CODE OF FEDERAL REGULATIONS49
CONTAINING
A CODIFICATION OF DOCUMENTS
OF GENERAL APPLICABILITY
AND FUTURE EFFECT
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the Office of the Federal Register
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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, and § 172.102 for the Optional Hazardous Materials Table. An Identification Number Cross Reference Index to Proper Shipping Names in §§ 172.101 and 172.102 appears at the beginning of part 172. The Federal Motor Vehicle Safety Standards appear in part 571.
Redesignation tables for chapter X—Surface Transportation Board, Department of Transportation appear in the Finding Aids section of the sixth and seventh volumes.
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33 U.S.C. 1321; 49 U.S.C. 5101-5127, 60101
(a) This part prescribes procedures used by the Research and Special Programs 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 or by registered or certified mail.
(b) Service upon a person's duly authorized representative or agent constitutes service upon that person.
(c) Service by registered or certified mail is complete upon mailing. An official U. S. Postal Service receipt from the registered or certified mailing constitutes prima facie evidence of service.
(a) The Administrator, RSPA, the Chief Counsel, RSPA, or the official designated by the Administrator, RSPA, 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 agent in charge of any office of the person, or by mailing them by registered or certified mail to that agent or representative and the fees are made available prior to the return date.
(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 RSPA 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, RSPA 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, RSPA, 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 RSPA 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 RSPA, 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, Research and Special Programs Administration, 400 7th Street SW., Washington, DC 20590.
(2) For operators seeking a finding or approval involving interstate pipeline transportation, petitions must be sent to the Administrator, Research and Special Programs Administration, 400 7th Street SW., 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 state agency receiving petitions initiated under this section shall provide the Administrator a written recommendation as to the disposition of any petition received by them. Where the Administrator does not reverse or modify a recommendation made by a state agency within 10 business days of its receipt, the recommended disposition shall constitute the Administrator's decision on the petition.
(a)
(2) RSPA'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, RSPA, 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, RSPA 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) When the information obtained from an inspection or from other appropriate sources indicates that further OPS action is warranted, the OPS issues a warning letter under § 190.205 or initiates 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 et seq. or any regulation or order issued thereunder.
(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 § 190.217, the respondent shall have the opportunity to respond under § 190.209.
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.
(a) A request for a hearing provided for in this part must be accompanied by a statement of the issues that the
(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, Research and Special Programs 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, explanations, documents, testimony or other items which are relevant to the issues under consideration.
(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 within 45 days of receipt of the case file, unless it is found impracticable to take action within that time. In cases where it is so found and the delay beyond that period is expected to be substantial, notice of that fact and the date by which it is expected that action will be taken is issued to the respondent.
(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 contain a brief statement of the complaint and an explanation as to why the effectiveness of the final order should be stayed.
(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 within 20 days after receipt of the petition, unless it is found impracticable to take action within that time. In cases where it is so found and delay beyond that period is expected to be substantial, notice of that fact and the date by which it is expected that action will be taken is issued to the respondent.
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
(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 subject 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) 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.
The Associate Administrator, OPS assesses a civil penalty under this part only after considering:
(a) The nature, circumstances and gravity of the violation;
(b) The degree of the respondent's culpability;
(c) The respondent's history of prior offenses;
(d) The respondent's ability to pay;
(e) Any good faith by the respondent in attempting to achieve compliance;
(f) The effect on the respondent's ability to continue in business; and
(g) 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 this case) payable to “U.S. Department of Transportation” to the Federal Aviation Administration, Mike Monroney Aeronautical Center, Financial Operations Division (AMZ-320), 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. Payments, or in the case of wire transfers, notices of payment, must be sent to the Chief, General Accounting
(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 or any interstate pipeline facility (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) 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 Research and Special Programs 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, Research and Special Programs 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 or property, 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 action, as appropriate.
(b) The Associate Administrator, OPS may waive the requirement for notice and 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 or property. However, the Associate Administrator, OPS shall include in the
(c) Notice and hearing:
(1) Written notice that OPS intends to issue an order under this section shall be served in accordance with § 190.5, upon the owner or operator of an alleged hazardous facility. The notice shall allege the existence of a hazardous facility, stating the facts and circumstances supporting the issuance of a “hazardous facility order”, and providing the owner or operator an opportunity for a hearing, identifying the time and location of the hearing.
(2) An owner or operator elects to exercise his opportunity for a hearing under this section, by notifying 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. Absence of such written notification waives an owner or operator's opportunity for a hearing and allows the Associate Administrator, OPS to proceed to issue a “hazardous facility 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, Research and Special Programs Administration, acting as Presiding Official, and conducted without strict adherence to 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 “hazardous facility 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 “hazardous facility 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 to be hazardous to life or property the Associate Administrator, OPS shall issue an order in accordance with this section. If the Associate Administrator, OPS does not find the facility to be hazardous to life or property, the Associate Administrator, OPS shall dismiss the allegations 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 or property; 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 or property, 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 to life or property.
(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), the sequence in which such materials are transported, and the pressure required for such transportation;
(3) The aspects of the 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) The order shall contain the following information:
(1) A finding that the pipeline facility is hazardous to life or property.
(2) The relevant facts which form the basis for that finding.
(3) The legal basis for the order.
(4) The nature and description of particular corrective action required of the respondent.
(5) The date by which the required action must be taken, or completed and, where appropriate, the duration of the order.
(6) If a hearing has been waived pursuant to paragraph (b) of this section, a statement that an opportunity for a hearing is provided at a particular location and at a certain time after issuance of the order.
(g) The Associate Administrator, OPS shall rescind or suspend a hazardous facility order whenever the Associate Administrator, OPS determines that the facility is no longer hazardous to life or property. 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 an 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.
This subpart prescribes general rulemaking procedures for the issue, amendment, and repeal of Pipeline Safety Program regulations of the Research and Special Programs 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 Research and Special Programs Administration at 400 7th Street, SW, Washington, D.C. 20590-0001.
(b) Any person may examine any docketed material at the offices of the Research and Special Programs Administration at any time during regular business hours after the docket is established, except material which the Administrator determines should be withheld from public disclosure under applicable provisions of any statute administered by the Administrator and section 552(b) of Title 5, United States Code, and may obtain a copy of it upon payment of a fee.
Records of the Research and Special Programs 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, Research and Special Programs Administration, U.S. Department of Transportation, 400 7th Street, SW., 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
(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
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 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; or
(2) 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.
(3) On the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator.
As used in this part and the RSPA 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 the Information Resources Manager, Office of Pipeline Safety, Research and Special Programs
(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, general corrosion that has reduced the wall thickness to less than that required for the maximum allowable operating pressure, and localized corrosion pitting to a degree where leakage might result.
(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
(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 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 § 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 Information Officer, Research and Special Programs Administration, Department of Transportation, 400 Seventh Street, SW., Washington, DC 20590.
49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, and 60118; and 49 CFR 1.53.
(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 pipelines 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) 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.
(3) Onshore gathering of gas within inlets of the Gulf of Mexico except as provided in § 192.612.
(4) 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).
(5) On the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator.
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) Transports gas from a gathering line or storage facility to a distribution center, storage facility, or large volume customer that is not downstream from a distribution center;
(b) Operates at a hoop stress of 20 percent or more of SMYS; or
(c) Transports gas within a storage field. 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 Research and Special Programs Administration, 400 Seventh Street, SW., Washington, DC, and at the Office of the Federal Register, 800 North Capitol Street, NW., suite 700, Washington, DC. These materials have been approved for incorporation by reference by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. In addition, the incorporated materials are available from the respective organizations listed in appendix A to this part.
(c) The full titles for the publications incorporated by reference in this part are provided in appendix A to this part. Numbers in parentheses indicate applicable editions. Earlier editions of documents listed or editions of documents formerly listed in previous editions of appendix A may be used for materials and components manufactured, designed, or installed in accordance with those earlier editions or earlier documents at the time they were listed. The user must refer to the appropriate previous edition of 49 CFR for a listing of the earlier listed editions or documents.
Except as provided in §§ 192.1 and 192.150, each operator of a gathering line must comply with the requirements of this part applicable to transmission lines.
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 RSPA 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 that is readied for service after March 12, 1971, or in the case of an
(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 in accordance with § 192.14.
(b) No person may operate a segment of pipeline that is replaced, relocated, or otherwise changed after November 12, 1970, or in the case of an offshore gathering line, after July 31, 1977, unless that replacement, relocation, or change has been made in accordance with 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 participating under 49 U.S.C. 60105 or 60106:
(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
(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 river crossing headers) or is used within five pipe diameters in any direction from the last fitting of a fabricated assembly, other than a transition piece or an elbow used in place of a pipe bend which is not associated with a fabricated assembly.
(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.
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 determined in accordance with either of the following formulas:
(a) The design pressure may not exceed a gauge pressure of 689 kPa (100 psig) 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 long-term hydrostatic strength used in the design formula under § 192.121 is determined. However, if the pipe was manufactured before May 18, 1978 and its long-term hydrostatic strength was determined at 73°F (23°C), it may be used at temperatures up to 100°F (38°C).
(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:
(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.
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.
Notwithstanding any requirement of this subpart which incorporates by reference an edition of a document listed in appendix A 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 appendix A:
(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, or equivalent, of API 6D. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those requirements.
(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 line section of a transmission line 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 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 pipelines, other than transmission lines 10 inches (254 millimeters) or greater in nominal diameter, that transport gas to onshore facilities; 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
(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 closures and fish tails may not be used on pipe that either operates at 100 p.s.i. (689 kPa) gage, or more, or is more than 3 inches (76 millimeters) nominal diameter.
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 minimum clearance from the fence as follows:
(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 under 60 p.s.i. (414 kPa) gage 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. This device may be either a relief valve or an automatic shutoff that shuts, if the pressure on the inlet of the service regulator exceeds the set pressure (60 p.s.i. (414 kPa) gage or less), and remains closed until manually reset.
(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
(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 maximum allowable operating pressure plus 6 p.s.i. (41 kPa) gage; or
(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
(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 to produce welds meeting the requirements of this subpart. The quality of the test welds used to qualify the procedure shall be determined by destructive testing.
(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 3 of API Standard 1104 or section IX of the ASME Boiler and Pressure Vessel Code. However, a welder qualified under an earlier edition than listed in appendix A 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
(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 section 3 or 6 of API Standard 1104, except that a welder qualified under an earlier edition previously listed in Appendix A of this part may weld but may not requalify under that earlier edition; and
(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 to insure 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
(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 6 of API Standard 1104. However, if a girth weld is unacceptable under those standards for a reason other than a crack, and if the Appendix to API Standard 1104 applies to the weld, the acceptability of the weld may be further determined under that Appendix.
(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 Pressure (Quick Burst)) of ASTM D 2513;
(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; or
(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.
(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 nonlateral pipe connections, follow the tensile test requirements of ASTM D638, except that the test may be conducted at ambient temperature and humidity. If the specimen elongates no less than 25 percent or failure initiates outside the joint area, the procedure qualifies for use.
(b)
(1) Use an apparatus for the test as specified in ASTM D 638 (except for conditioning).
(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
(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 his system is qualified in accordance with this section.
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:
(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 pipe must be removed by cutting out the damaged portion as a cylinder.
Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired by a patching saddle 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 unless otherwise permitted by paragraph (g) 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 conductive wire or other means of locating the pipe while it is underground.
(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
(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.
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 (1219 millimeters) in soil or 24 inches (610 millimeters) in consolidated rock between the top of the pipe and the natural bottom.
(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).
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 of a building, must be installed in a readily accessible location and be protected from corrosion and other damage. 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
(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 above grade, terminating in a rain and insect resistant fitting.
(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
(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]
Notwithstanding the date the pipeline was installed or any earlier deadlines for compliance, each pipeline which qualifies for use under this part in accordance with § 192.14 must meet the requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, and all other applicable requirements within 1 year after the pipeline is readied for service. However, the requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply if the pipeline substantially meets those requirements before it is readied for service or it is a segment which is replaced, relocated, or substantially altered.
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
(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. The operator shall determine the areas of active corrosion by electrical survey, or where electrical survey is impractical, by the study of corrosion and leak history records, by leak detection survey, or by other means.
(c) For the purpose of this subpart, active corrosion means continuing corrosion which, unless controlled, could result in a condition that is detrimental to public safety.
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 is found, remedial action must be taken to the extent required by § 192.483 and the applicable paragraphs of §§ 192.485, 192.487, or 192.489.
(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
(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 paragraphs (b) and (c) of § 192.455 and paragraph (b) of § 192.457, each operator shall, at intervals not exceeding 3 years, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator shall determine the areas of active corrosion by electrical survey, or where electrical survey is impractical, by the study of corrosion and leak history records, by leak detection survey, or by other means.
(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
(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
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)
(b)
(1) Determine the areas of atmospheric corrosion on the pipeline;
(2) If atmospheric corrosion is found, take remedial measures to the extent required by the applicable paragraphs of §§ 192.485, 192.487, or 192.489; and
(3) Clean and either coat or jacket the areas of atmospheric corrosion on the pipeline with a material suitable for the prevention of atmospheric corrosion.
After meeting the requirements of § 192.479 (a) and (b), each operator shall, at intervals not exceeding 3 years for onshore pipelines and at least once each calendar year, but with intervals not exceeding 15 months, for offshore pipelines, reevaluate each pipeline that is exposed to the atmosphere and take remedial action whenever necessary to maintain protection against atmospheric corrosion.
(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
(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)
(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
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; or
(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.
(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
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
(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.
Each operator shall make, and retain for the useful life of the pipeline, a record of each test performed under §§ 192.505 and 192.507. The record must contain at least the following information:
(a) The operator's name, the name of the operator's employee responsible for making the test, and the name of any test company used.
(b) Test medium used.
(c) Test pressure.
(d) Test duration.
(e) Pressure recording charts, or other record of pressure readings.
(f) Elevation variations, whenever significant for the particular test.
(g) Leaks and failures noted and their disposition.
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
(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 pressure the highest pressure to which the segment of pipeline was previously subjected (either in a strength test or in actual operation).
(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
(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
(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.
(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,
(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, 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.
(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
(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 times the test pressure for Class 4 locations.
(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.
(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 18 months of the change in class location. Pressure reduction under paragraph (a) (1) or (2) of this section within the 18-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, in accordance with this section, conduct an underwater inspection of its pipelines in the Gulf of Mexico and its inlets. The inspection must be conducted after October 3, 1989 and before November 16, 1992.
(b) If, as a result of an inspection under paragraph (a) of this section, or upon notification by any person, an operator discovers that a pipeline it operates is exposed on the seabed or constitutes 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 the discovery is made, place the pipeline 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) 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
(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 possible, 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.
Each operator shall establish a continuing educational program to enable customers, the public, appropriate government organizations, and persons engaged in excavation related activities to recognize a gas pipeline emergency for the purpose of reporting it to the operator or the appropriate public officials. The program and the media used must be as comprehensive as necessary to reach all areas in which the operator transports gas. 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.
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) Except as provided in paragraph (c) of this section, no person may operate a segment of steel or plastic pipeline at a pressure that exceeds 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 the design formula (§ 192.105) is 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 factor in paragraph (a)(2)(ii) of this section; or
(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 July 1, 1970 (or in the case of offshore gathering lines, July 1, 1976), unless the segment was tested in accordance with paragraph (a)(2) of this section after July 1, 1965 (or in the case of offshore gathering lines, July 1, 1971), or the segment was uprated in accordance with 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) Notwithstanding the other requirements of this section, 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 July 1, 1970, or in the case of offshore gathering lines, July 1, 1976, subject to the requirements of § 192.611.
For
(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 detectable by a person with a normal sense of smell.
(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) Each operator shall conduct periodic sampling of combustible gases to assure the proper concentration of odorant in accordance with this section. 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(a)(3), no operator may use a welded patch as a means of repair.
(a) Except as provided in paragraph (b) of this section, each imperfection or damage that impairs the serviceability of a segment of steel transmission line operating at or above 40 percent of SMYS must be repaired as follows:
(1) If it is feasible to take the segment out of service, the imperfection or damage must be removed by cutting out a cylindrical piece of pipe and replacing it with pipe of similar or greater design strength.
(2) If it is not feasible to take the segment out of service, a full encirclement welded split sleeve of appropriate design must be applied over the imperfection or damage.
(3) If the segment is not taken out of service, the operating pressure must be reduced to a safe level during the repair operations.
(b) Submerged offshore pipelines and submerged pipelines in inland navigable waters may be repaired by mechanically applying a full encirclement
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.
(a) Except as provided in paragraph (b) of this section, each permanent field repair of a leak on a transmission line must be made as follows:
(1) If feasible, the segment of transmission line must be taken out of service and repaired by cutting out a cylindrical piece of pipe and replacing it with pipe of similar or greater design strength.
(2) If it is not feasible to take the segment of transmission line out of service, repairs must be made by installing a full encirclement welded split sleeve of appropriate design, unless the transmission line:
(i) Is joined by mechanical couplings; and
(ii) Operates at less than 40 percent of SMYS.
(3) If the leak is due to a corrosion pit, the repair may be made by installing a properly designed bolt-on-leak clamp; or, if the leak is due to a corrosion pit and on pipe of not more than 40,000 p.s.i. (267 MPa) gage SMYS, the repair may be made by fillet welding over the pitted area a steel plate patch with rounded corners, of the same or greater thickness than the pipe, and not more than one-half of the diameter of the pipe in size.
(b) Submerged offshore pipelines and submerged pipelines in inland navigable waters may be repaired by mechanically applying a full encirclement split sleeve of appropriate design over the leak.
(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 intervals not exceeding 5 years. However, for cathodically unprotected distribution lines subject to § 192.465(e) on which electrical surveys for corrosion are impractical, survey intervals may not exceed 3 years.
(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.
(a) Except for rupture discs, each pressure relieving device in a compressor station must be inspected and tested in accordance with §§ 192.739 and 192.743, and must be operated periodically to determine that it opens at the correct set pressure.
(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.
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—
(a) In good mechanical condition;
(b) Adequate from the standpoint of capacity and reliability of operation for the service in which it is employed;
(c) Set to function at the correct pressure; and
(d) Properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation.
(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 the necessity of installing telemetering or recording gauges in the district, taking into consideration the number of customers supplied, the operating pressures, the capacity of the installation, and other operating conditions.
(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) If feasible, pressure relief devices (except rupture discs) must be tested in place, at intervals not exceeding 15 months, but at least once each calendar year, to determine that they have enough capacity to limit the pressure on the facilities to which they are connected to the desired maximum pressure.
(b) If a test is not feasible, review and calculation of the required capacity of the relieving device at each station must be made at intervals not exceeding 15 months, but at least once each calendar year, and these required capacities compared with the rated or experimentally determined relieving capacity of the device for the operating conditions under which it works. After the initial calculations, subsequent calculations are not required if the review documents that parameters have not changed in a manner which would cause the capacity to be less than required.
(c) If the relieving device is of insufficient capacity, a new or additional device must be installed to provide the additional capacity required.
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.
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.
(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 25 p.s.i. (172 kPa) gage or more 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 less than 25 p.s.i. (172 kPa) gage 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. American Gas Association (AGA), 1515 Wilson Boulevard, Arlington, VA 22209.
B. American National Standards Institute (ANSI), 11 West 42nd Street, New York, NY 10036.
C. American Petroleum Institute (API), 1220 L Street, NW., Washington, DC 20005.
D. The American Society of Mechanical Engineers (ASME), United Engineering Center, 345 East 47th Street, New York, NY 10017.
E. American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, West Conshohocken, PA 19428.
F. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park Street, NW., Vienna, VA 22180.
G. National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O. 9101, Quincy, MA 02269-9101.
A. American Gas Association (AGA):
(1). AGA Pipeline Research Committee, Project PR-3-805, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 22, 1989).
B. American Petroleum Institute (API):
(1) API Specification 5L “Specification for Line Pipe (41st edition, 1995).
(2). API Recommended Practice 5L1 “Recommended Practice for Railroad Transportation of Line Pipe” (4th edition, 1990).
(3) API Specification 6D “Specification for Pipeline Valves (Gate, Plug, Ball, and Check Valves)” (21st edition, 1994).
(4) API Standard 1104 “Welding of Pipelines and Related Facilities” (18th edition, 1994).
C. American Society for Testing and Materials (ASTM):
(1) ASTM Designation: A 53 “Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless” (A53-96).
(2) ASTM Designation A 106 “Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service” (A106-95).
(3) ASTM Designation: A 333/A 333M “Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service” (A 333/A 333M-94).
(4) ASTM Designation: A 372/A 372M “Standard Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure Vessels” (A 372/A 372M-95).
(5) ASTM Designation: A 381 “Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems (A 381-93).
(6) ASTM Designation: A 671 “Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures” (A 671-94).
(7) ASTM Designation: A 672 “Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures” (A 672-94).
(8) ASTM Designation A 691 “Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High- Pressure Service at High Temperatures” (A 691-93).
(9) ASTM Designation D638 “Standard Test Method for Tensile Properties of Plastics” (D638-96).
(10) ASTM Designation D2513 “Standard Specification for Thermoplastic Gas Pressure Pipe, Tubing and Fittings” (D 2513-87 edition for § 192.63(a)(1), otherwise D 2513-96a).
(11) ASTM Designation D 2517 “Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings” (D 2517-94).
(12) ASTM Designation: F1055 “Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing” (F1055-95).
D. The American Society of Mechanical Engineers (ASME):
(1) ASME/ANSI B16.1 “Cast Iron Pipe Flanges and Flanged Fittings” (1989).
(2) ASME/ANSI B16.5 “Pipe Flanges and Flanged Fittings” (1988 with October 1988 Errata and ASME/ANSI B16.5a-1992 Addenda).
(3) ASME/ANSI B31G “Manual for Determining the Remaining Strength of Corroded Pipelines” (1991).
(4) ASME/ANSI B31.8 “Gas Transmission and Distribution Piping Systems” (1995).
(5) ASME Boiler and Pressure Vessel Code, Section I “Power Boilers” (1995 edition with 1995 Addenda).
(6) ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 “Pressure Vessels” (1995 edition with 1995 Addenda).
(7) ASME Boiler and Pressure Vessel Code, Section VIII, Division 2 “Pressure Vessels: Alternative Rules” (1995 edition with 1995 Addenda).
(8) ASME Boiler and Pressure Vessel Code, Section IX “Welding and Brazing Qualifications” (1995 edition with 1995 Addenda).
E. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS):
1. MSS SP44-96 “Steel Pipe Line Flanges” (includes 1996 errata) (1996).
2. [Reserved]
F. National Fire Protection Association (NFPA):
(1) NFPA 30 “Flammable and Combustible Liquids Code” (1996).
(2) ANSI/NFPA 58 “Standard for the Storage and Handling of Liquefied Petroleum Gases” (1995).
(3) ANSI/NFPA 59 “Standard for the Storage and Handling of Liquefied Petroleum Gases at Utility Gas Plants” (1995).
(4) ANSI/NFPA 70 “National Electrical Code” (1996).
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, except that the number of tests must be at least equal to the minimum required in paragraph II-D of this appendix to determine yield strength.
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.
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 bending test prescribed in subparagraph (1) of this paragraph.
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
(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 equivalent referred to a saturated copper-copper sulfate half cell is established.
49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109, 60110, 60113, 60118; and 49 CFR 1.53.
(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
(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)).
An LNG facility used in the transportation or storage of LNG in a semisolid state need not comply with any requirement of this part which the Director finds impractical or unnecessary because of the semisolid state of LNG. In making such a finding, the Director may impose appropriate alternative safety conditions.
(a) New or amended standards in this part governing the siting, design, installation, or construction of an LNG facility and related personnel qualifications and training do not apply to:
(1) LNG facilities under construction before the date such standards are published; or
(2) LNG facilities for which an application for approval of the siting, construction, or operation was filed before March 1, 1978, with the Department of Energy (or any predecessor organization of that Department) or the appropriate State or local agency in the case of any facility not subject to the jurisdiction of the Department of Energy under the Natural Gas Act (not including any facility the construction of which began after November 29, 1979, not pursuant to such an approval).
(b) If an LNG facility listed in paragraph (a) of this section is replaced, relocated, or significantly altered after February 11, 1980, the replacement, relocated facility, or significantly altered 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, not pursuant to an application for approval filed as provided by paragraph (a)(2) of this section before March 1, 1978; and
(2) To the extent compliance with the design, installation, and construction requirements would make the replaced, relocated, or altered facility incompatible with other facilities or would otherwise be impracticable, the replaced, relocated, or significantly altered facility may be designed, installed, or constructed in accordance with the original specifications for the facility, or in a manner that the Director finds acceptable.
(c) The siting, design, installation, and construction of an LNG facility under construction before February 11, 1980, or that is listed in paragraph (a)(2) of this section (except a facility under construction before July 1, 1976) must meet the applicable requirements of ANSI/NFPA 59A (1972 edition) and part 192 of this chapter or the applicable requirements of this part, except that no part 192 standard issued after March 1, 1978, applies to an LNG facility listed in paragraph (a)(2) of this section.
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) There are incorporated by reference in this part all materials referred to in this part that are not set forth in full. The incorporated materials are deemed published under 5 U.S.C. 552(a) and 1 CFR part 51 and are part of this regulation as though set forth in full. All incorporated materials are listed in appendix A to this part 193 with the applicable editions in parentheses following the title of the referenced material. Only the latest listed edition applies, except that an earlier listed edition may be followed with respect to components which are designed, manufactured, or installed in accordance with the earlier edition before the latest edition is adopted, unless otherwise provided in this part. The incorporated materials are subject to change, but any change will be announced by publication in the
(b) All incorporated materials are available for inspection in the Research and Special Programs Administration, 400 Seventh Street, SW., Washington, DC, and at the Office of the Federal Register, 800 North Capitol Street, NW., suite 700, Washington, DC. These materials have been approved for incorporation by reference by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. In addition, the incorporated materials are available from the respective organizations listed in appendix A to this part.
(c) Incorporated by reference provisions approved by the Director of the Federal Register.
(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
(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.
(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 (1996 edition).
(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 access, except that in the case of emergency where such notice is not possible, as much advance notice as possible must be provided.
This subpart prescribes siting requirements for the following LNG facilities: Containers and their impounding systems, transfer systems and their impounding systems, emergency shutdown control systems, fire control systems, and associated foundations, support systems, and normal or auxiliary power facilities necessary to maintain safety.
An LNG facility must be located at a site of suitable size, topography, and configuration so that the facility can be designed to minimize the hazards to persons and offsite property resulting from leaks and spills of LNG and other hazardous fluids at the site. In selecting a site, each operator shall determine all site-related characteristics which could jeopardize the integrity and security of the facility. A site must provide ease of access so that personnel, equipment, and materials from offsite locations can reach the site for fire fighting or controlling spill associated hazards or for evacuation of personnel.
(a)
(1) Within the thermal exclusion zone, the impounding system may not be located closer to targets listed in paragraph (d) of this section than the exclusion distance “d” determined according to this section, unless the target is a pipeline facility of the operator.
(2) If grading and drainage are used under § 193.2149(b), operators must comply with the requirements of this section by assuming the space needed for drainage and collection of spilled liquid is an impounding system.
(b)
(1) The maximum calculated exclusion distance for each thermal flux level shall be used for that exposure (offsite target) in paragraph (d) of this section.
(2) 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.
(3) The ambient temperature and relative humidity that produce the maximum exclusion distance shall be used except that values that occur less than 5 percent of the time based on recorded data for the area shall not be used.
(4) Properties of LNG with the highest anticipated heating value shall be used.
(5) The height of the flame base should be that of any dike or containment in relation to the horizontal reference plane. The height of the target shall be in relation to the same reference plane.
(c)
(1) The method of calculating the exclusion distances for levels of radiant exposure listed in paragraph (d) of this section shall be the method described in Gas Research Institute report GRI-89/0176 and also available as the “LNGFIRE” computer program from GRI.
(2) Determine “d” from a mathematical model for thermal radiation and other appropriate fire characteristics which assures that the incident thermal flux levels in paragraph (d) of this section are not exceeded. The model must:
(i) Use atmospheric conditions which, if applicable, result in longer exclusion distances than other atmospheric conditions occurring at least 95 percent of the time based on recorded data for the site area;
(ii) Have been evaluated and verified by testing at a scale, considering scaling effects, appropriate for the range of application;
(iii) Have been submitted to the Administrator for approval, with supportive data as necessary to demonstrate validity; and
(iv) Have received approval by the Administrator.
(d)
(a)
(1) Outdoor areas occupied by 20 or more persons during normal use, such
(2) Buildings that are:
(i) Used for residences;
(ii) Occupied by 20 or more persons during normal use;
(iii) Contain explosive, flammable, or toxic materials in hazardous quantities;
(iv) Have exceptional value or contain objects of exceptional value based on historic uniqueness described in Federal, State, or local registers; or
(v) Could result in additional hazard if exposed to a vapor-gas cloud.
(b)
(c)
(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 U.S. Government weather data, or as an alternative where the model used gives longer distances at lower wind speeds, Category F atmosphere, wind speed = 4.5 miles/hour (7.2 km/hour), relative humidity equals 50.0 percent, and atmospheric temperatures = 0.0 C.
(3) Dispersion coordinates y, z, and H, where applicable, = 0.
(4) A surface roughness factor of 3 cm 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.
(d)
(1) Vaporization results from the spill caused by an assumed rupture of a single transfer pipe (or multiple pipes that lack provisions to prevent parallel flow) which has the greatest overall flow capacity, discharging at maximum potential capacity, in accordance with the following conditions:
(i) The rate of vaporization is not less than the sum of flash vaporization and vaporization from boiling by heat transfer from contact surfaces during the time necessary for spill detection, instrument response, and automatic shutdown by the emergency shutdown system, but not less than 10 minutes, plus, in the case of impounding systems for LNG storage tanks with side or bottom penetrations, the time necessary for the liquid level in the tank to reach the level of the penetration or equilibrate with the liquid impounded assuming failure of the internal shutoff valve.
(ii) In determining variations in the vaporization rate due to surface contact, the time necessary to wet 100 percent of the impounding floor area shall be determined by equation C-9 in the 1974 AGA report titled “Evaluation of LNG Vapor Control Methods,” or by using an equivalent personal computer program based on equation C-9 or by an alternative model which meets the requirements of § 193.2057(c)(2)(ii) through (iv).
(iii) After spill flow is terminated, the rate of vaporization is vaporization of the remaining spillage, if any, from boiling by heat transfer from contact surfaces that are reducing in area and temperature as a function of time.
(iv) Vapor detention space is all space provided for liquid impoundment and vapor detention outside the component served, less the volume occupied by the spilled liquid at the time the
(2) The boiling rate of LNG on which dispersion distance is based is determined using the weighted average value of the thermal properties of the contact surfaces in the impounding space determined from eight representative experimental tests on the materials involved. If surfaces are insulated, the insulation must be designed, installed, and maintained so that it will retain its performance characteristics under spill conditions.
(e)
(a) Except for shop fabricated storage tanks of 70,000 gallons (265,000 liters) or less capacity mounted within 2 feet of the ground, if an LNG facility is located at a site in Zone 0 or 1 of the “Seismic Risk Map of the United States,” UBC, each operator shall determine, based on a study of faults, hydrologic regime, and soil conditions, whether a potential exists at the site for surface faulting or soil liquefaction.
(b) Subject to paragraph (f) of this section, LNG facilities must be designed and built to withstand, without loss of structural or functional integrity, the following seismic design forces, as applicable:
(1) For LNG facilities (other than shop fabricated storage tanks of 70,000 gallons (265,000 liters) or less capacity mounted within 2 feet (610 millimeters) of the ground) located at a site in Puerto Rico in Zone 2, 3, or 4 of the “Seismic Risk Map of the United States,” or at a site determined under paragraph (a) of this section to have a potential for surface faulting or soil liquefaction, the forces that could reasonably be expected to occur at the foundation of the facility due to the most critical ground motion, motion amplification, permanent differential ground displacement, soil liquefaction, and symmetric and asymmetric reaction forces resulting from hydrodynamic pressure and motion of contained liquid in interaction with the facility structure.
(2) For all other LNG facilities, the total lateral force set forth in UBC, Volume 1, corresponding to the zone of the “Seismic Risk Map of the United States” in which the facility is located, and a vertical force equal to the total lateral force.
(c) Each operator of an LNG facility to which paragraph (b)(1) of this section applies shall determine the seismic design forces on the basis of a detailed geotechnical investigation and in accordance with paragraphs (d) and (e) of this section. The investigation must include each of the following items that could reasonably be expected to affect the site and be sufficient in scope to identify all hazards that could reasonably be expected to affect the facility design:
(1) Identification and evaluation of faults, Quaternary activity of those faults, tectonic structures, static and dynamic properties of materials underlying the site, and, as applicable, tectonic provinces within 100 miles of the site;
(2) Identification and evaluation of all historically reported earthquakes which could affect the determination under this section of the most critical ground motion or differential displacement at the site when correlated with particular faults, tectonic structures, and tectonic provinces, as applicable; and
(3) Identification and evaluation of the hydrologic regime and the potential of liquefaction-induced soil failures.
(d) The most critical ground motion must be determined in accordance with paragraph (e) of this section either:
(1) Probabilistically, when the available earthquake data are sufficient to show that the yearly probability of exceedance of most critical ground motion is 10
(2) Deterministically, when the available earthquake data are insufficient to provide probabilistic estimates, with the objective of determining a most critical ground motion with a yearly probability of exceedance of 10
(e) The determination of most critical ground motion, considering local and regional seismological conditions, must be made by using the following:
(1) A regionally appropriate attenuation relationship, assuming that earthquakes occur at a location on a fault, tectonic structure, or tectonic province, as applicable, which would cause the most critical seismic movement at the site, except that where epicenters of historically reported earthquakes cannot be reasonably related to known faults or tectonic structures, but are recognized as being within a specific tectonic province which is within 100 miles (161 kilometers) of the site, assume that those earthquakes occur within their respective provinces at a source closest to the site.
(2) A horizontal design response spectrum determined from the mean plus one standard deviation of a free-field horizontal elastic response spectra whose spectral amplitudes are consistent with values expected for the most critical ground motion.
(3) A vertical design response spectrum that is either two-thirds of the amplitude of the horizontal design response spectrum at all frequencies or equal to the horizontal design response spectrum where the site is located within 10 miles (16 kilometers) of the earthquake source.
(f) An LNG storage tank or its impounding system may not be located at a site where an investigation under paragraph (c) of this section shows that any of the following conditions exists unless the Administrator grants an approval for the site:
(1) The estimated design horizontal acceleration exceeds 0.8g at the tank or dike foundation.
(2) The specific local geologic and seismic data base is sufficient to predict future differential surface displacement beneath the tank and dike area, but displacement not exceeding 30 inches (762 millimeters) cannot be assured with a high level of confidence.
(3) The specific local geologic and seismic data base is not sufficient to predict future differential surface displacement beneath the tank and dike area, and the estimated cumulative displacement of a Quaternary fault within 1 mile (1.6 kilometers) of the tank foundation exceeds 60 inches (1.5 meters).
(4) The potential for soil liquefaction cannot be accommodated by design and construction in accordance with paragraph (b)(1) of this section.
(g) An application for approval of a site under paragraph (f) of this section must provide at least the following:
(1) A detailed analysis and evaluation of the geologic and seismic characteristics of the site based on the geotechnical investigation performed under paragraph (c) of this section, with emphasis on prediction of near-field seismic response.
(2) The design plans and structural analysis for the tank, its impounding system, and related foundations, with a report demonstrating that the design requirements of this section are satisfied, including any test results or other documentation as appropriate.
(3) A description of safety-related features of the site or designs, in addition to those required by this part, if applicable, that would mitigate the potential effects of a catastrophic spill (e.g., remoteness or topographic features of the site, additional exclusion distances, or multiple barriers for containing or impounding LNG).
(h) Each container which does not have a structurally liquid-tight cover must have sufficient freeboard with an appropriate configuration to prevent the escape of liquid due to sloshing, wave action, and vertical liquid displacement caused by seismic action.
(a) Each operator shall determine the effects of flooding on an LNG facility site based on the worst occurrence in a 100-year period. The determination must take into account:
(1) Volume and velocity of the floodwater;
(2) Tsunamis (local, regional, and distant);
(3) Potential failure of dams;
(4) Predictable land developments which would affect runoff accumulation of water; and
(5) Tidal action.
(b) The effect of flooding determined under paragraph (a) of this section must be accommodated by location or design and construction, as applicable, to reasonably assure:
(1) The structural or functional integrity of LNG facilities; and
(2) Access from outside the LNG facility and movement of personnel and equipment about the LNG facility site for the control of fire and other emergencies.
(a) Soil investigations including borings and other appropriate tests must be made at the site of each LNG facility to determine bearing capacity, settlement characteristics, potential for erosion, and other soil characteristics applicable to the integrity of the facility.
(b) The naturally occurring or designed soil characteristics at each LNG facility site must provide load bearing capacities, using appropriate safety factors, which can support the following loads without excessive lateral or vertical movement that causes a loss of the functional or structural integrity of the facility involved:
(1) Static loading caused by the facility and its contents and any hydrostatic testing of the facility; and
(2) Dynamic loading caused by movement of contents of the facility during normal operation, including flow, sloshing, and rollover.
(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 (265,000 liters), applicable wind load data in ASCE 7-88.
(2) For all other LNG facilities:
(i) An assumed sustained wind velocity of not less than 200 miles (322 kilometers) 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.
(a) In addition to the requirements of §§ 193.2061, 193.2063, 193.2065, and 193.2067, each operator shall determine from historical records and engineering studies the worst effect of other weather and natural conditions which may predictably occur at an LNG facility site.
(b) The facility must be located and designed so that such severe conditions cannot reasonably be expected to result in an emergency involving the factors listed in § 193.2063(b).
(a) Each operator shall determine that present and reasonably foreseeable activities adjacent to an LNG facility site that could adversely affect the operation of the LNG facility or the safety of persons or offsite property, if damage to the facility occurs.
(b) An LNG facility must not be located where present or projected offsite activities would be reasonably expected to:
(1) Adversely affect the operation of any of its safety control systems;
(2) Cause failure of the facility; or
(3) Cause the facility not to meet the requirements of this part.
Each LNG facility site must be large enough to provide for minimum separations between facilities and between facilities and the site boundary to:
(a) Permit movement of personnel, maintenance equipment, and emergency equipment around the facility; and
(b) Comply with distances specified in sections 2-2.4 through 2-2.7 of ANSI/NFPA 59A.
This subpart prescribes requirements for the selection and qualification of materials for components, and for the design and installation or construction of components and buildings, including separate requirements for impounding systems, LNG storage tanks, and transfer systems.
Materials for all components must be—
(a) Able to maintain their structural integrity under all design loadings, including applicable environmental design forces under subpart B of this part;
(b) Physically, chemically, and thermally compatible within design limits with any fluid or other materials with which they are in contact; and
(c) Qualified in accordance with the applicable requirements of this subpart.
Each operator shall—
(a) Determine the range of temperatures to which components will be subjected during normal operations, including required testing, initial startup, cooldown operations, and shutdown conditions; and
(b) Use component materials that meet the design standards of this part for strength, ductility, and other properties throughout the entire range of temperatures to which the component will be subjected in normal operations.
(a) Each operator shall determine the effects on components not normally exposed to extreme cold (including a component's foundation or support system) of contact by LNG or cold refrigerant that could result from error, a spill, or other emergency determined as required by this part.
(b) Each operator shall determine the effects on components (including their foundations or support systems) of the extreme heat which could result from an LNG or other hazardous fluid fire.
(c) Where the exposure determined under paragraph (a) or (b) of this section could result in a failure that would worsen the emergency, the component or its foundation or support system, as appropriate, must be:
(1) Made of material or constructed to be suitable for the extreme temperature to which it could be subjected; or
(2) Protected by insulation or other means that will delay failure due to extreme temperature in order to allow adequate time to take emergency responses.
(d) If a material that has low resistance to flame temperatures is used in any component containing a hazardous fluid, the material must be protected so that any heat resulting from a controllable emergency does not cause the release of fluid that would result in an uncontrollable emergency.
During normal operations, insulation materials must:
(a) Maintain insulating values;
(b) Withstand thermal and mechanical design loads; and
(c) Be covered with a material that is noncombustible in the installed state,
All cold boxes must be made of noncombustible material and the insulation must be made of materials which are noncombustible in the installed condition.
(a) Piping made of cast iron, malleable iron, or ductile iron may not be used to carry any cryogenic or hazardous fluids.
(b) Piping materials intended for normal use at temperatures below −28.9° C (−20° F) or for use under § 193.2107(c)(1) must be qualified by testing in accordance with ASME/ANSI B 31.3 to comply with § 193.2103(b).
Concrete intended for normal use at cryogenic temperatures or for use under § 193.2107(c)(1) may not be used unless:
(a) Materials, measurements, mixing, placing, prestressing, and poststressing of concrete meets generally accepted engineering practices;
(b) Metallic reinforcing, prestressing wire, structural and nonstructural members used in concrete are acceptable in the installed condition for the temperature and stress levels encountered at design loading conditions; and
(c) Tests for the compressive strength, the coefficient of contraction, an acceptable thermal gradient, and, if applicable, acceptable surface loading to prevent detrimental spalling are performed on the concrete at the lowest temperature for which the concrete is designed or similar test data on these properties are available.
Combustible materials are not permitted for the construction of buildings, plant equipment, and the foundations and supports of buildings and plant equipment in areas where ignition of the material would worsen an emergency. However, limited combustible materials may be used when the use of noncombustible materials is impractical.
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.
Components, including their foundations and support systems, must be designed, fabricated, and installed to withstand, without loss of functional or structural integrity, predictable loadings not including environmental design forces under subpart B of this part unless applicable under that subpart.
(a) Each valve, including control valves and relief valves, must be designed, manufactured, and tested to comply with ASME/ANSI B31.3 or ASME/ANSI B31.5 or ASME/ANSI B31.8 or API Standard 6D, if design conditions fall within their scope.
(b) Extended bonnet valves must be used for service temperatures below −45.6° C (−50° F).
(c) Valves used for cryogenic liquid service must be designed to operate in the position in which they are installed.
(d) Powered local and remote operation must be provided for valves intended for use during a controllable emergency that would be difficult or excessively time-consuming to operate manually during such an emergency.
(e) Valves must be designed and installed so that an excessive load on the
Each automatic shutoff valve or combination of valves must:
(a) Have a fail-safe design;
(b) Operate to stop fluid flow which would endanger the operational integrity of plant equipment; and
(c) Close at a rate to avoid fluid hammer which would endanger the operating integrity of a component.
(a) Piping must be designed, manufactured, and tested to comply with ASME/ANSI B 31.3.
(b) All cryogenic and hazardous fluid piping must have connections to facilitate blowdown and purge as required by this part.
(c) Each cryogenic or hazardous fluid piping system that is aboveground must be identified by color coding, painting, or labeling.
(d) Seamless pipe or pipe with a longitudinal joint efficiency of 1.0 determined in accordance with ASME/ANSI B31.3, or pipe with a design pressure less than two-thirds of the mill-proof test pressure or subsequent shop or field hydrostatic test pressure must be used for process and transfer piping handling cryogenic or other hazardous fluids with a service temperature below −22° F (−30° C).
(e) For longitudinal or spiral weld piping handling LNG or cryogenic fluids, the heat affected zone must comply with section 323.2.2 of ASME/ANSI B31.3.
(f) Threaded piping used in hazardous fluid service must be at least Schedule 80.
Piping attachments and supports for LNG or refrigerant piping must be designed to prevent excessive heat transfer which can result in either unintentional restraint of piping caused by ice formations or the embrittlement of supporting steel.
(a) Each building or structural enclosure in which potentially hazardous quantities of flammable materials are handled must be designed and constructed to minimize fire hazards.
(b) Buildings or structural enclosures in which hazardous or cryogenic fluids are handled shall be of light-weight, noncombustible construction with nonload-bearings walls.
(c) If rooms containing such fluids are located within or attached to buildings in which such fluids are not handled, i.e., control rooms, shops, etc., the common walls shall be limited to not more than two in number, shall be designed to withstand a static pressure of at least 4800 Pa (100 psf), have no doors or other communicating openings, and shall have a fire resistance rating of at least 1 hour.
(a) Each building in which potentially hazardous quantities of flammable fluids are handled must be ventilated to minimize the possibility, during normal operation, of hazardous accumulation of a flammable gas and air mixture, hazardous products of combustion, and other hazardous vapors in enclosed process areas by one of the following means:
(1) A continuously operating mechanical ventilation system;
(2) A combination gravity ventilation system and normally off mechanical ventilation system which is activated by suitable flammable gas detectors at a concentration not exceeding 25 percent of the lower flammable limit of the gas;
(3) A dual rate mechanical ventilation system with the high rate activated by suitable flammable gas detectors at a concentration not exceeding 25 percent of the lower flammable limit of the gas; or
(4) A gravity ventilation system composed of a combination of wall openings, roof ventilators, and, if there are basements or depressed floor levels, a supplemental mechanical ventilation system.
(b) The ventilation rate must be at least 1 cubic foot (.035 cubic meters) per minute of air per square foot (per square meter) of floor area. If vapors heavier than air can be present, the ventilation must be proportioned according to the area of each level.
Each operator shall consider the amount of contraction and expansion of each component during operating and environmental thermal cycling and shall:
(a) Provide components that operate without detrimental stress or restriction of movement, within each component and between components, caused by contraction and expansion; and
(b) Prevent ice buildup from detrimentally restricting the movement of components caused by contraction and expansion.
(a) Each operator shall:
(1) Determine which components and their foundations could be endangered by frost heave from ambient temperatures or operating temperatures of the component; and
(2) Provide protection against frost heave which might impair their structural integrity.
(b) For each component and foundation determined under paragraph (a) of this section, instrumentation must be installed to warn of potential structural impairment due to frost heave, unless the operator includes in the maintenance procedures required by this part, a method and schedule of inspection that will detect changes in the elevation.
(a) Components must be designed to support the weight of ice and snow which could normally collect or form on them.
(b) Each operator shall provide protection for components from falling ice or snow which may accumulate on structures.
(c) Valves and moving components must not become inoperative due to ice formation on the component.
(a) Each operator shall select and install electrical equipment and wiring for components in accordance with ANSI/NFPA 70 and, where applicable, section 7-6.2 of ANSI/NFPA 59A.
(b) Electrical grounding and bonding must be in accordance with section 7-7.1.1 of ANSI/NFPA 59A.
(c) Protective measures for stray or impressed currents must be provided in accordance with section 7-7.3 of ANSI/NFPA 59A.
Each operator shall install proper grounds as necessary to minimize the hazard to plant personnel and components, including all electrical circuits, as a result of lightning.
Boilers must be designed and fabricated in accordance with section I or section IV of the ASME Boiler and Pressure Vessel Code. Other pressure vessels subject to that Code must be designed and fabricated in accordance with Division 1 or Division 2 of section VIII.
Combustion engines and gas turbines must be installed in accordance with ANSI/NFPA-37.
(a) An impounding system must be provided for storage tanks to contain a potential spill of LNG or other hazardous liquid.
(b) Grading or drainage or an impounding system must be provided to ensure that accidental spills or leaks from the following components and areas do not endanger components or adjoining property or enter navigable waterways:
(1) Liquefaction and other process equipment;
(2) Vaporizers;
(3) Transfer systems;
(4) Parking areas for tank cars or tank trucks; and
(5) Areas for loading, unloading, or storing portable containers and dewar vessels.
(c) Impounding systems for LNG must be designed and constructed in accordance with this subpart. Impounding systems intended for containment of hazardous liquids other than LNG must meet the requirements of ANSI/NFPA-30.
(a) An impounding system must have a configuration or design which, to the maximum extent possible, will prevent liquid from escaping impoundment by leakage, splash from collapse of a structure or part thereof, momentum and low surface friction, foaming, failure of pressurized piping, and accidental pumping.
(b) The basic form of an impounding system may be excavation, a natural geological formation, manufactured diking, such as berms or walls, or any combination thereof.
(a) For the purpose of this part, impounding systems are classified as follows:
(b) In the case of an impounding system consisting of a combination of classes, requirements of this part regarding a single class apply according to the percentage of impoundment provided by each class.
(a) Subject to paragraph (b) of this section, the structural parts of an impounding 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) For spills from LNG storage tanks with Class 2 or 3 impounding systems, imposed loading and surging flow characteristics must be based on a credible release of the tank contents.
(c) If an LNG storage tank is located within a horizontal distance of 6,100 m. (20,000 ft.) from the nearest point of the nearest runway serving large aircraft as defined in 14 CFR part 1.1, a Class 1 impounding system must be used which is designed to withstand collision by, or explosion of, the heaviest aircraft
Insulation, sealants, or other coatings and coverings which are part of an impounding system—
(a) Must be noncombustible in an installed condition when exposed to an LNG fire resulting from a spill that covers the floor of the impounding space;
(b) Must withstand exposure to fire from sources determined as required by this part, other than impounded LNG, for a period of time until fire protective or fire extinguishing action is taken; and
(c) When used for the purpose of maintaining the functional integrity of an impounding system, must be capable of withstanding sudden exposure to LNG without loss of such integrity.
Floors of Class 2 and Class 3 impounding systems must, to the extent feasible—
(a) Slope away from the component or item impounded and to a sump basin installed under § 193.2171;
(b) Slope away from the nearest adjacent component;
(c) Drain surface waters from the floor at rates based on a storm of 10-year frequency and 1-hour duration and other natural water sources; and
(d) Be designed to minimize the wetted floor area.
(a) Penetrations in dikes to accommodate piping or any other purpose are prohibited.
(b) An outer wall of a component served by an impounding system may not be used as a dike except for a concrete wall designed to comply with the requirements of § 193.2155(c) or equivalent design impact loading.
If vapor barriers are installed in meeting the requirements of § 193.2059, they must be designed and constructed to detain LNG vapor.
In addition to dike dimensions needed to comply with other requirements of this subpart, to minimize the possibility that a trajectory of accidentally discharged liquid would pass over the top of a dike, the horizontal distance from the inner wall of the component or vessel served to the closest inside edge of the top of the dike must at least equal the vertical distance from the maximum liquid level in the component or vessel to the inside edge of the top of the dike.
(a) A covered impounding system is prohibited unless it is—
(1) Sealed from the atmosphere and filled with an inert gas; or
(2) Permanently interconnected with the vapor space of the component served.
(b) Flammable nonmetallic membranous covering is prohibited in a covered system.
(c) For systems to which paragraph (a)(1) of this section applies, instrumentation and controls must be provided to—
(1) Maintain pressures at a safe level; and
(2) Monitor gas concentrations in accordance with § 193.2169.
(d) Dikes must have adequate structural strength to assure that they can withstand impact from a collapsed cover and all anticipated conditions which could cause a failure of the impounding space cover.
Appropriate areas within an impounding system where collection or passage of LNG or LNG vapor could be expected must be equipped with sensing and warning devices to monitor continuously for the presence of LNG or LNG vapor and to warn before LNG gas concentration levels exceed 25 percent of the lower flammable limit.
Except for Class 1 impounding systems, a sump basin must be located in
(a) Except for Class 1 systems, impounding systems must have sump pumps and piping running over the dike to remove water collecting in the sump basin.
(b) The water removal system must have adequate capacity to remove water at rates which equal the maximum predictable collection rate from a storm of 10-year frequency and 1-hour duration, and other natural causes.
(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.
When an impounding system serves more than one LNG storage tank, a means must be provided to prevent low temperature or fire resulting from leakage from any one of the storage tanks served causing any other storage tank to leak. The means must not result in a vapor dispersion distance which exceeds the exclusion zone required by § 193.2059.
In addition to capacities otherwise required by this subpart, an impounding system must have sufficient volumetric capacity to provide for—
(a) Displacement by the component, tank car, tank truck, container, or dewar vessel served; and
(b) Where applicable, displacement which could occur when a higher density substance than the liquid to be impounded enters the system, considering all relevant means of assuring capacity.
(a) Except as provided in paragraph (b) of this section, each impounding system serving an LNG storage tank must have a minimum volumetric liquid impoundment capacity as follows:
(b) For purposes of this section, a covered impounding system serving a single LNG storage tank may have a capacity of 110 percent of the LNG tank's maximum liquid capacity if it is covered by a roof that is separate and independent from the LNG storage tank.
If an impounding system serves a component under § 193.2149(b) (1)-(3), it must have a minimum volumetric liquid impoundment capacity equal to the sum of—
(a) One-hundred percent of the volume of liquid that could be contained in the component and, where applicable, tank car or tank truck served; and
(b) The maximum volume of liquid which could discharge into the impounding space from any single failure of equipment or piping during the time period necessary for spill detection, instrument response, and sequenced shutdown by the automatic shutdown system under § 193.2439.
Each impounding system serving an area listed under § 193.2149(b) (4) or (5) must have a minimum volumetric liquid impoundment capacity which complies with the requirements of § 193.2181, assuming each tank car, tank truck, portable container, or dewar vessel to be a storage tank.
(a) LNG storage tanks must comply with the requirements of this subpart and the other applicable requirements of this part.
(b) A flammable nonmetallic membrane liner may not be used as an inner container in a storage tank.
Each part of an LNG storage tank must be designed to withstand without loss of functional or structural integrity any predictable combination of forces which would result in the highest stress to the part, including the following:
(a) Internal design pressure determined under § 193.2197.
(b) External design pressure determined under § 193.2199.
(c) Weight of the structure.
(d) Weight of liquid to be stored, except that in no case will the density assumed be less than 29.3 pounds per cubic foot (470 kilograms per cubic meter).
(e) Loads due to testing required by § 193.2327.
(f) Nonuniform reaction forces on the foundation due to predictable settling and other movement.
(g) Superimposed forces from piping, stairways, and other connected appurtenances.
(h) Predictable snow and ice loads.
(i) The loading of internal insulation on the inner container and outer shell due to compaction and movement of the container and shell over the design life of the insulation.
(j) In the case of vacuum insulation, the forces due to the vacuum.
(k) In the case of a positive pressure purge, the forces due to the maximum positive pressure of the purge gas.
LNG storage tanks with a capacity of 5,000 barrels (795 cubic meters) or more must be equipped with means to mitigate a potential for rollover and overpressure such as:
(a) Selective filling at the top and bottom of the tank;
(b) Circulating liquid from the bottom to the top of the same tank; or
(c) Transferring liquid selectively from the bottom of the tank to the bottom or top of any adjacent storage tank.
(a) Each operator shall determine for normal operations of each LNG storage tank—
(1) The amount and pattern of predictable movement of components, including transfer piping, and the foundation, which could result from thermal cycling, loading forces, and ambient air changes; and
(2) For a storage tank with an inner container, the predictable movement of the inner container and the outer shell in relation to each other.
(b) Storage tanks must be designed to provide adequate allowance for stress due to movement determined under paragraph (a) of this section, including provisions that—
(1) Backfill does not cause excessive stresses on the tank structure due to expansion of the storage tank during warmup;
(2) Insulation does not settle to a damaging degree or unsafe condition during thermal cycling; and
(3) Expansion bends and other expansion or contraction devices are adequate to prevent excessive stress on tank penetrations, especially during cooldown from ambient temperatures.
(a) All penetrations in an LNG storage tank must be designed in accordance with API 620, including appendix Q.
(b) The loadings on all penetrations must be determined by an analysis of all contributing forces, including those from tank thermal movements, connecting piping thermal movements, hydraulic forces, applicable wind and earthquake forces, and the forces resulting from settlement or movement of the tank foundation or pipe supports.
(c) All penetrations in an LNG storage tank below the design liquid level must be fitted with an internal shutoff valve which is designed and installed so that any failure of the nozzle penetrating the tank will be outside the tank.
(d) The requirements of paragraphs (a) and (c) of this section do not apply to shop fabricated tanks of 70,000 gallons (265,000 liters) or less capacity. All penetrations in such tanks must be designed and installed in accordance with
(a) Each operator shall establish the internal design pressure at the top of each LNG storage tank, including a suitable margin above the maximum allowable working pressure.
(b) The internal design pressure of a storage tank may not be lower than the highest pressure in the vapor space resulting from each of the following events or combination thereof that predictably might occur, giving consideration to vapor handling equipment, relief devices in accordance with § 193.2429, and any other mitigating measures:
(1) Filling the tank with LNG including effects of increased vaporization rate due to superheat and sensible heat of the added liquid;
(2) Rollover;
(3) Fall in barometric pressure, using the worst combination of amount of fall and rate of fall which might predictably occur;
(4) Loss of effective insulation that may result from an adjacent fire, leak of liquid into the intertank space, or other predictable accident; and
(5) Flash vaporization resulting from pump recirculation.
(a) Each operator shall establish the external design pressure at the top of each LNG storage tank, including a suitable margin below the minimum allowable working pressure.
(b) The external design pressure may not be higher than the lowest vapor pressure in the vapor space resulting from each of the following events or combinations thereof that predictably might occur, giving consideration to gas makeup systems, vacuum relief devices in accordance with § 193.2429, and any other mitigating measures.
(1) Withdrawing liquid from the tank;
(2) Withdrawing gas from the tank;
(3) Adding subcooled LNG to the tank; and
(4) Rise in barometric pressure, based on the worst combination of amount of rise and rate of rise which predictably might occur.
The liquid container of each LNG storage tank and all tank parts used in contact with LNG or its cold vapor shall be designed for the lowest bulk liquid temperature which can be attained in the LNG storage tank.
(a) Each LNG storage tank must have a stable foundation designed in accordance with generally accepted structural engineering practices.
(b) Each foundation must support design loading forces without detrimental settling that could impair the structural integrity of the tank.
If the protection provided for LNG storage tank foundations from frost heave under § 193.2137(a) includes heating the foundation area—
(a) An instrumentation and alarm system must be provided to warn of malfunction of the heating system; and
(b) A means to correct the malfunction must be provided.
(a) Insulation on the outside of the outer shell of an LNG storage tank may not be used to maintain stored LNG at an operating temperature during normal operation.
(b) Insulation between an inner container and the outer shell of an LNG storage tank must—
(1) Be compatible with the contained liquid and its vapor;
(2) In its installed condition, be noncombustible; and
(3) Not significantly lose insulating properties by melting, settling, or other means due to a fire resulting from a spill that covers the floor of the impounding space around the tank.
(a) Each LNG storage tank having a capacity over 70,000 gallons (265,000 liters) must be equipped with a sufficient number of sensing devices and personnel warning devices, as prescribed, which operate continuously while the
(b) LNG storage tanks with a capacity of 70,000 gallons (265,000 liters) or less must be equipped with the following:
(1) LNG liquid trycocks, when attended during the filling operation.
(2) Pressure gages and recorders with high pressure alarm.
(3) Differential pressure liquid level gage.
(c) Each storage tank must be designed as appropriate to provide for compliance with the inspection requirements of this part.
(a) Metal storage tanks with internal design pressures of not more than 15 psi (103 kPa) gage must be designed and constructed in accordance with API Standard 620 and, where applicable, appendix Q of that standard.
(b) Metal storage tanks with internal design pressures above 15 psi (103 kPa) gage must be designed in accordance with the applicable division of section VIII of the ASME Boiler and Pressure Vessel Code.
Concrete storage tanks must be designed and constructed in accordance with section 4-3 of ANSI/NFPA-59A.
Thermal barriers must be provided between piping and an outer shell when necessary to prevent the outer shell from being exposed during normal operation to temperatures lower than its design temperature.
(a) Saddles and legs must be designed in accordance with generally accepted structural engineering practices, taking into account loads during transportation, erection loads, and thermal loads.
(b) Storage tank stress concentrations from support systems must be minimized by distribution of loads using pads, load rings, or other means.
(c) For a storage tank with an inner container, support systems must be designed to—
(1) Minimize thermal stresses imparted to the inner container and outer shell from expansion and contraction; and
(2) Sustain the maximum applicable loading from shipping and operating conditions.
(d) LNG storage tanks with an air space beneath the tank bottom or its foundation must be designed to withstand without loss of functional or structural integrity, the forces caused by the ignition of a combustible vapor cloud in this space.
Piping connected to an inner container that is located in the space between the inner container and outer shell must be designed for not less than the pressure rating of the inner container. The piping must contain expansion loops where necessary to protect against thermal and other secondary stresses created by operation of the tank. Bellows may not be used within the space between the inner container and outer shell.
(a) Each operator shall install and maintain a name plate in an accessible place on each storage tank and mark it in accordance with the applicable code or standard incorporated by reference in § 193.2211 or § 193.2213.
(b) Each penetration in a storage tank must be marked indicating the function of the penetration.
(c) Marking required by this section must not be obscured by frosting.
(a) Transfer systems must comply with the requirements of this subpart and other applicable requirements of this part.
(b) The design of transfer systems must provide for stress due to the frequency of thermal cycling and intermittent use to which the transfer system may be subjected.
(c) Slip type expansion joints are prohibited and packing-type joints may not be used in transfer systems for LNG or flammable refrigerants.
(d) A suitable means must be provided to precool the piping in a manner that prevents excessive stress prior to normal transfer of cold fluids.
(e) Stresses due to thermal and hydraulic shock in the piping system must be determined and accommodated by design to avoid damage to piping.
(a) Each transfer system must operate with a means to—
(1) Prevent backflow of liquid from a receiving container, tank car, or tank truck from causing a hazardous condition; and
(2) Maintain one-way flow where necessary for the integrity or safe operation of the LNG facility.
(b) The means provided under paragraph (a)(1) of this section must be located as close as practical to the point of connection of the transfer system and the receiving container, tank car, or tank truck.
(a) Each cargo transfer system must have—
(1) A means of safely depressurizing and venting that system before disconnection;
(2) A means to provide for safe vapor displacement during transfer;
(3) Transfer piping, pumps, and compressors located or protected by suitable barriers so that they are safe from damage by tank car or tank truck movements;
(4) A signal light at each control location or remotely located pumps or compressors used for transfer which indicates whether the pump or compressor is off or in operation; and
(5) A means of communication between loading or unloading areas and other areas in which personnel are associated with the transfer operations.
(b) Hoses and arms for cargo transfer systems must be designed as follows—
(1) The design must accommodate operating pressures and temperatures encountered during the transfers;
(2) Hoses must have a bursting pressure of not less than five times the operating pressure.
(3) Arms must meet the requirements of ASME/ANSI B31.3.
(4) Adequate support must be provided, taking into account ice formation.
(5) Couplings must be designed for the frequency of any coupling or uncoupling.
The transfer area of a cargo transfer system must be designed—
(a) To accommodate tank cars and tank trucks without excessive maneuvering; and
(b) To permit tank trucks to enter or exit the transfer area without backing.
(a) Shutoff valves on transfer systems must be located—
(1) On each liquid supply line, or common line to multiple supply lines, to a storage tank, or to a cargo transfer system;
(2) On each vapor or liquid return line from multiple return lines, used in a cargo transfer system;
(3) At the connection of a transfer system with a pipeline subject to part 192 of this chapter; and
(4) To provide for proper operation and maintenance of each transfer system.
(b) Transfer system shutoff valves that are designated for operation in the emergency procedures must be manually operable at the valve and power operable at the valve and at a remote location at least 50 feet (15 meters) from the valve.
This subpart prescribes requirements for the construction or installation of components.
No person may place in service any component until it passes all applicable inspections and tests prescribed by this subpart.
(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.
(a) In performing construction, installation, inspection, or testing, an operator must follow written specifications, procedures, and drawings, as appropriate, that are consistent with this part, taking into account relevant mechanical, chemical, and thermal properties, component functions, and environmental effects that are involved.
(b) All procedures, including any field revisions, must be substantiated by testing or experience to produce a component that is reliable and complies with the design and installation requirements of this part.
(a) All construction, installation, and testing activities must be inspected as frequently as necessary in accordance with a written plan to assure that—
(1) Activities are in compliance with all applicable requirements of this subpart; and
(2) Components comply with the applicable material, design, fabrication, installation, and construction requirements of this part.
(b) In addition to the requirements of paragraph (a) of this section, the construction of concrete storage tanks must be inspected in accordance with ACI 311.4R-88 or ACI 311.5R-88.
(c) Each operator shall have a quality assurance inspection program to verify that components comply with their design specifications and drawings, including any field design changes, before they are placed in service.
Except as otherwise provided by this subpart, each operator shall determine, commensurate with the hazard that would result from failure of the component concerned, the scope and nature of—
(a) Inspections and tests required by this subpart; and
(b) Inspection and testing procedures required by § 193.2305.
After construction or installation, as the case may be, all components must be cleaned to remove all detrimental contaminants which could cause a hazard during operation, including the following:
(a) All flux residues used in brazing or soldering must be removed from the joints and the base metal to prevent corrosive solutions from being formed.
(b) All solvent type cleaners must be tested to ensure that they will not damage equipment integrity or reliability.
(c) Incompatible chemicals must be removed.
(d) All contaminants must be captured and disposed of in a manner that does not reduce the effectiveness of corrosion protection and monitoring provided as required by this part.
(a) Each operator shall provide the following for welding on pressurized piping for LNG and other hazardous fluids:
(1) Welding procedures and welders qualified in accordance with section IX of the ASME Boiler and Pressure Vessel Code or API 1104, as applicable;
(2) When welding materials that are qualified by impact testing, welding procedures selected to minimize degradation of low temperature properties of the pipe material; and
(3) When welding attachments to pipe, procedures and techniques selected to minimize the danger of burn-throughs and stress intensification.
(b) Oxygen fuel gas welding is not permitted on flammable fluid piping with a service temperature below −29°C(−20°F).
(c) Marking materials for identifying welds on pipe must be compatible with the basic pipe material.
(d) Surfaces of components that are less than 6.35 mm (0.25 in.) thick may not be field die stamped.
(e) Where die stamping is permitted, any identification marks must be made with a die having blunt edges to minimize stress concentration.
(a) Piping more than 2 inches nominal diameter must be joined by welding, except that—
(1) Threaded or flanged connections may be used where necessary for special connections, including connections for material transitions, instrument connections, testing, and maintenance;
(2) Copper piping in nonflammable service may be joined by silver brazing; and
(3) Material transitions may be made by any joining technique proven reliable under § 193.2305(b).
(b) If socket fittings are used, a clearance of 1.6 to 3.2 mm (0.063 to 0.126 in.) between the pipe end and the bottom of the socket recess must be provided and appropriate measurement reference marks made on the piping for the purpose of inspection.
(c) Threaded joints must be—
(1) Free of stress from external loading; and
(2) Seal welded, or sealed by other means which have been tested and proven reliable.
(d) Compression type couplings must meet the requirements of ASME/ANSI B31.3.
(e) Care shall be taken to ensure the tightness of all bolted connections. Spring washers or other such devices designed to compensate for the contraction and expansion of bolted connections during operating cycles shall be used where required.
(f) The selection of gasket material shall include the consideration of fire.
After testing required by this subpart is completed on a component to contain a hazardous fluid, the component must be retested whenever—
(a) Penetration welding other than tie-in welding is performed; or
(b) The structural integrity of the component is disturbed.
(a) A strength test must be performed on each piping system and container to determine whether the component is capable of performing its design function, taking into account—
(1) The maximum allowable working pressure;
(2) The maximum weight of product which the component may contain or support;
(b) For piping, the test required by paragraph (a) of this section must include a pressure test conducted in accordance with section 345 of ASME/ANSI B31.3, except that test pressures must be based on the design pressure. Carbon and low alloy steel piping must be pressure tested above their nil ductility transition temperature.
(c) All shells and internal parts of heat exchangers to which section VIII, Division 1, or Division 2 of the ASME Boiler and Pressure Vessel Code, applies must be pressure tested, inspected, and stamped in accordance therewith.
(a) The following percentages of each day's circumferentially welded pipe joints for hazardous fluid piping, selected at random, must be nondestructively tested over the entire circumference to indicate any defects which could adversely affect the integrity of the weld or pipe:
(b) Evaluation of weld tests and repair of defects must be in accordance with the requirements of ASME/ANSI B31.3 or API 1104, as applicable.
(c) Where longitudinally or spiral welded pipe is used in transfer systems, 100 percent of the seam weld must be examined by radiographic or ultrasonic inspection.
(d) The butt welds in metal shells of storage tanks with internal design pressure of not more than 15 psi (103 kPa) gage must be radiographically tested in accordance with section Q.7.6, API 620, appendix Q, except that for hydraulic load bearing shells with curved surfaces that are subject to cryogenic temperatures, 100 percent of both longitudinal (or meridional) and circumferential or (or latitudinal) welds must be radiographically tested.
(e) The butt welds in metal shells of storage tanks with internal design pressure above 15 psi (103 kPa) gage must be radiographically tested in accordance with section IX of the ASME Boiler and Pressure Vessel Code, except that for 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.
(a) Each container and piping system must be initially tested to assure that the component will contain the product for which it is designed without leakage.
(b) Shop fabricated containers and all flammable fluid piping must be leak tested to a minimum of the design pressure after installation but before placing it in service.
(c) For a storage tank with vacuum insulation, the inner container, outer shell, and all internal piping must be tested for vacuum leaks in accordance with an appropriate procedure.
Each control system must be tested before being placed in service to assure that it has been installed properly and will function as required by this part.
(a) In addition to other applicable requirements of this subpart, storage tanks for cryogenic fluids with internal design pressures of not more than 15
(b) Metal storage tanks for cryogenic fluids with internal design pressures above 15 psi (103 kPa) gage must be tested in accordance with the applicable division of section VIII of the ASME Boiler and Pressure Vessel Code.
(c) Reference measurements must be made with appropriate precise instruments to assure that the tank is gas tight and lateral and vertical movement of the storage tank does not exceed predetermined design tolerances.
For the service life of the component concerned, each operator shall retain appropriate records of the following:
(a) Specifications, procedures, and drawings prepared for compliance with § 193.2305; and
(b) Results of tests, inspections, and the quality assurance program required by this subpart.
This subpart prescribes requirements for the design, fabrication, and installation of vaporization equipment, liquefaction equipment, and control systems.
Vaporizers must comply with the requirements of this subpart and the other applicable requirements of this part.
(a) Vaporizers must be designed and fabricated in accordance with applicable provisions of section VIII, Division 1 of the ASME Boiler and Pressure Vessel Code.
(b) Each vaporizer must be designed for the maximum allowable working pressure at least equal to the maximum discharge pressure of the pump or pressurized container system supplying it, whichever is greater.
(a) Vaporizers must be equipped with devices which monitor the inlet pressure of the LNG, the outlet temperature, and the pressure of the vaporized gas, and the inlet pressure of the heating medium fluids.
(b) Manifolded vaporizers must be equipped with:
(1) Two inlet valves in series to prevent LNG from entering an idle vaporizer; and
(2) A means to remove LNG or gas which accumulates between the valves.
(a) A shutoff valve must be located on transfer piping supplying LNG to a vaporizer. The shutoff valve must be located at a sufficient distance from the vaporizer to minimize potential for damage from explosion or fire at the vaporizer. If the vaporizer is installed in a building, the shutoff valve must be located outside the building.
(b) A shutoff valve must be located on each outlet of a vaporizer.
(c) For vaporizers designed to use a flammable intermediate fluid, a shutoff valve must be located on the inlet and outlet line of the intermediate fluid piping system where they will be operable during a controllable emergency involving the vaporizer.
The capacity of pressure relief devices required for vaporizers by § 193.2429 is governed by the following:
(a) For heated vaporizers, the capacity must be at least 110 percent of rated natural gas flow capacity without allowing the pressure to rise more than 10 percent above the vaporizer's maximum allowable working pressure.
(b) For ambient vaporizers, the capacity must be at least 150 percent of rated natural gas flow capacity without allowing the pressure to rise more than 10 percent above the vaporizer's maximum allowable working pressure.
(a) Combustion air intakes to vaporizers must be equipped with sensing devices to detect the induction of a flammable vapor.
(b) If a heated vaporizer or vaporizer heater is located in a building, the
Liquefaction equipment must comply with the requirements of this subpart and the other applicable requirements of this part.
A shutoff valve must be located on piping delivering natural gas to each liquefaction system.
Each multiple parallel piping system connected to liquefaction equipment must have devices to prevent backflow from causing a hazardous condition.
(a) Each cold box in a liquefaction system must be equipped with a means of monitoring or detecting, as appropriate, the concentration of natural gas in the insulation space.
(b) If the insulation space in a cold box is designed to operate with a gas rich atmosphere, additional natural gas must be introduced when the concentration of gas falls to 30 percent.
(c) If the insulation space of a cold box is designed to operate with a gas free atmosphere, additional air or inert gas, as appropriate, must be introduced when the concentration of gas is 25 percent of the lower flammable limit.
Where incoming gas to liquefaction equipment contains air, each operator shall provide a means of preventing a flammable mixture from occurring under any operating condition.
(a) Control systems must comply with the requirements of this subpart and other applicable requirements of this part.
(b) Each control system must be capable of performing its design function under normal operating conditions.
(c) Control systems must be designed and installed in a manner to permit maintenance, including inspection or testing, in accordance with this part.
(d) Local, remote, and redundant signal lines installed for control systems that can affect the operation of a component that does not fail safe must be routed separately or in separate underground conduits installed in accordance with ANSI/NFPA-70.
(a) Each component containing a hazardous fluid must be equipped with a system of automatic relief devices which will release the contained fluid at a rate sufficient to prevent pressures from exceeding 110 percent of the maximum allowable working pressure. In establishing relief capacity, each operator shall consider trapping of fluid between valves; the maximum rates of boiloff and expansion of fluid which may occur during normal operation, particularly cooldown; and controllable emergencies.
(b) A component in which internal vacuum conditions can occur must be equipped with a system of relief devices or other control system to prevent development in the component of a vacuum that might create a hazardous condition. Introduction of gas into a component must not create a flammable mixture within the component.
(c) In addition to the control system required by paragraphs (a) and (b) of this section—
(1) Each LNG Storage tank must be equipped with relief devices to assure that design pressure and vacuum relief capacity is available during maintenance of the system; and
(2) A manual means must be provided to relieve pressure and vacuum in an emergency.
(d) Relief devices must be installed in a manner to minimize the possibility that release of fluid could—
(1) Cause an emergency; or
(2) Worsen a controllable emergency.
(e) The means for adjusting the setpoint pressure of all adjustable relief devices must be sealed.
(f) Relief devices which are installed to limit minimum or maximum pressure may not be used to handle boiloff
(a) Hazardous fluids may not be relieved into the atmosphere of a building or other confined space.
(b) Boiloff vents for hazardous fluids may not draw in air during operation.
(c) Venting of natural gas/vapor under operational control which could produce a hazardous gas atmosphere must be directed to a flare stack or heat exchanger in order to raise its temperature to achieve positive buoyancy and safe venting.
(a) Each operator shall determine the appropriate location for and install sensing devices as necessary to—
(1) Monitor the operation of components to detect a malfunction which could cause a hazardous condition if permitted to continue; and
(2) Detect the presence of fire or combustible gas in areas determined in accordance with section 500-5 of ANSI/NFPA 70 to have a potential for presence of flammable fluids.
(b) Buildings in which potentially hazardous quantities of flammable fluids are used or handled must be continuously monitored by gas sensing devices set to activate audible and visual alarms in the building and at the control center when the concentration of the fluid in air is not more than 25 percent of the lower flammable limit.
Each operator shall install warning devices in the control center to warn of hazardous conditions detected by all sensing devices required by this part. Warnings must be given both audibly and visibly and must be designed to gain the attention of personnel. Warnings must indicate the location and nature of the existing or potential hazard.
(a) Each pump and compressor for hazardous fluids must be equipped with—
(1) A control system, operable locally and remotely, to shut down the pump or compressor in a controllable emergency;
(2) A signal light at the pump or compressor and the remote control location which indicates whether the pump or compressor is in operation or off;
(3) Adequate valving to ensure that the pump or compressor can be isolated for maintenance; and
(4) A check valve on each discharge line where pumps or compressors operate in parallel.
(b) Pumps or compressors in a cargo transfer system must have shutdown controls at the loading or unloading area and at the pump or compressor site.
(a) Each transfer system, vaporizer, liquefaction system, and storage system tank must be equipped with an emergency shutdown control system. The control must automatically actuate the shutdown of the component (providing pressure relief as necessary) when any of the following occurs:
(1) Temperatures of the component exceed the limits determined under § 193.2105;
(2) Pressure outside the limits of the maximum and minimum design pressure;
(3) Liquid in receiving vessel reaches the design maximum liquid level;
(4) Gas concentrations in the area of the component exceed 40 percent of the lower flammable limit;
(5) A sudden excessive pressure change or other condition indicating a potentially dangerous condition; and
(6) Presence of fire in area of component.
(b) For cargo transfer systems where all transfer operations are continuously manned and visually supervised by qualified personnel, actuation of the emergency shutdown control system may be manual after devices warn of the events listed in paragraph (a) of this section.
(c) Except for components that operate unattended and are remote from the control center, a reasonable delay may be programmed in emergency shutdown control systems required by this section between warning and automated shutdown to provide for manual response.
(d) Each LNG plant must have a shutdown control system to shut down all operations of the plant safely. The system must be operable at—
(1) The control center; and
(2) In the case of a plant where LNG facilities other than the control center are designed to operate unattended at the site of these facilities.
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.
Control systems for components must have a fail-safe design. A safe condition must be maintained until personnel take appropriate action either to reactivate the component served or to prevent a hazard from occurring.
(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; and
(h) Compliance with § 193.2805(b).
(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 determined under § 193.2805(a)(2) in which a hazard to persons or property could exist must be monitored to detect fire or any malfunction or flammable fluid which could cause a hazardous condition. Monitoring must be accomplished by watching or listening from an attended control center for warning alarms, such as gas, temperature, pressure, vacuum, and flow alarms, or by conducting an inspection or test at intervals specified in the operating procedures.
(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 identified under § 193.2817(a), each operator shall 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 the results of each inspection, test, and investigation required by this subpart. Such records must be kept for a period of not less than 5 years.
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 in accordance with the requirements of this subpart and § 193.2805.
(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 or controlled to maintain the operational safety of each component.
(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), must be inspected and tested once each calendar year, but with intervals 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
(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
(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 subpart, including periodic tests and inspections, for a period of not less than five years.
(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
(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 duties under § 193.2307 are satisfactorily performing their assigned function.
(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 in accordance with a written plan of initial instruction, including plant fire drills, to:
(1) Know and follow the fire prevention procedures under § 193.2805(b);
(2) Know the potential causes and areas of fire determined under § 193.2805(a);
(3) Know the types, sizes, and predictable consequences of fire determined under § 193.2817(a); and
(4) 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 § 193.2817.
(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.
(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.
This subpart prescribes requirements for fire prevention and fire control at LNG plants. However, the requirements do not apply to existing LNG plants that do not contain LNG.
Each operator shall use sound fire protection engineering principles to minimize the occurrence and consequences of fire.
(a) Each operator shall determine—
(1) Those potential sources of ignition located inside and adjacent to the LNG plant which could cause fires that affect the safety of the plant; and
(2) Those areas, as described in section 500-5 of ANSI/NFPA 70, where the potential exists for the presence of flammable fluids in an LNG plant. Determinations made under this paragraph must be kept current.
(b) With respect to areas determined under paragraph (a)(2) of this section, each operator shall include in the operating and maintenance procedures under §§ 193.2503 and 193.2605, as appropriate, steps necessary to minimize—
(1) The leakage or release of flammable fluids; and
(2) The possibility of flammable fluids being ignited by sources identified under paragraph (a)(1) of this section.
(a)(1) Smoking is prohibited at an LNG plant in areas identified under § 193.2805(a)(2).
(2) Smoking is permitted only in such locations that the operator designates as a smoking area.
(b) Signs marked with the words “smoking permitted” must be displayed in prominent places in each smoking area designated under paragraph (a) of this section.
(c) Signs marked with the words “NO SMOKING” must be displayed in prominent places in areas where smoking is prohibited.
(a) No open fires are permitted at an LNG plant, except at flare stacks and at times and places designated by the operator.
(b) Whenever an open fire is designated, there must be at the site of the fire—
(1) Trained fire fighting personnel; and
(2) Fire control equipment which has the capability of extinguishing the fire.
(c) The fire fighting personnel and equipment must remain at the fire site until the fire is extinguished and there is no possibility of reignition.
Welding, flame cutting, and similar operations are prohibited, except at times and places that the operator designates in writing as safe and when constantly supervised in accordance with ANSI/NFPA-51B.
Flammable fluids may not be stored in areas where ignition sources are present, unless stored in accordance with the requirements of chapter 4 of ANSI/NFPA 30.
Use of motor vehicles and other motorized equipment which constitute potential ignition sources is prohibited in an impounding space, in areas within 15 m (49.2 ft) of a storage tank, and in areas within 15 m (49.2 ft) of processing equipment containing a flammable fluid except-
(a) At times the operator designates in writing as safe; and
(b) When the motorized equipment is constantly attended.
(a) Each operator shall determine: (1) The types and sizes of fires that may reasonably be expected to occur within and adjacent to each LNG plant that could affect the safety of components; and
(2) The foreseeable consequences of these fires, including the failure of components or buildings due to heat exposure.
(b) Each operator shall provide and maintain fire control equipment and supplies in accordance with the applicable requirements of ANSI/NFPA 59A to protect or cool components that could fail due to heat exposure from fires determined under paragraph (a) of this section and either worsen an emergency or endanger persons or property located outside the plant. Protection or cooling must be provided for as long as the heat exposure exists. The fire control equipment and supplies must include the following:
(1) Portable fire extinguishers suitable for types of fires identified under paragraph (a) of this section; and
(2) If the total inventory of LNG is 265 m
(c) Each operator shall determine the type, size, quantity and location of the fire control equipment and supplies required under paragraph (b) of this section.
(d) Each operator shall provide each facility person who may be endangered by exposure to fire or the products of combustion in performing fire control duties protective clothing and equipment, including, if necessary, a self-contained breathing apparatus.
(e) Portable fire control equipment, protective clothing and equipment for personnel use, controls for fixed fire control equipment, and fire control supplies must be conspicuously located, marked for easy recognition, and readily available for use.
(f) Fire control equipment must have operating instructions. Instructions
(a) All areas determined under § 193.2805(a)(2) in which a hazard to persons or property could exist must be continuously monitored for the presence of flammable gases and vapors with fixed flammable gas detection systems provided and maintained according to the applicable requirements of ANSI/NFPA 59A.
(b) Each fixed flammable gas detection system must be provided with audible and visible alarms located at an attended control room or control station, and an audible alarm in the area of gas detection.
(c) Flammable gas detection alarms must be set to activate at not more than 25 percent of the lower flammable limit of the gas or vapor being monitored.
(d) Gas detection systems must be installed so that they can be readily tested as required by ANSI/NFPA 59A.
(e) A minimum of two portable flammable gas detectors capable of measuring the lower flammable limit must be available at the LNG plant for use at all times.
(f) All enclosed buildings that house a flammable fluid or are connected by piping or uninterrupted conduit to a source of flammable fluid must be continuously monitored for the presence of flammable gases and vapors with a fixed flammable gas detection system that provides a visible or audible alarm outside the enclosed building. The systems must be provided and maintained according to the applicable requirements of ANSI/NFPA 59A.
(a) Fire detectors that continuously monitor for the presence of either flame, heat, or products of combustion must be provided in all areas determined under § 193.2805(a)(2) in which a hazard to persons or property could exist and in all other areas that are used for the storage of flammable or combustible material.
(b) Each fire detection system must be provided with audible and visible alarms located at an attended control room or control station, and an audible alarm in the area of fire detection. The systems must be provided and maintained according to the applicable requirements of ANSI/NFPA 59A.
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
(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 and security monitoring and warning systems required under §§ 193.2911 and 193.2913.
(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:
A. American Concrete Institute (ACI), Box 19150, Redford Station, Detroit, MI 48219-0150.
B. American Gas Association (AGA), 1515 Wilson Boulevard, Arlington, VA 22209.
C. American National Standards Institute (ANSI), 11 West 42nd Street, New York, NY 10036.
D. American Petroleum Institute (API), 1220 L Street, NW., Washington, DC 20005.
E. American Society of Civil Engineers (ASCE), 345 East 47th Street, New York, NY 10017-2398.
F. American Society of Mechanical Engineers (ASME), United Engineering Center, 345 East 47th Street, New York, NY 10017.
G. Gas Research Institute (GRI), 8600 West Bryn Mawr Ave, Chicago, IL 60631.
H. International Conference of Building Officials, 5360 South Workman Mill Road, Whittier, CA 90601.
I. National Fire Protection Association (NFPA), 1 Batterymarch Park, P.O.Box 9101, Quincy, MA 02269-9101.
A. American Concrete Institute (ACI):
1. ACI Standard 311.4R-88 “Guide for Concrete Inspection” (1988).
2. ACI Standard 311.5R-88 “Batch Plant Inspection and Field Testing of Ready-Mixed Concrete” (1988).
B. American Gas Association (AGA):
1. “Evaluation of LNG Vapor Control Methods” (October 1974).
2. “Purging Principles and Practices” (1975).
C. American Society of Civil Engineers (ASCE):
1. ASCE 7-95 “Minimum Design Loads for Buildings and Other Structures” (1995).
D. American Petroleum Institute (API):
1. API Specification 6D “Specification for Pipeline Valves (Gate, Plug, Ball, and Check Valves)” (21st edition, 1994).
2. API Standard 620 “Design and Construction of Large, Welded, Low-Pressure Storage Tanks” (8th edition, 1990).
3. API Standard 1104 “Welding of Pipelines and Related Facilities” (18th edition, 1994).
E. American Society of Mechanical Engineers (ASME):
1. ASME/ANSI B31.3 “Process Piping” (1996)—Includes 1996 Addenda.
2. ASME/ANSI B31.5 “Refrigeration Piping” (1992 edition with ASME B31.5a-1994 Addenda).
3. ASME/ANSI B31.8 “Gas Transmission and Distribution Piping Systems” (1995).
4. ASME Boiler and Pressure Vessel Code, Section I “Power Boilers” (1995 edition with 1995 Addenda).
5. ASME Boiler and Pressure Vessel Code, Section IV, “Heating Boilers” (1995 edition with 1995 Addenda).
6. ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 “Pressure Vessels” (1995 edition with 1995 Addenda).
7. ASME Boiler and Pressure Vessel Code, Section VIII, Division 2, “Pressure Vessels: Alternative Rules” (1995 edition with 1995 Addenda).
8. ASME Boiler and Pressure Vessel Code, Section IX, “Welding and Brazing Qualifications” (1995 edition with 1995 Addenda).
F. Gas Research Institute (GRI):
1. GRI-89/0176 “LNGFIRE: A Thermal Radiation Model for LNG Fires” (June 29, 1990).
2. GRI-89/0242 “LNG Vapor Dispersion Prediction with the DEGADIS Dense Gas Dispersion Model” (April 1988-July 1990).
G. International Conference of Building Officials (ICBU):
1. NFPA 30 “Flammable and Combustible Liquids Code” (1996).
H. National Fire Protection Association (NFPA):
1. ANSI/NFPA 30 “Flammable and Combustible Liquids Code” (1993)
2. ANSI/NFPA 37 “Standard for the Installation and Use of Stationary Combustion Engines and Gas Turbines” (1994).
3. ANSI/NFPA 51B “Standard for Fire Prevention in Use of Cutting and Welding Processes” (1994).
4. ANSI/NFPA 59A “Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)” (1972 edition for § 193.2005(c), otherwise 1996 edition).
5. ANSI/NFPA 70 “National Electrical Code” (1996).
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 stipulated response times for a specified geographic area.
(a) After February 18, 1993, 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) After August 18, 1993, an operator must operate its onshore pipeline facilities in accordance with the applicable response plan.
(c) After August 18, 1993, 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, or unless RSPA grants a request from the OSC to require an operator of the following pipelines to submit a response plan or the pipeline is covered by § 194.103, each operator of an onshore pipeline facility shall prepare a response plan and submit the response plan to RSPA, as provided in § 194.119.
(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).
(a) Each response plan must plan for resources for responding, to the maximum extent practicable, to a worst case discharge, and to a substantial threat of such a discharge.
(b) Each response plan must be written in English and also, if applicable, in a language that is understood by the
(c) Each response plan must be consistent with the National Contingency Plan (NCP) (40 CFR part 300) and each applicable Area Contingency Plan (ACP). An operator must certify that it has reviewed the NCP and each applicable ACP and that its response plan is consistent with the existing NCP and each existing applicable ACP.
(d) 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 types, schedules, and procedures, and
(x) Plan review and update procedures; and
(2) An appendix for each response zone. Each response zone appendix must include the information required in paragraph (d)(1) (i)-(ix) of this section that is specific to the response zone and the worst case discharge calculations.
(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) Name the qualified individual; 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 following locations:
(1) The response plan at the operator's headquarters;
(2) The core plan and relevant response zone appendices for each line section whose pressure may be affected by the operation of a particular pump station, at that pump station; and
(3) The core plan and relevant response zone appendices at any other locations where response activities may be conducted.
(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 name and telephone number of the qualified individual available on a 24-hour basis;
(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 which are available to respond within the time specified, after discovery of a worst case discharge, or to mitigate the substantial threat of such a discharge, as follows:
(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: Pipeline Response Plans Officer, Research and Special Programs Administration, Department of Transportation, 400 Seventh Street, SW., Washington, DC 20590-0001.
(b) If RSPA determines that a response plan requiring approval does not meet all the requirements of this part, RSPA 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 RSPA determination that a plan contains alleged deficiencies may petition RSPA for reconsideration within 30 days from the date of receipt of RSPA's notice. After considering all relevant material presented in writing or at an informal conference, RSPA will notify the operator of its final decision. The operator must comply with the final decision within 30 days of issuance unless RSPA allows additional time.
(d) For those response zones of pipelines, described in § 194.103(c), that could reasonably be expected to cause
(e) If RSPA has not approved a response plan for a pipeline described in § 194.103(c), the operator may submit a certification to RSPA by July 18, 1993, 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. The certificate must be signed by the qualified individual or an appropriate corporate officer.
(f) If RSPA receives a request from an OSC to review a response plan, RSPA may require an operator to provide a copy of the response plan to the OSC. If an OSC recommends that an operator not previously required to submit a plan to RSPA, should submit one, RSPA will require the operator to prepare and submit a response plan and send a copy to the OSC.
(a) Each operator shall review its response plan at least every 5 years from the date of submission and modify the plan to address new or different operating conditions or information included in the plan.
(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 RSPA. 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 RSPA determines that a change to a response plan does not meet the requirements of this part, RSPA 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 RSPA for reconsideration, within 30 days from the date of receipt of RSPA's notice. After considering all relevant material presented in writing or at the conference, RSPA will notify the operator of its final decision. The operator must comply with the final decision within 30 days of issuance unless RSPA allows additional time.
This appendix provides a recommended form for the preparation and submission of response plans required by 49 CFR part 194. Operators may use other forms provided the form chosen provides the information required by 49 CFR part 194.
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.
This part prescribes safety standards and reporting requirements for pipeline facilities used in the transportation of hazardous liquids or carbon dioxide.
(a) Except as provided in paragraph (b) of this section, this part applies to pipeline facilities and the transportation of hazardous liquids or carbon dioxide associated with those facilities in or affecting interstate or foreign commerce, including pipeline facilities on the Outer Continental Shelf.
(b) This part does not apply to—
(1) Transportation of a hazardous liquid that is transported in a gaseous state;
(2) Transportation of a hazardous liquid through a pipeline by gravity;
(3) Transportation through any of the following low-stress pipelines:
(i) An onshore pipeline or pipeline segment that—
(A) Does not transport HVL;
(B) Is located in a rural area; and
(C) Is located outside a waterway currently used for commercial navigation;
(ii) A pipeline subject to safety regulations of the U.S. Coast Guard; or
(iii) A pipeline that serves refining, manufacturing, or truck, rail, or vessel terminal facilities, if the pipeline is less than 1 mile long (measured outside facility grounds) and does not cross an offshore area or a waterway currently used for commercial navigation;
(4) Transportation of petroleum in onshore gathering lines in rural areas except gathering lines in the inlets of the Gulf of Mexico subject to § 195.413;
(5) Transportation of hazardous liquid or carbon dioxide in offshore pipelines which are located upstream from the outlet flange of each facility where hydrocarbons or carbon dioxide are produced or where produced hydrocarbons or carbon dioxide are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream;
(6) Transportation of hazardous liquid or carbon dioxide in Outer Continental Shelf pipelines which are located upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator.
(7) 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;
(8) Transportation of 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 that 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, not including any device and associated piping that are necessary to control pressure in the pipeline under § 195.406(b); and
(9) Transportation of carbon dioxide downstream from the following point, as applicable:
(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 that transports carbon dioxide to injection wells or to headers or manifolds from which pipelines branch to injection wells.
(c) A low-stress pipeline to which this part applies that exists on July 12, 1994 need not comply with this part or part 199 of this chapter until July 12, 1996, except as follows:
(1) Subpart B of this part applies beginning on October 10, 1994; and
(2) Any replacement, relocation, or other change made to existing pipelines after October 9, 1994 must comply with subparts A and C through E of this part.
By Amdt. 195-64, 63 FR 46693, Sept. 2, 1998, § 195.1 was amended by revising paragraph (b)(3), effective Oct. 2, 1998. For the convenience of the user, the superseded text is set forth as follows:
(b) * * *
(3) Transportation of non-HVL through low-stress pipelines, except for any pipeline or pipeline segment that is located—
(i) In an onshore area other than a rural area;
(ii) Offshore; or
(iii) In a waterway that is navigable in fact and currently used for commercial navigation;
As used in this part—
By Amdt. 195-62, 63 FR 36376, July 6, 1998, § 195.2 was amended by adding the definition for “Computational Pipeline Monitoring”, effective July 6, 1999.
(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 Research and Special Programs Administration, 400 Seventh Street, SW., Washington, DC, and at the Office of the Federal Register, 800 North Capitol Street, NW., suite 700, Washington, DC. These materials have been approved for incorporation by reference by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. In addition, materials incorporated by reference are available as follows:
(1) American Gas Association (AGA), 1515 Wilson Boulevard, Arlington, VA 22209.
(2) American Petroleum Institute (API), 1220 L Street, NW., Washington, DC 20005.
(3) The American Society of Mechanical Engineers (ASME), United Engineering Center, 345 East 47th Street, New York, NY 10017.
(4) Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park Street, NE., Vienna, VA 22180.
(5) American National Standards Institute (ANSI), 11 West 42nd Street, New York, NY 10036.
(6) American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, West Conshohocken, PA 19428.
(c) The full title for the publications incorporated by reference in this part are as follows. Numbers in parentheses indicate applicable editions:
(1) American Gas Association (AGA): AGA Pipeline Research Committee, Project PR-3-805, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe” (December 1989). The RSTRENG program may be used for calculating remaining strength.
(2) American Petroleum Institute (API):
(i) API 1130 “Computational Pipeline Monitoring” (1st Edition, 1995).
(ii) API Specification 5L “Specification for Line Pipe” (41st edition, 1995).
(iii) API Specification 6D “Specification for Pipeline Valves (Gate, Plug, Ball, and Check Valves)” (21st Edition, 1994).
(iv) API Specification 1104 “Welding of Pipelines and Related Facilities” (18th edition, 1994).
(3) American Society of Mechanical Engineers (ASME):
(i) ASME/ANSI B16.9 “Factory-Made Wrought Steel Buttwelding Fittings” (1993).
(ii) ASME/ANSI B31.4 “Liquid Transportation Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and Alcohols” (1992 edition with ASME B31.4a-1994 Addenda).
(iii) ASME/ANSI B31.8 “Gas Transmission and Distribution Piping Systems” (1995)
(iv) ASME/ANSI B31G “Manual for Determining the Remaining Strength of Corroded Pipelines” (1991).
(v) ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 “Pressure Vessels” (1995 edition with 1995 Addenda).
(vi) ASME Boiler and Pressure Vessel Code, Section IX “Welding and Brazing Qualifications” (1995 edition with 1995 Addenda).
(4) Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS):
(i) MSS SP-75 “Specification for High Test Wrought Butt Welding Fittings” (1993).
(ii) [Reserved]
(5) American Society for Testing and Materials (ASTM):
(i) ASTM Designation A 53 “Standard specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated Welded and Seamless” (A 53-96).
(ii) ASTM Designation: A 106 “Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service” (A 106-95).
(iii) ASTM Designation: A 333/A 333M “Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service”(A 333/A 333M-94).
(iv) ASTM Designation: A 381 “Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High-Pressure Transmission Systems” (A 381-93).
(v) ASTM Designation: A 671 “Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Temperatures” (A 671-94).
(vi) ASTM Designation: A 672 “Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures” (A 672-94).
(vii) ASTM Designation: A 691 “Standard Specification for Carbon and Alloy Steel Pipe Electric-Fusion-Welded for High- Pressure Service at High Temperatures” (A 691-93).
By Amdt. 195-62, 63 FR 36376, July 6, 1998, § 195.3 was amended by redesignating paragraphs (c)(2)(i) through (c)(2)(iii) as paragraphs (c)(2)(ii) through
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 which qualifies for use under this section need not comply with the corrosion control requirements of this part until 12 months after it is placed in service, notwithstanding any earlier deadlines for compliance. In addition to the requirements of subpart F of this part, the corrosion control requirements of subpart D apply to each pipeline which substantially meets those requirements before it is placed in service or which is a segment that is replaced, relocated, or substantially altered.
(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.
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 the pipeline. If the Administrator determines that the transportation of the hazardous liquid or carbon dioxide in the manner proposed would be unduly hazardous, he will, within 90 days after receipt of the notice, order the person that gave the notice, in writing, not to transport the hazardous liquid or carbon dioxide in the proposed manner until further notice.
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 RSPA 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.
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) Loss of 50 or more barrels (8 or more cubic meters) of hazardous liquid or carbon dioxide.
(c) Escape to the atmosphere of more than 5 barrels (0.8 cubic meters) a day of highly volatile liquids.
(d) Death of any person.
(e) Bodily harm to any person resulting in one or more of the following:
(1) Loss of consciousness.
(2) Necessity to carry the person from the scene.
(3) Necessity for medical treatment.
(4) Disability which prevents the discharge of normal duties or the pursuit of normal activities beyond the day of the accident.
(f) 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 267-
(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 the cause of the failure or extent of the damages.
(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
(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 Information Officer, Research and Special Programs Administration, Department of Transportation, 400 Seventh Street, SW., Washington, DC 20590.
Each written report required by this subpart must be made to the Information Resources Manager, Office of Pipeline Safety, Research and Special Programs Administration, U.S. Department of Transportation, Room 2335, 400 Seventh Street SW., Washington DC 20590. 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
If the Department of Transportation investigates an accident, the operator involved shall make available to the representative of the Department all
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 Information Resources Manager, Office of Pipeline Safety, Department of Transportation, Washington, DC 20590.
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 that are not measured must be verified by applying a gage set to the minimum thickness found by the measurement. The nominal wall thickness to be used is the next wall thickness found in commercial specifications that is below the average of all the measurements taken. However, the nominal wall thickness may not be more than 1.14 times the smallest measurement taken on pipe that is less than 20 inches (508 mm) nominal outside diameter, nor more than 1.11 times the smallest measurement taken on pipe that is 20 inches (508 mm) or more in nominal outside diameter.
(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
(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 5 of API Standard 6D.
(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.
Each above ground breakout tank must be designed to withstand the internal pressure produced by the hazardous liquid to be stored therein and any anticipated external loads.
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.
By Amdt. 195-62, 63 FR 36376, July 6, 1997, § 195.134 was added, effective July 6, 1999.
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.
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 to produce welds meeting the requirements of this subpart. The quality of the test welds used to qualify the procedure shall be determined by destructive testing.
(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).
Each welder must be qualified in accordance with section 3 of API Standard 1104 or section IX of the ASME Boiler and Pressure Vessel Code, except that a welder qualified under an earlier edition than listed in § 195.3 may weld but may not requalify under that earlier edition.
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
(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 6 of API Standard 1104. However, if a girth weld is unacceptable under those standards for a reason other than a crack, and if the Appendix to API Standard 1104 applies to the weld, the acceptability of the weld may be determined under that appendix.
(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, river, lake, reservoir, or other body of water, and any offshore area;
(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
Each component in the pipeline system must be provided with protection against external corrosion.
(a) No pipeline system component may be buried or submerged unless that component has an external protective coating that—
(1) Is designed to mitigate corrosion of the buried or submerged component;
(2) Has sufficient adhesion to the metal surface to prevent underfilm migration of moisture;
(3) Is sufficiently ductile to resist cracking;
(4) Has enough strength to resist damage due to handling and soil stress; and
(5) Supports any supplemental cathodic protection.
(b) All pipe coating must be inspected just prior to lowering the pipe into the ditch or submerging the pipe, and any damage discovered must be repaired.
(a) A cathodic protection system must be installed for all buried or submerged facilities to mitigate corrosion
(b) A cathodic protection system must be installed not later than 1 year after completing the construction.
(a) Except for offshore pipelines, electrical test leads used for corrosion control or electrolysis testing must be installed at intervals frequent enough to obtain electrical measurements indicating the adequacy of the cathodic protection.
(b) Test leads must be installed as follows:
(1) Enough looping or slack must be provided to prevent test leads from being unduly stressed or broken during backfilling.
(2) Each lead must be attached to the pipe so as to prevent stress concentration on the pipe.
(3) Each lead installed in a conduit must be suitably insulated from the conduit.
(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, all offshore pipe in water at least 3.7 m (12 ft) deep but not more than 61 m (200 ft) deep, as measured from the mean low tide, 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.
(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 sea bottom, as applicable, complies with the following table:
(b) Except for the Gulf of Mexico and its inlets, 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.
Backfilling must be performed in a manner that protects any pipe coating and provides firm support for the pipe.
(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.
For above ground breakout tanks—
(a) A means must be provided for containing hazardous liquids in the event of spillage or tank failure.
(b) Tank areas must be adequately protected against unauthorized entry.
(c) Normal and emergency relief venting must be provided for each tank.
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 § 195.304(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
(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.
(c) Except for onshore pipelines that transport HVL, 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).
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.
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; and
(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.
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.
(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 respondinq 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 ignition by assisting with evacuation of residents and assisting with halting traffic on roads and railroads in the affected area, or taking other appropriate action.
(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 operating and maintenance personnel to:
(1) Carry out the operating and maintenance, and 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 the 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 liquid or carbon dioxide spills, and to 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;
(5) Learn the proper use of firefighting procedures and equipment, fire suits, and breathing apparatus by utilizing, where feasible, a simulated pipeline emergency condition; and
(6) In the case of maintenance personnel, to safely repair facilities using appropriate special precautions, such as isolation and purging, when highly volatile liquids are involved.
(b) At 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 training program set forth in paragraph (a) of this section; and
(2) Make appropriate changes to the training program as necessary to insure that it is effective.
(c) Each operator shall require and verify that its supervisors maintain a thorough knowledge of that portion of the procedures established under § 195.402 for which they are responsible to insure 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) Cathodically protected facilities;
(vi) Facilities to which § 195.402(c)(9) applies;
(vii) Rights-of-way; and
(viii) 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) 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 § 195.304.
(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 controls and protective equipment to control the pressure within this limit.
(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) If, as a result of an inspection under paragraph (a) of this section, or upon notification by any person, an operator discovers that a pipeline it operates is exposed on the seabed or constitutes 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 after November 1 of the year that the discovery is made, place the pipeline so that the top of the pipe is 36 inches (914
(a) No operator may operate a hazardous liquid interstate pipeline after March 31, 1973, a hazardous liquid intrastate pipeline after October 19, 1988, or a carbon dioxide pipeline after July 12, 1993 that has an effective external surface coating material, unless that pipeline is cathodically protected. This paragraph does not apply to breakout tank areas and buried pumping station piping. For the purposes of this subpart, a pipeline does not have an effective external coating, and shall be considered bare, if its cathodic protection current requirements are substantially the same as if it were bare.
(b) Each operator shall electrically inspect each bare hazardous liquid interstate pipeline, other than a low-stress pipeline, before April 1, 1975; each bare hazardous liquid intrastate pipeline, other than a low-stress pipeline, before October 20, 1990; each bare carbon dioxide pipeline before July 12, 1994; and each bare low-stress pipeline before July 12, 1996 to determine any areas in which active corrosion is taking place. The operator may not increase its established operating pressure on a section of bare pipeline until the section has been so electrically inspected. In any areas where active corrosion is found, the operator shall provide cathodic protection. Section 195.416(f) and (g) apply to all corroded pipe that is found.
(c) Each operator shall electrically inspect all breakout tank areas and buried pumping station piping on hazardous liquid interstate pipelines, other than low-stress pipelines, before April 1, 1973; on hazardous liquid intrastate pipelines, other than low-stress pipelines, before October 20, 1988; on carbon dioxide pipelines before July 12, 1994; and on low-stress pipelines before July 12, 1996 as to the need for cathodic protection, and cathodic protection shall be provided where necessary.
(a) Each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, conduct tests on each buried, in contact with the ground, or submerged pipeline facility in its pipeline system that is under cathodic protection to determine whether the protection is adequate.
(b) Each operator shall maintain the test leads required for cathodic protection in such a condition that electrical measurements can be obtained to ensure adequate protection.
(c) Each operator shall, at intervals not exceeding 2
(d) Each operator shall, at intervals not exceeding 5 years, electrically inspect the bare pipe in its pipeline system that is not cathodically protected and must study leak records for that pipe to determine if additional protection is needed.
(e) Whenever any buried pipe is exposed for any reason, the operator shall examine the pipe for evidence of external corrosion. If the operator finds that there is active corrosion, that the surface of the pipe is generally pitted, or that corrosion has caused a leak, it shall investigate further to determine the extent of the corrosion.
(f) Any pipe that is found to be generally corroded so that the remaining wall thickness is less than the minimum thickness required by the pipe specification tolerances must either be replaced with coated pipe that meets the requirements of this part or, if the area is small, must be repaired. However, the operator need not replace generally corroded pipe if the operating pressure is reduced to be commensurate with the limits on operating pressure specified in this subpart, based on the actual remaining wall thickness.
(g) If localized corrosion pitting is found to exist to a degree where leakage might result, the pipe must be replaced or repaired, or the operating pressure must be reduced commensurate with the strength of the pipe based on the actual remaining wall thickness in the pits.
(h) The strength of the pipe, based on actual remaining wall thickness, for paragraphs (f) and (g) of this section may be determined by the procedure in ASME B31G manual for Determining the Remaining Strength of Corroded Pipelines or by the procedure developed by AGA/Battelle—A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (with RSTRENG disk). Application of the procedure in the ASME B31G manual or the AGA/Battelle Modified Criterion is applicable to corroded regions (not penetrating the pipe wall) in existing steel pipelines in accordance with limitations set out in the respective procedures.
(i) Each operator shall clean, coat with material suitable for the prevention of atmospheric corrosion, and, maintain this protection for, each component in its pipeline system that is exposed to the atmosphere.
(a) No operator may transport any hazardous liquid or carbon dioxide that would corrode the pipe or other components of its pipeline system, unless it has investigated the corrosive effect of the hazardous liquid or carbon dioxide on the system and has taken adequate steps to mitigate corrosion.
(b) If corrosion inhibitors are used to mitigate internal corrosion the operator shall use inhibitors in sufficient quantity to protect the entire part of the system that the inhibitors are designed to protect and shall also use coupons or other monitoring equipment to determine their effectiveness.
(c) The operator shall, at intervals not exceeding 7
(d) Whenever any pipe is removed from the pipeline for any reason, the operator must inspect the internal surface for evidence of corrosion. If the pipe is generally corroded such that the remaining wall thickness is less than the minimum thickness required by the pipe specification tolerances, the operator shall investigate adjacent pipe to determine the extent of the corrosion. The corroded pipe must be replaced with pipe that meets the requirements of this part or, based on the actual remaining wall thickness, the operating pressure must be reduced to be commensurate with the limits on operating pressure specified in this subpart.
(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
(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, but not less than 50 p.s.i. (345 kPa) gage above the vapor pressure of the commodity.
(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.
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.
Each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, inspect each breakout tank (including atmospheric and pressure tanks).
Each operator shall maintain signs visible to the public around each pumping station and breakout tank area. Each sign must contain the name of the operator and an emergency telephone number to contact.
Each operator shall provide protection for each pumping station and
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.
Each operator shall establish a continuing educational program to enable the public, appropriate government organizations and persons engaged in excavation-related activities to recognize a hazardous liquid or a carbon dioxide pipeline emergency and to report it to the operator or the fire, police, or other appropriate public officials. The program must be conducted in English and in other languages commonly understood by a significant number and concentration of non-English speaking population in the operator's operating areas.
(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. For the purpose 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 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.
By Amdt. 195-62, 63 FR 36376, July 6, 1998, § 195.444 was added, effective July 6, 1999.
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
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 within the meaning of the HLPSA. The types of situations in which DOT will ignore the existence or non-existence of a filing with FERC will be limited to those cases in which it appears obvious that a complaint filed with FERC would be successful or in which blind reliance on a FERC filing would result in a situation clearly not intended by the HLPSA such as a pipeline facility not being subject to either State or Federal safety regulation. DOT anticipates that the situations in which there is any question about the validity of the FERC filings as a ready reference will be few and that the actual variations from reliance on those filings will be rare. The following examples indicate the types of facilities which DOT believes are interstate pipeline facilities subject to the HLPSA despite the lack of a filing with FERC and the types of facilities over which DOT will generally defer to the jurisdiction of a certifying state despite the existence of a filing with FERC.
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.
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, RSPA 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
(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 applicable State statute of limitations on tort actions.
(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.
(a) This part requires operators of pipeline facilities subject to part 192, 193, or 195 of this chapter to test employees for the presence of prohibited drugs and provide an employee assistance program. However, this subpart does not apply to operators of “master meter systems” as defined in § 191.3 of this chapter or to liquefied petroleum gas (LPG) operators.
(b) Operators with more than 50 employees subject to drug testing under this part need not comply with this part until April 20, 1990. Operators with 50 or fewer employees subject to drug testing under this part need not comply with this part until August 21, 1990.
(c) This part shall not apply to any person for whom compliance with this part would violate the domestic laws or policies of another country.
(d) This part applies to pipeline operators, only with respect to pipeline 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).
As used in this part—
The anti-drug program required by this part must be conducted according to the requirements of this part and the DOT Procedures. In the event of conflict, the provisions of this part prevail. Terms and concepts used in this part have the same meaning as in the DOT Procedures.
(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 § 199.15(d)(2); 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 recommended by the medical review officer for return to duty in accordance with § 199.15(c); 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 § 199.25 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 § 199.25 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-
(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 drug testing at the percentage rate established for the calendar year by the DOT agency regulating more than 50 percent of the employee's function.
(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)
(1) Review the results of drug testing before they are reported to the operator.
(2) Review and interpret each confirmed positive test result as follows to determine if there is an alternative medical explanation for the confirmed positive test result:
(i) Conduct a medical interview with the individual tested.
(ii) Review the individual's medical history and any relevant biomedical factors.
(iii) Review all medical records made available by the individual tested to determine if a confirmed positive test resulted from legally prescribed medication.
(iv) If necessary, require that the original specimen be reanalyzed to determine the accuracy of the reported test result.
(v) Verify that the laboratory report and assessment are correct.
(3) Ensure that an employee has been drug tested in accordance with the DOT Procedures before the employee returns to duty.
(d)
(1) If the MRO determines, after appropriate review, that there is a legitimate medical explanation for the confirmed positive test result other than the unauthorized use of a prohibited drug, the MRO is not required to take further action.
(2) If the MRO determines, after appropriate review, that there is no legitimate medical explanation for the confirmed positive test result other than the unauthorized use of a prohibited drug, the MRO shall refer:
(i) The individual tested to a personnel or administrative office for further proceedings in accordance with the operator's anti-drug plan; and
(ii) For evaluation by a SAP who shall determine what assistance, if any, the employee needs in resolving problems associated with drug misuse.
(3) Based on a review of laboratory inspection reports, quality assurance and quality control data, and other drug test results, the MRO may conclude that a particular drug test result is scientifically insufficient for further action. Under these circumstances, the MRO should conclude that the test is negative for the presence of a prohibited drug or drug metabolite in an individual's system.
(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
(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, the original sample must be retested if the employee makes a written request for retesting within 60 days of receipt of the final test result from the MRO. The employee may specify retesting 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 retest is negative.
(c) If the employee specifies retesting 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 may contract with an entity that provides EAP services. Each EAP must include education and training on drug use. At the discretion of the operator, the EAP may include an opportunity for employee rehabilitation.
(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 results that show employees who had a positive test, and the type of test (e.g., post-accident), and records that demonstrate rehabilitation, if any, must be kept for at least 5 years, and include the following information:
(i) The function performed by each employee who had a positive drug test result.
(ii) The prohibited drug(s) that were used by an employee who had a positive drug test.
(iii) The disposition of each employee who had a positive drug test or refused a drug test (e.g., termination, rehabilitation, removed from covered function, other).
(3) Records of employee drug test results that show employees passed a drug test must be kept for at least 1 year.
(4) A record of the number of employees tested, by type of test (e.g., post-accident), must be kept for at least 5 years.
(5) 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 may be released only upon the written consent of the individual, except that such information must be released regardless of consent to the Administrator or the representative of a state agency upon request as part of an accident investigation. 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 RSPA of its anti-drug testing results in the form and manner prescribed by the Administrator, 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 RSPA.
(b) Each report, required under this section, shall be submitted to the Office of Pipeline Safety Compliance (OPS), Research and Special Programs Administration, Department of Transportation, room 2335, 400 Seventh Street, SW., Washington, DC 20590.
(c) Each report shall be submitted in the form and manner prescribed by the Administrator. No other form, including another DOT Operating Administration's MIS form, is acceptable for submission to RSPA.
(d) Each report shall be signed by the Operator's anti-drug manager or designated representative. RSPA will allow the operator the option of sending the report on the computer disk provided by RSPA. If this option is used, a signature page attesting to the validity of the information on the computer disk must be sent to the address in paragraph (b) of this section.
(e) Each operator's report with verified positive test results or refusals to
(1) Number of covered employees.
(2) Number of covered employees subject to testing under the anti-drug rules of another operating administration.
(3) Number of specimens collected by type of test.
(4) Number of positive test results, verified by a Medical Review Officer (MRO), by type of test and type of drug.
(5) Number of employee action(s) taken following verified positive(s), by type of action(s).
(6) Number of negative tests reported by an MRO by type of test.
(7) Number of persons denied a position as a covered employee following a verified positive drug test.
(8) Number of covered employees, returned to duty during this reporting period after having failed or refused a drug test required under the RSPA rule.
(9) Number of covered employees with tests verified positive by an MRO for multiple drugs.
(10) Number of covered employees who refused to submit to a random or non-random (post-accident, reasonable cause, return-to- duty, or follow-up) drug test and the action taken in response to each refusal.
(11) Number of supervisors who have received required initial training during the reporting period.
(f) Each operator's report with only negative test results shall include all of the following informational elements:
(1) Number of covered employees.
(2) Number of covered employees subject to testing under the anti-drug rules of another operating administration.
(3) Number of specimens collected by type of test.
(4) Number of negative tests reported by an MRO by type of test.
(5) Number of covered employees who refused to submit to a random or non-random (post-accident, reasonable cause, return-to-duty, or follow-up) drug test and the action taken in response to each refusal.
(6) Number of supervisors who have received required initial training during the reporting period.
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.
This subpart applies to gas, hazardous liquid and carbon dioxide pipeline operators and liquefied natural gas operators subject to parts 192, 193, or 195 of this chapter. However, this subpart does not apply to operators of master meter systems defined in § 191.3 or liquefied petroleum gas (LPG) operators as discussed in § 192.11 of this chapter.
Each operator shall maintain and follow a written alcohol misuse plan that conforms to the requirements of this subpart and the DOT procedures in part 40 of this title. 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.
Each operator shall ensure that all alcohol testing conducted under this subpart complies with the procedures set forth in part 40 of this title. The provisions of 49 CFR part 40 that address alcohol testing are made applicable to operators by this subpart.
As used in this subpart:
(a) Except as provided in paragraph (b) of this section, this subpart 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 subpart is not possible;
(2) Compliance with the State or local requirement is an obstacle to the accomplishment and execution of any requirement in this subpart; or
(3) The State or local requirement is a pipeline safety standard applicable to interstate pipeline facilities.
(b) This subpart shall not be construed to preempt provisions of State
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.
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.
(a)
(b)
(c) All operators commencing operations after February 15, 1994 shall have an alcohol misuse program that conforms to this subpart by January 1, 1996, or by the date an operator begins operations, whichever is later.
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) For the years stated in this paragraph, employers who submit MIS reports shall submit to RSPA each record of a test required by this section that is not completed within 8 hours. The employer's records of tests that could not be completed within 8 hours shall be submitted to RSPA by March 15, 1996; March 15, 1997; and March 15, 1998; for calendar years 1995, 1996, and 1997, respectively. Employers shall append these records to their MIS submissions. Each record shall include the following information:
(A) Type of test (reasonable suspicion/post-accident);
(B) Triggering event (including date, time, and location);
(C) Employee category (do not include employee name or other identifying information);
(D) Reason(s) test could not be completed within 8 hours; and
(E) If blood alcohol testing could have been completed within eight hours, the name, address, and telephone number of the testing site where blood testing could have occurred.
(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 RSPA upon request of the Administrator.
(ii) For the years stated in this paragraph, employers who submit MIS reports shall submit to RSPA each record of a test required by this section that is not completed within 8 hours. The employer's records of tests that could not be completed within 8 hours shall be submitted to RSPA by March 15, 1996; March 15, 1997; and March 15, 1998; for calendar years 1995, 1996, and 1997, respectively. Employers shall append these records to their MIS submissions. Each record shall include the following information:
(A) Type of test (reasonable suspicion/post-accident);
(B) Triggering event (including date, time, and location);
(C) Employee category (do
(D) Reason(s) test could not be completed within 8 hours; and
(E) If blood alcohol testing could have been completed within eight hours, the name, address, and telephone number of the testing site where blood testing could have occurred.
(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 management information system (MIS) report to RSPA of its alcohol testing results in the form and manner prescribed by the Administrator, by March 15 of each year for the previous calendar year (January 1 through December 31). The Administrator may require by written notice that a small operator (50 or fewer covered employees), not otherwise required to submit annual MIS reports, submit such a report to RSPA.
(b) Each operator that is subject to more than one DOT agency alcohol rule shall identify each employee covered by the regulations of more than
(c) Each report, required under this section, shall be submitted to the Office of Pipeline Safety, Research and Special Programs Administration, Department of Transportation, room 2335, 400 Seventh Street, SW., Washington, DC 20590. RSPA will allow the operator the option of sending the report on the computer disk provided by RSPA. If this option is used, a signature page attesting to the validity of the information on the computer disk must be sent to the address in this section.
(d) Each report that contains information on an alcohol screening test result of 0.02 or greater or a violation of the alcohol misuse provisions of §§ 199.215 through 199.223 of this subpart shall be submitted on “RSPA Alcohol Testing MIS Data Collection Form” and include the following informational elements:
(1) Number of covered employees.
(2) Number of covered employees subject to testing under the alcohol misuse rule of another operating administration by each agency.
(3)(i) Number of screening tests by type of test.
(ii) Number of confirmation tests by type of test.
(4) Number of confirmation tests indicating an alcohol concentration of 0.02 or greater but less than 0.04, by type of test.
(5) Number of confirmation tests indicating an alcohol concentration of 0.04 or greater, by type of test.
(6) Number of covered employees with a confirmation test indicating an alcohol concentration of 0.04 or greater or who have violations of other alcohol misuse provisions who were returned to duty in covered positions (having complied with the recommendations of a substance abuse professional as described in §§ 199.235 and 199.243).
(7) Number of covered employees who were administered alcohol and drug tests at the same time, with both a positive drug test and an alcohol test indicating an alcohol concentration of 0.04 or greater.
(8) Number of covered employees who were found to have violated other provisions of §§ 199.215 through 199.221, and any action taken in response to the violation.
(9) Number of covered employees who refused to submit to an alcohol test required under this subpart, and the action taken in response to the refusal.
(10) Number of supervisors who have received required training during the reporting period in determining the existence of reasonable suspicion of alcohol misuse.
(e) Each report with no screening alcohol test results of 0.02, or greater or violations of the alcohol misuse provisions of §§ 199.215 through 199.223 of this subpart shall be submitted on “RSPA Alcohol Testing MIS Data Collection EZ Form” and include the following informational elements. (This “EZ” report may only be submitted if the program results meet these criteria)
(1) Number of covered employees.
(2) Number of covered employees subject to testing under the alcohol misuse rule of another operating administration identified by each agency.
(3) Number of screening tests by type of test.
(4) Number of covered employees who refused to submit to an alcohol test required under this subpart, and the action taken in response to the refusal.
(5) Number of supervisors who have received required training during the reporting period in determining the existence of reasonable suspicion of alcohol misuse.
(f) A consortium may prepare reports on behalf of individual pipeline operators for purposes of compliance with this reporting requirement. However, the pipeline operator shall sign and submit such a report and shall remain responsible for ensuring the accuracy and timeliness of each report prepared on its behalf by a consortium.
(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 a 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 an accident investigation, an operator shall disclose information related to the operator's administration of any post- accident alcohol tests administered following the accident under investigation.
(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 required to be maintained under this subpart pertaining to a covered employee to the employee or the decisionmaker in a lawsuit, grievance, or other proceeding initiated by or on behalf of the individual, and arising from the results of an alcohol test administered under this subpart, or from the operator's determination that the covered employee engaged in conduct prohibited by §§ 199.215 through 199.223 (including, but not limited to, a worker's compensation, unemployment compensation, or other proceeding relating to a benefit sought by the employee).
(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
(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 may include testing for drugs, as directed by the substance abuse professional, to be performed in accordance with 49 CFR part 40. Follow-up testing shall not exceed 60 months from the date of the employee's return to duty. The substance abuse professional may terminate the requirement for follow-up testing at any time after the first six tests have been administered, if the substance abuse professional determines that such testing is no longer necessary.
(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.
Material Approved for Incorporation by Reference
Table of CFR Titles and Chapters
Alphabetical List of Agencies Appearing in the CFR
List of CFR Sections Affected
The Director of the Federal Register has approved under 5 U.S.C. 552(a) and 1 CFR Part 51 the incorporation by reference of the following publications. This list contains only those incorporations by reference effective as of the revision date of this volume. Incorporations by reference found within a regulation are effective upon the effective date of that regulation. For more information on incorporation by reference, see the preliminary pages of this volume.
All changes in this volume of the Code of Federal Regulations which were made by documents published in the
For the period before January 1, 1986, see the “List of CFR Sections Affected, 1949-1963, 1964-1972, and 1973-1985” published in seven separate volumes.