
(i) In the case of thermoplastic pipe, paragraph 6.6 (sustained pressure test) or paragraph 6.7 (Minimum Hydrostatic Burst Test) or paragraph 8.9 ( Sustained Static pressure Test) of ASTM D2513 (incorporated by reference,
(ii) In the case of thermosetting plastic pipe, paragraph 8.5 (Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static Pressure Test) of ASTM D2517 (incorporated by reference,
(iii) In the case of electrofusion fittings for polyethylene pipe and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM Designation F1055 (incorporated by reference,
(2) For procedures intended for lateral pipe connections, subject a specimen joint made from pipe sections joined at right angles according to the procedure to a force on the lateral pipe until failure occurs in the specimen. If failure initiates outside the joint area, the procedure qualifies for use; and
(3) For procedures intended for non-lateral pipe connections, follow the tensile test requirements of ASTM D638 (incorporated by reference,
(b)
(1) Use an apparatus for the test as specified in ASTM D 638 (except for conditioning), (incorporated by reference,
(2) The specimen must be of such length that the distance between the grips of the apparatus and the end of the stiffener does not affect the joint strength.
(3) The speed of testing is 0.20 in (5.0 mm) per minute, plus or minus 25 percent.
(4) Pipe specimens less than 4 inches (102 mm) in diameter are qualified if the pipe yields to an elongation of no less than 25 percent or failure initiates outside the joint area.
(5) Pipe specimens 4 inches (102 mm) and larger in diameter shall be pulled until the pipe is subjected to a tensile stress equal to or greater than the maximum thermal stress that would be produced by a temperature change of 100°F (38°C) or until the pipe is pulled from the fitting. If the pipe pulls from the fitting, the lowest value of the five test results or the manufacturer's rating, whichever is lower must be used in the design calculations for stress.
(6) Each specimen that fails at the grips must be retested using new pipe.
(7) Results obtained pertain only to the specific outside diameter, and material of the pipe tested, except that testing of a heavier wall pipe may be used to qualify pipe of the same material but with a lesser wall thickness.
(c) A copy of each written procedure being used for joining plastic pipe must be available to the persons making and inspecting joints.
(d) Pipe or fittings manufactured before July 1, 1980, may be used in accordance with procedures that the manufacturer certifies will produce a joint as strong as the pipe.
(a) No person may make a plastic pipe joint unless that person has been qualified under the applicable joining procedure by:
(1) Appropriate training or experience in the use of the procedure; and
(2) Making a specimen joint from pipe sections joined according to the procedure that passes the inspection and test set forth in paragraph (b) of this section.
(b) The specimen joint must be:
(1) Visually examined during and after assembly or joining and found to have the same appearance as a joint or photographs of a joint that is acceptable under the procedure; and
(2) In the case of a heat fusion, solvent cement, or adhesive joint:
(i) Tested under any one of the test methods listed under § 192.283(a) applicable to the type of joint and material being tested;
(ii) Examined by ultrasonic inspection and found not to contain flaws that would cause failure; or
(iii) Cut into at least 3 longitudinal straps, each of which is:
(A) Visually examined and found not to contain voids or discontinuities on the cut surfaces of the joint area; and
(B) Deformed by bending, torque, or impact, and if failure occurs, it must not initiate in the joint area.
(c) A person must be requalified under an applicable procedure, if during any 12-month period that person:
(1) Does not make any joints under that procedure; or
(2) Has 3 joints or 3 percent of the joints made, whichever is greater, under that procedure that are found unacceptable by testing under § 192.513.
(d) Each operator shall establish a method to determine that each person making joints in plastic pipelines in
No person may carry out the inspection of joints in plastic pipes required by §§ 192.273(c) and 192.285(b) unless that person has been qualified by appropriate training or experience in evaluating the acceptability of plastic pipe joints made under the applicable joining procedure.
This subpart prescribes minimum requirements for constructing transmission lines and mains.
Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this part.
Each transmission line or main must be inspected to ensure that it is constructed in accordance with this part.
Each length of pipe and each other component must be visually inspected at the site of installation to ensure that it has not sustained any visually determinable damage that could impair its serviceability.
(a) Each imperfection or damage that impairs the serviceability of a length of steel pipe must be repaired or removed. If a repair is made by grinding, the remaining wall thickness must at least be equal to either:
(1) The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or
(2) The nominal wall thickness required for the design pressure of the pipeline.
(b) Each of the following dents must be removed from steel pipe to be operated at a pressure that produces a hoop stress of 20 percent, or more, of SMYS, unless the dent is repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe:
(1) A dent that contains a stress concentrator such as a scratch, gouge, groove, or arc burn.
(2) A dent that affects the longitudinal weld or a circumferential weld.
(3) In pipe to be operated at a pressure that produces a hoop stress of 40 percent or more of SMYS, a dent that has a depth of:
(i) More than
(ii) More than 2 percent of the nominal pipe diameter in pipe over 12
(c) Each arc burn on steel pipe to be operated at a pressure that produces a hoop stress of 40 percent, or more, of SMYS must be repaired or removed. If a repair is made by grinding, the arc burn must be completely removed and the remaining wall thickness must be at least equal to either:
(1) The minimum wall thickness required by the tolerances in the specification to which the pipe was manufactured; or
(2) The nominal wall thickness required for the design pressure of the pipeline.
(d) A gouge, groove, arc burn, or dent may not be repaired by insert patching or by pounding out.
(e) Each gouge, groove, arc burn, or dent that is removed from a length of
Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired or removed.
(a) Each field bend in steel pipe, other than a wrinkle bend made in accordance with § 192.315, must comply with the following:
(1) A bend must not impair the serviceability of the pipe.
(2) Each bend must have a smooth contour and be free from buckling, cracks, or any other mechanical damage.
(3) On pipe containing a longitudinal weld, the longitudinal weld must be as near as practicable to the neutral axis of the bend unless:
(i) The bend is made with an internal bending mandrel; or
(ii) The pipe is 12 inches (305 millimeters) or less in outside diameter or has a diameter to wall thickness ratio less than 70.
(b) Each circumferential weld of steel pipe which is located where the stress during bending causes a permanent deformation in the pipe must be nondestructively tested either before or after the bending process.
(c) Wrought-steel welding elbows and transverse segments of these elbows may not be used for changes in direction on steel pipe that is 2 inches (51 millimeters) or more in diameter unless the arc length, as measured along the crotch, is at least 1 inch (25 millimeters).
(a) A wrinkle bend may not be made on steel pipe to be operated at a pressure that produces a hoop stress of 30 percent, or more, of SMYS.
(b) Each wrinkle bend on steel pipe must comply with the following:
(1) The bend must not have any sharp kinks.
(2) When measured along the crotch of the bend, the wrinkles must be a distance of at least one pipe diameter.
(3) On pipe 16 inches (406 millimeters) or larger in diameter, the bend may not have a deflection of more than 1
(4) On pipe containing a longitudinal weld the longitudinal seam must be as near as practicable to the neutral axis of the bend.
(a) The operator must take all practicable steps to protect each transmission line or main from washouts, floods, unstable soil, landslides, or other hazards that may cause the pipeline to move or to sustain abnormal loads. In addition, the operator must take all practicable steps to protect offshore pipelines from damage by mud slides, water currents, hurricanes, ship anchors, and fishing operations.
(b) Each aboveground transmission line or main, not located offshore or in inland navigable water areas, must be protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a safe distance from the traffic or by installing barricades.
(c) Pipelines, including pipe risers, on each platform located offshore or in inland navigable waters must be protected from accidental damage by vessels.
(a) When installed in a ditch, each transmission line that is to be operated at a pressure producing a hoop stress of 20 percent or more of SMYS must be installed so that the pipe fits the ditch so as to minimize stresses and protect the pipe coating from damage.
(b) When a ditch for a transmission line or main is backfilled, it must be backfilled in a manner that:
(1) Provides firm support under the pipe; and
(2) Prevents damage to the pipe and pipe coating from equipment or from the backfill material.
(c) All offshore pipe in water at least 12 feet (3.7 meters) deep but not more than 200 feet (61 meters) deep, as measured from the mean low tide, except pipe in the Gulf of Mexico and its inlets under 15 feet (4.6 meters) of water, must be installed so that the top of the pipe is below the natural bottom unless the pipe is supported by stanchions, held in place by anchors or heavy concrete coating, or protected by an equivalent means. Pipe in the Gulf of Mexico and its inlets under 15 feet (4.6 meters) of water must be installed so that the top of the pipe is 36 inches (914 millimeters) below the seabed for normal excavation or 18 inches (457 millimeters) for rock excavation.
(a) Plastic pipe must be installed below ground level except as provided by paragraphs (g) and (h) of this section.
(b) Plastic pipe that is installed in a vault or any other below grade enclosure must be completely encased in gas-tight metal pipe and fittings that are adequately protected from corrosion.
(c) Plastic pipe must be installed so as to minimize shear or tensile stresses.
(d) Thermoplastic pipe that is not encased must have a minimum wall thickness of 0.090 inch (2.29 millimeters), except that pipe with an outside diameter of 0.875 inch (22.3 millimeters) or less may have a minimum wall thickness of 0.062 inch (1.58 millimeters).
(e) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means.
(f) Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. The leading end of the plastic must be closed before insertion.
(g) Uncased plastic pipe may be temporarily installed above ground level under the following conditions:
(1) The operator must be able to demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer's recommended maximum period of exposure or 2 years, whichever is less.
(2) The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage.
(3) The pipe adequately resists exposure to ultraviolet light and high and low temperatures.
(h) Plastic pipe may be installed on bridges provided that it is:
(1) Installed with protection from mechanical damage, such as installation in a metallic casing;
(2) Protected from ultraviolet radiation; and
(3) Not allowed to exceed the pipe temperature limits specified in § 192.123.
Each casing used on a transmission line or main under a railroad or highway must comply with the following:
(a) The casing must be designed to withstand the superimposed loads.
(b) If there is a possibility of water entering the casing, the ends must be sealed.
(c) If the ends of an unvented casing are sealed and the sealing is strong enough to retain the maximum allowable operating pressure of the pipe, the casing must be designed to hold this pressure at a stress level of not more than 72 percent of SMYS.
(d) If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing.
(a) Each transmission line must be installed with at least 12 inches (305 millimeters) of clearance from any other underground structure not associated with the transmission line. If this clearance cannot be attained, the transmission line must be protected from damage that might result from the proximity of the other structure.
(b) Each main must be installed with enough clearance from any other underground structure to allow proper maintenance and to protect against damage that might result from proximity to other structures.
(c) In addition to meeting the requirements of paragraph (a) or (b) of this section, each plastic transmission line or main must be installed with sufficient clearance, or must be insulated, from any source of heat so as to prevent the heat from impairing the serviceability of the pipe.
(d) Each pipe-type or bottle-type holder must be installed with a minimum clearance from any other holder as prescribed in § 192.175(b).
(a) Except as provided in paragraphs (c), (e), (f), and (g) of this section, each buried transmission line must be installed with a minimum cover as follows:
(b) Except as provided in paragraphs (c) and (d) of this section, each buried main must be installed with at least 24 inches (610 millimeters) of cover.
(c) Where an underground structure prevents the installation of a transmission line or main with the minimum cover, the transmission line or main may be installed with less cover if it is provided with additional protection to withstand anticipated external loads.
(d) A main may be installed with less than 24 inches (610 millimeters) of cover if the law of the State or municipality:
(1) Establishes a minimum cover of less than 24 inches (610 millimeters);
(2) Requires that mains be installed in a common trench with other utility lines; and
(3) Provides adequately for prevention of damage to the pipe by external forces.
(e) Except as provided in paragraph (c) of this section, all pipe installed in a navigable river, stream, or harbor must be installed with a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches (610 millimeters) in consolidated rock between the top of the pipe and the underwater natural bottom (as determined by recognized and generally accepted practices).
(f) All pipe installed offshore, except in the Gulf of Mexico and its inlets, under water not more than 200 feet (60 meters) deep, as measured from the mean low tide, must be installed as follows:
(1) Except as provided in paragraph (c) of this section, pipe under water less than 12 feet (3.66 meters) deep, must be installed with a minimum cover of 36 inches (914 millimeters) in soil or 18 inches (457 millimeters) in consolidated rock between the top of the pipe and the natural bottom.
(2) Pipe under water at least 12 feet (3.66 meters) deep must be installed so that the top of the pipe is below the natural bottom, unless the pipe is supported by stanchions, held in place by anchors or heavy concrete coating, or protected by an equivalent means.
(g) All pipelines installed under water in the Gulf of Mexico and its inlets, as defined in § 192.3, must be installed in accordance with § 192.612(b)(3).
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure calculated under § 192.620, a segment must meet the following additional construction requirements. Records must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
This subpart prescribes minimum requirements for installing customer meters, service regulators, service lines, service line valves, and service line connections to mains.
(a) Each meter and service regulator, whether inside or outside a building, must be installed in a readily accessible location and be protected from corrosion and other damage, including, if installed outside a building, vehicular damage that may be anticipated. However, the upstream regulator in a series may be buried.
(b) Each service regulator installed within a building must be located as near as practical to the point of service line entrance.
(c) Each meter installed within a building must be located in a ventilated place and not less than 3 feet (914 millimeters) from any source of ignition or any source of heat which might damage the meter.
(d) Where feasible, the upstream regulator in a series must be located outside the building, unless it is located in a separate metering or regulating building.
(a)
(b)
(1) Be rain and insect resistant;
(2) Be located at a place where gas from the vent can escape freely into the atmosphere and away from any opening into the building; and
(3) Be protected from damage caused by submergence in areas where flooding may occur.
(c)
(a) Each meter and each regulator must be installed so as to minimize anticipated stresses upon the connecting piping and the meter.
(b) When close all-thread nipples are used, the wall thickness remaining after the threads are cut must meet the minimum wall thickness requirements of this part.
(c) Connections made of lead or other easily damaged material may not be used in the installation of meters or regulators.
(d) Each regulator that might release gas in its operation must be vented to the outside atmosphere.
(a) A meter may not be used at a pressure that is more than 67 percent of the manufacturer's shell test pressure.
(b) Each newly installed meter manufactured after November 12, 1970, must have been tested to a minimum of 10 p.s.i. (69 kPa) gage.
(c) A rebuilt or repaired tinned steel case meter may not be used at a pressure that is more than 50 percent of the pressure used to test the meter after rebuilding or repairing.
(a)
(b)
(c)
(d)
(e)
(1) In the case of a metal service line, be protected against corrosion;
(2) In the case of a plastic service line, be protected from shearing action and backfill settlement; and
(3) Be sealed at the foundation wall to prevent leakage into the building.
(f)
(1) It must be encased in a gas tight conduit;
(2) The conduit and the service line must, if the service line supplies the building it underlies, extend into a normally usable and accessible part of the building; and
(3) The space between the conduit and the service line must be sealed to prevent gas leakage into the building and, if the conduit is sealed at both ends, a vent line from the annular space must extend to a point where gas would not be a hazard, and extend
(g)
(a) Each service line must have a service-line valve that meets the applicable requirements of subparts B and D of this part. A valve incorporated in a meter bar, that allows the meter to be bypassed, may not be used as a service-line valve.
(b) A soft seat service line valve may not be used if its ability to control the flow of gas could be adversely affected by exposure to anticipated heat.
(c) Each service-line valve on a high-pressure service line, installed above ground or in an area where the blowing of gas would be hazardous, must be designed and constructed to minimize the possibility of the removal of the core of the valve with other than specialized tools.
(a)
(b)
(c)
(a)
(b)
(1) Be designed and installed to effectively sustain the longitudinal pull-out or thrust forces caused by contraction or expansion of the piping, or by anticipated external or internal loading; and
(2) If gaskets are used in connecting the service line to the main connection fitting, have gaskets that are compatible with the kind of gas in the system.
(a) Each service line connected to a cast iron or ductile iron main must be connected by a mechanical clamp, by drilling and tapping the main, or by another method meeting the requirements of § 192.273.
(b) If a threaded tap is being inserted, the requirements of § 192.151 (b) and (c) must also be met.
Each steel service line to be operated at less than 100 p.s.i. (689 kPa) gage must be constructed of pipe designed for a minimum of 100 p.s.i. (689 kPa) gage.
(a) Cast or ductile iron pipe less than 6 inches (152 millimeters) in diameter may not be installed for service lines.
(b) If cast iron pipe or ductile iron pipe is installed for use as a service line, the part of the service line which extends through the building wall must be of steel pipe.
(c) A cast iron or ductile iron service line may not be installed in unstable soil or under a building.
(a) Each plastic service line outside a building must be installed below ground level, except that—
(1) It may be installed in accordance with § 192.321(g); and
(2) It may terminate above ground level and outside the building, if—
(i) The above ground level part of the plastic service line is protected against deterioration and external damage; and
(ii) The plastic service line is not used to support external loads.
(b) Each plastic service line inside a building must be protected against external damage.
Each copper service line installed within a building must be protected against external damage.
Each service line that is not placed in service upon completion of installation must comply with one of the following until the customer is supplied with gas:
(a) The valve that is closed to prevent the flow of gas to the customer must be provided with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator.
(b) A mechanical device or fitting that will prevent the flow of gas must be installed in the service line or in the meter assembly.
(c) The customer's piping must be physically disconnected from the gas supply and the open pipe ends sealed.
(a) Excess flow valves to be used on single residence service lines that operate continuously throughout the year at a pressure not less than 10 p.s.i. (69 kPa) gage must be manufactured and tested by the manufacturer according to an industry specification, or the manufacturer's written specification, to ensure that each valve will:
(1) Function properly up to the maximum operating pressure at which the valve is rated;
(2) Function properly at all temperatures reasonably expected in the operating environment of the service line;
(3) At 10 p.s.i. (69 kPa) gage:
(i) Close at, or not more than 50 percent above, the rated closure flow rate specified by the manufacturer; and
(ii) Upon closure, reduce gas flow—
(A) For an excess flow valve designed to allow pressure to equalize across the valve, to no more than 5 percent of the manufacturer's specified closure flow rate, up to a maximum of 20 cubic feet per hour (0.57 cubic meters per hour); or
(B) For an excess flow valve designed to prevent equalization of pressure across the valve, to no more than 0.4 cubic feet per hour (.01 cubic meters per hour); and
(4) Not close when the pressure is less than the manufacturer's minimum specified operating pressure and the flow rate is below the manufacturer's minimum specified closure flow rate.
(b) An excess flow valve must meet the applicable requirements of Subparts B and D of this part.
(c) An operator must mark or otherwise identify the presence of an excess flow valve in the service line.
(d) An operator shall locate an excess flow valve as near as practical to the fitting connecting the service line to its source of gas supply.
(e) An operator should not install an excess flow valve on a service line where the operator has prior experience with contaminants in the gas stream, where these contaminants could be expected to cause the excess flow valve to malfunction or where the excess flow valve would interfere with necessary operation and maintenance activities on the service, such as blowing liquids from the line.
(a)
(b)
(c)
(2) An explanation for the customer of the potential safety benefits that may be derived from installing an excess flow valve. The explanation must include that an excess flow valve is designed to shut off flow of natural gas automatically if the service line breaks;
(3) A description of installation, maintenance, and replacement costs. The notice must explain that if the customer requests the operator to install an EFV, the customer bears all costs associated with installation, and what those costs are. The notice must alert the customer that the costs for maintaining and replacing an EFV may later be incurred, and what those costs will be, to the extent known.
(d)
(i) On new service lines when the customer applies for service.
(ii) On replaced service lines when the operator determines the service line will be replaced.
(2) If a service line customer requests installation an operator must install the EFV at a mutually agreeable date.
(e)
(i) A copy of the notice currently in use; and
(ii) Evidence that notice has been sent to the service line customers set forth in paragraph (b) of this section, within the previous three years.
(2) [Reserved]
(f)
(1) That the operator will voluntarily install an excess flow valve or that the state or local jurisdiction requires installation;
(2) That excess flow valves meeting the performance standards in § 192.381 are not available to the operator;
(3) That the operator has prior experience with contaminants in the gas stream that could interfere with the operation of an excess flow valve, cause loss of service to a residence, or interfere with necessary operation or maintenance activities, such as blowing liquids from the line.
(4) That an emergency or short time notice replacement situation made it impractical for the operator to notify a service line customer before replacing a service line. Examples of these situations would be where an operator has to replace a service line quickly because of—
(i) Third party excavation damage;
(ii) Grade 1 leaks as defined in the Appendix G-192-11 of the Gas Piping Technology Committee guide for gas transmission and distribution systems;
(iii) A short notice service line relocation request.
(a) This subpart prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion.
(b) [Reserved]
(a)
(b)
(1) The requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, apply to the gathering line regardless of the date the pipeline was actually installed; and
(2) The requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply only if the pipeline substantially meets those requirements.
The corrosion control procedures required by § 192.605(b)(2), including those for the design, installation, operation, and maintenance of cathodic protection systems, must be carried out by, or under the direction of, a person qualified in pipeline corrosion control methods.
(a) Except as provided in paragraphs (b), (c), and (f) of this section, each buried or submerged pipeline installed after July 31, 1971, must be protected against external corrosion, including the following:
(1) It must have an external protective coating meeting the requirements of § 192.461.
(2) It must have a cathodic protection system designed to protect the pipeline in accordance with this subpart, installed and placed in operation within 1 year after completion of construction.
(b) An operator need not comply with paragraph (a) of this section, if the operator can demonstrate by tests, investigation, or experience in the area of application, including, as a minimum, soil resistivity measurements and tests for corrosion accelerating bacteria, that a corrosive environment does not exist. However, within 6 months after an installation made pursuant to the preceding sentence, the operator shall conduct tests, including pipe-to-soil potential measurements with respect to either a continuous reference electrode or an electrode using close spacing, not to exceed 20 feet (6 meters), and soil resistivity measurements at potential profile peak locations, to adequately evaluate the potential profile along the entire pipeline. If the tests made indicate that a corrosive condition exists, the pipeline must be cathodically protected in accordance with paragraph (a)(2) of this section.
(c) An operator need not comply with paragraph (a) of this section, if the operator can demonstrate by tests, investigation, or experience that—
(1) For a copper pipeline, a corrosive environment does not exist; or
(2) For a temporary pipeline with an operating period of service not to exceed 5 years beyond installation, corrosion during the 5-year period of service of the pipeline will not be detrimental to public safety.
(d) Notwithstanding the provisions of paragraph (b) or (c) of this section, if a pipeline is externally coated, it must be cathodically protected in accordance with paragraph (a)(2) of this section.
(e) Aluminum may not be installed in a buried or submerged pipeline if that aluminum is exposed to an environment with a natural pH in excess of 8, unless tests or experience indicate its suitability in the particular environment involved.
(f) This section does not apply to electrically isolated, metal alloy fittings in plastic pipelines, if:
(1) For the size fitting to be used, an operator can show by test, investigation, or experience in the area of application that adequate corrosion control is provided by the alloy composition; and
(2) The fitting is designed to prevent leakage caused by localized corrosion pitting.
(a) Except for buried piping at compressor, regulator, and measuring stations, each buried or submerged transmission line installed before August 1, 1971, that has an effective external coating must be cathodically protected along the entire area that is effectively coated, in accordance with this subpart. For the purposes of this subpart, a pipeline does not have an effective external coating if its cathodic protection current requirements are substantially the same as if it were bare. The operator shall make tests to determine the cathodic protection current requirements.
(b) Except for cast iron or ductile iron, each of the following buried or submerged pipelines installed before August 1, 1971, must be cathodically protected in accordance with this subpart in areas in which active corrosion is found:
(1) Bare or ineffectively coated transmission lines.
(2) Bare or coated pipes at compressor, regulator, and measuring stations.
(3) Bare or coated distribution lines.
Whenever an operator has knowledge that any portion of a buried pipeline is exposed, the exposed portion must be examined for evidence of external corrosion if the pipe is bare, or if the coating is deteriorated. If external corrosion requiring remedial action under §§ 192.483 through 192.489 is found, the operator shall investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion.
(a) Each external protective coating, whether conductive or insulating, applied for the purpose of external corrosion control must—
(1) Be applied on a properly prepared surface;
(2) Have sufficient adhesion to the metal surface to effectively resist underfilm migration of moisture;
(3) Be sufficiently ductile to resist cracking;
(4) Have sufficient strength to resist damage due to handling and soil stress; and
(5) Have properties compatible with any supplemental cathodic protection.
(b) Each external protective coating which is an electrically insulating type must also have low moisture absorption and high electrical resistance.
(c) Each external protective coating must be inspected just prior to lowering the pipe into the ditch and backfilling, and any damage detrimental to effective corrosion control must be repaired.
(d) Each external protective coating must be protected from damage resulting from adverse ditch conditions or damage from supporting blocks.
(e) If coated pipe is installed by boring, driving, or other similar method, precautions must be taken to minimize damage to the coating during installation.
(a) Each cathodic protection system required by this subpart must provide a level of cathodic protection that complies with one or more of the applicable criteria contained in appendix D of this part. If none of these criteria is applicable, the cathodic protection system must provide a level of cathodic protection at least equal to that provided by compliance with one or more of these criteria.
(b) If amphoteric metals are included in a buried or submerged pipeline containing a metal of different anodic potential—
(1) The amphoteric metals must be electrically isolated from the remainder of the pipeline and cathodically protected; or
(2) The entire buried or submerged pipeline must be cathodically protected at a cathodic potential that meets the requirements of appendix D of this part for amphoteric metals.
(c) The amount of cathodic protection must be controlled so as not to damage the protective coating or the pipe.
(a) Each pipeline that is under cathodic protection must be tested at least once each calendar year, but with intervals not exceeding 15 months, to determine whether the cathodic protection meets the requirements of § 192.463. However, if tests at those intervals are impractical for separately protected short sections of mains or transmission lines, not in excess of 100 feet (30 meters), or separately protected service lines, these pipelines may be surveyed on a sampling basis. At least 10 percent of these protected structures, distributed over the entire system must be surveyed each calendar year, with a different 10 percent checked each subsequent year, so that the entire system is tested in each 10-year period.
(b) Each cathodic protection rectifier or other impressed current power source must be inspected six times each calendar year, but with intervals not exceeding 2
(c) Each reverse current switch, each diode, and each interference bond whose failure would jeopardize structure protection must be electrically checked for proper performance six times each calendar year, but with intervals not exceeding 2
(d) Each operator shall take prompt remedial action to correct any deficiencies indicated by the monitoring.
(e) After the initial evaluation required by §§ 192.455(b) and (c) and 192.457(b), each operator must, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator must determine the areas of active corrosion by electrical survey. However, on distribution lines and where an electrical survey is impractical on transmission lines, areas of active corrosion may be determined by other means that include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. In this section:
(1)
(2)
(3)
(a) Each buried or submerged pipeline must be electrically isolated from other underground metallic structures, unless the pipeline and the other structures are electrically interconnected and cathodically protected as a single unit.
(b) One or more insulating devices must be installed where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control.
(c) Except for unprotected copper inserted in ferrous pipe, each pipeline must be electrically isolated from metallic casings that are a part of the underground system. However, if isolation is not achieved because it is impractical, other measures must be taken to minimize corrosion of the pipeline inside the casing.
(d) Inspection and electrical tests must be made to assure that electrical isolation is adequate.
(e) An insulating device may not be installed in an area where a combustible atmosphere is anticipated unless precautions are taken to prevent arcing.
(f) Where a pipeline is located in close proximity to electrical transmission tower footings, ground cables or counterpoise, or in other areas where fault currents or unusual risk of lightning may be anticipated, it must be provided with protection against damage due to fault currents or lightning, and protective measures must also be taken at insulating devices.
Each pipeline under cathodic protection required by this subpart must have sufficient test stations or other contact points for electrical measurement to determine the adequacy of cathodic protection.
(a) Each test lead wire must be connected to the pipeline so as to remain mechanically secure and electrically conductive.
(b) Each test lead wire must be attached to the pipeline so as to minimize stress concentration on the pipe.
(c) Each bared test lead wire and bared metallic area at point of connection to the pipeline must be coated with an electrical insulating material compatible with the pipe coating and the insulation on the wire.
(a) Each operator whose pipeline system is subjected to stray currents shall have in effect a continuing program to minimize the detrimental effects of such currents.
(b) Each impressed current type cathodic protection system or galvanic anode system must be designed and installed so as to minimize any adverse effects on existing adjacent underground metallic structures.
(a) Corrosive gas may not be transported by pipeline, unless the corrosive effect of the gas on the pipeline has been investigated and steps have been taken to minimize internal corrosion.
(b) Whenever any pipe is removed from a pipeline for any reason, the internal surface must be inspected for evidence of corrosion. If internal corrosion is found—
(1) The adjacent pipe must be investigated to determine the extent of internal corrosion;
(2) Replacement must be made to the extent required by the applicable paragraphs of §§ 192.485, 192.487, or 192.489; and
(3) Steps must be taken to minimize the internal corrosion.
(c) Gas containing more than 0.25 grain of hydrogen sulfide per 100 cubic feet (5.8 milligrams/m
(a)
(1) Be configured to reduce the risk that liquids will collect in the line;
(2) Have effective liquid removal features whenever the configuration would allow liquids to collect; and
(3) Allow use of devices for monitoring internal corrosion at locations with significant potential for internal corrosion.
(b)
(1) Offshore pipeline; and
(2) Pipeline installed or line pipe, valve, fitting or other line component replaced before May 23, 2007.
(c)
(d)
If corrosive gas is being transported, coupons or other suitable means must be used to determine the effectiveness of the steps taken to minimize internal corrosion. Each coupon or other means of monitoring internal corrosion must be checked two times each calendar year, but with intervals not exceeding 7
(a) Each operator must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section.
(b) Coating material must be suitable for the prevention of atmospheric corrosion.
(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, the operator need not protect from atmospheric corrosion any pipeline for which the operator demonstrates by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will—
(1) Only be a light surface oxide; or
(2) Not affect the safe operation of the pipeline before the next scheduled inspection.
(a) Each operator must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows:
(b) During inspections the operator must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water.
(c) If atmospheric corrosion is found during an inspection, the operator must provide protection against the corrosion as required by § 192.479.
(a) Each segment of metallic pipe that replaces pipe removed from a buried or submerged pipeline because of external corrosion must have a properly prepared surface and must be provided with an external protective coating that meets the requirements of § 192.461.
(b) Each segment of metallic pipe that replaces pipe removed from a buried or submerged pipeline because of external corrosion must be cathodically protected in accordance with this subpart.
(c) Except for cast iron or ductile iron pipe, each segment of buried or submerged pipe that is required to be repaired because of external corrosion must be cathodically protected in accordance with this subpart.
(a)
(b)
(c) Under paragraphs (a) and (b) of this section, the strength of pipe based on actual remaining wall thickness may be determined by the procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations prescribed in the procedures.
(a)
(b)
(a)
(b)
Each operator that uses direct assessment as defined in § 192.903 on an onshore transmission line made primarily of steel or iron to evaluate the effects of a threat in the first column must carry out the direct assessment according to the standard listed in the second column. These standards do not apply to methods associated with direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process.
(a) Each operator shall maintain records or maps to show the location of cathodically protected piping, cathodic protection facilities, galvanic anodes, and neighboring structures bonded to the cathodic protection system. Records or maps showing a stated number of anodes, installed in a stated manner or spacing, need not show specific distances to each buried anode.
(b) Each record or map required by paragraph (a) of this section must be retained for as long as the pipeline remains in service.
(c) Each operator shall maintain a record of each test, survey, or inspection required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that a corrosive condition does not exist. These records must be retained for at least 5 years, except that records related to §§ 192.465 (a) and (e) and 192.475(b) must be retained for as long as the pipeline remains in service.
This subpart prescribes minimum leak-test and strength-test requirements for pipelines.
(a) No person may operate a new segment of pipeline, or return to service a segment of pipeline that has been relocated or replaced, until—
(1) It has been tested in accordance with this subpart and § 192.619 to substantiate the maximum allowable operating pressure; and
(2) Each potentially hazardous leak has been located and eliminated.
(b) The test medium must be liquid, air, natural gas, or inert gas that is—
(1) Compatible with the material of which the pipeline is constructed;
(2) Relatively free of sedimentary materials; and
(3) Except for natural gas, nonflammable.
(c) Except as provided in § 192.505(a), if air, natural gas, or inert gas is used as the test medium, the following maximum hoop stress limitations apply:
(d) Each joint used to tie in a test segment of pipeline is excepted from the specific test requirements of this subpart, but each non-welded joint must be leak tested at not less than its operating pressure.
(a) Except for service lines, each segment of a steel pipeline that is to operate at a hoop stress of 30 percent or more of SMYS must be strength tested in accordance with this section to substantiate the proposed maximum allowable operating pressure. In addition, in a Class 1 or Class 2 location, if there is a building intended for human occupancy within 300 feet (91 meters) of a pipeline, a hydrostatic test must be conducted to a test pressure of at least 125 percent of maximum operating pressure on that segment of the pipeline within 300 feet (91 meters) of such a building, but in no event may the test section be less than 600 feet (183 meters) unless the length of the newly installed or relocated pipe is less than 600 feet (183 meters). However, if the buildings are evacuated while the hoop stress exceeds 50 percent of SMYS, air or inert gas may be used as the test medium.
(b) In a Class 1 or Class 2 location, each compressor station regulator station, and measuring station, must be tested to at least Class 3 location test requirements.
(c) Except as provided in paragraph (e) of this section, the strength test must be conducted by maintaining the pressure at or above the test pressure for at least 8 hours.
(d) If a component other than pipe is the only item being replaced or added to a pipeline, a strength test after installation is not required, if the manufacturer of the component certifies that—
(1) The component was tested to at least the pressure required for the pipeline to which it is being added;
(2) The component was manufactured under a quality control system that ensures that each item manufactured is at least equal in strength to a prototype and that the prototype was tested to at least the pressure required for the pipeline to which it is being added; or
(3) The component carries a pressure rating established through applicable ASME/ANSI, MSS specifications, or by unit strength calculations as described in § 192.143.
(e) For fabricated units and short sections of pipe, for which a post installation test is impractical, a preinstallation strength test must be conducted by maintaining the pressure at or above the test pressure for at least 4 hours.
Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage must be tested in accordance with the following:
(a) The pipeline operator must use a test procedure that will ensure discovery of all potentially hazardous leaks in the segment being tested.
(b) If, during the test, the segment is to be stressed to 20 percent or more of SMYS and natural gas, inert gas, or air is the test medium—
(1) A leak test must be made at a pressure between 100 p.s.i. (689 kPa) gage and the pressure required to produce a hoop stress of 20 percent of SMYS; or
(2) The line must be walked to check for leaks while the hoop stress is held at approximately 20 percent of SMYS.
(c) The pressure must be maintained at or above the test pressure for at least 1 hour.
Except for service lines and plastic pipelines, each segment of a pipeline that is to be operated below 100 p.s.i. (689 kPa) gage must be leak tested in accordance with the following:
(a) The test procedure used must ensure discovery of all potentially hazardous leaks in the segment being tested.
(b) Each main that is to be operated at less than 1 p.s.i. (6.9 kPa) gage must be tested to at least 10 p.s.i. (69 kPa) gage and each main to be operated at or above 1 p.s.i. (6.9 kPa) gage must be tested to at least 90 p.s.i. (621 kPa) gage.
(a) Each segment of a service line (other than plastic) must be leak tested in accordance with this section before being placed in service. If feasible, the service line connection to the main must be included in the test; if not feasible, it must be given a leakage test at the operating pressure when placed in service.
(b) Each segment of a service line (other than plastic) intended to be operated at a pressure of at least 1 p.s.i. (6.9 kPa) gage but not more than 40 p.s.i. (276 kPa) gage must be given a leak test at a pressure of not less than 50 p.s.i. (345 kPa) gage.
(c) Each segment of a service line (other than plastic) intended to be operated at pressures of more than 40 p.s.i. (276 kPa) gage must be tested to at least 90 p.s.i. (621 kPa) gage, except that each segment of a steel service line stressed to 20 percent or more of SMYS must be tested in accordance with § 192.507 of this subpart.
(a) Each segment of a plastic pipeline must be tested in accordance with this section.
(b) The test procedure must insure discovery of all potentially hazardous leaks in the segment being tested.
(c) The test pressure must be at least 150 percent of the maximum operating pressure or 50 p.s.i. (345 kPa) gage, whichever is greater. However, the maximum test pressure may not be more than three times the pressure determined under § 192.121, at a temperature not less than the pipe temperature during the test.
(d) During the test, the temperature of thermoplastic material may not be more than 100°F (38°C), or the temperature at which the material's long-term hydrostatic strength has been determined under the listed specification, whichever is greater.
(a) In conducting tests under this subpart, each operator shall insure that every reasonable precaution is taken to protect its employees and the general public during the testing. Whenever the hoop stress of the segment of the pipeline being tested will exceed 50 percent of SMYS, the operator shall take all practicable steps to keep persons not working on the testing operation outside of the testing area until the pressure is reduced to or below the proposed maximum allowable operating pressure.
(b) The operator shall insure that the test medium is disposed of in a manner that will minimize damage to the environment.
(a) Each operator shall make, and retain for the useful life of the pipeline,
(1) The operator's name, the name of the operator's employee responsible for making the test, and the name of any test company used.
(2) Test medium used.
(3) Test pressure.
(4) Test duration.
(5) Pressure recording charts, or other record of pressure readings.
(6) Elevation variations, whenever significant for the particular test.
(7) Leaks and failures noted and their disposition.
(b) Each operator must maintain a record of each test required by §§ 192.509, 192.511, and 192.513 for at least 5 years.
This subpart prescribes minimum requirements for increasing maximum allowable operating pressures (uprating) for pipelines.
(a)
(1) At the end of each incremental increase, the pressure must be held constant while the entire segment of pipeline that is affected is checked for leaks.
(2) Each leak detected must be repaired before a further pressure increase is made, except that a leak determined not to be potentially hazardous need not be repaired, if it is monitored during the pressure increase and it does not become potentially hazardous.
(b)
(c)
(d)
(a) Unless the requirements of this section have been met, no person may subject any segment of a steel pipeline to an operating pressure that will produce a hoop stress of 30 percent or more of SMYS and that is above the established maximum allowable operating pressure.
(b) Before increasing operating pressure above the previously established maximum allowable operating pressure the operator shall:
(1) Review the design, operating, and maintenance history and previous testing of the segment of pipeline and determine whether the proposed increase is safe and consistent with the requirements of this part; and
(2) Make any repairs, replacements, or alterations in the segment of pipeline that are necessary for safe operation at the increased pressure.
(c) After complying with paragraph (b) of this section, an operator may increase the maximum allowable operating pressure of a segment of pipeline constructed before September 12, 1970, to the highest pressure that is permitted under § 192.619, using as test
(d) After complying with paragraph (b) of this section, an operator that does not qualify under paragraph (c) of this section may increase the previously established maximum allowable operating pressure if at least one of the following requirements is met:
(1) The segment of pipeline is successfully tested in accordance with the requirements of this part for a new line of the same material in the same location.
(2) An increased maximum allowable operating pressure may be established for a segment of pipeline in a Class 1 location if the line has not previously been tested, and if:
(i) It is impractical to test it in accordance with the requirements of this part;
(ii) The new maximum operating pressure does not exceed 80 percent of that allowed for a new line of the same design in the same location; and
(iii) The operator determines that the new maximum allowable operating pressure is consistent with the condition of the segment of pipeline and the design requirements of this part.
(e) Where a segment of pipeline is uprated in accordance with paragraph (c) or (d)(2) of this section, the increase in pressure must be made in increments that are equal to:
(1) 10 percent of the pressure before the uprating; or
(2) 25 percent of the total pressure increase,
(a) Unless the requirements of this section have been met, no person may subject:
(1) A segment of steel pipeline to an operating pressure that will produce a hoop stress less than 30 percent of SMYS and that is above the previously established maximum allowable operating pressure; or
(2) A plastic, cast iron, or ductile iron pipeline segment to an operating pressure that is above the previously established maximum allowable operating pressure.
(b) Before increasing operating pressure above the previously established maximum allowable operating pressure, the operator shall:
(1) Review the design, operating, and maintenance history of the segment of pipeline;
(2) Make a leakage survey (if it has been more than 1 year since the last survey) and repair any leaks that are found, except that a leak determined not to be potentially hazardous need not be repaired, if it is monitored during the pressure increase and it does not become potentially hazardous;
(3) Make any repairs, replacements, or alterations in the segment of pipeline that are necessary for safe operation at the increased pressure;
(4) Reinforce or anchor offsets, bends and dead ends in pipe joined by compression couplings or bell and spigot joints to prevent failure of the pipe joint, if the offset, bend, or dead end is exposed in an excavation;
(5) Isolate the segment of pipeline in which the pressure is to be increased from any adjacent segment that will continue to be operated at a lower pressure; and
(6) If the pressure in mains or service lines, or both, is to be higher than the pressure delivered to the customer, install a service regulator on each service line and test each regulator to determine that it is functioning. Pressure may be increased as necessary to test each regulator, after a regulator has been installed on each pipeline subject to the increased pressure.
(c) After complying with paragraph (b) of this section, the increase in maximum allowable operating pressure must be made in increments that are equal to 10 p.s.i. (69 kPa) gage or 25 percent of the total pressure increase, whichever produces the fewer number of increments. Whenever the requirements of paragraph (b)(6) of this section apply, there must be at least two approximately equal incremental increases.
(d) If records for cast iron or ductile iron pipeline facilities are not complete enough to determine stresses produced by internal pressure, trench loading, rolling loads, beam stresses, and other bending loads, in evaluating the level of safety of the pipeline when operating at the proposed increased pressure, the following procedures must be followed:
(1) In estimating the stresses, if the original laying conditions cannot be ascertained, the operator shall assume that cast iron pipe was supported on blocks with tamped backfill and that ductile iron pipe was laid without blocks with tamped backfill.
(2) Unless the actual maximum cover depth is known, the operator shall measure the actual cover in at least three places where the cover is most likely to be greatest and shall use the greatest cover measured.
(3) Unless the actual nominal wall thickness is known, the operator shall determine the wall thickness by cutting and measuring coupons from at least three separate pipe lengths. The coupons must be cut from pipe lengths in areas where the cover depth is most likely to be the greatest. The average of all measurements taken must be increased by the allowance indicated in the following table:
(4) For cast iron pipe, unless the pipe manufacturing process is known, the operator shall assume that the pipe is pit cast pipe with a bursting tensile strength of 11,000 p.s.i. (76 MPa) gage and a modulus of rupture of 31,000 p.s.i. (214 MPa) gage.
This subpart prescribes minimum requirements for the operation of pipeline facilities.
(a) No person may operate a segment of pipeline unless it is operated in accordance with this subpart.
(b) Each operator shall keep records necessary to administer the procedures established under § 192.605.
(c) The Administrator or the State Agency that has submitted a current certification under the pipeline safety laws, (49 U.S.C. 60101
(a)
(b)
(1) Operating, maintaining, and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part.
(2) Controlling corrosion in accordance with the operations and maintenance requirements of subpart I of this part.
(3) Making construction records, maps, and operating history available to appropriate operating personnel.
(4) Gathering of data needed for reporting incidents under Part 191 of this chapter in a timely and effective manner.
(5) Starting up and shutting down any part of the pipeline in a manner designed to assure operation within the MAOP limits prescribed by this part, plus the build-up allowed for operation of pressure-limiting and control devices.
(6) Maintaining compressor stations, including provisions for isolating units or sections of pipe and for purging before returning to service.
(7) Starting, operating and shutting down gas compressor units.
(8) Periodically reviewing the work done by operator personnel to determine the effectiveness, and adequacy of the procedures used in normal operation and maintenance and modifying the procedures when deficiencies are found.
(9) Taking adequate precautions in excavated trenches to protect personnel from the hazards of unsafe accumulations of vapor or gas, and making available when needed at the excavation, emergency rescue equipment, including a breathing apparatus and, a rescue harness and line.
(10) Systematic and routine testing and inspection of pipe-type or bottle-type holders including—
(i) Provision for detecting external corrosion before the strength of the container has been impaired;
(ii) Periodic sampling and testing of gas in storage to determine the dew point of vapors contained in the stored gas which, if condensed, might cause internal corrosion or interfere with the safe operation of the storage plant; and
(iii) Periodic inspection and testing of pressure limiting equipment to determine that it is in safe operating condition and has adequate capacity.
(11) Responding promptly to a report of a gas odor inside or near a building, unless the operator's emergency procedures under § 192.615(a)(3) specifically apply to these reports.
(c)
(1) Responding to, investigating, and correcting the cause of:
(i) Unintended closure of valves or shutdowns;
(ii) Increase or decrease in pressure or flow rate outside normal operating limits;
(iii) Loss of communications;
(iv) Operation of any safety device; and
(v) Any other foreseeable malfunction of a component, deviation from normal operation, or personnel error, which may result in a hazard to persons or property.
(2) Checking variations from normal operation after abnormal operation has ended at sufficient critical locations in the system to determine continued integrity and safe operation.
(3) Notifying responsible operator personnel when notice of an abnormal operation is received.
(4) Periodically reviewing the response of operator personnel to determine the effectiveness of the procedures controlling abnormal operation and taking corrective action where deficiencies are found.
(5) The requirements of this paragraph (c) do not apply to natural gas distribution operators that are operating transmission lines in connection with their distribution system.
(d)
(e)
Whenever an increase in population density indicates a change in class location for a segment of an existing steel pipeline operating at hoop stress that is more than 40 percent of SMYS, or indicates that the hoop stress corresponding to the established maximum allowable operating pressure for a segment of existing pipeline is not commensurate with the present class location, the operator shall immediately make a study to determine:
(a) The present class location for the segment involved.
(b) The design, construction, and testing procedures followed in the original construction, and a comparison of these procedures with those required for the present class location by the applicable provisions of this part.
(c) The physical condition of the segment to the extent it can be ascertained from available records;
(d) The operating and maintenance history of the segment;
(e) The maximum actual operating pressure and the corresponding operating hoop stress, taking pressure gradient into account, for the segment of pipeline involved; and
(f) The actual area affected by the population density increase, and physical barriers or other factors which may limit further expansion of the more densely populated area.
(a) If the hoop stress corresponding to the established maximum allowable operating pressure of a segment of pipeline is not commensurate with the present class location, and the segment is in satisfactory physical condition, the maximum allowable operating pressure of that segment of pipeline must be confirmed or revised according to one of the following requirements:
(1) If the segment involved has been previously tested in place for a period of not less than 8 hours:
(i) The maximum allowable operating pressure is 0.8 times the test pressure in Class 2 locations, 0.667 times the test pressure in Class 3 locations, or 0.555 times the test pressure in Class 4 locations. The corresponding hoop stress may not exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 50 percent of SMYS in Class 4 locations.
(ii) The alternative maximum allowable operating pressure is 0.8 times the test pressure in Class 2 locations and 0.667 times the test pressure in Class 3 locations. For pipelines operating at alternative maximum allowable pressure per § 192.620, the corresponding hoop stress may not exceed 80 percent of the SMYS of the pipe in Class 2 locations and 67 percent of SMYS in Class 3 locations.
(2) The maximum allowable operating pressure of the segment involved must be reduced so that the corresponding hoop stress is not more than that allowed by this part for new segments of pipelines in the existing class location.
(3) The segment involved must be tested in accordance with the applicable requirements of subpart J of this part, and its maximum allowable operating pressure must then be established according to the following criteria:
(i) The maximum allowable operating pressure after the requalification test is 0.8 times the test pressure for Class 2 locations, 0.667 times the test pressure for Class 3 locations, and 0.555
(ii) The corresponding hoop stress may not exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 50 percent of SMYS in Class 4 locations.
(iii) For pipeline operating at an alternative maximum allowable operating pressure per § 192.620, the alternative maximum allowable operating pressure after the requalification test is 0.8 times the test pressure for Class 2 locations and 0.667 times the test pressure for Class 3 locations. The corresponding hoop stress may not exceed 80 percent of the SMYS of the pipe in Class 2 locations and 67 percent of SMYS in Class 3 locations.
(b) The maximum allowable operating pressure confirmed or revised in accordance with this section, may not exceed the maximum allowable operating pressure established before the confirmation or revision.
(c) Confirmation or revision of the maximum allowable operating pressure of a segment of pipeline in accordance with this section does not preclude the application of §§ 192.553 and 192.555.
(d) Confirmation or revision of the maximum allowable operating pressure that is required as a result of a study under § 192.609 must be completed within 24 months of the change in class location. Pressure reduction under paragraph (a) (1) or (2) of this section within the 24-month period does not preclude establishing a maximum allowable operating pressure under paragraph (a)(3) of this section at a later date.
(a) Each operator shall prepare and follow a procedure to identify its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water that are at risk of being an exposed underwater pipeline or a hazard to navigation. The procedures must be in effect August 10, 2005.
(b) Each operator shall conduct appropriate periodic underwater inspections of its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water based on the identified risk.
(c) If an operator discovers that its pipeline is an exposed underwater pipeline or poses a hazard to navigation, the operator shall—
(1) Promptly, but not later than 24 hours after discovery, notify the National Response Center, telephone: 1-800-424-8802, of the location and, if available, the geographic coordinates of that pipeline.
(2) Promptly, but not later than 7 days after discovery, mark the location of the pipeline in accordance with 33 CFR part 64 at the ends of the pipeline segment and at intervals of not over 500 yards (457 meters) long, except that a pipeline segment less than 200 yards (183 meters) long need only be marked at the center; and
(3) Within 6 months after discovery, or not later than November 1 of the following year if the 6 month period is later than November 1 of the year of discovery, bury the pipeline so that the top of the pipe is 36 inches (914 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) for normal excavation or 18 inches (457 millimeters) for rock excavation.
(i) An operator may employ engineered alternatives to burial that meet or exceed the level of protection provided by burial.
(ii) If an operator cannot obtain required state or Federal permits in time to comply with this section, it must notify OPS; specify whether the required permit is State or Federal; and, justify the delay.
(a) Each operator shall have a procedure for continuing surveillance of its facilities to determine and take appropriate action concerning changes in class location, failures, leakage history, corrosion, substantial changes in cathodic protection requirements, and other unusual operating and maintenance conditions.
(b) If a segment of pipeline is determined to be in unsatisfactory condition but no immediate hazard exists, the operator shall initiate a program to recondition or phase out the segment involved, or, if the segment cannot be reconditioned or phased out, reduce the maximum allowable operating pressure in accordance with § 192.619 (a) and (b).
(a) Except as provided in paragraphs (d) and (e) of this section, each operator of a buried pipeline must carry out, in accordance with this section, a written program to prevent damage to that pipeline from excavation activities. For the purposes of this section, the term “excavation activities” includes excavation, blasting, boring, tunneling, backfilling, the removal of aboveground structures by either explosive or mechanical means, and other earthmoving operations.
(b) An operator may comply with any of the requirements of paragraph (c) of this section through participation in a public service program, such as a one-call system, but such participation does not relieve the operator of responsibility for compliance with this section. However, an operator must perform the duties of paragraph (c)(3) of this section through participation in a one-call system, if that one-call system is a qualified one-call system. In areas that are covered by more than one qualified one-call system, an operator need only join one of the qualified one-call systems if there is a central telephone number for excavators to call for excavation activities, or if the one-call systems in those areas communicate with one another. An operator's pipeline system must be covered by a qualified one-call system where there is one in place. For the purpose of this section, a one-call system is considered a “qualified one-call system” if it meets the requirements of section (b)(1) or (b)(2) of this section.
(1) The state has adopted a one-call damage prevention program under § 198.37 of this chapter; or
(2) The one-call system:
(i) Is operated in accordance with § 198.39 of this chapter;
(ii) Provides a pipeline operator an opportunity similar to a voluntary participant to have a part in management responsibilities; and
(iii) Assesses a participating pipeline operator a fee that is proportionate to the costs of the one-call system's coverage of the operator's pipeline.
(c) The damage prevention program required by paragraph (a) of this section must, at a minimum:
(1) Include the identity, on a current basis, of persons who normally engage in excavation activities in the area in which the pipeline is located.
(2) Provides for notification of the public in the vicinity of the pipeline and actual notification of the persons identified in paragraph (c)(1) of this section of the following as often as needed to make them aware of the damage prevention program:
(i) The program's existence and purpose; and
(ii) How to learn the location of underground pipelines before excavation activities are begun.
(3) Provide a means of receiving and recording notification of planned excavation activities.
(4) If the operator has buried pipelines in the area of excavation activity, provide for actual notification of persons who give notice of their intent to excavate of the type of temporary marking to be provided and how to identify the markings.
(5) Provide for temporary marking of buried pipelines in the area of excavation activity before, as far as practical, the activity begins.
(6) Provide as follows for inspection of pipelines that an operator has reason to believe could be damaged by excavation activities:
(i) The inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline; and
(ii) In the case of blasting, any inspection must include leakage surveys.
(d) A damage prevention program under this section is not required for the following pipelines:
(1) Pipelines located offshore.
(2) Pipelines, other than those located offshore, in Class 1 or 2 locations until September 20, 1995.
(3) Pipelines to which access is physically controlled by the operator.
(e) Pipelines operated by persons other than municipalities (including operators of master meters) whose primary activity does not include the transportation of gas need not comply with the following:
(1) The requirement of paragraph (a) of this section that the damage prevention program be written; and
(2) The requirements of paragraphs (c)(1) and (c)(2) of this section.
(a) Each operator shall establish written procedures to minimize the hazard resulting from a gas pipeline emergency. At a minimum, the procedures must provide for the following:
(1) Receiving, identifying, and classifying notices of events which require immediate response by the operator.
(2) Establishing and maintaining adequate means of communication with appropriate fire, police, and other public officials.
(3) Prompt and effective response to a notice of each type of emergency, including the following:
(i) Gas detected inside or near a building.
(ii) Fire located near or directly involving a pipeline facility.
(iii) Explosion occurring near or directly involving a pipeline facility.
(iv) Natural disaster.
(4) The availability of personnel, equipment, tools, and materials, as needed at the scene of an emergency.
(5) Actions directed toward protecting people first and then property.
(6) Emergency shutdown and pressure reduction in any section of the operator's pipeline system necessary to minimize hazards to life or property.
(7) Making safe any actual or potential hazard to life or property.
(8) Notifying appropriate fire, police, and other public officials of gas pipeline emergencies and coordinating with them both planned responses and actual responses during an emergency.
(9) Safely restoring any service outage.
(10) Beginning action under § 192.617, if applicable, as soon after the end of the emergency as possible.
(b) Each operator shall:
(1) Furnish its supervisors who are responsible for emergency action a copy of that portion of the latest edition of the emergency procedures established under paragraph (a) of this section as necessary for compliance with those procedures.
(2) Train the appropriate operating personnel to assure that they are knowledgeable of the emergency procedures and verify that the training is effective.
(3) Review employee activities to determine whether the procedures were effectively followed in each emergency.
(c) Each operator shall establish and maintain liaison with appropriate fire, police, and other public officials to:
(1) Learn the responsibility and resources of each government organization that may respond to a gas pipeline emergency;
(2) Acquaint the officials with the operator's ability in responding to a gas pipeline emergency;
(3) Identify the types of gas pipeline emergencies of which the operator notifies the officials; and
(4) Plan how the operator and officials can engage in mutual assistance to minimize hazards to life or property.
(a) Except for an operator of a master meter or petroleum gas system covered under paragraph (j) of this section, each pipeline operator must develop and implement a written continuing public education program that follows the guidance provided in the American Petroleum Institute's (API) Recommended Practice (RP) 1162 (incorporated by reference,
(b) The operator's program must follow the general program recommendations of API RP 1162 and assess the unique attributes and characteristics of the operator's pipeline and facilities.
(c) The operator must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162, unless the operator provides justification in its program or procedural manual as to why compliance with all or certain provisions of the recommended practice is not practicable and not necessary for safety.
(d) The operator's program must specifically include provisions to educate the public, appropriate government organizations, and persons engaged in excavation related activities on:
(1) Use of a one-call notification system prior to excavation and other damage prevention activities;
(2) Possible hazards associated with unintended releases from a gas pipeline facility;
(3) Physical indications that such a release may have occurred;
(4) Steps that should be taken for public safety in the event of a gas pipeline release; and
(5) Procedures for reporting such an event.
(e) The program must include activities to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations.
(f) The program and the media used must be as comprehensive as necessary to reach all areas in which the operator transports gas.
(g) The program must be conducted in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator's area.
(h) Operators in existence on June 20, 2005, must have completed their written programs no later than June 20, 2006. The operator of a master meter or petroleum gas system covered under paragraph (j) of this section must complete development of its written procedure by June 13, 2008. Upon request, operators must submit their completed programs to PHMSA or, in the case of an intrastate pipeline facility operator, the appropriate State agency.
(i) The operator's program documentation and evaluation results must be available for periodic review by appropriate regulatory agencies.
(j) Unless the operator transports gas as a primary activity, the operator of a master meter or petroleum gas system is not required to develop a public awareness program as prescribed in paragraphs (a) through (g) of this section. Instead the operator must develop and implement a written procedure to provide its customers public awareness messages twice annually. If the master meter or petroleum gas system is located on property the operator does not control, the operator must provide similar messages twice annually to persons controlling the property. The public awareness message must include:
(1) A description of the purpose and reliability of the pipeline;
(2) An overview of the hazards of the pipeline and prevention measures used;
(3) Information about damage prevention;
(4) How to recognize and respond to a leak; and
(5) How to get additional information.
Each operator shall establish procedures for analyzing accidents and failures, including the selection of samples of the failed facility or equipment for laboratory examination, where appropriate, for the purpose of determining the causes of the failure and minimizing the possibility of a recurrence.
(a) No person may operate a segment of steel or plastic pipeline at a pressure that exceeds a maximum allowable operating pressure determined under paragraph (c) or (d) of this section, or the lowest of the following:
(1) The design pressure of the weakest element in the segment, determined in accordance with subparts C and D of this part. However, for steel pipe in pipelines being converted under § 192.14 or uprated under subpart K of this part, if any variable necessary to determine the design pressure under
(i) Eighty percent of the first test pressure that produces yield under section N5 of Appendix N of ASME B31.8 (incorporated by reference,
(ii) If the pipe is 12
(2) The pressure obtained by dividing the pressure to which the segment was tested after construction as follows:
(i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5.
(ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, the test pressure is divided by a factor determined in accordance with the following table:
(3) The highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested according to the requirements in paragraph (a)(2) of this section after the applicable date in the third column or the segment was uprated according to the requirements in subpart K of this part:
(4) The pressure determined by the operator to be the maximum safe pressure after considering the history of the segment, particularly known corrosion and the actual operating pressure.
(b) No person may operate a segment to which paragraph (a)(4) of this section is applicable, unless over-pressure protective devices are installed on the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with § 192.195.
(c) The requirements on pressure restrictions in this section do not apply in the following instance. An operator may operate a segment of pipeline found to be in satisfactory condition, considering its operating and maintenance history, at the highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column of the table in paragraph (a)(3) of this section. An operator must still comply with § 192.611.
(d) The operator of a pipeline segment of steel pipeline meeting the conditions prescribed in § 192.620(b) may elect to operate the segment at a maximum allowable operating pressure determined under § 192.620(a).
For
(a)
(1) In determining the alternative design pressure under § 192.105, use a design factor determined in accordance with § 192.111(b), (c), or (d) or, if none of these paragraphs apply, in accordance with the following table:
(i) For facilities installed prior to November 17, 2008, for which § 192.111(b), (c), or (d) apply, use the following design factors as alternatives for the factors specified in those paragraphs: § 192.111(b)—0.67 or less; 192.111(c) and (d)—0.56 or less.
(ii) [Reserved]
(2) The alternative maximum allowable operating pressure is the lower of the following:
(i) The design pressure of the weakest element in the pipeline segment, determined under subparts C and D of this part.
(ii) The pressure obtained by dividing the pressure to which the pipeline segment was tested after construction by a factor determined in the following table:
(b)
(1) The pipeline segment is in a Class 1, 2, or 3 location;
(2) The pipeline segment is constructed of steel pipe meeting the additional design requirements in § 192.112;
(3) A supervisory control and data acquisition system provides remote monitoring and control of the pipeline segment. The control provided must include monitoring of pressures and flows, monitoring compressor start-ups and shut-downs, and remote closure of valves;
(4) The pipeline segment meets the additional construction requirements described in § 192.328;
(5) The pipeline segment does not contain any mechanical couplings used in place of girth welds;
(6) If a pipeline segment has been previously operated, the segment has not experienced any failure during normal operations indicative of a systemic fault in material as determined by a root cause analysis, including metallurgical examination of the failed pipe. The results of this root cause analysis must be reported to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operation at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and
(7) At least 95 percent of girth welds on a segment that was constructed prior to November 17, 2008, must have been non-destructively examined in accordance with § 192.243(b) and (c).
(c)
(1) Notify each PHMSA pipeline safety regional office where the pipeline is in service of its election with respect to a segment at least 180 days before operating at the alternative maximum allowable operating pressure. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.
(2) Certify, by signature of a senior executive officer of the company, as follows:
(i) The pipeline segment meets the conditions described in paragraph (b) of this section; and
(ii) The operating and maintenance procedures include the additional operating and maintenance requirements of paragraph (d) of this section; and
(iii) The review and any needed program upgrade of the damage prevention program required by paragraph (d)(4)(v) of this section has been completed.
(3) Send a copy of the certification required by paragraph (c)(2) of this section to each PHMSA pipeline safety regional office where the pipeline is in service 30 days prior to operating at the alternative MAOP. An operator must also send a copy to a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.
(4) For each pipeline segment, do one of the following:
(i) Perform a strength test as described in § 192.505 at a test pressure calculated under paragraph (a) of this section or
(ii) For a pipeline segment in existence prior to November 17, 2008, certify, under paragraph (c)(2) of this section, that the strength test performed under § 192.505 was conducted at a test pressure calculated under paragraph (a) of this section, or conduct a new strength test in accordance with paragraph (c)(4)(i) of this section.
(5) Comply with the additional operation and maintenance requirements described in paragraph (d) of this section.
(6) If the performance of a construction task associated with implementing alternative MAOP can affect the integrity of the pipeline segment, treat that task as a “covered task”, notwithstanding the definition in § 192.801(b) and implement the requirements of subpart N as appropriate.
(7) Maintain, for the useful life of the pipeline, records demonstrating compliance with paragraphs (b), (c)(6), and (d) of this section.
(8) A Class 1 and Class 2 pipeline location can be upgraded one class due to class changes per § 192.611(a)(3)(i). All class location changes from Class 1 to Class 2 and from Class 2 to Class 3 must have all anomalies evaluated and remediated per: The “original pipeline class grade” § 192.620(d)(11) anomaly repair requirements; and all anomalies with a wall loss equal to or greater than 40 percent must be excavated and remediated. Pipelines in Class 4 may not operate at an alternative MAOP.
(d)
(e)
(1) Provide overpressure protection that limits mainline pressure to a maximum of 104 percent of the maximum allowable operating pressure; and
(2) Develop and follow a procedure for establishing and maintaining accurate set points for the supervisory control and data acquisition system.
(a) No person may operate a segment of a high pressure distribution system at a pressure that exceeds the lowest of the following pressures, as applicable:
(1) The design pressure of the weakest element in the segment, determined in accordance with subparts C and D of this part.
(2) 60 p.s.i. (414 kPa) gage, for a segment of a distribution system otherwise designed to operate at over 60 p.s.i. (414 kPa) gage, unless the service lines in the segment are equipped with service regulators or other pressure limiting devices in series that meet the requirements of § 192.197(c).
(3) 25 p.s.i. (172 kPa) gage in segments of cast iron pipe in which there are unreinforced bell and spigot joints.
(4) The pressure limits to which a joint could be subjected without the possibility of its parting.
(5) The pressure determined by the operator to be the maximum safe pressure after considering the history of the segment, particularly known corrosion and the actual operating pressures.
(b) No person may operate a segment of pipeline to which paragraph (a)(5) of this section applies, unless overpressure protective devices are installed on the segment in a manner that will prevent the maximum allowable operating pressure from being exceeded, in accordance with § 192.195.
(a) No person may operate a low-pressure distribution system at a pressure high enough to make unsafe the operation of any connected and properly adjusted low-pressure gas burning equipment.
(b) No person may operate a low pressure distribution system at a pressure lower than the minimum pressure at which the safe and continuing operation of any connected and properly adjusted low-pressure gas burning equipment can be assured.
(a) A combustible gas in a distribution line must contain a natural odorant or be odorized so that at a concentration in air of one-fifth of the lower explosive limit, the gas is readily
(b) After December 31, 1976, a combustible gas in a transmission line in a Class 3 or Class 4 location must comply with the requirements of paragraph (a) of this section unless:
(1) At least 50 percent of the length of the line downstream from that location is in a Class 1 or Class 2 location;
(2) The line transports gas to any of the following facilities which received gas without an odorant from that line before May 5, 1975;
(i) An underground storage field;
(ii) A gas processing plant;
(iii) A gas dehydration plant; or
(iv) An industrial plant using gas in a process where the presence of an odorant:
(A) Makes the end product unfit for the purpose for which it is intended;
(B) Reduces the activity of a catalyst; or
(C) Reduces the percentage completion of a chemical reaction;
(3) In the case of a lateral line which transports gas to a distribution center, at least 50 percent of the length of that line is in a Class 1 or Class 2 location; or
(4) The combustible gas is hydrogen intended for use as a feedstock in a manufacturing process.
(c) In the concentrations in which it is used, the odorant in combustible gases must comply with the following:
(1) The odorant may not be deleterious to persons, materials, or pipe.
(2) The products of combustion from the odorant may not be toxic when breathed nor may they be corrosive or harmful to those materials to which the products of combustion will be exposed.
(d) The odorant may not be soluble in water to an extent greater than 2.5 parts to 100 parts by weight.
(e) Equipment for odorization must introduce the odorant without wide variations in the level of odorant.
(f) To assure the proper concentration of odorant in accordance with this section, each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable. Operators of master meter systems may comply with this requirement by—
(1) Receiving written verification from their gas source that the gas has the proper concentration of odorant; and
(2) Conducting periodic “sniff” tests at the extremities of the system to confirm that the gas contains odorant.
For
Each tap made on a pipeline under pressure must be performed by a crew qualified to make hot taps.
(a) When a pipeline is being purged of air by use of gas, the gas must be released into one end of the line in a moderately rapid and continuous flow. If gas cannot be supplied in sufficient quantity to prevent the formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the gas.
(b) When a pipeline is being purged of gas by use of air, the air must be released into one end of the line in a moderately rapid and continuous flow. If air cannot be supplied in sufficient quantity to prevent the formation of a hazardous mixture of gas and air, a slug of inert gas must be released into the line before the air.
This subpart prescribes minimum requirements for maintenance of pipeline facilities.
(a) No person may operate a segment of pipeline, unless it is maintained in accordance with this subpart.
(b) Each segment of pipeline that becomes unsafe must be replaced, repaired, or removed from service.
(c) Hazardous leaks must be repaired promptly.
(a) Each operator shall have a patrol program to observe surface conditions on and adjacent to the transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation.
(b) The frequency of patrols is determined by the size of the line, the operating pressures, the class location, terrain, weather, and other relevant factors, but intervals between patrols may not be longer than prescribed in the following table:
(c) Methods of patrolling include walking, driving, flying or other appropriate means of traversing the right-of-way.
Leakage surveys of a transmission line must be conducted at intervals not exceeding 15 months, but at least once each calendar year. However, in the case of a transmission line which transports gas in conformity with § 192.625 without an odor or odorant, leakage surveys using leak detector equipment must be conducted—
(a) In Class 3 locations, at intervals not exceeding 7
(b) In Class 4 locations, at intervals not exceeding 4
(a)
(1) At each crossing of a public road and railroad; and
(2) Wherever necessary to identify the location of the transmission line or main to reduce the possibility of damage or interference.
(b)
(1) Mains and transmission lines located offshore, or at crossings of or under waterways and other bodies of water.
(2) Mains in Class 3 or Class 4 locations where a damage prevention program is in effect under § 192.614.
(3) Transmission lines in Class 3 or 4 locations until March 20, 1996.
(4) Transmission lines in Class 3 or 4 locations where placement of a line marker is impractical.
(c)
(d)
(1) The word “Warning,” “Caution,” or “Danger” followed by the words “Gas (or name of gas transported) Pipeline” all of which, except for markers in heavily developed urban areas, must be in letters at least 1 inch (25 millimeters) high with
(2) The name of the operator and the telephone number (including area code) where the operator can be reached at all times.
Each operator shall maintain the following records for transmission lines for the periods specified:
(a) The date, location, and description of each repair made to pipe (including pipe-to-pipe connections) must be retained for as long as the pipe remains in service.
(b) The date, location, and description of each repair made to parts of the pipeline system other than pipe must be retained for at least 5 years. However, repairs generated by patrols, surveys, inspections, or tests required by subparts L and M of this part must be retained in accordance with paragraph (c) of this section.
(c) A record of each patrol, survey, inspection, and test required by subparts L and M of this part must be retained for at least 5 years or until the next patrol, survey, inspection, or test is completed, whichever is longer.
(a) Each operator shall take immediate temporary measures to protect the public whenever:
(1) A leak, imperfection, or damage that impairs its serviceability is found in a segment of steel transmission line operating at or above 40 percent of the SMYS; and
(2) It is not feasible to make a permanent repair at the time of discovery.
(b) Except as provided in § 192.717(b)(3), no operator may use a welded patch as a means of repair.
(a) Each imperfection or damage that impairs the serviceability of pipe in a steel transmission line operating at or above 40 percent of SMYS must be—
(1) Removed by cutting out and replacing a cylindrical piece of pipe; or
(2) Repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe.
(b) Operating pressure must be at a safe level during repair operations.
Each weld that is unacceptable under § 192.241(c) must be repaired as follows:
(a) If it is feasible to take the segment of transmission line out of service, the weld must be repaired in accordance with the applicable requirements of § 192.245.
(b) A weld may be repaired in accordance with § 192.245 while the segment of transmission line is in service if:
(1) The weld is not leaking;
(2) The pressure in the segment is reduced so that it does not produce a stress that is more than 20 percent of the SMYS of the pipe; and
(3) Grinding of the defective area can be limited so that at least
(c) A defective weld which cannot be repaired in accordance with paragraph (a) or (b) of this section must be repaired by installing a full encirclement welded split sleeve of appropriate design.
Each permanent field repair of a leak on a transmission line must be made by—
(a) Removing the leak by cutting out and replacing a cylindrical piece of pipe; or
(b) Repairing the leak by one of the following methods:
(1) Install a full encirclement welded split sleeve of appropriate design, unless the transmission line is joined by mechanical couplings and operates at less than 40 percent of SMYS.
(2) If the leak is due to a corrosion pit, install a properly designed bolt-on-leak clamp.
(3) If the leak is due to a corrosion pit and on pipe of not more than 40,000 psi (267 Mpa) SMYS, fillet weld over
(4) If the leak is on a submerged offshore pipeline or submerged pipeline in inland navigable waters, mechanically apply a full encirclement split sleeve of appropriate design.
(5) Apply a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe.
(a)
(b)
(a) The frequency of patrolling mains must be determined by the severity of the conditions which could cause failure or leakage, and the consequent hazards to public safety.
(b) Mains in places or on structures where anticipated physical movement or external loading could cause failure or leakage must be patrolled—
(1) In business districts, at intervals not exceeding 4
(2) Outside business districts, at intervals not exceeding 7
(a) Each operator of a distribution system shall conduct periodic leakage surveys in accordance with this section.
(b) The type and scope of the leakage control program must be determined by the nature of the operations and the local conditions, but it must meet the following minimum requirements:
(1) A leakage survey with leak detector equipment must be conducted in business districts, including tests of the atmosphere in gas, electric, telephone, sewer, and water system manholes, at cracks in pavement and sidewalks, and at other locations providing an opportunity for finding gas leaks, at intervals not exceeding 15 months, but at least once each calendar year.
(2) A leakage survey with leak detector equipment must be conducted outside business districts as frequently as necessary, but at least once every 5 calendar years at intervals not exceeding 63 months. However, for cathodically unprotected distribution lines subject to § 192.465(e) on which electrical surveys for corrosion are impractical, a leakage survey must be conducted at least once every 3 calendar years at intervals not exceeding 39 months.
(a) Except as provided in paragraph (b) of this section, each disconnected service line must be tested in the same manner as a new service line, before being reinstated.
(b) Each service line temporarily disconnected from the main must be tested from the point of disconnection to the service line valve in the same manner as a new service line, before reconnecting. However, if provisions are made to maintain continuous service, such as by installation of a bypass, any part of the original service line used to maintain continuous service need not be tested.
(a) Each operator shall conduct abandonment or deactivation of pipelines in accordance with the requirements of this section.
(b) Each pipeline abandoned in place must be disconnected from all sources and supplies of gas; purged of gas; in the case of offshore pipelines, filled with water or inert materials; and sealed at the ends. However, the pipeline need not be purged when the volume of gas is so small that there is no potential hazard.
(c) Except for service lines, each inactive pipeline that is not being maintained under this part must be disconnected from all sources and supplies of gas; purged of gas; in the case of offshore pipelines, filled with water or inert materials; and sealed at the ends. However, the pipeline need not be purged when the volume of gas is so small that there is no potential hazard.
(d) Whenever service to a customer is discontinued, one of the following must be complied with:
(1) The valve that is closed to prevent the flow of gas to the customer must be provided with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator.
(2) A mechanical device or fitting that will prevent the flow of gas must be installed in the service line or in the meter assembly.
(3) The customer's piping must be physically disconnected from the gas supply and the open pipe ends sealed.
(e) If air is used for purging, the operator shall insure that a combustible mixture is not present after purging.
(f) Each abandoned vault must be filled with a suitable compacted material.
(g) For each abandoned offshore pipeline facility or each abandoned onshore pipeline facility that crosses over, under or through a commercially navigable waterway, the last operator of that facility must file a report upon abandonment of that facility.
(1) The preferred method to submit data on pipeline facilities abandoned after October 10, 2000 is to the National Pipeline Mapping System (NPMS) in accordance with the NPMS “Standards for Pipeline and Liquefied Natural Gas Operator Submissions.” To obtain a copy of the NPMS Standards, please refer to the NPMS homepage at
(2) [Reserved]
(a) Except for rupture discs, each pressure relieving device in a compressor station must be inspected and tested in accordance with §§ 192.739 and
(b) Any defective or inadequate equipment found must be promptly repaired or replaced.
(c) Each remote control shutdown device must be inspected and tested at intervals not exceeding 15 months, but at least once each calendar year, to determine that it functions properly.
(a) Flammable or combustible materials in quantities beyond those required for everyday use, or other than those normally used in compressor buildings, must be stored a safe distance from the compressor building.
(b) Aboveground oil or gasoline storage tanks must be protected in accordance with National Fire Protection Association Standard No. 30.
(a) Not later than September 16, 1996, each compressor building in a compressor station must have a fixed gas detection and alarm system, unless the building is—
(1) Constructed so that at least 50 percent of its upright side area is permanently open; or
(2) Located in an unattended field compressor station of 1,000 horsepower (746 kW) or less.
(b) Except when shutdown of the system is necessary for maintenance under paragraph (c) of this section, each gas detection and alarm system required by this section must—
(1) Continuously monitor the compressor building for a concentration of gas in air of not more than 25 percent of the lower explosive limit; and
(2) If that concentration of gas is detected, warn persons about to enter the building and persons inside the building of the danger.
(c) Each gas detection and alarm system required by this section must be maintained to function properly. The maintenance must include performance tests.
(a) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is—
(1) In good mechanical condition;
(2) Adequate from the standpoint of capacity and reliability of operation for the service in which it is employed;
(3) Except as provided in paragraph (b) of this section, set to control or relieve at the correct pressure consistent with the pressure limits of § 192.201(a); and
(4) Properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation.
(b) For steel pipelines whose MAOP is determined under § 192.619(c), if the MAOP is 60 psi (414 kPa) gage or more, the control or relief pressure limit is as follows:
(a) Each distribution system supplied by more than one district pressure regulating station must be equipped with telemetering or recording pressure gauges to indicate the gas pressure in the district.
(b) On distribution systems supplied by a single district pressure regulating station, the operator shall determine
(c) If there are indications of abnormally high or low pressure, the regulator and the auxiliary equipment must be inspected and the necessary measures employed to correct any unsatisfactory operating conditions.
(a) Pressure relief devices at pressure limiting stations and pressure regulating stations must have sufficient capacity to protect the facilities to which they are connected. Except as provided in § 192.739(b), the capacity must be consistent with the pressure limits of § 192.201(a). This capacity must be determined at intervals not exceeding 15 months, but at least once each calendar year, by testing the devices in place or by review and calculations.
(b) If review and calculations are used to determine if a device has sufficient capacity, the calculated capacity must be compared with the rated or experimentally determined relieving capacity of the device for the conditions under which it operates. After the initial calculations, subsequent calculations need not be made if the annual review documents that parameters have not changed to cause the rated or experimentally determined relieving capacity to be insufficient.
(c) If a relief device is of insufficient capacity, a new or additional device must be installed to provide the capacity required by paragraph (a) of this section.
(a) Each transmission line valve that might be required during any emergency 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, unless the operator designates an alternative valve.
(a) Each valve, the use of which may be necessary for the safe operation of a distribution system, must be checked and serviced 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, unless the operator designates an alternative valve.
(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 is in good physical condition and adequately ventilated.
(b) If gas is found in the vault, the equipment in the vault must be inspected for leaks, and any leaks found must be repaired.
(c) The ventilating equipment must also be inspected to determine that it is functioning properly.
(d) Each vault cover must be inspected to assure that it does not present a hazard to public safety.
Each operator shall take 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, including the following:
(a) When a hazardous amount of gas is being vented into open air, each potential source of ignition must be removed from the area and a fire extinguisher must be provided.
(b) Gas or electric welding or cutting may not be performed on pipe or on pipe components that contain a combustible mixture of gas and air in the area of work.
(c) Post warning signs, where appropriate.
(a) Each cast iron caulked bell and spigot joint that is subject to pressures of more than 25 psi (172kPa) gage must be sealed with:
(1) A mechanical leak clamp; or
(2) A material or device which:
(i) Does not reduce the flexibility of the joint;
(ii) Permanently bonds, either chemically or mechanically, or both, with the bell and spigot metal surfaces or adjacent pipe metal surfaces; and
(iii) Seals and bonds in a manner that meets the strength, environmental, and chemical compatibility requirements of §§ 192.53 (a) and (b) and 192.143.
(b) Each cast iron caulked bell and spigot joint that is subject to pressures of 25 psi (172kPa) gage or less and is exposed for any reason must be sealed by a means other than caulking.
When an operator has knowledge that the support for a segment of a buried cast-iron pipeline is disturbed:
(a) That segment of the pipeline must be protected, as necessary, against damage during the disturbance by:
(1) Vibrations from heavy construction equipment, trains, trucks, buses, or blasting;
(2) Impact forces by vehicles;
(3) Earth movement;
(4) Apparent future excavations near the pipeline; or
(5) Other foreseeable outside forces which may subject that segment of the pipeline to bending stress.
(b) As soon as feasible, appropriate steps must be taken to provide permanent protection for the disturbed segment from damage that might result from external loads, including compliance with applicable requirements of §§ 192.317(a), 192.319, and 192.361(b)-(d).
(a) This subpart prescribes the minimum requirements for operator qualification of individuals performing covered tasks on a pipeline facility.
(b) For the purpose of this subpart, a covered task is an activity, identified by the operator, that:
(1) Is performed on a pipeline facility;
(2) Is an operations or maintenance task;
(3) Is performed as a requirement of this part; and
(4) Affects the operation or integrity of the pipeline.
(a) Indicate a condition exceeding design limits; or
(b) Result in a hazard(s) to persons, property, or the environment.
(a) Written examination;
(b) Oral examination;
(c) Work performance history review;
(d) Observation during:
(1) Performance on the job,
(2) On the job training, or
(3) Simulations;
(e) Other forms of assessment.
(a) Perform assigned covered tasks; and
(b) Recognize and react to abnormal operating conditions.
Each operator shall have and follow a written qualification program. The program shall include provisions to:
(a) Identify covered tasks;
(b) Ensure through evaluation that individuals performing covered tasks are qualified;
(c) Allow individuals that are not qualified pursuant to this subpart to perform a covered task if directed and observed by an individual that is qualified;
(d) Evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an incident as defined in Part 191;
(e) Evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task;
(f) Communicate changes that affect covered tasks to individuals performing those covered tasks;
(g) Identify those covered tasks and the intervals at which evaluation of the individual's qualifications is needed;
(h) After December 16, 2004, provide training, as appropriate, to ensure that individuals performing covered tasks have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities; and
(i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the Administrator or state agency has verified that it complies with this section.
Each operator shall maintain records that demonstrate compliance with this subpart.
(a) Qualification records shall include:
(1) Identification of qualified individual(s);
(2) Identification of the covered tasks the individual is qualified to perform;
(3) Date(s) of current qualification; and
(4) Qualification method(s).
(b) Records supporting an individual's current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of five years.
(a) Operators must have a written qualification program by April 27, 2001. The program must be available for review by the Administrator or by a state agency participating under 49 U.S.C. Chapter 601 if the program is under the authority of that state agency.
(b) Operators must complete the qualification of individuals performing covered tasks by October 28, 2002.
(c) Work performance history review may be used as a sole evaluation method for individuals who were performing a covered task prior to October 26, 1999.
(d) After October 28, 2002, work performance history may not be used as a sole evaluation method.
(e) After December 16, 2004, observation of on-the-job performance may not be used as the sole method of evaluation.
This subpart prescribes 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
The following definitions apply to this subpart:
(1) An area defined as—
(i) A Class 3 location under § 192.5; or
(ii) A Class 4 location under § 192.5; or
(iii) Any area in a Class 1 or Class 2 location where the potential impact radius is greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential impact circle contains an identified site.
(2) The area within a potential impact circle containing—
(i) 20 or more buildings intended for human occupancy, unless the exception in paragraph (4) applies; or
(ii) An identified site.
(3) Where a potential impact circle is calculated under either method (1) or (2) to establish a high consequence area, the length of the high consequence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle that contains either an identified site or 20 or more buildings intended for human occupancy to the outermost edge of the last contiguous potential impact circle that contains either an identified site or 20 or more buildings intended for human occupancy. (See figure E.I.A. in appendix E.)
(4) If in identifying a high consequence area under paragraph (1)(iii) of this definition or paragraph (2)(i) of this definition, the radius of the potential impact circle is greater than 660 feet (200 meters), the operator may identify a high consequence area based on a prorated number of buildings intended for human occupancy with a distance of 660 feet (200 meters) from the centerline of the pipeline until December 17, 2006. If an operator chooses this approach, the operator must prorate the number of buildings intended for human occupancy based on the ratio of an area with a radius of 660 feet (200 meters) to the area of the potential impact circle (i.e., the prorated number of buildings intended for human occupancy is equal to 20 × (660 feet) [or 200 meters]/potential impact radius in feet [or meters]
(a) An outside area or open structure that is occupied by twenty (20) or more persons on at least 50 days in any twelve (12)-month period. (The days need not be consecutive.) Examples include but are not limited to, beaches, playgrounds, recreational facilities, camping grounds, outdoor theaters, stadiums, recreational areas near a body of water, or areas outside a rural building such as a religious facility; or
(b) A building that is occupied by twenty (20) or more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)-month period. (The days and weeks need not be consecutive.) Examples include, but are not limited to, religious facilities, office buildings, community centers, general
(c) A facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate. Examples include but are not limited to hospitals, prisons, schools, day-care facilities, retirement facilities or assisted-living facilities.
0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat of combustion. An operator transporting gas other than natural gas must use section 3.2 of ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; incorporated by reference,
(a)
(b)(1)
(2) If a public official with safety or emergency response or planning responsibilities informs an operator that it does not have the information to identify an identified site, the operator must use one of the following sources, as appropriate, to identify these sites.
(i) Visible marking (
(ii) The site is licensed or registered by a Federal, State, or local government agency; or
(iii) The site is on a list (including a list on an internet web site) or map maintained by or available from a Federal, State, or local government agency and available to the general public.
(c)
(a)
(b)
(a)
(b)
An operator's initial integrity management program begins with a framework (
(a) An identification of all high consequence areas, in accordance with § 192.905.
(b) A baseline assessment plan meeting the requirements of § 192.919 and § 192.921.
(c) An identification of threats to each covered pipeline segment, which must include data integration and a risk assessment. An operator must use the threat identification and risk assessment to prioritize covered segments for assessment (§ 192.917) and to evaluate the merits of additional preventive and mitigative measures (§ 192.935) for each covered segment.
(d) A direct assessment plan, if applicable, meeting the requirements of § 192.923, and depending on the threat assessed, of §§ 192.925, 192.927, or 192.929.
(e) Provisions meeting the requirements of § 192.933 for remediating conditions found during an integrity assessment.
(f) A process for continual evaluation and assessment meeting the requirements of § 192.937.
(g) If applicable, a plan for confirmatory direct assessment meeting the requirements of § 192.931.
(h) Provisions meeting the requirements of § 192.935 for adding preventive and mitigative measures to protect the high consequence area.
(i) A performance plan as outlined in ASME/ANSI B31.8S, section 9 that includes performance measures meeting the requirements of § 192.945.
(j) Record keeping provisions meeting the requirements of § 192.947.
(k) A management of change process as outlined in ASME/ANSI B31.8S, section 11.
(l) A quality assurance process as outlined in ASME/ANSI B31.8S, section 12.
(m) A communication plan that includes the elements of ASME/ANSI B31.8S, section 10, and that includes procedures for addressing safety concerns raised by—
(1) OPS; and
(2) A State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement.
(n) Procedures for providing (when requested), by electronic or other means, a copy of the operator's risk analysis or integrity management program to—
(1) OPS; and
(2) A State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement.
(o) Procedures for ensuring that each integrity assessment is being conducted in a manner that minimizes environmental and safety risks.
(p) A process for identification and assessment of newly-identified high consequence areas. (
(a)
(b)
(1) To deviate from any of the requirements set forth in paragraph (c) of this section, an operator must have a performance-based integrity management program that meets or exceed the performance-based requirements of ASME/ANSI B31.8S and includes, at a minimum, the following elements—
(i) A comprehensive process for risk analysis;
(ii) All risk factor data used to support the program;
(iii) A comprehensive data integration process;
(iv) A procedure for applying lessons learned from assessment of covered pipeline segments to pipeline segments not covered by this subpart;
(v) A procedure for evaluating every incident, including its cause, within the operator's sector of the pipeline industry for implications both to the operator's pipeline system and to the operator's integrity management program;
(vi) A performance matrix that demonstrates the program has been effective in ensuring the integrity of the covered segments by controlling the identified threats to the covered segments;
(vii) Semi-annual performance measures beyond those required in § 192.945 that are part of the operator's performance plan. (
(viii) An analysis that supports the desired integrity reassessment interval and the remediation methods to be used for all covered segments.
(2) In addition to the requirements for the performance-based plan, an operator must—
(i) Have completed at least two integrity assessments on each covered pipeline segment the operator is including under the performance-based approach, and be able to demonstrate that each assessment effectively addressed the identified threats on the covered segment.
(ii) Remediate all anomalies identified in the more recent assessment according to the requirements in § 192.933, and incorporate the results and lessons learned from the more recent assessment into the operator's data integration and risk assessment.
(c)
(1) The time frame for reassessment as provided in § 192.939 except that reassessment by some method allowed under this subpart (
(2) The time frame for remediation as provided in § 192.933 if the operator demonstrates the time frame will not jeopardize the safety of the covered segment.
(a)
(b)
(1) Who conducts an integrity assessment allowed under this subpart; or
(2) Who reviews and analyzes the results from an integrity assessment and evaluation; or
(3) Who makes decisions on actions to be taken based on these assessments.
(c)
(1) Who implements preventive and mitigative measures to carry out this subpart, including the marking and locating of buried structures; or
(2) Who directly supervises excavation work carried out in conjunction with an integrity assessment.
(a)
(1) Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking;
(2) Static or resident threats, such as fabrication or construction defects;
(3) Time independent threats such as third party damage and outside force damage; and
(4) Human error.
(b)
(c)
(d)
(e)
(1)
An operator must also have procedures in its integrity management program addressing actions it will take to respond to findings from this data integration.
(2)
(3)
(i) Operating pressure increases above the maximum operating pressure experienced during the preceding five years;
(ii) MAOP increases; or
(iii) The stresses leading to cyclic fatigue increase.
(4)
(5)
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. (
(b) The methods selected to assess the integrity of the line pipe, including an explanation of why the assessment method was selected to address the identified threats to each covered segment. The integrity assessment method an operator uses must be based on the threats identified to the covered segment. (
(c) A schedule for completing the integrity assessment of all covered segments, including risk factors considered in establishing the assessment schedule;
(d) If applicable, a direct assessment plan that meets the requirements of §§ 192.923, and depending on the threat to be addressed, of § 192.925, § 192.927, or § 192.929; and
(e) A procedure to ensure that the baseline assessment is being conducted in a manner that minimizes environmental and safety risks.
(a)
(1) Internal inspection tool or tools capable of detecting corrosion, and any other threats to which the covered segment is susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by reference,
(2) Pressure test conducted in accordance with subpart J of this part. An operator must use the test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S, to justify an extended reassessment interval in accordance with § 192.939.
(3) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with, as applicable, the requirements specified in §§ 192.925, 192.927 or 192.929;
(4) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 180 days before conducting the assessment, in accordance with § 192.949. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State.
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(a)
(b)
(1) ASME/ANSI B31.8S (incorporated by reference,
(2) ASME/ANSI B31.8S, section 6.4 and appendix B2, and § 192.927 if addressing internal corrosion (ICDA).
(3) ASME/ANSI B31.8S, appendix A3, and § 192.929 if addressing stress corrosion cracking (SCCDA).
(c)
(a)
(b)
(1)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; and
(ii) The basis on which an operator selects at least two different, but complementary indirect assessment tools to assess each ECDA Region. If an operator utilizes an indirect inspection method that is not discussed in Appendix A of NACE RP0502-2002, the operator must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method.
(2)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment;
(ii) Criteria for identifying and documenting those indications that must be considered for excavation and direct examination. Minimum identification criteria include the known sensitivities of assessment tools, the procedures for using each tool, and the approach to be used for decreasing the physical spacing of indirect assessment tool readings when the presence of a defect is suspected;
(iii) Criteria for defining the urgency of excavation and direct examination of each indication identified during the indirect examination. These criteria must specify how an operator will define the urgency of excavating the indication as immediate, scheduled or monitored; and
(iv) Criteria for scheduling excavation of indications for each urgency level.
(3)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment;
(ii) Criteria for deciding what action should be taken if either:
(A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE RP0502-2002), or
(B) Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE RP0502-2002);
(iii) Criteria and notification procedures for any changes in the ECDA Plan, including changes that affect the severity classification, the priority of direct examination, and the time frame for direct examination of indications; and
(iv) Criteria that describe how and on what basis an operator will reclassify and reprioritize any of the provisions that are specified in section 5.9 of NACE RP0502-2002.
(4)
(i) Measures for evaluating the long-term effectiveness of ECDA in addressing external corrosion in covered segments; and
(ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the covered segment at an interval less than that specified in § 192.939. (See Appendix D of NACE RP0502-2002.)
(a)
(b)
(c)
(1)
(i) All data elements listed in appendix A2 of ASME/ANSI B31.8S;
(ii) Information needed to support use of a model that an operator must use to identify areas along the pipeline where internal corrosion is most likely to occur. (
(iii) Operating experience data that would indicate historic upsets in gas conditions, locations where these upsets have occurred, and potential damage resulting from these upset conditions; and
(iv) Information on covered segments where cleaning pigs may not have been used or where cleaning pigs may deposit electrolytes.
(2)
(3)
(i) Evaluate the severity of the defect (remaining strength) and remediate the defect in accordance with § 192.933;
(ii) As part of the operator's current integrity assessment either perform additional excavations in each covered segment within the ICDA region, or use an alternative assessment method allowed by this subpart to assess the line pipe in each covered segment within the ICDA region for internal corrosion; and
(iii) Evaluate the potential for internal corrosion in all pipeline segments (both covered and non-covered) in the operator's pipeline system with similar characteristics to the ICDA region containing the covered segment in which the corrosion was found, and as appropriate, remediate the conditions the operator finds in accordance with § 192.933.
(4)
(i) Evaluating the effectiveness of ICDA as an assessment method for addressing internal corrosion and determining whether a covered segment should be reassessed at more frequent intervals than those specified in § 192.939. An operator must carry out this evaluation within a year of conducting an ICDA; and
(ii) Continually monitoring each covered segment where internal corrosion has been identified using techniques such as coupons, UT sensors or electronic probes, periodically drawing off liquids at low points and chemically analyzing the liquids for the presence of corrosion products. An operator must base the frequency of the monitoring and liquid analysis on results from all integrity assessments that have been conducted in accordance with the requirements of this subpart, and risk factors specific to the covered segment. If an operator finds any evidence of corrosion products in the covered segment, the operator must take prompt action in accordance with one of the two following required actions and remediate the conditions the operator finds in accordance with § 192.933.
(A) Conduct excavations of covered segments at locations downstream from where the electrolyte might have entered the pipe; or
(B) Assess the covered segment using another integrity assessment method allowed by this subpart.
(5)
(i) Criteria an operator will apply in making key decisions (
(ii) Provisions for applying more restrictive criteria when conducting ICDA for the first time on a covered segment and that become less stringent as the operator gains experience; and
(iii) Provisions that analysis be carried out on the entire pipeline in which covered segments are present, except that application of the remediation criteria of § 192.933 may be limited to covered segments.
(a)
(b)
(1)
(2)
An operator using the confirmatory direct assessment (CDA) method as allowed in § 192.937 must have a plan that meets the requirements of this section and of §§ 192.925 (ECDA) and § 192.927 (ICDA).
(a)
(b)
(1) The procedures for indirect examination may allow use of only one indirect examination tool suitable for the application.
(2) The procedures for direct examination and remediation must provide that—
(i) All immediate action indications must be excavated for each ECDA region; and
(ii) At least one high risk indication that meets the criteria of scheduled action must be excavated in each ECDA region.
(c)
(d)
(a)
(1)
(2)
(b)
(c)
(d)
(i) A calculation of the remaining strength of the pipe shows a predicted failure pressure less than or equal to 1.1 times the maximum allowable operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, ASME/ANSI B31G; RSTRENG; or an alternative equivalent method of remaining strength calculation. These documents are incorporated by reference and available at the addresses listed in appendix A to part 192.
(ii) A dent that has any indication of metal loss, cracking or a stress riser.
(iii) An indication or anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.
(2)
(i) A smooth dent located between the 8 o'clock and 4 o'clock positions
(ii) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or at a longitudinal seam weld.
(3)
(i) A dent with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12) located between the 4 o'clock position and the 8 o'clock position (bottom
(ii) A dent located between the 8 o'clock and 4 o'clock positions (upper
(iii) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld, and engineering analyses of the dent and girth or seam weld demonstrate critical strain levels are not exceeded. These analyses must consider weld properties.
(a)
(b) Third party damage and outside force damage—
(1)
(i) Using qualified personnel (
(ii) Collecting in a central database information that is location specific on excavation damage that occurs in covered and non covered segments in the transmission system and the root cause analysis to support identification of targeted additional preventative and mitigative measures in the high consequence areas. This information must include recognized damage that is not required to be reported as an incident under part 191.
(iii) Participating in one-call systems in locations where covered segments are present.
(iv) Monitoring of excavations conducted on covered pipeline segments by pipeline personnel. If an operator finds physical evidence of encroachment involving excavation that the operator
(2)
(c)
(d)
(1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) of this section to the pipeline; and
(2) Either monitor excavations near the pipeline, or conduct patrols as required by § 192.705 of the pipeline at bi-monthly intervals. If an operator finds any indication of unreported construction activity, the operator must conduct a follow up investigation to determine if mechanical damage has occurred.
(3) Perform semi-annual leak surveys (quarterly for unprotected pipelines or cathodically protected pipe where electrical surveys are impractical).
(e)
(a)
(b)
(c)
(1) Internal inspection tool or tools capable of detecting corrosion, and any other threats to which the covered segment is susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by reference,
(2) Pressure test conducted in accordance with subpart J of this part. An operator must use the test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S, to justify an extended reassessment interval in accordance with § 192.939.
(3) Direct assessment to address threats of external corrosion, internal corrosion, or stress corrosion cracking. An operator must conduct the direct assessment in accordance with the requirements listed in § 192.923 and with as applicable, the requirements specified in §§ 192.925, 192.927 or 192.929;
(4) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 180 days before conducting the assessment, in accordance with § 192.949. An operator must also notify a State or local pipeline safety authority when either a covered segment is located in a State where OPS has an interstate agent agreement, or an intrastate covered segment is regulated by that State.
(5) Confirmatory direct assessment when used on a covered segment that is scheduled for reassessment at a period longer than seven years. An operator using this reassessment method must comply with § 192.931.
An operator must comply with the following requirements in establishing the reassessment interval for the operator's covered pipeline segments.
(a)
(1)
(i) Basing the interval on the identified threats for the covered segment (see § 192.917) and on the analysis of the results from the last integrity assessment and from the data integration and risk assessment required by § 192.917; or
(ii) Using the intervals specified for different stress levels of pipeline (operating at or above 30% SMYS) listed in ASME/ANSI B31.8S, section 5, Table 3.
(2)
(3)
(i) Determine the largest defect most likely to remain in the covered segment and the corrosion rate appropriate for the pipe, soil and protection conditions;
(ii) Use the largest remaining defect as the size of the largest defect discovered in the SCC or ICDA segment; and
(iii) Estimate the reassessment interval as half the time required for the largest defect to grow to a critical size.
(b)
(1) Reassessment by pressure test, internal inspection or other equivalent technology following the requirements in paragraph (a)(1) of this section except that the stress level referenced in paragraph (a)(1)(ii) of this section would be adjusted to reflect the lower operating stress level. If an established interval is more than seven years, the operator must conduct by the seventh year of the interval either a confirmatory direct assessment in accordance with § 192.931, or a low stress reassessment in accordance with § 192.941.
(2) Reassessment by ECDA following the requirements in paragraph (a)(2) of this section.
(3) Reassessment by ICDA or SCCDA following the requirements in paragraph (a)(3) of this section.
(4) Reassessment by confirmatory direct assessment at 7-year intervals in accordance with § 192.931, with reassessment by one of the methods listed in paragraphs (b)(1) through (b)(3) of this section by year 20 of the interval.
(5) Reassessment by the low stress assessment method at 7-year intervals in accordance with § 192.941 with reassessment by one of the methods listed in paragraphs (b)(1) through (b)(3) of this section by year 20 of the interval.
(6) The following table sets forth the maximum reassessment intervals. Also refer to Appendix E.II for guidance on Assessment Methods and Assessment Schedule for Transmission Pipelines Operating Below 30% SMYS. In case of conflict between the rule and the guidance in the Appendix, the requirements of the rule control. An operator must comply with the following requirements in establishing a reassessment interval for a covered segment:
(a)
(b)
(1)
(2)
(i) Conduct leakage surveys as required by § 192.706 at 4-month intervals; and
(ii) Every 18 months, identify and remediate areas of active corrosion by evaluating leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment.
(c)
(1) Conduct a gas analysis for corrosive agents at least once each calendar year;
(2) Conduct periodic testing of fluids removed from the segment. At least once each calendar year test the fluids removed from each storage field that may affect a covered segment; and
(3) At least every seven (7) years, integrate data from the analysis and testing required by paragraphs (c)(1)-(c)(2) with applicable internal corrosion leak records, incident reports, safety-related condition reports, repair records, patrol records, exposed pipe reports, and test records, and define and implement appropriate remediation actions.
(a)
(1)
(2)
(b)
(a)
(b)
An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At minimum, an operator must maintain the following records for review during an inspection.
(a) A written integrity management program in accordance with § 192.907;
(b) Documents supporting the threat identification and risk assessment in accordance with § 192.917;
(c) A written baseline assessment plan in accordance with § 192.919;
(d) Documents to support any decision, analysis and process developed and used to implement and evaluate each element of the baseline assessment plan and integrity management program. Documents include those developed and used in support of any identification, calculation, amendment, modification, justification, deviation and determination made, and any action taken to implement and evaluate any of the program elements;
(e) Documents that demonstrate personnel have the required training, including a description of the training program, in accordance with § 192.915;
(f) Schedule required by § 192.933 that prioritizes the conditions found during an assessment for evaluation and remediation, including technical justifications for the schedule.
(g) Documents to carry out the requirements in §§ 192.923 through 192.929 for a direct assessment plan;
(h) Documents to carry out the requirements in § 192.931 for confirmatory direct assessment;
(i) Verification that an operator has provided any documentation or notification required by this subpart to be provided to OPS, and when applicable, a State authority with which OPS has an interstate agent agreement, and a State or local pipeline safety authority that regulates a covered pipeline segment within that State.
An operator must provide any notification required by this subpart by—
(a) Sending the notification to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001;
(b) Sending the notification to the Information Resources Manager by facsimile to (202) 366-7128; or
(c) Entering the information directly on the Integrity Management Database (IMDB) Web site at
An operator must send any performance report required by this subpart to the Information Resources Manager—
(a) By mail to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001;
(b) Via facsimile to (202) 366-7128; or
(c) Through the online reporting system provided by OPS for electronic reporting available at the OPS Home Page at
I. Listed Pipe Specifications
API 5L—Steel pipe, “API Specification for Line Pipe” (incorporated by reference,
ASTM A53/A53M—Steel pipe, “Standard Specification for Pipe, Steel Black and Hot-Dipped, Zinc-Coated, Welded and Seamless” (incorporated by reference,
ASTM A106—Steel pipe, “Standard Specification for Seamless Carbon Steel Pipe for High Temperature Service” (incorporated by reference,
ASTM A333/A333M—Steel pipe, “Standard Specification for Seamless and Welded Steel Pipe for Low Temperature Service” (incorporated by reference,
ASTM A381—Steel pipe, “Standard Specification for Metal-Arc-Welded Steel Pipe for Use with High-Pressure Transmission Systems” (incorporated by reference,
ASTM A671—Steel pipe, “Standard Specification for Electric-Fusion-Welded Pipe for Atmospheric and Lower Temperatures” (incorporated by reference,
ASTM A672—Steel pipe, “Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures” (incorporated by reference,
ASTM A691—Steel pipe, “Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High Pressure Service at High Temperatures” (incorporated by reference,
ASTM D2513—Thermoplastic pipe and tubing, “Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings” (incorporated by reference,
ASTM D2517—Thermosetting plastic pipe and tubing, “Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings” (incorporated by reference,
II.
A.
For pipe more than 2 inches (51 millimeters) in diameter, the pipe must meet the requirements of the flattening tests set forth in ASTM A53 (incorporated by reference,
B.
C.
D.
III.
A.
B.
(1) Physical (mechanical) properties of pipe, including yield and tensile strength, elongation, and yield to tensile ratio, and testing requirements to verify those properties.
(2) Chemical properties of pipe and testing requirements to verify those properties.
C.
(1) The edition of the listed specification to which the pipe was manufactured must have substantially the same requirements with respect to nondestructive inspection of welded seams and the standards for acceptance or rejection and repair as a later edition of the specification listed in section I of this appendix.
(2) The pipe must be tested in accordance with subpart J of this part to at least 1.25 times the maximum allowable operating pressure if it is to be installed in a class 1 location and to at least 1.5 times the maximum allowable operating pressure if it is to be installed in a class 2, 3, or 4 location. Notwithstanding any shorter time period permitted under subpart J of this part, the test pressure must be maintained for at least 8 hours.
For
I.
II.
III.
(1) One sample is centered in a guided bend testing machine and bent to the contour of the die for a distance of 2 inches (51 millimeters) on each side of the weld. If the sample shows any breaks or cracks after removal from the bending machine, it is unacceptable.
(2) The ends of the second sample are flattened and the entire joint subjected to a tensile strength test. If failure occurs adjacent to or in the weld metal, the weld is unacceptable. If a tensile strength testing machine is not available, this sample must also pass the
I.
(2) A negative (cathodic) voltage shift of at least 300 millivolts. Determination of this voltage shift must be made with the protective current applied, and in accordance with sections II and IV of this appendix. This criterion of voltage shift applies to structures not in contact with metals of different anodic potentials.
(3) A minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with sections III and IV of this appendix.
(4) A voltage at least as negative (cathodic) as that originally established at the beginning of the Tafel segment of the E-log-I curve. This voltage must be measured in accordance with section IV of this appendix.
(5) A net protective current from the electrolyte into the structure surface as measured by an earth current technique applied at predetermined current discharge (anodic) points of the structure.
B.
(2) Except as provided in paragraphs (3) and (4) of this paragraph, a minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with sections III and IV of this appendix.
(3) Notwithstanding the alternative minimum criteria in paragraphs (1) and (2) of this paragraph, aluminum, if cathodically protected at voltages in excess of 1.20 volts as measured with reference to a copper-copper sulfate half cell, in accordance with section IV of this appendix, and compensated for the voltage (IR) drops other than those across the structure-electrolyte boundary may suffer corrosion resulting from the build-up of alkali on the metal surface. A voltage in excess of 1.20 volts may not be used unless previous test results indicate no appreciable corrosion will occur in the particular environment.
(4) Since aluminum may suffer from corrosion under high pH conditions, and since application of cathodic protection tends to increase the pH at the metal surface, careful investigation or testing must be made before applying cathodic protection to stop pitting attack on aluminum structures in environments with a natural pH in excess of 8.
C.
D.
II.
III.
IV.
B. Other standard reference half cells may be substituted for the saturated cooper-copper sulfate half cell. Two commonly used reference half cells are listed below along with their voltage equivalent to −0.85 volt as referred to a saturated copper-copper sulfate half cell:
(1) Saturated KCl calomel half cell: −0.78 volt.
(2) Silver-silver chloride half cell used in sea water: −0.80 volt.
C. In addition to the standard reference half cells, an alternate metallic material or structure may be used in place of the saturated copper-copper sulfate half cell if its potential stability is assured and if its voltage
To determine which segments of an operator's transmission pipeline system are covered for purposes of the integrity management program requirements, an operator must identify the high consequence areas. An operator must use method (1) or (2) from the definition in § 192.903 to identify a high consequence area. An operator may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. (Refer to figure E.I.A for a diagram of a high consequence area).
(a) Table E.II.1 gives guidance to help an operator implement requirements on additional preventive and mitigative measures for addressing time dependent and independent threats for a transmission pipeline operating below 30% SMYS not in an HCA (
(b) Table E.II.2 gives guidance to help an operator implement requirements on assessment methods for addressing time dependent and independent threats for a transmission pipeline in an HCA.
(c) Table E.II.3 gives guidance on preventative & mitigative measures addressing time
49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109, 60110, 60113, 60118; and 49 CFR 1.53.
Nomenclature changes to part 193 appear at 71 FR 33408, June 9, 2006.
(a) This part prescribes safety standards for LNG facilities used in the transportation of gas by pipeline that is subject to the pipeline safety laws (49 U.S.C. 60101
(b) This part does not apply to:
(1) LNG facilities used by ultimate consumers of LNG or natural gas.
(2) LNG facilities used in the course of natural gas treatment or hydrocarbon extraction which do not store LNG.
(3) In the case of a marine cargo transfer system and associated facilities, any matter other than siting pertaining to the system or facilities between the marine vessel and the last manifold (or in the absence of a manifold, the last valve) located immediately before a storage tank.
(4) Any LNG facility located in navigable waters (as defined in Section 3(8) of the Federal Power Act (16 U.S.C. 796(8)).
(a) Regulations in this part governing siting, design, installation, or construction of LNG facilities (including material incorporated by reference in these regulations) do not apply to LNG facilities in existence or under construction when the regulations go into effect.
(b) If an existing LNG facility (or facility under construction before March 31, 2000 is replaced, relocated or significantly altered after March 31, 2000, the facility must comply with the applicable requirements of this part governing, siting, design, installation, and construction, except that:
(1) The siting requirements apply only to LNG storage tanks that are significantly altered by increasing the original storage capacity or relocated, and
(2) To the extent compliance with the design, installation, and construction requirements would make the replaced, relocated, or altered facility incompatible with the other facilities or would otherwise be impractical, the replaced, relocated, or significantly altered facility may be designed, installed, or constructed in accordance with the original specifications for the facility, or in another manner subject to the approval of the Administrator.
As used in this part:
(a) As used in this part:
(1)
(2)
(3)
(4)
(b) In this part:
(1) Words importing the singular include the plural; and
(2) Words importing the plural include the singular.
Leaks and spills of LNG must be reported in accordance with the requirements of part 191 of this chapter.
(a) Any document or portion thereof incorporated by reference in this part is included in this part as though it were printed in full. When only a portion of a document is referenced, then this part incorporates only that referenced portion of the document and the remainder is not incorporated. Applicable editions are listed in paragraph (c) of this section in parentheses following the title of the referenced material. Earlier editions listed in previous editions of this section may be used for components manufactured, designed, or installed in accordance with those earlier editions at the time they were listed. The user must refer to the appropriate previous edition of 49 CFR for a listing of the earlier editions.
(b) All incorporated materials are available for inspection in the Pipeline and Hazardous Materials Safety Administration, PHP-30, 1200 New Jersey Avenue, SE., Washington, DC, 20590-0001, or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030 or go to:
Documents incorporated by reference are available from the publishers as follows:
A. American Gas Association (AGA), 400 North Capitol Street, NW., Washington, DC 20001.
B. American Society of Civil Engineers (ASCE), Parallel Centre, 1801 Alexander Bell Drive, Reston, VA 20191-4400.
C. ASME International (ASME), Three Park Avenue, New York, NY 10016-5990.
D. Gas Technology Institute (GTI), 1700 S. Mount Prospect Road, Des Plaines, IL 60018.
E. National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O. Box 9101, Quincy, MA 02269-9101.
(c) Documents incorporated by reference.
(a) Each operator shall maintain at each LNG plant the plans and procedures required for that plant by this part. The plans and procedures must be available upon request for review and inspection by the Administrator or any State Agency that has submitted a current certification or agreement with respect to the plant under the pipeline safety laws (49 U.S.C. 60101
(b) The Administrator or the State Agency that has submitted a current certification under section 5(a) of the Natural Gas Pipeline Safety Act with respect to the pipeline facility governed by an operator's plans and procedures may, after notice and opportunity for hearing as provided in 49 CFR 190.237 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety.
(c) Each operator must review and update the plans and procedures required by this part—
(1) When a component is changed significantly or a new component is installed; and
(2) At intervals not exceeding 27 months, but at least once every 2 calendar years.
(a) Mobile and temporary LNG facilities for peakshaving application, for service maintenance during gas pipeline systems repair/alteration, or for other short term applications need not meet the requirements of this part if the facilities are in compliance with applicable sections of NFPA 59A (incorporated by reference,
(b) The State agency having jurisdiction over pipeline safety in the State in which the portable LNG equipment is to be located must be provided with a location description for the installation at least 2 weeks in advance, including to the extent practical, the details of siting, leakage containment or control, fire fighting equipment, and methods employed to restrict public
Each LNG facility designed, constructed, replaced, relocated or significantly altered after March 31, 2000 must be provided with siting requirements in accordance with the requirements of this part and of NFPA 59A (incorporated by reference,
Each LNG container and LNG transfer system must have a thermal exclusion zone in accordance with section 2.2.3.2 of NFPA 59A (incorporated by reference,
(a) The thermal radiation distances shall be calculated using Gas Research Institute's (GRI) report GRI-89/0176 (incorporated by reference,
(b) In calculating exclusion distances, the wind speed producing the maximum exclusion distances shall be used except for wind speeds that occur less than 5 percent of the time based on recorded data for the area.
(c) In calculating exclusion distances, the ambient temperature and relative humidity that produce the maximum exclusion distances shall be used except for values that occur less than five percent of the time based on recorded data for the area.
Each LNG container and LNG transfer system must have a dispersion exclusion zone in accordance with sections 2.2.3.3 and 2.2.3.4 of NFPA 59A (incorporated by reference,
(a) Flammable vapor-gas dispersion distances must be determined in accordance with the model described in the Gas Research Institute report GRI-89/0242 (incorporated by reference,
(b) The following dispersion parameters must be used in computing dispersion distances:
(1) Average gas concentration in air = 2.5 percent.
(2) Dispersion conditions are a combination of those which result in longer predicted downwind dispersion distances than other weather conditions at the site at least 90 percent of the time, based on figures maintained by National Weather Service of the U.S. Department of Commerce, or as an alternative where the model used gives longer distances at lower wind speeds, Atmospheric Stability (Pasquill Class) F, wind speed = 4.5 miles per hour (2.01 meters/sec) at reference height of 10
(3) The elevation for contour (receptor) output H = 0.5 meters.
(4) A surface roughness factor of 0.03 meters shall be used. Higher values for the roughness factor may be used if it can be shown that the terrain both upwind and downwind of the vapor cloud has dense vegetation and that the vapor cloud height is more than ten times the height of the obstacles encountered by the vapor cloud.
(c) The design spill shall be determined in accordance with section 2.2.3.5 of NFPA 59A (incorporated by reference,
(a) LNG facilities must be designed to withstand without loss of structural or functional integrity:
(1) The direct effect of wind forces;
(2) The pressure differential between the interior and exterior of a confining, or partially confining, structure; and
(3) In the case of impounding systems for LNG storage tanks, impact forces and potential penetrations by wind borne missiles.
(b) The wind forces at the location of the specific facility must be based on one of the following:
(1) For shop fabricated containers of LNG or other hazardous fluids with a capacity of not more than 70,000 gallons, applicable wind load data in SEI/ASCE 7-02 (incorporated by reference,
(2) For all other LNG facilities:
(i) An assumed sustained wind velocity of not less than 150 miles per hour, unless the Administrator finds a lower velocity is justified by adequate supportive data; or
(ii) The most critical combination of wind velocity and duration, with respect to the effect on the structure, having a probability of exceedance in a 50-year period of 0.5 percent or less, if adequate wind data are available and the probabilistic methodology is reliable.
Each LNG facility designed after March 31, 2000 must comply with requirements of this part and of NFPA 59A (incorporated by reference,
Each operator shall keep a record of all materials for components, buildings, foundations, and support systems, as necessary to verify that material properties meet the requirements of this part. These records must be maintained for the life of the item concerned.
(a) The structural members of an impoundment system must be designed and constructed to prevent impairment of the system's performance reliability and structural integrity as a result of the following:
(1) The imposed loading from—
(i) Full hydrostatic head of impounded LNG;
(ii) Hydrodynamic action, including the effect of any material injected into the system for spill control;
(iii) The impingement of the trajectory of an LNG jet discharged at any predictable angle; and
(iv) Anticipated hydraulic forces from a credible opening in the component or item served, assuming that the discharge pressure equals design pressure.
(2) The erosive action from a spill, including jetting of spilling LNG, and any other anticipated erosive action including surface water runoff, ice formation, dislodgement of ice formation, and snow removal.
(3) The effect of the temperature, any thermal gradient, and any other anticipated degradation resulting from sudden or localized contact with LNG.
(4) Exposure to fire from impounded LNG or from sources other than impounded LNG.
(5) If applicable, the potential impact and loading on the dike due to—
(i) Collapse of the component or item served or adjacent components; and
(ii) If the LNG facility adjoins the right-of-way of any highway or railroad, collision by or explosion of a train, tank car, or tank truck that could reasonably be expected to cause the most severe loading.
(b) An LNG storage tank must not be located within a horizontal distance of one mile (1.6 km) from the ends, or
An outer wall of a component served by an impounding system may not be used as a dike unless the outer wall is constructed of concrete.
A covered impounding system is prohibited except for concrete wall designed tanks where the concrete wall is an outer wall serving as a dike.
(a) Impoundment areas must be constructed such that all areas drain completely to prevent water collection. Drainage pumps and piping must be provided to remove water from collecting in the impoundment area. Alternative means of draining may be acceptable subject to the Administrator's approval.
(b) The water removal system must have adequate capacity to remove water at a rate equal to 25% of the maximum predictable collection rate from a storm of 10-year frequency and 1-hour duration, and other natural causes. For rainfall amounts, operators must use the “Rainfall Frequency Atlas of the United States” published by the National Weather Service of the U.S. Department of Commerce.
(c) Sump pumps for water removal must—
(1) Be operated as necessary to keep the impounding space as dry as practical; and
(2) If sump pumps are designed for automatic operation, have redundant automatic shutdown controls to prevent operation when LNG is present.
Each impounding system serving an LNG storage tank must have a minimum volumetric liquid impoundment capacity of:
(a) 110 percent of the LNG tank's maximum liquid capacity for an impoundment serving a single tank;
(b) 100 percent of all tanks or 110 percent of the largest tank's maximum liquid capacity, whichever is greater, for the impoundment serving more than one tank; or
(c) If the dike is designed to account for a surge in the event of catastrophic failure, then the impoundment capacity may be reduced to 100 percent in lieu of 110 percent.
A flammable nonmetallic membrane liner may not be used as an inner container in a storage tank.
Each LNG facility constructed after March 31, 2000 must comply with requirements of this part and of NFPA 59A (incorporated by reference
No person may place in service any component until it passes all applicable inspections and tests prescribed by this subpart and NFPA 59A (incorporated by reference,
(a) Subject to paragraph (b) of this section, components may not be constructed, repaired, replaced, or significantly altered until a person qualified under § 193.2707(c) reviews the applicable design drawings and materials specifications from a corrosion control viewpoint and determines that the materials involved will not impair the safety or reliability of the component or any associated components.
(b) The repair, replacement, or significant alteration of components must be reviewed only if the action to be taken—
(1) Involves a change in the original materials specified;
(2) Is due to a failure caused by corrosion; or
(3) Is occasioned by inspection revealing a significant deterioration of the component due to corrosion.
The butt welds in metal shells of storage tanks with internal design pressure above 15 psig must be radiographically tested in accordance with the ASME Boiler and Pressure Vessel Code (Section VIII Division 1), except that hydraulic load bearing shells with curved surfaces that are subject to cryogenic temperatures, 100 percent of both longitudinal (or meridional) and circumferential (or latitudinal) welds must be radiographically tested.
After March 31, 2000, each new, replaced, relocated or significantly altered vaporization equipment, liquefaction equipment, and control systems must be designed, fabricated, and installed in accordance with requirements of this part and of NFPA 59A. In the event of a conflict between this part and NFPA 59A (incorporated by reference,
Each LNG plant must have a control center from which operations and warning devices are monitored as required by this part. A control center must have the following capabilities and characteristics:
(a) It must be located apart or protected from other LNG facilities so that it is operational during a controllable emergency.
(b) Each remotely actuated control system and each automatic shutdown control system required by this part must be operable from the control center.
(c) Each control center must have personnel in continuous attendance while any of the components under its control are in operation, unless the control is being performed from another control center which has personnel in continuous attendance.
(d) If more than one control center is located at an LNG Plant, each control center must have more than one means of communication with each other center.
(e) Each control center must have a means of communicating a warning of hazardous conditions to other locations within the plant frequented by personnel.
(a) Electrical control systems, means of communication, emergency lighting, and firefighting systems must have at least two sources of power which function so that failure of one source does not affect the capability of the other source.
(b) Where auxiliary generators are used as a second source of electrical power:
(1) They must be located apart or protected from components so that they are not unusable during a controllable emergency; and
(2) Fuel supply must be protected from hazards.
This subpart prescribes requirements for the operation of LNG facilities.
Each operator shall follow one or more manuals of written procedures to provide safety in normal operation and in responding to an abnormal operation that would affect safety. The procedures must include provisions for:
(a) Monitoring components or buildings according to the requirements of § 193.2507.
(b) Startup and shutdown, including for initial startup, performance testing to demonstrate that components will operate satisfactory in service.
(c) Recognizing abnormal operating conditions.
(d) Purging and inerting components according to the requirements of § 193.2517.
(e) In the case of vaporization, maintaining the vaporization rate, temperature and pressure so that the resultant gas is within limits established for the vaporizer and the downstream piping.
(f) In the case of liquefaction, maintaining temperatures, pressures, pressure differentials and flow rates, as applicable, within their design limits for:
(1) Boilers;
(2) Turbines and other prime movers;
(3) Pumps, compressors, and expanders;
(4) Purification and regeneration equipment; and
(5) Equipment within cold boxes.
(g) Cooldown of components according to the requirements of § 193.2505.
(a) The cooldown of each system of components that is subjected to cryogenic temperatures must be limited to a rate and distribution pattern that keeps thermal stresses within design limits during the cooldown period, paying particular attention to the performance of expansion and contraction devices.
(b) After cooldown stabilization is reached, cryogenic piping systems must be checked for leaks in areas of flanges, valves, and seals.
Each component in operation or building in which a hazard to persons or property could exist must be monitored to detect fire or any malfunction or flammable fluid that could cause a hazardous condition. Monitoring must be accomplished by watching or listening from an attended control center for
(a) Each operator shall determine the types and places of emergencies other than fires that may reasonably be expected to occur at an LNG plant due to operating malfunctions, structural collapse, personnel error, forces of nature, and activities adjacent to the plant.
(b) To adequately handle each type of emergency identified under paragraph (a) of this section and each fire emergency, each operator must follow one or more manuals of written procedures. The procedures must provide for the following:
(1) Responding to controllable emergencies, including notifying personnel and using equipment appropriate for handling the emergency.
(2) Recognizing an uncontrollable emergency and taking action to minimize harm to the public and personnel, including prompt notification of appropriate local officials of the emergency and possible need for evacuation of the public in the vicinity of the LNG plant.
(3) Coordinating with appropriate local officials in preparation of an emergency evacuation plan, which sets forth the steps required to protect the public in the event of an emergency, including catastrophic failure of an LNG storage tank.
(4) Cooperating with appropriate local officials in evacuations and emergencies requiring mutual assistance and keeping these officials advised of:
(i) The LNG plant fire control equipment, its location, and quantity of units located throughout the plant;
(ii) Potential hazards at the plant, including fires;
(iii) Communication and emergency control capabilities at the LNG plant; and
(iv) The status of each emergency.
(a) Each operator shall provide any special protective clothing and equipment necessary for the safety of personnel while they are performing emergency response duties.
(b) All personnel who are normally on duty at a fixed location, such as a building or yard, where they could be harmed by thermal radiation from a burning pool of impounded liquid, must be provided a means of protection at that location from the harmful effects of thermal radiation or a means of escape.
(c) Each LNG plant must be equipped with suitable first-aid material, the location of which is clearly marked and readily available to personnel.
(a) Each transfer of LNG or other hazardous fluid must be conducted in accordance with one or more manuals of written procedures to provide for safe transfers.
(b) The transfer procedures must include provisions for personnel to:
(1) Before transfer, verify that the transfer system is ready for use, with connections and controls in proper positions, including if the system could contain a combustible mixture, verifying that it has been adequately purged in accordance with a procedure which meets the requirements of AGA “Purging Principles and Practice.”
(2) Before transfer, verify that each receiving container or tank vehicle does not contain any substance that would be incompatible with the incoming fluid and that there is sufficient capacity available to receive the amount of fluid to be transferred;
(3) Before transfer, verify the maximum filling volume of each receiving container or tank vehicle to ensure that expansion of the incoming fluid due to warming will not result in overfilling or overpressure;
(4) When making bulk transfer of LNG into a partially filled (excluding cooldown heel) container, determine any differences in temperature or specific gravity between the LNG being transferred and the LNG already in the container and, if necessary, provide a means to prevent rollover due to stratification.
(5) Verify that the transfer operations are proceeding within design conditions and that overpressure or overfilling does not occur by monitoring applicable flow rates, liquid levels, and vapor returns.
(6) Manually terminate the flow before overfilling or overpressure occurs; and
(7) Deactivate cargo transfer systems in a safe manner by depressurizing, venting, and disconnecting lines and conducting any other appropriate operations.
(c) In addition to the requirements of paragraph (b) of this section, the procedures for cargo transfer must be located at the transfer area and include provisions for personnel to:
(1) Be in constant attendance during all cargo transfer operations;
(2) Prohibit the backing of tank trucks in the transfer area, except when a person is positioned at the rear of the truck giving instructions to the driver;
(3) Before transfer, verify that:
(i) Each tank car or tank truck complies with applicable regulations governing its use;
(ii) All transfer hoses have been visually inspected for damage and defects;
(iii) Each tank truck is properly immobilized with chock wheels, and electrically grounded; and
(iv) Each tank truck engine is shut off unless it is required for transfer operations;
(4) Prevent a tank truck engine that is off during transfer operations from being restarted until the transfer lines have been disconnected and any released vapors have dissipated;
(5) Prevent loading LNG into a tank car or tank truck that is not in exclusive LNG service or that does not contain a positive pressure if it is in exclusive LNG service, until after the oxygen content in the tank is tested and if it exceeds 2 percent by volume, purged in accordance with a procedure that meets the requirements of AGA “Purging Principles and Practice;”
(6) Verify that all transfer lines have been disconnected and equipment cleared before the tank car or tank truck is moved from the transfer position; and
(7) Verify that transfers into a pipeline system will not exceed the pressure or temperature limits of the system.
(a) Each operator shall investigate the cause of each explosion, fire, or LNG spill or leak which results in:
(1) Death or injury requiring hospitalization; or
(2) Property damage exceeding $10,000.
(b) As a result of the investigation, appropriate action must be taken to minimize recurrence of the incident.
(c) If the Administrator or relevant state agency under the pipeline safety laws (49 U.S.C. 60101
When necessary for safety, components that could accumulate significant amounts of combustible mixtures must be purged in accordance with a procedure which meets the provisions of the AGA “Purging Principles and Practice” after being taken out of service and before being returned to service.
(a) Each LNG plant must have a primary communication system that provides for verbal communications between all operating personnel at their work stations in the LNG plant.
(b) Each LNG plant in excess of 70,000 gallons (265,000 liters) storage capacity must have an emergency communication system that provides for verbal communications between all persons and locations necessary for the orderly shutdown of operating equipment and the operation of safety equipment in time of emergency. The emergency communication system must be independent of and physically separated from the primary communication system and the security communication system under § 193.2909.
(c) Each communication system required by this part must have an auxiliary source of power, except sound-powered equipment.
Each operator shall maintain a record of results of each inspection, test and investigation required by this subpart. For each LNG facility that is designed and constructed after March 31, 2000 the operator shall also maintain related inspection, testing, and investigation records that NFPA 59A (incorporated by reference,
This subpart prescribes requirements for maintaining components at LNG plants.
(a) Each component in service, including its support system, must be maintained in a condition that is compatible with its operational or safety purpose by repair, replacement, or other means.
(b) An operator may not place, return, or continue in service any component which is not maintained in accordance with this subpart.
(c) Each component taken out of service must be identified in the records kept under § 193.2639.
(d) If a safety device is taken out of service for maintenance, the component being served by the device must be taken out of service unless the same safety function is provided by an alternate means.
(e) If the inadvertent operation of a component taken out of service could cause a hazardous condition, that component must have a tag attached to the controls bearing the words “do not operate” or words of comparable meaning.
(a) Each operator shall determine and perform, consistent with generally accepted engineering practice, the periodic inspections or tests needed to meet the applicable requirements of this subpart and to verify that components meet the maintenance standards prescribed by this subpart.
(b) Each operator shall follow one or more manuals of written procedures for the maintenance of each component, including any required corrosion control. The procedures must include:
(1) The details of the inspections or tests determined under paragraph (a) of this section and their frequency of performance; and
(2) A description of other actions necessary to maintain the LNG plant according to the requirements of this subpart.
(c) Each operator shall include in the manual required by paragraph (b) of this section instructions enabling personnel who perform operation and maintenance activities to recognize conditions that potentially may be safety-related conditions that are subject to the reporting requirements of § 191.23 of this subchapter.
(a) The presence of foreign material, contaminants, or ice shall be avoided
(b) LNG plant grounds must be free from rubbish, debris, and other material which present a fire hazard. Grass areas on the LNG plant grounds must be maintained in a manner that does not present a fire hazard.
Each support system or foundation of each component must be inspected for any detrimental change that could impair support.
(a) Maintenance activities on fire control equipment must be scheduled so that a minimum of equipment is taken out of service at any one time and is returned to service in a reasonable period of time.
(b) Access routes for movement of fire control equipment within each LNG plant must be maintained to reasonably provide for use in all weather conditions.
Each auxiliary power source must be tested monthly to check its operational capability and tested annually for capacity. The capacity test must take into account the power needed to start up and simultaneously operate equipment that would have to be served by that power source in an emergency.
(a) Before personnel begin maintenance activities on components handling flammable fluids which are isolated for maintenance, the component must be purged in accordance with a procedure which meets the requirements of AGA “Purging Principles and Practices,” unless the maintenance procedures under § 193.2605 provide that the activity can be safely performed without purging.
(b) If the component or maintenance activity provides an ignition source, a technique in addition to isolation valves (such as removing spool pieces or valves and blank flanging the piping, or double block and bleed valving) must be used to ensure that the work area is free of flammable fluids.
(a) Repair work on components must be performed and tested in a manner which:
(1) As far as practicable, complies with the applicable requirements of Subpart D of this part; and
(2) Assures the integrity and operational safety of the component being repaired.
(b) For repairs made while a component is operating, each operator shall include in the maintenance procedures under § 193.2605 appropriate precautions to maintain the safety of personnel and property during repair activities.
(a) Each control system must be properly adjusted to operate within design limits.
(b) If a control system is out of service for 30 days or more, it must be inspected and tested for operational capability before returning it to service.
(c) Control systems in service, but not normally in operation, such as relief valves and automatic shutdown devices, and control systems for internal shutoff valves for bottom penetration tanks must be inspected and tested once each calender year, not exceeding 15 months, with the following exceptions:
(1) Control systems used seasonally, such as for liquefaction or vaporization, must be inspected and tested before use each season.
(2) Control systems that are intended for fire protection must be inspected and tested at regular intervals not to exceed 6 months.
(d) Control systems that are normally in operation, such as required by a base load system, must be inspected and tested once each calendar year but with intervals not exceeding 15 months.
(e) Relief valves must be inspected and tested for verification of the valve seat lifting pressure and reseating.
Hoses used in LNG or flammable refrigerant transfer systems must be:
(a) Tested once each calendar year, but with intervals not exceeding 15 months, to the maximum pump pressure or relief valve setting; and
(b) Visually inspected for damage or defects before each use.
Each LNG storage tank must be inspected or tested to verify that each of the following conditions does not impair the structural integrity or safety of the tank:
(a) Foundation and tank movement during normal operation and after a major meteorological or geophysical disturbance.
(b) Inner tank leakage.
(c) Effectiveness of insulation.
(d) Frost heave.
(a) Each operator shall determine which metallic components could, unless corrosion is controlled, have their integrity or reliability adversely affected by external, internal, or atmospheric corrosion during their intended service life.
(b) Components whose integrity or reliability could be adversely affected by corrosion must be either—
(1) Protected from corrosion in accordance with §§ 193.2627 through 193.2635, as applicable; or
(2) Inspected and replaced under a program of scheduled maintenance in accordance with procedures established under § 193.2605.
Each exposed component that is subject to atmospheric corrosive attack must be protected from atmospheric corrosion by—
(a) Material that has been designed and selected to resist the corrosive atmosphere involved; or
(b) Suitable coating or jacketing.
(a) Each buried or submerged component that is subject to external corrosive attack must be protected from external corrosion by—
(1) Material that has been designed and selected to resist the corrosive environment involved; or
(2) The following means:
(i) An external protective coating designed and installed to prevent corrosion attack and to meet the requirements of § 192.461 of this chapter; and
(ii) A cathodic protection system designed to protect components in their entirety in accordance with the requirements of § 192.463 of this chapter and placed in operation before October 23, 1981, or within 1 year after the component is constructed or installed, whichever is later.
(b) Where cathodic protection is applied, components that are electrically interconnected must be protected as a unit.
Each component that is subject to internal corrosive attack must be protected from internal corrosion by—
(a) Material that has been designed and selected to resist the corrosive fluid involved; or
(b) Suitable coating, inhibitor, or other means.
(a) Each component that is subject to electrical current interference must be protected by a continuing program to minimize the detrimental effects of currents.
(b) Each cathodic protection system must be designed and installed so as to minimize any adverse effects it might cause to adjacent metal components.
(c) Each impressed current power source must be installed and maintained to prevent adverse interference with communications and control systems.
Corrosion protection provided as required by this subpart must be periodically monitored to give early recognition of ineffective corrosion protection, including the following, as applicable:
(a) Each buried or submerged component under cathodic protection must be tested at least once each calendar year, but with intervals not exceeding 15 months, to determine whether the cathodic protection meets the requirements of § 192.463 of this chapter.
(b) Each cathodic protection rectifier or other impressed current power source must be inspected at least 6 times each calendar year, but with intervals not exceeding 2
(c) Each reverse current switch, each diode, and each interference bond whose failure would jeopardize component protection must be electrically checked for proper performance at least 6 times each calendar year, but with intervals not exceeding 2
(d) Each component that is protected from atmospheric corrosion must be inspected at intervals not exceeding 3 years.
(e) If a component is protected from internal corrosion, monitoring devices designed to detect internal corrosion, such as coupons or probes, must be located where corrosion is most likely to occur. However, monitoring is not required for corrosion resistant materials if the operator can demonstrate that the component will not be adversely affected by internal corrosion during its service life. Internal corrosion control monitoring devices must be checked at least two times each calendar year, but with intervals not exceeding 7
Prompt corrective or remedial action must be taken whenever an operator learns by inspection or otherwise that atmospheric, external, or internal corrosion is not controlled as required by this subpart.
(a) Each operator shall keep a record at each LNG plant of the date and type of each maintenance activity performed on each component to meet the requirements of this part. For each LNG facility that is designed and constructed after March 31, 2000 the operator shall also maintain related periodic inspection and testing records that NFPA 59A (incorporated by reference,
(b) Each operator shall maintain records or maps to show the location of cathodically protected components, neighboring structures bonded to the cathodic protection system, and corrosion protection equipment.
(c) Each of the following records must be retained for as long as the LNG facility remains in service:
(1) Each record or map required by paragraph (b) of this section.
(2) Records of each test, survey, or inspection required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures.
This subpart prescribes requirements for personnel qualifications and training.
For the design and fabrication of components, each operator shall use—
(a) With respect to design, persons who have demonstrated competence by training or experience in the design of comparable components.
(b) With respect to fabrication, persons who have demonstrated competence by training or experience in the fabrication of comparable components.
(a) Supervisors and other personnel utilized for construction, installation, inspection, or testing must have demonstrated their capability to perform satisfactorily the assigned function by appropriate training in the methods and equipment to be used or related experience and accomplishments.
(b) Each operator must periodically determine whether inspectors performing construction, installation, and testing duties required by this part are satisfactorily performing their assigned functions.
(a) Each operator shall utilize for operation or maintenance of components only those personnel who have demonstrated their capability to perform their assigned functions by—
(1) Successful completion of the training required by §§ 193.2713 and 193.2717; and
(2) Experience related to the assigned operation or maintenance function; and
(3) Acceptable performance on a proficiency test relevant to the assigned function.
(b) A person who does not meet the requirements of paragraph (a) of this section may operate or maintain a component when accompanied and directed by an individual who meets the requirements.
(c) Corrosion control procedures under § 193.2605(b), including those for the design, installation, operation, and maintenance of cathodic protection systems, must be carried out by, or under the direction of, a person qualified by experience and training in corrosion control technology.
Personnel having security duties must be qualified to perform their assigned duties by successful completion of the training required under § 193.2715.
Each operator shall follow a written plan to verify that personnel assigned operating, maintenance, security, or fire protection duties at the LNG plant do not have any physical condition that would impair performance of their assigned duties. The plan must be designed to detect both readily observable disorders, such as physical handicaps or injury, and conditions requiring professional examination for discovery.
(a) Each operator shall provide and implement a written plan of initial training to instruct—
(1) All permanent maintenance, operating, and supervisory personnel—
(i) About the characteristics and hazards of LNG and other flammable fluids used or handled at the facility, including, with regard to LNG, low temperatures, flammability of mixtures with air, odorless vapor, boiloff characteristics, and reaction to water and water spray;
(ii) About the potential hazards involved in operating and maintenance activities; and
(iii) To carry out aspects of the operating and maintenance procedures under §§ 193.2503 and 193.2605 that relate to their assigned functions; and
(2) All personnel—
(i) To carry out the emergency procedures under § 193.2509 that relate to their assigned functions; and
(ii) To give first-aid; and
(3) All operating and appropriate supervisory personnel—
(i) To understand detailed instructions on the facility operations, including controls, functions, and operating procedures; and
(ii) To understand the LNG transfer procedures provided under § 193.2513.
(b) A written plan of continuing instruction must be conducted at intervals of not more than two years to keep all personnel current on the knowledge and skills they gained in the program of initial instruction.
(a) Personnel responsible for security at an LNG plant must be trained in accordance with a written plan of initial instruction to:
(1) Recognize breaches of security;
(2) Carry out the security procedures under § 193.2903 that relate to their assigned duties;
(3) Be familiar with basic plant operations and emergency procedures, as necessary to effectively perform their assigned duties; and
(4) Recognize conditions where security assistance is needed.
(b) A written plan of continuing instruction must be conducted at intervals of not more than two years to keep all personnel having security duties current on the knowledge and skills they gained in the program of initial instruction.
(a) All personnel involved in maintenance and operations of an LNG plant, including their immediate supervisors, must be trained according to a written plan of initial instruction, including plant fire drills, to:
(1) Know the potential causes and areas of fire;
(2) Know the types, sizes, and predictable consequences of fire; and
(3) Know and be able to perform their assigned fire control duties according to the procedures established under § 193.2509 and by proper use of equipment provided under § 193.2801.
(b) A written plan of continuing instruction, including plant fire drills, must be conducted at intervals of not more than two years to keep personnel current on the knowledge and skills they gained in the instruction under paragraph (a) of the section.
(c) Plant fire drills must provide personnel hands-on experience in carrying out their duties under the fire emergency procedures required by § 193.2509.
(a) Each operator shall maintain a system of records which—
(1) Provide evidence that the training programs required by this subpart have been implemented; and
(2) Provide evidence that personnel have undergone and satisfactorily completed the required training programs.
(b) Records must be maintained for one year after personnel are no longer assigned duties at the LNG plant.
Each operator must provide and maintain fire protection at LNG plants according to sections 9.1 through 9.7 and section 9.9 of NFPA 59A (incorporated by reference,
This subpart prescribes requirements for security at LNG plants. However, the requirements do not apply to existing LNG plants that do not contain LNG.
Each operator shall prepare and follow one or more manuals of written procedures to provide security for each LNG plant. The procedures must be available at the plant in accordance with § 193.2017 and include at least:
(a) A description and schedule of security inspections and patrols performed in accordance with § 193.2913;
(b) A list of security personnel positions or responsibilities utilized at the LNG plant;
(c) A brief description of the duties associated with each security personnel position or responsibility;
(d) Instructions for actions to be taken, including notification of other appropriate plant personnel and law enforcement officials, when there is any indication of an actual or attempted breach of security;
(e) Methods for determining which persons are allowed access to the LNG plant;
(f) Positive identification of all persons entering the plant and on the plant, including methods at least as effective as picture badges; and
(g) Liaison with local law enforcement officials to keep them informed about current security procedures under this section.
(a) The following facilities must be surrounded by a protective enclosure:
(1) Storage tanks;
(2) Impounding systems;
(3) Vapor barriers;
(4) Cargo transfer systems;
(5) Process, liquefaction, and vaporization equipment;
(6) Control rooms and stations;
(7) Control systems;
(8) Fire control equipment;
(9) Security communications systems; and
(10) Alternative power sources.
(b) Ground elevations outside a protective enclosure must be graded in a manner that does not impair the effectiveness of the enclosure.
(c) Protective enclosures may not be located near features outside of the facility, such as trees, poles, or buildings, which could be used to breach the security.
(d) At least two accesses must be provided in each protective enclosure and be located to minimize the escape distance in the event of emergency.
(e) Each access must be locked unless it is continuously guarded. During normal operations, an access may be unlocked only by persons designated in writing by the operator. During an emergency, a means must be readily available to all facility personnel within the protective enclosure to open each access.
(a) Each protective enclosure must have sufficient strength and configuration to obstruct unauthorized access to the facilities enclosed.
(b) Openings in or under protective enclosures must be secured by grates, doors or covers of construction and fastening of sufficient strength such that the integrity of the protective enclosure is not reduced by any opening.
A means must be provided for:
(a) Prompt communications between personnel having supervisory security duties and law enforcement officials; and
(b) Direct communications between all on-duty personnel having security duties and all control rooms and control stations.
Where security warning systems are not provided for security monitoring under § 193.2913, the area around the facilities listed under § 193.2905(a) and each protective enclosure must be illuminated with a minimum in service lighting intensity of not less than 2.2 lux (0.2 ft
Each protective enclosure and the area around each facility listed in § 193.2905(a) must be monitored for the presence of unauthorized persons. Monitoring must be by visual observation in accordance with the schedule in the security procedures under § 193.2903(a) or by security warning systems that continuously transmit data to an attended location. At an LNG plant with less than 40,000 m
An alternative source of power that meets the requirements of § 193.2445 must be provided for security lighting
(a) Warning signs must be conspicuously placed along each protective enclosure at intervals so that at least one sign is recognizable at night from a distance of 30m (100 ft.) from any way that could reasonably be used to approach the enclosure.
(b) Signs must be marked with at least the following on a background of sharply contrasting color:
33 U.S.C. 1231, 1321(j)(1)(C), (j)(5) and (j)(6); sec. 2, E.O. 12777, 56 FR 54757, 3 CFR, 1991 Comp., p. 351; 49 CFR 1.53.
This part contains requirements for oil spill response plans to reduce the environmental impact of oil discharged from onshore oil pipelines.
This part applies to an operator of an onshore oil pipeline that, because of its location, could reasonably be expected to cause substantial harm, or significant and substantial harm to the environment by discharging oil into or on any navigable waters of the United States or adjoining shorelines.
(1) Relieve surges in an oil pipeline system or
(2) Receive and store oil transported by a pipeline for reinjection and continued transportation by pipeline.
(1) A written contract or other legally binding agreement between the operator and a response contractor or other spill response organization identifying and ensuring the availability of the specified personnel and equipment within stipulated response times for a specified geographic area;
(2) Certification that specified equipment is owned or operated by the pipeline operator, and operator personnel and equipment are available within stipulated response times for a specified geographic area; or
(3) Active membership in a local or regional oil spill removal organization that has identified specified personnel and equipment to be available within
(a) An operator of a pipeline for which a response plan is required under § 194.101, may not handle, store, or transport oil in that pipeline unless the operator has submitted a response plan meeting the requirements of this part.
(b) An operator must operate its onshore pipeline facilities in accordance with the applicable response plan.
(c) The operator of a pipeline line section described in § 194.103(c), may continue to operate the pipeline for two years after the date of submission of a response plan, pending approval or disapproval of that plan, only if the operator has submitted the certification required by § 194.119(e).
(a) Except as provided in paragraph (b) of this section, unless OPS grants a request from an Federal On-Scene Coordinator (FOSC) to require an operator of a pipeline in paragraph (b) to submit a response plan, each operator of an onshore pipeline facility shall prepare and submit a response plan to PHMSA as provided in § 194.119. A pipeline which does not meet the criteria for significant and substantial harm as defined in § 194.103(c) and is not eligible for an exception under § 194.101(b), can be expected to cause substantial harm. Operators of substantial harm pipeline facilities must prepare and submit plans to PHMSA for review.
(b)
(1) A pipeline that is 6
(i) The pipeline has not experienced a release greater than 1,000 barrels (159 cubic meters) within the previous five years,
(ii) The pipeline has not experienced at least two reportable releases, as defined in § 195.50, within the previous five years,
(iii) A pipeline containing any electric resistance welded pipe, manufactured prior to 1970, does not operate at a maximum operating pressure established under § 195.406 that corresponds to a stress level greater than 50 percent of the specified minimum yield strength of the pipe, and
(iv) The pipeline is not in proximity to navigable waters, public drinking water intakes, or environmentally sensitive areas.
(2)(i) A line section that is greater than 6
(ii) A line section that is 6
(a) Each operator shall submit a statement with its response plan, as required by §§ 194.107 and 194.113, identifying which line sections in a response zone can be expected to cause significant and substantial harm to the environment in the event of a discharge of oil into or on the navigable waters or adjoining shorelines.
(b) If an operator expects a line section in a response zone to cause significant and substantial harm, then the entire response zone must, for the purpose of response plan review and approval, be treated as if it is expected to cause significant and substantial harm. However, an operator will not have to submit separate plans for each line section.
(c) A line section can be expected to cause significant and substantial harm to the environment in the event of a discharge of oil into or on the navigable waters or adjoining shorelines if; the pipeline is greater than 6
(1) Has experienced a release greater than 1,000 barrels (159 cubic meters) within the previous five years,
(2) Has experienced two or more reportable releases, as defined in § 195.50, within the previous five years,
(3) Containing any electric resistance welded pipe, manufactured prior to 1970, operates at a maximum operating pressure established under § 195.406 that corresponds to a stress level greater than 50 percent of the specified minimum yield strength of the pipe,
(4) Is located within a 5 mile (8 kilometer) radius of potentially affected public drinking water intakes and could reasonably be expected to reach public drinking water intakes, or
(5) Is located within a 1 mile (1.6 kilometer) radius of potentially affected environmentally sensitive areas, and could reasonably be expected to reach these areas.
(a) Each operator shall determine the worst case discharge for each of its response zones and provide the methodology, including calculations, used to arrive at the volume.
(b) The worst case discharge is the largest volume, in barrels (cubic meters), of the following:
(1) The pipeline's maximum release time in hours, plus the maximum shutdown response time in hours (based on historic discharge data or in the absence of such historic data, the operator's best estimate), multiplied by the maximum flow rate expressed in barrels per hour (based on the maximum daily capacity of the pipeline), plus the largest line drainage volume after shutdown of the line section(s) in the response zone expressed in barrels (cubic meters); or
(2) The largest foreseeable discharge for the line section(s) within a response zone, expressed in barrels (cubic meters), based on the maximum historic discharge, if one exists, adjusted for any subsequent corrective or preventive action taken; or
(3) If the response zone contains one or more breakout tanks, the capacity of the single largest tank or battery of tanks within a single secondary containment system, adjusted for the capacity or size of the secondary containment system, expressed in barrels (cubic meters).
(4) Operators may claim prevention credits for breakout tank secondary containment and other specific spill prevention measures as follows:
(a) Each response plan must include procedures and a list of resources for responding, to the maximum extent practicable, to a worst case discharge and to a substantial threat of such a discharge. The “substantial threat” term is equivalent to abnormal operations outlined in 49 CFR 195.402(d). To comply with this requirement, an operator can incorporate by reference into the response plan the appropriate procedures from its manual for operations, maintenance, and emergencies, which is prepared in compliance with 49 CFR 195.402.
(b) An operator must certify in the response plan that it reviewed the NCP and each applicable ACP and that its response plan is consistent with the NCP and each applicable ACP as follows:
(1) As a minimum to be consistent with the NCP a facility response plan must:
(i) Demonstrate an operator's clear understanding of the function of the Federal response structure, including procedures to notify the National Response Center reflecting the relationship between the operator's response organization's role and the Federal On Scene Coordinator's role in pollution response;
(ii) Establish provisions to ensure the protection of safety at the response site; and
(iii) Identify the procedures to obtain any required Federal and State permissions for using alternative response strategies such as in-situ burning and dispersants as provided for in the applicable ACPs; and
(2) As a minimum, to be consistent with the applicable ACP the plan must:
(i) Address the removal of a worst case discharge and the mitigation or prevention of a substantial threat of a worst case discharge;
(ii) Identify environmentally and economically sensitive areas;
(iii) Describe the responsibilities of the operator and of Federal, State and local agencies in removing a discharge and in mitigating or preventing a substantial threat of a discharge; and
(iv) Establish the procedures for obtaining an expedited decision on use of dispersants or other chemicals.
(c) Each response plan must include:
(1) A core plan consisting of—
(i) An information summary as required in § 194.113,
(ii) Immediate notification procedures,
(iii) Spill detection and mitigation procedures,
(iv) The name, address, and telephone number of the oil spill response organization, if appropriate,
(v) Response activities and response resources,
(vi) Names and telephone numbers of Federal, State and local agencies which the operator expects to have pollution control responsibilities or support,
(vii) Training procedures,
(viii) Equipment testing,
(ix) Drill program—an operator will satisfy the requirement for a drill program by following the National Preparedness for Response Exercise Program (PREP) guidelines. An operator choosing not to follow PREP guidelines must have a drill program that is equivalent to PREP. The operator must describe the drill program in the response plan and OPS will determine if the program is equivalent to PREP.
(x) Plan review and update procedures;
(2) An appendix for each response zone that includes the information required in paragraph (c)(1)(i)-(ix) of this section and the worst case discharge calculations that are specific to that response zone. An operator submitting a response plan for a single response zone does not need to have a core plan and a response zone appendix. The operator of a single response zone onshore pipeline shall have a single summary in the plan that contains the required information in § 194.113.7; and
(3) A description of the operator's response management system including the functional areas of finance, logistics, operations, planning, and command. The plan must demonstrate that the operator's response management system uses common terminology and has a manageable span of control, a clearly defined chain of command, and sufficient trained personnel to fill each position.
(a) In lieu of submitting a response plan required by § 194.103, an operator may submit a response plan that complies with a state law or regulation, if the state law or regulation requires a plan that provides equivalent or greater spill protection than a plan required under this part.
(b) A plan submitted under this section must
(1) Have an information summary required by § 194.113;
(2) List the names or titles and 24-hour telephone numbers of the qualified individual(s) and at least one alternate qualified individual(s); and
(3) Ensure through contract or other approved means the necessary private personnel and equipment to respond to a worst case discharge or a substantial threat of such a discharge.
(a) Each operator shall maintain relevant portions of its response plan at the operator's headquarters and at other locations from which response activities may be conducted, for example, in field offices, supervisors' vehicles, or spill response trailers.
(b) Each operator shall provide a copy of its response plan to each qualified individual.
(a) The information summary for the core plan, required by § 194.107, must include:
(1) The name and address of the operator; and
(2) For each response zone which contains one or more line sections that meet the criteria for determining significant and substantial harm as described in § 194.103, a listing and description of the response zones, including county(s) and state(s).
(b) The information summary for the response zone appendix, required in § 194.107, must include:
(1) The information summary for the core plan;
(2) The names or titles and 24-hour telephone numbers of the qualified individual(s) and at least one alternate qualified individual(s);
(3) The description of the response zone, including county(s) and state(s), for those zones in which a worst case discharge could cause substantial harm to the environment;
(4) A list of line sections for each pipeline contained in the response zone, identified by milepost or survey station number, or other operator designation;
(5) The basis for the operator's determination of significant and substantial harm; and
(6) The type of oil and volume of the worst case discharge.
(a) Each operator shall identify and ensure, by contract or other approved means, the resources necessary to remove, to the maximum extent practicable, a worst case discharge and to mitigate or prevent a substantial threat of a worst case discharge.
(b) An operator shall identify in the response plan the response resources
(a) Each operator shall conduct training to ensure that:
(1) All personnel know—
(i) Their responsibilities under the response plan,
(ii) The name and address of, and the procedure for contacting, the operator on a 24-hour basis, and
(iii) The name of, and procedures for contacting, the qualified individual on a 24-hour basis;
(2) Reporting personnel know—
(i) The content of the information summary of the response plan,
(ii) The toll-free telephone number of the National Response Center, and
(iii) The notification process; and
(3) Personnel engaged in response activities know—
(i) The characteristics and hazards of the oil discharged,
(ii) The conditions that are likely to worsen emergencies, including the consequences of facility malfunctions or failures, and the appropriate corrective actions,
(iii) The steps necessary to control any accidental discharge of oil and to minimize the potential for fire, explosion, toxicity, or environmental damage, and
(iv) The proper firefighting procedures and use of equipment, fire suits, and breathing apparatus.
(b) Each operator shall maintain a training record for each individual that has been trained as required by this section. These records must be maintained in the following manner as long as the individual is assigned duties under the response plan:
(1) Records for operator personnel must be maintained at the operator's headquarters; and
(2) Records for personnel engaged in response, other than operator personnel, shall be maintained as determined by the operator.
(c) Nothing in this section relieves an operator from the responsibility to ensure that all response personnel are trained to meet the Occupational Safety and Health Administration (OSHA) standards for emergency response operations in 29 CFR 1910.120, including volunteers or casual laborers employed during a response who are subject to those standards pursuant to 40 CFR part 311.
(a) Each operator shall submit two copies of the response plan required by this part. Copies of the response plan shall be submitted to: Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, Department of Transportation, PHP 80, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. Note: Submission of plans in electronic format is preferred.
(b) If PHMSA determines that a response plan requiring approval does not meet all the requirements of this part, PHMSA will notify the operator of any alleged deficiencies, and to provide the operator an opportunity to respond, including the opportunity for an informal conference, on any proposed plan revisions and an opportunity to correct any deficiencies.
(c) An operator who disagrees with the PHMSA determination that a plan contains alleged deficiencies may petition PHMSA for reconsideration within 30 days from the date of receipt of PHMSA's notice. After considering all relevant material presented in writing or at an informal conference, PHMSA will notify the operator of its final decision. The operator must comply with the final decision within 30 days of issuance unless PHMSA allows additional time.
(d) For response zones of pipelines described in § 194.103(c) OPS will approve the response plan if OPS determines that the response plan meets all requirements of this part. OPS may consult with the U.S. Environmental Protection Agency (EPA) or the U.S. Coast Guard (USCG) if a Federal on-scene coordinator (FOSC) has concerns about the operator's ability to respond to a worst case discharge.
(e) If OPS has not approved a response plan for a pipeline described in § 194.103(c), the operator may submit a certification to OPS that the operator has obtained, through contract or other approved means, the necessary personnel and equipment to respond, to the maximum extent practicable, to a worst case discharge or a substantial threat of such a discharge. The certificate must be signed by the qualified individual or an appropriate corporate officer.
(f) If OPS receives a request from a FOSC to review a response plan, OPS may require an operator to give a copy of the response plan to the FOSC. OPS may consider FOSC comments on response techniques, protecting fish, wildlife and sensitive environments, and on consistency with the ACP. OPS remains the approving authority for the response plan.
(a) Each operator shall update its response plan to address new or different operating conditions or information. In addition, each operator shall review its response plan in full at least every 5 years from the date of the last submission or the last approval as follows:
(1) For substantial harm plans, an operator shall resubmit its response plan to OPS every 5 years from the last submission date.
(2) For significant and substantial harm plans, an operator shall resubmit every 5 years from the last approval date.
(b) If a new or different operating condition or information would substantially affect the implementation of a response plan, the operator must immediately modify its response plan to address such a change and, within 30 days of making such a change, submit the change to PHMSA. Examples of changes in operating conditions that would cause a significant change to an operator's response plan are:
(1) An extension of the existing pipeline or construction of a new pipeline in a response zone not covered by the previously approved plan;
(2) Relocation or replacement of the pipeline in a way that substantially affects the information included in the response plan, such as a change to the worst case discharge volume;
(3) The type of oil transported, if the type affects the required response resources, such as a change from crude oil to gasoline;
(4) The name of the oil spill removal organization;
(5) Emergency response procedures;
(6) The qualified individual;
(7) A change in the NCP or an ACP that has significant impact on the equipment appropriate for response activities; and
(8) Any other information relating to circumstances that may affect full implementation of the plan.
(c) If PHMSA determines that a change to a response plan does not meet the requirements of this part, PHMSA will notify the operator of any alleged deficiencies, and provide the operator an opportunity to respond, including an opportunity for an informal conference, to any proposed plan revisions and an opportunity to correct any deficiencies.
(d) An operator who disagrees with a determination that proposed revisions to a plan are deficient may petition PHMSA for reconsideration, within 30 days from the date of receipt of PHMSA's notice. After considering all relevant material presented in writing or at the conference, PHMSA will notify the operator of its final decision. The operator must comply with the final decision within 30 days of issuance unless PHMSA allows additional time.
This appendix provides a recommended format for the preparation and submission of the response plans required by 49 CFR Part 194. Operators are referenced to the most current version of the guidance documents
(1) The “National Preparedness for Response Exercise Program (PREP) Guidelines” (PREP), which can be found using the search function on the USCG's PREP Web page,
(2) The National Response Team's “Integrated Contingency Plan Guidance,” which can be found using the search function at the National Response Center's Web site,
(3) 33 CFR Part 154, Appendix C, “Guidelines for Determining and Evaluating Required Response Resources for Facility Response Plans.”
Section 1 would include the following:
(a) For the core plan:
(1) The name and address of the operator; and
(2) For each response zone which contains one or more line sections that meet the criteria for determining significant and substantial harm as described in § 194.103, a listing and description of the response zones, including county(s) and state(s).
(b) For each response zone appendix:
(1) The information summary for the core plan;
(2) The name and telephone number of the qualified individual, available on a 24-hour basis;
(3) A description of the response zone, including county(s) and state(s) in which a worst case discharge could cause substantial harm to the environment;
(4) A list of line sections contained in the response zone, identified by milepost or survey station number or other operator designation.
(5) The basis for the operator's determination of significant and substantial harm; and
(6) The type of oil and volume of the worst case discharge.
(c) The certification that the operator has obtained, through contract or other approved means, the necessary private personnel and equipment to respond, to the maximum extent practicable, to a worst case discharge or a substantial threat of such a discharge.
Section 2 would include the following:
(a) Notification requirements that apply in each area of operation of pipelines covered by the plan, including applicable State or local requirements;
(b) A checklist of notifications the operator or qualified individual is required to make under the response plan, listed in the order of priority;
(c) Names of persons (individuals or organizations) to be notified of a discharge, indicating whether notification is to be performed by operating personnel or other personnel;
(d) Procedures for notifying qualified individuals;
(e) The primary and secondary communication methods by which notifications can be made; and
(f) The information to be provided in the initial and each follow-up notification, including the following:
(1) Name of pipeline;
(2) Time of discharge;
(3) Location of discharge;
(4) Name of oil involved;
(5) Reason for discharge (e.g., material failure, excavation damage, corrosion);
(6) Estimated volume of oil discharged;
(7) Weather conditions on scene; and
(8) Actions taken or planned by persons on scene.
Section 3 would include the following:
(a) Methods of initial discharge detection;
(b) Procedures, listed in the order of priority, that personnel are required to follow in responding to a pipeline emergency to mitigate or prevent any discharge from the pipeline;
(c) A list of equipment that may be needed in response activities on land and navigable waters, including—
(1) Transfer hoses and connection equipment;
(2) Portable pumps and ancillary equipment; and
(3) Facilities available to transport and receive oil from a leaking pipeline;
(d) Identification of the availability, location, and contact telephone numbers to obtain equipment for response activities on a 24-hour basis; and
(e) Identification of personnel and their location, telephone numbers, and responsibilities for use of equipment in response activities on a 24-hour basis.
Section 4 would include the following:
(a) Responsibilities of, and actions to be taken by, operating personnel to initiate and supervise response actions pending the arrival of the qualified individual or other response resources identified in the response plan;
(b) The qualified individual's responsibilities and authority, including notification of the response resources identified in the plan;
(c) Procedures for coordinating the actions of the operator or qualified individual with the action of the OSC responsible for monitoring or directing those actions;
(d) Oil spill response organizations available, through contract or other approved means, to respond to a worst case discharge to the maximum extent practicable; and
(e) For each organization identified under paragraph (d) of this section, a listing of:
(1) Equipment and supplies available; and
(2) Trained personnel necessary to continue operation of the equipment and staff the oil spill removal organization for the first 7 days of the response.
Section 5 would include the names and addresses of the following individuals or organizations, with telephone numbers at which they can be contacted on a 24-hour basis:
(a) A list of persons the plan requires the operator to contact;
(b) Qualified individuals for the operator's areas of operation;
(c) Applicable insurance representatives or surveyors for the operator's areas of operation; and
(d) Persons or organizations to notify for activation of response resources.
Section 6 would include a description of the training procedures and programs of the operator.
Section 7 would include a description of the drill procedures and programs the operator uses to assess whether its response plan will function as planned. It would include:
(a) Announced and unannounced drills;
(b) The types of drills and their frequencies. For example, drills could be described as follows:
(1) Manned pipeline emergency procedures and qualified individual notification drills conducted quarterly.
(2) Drills involving emergency actions by assigned operating or maintenance personnel and notification of the qualified individual on pipeline facilities which are normally unmanned, conducted quarterly.
(3) Shore-based spill management team tabletop drills conducted yearly.
(4) Oil spill removal organization field equipment deployment drills conducted yearly.
(5) A drill that exercises the entire response plan for each response zone, would be conducted at least once every 3 years.
Section 8 would include the following:
(a) Procedures to meet § 194.121; and
(b) Procedures to review the plan after a worst case discharge and to evaluate and record the plan's effectiveness.
Each response zone appendix would provide the following information:
(a) The name and telephone number of the qualified individual;
(b) Notification procedures;
(c) Spill detection and mitigation procedures;
(d) Name, address, and telephone number of oil spill response organization;
(e) Response activities and response resources including—
(1) Equipment and supplies necessary to meet § 194.115, and
(2) The trained personnel necessary to sustain operation of the equipment and to staff the oil spill removal organization and spill management team for the first 7 days of the response;
(f) Names and telephone numbers of Federal, state and local agencies which the operator expects to assume pollution response responsibilities;
(g) The worst case discharge volume;
(h) The method used to determine the worst case discharge volume, with calculations;
(i) A map that clearly shows—
(1) The location of the worst case discharge, and
(2) The distance between each line section in the response zone and—
(i) Each potentially affected public drinking water intake, lake, river, and stream within a radius of 5 miles (8 kilometers) of the line section, and
(ii) Each potentially affected environmentally sensitive area within a radius of 1 mile (1.6 kilometer) of the line section;
(j) A piping diagram and plan-profile drawing of each line section, which may be kept separate from the response plan if the location is identified; and
(k) For every oil transported by each pipeline in the response zone, emergency response data that—
(1) Include the name, description, physical and chemical characteristics, health and safety hazards, and initial spill-handling and firefighting methods; and
(2) Meet 29 CFR 1910.1200 or 49 CFR 172.602.
As of January 5, 1993 the following areas are high volume areas:
49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118; and 49 CFR 1.53.
Nomenclature changes to part 195 appear at 71 FR 33409, June 9, 2006.
This part prescribes safety standards and reporting requirements for pipeline facilities used in the transportation of hazardous liquids or carbon dioxide.
(a)
(1) Any pipeline that transports a highly volatile liquid (HVL);
(2) Transportation through any pipeline, other than a gathering line, that has a maximum operating pressure (MOP) greater than 20-percent of the specified minimum yield strength;
(3) Any pipeline segment that crosses a waterway currently used for commercial navigation;
(4) Transportation of petroleum in any of the following onshore gathering lines:
(i) A pipeline located in a non-rural area;
(ii) To the extent provided in § 195.11, a regulated rural gathering line defined in § 195.11; or
(iii) To the extent provided in § 195.413, a pipeline located in an inlet of the Gulf of Mexico.
(5) Transportation of a hazardous liquid or carbon dioxide through a low-stress pipeline or segment of pipeline that:
(i) Is in a non-rural area; or
(ii) Meets the criteria defined in § 195.12(a).
(6) For purposes of the reporting requirements in subpart B, a rural low-stress pipeline of any diameter.
(b)
(1) Transportation of a hazardous liquid transported in a gaseous state;
(2) Transportation of a hazardous liquid through a pipeline by gravity;
(3) A pipeline subject to safety regulations of the U.S. Coast Guard;
(4) A low-stress pipeline that serves refining, manufacturing, or truck, rail, or vessel terminal facilities, if the pipeline is less than one mile long (measured outside facility grounds) and does not cross an offshore area or a waterway currently used for commercial navigation;
(5) Transportation of hazardous liquid or carbon dioxide in an offshore pipeline in State waters where the pipeline is located upstream from the outlet flange of the following farthest downstream facility: The facility where hydrocarbons or carbon dioxide are produced or the facility where produced hydrocarbons or carbon dioxide are first separated, dehydrated, or otherwise processed;
(6) Transportation of hazardous liquid or carbon dioxide in a pipeline on the OCS where the pipeline is located upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator;
(7) A pipeline segment upstream (generally seaward) of the last valve on the last production facility on the OCS where a pipeline on the OCS is producer-operated and crosses into State waters without first connecting to a transporting operator's facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. A producing operator of a segment falling within this exception may petition the Administrator, under § 190.9 of this chapter, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance;
(8) Transportation of a hazardous liquid or carbon dioxide through onshore production (including flow lines), refining, or manufacturing facilities or storage or in-plant piping systems associated with such facilities;
(9) Transportation of a hazardous liquid or carbon dioxide:
(i) By vessel, aircraft, tank truck, tank car, or other non-pipeline mode of transportation; or
(ii) Through facilities located on the grounds of a materials transportation terminal if the facilities are used exclusively to transfer hazardous liquid or carbon dioxide between non-pipeline modes of transportation or between a non-pipeline mode and a pipeline. These facilities do not include any device and associated piping that are necessary to control pressure in the pipeline under § 195.406(b); or
(10) Transportation of carbon dioxide downstream from the applicable following point:
(i) The inlet of a compressor used in the injection of carbon dioxide for oil recovery operations, or the point where recycled carbon dioxide enters the injection system, whichever is farther upstream; or
(ii) The connection of the first branch pipeline in the production field where the pipeline transports carbon dioxide to an injection well or to a header or manifold from which a pipeline branches to an injection well.
(c)
For
As used in this part—
(a) Any document or portion thereof incorporated by reference in this part is included in this part as though it were printed in full. When only a portion of a document is referenced, then this part incorporates only that referenced portion of the document and the remainder is not incorporated. Applicable editions are listed in paragraph (c) of this section in parentheses following the title of the referenced material. Earlier editions listed in previous editions of this section may be
(b) All incorporated materials are available for inspection in the Office of Pipelline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue, SE., Washington, DC, 20590-0001 or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030 or go to:
1. Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX 77098.
2. American Petroleum Institute (API), 1220 L Street, NW., Washington, DC 20005.
3. ASME International (ASME), Three Park Avenue, New York, NY 10016-5990.
4. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park Street, NE., Vienna, VA 22180.
5. American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, West Conshohocken, PA 19428.
6. National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O. Box 9101, Quincy, MA 02269-9101.
7. NACE International, 1440 South Creek Drive, Houston, TX 77084.
(c) The full titles of publications incorporated by reference wholly or partially in this part are as follows. Numbers in parentheses indicate applicable editions:
No person may transport any hazardous liquid or carbon dioxide unless the hazardous liquid or carbon dioxide is chemically compatible with both the pipeline, including all components, and any other commodity that it may come into contact with while in the pipeline.
(a) A steel pipeline previously used in service not subject to this part qualifies for use under this part if the operator prepares and follows a written procedure to accomplish the following:
(1) The design, construction, operation, and maintenance history of the pipeline must be reviewed and, where sufficient historical records are not available, appropriate tests must be performed to determine if the pipeline is in satisfactory condition for safe operation. If one or more of the variables necessary to verify the design pressure under § 195.106 or to perform the testing under paragraph (a)(4) of this section is unknown, the design pressure may be verified and the maximum operating pressure determined by—
(i) Testing the pipeline in accordance with ASME B31.8, Appendix N, to produce a stress equal to the yield strength; and
(ii) Applying, to not more than 80 percent of the first pressure that produces a yielding, the design factor F in § 195.106(a) and the appropriate factors in § 195.106(e).
(2) The pipeline right-of-way, all aboveground segments of the pipeline, and appropriately selected underground segments must be visually inspected for physical defects and operating conditions which reasonably could be expected to impair the strength or tightness of the pipeline.
(3) All known unsafe defects and conditions must be corrected in accordance with this part.
(4) The pipeline must be tested in accordance with subpart E of this part to substantiate the maximum operating pressure permitted by § 195.406.
(b) A pipeline that qualifies for use under this section need not comply with the corrosion control requirements of subpart H of this part until 12 months after it is placed into service, notwithstanding any previous deadlines for compliance.
(c) Each operator must keep for the life of the pipeline a record of the investigations, tests, repairs, replacements, and alterations made under the requirements of paragraph (a) of this section.
As used in this part, a USA means a drinking water or ecological resource area that is unusually sensitive to environmental damage from a hazardous liquid pipeline release.
(a) An USA drinking water resource is:
(1) The water intake for a Community Water System (CWS) or a Non-transient Non-community Water System (NTNCWS) that obtains its water supply primarily from a surface water source and does not have an adequate alternative drinking water source;
(2) The Source Water Protection Area (SWPA) for a CWS or a NTNCWS that obtains its water supply from a Class I or Class IIA aquifer and does not have an adequate alternative drinking water source. Where a state has not yet identified the SWPA, the Wellhead Protection Area (WHPA) will be used until the state has identified the SWPA; or
(3) The sole source aquifer recharge area where the sole source aquifer is a karst aquifer in nature.
(b) An USA ecological resource is:
(1) An area containing a critically imperiled species or ecological community;
(2) A multi-species assemblage area;
(3) A migratory waterbird concentration area;
(4) An area containing an imperiled species, threatened or endangered species, depleted marine mammal species, or an imperiled ecological community where the species or community is aquatic, aquatic dependent, or terrestrial with a limited range; or
(5) An area containing an imperiled species, threatened or endangered species, depleted marine mammal species, or imperiled ecological community where the species or community occurrence is considered to be one of the most viable, highest quality, or in the best condition, as identified by an element occurrence ranking (EORANK) of A (excellent quality) or B (good quality).
(c) As used in this part—
(1) Unconsolidated Aquifers (Class Ia) that consist of surficial, unconsolidated, and permeable alluvial, terrace, outwash, beach, dune and other similar deposits. These aquifers generally contain layers of sand and gravel that, commonly, are interbedded to some degree with silt and clay. Not all Class Ia aquifers are important water-bearing units, but they are likely to be both permeable and vulnerable. The only natural protection of these aquifers is the thickness of the unsaturated zone and the presence of fine-grained material;
(2) Soluble and Fractured Bedrock Aquifers (Class Ib). Lithologies in this class include limestone, dolomite, and, locally, evaporitic units that contain documented karst features or solution channels, regardless of size. Generally these aquifers have a wide range of permeability. Also included in this class are sedimentary strata, and metamorphic and igneous (intrusive and extrusive) rocks that are significantly faulted, fractured, or jointed. In all cases groundwater movement is largely controlled by secondary openings. Well yields range widely, but the important feature is the potential for rapid vertical and lateral ground water movement along preferred pathways, which result in a high degree of vulnerability;
(3) Semiconsolidated Aquifers (Class Ic) that generally contain poorly to moderately indurated sand and gravel that is interbedded with clay and silt. This group is intermediate to the unconsolidated and consolidated end members. These systems are common in the Tertiary age rocks that are exposed throughout the Gulf and Atlantic coastal states. Semiconsolidated conditions also arise from the presence of intercalated clay and caliche within primarily unconsolidated to poorly consolidated units, such as occurs in parts of the High Plains Aquifer; or
(4) Covered Aquifers (Class Id) that are any Class I aquifer overlain by less than 50 feet of low permeability, unconsolidated material, such as glacial till, lacustrian, and loess deposits.
No person may transport any hazardous liquid or carbon dioxide through a pipe that is constructed after October 1, 1970, for hazardous liquids or after July 12, 1991 for carbon dioxide of material other than steel unless the person has notified the Administrator in writing at least 90 days before the transportation is to begin. The notice must state whether carbon dioxide or a hazardous liquid is to be transported and the chemical name, common name, properties and characteristics of the hazardous liquid to be transported and the material used in construction of
Operators of transportation pipelines on the Outer Continental Shelf must identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 1998 to identify the transfer points. If it is not practicable to durably mark a transfer point and the transfer point is located above water, the operator must depict the transfer point on a schematic maintained near the transfer point. If a transfer point is located subsea, the operator must identify the transfer point on a schematic which must be maintained at the nearest upstream facility and provided to PHMSA upon request. For those cases in which adjoining operators have not agreed on a transfer point by September 15, 1998 the Regional Director and the MMS Regional Supervisor will make a joint determination of the transfer point.
An operator may make arrangements with another person for the performance of any action required by this part. However, the operator is not thereby relieved from the responsibility for compliance with any requirement of this part.
Each operator of a regulated rural gathering line, as defined in paragraph (a) of this section, must comply with the safety requirements described in paragraph (b) of this section.
(a)
(1) Has a nominal diameter from 6
(2) Is located in or within one-quarter mile (.40 km) of an unusually sensitive area as defined in § 195.6; and
(3) Operates at a maximum pressure established under § 195.406 corresponding to—
(i) A stress level greater than 20-percent of the specified minimum yield strength of the line pipe; or
(ii) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure of more than 125 psi (861 kPa) gage.
(b)
(1) Identify all segments of pipeline meeting the criteria in paragraph (a) of this section before April 3, 2009.
(2) For steel pipelines constructed, replaced, relocated, or otherwise changed after July 3, 2009, design, install, construct, initially inspect, and initially test the pipeline in compliance with this part, unless the pipeline is converted under § 195.5.
(3) For non-steel pipelines constructed after July 3, 2009, notify the Administrator according to § 195.8.
(4) Beginning no later than January 3, 2009, comply with the reporting requirements in subpart B of this part.
(5) Establish the maximum operating pressure of the pipeline according to § 195.406 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009.
(6) Install line markers according to § 195.410 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. Continue to maintain line markers in compliance with § 195.410.
(7) Establish a continuing public education program in compliance with § 195.440 before transportation begins, or if the pipeline exists on July 3, 2008, before January 3, 2010. Continue to carry out such program in compliance with § 195.440.
(8) Establish a damage prevention program in compliance with § 195.442 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. Continue to carry out such program in compliance with § 195.442.
(9) For steel pipelines, comply with subpart H of this part, except corrosion control is not required for pipelines existing on July 3, 2008 before July 3, 2011.
(10) For steel pipelines, establish and follow a comprehensive and effective program to continuously identify operating conditions that could contribute to internal corrosion. The program must include measures to prevent and mitigate internal corrosion, such as cleaning the pipeline and using inhibitors. This program must be established before transportation begins or if the pipeline exists on July 3, 2008, before July 3, 2009.
(11) To comply with the Operator Qualification program requirements in subpart G of this part, have a written description of the processes used to carry out the requirements in § 195.505 to determine the qualification of persons performing operations and maintenance tasks. These processes must be established before transportation begins or if the pipeline exists on July 3, 2008, before July 3, 2009.
(c)
(d)
(1) An operator must maintain the segment identification records required in paragraph (b)(1) of this section and the records required to comply with (b)(10) of this section, for the life of the pipe.
(2) An operator must maintain the records necessary to demonstrate compliance with each requirement in paragraphs (b)(2) through (b)(9), and (b)(11) of this section according to the record retention requirements of the referenced section or subpart.
(a)
(1) Has a nominal diameter of 8
(2) Is located in or within a half mile (.80 km) of an unusually sensitive area (USA) as defined in § 195.6; and
(3) Operates at a maximum pressure established under § 195.406 corresponding to:
(i) A stress level equal to or less than 20-percent of the specified minimum yield strength of the line pipe; or
(ii) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure equal to or less than 125 psi (861 kPa) gage.
(b)
(1) Identify all segments of pipeline meeting the criteria in paragraph (a) of this section before April 3, 2009.
(2) Beginning no later than January 3, 2009, comply with the reporting requirements of subpart B for the identified segments.
(3)(i) Establish a written program in compliance with § 195.452 before July 3, 2009, to assure the integrity of the low-stress pipeline segments. Continue to carry out such program in compliance with § 195.452.
(ii) To carry out the integrity management requirements in § 195.452, an operator may conduct a determination per § 195.452(a) in lieu of the half mile buffer.
(iii) Complete the baseline assessment of all segments in accordance with § 195.452(c) before July 3, 2015, and complete at least 50-percent of the assessments, beginning with the highest risk pipe, before January 3, 2012.
(4) Comply with all other safety requirements of this part, except subpart H, before July 3, 2009. Comply with subpart H before July 3, 2011.
(c)
(i) The pipeline meets the criteria in paragraph (a) of this section;
(ii) The pipeline carries crude oil from a production facility;
(iii) The pipeline, when in operation, operates at a flow rate less than or equal to 14,000 barrels per day; and
(iv) The operator determines it would abandon or shut-down the pipeline as a result of the economic burden to comply with the assessment requirements in §§ 195.452(d) or 195.452(j).
(2) A notification submitted under this provision must include, at minimum, the following information about the pipeline: Its operating, maintenance and leak history; the estimated cost to comply with the integrity assessment requirements (with a brief description of the basis for the estimate); the estimated amount of production from affected wells per year, whether wells will be shut in or alternate transportation used, and if alternate transportation will be used, the estimated cost to do so.
(3) When an operator notifies PHMSA in accordance with paragraph (c)(1) of this section, PHMSA will stay compliant with §§ 195.452(d) and 195.452(j)(3) until it has completed an analysis of the notification. PHMSA will consult the Department of Energy (DOE), as appropriate, to help analyze the potential energy impact of loss of the pipeline. Based on the analysis, PHMSA may grant the operator a special permit to allow continued operation of the pipeline subject to alternative safety requirements.
(d)
(1) Except for paragraph (b)(2) of this section and the requirements of subpart H, comply with all other safety requirements of this part before July 3, 2009. Comply with subpart H before July 3, 2011.
(2) Establish the program required in paragraph (b)(2)(i) within 12 months following the date the area is identified. Continue to carry out such program in compliance with § 195.452; and
(3) Complete the baseline assessment required by paragraph (b)(2)(ii) of this section according to the schedule in § 195.452(d)(3).
(d)
(1) An operator must maintain the segment identification records required in paragraph (b)(1) of this section for the life of the pipe.
(2) An operator must maintain the records necessary to demonstrate compliance with each requirement in paragraphs (b)(2) through (b)(4) of this section according to the record retention requirements of the referenced section or subpart.
This subpart prescribes requirements for periodic reporting and for reporting
Beginning no later than June 15, 2005, each operator must annually complete and submit DOT form RSPA F 7000-1.1 for each type of hazardous liquid pipeline facility operated at the end of the previous year. A separate report is required for crude oil, HVL (including anhydrous ammonia), petroleum products, and carbon dioxide pipelines. Operators are encouraged, but not required, to file an annual report by June 15, 2004, for calendar year 2003.
An accident report is required for each failure in a pipeline system subject to this part in which there is a release of the hazardous liquid or carbon dioxide transported resulting in any of the following:
(a) Explosion or fire not intentionally set by the operator.
(b) Release of 5 gallons (19 liters) or more of hazardous liquid or carbon dioxide, except that no report is required for a release of less than 5 barrels (0.8 cubic meters) resulting from a pipeline maintenance activity if the release is:
(1) Not otherwise reportable under this section;
(2) Not one described in § 195.52(a)(4);
(3) Confined to company property or pipeline right-of-way; and
(4) Cleaned up promptly;
(c) Death of any person;
(d) Personal injury necessitating hospitalization;
(e) Estimated property damage, including cost of clean-up and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding $50,000.
(a) At the earliest practicable moment following discovery of a release of the hazardous liquid or carbon dioxide transported resulting in an event described in § 195.50, the operator of the system shall give notice, in accordance with paragraph (b) of this section, of any failure that:
(1) Caused a death or a personal injury requiring hospitalization;
(2) Resulted in either a fire or explosion not intentionally set by the operator;
(3) Caused estimated property damage, including cost of cleanup and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding $50,000;
(4) Resulted in pollution of any stream, river, lake, reservoir, or other similar body of water that violated applicable water quality standards, caused a discoloration of the surface of the water or adjoining shoreline, or deposited a sludge or emulsion beneath the surface of the water or upon adjoining shorelines; or
(5) In the judgment of the operator was significant even though it did not meet the criteria of any other paragraph of this section.
(b) Reports made under paragraph (a) of this section are made by telephone to 800-424-8802 (in Washington, DC, 20590-0001 (202) 372-2428) and must include the following information:
(1) Name and address of the operator.
(2) Name and telephone number of the reporter.
(3) The location of the failure.
(4) The time of the failure.
(5) The fatalities and personal injuries, if any.
(6) All other significant facts known by the operator that are relevant to
(a) Each operator that experiences an accident that is required to be reported under § 195.50 shall as soon as practicable, but not later than 30 days after discovery of the accident, prepare and file an accident report on DOT Form 7000-1, or a facsimile.
(b) Whenever an operator receives any changes in the information reported or additions to the original report on DOT Form 7000-1, it shall file a supplemental report within 30 days.
(a) Except as provided in paragraph (b) of this section, each operator shall report in accordance with § 195.56 the existence of any of the following safety-related conditions involving pipelines in service:
(1) General corrosion that has reduced the wall thickness to less than that required for the maximum operating pressure, and localized corrosion pitting to a degree where leakage might result.
(2) Unintended movement or abnormal loading of a pipeline by environmental causes, such as an earthquake, landslide, or flood, that impairs its serviceability.
(3) Any material defect or physical damage that impairs the serviceability of a pipeline.
(4) Any malfunction or operating error that causes the pressure of a pipeline to rise above 110 percent of its maximum operating pressure.
(5) A leak in a pipeline that constitutes an emergency.
(6) Any safety-related condition that could lead to an imminent hazard and causes (either directly or indirectly by remedial action of the operator), for purposes other than abandonment, a 20 percent or more reduction in operating pressure or shutdown of operation of a pipeline.
(b) A report is not required for any safety-related condition that—
(1) Exists on a pipeline that is more than 220 yards (200 meters) from any building intended for human occupancy or outdoor place of assembly, except that reports are required for conditions within the right-of-way of an active railroad, paved road, street, or highway, or that occur offshore or at onshore locations where a loss of hazardous liquid could reasonably be expected to pollute any stream, river, lake, reservoir, or other body of water;
(2) Is an accident that is required to be reported under § 195.50 or results in such an accident before the deadline for filing the safety-related condition report; or
(3) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report, except that reports are required for all conditions under paragraph (a)(1) of this section other than localized corrosion pitting on an effectively coated and cathodically protected pipeline.
(a) Each report of a safety-related condition under § 195.55(a) must be filed (received by the Administrator) in writing within 5 working days (not including Saturdays, Sundays, or Federal holidays) after the day a representative of the operator first determines that the condition exists, but not later than 10 working days after the day a representative of the operator discovers the condition. Separate conditions may be described in a single report if they are closely related. To file a report by facsimile (fax), dial (202) 366-7128.
(b) The report must be headed “Safety-Related Condition Report” and provide the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person submitting the report.
(4) Name, job title, and business telephone number of person who determined that the condition exists.
(5) Date condition was discovered and date condition was first determined to exist.
(6) Location of condition, with reference to the State (and town, city, or county) or offshore site, and as appropriate nearest street address, offshore platform, survey station number, milepost, landmark, or name of pipeline.
(7) Description of the condition, including circumstances leading to its discovery, any significant effects of the condition on safety, and the name of the commodity transported or stored.
(8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned follow-up or future corrective action, including the anticipated schedule for starting and concluding such action.
(a) Each operator shall, within 60 days after completion of the inspection of all its underwater pipelines subject to § 195.413(a), report the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person submitting the report.
(4) Total number of miles (kilometers) of pipeline inspected.
(5) Length and date of installation of each exposed pipeline segment, and location; including, if available, the location according to the Minerals Management Service or state offshore area and block number tract.
(6) Length and date of installation of each pipeline segment, if different from a pipeline segment identified under paragraph (a)(5) of this section, that is a hazard to navigation, and the location; including, if available, the location according to the Minerals Management Service or state offshore area and block number tract.
(b) The report shall be mailed to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590.
Each written report required by this subpart must be made to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. However, accident reports for intrastate pipelines subject to the jurisdiction of a State agency pursuant to a certification under the pipeline safety laws (49 U.S.C. 60101
For each abandoned offshore pipeline facility or each abandoned onshore pipeline facility that crosses over, under or through a commercially navigable waterway, the last operator of
(a) The preferred method to submit data on pipeline facilities abandoned after October 10, 2000 is to the National Pipeline Mapping System (NPMS) in accordance with the NPMS “Standards for Pipeline and Liquefied Natural Gas Operator Submissions.” To obtain a copy of the NPMS Standards, please refer to the NPMS homepage at
(b) [Reserved]
If the Department of Transportation investigates an accident, the operator involved shall make available to the representative of the Department all records and information that in any way pertain to the accident, and shall afford all reasonable assistance in the investigation of the accident.
Each operator shall maintain an adequate supply of forms that are a facsimile of DOT Form 7000-1 to enable it to promptly report accidents. The Department will, upon request, furnish specimen copies of the form. Requests should be addressed to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001.
The control number assigned by the Office of Management and Budget to the hazardous liquid pipeline information collection requirements of this part pursuant to the Paperwork Reduction Act of 1980 is 2137-0047.
This subpart prescribes minimum design requirements for new pipeline systems constructed with steel pipe and for relocating, replacing, or otherwise changing existing systems constructed with steel pipe. However, it does not apply to the movement of line pipe covered by § 195.424.
Notwithstanding any requirement of the subpart which incorporates by reference an edition of a document listed in § 195.3, a metallic component other than pipe manufactured in accordance with any other edition of that document is qualified for use if—
(a) It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component: and
(b) The edition of the document under which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in § 195.3:
(1) Pressure testing;
(2) Materials; and
(3) Pressure and temperature ratings.
(a) Material for components of the system must be chosen for the temperature environment in which the components will be used so that the pipeline will maintain its structural integrity.
(b) Components of carbon dioxide pipelines that are subject to low temperatures during normal operation because of rapid pressure reduction or during the initial fill of the line must be made of materials that are suitable for those low temperatures.
If, within a pipeline system, two or more components are to be connected at a place where one will operate at a higher pressure than another, the system must be designed so that any component operating at the lower pressure will not be overstressed.
(a) Internal design pressure for the pipe in a pipeline is determined in accordance with the following formula:
(b) The yield strength to be used in determining the internal design pressure under paragraph (a) of this section is the specified minimum yield strength. If the specified minimum yield strength is not known, the yield strength to be used in the design formula is one of the following:
(1)(i) The yield strength determined by performing all of the tensile tests of API Specification 5L on randomly selected specimens with the following number of tests:
(ii) If the average yield-tensile ratio exceeds 0.85, the yield strength shall be taken as 24,000 p.s.i. (165,474 kPa). If the average yield-tensile ratio is 0.85 or less, the yield strength of the pipe is taken as the lower of the following:
(A) Eighty percent of the average yield strength determined by the tensile tests.
(B) The lowest yield strength determined by the tensile tests.
(2) If the pipe is not tensile tested as provided in paragraph (b) of this section, the yield strength shall be taken as 24,000 p.s.i. (165,474 kPa).
(c) If the nominal wall thickness to be used in determining internal design pressure under paragraph (a) of this section is not known, it is determined by measuring the thickness of each piece of pipe at quarter points on one end. However, if the pipe is of uniform grade, size, and thickness, only 10 individual lengths or 5 percent of all lengths, whichever is greater, need be measured. The thickness of the lengths
(d) The minimum wall thickness of the pipe may not be less than 87.5 percent of the value used for nominal wall thickness in determining the internal design pressure under paragraph (a) of this section. In addition, the anticipated external loads and external pressures that are concurrent with internal pressure must be considered in accordance with §§ 195.108 and 195.110 and, after determining the internal design pressure, the nominal wall thickness must be increased as necessary to compensate for these concurrent loads and pressures.
(e) The seam joint factor used in paragraph (a) of this section is determined in accordance with the following table:
Any external pressure that will be exerted on the pipe must be provided for in designing a pipeline system.
(a) Anticipated external loads (e.g.), earthquakes, vibration, thermal expansion, and contraction must be provided for in designing a pipeline system. In providing for expansion and flexibility, section 419 of ASME/ANSI B31.4 must be followed.
(b) The pipe and other components must be supported in such a way that the support does not cause excess localized stresses. In designing attachments to pipe, the added stress to the wall of the pipe must be computed and compensated for.
A carbon dioxide pipeline system must be designed to mitigate the effects of fracture propagation.
Any new pipe installed in a pipeline system must comply with the following:
(a) The pipe must be made of steel of the carbon, low alloy-high strength, or alloy type that is able to withstand the internal pressures and external loads and pressures anticipated for the pipeline system.
(b) The pipe must be made in accordance with a written pipe specification that sets forth the chemical requirements for the pipe steel and mechanical tests for the pipe to provide pipe suitable for the use intended.
(c) Each length of pipe with a nominal outside diameter of 4
Any used pipe installed in a pipeline system must comply with § 195.112 (a) and (b) and the following:
(a) The pipe must be of a known specification and the seam joint factor must be determined in accordance with § 195.106(e). If the specified minimum yield strength or the wall thickness is not known, it is determined in accordance with § 195.106 (b) or (c) as appropriate.
(b) There may not be any:
(1) Buckles;
(2) Cracks, grooves, gouges, dents, or other surface defects that exceed the maximum depth of such a defect permitted by the specification to which the pipe was manufactured; or
(3) Corroded areas where the remaining wall thickness is less than the minimum thickness required by the tolerances in the specification to which the pipe was manufactured.
Each valve installed in a pipeline system must comply with the following:
(a) The valve must be of a sound engineering design.
(b) Materials subject to the internal pressure of the pipeline system, including welded and flanged ends, must be compatible with the pipe or fittings to which the valve is attached.
(c) Each part of the valve that will be in contact with the carbon dioxide or hazardous liquid stream must be made of materials that are compatible with carbon dioxide or each hazardous liquid that it is anticipated will flow through the pipeline system.
(d) Each valve must be both hydrostatically shell tested and hydrostatically seat tested without leakage to at least the requirements set forth in section 10 of API Standard 6D (incorporated by reference,
(e) Each valve other than a check valve must be equipped with a means for clearly indicating the position of the valve (open, closed, etc.).
(f) Each valve must be marked on the body or the nameplate, with at least the following:
(1) Manufacturer's name or trademark.
(2) Class designation or the maximum working pressure to which the valve may be subjected.
(3) Body material designation (the end connection material, if more than one type is used).
(4) Nominal valve size.
(a) Butt-welding type fittings must meet the marking, end preparation, and the bursting strength requirements of ASME/ANSI B16.9 or MSS Standard Practice SP-75.
(b) There may not be any buckles, dents, cracks, gouges, or other defects in the fitting that might reduce the strength of the fitting.
(c) The fitting must be suitable for the intended service and be at least as strong as the pipe and other fittings in the pipeline system to which it is attached.
(a) Except as provided in paragraphs (b) and (c) of this section, each new pipeline and each line section of a pipeline where the line pipe, valve, fitting or other line component is replaced; must be designed and constructed to accommodate the passage of instrumented internal inspection devices.
(b) This section does not apply to:
(1) Manifolds;
(2) Station piping such as at pump stations, meter stations, or pressure reducing stations;
(3) Piping associated with tank farms and other storage facilities;
(4) Cross-overs;
(5) Sizes of pipe for which an instrumented internal inspection device is not commercially available;
(6) Offshore pipelines, other than main lines 10 inches (254 millimeters) or greater in nominal diameter, that transport liquids to onshore facilities; and
(7) Other piping that the Administrator under § 190.9 of this chapter, finds in a particular case would be impracticable to design and construct to accommodate the passage of instrumented internal inspection devices.
(c) An operator encountering emergencies, construction time constraints and other unforeseen construction problems need not construct a new or replacement segment of a pipeline to meet paragraph (a) of this section, if the operator determines and documents why an impracticability prohibits compliance with paragraph (a) of this section. Within 30 days after discovering the emergency or construction problem the operator must petition, under § 190.9 of this chapter, for approval that design and construction to accommodate passage of instrumented internal inspection devices would be impracticable. If the petition is denied, within 1 year after the date of the notice of the denial, the operator must modify that segment to allow passage of instrumented internal inspection devices.
Each pipeline system must be designed so that the addition of any fabricated branch connections will not reduce the strength of the pipeline system.
Each closure to be installed in a pipeline system must comply with the ASME Boiler and Pressure Vessel Code, section VIII, Pressure Vessels, Division 1, and must have pressure and temperature ratings at least equal to those of the pipe to which the closure is attached.
Each component of a flange connection must be compatible with each other component and the connection as a unit must be suitable for the service in which it is to be used.
Any pipe to be installed in a station that is subject to system pressure must meet the applicable requirements of this subpart.
Each fabricated assembly to be installed in a pipeline system must meet the applicable requirements of this subpart.
(a) Each aboveground breakout tank must be designed and constructed to withstand the internal pressure produced by the hazardous liquid to be stored therein and any anticipated external loads.
(b) For aboveground breakout tanks first placed in service after October 2, 2000, compliance with paragraph (a) of this section requires one of the following:
(1) Shop-fabricated, vertical, cylindrical, closed top, welded steel tanks with nominal capacities of 90 to 750 barrels (14.3 to 119.2 m
(2) Welded, low-pressure (i.e., internal vapor space pressure not greater than 15 psig (103.4 kPa)), carbon steel tanks that have wall shapes that can be generated by a single vertical axis of revolution must be designed and constructed in accordance with API Standard 620.
(3) Vertical, cylindrical, welded steel tanks with internal pressures at the tank top approximating atmospheric pressures (i.e., internal vapor space pressures not greater than 2.5 psig (17.2 kPa), or not greater than the pressure developed by the weight of the tank roof) must be designed and constructed in accordance with API Standard 650.
(4) High pressure steel tanks (i.e., internal gas or vapor space pressures greater than 15 psig (103.4 kPa)) with a nominal capacity of 2000 gallons (7571 liters) or more of liquefied petroleum gas (LPG) must be designed and constructed in accordance with API Standard 2510.
This section applies to each hazardous liquid pipeline transporting liquid in single phase (without gas in the liquid). On such systems, each new computational pipeline monitoring (CPM) leak detection system and each replaced component of an existing CPM system must comply with section 4.2 of API 1130 in its design and with any other design criteria addressed in API 1130 for components of the CPM leak detection system.
This subpart prescribes minimum requirements for constructing new pipeline systems with steel pipe, and for relocating, replacing, or otherwise changing existing pipeline systems that are constructed with steel pipe. However, this subpart does not apply to the movement of pipe covered by § 195.424.
Each pipeline system must be constructed in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part.
Inspection must be provided to ensure the installation of pipe or pipeline systems in accordance with the requirements of this subpart. No person may be used to perform inspections unless that person has been trained and is qualified in the phase of construction to be inspected.
(a) Aboveground breakout tanks that have been repaired, altered, or reconstructed and returned to service must be capable of withstanding the internal pressure produced by the hazardous liquid to be stored therein and any anticipated external loads.
(b) After October 2, 2000, compliance with paragraph (a) of this section requires the following for the tanks specified:
(1) For tanks designed for approximately atmospheric pressure constructed of carbon and low alloy steel, welded or riveted, and non-refrigerated and tanks built to API Standard 650 or its predecessor Standard 12C, repair, alteration, and reconstruction must be in accordance with API Standard 653.
(2) For tanks built to API Specification 12F or API Standard 620, the repair, alteration, and reconstruction must be in accordance with the design, welding, examination, and material requirements of those respective standards.
(3) For high pressure tanks built to API Standard 2510, repairs, alterations, and reconstruction must be in accordance with API 510.
No pipe or other component may be installed in a pipeline system unless it has been visually inspected at the site of installation to ensure that it is not damaged in a manner that could impair its strength or reduce its serviceability.
Supports or braces may not be welded directly to pipe that will be operated at a pressure of more than 100 p.s.i. (689 kPa) gage.
(a) Pipeline right-of-way must be selected to avoid, as far as practicable, areas containing private dwellings, industrial buildings, and places of public assembly.
(b) No pipeline may be located within 50 feet (15 meters) of any private dwelling, or any industrial building or place of public assembly in which persons work, congregate, or assemble, unless it is provided with at least 12 inches (305 millimeters) of cover in addition to that prescribed in § 195.248.
(a) Pipe must not have a wrinkle bend.
(b) Each field bend must comply with the following:
(1) A bend must not impair the serviceability of the pipe.
(2) Each bend must have a smooth contour and be free from buckling, cracks, or any other mechanical damage.
(3) On pipe containing a longitudinal weld, the longitudinal weld must be as near as practicable to the neutral axis of the bend unless—
(i) The bend is made with an internal bending mandrel; or
(ii) The pipe is 12
(c) Each circumferential weld which is located where the stress during bending causes a permanent deformation in the pipe must be nondestructively tested either before or after the bending process.
(a) Welding must be performed by a qualified welder in accordance with welding procedures qualified under Section 5 of API 1104 or Section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference,
(b) Each welding procedure must be recorded in detail, including the results of the qualifying tests. This record must be retained and followed whenever the procedure is used.
A miter joint is not permitted (not including deflections up to 3 degrees that are caused by misalignment).
(a) Each welder must be qualified in accordance with section 6 of API 1104 (incorporated by reference,
(b) No welder may weld with a welding process unless, within the preceding 6 calendar months, the welder has—
(1) Engaged in welding with that process; and
(2) Had one welded tested and found acceptable under section 9 of API 1104 (incorporated by reference,
Welding must be protected from weather conditions that would impair the quality of the completed weld.
(a) Each arc burn must be repaired.
(b) An arc burn may be repaired by completely removing the notch by grinding, if the grinding does not reduce the remaining wall thickness to less than the minimum thickness required by the tolerances in the specification to which the pipe is manufactured. If a notch is not repairable by grinding, a cylinder of the pipe containing the entire notch must be removed.
(c) A ground may not be welded to the pipe or fitting that is being welded.
(a) Each weld and welding must be inspected to insure compliance with the requirements of this subpart. Visual inspection must be supplemented by nondestructive testing.
(b) The acceptability of a weld is determined according to the standards in Section 9 of API 1104. However, if a girth weld is unacceptable under those standards for a reason other than a crack, and if Appendix A to API 1104 (incorporated by reference,
(a) Each weld that is unacceptable under § 195.228 must be removed or repaired. Except for welds on an offshore pipeline being installed from a pipelay vessel, a weld must be removed if it has a crack that is more than 8 percent of the weld length.
(b) Each weld that is repaired must have the defect removed down to sound metal and the segment to be repaired must be preheated if conditions exist which would adversely affect the quality of the weld repair. After repair, the segment of the weld that was repaired must be inspected to ensure its acceptability.
(c) Repair of a crack, or of any defect in a previously repaired area must be in accordance with written weld repair procedures that have been qualified under § 195.214. Repair procedures must provide that the minimum mechanical properties specified for the welding procedure used to make the original weld are met upon completion of the final weld repair.
(a) A weld may be nondestructively tested by any process that will clearly indicate any defects that may affect the integrity of the weld.
(b) Any nondestructive testing of welds must be performed—
(1) In accordance with a written set of procedures for nondestructive testing; and
(2) With personnel that have been trained in the established procedures and in the use of the equipment employed in the testing.
(c) Procedures for the proper interpretation of each weld inspection must be established to ensure the acceptability of the weld under § 195.228.
(d) During construction, at least 10 percent of the girth welds made by each welder during each welding day must be nondestructively tested over the entire circumference of the weld.
(e) All girth welds installed each day in the following locations must be nondestructively tested over their entire circumference, except that when nondestructive testing is impracticable for a girth weld, it need not be tested if the number of girth welds for which testing is impracticable does not exceed 10 percent of the girth welds installed that day:
(1) At any onshore location where a loss of hazardous liquid could reasonably be expected to pollute any stream,
(2) Within railroad or public road rights-of-way;
(3) At overhead road crossings and within tunnels;
(4) Within the limits of any incorporated subdivision of a State government; and
(5) Within populated areas, including, but not limited to, residential subdivisions, shopping centers, schools, designated commercial areas, industrial facilities, public institutions, and places of public assembly.
(f) When installing used pipe, 100 percent of the old girth welds must be nondestructively tested.
(g) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent of the girth welds must be nondestructively tested.
(a) All pipe installed in a ditch must be installed in a manner that minimizes the introduction of secondary stresses and the possibility of damage to the pipe.
(b) Except for pipe in the Gulf of Mexico and its inlets in waters less than 15 feet deep, all offshore pipe in water at least 12 feet deep (3.7 meters) but not more than 200 feet deep (61 meters) deep as measured from the mean low water must be installed so that the top of the pipe is below the underwater natural bottom (as determined by recognized and generally accepted practices) unless the pipe is supported by stanchions held in place by anchors or heavy concrete coating or protected by an equivalent means.
(a) Unless specifically exempted in this subpart, all pipe must be buried so that it is below the level of cultivation. Except as provided in paragraph (b) of this section, the pipe must be installed so that the cover between the top of the pipe and the ground level, road bed, river bottom, or underwater natural bottom (as determined by recognized and generally accepted practices), as applicable, complies with the following table:
(b) Except for the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep, less cover than the minimum required by paragraph (a) of this section and § 195.210 may be used if—
(1) It is impracticable to comply with the minimum cover requirements; and
(2) Additional protection is provided that is equivalent to the minimum required cover.
Any pipe installed underground must have at least 12 inches (305 millimeters) of clearance between the outside of the pipe and the extremity of any other underground structure, except that for drainage tile the minimum clearance may be less than 12 inches (305 millimeters) but not less than 2 inches (51 millimeters). However, where 12 inches (305 millimeters) of clearance is impracticable, the clearance may be reduced if adequate provisions are made for corrosion control.
When a ditch for a pipeline is backfilled, it must be backfilled in a manner that:
(a) Provides firm support under the pipe; and
(b) Prevents damage to the pipe and pipe coating from equipment or from the backfill material.
(a) Any component may be installed above ground in the following situations, if the other applicable requirements of this part are complied with:
(1) Overhead crossings of highways, railroads, or a body of water.
(2) Spans over ditches and gullies.
(3) Scraper traps or block valves.
(4) Areas under the direct control of the operator.
(5) In any area inaccessible to the public.
(b) Each component covered by this section must be protected from the forces exerted by the anticipated loads.
The pipe at each railroad or highway crossing must be installed so as to adequately withstand the dynamic forces exerted by anticipated traffic loads.
(a) Each valve must be installed in a location that is accessible to authorized employees and that is protected from damage or tampering.
(b) Each submerged valve located offshore or in inland navigable waters must be marked, or located by conventional survey techniques, to facilitate quick location when operation of the valve is required.
A valve must be installed at each of the following locations:
(a) On the suction end and the discharge end of a pump station in a manner that permits isolation of the pump station equipment in the event of an emergency.
(b) On each line entering or leaving a breakout storage tank area in a manner that permits isolation of the tank area from other facilities.
(c) On each mainline at locations along the pipeline system that will minimize damage or pollution from accidental hazardous liquid discharge, as appropriate for the terrain in open country, for offshore areas, or for populated areas.
(d) On each lateral takeoff from a trunk line in a manner that permits shutting off the lateral without interrupting the flow in the trunk line.
(e) On each side of a water crossing that is more than 100 feet (30 meters) wide from high-water mark to high-water mark unless the Administrator finds in a particular case that valves are not justified.
(f) On each side of a reservoir holding water for human consumption.
(a) Adequate ventilation must be provided in pump station buildings to prevent the accumulation of hazardous vapors. Warning devices must be installed to warn of the presence of hazardous vapors in the pumping station building.
(b) The following must be provided in each pump station:
(1) Safety devices that prevent overpressuring of pumping equipment, including the auxiliary pumping equipment within the pumping station.
(2) A device for the emergency shutdown of each pumping station.
(3) If power is necessary to actuate the safety devices, an auxiliary power supply.
(c) Each safety device must be tested under conditions approximating actual operations and found to function properly before the pumping station may be used.
(d) Except for offshore pipelines, pumping equipment must be installed on property that is under the control of the operator and at least 15.2 m (50 ft) from the boundary of the pump station.
(e) Adequate fire protection must be installed at each pump station. If the fire protection system installed requires the use of pumps, motive power must be provided for those pumps that is separate from the power that operates the station.
(a) A means must be provided for containing hazardous liquids in the event of spillage or failure of an aboveground breakout tank.
(b) After October 2, 2000, compliance with paragraph (a) of this section requires the following for the aboveground breakout tanks specified:
(1) For tanks built to API Specification 12F, API Standard 620, and others (such as API Standard 650 or its predecessor Standard 12C), the installation of impoundment must be in accordance with the following sections of NFPA 30:
(i) Impoundment around a breakout tank must be installed in accordance with section 4.3.2.3.2; and
(ii) Impoundment by drainage to a remote impounding area must be installed in accordance with section 4.3.2.3.1.
(2) For tanks built to API 2510, the installation of impoundment must be in accordance with section 5 or 11 of API 2510 (incorporated by reference,
(c) Aboveground breakout tank areas must be adequately protected against unauthorized entry.
(d) Normal/emergency relief venting must be provided for each atmospheric pressure breakout tank. Pressure/vacuum-relieving devices must be provided for each low-pressure and high-pressure breakout tank.
(e) For normal/emergency relief venting and pressure/vacuum-relieving devices installed on aboveground breakout tanks after October 2, 2000, compliance with paragraph (d) of this section requires the following for the tanks specified:
(1) Normal/emergency relief venting installed on atmospheric pressure tanks built to API Specification 12F must be in accordance with Section 4, and Appendices B and C, of API Specification 12F.
(2) Normal/emergency relief venting installed on atmospheric pressure tanks (such as those built to API Standard 650 or its predecessor Standard 12C) must be in accordance with API Standard 2000.
(3) Pressure-relieving and emergency vacuum-relieving devices installed on low pressure tanks built to API Standard 620 must be in accordance with section 9 of API Standard 620 (incorporated by reference,
(4) Pressure and vacuum-relieving devices installed on high pressure tanks built to API Standard 2510 must be in accordance with sections 7 or 11 of API 2510 (incorporated by reference,
A complete record that shows the following must be maintained by the operator involved for the life of each pipeline facility:
(a) The total number of girth welds and the number nondestructively tested, including the number rejected and the disposition of each rejected weld.
(b) The amount, location; and cover of each size of pipe installed.
(c) The location of each crossing of another pipeline.
(d) The location of each buried utility crossing.
(e) The location of each overhead crossing.
(f) The location of each valve and corrosion test station.
This subpart prescribes minimum requirements for the pressure testing of steel pipelines. However, this subpart does not apply to the movement of pipe under § 195.424.
(a) Except as otherwise provided in this section and in § 195.305(b), no operator may operate a pipeline unless it has been pressure tested under this subpart without leakage. In addition, no operator may return to service a segment of pipeline that has been replaced, relocated, or otherwise changed until it has been pressure tested under this subpart without leakage.
(b) Except for pipelines converted under § 195.5, the following pipelines may be operated without pressure testing under this subpart:
(1) Any hazardous liquid pipeline whose maximum operating pressure is established under § 195.406(a)(5) that is—
(i) An interstate pipeline constructed before January 8, 1971;
(ii) An interstate offshore gathering line constructed before August 1, 1977;
(iii) An intrastate pipeline constructed before October 21, 1985; or
(iv) A low-stress pipeline constructed before August 11, 1994 that transports HVL.
(2) Any carbon dioxide pipeline constructed before July 12, 1991, that—
(i) Has its maximum operating pressure established under § 195.406(a)(5); or
(ii) Is located in a rural area as part of a production field distribution system.
(3) Any low-stress pipeline constructed before August 11, 1994 that does not transport HVL.
(4) Those portions of older hazardous liquid and carbon dioxide pipelines for which an operator has elected the risk-based alternative under § 195.303 and which are not required to be tested based on the risk-based criteria.
(c) Except for pipelines that transport HVL onshore, low-stress pipelines, and pipelines covered under § 195.303, the following compliance deadlines apply to pipelines under paragraphs (b)(1) and (b)(2)(i) of this section that have not been pressure tested under this subpart:
(1) Before December 7, 1998, for each pipeline each operator shall—
(i) Plan and schedule testing according to this paragraph; or
(ii) Establish the pipeline's maximum operating pressure under § 195.406(a)(5).
(2) For pipelines scheduled for testing, each operator shall—
(i) Before December 7, 2000, pressure test—
(A) Each pipeline identified by name, symbol, or otherwise that existing records show contains more than 50 percent by mileage (length) of electric resistance welded pipe manufactured before 1970; and
(B) At least 50 percent of the mileage (length) of all other pipelines; and
(ii) Before December 7, 2003, pressure test the remainder of the pipeline mileage (length).
(a) An operator may elect to follow a program for testing a pipeline on risk-based criteria as an alternative to the pressure testing in § 195.302(b)(1)(i)-(iii) and § 195.302(b)(2)(i) of this subpart. Appendix B provides guidance on how this program will work. An operator electing such a program shall assign a risk classification to each pipeline segment according to the indicators described in paragraph (b) of this section as follows:
(1) Risk Classification A if the location indicator is ranked as low or medium risk, the product and volume indicators are ranked as low risk, and the probability of failure indicator is ranked as low risk;
(2) Risk Classification C if the location indicator is ranked as high risk; or
(3) Risk Classification B.
(b) An operator shall evaluate each pipeline segment in the program according to the following indicators of risk:
(1) The location indicator is—
(i) High risk if an area is non-rural or environmentally sensitive
(ii) Medium risk; or
(iii) Low risk if an area is not high or medium risk.
(2) The product indicator is
(i) High risk if the product transported is highly toxic or is both highly volatile and flammable;
(ii) Medium risk if the product transported is flammable with a flashpoint of less than 100° F, but not highly volatile; or
(iii) Low risk if the product transported is not high or medium risk.
(3) The volume indicator is—
(i) High risk if the line is at least 18 inches in nominal diameter;
(ii) Medium risk if the line is at least 10 inches, but less than 18 inches, in nominal diameter; or
(iii) Low risk if the line is not high or medium risk.
(4) The probability of failure indicator is—
(i) High risk if the segment has experienced more than three failures in the last 10 years due to time-dependent defects (e.g., corrosion, gouges, or problems developed during manufacture, construction or operation, etc.); or
(ii) Low risk if the segment has experienced three failures or less in the last 10 years due to time-dependent defects.
(c) The program under paragraph (a) of this section shall provide for pressure testing for a segment constructed of electric resistance-welded (ERW) pipe and lapwelded pipe manufactured prior to 1970 susceptible to longitudinal seam failures as determined through paragraph (d) of this section. The timing of such pressure test may be determined based on risk classifications discussed under paragraph (b) of this section. For other segments, the program may provide for use of a magnetic flux leakage or ultrasonic internal inspection survey as an alternative to pressure testing and, in the case of such segments in Risk Classification A, may provide for no additional measures under this subpart.
(d) All pre-1970 ERW pipe and lapwelded pipe is deemed susceptible to longitudinal seam failures unless an engineering analysis shows otherwise. In conducting an engineering analysis an operator must consider the seam-related leak history of the pipe and pipe manufacturing information as available, which may include the pipe steel's mechanical properties, including fracture toughness; the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-making process; and other factors pertinent to seam properties and quality.
(e) Pressure testing done under this section must be conducted in accordance with this subpart. Except for segments in Risk Classification B which are not constructed with pre-1970 ERW pipe, water must be the test medium.
(f) An operator electing to follow a program under paragraph (a) must develop plans that include the method of testing and a schedule for the testing by December 7, 1998. The compliance deadlines for completion of testing are as shown in the table below:
(g) An operator must review the risk classifications for those pipeline segments which have not yet been tested under paragraph (a) of this section or otherwise inspected under paragraph (c) of this section at intervals not to
(h) An operator must maintain records establishing compliance with this section, including records verifying the risk classifications, the plans and schedule for testing, the conduct of the testing, and the review of the risk classifications.
(i) An operator may discontinue a program under this section only after written notification to the Administrator and approval, if needed, of a schedule for pressure testing.
The test pressure for each pressure test conducted under this subpart must be maintained throughout the part of the system being tested for at least 4 continuous hours at a pressure equal to 125 percent, or more, of the maximum operating pressure and, in the case of a pipeline that is not visually inspected for leakage during the test, for at least an additional 4 continuous hours at a pressure equal to 110 percent, or more, of the maximum operating pressure.
(a) Each pressure test under § 195.302 must test all pipe and attached fittings, including components, unless otherwise permitted by paragraph (b) of this section.
(b) A component, other than pipe, that is the only item being replaced or added to the pipeline system need not be hydrostatically tested under paragraph (a) of this section if the manufacturer certifies that either—
(1) The component was hydrostatically tested at the factory; or
(2) The component was manufactured under a quality control system that ensures each component is at least equal in strength to a prototype that was hydrostatically tested at the factory.
(a) Except as provided in paragraphs (b), (c), and (d) of this section, water must be used as the test medium.
(b) Except for offshore pipelines, liquid petroleum that does not vaporize rapidly may be used as the test medium if—
(1) The entire pipeline section under test is outside of cities and other populated areas;
(2) Each building within 300 feet (91 meters) of the test section is unoccupied while the test pressure is equal to or greater than a pressure which produces a hoop stress of 50 percent of specified minimum yield strength;
(3) The test section is kept under surveillance by regular patrols during the test; and
(4) Continuous communication is maintained along entire test section.
(c) Carbon dioxide pipelines may use inert gas or carbon dioxide as the test medium if—
(1) The entire pipeline section under test is outside of cities and other populated areas;
(2) Each building within 300 feet (91 meters) of the test section is unoccupied while the test pressure is equal to or greater than a pressure that produces a hoop stress of 50 percent of specified minimum yield strength;
(3) The maximum hoop stress during the test does not exceed 80 percent of specified minimum yield strength;
(4) Continuous communication is maintained along entire test section; and
(5) The pipe involved is new pipe having a longitudinal joint factor of 1.00.
(d) Air or inert gas may be used as the test medium in low-stress pipelines.
(a) For aboveground breakout tanks built to API Specification 12F and first placed in service after October 2, 2000, pneumatic testing must be in accordance with section 5.3 of API Specification 12F.
(b) For aboveground breakout tanks built to API Standard 620 and first placed in service after October 2, 2000, hydrostatic and pneumatic testing must be in accordance with section 7.18 of API Standard 620 (incorporated by reference,
(c) For aboveground breakout tanks built to API Standard 650 and first placed in service after October 2, 2000, hydrostatic and pneumatic testing must be in accordance with section 5.3 of API Standard 650.
(d) For aboveground atmospheric pressure breakout tanks constructed of carbon and low alloy steel, welded or riveted, and non-refrigerated and tanks built to API Standard 650 or its predecessor Standard 12C that are returned to service after October 2, 2000, the necessity for the hydrostatic testing of repair, alteration, and reconstruction is covered in section 10.3 of API Standard 653.
(e) For aboveground breakout tanks built to API Standard 2510 and first placed in service after October 2, 2000, pressure testing must be in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 or 2.
Pipe associated with tie-ins must be pressure tested, either with the section to be tied in or separately.
(a) A record must be made of each pressure test required by this subpart, and the record of the latest test must be retained as long as the facility tested is in use.
(b) The record required by paragraph (a) of this section must include:
(1) The pressure recording charts;
(2) Test instrument calibration data;
(3) The name of the operator, the name of the person responsible for making the test, and the name of the test company used, if any;
(4) The date and time of the test;
(5) The minimum test pressure;
(6) The test medium;
(7) A description of the facility tested and the test apparatus;
(8) An explanation of any pressure discontinuities, including test failures, that appear on the pressure recording charts;
(9) Where elevation differences in the section under test exceed 100 feet (30 meters), a profile of the pipeline that shows the elevation and test sites over the entire length of the test section; and
(10) Temperature of the test medium or pipe during the test period.
This subpart prescribes minimum requirements for operating and maintaining pipeline systems constructed with steel pipe.
(a) No operator may operate or maintain its pipeline systems at a level of safety lower than that required by this subpart and the procedures it is required to establish under § 195.402(a) of this subpart.
(b) Whenever an operator discovers any condition that could adversely affect the safe operation of its pipeline system, it shall correct it within a reasonable time. However, if the condition is of such a nature that it presents an immediate hazard to persons or property, the operator may not operate the affected part of the system until it has corrected the unsafe condition.
(c) Except as provided in § 195.5, no operator may operate any part of any of the following pipelines unless it was designed and constructed as required by this part:
(1) An interstate pipeline, other than a low-stress pipeline, on which construction was begun after March 31, 1970, that transports hazardous liquid.
(2) An interstate offshore gathering line, other than a low-stress pipeline, on which construction was begun after July 31, 1977, that transports hazardous liquid.
(3) An intrastate pipeline, other than a low-stress pipeline, on which construction was begun after October 20, 1985, that transports hazardous liquid.
(4) A pipeline on which construction was begun after July 11, 1991, that transports carbon dioxide.
(5) A low-stress pipeline on which construction was begun after August 10, 1994.
(a)
(b) The Administrator or the State Agency that has submitted a current certification under the pipeline safety laws (49 U.S.C. 60101
(c)
(1) Making construction records, maps, and operating history available as necessary for safe operation and maintenance.
(2) Gathering of data needed for reporting accidents under subpart B of this part in a timely and effective manner.
(3) Operating, maintaining, and repairing the pipeline system in accordance with each of the requirements of this subpart and subpart H of this part.
(4) Determining which pipeline facilities are located in areas that would require an immediate response by the operator to prevent hazards to the public if the facilities failed or malfunctioned.
(5) Analyzing pipeline accidents to determine their causes.
(6) Minimizing the potential for hazards identified under paragraph (c)(4) of this section and the possibility of recurrence of accidents analyzed under paragraph (c)(5) of this section.
(7) Starting up and shutting down any part of the pipeline system in a manner designed to assure operation within the limits prescribed by § 195.406, consider the hazardous liquid or carbon dioxide in transportation, variations in altitude along the pipeline, and pressure monitoring and control devices.
(8) In the case of a pipeline that is not equipped to fail safe, monitoring from an attended location pipeline pressure during startup until steady state pressure and flow conditions are reached and during shut-in to assure operation within limits prescribed by § 195.406.
(9) In the case of facilities not equipped to fail safe that are identified under paragraph 195.402(c)(4) or that control receipt and delivery of the hazardous liquid or carbon dioxide, detecting abnormal operating conditions by monitoring pressure, temperature, flow or other appropriate operational data and transmitting this data to an attended location.
(10) Abandoning pipeline facilities, including safe disconnection from an
(11) Minimizing the likelihood of accidental ignition of vapors in areas near facilities identified under paragraph (c)(4) of this section where the potential exists for the presence of flammable liquids or gases.
(12) Establishing and maintaining liaison with fire, police, and other appropriate public officials to learn the responsibility and resources of each government organization that may respond to a hazardous liquid or carbon dioxide pipeline emergency and acquaint the officials with the operator's ability in responding to a hazardous liquid or carbon dioxide pipeline emergency and means of communication.
(13) Periodically reviewing the work done by operator personnel to determine the effectiveness of the procedures used in normal operation and maintenance and taking corrective action where deficiencies are found.
(14) Taking adequate precautions in excavated trenches to protect personnel from the hazards of unsafe accumulations of vapor or gas, and making available when needed at the excavation, emergency rescue equipment, including a breathing apparatus and, a rescue harness and line.
(d)
(1) Responding to, investigating, and correcting the cause of:
(i) Unintended closure of valves or shutdowns;
(ii) Increase or decrease in pressure or flow rate outside normal operating limits;
(iii) Loss of communications;
(iv) Operation of any safety device;
(v) Any other malfunction of a component, deviation from normal operation, or personnel error which could cause a hazard to persons or property.
(2) Checking variations from normal operation after abnormal operation has ended at sufficient critical locations in the system to determine continued integrity and safe operation.
(3) Correcting variations from normal operation of pressure and flow equipment and controls.
(4) Notifying responsible operator personnel when notice of an abnormal operation is received.
(5) Periodically reviewing the response of operator personnel to determine the effectiveness of the procedures controlling abnormal operation and taking corrective action where deficiencies are found.
(e)
(1) Receiving, identifying, and classifying notices of events which need immediate response by the operator or notice to fire, police, or other appropriate public officials and communicating this information to appropriate operator personnel for corrective action.
(2) Prompt and effective response to a notice of each type emergency, including fire or explosion occurring near or directly involving a pipeline facility, accidental release of hazardous liquid or carbon dioxide from a pipeline facility, operational failure causing a hazardous condition, and natural disaster affecting pipeline facilities.
(3) Having personnel, equipment, instruments, tools, and material available as needed at the scene of an emergency.
(4) Taking necessary action, such as emergency shutdown or pressure reduction, to minimize the volume of hazardous liquid or carbon dioxide that is released from any section of a pipeline system in the event of a failure.
(5) Control of released hazardous liquid or carbon dioxide at an accident scene to minimize the hazards, including possible intentional ignition in the cases of flammable highly volatile liquid.
(6) Minimization of public exposure to injury and probability of accidental
(7) Notifying fire, police, and other appropriate public officials of hazardous liquid or carbon dioxide pipeline emergencies and coordinating with them preplanned and actual responses during an emergency, including additional precautions necessary for an emergency involving a pipeline system transporting a highly volatile liquid.
(8) In the case of failure of a pipeline system transporting a highly volatile liquid, use of appropriate instruments to assess the extent and coverage of the vapor cloud and determine the hazardous areas.
(9) Providing for a post accident review of employee activities to determine whether the procedures were effective in each emergency and taking corrective action where deficiencies are found.
(f)
(a) Each operator shall establish and conduct a continuing training program to instruct emergency response personnel to:
(1) Carry out the emergency procedures established under 195.402 that relate to their assignments;
(2) Know the characteristics and hazards of the hazardous liquids or carbon dioxide transported, including, in case of flammable HVL, flammability of mixtures with air, odorless vapors, and water reactions;
(3) Recognize conditions that are likely to cause emergencies, predict the consequences of facility malfunctions or failures and hazardous liquids or carbon dioxide spills, and take appropriate corrective action;
(4) Take steps necessary to control any accidental release of hazardous liquid or carbon dioxide and to minimize the potential for fire, explosion, toxicity, or environmental damage; and
(5) Learn the potential causes, types, sizes, and consequences of fire and the appropriate use of portable fire extinguishers and other on-site fire control equipment, involving, where feasible, a simulated pipeline emergency condition.
(b) At the intervals not exceeding 15 months, but at least once each calendar year, each operator shall:
(1) Review with personnel their performance in meeting the objectives of the emergency response training program set forth in paragraph (a) of this section; and
(2) Make appropriate changes to the emergency response training program as necessary to ensure that it is effective.
(c) Each operator shall require and verify that its supervisors maintain a thorough knowledge of that portion of the emergency response procedures established under 195.402 for which they are responsible to ensure compliance.
(a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information:
(1) Location and identification of the following pipeline facilities:
(i) Breakout tanks;
(ii) Pump stations;
(iii) Scraper and sphere facilities;
(iv) Pipeline valves;
(v) Facilities to which § 195.402(c)(9) applies;
(vi) Rights-of-way; and
(vii) Safety devices to which § 195.428 applies.
(2) All crossings of public roads, railroads, rivers, buried utilities, and foreign pipelines.
(3) The maximum operating pressure of each pipeline.
(4) The diameter, grade, type, and nominal wall thickness of all pipe.
(b) Each operator shall maintain for at least 3 years daily operating records that indicate—
(1) The discharge pressure at each pump station; and
(2) Any emergency or abnormal operation to which the procedures under § 195.402 apply.
(c) Each operator shall maintain the following records for the periods specified:
(1) The date, location, and description of each repair made to pipe shall be maintained for the useful life of the pipe.
(2) The date, location, and description of each repair made to parts of the pipeline system other than pipe shall be maintained for at least 1 year.
(3) A record of each inspection and test required by this subpart shall be maintained for at least 2 years or until the next inspection or test is performed, whichever is longer.
(a) After October 2, 2000, protection provided against ignitions arising out of static electricity, lightning, and stray currents during operation and maintenance activities involving aboveground breakout tanks must be in accordance with API Recommended Practice 2003, unless the operator notes in the procedural manual (§ 195.402(c)) why compliance with all or certain provisions of API Recommended Practice 2003 is not necessary for the safety of a particular breakout tank.
(b) The hazards associated with access/egress onto floating roofs of in-service aboveground breakout tanks to perform inspection, service, maintenance or repair activities (other than specified general considerations, specified routine tasks or entering tanks removed from service for cleaning) are addressed in API Publication 2026. After October 2, 2000, the operator must review and consider the potentially hazardous conditions, safety practices and procedures in API Publication 2026 for inclusion in the procedure manual (§ 195.402(c)).
(a) Except for surge pressures and other variations from normal operations, no operator may operate a pipeline at a pressure that exceeds any of the following:
(1) The internal design pressure of the pipe determined in accordance with § 195.106. However, for steel pipe in pipelines being converted under § 195.5, if one or more factors of the design formula (§ 195.106) are unknown, one of the following pressures is to be used as design pressure:
(i) Eighty percent of the first test pressure that produces yield under section N5.0 of appendix N of ASME B31.8, reduced by the appropriate factors in §§ 195.106 (a) and (e); or
(ii) If the pipe is 12
(2) The design pressure of any other component of the pipeline.
(3) Eighty percent of the test pressure for any part of the pipeline which has been pressure tested under subpart E of this part.
(4) Eighty percent of the factory test pressure or of the prototype test pressure for any individually installed component which is excepted from testing under § 195.305.
(5) For pipelines under §§ 195.302(b)(1) and (b)(2)(i) that have not been pressure tested under subpart E of this part, 80 percent of the test pressure or highest operating pressure to which the pipeline was subjected for 4 or more continuous hours that can be demonstrated by recording charts or logs made at the time the test or operations were conducted.
(b) No operator may permit the pressure in a pipeline during surges or other variations from normal operations to exceed 110 percent of the operating pressure limit established under paragraph (a) of this section. Each operator must provide adequate
(a) Each operator must have a communication system to provide for the transmission of information needed for the safe operation of its pipeline system.
(b) The communication system required by paragraph (a) of this section must, as a minimum, include means for:
(1) Monitoring operational data as required by § 195.402(c)(9);
(2) Receiving notices from operator personnel, the public, and public authorities of abnormal or emergency conditions and sending this information to appropriate personnel or government agencies for corrective action;
(3) Conducting two-way vocal communication between a control center and the scene of abnormal operations and emergencies; and
(4) Providing communication with fire, police, and other appropriate public officials during emergency conditions, including a natural disaster.
(a) Except as provided in paragraph (b) of this section, each operator shall place and maintain line markers over each buried pipeline in accordance with the following:
(1) Markers must be located at each public road crossing, at each railroad crossing, and in sufficient number along the remainder of each buried line so that its location is accurately known.
(2) The marker must state at least the following on a background of sharply contrasting color:
(i) The word “Warning,” “Caution,” or “Danger” followed by the words “Petroleum (or the name of the hazardous liquid transported) Pipeline”, or “Carbon Dioxide Pipeline,” all of which, except for markers in heavily developed urban areas, must be in letters at least 1 inch (25 millimeters) high with an approximate stroke of
(ii) The name of the operator and a telephone number (including area code) where the operator can be reached at all times.
(b) Line markers are not required for buried pipelines located—
(1) Offshore or at crossings of or under waterways and other bodies of water; or
(2) In heavily developed urban areas such as downtown business centers where—
(i) The placement of markers is impractical and would not serve the purpose for which markers are intended; and
(ii) The local government maintains current substructure records.
(c) Each operator shall provide line marking at locations where the line is above ground in areas that are accessible to the public.
(a) Each operator shall, at intervals not exceeding 3 weeks, but at least 26 times each calendar year, inspect the surface conditions on or adjacent to each pipeline right-of-way. Methods of inspection include walking, driving, flying or other appropriate means of traversing the right-of-way.
(b) Except for offshore pipelines, each operator shall, at intervals not exceeding 5 years, inspect each crossing under a navigable waterway to determine the condition of the crossing.
(a) Except for gathering lines of 4
(b) Each operator shall conduct appropriate periodic underwater inspections of its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water based on the identified risk.
(c) If an operator discovers that its pipeline is an exposed underwater pipeline or poses a hazard to navigation, the operator shall—
(1) Promptly, but not later than 24 hours after discovery, notify the National Response Center, telephone: 1-800-424-8802, of the location and, if available, the geographic coordinates of that pipeline.
(2) Promptly, but not later than 7 days after discovery, mark the location of the pipeline in accordance with 33 CFR Part 64 at the ends of the pipeline segment and at intervals of not over 500 yards (457 meters) long, except that a pipeline segment less than 200 yards (183 meters) long need only be marked at the center; and
(3) Within 6 months after discovery, or not later than November 1 of the following year if the 6 month period is later than November 1 of the year of discovery, bury the pipeline so that the top of the pipe is 36 inches (914 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) for normal excavation or 18 inches (457 millimeters) for rock excavation.
(i) An operator may employ engineered alternatives to burial that meet or exceed the level of protection provided by burial.
(ii) If an operator cannot obtain required state or Federal permits in time to comply with this section, it must notify OPS; specify whether the required permit is State or Federal; and, justify the delay.
(a) Each operator shall maintain each valve that is necessary for the safe operation of its pipeline systems in good working order at all times.
(b) Each operator shall, at intervals not exceeding 7
(c) Each operator shall provide protection for each valve from unauthorized operation and from vandalism.
(a) Each operator shall, in repairing its pipeline systems, insure that the repairs are made in a safe manner and are made so as to prevent damage to persons or property.
(b) No operator may use any pipe, valve, or fitting, for replacement in repairing pipeline facilities, unless it is designed and constructed as required by this part.
(a) No operator may move any line pipe, unless the pressure in the line section involved is reduced to not more than 50 percent of the maximum operating pressure.
(b) No operator may move any pipeline containing highly volatile liquids where materials in the line section involved are joined by welding unless—
(1) Movement when the pipeline does not contain highly volatile liquids is impractical;
(2) The procedures of the operator under § 195.402 contain precautions to protect the public against the hazard in moving pipelines containing highly volatile liquids, including the use of warnings, where necessary, to evacuate the area close to the pipeline; and
(3) The pressure in that line section is reduced to the lower of the following:
(i) Fifty percent or less of the maximum operating pressure; or
(ii) The lowest practical level that will maintain the highly volatile liquid in a liquid state with continuous flow,
(c) No operator may move any pipeline containing highly volatile liquids where materials in the line section involved are not joined by welding unless—
(1) The operator complies with paragraphs (b) (1) and (2) of this section; and
(2) That line section is isolated to prevent the flow of highly volatile liquid.
No operator may use a launcher or receiver that is not equipped with a relief device capable of safely relieving pressure in the barrel before insertion or removal of scrapers or spheres. The operator must use a suitable device to indicate that pressure has been relieved in the barrel or must provide a means to prevent insertion or removal of scrapers or spheres if pressure has not been relieved in the barrel.
(a) Except as provided in paragraph (b) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, or in the case of pipelines used to carry highly volatile liquids, at intervals not to exceed 7
(b) In the case of relief valves on pressure breakout tanks containing highly volatile liquids, each operator shall test each valve at intervals not exceeding 5 years.
(c) Aboveground breakout tanks that are constructed or significantly altered according to API Standard 2510 after October 2, 2000, must have an overfill protection system installed according to section 5.1.2 of API Standard 2510. Other aboveground breakout tanks with 600 gallons (2271 liters) or more of storage capacity that are constructed or significantly altered after October 2, 2000, must have an overfill protection system installed according to API Recommended Practice 2350. However, operators need not comply with any part of API Recommended Practice 2350 for a particular breakout tank if the operator notes in the manual required by § 195.402 why compliance with that part is not necessary for safety of the tank.
(d) After October 2, 2000, the requirements of paragraphs (a) and (b) of this section for inspection and testing of pressure control equipment apply to the inspection and testing of overfill protection systems.
Each operator shall maintain adequate firefighting equipment at each pump station and breakout tank area. The equipment must be—
(a) In proper operating condition at all times;
(b) Plainly marked so that its identity as firefighting equipment is clear; and
(c) Located so that it is easily accessible during a fire.
(a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, inspect each in-service breakout tank.
(b) Each operator shall inspect the physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to section 4 of API Standard 653. However, if structural conditions prevent access to the tank bottom, the bottom integrity may be assessed according to a plan included in the operations and maintenance manual under § 195.402(c)(3).
(c) Each operator shall inspect the physical integrity of in-service steel aboveground breakout tanks built to API Standard 2510 according to section 6 of API 510.
(d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier.
Each operator must maintain signs visible to the public around each pumping station and breakout tank area. Each sign must contain the name of the operator and a telephone number (including area code) where the operator can be reached at all times.
Each operator shall provide protection for each pumping station and breakout tank area and other exposed facility (such as scraper traps) from vandalism and unauthorized entry.
Each operator shall prohibit smoking and open flames in each pump station area and each breakout tank area where there is a possibility of the leakage of a flammable hazardous liquid or of the presence of flammable vapors.
(a) Each pipeline operator must develop and implement a written continuing public education program that follows the guidance provided in the American Petroleum Institute's (API) Recommended Practice (RP) 1162 (incorporated by reference,
(b) The operator's program must follow the general program recommendations of API RP 1162 and assess the unique attributes and characteristics of the operator's pipeline and facilities.
(c) The operator must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162, unless the operator provides justification in its program or procedural manual as to why compliance with all or certain provisions of the recommended practice is not practicable and not necessary for safety.
(d) The operator's program must specifically include provisions to educate the public, appropriate government organizations, and persons engaged in excavation related activities on:
(1) Use of a one-call notification system prior to excavation and other damage prevention activities;
(2) Possible hazards associated with unintended releases from a hazardous liquid or carbon dioxide pipeline facility;
(3) Physical indications that such a release may have occurred;
(4) Steps that should be taken for public safety in the event of a hazardous liquid or carbon dioxide pipeline release; and
(5) Procedures to report such an event.
(e) The program must include activities to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations.
(f) The program and the media used must be as comprehensive as necessary to reach all areas in which the operator transports hazardous liquid or carbon dioxide.
(g) The program must be conducted in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator's area.
(h) Operators in existence on June 20, 2005, must have completed their written programs no later than June 20, 2006. Upon request, operators must submit their completed programs to PHMSA or, in the case of an intrastate pipeline facility operator, the appropriate State agency.
(i) The operator's program documentation and evaluation results must be available for periodic review by appropriate regulatory agencies.
(a) Except as provided in paragraph (d) of this section, each operator of a buried pipeline must carry out, in accordance with this section, a written program to prevent damage to that pipeline from excavation activities.
(b) An operator may comply with any of the requirements of paragraph (c) of this section through participation in a public service program, such as a one-call system, but such participation does not relieve the operator of the responsibility for compliance with this section. However, an operator must perform the duties of paragraph (c)(3) of this section through participation in a one-call system, if that one-call system is a qualified one-call system. In areas that are covered by more than one qualified one-call system, an operator need only join one of the qualified one-call systems if there is a central telephone number for excavators to call for excavation activities, or if the one-call systems in those areas communicate with one another. An operator's pipeline system must be covered by a qualified one-call system where there is one in place. For the purpose of this section, a one-call system is considered a “qualified one-call system” if it meets the requirements of section (b)(1) or (b)(2) or this section.
(1) The state has adopted a one-call damage prevention program under § 198.37 of this chapter; or
(2) The one-call system:
(i) Is operated in accordance with § 198.39 of this chapter;
(ii) Provides a pipeline operator an opportunity similar to a voluntary participant to have a part in management responsibilities; and
(iii) Assesses a participating pipeline operator a fee that is proportionate to the costs of the one-call system's coverage of the operator's pipeline.
(c) The damage prevention program required by paragraph (a) of this section must, at a minimum:
(1) Include the identity, on a current basis, of persons who normally engage in excavation activities in the area in which the pipeline is located.
(2) Provides for notification of the public in the vicinity of the pipeline and actual notification of persons identified in paragraph (c)(1) of this section of the following as often as needed to make them aware of the damage prevention program:
(i) The program's existence and purpose; and
(ii) How to learn the location of underground pipelines before excavation activities are begun.
(3) Provide a means of receiving and recording notification of planned excavation activities.
(4) If the operator has buried pipelines in the area of excavation activity, provide for actual notification of persons who give notice of their intent to excavate of the type of temporary marking to be provided and how to identify the markings.
(5) Provide for temporary marking of buried pipelines in the area of excavation activity before, as far as practical, the activity begins.
(6) Provide as follows for inspection of pipelines that an operator has reason to believe could be damaged by excavation activities:
(i) The inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline; and
(ii) In the case of blasting, any inspection must include leakage surveys.
(d) A damage prevention program under this section is not required for the following pipelines:
(1) Pipelines located offshore.
(2) Pipelines to which access is physically controlled by the operator.
Each computational pipeline monitoring (CPM) leak detection system installed on a hazardous liquid pipeline transporting liquid in single phase (without gas in the liquid) must comply with API 1130 in operating, maintaining, testing, record keeping, and dispatcher training of the system.
The following definitions apply to this section and § 195.452:
(1)
(2)
(1) A
(2) A
(3) An
(4) An
(a)
(1) Category 1 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipeline subject to this part.
(2) Category 2 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated less than 500 miles of pipeline subject to this part.
(3) Category 3 includes pipelines constructed or converted after May 29, 2001.
(b)
(1) Develop a written integrity management program that addresses the risks on each segment of pipeline in the first column of the following table not later than the date in the second column:
(2) Include in the program an identification of each pipeline or pipeline segment in the first column of the following table not later than the date in the second column:
(3) Include in the program a plan to carry out baseline assessments of line pipe as required by paragraph (c) of this section.
(4) Include in the program a framework that—
(i) Addresses each element of the integrity management program under paragraph (f) of this section, including continual integrity assessment and evaluation under paragraph (j) of this section; and
(ii) Initially indicates how decisions will be made to implement each element.
(5) Implement and follow the program.
(6) Follow recognized industry practices in carrying out this section, unless—
(i) This section specifies otherwise; or
(ii) The operator demonstrates that an alternative practice is supported by a reliable engineering evaluation and provides an equivalent level of public safety and environmental protection.
(c)
(i) The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to assess low frequency electric resistance welded pipe or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies.
(A) Internal inspection tool or tools capable of detecting corrosion and deformation anomalies including dents, gouges and grooves;
(B) Pressure test conducted in accordance with subpart E of this part;
(C) External corrosion direct assessment in accordance with § 195.588; or
(D) Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 90 days before conducting the assessment, by sending a notice to the address or facsimile number specified in paragraph (m) of this section.
(ii) A schedule for completing the integrity assessment;
(iii) An explanation of the assessment methods selected and evaluation of risk factors considered in establishing the assessment schedule.
(2) An operator must document, prior to implementing any changes to the plan, any modification to the plan, and reasons for the modification.
(d)
(1)
(2)
(3)
(ii) An operator must incorporate a new unusually sensitive area into its baseline assessment plan within one year from the date the area is identified. An operator must complete the baseline assessment of any line pipe that could affect the newly-identified high consequence area within five years from the date the area is identified.
(e)
(i) Results of the previous integrity assessment, defect type and size that the assessment method can detect, and defect growth rate;
(ii) Pipe size, material, manufacturing information, coating type and condition, and seam type;
(iii) Leak history, repair history and cathodic protection history;
(iv) Product transported;
(v) Operating stress level;
(vi) Existing or projected activities in the area;
(vii) Local environmental factors that could affect the pipeline (
(viii) geo-technical hazards; and
(ix) Physical support of the segment such as by a cable suspension bridge.
(2) Appendix C of this part provides further guidance on risk factors.
(f)
(1) A process for identifying which pipeline segments could affect a high consequence area;
(2) A baseline assessment plan meeting the requirements of paragraph (c) of this section;
(3) An analysis that integrates all available information about the integrity of the entire pipeline and the consequences of a failure (see paragraph (g) of this section);
(4) Criteria for remedial actions to address integrity issues raised by the assessment methods and information analysis (see paragraph (h) of this section);
(5) A continual process of assessment and evaluation to maintain a pipeline's integrity (see paragraph (j) of this section);
(6) Identification of preventive and mitigative measures to protect the high consequence area (see paragraph (i) of this section);
(7) Methods to measure the program's effectiveness (see paragraph (k) of this section);
(8) A process for review of integrity assessment results and information analysis by a person qualified to evaluate the results and information (see paragraph (h)(2) of this section).
(g)
(1) Information critical to determining the potential for, and preventing, damage due to excavation, including current and planned damage prevention activities, and development or planned development along the pipeline segment;
(2) Data gathered through the integrity assessment required under this section;
(3) Data gathered in conjunction with other inspections, tests, surveillance and patrols required by this Part, including, corrosion control monitoring and cathodic protection surveys; and
(4) Information about how a failure would affect the high consequence area, such as location of the water intake.
(h)
(i)
(ii)
(2)
(3)
(4)
(A) Metal loss greater than 80% of nominal wall regardless of dimensions.
(B) A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)). These documents are incorporated by reference and are available at the addresses listed in § 195.3.
(C) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking or a stress riser.
(D) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter.
(E) An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.
(ii)
(A) A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12).
(B) A dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser.
(iii)
(A) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld.
(B) A dent located on the top of the pipeline (above 4 and 8 o'clock position) with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12).
(C) A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline's diameter.
(D) A calculation of the remaining strength of the pipe shows an operating pressure that is less than the current established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (“Manual for Determining the Remaining Strength of Corroded Pipelines” (1991)) or AGA Pipeline Research Committee Project PR-3-805 (“A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989)). These documents are incorporated by reference and are available at the addresses listed in § 195.3.
(E) An area of general corrosion with a predicted metal loss greater than 50% of nominal wall.
(F) Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld.
(G) A potential crack indication that when excavated is determined to be a crack.
(H) Corrosion of or along a longitudinal seam weld.
(I) A gouge or groove greater than 12.5% of nominal wall.
(iv)
(i)
(2)
(i) Terrain surrounding the pipeline segment, including drainage systems such as small streams and other smaller waterways that could act as a conduit to the high consequence area;
(ii) Elevation profile;
(iii) Characteristics of the product transported;
(iv) Amount of product that could be released;
(v) Possibility of a spillage in a farm field following the drain tile into a waterway;
(vi) Ditches along side a roadway the pipeline crosses;
(vii) Physical support of the pipeline segment such as by a cable suspension bridge;
(viii) Exposure of the pipeline to operating pressure exceeding established maximum operating pressure.
(3)
(4)
(j)
(2)
(3)
(4)
(ii)
(5)
(i) Internal inspection tool or tools capable of detecting corrosion and deformation anomalies including dents, gouges and grooves;
(ii) Pressure test conducted in accordance with subpart E of this part;
(iii) External corrosion direct assessment in accordance with § 195.588; or
(iv) Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify OPS 90 days before conducting the assessment, by sending a notice to the address or facsimile number specified in paragraph (m) of this section.
(k)
(l)
(i) A written integrity management program in accordance with paragraph (b) of this section.
(ii) Documents to support the decisions and analyses, including any modifications, justifications, variances, deviations and determinations made, and actions taken, to implement and evaluate each element of the integrity management program listed in paragraph (f) of this section.
(2) See Appendix C of this part for examples of records an operator would be required to keep.
(m)
(1) Entering the information directly on the Integrity Management Database Web site at
(2) Sending the notification to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., Washington, DC 20590; or
(3) Sending the notification to the Information Resources Manager by facsimile to (202) 366-7128.
By Amdt. 195-87, 72 FR 39017, July 17, 2007, § 195.452 was amended by revising paragraph (h)(4); however, the amendment could not be incorporated due to inaccurate amendatory instruction.
(a) This subpart prescribes the minimum requirements for operator qualification of individuals performing covered tasks on a pipeline facility.
(b) For the purpose of this subpart, a covered task is an activity, identified by the operator, that:
(1) Is performed on a pipeline facility;
(2) Is an operations or maintenance task;
(3) Is performed as a requirement of this part; and
(4) Affects the operation or integrity of the pipeline.
(a) Indicate a condition exceeding design limits; or
(b) Result in a hazard(s) to persons, property, or the environment.
(a) Written examination;
(b) Oral examination;
(c) Work performance history review;
(d) Observation during:
(1) performance on the job,
(2) on the job training, or
(3) simulations;
(e) Other forms of assessment.
(a) Perform assigned covered tasks and
(b) Recognize and react to abnormal operating conditions.
Each operator shall have and follow a written qualification program. The program shall include provisions to:
(a) Identify covered tasks;
(b) Ensure through evaluation that individuals performing covered tasks are qualified;
(c) Allow individuals that are not qualified pursuant to this subpart to perform a covered task if directed and observed by an individual that is qualified;
(d) Evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an accident as defined in Part 195;
(e) Evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task;
(f) Communicate changes that affect covered tasks to individuals performing those covered tasks;
(g) Identify those covered tasks and the intervals at which evaluation of the individual's qualifications is needed;
(h) After December 16, 2004, provide training, as appropriate, to ensure that individuals performing covered tasks have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities; and
(i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the Administrator or state agency has verified that it complies with this section.
Each operator shall maintain records that demonstrate compliance with this subpart.
(a) Qualification records shall include:
(1) Identification of qualified individual(s);
(2) Identification of the covered tasks the individual is qualified to perform;
(3) Date(s) of current qualification; and
(4) Qualification method(s).
(b) Records supporting an individual's current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of five years.
(a) Operators must have a written qualification program by April 27, 2001. The program must be available for review by the Administrator or by a state agency participating under 49 U.S.C. Chapter 601 if the program is under the authority of that state agency.
(b) Operators must complete the qualification of individuals performing covered tasks by October 28, 2002.
(c) Work performance history review may be used as a sole evaluation method for individuals who were performing a covered task prior to October 26, 1999.
(d) After October 28, 2002, work performance history may not be used as a sole evaluation method.
(e) After December 16, 2004, observation of on-the-job performance may not be used as the sole method of evaluation.
This subpart prescribes minimum requirements for protecting steel pipelines against corrosion.
As used in this subpart—
Active corrosion means continuing corrosion which, unless controlled, could result in a condition that is detrimental to public safety or the environment.
You must require and verify that supervisors maintain a thorough knowledge of that portion of the corrosion control procedures established under § 195.402(c)(3) for which they are responsible for insuring compliance.
Except bottoms of aboveground breakout tanks, each buried or submerged pipeline must have an external coating for external corrosion control if the pipeline is—
(a) Constructed, relocated, replaced, or otherwise changed after the applicable date in § 195.401(c), not including the movement of pipe covered by § 195.424; or
(b) Converted under § 195.5 and—
(1) Has an external coating that substantially meets § 195.559 before the pipeline is placed in service; or
(2) Is a segment that is relocated, replaced, or substantially altered.
Coating material for external corrosion control under § 195.557 must—
(a) Be designed to mitigate corrosion of the buried or submerged pipeline;
(b) Have sufficient adhesion to the metal surface to prevent under film migration of moisture;
(c) Be sufficiently ductile to resist cracking;
(d) Have enough strength to resist damage due to handling and soil stress;
(e) Support any supplemental cathodic protection; and
(f) If the coating is an insulating type, have low moisture absorption and provide high electrical resistance.
(a) You must inspect all external pipe coating required by § 195.557 just prior to lowering the pipe into the ditch or submerging the pipe.
(b) You must repair any coating damage discovered.
(a) Each buried or submerged pipeline that is constructed, relocated, replaced, or otherwise changed after the applicable date in § 195.401(c) must have cathodic protection. The cathodic protection must be in operation not later than 1 year after the pipeline is constructed, relocated, replaced, or otherwise changed, as applicable.
(b) Each buried or submerged pipeline converted under § 195.5 must have cathodic protection if the pipeline—
(1) Has cathodic protection that substantially meets § 195.571 before the pipeline is placed in service; or
(2) Is a segment that is relocated, replaced, or substantially altered.
(c) All other buried or submerged pipelines that have an effective external coating must have cathodic protection.
(d) Bare pipelines, breakout tank areas, and buried pumping station piping must have cathodic protection in places where regulations in effect before January 28, 2002 required cathodic protection as a result of electrical inspections. See previous editions of this part in 49 CFR, parts 186 to 199.
(e) Unprotected pipe must have cathodic protection if required by § 195.573(b).
After October 2, 2000, when you install cathodic protection under § 195.563(a) to protect the bottom of an aboveground breakout tank of more than 500 barrels (79.5m
(a)
(b)
(1) Locate the leads at intervals frequent enough to obtain electrical measurements indicating the adequacy of cathodic protection.
(2) Provide enough looping or slack so backfilling will not unduly stress or break the lead and the lead will otherwise remain mechanically secure and electrically conductive.
(3) Prevent lead attachments from causing stress concentrations on pipe.
(4) For leads installed in conduits, suitably insulate the lead from the conduit.
(5) At the connection to the pipeline, coat each bared test lead wire and bared metallic area with an electrical insulating material compatible with the pipe coating and the insulation on the wire.
(c)
Whenever you have knowledge that any portion of a buried pipeline is exposed, you must examine the exposed portion for evidence of external corrosion if the pipe is bare, or if the coating is deteriorated. If you find external
Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained in paragraphs 6.2 and 6.3 of NACE Standard RP 0169 (incorporated by reference,
(a)
(1) Conduct tests on the protected pipeline at least once each calendar year, but with intervals not exceeding 15 months. However, if tests at those intervals are impractical for separately protected short sections of bare or ineffectively coated pipelines, testing may be done at least once every 3 calendar years, but with intervals not exceeding 39 months.
(2) Identify not more than 2 years after cathodic protection is installed, the circumstances in which a close-interval survey or comparable technology is practicable and necessary to accomplish the objectives of paragraph 10.1.1.3 of NACE Standard RP 0169 (incorporated by reference,
(b)
(1) Determine the areas of active corrosion by electrical survey, or where an electrical survey is impractical, by other means that include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment.
(2) For the period in the first column, the second column prescribes the frequency of evaluation.
(c)
(d)
(e)
(a) You must electrically isolate each buried or submerged pipeline from other metallic structures, unless you electrically interconnect and cathodically protect the pipeline and the other structures as a single unit.
(b) You must install one or more insulating devices where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control.
(c) You must inspect and electrically test each electrical isolation to assure the isolation is adequate.
(d) If you install an insulating device in an area where a combustible atmosphere is reasonable to foresee, you must take precautions to prevent arcing.
(e) If a pipeline is in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, you must protect the pipeline against damage from fault currents or lightning and take protective measures at insulating devices.
(a) For pipelines exposed to stray currents, you must have a program to identify, test for, and minimize the detrimental effects of such currents.
(b) You must design and install each impressed current or galvanic anode system to minimize any adverse effects on existing adjacent metallic structures.
(a)
(b)
(1) Use inhibitors in sufficient quantity to protect the entire part of the pipeline system that the inhibitors are designed to protect;
(2) Use coupons or other monitoring equipment to determine the effectiveness of the inhibitors in mitigating internal corrosion; and
(3) Examine the coupons or other monitoring equipment at least twice each calendar year, but with intervals not exceeding 7
(c)
(d)
(a) You must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section.
(b) Coating material must be suitable for the prevention of atmospheric corrosion.
(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you need not protect against atmospheric corrosion any pipeline for which you demonstrate by test, investigation, or experience appropriate to
(1) Only be a light surface oxide; or
(2) Not affect the safe operation of the pipeline before the next scheduled inspection.
(a) You must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows:
(b) During inspections you must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water.
(c) If you find atmospheric corrosion during an inspection, you must provide protection against the corrosion as required by § 195.581.
(a)
(1) Reduce the maximum operating pressure commensurate with the strength of the pipe needed for serviceability based on actual remaining wall thickness; or
(2) Repair the pipe by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe.
(b)
Under § 195.585, you may use the procedure in ASME B31G, “Manual for Determining the Remaining Strength of Corroded Pipelines,” or the procedure developed by AGA/Battelle, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (with RSTRENG disk),” to determine the strength of corroded pipe based on actual remaining wall thickness. These procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations set out in the respective procedures.
(a) If you use direct assessment on an onshore pipeline to evaluate the effects of external corrosion, you must follow the requirements of this section for performing external corrosion direct assessment. This section does not apply to methods associated with direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process.
(b) The requirements for performing external corrosion direct assessment are as follows:
(1)
(2)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a pipeline segment;
(ii) The basis on which you select at least two different, but complementary, indirect assessment tools to assess each ECDA region; and
(iii) If you utilize an indirect inspection method not described in Appendix A of NACE Standard RP0502-2002, you must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method.
(3)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a pipeline segment;
(ii) Criteria for identifying and documenting those indications that must be considered for excavation and direct examination, including at least the following:
(A) The known sensitivities of assessment tools;
(B) The procedures for using each tool; and
(C) The approach to be used for decreasing the physical spacing of indirect assessment tool readings when the presence of a defect is suspected;
(iii) For each indication identified during the indirect examination, criteria for—
(A) Defining the urgency of excavation and direct examination of the indication; and
(B) Defining the excavation urgency as immediate, scheduled, or monitored; and
(iv) Criteria for scheduling excavations of indications in each urgency level.
(4)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a pipeline segment;
(ii) Criteria for deciding what action should be taken if either:
(A) Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE Standard RP0502-2002 provides guidance for criteria); or
(B) Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE Standard RP0502-2002 provides guidance for criteria);
(iii) Criteria and notification procedures for any changes in the ECDA plan, including changes that affect the severity classification, the priority of direct examination, and the time frame for direct examination of indications; and
(iv) Criteria that describe how and on what basis you will reclassify and re-prioritize any of the provisions specified in Section 5.9 of NACE Standard RP0502-2002.
(5)
(i) Measures for evaluating the long-term effectiveness of ECDA in addressing external corrosion in pipeline segments; and
(ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the pipeline segment at an interval less than that specified in Sections 6.2 and 6.3 of NACE Standard RP0502-2002 (see appendix D of NACE Standard RP0502-2002).
(a) You must maintain current records or maps to show the location of—
(1) Cathodically protected pipelines;
(2) Cathodic protection facilities, including galvanic anodes, installed after January 28, 2002; and
(3) Neighboring structures bonded to cathodic protection systems.
(b) Records or maps showing a stated number of anodes, installed in a stated manner or spacing, need not show specific distances to each buried anode.
(c) You must maintain a record of each analysis, check, demonstration, examination, inspection, investigation, review, survey, and test required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist.
In 1979, Congress enacted comprehensive safety legislation governing the transportation of hazardous liquids by pipeline, the Hazardous Liquids Pipeline Safety Act of 1979, 49 U.S.C. 2001
In deciding that an administratively practical approach was necessary in distinguishing between interstate and intrastate liquid pipeline facilities and in determining how best to accomplish this, DOT has logically examined the approach used in the NGPSA. The NGPSA defines the interstate gas pipeline facilities subject to exclusive Federal jurisdiction as those subject to the economic regulatory jurisdiction of the Federal Energy Regulatory Commission (FERC). Experience has proven this approach practical. Unlike the NGPSA however, the HLPSA has no specific reference to FERC jurisdiction, but instead defines interstate liquid pipeline facilities by the more commonly used means of specifying the end points of the transportation involved. For example, the economic regulatory jurisdiction of FERC over the transportation of both gas and liquids by pipeline is defined in much the same way. In implementing the HLPSA DOT has sought a practicable means of distinguishing between interstate and intrastate pipeline facilities that provide the requisite degree of certainty to Federal and State enforcement personnel and to the regulated entities. DOT intends that this statement of agency policy and interpretation provide that certainty.
In 1981, DOT decided that the inventory of liquid pipeline facilities identified as subject to the jurisdiction of FERC approximates the HLPSA category of “interstate pipeline facilities.” Administrative use of the FERC inventory has the added benefit of avoiding the creation of a separate Federal scheme for determination of jurisdiction over the same regulated entities. DOT recognizes that the FERC inventory is only an approximation and may not be totally satisfactory without some modification. The difficulties stem from some significant differences in the economic regulation of liquid and of natural gas pipelines. There is an affirmative assertion of jurisdiction by FERC over natural gas pipelines through the issuance of certificates of public convenience and necessity prior to commencing operations. With liquid pipelines, there is only a rebuttable presumption of jurisdiction created by the filing by pipeline operators of tariffs (or concurrences) for movement of liquids through existing facilities. Although FERC does police the filings for such matters as compliance with the general duties of common carriers, the question of jurisdiction is normally only aired upon complaint. While any person, including State or Federal agencies, can avail themselves of the FERC forum by use of the complaint process, that process has only been rarely used to review jurisdictional matters (probably because of the infrequency of real disputes on the issue). Where the issue has arisen, the reviewing body has noted the need to examine various criteria primarily of an economic nature. DOT believes that, in most cases, the formal FERC forum can better receive and evaluate the type of information that is needed to make decisions of this nature than can DOT.
In delineating which liquid pipeline facilities are interstate pipeline facilities within the meaning of the HLPSA, DOT will generally rely on the FERC filings; that is, if there is a tariff or concurrence filed with FERC governing the transportation of hazardous liquids over a pipeline facility or if there has been an exemption from the obligation to file tariffs obtained from FERC, then DOT will, as a general rule, consider the facility to be an interstate pipeline facility
Pipeline company P operates a pipeline from “Point A” located in State X to “Point B” (also in X). The physical facilities never cross a state line and do not connect with any other pipeline which does cross a state line. Pipeline company P also operates another pipeline between “Point C” in State X and “Point D” in an adjoining State Y. Pipeline company P files a tariff with FERC for transportation from “Point A” to “Point B” as well as for transportation from “Point C” to “Point D.” DOT will ignore filing for the line from “Point A” to “Point B” and consider the line to be intrastate.
Same as in example 1 except that P does not file any tariffs with FERC. DOT will assume jurisdiction of the line between “Point C” and “Point D.”
Same as in example 1 except that P files its tariff for the line between “Point C” and “Point D” not only with FERC but also with State X. DOT will rely on the FERC filing as indication of interstate commerce.
Same as in example 1 except that the pipeline from “Point A” to “Point B” (in State X) connects with a pipeline operated by another company transports liquid between “Point B” (in State X) and “Point D” (in State Y). DOT will rely on the FERC filing as indication of interstate commerce.
Same as in example 1 except that the line between “Point C” and “Point D” has a lateral line connected to it. The lateral is located entirely with State X. DOT will rely on the existence or non-existence of a FERC filing covering transportation over that lateral as determinative of interstate commerce.
Same as in example 1 except that the certified agency in State X has brought an enforcement action (under the pipeline safety laws) against P because of its operation of the line between “Point A” and “Point B”. P has successfully defended against the action on jurisdictional grounds. DOT will assume jurisdiction if necessary to avoid the anomaly of a pipeline subject to neither State or Federal safety enforcement. DOT's assertion of jurisdiction in such a case would be based on the gap in the state's enforcement authority rather than a DOT decision that the pipeline is an interstate pipeline facility.
Pipeline Company P operates a pipeline that originates on the Outer Continental Shelf. P does not file any tariff for that line with FERC. DOT will consider the pipeline to be an interstate pipeline facility.
Pipeline Company P is constructing a pipeline from “Point C” (in State X) to “Point D” (in State Y). DOT will consider the pipeline to be an interstate pipeline facility.
Pipeline company P is constructing a pipeline from “Point C” to “Point E” (both in State X) but intends to file tariffs with FERC in the transportation of hazardous liquid in interstate commerce. Assuming there is some connection to an interstate pipeline facility, DOT will consider this line to be an interstate pipeline facility.
Pipeline Company P has operated a pipeline subject to FERC economic regulation. Solely because of some statutory economic deregulation, that pipeline is no longer regulated by FERC. DOT will continue to consider that pipeline to be an interstate pipeline facility.
As seen from the examples, the types of situations in which DOT will not defer to the FERC regulatory scheme are generally clear-cut cases. For the remainder of the situations where variation from the FERC scheme would require DOT to replicate the forum already provided by FERC and to consider economic factors better left to that agency, DOT will decline to vary its reliance on the FERC filings unless, of course, not doing so would result in situations clearly not intended by the HLPSA.
This Appendix provides guidance on how a risk-based alternative to pressure testing older hazardous liquid and carbon dioxide pipelines rule allowed by § 195.303 will work. This risk-based alternative establishes test priorities for older pipelines, not previously pressure tested, based on the inherent risk of a given pipeline segment. The first step is to
Tables 2-6 give definitions of risk classification A, B, and C facilities. For the purposes of this rule, pipeline segments containing high risk electric resistance-welded pipe (ERW pipe) and lapwelded pipe manufactured prior to 1970 and considered a risk classification C or B facility shall be treated as the top priority for testing because of the higher risk associated with the susceptibility of this pipe to longitudinal seam failures.
In all cases, operators shall annually, at intervals not to exceed 15 months, review their facilities to reassess the classification and shall take appropriate action within two years or operate the pipeline system at a lower pressure. Pipeline failures, changes in the characteristics of the pipeline route, or changes in service should all trigger a reassessment of the originally classification.
Table 1 explains different levels of test requirements depending on the inherent risk of a given pipeline segment. The overall risk classification is determined based on the type of pipe involved, the facility's location, the product transported, the relative volume of flow and pipeline failure history as determined from Tables 2-6.
Using LOCATION, PRODUCT, VOLUME, and FAILURE HISTORY “Indicators” from Tables 3, 4, 5, and 6 respectively, the overall risk classification of a given pipeline or pipeline segment can be established from Table 2. The LOCATION Indicator is the primary factor which determines overall risk, with the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators used to adjust to a higher or lower overall risk classification per the following table.
Table 3 is used to establish the LOCATION Indicator used in Table 2. Based on the population and environment characteristics associated with a pipeline facility's location, a LOCATION Indicator of H, M or L is selected.
Tables 4, 5 and 6 are used to establish the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators respectively, in Table 2. The PRODUCT Indicator is selected from Table 4 as H, M, or L based on the acute and chronic hazards associated with the product transported. The VOLUME Indicator is selected from Table 5 as H, M, or L based on the nominal diameter of the pipeline. The Probability of Failure Indicator is selected from Table 6.
Considerations: The degree of acute and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and, volatility, flammability, and water solubility determine the Product Indicator. Comprehensive Environmental Response, Compensation and Liability Act Reportable Quantity values can be used as an indication of chronic toxicity. National Fire Protection Association health factors can be used for rating acute hazards.
Table 6 is used to establish the PROBABILITY OF FAILURE Indicator used in Table 2. The “Probability of Failure” Indicator is selected from Table 6 as H or L.
This Appendix gives guidance to help an operator implement the requirements of the integrity management program rule in §§ 195.450 and 195.452. Guidance is provided on:
(1) Information an operator may use to identify a high consequence area and factors an operator can use to consider the potential impacts of a release on an area;
(2) Risk factors an operator can use to determine an integrity assessment schedule;
(3) Safety risk indicator tables for leak history, volume or line size, age of pipeline, and product transported, an operator may use to determine if a pipeline segment falls into a high, medium or low risk category;
(4) Types of internal inspection tools an operator could use to find pipeline anomalies;
(5) Measures an operator could use to measure an integrity management program's performance; and
(6) Types of records an operator will have to maintain.
(7) Types of conditions that an integrity assessment may identify that an operator should include in its required schedule for evaluation and remediation.
I. Identifying a high consequence area and factors for considering a pipeline segment's potential impact on a high consequence area.
A. The rule defines a High Consequence Area as a high population area, an other populated area, an unusually sensitive area, or a commercially navigable waterway. The Office of Pipeline Safety (OPS) will map these areas on the National Pipeline Mapping System (NPMS). An operator, member of the public, or other government agency may view and download the data from the NPMS home page
(1) Digital Data on populated areas available on U.S. Census Bureau maps.
(2) Geographic Database on the commercial navigable waterways available on
(3) The Bureau of Transportation Statistics database that includes commercially navigable waterways and non-commercially navigable waterways. The database can be downloaded from the BTS website at
B. The rule requires an operator to include a process in its program for identifying which pipeline segments could affect a high consequence area and to take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. (See §§ 195.452 (f) and (i).) Thus, an operator will need to consider how each pipeline segment could affect a high consequence area. The primary source for the listed risk factors is a US DOT study on instrumented Internal Inspection devices (November 1992). Other sources include the National Transportation Safety Board, the Environmental Protection Agency and the Technical Hazardous Liquid Pipeline Safety Standards Committee. The following list provides guidance to an operator on both the mandatory and additional factors:
(1) Terrain surrounding the pipeline. An operator should consider the contour of the land profile and if it could allow the liquid from a release to enter a high consequence area. An operator can get this information from topographical maps such as U.S. Geological Survey quadrangle maps.
(2) Drainage systems such as small streams and other smaller waterways that could serve as a conduit to a high consequence area.
(3) Crossing of farm tile fields. An operator should consider the possibility of a spillage in the field following the drain tile into a waterway.
(4) Crossing of roadways with ditches along the side. The ditches could carry a spillage to a waterway.
(5) The nature and characteristics of the product the pipeline is transporting (refined products, crude oils, highly volatile liquids, etc.) Highly volatile liquids becomes gaseous when exposed to the atmosphere. A spillage could create a vapor cloud that could settle into the lower elevation of the ground profile.
(6) Physical support of the pipeline segment such as by a cable suspension bridge. An operator should look for stress indicators on the pipeline (strained supports, inadequate support at towers), atmospheric corrosion, vandalism, and other obvious signs of improper maintenance.
(7) Operating conditions of the pipeline (pressure, flow rate, etc.). Exposure of the pipeline to an operating pressure exceeding the established maximum operating pressure.
(8) The hydraulic gradient of the pipeline.
(9) The diameter of the pipeline, the potential release volume, and the distance between the isolation points.
(10) Potential physical pathways between the pipeline and the high consequence area.
(11) Response capability (time to respond, nature of response).
(12) Potential natural forces inherent in the area (flood zones, earthquakes, subsidence areas, etc.)
II. Risk factors for establishing frequency of assessment.
A. By assigning weights or values to the risk factors, and using the risk indicator tables, an operator can determine the priority for assessing pipeline segments, beginning with those segments that are of highest risk, that have not previously been assessed. This list provides some guidance on some of the risk factors to consider (see § 195.452(e)). An operator should also develop factors specific to each pipeline segment it is assessing, including:
(1) Populated areas, unusually sensitive environmental areas, National Fish Hatcheries, commercially navigable waters, areas where people congregate.
(2) Results from previous testing/inspection. (See § 195.452(h).)
(3) Leak History. (See leak history risk table.)
(4) Known corrosion or condition of pipeline. (See § 195.452(g).)
(5) Cathodic protection history.
(6) Type and quality of pipe coating (disbonded coating results in corrosion).
(7) Age of pipe (older pipe shows more corrosion—may be uncoated or have an ineffective coating) and type of pipe seam. (See Age of Pipe risk table.)
(8) Product transported (highly volatile, highly flammable and toxic liquids present a greater threat for both people and the environment) (see Product transported risk table.)
(9) Pipe wall thickness (thicker walls give a better safety margin)
(10) Size of pipe (higher volume release if the pipe ruptures).
(11) Location related to potential ground movement (e.g., seismic faults, rock quarries, and coal mines); climatic (permafrost causes settlement—Alaska); geologic (landslides or subsidence).
(12) Security of throughput (effects on customers if there is failure requiring shutdown).
(13) Time since the last internal inspection/pressure testing.
(14) With respect to previously discovered defects/anomalies, the type, growth rate, and size.
(15) Operating stress levels in the pipeline.
(16) Location of the pipeline segment as it relates to the ability of the operator to detect and respond to a leak. (
(17) Physical support of the segment such as by a cable suspension bridge.
(18) Non-standard or other than recognized industry practice on pipeline installation (
B.
i. For the baseline assessment schedule, we would plan to assess 50% of all pipeline segments covered by the rule, beginning with the highest risk segments, within the first 3
ii. For our hypothetical pipeline segment, we have chosen the following risk factors and obtained risk factor values from the appropriate table. The values assigned to the risk factors are for illustration only.
iii. Overall risk value for this hypothetical segment of pipe is 34. Assume we have two other pipeline segments for which we conduct similar risk rankings. The second pipeline segment has an overall risk value of 20, and the third segment, 11. For the baseline assessment we would establish a schedule where we assess the first segment (highest risk segment) within two years, the second segment within five years and the third segment within seven years. Similarly, for the continuing integrity assessment, we could establish an assessment schedule where we assess the highest risk segment no later than the second year, the second segment no later than the third year, and the third segment no later than the fifth year.
III. Safety risk indicator tables for leak history, volume or line size, age of pipeline, and product transported.
IV. Types of internal inspection tools to use.
An operator should consider at least two types of internal inspection tools for the integrity assessment from the following list. The type of tool or tools an operator selects will depend on the results from previous internal inspection runs, information analysis and risk factors specific to the pipeline segment:
(1) Geometry Internal inspection tools for detecting changes to ovality, e.g., bends, dents, buckles or wrinkles, due to construction flaws or soil movement, or other outside force damage;
(2) Metal Loss Tools (Ultrasonic and Magnetic Flux Leakage) for determining pipe wall anomalies, e.g., wall loss due to corrosion.
(3) Crack Detection Tools for detecting cracks and crack-like features, e.g., stress corrosion cracking (SCC), fatigue cracks, narrow axial corrosion, toe cracks, hook cracks, etc.
V. Methods to measure performance.
A.
(2) An operator should select a set of measurements to judge how well its program is performing. An operator's objectives for its program are to ensure public safety, prevent or minimize leaks and spills and prevent property and environmental damage. A typical integrity management program will be an ongoing program and it may contain many elements. Therefore, several performance measure are likely to be needed to measure the effectiveness of an ongoing program.
B.
(1) Selected Activity Measures—Measures that monitor the surveillance and preventive activities the operator has implemented. These measure indicate how well an operator is implementing the various elements of its integrity management program.
(2) Deterioration Measures—Operation and maintenance trends that indicate when the integrity of the system is weakening despite preventive measures. This category of performance measure may indicate that the system condition is deteriorating despite well executed preventive activities.
(3) Failure Measures—Leak History, incident response, product loss, etc. These measures will indicate progress towards fewer spills and less damage.
C.
(1) Internal—Comparing data from the pipeline segment that could affect the high
(2) External—Comparing data external to the pipeline segment (e.g., OPS incident data) may provide measures on the frequency and size of leaks in relation to other companies.
D.
(1) A performance measurement goal to reduce the total volume from unintended releases by -% (percent to be determined by operator) with an ultimate goal of zero.
(2) A performance measurement goal to reduce the total number of unintended releases (based on a threshold of 5 gallons) by __-% (percent to be determined by operator) with an ultimate goal of zero.
(3) A performance measurement goal to document the percentage of integrity management activities completed during the calendar year.
(4) A performance measurement goal to track and evaluate the effectiveness of the operator's community outreach activities.
(5) A narrative description of pipeline system integrity, including a summary of performance improvements, both qualitative and quantitative, to an operator's integrity management program prepared periodically.
(6) A performance measure based on internal audits of the operator's pipeline system per 49 CFR Part 195.
(7) A performance measure based on external audits of the operator's pipeline system per 49 CFR Part 195.
(8) A performance measure based on operational events (for example: relief occurrences, unplanned valve closure, SCADA outages, etc.) that have the potential to adversely affect pipeline integrity.
(9) A performance measure to demonstrate that the operator's integrity management program reduces risk over time with a focus on high risk items.
(10) A performance measure to demonstrate that the operator's integrity management program for pipeline stations and terminals reduces risk over time with a focus on high risk items.
VI. Examples of types of records an operator must maintain.
The rule requires an operator to maintain certain records. (See § 195.452(l)). This section provides examples of some records that an operator would have to maintain for inspection to comply with the requirement. This is not an exhaustive list.
(1) a process for identifying which pipelines could affect a high consequence area and a document identifying all pipeline segments that could affect a high consequence area;
(2) a plan for baseline assessment of the line pipe that includes each required plan element;
(3) modifications to the baseline plan and reasons for the modification;
(4) use of and support for an alternative practice;
(5) a framework addressing each required element of the integrity management program, updates and changes to the initial framework and eventual program;
(6) a process for identifying a new high consequence area and incorporating it into the baseline plan, particularly, a process for identifying population changes around a pipeline segment;
(7) an explanation of methods selected to assess the integrity of line pipe;
(8) a process for review of integrity assessment results and data analysis by a person qualified to evaluate the results and data;
(9) the process and risk factors for determining the baseline assessment interval;
(10) results of the baseline integrity assessment;
(11) the process used for continual evaluation, and risk factors used for determining the frequency of evaluation;
(12) process for integrating and analyzing information about the integrity of a pipeline, information and data used for the information analysis;
(13) results of the information analyses and periodic evaluations;
(14) the process and risk factors for establishing continual re-assessment intervals;
(15) justification to support any variance from the required re-assessment intervals;
(16) integrity assessment results and anomalies found, process for evaluating and remediating anomalies, criteria for remedial actions and actions taken to evaluate and remediate the anomalies;
(17) other remedial actions planned or taken;
(18) schedule for evaluation and remediation of anomalies, justification to support deviation from required remediation times;
(19) risk analysis used to identify additional preventive or mitigative measures, records of preventive and mitigative actions planned or taken;
(20) criteria for determining EFRD installation;
(21) criteria for evaluating and modifying leak detection capability;
(22) methods used to measure the program's effectiveness.
VII. Conditions that may impair a pipeline's integrity.
Section 195.452(h) requires an operator to evaluate and remediate all pipeline integrity issues raised by the integrity assessment or information analysis. An operator must develop a schedule that prioritizes conditions discovered on the pipeline for evaluation and
A. Any change since the previous assessment.
B. Mechanical damage that is located on the top side of the pipe.
C. An anomaly abrupt in nature.
D. An anomaly longitudinal in orientation.
E. An anomaly over a large area.
F. An anomaly located in or near a casing, a crossing of another pipeline, or an area with suspect cathodic protection.
49 U.S.C. 60105, 60106, 60114; and 49 CFR 1.53.
This part prescribes regulations governing grants-in-aid for State pipeline safety compliance programs.
As used in this part:
The pipeline safety laws (49 U.S.C. 60101
(a) Beginning in calendar year 1993, the Administrator places increasing emphasis on program performance in allocating state agency funds under § 198.11. The maximum percent of each state agency allocation that is based on performance follows: 1993—75 percent; 1994 and subsequent years—100 percent.
(b) A state's annual grant allocation is based on maximum of 100 performance points derived as follows:
(1) Fifty points based on information provided in the state's annual certification/agreement attachments which document its activities for the past year; and
(2) Fifty points based on the annual state program evaluation.
(c) The Administrator assigns weights to various performance factors reflecting program compliance, safety priorities, and national concerns identified by the Administrator and communicated to each State agency. At a minimum, the Administrator considers the following performance factors in allocating funds:
(1) Adequacy of state operating practices;
(2) Quality of state inspections, investigations, and enforcement/compliance actions;
(3) Adequacy of state recordkeeping;
(4) Extent of state safety regulatory jurisdiction over pipeline facilities;
(5) Qualifications of state inspectors;
(6) Number of state inspection person-days;
(7) State adoption of applicable federal pipeline safety standards; and
(8) Any other factor the Administrator deems necessary to measure performance.
(d) Notwithstanding these performance factors, the Administrator may, in 1993 and subsequent years, continue funding any state at the 1991 level, provided its request is at the 1991 level or higher and appropriated funds are at the 1991 level or higher.
(e) The Administrator notifies each state agency in writing of the specific performance factors to be used and the weights to be assigned to each factor at least 9 months prior to allocating funds. Prior to notification, PHMSA seeks state agency comments on any proposed changes to the allocation formula.
(f) Grants are limited to the appropriated funds available. If total state agency requests for grants exceed the funds available, the Administrator prorates each state agency's allocation.
This subpart implements parts of the pipeline safety laws (49 U.S.C. 60101
In allocating grants to State agencies under the pipeline safety laws, (49 U.S.C. 60101
A State must adopt a one-call damage prevention program that requires each of the following at a minimum:
(a) Each area of the State that contains underground pipeline facilities must be covered by a one-call notification system.
(b) Each one-call notification system must be operated in accordance with § 198.39.
(c) Excavators must be required to notify the operational center of the one-call notification system that covers the area of each intended excavation activity and provide the following information:
(1) Name of the person notifying the system.
(2) Name, address and telephone number of the excavator.
(3) Specific location, starting date, and description of the intended excavation activity.
(d) The State must determine whether telephonic and other communications to the operational center of a one-call notification system under paragraph (c) of this section are to be toll free or not.
(e) Except with respect to interstate transmission facilities as defined in the pipeline safety laws (49 U.S.C. 60101
(f) Operators of underground pipeline facilities participating in the one-call notification systems must be required to respond in the manner prescribed by § 192.614 (b)(4) through (b)(6) of this chapter to notices of intended excavation activity received from the operational center of a one-call notification system.
(g) Persons who operate one-call notification systems or operators of underground pipeline facilities participating or required to participate in the one-call notification systems must be required to notify the public and known excavators in the manner prescribed by § 192.614 (b)(1) and (b)(2) of this chapter of the availability and use of one-call notification systems to locate underground pipeline facilities. However, this paragraph does not apply to persons (including operator's master meters) whose primary activity does not include the production, transportation or marketing of gas or hazardous liquids.
(h) Operators of underground pipeline facilities (other than operators of interstate transmission facilities as defined in the pipeline safety laws (49 U.S.C. 60101
A one-call notification system qualifies to operate under this subpart if it complies with the following:
(a) It is operated by one or more of the following:
(1) A person who operates underground pipeline facilities or other underground facilities.
(2) A private contractor.
(3) A State or local government agency.
(4) A person who is otherwise eligible under State law to operate a one-call notification system.
(b) It receives and records information from excavators about intended excavation activities.
(c) It promptly transmits to the appropriate operators of underground pipeline facilities the information received from excavators about intended excavation activities.
(d) It maintains a record of each notice of intent to engage in an excavation activity for the minimum time set by the State or, in the absence of such time, for the time specified in the
(e) It tells persons giving notice of an intent to engage in an excavation activity the names of participating operators of underground pipeline facilities to whom the notice will be transmitted.
49 U.S.C. 5103, 60102, 60104, 60108, 60117, and 60118; 49 CFR 1.53.
This part requires operators of pipeline facilities subject to part 192, 193, or 195 of this chapter to test covered employees for the presence of prohibited drugs and alcohol.
(a) This part applies to pipeline operators only with respect to employees located within the territory of the United States, including those employees located within the limits of the “Outer Continental Shelf “ as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331).
(b) This part does not apply to any person for whom compliance with this part would violate the domestic laws or policies of another country.
(c) This part does not apply to covered functions performed on—
(1) Master meter systems, as defined in § 191.3 of this chapter; or
(2) Pipeline systems that transport only petroleum gas or petroleum gas/air mixtures.
As used in this part—
The anti-drug and alcohol programs required by this part must be conducted according to the requirements of this part and DOT Procedures. Terms and concepts used in this part have the same meaning as in DOT Procedures. Violations of DOT Procedures with respect to anti-drug and alcohol programs required by this part are violations of this part.
(a) Each operator who seeks a waiver under § 40.21 of this title from the stand-down restriction must submit an application for waiver in duplicate to the Associate Administrator for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue, SE, Washington, DC 20590-0001.
(b) Each application must—
(1) Identify § 40.21 of this title as the rule from which the waiver is sought;
(2) Explain why the waiver is requested and describe the employees to be covered by the waiver;
(3) Contain the information required by § 40.21 of this title and any other information or arguments available to support the waiver requested; and
(4) Unless good cause is shown in the application, be submitted at least 60 days before the proposed effective date of the waiver.
(c) No public hearing or other proceeding is held directly on an application before its disposition under this section. If the Associate Administrator determines that the application contains adequate justification, he or she grants the waiver. If the Associate Administrator determines that the application does not justify granting the
(a) Except as provided in paragraph (b) of this section, this part preempts any State or local law, rule, regulation, or order to the extent that:
(1) Compliance with both the State or local requirement and this part is not possible;
(2) Compliance with the State or local requirement is an obstacle to the accomplishment and execution of any requirement in this part; or
(3) The State or local requirement is a pipeline safety standard applicable to interstate pipeline facilities.
(b) This part shall not be construed to preempt provisions of State criminal law that impose sanctions for reckless conduct leading to actual loss of life, injury, or damage to property, whether the provisions apply specifically to transportation employees or employers or to the general public.
The purpose of this subpart is to establish programs designed to help prevent accidents and injuries resulting from the use of prohibited drugs by employees who perform covered functions for operators of certain pipeline facilities subject to part 192, 193, or 195 of this chapter.
(a) Each operator shall maintain and follow a written anti-drug plan that conforms to the requirements of this part and the DOT Procedures. The plan must contain—
(1) Methods and procedures for compliance with all the requirements of this part, including the employee assistance program;
(2) The name and address of each laboratory that analyzes the specimens collected for drug testing;
(3) The name and address of the operator's Medical Review Officer, and Substance Abuse Professional; and
(4) Procedures for notifying employees of the coverage and provisions of the plan.
(b) The Administrator or the State Agency that has submitted a current certification under the pipeline safety laws (49 U.S.C. 60101
(a) An operator may not knowingly use as an employee any person who—
(1) Fails a drug test required by this part and the medical review officer makes a determination under DOT Procedures; or
(2) Refuses to take a drug test required by this part.
(b) Paragraph (a)(1) of this section does not apply to a person who has—
(1) Passed a drug test under DOT Procedures;
(2) Been considered by the medical review officer in accordance with DOT Procedures and been determined by a substance abuse professional to have successfully completed required education or treatment; and
(3) Not failed a drug test required by this part after returning to duty.
Each operator shall conduct the following drug tests for the presence of a prohibited drug:
(a)
(b)
(c)
(2) The Administrator's decision to increase or decrease the minimum annual percentage rate for random drug testing is based on the reported positive rate for the entire industry. All information used for this determination is drawn from the drug MIS reports required by this subpart. In order to ensure reliability of the data, the Administrator considers the quality and completeness of the reported data, may obtain additional information or reports from operators, and may make appropriate modifications in calculating the industry positive rate. Each year, the Administrator will publish in the
(3) When the minimum annual percentage rate for random drug testing is 50 percent, the Administrator may lower this rate to 25 percent of all covered employees if the Administrator determines that the data received under the reporting requirements of § 199.119 for two consecutive calendar years indicate that the reported positive rate is less than 1.0 percent.
(4) When the minimum annual percentage rate for random drug testing is 25 percent, and the data received under the reporting requirements of § 199.119 for any calendar year indicate that the reported positive rate is equal to or greater than 1.0 percent, the Administrator will increase the minimum annual percentage rate for random drug testing to 50 percent of all covered employees.
(5) The selection of employees for random drug testing shall be made by a scientifically valid method, such as a random number table or a computer-based random number generator that is matched with employees' Social Security numbers, payroll identification numbers, or other comparable identifying numbers. Under the selection process used, each covered employee shall have an equal chance of being tested each time selections are made.
(6) The operator shall randomly select a sufficient number of covered employees for testing during each calendar year to equal an annual rate not less than the minimum annual percentage rate for random drug testing determined by the Administrator. If the operator conducts random drug testing through a consortium, the number of employees to be tested may be calculated for each individual operator or may be based on the total number of covered employees covered by the consortium who are subject to random drug testing at the same minimum annual percentage rate under this subpart or any DOT drug testing rule.
(7) Each operator shall ensure that random drug tests conducted under this subpart are unannounced and that the dates for administering random tests are spread reasonably throughout the calendar year.
(8) If a given covered employee is subject to random drug testing under the drug testing rules of more than one DOT agency for the same operator, the employee shall be subject to random
(9) If an operator is required to conduct random drug testing under the drug testing rules of more than one DOT agency, the operator may—
(i) Establish separate pools for random selection, with each pool containing the covered employees who are subject to testing at the same required rate; or
(ii) Randomly select such employees for testing at the highest percentage rate established for the calendar year by any DOT agency to which the operator is subject.
(d)
(e)
(f)
(a) Each operator shall use for the drug testing required by this part only drug testing laboratories certified by the Department of Health and Human Services under the DOT Procedures.
(b) The drug testing laboratory must permit—
(1) Inspections by the operator before the laboratory is awarded a testing contract; and
(2) Unannounced inspections, including examination of records, at any time, by the operator, the Administrator, and if the operator is subject to state agency jurisdiction, a representative of that state agency.
(a)
(b)
(c)
(d)
(e) Evaluation and rehabilitation may be provided by the operator, by a substance abuse professional under contract with the operator, or by a substance abuse professional not affiliated with the operator. The choice of substance abuse professional and assignment of costs shall be made in accordance with the operator/employee agreements and operator/employee policies.
(f) The operator shall ensure that a substance abuse professional, who determines that a covered employee requires assistance in resolving problems with drug abuse, does not refer the covered employee to the substance abuse professional's private practice or to a person or organization from which the substance abuse professional receives remuneration or in which the substance abuse professional has a financial interest. This paragraph does not prohibit a substance abuse professional from referring a covered employee for assistance provided through:
(1) A public agency, such as a State, county, or municipality;
(2) The operator or a person under contract to provide treatment for drug problems on behalf of the operator;
(3) The sole source of therapeutically appropriate treatment under the employee's health insurance program; or
(4) The sole source of therapeutically appropriate treatment reasonably accessible to the employee.
(a) Samples that yield positive results on confirmation must be retained by the laboratory in properly secured, long-term, frozen storage for at least 365 days as required by the DOT Procedures. Within this 365-day period, the employee or the employee's representative, the operator, the Administrator, or, if the operator is subject to the jurisdiction of a state agency, the state agency may request that the laboratory retain the sample for an additional period. If, within the 365-day period, the laboratory has not received a proper written request to retain the sample for a further reasonable period specified in the request, the sample may be discarded following the end of the 365-day period.
(b) If the medical review officer (MRO) determines there is no legitimate medical explanation for a confirmed positive test result other than the unauthorized use of a prohibited drug, and if timely additional testing is requested by the employee according to DOT Procedures, the split specimen must be tested. The employee may specify testing by the original laboratory or by a second laboratory that is certified by the Department of Health and Human Services. The operator may require the employee to pay in advance the cost of shipment (if any) and reanalysis of the sample, but the employee must be reimbursed for such expense if the additional test is negative.
(c) If the employee specifies testing by a second laboratory, the original laboratory must follow approved chain-of-custody procedures in transferring a portion of the sample.
(d) Since some analytes may deteriorate during storage, detected levels of the drug below the detection limits established in the DOT Procedures, but equal to or greater than the established sensitivity of the assay, must, as technically appropriate, be reported and considered corroborative of the original positive results.
(a) Each operator shall provide an employee assistance program (EAP) for its employees and supervisory personnel who will determine whether an employee must be drug tested based on reasonable cause. The operator may establish the EAP as a part of its internal personnel services or the operator
(b) Education under each EAP must include at least the following elements: display and distribution of informational material; display and distribution of a community service hot-line telephone number for employee assistance; and display and distribution of the employer's policy regarding the use of prohibited drugs.
(c) Training under each EAP for supervisory personnel who will determine whether an employee must be drug tested based on reasonable cause must include one 60-minute period of training on the specific, contemporaneous physical, behavioral, and performance indicators of probable drug use.
With respect to those employees who are contractors or employed by a contractor, an operator may provide by contract that the drug testing, education, and training required by this part be carried out by the contractor provided:
(a) The operator remains responsible for ensuring that the requirements of this part are complied with; and
(b) The contractor allows access to property and records by the operator, the Administrator, and if the operator is subject to the jurisdiction of a state agency, a representative of the state agency for the purpose of monitoring the operator's compliance with the requirements of this part.
(a) Each operator shall keep the following records for the periods specified and permit access to the records as provided by paragraph (b) of this section:
(1) Records that demonstrate the collection process conforms to this part must be kept for at least 3 years.
(2) Records of employee drug test that indicate a verified positive result, records that demonstrate compliance with the recommendations of a substance abuse professional, and MIS annual report data shall be maintained for a minimum of five years.
(3) Records of employee drug test results that show employees passed a drug test must be kept for at least 1 year.
(4) Records confirming that supervisors and employees have been trained as required by this part must be kept for at least 3 years.
(b) Information regarding an individual's drug testing results or rehabilitation must be released upon the written consent of the individual and as provided by DOT Procedures. Statistical data related to drug testing and rehabilitation that is not name-specific and training records must be made available to the Administrator or the representative of a state agency upon request.
(a) Each large operator (having more than 50 covered employees) shall submit an annual MIS report to PHMSA of its anti-drug testing using the Management Information System (MIS) form and instructions as required by 49 CFR part 40 (at § 40.25 and appendix H to Part 40), not later than March 15 of each year for the prior calendar year (January 1 through December 31). The Administrator shall require by written notice that small operators (50 or fewer covered employees) not otherwise required to submit annual MIS reports to prepare and submit such reports to PHMSA.
(b) Each report required under this section shall be submitted to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, PHP-60, 1200 New Jersey Avenue, SE., Washington, DC 20590.
(c) To calculate the total number of covered employees eligible for random
(d) As an employer, you may use a service agent (
(e) Each operator that has a covered employee who performs multi-DOT agency functions (
(f) A service agent (
The purpose of this subpart is to establish programs designed to help prevent accidents and injuries resulting from the misuse of alcohol by employees who perform covered functions for operators of certain pipeline facilities subject to parts 192, 193, or 195 of this chapter.
Each operator must maintain and follow a written alcohol misuse plan that conforms to the requirements of this part and DOT Procedures concerning alcohol testing programs. The plan shall contain methods and procedures for compliance with all the requirements of this subpart, including required testing, recordkeeping, reporting, education and training elements.
(a) Except as expressly provided in this subpart, nothing in this subpart shall be construed to affect the authority of operators, or the rights of employees, with respect to the use or possession of alcohol, including authority and rights with respect to alcohol testing and rehabilitation.
(b) Operators may, but are not required to, conduct pre-employment alcohol testing under this subpart. Each operator that conducts pre-employment alcohol testing must—
(1) Conduct a pre-employment alcohol test before the first performance of covered functions by every covered employee (whether a new employee or someone who has transferred to a position involving the performance of covered functions);
(2) Treat all covered employees the same for the purpose of pre-employment alcohol testing (i.e., you must not test some covered employees and not others);
(3) Conduct the pre-employment tests after making a contingent offer of employment or transfer, subject to the employee passing the pre-employment alcohol test;
(4) Conduct all pre-employment alcohol tests using the alcohol testing procedures in DOT Procedures; and
(5) Not allow any covered employee to begin performing covered functions unless the result of the employee's test indicates an alcohol concentration of less than 0.04.
Before performing an alcohol test under this subpart, each operator shall notify a covered employee that the alcohol test is required by this subpart. No operator shall falsely represent that a test is administered under this subpart.
Each operator shall prohibit a covered employee from reporting for duty or remaining on duty requiring the performance of covered functions while having an alcohol concentration of 0.04 or greater. No operator having actual knowledge that a covered employee has an alcohol concentration of 0.04 or greater shall permit the employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee from using alcohol while performing covered functions. No operator having actual knowledge that a covered employee is using alcohol while performing covered functions shall permit the employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee from using alcohol within four hours prior to performing covered functions, or, if an employee is called to duty to respond to an emergency, within the time period after the employee has been notified to report for duty. No operator having actual knowledge that a covered employee has used alcohol within four hours prior to performing covered functions or within the time period after the employee has been notified to report for duty shall permit that covered employee to perform or continue to perform covered functions.
Each operator shall prohibit a covered employee who has actual knowledge of an accident in which his or her performance of covered functions has not been discounted by the operator as a contributing factor to the accident from using alcohol for eight hours following the accident, unless he or she has been given a post-accident test under § 199.225(a), or the operator has determined that the employee's performance could not have contributed to the accident.
Each operator shall require a covered employee to submit to a post-accident alcohol test required under § 199.225(a), a reasonable suspicion alcohol test required under § 199.225(b), or a follow-up alcohol test required under § 199.225(d). No operator shall permit an employee who refuses to submit to such a test to perform or continue to perform covered functions.
Each operator shall conduct the following types of alcohol tests for the presence of alcohol:
(a)
(2)(i) If a test required by this section is not administered within 2 hours following the accident, the operator shall prepare and maintain on file a record stating the reasons the test was not promptly administered. If a test required by paragraph (a) is not administered within 8 hours following the accident, the operator shall cease attempts to administer an alcohol test and shall state in the record the reasons for not administering the test.
(ii) [Reserved]
(3) A covered employee who is subject to post-accident testing who fails to remain readily available for such testing, including notifying the operator or operator representative of his/her location if he/she leaves the scene of the accident prior to submission to such test, may be deemed by the operator to have refused to submit to testing. Nothing in this section shall be construed to require the delay of necessary medical attention for injured people following an accident or to prohibit a covered employee from leaving the scene of an accident for the period necessary to obtain assistance in responding to the accident or to obtain necessary emergency medical care.
(b)
(2) The operator's determination that reasonable suspicion exists to require the covered employee to undergo an alcohol test shall be based on specific, contemporaneous, articulable observations concerning the appearance, behavior, speech, or body odors of the employee. The required observations shall be made by a supervisor who is trained in detecting the symptoms of alcohol misuse. The supervisor who makes the determination that reasonable suspicion exists shall not conduct the breath alcohol test on that employee.
(3) Alcohol testing is authorized by this section only if the observations required by paragraph (b)(2) of this section are made during, just preceding, or just after the period of the work day that the employee is required to be in compliance with this subpart. A covered employee may be directed by the operator to undergo reasonable suspicion testing for alcohol only while the employee is performing covered functions; just before the employee is to perform covered functions; or just after the employee has ceased performing covered functions.
(4)(i) If a test required by this section is not administered within 2 hours following the determination under paragraph (b)(2) of this section, the operator shall prepare and maintain on file a record stating the reasons the test was not promptly administered. If a test required by this section is not administered within 8 hours following the determination under paragraph (b)(2) of this section, the operator shall cease attempts to administer an alcohol test and shall state in the record the reasons for not administering the test. Records shall be submitted to PHMSA upon request of the Administrator.
(ii) [Reserved]
(iii) Notwithstanding the absence of a reasonable suspicion alcohol test under this section, an operator shall not permit a covered employee to report for duty or remain on duty requiring the performance of covered functions while the employee is under the influence of or impaired by alcohol, as shown by the behavioral, speech, or performance indicators of alcohol misuse, nor shall an operator permit the covered employee to perform or continue to perform covered functions, until:
(A) An alcohol test is administered and the employee's alcohol concentration measures less than 0.02; or
(B) The start of the employee's next regularly scheduled duty period, but not less than 8 hours following the determination under paragraph (b)(2) of this section that there is reasonable suspicion to believe that the employee has violated the prohibitions in this subpart.
(iv) Except as provided in paragraph (b)(4)(ii), no operator shall take any action under this subpart against a covered employee based solely on the employee's behavior and appearance in the absence of an alcohol test. This does not prohibit an operator with the authority independent of this subpart from taking any action otherwise consistent with law.
(c)
(d)
(2) Follow-up testing shall be conducted when the covered employee is performing covered functions; just before the employee is to perform covered functions; or just after the employee has ceased performing such functions.
(e)
(a)
(b)
(1)
(2)
(3)
(c)
(1) Records related to the collection process:
(i) Collection log books, if used.
(ii) Calibration documentation for evidential breath testing devices.
(iii) Documentation of breath alcohol technician training.
(iv) Documents generated in connection with decisions to administer reasonable suspicion alcohol tests.
(v) Documents generated in connection with decisions on post- accident tests.
(vi) Documents verifying existence of a medical explanation of the inability of a covered employee to provide adequate breath for testing.
(2) Records related to test results:
(i) The operator's copy of the alcohol test form, including the results of the test.
(ii) Documents related to the refusal of any covered employee to submit to an alcohol test required by this subpart.
(iii) Documents presented by a covered employee to dispute the result of an alcohol test administered under this subpart.
(3) Records related to other violations of this subpart.
(4) Records related to evaluations:
(i) Records pertaining to a determination by a substance abuse professional concerning a covered employee's need for assistance.
(ii) Records concerning a covered employee's compliance with the recommendations of the substance abuse professional.
(5) Record(s) related to the operator's MIS annual testing data.
(6) Records related to education and training:
(i) Materials on alcohol misuse awareness, including a copy of the operator's policy on alcohol misuse.
(ii) Documentation of compliance with the requirements of § 199.231.
(iii) Documentation of training provided to supervisors for the purpose of qualifying the supervisors to make a determination concerning the need for alcohol testing based on reasonable suspicion.
(iv) Certification that any training conducted under this subpart complies with the requirements for such training.
(a) Each large operator (having more than 50 covered employees) shall submit an annual MIS report to PHMSA of its alcohol testing results using the Management Information System (MIS) form and instructions as required by 49 CFR part 40 (at § 40.25 and appendix H to part 40), not later than March 15 of each year for the previous calendar year (January 1 through December 31). The Administrator may require by written notice that small operators (50 or fewer covered employees) not otherwise required to submit annual MIS reports to prepare and submit such reports to PHMSA.
(b) Each operator that has a covered employee who performs multi-DOT agency functions (
(c) Each report required under this section shall be submitted to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, PHP-60, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001.
(d) A service agent (
(a) Except as required by law or expressly authorized or required in this subpart, no employer shall release covered employee information that is contained in records required to be maintained in § 199.227.
(b) A covered employee is entitled, upon written request, to obtain copies of any records pertaining to the employee's use of alcohol, including any records pertaining to his or her alcohol tests. The operator shall promptly provide the records requested by the employee. Access to an employee's records shall not be contingent upon payment for records other than those specifically requested.
(c) Each operator shall permit access to all facilities utilized in complying with the requirements of this subpart to the Secretary of Transportation, any DOT agency, or a representative of a state agency with regulatory authority over the operator.
(d) Each operator shall make available copies of all results for employer alcohol testing conducted under this subpart and any other information pertaining to the operator's alcohol misuse prevention program, when requested by the Secretary of Transportation, any DOT agency with regulatory authority over the operator, or a representative of a state agency with regulatory authority over the operator. The information shall include name-specific alcohol test results, records, and reports.
(e) When requested by the National Transportation Safety Board as part of
(f) An operator shall make records available to a subsequent employer upon receipt of the written request from the covered employee. Disclosure by the subsequent employer is permitted only as expressly authorized by the terms of the employee's written request.
(g) An operator may disclose information without employee consent as provided by DOT Procedures concerning certain legal proceedings.
(h) An operator shall release information regarding a covered employee's records as directed by the specific, written consent of the employee authorizing release of the information to an identified person. Release of such information by the person receiving the information is permitted only in accordance with the terms of the employee's consent.
Except as provided in §§ 199.239 through 199.243, no operator shall permit any covered employee to perform covered functions if the employee has engaged in conduct prohibited by §§ 199.215 through 199.223 or an alcohol misuse rule of another DOT agency.
No operator shall permit a covered employee who has engaged in conduct prohibited by §§ 199.215 through 199.223 to perform covered functions unless the employee has met the requirements of § 199.243.
(a) No operator shall permit a covered employee tested under the provisions of § 199.225, who is found to have an alcohol concentration of 0.02 or greater but less than 0.04, to perform or continue to perform covered functions, until:
(1) The employee's alcohol concentration measures less than 0.02 in accordance with a test administered under § 199.225(e); or
(2) The start of the employee's next regularly scheduled duty period, but not less than eight hours following administration of the test.
(b) Except as provided in paragraph (a) of this section, no operator shall take any action under this subpart against an employee based solely on test results showing an alcohol concentration less than 0.04. This does not prohibit an operator with authority independent of this subpart from taking any action otherwise consistent with law.
(a)
(1) The operator shall ensure that a copy of these materials is distributed to each covered employee prior to start of alcohol testing under this subpart, and to each person subsequently hired for or transferred to a covered position.
(2) Each operator shall provide written notice to representatives of employee organizations of the availability of this information.
(b)
(1) The identity of the person designated by the operator to answer covered employee questions about the materials.
(2) The categories of employees who are subject to the provisions of this subpart.
(3) Sufficient information about the covered functions performed by those employees to make clear what period of the work day the covered employee is required to be in compliance with this subpart.
(4) Specific information concerning covered employee conduct that is prohibited by this subpart.
(5) The circumstances under which a covered employee will be tested for alcohol under this subpart.
(6) The procedures that will be used to test for the presence of alcohol, protect the covered employee and the integrity of the breath testing process, safeguard the validity of the test results, and ensure that those results are attributed to the correct employee.
(7) The requirement that a covered employee submit to alcohol tests administered in accordance with this subpart.
(8) An explanation of what constitutes a refusal to submit to an alcohol test and the attendant consequences.
(9) The consequences for covered employees found to have violated the prohibitions under this subpart, including the requirement that the employee be removed immediately from covered functions, and the procedures under § 199.243.
(10) The consequences for covered employees found to have an alcohol concentration of 0.02 or greater but less than 0.04.
(11) Information concerning the effects of alcohol misuse on an individual's health, work, and personal life; signs and symptoms of an alcohol problem (the employee's or a coworker's); and including intervening evaluating and resolving problems associated with the misuse of alcohol including intervening when an alcohol problem is suspected, confrontation, referral to any available EAP, and/or referral to management.
(c)
Each operator shall ensure that persons designated to determine whether reasonable suspicion exists to require a covered employee to undergo alcohol testing under § 199.225(b) receive at least 60 minutes of training on the physical, behavioral, speech, and performance indicators of probable alcohol misuse.
(a) Each covered employee who has engaged in conduct prohibited by §§ 199.215 through 199.223 of this subpart shall be advised of the resources available to the covered employee in evaluating and resolving problems associated with the misuse of alcohol, including the names, addresses, and telephone numbers of substance abuse professionals and counseling and treatment programs.
(b) Each covered employee who engages in conduct prohibited under §§ 199.215 through 199.223 shall be evaluated by a substance abuse professional who shall determine what assistance, if any, the employee needs in resolving problems associated with alcohol misuse.
(c)(1) Before a covered employee returns to duty requiring the performance of a covered function after engaging in conduct prohibited by §§ 199.215 through 199.223 of this subpart, the employee shall undergo a return-to-duty alcohol test with a result indicating an alcohol concentration of less than 0.02.
(2) In addition, each covered employee identified as needing assistance in resolving problems associated with alcohol misuse—
(i) Shall be evaluated by a substance abuse professional to determine that the employee has properly followed any rehabilitation program prescribed under paragraph (b) of this section, and
(ii) Shall be subject to unannounced follow-up alcohol tests administered by the operator following the employee's return to duty. The number and frequency of such follow-up testing shall be determined by a substance abuse professional, but shall consist of at least six tests in the first 12 months following the employee's return to duty. In addition, follow-up testing
(d) Evaluation and rehabilitation may be provided by the operator, by a substance abuse professional under contract with the operator, or by a substance abuse professional not affiliated with the operator. The choice of substance abuse professional and assignment of costs shall be made in accordance with the operator/employee agreements and operator/employee policies.
(e) The operator shall ensure that a substance abuse professional who determines that a covered employee requires assistance in resolving problems with alcohol misuse does not refer the employee to the substance abuse professional's private practice or to a person or organization from which the substance abuse professional receives remuneration or in which the substance abuse professional has a financial interest. This paragraph does not prohibit a substance abuse professional from referring an employee for assistance provided through—
(1) A public agency, such as a State, county, or municipality;
(2) The operator or a person under contract to provide treatment for alcohol problems on behalf of the operator;
(3) The sole source of therapeutically appropriate treatment under the employee's health insurance program; or
(4) The sole source of therapeutically appropriate treatment reasonably accessible to the employee.
(a) With respect to those covered employees who are contractors or employed by a contractor, an operator may provide by contract that the alcohol testing, training and education required by this subpart be carried out by the contractor provided:
(b) The operator remains responsible for ensuring that the requirements of this subpart and part 40 of this title are complied with; and
(c) The contractor allows access to property and records by the operator, the Administrator, any DOT agency with regulatory authority over the operator or covered employee, and, if the operator is subject to the jurisdiction of a state agency, a representative of the state agency for the purposes of monitoring the operator's compliance with the requirements of this subpart and part 40 of this title.
A list of CFR titles, subtitles, chapters, subchapters and parts and an alphabetical list of agencies publishing in the CFR are included in the CFR Index and Finding Aids volume to the Code of Federal Regulations which is published separately and revised annually.
Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
List of CFR Sections Affected
All changes in this volume of the Code of Federal Regulations that were made by documents published in the
For the period before January 1, 2001, see the “List of CFR Sections Affected, 1949-1963, 1964-1972, 1973-1985, and 1986-2000” published in 11 separate volumes.