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Updated through October 15, 2022
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What’s in this book?
Quick Reference
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§195.15
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Recent changes in regulations:
What requirements apply to reportingregulated-only gathering lines?
(a) Scope. Gathering lines that do not otherwise meet the definition of a regulated rural gathering line in §195.11 and any gathering line not already covered under §195.1(a)(1), (2), (3) or (4) must comply with the reporting requirements of subpart B of this part. 195.15(a)
(b) Implementation period 195.15(b)
(1) Annual reporting. Operators must comply with the reporting requirements in subpart B of this part by March 31, 2021. 195.15(b)(1)
(2) Accident and safety-related condition reporting. Operators must comply with the accident and safety-related condition reporting requirements in subpart B by January 1, 2021. 195.15(b)(2)
§195.18
How to notify PHMSA
(a) An operator must provide any notification required by this part by: 195.18(a)
(1) Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or 195.18(a)(1)
(2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE, Washington, DC 20590. 195.18(a)(2)
(b) An operator must also notify the appropriate State or local pipeline safety authority when an applicable pipeline segment is located in a State where OPS has an interstate agent agreement, or an intrastate pipeline segment is regulated by that State. 195.18(b)
(c) Unless otherwise specified, if an operator submits, pursuant to §195.258, §195.260, §195.418, §195.419, §195.420 or §195.452 a notification requesting use of a different integrity assessment method, analytical method, sampling it receives a letter from the Associate Administrator of Pipeline Safety informing the operator that PHMSA objects to the proposal, or that PHMSA requires additional time and/ or information to conduct its review. 195.18(c)
This book includes all PHMSA updates to the pipeline regulations through October 15th, 2022:
(1) Amended the pipeline safety regulations to explicitly state that certain coastal waters, the Great Lakes, and coastal beaches are classified as unusually sensitive areas for the purpose of compliance with the hazardous liquid integrity management regulations.
(2) Incorporated within its regulations language noting its employees' ability to refer actual or possible criminal activity in connection with PHMSA's jurisdictional statutes directly to the DOT Office of Inspector General (OIG).
(3) Extended safety reporting requirements to all onshore gas gathering operators and applied a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures. Included is the requirement that operators of all onshore gas gathering lines to report incidents and file annual reports under part 191.
(4) Codified that the safety-related condition reporting of MAOP exceedances is not required for operators of gathering lines not required to establish an MAOP pursuant to §§ 192.9(e) and (f) and 192.619.
(5) Revised the Federal Pipeline Safety Regulations applicable to most newly constructed and entirely replaced onshore gas transmission, Type A gas gathering, and hazardous liquid pipelines with diameters of 6 inches or greater. The revision requires operators of these lines to install rupture-mitigation valves (i.e., remote-control or automatic shut-off valves) or alternative equivalent technologies, and establishes minimum performance standards for those valves' operation to prevent or mitigate the public safety and environmental consequences of pipeline ruptures.
For more information about the most recent updates, check out Regs2Go.com.
Disclaimer
Although the author and publisher of this book have made every effort to ensure the accuracy and timeliness of the information contained herein, the author and publisher assume no liability with respect to loss or damage caused by or alleged to be caused by reliance on any information contained herein and disclaim any and all warranties, expressed or implied.
Part 190 Pipeline Safety Programs And Rulemaking Procedures .......................1
Part 191 Transportation of natural and other gas by pipeline; annual, incident, and other reporting ...............15
Part 192 Transportation Of Natural And Other Gas By Pipeline: Minimum Federal Safety Standards .......................19
Part 193 Liquefied Natural Gas Facilities: Federal Safety Standards........... 91
Part 194 Response Plans For Onshore Oil Pipelines .................101
Part 195 Transportation Of Hazardous Liquids By Pipeline ...................107
Part 196 Protection Of Underground Pipelines From Excavation Activity ..........................147
Part 198 Regulations For Grants To Aid State Pipeline Safety Programs ..........149
Insights
Part 190 – Pipeline Safety Programs And Rulemaking Procedures
Formal hearing means a formal review in accordance with 5 U.S.C. 554, conducted by an administrative law judge.
Hearing means an informal conference or a proceeding for oral presentation. Unless otherwise specifically prescribed in this part, the use of "hearing" is not intended to require a hearing on the record in accordance with section 554 of title 5, U.S.C.
Imminent hazard means the existence of a condition relating to a gas or hazardous liquid pipeline facility that presents a substantial likelihood that death, serious illness, severe personal injury, or a substantial endangerment to health, property, or the environment may occur before the reasonably foreseeable completion date of a formal proceeding begun to lessen the risk of such death, illness, injury or endangerment.
New and novel technologies means any products, designs, materials, testing, construction, inspection, or operational procedures that are not addressed in 49 CFR parts 192, 193, or 195, due to technology or design advances and innovation for new construction. Technologies that are addressed in consensus standards that are incorporated by reference into parts 192, 193, and 195 are not "new or novel technologies."
Operator means any owner or operator.
OPS means the Office of Pipeline Safety, which is part of the Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation.
Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof.
PHMSA means the Pipeline and Hazardous Materials Safety Administration of the United States Department of Transportation.
Presiding Official means the person who conducts any hearing relating to civil penalty assessments, compliance orders, orders directing amendment, safety orders, or corrective action orders and who has the duties and powers set forth in §190.212.
Regional Director means the head of any one of the Regional Offices of the Office of Pipeline Safety, or a designee appointed by the Regional Director. Regional Offices are located in Trenton, NJ (Eastern Region); Atlanta, Georgia (Southern Region); Kansas City, Missouri (Central Region); Houston, Texas (Southwest Region); and Lakewood, Colorado (Western Region).
Respondent means a person upon whom OPS has served an enforcement action described in this part.
State means a State of the United States, the District of Columbia and the Commonwealth of Puerto Rico.
§190.5 Service
(a) Each order, notice, or other document required to be served under this part, will be served personally, by certified mail, overnight courier, or electronic transmission by facsimile or other electronic means that includes reliable acknowledgement of actual receipt. 190.5(a)
(b) Service upon a person's duly authorized representative or agent constitutes service upon that person. 190.5(b)
Subpart A – General
§190.1 Purpose and scope
(a) This part prescribes procedures used by the Pipeline and Hazardous Materials Safety Administration in carrying out duties regarding pipeline safety under 49 U.S.C. 60101 et seq. (the pipeline safety laws) and 33 U.S.C. 1321 (the water pollution control laws). 190.1(a)
(b) This subpart defines certain terms and prescribes procedures that are applicable to each proceeding described in this part. 190.1(b)
§190.3 Definitions
As used in this part:
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Associate Administrator means the Associate Administrator for Pipeline Safety, or his or her delegate.
Chief Counsel means the Chief Counsel of PHMSA.
Day means a 24-hour period ending at 11:59 p.m. Unless otherwise specified, a day refers to a calendar day.
Emergency order means a written order issued in response to an imminent hazard imposing restrictions, prohibitions, or safety measures on owners and operators of gas or hazardous liquid pipeline facilities, without prior notice or an opportunity for a hearing.
(c) Service by certified mail or overnight courier is complete upon mailing. Service by electronic transmission is complete upon transmission and acknowledgement of receipt. An official receipt for the mailing from the U.S. Postal Service or overnight courier, or a facsimile or other electronic transmission confirmation, constitutes prima facie evidence of service. 190.5(c)
§190.7
Subpoenas; witness fees
(a) The Administrator, Chief Counsel, or the official designated by the Administrator to preside over a hearing convened in accordance with this part, may sign and issue subpoenas individually on his or her own initiative at any time, including pursuant to an inspection or investigation, or upon request and adequate showing by a participant to an enforcement proceeding that the information sought will materially advance the proceeding. 190.7(a)
(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. 190.7(b)
(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 mail. 190.7(c)
(d) Service of a subpoena upon the person named in the subpoena is achieved by delivering a copy of the subpoena to the person and by paying 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 a person in charge, leaving them at the person's residence with a person of suitable age and discretion residing there, by mailing them by 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. 190.7(d)
(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 achieved 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 certified mail to that agent or representative and the fees are made available prior to the return date. 190.7(e)
(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. 190.7(f)
(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. 190.7(g)
(h) Notwithstanding the provisions of paragraph (g) of this section, and upon request, the witness fees and mileage may be paid by the PHMSA if the official who issued the subpoena determines on the basis of good cause shown, that: 190.7(h)
(1) The presence of the subpoenaed witness will materially advance the proceeding; and 190.7(h)(1)
(2) The person at whose instance the subpoena was issued would suffer a serious hardship if required to pay the witness fees and mileage. 190.7(h)(2)
(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 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, or this issuing official, as the case may be, may: 190.7(i)
(1) Deny the application;190.7(i)(1)
(2) Quash or modify the subpoena; or190.7(i)(2)
(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. 190.7(i)(3)
(j) Upon refusal to obey a subpoena served upon any person under the provisions of this section, the PHMSA may request the Attorney General to seek the aid of the U. S. District Court for any District in which the person is found to compel that person, after notice, to appear and give testimony, or to appear and produce the subpoenaed documents before the PHMSA, or both. 190.7(j)
§190.9
Petitions for finding or approval
(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. 190.9(a)
(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. 190.9(b)
(1) For operators seeking a finding or approval involving intrastate pipeline transportation, petitions must be sent to: 190.9(b)(1)
(i) The State agency certified to participate under 49 U.S.C. 60105.190.9(b)(1)(i)
(ii) Where there is no state agency certified to participate, the Administrator, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE, Washington, DC 20590.190.9(b)(1)(ii)
(2) For operators seeking a finding or approval involving interstate pipeline transportation, petitions must be sent to the Administrator, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE, Washington, DC 20590. 190.9(b)(2)
(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. 190.9(c)
(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. 190.9(d)
§190.11
Availability of informal guidance and interpretive assistance
(a) Availability of telephonic and Internet assistance. PHMSA has established a Web site and a telephone line to OPS headquarters where information on and advice about compliance with the pipeline safety regulations specified in 49 CFR parts 190-199 is available. The Web site and telephone line are staffed by personnel from PHMSA's OPS from 9:00 a.m. through 5:00 p.m., Eastern Time, Monday through Friday, with the exception of Federal holidays. When the lines are not staffed, individuals may leave a recorded voicemail message or post a message on the OPS Web site. The telephone number for the OPS information line is (202) 366-4595 and the OPS Web site can be accessed via the Internet at http://phmsa.dot.gov/pipeline. 190.11(a)
(b) Availability of written interpretations. A written regulatory interpretation, response to a question, or an opinion concerning a pipeline safety issue may be obtained by submitting a written request to the Office of Pipeline Safety (PHP-30), PHMSA, U.S. Department of Transportation, 1200 New Jersey Avenue SE., Washington, DC 20590-0001. The requestor must include his or her return address and should also include a daytime telephone number. Written requests should be submitted at least 120 days before the time the requestor needs a response. 190.11(b)
Subpart B – Enforcement
§190.201 Purpose and scope
(a) This subpart describes the enforcement authority and sanctions exercised by the Associate Administrator for achieving and maintaining pipeline safety and compliance under 49 U.S.C. 60101 et seq., 33 U.S.C. 1321(j), and any regulation or order issued thereunder. It also prescribes the procedures governing the exercise of that authority and the imposition of those sanctions. 190.201(a)
(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. 190.201(b)
§190.203 Inspections and investigations
(a) Officers, employees, or agents authorized by the Associate Administrator for Pipeline Safety, PHMSA, upon presenting appropriate credentials, are authorized to enter upon, inspect, and examine, at reasonable times and in a reasonable manner, the records and properties of persons to the extent such records and properties are relevant to determining the compliance of such persons with the requirements of 49 U.S.C. 60101 et seq., or regulations or orders issued thereunder. 190.203(a)
(b) Inspections are ordinarily conducted pursuant to one of the following: 190.203(b)
(1) Routine scheduling by the Regional Director of the Region in which the facility is located; 190.203(b)(1)
(2) A complaint received from a member of the public;190.203(b)(2)
(3) Information obtained from a previous inspection;190.203(b)(3)
(4) Report from a State Agency participating in the Federal Program under 49 U.S.C. 60105; 190.203(b)(4)
(5) Pipeline accident or incident; or190.203(b)(5)
(6) Whenever deemed appropriate by the Associate Administrator. 190.203(b)(6)
(c) If the Associate Administrator or Regional Director believes that further information is needed to determine appropriate action, the Associate Administrator or Regional Director may notify the pipeline operator in writing that the operator is required to provide specific information within 30 days from the time the notification is received by the operator, unless otherwise specified in the notification. The notification must provide a reasonable description of the specific information required. An operator may request an extension of time to respond by providing a written justification as to why such an extension is necessary and proposing an alternative submission date. A request for an extension may ask for the deadline to be stayed while the extension is considered. General statements of hardship are not acceptable bases for requesting an extension. 190.203(c)
(d) To the extent necessary to carry out the responsibilities under 49 U.S.C. 60101 et seq., the Administrator, or the Associate Administrator, may require testing of portions of pipeline facilities that have been involved in, or affected by, an accident. However, before exercising this authority, the Administrator, or the Associate Administrator, shall make every effort to negotiate a mutually acceptable plan with the owner of those facilities and, where appropriate, the National Transportation Safety Board for performing the testing. 190.203(d)
(e) If a representative of the U.S. Department of Transportation inspects or investigates an accident or incident involving a pipeline facility, the operator must make available to the representative all
records and information that pertain to the event in any way, including integrity management plans and test results. The operator must provide all reasonable assistance in the investigation. Any person who obstructs an inspection or investigation by taking actions that were known or reasonably should have been known to prevent, hinder, or impede an investigation without good cause will be subject to administrative civil penalties under this subpart. 190.203(e)
(f) When OPS determines that the information obtained from an inspection or from other appropriate sources warrants further action, OPS may initiate one or more of the enforcement proceedings prescribed in this subpart. 190.203(f)
§190.205 Warnings
Upon determining that a probable violation of 49 U.S.C. 60101 et seq., 33 U.S.C. 1321(j), or any regulation or order issued thereunder has occurred, the Associate Administrator or a Regional Director may issue a written warning notifying the operator of the probable violation and advising the operator to correct it or be subject to potential enforcement action in the future. The operator may submit a response to a warning, but is not required to. An adjudication under this subpart to determine whether a violation occurred is not conducted for warnings.
§190.206 Amendment of plans or procedures
(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 will specify the alleged inadequacies and the proposed revisions of the plans or procedures and provide an opportunity to respond. The notice will allow the operator 30 days following receipt of the notice to submit written comments, revised procedures, or a request for a hearing under §190.211. 190.206(a)
(b) After considering all material presented in writing or at the hearing, if applicable, the Associate Administrator determines whether the plans or procedures are inadequate as alleged. The Associate Administrator issues an order directing amendment of the plans or procedures if they are inadequate, or withdraws the notice if they are not. In determining the adequacy of an operator's plans or procedures, the Associate Administrator may consider: 190.206(b)
(1) Relevant pipeline safety data;190.206(b)(1)
(2) Whether the plans or procedures are appropriate for the particular type of pipeline transportation or facility, and for the location of the facility; 190.206(b)(2)
(3) The reasonableness of the plans or procedures; and190.206(b)(3)
(4) The extent to which the plans or procedures contribute to public safety. 190.206(b)(4)
(c) An order directing amendment of an operator's plans or procedures prescribed in this section may be in addition to, or in conjunction with, other appropriate enforcement actions prescribed in this subpart. 190.206(c)
§190.207 Notice of probable violation
(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., 33 U.S.C. 1321(j), or any regulation or order issued thereunder. 190.207(a)
(b) A notice of probable violation issued under this section shall include: 190.207(b)
(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; 190.207(b)(1)
(2) Notice of response options available to the respondent under §190.208; 190.207(b)(2)
(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 190.207(b)(3)
(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. 190.207(b)(4)
(c) The Regional Director 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, proposes an increased civil penalty amount, or proposes new or additional remedial action under §190.217, the respondent will have the opportunity to respond under §190.208. 190.207(c)
§190.208 Response options
Within 30 days of receipt of a notice of probable violation, the respondent must answer the Regional Director who issued the notice in the following manner:
(a) When the notice contains a proposed civil penalty — 190.208(a)
(1) If the respondent is not contesting an allegation of probable violation, pay the proposed civil penalty as provided in §190.227 and advise the Regional Director of the payment. The payment authorizes the Associate Administrator to make a finding of violation and to issue a final order under §190.213; 190.208(a)(1)
(2) If the respondent is not contesting an allegation of probable violation but wishes to submit a written explanation, information, or other materials the respondent believes may warrant mitigation or elimination of the proposed civil penalty, the respondent may submit such materials. This authorizes the Associate Administrator to make a finding of violation and to issue a final order under §190.213; 190.208(a)(2)
(3) If the respondent is contesting one or more allegations of probable violation but is not requesting a hearing under §190.211, the respondent may submit a written response in answer to the allegations; or 190.208(a)(3)
(4) The respondent may request a hearing under §190.211. 190.208(a)(4)
(b) When the notice contains a proposed compliance order — 190.208(b)
(1) If the respondent is not contesting an allegation of probable violation, agree to the proposed compliance order. This authorizes the Associate Administrator to make a finding of violation and to issue a final order under §190.213; 190.208(b)(1)
(2) Request the execution of a consent order under §190.219; 190.208(b)(2)
(3) If the respondent is contesting one or more of the allegations of probable violation or compliance terms, but is not requesting a hearing under §190.211, the respondent may 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 190.208(b)(3)
(4) The respondent may request a hearing under §190.211. 190.208(b)(4)
(c) Before or after responding in accordance with paragraph (a) of this section or, when applicable paragraph (b) of this section, the respondent may request a copy of the violation report from the Regional Director as set forth in §190.209. The Regional Director will provide the violation report to the respondent within five business days of receiving a request. 190.208(c)
(d) Failure to respond in accordance with paragraph (a) of this section or, when applicable paragraph (b) of this section, constitutes a waiver of the right to contest the allegations in the notice of probable violation and authorizes the Associate Administrator, without further notice to the respondent, to find the facts as alleged in the notice of probable violation and to issue a final order under §190.213. 190.208(d)
(e) All materials submitted by operators in response to enforcement actions may be placed on publicly accessible Web sites. A respondent seeking confidential treatment under 5 U.S.C. 552(b) for any portion of its responsive materials must provide a second copy of such materials along with the complete original document. A respondent may redact the portions it believes qualify for confidential treatment in the second copy but must provide a written explanation for each redaction. 190.208(e)
§190.209 Case file
(a) The case file, as defined in this section, is available to the respondent in all enforcement proceedings conducted under this subpart. 190.209(a)
(b) The case file of an enforcement proceeding consists of the following: 190.209(b)
(1) In cases commenced under §190.206, the notice of amendment and the relevant procedures; 190.209(b)(1)
(2) In cases commenced under §190.207, the notice of probable violation and the violation report; 190.209(b)(2)
(3) In cases commenced under §190.233, the corrective action order or notice of proposed corrective action order and the data report, if one is prepared; 190.209(b)(3)
(4) In cases commenced under §190.239, the notice of proposed safety order; 190.209(b)(4)
(5) Any documents and other material submitted by the respondent in response to the enforcement action; 190.209(b)(5)
(6) In cases involving a hearing, any material submitted during and after the hearing as set forth in §190.211; and 190.209(b)(6)
(7) The Regional Director's written evaluation of response material submitted by the respondent and recommendation for final action, if one is prepared. 190.209(b)(7)
§190.210 Separation of functions
(a) General. An agency employee who assists in the investigation or prosecution of an enforcement case may not participate in the decision of that case or a factually related one, but may participate
as a witness or counsel at a hearing as set forth in this subpart. Likewise, an agency employee who prepares a decision in an enforcement case may not have served in an investigative or prosecutorial capacity in that case or a factually related one. 190.210(a)
(b) Prohibition on ex parte communications. A party to an enforcement proceeding, including the respondent, its representative, or an agency employee having served in an investigative or prosecutorial capacity in the proceeding, may not communicate privately with the Associate Administrator, Presiding Official, or attorney drafting the recommended decision concerning information that is relevant to the questions to be decided in the proceeding. A party may communicate with the Presiding Official regarding administrative or procedural issues, such as for scheduling a hearing. 190.210(b)
§190.211 Hearing
(a) General. This section applies to hearings conducted under this part relating to civil penalty assessments, compliance orders, orders directing amendment, safety orders, and corrective action orders. The Presiding Official will convene hearings conducted under this section. 190.211(a)
(b) Hearing request and statement of issues. A request for a hearing must be accompanied by a statement of the issues that the respondent intends to raise at the hearing. The issues may relate to the allegations in the notice, the proposed corrective action, or the proposed civil penalty amount. A respondent's failure to specify an issue may result in waiver of the respondent's right to raise that issue at the hearing. The respondent's request must also indicate whether or not the respondent will be represented by counsel at the hearing. The respondent may withdraw a request for a hearing in writing and provide a written response. 190.211(b)
(c) Telephonic and in-person hearings. 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 $25,000, unless the respondent or OPS submits a written request for an in-person hearing. In-person hearings will normally be held at the office of the appropriate OPS Region. Hearings may be held by video teleconference if the necessary equipment is available to all parties. 190.211(c)
(d) Pre-hearing submissions. If OPS or the respondent intends to introduce material, including records, documents, and other exhibits not already in the case file, the material must be submitted to the Presiding Official and the other party at least 10 days prior to the date of the hearing, unless the Presiding Official sets a different deadline or waives the deadline for good cause. 190.211(d)
(e) Conduct of the hearing. The hearing is conducted informally without strict adherence to rules of evidence. The Presiding Official regulates the course of the hearing and gives each party an opportunity to offer facts, statements, explanations, documents, testimony or other evidence that is relevant and material to the issues under consideration. The parties may call witnesses on their own behalf and examine the evidence and witnesses presented by the other party. After the evidence in the case has been presented, the Presiding Official will permit reasonable discussion of the issues under consideration. 190.211(e)
(f) Written transcripts. If a respondent elects to transcribe a hearing, the respondent must make arrangements with a court reporter at cost to the respondent and submit a complete copy of the transcript for the case file. The respondent must notify the Presiding Official in advance if it intends to transcribe a hearing. 190.211(f)
(g) Post-hearing submission. The respondent and OPS may request an opportunity to submit further written material after the hearing for inclusion in the record. The Presiding Official will allow a reasonable time for the submission of the material and will specify the submission date. If the material is not submitted within the time prescribed, the case will proceed to final action without the material. 190.211(g)
(h) Preparation of decision. After consideration of the case file, the Presiding Official prepares a recommended decision in the case, which is then forwarded to the Associate Administrator for issuance of a final order. 190.211(h)
§190.212
Presiding official, powers, and duties
(a) General. The Presiding Official for a hearing conducted under §190.211 is an attorney on the staff of the Deputy Chief Counsel who is not engaged in any investigative or prosecutorial functions, such as the issuance of notices under this subpart. If the designated Presiding Official is unavailable, the Deputy Chief Counsel may delegate the powers and duties specified in this section to another attorney in the Office of Chief Counsel who is not engaged in any investigative or prosecutorial functions under this subpart. 190.212(a)
(b) Time and place of the hearing. The Presiding Official will set the date, time and location of the hearing. To the extent practicable, the Presiding Official will accommodate the parties' schedules when setting the hearing. Reasonable notice of the hearing will be provided to all parties. 190.212(b)
(c) Powers and duties of Presiding Official. The Presiding Official will conduct a fair and impartial hearing and take all action necessary to avoid delay in the disposition of the proceeding and maintain order. The Presiding Official has all powers necessary to achieve those ends, including, but not limited to the power to: 190.212(c)
(1) Regulate the course of the hearing and conduct of the parties and their counsel; 190.212(c)(1)
(2) Receive evidence and inquire into the relevant and material facts; 190.212(c)(2)
(3) Require the submission of documents and other information; 190.212(c)(3)
(4) Direct that documents or briefs relate to issues raised during the course of the hearing; 190.212(c)(4)
(5) Set the date for filing documents, briefs, and other items; 190.212(c)(5)
(6) Prepare a recommended decision; and190.212(c)(6)
(7) Exercise the authority necessary to carry out the responsibilities of the Presiding Official under this subpart. 190.212(c)(7)
§190.213 Final order
(a) In an enforcement proceeding commenced under §190.207, an attorney from the Office of Chief Counsel prepares a recommended decision after expiration of the 30-day response period prescribed in §190.208. If a hearing is held, the Presiding Official prepares the recommended decision as set forth in §190.211. The recommended decision is forwarded to the Associate Administrator who considers the case file and issues a final order. The final order includes — 190.213(a)
(1) A statement of findings and determinations on all material issues, including a determination as to whether each alleged violation has been proved; 190.213(a)(1)
(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 190.213(a)(2)
(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. 190.213(a)(3)
(b) In cases where a substantial delay is expected in the issuance of a final order, notice of that fact and the date by which it is expected that action will be taken is provided to the respondent upon request and whenever practicable. 190.213(b)
§190.215 [Reserved]
COMPLIANCE ORDERS
§190.217 Compliance orders generally
When a Regional Director has reason to believe that a person is engaging in conduct that violates 49 U.S.C. 60101 et seq., 33 U.S.C. 1321(j), or any regulation or order issued thereunder, and if the nature of the violation and the public interest so warrant, the Regional Director may initiate proceedings under §§190.207 through 190.213 to determine the nature and extent of the violations and for the issuance of an order directing compliance.
§190.219 Consent order
(a) At any time prior to the issuance of a compliance order under §190.217, a corrective action order under §190.233, or a safety order under §190.239, the Regional Director and the respondent may agree to resolve the case by execution of a consent agreement and order, which may be jointly executed by the parties and issued by the Associate Administrator. Upon execution, the consent order is considered a final order under §190.213. 190.219(a)
(b) A consent order executed under paragraph (a) of this section shall include: 190.219(b)
(1) An admission by the respondent of all jurisdictional facts; 190.219(b)(1)
(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; 190.219(b)(2)
(3) An acknowledgement that the notice of probable violation may be used to construe the terms of the consent order; and 190.219(b)(3)
(4) A statement of the actions required of the respondent and the time by which such actions shall be accomplished. 190.219(b)(4)
(c) Prior to the execution of a consent agreement and order arising out of a corrective action order under §190.233, the Associate Administrator will notify any appropriate State official in accordance with 49 U.S.C. 60112(c). 190.219(c)
CIVIL PENALTIES
§190.221
Civil penalties generally
When a Regional Director has reason to believe that a person has committed an act violating 49 U.S.C. 60101 et seq., 33 U.S.C. 1321(j), or any regulation or order issued thereunder, the Regional Director may initiate proceedings under §§190.207 through 190.213 to determine the nature and extent of the violations and appropriate civil penalty.
§190.223
Maximum penalties
(a) Any person found to have violated a provision of 49 U.S.C. 60101, et seq., or any regulation in 49 CFR parts 190 through 199, or order issued pursuant to 49 U.S.C. 60101, et seq. or 49 CFR part 190, is subject to an administrative civil penalty not to exceed $222,504 for each violation for each day the violation continues, with a maximum administrative civil penalty not to exceed $2,225,034 for any related series of violations. 190.223(a)
(b) Any person found to have violated a provision of 33 U.S.C. 1321(j), or any regulation or order issued thereunder, is subject to an administrative civil penalty under 33 U.S.C. 1321(b)(6), as adjusted by 40 CFR 19.4. 190.223(b)
(c) Any person found to have violated any standard or order under 49 U.S.C. 60103 is subject to an administrative civil penalty not to exceed $81,284, which may be in addition to other penalties to which such person may be subject under paragraph (a) of this section. 190.223(c)
(d) Any person who is determined to have violated any standard or order under 49 U.S.C. 60129 is subject to an administrative civil penalty not to exceed $1,292, which may be in addition to other penalties to which such person may be subject under paragraph (a) of this section. 190.223(d)
(e) Separate penalties for violating a regulation prescribed under this subchapter and for violating an order issued under §§190.206, 190.213, 190.233, or 190.239 may not be imposed under this section if both violations are based on the same act. 190.223(e)
§190.225 Assessment considerations
In determining the amount of a civil penalty under this part,
(a) The Associate Administrator will consider: 190.225(a)
(1) The nature, circumstances and gravity of the violation, including adverse impact on the environment; 190.225(a)(1)
(2) The degree of the respondent's culpability;190.225(a)(2)
(3) The respondent's history of prior offenses;190.225(a)(3)
(4) Any good faith by the respondent in attempting to achieve compliance; 190.225(a)(4)
(5) The effect on the respondent's ability to continue in business; and 190.225(a)(5)
(b) The Associate Administrator may consider: 190.225(b)
(1) The economic benefit gained from violation, if readily ascertainable, without any reduction because of subsequent damages; and 190.225(b)(1)
(2) Such other matters as justice may require.190.225(b)(2)
§190.227 Payment of penalty
(a) Except for payments exceeding $10,000, payment of a civil penalty proposed or assessed under this subpart may be made by certified check or money order (containing the CPF Number for the case), payable to "U.S. Department of Transportation," to the Federal Aviation Administration, Mike Monroney Aeronautical Center, Financial Operations Division (AMZ-341), P.O. Box 25770, Oklahoma City, OK 73125, or by wire transfer through the Federal Reserve Communications System (Fedwire) to the account of the U.S. Treasury, or via https://www.pay.gov. Payments exceeding $10,000 must be made by wire transfer. 190.227(a)
(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. 190.227(b)
§190.229 [Reserved]
§190.231 [Reserved]
SPECIFIC RELIEF
§190.233 Corrective action orders
(a) Generally. Except as provided by paragraph (b) of this section, if the Associate Administrator finds, after reasonable notice and opportunity for hearing in accord with paragraph (c) of this section, a particular pipeline facility is or would be hazardous to life, property, or the environment, the Associate Administrator may issue an order pursuant to this section requiring the operator of the facility to take corrective action. Corrective action may include suspended or restricted use of the facility, physical inspection, testing, repair, replacement, or other appropriate action. 190.233(a)
(b) Waiver of notice and expedited review. The Associate Administrator may waive the requirement for notice and opportunity for hearing under paragraph (a) of this section before issuing an order whenever the Associate Administrator determines that the failure to do so would result in the likelihood of serious harm to life, property, or the environment. When an order is issued under this paragraph, a respondent that contests the order may obtain expedited review of the order either by answering in writing to the order within 10 days of receipt or requesting a hearing under §190.211 to be held as soon as practicable in accordance with paragraph (c)(2) of this section. For purposes of this section, the term "expedited review" is defined as the process for making a prompt determination of whether the order should remain in effect or be amended or terminated. The expedited review of an order issued under this paragraph will be complete upon issuance of such determination. 190.233(b)
(c) Notice and hearing: 190.233(c)
(1) Written notice that OPS intends to issue an order under this section will be served upon the owner or operator of an alleged hazardous facility in accordance with §190.5. The notice must allege the existence of a hazardous facility and state the facts and circumstances supporting the issuance of a corrective action order. The notice must provide the owner or operator with an opportunity to respond within 10 days of receipt. 190.233(c)(1)
(2) An owner or operator that elects to exercise its opportunity for a hearing under this section must notify the Associate Administrator of that election in writing within 10 days of receipt of the notice provided under paragraph (c)(1) of this section, or the order under paragraph (b) of this section when applicable. The absence of such written notification waives an owner or operator's opportunity for a hearing. 190.233(c)(2)
(3) At any time after issuance of a notice or order under this section, the respondent may request a copy of the case file as set forth in §190.209. 190.233(c)(3)
(4) A hearing under this section is conducted pursuant to §190.211. The hearing should be held within 15 days of receipt of the respondent's request for a hearing. 190.233(c)(4)
(5) After conclusion of a hearing under this section, the Presiding Official submits a recommended decision to the Associate Administrator as to whether or not the facility is or would be hazardous to life, property, or the environment, and if necessary, requiring expeditious corrective action. If a notice or order is contested in writing without a hearing, an attorney from the Office of Chief Counsel prepares the recommended decision. The recommended decision should be submitted to the Associate Administrator within five business days after conclusion of the hearing or after receipt of the respondent's written objection if no hearing is held. Upon receipt of the recommendation, the Associate Administrator will proceed in accordance with paragraphs (d) through (h) of this section. If the Associate Administrator finds the facility is or would be hazardous to life, property, or the environment, the Associate Administrator issues a corrective action order in accordance with this section, or confirms (or amends) the corrective action order issued under paragraph (b) of this section. If the Associate Administrator does not find the facility is or would be hazardous to life, property, or the environment, the Associate Administrator withdraws the notice or terminates the order issued under paragraph (b) of this section, and promptly notifies the operator in writing by service as prescribed in §190.5. 190.233(c)(5)
(d) The Associate Administrator may find a pipeline facility to be hazardous under paragraph (a) of this section: 190.233(d)
(1) If under the facts and circumstances the Associate Administrator determines the particular facility is hazardous to life, property, or the environment; or 190.233(d)(1)
(2) If the pipeline facility or a component thereof has been constructed or operated with any equipment, material, or technique which the Associate Administrator determines is hazardous to life, property, or the environment, unless the operator involved demon-
strates to the satisfaction of the Associate Administrator that, under the particular facts and circumstances involved, such equipment, material, or technique is not hazardous. 190.233(d)(2)
(e) In making a determination under paragraph (d) of this section, the Associate Administrator shall consider, if relevant: 190.233(e)
(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; 190.233(e)(1)
(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; 190.233(e)(2)
(3) The characteristics of the geographical areas in which the pipeline facility is located, in particular the climatic and geologic conditions (including soil characteristics) associated with such areas, and the population density and population and growth patterns of such areas; 190.233(e)(3)
(4) Any recommendation of the National Transportation Safety Board issued in connection with any investigation conducted by the Board; and 190.233(e)(4)
(5) Such other factors as the Associate Administrator may consider appropriate. 190.233(e)(5)
(f) A corrective action order shall contain the following information: 190.233(f)
(1) A finding that the pipeline facility is or would be hazardous to life, property, or the environment. 190.233(f)(1)
(2) The relevant facts which form the basis of that finding. 190.233(f)(2)
(3) The legal basis for the order.190.233(f)(3)
(4) The nature and description of any particular corrective action required of the respondent. 190.233(f)(4)
(5) The date by which the required corrective action must be taken or completed and, where appropriate, the duration of the order. 190.233(f)(5)
(6) If the opportunity for a hearing was waived pursuant to paragraph (b) of this section, a statement that an opportunity for a hearing will be available at a particular time and location after issuance of the order. 190.233(f)(6)
(g) The Associate Administrator will terminate a corrective action order whenever the Associate Administrator determines that the facility is no longer hazardous to life, property, or the environment. If appropriate, however, a notice of probable violation may be issued under §190.207. 190.233(g)
(h) At any time after a corrective action order issued under this section has become effective, the Associate Administrator may request the Attorney General to bring an action for appropriate relief in accordance with §190.235. 190.233(h)
(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. 190.233(i)
§190.235 Civil actions generally
Whenever it appears to the Associate Administrator 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 et seq., or any regulations issued thereunder, the Administrator, or the person to whom the authority has been delegated, may request the Attorney General to bring an action in the appropriate U.S. District Court for such relief as is necessary or appropriate, including mandatory or prohibitive injunctive relief, interim equitable relief, civil penalties, and punitive damages as provided under 49 U.S.C. 60120 and 49 U.S.C. 5123.
§190.236 Emergency orders: Procedures for issuance and rescision
(a) Determination of imminent hazard. When the Administrator determines that an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes or is causing an imminent hazard, as defined in §190.3, the Administrator may issue or impose an emergency order, without advance notice or an opportunity for a hearing, but only to the extent necessary to abate the imminent hazard. The order will contain a written description of: 190.236(a)
(1) The violation, condition, or practice that constitutes or is causing the imminent hazard; 190.236(a)(1)
(2) Those entities subject to the order;190.236(a)(2)
(3) The restrictions, prohibitions, or safety measures imposed; 190.236(a)(3)
(4) The standards and procedures for obtaining relief from the order; 190.236(a)(4)
(5) How the order is tailored to abate the imminent hazard and the reasons the authorities under 49 U.S.C. 60112 and 60117(l) are insufficient to do so; and 190.236(a)(5)
(6) How the considerations listed in paragraph (c) of this section were taken into account. 190.236(a)(6)
(b) Consultation. In considering the factors under paragraph (c) of this section, the Administrator shall consult, as the Administrator determines appropriate, with appropriate Federal agencies, State agencies, and other entities knowledgeable in pipeline safety or operations. 190.236(b)
(c) Considerations. Prior to issuing an emergency order, the Administrator shall consider the following, as appropriate: 190.236(c)
(1) The impact of the emergency order on public health and safety; 190.236(c)(1)
(2) The impact, if any, of the emergency order on the national or regional economy or national security; 190.236(c)(2)
(3) The impact of the emergency order on the ability of owners and operators of pipeline facilities to maintain reliability and continuity of service to customers; and 190.236(c)(3)
(4) The results of any consultations with appropriate Federal agencies, State agencies, and other entities knowledgeable in pipeline safety or operations. 190.236(c)(4)
(d) Service. The Administrator will provide service of emergency orders in accordance with §190.5 to all operators of gas and hazardous liquid pipeline facilities that the Administrator reasonably expects to be affected by the emergency order. In addition, the Administrator will publish emergency orders in the Federal Register and post them on the PHMSA website as soon as practicable upon issuance. Publication in the Federal Register will serve as general notice of an emergency order. Each emergency order must contain information specifying how pipeline operators and owners may respond to the emergency order, filing procedures, and service requirements, including the address of DOT Docket Operations and the names and addresses of all persons to be served if a petition for review is filed. 190.236(d)
(e) Rescission. If an emergency order has been in effect for more than 365 days, the Administrator will make an assessment regarding whether the unsafe condition or practice, or combination of unsafe conditions and practices, constituting or causing an imminent hazard, as defined in §190.3, continues to exist. If the imminent hazard does not continue to exist, the Administrator will rescind the emergency order and follow the service procedures set forth in §190.236(d). If the imminent hazard underlying the emergency order continues to exist, PHMSA will initiate a rulemaking action as soon as practicable. 190.236(e)
§190.237 Emergency orders: Petitions for review
(a) Requirements. An entity that is subject to and aggrieved by an emergency order may petition the Administrator for review to determine whether the order will remain in place, be modified, or terminated. A petition for review must: 190.237(a)
(1) Be in writing;190.237(a)(1)
(2) State with particularity each part of the emergency order that is sought to be amended or rescinded and include all information, evidence and arguments in support thereof; 190.237(a)(2)
(3) State whether a formal hearing in accordance with 5 U.S.C. 554 is requested, and, if so, the material facts in dispute giving rise to the request for a hearing; and, 190.237(a)(3)
(4) Be filed and served in accordance with paragraph (f) of this section. 190.237(a)(4)
(b) Response to the petition for review. An attorney designated by the Office of Chief Counsel may file and serve, in accordance with paragraph (f) of this section, a response, including appropriate pleadings, within five days of receipt of the petition by the Chief Counsel. 190.237(b)
(c) Response to the petition for review. An attorney designated by the Office of Chief Counsel may file and serve, in accordance with paragraph (h) of this section, a response to the petition, including appropriate pleadings, within five calendar days of receipt of the petition by the Chief Counsel. 190.237(c)
(1) Formal hearing requested. Upon receipt of a petition for review that includes a formal hearing request under this section, the Associate Administrator will, within three days after receipt of the petition, assign the petition to the Office of Hearings, DOT, for a formal hearing. 190.237(d)(1)
(2) No formal hearing requested. Upon receipt of a petition for review that does not include a formal hearing request, the Associate Administrator will issue an administrative decision on the merits within 30 days of receipt of the petition for review. The Associate Administrator's decision constitutes the agency's final decision. 190.237(d)(2)
(3) Consolidation. If the Associate Administrator receives more than one petition for review and they share common issues of law or fact, the Associate Administrator may consolidate the petitions for the purpose of complying with this section, provided such consolidation occurs prior to the commencement of a formal hearing. The Associate Administrator may reassign a petition that does not request a formal hearing to the Office of Hearings, DOT, provided the petition otherwise meets the requirements for consolidation. If the Associate Administrator has consolidated multiple petitions that do not request a formal hearing, he may de-consolidate such petitions if there has been a change in circumstances that, in his discretion, warrant separation for the purpose of rendering a final decision. 190.237(d)(3)
(e) Formal Hearings. Formal hearings must be conducted by an administrative law judge assigned by the chief administrative law judge of the Office of Hearings, DOT. The administrative law judge may: 190.237(e)
(1) Administer oaths and affirmations;190.237(e)(1)
(2) Issue subpoenas as provided by the appropriate statutes and agency regulations (e.g., 49 U.S.C. 60117 and 49 CFR 190.7); 190.237(e)(2)
(3) Adopt the relevant Federal Rules of Civil Procedure for the United States District Courts for the procedures governing the hearings, when appropriate; 190.237(e)(3)
(4) Adopt the relevant Federal Rules of Evidence for United States Courts and Magistrates for the submission of evidence, when appropriate; 190.237(e)(4)
(5) Take or cause depositions to be taken;190.237(e)(5)
(6) Examine witnesses at the hearing;190.237(e)(6)
(7) Rule on offers of proof and receive relevant evidence; 190.237(e)(7)
(8) Convene, recess, adjourn or otherwise regulate the course of the hearing; 190.237(e)(8)
(9) Hold conferences for settlement, simplification of the issues, or any other proper purpose; and 190.237(e)(9)
(10) Take any other action authorized by or consistent with the provisions of this part and permitted by law that may expedite the hearing or aid in the disposition of an issue raised. 190.237(e)(10)
(f) Parties. The petitioner may appear and be heard in person or by an authorized representative. PHMSA will be represented by an attorney designated by the Office of Chief Counsel. 190.237(f)
(g) Burden of proof. Except in the case of an affirmative defense, PHMSA shall bear the burden of proving, by a preponderance of the evidence, the validity of an emergency order in a proceeding under this section by a preponderance of the evidence. A party asserting an affirmative defense shall bear the burden of proving, by a preponderance of the evidence, the affirmative defense in a proceeding under this section. 190.237(g)
(h) Filing and service. 190.237(h)
(1) Each petition, pleading, motion, notice, order, or other document submitted in connection with an emergency order issued under this section must be filed (commercially delivered or submitted electronically) with: U.S. Department of Transportation, Docket Operations, M-30, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE, Washington, DC 20590. All documents filed will be published on the Department's docket management website, http://www.regulations.gov. The emergency order must state the above filing requirements and the address of DOT Docket Operations. 190.237(h)(1)
(2) Each document filed in accordance with paragraph (h)(1) of this section must be concurrently served upon the following persons: 190.237(h)(2)
(i) Associate Administrator for Pipeline Safety, OPS, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue SE, East Building, Washington, DC 20590;190.237(h)(2)(i)
(ii) Chief Counsel, PHC, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue SE, East Building, Washington, DC 20590 (facsimile: 202-366-7041); and190.237(h)(2)(ii)
(iii) If the petition for review requests a formal hearing, the Chief Administrative Law Judge, U.S. Department of Transportation, Office of Hearings, 1200 New Jersey Ave SE, c/o Mail Center (E11-310), Washington, DC 20590 (facsimile: 202-366-7536). 190.237(h)(2)(iii)
(3) Service must be made in accordance with §190.5 of this part. The emergency order must state all relevant service requirements and list the persons to be served and may be updated as necessary. 190.237(h)(3)
(4) Certificate of service. Each order, pleading, motion, notice, or other document must be accompanied by a certificate of service specifying the manner in which and the date on which service was made. 190.237(h)(4)
(5) If applicable, service upon a person's duly authorized representative, agent for service, or an organization's president or chief executive officer constitutes service upon that person. 190.237(h)(5)
(i) Report and recommendation. The administrative law judge must issue a report and recommendation to the Associate Administrator at the close of the record. The report and recommendation must: 190.237(i)
(1) Contain findings of fact and conclusions of law and the grounds for the decision, based on the material issues of fact or law presented on the record; 190.237(i)(1)
(2) Be served on the parties to the proceeding; and190.237(i)(2)
(3) Be issued no later than 25 days after receipt of the petition for review by the Associate Administrator. 190.237(i)(3)
(j) Petition for reconsideration. 190.237(j)
(1) A petitioner aggrieved by the administrative law judge's report and recommendation may file a petition for reconsideration with the Associate Administrator. The petition for reconsideration must be filed: 190.237(j)(1)
(i) Not more than five days after the administrative law judge has issued a report and recommendation under paragraph (i) of this section, provided such report and recommendation is issued 20 days or less after the petition for review was filed with PHMSA; or190.237(j)(1)(i)
(ii) Not more than two days after the administrative law judge has issued his or her report and recommendation under paragraph (h) of this section, where such report and recommendation are issued more than 20 days after the petition for review was filed with PHMSA.190.237(j)(1)(ii)
(2) The Associate Administrator must issue a decision on a petition for reconsideration no later than 30 days after receipt of the petition for review. Such decision constitutes final agency action on a petition for review. 190.237(j)(2)
(k) Judicial review. 190.237(k)
(1) After the issuance of a final agency decision pursuant to paragraphs (d)(2) or (j)(2) of this section, or the issuance of a written determination by the Administrator pursuant to paragraph (l) of this section, a pipeline owner or operator subject to and aggrieved by an emergency order issued under §190.236 may seek judicial review of the order in the appropriate district court of the United States. The filing of an action seeking judicial review does not stay or modify the force and effect of the agency's final decision under paragraphs (d)(2) or (j)(3) of this section, or the written determination under paragraph (l) of this section, unless stayed or modified by the Administrator. 190.237(k)(1)
(l) Expiration of order. 190.237(l)
(1) No petition for review filed: If no petition for review is filed challenging the emergency order, then the emergency order shall remain in effect until PHMSA determines, in writing, that the imminent hazard no longer exists or the order is terminated by a court of competent jurisdiction. 190.237(l)(1)
(2) Petition for review filed and decision rendered within 30 days. If the Associate Administrator renders a final decision upon a petition for review within 30 days of its receipt by PHMSA, any elements of the emergency order upheld or modified by the decision shall remain in effect until PHMSA determines, in writing, that the imminent hazard no longer exists or the order is terminated by a court of competent jurisdiction. 190.237(l)(2)
(3) Petition for review filed but no decision rendered within 30 days. If the Associate Administrator has not reached a decision on the petition for review within 30 days of receipt of the petition for review, the emergency order will cease to be effective unless the Administrator determines, in writing, that the imminent hazard providing a basis for the emergency order continues to exist. 190.237(l)(3)
(m) Time. In computing any period of time prescribed by this section or an order or report and recommendation issued by an administrative law judge under this section, the day of filing of a petition for review or of any other act, event or default from which the designated period of time begins to run will not be included. The last day of the period so computed will be included, unless it is a Saturday, Sunday, or Federal holiday, in which event the period runs until end of the next day which is not one of the aforementioned days. 190.237(m)
§190.239 Safety orders
(a) When may PHMSA issue a safety order? If the Associate Administrator finds, after notice and an opportunity for hearing under paragraph (b) of this section, that a particular pipeline facility has a condition or conditions that pose a pipeline integrity risk to public safety, property, or the environment, the Associate Administrator may issue an order requiring the operator of the facility to take necessary corrective action. Such action may include physical inspection, testing, repair or other appropriate action to remedy the identified risk condition. 190.239(a)
(b) How is an operator notified of the proposed issuance of a safety order and what are its responses options? 190.239(b)
(1) Notice of proposed safety order. PHMSA will serve written notice of a proposed safety order under §190.5 to an operator of the pipeline facility. The notice will allege the existence of a condition that poses a pipeline integrity risk to public safety, property, or the environment, and state the facts and circumstances that support issuing a safety order for the specified pipeline or portion thereof. The notice will also specify proposed testing, evaluations, integrity assessment, or other actions to be taken by the operator and may propose that the operator submit a work plan and schedule to address the conditions identified in the notice. The notice will also provide the operator with its response options, including procedures for requesting informal consultation and a hearing. An operator receiving a notice will have 30 days to respond to the PHMSA official who issued the notice. 190.239(b)(1)
(2) Informal consultation. Upon timely request by the operator, PHMSA will provide an opportunity for informal consultation concerning the proposed safety order. Such informal consultation shall commence within 30 days, provided that PHMSA may extend this time by request or otherwise for good cause. Informal consultation provides an opportunity for the respondent to explain the circumstances associated with the risk condition(s) identified in the notice and, where appropriate, to present a proposal for corrective action, without prejudice to the operator's position in any subsequent hearing. If the respondent and Regional Director agree within 30 days of the informal consultation on a plan for the operator to address each risk condition, they may enter into a written consent agreement and the Associate Administrator may issue a consent order incorporating the terms of the agreement. If a consent agreement is reached, no further hearing will be provided in the matter and any pending hearing request will be considered withdrawn. If a consent agreement is not reached within 30 days of the informal consultation (or if informal consultation is not requested), the Associate Administrator may proceed under paragraphs (b)(3) through (5) of this section. If PHMSA subsequently determines that an operator has failed to comply with the terms of a consent order, PHMSA may obtain any administrative or judicial remedies available under 49 U.S.C. 60101 et seq. and this part. If a consent agreement is not reached, any admissions made by the operator during the informal consultation shall be excluded from the record in any subsequent hearing. Nothing in this paragraph (b) precludes PHMSA from terminating the informal consultation process if it has reason to believe that the operator is not engaging in good faith discussions or otherwise concludes that further consultation would not be productive or in the public interest. 190.239(b)(2)
(3) Hearing. An operator receiving a notice of proposed safety order may contest the notice, or any portion thereof, by filing a written request for a hearing within 30 days following receipt of the notice or within 10 days following the conclusion of informal consultation that did not result in a consent agreement, as applicable. In the absence of a timely request for a hearing, the Associate Administrator may issue a safety order in the form of the proposed order in accordance with paragraphs (c) through (g) of this section. 190.239(b)(3)
(4) Conduct of hearing. An attorney from the Office of Chief Counsel, will serve as the Presiding Official in a hearing under this section. The hearing will be conducted informally, without strict adherence to formal rules of evidence in accordance with §190.211. The respondent may submit any relevant information or materials, call witnesses, and present arguments on the issue of whether a safety order should be issued to address the alleged presence of a condition that poses a pipeline integrity risk to public safety, property, or the environment. 190.239(b)(4)
(5) Post-hearing action. Following a hearing under this section, the Presiding Official will submit a recommendation to the Associate Administrator concerning issuance of a final safety order. Upon receipt of the recommendation, the Associate Administrator may proceed under paragraphs (c) through (g) of this section. If the Associate Administrator finds the facility to have a condition that poses a pipeline integrity risk to public safety, property, or the environment, the Associate Administrator will issue a safety order under this section. If the Associate Administrator does not find that the facility has such a condition, or concludes that a safety order is otherwise not warranted, the Associate Administrator will withdraw the notice and promptly notify the operator in writing by service as prescribed in §190.5. Nothing in this subsection precludes PHMSA and the operator from entering into a consent agreement at any time before a safety order is issued. 190.239(b)(5)
(6) Termination of safety order. Once all remedial actions set forth in the safety order and associated work plans are completed, as determined by PHMSA, the Associate Administrator will notify the operator that the safety order has been lifted. The Associate Administrator shall suspend or terminate a safety order whenever
the Associate Administrator determines that the pipeline facility no longer has a condition or conditions that pose a pipeline integrity risk to public safety, property, or the environment. 190.239(b)(6)
(c) How is the determination made that a pipeline facility has a condition that poses an integrity risk? The Associate Administrator may find a pipeline facility to have a condition that poses a pipeline integrity risk to public safety, property, or the environment under paragraph (a) of this section: 190.239(c)
(1) If under the facts and circumstances the Associate Administrator determines the particular facility has such a condition; or 190.239(c)(1)
(2) If the pipeline facility or a component thereof has been constructed or operated with any equipment, material, or technique with a history of being susceptible to failure when used in pipeline service, unless the operator involved demonstrates that such equipment, material, or technique is not susceptible to failure given the manner it is being used for a particular facility. 190.239(c)(2)
(d) What factors must PHMSA consider in making a determination that a risk condition is present? In making a determination under paragraph (c) of this section, the Associate Administrator shall consider, if relevant: 190.239(d)
(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; 190.239(d)(1)
(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; 190.239(d)(2)
(3) The characteristics of the geographical areas where the pipeline facility is located, in particular the climatic and geologic conditions (including soil characteristics) associated with such areas; 190.239(d)(3)
(4) For hazardous liquid pipelines, the proximity of the pipeline to an unusually sensitive area; 190.239(d)(4)
(5) The population density and growth patterns of the area in which the pipeline facility is located; 190.239(d)(5)
(6) Any relevant recommendation of the National Transportation Safety Board issued in connection with any investigation conducted by the Board; 190.239(d)(6)
(7) The likelihood that the condition will impair the serviceability of the pipeline; 190.239(d)(7)
(8) The likelihood that the condition will worsen over time; and 190.239(d)(8)
(9) The likelihood that the condition is present or could develop on other areas of the pipeline. 190.239(d)(9)
(e) What information will be included in a safety order? A safety order shall contain the following: 190.239(e)
(1) A finding that the pipeline facility has a condition that poses a pipeline integrity risk to public safety, property, or the environment; 190.239(e)(1)
(2) The relevant facts which form the basis of that finding; 190.239(e)(2)
(3) The legal basis for the order;190.239(e)(3)
(4) The nature and description of any particular corrective actions to be required of the operator; and 190.239(e)(4)
(5) The date(s) by which the required corrective actions must be taken or completed and, where appropriate, the duration of the order. 190.239(e)(5)
(f) Can PHMSA take other enforcement actions on the affected facilities? Nothing in this section precludes PHMSA from issuing a Notice of Probable Violation under §190.207 or taking other enforcement action if noncompliance is identified at the facilities that are the subject of a safety order proceeding. 190.239(f)
(g) May I petition for reconsideration of a safety order? Yes, a petition for reconsideration may be submitted in accordance with §190.243. 190.239(g)
§190.241 Finality
Except as otherwise provided by §190.243, an order directing amendment issued under §190.206, a final order issued under §190.213, a corrective action order issued under §190.233, or a safety order issued under §190.239 is considered final administrative action on that enforcement proceeding.
§190.243 Petitions for reconsideration
(a) A respondent may petition the Associate Administrator for reconsideration of an order directing amendment of plans or procedures issued under §190.206, a final order issued under §190.213, or a safety order issued under §190.239. The written petition must be received no later than 20 days after receipt of the order by the respondent. A copy of the petition must be provided to the Chief Counsel of the Pipeline and Hazardous Materials
Safety Administration, East Building, 2nd Floor, Mail Stop E26105, 1200 New Jersey Ave. SE., Washington, DC 20590 or by email to phmsachiefcounsel@dot.gov. 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 order should be reconsidered. 190.243(a)
(b) If the respondent requests the consideration of additional facts or arguments, the respondent must submit the reasons why they were not presented prior to issuance of the final order. 190.243(b)
(c) The filing of a petition under this section stays the payment of any civil penalty assessed. However, unless the Associate Administrator otherwise provides, the order, including any required corrective action, is not stayed. 190.243(c)
(d) The Associate Administrator may grant or deny, in whole or in part, any petition for reconsideration without further proceedings. If the Associate Administrator reconsiders an order under this section, 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, as deemed appropriate. 190.243(d)
(e) It is the policy of the Associate Administrator to expeditiously issue notice of the action taken on a petition for reconsideration. In cases where a substantial delay is expected, notice of that fact and the date by which it is expected that action will be taken is provided to the respondent upon request and whenever practicable. 190.243(e)
(f) If the Associate Administrator reconsiders an order under this section, the decision on reconsideration is the final administrative action on that enforcement proceeding. 190.243(f)
(g) Any application for judicial review must be filed no later than 89 days after the issuance of the decision in accordance with 49 U.S.C. 60119(a). 190.243(g)
(h) Judicial review of agency action under 49 U.S.C. 60119(a) will apply the standards of review established in 5 U.S.C. 706. 190.243(h)
Subpart C – Criminal Enforcement
§190.291 Criminal penalties generally
(a) Any person who willfully and knowingly violates a provision of 49 U.S.C. 60101 et seq. or any regulation or order issued thereunder will upon conviction be subject to a fine under title 18, United States Code, and imprisonment for not more than five years, or both, for each offense. 190.291(a)
(b) Any person who willfully and knowingly injures or destroys, or attempts to injure or destroy, any interstate transmission facility, any interstate pipeline facility, or any intrastate pipeline facility used in interstate or foreign commerce or in any activity affecting interstate or foreign commerce (as those terms are defined in 49 U.S.C. 60101 et seq.) will, upon conviction, be subject to a fine under title 18, United States Code, imprisonment for a term not to exceed 20 years, or both, for each offense. 190.291(b)
(c) Any person who willfully and knowingly defaces, damages, removes, or destroys any pipeline sign, right-of-way marker, or marine buoy required by 49 U.S.C. 60101 et seq. or any regulation or order issued thereunder will, upon conviction, be subject to a fine under title 18, United States Code, imprisonment for a term not to exceed 1 year, or both, for each offense. 190.291(c)
(d) Any person who willfully and knowingly engages in excavation activity without first using an available one-call notification system to establish the location of underground facilities in the excavation area; or without considering location information or markings established by a pipeline facility operator; and 190.291(d)
(1) Subsequently damages a pipeline facility resulting in death, serious bodily harm, or property damage exceeding $50,000; 190.291(d)(1)
(2) Subsequently damages a pipeline facility and knows or has reason to know of the damage but fails to promptly report the damage to the operator and to the appropriate authorities; or 190.291(d)(2)
(3) Subsequently damages a hazardous liquid pipeline facility that results in the release of more than 50 barrels of product; will, upon conviction, be subject to a fine under title 18, United States Code, imprisonment for a term not to exceed 5 years, or both, for each offense. 190.291(d)(3)
(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 190.291 if both violations are based on the same act. 190.291(e)
§190.293 Criminal referrals
(a)If a PHMSA employee becomes aware of any actual or possible activity subject to criminal penalties under §190.291, the employee must report it to the Office of Chief Counsel, Pipeline and Hazard-
ous Materials Safety Administration, and to the employee's supervisor. The Chief Counsel may refer the report to the Associate Administrator to investigate. If appropriate, the Chief Counsel shall refer the report to the Office of Inspector General, or other law enforcement as appropriate (with notification to the Office of Inspector General as soon as possible).
(b)A PHMSA employee also has the option of making a direct referral to the Office of Inspector General (OIG), either by directly contacting an OIG investigator, or via the OIG hotline at 800-4249071, at https://www.oig.dot.gov/hotline, by email at hotline@oig.dot.gov, or by mail to the Office of Inspector General, 1200 New Jersey Ave. SE, West Bldg. 7th Floor, Washington, DC 20590.
Subpart D – Procedures for Adoption of Rules
§190.301 Scope
This subpart prescribes general rulemaking procedures for the issue, amendment, and repeal of Pipeline Safety Program regulations of the Pipeline and Hazardous Materials Safety Administration of the Department of Transportation.
§190.303 Delegations
For the purposes of this subpart, Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration, or his or her delegate.
§190.305
Regulatory dockets
(a) Information and data considered relevant by the Administrator relating to rulemaking actions, including notices of proposed rulemaking; comments received in response to notices; petitions for rulemaking and reconsideration; denials of petitions for rulemaking and reconsideration; records of additional rulemaking proceedings under §190.325; and final regulations are maintained by the Pipeline and Hazardous Materials Safety Administration at 1200 New Jersey Avenue, SE, Washington, D.C. 20590-0001. 190.305(a)
(b) Once a public docket is established, docketed material may be accessed at http://www.regulations.gov. Public comments also may be submitted at http://www.regulations.gov. Comment submissions must identify the docket number. You may also examine public docket material at the offices of the Docket Operations Facility (M-30), U.S. Department of Transportation, West Building, First Floor, Room W12-140, 1200 New Jersey Avenue, SE., Washington, DC 20590. You may obtain a copy during normal business hours, excluding Federal holidays, for a fee, with the exception of material which the Administrator of PHMSA determines should be withheld from public disclosure under 5 U.S.C. 552(b) or any other applicable statutory provision. 190.305(b)
§190.307 Records
Records of the Pipeline and Hazardous Materials Safety Administration relating to rulemaking proceedings are available for inspection as provided in section 552(b) of title 5, United States Code, and part 7 of the Regulations of the Office of the Secretary of Transportation (part 7 of this title).
§190.309 Where to file petitions
Petitions for extension of time to comment submitted under §190.319, petitions for hearings submitted under §190.327, petitions for rulemaking submitted under §190.331, and petitions for reconsideration submitted under §190.335 must be submitted to: Administrator, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue, SE, Washington, D.C. 20590-0001.
§190.311 General
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.
§190.313 Initiation of rulemaking
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.
§190.315 Contents of notices of proposed rulemaking
(a) Each notice of proposed rulemaking is published in the Federal Register, unless all persons subject to it are named and are personally served with a copy of it. 190.315(a)
(b) Each notice, whether published in the Federal Register or personally served, includes: 190.315(b)
(1) A statement of the time, place, and nature of the proposed rulemaking proceeding; 190.315(b)(1)
(2) A reference to the authority under which it is issued; 190.315(b)(2)
(3) A description of the subjects and issues involved or the substance and terms of the proposed regulation; 190.315(b)(3)
(4) A statement of the time within which written comments must be submitted; and 190.315(b)(4)
(5) A statement of how and to what extent interested persons may participate in the proceeding. 190.315(b)(5)
§190.317 Participation by interested persons
(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. 190.317(a)
(b) The Administrator may invite any interested person to participate in the rulemaking proceedings described in §190.325. 190.317(b)
(c) For the purposes of this subpart, an interested person includes any Federal or State government agency or any political subdivision of a State. 190.317(c)
§190.319 Petitions for extension of time to comment
A petition for extension of the time to submit comments must be submitted to PHMSA in accordance with §190.309 and received by PHMSA not later than 10 days before expiration of the time stated in the notice. 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 Federal Register.
§190.321 Contents of written comments
All written comments must be in English. 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 must be identified by document title and page.
§190.323 Consideration of comments received
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.
§190.325 Additional
rulemaking proceedings
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.
§190.327 Hearings
(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 Federal Register. 190.327(a)
(b) Sections 556 and 557 of title 5, United States Code, do not apply to hearings held under this subpart. Unless otherwise specified, hearings held under this subpart are informal, non-adversarial fact-finding proceedings, at which there are no formal pleadings or adverse parties. Any regulation issued in a case in which an informal hearing is held is not necessarily based exclusively on the record of the hearing. 190.327(b)
(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. 190.327(c)
§190.329 Adoption of final rules
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 Federal Register, unless all persons subject to it are named and are personally served with a copy of it.
§190.331 Petitions for rulemaking
(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. 190.331(a)
(b) Each petition filed under this section must — 190.331(b)
(1) Summarize the proposed action and explain its purpose; 190.331(b)(1)
(2) State the text of the proposed rule or amendment, or specify the rule proposed to be repealed; 190.331(b)(2)
(3) Explain the petitioner's interest in the proposed action and the interest of any party the petitioner represents; and 190.331(b)(3)
(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. 190.331(b)(4)
(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 — 190.331(c)
(1) The costs and benefits to society and identifiable groups within society, quantifiable and otherwise; 190.331(c)(1)
(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; 190.331(c)(2)
(3) The regulatory burden on small businesses, small organizations and small governmental jurisdictions; 190.331(c)(3)
(4) The recordkeeping and reporting requirements and to whom they would apply; and 190.331(c)(4)
(5) Impacts on the quality of the natural and social environments. 190.331(c)(5)
(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. 190.331(d)
§190.333 Processing of petition
(a) General. Unless the Associate Administrator or the Chief Counsel otherwise specifies, no public hearing, argument, or other proceeding is held directly on a petition before its disposition under this section. 190.333(a)
(b) Grants. If the Associate Administrator or the Chief Counsel determines that the petition contains adequate justification, he or she initiates rulemaking action under this subpart. 190.333(b)
(c) Denials. If the Associate Administrator or the Chief Counsel determines that the petition does not justify rulemaking, the petition is denied. 190.333(c)
(d) Notification. The Associate Administrator or the Chief Counsel will notify a petitioner, in writing, of the decision to grant or deny a petition for rulemaking. 190.333(d)
§190.335 Petitions for reconsideration
(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. The petition must be received not later than 30 days after publication of the rule in the Federal Register. Petitions filed after that time will be considered as petitions filed under §190.331. The petition must contain a brief statement of the complaint and an explanation as to why compliance with the rule is not practicable, is unreasonable, or is not in the public interest. 190.335(a)
(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. 190.335(b)
(c) The Associate Administrator or the Chief Counsel does not consider repetitious petitions. 190.335(c)
(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. 190.335(d)
§190.337
Proceedings on petitions for reconsideration
(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. 190.337(a)
(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 Federal Register, 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 petitioner and published in the Federal Register. 190.337(b)
§190.338 Appeals
(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. 190.338(a)
(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 Federal Register, and should set forth the contested aspects of the decision as well as any new arguments or information. 190.338(b)
(c) Unless the Administrator otherwise provides, the filing of an appeal under this section does not stay the effectiveness of any rule. 190.338(c)
§190.339 Direct final rulemaking
(a) Where practicable, the Administrator will use direct final rulemaking to issue the following types of rules: 190.339(a)
(1) Minor, substantive changes to regulations; 190.339(a)(1)
(2) Incorporation by reference of the latest edition of technical or industry standards; 190.339(a)(2)
(3) Extensions of compliance dates; and190.339(a)(3)
(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. 190.339(a)(4)
(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 Federal Register, the Administrator will issue a confirmation document, generally within 15 days after the close of the comment period, advising the public that the direct final rule will either become effective on the date stated in the direct final rule or at least 30 days after the publication date of the confirmation document, whichever is later. 190.339(b)
(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. 190.339(c)
(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. 190.339(d)
(e) If an adverse comment or notice of intent to file an adverse comment is received, a timely document will be published in the Federal Register advising the public and withdrawing the direct final
rule in whole or in part. The Administrator may then incorporate the adverse comment into a subsequent direct final rule or may publish a notice of proposed rulemaking. A notice of proposed rulemaking will provide an opportunity for public comment, generally a minimum of 60 days, and will be processed in accordance with §§190.311-190.329. 190.339(e)
§190.341 Special permits
(a) What is a special permit? A special permit is an order by which PHMSA waives compliance with one or more of the Federal pipeline safety regulations under the standards set forth in 49 U.S.C. 60118(c) and subject to conditions set forth in the order. A special permit is issued to a pipeline operator (or prospective operator) for specified facilities that are or, absent waiver, would be subject to the regulation. 190.341(a)
(b) How do I apply for a special permit? Applications for special permits must be submitted at least 120 days before the requested effective date using any of the following methods: 190.341(b)
(1) Direct fax to PHMSA at: 202-366-4566; or 190.341(b)(1)
(2) Mail, express mail, or overnight courier to the Associate Administrator for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., East Building, Washington, DC 20590. 190.341(b)(2)
(c) What information must be contained in the application? Applications must contain the following information: 190.341(c)
(1) The name, mailing address, and telephone number of the applicant and whether the applicant is an operator; 190.341(c)(1)
(2) A detailed description of the pipeline facilities for which the special permit is sought, including: 190.341(c)(2)
(i) The beginning and ending points of the pipeline mileage to be covered and the Counties and States in which it is located; 190.341(c)(2)(i)
(ii) Whether the pipeline is interstate or intrastate and a general description of the right-of-way including proximity of the affected segments to populated areas and unusually sensitive areas; 190.341(c)(2)(ii)
(iii) Relevant pipeline design and construction information including the year of installation, the material, grade, diameter, wall thickness, and coating type; and190.341(c)(2)(iii)
(iv) Relevant operating information including operating pressure, leak history, and most recent testing or assessment results; 190.341(c)(2)(iv)
(3) A list of the specific regulation(s) from which the applicant seeks relief; 190.341(c)(3)
(4) An explanation of the unique circumstances that the applicant believes make the applicability of that regulation or standard (or portion thereof) unnecessary or inappropriate for its facility; 190.341(c)(4)
(5) A description of any measures or activities the applicant proposes to undertake as an alternative to compliance with the relevant regulation, including an explanation of how such measures will mitigate any safety or environmental risks; 190.341(c)(5)
(6) A description of any positive or negative impacts on affected stakeholders and a statement indicating how operating the pipeline pursuant to a special permit would be in the public interest; 190.341(c)(6)
(7) A certification that operation of the applicant's pipeline under the requested special permit would not be inconsistent with pipeline safety; 190.341(c)(7)
(8) Any other information PHMSA may need to process the application including environmental analysis where necessary. 190.341(c)(8)
(d) How does PHMSA handle special permit applications? 190.341(d)
(1) Public notice. Upon receipt of an application or renewal of a special permit, PHMSA will provide notice to the public of its intent to consider the application and invite comment. In addition, PHMSA may consult with other Federal agencies before granting or denying an application or renewal on matters that PHMSA believes may have significance for proceedings under their areas of responsibility. 190.341(d)(1)
(2) Grants, renewals, and denials. If the Associate Administrator determines that the application complies with the requirements of this section and that the waiver of the relevant regulation or standard is not inconsistent with pipeline safety, the Associate Administrator may grant the application, in whole or in part, for a period of time from the date granted. Conditions may be imposed on the grant if the Associate Administrator concludes they are necessary to assure safety, environmental protection, or are otherwise in the public interest. If the Associate Administrator determines that the application does not comply with the requirements of this section or that a waiver is not justified, the application will be denied. Whenever the Associate Administrator grants or denies an application, notice of the decision will be provided to the applicant. PHMSA will post all special permits on its Web site at http:// www.phmsa.dot.gov/. 190.341(d)(2)
§190.341 Part 190 – Pipeline Safety Programs And
(e) How does PHMSA handle special permit renewals? 190.341(e)
(1) The grantee of the special permit must apply for a renewal of the permit 180 days prior to the permit expiration. 190.341(e)(1)
(2) If, at least 180 days before an existing special permit expires the holder files an application for renewal that is complete and conforms to the requirements of this section, the special permit will not expire until final administrative action on the application for renewal has been taken: 190.341(e)(2)
(i) Direct fax to PHMSA at: 202-366-4566; or190.341(e)(2)(i)
(ii) Express mail, or overnight courier to the Associate Administrator for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590.190.341(e)(2)(ii)
(f) What information must be included in the renewal application?
190.341(f)
(1) The renewal application must include a copy of the original special permit, the docket number on the special permit, and the following information as applicable: 190.341(f)(1)
(i) A summary report in accordance with the requirements of the original special permit including verification that the grantee's operations and maintenance plan (O&M Plan) is consistent with the conditions of the special permit;190.341(f)(1)(i)
(ii) Name, mailing address and telephone number of the special permit grantee;190.341(f)(1)(ii)
(iii) Location of special permit — areas on the pipeline where the special permit is applicable including: Diameter, mile posts, county, and state;190.341(f)(1)(iii)
(iv) Applicable usage of the special permit — original and future; and190.341(f)(1)(iv)
(v) Data for the special permit segment and area identified in the special permit as needing additional inspections to include, as applicable:190.341(f)(1)(v)
[A] Pipe attributes: Pipe diameter, wall thickness, grade, seam type; and pipe coating including girth weld coating; 190.341(f)(1)(v)[A]
[B] Operating Pressure: Maximum allowable operating pressure (MAOP); class location (including boundaries on aerial photography);190.341(f)(1)(v)[B]
[C] High Consequence Areas (HCAs): HCA boundaries on aerial photography;190.341(f)(1)(v)[C]
[D] Material Properties: Pipeline material documentation for all pipe, fittings, flanges, and any other facilities included in the special permit. Material documentation must include: Yield strength, tensile strength, chemical composition, wall thickness, and seam type;190.341(f)(1)(v)[D]
[E] Test Pressure: Hydrostatic test pressure and date including pressure and temperature charts and logs and any known test failures or leaks;190.341(f)(1)(v)[E]
[F] In-line inspection (ILI): Summary of ILI survey results from all ILI tools used on the special permit segments during the previous five years or latest ILI survey result;190.341(f)(1)(v)[F]
[G] Integrity Data and Integration: The following information, as applicable, for the past five (5) years: Hydrostatic test pressure including any known test failures or leaks; casings(any shorts); any in-service ruptures or leaks; close interval survey (CIS) surveys; depth of cover surveys; rectifier readings; test point survey readings; alternating current/direct current (AC/DC) interference surveys; pipe coating surveys; pipe coating and anomaly evaluations from pipe excavations; stress corrosion cracking (SCC), selective seam weld corrosion (SSWC) and hard spot excavations and findings; and pipe exposures from encroachments;190.341(f)(1)(v)[G]
[H] In-service: Any in-service ruptures or leaks including repair type and failure investigation findings; and190.341(f)(1)(v)[H]
[I] Aerial Photography: Special permit segment and special permit inspection area, if applicable.190.341(f)(1)(v)[I]
(2) PHMSA may request additional operational, integrity or environmental assessment information prior to granting any request for special permit renewal. 190.341(f)(2)
(3) The existing special permit will remain in effect until PHMSA acts on the application for renewal by granting or denying the request. 190.341(f)(3)
(g) Can a special permit be requested on an emergency basis? Yes. PHMSA may grant an application for an emergency special permit without notice and comment or hearing if the Associate Administrator determines that such action is in the public interest, is not inconsistent with pipeline safety, and is necessary to address an actual or impending emergency involving pipeline transportation. For purposes of this section, an emergency event may be local, regional, or national in scope and includes significant fuel supply disruptions and natural or manmade disasters such as hurricanes, floods, earthquakes, terrorist acts, biological outbreaks, releases of dangerous radiological, chemical, or bio-
logical materials, war-related activities, or other similar events. PHMSA will determine on a case-by-case basis what duration is necessary to address the emergency. However, as required by statute, no emergency special permit may be issued for a period of more than 60 days. Each emergency special permit will automatically expire on the date specified in the permit. Emergency special permits may be renewed upon application to PHMSA only after notice and opportunity for a hearing on the renewal. 190.341(g)
(h) How do I apply for an emergency special permit? Applications for emergency special permits may be submitted to PHMSA using any of the following methods: 190.341(h)
(1) Direct fax to the Crisis Management Center at: 202-366-3768; 190.341(h)(1)
(2) Direct e-mail to PHMSA at: phmsa.pipeline-emergencyspecpermit@dot.gov; or 190.341(h)(2)
(3) Express mail/overnight courier to the Associate Administrator for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., East Building, Washington, DC 20590. 190.341(h)(3)
(i) What must be contained in an application for an emergency special permit? In addition to the information required under paragraph (c) of this section, applications for emergency special permits must include: 190.341(i)
(1) An explanation of the actual or impending emergency and how the applicant is affected; 190.341(i)(1)
(2) A citation of the regulations that are implicated and the specific reasons the permit is necessary to address the emergency (e.g., lack of accessibility, damaged equipment, insufficient manpower); 190.341(i)(2)
(3) A statement indicating how operating the pipeline pursuant to an emergency special permit is in the public interest (e.g., continuity of service, service restoration); 190.341(i)(3)
(4) A description of any proposed alternatives to compliance with the regulation (e.g., additional inspections and tests, shortened reassessment intervals); and 190.341(i)(4)
(5) A description of any measures to be taken after the emergency situation or permit expires — whichever comes first — to confirm long-term operational reliability of the pipeline facility. 190.341(i)(5)
Note to paragraph (g): If PHMSA determines that handling of the application on an emergency basis is not warranted, PHMSA will notify the applicant and process the application under normal special permit procedures of this section.
(j) In what circumstances will PHMSA revoke, suspend, or modify a special permit? 190.341(j)
(1) PHMSA may revoke, suspend, or modify a special permit on a finding that: 190.341(j)(1)
(i) Intervening changes in Federal law mandate revocation, suspension, or modification of the special permit;190.341(j)(1)(i)
(ii) Based on a material change in conditions or circumstances, continued adherence to the terms of the special permit would be inconsistent with safety;190.341(j)(1)(ii)
(iii) The application contained inaccurate or incomplete information, and the special permit would not have been granted had the application been accurate and complete;190.341(j)(1)(iii)
(iv) The application contained deliberately inaccurate or incomplete information; or190.341(j)(1)(iv)
(v) The holder has failed to comply with any material term or condition of the special permit.190.341(j)(1)(v)
(2) Except as provided in paragraph (h)(3) of this section, before a special permit is modified, suspended or revoked, PHMSA will notify the holder in writing of the proposed action and the reasons for it, and provide an opportunity to show cause why the proposed action should not be taken. 190.341(j)(2)
(i) The holder may file a written response that shows cause why the proposed action should not be taken within 30 days of receipt of notice of the proposed action.190.341(j)(2)(i)
(ii) After considering the holder's written response, or after 30 days have passed without response since receipt of the notice, PHMSA will notify the holder in writing of the final decision with a brief statement of reasons.190.341(j)(2)(ii)
(3) If necessary to avoid a risk of significant harm to persons, property, or the environment, PHMSA may in the notification declare the proposed action immediately effective. 190.341(j)(3)
(4) Unless otherwise specified, the terms and conditions of a corrective action order, compliance order, or other order applicable to a pipeline facility covered by a special permit will take precedence over the terms of the special permit. 190.341(j)(4)
(5) A special permit holder may seek reconsideration of a decision under paragraph (h) of this section as provided in paragraph (i) of this section. 190.341(j)(5)
(k) Can a denial of a request for a special permit or a revocation of an existing special permit be appealed? Reconsideration of the denial of an application for a special permit or a revocation of an existing special permit may be sought by petition to the Associate
Administrator. Petitions for reconsideration must be received by PHMSA within 20 calendar days of the notice of the grant or denial and must contain a brief statement of the issue and an explanation of why the petitioner believes that the decision being appealed is not in the public interest. The Associate Administrator may grant or deny, in whole or in part, any petition for reconsideration without further proceedings. The Associate Administrator's decision is the final administrative action. 190.341(k)
(l) Are documents related to an application for a special permit available for public inspection? Documents related to an application, including the application itself, are available for public inspection on regulations.gov or the Docket Operations Facility to the extent such documents do not include information exempt from public disclosure under 5 U.S.C. 552(b). Applicants may request confidential treatment under part 7 of this title. 190.341(l)
(m) Am I subject to enforcement action for non-compliance with the terms and conditions of a special permit? Yes. PHMSA inspects for compliance with the terms and conditions of special permits and if a probable violation is identified, PHMSA will initiate one or more of the enforcement actions under subpart B of this part. 190.341(m)
§190.343
Information made publicly available & request for protection of confidential commercial information
When you submit information to PHMSA during a rulemaking proceeding, as part of your application for special permit or renewal, or for any other reason, we may make that information publicly available unless you ask that we keep the information confidential.
(a) Asking for protection of confidential commercial information. You may ask us to give confidential treatment to information you give to the agency by taking the following steps: 190.343(a)
(1) Mark "confidential" on each page of the original document you would like to keep confidential. 190.343(a)(1)
(2) Send us, along with the original document, a second copy of the original document with the confidential commercial information deleted. 190.343(a)(2)
(3) Explain why the information you are submitting is confidential commercial information. 190.343(a)(3)
(b) PHMSA decision. PHMSA will treat as confidential the information that you submitted in accordance with this section, unless we notify you otherwise. If PHMSA decides to disclose the information, PHMSA will review your request to protect confidential commercial information under the criteria set forth in the Freedom of Information Act (FOIA), 5 U.S.C. 552, including following the consultation procedures set out in the Departmental FOIA regulations, 49 CFR 7.29. If PHMSA decides to disclose the information over your objections, we will notify you in writing at least five business days before the intended disclosure date. 190.343(b)
Subpart E – Cost Recovery for Design Reviews
§190.401 Scope
If PHMSA conducts a facility design and/or construction safety review or inspection in connection with a proposal to construct, expand, or operate a gas, hazardous liquid or carbon dioxide pipeline facility, or a liquefied natural gas facility that meets the applicability requirements in §190.403, PHMSA may require the applicant proposing the project to pay the costs incurred by PHMSA relating to such review, including the cost of design and construction safety reviews or inspections.
§190.403
Applicability
The following paragraph specifies which projects will be subject to the cost recovery requirements of this section.
(a) This section applies to any project that — 190.403(a)
(1) Has design and construction costs totaling at least $2,500,000,000, as periodically adjusted by PHMSA, to take into account increases in the Consumer Price Index for all urban consumers published by the Department of Labor, based on — 190.403(a)(1)
(i) The cost estimate provided to the Federal Energy Regulatory Commission in an application for a certificate of public convenience and necessity for a gas pipeline facility or an application for authorization for a liquefied natural gas pipeline facility; or 190.403(a)(1)(i)
(ii) A good faith estimate developed by the applicant proposing a hazardous liquid or carbon dioxide pipeline facility and submitted to the Associate Administrator. The good faith estimate for
design and construction costs must include all of the applicable cost items contained in the Federal Energy Regulatory Commission application referenced in §190.403(a)(1)(i) for a gas or LNG facility. In addition, an applicant must take into account all survey, design, material, permitting, right-of way acquisition, construction, testing, commissioning, start-up, construction financing, environmental protection, inspection, material transportation, sales tax, project contingency, and all other applicable costs, including all segments, facilities, and multi-year phases of the project;190.403(a)(1)(ii)
(2) Uses new or novel technologies or design, as defined in §190.3. 190.403(a)(2)
(b) The Associate Administrator may not collect design safety review fees under this section and 49 U.S.C. 60301 for the same design safety review. 190.403(b)
(c) The Associate Administrator, after receipt of the design specifications, construction plans and procedures, and related materials, determines if cost recovery is necessary. The Associate Administrator's determination is based on the amount of PHMSA resources needed to ensure safety and environmental protection. 190.403(c)
§190.405 Notification
For any new pipeline facility construction project in which PHMSA will conduct a design review, the applicant proposing the project must notify PHMSA and provide the design specifications, construction plans and procedures, project schedule and related materials at least 120 days prior to the commencement of any of the following activities: Route surveys for construction, material manufacturing, offsite facility fabrications, construction equipment move-in activities, onsite or offsite fabrications, personnel support facility construction, and any offsite or onsite facility construction. To the maximum extent practicable, but not later than 90 days after receiving such design specifications, construction plans and procedures, and related materials, PHMSA will provide written comments, feedback, and guidance on the project.
§190.407 Master Agreement
PHMSA and the applicant will enter into an agreement within 60 days after PHMSA received notification from the applicant provided in §190.405, outlining PHMSA's recovery of the costs associated with the facility design safety review.
(a) A Master Agreement, at a minimum, includes: 190.407(a)
(1) Itemized list of direct costs to be recovered by PHMSA; 190.407(a)(1)
(2) Scope of work for conducting the facility design safety review and an estimated total cost; 190.407(a)(2)
(3) Description of the method of periodic billing, payment, and auditing of cost recovery fees; 190.407(a)(3)
(4) Minimum account balance which the applicant must maintain with PHMSA at all times; 190.407(a)(4)
(5) Provisions for reconciling differences between total amount billed and the final cost of the design review, including provisions for returning any excess payments to the applicant at the conclusion of the project; 190.407(a)(5)
(6) A principal point of contact for both PHMSA and the applicant; and 190.407(a)(6)
(7) Provisions for terminating the agreement.190.407(a)(7)
(8) A project reimbursement cost schedule based upon the project timing and scope. 190.407(a)(8)
(b) [Reserved] 190.407(b)
§190.409 Fee structure
The fee charged is based on the direct costs that PHMSA incurs in conducting the facility design safety review (including construction review and inspections), and will be based only on costs necessary for conducting the facility design safety review. "Necessary for" means that but for the facility design safety review, the costs would not have been incurred and that the costs cover only those activities and items without which the facility design safety review cannot be completed.
(a) Costs qualifying for cost recovery include, but are not limited to — 190.409(a)
(1) Personnel costs based upon total cost to PHMSA; 190.409(a)(1)
(2) Travel, lodging and subsistence;190.409(a)(2)
(3) Vehicle mileage;190.409(a)(3)
(4) Other direct services, materials and supplies; 190.409(a)(4)
(5) Other direct costs as may be specified in the Master Agreement. 190.409(a)(5)
(b) [Reserved] 190.409(b)
§190.411 Part 190 –
§190.411 Procedures for billing and payment of fee
All PHMSA cost calculations for billing purposes are determined from the best available PHMSA records.
(a) PHMSA bills an applicant for cost recovery fees as specified in the Master Agreement, but the applicant will not be billed more frequently than quarterly. 190.411(a)
(1) PHMSA will itemize cost recovery bills in sufficient detail to allow independent verification of calculations. 190.411(a)(1)
(2) [Reserved]190.411(a)(2)
(b) PHMSA will monitor the applicant's account balance. Should the account balance fall below the required minimum balance specified in the Master Agreement, PHMSA may request at any time the applicant submit payment within 30 days to maintain the minimum balance. 190.411(b)
(c) PHMSA will provide an updated estimate of costs to the applicant on or near October 1st of each calendar year. 190.411(c)
(d) Payment of cost recovery fees is due within 30 days of issuance of a bill for the fees. If payment is not made within 30 days, PHMSA may charge an annual rate of interest (as set by the Department of Treasury's Statutory Debt Collection Authorities) on any outstanding debt, as specified in the Master Agreement. 190.411(d)
(e) Payment of the cost recovery fee by the applicant does not obligate or prevent PHMSA from taking any particular action during safety inspections on the project. 190.411(e)
§191.1
Scope
(a) This part prescribes requirements for the reporting of incidents, safety-related conditions, annual pipeline summary data, National Operator Registry information, and other miscellaneous conditions by operators of underground natural gas storage facilities and natural gas pipeline facilities located in the United States or Puerto Rico, including underground natural gas storage facilities and 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). This part applies to offshore gathering lines (except as provided in paragraph (b) of this section) and to onshore gathering lines, including Type R gathering lines as determined in §192.8 of this chapter. 191.1(a)
(b) This part does not apply to — 191.1(b)
(1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are produced or where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream; 191.1(b)(1)
(2) Pipelines on the Outer Continental Shelf (OCS) that are producer-operated and cross into State waters without first connecting to a transporting operator's facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS may petition the Administrator, or designee, for approval to operate under Pipeline and Hazardous Materials Safety Administration (PHMSA) regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9; or 191.1(b)(2)
(3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator. 191.1(b)(3)
(c) Sections 191.22(b) and (c) and 191.23 do not apply to the onshore gathering of gas — 191.1(c)
(1) Through a pipeline that operates at less than 0 psig (0 kPa); 191.1(c)(1)
(2) Through a pipeline that is not a regulated onshore gathering pipeline; or 191.1(c)(2)
(3) Within inlets of the Gulf of Mexico, except for the requirements in §192.612 of this chapter. 191.1(c)(3)
§191.3
Definitions
As used in this part and the PHMSA Forms referenced in this part — Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate
Confirmed Discovery means when it can be reasonably determined, based on information available to the operator at the time a reportable event has occurred, even if only based on a preliminary evaluation.
Gas means natural gas, flammable gas, or gas which is toxic or corrosive;
Incident means any of the following events:
(1) An event that involves a release of gas from a pipeline, gas from an underground natural gas storage facility (UNGSF), liquefied natural gas, liquefied petroleum gas, refrigerant gas, or gas from an LNG facility, and that results in one or more of the following consequences:
(i) A death, or personal injury necessitating in-patient hospitalization;
(ii) Estimated property damage of $122,000 or more, including loss to the operator and others, or both, but excluding the cost of gas lost. For adjustments for inflation observed in calendar year 2021 onwards, changes to the reporting threshold will be posted on PHMSA's website. These changes will be determined in accordance with the procedures in appendix A to part 191.
(iii) Unintentional estimated gas loss of three million cubic feet or more.
(2) An event that results in an emergency shutdown of an LNG facility or a UNGSF. Activation of an emergency shutdown system for reasons other than an actual emergency within the facility does not constitute an incident.
(3) An event that is significant in the judgment of the operator, even though it did not meet the criteria of paragraph (1) or (2) of this definition.
LNG facility means a liquefied natural gas facility as defined in §193.2007 of part 193 of this chapter;
Master Meter System means a pipeline system for distributing gas within, but not limited to, a definable area, such as a mobile home park, housing project, or apartment complex, where the operator purchases metered gas from an outside source for resale through a gas distribution pipeline system. The gas distribution pipeline system supplies the ultimate consumer who either purchases the gas directly through a meter or by other means, such as by rents;
Municipality means a city, county, or any other political subdivision of a State;
Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters;
Operator means a person who engages in the transportation of gas;
Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof;
Pipeline or Pipeline System means all parts of those physical facilities through which gas moves in transportation, including, but not limited to, pipe, valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
Regulated onshore gathering means a Type A, Type B, or Type C gas gathering pipeline system as determined in §192.8 of this chapter.
Reporting-regulated gathering means a Type R gathering line as determined in §192.8 of this chapter. A Type R gathering line is subject only to this part.
State includes each of the several States, the District of Columbia, and the Commonwealth of Puerto Rico;
Transportation of gas means the gathering, transmission, or distribution of gas by pipeline, or the storage of gas in or affecting interstate or foreign commerce.
Underground natural gas storage facility (UNGSF) means an underground natural gas storage facility or UNGSF as defined in §192.3 of this chapter.
§191.5 Immediate notice of certain incidents
(a) At the earliest practicable moment following discovery, but no later than one hour after confirmed discovery, each operator must give notice in accordance with paragraph (b) of this section of each incident as defined in §191.3. 191.5(a)
(b) Each notice required by paragraph (a) of this section must be made to the National Response Center either by telephone to 800-424-8802 (in Washington, DC, 202 267-2675) or electronically at http://www.nrc.uscg.mil and must include the following information: 191.5(b)
(1) Names of operator and person making report and their telephone numbers. 191.5(b)(1)
(2) The location of the incident.191.5(b)(2)
(3) The time of the incident.191.5(b)(3)
(4) The number of fatalities and personal injuries, if any. 191.5(b)(4)
(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. 191.5(b)(5)
(c) Within 48 hours after the confirmed discovery of an incident, to the extent practicable, an operator must revise or confirm its initial telephonic notice required in paragraph (b) of this section with an
estimate of the amount of product released, an estimate of the number of fatalities and injuries, and all other significant facts that are known by the operator that are relevant to the cause of the incident or extent of the damages. If there are no changes or revisions to the initial report, the operator must confirm the estimates in its initial report. 191.5(c)
§191.7 Report submission requirements
(a) General. Except as provided in paragraphs (b) and (e) of this section, an operator must submit each report required by this part electronically to the Pipeline and Hazardous Materials Safety Administration at http://portal.phmsa.dot.gov/pipeline unless an alternative reporting method is authorized in accordance with paragraph (d) of this section. 191.7(a)
(b) Exceptions: An operator is not required to submit a safety-related condition report §191.25) electronically. 191.7(b)
(c) Safety-related conditions. An operator must submit concurrently to the applicable State agency a safety-related condition report required by §191.23 for intrastate pipeline transportation or when the State agency acts as an agent of the Secretary with respect to interstate transmission facilities. 191.7(c)
(d) Alternative Reporting Method. If electronic reporting imposes an undue burden and hardship, an operator may submit a written request for an alternative reporting method to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, PHP-20, 1200 New Jersey Avenue, SE, Washington DC 20590. The request must describe the undue burden and hardship. PHMSA will review the request and may authorize, in writing, an alternative reporting method. An authorization will state the period for which it is valid, which may be indefinite. An operator must contact PHMSA at 202366-8075, or electronically to informationresourcesmanager@dot.gov or make arrangements for submitting a report that is due after a request for alternative reporting is submitted but before an authorization or denial is received. 191.7(d)
(e) National Pipeline Mapping System (NPMS). An operator must provide the NPMS data to the address identified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. 191.7(e)
§191.9 Distribution system: Incident report
(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. 191.9(a)
(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. 191.9(b)
(c) Master meter operators are not required to submit an incident report as required by this section. 191.9(c)
§191.11 Distribution system: Annual report
(a) General. Except as provided in paragraph (b) of this section, each operator of a distribution pipeline system must submit an annual report for that system on DOT Form PHMSA F 7100.1-1. This report must be submitted each year, not later than March 15, for the preceding calendar year. 191.11(a)
(b) Not required. The annual report requirement in this section does not apply to a master meter system, a petroleum gas system that serves fewer than 100 customers from a single source, or an individual service line directly connected to a production pipeline or a gathering line other than a regulated gathering line as determined in §192.8. 191.11(b)
§191.12 [Reserved]
§191.13 Distribution systems reporting transmission pipelines; transmission or gathering systems reporting distribution pipelines
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.
§191.15 Transmission systems; gathering systems; liquefied natural gas facilities; and underground natural gas storage facilities: Incident report
(a) Pipeline systems 191.15(a)
(1) Transmission, offshore gathering, or regulated onshore gathering. Each operator of a transmission, offshore gathering, or a regulated onshore gathering pipeline system must submit Department of Transportation (DOT) Form PHMSA 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. 191.15(a)(1)
(2) Reporting-regulated gathering. Each operator of a reporting-regulated gathering pipeline system must submit DOT Form PHMSA F 7100.2-2 as soon as practicable but not more than 30 days after detection of an incident required to be reported under §191.5 that occurs after May 16, 2022. 191.15(a)(2)
(b) LNG. Each operator of a liquefied natural gas plant or facility must submit DOT Form PHMSA F 7100.3 as soon as practicable but not more than 30 days after detection of an incident required to be reported under §191.5 of this part. 191.15(b)
(c) Underground natural gas storage facility. Each operator of a UNGSF must submit DOT Form PHMSA F7100.2 as soon as practicable but not more than 30 days after the detection of an incident required to be reported under §191.5. 191.15(c)
(d) Supplemental report. Where additional related information is obtained after an operator submits a report under paragraph (a), (b), or (c) of this section, the operator must make a supplemental report as soon as practicable, with a clear reference by date to the original report. 191.15(d)
§191.17 Transmission systems; gathering systems; liquefied natural gas facilities; and underground natural gas storage facilities:
Annual report
(a) Pipeline systems. 191.17(a)
(1) Transmission, offshore gathering, or regulated onshore gathering. Each operator of a transmission, offshore gathering, or regulated onshore gathering pipeline system must submit an annual report for that system on DOT Form PHMSA F 7100.2-1. This report must be submitted each year, not later than March 15, for the preceding calendar year. 191.17(a)(1)
(2) Type R gathering. Beginning with an initial annual report submitted in March 2023 for the 2022 calendar year, each operator of a reporting-regulated gas gathering pipeline system must submit an annual report for that system on DOT Form PHMSA F 7100.2-3. This report must be submitted each year, not later than March 15, for the preceding calendar year. 191.17(a)(2)
(b) LNG. Each operator of a liquefied natural gas facility must submit an annual report for that system on DOT Form PHMSA 7100.3-1 This report must be submitted each year, not later than March 15, for the preceding calendar year, except that for the 2010 reporting year the report must be submitted by June 15, 2011. 191.17(b)
(c) Underground natural gas storage facility. Each operator of a UNGSF must submit an annual report through DOT Form PHMSA 7100.4-1. This report must be submitted each year, no later than March 15, for the preceding calendar year. 191.17(c)
§191.21 OMB control number assigned to information collection
This section displays the control number assigned by the Office of Management and Budget (OMB) to the information collection requirements in this part. The Paperwork Reduction Act requires agencies to display a current control number assigned by the Director of OMB for each agency information collection requirement.
OMB Control Number 2137-0522
Section of 49 CFR Part 191 where identified Form No.
OMB Control Number 2137-0522 (continued)
Section of 49 CFR Part 191 where identified Form No.
(a) OPID request. Effective January 1, 2012, each operator of a gas pipeline, gas pipeline facility, UNGSF, LNG plant, or LNG facility must obtain from PHMSA an Operator Identification Number (OPID). An OPID is assigned to an operator for the pipeline, pipeline facility, or pipeline system for which the operator has primary responsibility. To obtain an OPID, an operator must submit an OPID Assignment Request DOT Form PHMSA F 1000.1 through the National Registry of Operators in accordance with §191.7. 191.22(a)
(b) OPID validation. An operator who has already been assigned one or more OPIDs by January 1, 2011, must validate the information associated with each OPID through the National Registry of Operators at https://portal.phmsa .dot.gov, and correct that information as necessary, no later than June 30, 2012. 191.22(b)
(c) Changes. Each operator of a gas pipeline, gas pipeline facility, UNGSF, LNG plant, or LNG facility must notify PHMSA electronically through the National Registry of Operators at https://portal.phmsa.dot.gov of certain events. 191.22(c)
(1) An operator must notify PHMSA of any of the following events not later than 60 days before the event occurs: 191.22(c)(1)
(i) Construction of any planned rehabilitation, replacement, modification, upgrade, uprate, or update of a facility, other than a section of line pipe, that costs $10 million or more. If 60-day notice is not feasible because of an emergency, an operator must notify PHMSA as soon as practicable;191.22(c)(1)(i)
(ii) Construction of 10 or more miles of a new pipeline;191.22(c)(1)(ii)
(iii) Construction of a new LNG plant, LNG facility, or UNGSF; 191.22(c)(1)(iii)
(iv) Maintenance of a UNGSF that involves the plugging or abandonment of a well, or that requires a workover rig and costs $200,000 or more for an individual well, including its wellhead. If 60-days' notice is not feasible due to an emergency, an operator must promptly respond to the emergency and notify PHMSA as soon as practicable;191.22(c)(1)(iv)
(v) Reversal of product flow direction when the reversal is expected to last more than 30 days. This notification is not required for pipeline systems already designed for bi-directional flow; or 191.22(c)(1)(v)
(vi) A pipeline converted for service under §192.14 of this chapter, or a change in commodity as reported on the annual report as required by §191.17.191.22(c)(1)(vi)
(2) An operator must notify PHMSA of any of the following events not later than 60 days after the event occurs: 191.22(c)(2)
(i) A change in the primary entity responsible (i.e., with an assigned OPID) for managing or administering a safety program required by this part covering pipeline facilities operated under multiple OPIDs;191.22(c)(2)(i)
(ii) A change in the name of the operator;191.22(c)(2)(ii)
(iii) A change in the entity (e.g., company, municipality) responsible for an existing pipeline, pipeline segment, pipeline facility, UNGSF, or LNG facility;191.22(c)(2)(iii)
(iv) The acquisition or divestiture of 50 or more miles of a pipeline or pipeline system subject to part 192 of this subchapter; or 191.22(c)(2)(iv)
(v) The acquisition or divestiture of an existing UNGSF, or an LNG plant or LNG facility subject to part 193 of this subchapter. 191.22(c)(2)(v)
(d) Reporting. An operator must use the OPID issued by PHMSA for all reporting requirements covered under this subchapter and for submissions to the National Pipeline Mapping System. 191.22(d)
§191.23
Reporting safety-related conditions.
(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: 191.23(a)
(1) In the case of a pipeline (other than an LNG facility) that operates at a hoop stress of 20% 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. 191.23(a)(1)
(2) In the case of a UNGSF, general corrosion that has reduced the wall thickness of any metal component to less than that required for the well's maximum operating pressure, or localized corrosion pitting to a degree where leakage might result. 191.23(a)(2)
(3) 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 a UNGSF or LNG facility that contains, controls, or processes gas or LNG. 191.23(a)(3)
(4) Any crack or other material defect that impairs the structural integrity or reliability of a UNGSF or an LNG facility that contains, controls, or processes gas or LNG. 191.23(a)(4)
(5) Any material defect or physical damage that impairs the serviceability of a pipeline that operates at a hoop stress of 20% or more of its specified minimum yield strength, or the serviceability or the structural integrity of a UNGSF. 191.23(a)(5)
(6) Any malfunction or operating error that causes the pressure — plus the margin (build-up) allowed for operation of pressure limiting or control devices — to exceed either the maximum allowable operating pressure of a distribution or gathering line, the maximum well allowable operating pressure of an underground natural gas storage facility, or the maximum allowable working pressure of an LNG facility that contains or processes gas or LNG. 191.23(a)(6)
(7) A leak in a pipeline, UNGSF, or LNG facility containing or processing gas or LNG that constitutes an emergency. 191.23(a)(7)
(8) Inner tank leakage, ineffective insulation, or frost heave that impairs the structural integrity of an LNG storage tank. 191.23(a)(8)
(9) 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% or more reduction in operating pressure or shutdown of operation of a pipeline, UNGSF, or an LNG facility that contains or processes gas or LNG. 191.23(a)(9)
(10) For transmission pipelines only, each exceedance of the maximum allowable operating pressure that exceeds the margin (buildup) allowed for operation of pressure-limiting or control devices as specified in the applicable requirements of §§192.201, 192.620(e), and 192.739. The reporting requirement of this paragraph (a)(10) is not applicable to gathering lines, distribution lines, LNG facilities, or underground natural gas storage facilities (See paragraph (a)(6) of this section). 191.23(a)(10)
(11) Any malfunction or operating error that causes the pressure of a UNGSF using a salt cavern for natural gas storage to fall below its minimum allowable operating pressure, as defined by the facility's State or Federal operating permit or certificate, whichever pressure is higher. 191.23(a)(11)
(b) A report is not required for any safety-related condition that — 191.23(b)
(1) Exists on a master meter system, a reporting-regulated gathering pipeline, or a customer-owned service line; 191.23(b)(1)
(2) Is an incident or results in an incident before the deadline for filing the safety-related condition report; 191.23(b)(2)
(3) Exists on a pipeline (other than an UNGSF or 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 191.23(b)(3)
(4) Is corrected by repair or replacement in accordance with applicable safety standards before the deadline for filing the safety-related condition report. Notwithstanding this exception, a report must be filed for: 191.23(b)(4)
(i) Conditions under paragraph (a)(1) of this section, unless the condition is localized corrosion pitting on an effectively coated and cathodically protected pipeline; and191.23(b)(4)(i)
(ii) Any condition under paragraph (a)(10) of this section. 191.23(b)(4)(ii)
(5) Exists on an UNGSF, where a well or wellhead is isolated, allowing the reservoir or cavern and all other components of the facility to continue to operate normally and without pressure restriction. 191.23(b)(5)
§191.25
Filing safety-related condition reports
(a) Each report of a safety-related condition under §191.23(a)(1) through (9) must be filed (received by the Associate Administrator) in writing within 5 working days (not including Saturday, Sunday, or Federal holidays) after the day a representative of an operator first determines that the condition exists, but not later than 10 working days after the day a representative of an operator discovers the condition. Separate conditions may be described in a single report if they are closely related. Reporting methods and report requirements are described in paragraph (c) of this section. 191.25(a)
(b) Each report of a maximum allowable operating pressure exceedance meeting the requirements of criteria in §191.23(a)(10) for a gas transmission pipeline must be filed (received by the Associate Administrator) in writing within 5 calendar days of the exceedance using the reporting methods and report requirements described in paragraph (c) of this section. 191.25(b)
(c) Reports must be filed by email to InformationResourcesManager@dot.gov or by facsimile to (202) 366-7128. For a report made pursuant to §191.23(a)(1) through (9), the report must be headed “Safety-Related Condition Report.” For a report made pursuant to §191.23(a)(10), the report must be headed “Maximum Allowable Operating Pressure Exceedances.” All reports must provide the following information: 191.25(c)
(1) Name, principal address, and operator identification number (OPID) of the operator. 191.25(c)(1)
(2) Date of report.191.25(c)(2)
(3) Name, job title, and business telephone number of person submitting the report. 191.25(c)(3)
(4) Name, job title, and business telephone number of person who determined that the condition exists. 191.25(c)(4)
(5) Date condition was discovered and date condition was first determined to exist. 191.25(c)(5)
(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. 191.25(c)(6)
(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. 191.25(c)(7)
(8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned followup or future corrective action, including the anticipated schedule for starting and concluding such action. 191.25(c)(8)
§191.29 National Pipeline Mapping System
(a) Each operator of a gas transmission pipeline or liquefied natural gas facility must provide the following geospatial data to PHMSA for that pipeline or facility: 191.29(a)
(1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards Manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. 191.29(a)(1)
(2) The name of and address for the operator.191.29(a)(2)
(3) The name and contact information of a pipeline company employee, to be displayed on a public Web site, who will serve as a contact for questions from the general public about the operator's NPMS data. 191.29(a)(3)
(b) The information required in paragraph (a) of this section must be submitted each year, on or before March 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, the operator must comply with the guidance provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information Systems Manager at (202) 366-4595. 191.29(b)
(c) This section does not apply to gathering pipelines. 191.29(c)
Appendix A Part 191 — Procedure for Determining Reporting Threshold
I. Property Damage Threshold Formula Appendix A I. Each year after calendar year 2021, the Administrator will publish a notice on PHMSA's website announcing the updates to the property damage threshold criterion that will take effect on July 1 of that year and will remain in effect until the June 30 of the next year. The property damage threshold used in the definition of an Incident at §191.3 shall be determined in accordance with the following formula:
Where:
Tr is the revised damage threshold, Tp is the previous damage threshold, CPIr is the average Consumer Price Indices for all Urban Consumers (CPI-U) published by the Bureau of Labor Statistics each month during the most recent complete calendar year, and CPIp is the average CPI-U for the calendar year used to establish the previous property damage criteria.
Part 192 – Minimum Federal Safety Standards
49 U.S.C.
§192.3 Part 192 – Minimum Federal Safety Standards
may petition the Administrator, or designee, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance under 49 CFR 190.9; 192.1(b)(2)
(3) Pipelines on the Outer Continental Shelf upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator; 192.1(b)(3)
(4) Onshore gathering of gas — 192.1(b)(4)
(i) Through a pipeline that operates at less than 0 psig (0 kPa); 192.1(b)(4)(i)
(ii) Through a pipeline that is not a regulated onshore gathering line (as determined in §192.8); and192.1(b)(4)(ii)
(iii) Within inlets of the Gulf of Mexico, except for the requirements in §192.612; or192.1(b)(4)(iii)
(5) Any pipeline system that transports only petroleum gas or petroleum gas/air mixtures to — 192.1(b)(5)
(i) Fewer than 10 customers, if no portion of the system is located in a public place; or192.1(b)(5)(i)
(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).192.1(b)(5)(ii)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, Aug. 16, 1976; Amdt. 192-67, 56 FR 63771, Dec. 5, 1991; Amdt. 192-78, 61 FR 28782, June 6, 1996; Amdt. 192-81, 62 FR 61695, Nov. 19, 1997; Amdt. 192-92, 68 FR 46112, Aug. 5, 2003; 70 FR 11139, Mar. 8, 2005; Amdt. 192-102, 71 FR 13301, Mar. 15, 2006; Amdt. 192-103, 72 FR 4656, Feb. 1, 2007]
§192.3
Definitions
As used in this part:
Abandoned means permanently removed from service.
Active corrosion means continuing corrosion that, unless controlled, could result in a condition that is detrimental to public safety.
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safetyrelated parameters.
Composite materials means materials used to make pipe or components manufactured with a combination of either steel and/or plastic and with a reinforcing material to maintain its circumferential or longitudinal strength.
§192.935 What additional preventive and mitigative measures must an operator take?.....................................................79
§192.937 What is a continual process of evaluation and assessment to maintain a pipeline's integrity?...........................80
§192.939 What are the required reassessment intervals?.....................................................................................................80
§192.941 What is a low stress reassessment?.......................................................................................................................81
§192.943 When can an operator deviate from these reassessment intervals?....................................................................81
§192.945 What methods must an operator use to measure program effectiveness?..........................................................82
§192.947 What records must an operator keep?....................................................................................................................82
§192.949§192.951Where does an operator file a report?......................................................................................................82 Subpart P – Gas Distribution Pipeline Integrity Management (IM)...........................................................82
§192.1001What definitions apply to this subpart?...................................................................................................................82
§192.1003What do the regulations in this subpart cover?......................................................................................................82
§192.1005What must a gas distribution operator (other than a small LPG operator) do to implement this subpart?........82
§192.1007What are the required elements of an integrity management plan?.....................................................................82
§192.1011What records must an operator keep?...................................................................................................................83
§192.1013When may an operator deviate from required periodic inspections under this part?..........................................83
§192.1015 What must a small LPG operator do to implement this subpart?........................................................................83
Appendix BPart 192 — Qualification of Pipe and Components............................................................................................83
Appendix CPart 192 — Qualification of Welders for Low Stress Level Pipe........................................................................84
Appendix DPart 192 — Criteria for Cathodic Protection and Determination of Measurements.........................................85
Appendix EPart 192 — Guidance on Determining High Consequence Areas and on Carrying out Requirements in the Integrity Management Rule......................................................................................................................................85
Appendix FPart 192-Criteria for Conducting Integrity Assessments Using Guided Wave Ultrasonic Testing (GWUT)...87
Subpart A – General
§192.1 What is the scope of this part?
(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). 192.1(a)
(b) This part does not apply to — 192.1(b)
(1) Offshore gathering of gas in State waters upstream from the outlet flange of each facility where hydrocarbons are produced or where produced hydrocarbons are first separated, dehydrated, or otherwise processed, whichever facility is farther downstream; 192.1(b)(1)
(2) Pipelines on the Outer Continental Shelf (OCS) that are produceroperated and cross into State waters without first connecting to a transporting operator's facility on the OCS, upstream (generally seaward) of the last valve on the last production facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. Producing operators for those pipeline segments upstream of the last valve of the last production facility on the OCS
Control room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility.
Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility.
Customer meter means the meter that measures the transfer of gas from an operator to a consumer.
Distribution line means a pipeline other than a gathering or transmission line.
Electrical survey means a series of closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline.
Engineering critical assessment (ECA) means a documented analytical procedure based on fracture mechanics principles, relevant material properties (mechanical and fracture resistance properties), operating history, operational environment, in-service degradation, possible failure mechanisms, initial and final defect sizes, and usage of future operating and maintenance procedures to determine the maximum tolerable sizes for imperfections based upon the pipeline segment maximum allowable operating pressure.
Entirely replaced onshore transmission pipeline segments means, for the purposes of §§192.179 and 192.634, where 2 or more miles, in the aggregate, of onshore transmission pipeline have been replaced within any 5 contiguous miles of pipeline within any 24month period.
Exposed underwater pipeline means an underwater pipeline where the top of the pipe protrudes above the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from mean low water.
Gas means natural gas, flammable gas, or gas which is toxic or corrosive.
Gathering line means a pipeline that transports gas from a current production facility to a transmission line or main.
Gulf of Mexico and its inlets means the waters from the mean high water mark of the coast of the Gulf of Mexico and its inlets open to the sea (excluding rivers, tidal marshes, lakes, and canals) seaward to
include the territorial sea and Outer Continental Shelf to a depth of 15 feet (4.6 meters), as measured from the mean low water.
Hazard to navigation means, for the purposes of this part, a pipeline where the top of the pipe is less than 12 inches (305 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from the mean low water.
High-pressure distribution system means a distribution system in which the gas pressure in the main is higher than the pressure provided to the customer.
Line section means a continuous run of transmission line between adjacent compressor stations, between a compressor station and storage facilities, between a compressor station and a block valve, or between adjacent block valves.
Listed specification means a specification listed in section I of appendix B of this part.
Low-pressure distribution system means a distribution system in which the gas pressure in the main is substantially the same as the pressure provided to the customer.
Main means a distribution line that serves as a common source of supply for more than one service line.
Maximum actual operating pressure means the maximum pressure that occurs during normal operations over a period of 1 year.
Maximum allowable operating pressure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this part.
Moderate consequence area means:
(1) An onshore area that is within a potential impact circle, as defined in §192.903, containing either:
(i) Five or more buildings intended for human occupancy; or
(ii) Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, as defined in the Federal Highway Administration's Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1 (see: https://www.fhwa.dot.gov/planning/processes/statewide/ related/highway_functional_classifications/fcauab.pdf), and that does not meet the definition of high consequence area, as defined in §192.903.
(2) The length of the moderate consequence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle containing either 5 or more buildings intended for human occupancy; or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes, to the outermost edge of the last contiguous potential impact circle that contains either 5 or more buildings intended for human occupancy, or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes.
Municipality means a city, county, or any other political subdivision of a State.
Notification of potential rupture means the notification to, or observation by, an operator of indicia identified in §192.635 of a potential unintentional or uncontrolled release of a large volume of gas from a pipeline.
Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters.
Operator means a person who engages in the transportation of gas.
Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof.
Petroleum gas means propane, propylene, butane, (normal butane or isobutanes), and butylene (including isomers), or mixtures composed predominantly of these gases, having a vapor pressure not exceeding 208 psi (1434 kPa) gage at 100 °F (38 °C).
Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders.
Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenance attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies.
Pipeline environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activ
ity, and other known conditions that could affect the probability of active corrosion.
Pipeline facility means new and existing pipelines, rights-of-way, and any equipment, facility, or building used in the transportation of gas or in the treatment of gas during the course of transportation.
Rupture-mitigation valve (RMV) means an automatic shut-off valve (ASV) or a remote-control valve (RCV) that a pipeline operator uses to minimize the volume of gas released from the pipeline and to mitigate the consequences of a rupture.
Service line means a distribution line that transports gas from a common source of supply to an individual customer, to two adjacent or adjoining residential or small commercial customers, or to multiple residential or small commercial customers served through a meter header or manifold. A service line ends at the outlet of the customer meter or at the connection to a customer's piping, whichever is further downstream, or at the connection to customer piping if there is no meter.
Service regulator means the device on a service line that controls the pressure of gas delivered from a higher pressure to the pressure provided to the customer. A service regulator may serve one customer or multiple customers through a meter header or manifold.
SMYS means specified minimum yield strength is:
(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).
State means each of the several States, the District of Columbia, and the Commonwealth of Puerto Rico.
Supervisory Control and Data Acquisition (SCADA) system means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility.
Transmission line means a pipeline, other than a gathering line, that:
(1) Transports gas from a gathering line or storage facility to a distribution center, storage facility, or large volume customer that is not down-stream from a distribution center;
(2) operates at a hoop stress of 20 percent or more of SMYS; or (3) transports gas within a storage field.
Note: A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.
Transportation of gas means the gathering, transmission, or distribution of gas by pipeline or the storage of gas, in or affecting interstate or foreign commerce.
Underground natural gas storage facility (UNGSF) means a gas pipeline facility that stores natural gas underground incidental to the transportation of natural gas, including:
(1) (i) A depleted hydrocarbon reservoir; (ii) An aquifer reservoir; or (iii) A solution-mined salt cavern.
(2) In addition to the reservoir or cavern, a UNGSF includes injection, withdrawal, monitoring, and observation wells; wellbores and downhole components; wellheads and associated wellhead piping; wing-valve assemblies that isolate the wellhead from connected piping beyond the wing-valve assemblies; and any other equipment, facility, right-of-way, or building used in the underground storage of natural gas.
(3) A solution-mined salt cavern reservoir, including associated material and equipment used for injection, withdrawal, monitoring, or observation wells, and wellhead equipment, piping, rights-ofway, property, buildings, compressor units, separators, metering equipment, and regulator equipment.
Weak link means a device or method used when pulling polyethylene pipe, typically through methods such as horizontal directional drilling, to ensure that damage will not occur to the pipeline by exceeding the maximum tensile stresses allowed.
Welder means a person who performs manual or semi-automatic welding.
Welding operator means a person who operates machine or automatic welding equipment.
[Amdt. 192-13, 38 FR 9084, Apr. 10, 1973]
Editorial Note: For Federal Register citations affecting §192.3, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and on GPO Access.
§192.7 Part 192 – Minimum Federal Safety Standards
Advisory Bulletin: Clarification of Terms Relating to Pipeline Operational Status
To: Owners and Operators of Hazardous Liquid, Carbon Dioxide and Gas Pipelines
Subject: Clarification of Terms Relating to Pipeline Operational Status
Advisory: PHMSA regulations do not recognize an "idle" status for a hazardous liquid or gas pipelines. The regulations consider pipelines to be either active and fully subject to all parts of the safety regulations or abandoned. The process and requirements for pipeline abandonment are captured in §§192.727 and 195.402(c)(10) for gas and hazardous liquid pipelines, respectively. Pipelines abandoned after the effective date of the regulations must comply with requirements to purge all combustibles and seal any facilities left in place. The last owner or operator of abandoned offshore facilities and abandoned onshore facilities that cross over, under, or through commercially navigable waterways must file a report with PHMSA. PHMSA regulations define the term "abandoned" to mean permanently removed from service.
§192.5 Class locations
(a) This section classifies pipeline locations for purposes of this part. The following criteria apply to classifications under this section. 192.5(a)
(1) A "class location unit" is an onshore area that extends 220 yards (200 meters) on either side of the centerline of any continuous 1mile (1.6 kilometers) length of pipeline. 192.5(a)(1)
(2) Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy. 192.5(a)(2)
(b) Except as provided in paragraph (c) of this section, pipeline locations are classified as follows: 192.5(b)
(1) A Class 1 location is: 192.5(b)(1)
(i) An offshore area; or192.5(b)(1)(i)
(ii) Any class location unit that has 10 or fewer buildings intended for human occupancy.192.5(b)(1)(ii)
(2) A Class 2 location is any class location unit that has more than 10 but fewer than 46 buildings intended for human occupancy. 192.5(b)(2)
(3) A Class 3 location is: 192.5(b)(3)
(i) Any class location unit that has 46 or more buildings intended for human occupancy; or192.5(b)(3)(i)
(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.)192.5(b)(3)(ii)
(4) A Class 4 location is any class location unit where buildings with four or more stories above ground are prevalent. 192.5(b)(4)
(c) The length of Class locations 2, 3, and 4 may be adjusted as follows: 192.5(c)
(1) A Class 4 location ends 220 yards (200 meters) from the nearest building with four or more stories above ground. 192.5(c)(1)
(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. 192.5(c)(2)
(d) An operator must have records that document the current class location of each gas transmission pipeline segment and that demonstrate how the operator determined each current class location in accordance with this section. 192.5(d)
[Amdt. 192-78, 61 FR 28783, June 6, 1996; 61 FR 35139, July 5, 1996, as amended by Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. No. 192-125, 84 FR 52243, Oct. 1, 2019; Amdt. No. 192-127, 85 FR 40134, July 6, 2020]
§192.7 What documents are incorporated by reference partly or wholly in this part?
(a) Certain material is incorporated by reference into this part with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. The materials listed in this section have the full force of law. All approved material is available for inspection at Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590, 202-3664046 https://www.phmsa.dot.gov/pipeline/regs, and is available from the sources listed in the remaining paragraphs of this section. It is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, email fedreg.legal@nara.gov or go to www.archives.gov/federal-register/cfr/ibr-locations.html. 192.7(a)
(b) American Petroleum Institute (API), 200 Massachusetts Ave. NW, Suite 1100, Washington, DC 20001, and phone: 202-682-8000, website: https://www.api.org/. 192.7(b)
(1) API Recommended Practice 5L1, "Recommended Practice for Railroad Transportation of Line Pipe," 7th edition, September 2009, (API RP 5L1), IBR approved for §192.65(a). 192.7(b)(1)
(2) API Recommended Practice 5LT, "Recommended Practice for Truck Transportation of Line Pipe," First edition, March 2012, (API RP 5LT), IBR approved for §192.65(c). 192.7(b)(2)
(3) API Recommended Practice 5LW, "Recommended Practice for Transportation of Line Pipe on Barges and Marine Vessels," 3rd edition, September 2009, (API RP 5LW), IBR approved for §192.65(b). 192.7(b)(3)
(4) API Recommended Practice 80, "Guidelines for the Definition of Onshore Gas Gathering Lines," 1st edition, April 2000, (API RP 80), IBR approved for §192.8(a). 192.7(b)(4)
(5) API Recommended Practice 1162, "Public Awareness Programs for Pipeline Operators," 1st edition, December 2003, (API RP 1162), IBR approved for §192.616(a), (b), and (c). 192.7(b)(5)
(6) API Recommended Practice 1165, "Recommended Practice for Pipeline SCADA Displays," First edition, January 2007, (API RP 1165), IBR approved for §192.631(c). 192.7(b)(6)
(7) API Specification 5L, "Specification for Line Pipe," 45th edition, effective July 1, 2013, (API Spec 5L), IBR approved for §§192.55(e); 192.112(a), (b), (d), (e); 192.113; and Item I, Appendix B to Part 192. 192.7(b)(7)
(9) API Standard 1104, “Welding of Pipelines and Related Facilities,” 20th edition, October 2005, including errata/addendum (July 2007) and errata 2 (2008), (API Std 1104), IBR approved for §§192.225(a); 192.227(a); 192.229(b) and (c); 192.241(c); and Item II, Appendix B. 192.7(b)(9)
(10) API Recommended Practice 1170, "Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage," First edition, July 2015 (API RP 1170), IBR approved for §192.12. 192.7(b)(10)
(11) API Recommended Practice 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs," First edition, September 2015, (API RP 1171), IBR approved for §192.12. 192.7(b)(11)
(12) API STANDARD 1163, “In-Line Inspection Systems Qualification,” Second edition, April 2013, Reaffirmed August 2018, (API STD 1163), IBR approved for §192.493. 192.7(b)(12)
(c) ASME International (ASME), Three Park Avenue, New York, NY 10016, 800-843-2763 (U.S./Canada), http://www.asme.org/. 192.7(c)
(1) ASME/ANSI B16.1-2005, "Gray Iron Pipe Flanges and Flanged Fittings: (Classes 25, 125, and 250)," August 31, 2006, (ASME/ANSI B16.1), IBR approved for §192.147(c). 192.7(c)(1)
(2) ASME/ANSI B16.5-2003, “Pipe Flanges and Flanged Fittings,” October 2004, (ASME/ANSI B16.5), IBR approved for §§192.147(a), 192.279, and 192.607(f). 192.7(c)(2)
(3) ASME B16.40-2008, "Manually Operated Thermoplastic Gas Shutoffs and Valves in Gas Distribution Systems," March 18, 2008, approved by ANSI, (ASME B16.40-2008), IBR approved for Item I, Appendix B to Part 192. 192.7(c)(3)
(4) ASME/ANSI B31G-1991 (Reaffirmed 2004), “Manual for Determining the Remaining Strength of Corroded Pipelines,” 2004, (ASME/ ANSI B31G), IBR approved for §§192.485(c), 192.632(a), 192.712(b), and 192.933(a). 192.7(c)(4)
(5) ASME/ANSI B31.8-2007, "Gas Transmission and Distribution Piping Systems," November 30, 2007, (ASME/ANSI B31.8), IBR approved for §§192.112(b) and 192.619(a). 192.7(c)(5)
(6) ASME/ANSI B31.8S-2004, "Supplement to B31.8 on Managing System Integrity of Gas Pipelines," 2004, (ASME/ANSI B31.8S2004), IBR approved for §§192.903 note to Potential impact radius; 192.907 introductory text, (b); 192.911 introductory text, (i), (k), (l), (m); 192.913(a), (b), (c); 192.917 (a), (b), (c), (d), (e); 192.921(a); 192.923(b); 192.925(b); 192.927(b), (c); 192.929(b); 192.933(c), (d); 192.935 (a), (b); 192.937(c); 192.939(a); and 192.945(a). 192.7(c)(6)
(7) ASME Boiler & Pressure Vessel Code, Section I, "Rules for Construction of Power Boilers 2007," 2007 edition, July 1, 2007, (ASME BPVC, Section I), IBR approved for §192.153(b). 192.7(c)(7)
(8) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1 "Rules for Construction of Pressure Vessels," 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 1), IBR approved for §§192.153(a), (b), (d); and 192.165(b). 192.7(c)(8)
(9) ASME Boiler & Pressure Vessel Code, Section VIII, Division 2 "Alternate Rules, Rules for Construction of Pressure Vessels," 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 2), IBR approved for §§192.153(b), (d); and 192.165(b). 192.7(c)(9)
(10) ASME Boiler & Pressure Vessel Code, Section IX: "Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators," 2007 edition, July 1, 2007, ASME BPVC, Section IX, IBR approved for §§192.225(a); 192.227(a); and Item II, Appendix B to Part 192. 192.7(c)(10)
(d) American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228, phone: 800-2222768, website: https://www.asnt.org/. 192.7(d)
(1) ANSI/ASNT ILI-PQ-2005(2010), “In-line Inspection Personnel Qualification and Certification,” Reapproved October 11, 2010, (ANSI/ASNT ILI-PQ), IBR approved for §192.493. 192.7(d)(1)
(2) [Reserved] 192.7(d)(2)
(e) ASTM International (formerly American Society for Testing and Materials), 100 Barr Harbor Drive, PO Box C700, West Conshohocken, PA 19428, phone: (610) 832-9585, website: http://astm.org. 192.7(e)
(1) ASTM A53/A53M-10, "Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless," approved October 1, 2010, (ASTM A53/A53M), IBR approved for §192.113; and Item II, Appendix B to Part 192. 192.7(e)(1)
(2) ASTM A106/A106M-10, "Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service," approved October 1, 2010, (ASTM A106/A106M), IBR approved for §192.113; and Item I, Appendix B to Part 192. 192.7(e)(2)
(3) ASTM A333/A333M-11, "Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service," approved April 1, 2011, (ASTM A333/A333M), IBR approved for §192.113; and Item I, Appendix B to Part 192. 192.7(e)(3)
(4) ASTM A372/A372M-10, "Standard Specification for Carbon and Alloy Steel Forgings for Thin-Walled Pressure Vessels," approved October 1, 2010, (ASTM A372/A372M), IBR approved for §192.177(b). 192.7(e)(4)
(5) ASTM A381-96 (reapproved 2005), "Standard Specification for Metal-Arc Welded Steel Pipe for Use with High-Pressure Transmission Systems," approved October 1, 2005, (ASTM A381), IBR approved for §192.113; and Item I, Appendix B to Part 192. 192.7(e)(5)
(6) ASTM A578/A578M-96 (reapproved 2001), "Standard Specification for Straight-Beam Ultrasonic Examination of Plain and Clad Steel Plates for Special Applications," (ASTM A578/A578M), IBR approved for §192.112(c). 192.7(e)(6)
(7) ASTM A671/A671M-10, "Standard Specification for Electric-FusionWelded Steel Pipe for Atmospheric and Lower Temperatures," approved April 1, 2010, (ASTM A671/A671M), IBR approved for §192.113; and Item I, Appendix B to Part 192. 192.7(e)(7)
(8) ASTM A672/A672M-09, "Standard Specification for Electric-FusionWelded Steel Pipe for High-Pressure Service at Moderate Temperatures," approved October 1, 2009, (ASTM A672/672M), IBR approved for §192.113 and Item I, Appendix B to Part 192. 192.7(e)(8)
(9) ASTM A691/A691M-09, "Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures," approved October 1, 2009, (ASTM A691/ A691M), IBR approved for §192.113 and Item I, Appendix B to Part 192. 192.7(e)(9)
(10) ASTM D638-03, "Standard Test Method for Tensile Properties of Plastics," 2003, (ASTM D638), IBR approved for §192.283(a) and (b). 192.7(e)(10)
(11) ASTM D2513-18a, “Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings,” approved August 1, 2018, (ASTM D2513), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(11)
(12) ASTM D2517-00, “Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings,” (ASTM D 2517), IBR approved for §§192.191(a); 192.281(d); 192.283(a); and Item I, Appendix B to Part 192. 192.7(e)(12)
(13) ASTM D2564-12, “Standard Specification for Solvent Cements for Poly (Vinyl Chloride) (PVC) Plastic Piping Systems,” Aug. 1, 2012, (ASTM D2564-12), IBR approved for §192.281(b)(2). 192.7(e)(13)
(14) ASTM F1055-98 (Reapproved 2006), "Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing," March 1, 2006, (ASTM F1055-98 (2006)), IBR approved for §192.283(a), Item I, Appendix B to Part 192. 192.7(e)(14)
(15) ASTM F1924-12, “Standard Specification for Plastic Mechanical Fittings for Use on Outside Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing,” April 1, 2012, (ASTM F1924-12), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(15)
(16) ASTM F1948-12, “Standard Specification for Metallic Mechanical Fittings for Use on Outside Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing,” April 1, 2012, (ASTM F1948-12), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(16)
(17) ASTM F1973-13, “Standard Specification for Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene (PE) and Polyamide 11 (PA11) and Polyamide 12 (PA12) Fuel Gas Distribution Systems,” May 1, 2013, (ASTM F1973-13), IBR approved for §192.204(b); and Item I, Appendix B to Part 192. 192.7(e)(17)
(18) ASTM F2145-13, “Standard Specification for Polyamide 11 (PA 11) and Polyamide 12 (PA12) Mechanical Fittings for Use on Outside Diameter Controlled Polyamide 11 and Polyamide 12 Pipe and Tubing,” May 1, 2013, (ASTM F2145-13), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(18)
(19) ASTM F 2600-09, “Standard Specification for Electrofusion Type Polyamide-11 Fittings for Outside Diameter Controlled Polyamide11 Pipe and Tubing,” April 1, 2009, (ASTM F 2600-09), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(19) (20) ASTM F2620-19, “Standard Practice for Heat Fusion Joining of Polyethylene Pipe and Fittings,” approved February 1, 2019, (ASTM F2620), IBR approved for §§192.281(c) and 192.285(b). 192.7(e)(20) (21) ASTM F2767-12, “Specification for Electrofusion Type Polyamide12 Fittings for Outside Diameter Controlled Polyamide-12 Pipe and Tubing for Gas Distribution,” Oct. 15, 2012, (ASTM F2767-12), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(21) (22) ASTM F2785-12, “Standard Specification for Polyamide 12 Gas Pressure Pipe, Tubing, and Fittings,” Aug. 1, 2012, (ASTM F278512), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(22) (23) ASTM F2817-10, “Standard Specification for Poly (Vinyl Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or Repair,” Feb. 1, 2010, (ASTM F2817-10), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(23) (24) ASTM F2945-12a “Standard Specification for Polyamide 11 Gas Pressure Pipe, Tubing, and Fittings,” Nov. 27, 2012, (ASTM F294512a), IBR approved for Item I, Appendix B to Part 192. 192.7(e)(24) (f) Gas Technology Institute (GTI), formerly the Gas Research Institute (GRI)), 1700 S. Mount Prospect Road, Des Plaines, IL 60018, phone: 847-768-0500, Web site: www.gastechnology.org. 192.7(f) (1) GRI 02/0057 (2002) "Internal Corrosion Direct Assessment of Gas Transmission Pipelines Methodology," (GRI 02/0057), IBR approved for §192.927(c). 192.7(f)(1) (2) [Reserved] 192.7(f)(2)
(g) Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park St. NE., Vienna, VA 22180, phone: 703-281-6613, Web site: http://www.mss-hq.org/. 192.7(g) (1) MSS SP-44-2010, Standard Practice, "Steel Pipeline Flanges," 2010 edition, (including Errata (May 20, 2011)), (MSS SP-44), IBR approved for §192.147(a). 192.7(g)(1) (2) [Reserved] 192.7(g)(2)
(h) NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084: phone: 281-228-6223 or 800-797-6223, Web site: http:// www.nace.org/Publications/. 192.7(h)
(1) ANSI/NACE SP0502-2010, Standard Practice, "Pipeline External Corrosion Direct Assessment Methodology," revised June 24, 2010, (NACE SP0502), IBR approved for §§192.923(b); 192.925(b); 192.931(d); 192.935(b) and 192.939(a). 192.7(h)(1)
(2) NACE Standard Practice 0102-2010, “In-Line Inspection of Pipelines,” Revised 2010-03-13, (NACE SP0102), IBR approved for §§192.150(a) and 192.493. 192.7(h)(2)
(i) National Fire Protection Association (NFPA), 1 Batterymarch Park, Quincy, Massachusetts 02169, phone: 1 617 984-7275, Web site: http://www.nfpa.org/. 192.7(i)
(1) NFPA-30 (2012), "Flammable and Combustible Liquids Code," 2012 edition, June 20, 2011, including Errata 30-12-1 (September 27, 2011) and Errata 30-12-2 (November 14, 2011), (NFPA-30), IBR approved for §192.735(b). 192.7(i)(1)
(2) NFPA-58 (2004), "Liquefied Petroleum Gas Code (LP-Gas Code)," (NFPA-58), IBR approved for §192.11(a), (b), and (c). 192.7(i)(2) (3) NFPA-59 (2004), "Utility LP-Gas Plant Code," (NFPA-59), IBR approved for §192.11(a), (b); and (c). 192.7(i)(3)
(4) NFPA-70 (2011), "National Electrical Code," 2011 edition, issued August 5, 2010, (NFPA-70), IBR approved for §§192.163(e); and 192.189(c). 192.7(i)(4)
(j) Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, P.O. Box 980550, Houston, TX 77098, phone: 713-630-0505, toll free: 866-866-6766, Web site: http://www.ttoolboxes.com/. (Contract number PR-3-805.) 192.7(j)
(1) AGA, Pipeline Research Committee Project, PR-3-805, “A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,” (December 22, 1989), (PRCI PR-3-805 (R-STRENG)), IBR approved for §§192.485(c); 192.632(a); 192.712(b); 192.933(a) and (d). 192.7(j)(1)
§192.8
(2) [Reserved] 192.7(j)(2)
Part 192 – Minimum Federal Safety Standards
(k) Plastics Pipe Institute, Inc. (PPI), 105 Decker Court, Suite 825 Irving TX 75062, phone: 469-499-1044, http://www.plasticpipe.org/. 192.7(k)
(1) PPI TR-3/2012, HDB/HDS/PDB/SDB/MRS/CRS, Policies, “Policies and Procedures for Developing Hydrostatic Design Basis (HDB), Hydrostatic Design Stresses (HDS), Pressure Design Basis (PDB), Strength Design Basis (SDB), Minimum Required Strength (MRS) Ratings, and Categorized Required Strength (CRS) for Thermoplastic Piping Materials or Pipe,” updated November 2012, (PPI TR-3/2012), IBR approved for §192.121. 192.7(k)(1)
(2) PPI TR-4, HDB/HDS/SDB/MRS, Listed Materials, “PPI Listing of Hydrostatic Design Basis (HDB), Hydrostatic Design Stress (HDS), Strength Design Basis (SDB), Pressure Design Basis (PDB) and Minimum Required Strength (MRS) Rating For Thermoplastic Piping Materials or Pipe,” updated March, 2011, (PPI TR-4/2012), IBR approved for §192.121. 192.7(k)(2)
[35 FR 13257, Aug. 19, 1970]
Editorial Note: For Federal Register citations affecting §192.7, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and on GPO Access.
§192.8 How are onshore gathering pipelines and regulated onshore gathering pipelines determined?
(a)An operator must use API RP 80 (incorporated by reference, see §192.7), to determine if an onshore pipeline (or part of a connected series of pipelines) is an onshore gathering line. The determination is subject to the limitations listed below. After making this determination, an operator must determine if the onshore gathering line is a regulated onshore gathering line under paragraph (b) of this section. 192.8(a)
(1) The beginning of gathering, under section 2.2(a)(1) of API RP 80, may not extend beyond the furthermost downstream point in a production operation as defined in section 2.3 of API RP 80. This furthermost downstream point does not include equipment that can be used in either production or transportation, such as separators or dehydrators, unless that equipment is involved in the processes of "production and preparation for transportation or delivery of hydrocarbon gas" within the meaning of "production operation." 192.8(a)(1)
(2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 80, may not extend beyond the first downstream natural gas processing plant, unless the operator can demonstrate, using sound engineering principles, that gathering extends to a further downstream plant. 192.8(a)(2)
(3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API RP 80, is determined by the commingling of gas from separate production fields, the fields may not be more than 50 miles from each other, unless the Administrator finds a longer separation distance is justified in a particular case (see 49 CFR §190.9). 192.8(a)(3)
Table 1 to Paragraph (c)(2)
A
—Metallic and the MAOP produces a hoop stress of 20 percent or more of SMYS —If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part —Non-metallic and the MAOP is more than 125 psig (862 kPa)
B
—Metallic and the MAOP produces a hoop stress of less than 20 percent of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in subpart C of this part —Non-metallic and the MAOP is 125 psig (862 kPa) or less
Outside diameter greater than or equal to 8.625 inches and any of the following:
—Metallic and the MAOP produces a hoop stress of 20 percent or more of SMYS;
—If the stress level is unknown, segment is metallic and the MAOP is more than 125 psig (862 kPa); or
—Non-metallic and the MAOP is more than 125 psig (862 kPa)
R —All other onshore gathering lines
(4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 80, may not extend beyond the furthermost downstream compressor used to increase gathering line pressure for delivery to another pipeline. 192.8(a)(4)
(5) For new, replaced, relocated, or otherwise changed gas gathering pipelines installed after May 16, 2022, the endpoint of gathering under sections 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 (incorporated by reference, see §192.7)—also known as "incidental gathering"—may not be used if the pipeline terminates 10 or more miles downstream from the furthermost downstream endpoint as defined in paragraphs 2.2(a)(1)(A) through (a)(1)(D) of API RP 80 (incorporated by reference, see §192.7) and this section. If an "incidental gathering" pipeline is 10 miles or more in length, the entire portion of the pipeline that is designated as an incidental gathering line under 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 shall be classified as a transmission pipeline subject to all applicable regulations in this chapter for transmission pipelines.192.8(a)(5)
(b)Each operator must determine and maintain for the life of the pipeline records documenting the methodology by which it calculated the beginning and end points of each onshore gathering pipeline it operates, as described in the second column of table 1 to paragraph (c)(2) of this section, by:192.8(b)
(1) November 16, 2022, or before the pipeline is placed into operation, whichever is later; or192.8(b)(1)
(2) An alternative deadline approved by the Pipeline and Hazardous Materials Safety Administration (PHMSA). The operator must notify PHMSA and State or local pipeline safety authorities, as applicable, no later than 90 days in advance of the deadline in paragraph (b)(1) of this section. The notification must be made in accordance with §192.18 and must include the following information:192.8(b)(2)
(i) Description of the affected facilities and operating environment; 192.8(b)(2)(i)
(ii) Justification for an alternative compliance deadline; and 192.8(b)(2)(ii)
(iii) Proposed alternative deadline.192.8(b)(2)(iii)
(c) For purposes of part 191 of this chapter and §192.9, the term "regulated onshore gathering pipeline" means: 192.8(c)
(1) Each Type A, Type B, or Type C onshore gathering pipeline (or segment of onshore gathering pipeline) with a feature described in the second column of table 1 to paragraph (c)(2) of this section that lies in an area described in the third column; and 192.8(c)(1)
(2) As applicable, additional lengths of pipeline described in the fourth column to provide a safety buffer: 192.8(c)(2)
1. Class 3, or 4 location Area 2. An area within a Class 2 location the operator determines by using any of the following three methods:
(a) A Class 2 location;
(b) An area extending 150 feet (45.7 m) on each side of the centerline of any continuous 1 mile (1.6 km) of pipeline and including more than 10 but fewer than 46 dwellings; or
(c) An area extending 150 feet (45.7 m) on each side of the centerline of any continuous 1000 feet (305 m) of pipeline and including 5 or more dwellings
If the gathering pipeline is in Area 2(b) or 2(c), the additional lengths of line extend upstream and downstream from the area to a point where the line is at least 150 feet (45.7 m) from the nearest dwelling in the area.
However, if a cluster of dwellings in Area 2(b) or 2(c) qualifies a pipeline as Type B, the Type B classification ends 150 feet (45.7 m) from the nearest dwelling in the cluster.
Class 1 location
Class 1 and Class 2 locations
None.
(3) A Type R gathering line is subject to reporting requirements under part 191 of this chapter but is not a regulated onshore gathering line under this part. 192.8(c)(3)
(4) For the purpose of identifying Type C lines in table 1 to paragraph (c)(2) of this section, if an operator has not calculated MAOP consistent with the methods at §192.619(a) or (c)(1), the operator must either: 192.8(c)(4)
(i) Calculate MAOP consistent with the methods at §192.619(a) or (c)(1); or192.8(c)(4)(i)
(ii) Use as a substitute for MAOP the highest operating pressure to which the segment was subjected during the preceding 5 operating years.192.8(c)(4)(ii)
[Amdt. 192-102, 71 FR 13302, Mar. 15, 2006]
§192.9 What requirements apply to gathering pipelines?
(a) Requirements. An operator of a gathering line must follow the safety requirements of this part as prescribed by this section. 192.9(a)
(b) Offshore lines. An operator of an offshore gathering line must comply with requirements of this part applicable to transmission lines, except the requirements in §§192.150, 192.285(e), 192.493, 192.506, 192.607, 192.619(e), 192.624, 192.710, 192.712, and in subpart O of this part. 192.9(b)
(c) Type A lines. An operator of a Type A regulated onshore gathering line must comply with the requirements of this part applicable to transmission lines, except the requirements in §§192.150, 192.285(e), 192.493, 192.506, 192.607, 192.619(e), 192.624, 192.710, 192.712, and in subpart O of this part. However, operators of Type A regulated onshore gathering lines in a Class 2 location may demonstrate compliance with subpart N by describing the processes it uses to determine the qualification of persons performing operations and maintenance tasks. 192.9(c)
(d) Type B lines. An operator of a Type B regulated onshore gathering line must comply with the following requirements: 192.9(d)
(1) If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspection, and initial testing must be in accordance with requirements of this part applicable to transmission lines. Compliance with §§192.67, 192.127, 192.179(e), 192.179(f), 192.205, 192.227(c), 192.285(e), 192.506, 192.634, and 192.636 is not required. 192.9(d)(1)
(2) If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines except the requirements in §192.493; 192.9(d)(2)
(3) If the pipeline contains plastic pipe or components, the operator must comply with all applicable requirements of this part for plastic pipe components; 192.9(d)(3)
(4) Carry out a damage prevention program under §192.614; 192.9(d)(4)
(5) Establish a public education program under §192.616; 192.9(d)(5)
(6) Establish the MAOP of the line under §192.619(a), (b), and (c); 192.9(d)(6)
(7) Install and maintain line markers according to the requirements for transmission lines in §192.707; and 192.9(d)(7)
(8) Conduct leakage surveys in accordance with the requirements for transmission lines in §192.706, using leak-detection equipment, and promptly repair hazardous leaks in accordance with §192.703(c). 192.9(d)(8)
(e)Type C lines. The requirements for Type C gathering lines are as follows.192.9(e)
(1) An operator of a Type C onshore gathering line with an outside diameter greater than or equal to 8.625 inches must comply with the following requirements:192.9(e)(1)
(i) Except as provided in paragraph (h) of this section for pipe and components made with composite materials, the design, installation, construction, initial inspection, and initial testing of a new, replaced, relocated, or otherwise changed Type C gathering line, must be done in accordance with the requirements in subparts B though G and J of this part applicable to transmission lines. Compliance with §§192.67, 192.127, 192.205, 192.227(c), 192.285(e), and 192.506 is not required;192.9(e)(1)(i)
(ii) If the pipeline is metallic, control corrosion according to requirements of subpart I of this part applicable to transmission lines except for §192.493;192.9(e)(1)(ii)
(iii) Carry out a damage prevention program under §192.614; 192.9(e)(1)(iii)
(iv) Develop and implement procedures for emergency plans in accordance with §192.615;192.9(e)(1)(iv)
(v) Develop and implement a written public awareness program in accordance with §192.616;192.9(e)(1)(v)
(vi) Install and maintain line markers according to the requirements for transmission lines in §192.707; and192.9(e)(1)(vi)
(vii)Conduct leakage surveys in accordance with the requirements for transmission lines in §192.706 using leak-detection equipment, and promptly repair hazardous leaks in accordance with §192.703(c).192.9(e)(1)(vii)
(2) An operator of a Type C onshore gathering line with an outside diameter greater than 12.75 inches must comply with the requirements in paragraph (e)(1) of this section and the following:192.9(e)(2)
(i) If the pipeline contains plastic pipe, the operator must comply with all applicable requirements of this part for plastic pipe or components. This does not include pipe and components made of composite materials that incorporate plastic in the design; and192.9(e)(2)(i)
(ii) Establish the MAOP of the pipeline under §192.619(a) or (c) and maintain records used to establish the MAOP for the life of the pipeline.192.9(e)(2)(ii)
(f)Exceptions.192.9(f)
(1) Compliance with paragraphs (e)(1)(ii), (v), (vi), and (vii) and (e)(2)(i) and (ii) of this section is not required for pipeline segments that are 16 inches or less in outside diameter if one of the following criteria are met:192.9(f)(1)
(i) Method 1. The segment is not located within a potential impact circle containing a building intended for human occupancy or other impacted site. The potential impact circle must be calculated as specified in §192.903, except that a factor of 0.73 must be used instead of 0.69. The MAOP used in this calculation must be determined and documented in accordance with paragraph (e)(2)(ii) of this section.192.9(f)(1)(i)
(ii) Method 2. The segment is not located within a class location unit (seeSec. 192.5) containing a building intended for human occupancy or other impacted site.192.9(f)(1)(ii)
(2) Paragraph (e)(1)(i) of this section is not applicable to pipeline segments 40 feet or shorter in length that are replaced, relocated, or changed on a pipeline existing on or before May 16, 2022.192.9(f)(2)
(3) For purposes of this section, the term "building intended for human occupancy or other impacted site" means any of the following: 192.9(f)(3)
(i) Any building that may be occupied by humans, including homes, office buildings factories, outside recreation areas, plant facilities, etc.;192.9(f)(3)(i)
(ii) 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); or192.9(f)(3)(ii)
(iii) Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with 4 or more lanes.192.9(f)(3)(iii) (g)Compliance deadlines. An operator of a regulated onshore gathering line must comply with the following deadlines, as applicable.192.9(g)
(1) An operator of a new, replaced, relocated, or otherwise changed line must be in compliance with the applicable requirements of this section by the date the line goes into service, unless an exception in §192.13 applies.192.9(g)(1)
(i) Except as provided in paragraph (h) of this section for pipe and components made with composite materials, the design, installation, construction, initial inspection, and initial testing of a new, replaced, relocated, or otherwise changed Type C gathering line, must be done in accordance with the requirements in subparts B though G and J of this part applicable to transmission lines. Compliance with §§192.67, 192.127, 192.179(e), 192.179(f), 192.205, 192.227(c), 192.285(e), 192.506, 192.634, and 192.636 is not required;192.9(g)(1)(i)
(2) If a Type A or Type B regulated onshore gathering pipeline existing on April 14, 2006, was not previously subject to this part, an operator has until the date stated in the second column to comply with the applicable requirement for the pipeline listed in the first column, unless the Administrator finds a later deadline is justified in a particular case:192.9(g)(2)
Requirement
Compliance deadline
(i) Control corrosion according to requirements for transmission lines in subpart I of this part April 15, 2009.
(ii) Carry out a damage prevention program under §192.614 October 15, 2007.
(iii) Establish MAOP under §192.619 October 15, 2007.
(iv) Install and maintain line markers under §192.707 April 15, 2008.
Requirement
(continued)
Compliance deadline
(v) Establish a public education program under §192.616 April 15, 2008.
(vi) Other provisions of this part as required by paragraph (c) of this section for Type A lines April 15, 2009.
(3) If, after April 14, 2006, a change in class location or increase in dwelling density causes an onshore gathering pipeline to become a Type A or Type B regulated onshore gathering line, the operator has 1 year for Type B lines and 2 years for Type A lines after the pipeline becomes a regulated onshore gathering pipeline to comply with this section. 192.9(g)(3)
(4) If a Type C gathering pipeline existing on or before May 16, 2022, was not previously subject to this part, an operator must comply with the applicable requirements of this section, except for paragraph (h) of this section, on or before: 192.9(g)(4)
(i) May 16, 2023; or 192.9(g)(4)(i)
(ii) An alternative deadline approved by PHMSA. The operator must notify PHMSA and State or local pipeline safety authorities, as applicable, no later than 90 days in advance of the deadline in paragraph (b)(1) of this section. The notification must be made in accordance with §192.18 and must include a description of the affected facilities and operating environment, the proposed alternative deadline for each affected requirement, the justification for each alternative compliance deadline, and actions the operator will take to ensure the safety of affected facilities. 192.9(g)(4)(ii)
(5) If, after May 16, 2022, a change in class location, an increase in dwelling density, or an increase in MAOP causes a pipeline to become a Type C gathering pipeline, or causes a Type C gathering pipeline to become subject to additional Type C requirements (seeparagraph (f) of this section), the operator has 1 year after the pipeline becomes subject to the additional requirements to comply with this section. 192.9(g)(5)
(h) Composite materials. Pipe and components made with composite materials not otherwise authorized for use under this part may be used on Type C gathering pipelines if the following requirements are met: 192.9(h)
(1) Steel and plastic pipe and components must meet the installation, construction, initial inspection, and initial testing requirements in subparts B through G and J of this part applicable to transmission lines. 192.9(h)(1)
(2) Operators must notify PHMSA in accordance with §192.18 at least 90 days prior to installing new or replacement pipe or components made of composite materials otherwise not authorized for use under this part in a Type C gathering pipeline. The notifications required by this section must include a detailed description of the pipeline facilities in which pipe or components made of composite materials would be used, including: 192.9(h)(2)
(i) The beginning and end points (stationing by footage and mileage with latitude and longitude coordinates) of the pipeline segment containing composite pipeline material and the counties and States in which it is located; 192.9(h)(2)(i)
(ii) A general description of the right-of-way including high consequence areas, as defined in §192.905; 192.9(h)(2)(ii)
(iii) Relevant pipeline design and construction information including the year of installation, the specific composite material, diameter, wall thickness, and any manufacturing and construction specifications for the pipeline; 192.9(h)(2)(iii)
(iv) Relevant operating information, including MAOP, leak and failure history, and the most recent pressure test (identification of the actual pipe tested, minimum and maximum test pressure, duration of test, any leaks and any test logs and charts) or assessment results; 192.9(h)(2)(iv)
(v) An explanation of the circumstances that the operator believes make the use of composite pipeline material appropriate and how the design, construction, operations, and maintenance will mitigate safety and environmental risks; 192.9(h)(2)(v)
(vi) An explanation of procedures and tests that will be conducted periodically over the life of the composite pipeline material to document that its strength is being maintained; 192.9(h)(2)(vi)
(vii) Operations and maintenance procedures that will be applied to the alternative materials. These include procedures that will be used to evaluate and remediate anomalies and how the operator will determine safe operating pressures for composite pipe when defects are found; 192.9(h)(2)(vii)
(viii) An explanation of how the use of composite pipeline material would be in the public interest; and 192.9(h)(2)(viii)
(ix) A certification signed by a vice president (or equivalent or higher officer) of the operator's company that operation of the applicant's pipeline using composite pipeline material would be consistent with pipeline safety. 192.9(h)(2)(ix)
(3) Repairs or replacements using materials authorized under this part do not require notification under this section. 192.9(h)(3)
[Amdt. 192-102, 71 FR 13301, Mar. 15, 2006, as amended by Amdt. 192-120, 80 FR 12777, Mar. 11, 2015; Amdt. 192124, 83 FR 58716, Nov. 20, 2018]
§192.10 Outer continental shelf pipelines
Operators of transportation pipelines on the Outer Continental Shelf (as defined in the Outer Continental Shelf Lands Act; 43 U.S.C. 1331) must identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 1998 to identify the transfer points. If it is not practicable to durably mark a transfer point and the transfer point is located above water, the operator must depict the transfer point on a schematic located near the transfer point. If a transfer point is located subsea, then the operator must identify the transfer point on a schematic which must be maintained at the nearest upstream facility and provided to PHMSA upon request. For those cases in which adjoining operators have not agreed on a transfer point by September 15, 1998 the Regional Director and the MMS Regional Supervisor will make a joint determination of the transfer point.
[Amdt. 192-81, 62 FR 61695, Nov. 19, 1997, as amended at 70 FR 11139, Mar. 8, 2005]
§192.11
Petroleum gas systems
(a) Each plant that supplies petroleum gas by pipeline to a natural gas distribution system must meet the requirements of this part and NFPA 58 and NFPA 59 (incorporated by reference, see §192.7). 192.11(a)
(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. 192.11(b)
(c) In the event of a conflict between this part and NFPA 58 and NFPA 59 (incorporated by reference, see §192.7), NFPA 58 and NFPA 59 prevail. 192.11(c)
[Amdt. 192-78, 61 FR 28783, June 6, 1996, as amended by Amdt. 192-119, 80 FR 180, Jan. 5, 2015; 80 FR 46847, Aug. 6, 2015]
§192.12
Underground natural gas storage facilities
Underground natural gas storage facilities (UNGSFs), as defined in §192.3, are not subject to any requirements of this part aside from this section.
(a) Salt cavern UNGSFs. 192.12(a)
(1) Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed after March 13, 2020, must meet all the provisions of API RP 1170 (incorporated by reference, see §192.7), the provisions of section 8 of API RP 1171 (incorporated by reference, see §192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraphs (c) and (d) of this section prior to commencing operations. 192.12(a)(1)
(2) Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed between July 18, 2017, and March 13, 2020, must meet all the provisions of API RP 1170 (incorporated by reference, see §192.7) and paragraph (c) of this section prior to commencing operations, and must meet all the provisions of section 8 of API RP 1171 (incorporated by reference, see §192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraph (d) of this section, by March 13, 2021. 192.12(a)(2)
(3) Each UNGSF that uses a solution-mined salt cavern for natural gas storage and was constructed on or before July 18, 2017, must meet the provisions of API RP 1170 (incorporated by reference, see §192.7), sections 9, 10, and 11, and paragraph (c) of this section, by January 18, 2018, and must meet all provisions of section 8 of API RP 1171 (incorporated by reference, see §192.7) that are applicable to the physical characteristics and operations of a solution-mined salt cavern UNGSF, and paragraph (d) of this section, by March 13, 2021. 192.12(a)(3)
(b) Depleted hydrocarbon and aquifer reservoir UNGSFs. 192.12(b)
(1) Each UNGSF that uses a depleted hydrocarbon reservoir or an aquifer reservoir for natural gas storage and was constructed after July 18, 2017, must meet all provisions of API RP 1171 (incorporated by reference, see §192.7), and paragraphs (c) and (d) of this section, prior to commencing operations. 192.12(b)(1)
(2) Each UNGSF that uses a depleted hydrocarbon reservoir or an aquifer reservoir for natural gas storage and was constructed on or before July 18, 2017, must meet the provisions of API RP 1171 (incorporated by reference, see §192.7), sections 8, 9, 10, and 11,
and paragraph (c) of this section, by January 18, 2018, and must meet all provisions of paragraph (d) of this section by March 13, 2021. 192.12(b)(2)
(c) Procedural manuals. Each operator of a UNGSF must prepare and follow for each facility one or more manuals of written procedures for conducting operations, maintenance, and emergency preparedness and response activities under paragraphs (a) and (b) of this section. Each operator must keep records necessary to administer such procedures and review and update these manuals at intervals not exceeding 15 months, but at least once each calendar year. Each operator must keep the appropriate parts of these manuals accessible at locations where UNGSF work is being performed. Each operator must have written procedures in place before commencing operations or beginning an activity not yet implemented. 192.12(c)
(d) Integrity management program 192.12(d)
(1) Integrity management program elements. The integrity management program for each UNGSF under this paragraph (d) must consist, at a minimum, of a framework developed under API RP 1171 (incorporated by reference, see §192.7), section 8 (“Risk Management for Gas Storage Operations”), and that also describes how relevant decisions will be made and by whom. An operator must make continual improvements to the program and its execution. The integrity management program must include the following elements: 192.12(d)(1)
(i) A plan for developing and implementing each program element to meet the requirements of this section;192.12(d)(1)(i)
(ii) An outline of the procedures to be developed;192.12(d)(1)(ii)
(iii) The roles and responsibilities of UNGSF staff assigned to develop and implement the procedures required by this paragraph (d);192.12(d)(1)(iii)
(iv) A plan for how staff will be trained in awareness and application of the procedures required by this paragraph (d); 192.12(d)(1)(iv)
(v) Timelines for implementing each program element, including the risk analysis and baseline risk assessments; and 192.12(d)(1)(v)
(vi) A plan for how to incorporate information gained from experience into the integrity management program on a continuous basis.192.12(d)(1)(vi)
(2) Integrity management baseline risk-assessment intervals. No later than March 13, 2024, each UNGSF operator must complete the baseline risk assessments of all reservoirs and caverns, and at least 40% of the baseline risk assessments for each of its UNGSF wells (including wellhead assemblies), beginning with the highest-risk wells, as identified by the risk analysis process. No later than March 13, 2027, an operator must complete baseline risk assessments on all its wells (including wellhead assemblies). Operators may use prior risk assessments for a well as a baseline (or part of the baseline) risk assessment in implementing its initial integrity management program, so long as the prior assessments meet the requirements of API RP 1171 (incorporated by reference, see §192.7), section 8, and continue to be relevant and valid for the current operating and environmental conditions. When evaluating prior risk-assessment results, operators must account for the growth and effects of indicated defects since the time the assessment was performed. 192.12(d)(2)
(3) Integrity management re-assessment intervals. The operator must determine the appropriate interval for risk assessments under API RP 1171 (incorporated by reference, see §192.7), subsection 8.7.1, and this paragraph (d) for each reservoir, cavern, and well, using the results from earlier assessments and updated risk analyses. The reassessment interval for each reservoir, cavern, and well must not exceed seven years from the date of the baseline assessment for each reservoir, cavern, and well. 192.12(d)(3)
(4) Integrity management procedures and recordkeeping. Each UNGSF operator must establish and follow written procedures to carry out its integrity management program under API RP 1171 (incorporated by reference, see §192.7), section 8 (“Risk Management for Gas Storage Operations”), and this paragraph (d). The operator must also maintain, for the useful life of the UNGSF, records that demonstrate compliance with the requirements of this paragraph (d). This includes records developed and used in support of any identification, calculation, amendment, modification, justification, deviation, and determination made, and any action taken to implement and evaluate any integrity management program element. 192.12(d)(4)
§192.13 What general requirements apply to pipelines regulated under this part?
(a) No person may operate a segment of pipeline listed in the first column of paragraph (a)(3) of this section that is readied for service after the date in the second column, unless: 192.13(a)
(1) The pipeline has been designed, installed, constructed, initially inspected, and initially tested in accordance with this part; or 192.13(a)(1)
(2) The pipeline qualifies for use under this part according to the requirements in §192.14. 192.13(a)(2)
(3) The compliance deadlines are as follows: 192.13(a)(3)
Pipeline Date
(i) Offshore gathering pipeline
July 31, 1977.
(ii) Regulated onshore gathering pipeline to which this part did not apply until April 14, 2006 March 15, 2007.
(iii) Regulated onshore gathering pipeline to which this part did not apply until May 16, 2022 May 16, 2023.
(iv) All other pipelines March 12, 1971.
(b) No person may operate a segment of pipeline listed in the first column of this paragraph (b) that is replaced, relocated, or otherwise changed after the date in the second column of this paragraph (b), unless the replacement, relocation or change has been made according to the requirements in this part. 192.13(b)
Pipeline Date
(1) Offshore gathering pipeline July 31, 1977.
(2) Regulated onshore gathering pipeline to which this part did not apply until April 14, 2006 March 15, 2007.
(3) Regulated onshore gathering pipeline to which this part did not apply until May 16, 2022 May 16, 2023.
(4) All other pipelines November 12, 1970.
(c) Each operator shall maintain, modify as appropriate, and follow the plans, procedures, and programs that it is required to establish under this part. 192.13(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, Aug. 16, 1976; Amdt. 192-30, 42 FR 60148, Nov. 25, 1977; Amdt. 192-102, 71 FR 13303, Mar. 15, 2006]
§192.14
Conversion to service subject to 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: 192.14(a)
(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. 192.14(a)(1)
(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. 192.14(a)(2)
(3) All known unsafe defects and conditions must be corrected in accordance with this part. 192.14(a)(3)
(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. 192.14(a)(4)
(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. 192.14(b)
(c) An operator converting a pipeline from service not previously covered by this part must notify PHMSA 60 days before the conversion occurs as required by §191.22 of this chapter. 192.14(c)
[Amdt. 192-30, 42 FR 60148, Nov. 25, 1977, as amended by Amdt. 192-123, 82 FR 7997, Jan. 23, 2017]
§192.15
Rules of regulatory construction
(a) As used in this part: 192.15(a)
Includes means including but not limited to.
May means "is permitted to" or "is authorized to".
May not means "is not permitted to" or "is not authorized to".
Shall is used in the mandatory and imperative sense.
(b) In this part: 192.15(b)
(1) Words importing the singular include the plural; 192.15(b)(1)
(2) Words importing the plural include the singular; and 192.15(b)(2)
(3) Words importing the masculine gender include the feminine. 192.15(b)(3)
§192.16
Customer notification
(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. 192.16(a)
(b) Each operator shall notify each customer once in writing of the following information: 192.16(b)
(1) The operator does not maintain the customer's buried piping. 192.16(b)(1)
(2) If the customer's buried piping is not maintained, it may be subject to the potential hazards of corrosion and leakage. 192.16(b)(2)
(3) Buried gas piping should be — 192.16(b)(3)
(i) Periodically inspected for leaks;192.16(b)(3)(i)
(ii) Periodically inspected for corrosion if the piping is metallic; and 192.16(b)(3)(ii)
(iii) Repaired if any unsafe condition is discovered.192.16(b)(3)(iii)
(4) When excavating near buried gas piping, the piping should be located in advance, and the excavation done by hand. 192.16(b)(4)
(5) The operator (if applicable), plumbing contractors, and heating contractors can assist in locating, inspecting, and repairing the customer's buried piping. 192.16(b)(5)
(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. 192.16(c)
(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: 192.16(d)
(1) A copy of the notice currently in use; and 192.16(d)(1)
(2) Evidence that notices have been sent to customers within the previous 3 years. 192.16(d)(2)
[Amdt. 192-74, 60 FR 41828, Aug. 14, 1995, as amended by Amdt. 192-74A, 60 FR 63451, Dec. 11, 1995; Amdt. 19283, 63 FR 7723, Feb. 17, 1998]
§192.18
How to notify PHMSA
(a) An operator must provide any notification required by this part by — 192.18(a)
(1) Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or 192.18(a)(1)
(2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE, Washington, DC 20590. 192.18(a)(2)
(b) An operator must also notify the appropriate State or local pipeline safety authority when an applicable pipeline segment is located in a State where OPS has an interstate agent agreement, or an intrastate applicable pipeline segment is regulated by that State. 192.18(b)
(c) Unless otherwise specified, if an operator submits, pursuant to §192.8, §192.9, §192.179, §192.506, §192.607, §192.619, §192.624, §192.632, §192.634, §192.636, §192.710, §192.712, §192.745, §192.921, or §192.937, a notification for use of a different integrity assessment method, analytical method, sampling approach, or technique (e.g., “other technology” or “alternative equivalent technology”) than otherwise prescribed in those sections, that notification must be submitted to PHMSA for review at least 90 days in advance of using the other method, approach, compliance timeline, or technique. An operator may proceed to use the other method, approach, compliance timeline, or technique 91 days after submitting the notification unless it receives a letter from the Associate Administrator for Pipeline Safety informing the operator that PHMSA objects to the proposal, or that PHMSA requires additional time and/or more information to conduct its review. 192.18(c)
Subpart B – Materials
§192.51 Scope
This subpart prescribes minimum requirements for the selection and qualification of pipe and components for use in pipelines.
§192.53 General
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; 192.53(a)
(b) Chemically compatible with any gas that they transport and with any other material in the pipeline with which they are in contact; and 192.53(b)
(c) Qualified in accordance with the applicable requirements of this subpart. 192.53(c)
§192.55 Steel pipe
(a) New steel pipe is qualified for use under this part if: 192.55(a)
(1) It was manufactured in accordance with a listed specification; 192.55(a)(1)
(2) It meets the requirements of — 192.55(a)(2)
(i) Section II of appendix B to this part; or192.55(a)(2)(i)
(ii) If it was manufactured before November 12, 1970, either section II or III of appendix B to this part; or192.55(a)(2)(ii)
(3) It is used in accordance with paragraph (c) or (d) of this section. 192.55(a)(3)
(b) Used steel pipe is qualified for use under this part if: 192.55(b)
(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; 192.55(b)(1)
(2) It meets the requirements of: 192.55(b)(2)
(i) Section II of appendix B to this part; or192.55(b)(2)(i)
(ii) If it was manufactured before November 12, 1970, either section II or III of appendix B to this part;192.55(b)(2)(ii)
(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 192.55(b)(3)
(4) It is used in accordance with paragraph (c) of this section. 192.55(b)(4)
(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. 192.55(c)
(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. 192.55(d)
(e) New steel pipe that has been cold expanded must comply with the mandatory provisions of API Spec 5L (incorporated by reference, see §192.7). 192.55(e)
(a) New plastic pipe is qualified for use under this part if: 192.59(a)
(1) It is manufactured in accordance with a listed specification; 192.59(a)(1)
(2) It is resistant to chemicals with which contact may be anticipated; and 192.59(a)(2)
(3) It is free of visible defects. 192.59(a)(3)
(b) Used plastic pipe is qualified for use under this part if: 192.59(b)
(1) It was manufactured in accordance with a listed specification; 192.59(b)(1)
(2) It is resistant to chemicals with which contact may be anticipated; 192.59(b)(2)
(3) It has been used only in gas service; 192.59(b)(3)
(4) Its dimensions are still within the tolerances of the specification to which it was manufactured; and 192.59(b)(4)
(5) It is free of visible defects. 192.59(b)(5)
(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: 192.59(c)
(1) Meets the strength and design criteria required of pipe included in that listed specification; and 192.59(c)(1)
(2) Is manufactured from plastic compounds which meet the criteria for material required of pipe included in that listed specification. 192.59(c)(2)
(d) Rework and/or regrind material is not allowed in plastic pipe produced after March 6, 2015 used under this part. 192.59(d)
(a) Except as provided in paragraph (d) and (e) of this section, each valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which it was manufactured. 192.63(a)
(b) Surfaces of pipe and components that are subject to stress from internal pressure may not be field die stamped. 192.63(b)
(c) If any item is marked by die stamping, the die must have blunt or rounded edges that will minimize stress concentrations. 192.63(c)
(d) Paragraph (a) of this section does not apply to items manufactured before November 12, 1970, that meet all of the following: 192.63(d)
(1) The item is identifiable as to type, manufacturer, and model. 192.63(d)(1)
(2) Specifications or standards giving pressure, temperature, and other appropriate criteria for the use of items are readily available. 192.63(d)(2)
(e) All plastic pipe and components must also meet the following requirements: 192.63(e)
(1) All markings on plastic pipe prescribed in the listed specification and the requirements of paragraph (e)(2) of this section must be repeated at intervals not exceeding two feet. 192.63(e)(1)
(2) Plastic pipe and components manufactured after December 31, 2019 must be marked in accordance with the listed specification. 192.63(e)(2)
(3) All physical markings on plastic pipelines prescribed in the listed specification and paragraph (e)(2) of this section must be legible until the time of installation. 192.63(e)(3)
(a) Railroad. In a pipeline to be operated at a hoop stress of 20 percent or more of SMYS, an operator may not install pipe having an outer diameter to wall thickness of 70 to 1, or more, that is transported by railroad unless the transportation is performed by API RP 5L1 (incorporated by reference, see §192.7). 192.65(a)
(b) Ship or barge. 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 ship or barge on both inland and marine waterways unless the transportation is performed in accordance with API RP 5LW (incorporated by reference, see §192.7). 192.65(b)
(c) Truck. 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 truck unless the transportation is performed in accordance with API RP 5LT (incorporated by reference, see §192.7). 192.65(c)
[Amdt. 192-114, 75 FR 48603, Aug. 11, 2010, as amended by Amdt. 192-119, 80 FR 180, Jan. 5, 2015; Amdt. 192-120, 80 FR 12777, Mar. 11, 2015]
§192.67 Records: Material properties.
(a) For steel transmission pipelines installed after [July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records that document the physical characteristics of the pipeline, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition of materials for pipe in accordance with §§192.53 and 192.55. Records must include tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed. 192.67(a)
(b) For steel transmission pipelines installed on or before July 1, 2020], if operators have records that document tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition in accordance with §§192.53 and 192.55, operators must retain such records for the life of the pipeline. 192.67(b)
(c) For steel transmission pipeline segments installed on or before July 1, 2020], if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of §192.624 according to the terms of that section. 192.67(c)
§192.69 Storage and handling of plastic pipe and associated components
Subpart C – Pipe Design
§192.101 Scope
This subpart prescribes the minimum requirements for the design of pipe.
§192.103 General
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.
§192.105 Design formula for steel pipe
(a) The design pressure for steel pipe is determined in accordance with the following formula: 192.105(a)
P=(2 St/D) × F × E × T
P = Design pressure in pounds per square inch (kPa) gauge.
S = Yield strength in pounds per square inch (kPa) determined in accordance with §192.107.
D = Nominal outside diameter of the pipe in inches (millimeters).
t = Nominal wall thickness of the pipe in inches (millimeters). If this is unknown, it is determined in accordance with §192.109. Additional wall thickness required for concurrent external loads in accordance with §192.103 may not be included in computing design pressure.
F = Design factor determined in accordance with §192.111.
E = Longitudinal joint factor determined in accordance with §192.113.
T = Temperature derating factor determined in accordance with §192.115.
(b) If steel pipe that has been subjected to cold expansion to meet the SMYS is subsequently heated, other than by welding or stress relieving as a part of welding, the design pressure is limited to 75 percent of the pressure determined under paragraph (a) of this section if the temperature of the pipe exceeds 900 °F (482 °C) at any time or is held above 600 °F (316 °C) for more than 1 hour. 192.105(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-47, 49 FR 7569, Mar. 1, 1984; Amdt. 192-85, 63 FR 37502, July 13, 1998]
§192.107
Yield
strength (S) for steel pipe
(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. 192.107(a)
(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: 192.107(b)
(1) If the pipe is tensile tested in accordance with section II-D of appendix B to this part, the lower of the following: 192.107(b)(1)
(i) 80 percent of the average yield strength determined by the tensile tests.192.107(b)(1)(i)
(ii) The lowest yield strength determined by the tensile tests. 192.107(b)(1)(ii)
(2) If the pipe is not tensile tested as provided in paragraph (b)(1) of this section, 24,000 p.s.i. (165 MPa). 192.107(b)(2)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28783, June 6, 1996; Amdt. 192-83, 63 FR 7723, Feb. 17, 1998; Amdt. 192-85, 63 FR 37502, July 13, 1998]
§192.109
Nominal wall thickness (t) for steel pipe
(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. 192.109(a)
(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. 192.109(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, July 13, 1998]
§192.112 Part 192 – Minimum Federal Safety Standards
§192.111 Design factor (F) for steel pipe
(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: 192.111(a)
(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: 192.111(b)
(1) Crosses the right-of-way of an unimproved public road, without a casing; 192.111(b)(1)
(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; 192.111(b)(2)
(3) Is supported by a vehicular, pedestrian, railroad, or pipeline bridge; or 192.111(b)(3)
(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
To address this design issue:
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. 192.111(b)(4)
(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. 192.111(c)
(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 — 192.111(d)
(1) Steel pipe in a compressor station, regulating station, or measuring station; and 192.111(d)(1)
(2) Steel pipe, including a pipe riser, on a platform located offshore or in inland navigable waters. 192.111(d)(2)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, Aug. 16, 1976]
§192.112 Additional design requirements for steel pipe using alternative maximum allowable operating pressure
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure (MAOP) calculated under §192.620, a segment must meet the following additional design requirements. Records for alternative MAOP must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
The pipeline segment must meet these additional requirements:
(a) General standards for the steel pipe (1) The plate, skelp, or coil used for the pipe must be micro-alloyed, fine grain, fully killed, continuously cast steel with calcium treatment.
(2) The carbon equivalents of the steel used for pipe must not exceed 0.25 percent by weight, as calculated by the Ito-Bessyo formula (Pcm formula) or 0.43 percent by weight, as calculated by the International Institute of Welding (IIW) formula.
(3) The ratio of the specified outside diameter of the pipe to the specified wall thickness must be less than 100. The wall thickness or other mitigative measures must prevent denting and ovality anomalies during construction, strength testing and anticipated operational stresses.
(4) The pipe must be manufactured using API Spec 5L, product specification level 2 (incorporated by reference, see §192.7) for maximum operating pressures and minimum and maximum operating temperatures and other requirements under this section.
(b) Fracture control
(1) The toughness properties for pipe must address the potential for initiation, propagation and arrest of fractures in accordance with:
(i) API Spec 5L (incorporated by reference, see §192.7); or
(ii) American Society of Mechanical Engineers (ASME) B31.8 (incorporated by reference, see §192.7); and
(iii) Any correction factors needed to address pipe grades, pressures, temperatures, or gas compositions not expressly addressed in API Spec 5L, product specification level 2 or ASME B31.8 (incorporated by reference, see §192.7).
(2) Fracture control must:
(i) Ensure resistance to fracture initiation while addressing the full range of operating temperatures, pressures, gas compositions, pipe grade and operating stress levels, including maximum pressures and minimum temperatures for shut-in conditions, that the pipeline is expected to experience. If these parameters change during operation of the pipeline such that they are outside the bounds of what was considered in the design evaluation, the evaluation must be reviewed and updated to assure continued resistance to fracture initiation over the operating life of the pipeline;
(ii) Address adjustments to toughness of pipe for each grade used and the decompression behavior of the gas at operating parameters;
(iii) Ensure at least 99 percent probability of fracture arrest within eight pipe lengths with a probability of not less than 90 percent within five pipe lengths; and
(iv) Include fracture toughness testing that is equivalent to that described in supplementary requirements SR5A, SR5B, and SR6 of API Specification 5L (incorporated by reference, see §192.7) and ensures ductile fracture and arrest with the following exceptions:
(A) The results of the Charpy impact test prescribed in SR5A must indicate at least 80 percent minimum shear area for any single test on each heat of steel; and
(B) The results of the drop weight test prescribed in SR6 must indicate 80 percent average shear area with a minimum single test result of 60 percent shear area for any steel test samples. The test results must ensure a ductile fracture and arrest.
(3) If it is not physically possible to achieve the pipeline toughness properties of paragraphs (b)(1) and (2) of this section, additional design features, such as mechanical or composite crack arrestors and/or heavier walled pipe of proper design and spacing, must be used to ensure fracture arrest as described in paragraph (b)(2)(iii) of this section.
(c) Plate/coil quality control
(1) There must be an internal quality management program at all mills involved in producing steel, plate, coil, skelp, and/or rolling pipe to be operated at alternative MAOP. These programs must be structured to eliminate or detect defects and inclusions affecting pipe quality.
(2) A mill inspection program or internal quality management program must include (i) and either (ii) or (iii):
(i) An ultrasonic test of the ends and at least 35 percent of the surface of the plate/coil or pipe to identify imperfections that impair serviceability such as laminations, cracks, and inclusions. At least 95 percent of the lengths of pipe manufactured must be tested. For all pipelines designed after December 22, 2008, the test must be done in accordance with ASTM A578/A578M Level B, or API Spec 5L Paragraph 7.8.10 (incorporated by reference, see §192.7) or equivalent method, and either
(ii) A macro etch test or other equivalent method to identify inclusions that may form centerline segregation during the continuous casting process. Use of sulfur prints is not an equivalent method. The test must be carried out on the first or second slab of each sequence graded with an acceptance criteria of one or two on the Mannesmann scale or equivalent; or
(iii) A quality assurance monitoring program implemented by the operator that includes audits of: (a) all steelmaking and casting facilities, (b) quality control plans and manufacturing procedure specifications, (c) equipment maintenance and records of conformance, (d) applicable casting superheat and speeds, and (e) centerline segregation monitoring records to ensure mitigation of centerline segregation during the continuous casting process.
(d) Seam quality control
(1) There must be a quality assurance program for pipe seam welds to assure tensile strength provided in API Spec 5L (incorporated by reference, see §192.7) for appropriate grades.
(2) There must be a hardness test, using Vickers (Hv10) hardness test method or equivalent test method, to assure a maximum hardness of 280 Vickers of the following:
(i) A cross section of the weld seam of one pipe from each heat plus one pipe from each welding line per day; and
(ii) For each sample cross section, a minimum of 13 readings (three for each heat affected zone, three in the weld metal, and two in each section of pipe base metal).
(e) Mill hydrostatic test
(f) Coating
(g) Fittings and flanges
(h) Compressor stations
(3) All of the seams must be ultrasonically tested after cold expansion and mill hydrostatic testing.
(1) All pipe to be used in a new pipeline segment installed after October 1, 2015, must be hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds.
(2) Pipe in operation prior to December 22, 2008, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 90 percent SMYS for 10 seconds.
(3) Pipe in operation on or after December 22, 2008, but before October 1, 2015, must have been hydrostatically tested at the mill at a test pressure corresponding to a hoop stress of 95 percent SMYS for 10 seconds. The test pressure may include a combination of internal test pressure and the allowance for end loading stresses imposed by the pipe mill hydrostatic testing equipment as allowed by "ANSI/API Spec 5L" (incorporated by reference, see §192.7).
(1) The pipe must be protected against external corrosion by a non-shielding coating.
(2) Coating on pipe used for trenchless installation must be non-shielding and resist abrasions and other damage possible during installation.
(3) A quality assurance inspection and testing program for the coating must cover the surface quality of the bare pipe, surface cleanliness and chlorides, blast cleaning, application temperature control, adhesion, cathodic disbondment, moisture permeation, bending, coating thickness, holiday detection, and repair.
(1) There must be certification records of flanges, factory induction bends and factory weld ells. Certification must address material properties such as chemistry, minimum yield strength and minimum wall thickness to meet design conditions.
(2) If the carbon equivalents of flanges, bends and ells are greater than 0.42 percent by weight, the qualified welding procedures must include a pre-heat procedure.
(3) Valves, flanges and fittings must be rated based upon the required specification rating class for the alternative MAOP.
(1) A compressor station must be designed to limit the temperature of the nearest downstream segment operating at alternative MAOP to a maximum of 120 degrees Fahrenheit (49 degrees Celsius) or the higher temperature allowed in paragraph (h)(2) of this section unless a long-term coating integrity monitoring program is implemented in accordance with paragraph (h)(3) of this section.
(2) If research, testing and field monitoring tests demonstrate that the coating type being used will withstand a higher temperature in long-term operations, the compressor station may be designed to limit downstream piping to that higher temperature. Test results and acceptance criteria addressing coating adhesion, cathodic disbondment, and coating condition must be provided to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operating above 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.
(3) Pipeline segments operating at alternative MAOP may operate at temperatures above 120 degrees Fahrenheit (49 degrees Celsius) if the operator implements a long-term coating integrity monitoring program. The monitoring program must include examinations using direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), or an equivalent method of monitoring coating integrity. An operator must specify the periodicity at which these examinations occur and criteria for repairing identified indications. An operator must submit its long-term coating integrity monitoring program to each PHMSA pipeline safety regional office in which the pipeline is located for review before the pipeline segments may be operated at temperatures in excess of 120 degrees Fahrenheit (49 degrees Celsius). An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.
§192.115 Temperature derating factor (T) for steel pipe
The temperature derating factor to be used in the design formula in
§192.105 is determined as follows:
P = Design pressure, gage, psi (kPa).
S = For thermoplastic pipe, the hydrostatic design basis (HDB) is determined in accordance with the listed specification at a temperature equal to 73 °F (23 °C), 100 °F (38 °C), 120 °F (49 °C), or 140 °F (60 °C). In the absence of an HDB established at the specified temperature, the HDB of a higher temperature may be used in determining a design pressure rating at the specified temperature by arithmetic interpolation using the procedure in Part D.2 of PPI TR-3/2012, (incorporated by reference, see §192.7). For reinforced thermosetting plastic pipe, 11,000 psig (75,842 kPa).
t = Specified wall thickness, inches (mm).
D = Specified outside diameter, inches (mm).
SDR = Standard dimension ratio, the ratio of the average specified outside diameter to the minimum specified wall thickness, corresponding to a value from a common numbering system that was derived from the American National Standards Institute (ANSI) preferred number series 10.
DF = Design Factor, a maximum of 0.32 unless otherwise specified for a particular material in this section
(b) General requirements for plastic pipe and components.
(1) Except as provided in paragraphs (c) through (f) of this section, the design pressure for plastic pipe may not exceed a gauge pressure of 100 psig (689 kPa) for pipe used in:
(i) Distribution systems; or
(ii) Transmission lines in Class 3 and 4 locations.
(2) Plastic pipe may not be used where operating temperatures of the pipe will be:
(i) Below -20°F (-29 °C), or below -40°F (-40 °C) if all pipe and pipeline components whose operating temperature will be below -20°F (-29 °C) have a temperature rating by the manufacturer consistent with that operating temperature; or
(ii) Above the temperature at which the HDB used in the design formula under this section is determined.
(3) Unless specified for a particular material in this section, the wall thickness of plastic pipe may not be less than 0.062 inches (1.57 millimeters).
(4) All plastic pipe must have a listed HDB in accordance with PPI TR-4/2012 (incorporated by reference, see §192.7).
(c) Polyethylene (PE) pipe requirements.
(1) For PE pipe produced after July 14, 2004, but before January 22, 2019, a design pressure of up to 125 psig may be used, provided:
(i) The material designation code is PE2406 or PE3408.
(ii) The pipe has a nominal size (Iron Pipe Size (IPS) or Copper Tubing Size (CTS)) of 12 inches or less (above nominal pipe size of 12 inches, the design pressure is limited to 100 psig); and
(iii) The wall thickness is not less than 0.062 inches (1.57 millimeters).
(2) For PE pipe produced after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(i) The design pressure does not exceed 125 psig;
(ii) The material designation code is PE2708 or PE4710;
(iii) The pipe has a nominal size (IPS or CTS) of 24 inches or less; and
(iv) The wall thickness for a given outside diameter is not less than that listed in table 1 to this paragraph (c)(2)(iv).
Table 1 to Paragraph (c)(2)(iv)
(d) Polyamide (PA-11) pipe requirements.
(1) For PA-11 pipe produced after January 23, 2009, but before January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(i) The design pressure does not exceed 200 psig;
(ii) The material designation code is PA32312 or PA32316;
(iii) The pipe has a nominal size (IPS or CTS) of 4 inches or less; and
(iv) The pipe has a standard dimension ratio of SDR-11 or less (i.e., thicker wall pipe).
(2) For PA-11 pipe produced on or after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(i) The design pressure does not exceed 250 psig;
(ii) The material designation code is PA32316;
(iii) The pipe has a nominal size (IPS or CTS) of 6 inches or less; and
(iv) The minimum wall thickness for a given outside diameter is not less than that listed in table 2 to paragraph (d)(2)(iv):
Table 2 to Paragraph (d)(2)(iv)
(e) Polyamide (PA-12) pipe requirements. For PA-12 pipe produced after January 22, 2019, a DF of 0.40 may be used in the design formula, provided:
(1) The design pressure does not exceed 250 psig;
(2) The material designation code is PA42316;
(3) The pipe has a nominal size (IPS or CTS) of 6 inches or less; and (4) The minimum wall thickness for a given outside diameter is not less than that listed in table 3 to paragraph (e)(4).
(2) The wall thickness for reinforced thermosetting plastic pipe may not be less than that listed in the following table:
[Amdt. 192-124, 83 FR 58716, Nov. 20, 2018]
§192.123 [Reserved]
§192.125 Design of copper pipe
(a) Copper pipe used in mains must have a minimum wall thickness of 0.065 inches (1.65 millimeters) and must be hard drawn. 192.125(a)
(b) Copper pipe used in service lines must have wall thickness not less than that indicated in the following table: 192.125(b)
5
(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. 192.125(c)
(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 ft3 (6.9/m3) under standard conditions. Standard conditions refers to 60 °F and 14.7 psia (15.6 °C and one atmosphere) of gas. 192.125(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, Feb. 6, 1989; Amdt. 192-85, 63 FR 37502, July 13, 1998]
§192.127 Records: Pipe design.
(a) For steel transmission pipelines installed after July 1, 2020], an operator must collect or make, and retain for the life of the pipeline, records documenting that the pipe is designed to withstand anticipated external pressures and loads in accordance with §192.103 and documenting that the determination of design pressure for the pipe is made in accordance with §192.105. 192.127(a)
(b) For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting pipe design and the determination of design pressure in accordance with §§192.103 and 192.105, operators must retain such records for the life of the pipeline. 192.127(b)
(c) For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of §192.624 according to the terms of that section. 192.127(c)
Subpart D – Design of Pipeline Components
§192.141 Scope
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.
§192.143
General requirements
(a) Each component of a pipeline must be able to withstand operating pressures and other anticipated loadings without impairment of its serviceability with unit stresses equivalent to those allowed for comparable material in pipe in the same location and kind of service. However, if design based upon unit stresses is impractical for a particular
component, design may be based upon a pressure rating established by the manufacturer by pressure testing that component or a prototype of the component. 192.143(a)
(b) The design and installation of pipeline components and facilities must meet applicable requirements for corrosion control found in subpart I of this part. 192.143(b)
(c) Except for excess flow valves, each plastic pipeline component installed after January 22, 2019 must be able to withstand operating pressures and other anticipated loads in accordance with a listed specification. 192.143(c)
[Amdt. 48, 49 FR 19824, May 10, 1984, as amended at 72 FR 20059, Apr. 23, 2007; Amdt. 192-124, 83 FR 58717, Nov. 20, 2018]
§192.144 Qualifying metallic components
Notwithstanding any requirement of this subpart which incorporates by reference an edition of a document listed in §192.7 or Appendix B of this part, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this part if —
(a) It can be shown through visual inspection of the cleaned component that no defect exists which might impair the strength or tightness of the component; and 192.144(a)
(b) The edition of the document under which the component was manufactured has equal or more stringent requirements for the following as an edition of that document currently or previously listed in §192.7 or appendix B of this part: 192.144(b)
(1) Pressure testing; 192.144(b)(1)
(2) Materials; and 192.144(b)(2)
(3) Pressure and temperature ratings. 192.144(b)(3)
[Amdt. 192-45, 48 FR 30639, July 5, 1983, as amended by Amdt. 192-94, 69 FR 32894, June 14, 2004]
§192.145 Valves
(a) Except for cast iron and plastic valves, each valve must meet the minimum requirements of ANSI/API Spec 6D (incorporated by reference, see §192.7), or to a national or international standard that provides an equivalent performance level. A valve may not be used under operating conditions that exceed the applicable pressure-temperature ratings contained in those requirements. 192.145(a)
(b) Each cast iron and plastic valve must comply with the following: 192.145(b)
(1) The valve must have a maximum service pressure rating for temperatures that equal or exceed the maximum service temperature. 192.145(b)(1)
(2) The valve must be tested as part of the manufacturing, as follows: 192.145(b)(2)
(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.192.145(b)(2)(i)
(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. 192.145(b)(2)(ii)
(iii) After the last pressure test is completed, the valve must be operated through its full travel to demonstrate freedom from interference.192.145(b)(2)(iii)
(c) Each valve must be able to meet the anticipated operating conditions. 192.145(c)
(d) No valve having shell (body, bonnet, cover, and/or end flange) 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: 192.145(d)
(1) The temperature-adjusted service pressure does not exceed 1,000 p.s.i. (7 Mpa) gage; and 192.145(d)(1)
(2) Welding is not used on any ductile iron component in the fabrication of the valve shells or their assembly. 192.145(d)(2)
(e) No valve having shell (body, bonnet, cover, and/or end flange) components made of cast iron, malleable iron, or ductile iron may be used in the gas pipe components of compressor stations. 192.145(e)
(f) Except for excess flow valves, plastic valves installed after January 22, 2019, must meet the minimum requirements of a listed specification. A valve may not be used under operating conditions that exceed the applicable pressure and temperature ratings contained in the listed specification. 192.145(f)
[35
§192.153 Part 192 – Minimum Federal Safety Standards
§192.147 Flanges and flange accessories
(a) Each flange or flange accessory (other than cast iron) must meet the minimum requirements of ASME/ANSI B 16.5 and MSS SP-44 (incorporated by reference, see §192.7), or the equivalent. 192.147(a)
(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. 192.147(b)
(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 (incorporated by reference, see §192.7) and be cast integrally with the pipe, valve, or fitting. 192.147(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, Feb. 6, 1989; 58 FR 14521, Mar. 18, 1993; Amdt. 192-119, 80 FR 181, Jan. 5, 2015]
§192.149 Standard fittings
(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. 192.149(a)
(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. 192.149(b)
(c) Plastic fittings installed after January 22, 2019, must meet a listed specification. 192.149(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-124, 83 FR 58718, Nov. 20, 2018]
§192.150 Passage of internal inspection devices.
(a) Except as provided in paragraphs (b) and (c) of this section, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line, must be designed and constructed to accommodate the passage of instrumented internal inspection devices in accordance with NACE SP0102, section 7 (incorporated by reference, see §192.7). 192.150(a)
(b) This section does not apply to: 192.150(b)
(1) Manifolds; 192.150(b)(1)
(2) Station piping such as at compressor stations, meter stations, or regulator stations; 192.150(b)(2)
(3) Piping associated with storage facilities, other than a continuous run of transmission line between a compressor station and storage facilities; 192.150(b)(3)
(4) Cross-overs; 192.150(b)(4)
(5) Sizes of pipe for which an instrumented internal inspection device is not commercially available; 192.150(b)(5)
(6) Transmission lines, operated in conjunction with a distribution system which are installed in Class 4 locations; 192.150(b)(6)
(7) Offshore transmission lines, except transmission lines 10 3⁄4 inches (273 millimeters) or more in outside diameter on which construction begins after December 28, 2005, that run from platform to platform or platform to shore unless — 192.150(b)(7)
(i) Platform space or configuration is incompatible with launching or retrieving instrumented internal inspection devices; or 192.150(b)(7)(i)
(ii) If the design includes taps for lateral connections, the operator can demonstrate, based on investigation or experience, that there is no reasonably practical alternative under the design circumstances to the use of a tap that will obstruct the passage of instrumented internal inspection devices;192.150(b)(7)(ii)
(8) Gathering lines; and 192.150(b)(8)
(9) 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. 192.150(b)(9)
(c) An operator encountering emergencies, construction time constraints or other unforeseen construction problems need not construct a new or replacement segment of a transmission line to meet paragraph (a) of this section, if the operator determines and documents why an impracticability prohibits compliance with paragraph (a) of this section. Within 30 days after discovering the emergency or construction problem the operator must petition, under §190.9 of this chapter, for approval that design and construction to accommodate passage of instrumented internal inspection devices would be impracticable. If the petition is denied, within 1 year after the date of the notice of the denial, the operator must modify that segment to allow passage of instrumented internal inspection devices. 192.150(c)
[Amdt. 192-72, 59 FR 17281, Apr. 12, 1994, as amended by Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 192-97, 69 FR 36029, June 28, 2004]
§192.151 Tapping
(a) Each mechanical fitting used to make a hot tap must be designed for at least the operating pressure of the pipeline. 192.151(a)
(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. 192.151(b)
(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 192.151(c)
(1) Existing taps may be used for replacement service, if they are free of cracks and have good threads; and 192.151(c)(1)
(2) A 11⁄4-inch (32 millimeters) tap may be made in a 4-inch (102 millimeters) cast iron or ductile iron pipe, without reinforcement. 192.151(c)(2)
However, in areas where climate, soil, and service conditions may create unusual external stresses on cast iron pipe, unreinforced taps may be used only on 6-inch (152 millimeters) or larger pipe.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, July 13, 1998]
§192.153 Components fabricated by welding
(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 UG101 of the ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1) (incorporated by reference, see §192.7). 192.153(a)
(b) Each prefabricated unit that uses plate and longitudinal seams must be designed, constructed, and tested in accordance with the ASME BPVC (Rules for Construction of Pressure Vessels as defined in either Section VIII, Division 1 or Section VIII, Division 2; incorporated by reference, see §192.7), except for the following: 192.153(b)
(2) Pipe that has been produced and tested under a specification listed in appendix B to this part. 192.153(b)(2)
(3) Partial assemblies such as split rings or collars. 192.153(b)(3)
(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. 192.153(b)(4)
(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. 192.153(c)
(d) Except for flat closures designed in accordance with the ASME BPVC (Section VIII, Division 1 or 2), 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 in (76 millimeters) nominal diameter. 192.153(d)
(e) The test requirements for a prefabricated unit or pressure vessel, defined for this paragraph as components with a design pressure established in accordance with paragraph (a) or paragraph (b) of this section are as follows. 192.153(e)
(1) A prefabricated unit or pressure vessel installed after July 14, 2004 is not subject to the strength testing requirements at §192.505(b) provided the component has been tested in accordance with paragraph (a) or paragraph (b) of this section and with a test factor of at least 1.3 times MAOP. 192.153(e)(1)
(2) A prefabricated unit or pressure vessel must be tested for a duration specified as follows: 192.153(e)(2)
(i) A prefabricated unit or pressure vessel installed after July 14, 2004, but before October 1, 2021 is exempt from §§192.505(c) and (d) and 192.507(c) provided it has been tested for a duration consistent with the ASME BPVC requirements referenced in paragraph (a) or (b) of this section.192.153(e)(2)(i)
(ii) A prefabricated unit or pressure vessel installed on or after October 1, 2021 must be tested for the duration specified in either §192.505(c) or (d), §192.507(c), or §192.509(a), whichever is applicable for the pipeline in which the component is being installed.192.153(e)(2)(ii)
(3) For any prefabricated unit or pressure vessel permanently or temporarily installed on a pipeline facility, an operator must either: 192.153(e)(3)
(i) Test the prefabricated unit or pressure vessel in accordance with this section and Subpart J of this part after it has been placed on its support structure at its final installation location. The test may be performed before or after it has been tied-in to the pipeline. Test records that meet §192.517(a) must be kept for the operational life of the prefabricated unit or pressure vessel; or192.153(e)(3)(i)
(ii) For a prefabricated unit or pressure vessel that is pressure tested prior to installation or where a manufacturer's pressure test is used in accordance with paragraph (e) of this section, inspect the prefabricated unit or pressure vessel after it has
been placed on its support structure at its final installation location and confirm that the prefabricated unit or pressure vessel was not damaged during any prior operation, transportation, or installation into the pipeline. The inspection procedure and documented inspection must include visual inspection for vessel damage, including, at a minimum, inlets, outlets, and lifting locations. Injurious defects that are an integrity threat may include dents, gouges, bending, corrosion, and cracking. This inspection must be performed prior to operation but may be performed either before or after it has been tied-in to the pipeline. If injurious defects that are an integrity threat are found, the prefabricated unit or pressure vessel must be either non-destructively tested, re-pressure tested, or remediated in accordance with applicable part 192 requirements for a fabricated unit or with the applicable ASME BPVC requirements referenced in paragraphs (a) or (b) of this section. Test, inspection, and repair records for the fabricated unit or pressure vessel must be kept for the operational life of the component. Test records must meet the requirements in §192.517(a).192.153(e)(3)(ii)
(4) An initial pressure test from the prefabricated unit or pressure vessel manufacturer may be used to meet the requirements of this section with the following conditions: 192.153(e)(4)
(i) The prefabricated unit or pressure vessel is newly-manufactured and installed on or after October 1, 2021, except as provided in paragraph (e)(4)(ii) of this section.192.153(e)(4)(i)
(ii) An initial pressure test from the fabricated unit or pressure vessel manufacturer or other prior test of a new or existing prefabricated unit or pressure vessel may be used for a component that is temporarily installed in a pipeline facility in order to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement. The temporary component must be promptly removed after that task is completed. If operational and environmental constraints require leaving a temporary prefabricated unit or pressure vessel under this paragraph in place for longer than 30 days, the operator must notify PHMSA and State or local pipeline safety authorities, as applicable, in accordance with §192.18. 192.153(e)(4)(ii)
(iii) The manufacturer's pressure test must meet the minimum requirements of this part; and192.153(e)(4)(iii)
(iv) The operator inspects and remediates the prefabricated unit or pressure vessel after installation in accordance with paragraph (e)(3)(ii) of this section.192.153(e)(4)(iv)
(5) An existing prefabricated unit or pressure vessel that is temporarily removed from a pipeline facility to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement, and then re-installed at the same location must be inspected in accordance with paragraph (e)(3)(ii) of this section; however, a new pressure test is not required provided no damage or threats to the operational integrity of the prefabricated unit or pressure vessel were identified during the inspection and the MAOP of the pipeline is not increased. 192.153(e)(5)
(6) Except as provided in paragraphs (e)(4)(ii) and (5) of this section, on or after October 1, 2021, an existing prefabricated unit or pressure vessel relocated and operated at a different location must meet the requirements of this part and the following: 192.153(e)(6)
(i) The prefabricated unit or pressure vessel must be designed and constructed in accordance with the requirements of this part at the time the vessel is returned to operational service at the new location; and192.153(e)(6)(i)
(ii) The prefabricated unit or pressure vessel must be pressure tested by the operator in accordance with the testing and inspection requirements of this part applicable to newly installed prefabricated units and pressure vessels.192.153(e)(6)(ii)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, Nov. 17, 1970; 58 FR 14521, Mar. 18, 1993; Amdt. 192-68, 58 FR 45268, Aug. 27, 1993; Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 192-119, 80 FR 181, Jan. 5, 2015; Amdt. 192-120, 80 FR 12778, Mar. 11, 2015; Amdt. 192-119, 80 FR 46847, Aug. 6, 2015]
§192.155
Welded branch connections
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.
§192.157 Extruded outlets
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.
§192.159 Flexibility
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.
§192.161 Supports and anchors
(a) Each pipeline and its associated equipment must have enough anchors or supports to: 192.161(a)
(1) Prevent undue strain on connected equipment; 192.161(a)(1)
(2) Resist longitudinal forces caused by a bend or offset in the pipe; and 192.161(a)(2)
(3) Prevent or damp out excessive vibration. 192.161(a)(3)
(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. 192.161(b)
(c) Each support or anchor on an exposed pipeline must be made of durable, noncombustible material and must be designed and installed as follows: 192.161(c)
(1) Free expansion and contraction of the pipeline between supports or anchors may not be restricted. 192.161(c)(1)
(2) Provision must be made for the service conditions involved. 192.161(c)(2)
(3) Movement of the pipeline may not cause disengagement of the support equipment. 192.161(c)(3)
(d) Each support on an exposed pipeline operated at a stress level of 50 percent or more of SMYS must comply with the following: 192.161(d)
(1) A structural support may not be welded directly to the pipe. 192.161(d)(1)
(2) The support must be provided by a member that completely encircles the pipe. 192.161(d)(2)
(3) If an encircling member is welded to a pipe, the weld must be continuous and cover the entire circumference. 192.161(d)(3)
(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. 192.161(e)
(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. 192.161(f)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan. 21, 1988]
§192.163 Compressor stations: Design and construction
(a) Location of compressor building. Except for a compressor building on a platform located offshore or in inland navigable waters, each main compressor building of a compressor station must be located on property under the control of the operator. It must be far enough away from adjacent property, not under control of the operator, to minimize the possibility of fire being communicated to the compressor building from structures on adjacent property. There must be enough open space around the main compressor building to allow the free movement of fire-fighting equipment. 192.163(a)
(b) Building construction. Each building on a compressor station site must be made of noncombustible materials if it contains either — 192.163(b)
(1) Pipe more than 2 inches (51 millimeters) in diameter that is carrying gas under pressure; or 192.163(b)(1)
(2) Gas handling equipment other than gas utilization equipment used for domestic purposes. 192.163(b)(2)
(c) Exits. Each operating floor of a main compressor building must have at least two separated and unobstructed exits located so as to provide a convenient possibility of escape and an unobstructed passage to a place of safety. Each door latch on an exit must be of a type which can be readily opened from the inside without a key. Each swinging door located in an exterior wall must be mounted to swing outward. 192.163(c)
(d) Fenced areas. Each fence around a compressor station must have at least two gates located so as to provide a convenient opportunity for escape to a place of safety, or have other facilities affording a similarly convenient exit from the area. Each gate located within 200 feet (61 meters) of any compressor plant building must open outward and, when occupied, must be openable from the inside without a key. 192.163(d)
(e) Electrical facilities. Electrical equipment and wiring installed in compressor stations must conform to the NFPA-70, so far as that code is applicable. 192.163(e)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, Aug. 16, 1976; Amdt. 192-37, 46 FR 10159, Feb. 2, 1981; 58 FR 14521, Mar. 18, 1993; Amdt. 192-85, 63 FR 37502, 37503, July 13, 1998; Amdt. 192-119, 80 FR 181, Jan. 5, 2015]
§192.177 Part 192 – Minimum Federal Safety Standards
§192.165 Compressor stations: Liquid removal
(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. 192.165(a)
(b) Each liquid separator used to remove entrained liquids at a compressor station must: 192.165(b)
(1) Have a manually operable means of removing these liquids. 192.165(b)(1)
(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 192.165(b)(2)
(3) Be manufactured in accordance with section VIII ASME Boiler and Pressure Vessel Code (BPVC) (incorporated by reference, see §192.7) and the additional requirements of §192.153(e) except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4, or less. 192.165(b)(3)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-119, 80 FR 181, Jan. 5, 2015; Amdt. 192-120, 80 FR 12778, Mar. 11, 2015]
§192.167 Compressor stations: Emergency shutdown
(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: 192.167(a)
(1) It must be able to block gas out of the station and blow down the station piping. 192.167(a)(1)
(2) It must discharge gas from the blowdown piping at a location where the gas will not create a hazard. 192.167(a)(2)
(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: 192.167(a)(3)
(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; and192.167(a)(3)(i)
(ii) Electrical circuits needed to protect equipment from damage may remain energized.192.167(a)(3)(ii)
(4) It must be operable from at least two locations, each of which is: 192.167(a)(4)
(i) Outside the gas area of the station;192.167(a)(4)(i)
(ii) Near the exit gates, if the station is fenced, or near emergency exits, if not fenced; and192.167(a)(4)(ii)
(iii) Not more than 500 feet (153 meters) from the limits of the station.192.167(a)(4)(iii)
(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. 192.167(b)
(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: 192.167(c)
(1) In the case of an unattended compressor station: 192.167(c)(1)
(i) When the gas pressure equals the maximum allowable operating pressure plus 15 percent; or192.167(c)(1)(i)
(ii) When an uncontrolled fire occurs on the platform; and 192.167(c)(1)(ii)
(2) In the case of a compressor station in a building: 192.167(c)(2)
(i) When an uncontrolled fire occurs in the building; or192.167(c)(2)(i)
(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.192.167(c)(2)(ii)
For the purpose of paragraph (c)(2)(ii) of this section, an electrical facility which conforms to Class 1, Group D, of the National Electrical Code is not a source of ignition.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, Aug. 16, 1976; Amdt. 192-85, 63 FR 37503, July 13, 1998]
(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. 192.169(a)
(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. 192.169(b)
(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. 192.171(a)
(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. 192.171(b)
(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. 192.171(c)
(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. 192.171(d)
(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. 192.171(e)
§192.173 Compressor stations: Ventilation
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.
§192.175 Pipe-type and
bottle-type holders
(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. 192.175(a)
(b) Each pipe-type or bottle-type holder must have minimum clearance from other holders in accordance with the following formula: 192.175(b)
C = (3D*P*F)/1000) in inches; (C = (3D*P*F*)/6,895) in millimeters in which:
C = Minimum clearance between pipe containers or bottles in inches (millimeters).
D = Outside diameter of pipe containers or bottles in inches (millimeters).
P = Maximum allowable operating pressure, psi (kPa) gauge.
F = Design factor as set forth in §192.111 of this part.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-123, 82 FR 7997, Jan. 23, 2017]
§192.177 Additional provisions for bottle-type holders
(a) Each bottle-type holder must be — 192.177(a)
(1) Located on a site entirely surrounded by fencing that prevents access by unauthorized persons and with minimum clearance from the fence as follows: 192.177(a)(1)
Maximum allowable operating pressure Minimum clearance feet (meters)
Less than 1,000 p.s.i. (7 MPa) gage
1,000 p.s.i. (7 MPa) gage or more
25 (7.6)
100 (31)
(2) Designed using the design factors set forth in §192.111; and 192.177(a)(2)
(3) Buried with a minimum cover in accordance with §192.327. 192.177(a)(3)
(b) Each bottle-type holder manufactured from steel that is not weldable under field conditions must comply with the following: 192.177(b)
(1) A bottle-type holder made from alloy steel must meet the chemical and tensile requirements for the various grades of steel in ASTM A372/372M (incorporated by reference, see §192.7). 192.177(b)(1)
(2) The actual yield-tensile ratio of the steel may not exceed 0.85. 192.177(b)(2)
(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. 192.177(b)(3)
(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. 192.177(b)(4)
(5) The holder, connection pipe, and components must be leak tested after installation as required by subpart J of this part. 192.177(b)(5)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-62, 54 FR 5628, Feb. 6, 1989; 58 FR 14521, Mar. 18, 1993; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-119, 80 FR 181, Jan. 5, 2015]
§192.179 Transmission line valves
(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: 192.179(a)
(1) Each point on the pipeline in a Class 4 location must be within 21⁄2 miles (4 kilometers)of a valve. 192.179(a)(1)
(2) Each point on the pipeline in a Class 3 location must be within 4 miles (6.4 kilometers) of a valve. 192.179(a)(2)
(3) Each point on the pipeline in a Class 2 location must be within 71⁄2 miles (12 kilometers) of a valve. 192.179(a)(3)
(4) Each point on the pipeline in a Class 1 location must be within 10 miles (16 kilometers) of a valve. 192.179(a)(4)
(b) Each sectionalizing block valve on a transmission line, other than offshore segments, must comply with the following: 192.179(b)
(1) The valve and the operating device to open or close the valve must be readily accessible and protected from tampering and damage. 192.179(b)(1)
(2) The valve must be supported to prevent settling of the valve or movement of the pipe to which it is attached. 192.179(b)(2)
(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. 192.179(c)
(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. 192.179(d)
(e)For onshore transmission pipeline segments with diameters greater than or equal to 6 inches that are constructed after April 10, 2023, the operator must install rupture-mitigation valves (RMV) or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph (g) of this section. All RMVs and alternative equivalent technologies installed pursuant to this paragraph must meet the requirements of §§192.634 and 192.636. Exempted from this paragraph's installation requirements are pipeline segments in Class 1, or Class 2 locations that have a potential impact radius (PIR), as defined in §192.903, of 150 feet or less. An operator may request an extension of the installation compliance deadline requirements of this paragraph (e) if it can demonstrate to PHMSA, in accordance with the notification procedures in §192.18, that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular new pipeline. 192.179(e)
(f)For entirely replaced onshore transmission pipeline segments, as defined in §192.3, with diameters greater than or equal to 6 inches and that are installed after April 10, 2023, the operator must install RMVs or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph (g) of this section. All RMVs and alternative equivalent technologies installed pursuant to this paragraph must meet the requirements of §§192.634 and 192.636. The requirements of this paragraph apply when the applicable pipeline replacement project involves a valve, either through addition, replacement, or removal. This paragraph's installation requirements do not apply to pipe segments in Class 1 or Class 2 locations that have a PIR, as defined in §192.903, that is less than or equal to 150 feet. An operator may request an extension of the installation compliance deadline requirements of this paragraph if it can demonstrate to PHMSA, in accordance with the notification procedures in §192.18, that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular pipeline replacement project.192.179(f)
(g)If an operator elects to use alternative equivalent technology in accordance with paragraph (e) or (f) of this section, the operator must notify PHMSA in accordance with the procedures in §192.18. The operator must include a technical and safety evaluation in its notice to PHMSA. Valves that are installed as alternative equivalent technology must comply with §§192.634 and 192.636. An operator requesting use of manual valves as an alternative equivalent technology must also include within the notification submitted to PHMSA a demonstration that installation of an RMV as otherwise required would be economically, technically, or operationally infeasible. An operator may use a manual compressor station valve at a continuously manned station as an alternative equivalent technology, and use of such valve would not require a notification to PHMSA in accordance with §192.18, but it must comply with §192.636.192.179(g)
(h)The valve spacing requirements of paragraph (a) of this section do not apply to pipe replacements on a pipeline if the distance between each point on the pipeline and the nearest valve does not exceed: 192.179(h)
(1) Four (4) miles in Class 4 locations, with a total spacing between valves no greater than 8 miles; 192.179(h)(1)
(2) Seven-and-a-half (71⁄2) miles in Class 3 locations, with a total spacing between valves no greater than 15 miles; or 192.179(h)(2)
(3) Ten (10) miles in Class 1 or 2 locations, with a total spacing between valves no greater than 20 miles. 192.179(h)(3)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, Aug. 16, 1976; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.181
Distribution line valves
(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. 192.181(a)
(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. 192.181(b)
(c) Each valve on a main installed for operating or emergency purposes must comply with the following: 192.181(c)
(1) The valve must be placed in a readily accessible location so as to facilitate its operation in an emergency. 192.181(c)(1)
(2) The operating stem or mechanism must be readily accessible. 192.181(c)(2)
(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. 192.181(c)(3)
§192.183 Vaults: Structural design requirements
(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. 192.183(a)
(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. 192.183(b)
(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. 192.183(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.185 Vaults: Accessibility
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; 192.185(a)
(b) Points of minimum elevation, catch basins, or places where the access cover will be in the course of surface waters; and 192.185(b)
(c) Water, electric, steam, or other facilities. 192.185(c)
§192.187 Vaults: Sealing, venting, and ventilation
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): 192.187(a)
(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; 192.187(a)(1)
(2) The ventilation must be enough to minimize the formation of combustible atmosphere in the vault or pit; and 192.187(a)(2)
(3) The ducts must be high enough above grade to disperse any gasair mixtures that might be discharged. 192.187(a)(3)
(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): 192.187(b)
(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; 192.187(b)(1)
(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 192.187(b)(2)
(3) If the vault or pit is ventilated, paragraph (a) or (c) of this section applies. 192.187(b)(3)
§192.201 Part 192 – Minimum Federal Safety Standards
(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. 192.187(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.189 Vaults: Drainage and waterproofing
(a) Each vault must be designed so as to minimize the entrance of water. 192.189(a)
(b) A vault containing gas piping may not be connected by means of a drain connection to any other underground structure. 192.189(b)
(c) Electrical equipment in vaults must conform to the applicable requirements of Class 1, Group D, of the National Electrical Code, NFPA-70 (incorporated by reference, see §192.7). 192.189(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-76, 61 FR 26122, May 24, 1996; Amdt. 192-119, 80 FR 181, Jan. 5, 2015]
§192.191 [Reserved]
§192.193 Valve installation in plastic pipe
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.
§192.195 Protection against accidental overpressuring
(a) General requirements. Except as provided in §192.197, each pipeline that is connected to a gas source so that the maximum allowable operating pressure could be exceeded as the result of pressure control failure or of some other type of failure, must have pressure relieving or pressure limiting devices that meet the requirements of §§192.199 and 192.201. 192.195(a)
(b) Additional requirements for distribution systems. Each distribution system that is supplied from a source of gas that is at a higher pressure than the maximum allowable operating pressure for the system must — 192.195(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 192.195(b)(1)
(2) Be designed so as to prevent accidental overpressuring. 192.195(b)(2)
§192.197 Control of the pressure of gas delivered from high-pressure distribution systems
(a) If the maximum actual operating pressure of the distribution system is 60 p.s.i. (414 kPa) gage, or less and a service regulator having the following characteristics is used, no other pressure limiting device is required: 192.197(a)
(1) A regulator capable of reducing distribution line pressure to pressures recommended for household appliances. 192.197(a)(1)
(2) A single port valve with proper orifice for the maximum gas pressure at the regulator inlet. 192.197(a)(2)
(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. 192.197(a)(3)
(4) Pipe connections to the regulator not exceeding 2 inches (51 millimeters) in diameter. 192.197(a)(4)
(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. 192.197(a)(5)
(6) A self-contained service regulator with no external static or control lines. 192.197(a)(6)
(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. 192.197(b)
(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: 192.197(c)
(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. 192.197(c)(1)
(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. 192.197(c)(2)
(3) A service regulator with a relief valve vented to the outside atmosphere, with the relief valve set to open so that the pressure of gas going to the customer does not exceed a maximum safe value. The relief valve may either be built into the service regulator or it may be a separate unit installed downstream from the service regulator. This combination may be used alone only in those cases where the inlet pressure on the service regulator does not exceed the manufacturer's safe working pressure rating of the service regulator, and may not be used where the inlet pressure on the service regulator exceeds 125 p.s.i. (862 kPa) gage. For higher inlet pressures, the methods in paragraph (c) (1) or (2) of this section must be used. 192.197(c)(3)
(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. 192.197(c)(4)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, Nov. 7, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]
§192.199 Requirements for design of pressure relief and limiting devices
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; 192.199(a)
(b) Have valves and valve seats that are designed not to stick in a position that will make the device inoperative; 192.199(b)
(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; 192.199(c)
(d) Have support made of noncombustible material; 192.199(d)
(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; 192.199(e)
(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; 192.199(f)
(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 192.199(g)
(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. 192.199(h)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, Nov. 17, 1970]
§192.201 Required capacity of pressure relieving and limiting stations
(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: 192.201(a)
(1) In a low pressure distribution system, the pressure may not cause the unsafe operation of any connected and properly adjusted gas utilization equipment. 192.201(a)(1)
(2) In pipelines other than a low pressure distribution system: 192.201(a)(2)
(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;192.201(a)(2)(i)
(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; or192.201(a)(2)(ii)
(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. 192.201(a)(2)(iii)
(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. 192.201(b)
(c) Relief valves or other pressure limiting devices must be installed at or near each regulator station in a low-pressure distribution system, with a capacity to limit the maximum pressure in the main to a pressure that will not exceed the safe operating pressure for any connected and properly adjusted gas utilization equipment. 192.201(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-9, 37 FR 20827, Oct. 4, 1972; Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.203 Instrument, control, and sampling pipe and components
(a) Applicability. This section applies to the design of instrument, control, and sampling pipe and components. It does not apply to permanently closed systems, such as fluid-filled temperature-responsive devices. 192.203(a)
(b) Materials and design. All materials employed for pipe and components must be designed to meet the particular conditions of service and the following: 192.203(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. 192.203(b)(1)
(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. 192.203(b)(2)
(3) Brass or copper material may not be used for metal temperatures greater than 400 °F (204 °C). 192.203(b)(3)
(4) Pipe or components that may contain liquids must be protected by heating or other means from damage due to freezing. 192.203(b)(4)
(5) Pipe or components in which liquids may accumulate must have drains or drips. 192.203(b)(5)
(6) Pipe or components subject to clogging from solids or deposits must have suitable connections for cleaning. 192.203(b)(6)
(7) The arrangement of pipe, components, and supports must provide safety under anticipated operating stresses. 192.203(b)(7)
(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. 192.203(b)(8)
(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 overpressure protective device inoperative. 192.203(b)(9)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.204 Risers installed after January 22, 2019
(a) Riser designs must be tested to ensure safe performance under anticipated external and internal loads acting on the assembly. 192.204(a)
(b) Factory assembled anodeless risers must be designed and tested in accordance with ASTM F1973-13 (incorporated by reference, see §192.7). 192.204(b)
(c) All risers used to connect regulator stations to plastic mains must be rigid and designed to provide adequate support and resist lateral movement. Anodeless risers used in accordance with this paragraph must have a rigid riser casing. 192.204(c)
[Amdt. 192-124, 83 FR 58718, Nov. 20, 2018]
§192.205 Records: Pipeline components.
(a) For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with this subpart. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches must have records documenting the manufactur-
ing specification in effect at the time of manufacture, including yield strength, ultimate tensile strength, and chemical composition of materials. 192.205(a)
(b) For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting the manufacturing standard and pressure rating for valves, flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches, operators must retain such records for the life of the pipeline. 192.205(b)
(c) For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of §192.624 according to the terms of that section. 192.205(c)
Subpart E – Welding of Steel in Pipelines
§192.221 Scope
(a) This subpart prescribes minimum requirements for welding steel materials in pipelines. 192.221(a)
(b) This subpart does not apply to welding that occurs during the manufacture of steel pipe or steel pipeline components. 192.221(b)
§192.225 Welding procedures
(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see §192.7), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see §192.7) to produce welds meeting the requirements of this subpart. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the applicable welding standard(s). 192.225(a)
(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. 192.225(b)
(a) Except as provided in paragraph (b) of this section, each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see §192.7), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see §192.7). However, a welder or welding operator qualified under an earlier edition than the listed in §192.7 of this part may weld but may not requalify under that earlier edition. 192.227(a)
(b) A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than 20 percent of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in section I of Appendix C of this part. Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under section II of Appendix C of this part as a requirement of the qualifying test. 192.227(b)
(c) For steel transmission pipe installed after July 1, 2021, records demonstrating each individual welder qualification at the time of construction in accordance with this section must be retained for a minimum of 5 years following construction. 192.227(c)
[Amdt. 192-120, 80 FR 12778, Mar. 11, 2015, as amended by Amdt. 192-123, 82 FR 7997, Jan. 23, 2017]
§192.229
Limitations on welders and welding operators
(a) No welder or welding operator whose qualification is based on nondestructive testing may weld compressor station pipe and components. 192.229(a)
(b) A welder or welding operator may not weld with a particular welding process unless, within the preceding 6 calendar months, the welder or welding operator was engaged in welding with that process. Alternatively, welders or welding operators may demonstrate they have engaged in a specific welding process if they have performed a weld with that process that was tested and found acceptable under section 6, 9, 12, or Appendix A of API Std 1104 (incorporated by reference, see §192.7) within the preceding 71⁄2 months. 192.229(b)
(c) A welder or welding operator qualified under §192.227(a) — 192.229(c)
(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 or welding operator has had one weld tested and found acceptable under either section 6, section 9, section 12 or Appendix A of API Std 1104 (incorporated by reference, see §192.7). Alternatively, welders or welding operators may maintain an ongoing qualification status by performing welds
§192.275 Part 192 – Minimum Federal Safety Standards
tested and found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals not exceeding 71⁄2 months. A welder or welding operator qualified under an earlier edition of a standard listed in §192.7 of this part may weld, but may not re-qualify under that earlier edition; and, 192.229(c)(1)
(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 or welding operator is tested in accordance with paragraph (c)(1) of this section or re-qualifies under paragraph (d)(1) or (d)(2) of this section. 192.229(c)(2)
(d) A welder or welding operator qualified under §192.227(b) may not weld unless — 192.229(d)
(1) Within the preceding 15 calendar months, but at least once each calendar year, the welder or welding operator has re-qualified under §192.227(b); or 192.229(d)(1)
(2) Within the preceding 71⁄2 calendar months, but at least twice each calendar year, the welder or welding operator has had — 192.229(d)(2)
(i) A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or192.229(d)(2)(i)
(ii) For a welder who works only on service lines 2 inches (51 millimeters) or smaller in diameter, the welder has had two sample welds tested and found acceptable in accordance with the test in section III of Appendix C of this part.192.229(d)(2)(ii)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10159, Feb. 2, 1981; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-94, 69 FR 32895, June 14, 2004; Amdt. 192-119, 80 FR 181, Jan. 5, 2015;Amdt. 192-120, 80 FR 12778, Mar. 11, 2015]
§192.231 Protection from weather
The welding operation must be protected from weather conditions that would impair the quality of the completed weld.
§192.233 Miter joints
(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°. 192.233(a)
(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 121⁄2° and must be a distance equal to one pipe diameter or more away from any other miter joint, as measured from the crotch of each joint. 192.233(b)
(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°. 192.233(c)
§192.235 Preparation for welding
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.
§192.241 Inspection and test of welds
(a) Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that: 192.241(a)
(1) The welding is performed in accordance with the welding procedure; and 192.241(a)(1)
(2) The weld is acceptable under paragraph (c) of this section. 192.241(a)(2)
(b) The welds on a pipeline to be operated at a pressure that produces a hoop stress of 20 percent or more of SMYS must be nondestructively tested in accordance with §192.243, except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if: 192.241(b)
(1) The pipe has a nominal diameter of less than 6 inches (152 millimeters); or 192.241(b)(1)
(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. 192.241(b)(2)
(c) The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by reference, see §192.7). Appendix A of API Std 1104 may not be used to accept cracks. 192.241(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10160, Feb. 2, 1981; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-94, 69 FR 32894, June 14, 2004; Amdt. 192-119, 80 FR 181, Jan. 5, 2015; Amdt. 192-120, 80 FR 12778, Mar. 11, 2015]
§192.243 Nondestructive testing
(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. 192.243(a)
(b) Nondestructive testing of welds must be performed: 192.243(b)
(1) In accordance with written procedures; and 192.243(b)(1)
(2) By persons who have been trained and qualified in the established procedures and with the equipment employed in testing. 192.243(b)(2)
(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). 192.243(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: 192.243(d)
(1) In Class 1 locations, except offshore, at least 10 percent. 192.243(d)(1)
(2) In Class 2 locations, at least 15 percent. 192.243(d)(2)
(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. 192.243(d)(3)
(4) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent. 192.243(d)(4)
(e) Except for a welder or welding operator whose work is isolated from the principal welding activity, a sample of each welder or welding operator's work for each day must be nondestructively tested, when nondestructive testing is required under §192.241(b). 192.243(e)
(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. 192.243(f)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, Aug. 16, 1976; Amdt. 192-50, 50 FR 37192, Sept. 12, 1985; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]
§192.245 Repair or removal of defects
(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. 192.245(a)
(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. 192.245(b)
(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. 192.245(c)
[Amdt. 192-46, 48 FR 48674, Oct. 20, 1983]
Subpart F – Joining of Materials Other Than by Welding
§192.271 Scope
(a) This subpart prescribes minimum requirements for joining materials in pipelines, other than by welding. 192.271(a)
(b) This subpart does not apply to joining during the manufacture of pipe or pipeline components. 192.271(b)
§192.273 General
(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. 192.273(a)
(b) Each joint must be made in accordance with written procedures that have been proven by test or experience to produce strong gastight joints. 192.273(b)
(c) Each joint must be inspected to insure compliance with this subpart. 192.273(c)
§192.275 Cast iron pipe
(a) Each caulked bell and spigot joint in cast iron pipe must be sealed with mechanical leak clamps. 192.275(a)
(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. 192.275(b)
(c) Cast iron pipe may not be joined by threaded joints. 192.275(c)
(d) Cast iron pipe may not be joined by brazing. 192.275(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, Feb. 6, 1989]
§192.277 Ductile iron pipe
(a) Ductile iron pipe may not be joined by threaded joints. 192.277(a)
(b) Ductile iron pipe may not be joined by brazing. 192.277(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, Feb. 6, 1989]
§192.279 Copper pipe
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.
[Amdt. 192-62, 54 FR 5628, Feb. 6, 1989, as amended at 58 FR 14521, Mar. 18, 1993]
§192.281 Plastic pipe
(a) General. A plastic pipe joint that is joined by solvent cement, adhesive, or heat fusion may not be disturbed until it has properly set. Plastic pipe may not be joined by a threaded joint or miter joint. 192.281(a)
(b) Solvent cement joints. Each solvent cement joint on plastic pipe must comply with the following: 192.281(b)
(1) The mating surfaces of the joint must be clean, dry, and free of material which might be detrimental to the joint. 192.281(b)(1)
(2) The solvent cement must conform to ASTM D2564-12 for PVC (incorporated by reference, see §192.7). 192.281(b)(2)
(3) The joint may not be heated or cooled to accelerate the setting of the cement. 192.281(b)(3)
(c) Heat-fusion joints. Each heat fusion joint on a PE pipe or component, except for electrofusion joints, must comply with ASTM F2620 (incorporated by reference in §192.7), or an alternative written procedure that has been demonstrated to provide an equivalent or superior level of safety and has been proven by test or experience to produce strong gastight joints, and the following: 192.281(c)
(1) A butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the pipe or component, compresses the heated ends together, and holds the pipe in proper alignment in accordance with the appropriate procedure qualified under §192.283. 192.281(c)(1)
(2) A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the pipe or component, uniformly and simultaneously, to establish the same temperature. The device used must be the same device specified in the operator's joining procedure for socket fusion. 192.281(c)(2)
(3) An electrofusion joint must be made using the equipment and techniques prescribed by the fitting manufacturer, or using equipment and techniques shown, by testing joints to the requirements of §192.283(a)(1)(iii), to be equivalent to or better than the requirements of the fitting manufacturer. 192.281(c)(3)
(4) Heat may not be applied with a torch or other open flame. 192.281(c)(4)
(d) Adhesive joints. Each adhesive joint on plastic pipe must comply with the following: 192.281(d)
(1) The adhesive must conform to ASTM D 2517 (incorporated by reference, see §192.7). 192.281(d)(1)
(2) The materials and adhesive must be compatible with each other. 192.281(d)(2)
(e) Mechanical joints. Each compression type mechanical joint on plastic pipe must comply with the following: 192.281(e)
(1) The gasket material in the coupling must be compatible with the plastic. 192.281(e)(1)
(2) A rigid internal tubular stiffener, other than a split tubular stiffener, must be used in conjunction with the coupling. 192.281(e)(2)
(3) All mechanical fittings must meet a listed specification based upon the applicable material. 192.281(e)(3)
(4) All mechanical joints or fittings installed after January 22, 2019, must be Category 1 as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than 25% elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard. 192.281(e)(4)
§192.283 Plastic pipe: Qualifying joining procedures
(a) Heat fusion, solvent cement, and adhesive joints. Before any written procedure established under §192.273(b) is used for making plastic pipe joints by a heat fusion, solvent cement, or adhesive
method, the procedure must be qualified by subjecting specimen joints that are made according to the procedure to the following tests, as applicable: 192.283(a)
(1) The test requirements of — 192.283(a)(1)
(i) In the case of thermoplastic pipe, based on the pipe material, the Sustained Pressure Test or the Minimum Hydrostatic Burst Test per the listed specification requirements. Additionally, for electrofusion joints, based on the pipe material, the Tensile Strength Test or the Joint Integrity Test per the listed specification.192.283(a)(1)(i)
(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- 00 (incorporated by reference, see §192.7).192.283(a)(1)(ii)
(iii) In the case of electrofusion fittings for polyethylene (PE) 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 F1055-98(2006) (incorporated by reference, see §192.7).192.283(a)(1)(iii)
(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. 192.283(a)(2)
(3) For procedures intended for non-lateral pipe connections, perform tensile testing in accordance with a listed specification. If the test specimen elongates no less than 25% or failure initiates outside the joint area, the procedure qualifies for use. 192.283(a)(3)
(b) Mechanical joints. Before any written procedure established under §192.273(b) is used for making mechanical plastic pipe joints, the procedure must be qualified in accordance with a listed specification based upon the pipe material. 192.283(b)
(c) A copy of each written procedure being used for joining plastic pipe must be available to the persons making and inspecting joints. 192.283(c)
[Amdt. 192-124, 83 FR 58718, Nov. 20, 2018]
§192.285 Plastic pipe: Qualifying persons to make joints
(a) No person may make a plastic pipe joint unless that person has been qualified under the applicable joining procedure by: 192.285(a)
(1) Appropriate training or experience in the use of the procedure; and 192.285(a)(1)
(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. 192.285(a)(2)
(b) The specimen joint must be: 192.285(b)
(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 192.285(b)(1)
(2) In the case of a heat fusion, solvent cement, or adhesive joint: 192.285(b)(2)
(i) Tested under any one of the test methods listed under §192.283(a), and for PE heat fusion joints (except for electrofusion joints) visually inspected in accordance with ASTM F2620 (incorporated by reference, see §192.7), or a written procedure that has been demonstrated to provide an equivalent or superior level of safety, applicable to the type of joint and material being tested;192.285(b)(2)(i)
(ii) Examined by ultrasonic inspection and found not to contain flaws that would cause failure; or192.285(b)(2)(ii)
(iii) Cut into at least 3 longitudinal straps, each of which is: 192.285(b)(2)(iii)
[A] Visually examined and found not to contain voids or discontinuities on the cut surfaces of the joint area; and 192.285(b)(2)(iii)[A]
[B] Deformed by bending, torque, or impact, and if failure occurs, it must not initiate in the joint area.192.285(b)(2)(iii)[B]
(c) A person must be re-qualified under an applicable procedure once each calendar year at intervals not exceeding 15 months, or after any production joint is found unacceptable by testing under §192.513. 192.285(c)
(d) Each operator shall establish a method to determine that each person making joints in plastic pipelines in the operator's system is qualified in accordance with this section. 192.285(d)
(e) For transmission pipe installed after July 1, 2021, records demonstrating each person's plastic pipe joining qualifications at the time of construction in accordance with this section must be retained for a minimum of 5 years following construction. 192.285(e)
§192.319 Part 192 – Minimum Federal Safety Standards
§192.287 Plastic pipe: Inspection of joints
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.
[Amdt. 192-34, 44 FR 42974, July 23, 1979]
Subpart G – General Construction Requirements for Transmission Lines and Mains
§192.301 Scope
This subpart prescribes minimum requirements for constructing transmission lines and mains.
§192.303 Compliance with specifications or standards
Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this part.
§192.305 Inspection: General
Each transmission line or main must be inspected to ensure that it is constructed in accordance with this part.
Editor's Note: The effective date for the amendment revising 49 CFR 192.305, published March 11, 2015, at 80 FR 12779, (content is displayed below) is delayed indefinitely. This delay was published at 80 FR 58633, September 30, 2015.
Each transmission line and main must be inspected to ensure that it is constructed in accordance with this subpart. An operator must not use operator personnel to perform a required inspection if the operator personnel performed the construction task requiring inspection. Nothing in this section prohibits the operator from inspecting construction tasks with operator personnel who are involved in other construction tasks.
§192.307 Inspection of materials
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.
§192.309 Repair of steel pipe
(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: 192.309(a)
(1) The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or 192.309(a)(1)
(2) The nominal wall thickness required for the design pressure of the pipeline. 192.309(a)(2)
(b) Each of the following dents must be removed from steel pipe to be operated at a pressure that produces a hoop stress of 20 percent, or more, of SMYS, unless the dent is repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe: 192.309(b)
(1) A dent that contains a stress concentrator such as a scratch, gouge, groove, or arc burn. 192.309(b)(1)
(2) A dent that affects the longitudinal weld or a circumferential weld. 192.309(b)(2)
(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: 192.309(b)(3)
(i) More than 1⁄4 inch (6.4 millimeters) in pipe 123⁄4 inches (324 millimeters) or less in outer diameter; or192.309(b)(3)(i)
(ii) More than 2 percent of the nominal pipe diameter in pipe over 123⁄4 inches (324 millimeters) in outer diameter.192.309(b)(3)(ii)
For the purpose of this section a "dent" is a depression that produces a gross disturbance in the curvature of the pipe wall without reducing the pipe-wall thickness. The depth of a dent is measured as the gap between the lowest point of the dent and a prolongation of the original contour of the pipe.
(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: 192.309(c)
(1) The minimum wall thickness required by the tolerances in the specification to which the pipe was manufactured; or 192.309(c)(1)
(2) The nominal wall thickness required for the design pressure of the pipeline. 192.309(c)(2)
(d) A gouge, groove, arc burn, or dent may not be repaired by insert patching or by pounding out. 192.309(d)
(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. 192.309(e)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, Nov. 17, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-88, 64 FR 69664, Dec. 14, 1999]
§192.311
Repair of plastic pipe
Each imperfection or damage that would impair the serviceability of plastic pipe must be repaired or removed.
[Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]
§192.313
Bends and elbows
(a) Each field bend in steel pipe, other than a wrinkle bend made in accordance with §192.315, must comply with the following: 192.313(a)
(1) A bend must not impair the serviceability of the pipe. 192.313(a)(1)
(2) Each bend must have a smooth contour and be free from buckling, cracks, or any other mechanical damage. 192.313(a)(2)
(3) On pipe containing a longitudinal weld, the longitudinal weld must be as near as practicable to the neutral axis of the bend unless: 192.313(a)(3)
(i) The bend is made with an internal bending mandrel; or 192.313(a)(3)(i)
(ii) The pipe is 12 inches (305 millimeters) or less in outside diameter or has a diameter to wall thickness ratio less than 70. 192.313(a)(3)(ii)
(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. 192.313(b)
(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). 192.313(c)
(d) An operator may not install plastic pipe with a bend radius that is less than the minimum bend radius specified by the manufacturer for the diameter of the pipe being installed. 192.313(d)
(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. 192.315(a)
(b) Each wrinkle bend on steel pipe must comply with the following: 192.315(b)
(1) The bend must not have any sharp kinks. 192.315(b)(1)
(2) When measured along the crotch of the bend, the wrinkles must be a distance of at least one pipe diameter. 192.315(b)(2)
(3) On pipe 16 inches (406 millimeters) or larger in diameter, the bend may not have a deflection of more than 11⁄2° for each wrinkle. 192.315(b)(3)
(4) On pipe containing a longitudinal weld the longitudinal seam must be as near as practicable to the neutral axis of the bend. 192.315(b)(4)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.317 Protection from hazards
(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. 192.317(a)
(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. 192.317(b)
(c) Pipelines, including pipe risers, on each platform located offshore or in inland navigable waters must be protected from accidental damage by vessels. 192.317(c)
[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976, as amended by Amdt. 192-78, 61 FR 28784, June 6, 1996]
§192.319 Installation of pipe in a ditch
(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. 192.319(a)
(b) When a ditch for a transmission line or main is backfilled, it must be backfilled in a manner that: 192.319(b)
(1) Provides firm support under the pipe; and 192.319(b)(1)
(2) Prevents damage to the pipe and pipe coating from equipment or from the backfill material. 192.319(b)(2)
(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. 192.319(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, Aug. 16, 1976; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.321 Installation of plastic pipelines
(a) Plastic pipe must be installed below ground level except as provided in paragraphs (g), (h), and (i) of this section. 192.321(a)
(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. 192.321(b)
(c) Plastic pipe must be installed so as to minimize shear or tensile stresses. 192.321(c)
(d) Plastic pipe must have a minimum wall thickness in accordance with §192.121. 192.321(d)
(e) Plastic pipe that is not encased must have an electrically conducting wire or other means of locating the pipe while it is underground. Tracer wire may not be wrapped around the pipe and contact with the pipe must be minimized but is not prohibited. Tracer wire or other metallic elements installed for pipe locating purposes must be resistant to corrosion damage, either by use of coated copper wire or by other means. 192.321(e)
(f) Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. Plastic pipe that is being encased must be protected from damage at all entrance and all exit points of the casing. The leading end of the plastic must be closed before insertion. 192.321(f)
(g) Uncased plastic pipe may be temporarily installed above ground level under the following conditions: 192.321(g)
(1) The operator must be able to demonstrate that the cumulative aboveground exposure of the pipe does not exceed the manufacturer's recommended maximum period of exposure or 2 years, whichever is less. 192.321(g)(1)
(2) The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage. 192.321(g)(2)
(3) The pipe adequately resists exposure to ultraviolet light and high and low temperatures. 192.321(g)(3)
(h) Plastic pipe may be installed on bridges provided that it is: 192.321(h)
(1) Installed with protection from mechanical damage, such as installation in a metallic casing; 192.321(h)(1)
(2) Protected from ultraviolet radiation; and 192.321(h)(2)
(3) Not allowed to exceed the pipe temperature limits specified in §192.121. 192.321(h)(3)
(i) Plastic mains may terminate above ground level provided they comply with the following: 192.321(i)
(1) The above-ground level part of the plastic main is protected against deterioration and external damage. 192.321(i)(1)
(2) The plastic main is not used to support external loads. 192.321(i)(2)
(3) Installations of risers at regulator stations must meet the design requirements of §192.204. 192.321(i)(3)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003; Amdt. 192-94, 69 FR 32895, June 14, 2004; Amdt. 192-124, 83 FR 58718, Nov. 20, 2018]
§192.323 Casing
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. 192.323(a)
(b) If there is a possibility of water entering the casing, the ends must be sealed. 192.323(b)
(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. 192.323(c)
(d) If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing. 192.323(d)
§192.325 Underground clearance
(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. 192.325(a)
(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. 192.325(b)
(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. 192.325(c)
(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). 192.325(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.327 Cover
(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: 192.327(a)
Location Normal soil Consolidated rock Inches (Millimeters)
Class 1 locations 30 (762) 18 (457)
Class 2, 3, and 4 locations 36 (914) 24 (610)
Drainage ditches of public roads and railroad crossings 36 (914) 24 (610)
(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. 192.327(b)
(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. 192.327(c)
(d) A main may be installed with less than 24 inches (610 millimeters) of cover if the law of the State or municipality: 192.327(d)
(1) Establishes a minimum cover of less than 24 inches (610 millimeters); 192.327(d)(1)
(2) Requires that mains be installed in a common trench with other utility lines; and 192.327(d)(2)
(3) Provides adequately for prevention of damage to the pipe by external forces. 192.327(d)(3)
(e) Except as provided in paragraph (c) of this section, all pipe installed in a navigable river, stream, or harbor must be installed with a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches (610 millimeters) in consolidated rock between the top of the pipe and the underwater natural bottom (as determined by recognized and generally accepted practices). 192.327(e)
(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: 192.327(f)
(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. 192.327(f)(1)
(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. 192.327(f)(2)
(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). 192.327(g)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, Aug. 16, 1976; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-98, 69 FR 48406, Aug. 10, 2004]
§192.361 Part 192 – Minimum Federal Safety Standards
§192.328 Additional construction requirements for steel pipe using alternative maximum allowable operating pressure
For a new or existing pipeline segment to be eligible for operation at the alternative maximum allowable operating pressure calculated under §192.620, a segment must meet the following additional construction requirements. Records must be maintained, for the useful life of the pipeline, demonstrating compliance with these requirements:
To address this construction issue:
The pipeline segment must meet this additional construction requirement:
(1) The construction of the pipeline segment must be done under a quality assurance plan addressing pipe inspection, hauling and stringing, field bending, welding, non-destructive examination of girth welds, applying and testing field applied coating, lowering of the pipeline into the ditch, padding and backfilling, and hydrostatic testing.
(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. 192.353(c)
(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. 192.353(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]
§192.355 Customer meters and regulators: Protection from damage
(a) Protection from vacuum or back pressure. If the customer's equipment might create either a vacuum or a back pressure, a device must be installed to protect the system. 192.355(a)
(b) Service regulator vents and relief vents. Service regulator vents and relief vents must terminate outdoors, and the outdoor terminal must — 192.355(b)
(a) Quality assurance
(2) The quality assurance plan for applying and testing field applied coating to girth welds must be:
(i) Equivalent to that required under §192.112(f)(3) for pipe; and
(ii) Performed by an individual with the knowledge, skills, and ability to assure effective coating application.
(b) Girth welds (1) All girth welds on a new pipeline segment must be nondestructively examined in accordance with §192.243(b) and (c).
(1) Notwithstanding any lesser depth of cover otherwise allowed in §192.327, there must be at least 36 inches (914 millimeters) of cover or equivalent means to protect the pipeline from outside force damage.
(1) Be rain and insect resistant; 192.355(b)(1)
(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 192.355(b)(2)
(3) Be protected from damage caused by submergence in areas where flooding may occur. 192.355(b)(3)
(c) Pits and vaults. Each pit or vault that houses a customer meter or regulator at a place where vehicular traffic is anticipated, must be able to support that traffic. 192.355(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan. 21, 1988]
(c) Depth of cover
(d) Initial strength testing
(2) In areas where deep tilling or other activities could threaten the pipeline, the top of the pipeline must be installed at least one foot below the deepest expected penetration of the soil.
(1) The pipeline segment must not have experienced failures indicative of systemic material defects during strength testing, including initial hydrostatic testing. A root cause analysis, including metallurgical examination of the failed pipe, must be performed for any failure experienced to verify that it is not indicative of a systemic concern. The results of this root cause analysis must be reported to each PHMSA pipeline safety regional office where the pipe is in service at least 60 days prior to operating at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State.
§192.357 Customer meters and regulators: Installation
(a) Each meter and each regulator must be installed so as to minimize anticipated stresses upon the connecting piping and the meter. 192.357(a)
(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. 192.357(b)
(c) Connections made of lead or other easily damaged material may not be used in the installation of meters or regulators. 192.357(c)
(d) Each regulator that might release gas in its operation must be vented to the outside atmosphere. 192.357(d)
§192.359 Customer meter installations: Operating pressure
(e) Interference currents
[72 FR 62176, Oct. 17, 2008]
(1) For a new pipeline segment, the construction must address the impacts of induced alternating current from parallel electric transmission lines and other known sources of potential interference with corrosion control.
§192.329 Installation of plastic pipelines by trenchless excavation
Plastic pipelines installed by trenchless excavation must comply with the following:
(a) Each operator must take practicable steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and/or structures at the time of installation. 192.329(a)
(b) For each pipeline section, plastic pipe and components that are pulled through the ground must use a weak link, as defined by §192.3, to ensure the pipeline will not be damaged by any excessive forces during the pulling process. 192.329(b)
[Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]
Subpart H – Customer Meters, Service Regulators, and Service Lines
§192.351 Scope
This subpart prescribes minimum requirements for installing customer meters, service regulators, service lines, service line valves, and service line connections to mains.
§192.353 Customer meters and regulators: Location
(a) Each meter and service regulator, whether inside or outside a building, must be installed in a readily accessible location and be protected from corrosion and other damage, including, if installed outside a building, vehicular damage that may be anticipated. However, the upstream regulator in a series may be buried. 192.353(a)
(b) Each service regulator installed within a building must be located as near as practical to the point of service line entrance. 192.353(b)
(a) A meter may not be used at a pressure that is more than 67 percent of the manufacturer's shell test pressure. 192.359(a)
(b) Each newly installed meter manufactured after November 12, 1970, must have been tested to a minimum of 10 p.s.i. (69 kPa) gage. 192.359(b)
(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. 192.359(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, Nov. 17, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.361 Service lines: Installation
(a) Depth. Each buried service line must be installed with at least 12 inches (305 millimeters) of cover in private property and at least 18 inches (457 millimeters) of cover in streets and roads. However, where an underground structure prevents installation at those depths, the service line must be able to withstand any anticipated external load. 192.361(a)
(b) Support and backfill. Each service line must be properly supported on undisturbed or well-compacted soil, and material used for backfill must be free of materials that could damage the pipe or its coating. 192.361(b)
(c) Grading for drainage. Where condensate in the gas might cause interruption in the gas supply to the customer, the service line must be graded so as to drain into the main or into drips at the low points in the service line. 192.361(c)
(d) Protection against piping strain and external loading. Each service line must be installed so as to minimize anticipated piping strain and external loading. 192.361(d)
(e) Installation of service lines into buildings. Each underground service line installed below grade through the outer foundation wall of a building must: 192.361(e)
(1) In the case of a metal service line, be protected against corrosion; 192.361(e)(1)
(2) In the case of a plastic service line, be protected from shearing action and backfill settlement; and 192.361(e)(2)
(3) Be sealed at the foundation wall to prevent leakage into the building. 192.361(e)(3)
(f) Installation of service lines under buildings. Where an underground service line is installed under a building: 192.361(f)
(1) It must be encased in a gas tight conduit; 192.361(f)(1)
(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 192.361(f)(2)
(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. 192.361(f)(3)
(g) Locating underground service lines. Each underground nonmetallic service line that is not encased must have a means of locating the pipe that complies with §192.321(e). 192.361(g)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR 18517, Apr. 26, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]
§192.363
Service lines: Valve requirements
(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. 192.363(a)
(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. 192.363(b)
(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. 192.363(c)
§192.365 Service lines: Location of valves
(a) Relation to regulator or meter. Each service-line valve must be installed upstream of the regulator or, if there is no regulator, upstream of the meter. 192.365(a)
(b) Outside valves. Each service line must have a shut-off valve in a readily accessible location that, if feasible, is outside of the building. 192.365(b)
(c) Underground valves. Each underground service-line valve must be located in a covered durable curb box or standpipe that allows ready operation of the valve and is supported independently of the service lines. 192.365(c)
§192.367 Service lines: General requirements for connections to main piping
(a) Location. Each service line connection to a main must be located at the top of the main or, if that is not practical, at the side of the main, unless a suitable protective device is installed to minimize the possibility of dust and moisture being carried from the main into the service line. 192.367(a)
(b) Compression-type connection to main. Each compression-type service line to main connection must: 192.367(b)
(1) Be designed and installed to effectively sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping, or by anticipated external or internal loading; 192.367(b)(1)
(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; and 192.367(b)(2)
(3) If used on pipelines comprised of plastic, be a Category 1 connection as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than 25% elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard. 192.367(b)(3)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR 18517, Apr. 26, 1996; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]
§192.369 Service lines: Connections to cast iron or ductile iron mains
(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. 192.369(a)
(b) If a threaded tap is being inserted, the requirements of §192.151 (b) and (c) must also be met. 192.369(b)
§192.371 Service lines: Steel
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.
[Amdt. 192-1, 35 FR 17660, Nov. 17, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.373 Service lines: Cast iron and ductile iron
(a) Cast or ductile iron pipe less than 6 inches (152 millimeters) in diameter may not be installed for service lines. 192.373(a)
(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. 192.373(b)
(c) A cast iron or ductile iron service line may not be installed in unstable soil or under a building. 192.373(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, July 13, 1998]
§192.375 Service lines: Plastic
(a) Each plastic service line outside a building must be installed below ground level, except that — 192.375(a)
(1) It may be installed in accordance with §192.321(g); and 192.375(a)(1)
(2) It may terminate above ground level and outside the building, if — 192.375(a)(2)
(i) The above ground level part of the plastic service line is protected against deterioration and external damage;192.375(a)(2)(i)
(ii) The plastic service line is not used to support external loads; and192.375(a)(2)(ii)
(iii) The riser portion of the service line meets the design requirements of §192.204.192.375(a)(2)(iii)
(b) Each plastic service line inside a building must be protected against external damage. 192.375(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]
§192.376
Installation of plastic service lines by trenchless excavation
Plastic service lines installed by trenchless excavation must comply with the following:
(a) Each operator shall take practicable steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and structures at the time of installation. 192.376(a)
(b) For each pipeline section, plastic pipe and components that are pulled through the ground must use a weak link, as defined by §192.3, to ensure the pipeline will not be damaged by any excessive forces during the pulling process. 192.376(b)
[Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]
§192.377
Service lines: Copper
Each copper service line installed within a building must be protected against external damage.
§192.379
New service lines not in use
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. 192.379(a)
(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. 192.379(b)
(c) The customer's piping must be physically disconnected from the gas supply and the open pipe ends sealed. 192.379(c)
[Amdt. 192-8, 37 FR 20694, Oct. 3, 1972]
§192.381 Service lines: Excess flow valve performance standards
(a) Excess flow valves (EFVs) to be used on service lines that operate continuously throughout the year at a pressure not less than 10 p.s.i. (69 kPa) gage must be manufactured and tested by the manufacturer according to an industry specification, or the manufacturer's written specification, to ensure that each valve will: 192.381(a)
(1) Function properly up to the maximum operating pressure at which the valve is rated; 192.381(a)(1)
(2) Function properly at all temperatures reasonably expected in the operating environment of the service line; 192.381(a)(2)
(3) At 10 p.s.i. (69 kPa) gage: 192.381(a)(3)
(i) Close at, or not more than 50 percent above, the rated closure flow rate specified by the manufacturer; and192.381(a)(3)(i)
(ii) Upon closure, reduce gas flow — 192.381(a)(3)(ii)
[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 192.381(a)(3)(ii)[A]
[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); and192.381(a)(3)(ii)[B]
(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. 192.381(a)(4)
(b) An excess flow valve must meet the applicable requirements of Subparts B and D of this part. 192.381(b)
(c) An operator must mark or otherwise identify the presence of an excess flow valve in the service line. 192.381(c)
(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. 192.381(d)
(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. 192.381(e)
[Amdt. 192-79, 61 FR 31459, June 20, 1996, as amended by Amdt. 192-80, 62 FR 2619, Jan. 17, 1997; Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-121, 81 FR 71001, Oct. 14, 2016]
§192.383 Excess flow valve installation
(a) Definitions. As used in this section:
Branched service line means a gas service line that begins at the existing service line or is installed concurrently with the primary service line but serves a separate residence.
Replaced service line means a gas service line where the fitting that connects the service line to the main is replaced or the piping connected to this fitting is replaced.
Service line serving single-family residence means a gas service line that begins at the fitting that connects the service line to the main and serves only one single-family residence (SFR).
(b) Installation required. An EFV installation must comply with the performance standards in §192.381. After April 14, 2017, each operator must install an EFV on any new or replaced service line serving the following types of services before the line is activated: 192.383(b)
(1) A single service line to one SFR; 192.383(b)(1)
(2) A branched service line to a SFR installed concurrently with the primary SFR service line (i.e., a single EFV may be installed to protect both service lines); 192.383(b)(2)
(3) A branched service line to a SFR installed off a previously installed SFR service line that does not contain an EFV; 192.383(b)(3)
(4) Multifamily residences with known customer loads not exceeding 1,000 SCFH per service, at time of service installation based on installed meter capacity, and 192.383(b)(4)
(5) A single, small commercial customer served by a single service line with a known customer load not exceeding 1,000 SCFH, at the time of meter installation, based on installed meter capacity. 192.383(b)(5)
(c) Exceptions to excess flow valve installation requirement. An operator need not install an excess flow valve if one or more of the following conditions are present: 192.383(c)
(1) The service line does not operate at a pressure of 10 psig or greater throughout the year; 192.383(c)(1)
(2) The operator has prior experience with contaminants in the gas stream that could interfere with the EFV's operation or cause loss of service to a customer; 192.383(c)(2)
(3) An EFV could interfere with necessary operation or maintenance activities, such as blowing liquids from the line; or 192.383(c)(3)
(4) An EFV meeting the performance standards in §192.381 is not commercially available to the operator. 192.383(c)(4)
(d) Customer's right to request an EFV. Existing service line customers who desire an EFV on service lines not exceeding 1,000 SCFH and who do not qualify for one of the exceptions in paragraph (c) of this section may request an EFV to be installed on their service lines. If an eligible service line customer requests an EFV installation, an operator must install the EFV at a mutually agreeable date. The operator's ratesetter determines how and to whom the costs of the requested EFVs are distributed. 192.383(d)
(e) Operator notification of customers concerning EFV installation. Operators must notify customers of their right to request an EFV in the following manner: 192.383(e)
(1) Except as specified in paragraphs (c) and (e)(5) of this section, each operator must provide written or electronic notification to customers of their right to request the installation of an EFV. Electronic notification can include emails, Web site postings, and e-billing notices. 192.383(e)(1)
(2) The notification must include an explanation for the service line customer of the potential safety benefits that may be derived from installing an EFV. The explanation must include information that an EFV is designed to shut off the flow of natural gas automatically if the service line breaks. 192.383(e)(2)
(3) The notification must include a description of EFV installation and replacement costs. 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. 192.383(e)(3)
(4) The notification must indicate that if a service line customer requests installation of an EFV and the load does not exceed 1,000 SCFH and the conditions of paragraph (c) are not present, the operator must install an EFV at a mutually agreeable date. 192.383(e)(4)
(5) Operators of master-meter systems and liquefied petroleum gas (LPG) operators with fewer than 100 customers may continuously post a general notification in a prominent location frequented by customers. 192.383(e)(5)
(f) Operator evidence of customer notification. An operator must make a copy of the notice or notices currently in use available during PHMSA inspections or State inspections conducted under a pipeline safety program certified or approved by PHMSA under 49 U.S.C. 60105 or 60106. 192.383(f)
(g) Reporting. Except for operators of master-meter systems and LPG operators with fewer than 100 customers, each operator must report the EFV measures detailed in the annual report required by §191.11. 192.383(g)
§192.385 Manual service line shut-off valve installation
(a) Definitions. As used in this section:
Manual service line shut-off valve means a curb valve or other manually operated valve located near the service line that is safely accessible to operator personnel or other personnel authorized by the operator to manually shut off gas flow to the service line, if needed.
(b) Installation requirement. The operator must install either a manual service line shut-off valve or, if possible, based on sound engineering analysis and availability, an EFV for any new or replaced service line with installed meter capacity exceeding 1,000 SCFH. 192.385(b)
(c) Accessibility and maintenance. Manual service line shut-off valves for any new or replaced service line must be installed in such a way as to allow accessibility during emergencies. Manual service shut-off valves installed under this section are subject to regular scheduled maintenance, as documented by the operator and consistent with the valve manufacturer's specification. 192.385(c)
(a) This subpart prescribes minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion. 192.451(a)
(b) [Reserved] 192.451(b)
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-27, 41 FR 34606, Aug. 16, 1976; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978]
§192.452 How does this subpart apply to converted pipelines and regulated onshore gathering lines?
(a) Converted pipelines. 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. 192.452(a)
(b) Type A and B onshore gathering lines. For any Type A or Type B regulated onshore gathering line under §192.9 existing on April 14, 2006, that was not previously subject to this part, and for any onshore gathering line that becomes a regulated onshore gathering line under §192.9 after April 14, 2006, because of a change in class location or increase in dwelling density: 192.452(b)
(1) The requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, apply to the gathering line regardless of the date the pipeline was actually installed; and 192.452(b)(1)
(2) The requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply only if the pipeline substantially meets those requirements. 192.452(b)(2)
(c) Type C onshore regulated gathering lines. For any Type C onshore regulated gathering pipeline under §192.9 existing on May 16, 2022, that was not previously subject to this part, and for any Type C onshore gas gathering pipeline that becomes subject to this subpart
after May 16, 2022, because of an increase in MAOP, change in class location, or presence of a building intended for human occupancy or other impacted site: 192.452(c)
(1) The requirements of this subpart specifically applicable to pipelines installed before August 1, 1971, apply to the gathering line regardless of the date the pipeline was actually installed; and 192.452(c)(1)
(2) The requirements of this subpart specifically applicable to pipelines installed after July 31, 1971, apply only if the pipeline substantially meets those requirements. 192.452(c)(2)
(d) Regulated onshore gathering lines generally. Any gathering line that is subject to this subpart per §192.9 at the time of construction must meet the requirements of this subpart applicable to pipelines installed after July 31, 1971. 192.452(d)
[Amdt. 192-30, 42 FR 60148, Nov. 25, 1977, as amended by Amdt. 192-102, 71 FR 13303, Mar. 15, 2006]
§192.453 General
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.
[Amdt. 192-71, 59 FR 6584, Feb. 11, 1994]
§192.455 External corrosion control: Buried or submerged pipelines installed after July 31, 1971
(a) Except as provided in paragraphs (b), (c), (f), and (g) of this section, each buried or submerged pipeline installed after July 31, 1971, must be protected against external corrosion, including the following: 192.455(a)
(1) It must have an external protective coating meeting the requirements of §192.461. 192.455(a)(1)
(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. 192.455(a)(2)
(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. 192.455(b)
(c) An operator need not comply with paragraph (a) of this section, if the operator can demonstrate by tests, investigation, or experience that — 192.455(c)
(1) For a copper pipeline, a corrosive environment does not exist; or 192.455(c)(1)
(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. 192.455(c)(2)
(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. 192.455(d)
(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. 192.455(e)
(f) This section does not apply to electrically isolated, metal alloy fittings in plastic pipelines, if: 192.455(f)
(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 192.455(f)(1)
(2) The fitting is designed to prevent leakage caused by localized corrosion pitting. 192.455(f)(2)
(g) Electrically isolated metal alloy fittings installed after January 22, 2019, that do not meet the requirements of paragraph (f) must be cathodically protected, and must be maintained in accordance with the operator's integrity management plan. 192.455(g)
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended at Amdt. 192-28, 42 FR 35654, July 11, 1977; Amdt. 192-39, 47 FR 9844, Mar. 8, 1982; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]
§192.457 External corrosion control: Buried or submerged pipelines installed before August 1, 1971
(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. 192.457(a)
(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: 192.457(b)
(1) Bare or ineffectively coated transmission lines. 192.457(b)(1)
(2) Bare or coated pipes at compressor, regulator, and measuring stations. 192.457(b)(2)
(3) Bare or coated distribution lines. 192.457(b)(3)
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 FR 39390, Sept. 5, 1978; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]
§192.459
External corrosion control: Examination of buried pipeline when exposed
Whenever an operator has knowledge that any portion of a buried pipeline is exposed, the exposed portion must be examined for evidence of external corrosion if the pipe is bare, or if the coating is deteriorated. If external corrosion requiring remedial action under §§192.483 through 192.489 is found, the operator shall investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion.
(a) Each external protective coating, whether conductive or insulating, applied for the purpose of external corrosion control must — 192.461(a)
(1) Be applied on a properly prepared surface; 192.461(a)(1)
(2) Have sufficient adhesion to the metal surface to effectively resist underfilm migration of moisture; 192.461(a)(2)
(3) Be sufficiently ductile to resist cracking; 192.461(a)(3)
(4) Have sufficient strength to resist damage due to handling and soil stress; and 192.461(a)(4)
(5) Have properties compatible with any supplemental cathodic protection. 192.461(a)(5)
(b) Each external protective coating which is an electrically insulating type must also have low moisture absorption and high electrical resistance. 192.461(b)
(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. 192.461(c)
(d) Each external protective coating must be protected from damage resulting from adverse ditch conditions or damage from supporting blocks. 192.461(d)
(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. 192.461(e)
(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. 192.463(a)
(b) If amphoteric metals are included in a buried or submerged pipeline containing a metal of different anodic potential — 192.463(b)
(1) The amphoteric metals must be electrically isolated from the remainder of the pipeline and cathodically protected; or 192.463(b)(1)
(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. 192.463(b)(2)
(c) The amount of cathodic protection must be controlled so as not to damage the protective coating or the pipe. 192.463(c)
§192.465 External corrosion control: Monitoring
(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. 192.465(a)
(b) Cathodic protection rectifiers and impressed current power sources must be periodically inspected as follows: 192.465(b)
(1) Each cathodic protection rectifier or impressed current power source must be inspected six times each calendar year, but with intervals not exceeding 21⁄2 months between inspections, to ensure adequate amperage and voltage levels needed to provide cathodic protection are maintained. This may be done either through remote measurement or through an onsite inspection of the rectifier. 192.465(b)(1)
(2) After January 1, 2022, each remotely inspected rectifier must be physically inspected for continued safe and reliable operation at least once each calendar year, but with intervals not exceeding 15 months. 192.465(b)(2)
(c) Each reverse current switch, each diode, and each interference bond whose failure would jeopardize structure protection must be electrically checked for proper performance six times each calendar year, but with intervals not exceeding 21⁄2 months. Each other interference bond must be checked at least once each calendar year, but with intervals not exceeding 15 months. 192.465(c)
(d) Each operator shall take prompt remedial action to correct any deficiencies indicated by the monitoring. 192.465(d)
(e) After the initial evaluation required by §§192.455(b) and (c) and 192.457(b), each operator must, not less than every 3 years at intervals not exceeding 39 months, reevaluate its unprotected pipelines and cathodically protect them in accordance with this subpart in areas in which active corrosion is found. The operator must determine the areas of active corrosion by electrical survey. However, on distribution lines and where an electrical survey is impractical on transmission lines, areas of active corrosion may be determined by other means that include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. 192.465(e)
(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. 192.467(a)
(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. 192.467(b)
(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. 192.467(c)
(d) Inspection and electrical tests must be made to assure that electrical isolation is adequate. 192.467(d)
(e) An insulating device may not be installed in an area where a combustible atmosphere is anticipated unless precautions are taken to prevent arcing. 192.467(e)
(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. 192.467(f)
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 FR 39390, Sept. 5, 1978]
§192.469 External corrosion control: Test stations
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.
[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976]
§192.471 External corrosion control: Test leads
(a) Each test lead wire must be connected to the pipeline so as to remain mechanically secure and electrically conductive. 192.471(a)
(b) Each test lead wire must be attached to the pipeline so as to minimize stress concentration on the pipe. 192.471(b)
(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. 192.471(c)
(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. 192.473(a)
(b) Each impressed current type cathodic protection system or galvanic anode system must be designed and installed so as to minimize any adverse effects on existing adjacent underground metallic structures. 192.473(b)
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 FR 39390, Sept. 5, 1978]
§192.475 Internal corrosion control: General
(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. 192.475(a)
(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 — 192.475(b)
(1) The adjacent pipe must be investigated to determine the extent of internal corrosion; 192.475(b)(1)
(2) Replacement must be made to the extent required by the applicable paragraphs of §§192.485, 192.487, or 192.489; and 192.475(b)(2)
(3) Steps must be taken to minimize the internal corrosion. 192.475(b)(3)
(c) Gas containing more than 0.25 grain of hydrogen sulfide per 100 cubic feet (5.8 milligrams/m.3) at standard conditions (4 parts per million) may not be stored in pipe-type or bottle-type holders. 192.475(c)
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 FR 39390, Sept. 5, 1978; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.476 Internal corrosion control: Design and construction of transmission line
(a) Design and construction. Except as provided in paragraph (b) of this section, each new transmission line and each replacement of line pipe, valve, fitting, or other line component in a transmission line must have features incorporated into its design and construction to reduce the risk of internal corrosion. At a minimum, unless it is impracticable or unnecessary to do so, each new transmission line or replacement of line pipe, valve, fitting, or other line component in a transmission line must: 192.476(a)
(1) Be configured to reduce the risk that liquids will collect in the line; 192.476(a)(1)
(2) Have effective liquid removal features whenever the configuration would allow liquids to collect; and 192.476(a)(2)
(3) Allow use of devices for monitoring internal corrosion at locations with significant potential for internal corrosion. 192.476(a)(3)
(b) Exceptions to applicability. The design and construction requirements of paragraph (a) of this section do not apply to the following: 192.476(b)
(1) Offshore pipeline; and 192.476(b)(1)
(2) Pipeline installed or line pipe, valve, fitting or other line component replaced before May 23, 2007. 192.476(b)(2)
(c) Change to existing transmission line. When an operator changes the configuration of a transmission line, the operator must evaluate the impact of the change on internal corrosion risk to the downstream portion of an existing onshore transmission line and provide for removal of liquids and monitoring of internal corrosion as appropriate. 192.476(c)
(d) Records. An operator must maintain records demonstrating compliance with this section. Provided the records show why incorporating design features addressing paragraph (a)(1), (a)(2), or (a)(3) of this section is impracticable or unnecessary, an operator may fulfill this requirement through written procedures supported by as-built drawings or other construction records. 192.476(d)
[72 FR 20059, Apr. 23, 2007]
§192.477 Internal corrosion control: Monitoring
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 71⁄2 months.
[Amdt. 192-33, 43 FR 39390, Sept. 5, 1978]
§192.479 Atmospheric corrosion control: General
(a) Each operator must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section. 192.479(a)
(b) Coating material must be suitable for the prevention of atmospheric corrosion. 192.479(b)
(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, the operator need not protect from atmospheric corrosion any pipeline for which the operator demonstrates by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will — 192.479(c)
(1) Only be a light surface oxide; or 192.479(c)(1)
(2) Not affect the safe operation of the pipeline before the next scheduled inspection. 192.479(c)(2)
(a) Each operator must inspect and evaluate each pipeline or portion of the pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: 192.481(a)
(1) Onshore other than a Service Line At least once every 3 calendar years, but with intervals not exceeding 39 months.
(2) Onshore Service Line At least once every 5 calendar years, but with intervals not exceeding 63 months, except as provided in paragraph (d) of this section.
(3) OffshoreAt least once each calendar year, but with intervals not exceeding 15 months.
(b) During inspections the operator must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. 192.481(b)
(c) If atmospheric corrosion is found during an inspection, the operator must provide protection against the corrosion as required by §192.479. 192.481(c)
(d) If atmospheric corrosion is found on a service line during the most recent inspection, then the next inspection of that pipeline or portion of pipeline must be within 3 calendar years, but with intervals not exceeding 39 months. 192.481(d)
[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
§192.483 Remedial measures: General
(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. 192.483(a)
(b) Each segment of metallic pipe that replaces pipe removed from a buried or submerged pipeline because of external corrosion must be cathodically protected in accordance with this subpart. 192.483(b)
(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. 192.483(c)
§192.485
Remedial measures: Transmission lines
(a) General corrosion. Each segment of transmission line with general corrosion and with a remaining wall thickness less than that required for the MAOP of the pipeline must be replaced or the operating pressure reduced commensurate with the strength of the pipe based on actual remaining wall thickness. However, corroded pipe may be repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. Corrosion pitting so closely grouped as to affect the overall strength of the pipe is considered general corrosion for the purpose of this paragraph. 192.485(a)
(b) Localized corrosion pitting. Each segment of transmission line pipe with localized corrosion pitting to a degree where leakage might result 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. 192.485(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 (incorporated by reference, see §192.7) or the procedure in PRCI PR 3-805 (R-STRENG) (incorporated by reference, see §192.7). Both procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations prescribed in the procedures. 192.485(c)
Remedial measures: Distribution lines other than cast iron or ductile iron lines
(a) General corrosion. Except for cast iron or ductile iron pipe, each segment of generally corroded distribution line pipe with a remaining wall thickness less than that required for the MAOP of the pipeline, or a remaining wall thickness less than 30 percent of the nominal wall thickness, must be replaced. However, corroded pipe may be repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. Corrosion pitting so closely grouped as to affect the overall strength of the pipe is considered general corrosion for the purpose of this paragraph. 192.487(a)
(b) Localized corrosion pitting. Except for cast iron or ductile iron pipe, each segment of distribution line pipe with localized corrosion pitting to a degree where leakage might result must be replaced or repaired.
192.487(b)
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]
§192.489 Remedial measures: Cast iron and ductile iron pipelines
(a) General graphitization. Each segment of cast iron or ductile iron pipe on which general graphitization is found to a degree where a fracture or any leakage might result, must be replaced. 192.489(a)
(b) Localized graphitization. Each segment of cast iron or ductile iron pipe on which localized graphitization is found to a degree where any leakage might result, must be replaced or repaired, or sealed by internal sealing methods adequate to prevent or arrest any leakage.
192.489(b)
§192.490 Direct assessment
Each operator that uses direct assessment as defined in §192.903 on an onshore transmission line made primarily of steel or iron to evaluate the effects of a threat in the first column must carry out the direct assessment according to the standard listed in the second column. These standards do not apply to methods associated with direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process.
1For lines not subject to subpart O of this part, the terms "covered segment" and "covered pipeline segment" in §§192.925, 192.927, and 192.929 refer to the pipeline segment on which direct assessment is performed.
2In §192.925(b), the provision regarding detection of coating damage applies only to pipelines subject to subpart O of this part.
[Amdt. 192-101, 70 FR 61575, Oct. 25, 2005]
§192.491 Corrosion control records
(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. 192.491(a)
(b) Each record or map required by paragraph (a) of this section must be retained for as long as the pipeline remains in service. 192.491(b)
(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 with the following exceptions: 192.491(c)
(1) Operators must retain records related to §§192.465(a) and (e) and 192.475(b) for as long as the pipeline remains in service. 192.491(c)(1)
(2) Operators must retain records of the two most recent atmospheric corrosion inspections for each distribution service line that is being inspected under the interval in §192.481(a)(2). 192.491(c)(2)
[Amdt. 192-78, 61 FR 28785, June 6, 1996]
§192.493 In-line inspection of pipelines.
When conducting in-line inspections of pipelines required by this part, an operator must comply with API STD 1163, ANSI/ASNT ILI-PQ, and NACE SP0102, (incorporated by reference, see §192.7). Assessments may be conducted using tethered or remotely controlled tools, not explicitly discussed in NACE SP0102, provided they comply with those sections of NACE SP0102 that are applicable.
Pipeline type: Then the frequency of inspection is:
Subpart J – Test Requirements
§192.501 Scope
This subpart prescribes minimum leak-test and strength-test requirements for pipelines.
§192.503 General requirements
(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 — 192.503(a)
(1) It has been tested in accordance with this subpart and §192.619 to substantiate the maximum allowable operating pressure; and 192.503(a)(1)
(2) Each potentially hazardous leak has been located and eliminated. 192.503(a)(2)
(b) The test medium must be liquid, air, natural gas, or inert gas that is — 192.503(b)
(1) Compatible with the material of which the pipeline is constructed; 192.503(b)(1)
(2) Relatively free of sedimentary materials; and 192.503(b)(2)
(3) Except for natural gas, nonflammable. 192.503(b)(3)
(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: 192.503(c)
(a) Spike test requirements. Whenever a segment of steel transmission pipeline that is operated at a hoop stress level of 30 percent or more of SMYS is spike tested under this part, the spike hydrostatic pressure test must be conducted in accordance with this section. 192.506(a)
(1) The test must use water as the test medium. 192.506(a)(1)
(2) The baseline test pressure must be as specified in the applicable paragraphs of §192.619(a)(2) or §192.620(a)(2), whichever applies. 192.506(a)(2)
(3) The test must be conducted by maintaining a pressure at or above the baseline test pressure for at least 8 hours as specified in §192.505. 192.506(a)(3)
(4) After the test pressure stabilizes at the baseline pressure and within the first 2 hours of the 8-hour test interval, the hydrostatic pressure must be raised (spiked) to a minimum of the lesser of 1.5 times MAOP or 100% SMYS. This spike hydrostatic pressure test must be held for at least 15 minutes after the spike test pressure stabilizes. 192.506(a)(4)
(b) Other technology or other technical evaluation process. Operators may use other technology or another process supported by a documented engineering analysis for establishing a spike hydrostatic pressure test or equivalent. Operators must notify PHMSA 90 days in advance of the assessment or reassessment requirements of this subchapter. The notification must be made in accordance with §192.18 and must include the following information: 192.506(b)
(1) Descriptions of the technology or technologies to be used for all tests, examinations, and assessments; 192.506(b)(1)
(2) Procedures and processes to conduct tests, examinations, assessments, perform evaluations, analyze defects, and remediate defects discovered; 192.506(b)(2)
(3) Data requirements, including original design, maintenance and operating history, anomaly or flaw characterization; 192.506(b)(3)
(4) Assessment techniques and acceptance criteria; 192.506(b)(4)
(5) Remediation methods for assessment findings; 192.506(b)(5)
(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. 192.503(d)
(e) 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: 192.503(e)
(1) The component was tested to at least the pressure required for the pipeline to which it is being added; 192.503(e)(1)
(2) The component was manufactured under a quality control system that ensures that each item manufactured is at least equal in strength to a prototype and that the prototype was tested to at least the pressure required for the pipeline to which it is being added; or 192.503(e)(2)
(3) The component carries a pressure rating established through applicable ASME/ANSI, Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS) specifications, or by unit strength calculations as described in §192.143. 192.503(e)(3)
§192.505 Strength test requirements for steel pipelines to operate at a hoop stress of 30 percent or more of SMYS.
(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. 192.505(a)
(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. 192.505(b)
(c) Except as provided in paragraph (d) of this section, the strength test must be conducted by mai ntaining the pressure at or above the test pressure for at least 8 hours. 192.505(c)
(d) For fabricated units and short sections of pipe, for which a post installation test is impractical, a preinstallation strength test must be conducted by maintaining the pressure at or above the test pressure for at least 4 hours. 192.505(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-94, 69 FR 32895, June 14, 2004; Amdt. 195-94, 69 FR 54592, Sept. 9, 2004; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]
(6) Spike hydrostatic pressure test monitoring and acceptance procedures, if used; 192.506(b)(6)
(7) Procedures for remaining crack growth analysis and pipeline segment life analysis for the time interval for additional assessments, as required; and 192.506(b)(7)
(8) Evidence of a review of all procedures and assessments by a qualified technical subject matter expert. 192.506(b)(8)
§192.507 Test requirements for pipelines to operate at a hoop stress less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage
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. 192.507(a)
(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 — 192.507(b)
(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 192.507(b)(1)
(2) The line must be walked to check for leaks while the hoop stress is held at approximately 20 percent of SMYS. 192.507(b)(2)
(c) The pressure must be maintained at or above the test pressure for at least 1 hour. 192.507(c)
(d) For fabricated units and short sections of pipe, for which a post installation test is impractical, a pre-installation hydrostatic pressure test must be conducted in accordance with the requirements of this section. 192.507(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.509 Test requirements for pipelines to operate below 100 p.s.i. (689 kPa) gage
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. 192.509(a)
Class location Maximum hoop stress allowed as percentage of SMYS
(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. 192.509(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.511 Test requirements for service lines
(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. 192.511(a)
(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. 192.511(b)
(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. 192.511(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-74, 61 FR 18517, Apr. 26, 1996; Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.513 Test requirements for plastic pipelines
(a) Each segment of a plastic pipeline must be tested in accordance with this section. 192.513(a)
(b) The test procedure must insure discovery of all potentially hazardous leaks in the segment being tested. 192.513(b)
(c) The test pressure must be at least 150% of the maximum operating pressure or 50 psi (345 kPa) gauge, whichever is greater. However, the maximum test pressure may not be more than 2.5 times the pressure determined under §192.121 at a temperature not less than the pipe temperature during the test. 192.513(c)
(d) During the test, the temperature of thermoplastic material may not be more than 100 °F (38 °C), or the temperature at which the material's long-term hydrostatic strength has been determined under the listed specification, whichever is greater. 192.513(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-77, 61 FR 27793, June 3, 1996; 61 FR 45905, Aug. 30, 1996; Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]
§192.515
Environmental protection and safety requirements
(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. 192.515(a)
(b) The operator shall insure that the test medium is disposed of in a manner that will minimize damage to the environment. 192.515(b)
§192.517 Records: Tests.
(a) An operator must make, and retain for the useful life of the pipeline, a record of each test performed under §§192.505, 192.506, and 192.507. The record must contain at least the following information: 192.517(a)
(1) The operator's name, the name of the operator's employee responsible for making the test, and the name of any test company used.
192.517(a)(1)
(2) Test medium used. 192.517(a)(2)
(3) Test pressure. 192.517(a)(3)
(4) Test duration. 192.517(a)(4)
(5) Pressure recording charts, or other record of pressure readings.
192.517(a)(5)
(6) Elevation variations, whenever significant for the particular test.
192.517(a)(6)
(7) Leaks and failures noted and their disposition. 192.517(a)(7)
(b) Each operator must maintain a record of each test required by §§192.509, 192.511, and 192.513 for at least 5 years. 192.517(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
Subpart K – Uprating
§192.551 Scope
This subpart prescribes minimum requirements for increasing maximum allowable operating pressures (uprating) for pipelines.
§192.553 General requirements
(a) Pressure increases. Whenever the requirements of this subpart require that an increase in operating pressure be made in increments, the pressure must be increased gradually, at a rate that can be controlled, and in accordance with the following: 192.553(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. 192.553(a)(1)
(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. 192.553(a)(2)
(b) Records. Each operator who uprates a segment of pipeline shall retain for the life of the segment a record of each investigation required by this subpart, of all work performed, and of each pressure test conducted, in connection with the uprating. 192.553(b)
(c) Written plan. Each operator who uprates a segment of pipeline shall establish a written procedure that will ensure that each applicable requirement of this subpart is complied with. 192.553(c)
(d) Limitation on increase in maximum allowable operating pressure. Except as provided in §192.555(c), a new maximum allowable operating pressure established under this subpart may not exceed the maximum that would be allowed under §§192.619 and 192.621 for a new segment of pipeline constructed of the same materials in the same location. However, when uprating a steel pipeline, if any variable necessary to determine the design pressure under the design formula §192.105) is unknown, the MAOP may be increased as provided in §192.619(a)(1). 192.553(d)
[35 FR 13257, Aug. 10, 1970, as amended by Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
§192.555 Uprating to a pressure that will produce a hoop stress of 30 percent or more of SMYS in steel pipelines
(a) Unless the requirements of this section have been met, no person may subject any segment of a steel pipeline to an operating pressure that will produce a hoop stress of 30 percent or more of SMYS and that is above the established maximum allowable operating pressure. 192.555(a)
(b) Before increasing operating pressure above the previously established maximum allowable operating pressure the operator shall: 192.555(b)
(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 192.555(b)(1)
(2) Make any repairs, replacements, or alterations in the segment of pipeline that are necessary for safe operation at the increased pressure. 192.555(b)(2)
(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). 192.555(c)
(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: 192.555(d)
(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. 192.555(d)(1)
(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: 192.555(d)(2)
(i) It is impractical to test it in accordance with the requirements of this part;192.555(d)(2)(i)
(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; and192.555(d)(2)(ii)
(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. 192.555(d)(2)(iii)
(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: 192.555(e)
(1) 10 percent of the pressure before the uprating; or 192.555(e)(1)
(2) 25 percent of the total pressure increase, whichever produces the fewer number of increments. 192.555(e)(2)
§192.557 Uprating: Steel pipelines to a pressure that will produce a hoop stress less than 30 percent of SMYS: plastic, cast iron, and ductile iron pipelines
(a) Unless the requirements of this section have been met, no person may subject: 192.557(a)
(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 192.557(a)(1)
(2) A plastic, cast iron, or ductile iron pipeline segment to an operating pressure that is above the previously established maximum allowable operating pressure. 192.557(a)(2)
(b) Before increasing operating pressure above the previously established maximum allowable operating pressure, the operator shall: 192.557(b)
(1) Review the design, operating, and maintenance history of the segment of pipeline; 192.557(b)(1)
(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; 192.557(b)(2)
(3) Make any repairs, replacements, or alterations in the segment of pipeline that are necessary for safe operation at the increased pressure; 192.557(b)(3)
(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; 192.557(b)(4)
(5) Isolate the segment of pipeline in which the pressure is to be increased from any adjacent segment that will continue to be operated at a lower pressure; and 192.557(b)(5)
(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. 192.557(b)(6)
(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. 192.557(c)
(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: 192.557(d)
(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. 192.557(d)(1)
(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. 192.557(d)(2)
(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: 192.557(d)(3)
(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. 192.557(d)(4)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10160, Feb. 2, 1981; Amdt. 192-62, 54 FR 5628, Feb. 6, 1989; Amdt. 195-85, 63 FR 37504, July 13, 1998]
Subpart L – Operations
§192.601 Scope
This subpart prescribes minimum requirements for the operation of pipeline facilities.
§192.603 General provisions
(a) No person may operate a segment of pipeline unless it is operated in accordance with this subpart. 192.603(a)
(b) Each operator shall keep records necessary to administer the procedures established under §192.605. 192.603(b)
(c) The Associate Administrator or the State Agency that has submitted a current certification under the pipeline safety laws, (49 U.S.C. 60101 et seq.) 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 190.206 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety. 192.603(c)
§192.605 Procedural manual for operations, maintenance, and emergencies
(a) General. Each operator shall prepare and follow for each pipeline, a manual of written procedures for conducting operations and maintenance activities and for emergency response. For transmission lines, the manual must also include procedures for handling abnormal operations. This manual must be reviewed and updated by the operator at intervals not exceeding 15 months, but at least once each calendar year. This manual must be prepared before operations of a pipeline system commence. Appropriate parts of the manual must be kept at locations where operations and maintenance activities are conducted. 192.605(a)
(b) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following, if applicable, to provide safety during maintenance and operations. 192.605(b)
(1) Operating, maintaining, and repairing the pipeline in accordance with each of the requirements of this subpart and subpart M of this part. 192.605(b)(1)
(2) Controlling corrosion in accordance with the operations and maintenance requirements of subpart I of this part. 192.605(b)(2)
(3) Making construction records, maps, and operating history available to appropriate operating personnel. 192.605(b)(3)
(4) Gathering of data needed for reporting incidents under Part 191 of this chapter in a timely and effective manner. 192.605(b)(4)
(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. 192.605(b)(5)
(6) Maintaining compressor stations, including provisions for isolating units or sections of pipe and for purging before returning to service. 192.605(b)(6)
(7) Starting, operating and shutting down gas compressor units. 192.605(b)(7)
(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. 192.605(b)(8)
(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. 192.605(b)(9)
3
(10) Systematic and routine testing and inspection of pipe-type or bottle-type holders including — 192.605(b)(10)
(i) Provision for detecting external corrosion before the strength of the container has been impaired;192.605(b)(10)(i)
(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; and192.605(b)(10)(ii)
(iii) Periodic inspection and testing of pressure limiting equipment to determine that it is in safe operating condition and has adequate capacity.192.605(b)(10)(iii)
(11) Responding promptly to a report of a gas odor inside or near a building, unless the operator's emergency procedures under §192.615(a)(3) specifically apply to these reports. 192.605(b)(11)
(12) Implementing the applicable control room management procedures required by §192.631. 192.605(b)(12)
(c) Abnormal operation. For transmission lines, the manual required by paragraph (a) of this section must include procedures for the following to provide safety when operating design limits have been exceeded: 192.605(c)
(1) Responding to, investigating, and correcting the cause of: 192.605(c)(1)
(i) Unintended closure of valves or shutdowns;192.605(c)(1)(i)
(ii) Increase or decrease in pressure or flow rate outside normal operating limits;192.605(c)(1)(ii)
(iii) Loss of communications;192.605(c)(1)(iii)
(iv) Operation of any safety device; and192.605(c)(1)(iv)
(v) Any other foreseeable malfunction of a component, deviation from normal operation, or personnel error, which may result in a hazard to persons or property.192.605(c)(1)(v)
(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. 192.605(c)(2)
(3) Notifying responsible operator personnel when notice of an abnormal operation is received. 192.605(c)(3)
(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. 192.605(c)(4)
(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. 192.605(c)(5)
(d) Safety-related condition reports. The manual required by paragraph (a) of this section must include 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. 192.605(d)
(e) Surveillance, emergency response, and accident investigation. The procedures required by §§192.613(a), 192.615, and 192.617 must be included in the manual required by paragraph (a) of this section. 192.605(e)
§192.607 Verification of Pipeline Material Properties and Attributes: Onshore steel transmission pipelines.
(a) Applicability. Wherever required by this part, operators of onshore steel transmission pipelines must document and verify material properties and attributes in accordance with this section.
(b) Documentation of material properties and attributes. Records established under this section documenting physical pipeline characteristics and attributes, including diameter, wall thickness, seam type, and grade (e.g., yield strength, ultimate tensile strength, or pressure rating for valves and flanges, etc.), must be maintained for the life of the pipeline and be traceable, verifiable, and complete. Charpy v-notch toughness values established under this section needed to meet the requirements of the ECA method at §192.624(c)(3) or the fracture mechanics requirements at §192.712 must be maintained for the life of the pipeline.
(c) Verification of material properties and attributes. If an operator does not have traceable, verifiable, and complete records required by paragraph (b) of this section, the operator must develop and implement procedures for conducting nondestructive or destructive tests, examinations, and assessments in order to verify the material properties of aboveground line pipe and components, and of buried line pipe and components when excavations occur at the following opportunities: Anomaly direct examinations, in situ evaluations, repairs, remediations, maintenance, and excavations that are associated with replacements or relocations of pipeline segments that are removed from service. The procedures must also provide for the following:
(1) For nondestructive tests, at each test location, material properties for minimum yield strength and ultimate tensile strength must be determined at a minimum of 5 places in at least 2 circumferential quadrants of the pipe for a minimum total of 10 test readings at each pipe cylinder location.
(2) For destructive tests, at each test location, a set of material properties tests for minimum yield strength and ultimate tensile strength must be conducted on each test pipe cylinder removed from each location, in accordance with API Specification 5L.
(3) Tests, examinations, and assessments must be appropriate for verifying the necessary material properties and attributes.
(4) If toughness properties are not documented, the procedures must include accepted industry methods for verifying pipe material toughness.
(5) Verification of material properties and attributes for non-line pipe components must comply with paragraph (f) of this section.
(d) Special requirements for nondestructive Methods. Procedures developed in accordance with paragraph (c) of this section for verification of material properties and attributes using nondestructive methods must:
(1) Use methods, tools, procedures, and techniques that have been validated by a subject matter expert based on comparison with destructive test results on material of comparable grade and vintage;
(2) Conservatively account for measurement inaccuracy and uncertainty using reliable engineering tests and analyses; and
(3) Use test equipment that has been properly calibrated for comparable test materials prior to usage.
(e) Sampling multiple segments of pipe. To verify material properties and attributes for a population of multiple, comparable segments of pipe without traceable, verifiable, and complete records, an operator may use a sampling program in accordance with the following requirements:
(1) The operator must define separate populations of similar segments of pipe for each combination of the following material properties and attributes: Nominal wall thicknesses, grade, manufacturing process, pipe manufacturing dates, and construction dates. If the dates between the manufacture or construction of the pipeline segments exceeds 2 years, those segments cannot be considered as the same vintage for the purpose of defining a population under this section. The total population mileage is the cumulative mileage of pipeline segments in the population. The pipeline segments need not be continuous.
(2) For each population defined according to paragraph (e)(1) of this section, the operator must determine material properties at all excavations that expose the pipe associated with anomaly direct examinations, in situ evaluations, repairs, remediations, or maintenance, except for pipeline segments exposed during excavation activities pursuant to §192.614, until completion of the lesser of the following:
(i) One excavation per mile rounded up to the nearest whole number; or
(ii) 150 excavations if the population is more than 150 miles.
(3) Prior tests conducted for a single excavation according to the requirements of paragraph (c) of this section may be counted as one sample under the sampling requirements of this paragraph (e).
(4) If the test results identify line pipe with properties that are not consistent with available information or existing expectations or assumed properties used for operations and maintenance in the past, the operator must establish an expanded sampling program. The expanded sampling program must use valid statistical bases designed to achieve at least a 95% confidence level that material properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an expanded sampling approach in accordance with §192.18.
(5) An operator may use an alternative statistical sampling approach that differs from the requirements specified in paragraph (e)(2) of this section. The alternative sampling program must use valid statistical bases designed to achieve at least a 95% confidence level that material properties used in the operation and maintenance of the pipeline are valid. The approach must address how the sampling plan will be expanded to address findings that reveal material properties that are not consistent with all available information or existing expectations or assumed material properties used for pipeline operations and maintenance in the past. Operators must notify PHMSA in advance of using an alternative sampling approach in accordance with §192.18.
(f) Components. For mainline pipeline components other than line pipe, an operator must develop and implement procedures in accordance with paragraph (c) of this section for establishing and documenting the ANSI rating or pressure rating (in accordance with ASME/ANSI B16.5 (incorporated by reference, see §192.7)),
(1) Operators are not required to test for the chemical and mechanical properties of components in compressor stations, meter stations, regulator stations, separators, river crossing headers, mainline valve assemblies, valve operator piping, or cross-connections with isolation valves from the mainline pipeline.
(2) Verification of material properties is required for non-line pipe components, including valves, flanges, fittings, fabricated assemblies, and other pressure retaining components and appurtenances that are:
(i) Larger than 2 inches in nominal outside diameter, (ii) Material grades of 42,000 psi (Grade X-42) or greater, or (iii) Appurtenances of any size that are directly installed on the pipeline and cannot be isolated from mainline pipeline pressures.
(3) Procedures for establishing material properties of non-line pipe components must be based on the documented manufacturing specification for the components. If specifications are not known, usage of manufacturer's stamped, marked, or tagged material pressure ratings and material type may be used to establish pressure rating. Operators must document the method used to determine the pressure rating and the findings of that determination.
(g) Uprating. The material properties determined from the destructive or nondestructive tests required by this section cannot be used to raise the grade or specification of the material, unless the original grade or specification is unknown and MAOP is based on an assumed yield strength of 24,000 psi in accordance with §192.107(b)(2).
§192.609
Change in class location: Required study
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. 192.609(a)
(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. 192.609(b)
(c) The physical condition of the segment to the extent it can be ascertained from available records; 192.609(c)
(d) The operating and maintenance history of the segment; 192.609(d)
(e) The maximum actual operating pressure and the corresponding operating hoop stress, taking pressure gradient into account, for the segment of pipeline involved; and 192.609(e)
(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. 192.609(f)
§192.610 Change in class location: Change in valve spacing.
(a) If a class location change on a transmission pipeline occurs after October 5, 2022, and results in pipe replacement, of 2 or more miles, in the aggregate, within any 5 contiguous miles within a 24month period, to meet the maximum allowable operating pressure (MAOP) requirements in §192.611, §192.619, or §192.620, then the requirements in §§192.179, 192.634, and 192.636, as applicable, apply to the new class location, and the operator must install valves, including rupture-mitigation valves (RMV) or alternative equivalent technologies, as necessary, to comply with those sections. Such valves must be installed within 24 months of the class location change in accordance with the timing requirement in §192.611(d) for compliance after a class location change. 192.610(a)
(b) If a class location change occurs after October 5, 2022, and results in pipe replacement of less than 2 miles within 5 contiguous miles during a 24-month period, to meet the MAOP requirements in §192.611, §192.619, or §192.620, then within 24 months of the class location change, in accordance with §192.611(d), the operator must either: 192.610(b)
(1) Comply with the valve spacing requirements of §192.179(a) for the replaced pipeline segment; or 192.610(b)(1)
(2) Install or use existing RMVs or alternative equivalent technologies so that the entirety of the replaced pipeline segments are between at least two RMVs or alternative equivalent technologies. The distance between RMVs and alternative equivalent technologies for the replaced segment must not exceed 20 miles. The RMVs and alternative equivalent technologies must comply with the applicable requirements of §192.636. 192.610(b)(2)
(c) The provisions of paragraph (b) of this section do not apply to pipeline replacements that amount to less than 1,000 feet within any one contiguous mile during any 24-month period. 192.610(c)
§192.611 Change in class location: Confirmation or revision of maximum allowable operating pressure
(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: 192.611(a)
(1) If the segment involved has been previously tested in place for a period of not less than 8 hours: 192.611(a)(1)
(i) The maximum allowable operating pressure is 0.8 times the test pressure in Class 2 locations, 0.667 times the test pressure in Class 3 locations, or 0.555 times the test pressure in Class 4 locations. The corresponding hoop stress may not exceed 72 percent of the SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 50 percent of SMYS in Class 4 locations.192.611(a)(1)(i)
(ii) The alternative maximum allowable operating pressure is 0.8 times the test pressure in Class 2 locations and 0.667 times the test pressure in Class 3 locations. For pipelines operating at alternative maximum allowable pressure per §192.620, the corresponding hoop stress may not exceed 80 percent of the SMYS of the pipe in Class 2 locations and 67 percent of SMYS in Class 3 locations.192.611(a)(1)(ii)
(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. 192.611(a)(2)
(3) The segment involved must be tested in accordance with the applicable requirements of subpart J of this part, and its maximum allowable operating pressure must then be established according to the following criteria: 192.611(a)(3)
(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.192.611(a)(3)(i)
(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. 192.611(a)(3)(ii)
(iii) For pipeline operating at an alternative maximum allowable operating pressure per §192.620, the alternative maximum allowable operating pressure after the requalification test is 0.8 times the test pressure for Class 2 locations and 0.667 times the test pressure for Class 3 locations. The corresponding hoop stress may not exceed 80 percent of the SMYS of the pipe in Class 2 locations and 67 percent of SMYS in Class 3 locations. 192.611(a)(3)(iii)
(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. 192.611(b)
(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. 192.611(c)
(d) Confirmation or revision of the maximum allowable operating pressure that is required as a result of a study under §192.609 must be completed within 24 months of the change in class location. Pressure reduction under paragraph (a) (1) or (2) of this section within the 24month period does not preclude establishing a maximum allowable operating pressure under paragraph (a)(3) of this section at a later date. 192.611(d)
[Amdt. 192-63A, 54 FR 24174, June 6, 1989, as amended by Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-94, 69 FR 32895, June 14, 2004; 73 FR 62177, Oct. 17, 2008]
§192.612 Underwater inspection and reburial of pipelines in the Gulf of Mexico and its inlets
(a) Each operator shall prepare and follow a procedure to identify its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water that are at risk of being an exposed underwater pipeline or a hazard to navigation. The procedures must be in effect August 10, 2005. 192.612(a)
(b) Each operator shall conduct appropriate periodic underwater inspections of its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water based on the identified risk. 192.612(b)
(c) If an operator discovers that its pipeline is an exposed underwater pipeline or poses a hazard to navigation, the operator shall — 192.612(c)
(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. 192.612(c)(1)
(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 192.612(c)(2)
(3) Within 6 months after discovery, or not later than November 1 of the following year if the 6 month period is later than November 1 of the year of discovery, bury the pipeline so that the top of the pipe is 36 inches (914 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) for normal excavation or 18 inches (457 millimeters) for rock excavation. 192.612(c)(3)
(i) An operator may employ engineered alternatives to burial that meet or exceed the level of protection provided by burial. 192.612(c)(3)(i)
(ii) If an operator cannot obtain required state or Federal permits in time to comply with this section, it must notify OPS; specify whether the required permit is State or Federal; and, justify the delay.192.612(c)(3)(ii)
[Amdt. 192-98, 69 FR 48406, Aug. 10, 2004]
§192.613
Continuing surveillance
(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. 192.613(a)
(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). 192.613(b)
§192.614 Damage prevention program
(a) Except as provided in paragraphs (d) and (e) of this section, each operator of a buried pipeline must carry out, in accordance with this section, a written program to prevent damage to that pipeline from excavation activities. For the purposes of this section, the term "excavation activities" includes excavation, blasting, boring, tunneling, backfilling, the removal of aboveground structures by either explosive or mechanical means, and other earthmoving operations. 192.614(a)
(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. 192.614(b)
(1) The state has adopted a one-call damage prevention program under §198.37 of this chapter; or 192.614(b)(1)
(2) The one-call system: 192.614(b)(2)
(i) Is operated in accordance with §198.39 of this chapter; 192.614(b)(2)(i)
(ii) Provides a pipeline operator an opportunity similar to a voluntary participant to have a part in management responsibilities; and192.614(b)(2)(ii)
(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.192.614(b)(2)(iii)
(c) The damage prevention program required by paragraph (a) of this section must, at a minimum: 192.614(c)
(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. 192.614(c)(1)
(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: 192.614(c)(2)
(i) The program's existence and purpose; and192.614(c)(2)(i)
(ii) How to learn the location of underground pipelines before excavation activities are begun.192.614(c)(2)(ii)
(3) Provide a means of receiving and recording notification of planned excavation activities. 192.614(c)(3)
(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. 192.614(c)(4)
(5) Provide for temporary marking of buried pipelines in the area of excavation activity before, as far as practical, the activity begins. 192.614(c)(5)
(6) Provide as follows for inspection of pipelines that an operator has reason to believe could be damaged by excavation activities: 192.614(c)(6)
(i) The inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline; and 192.614(c)(6)(i)
(ii) In the case of blasting, any inspection must include leakage surveys.192.614(c)(6)(ii)
(d) A damage prevention program under this section is not required for the following pipelines: 192.614(d)
(1) Pipelines located offshore. 192.614(d)(1)
(2) Pipelines, other than those located offshore, in Class 1 or 2 locations until September 20, 1995. 192.614(d)(2)
(3) Pipelines to which access is physically controlled by the operator. 192.614(d)(3)
(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: 192.614(e)
(1) The requirement of paragraph (a) of this section that the damage prevention program be written; and 192.614(e)(1)
(2) The requirements of paragraphs (c)(1) and (c)(2) of this section. 192.614(e)(2)
[Amdt. 192-40, 47 FR 13824, Apr. 1, 1982, as amended by Amdt. 192-57, 52 FR 32800, Aug. 31, 1987; Amdt. 192-73, 60 FR 14650, Mar. 20, 1995; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt.192-82, 62 FR 61699, Nov. 19, 1997; Amdt. 192-84, 63 FR 38758, July 20, 1998]
§192.615 Emergency plans
(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: 192.615(a)
(1) Receiving, identifying, and classifying notices of events which require immediate response by the operator. 192.615(a)(1)
(2) Establishing and maintaining adequate means of communication with the appropriate public safety answering point (i.e., 9-1-1 emergency call center), where direct access to a 9-1-1 emergency call center is available from the location of the pipeline, and fire, police, and other public officials. Operators may establish liaison with the appropriate local emergency coordinating agencies, such as 9-1-1 emergency call centers or county emergency managers, in lieu of communicating individually with each fire, police, or other public entity. An operator must determine the responsibilities, resources, jurisdictional area(s), and emergency contact telephone number(s) for both local and out-of-area calls of each Federal, State, and local government organization that may respond to a pipeline emergency, and inform such officials about the operator's ability to respond to a pipeline emergency and the means of communication during emergencies. 192.615(a)(2)
(3) Prompt and effective response to a notice of each type of emergency, including the following: 192.615(a)(3)
(i) Gas detected inside or near a building.192.615(a)(3)(i)
(ii) Fire located near or directly involving a pipeline facility. 192.615(a)(3)(ii)
(iii) Explosion occurring near or directly involving a pipeline facility. 192.615(a)(3)(iii)
(iv) Natural disaster.192.615(a)(3)(iv)
(4) The availability of personnel, equipment, tools, and materials, as needed at the scene of an emergency. 192.615(a)(4)
(5) Actions directed toward protecting people first and then property. 192.615(a)(5)
(6) Taking necessary actions, including but not limited to, emergency shutdown, valve shut-off, or pressure reduction, in any section of the operator's pipeline system, to minimize hazards of released gas to life, property, or the environment. 192.615(a)(6)
(7) Making safe any actual or potential hazard to life or property. 192.615(a)(7)
(8) Notifying the appropriate public safety answering point (i.e., 9-11 emergency call center) where direct access to a 9-1-1 emergency call center is available from the location of the pipeline, and fire, police, and other public officials, of gas pipeline emergencies to coordinate and share information to determine the location of the emergency, including both planned responses and actual responses during an emergency. The operator must immediately and directly notify the appropriate public safety answering point or other coordinating agency for the communities and jurisdictions in which the pipeline is located after receiving a notification of potential rupture, as defined in §192.3, to coordinate and share information to
§192.617 Part 192 – Minimum Federal Safety Standards
determine the location of any release, regardless of whether the segment is subject to the requirements of §192.179, §192.634, or §192.636. 192.615(a)(8)
(9) Safely restoring any service outage. 192.615(a)(9)
(10) Beginning action under §192.617, if applicable, as soon after the end of the emergency as possible. 192.615(a)(10)
(11) Actions required to be taken by a controller during an emergency in accordance with the operator's emergency plans and requirements set forth in §§192.631, 192.634, and 192.636. 192.615(a)(11)
(12) Each operator must develop written rupture identification procedures to evaluate and identify whether a notification of potential rupture, as defined in §192.3, is an actual rupture event or a non-rupture event. These procedures must, at a minimum, specify the sources of information, operational factors, and other criteria that operator personnel use to evaluate a notification of potential rupture and identify an actual rupture. For operators installing valves in accordance with §192.179(e), §192.179(f), or that are subject to the requirements in §192.634, those procedures must provide for rupture identification as soon as practicable. 192.615(a)(12)
(b) Each operator shall: 192.615(b)
(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. 192.615(b)(1)
(2) Train the appropriate operating personnel to assure that they are knowledgeable of the emergency procedures and verify that the training is effective. 192.615(b)(2)
(3) Review employee activities to determine whether the procedures were effectively followed in each emergency. 192.615(b)(3)
(c) Each operator must establish and maintain liaison with the appropriate public safety answering point (i.e., 9-1-1 emergency call center) where direct access to a 9-1-1 emergency call center is available from the location of the pipeline, as well as fire, police, and other public officials, to: 192.615(c)
(1) Learn the responsibility and resources of each government organization that may respond to a gas pipeline emergency; 192.615(c)(1)
(2) Acquaint the officials with the operator's ability in responding to a gas pipeline emergency; 192.615(c)(2)
(3) Identify the types of gas pipeline emergencies of which the operator notifies the officials; and 192.615(c)(3)
(4) Plan how the operator and officials can engage in mutual assistance to minimize hazards to life or property. 192.615(c)(4)
[Amdt. 192-24, 41 FR 13587, Mar. 31, 1976, as amended by Amdt. 192-71, 59 FR 6585, Feb. 11, 1994; Amdt. 192-112,
74 FR 63327, Dec. 3, 2009]
§192.616 Public awareness
(a) Except for an operator of a master meter or petroleum gas system covered under paragraph (j) of this section, each pipeline operator must develop and implement a written continuing public education program that follows the guidance provided in the American Petroleum Institute's (API) Recommended Practice (RP) 1162 (incorporated by reference, see §192.7). 192.616(a)
(b) The operator's program must follow the general program recommendations of API RP 1162 and assess the unique attributes and characteristics of the operator's pipeline and facilities. 192.616(b)
(c) The operator must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162, unless the operator provides justification in its program or procedural manual as to why compliance with all or certain provisions of the recommended practice is not practicable and not necessary for safety. 192.616(c)
(d) The operator's program must specifically include provisions to educate the public, appropriate government organizations, and persons engaged in excavation related activities on: 192.616(d)
(1) Use of a one-call notification system prior to excavation and other damage prevention activities; 192.616(d)(1)
(2) Possible hazards associated with unintended releases from a gas pipeline facility; 192.616(d)(2)
(3) Physical indications that such a release may have occurred; 192.616(d)(3)
(4) Steps that should be taken for public safety in the event of a gas pipeline release; and 192.616(d)(4)
(5) Procedures for reporting such an event. 192.616(d)(5)
(e) The program must include activities to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations. 192.616(e)
(f) The program and the media used must be as comprehensive as necessary to reach all areas in which the operator transports gas. 192.616(f)
(g) The program must be conducted in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator's area. 192.616(g)
(h) Operators in existence on June 20, 2005, must have completed their written programs no later than June 20, 2006. The operator of a master meter or petroleum gas system covered under paragraph (j) of this section must complete development of its written procedure by June 13, 2008. Upon request, operators must submit their completed programs to PHMSA or, in the case of an intrastate pipeline facility operator, the appropriate State agency. 192.616(h)
(i) The operator's program documentation and evaluation results must be available for periodic review by appropriate regulatory agencies. 192.616(i)
(j) Unless the operator transports gas as a primary activity, the operator of a master meter or petroleum gas system is not required to develop a public awareness program as prescribed in paragraphs (a) through (g) of this section. Instead the operator must develop and implement a written procedure to provide its customers public awareness messages twice annually. If the master meter or petroleum gas system is located on property the operator does not control, the operator must provide similar messages twice annually to persons controlling the property. The public awareness message must include: 192.616(j)
(1) A description of the purpose and reliability of the pipeline; 192.616(j)(1)
(2) An overview of the hazards of the pipeline and prevention measures used; 192.616(j)(2)
(3) Information about damage prevention; 192.616(j)(3)
(4) How to recognize and respond to a leak; and 192.616(j)(4)
(5) How to get additional information. 192.616(j)(5)
[Amdt. 192-100, 70 FR 28842, May 19, 2005; 70 FR 35041, June 16, 2005; 72 FR 70810, Dec. 13, 2007]
§192.617 Investigation of failures and incidents
(a)Post-failure and incident procedures. Each operator must establish and follow procedures for investigating and analyzing failures and incidents as defined in §191.3, including sending the failed pipe, component, or equipment for laboratory testing or examination, where appropriate, for the purpose of determining the causes and contributing factor(s) of the failure or incident and minimizing the possibility of a recurrence.
(b)Post-failure and incident lessons learned. Each operator must develop, implement, and incorporate lessons learned from a postfailure or incident review into its written procedures, including personnel training and qualification programs, and design, construction, testing, maintenance, operations, and emergency procedure manuals and specifications.
(c)Analysis of rupture and valve shut-offs. If an incident on an onshore gas transmission pipeline or a Type A gathering pipeline involves the closure of a rupture-mitigation valve (RMV), as defined in §192.3, or the closure of alternative equivalent technology, the operator of the pipeline must also conduct a post-incident analysis of all of the factors that may have impacted the release volume and the consequences of the incident and identify and implement operations and maintenance measures to prevent or minimize the consequences of a future incident. The requirements of this paragraph (c) are not applicable to distribution pipelines or Types B and C gas gathering pipelines. The analysis must include all relevant factors impacting the release volume and consequences, including, but not limited to, the following:
(1) Detection, identification, operational response, system shut-off, and emergency response communications, based on the type and volume of the incident;
(2) Appropriateness and effectiveness of procedures and pipeline systems, including supervisory control and data acquisition (SCADA), communications, valve shut-off, and operator personnel;
(3) Actual response time from identifying a rupture following a notification of potential rupture, as defined at §192.3, to initiation of mitigative actions and isolation of the pipeline segment, and the appropriateness and effectiveness of the mitigative actions taken;
(4) Location and timeliness of actuation of RMVs or alternative equivalent technologies; and
(5)All other factors the operator deems appropriate.
(d)Rupture post-failure and incident summary. If a failure or incident on an onshore gas transmission pipeline or a Type A gathering pipeline involves the identification of a rupture following a notification of potential rupture, or the closure of an RMV (as those terms are defined in §192.3), or the closure of an alternative equivalent technology, the operator of the pipeline must complete a summary of the post-failure or incident review required by paragraph (c) of this section within 90 days of the incident, and while the investigation is pending, conduct quarterly status reviews until
the investigation is complete and a final post-incident summary is prepared. The final post-failure or incident summary, and all other reviews and analyses produced under the requirements of this section, must be reviewed, dated, and signed by the operator's appropriate senior executive officer. The final post-failure or incident summary, all investigation and analysis documents used to prepare it, and records of lessons learned must be kept for the useful life of the pipeline. The requirements of this paragraph (d) are not applicable to distribution pipelines or Types B and C gas gathering pipelines.
§192.619
Maximum allowable operating pressure:
Steel or plastic pipelines.
(a) No person may operate a segment of steel or plastic pipeline at a pressure that exceeds a maximum allowable operating pressure (MAOP) determined under paragraph (c), (d), or (e) of this section, or the lowest of the following: 192.619(a)
(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: 192.619(a)(1)
(i) Eighty percent of the first test pressure that produces yield under section N5 of Appendix N of ASME B31.8 (incorporated by reference, see §192.7), reduced by the appropriate factor in paragraph (a)(2)(ii) of this section; or192.619(a)(1)(i)
(ii) If the pipe is 123⁄4 inches (324 mm) or less in outside diameter and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa).192.619(a)(1)(ii)
(2) The pressure obtained by dividing the pressure to which the pipeline segment was tested after construction as follows: 192.619(a)(2)
(i) For plastic pipe in all locations, the test pressure is divided by a factor of 1.5.192.619(a)(2)(i)
(ii) For steel pipe operated at 100 psi (689 kPa) gage or more, the test pressure is divided by a factor determined in accordance with the Table 1 to paragraph (a)(2)(ii):192.619(a)(2)(ii)
Table 1 to Paragraph (a)(2)(ii)
Class location Installed before (Nov. 12, 1970)
Factors, 12 segment — Installed after (Nov. 11, 1970) and before July 1, 2020 Installed on or
1For offshore pipeline segments installed, uprated or converted after July 31, 1977, that are not located on an offshore platform, the factor is 1.25. For pipeline segments installed, uprated or converted after July 31, 1977, that are located on an offshore platform or on a platform in inland navigable waters, including a pipe riser, the factor is 1.5.
2For a component with a design pressure established in accordance with §192.153(a) or (b) installed after July 14, 2004, the factor is 1.3.
(3) The highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column. This pressure restriction applies unless the segment was tested according to the requirements in paragraph (a)(2) of this section after the applicable date in the third column or the segment was uprated according to the requirements in subpart K of this part: 192.619(a)(3)
(i) Onshore regulated gathering pipeline (Type A or Type B under §192.9(d)) that first became subject to this part (other than §192.612) after April 13, 2006
March 15, 2006, or date pipeline becomes subject to this part, whichever is later 5 years preceding applicable date in second column.
(ii) Onshore regulated gathering pipeline (Type C under §192.9(d)) that first became subject to this part (other than §192.612) on or after May 16, 2022 May 16, 2023, or date pipeline becomes subject to this part, whichever is later
5 years preceding applicable date in second column.
(continued) Pipeline
(iii) Onshore transmission pipeline that was a gathering pipeline not subject to this part before March 15, 2006
March 15, 2006, or date pipeline becomes subject to this part, whichever is later
5 years preceding applicable date in second column.
(iv) Offshore gathering pipelines July 1, 1976 July 1, 1971.
(v) All other pipelines July 1, 1970 July 1, 1965.
(4) The pressure determined by the operator to be the maximum safe pressure after considering and accounting for records of material properties, including material properties verified in accordance with §192.607, if applicable, and the history of the pipeline segment, including known corrosion and actual operating pressure. 192.619(a)(4)
(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. 192.619(b)
(c) The requirements on pressure restrictions in this section do not apply in the following instances: 192.619(c)
(1) An operator may operate a segment of pipeline found to be in satisfactory condition, considering its operating and maintenance history, at the highest actual operating pressure to which the segment was subjected during the 5 years preceding the applicable date in the second column of the table in paragraph (a)(3) of this section. An operator must still comply with §192.611. 192.619(c)(1)
(2) For any Type C gas gathering pipeline under §192.9 existing on or before May 16, 2022, that was not previously subject to this part and the operator cannot determine the actual operating pressure of the pipeline for the 5 years preceding May 16, 2023, the operator may establish MAOP using other criteria based on a combination of operating conditions, other tests, and design with approval from PHMSA. The operator must notify PHMSA in accordance with §192.18. The notification must include the following information: 192.619(c)(2)
(i) The proposed MAOP of the pipeline; 192.619(c)(2)(i)
(ii) Description of pipeline segment for which alternate methods are used to establish MAOP, including diameter, wall thickness, pipe grade, seam type, location, endpoints, other pertinent material properties, and age; 192.619(c)(2)(ii)
(iii) Pipeline operating data, including operating history and maintenance history; 192.619(c)(2)(iii)
(iv) Description of methods being used to establish MAOP; 192.619(c)(2)(iv)
(v) Technical justification for use of the methods chosen to establish MAOP; and 192.619(c)(2)(v)
(vi) Evidence of review and acceptance of the justification by a qualified technical subject matter expert. 192.619(c)(2)(vi)
(d) The operator of a pipeline segment of steel pipeline meeting the conditions prescribed in §192.620(b) may elect to operate the segment at a maximum allowable operating pressure determined under §192.620(a). 192.619(d)
(e) Notwithstanding the requirements in paragraphs (a) through (d) of this section, operators of onshore steel transmission pipelines that meet the criteria specified in §192.624(a) must establish and document the maximum allowable operating pressure in accordance with §192.624. 192.619(e)
(f) Operators of onshore steel transmission pipelines must make and retain records necessary to establish and document the MAOP of each pipeline segment in accordance with paragraphs (a) through (e) of this section as follows: 192.619(f)
(1) Operators of pipelines in operation as of [July 1, 2020 must retain any existing records establishing MAOP for the life of the pipeline; 192.619(f)(1)
(2) Operators of pipelines in operation as of July 1, 2020 that do not have records establishing MAOP and are required to reconfirm MAOP in accordance with §192.624, must retain the records reconfirming MAOP for the life of the pipeline; and 192.619(f)(2)
(3) Operators of pipelines placed in operation after July 1, 2020 must make and retain records establishing MAOP for the life of the pipeline. 192.619(f)(3)
[35 FR 13257, Aug. 19, 1970]
Editorial Note: For Federal Register citations affecting §192.619, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and on GPO Access.
§192.620 Part 192 – Minimum Federal Safety Standards
§192.620 Alternative maximum allowable operating pressure for certain steel pipelines
(a) How does an operator calculate the alternative maximum allowable operating pressure? An operator calculates the alternative maximum allowable operating pressure by using different factors in the same formulas used for calculating maximum allowable operating pressure under §192.619(a) as follows: 192.620(a)
(1) In determining the alternative design pressure under §192.105, use a design factor determined in accordance with §192.111(b), (c), or (d) or, if none of these paragraphs apply, in accordance with the following table: 192.620(a)(1)
ation at least 60 days prior to the earliest start date of either pipe manufacturing or construction activities. An operator must also notify the state pipeline safety authority when the pipeline is located in a state where PHMSA has an interstate agent agreement or where an intrastate pipeline is regulated by that state. 192.620(c)(1)
(2) Certify, by signature of a senior executive officer of the company, as follows: 192.620(c)(2)
(i) The pipeline segment meets the conditions described in paragraph (b) of this section; and192.620(c)(2)(i)
(ii) The operating and maintenance procedures include the additional operating and maintenance requirements of paragraph (d) of this section; and192.620(c)(2)(ii)
(iii) The review and any needed program upgrade of the damage prevention program required by paragraph (d)(4)(v) of this section has been completed.192.620(c)(2)(iii)
(i) For facilities installed prior to December 22, 2008, for which §192.111(b), (c), or (d) applies, use the following design factors as alternatives for the factors specified in those paragraphs: §192.111(b)-0.67 or less; 192.111(c) and (d)-0.56 or less. 192.620(a)(1)(i)
(ii) [Reserved]192.620(a)(1)(ii)
(2) The alternative maximum allowable operating pressure is the lower of the following: 192.620(a)(2)
(i) The design pressure of the weakest element in the pipeline segment, determined under subparts C and D of this part. 192.620(a)(2)(i)
(ii) The pressure obtained by dividing the pressure to which the pipeline segment was tested after construction by a factor determined in the following table:192.620(a)(2)(ii)
(3) Send a copy of the certification required by paragraph (c)(2) of this section to each PHMSA pipeline safety regional office where the pipeline is in service 30 days prior to operating at the alternative MAOP. An operator must also send a copy to a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State. 192.620(c)(3)
(4) For each pipeline segment, do one of the following: 192.620(c)(4)
(i) Perform a strength test as described in §192.505 at a test pressure calculated under paragraph (a) of this section or 192.620(c)(4)(i)
(ii) For a pipeline segment in existence prior to December 22, 2008, certify, under paragraph (c)(2) of this section, that the strength test performed under §192.505 was conducted at test pressure calculated under paragraph (a) of this section, or conduct a new strength test in accordance with paragraph (c)(4)(i) of this section.192.620(c)(4)(ii)
(5) Comply with the additional operation and maintenance requirements described in paragraph (d) of this section. 192.620(c)(5)
(6) If the performance of a construction task associated with implementing alternative MAOP that occurs after December 22, 2008, can affect the integrity of the pipeline segment, treat that task as a "covered task", notwithstanding the definition in §192.801(b) and implement the requirements of subpart N as appropriate. 192.620(c)(6)
1For Class 2 alternative maximum allowable operating pressure segments installed prior to December 22, 2008 the alternative test factor is 1.25.
(b) When may an operator use the alternative maximum allowable operating pressure calculated under paragraph (a) of this section? An operator may use an alternative maximum allowable operating pressure calculated under paragraph (a) of this section if the following conditions are met: 192.620(b)
(1) The pipeline segment is in a Class 1, 2, or 3 location; 192.620(b)(1)
(2) The pipeline segment is constructed of steel pipe meeting the additional design requirements in §192.112; 192.620(b)(2)
(3) A supervisory control and data acquisition system provides remote monitoring and control of the pipeline segment. The control provided must include monitoring of pressures and flows, monitoring compressor start-ups and shut-downs, and remote closure of valves per paragraph (d)(3) of this section; 192.620(b)(3)
(4) The pipeline segment meets the additional construction requirements described in §192.328; 192.620(b)(4)
(5) The pipeline segment does not contain any mechanical couplings used in place of girth welds; 192.620(b)(5)
(6) If a pipeline segment has been previously operated, the segment has not experienced any failure during normal operations indicative of a systemic fault in material as determined by a root cause analysis, including metallurgical examination of the failed pipe. The results of this root cause analysis must be reported to each PHMSA pipeline safety regional office where the pipeline is in service at least 60 days prior to operation at the alternative MAOP. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and 192.620(b)(6)
(7) At least 95 percent of girth welds on a segment that was constructed prior to December 22, 2008, must have been non-destructively examined in accordance with §192.243(b) and (c). 192.620(b)(7)
(c) What is an operator electing to use the alternative maximum allowable operating pressure required to do? If an operator elects to use the alternative maximum allowable operating pressure calculated under paragraph (a) of this section for a pipeline segment, the operator must do each of the following: 192.620(c)
(1) For pipelines already in service, notify the PHMSA pipeline safety regional office where the pipeline is in service of the intention to use the alternative pressure at least 180 days before operating at the alternative MAOP. For new pipelines, notify the PHMSA pipeline safety regional office of planned alternative MAOP design and oper-
(7) Maintain, for the useful life of the pipeline, records demonstrating compliance with paragraphs (b), (c)(6), and (d) of this section. 192.620(c)(7)
(8) A Class 1 and Class 2 location can be upgraded one class due to class changes per §192.611(a). All class location changes from Class 1 to Class 2 and from Class 2 to Class 3 must have all anomalies evaluated and remediated per: The "original pipeline class grade" §192.620(d)(11) anomaly repair requirements; and all anomalies with a wall loss equal to or greater than 40 percent must be excavated and remediated. Pipelines in Class 4 may not operate at an alternative MAOP. 192.620(c)(8)
(d) What additional operation and maintenance requirements apply to operation at the alternative maximum allowable operating pressure? In addition to compliance with other applicable safety standards in this part, if an operator establishes a maximum allowable operating pressure for a pipeline segment under paragraph (a) of this section, an operator must comply with the additional operation and maintenance requirements as follows: 192.620(d)
To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas:
(1) Identifying and evaluating threats
(2) Notifying the public
Develop a threat matrix consistent with §192.917 to do the following:
(i) Identify and compare the increased risk of operating the pipeline at the increased stress level under this section with conventional operation; and (ii) Describe and implement procedures used to mitigate the risk.
(i) Recalculate the potential impact circle as defined in §192.903 to reflect use of the alternative maximum operating pressure calculated under paragraph (a) of this section and pipeline operating conditions; and
(ii) In implementing the public education program required under §192.616, perform the following:
(A) Include persons occupying property within 220 yards of the centerline and within the potential impact circle within the targeted audience; and
To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas:
Take the following additional step:
(B) Include information about the integrity management activities performed under this section within the message provided to the audience.
(3) Responding to an emergency in an area defined as a high consequence area in §192.903
(i) Ensure that the identification of high consequence areas reflects the larger potential impact circle recalculated under paragraph (d)(2)(i) of this section.
(ii) If personnel response time to mainline valves on either side of the high consequence area exceeds one hour (under normal driving conditions and speed limits) from the time the event is identified in the control room, provide remote valve control through a supervisory control and data acquisition (SCADA) system, other leak detection system, or an alternative method of control.
(iii) Remote valve control must include the ability to close and monitor the valve position (open or closed), and monitor pressure upstream and downstream.
(iv) A line break valve control system using differential pressure, rate of pressure drop or other widely-accepted method is an acceptable alternative to remote valve control.
To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas:
(4) Protecting the right-of-way
(i) Patrol the right-of-way at intervals not exceeding 45 days, but at least 12 times each calendar year, to inspect for excavation activities, ground movement, wash outs, leakage, or other activities or conditions affecting the safety operation of the pipeline.
(ii) Develop and implement a plan to monitor for and mitigate occurrences of unstable soil and ground movement.
(iii) If observed conditions indicate the possible loss of cover, perform a depth of cover study and replace cover as necessary to restore the depth of cover or apply alternative means to provide protection equivalent to the originally-required depth of cover.
(iv) Use line-of-sight line markers satisfying the requirements of §192.707(d) except in agricultural areas, large water crossings or swamp, steep terrain, or where prohibited by Federal Energy Regulatory Commission orders, permits, or local law.
(v) Review the damage prevention program under §192.614(a) in light of national consensus practices, to ensure the program provides adequate protection of the right-of-way. Identify the standards or practices considered in the review, and meet or exceed those standards or practices by incorporating appropriate changes into the program.
(vi) Develop and implement a right-of-way management plan to protect the pipeline segment from damage due to excavation activities.
(5) Controlling internal corrosion
(i) Develop and implement a program to monitor for and mitigate the presence of, deleterious gas stream constituents.
(ii) At points where gas with potentially deleterious contaminants enters the pipeline, use filter separators or separators and gas quality monitoring equipment.
(iii) Use gas quality monitoring equipment that includes a moisture analyzer, chromatograph, and periodic hydrogen sulfide sampling.
(iv) Use cleaning pigs and sample accumulated liquids. Use inhibitors when corrosive gas or liquids are present.
(v) Address deleterious gas stream constituents as follows:
(A) Limit carbon dioxide to 3 percent by volume;
(B) Allow no free water and otherwise limit water to seven pounds per million cubic feet of gas; and
(6) Controlling interference that can impact external corrosion
Take the following additional step:
(C) Limit hydrogen sulfide to 1.0 grain per hundred cubic feet (16 ppm) of gas, where the hydrogen sulfide is greater than 0.5 grain per hundred cubic feet (8 ppm) of gas, implement a pigging and inhibitor injection program to address deleterious gas stream constituents, including followup sampling and quality testing of liquids at receipt points.
(vi) Review the program at least quarterly based on the gas stream experience and implement adjustments to monitor for, and mitigate the presence of, deleterious gas stream constituents.
(i) Prior to operating an existing pipeline segment at an alternate maximum allowable operating pressure calculated under this section, or within six months after placing a new pipeline segment in service at an alternate maximum allowable operating pressure calculated under this section, address any interference currents on the pipeline segment.
(ii) To address interference currents, perform the following:
(A) Conduct an interference survey to detect the presence and level of any electrical current that could impact external corrosion where interference is suspected;
(B) Analyze the results of the survey; and
(C) Take any remedial action needed within 6 months after completing the survey to protect the pipeline segment from deleterious current.
(7) Confirming external corrosion control through indirect assessment
(8) Controlling external corrosion through cathodic protection
(i) Within six months after placing the cathodic protection of a new pipeline segment in operation, or within six months after certifying a segment under §192.620(c)(1) of an existing pipeline segment under this section, assess the adequacy of the cathodic protection through an indirect method such as close-interval survey, and the integrity of the coating using direct current voltage gradient (DCVG) or alternating current voltage gradient (ACVG).
(ii) Remediate any construction damaged coating with a voltage drop classified as moderate or severe (IR drop greater than 35% for DCVG or 50 dBµv for ACVG) under section 4 of NACE RP0502-2002 (incorporated by reference, see §192.7).
(iii) Within six months after completing the baseline internal inspection required under paragraph (d)(9) of this section, integrate the results of the indirect assessment required under paragraph (d)(7)(i) of this section with the results of the baseline internal inspection and take any needed remedial actions.
(iv) For all pipeline segments in high consequence areas, perform periodic assessments as follows:
(A) Conduct periodic close interval surveys with current interrupted to confirm voltage drops in association with periodic assessments under subpart O of this part.
(B) Locate pipe-to-soil test stations at halfmile intervals within each high consequence area ensuring at least one station is within each high consequence area, if practicable.
(C) Integrate the results with those of the baseline and periodic assessments for integrity done under paragraphs (d)(9) and (d)(10) of this section.
(i) If an annual test station reading indicates cathodic protection below the level of protection required in subpart I of this part, complete remedial action within six months of the failed reading or notify each PHMSA pipeline safety regional office where the pipeline is in service demonstrating that the integrity of the pipeline is not compromised if the repair takes longer than 6 months. An operator must also notify a State pipeline safety authority when the pipeline is located in a State where PHMSA has an interstate agent agreement, or an intrastate pipeline is regulated by that State; and
To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas:
(9) Conducting a baseline assessment of integrity
Take the following additional step:
(ii) After remedial action to address a failed reading, confirm restoration of adequate corrosion control by a close interval survey on either side of the affected test station to the next test station unless the reason for the failed reading is determined to be a rectifier connection or power input problem that can be remediated and otherwise verified.
(iii) If the pipeline segment has been in operation, the cathodic protection system on the pipeline segment must have been operational within 12 months of the completion of construction.
(i) Except as provided in paragraph (d)(9)(iii) of this section, for a new pipeline segment operating at the new alternative maximum allowable operating pressure, perform a baseline internal inspection of the entire pipeline segment as follows:
(A) Assess using a geometry tool after the initial hydrostatic test and backfill and within six months after placing the new pipeline segment in service; and
(B) Assess using a high resolution magnetic flux tool within three years after placing the new pipeline segment in service at the alternative maximum allowable operating pressure.
(ii) Except as provided in paragraph (d)(9)(iii) of this section, for an existing pipeline segment, perform a baseline internal assessment using a geometry tool and a high resolution magnetic flux tool before, but within two years prior to, raising pressure to the alternative maximum allowable operating pressure as allowed under this section.
(iii) If headers, mainline valve by-passes, compressor station piping, meter station piping, or other short portion of a pipeline segment operating at alternative maximum allowable operating pressure cannot accommodate a geometry tool and a high resolution magnetic flux tool, use direct assessment (per §192.925, §192.927 and/or §192.929) or pressure testing (per subpart J of this part) to assess that portion.
To address increased risk of a maximum allowable operating pressure based on higher stress levels in the following areas:
(10) Conducting periodic assessments of integrity
(11) Making repairs
(i) Determine a frequency for subsequent periodic integrity assessments as if all the alternative maximum allowable operating pressure pipeline segments were covered by subpart O of this part and
(ii) Conduct periodic internal inspections using a high resolution magnetic flux tool on the frequency determined under paragraph (d)(10)(i) of this section, or
(iii) Use direct assessment (per §192.925, §192.927 and/or §192.929) or pressure testing (per subpart J of this part) for periodic assessment of a portion of a segment to the extent permitted for a baseline assessment under paragraph (d)(9)(iii) of this section.
(i) Perform the following when evaluating an anomaly:
(A) Use the most conservative calculation for determining remaining strength or an alternative validated calculation based on pipe diameter, wall thickness, grade, operating pressure, operating stress level, and operating temperature: and
(B) Take into account the tolerances of the tools used for the inspection.
(ii) Repair a defect immediately if any of the following apply:
(A) The defect is a dent discovered during the baseline assessment for integrity under paragraph (d)(9) of this section and the defect meets the criteria for immediate repair in §192.309(b).
(B) The defect meets the criteria for immediate repair in §192.933(d).
(C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure.
Take the following additional step:
(D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than or equal to 1.4 times the alternative maximum allowable operating pressure.
(iii) If paragraph (d)(11)(ii) of this section does not require immediate repair, repair a defect within one year if any of the following apply:
(A) The defect meets the criteria for repair within one year in §192.933(d).
(B) The alternative maximum allowable operating pressure was based on a design factor of 0.80 under paragraph (a) of this section and the failure pressure is less than 1.25 times the alternative maximum allowable operating pressure.
(C) The alternative maximum allowable operating pressure was based on a design factor of 0.67 under paragraph (a) of this section and the failure pressure is less than 1.50 times the alternative maximum allowable operating pressure.
(D) The alternative maximum allowable operating pressure was based on a design factor of 0.56 under paragraph (a) of this section and the failure pressure is less than or equal to 1.80 times the alternative maximum allowable operating pressure.
(iv) Evaluate any defect not required to be repaired under paragraph (d)(11)(ii) or (iii) of this section to determine its growth rate, set the maximum interval for repair or re-inspection, and repair or reinspect within that interval.
(e) Is there any change in overpressure protection associated with operating at the alternative maximum allowable operating pressure? Notwithstanding the required capacity of pressure relieving and limiting stations otherwise required by §192.201, if an operator establishes a maximum allowable operating pressure for a pipeline segment in accordance with paragraph (a) of this section, an operator must: 192.620(e)
(1) Provide overpressure protection that limits mainline pressure to a maximum of 104 percent of the maximum allowable operating pressure; and 192.620(e)(1)
(2) Develop and follow a procedure for establishing and maintaining accurate set points for the supervisory control and data acquisition system. 192.620(e)(2)
[73 FR 62177, Oct. 17, 2008, as amended by Amdt. 192-111, 74 FR 62505, Nov. 30, 2009; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]
§192.621
Maximum allowable operating pressure: High-pressure distribution systems
(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: 192.621(a)
(1) The design pressure of the weakest element in the segment, determined in accordance with subparts C and D of this part. 192.621(a)(1)
(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). 192.621(a)(2)
(3) 25 p.s.i. (172 kPa) gage in segments of cast iron pipe in which there are unreinforced bell and spigot joints. 192.621(a)(3)
(4) The pressure limits to which a joint could be subjected without the possibility of its parting. 192.621(a)(4)
(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. 192.621(a)(5)
(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. 192.621(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.623 Maximum and minimum allowable operating pressure; Low-pressure distribution systems
(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. 192.623(a)
(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. 192.623(b)
§192.624 Maximum allowable operating pressure reconfirmation: Onshore steel transmission pipelines.
(a) Applicability. Operators of onshore steel transmission pipeline segments must reconfirm the maximum allowable operating pressure (MAOP) of all pipeline segments in accordance with the requirements of this section if either of the following conditions are met: 192.624(a)
(1) Records necessary to establish the MAOP in accordance with §192.619(a)(2), including records required by §192.517(a), are not traceable, verifiable, and complete and the pipeline is located in one of the following locations: 192.624(a)(1)
(i) A high consequence area as defined in §192.903; or 192.624(a)(1)(i)
(ii) A Class 3 or Class 4 location.192.624(a)(1)(ii)
(2) The pipeline segment's MAOP was established in accordance with §192.619(c), the pipeline segment's MAOP is greater than or equal to 30 percent of the specified minimum yield strength, and the pipeline segment is located in one of the following areas: 192.624(a)(2)
(i) A high consequence area as defined in §192.903;192.624(a)(2)(i)
(ii) A Class 3 or Class 4 location; or192.624(a)(2)(ii)
(iii) A moderate consequence area as defined in §192.3, if the pipeline segment can accommodate inspection by means of instrumented inline inspection tools.192.624(a)(2)(iii)
(b) Procedures and completion dates. Operators of a pipeline subject to this section must develop and document procedures for completing all actions required by this section by July 1, 2021. These procedures must include a process for reconfirming MAOP for any pipelines that meet a condition of §192.624(a), and for performing a spike test or material verification in accordance with §§192.506 and 192.607, if applicable. All actions required by this section must be completed according to the following schedule: 192.624(b)
(1) Operators must complete all actions required by this section on at least 50% of the pipeline mileage by July 3, 2028. 192.624(b)(1)
(2) Operators must complete all actions required by this section on 100% of the pipeline mileage by July 2, 2035 or as soon as practicable, but not to exceed 4 years after the pipeline segment first meets a condition of §192.624(a) (e.g., due to a location becoming a high consequence area), whichever is later. 192.624(b)(2)
(3) If operational and environmental constraints limit an operator from meeting the deadlines in §192.624, the operator may petition for an extension of the completion deadlines by up to 1 year, upon submittal of a notification in accordance with §192.18. The notification must include an up-to-date plan for completing all actions in accordance with this section, the reason for the requested extension, current status, proposed completion date, outstanding remediation activities, and any needed temporary measures needed to mitigate the impact on safety. 192.624(b)(3)
(c) Maximum allowable operating pressure determination. Operators of a pipeline segment meeting a condition in paragraph (a) of this section must reconfirm its MAOP using one of the following methods: 192.624(c)
(1) Method 1: Pressure test. Perform a pressure test and verify material properties records in accordance with §192.607 and the following requirements: 192.624(c)(1)
(i) Pressure test. Perform a pressure test in accordance with subpart J of this part. The MAOP must be equal to the test pressure divided by the greater of either 1.25 or the applicable class location factor in §192.619(a)(2)(ii).192.624(c)(1)(i)
(ii) Material properties records. Determine if the following material properties records are documented in traceable, verifiable, and complete records: Diameter, wall thickness, seam type, and grade (minimum yield strength, ultimate tensile strength). 192.624(c)(1)(ii)
(iii) Material properties verification. If any of the records required by paragraph (c)(1)(ii) of this section are not documented in traceable, verifiable, and complete records, the operator must obtain the missing records in accordance with §192.607. An operator must test the pipe materials cut out from the test manifold sites at the time the pressure test is conducted. If there is a failure during the pressure test, the operator must test any removed pipe from the pressure test failure in accordance with §192.607. 192.624(c)(1)(iii)
(2) Method 2: Pressure Reduction. Reduce pressure, as necessary, and limit MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 5 years preceding October 1, 2019, divided by the greater of 1.25 or the applicable class location factor in §192.619(a)(2)(ii). The highest actual sustained pressure must have been reached for a minimum cumulative duration of 8 hours during a continuous 30-day period. The value used as the highest actual sustained operating pressure must account for differences between upstream and downstream pressure on the pipeline by use of either the lowest maximum pressure value for the entire pipeline segment or using the operating pressure gradient along the entire pipeline segment (i.e., the location-specific operating pressure at each location). 192.624(c)(2)
(i) Where the pipeline segment has had a class location change in accordance with §192.611, and records documenting diameter, wall thickness, seam type, grade (minimum yield strength and ultimate tensile strength), and pressure tests are not documented in traceable, verifiable, and complete records, the operator must reduce the pipeline segment MAOP as follows: 192.624(c)(2)(i)
[A] For pipeline segments where a class location changed from Class 1 to Class 2, from Class 2 to Class 3, or from Class 3 to Class 4, reduce the pipeline MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 5 years preceding October 1, 2019, divided by 1.39 for Class 1 to Class 2, 1.67 for Class 2 to Class 3, and 2.00 for Class 3 to Class 4.192.624(c)(2)(i)[A]
[B] For pipeline segments where a class location changed from Class 1 to Class 3, reduce the pipeline MAOP to no greater than the highest actual operating pressure sustained by the pipeline during the 5 years preceding October 1, 2019, divided by 2.00.192.624(c)(2)(i)[B]
(ii) Future uprating of the pipeline segment in accordance with subpart K is allowed if the MAOP is established using Method 2. 192.624(c)(2)(ii)
(iii) If an operator elects to use Method 2, but desires to use a less conservative pressure reduction factor or longer look-back period, the operator must notify PHMSA in accordance with §192.18 no later than 7 calendar days after establishing the reduced MAOP. The notification must include the following details:192.624(c)(2)(iii)
[A] Descriptions of the operational constraints, special circumstances, or other factors that preclude, or make it impractical, to use the pressure reduction factor specified in §192.624(c)(2);192.624(c)(2)(iii)[A]
[B] The fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis that complies with §192.712;192.624(c)(2)(iii)[B]
[C] Justification that establishing MAOP by another method allowed by this section is impractical;192.624(c)(2)(iii)[C]
[D] Justification that the reduced MAOP determined by the operator is safe based on analysis of the condition of the pipeline segment, including material properties records, material properties verified in accordance §192.607, and the history of the pipeline segment, particularly known corrosion and leakage, and the actual operating pressure, and additional compensatory preventive and mitigative measures taken or planned; and192.624(c)(2)(iii)[D]
[E] Planned duration for operating at the requested MAOP, longterm remediation measures and justification of this operating time interval, including fracture mechanics modeling for failure stress pressures and cyclic fatigue growth analysis and other validated forms of engineering analysis that have been reviewed and confirmed by subject matter experts. 192.624(c)(2)(iii)[E]
(3) Method 3: Engineering Critical Assessment (ECA). Conduct an ECA in accordance with §192.632. 192.624(c)(3)
(4) Method 4: Pipe Replacement. Replace the pipeline segment in accordance with this part. 192.624(c)(4)
(5) Method 5: Pressure Reduction for Pipeline Segments with Small Potential Impact Radius. Pipelines with a potential impact radius (PIR) less than or equal to 150 feet may establish the MAOP as follows: 192.624(c)(5)
(i) Reduce the MAOP to no greater than the highest actual operating pressure sustained by the pipeline during 5 years preceding October 1, 2019, divided by 1.1. The highest actual sustained pressure must have been reached for a minimum cumulative duration of 8 hours during one continuous 30-day period. The reduced MAOP must account for differences between discharge and upstream pressure on the pipeline by use of either the lowest value for the entire pipeline segment or the operating pressure gradient (i.e., the location specific operating pressure at each location);192.624(c)(5)(i)
(ii) Conduct patrols in accordance with §192.705 paragraphs (a) and (c) and conduct instrumented leakage surveys in accordance with §192.706 at intervals not to exceed those in the following table 1 to §192.624(c)(5)(ii):192.624(c)(5)(ii)
Table 1 to §192.624(c)(5)(ii)
Class locations Patrols Leakage surveys
(A) Class 1 and Class 2
(B) Class 3 and Class 4
3 1⁄2 months, but at least four times each calendar year
3 months, but at least six times each calendar year
3 1⁄2 months, but at least four times each calendar year.
3 months, but at least six times each calendar year.
(iii) Under Method 5, future uprating of the pipeline segment in accordance with subpart K is allowed.192.624(c)(5)(iii)
(6) Method 6: Alternative Technology. Operators may use an alternative technical evaluation process that provides a documented engineering analysis for establishing MAOP. If an operator elects to use alternative technology, the operator must notify PHMSA in advance in accordance with §192.18. The notification must include descriptions of the following details: 192.624(c)(6)
(i) The technology or technologies to be used for tests, examinations, and assessments; the method for establishing material properties; and analytical techniques with similar analysis from prior tool runs done to ensure the results are consistent with the required corresponding hydrostatic test pressure for the pipeline segment being evaluated;192.624(c)(6)(i)
(ii) Procedures and processes to conduct tests, examinations, assessments and evaluations, analyze defects and flaws, and remediate defects discovered;192.624(c)(6)(ii)
(iii) Pipeline segment data, including original design, maintenance and operating history, anomaly or flaw characterization; 192.624(c)(6)(iii)
(iv) Assessment techniques and acceptance criteria, including anomaly detection confidence level, probability of detection, and uncertainty of the predicted failure pressure quantified as a fraction of specified minimum yield strength;192.624(c)(6)(iv)
(v) If any pipeline segment contains cracking or may be susceptible to cracking or crack-like defects found through or identified by assessments, leaks, failures, manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with paragraph §192.712;192.624(c)(6)(v)
(vii) Methodology and criteria used to justify and establish the MAOP; and192.624(c)(6)(vii)
(viii) Documentation of the operator's process and procedures used to implement the use of the alternative technology, including any records generated through its use.192.624(c)(6)(viii)
(d) Records. An operator must retain records of investigations, tests, analyses, assessments, repairs, replacements, alterations, and other actions taken in accordance with the requirements of this section for the life of the pipeline. 192.624(d)
[Amdt. No. 192-125, 84 FR 52247, Oct. 1, 2019, as amended by Amdt. No. 192-127, 85 FR 40134, July 6, 2020]
§192.625 Odorization of gas
(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. 192.625(a)
(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: 192.625(b)
(1) At least 50 percent of the length of the line downstream from that location is in a Class 1 or Class 2 location; 192.625(b)(1)
(2) The line transports gas to any of the following facilities which received gas without an odorant from that line before May 5, 1975; 192.625(b)(2)
(i) An underground storage field;192.625(b)(2)(i)
(ii) A gas processing plant;192.625(b)(2)(ii)
(iii) A gas dehydration plant; or192.625(b)(2)(iii)
(iv) An industrial plant using gas in a process where the presence of an odorant:192.625(b)(2)(iv)
[A] Makes the end product unfit for the purpose for which it is intended;192.625(b)(2)(iv)[A]
[B] Reduces the activity of a catalyst; or192.625(b)(2)(iv)[B]
[C] Reduces the percentage completion of a chemical reaction; 192.625(b)(2)(iv)[C]
(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 192.625(b)(3)
(4) The combustible gas is hydrogen intended for use as a feedstock in a manufacturing process. 192.625(b)(4)
(c) In the concentrations in which it is used, the odorant in combustible gases must comply with the following: 192.625(c)
(1) The odorant may not be deleterious to persons, materials, or pipe. 192.625(c)(1)
(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. 192.625(c)(2)
(d) The odorant may not be soluble in water to an extent greater than 2.5 parts to 100 parts by weight. 192.625(d)
(e) Equipment for odorization must introduce the odorant without wide variations in the level of odorant. 192.625(e)
(f) To assure the proper concentration of odorant in accordance with this section, each operator must conduct periodic sampling of combustible gases using an instrument capable of determining the percentage of gas in air at which the odor becomes readily detectable. Operators of master meter systems may comply with this requirement by — 192.625(f)
(1) Receiving written verification from their gas source that the gas has the proper concentration of odorant; and 192.625(f)(1)
(2) Conducting periodic "sniff" tests at the extremities of the system to confirm that the gas contains odorant. 192.625(f)(2)
[35 FR 13257, Aug. 19, 1970]
Editorial Note: For Federal Register citations affecting §192.625, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and on GPO Access.
§192.627 Tapping pipelines under pressure
Each tap made on a pipeline under pressure must be performed by a crew qualified to make hot taps.
§192.629
Purging of pipelines
(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. 192.629(a)
(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.
192.629(b)
§192.631 Control room management
(a) General. 192.631(a)
(1) This section applies to each operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this section, except that for each control room where an operator's activities are limited to either or both of: 192.631(a)(1)
(i) Distribution with less than 250,000 services, or192.631(a)(1)(i)
(ii) Transmission without a compressor station, the operator must have and follow written procedures that implement only paragraphs (d) (regarding fatigue), (i) (regarding compliance validation), and (j) (regarding compliance and deviations) of this section.192.631(a)(1)(ii)
(2) The procedures required by this section must be integrated, as appropriate, with operating and emergency procedures required by §§192.605 and 192.615. An operator must develop the procedures no later than August 1, 2011, and must implement the procedures according to the following schedule. The procedures required by paragraphs (b), (c)(5), (d)(2) and (d)(3), (f) and (g) of this section must be implemented no later than October 1, 2011. The procedures required by paragraphs (c)(1) through (4), (d)(1), (d)(4), and (e) must be implemented no later than August 1, 2012. The training procedures required by paragraph (h) must be implemented no later than August 1, 2012, except that any training required by another paragraph of this section must be implemented no later than the deadline for that paragraph. 192.631(a)(2)
(b) Roles and responsibilities. Each operator must define the roles and responsibilities of a controller during normal, abnormal, and emergency operating conditions. To provide for a controller's prompt and appropriate response to operating conditions, an operator must define each of the following: 192.631(b)
(1) A controller's authority and responsibility to make decisions and take actions during normal operations; 192.631(b)(1)
(2) A controller's role when an abnormal operating condition is detected, even if the controller is not the first to detect the condition, including the controller's responsibility to take specific actions and to communicate with others; 192.631(b)(2)
(3) A controller's role during an emergency, even if the controller is not the first to detect the emergency, including the controller's responsibility to take specific actions and to communicate with others; 192.631(b)(3)
(4) A method of recording controller shift-changes and any hand-over of responsibility between controllers; and 192.631(b)(4)
(5) The roles, responsibilities and qualifications of others with the authority to direct or supersede the specific technical actions of a controller. 192.631(b)(5)
(c) Provide adequate information. Each operator must provide its controllers with the information, tools, processes and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined by performing each of the following: 192.631(c)
(1) Implement sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 (incorporated by reference, see §192.7) whenever a SCADA system is added, expanded or replaced, unless the operator demonstrates that certain provisions of sections 1, 4, 8, 9, 11.1, and 11.3 of API RP 1165 are not practical for the SCADA system used; 192.631(c)(1)
(2) Conduct a point-to-point verification between SCADA displays and related field equipment when field equipment is added or moved and when other changes that affect pipeline safety are made to field equipment or SCADA displays; 192.631(c)(2)
(3) Test and verify an internal communication plan to provide adequate means for manual operation of the pipeline safely, at least once each calendar year, but at intervals not to exceed 15 months; 192.631(c)(3)
(4) Test any backup SCADA systems at least once each calendar year, but at intervals not to exceed 15 months; and 192.631(c)(4)
(5) Establish and implement procedures for when a different controller assumes responsibility, including the content of information to be exchanged. 192.631(c)(5)
(d) Fatigue mitigation. Each operator must implement the following methods to reduce the risk associated with controller fatigue that could inhibit a controller's ability to carry out the roles and responsibilities the operator has defined: 192.631(d)
(1) Establish shift lengths and schedule rotations that provide controllers off-duty time sufficient to achieve eight hours of continuous sleep; 192.631(d)(1)
(2) Educate controllers and supervisors in fatigue mitigation strategies and how off-duty activities contribute to fatigue; 192.631(d)(2)
(3) Train controllers and supervisors to recognize the effects of fatigue; and 192.631(d)(3)
(4) Establish a maximum limit on controller hours-of-service, which may provide for an emergency deviation from the maximum limit if necessary for the safe operation of a pipeline facility. 192.631(d)(4)
(e) Alarm management. Each operator using a SCADA system must have a written alarm management plan to provide for effective controller response to alarms. An operator's plan must include provisions to: 192.631(e)
(1) Review SCADA safety-related alarm operations using a process that ensures alarms are accurate and support safe pipeline operations; 192.631(e)(1)
(2) Identify at least once each calendar month points affecting safety that have been taken off scan in the SCADA host, have had alarms inhibited, generated false alarms, or that have had forced or manual values for periods of time exceeding that required for associated maintenance or operating activities; 192.631(e)(2)
(3) Verify the correct safety-related alarm set-point values and alarm descriptions at least once each calendar year, but at intervals not to exceed 15 months; 192.631(e)(3)
(4) Review the alarm management plan required by this paragraph at least once each calendar year, but at intervals not exceeding 15 months, to determine the effectiveness of the plan; 192.631(e)(4)
(5) Monitor the content and volume of general activity being directed to and required of each controller at least once each calendar year, but at intervals not to exceed 15 months, that will assure controllers have sufficient time to analyze and react to incoming alarms; and 192.631(e)(5)
(6) Address deficiencies identified through the implementation of paragraphs (e)(1) through (e)(5) of this section. 192.631(e)(6)
(f) Change management. Each operator must assure that changes that could affect control room operations are coordinated with the control room personnel by performing each of the following: 192.631(f)
(1) Establish communications between control room representatives, operator's management, and associated field personnel when planning and implementing physical changes to pipeline equipment or configuration; 192.631(f)(1)
(2) Require its field personnel to contact the control room when emergency conditions exist and when making field changes that affect control room operations; and 192.631(f)(2)
(3) Seek control room or control room management participation in planning prior to implementation of significant pipeline hydraulic or configuration changes. 192.631(f)(3)
(g) Operating experience. Each operator must assure that lessons learned from its operating experience are incorporated, as appropriate, into its control room management procedures by performing each of the following: 192.631(g)
(1) Review incidents that must be reported pursuant to 49 CFR part 191 to determine if control room actions contributed to the event and, if so, correct, where necessary, deficiencies related to: 192.631(g)(1)
(i) Controller fatigue;192.631(g)(1)(i)
(ii) Field equipment;192.631(g)(1)(ii)
(iii) The operation of any relief device;192.631(g)(1)(iii)
(iv) Procedures;192.631(g)(1)(iv)
(v) SCADA system configuration; and192.631(g)(1)(v)
(vi) SCADA system performance.192.631(g)(1)(vi)
(2) Include lessons learned from the operator's experience in the training program required by this section. 192.631(g)(2)
(h) Training. Each operator must establish a controller training program and review the training program content to identify potential improvements at least once each calendar year, but at intervals not to exceed 15 months. An operator's program must provide for training each controller to carry out the roles and responsibilities defined by the operator. In addition, the training program must include the following elements: 192.631(h)
(1) Responding to abnormal operating conditions likely to occur simultaneously or in sequence; 192.631(h)(1)
(2) Use of a computerized simulator or non-computerized (tabletop) method for training controllers to recognize abnormal operating conditions; 192.631(h)(2)
(3) Training controllers on their responsibilities for communication under the operator's emergency response procedures; 192.631(h)(3)
(4) Training that will provide a controller a working knowledge of the pipeline system, especially during the development of abnormal operating conditions; 192.631(h)(4)
(5) For pipeline operating setups that are periodically, but infrequently used, providing an opportunity for controllers to review relevant procedures in advance of their application; and 192.631(h)(5)
(6) Control room team training and exercises that include both controllers and other individuals, defined by the operator, who would reasonably be expected to operationally collaborate with controllers (control room personnel) during normal, abnormal or emergency situations. Operators must comply with the team training requirements under this paragraph by no later than January 23, 2018. 192.631(h)(6) (i) Compliance validation. Upon request, operators must submit their procedures to PHMSA or, in the case of an intrastate pipeline facility regulated by a State, to the appropriate State agency. 192.631(i)
(j) Compliance and deviations. An operator must maintain for review during inspection: 192.631(j)
(1) Records that demonstrate compliance with the requirements of this section; and 192.631(j)(1)
(2) Documentation to demonstrate that any deviation from the procedures required by this section was necessary for the safe operation of a pipeline facility. 192.631(j)(2)
When an operator conducts an MAOP reconfirmation in accordance with §192.624(c)(3) “Method 3” using an ECA to establish the material strength and MAOP of the pipeline segment, the ECA must comply with the requirements of this section. The ECA must assess: Threats; loadings and operational circumstances relevant to those threats, including along the pipeline right-of way; outcomes of the threat assessment; relevant mechanical and fracture properties; in-service degradation or failure processes; and initial and final defect size relevance. The ECA must quantify the interacting effects of threats on any defect in the pipeline.
(a) ECA Analysis. 192.632(a)
(1) The material properties required to perform an ECA analysis in accordance with this paragraph are as follows: Diameter, wall thickness, seam type, grade (minimum yield strength and ultimate tensile strength), and Charpy v-notch toughness values based upon the lowest operational temperatures, if applicable. If any material properties required to perform an ECA for any pipeline segment in accordance with this paragraph are not documented in traceable, verifiable and complete records, an operator must use conservative assumptions and include the pipeline segment in its program to verify the undocumented information in accordance with §192.607. The ECA must integrate, analyze, and account for the material properties, the results of all tests, direct examinations, destructive tests, and assessments performed in accordance with this section, along
with other pertinent information related to pipeline integrity, including close interval surveys, coating surveys, interference surveys required by subpart I of this part, cause analyses of prior incidents, prior pressure test leaks and failures, other leaks, pipe inspections, and prior integrity assessments, including those required by §§192.617, 192.710, and subpart O of this part. 192.632(a)(1)
(2) The ECA must analyze and determine the predicted failure pressure for the defect being assessed using procedures that implement the appropriate failure criteria and justification as follows: 192.632(a)(2)
(i) The ECA must analyze any cracks or crack-like defects remaining in the pipe, or that could remain in the pipe, to determine the predicted failure pressure of each defect in accordance with §192.712.192.632(a)(2)(i)
(ii) The ECA must analyze any metal loss defects not associated with a dent, including corrosion, gouges, scrapes or other metal loss defects that could remain in the pipe, to determine the predicted failure pressure. ASME/ANSI B31G (incorporated by reference, see §192.7) or R-STRENG (incorporated by reference, see §192.7) must be used for corrosion defects. Both procedures and their analysis apply to corroded regions that do not penetrate the pipe wall over 80 percent of the wall thickness and are subject to the limitations prescribed in the equations' procedures. The ECA must use conservative assumptions for metal loss dimensions (length, width, and depth).192.632(a)(2)(ii)
(iii) When determining the predicted failure pressure for gouges, scrapes, selective seam weld corrosion, crack-related defects, or any defect within a dent, appropriate failure criteria and justification of the criteria must be used and documented. 192.632(a)(2)(iii)
(iv) If SMYS or actual material yield and ultimate tensile strength is not known or not documented by traceable, verifiable, and complete records, then the operator must assume 30,000 p.s.i. or determine the material properties using §192.607.192.632(a)(2)(iv)
(3) The ECA must analyze the interaction of defects to conservatively determine the most limiting predicted failure pressure. Examples include, but are not limited to, cracks in or near locations with corrosion metal loss, dents with gouges or other metal loss, or cracks in or near dents or other deformation damage. The ECA must document all evaluations and any assumptions used in the ECA process. 192.632(a)(3)
(4) The MAOP must be established at the lowest predicted failure pressure for any known or postulated defect, or interacting defects, remaining in the pipe divided by the greater of 1.25 or the applicable factor listed in §192.619(a)(2)(ii). 192.632(a)(4)
(b) Assessment to determine defects remaining in the pipe. An operator must utilize previous pressure tests or develop and implement an assessment program to determine the size of defects remaining in the pipe to be analyzed in accordance with paragraph (a) of this section. 192.632(b)
(1) An operator may use a previous pressure test that complied with subpart J to determine the defects remaining in the pipe if records for a pressure test meeting the requirements of subpart J of this part exist for the pipeline segment. The operator must calculate the largest defect that could have survived the pressure test. The operator must predict how much the defects have grown since the date of the pressure test in accordance with §192.712. The ECA must analyze the predicted size of the largest defect that could have survived the pressure test that could remain in the pipe at the time the ECA is performed. The operator must calculate the remaining life of the most severe defects that could have survived the pressure test and establish a re-assessment interval in accordance with the methodology in §192.712. 192.632(b)(1)
(2) Operators may use an inline inspection program in accordance with paragraph (c) of this section. 192.632(b)(2)
(3) Operators may use “other technology” if it is validated by a subject matter expert to produce an equivalent understanding of the condition of the pipe equal to or greater than pressure testing or an inline inspection program. If an operator elects to use “other technology” in the ECA, it must notify PHMSA in advance of using the other technology in accordance with §192.18. The “other technology” notification must have: 192.632(b)(3)
(i) Descriptions of the technology or technologies to be used for all tests, examinations, and assessments, including characterization of defect size used in the crack assessments (length, depth, and volumetric); and192.632(b)(3)(i)
(ii) Procedures and processes to conduct tests, examinations, assessments and evaluations, analyze defects, and remediate defects discovered.192.632(b)(3)(ii)
(c) In-line inspection. An inline inspection (ILI) program to determine the defects remaining the pipe for the ECA analysis must be performed using tools that can detect wall loss, deformation from dents, wrinkle
bends, ovalities, expansion, seam defects, including cracking and selective seam weld corrosion, longitudinal, circumferential and girth weld cracks, hard spot cracking, and stress corrosion cracking. 192.632(c)
(1) If a pipeline has segments that might be susceptible to hard spots based on assessment, leak, failure, manufacturing vintage history, or other information, then the ILI program must include a tool that can detect hard spots. 192.632(c)(1)
(2) If the pipeline has had a reportable incident, as defined in §191.3, attributed to a girth weld failure since its most recent pressure test, then the ILI program must include a tool that can detect girth weld defects unless the ECA analysis performed in accordance with this section includes an engineering evaluation program to analyze and account for the susceptibility of girth weld failure due to lateral stresses. 192.632(c)(2)
(3) Inline inspection must be performed in accordance with §192.493. 192.632(c)(3)
(4) An operator must use unity plots or equivalent methodologies to validate the performance of the ILI tools in identifying and sizing actionable manufacturing and construction related anomalies. Enough data points must be used to validate tool performance at the same or better statistical confidence level provided in the tool specifications. The operator must have a process for identifying defects outside the tool performance specifications and following up with the ILI vendor to conduct additional in-field examinations, reanalyze ILI data, or both. 192.632(c)(4)
(5) Interpretation and evaluation of assessment results must meet the requirements of §§192.710, 192.713, and subpart O of this part, and must conservatively account for the accuracy and reliability of ILI, inthe-ditch examination methods and tools, and any other assessment and examination results used to determine the actual sizes of cracks, metal loss, deformation and other defect dimensions by applying the most conservative limit of the tool tolerance specification. ILI and in-the-ditch examination tools and procedures for crack assessments (length and depth) must have performance and evaluation standards confirmed for accuracy through confirmation tests for the defect types and pipe material vintage being evaluated. Inaccuracies must be accounted for in the procedures for evaluations and fracture mechanics models for predicted failure pressure determinations. 192.632(c)(5)
(6) Anomalies detected by ILI assessments must be remediated in accordance with applicable criteria in §§192.713 and 192.933. 192.632(c)(6)
(d) Defect remaining life. If any pipeline segment contains cracking or may be susceptible to cracking or crack-like defects found through or identified by assessments, leaks, failures, manufacturing vintage histories, or any other available information about the pipeline, the operator must estimate the remaining life of the pipeline in accordance with §192.712. 192.632(d)
(e) Records. An operator must retain records of investigations, tests, analyses, assessments, repairs, replacements, alterations, and other actions taken in accordance with the requirements of this section for the life of the pipeline. 192.632(e)
§192.634 Transmission lines: Onshore valve shut-off for rupture mitigation.
(a) Applicability. For new or entirely replaced onshore transmission pipeline segments with diameters of 6 inches or greater that are located in high-consequence areas (HCA) or Class 3 or Class 4 locations and that are installed after April 10, 2023, an operator must install or use existing rupture-mitigation valves (RMV), or an alternative equivalent technology, according to the requirements of this section and §§192.179 and 192.636. RMVs and alternative equivalent technologies must be operational within 14 days of placing the new or replaced pipeline segment into service. An operator may request an extension of this 14-day operation requirement if it can demonstrate to PHMSA, in accordance with the notification procedures in §192.18, that application of that requirement would be economically, technically, or operationally infeasible. The requirements of this section apply to all applicable pipe replacement projects, even those that do not otherwise involve the addition or replacement of a valve. This section does not apply to pipe segments in Class 1 or Class 2 locations that have a potential impact radius (PIR), as defined in §192.903, that is less than or equal to 150 feet. 192.634(a)
(b) Maximum spacing between valves. RMVs, or alternative equivalent technology, must be installed in accordance with the following requirements: 192.634(b)
(1) Shut-off segment. For purposes of this section, a “shut-off segment” means the segment of pipe located between the upstream valve closest to the upstream endpoint of the new or replaced Class 3 or Class 4 or HCA pipeline segment and the downstream valve closest to the downstream endpoint of the new or replaced Class 3 or Class 4 or HCA pipeline segment so that the entirety of the segment that is within the HCA or the Class 3 or Class 4 location is between at least two RMVs or alternative equivalent technologies. If any crossover or
lateral pipe for gas receipts or deliveries connects to the shut-off segment between the upstream and downstream valves, the shutoff segment also must extend to a valve on the crossover connection(s) or lateral(s), such that, when all valves are closed, there is no flow path for gas to be transported to the rupture site (except for residual gas already in the shut-off segment). Multiple Class 3 or Class 4 locations or HCA segments may be contained within a single shut-off segment. The operator is not required to select the closest valve to the shut-off segment as the RMV, as that term is defined in §192.3, or the alternative equivalent technology. An operator may use a manual compressor station valve at a continuously manned station as an alternative equivalent technology, but it must be able to be closed within 30 minutes following rupture identification, as that term is defined at §192.3. Such a valve used as an alternative equivalent technology would not require a notification to PHMSA in accordance with §192.18. 192.634(b)(1)
(2) Shut-off segment valve spacing. A pipeline subject to paragraph (a) of this section must have RMVs or alternative equivalent technology on the upstream and downstream side of the pipeline segment. The distance between RMVs or alternative equivalent technologies must not exceed: 192.634(b)(2)
(i) Eight (8) miles for any Class 4 location, 192.634(b)(2)(i)
(ii) Fifteen (15) miles for any Class 3 location, or 192.634(b)(2)(ii)
(iii) Twenty (20) miles for all other locations. 192.634(b)(2)(iii)
(3) Laterals. Laterals extending from shut-off segments that contribute less than 5 percent of the total shut-off segment volume may have RMVs or alternative equivalent technologies that meet the actuation requirements of this section at locations other than mainline receipt/ delivery points, as long as all of the laterals contributing gas volumes to the shut-off segment do not contribute more than 5 percent of the total shut-off segment gas volume based upon maximum flow volume at the operating pressure. For laterals that are 12 inches in diameter or less, a check valve that allows gas to flow freely in one direction and contains a mechanism to automatically prevent flow in the other direction may be used as an alternative equivalent technology where it is positioned to stop flow into the shut-off segment. Such check valves that are used as an alternative equivalent technology in accordance with this paragraph are not subject to §192.636, but they must be inspected, operated, and remediated in accordance with §192.745, including for closure and leakage to ensure operational reliability. An operator using such a check valve as an alternative equivalent technology must notify PHMSA in accordance with §§192.18 and 192.179 develop and implement maintenance procedures for such equipment that meet §192.745. 192.634(b)(3)
(4) Crossovers. An operator may use a manual valve as an alternative equivalent technology in lieu of an RMV for a crossover connection if, during normal operations, the valve is closed to prevent the flow of gas by the use of a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator. The operator must develop and implement operating procedures and document that the valve has been closed and locked in accordance with the operator's lock-out and tag-out procedures to prevent the flow of gas. An operator using such a manual valve as an alternative equivalent technology must notify PHMSA in accordance with §§192.18 and 192.179. 192.634(b)(4)
(c) Manual operation upon identification of a rupture. Operators using a manual valve as an alternative equivalent technology as authorized pursuant to §§192.18 and 192.179 must develop and implement operating procedures that appropriately designate and locate nearby personnel to ensure valve shut-off in accordance with this section and §192.636. Manual operation of valves must include time for the assembly of necessary operating personnel, the acquisition of necessary tools and equipment, driving time under heavy traffic conditions and at the posted speed limit, walking time to access the valve, and time to shut off all valves manually, not to exceed the maximum response time allowed under §192.636(b). 192.634(c)
§192.635 Notification of potential rupture
(a) As used in this part, a “notification of potential rupture” refers to the notification of, or observation by, an operator (e.g., by or to its controller(s) in a control room, field personnel, nearby pipeline or utility personnel, the public, local responders, or public authorities) of one or more of the below indicia of a potential unintentional or uncontrolled release of a large volume of gas from a pipeline: 192.635(a)
(1) An unanticipated or unexplained pressure loss outside of the pipeline's normal operating pressures, as defined in the operator's written procedures. The operator must establish in its written procedures that an unanticipated or unplanned pressure loss is outside of the pipeline's normal operating pressures when there is a pressure loss greater than 10 percent occurring within a time interval of 15 minutes or less, unless the operator has documented in its written procedures the operational need for a greater pressure-change threshold due to pipeline flow dynamics (including changes in operating pressure, flow rate, or volume), that are caused by fluctuations in gas demand, gas receipts, or gas deliveries; or 192.635(a)(1)
(2) An unanticipated or unexplained flow rate change, pressure change, equipment function, or other pipeline instrumentation indication at the upstream or downstream station that may be representative of an event meeting paragraph (a)(1) of this section; or 192.635(a)(2)
(3) Any unanticipated or unexplained rapid release of a large volume of gas, a fire, or an explosion in the immediate vicinity of the pipeline. 192.635(a)(3)
(b) A notification of potential rupture occurs when an operator first receives notice of or observes an event specified in paragraph (a) of this section. 192.635(b)
§192.636 Transmission lines: Response to a rupture; capabilities of rupture-mitigation valves (RMVs) or alternative equivalent technologies
(a) Scope. The requirements in this section apply to rupture-mitigation valves (RMVs), as defined in §192.3, or alternative equivalent technologies, installed pursuant to §§192.179(e), (f), and (g) and 192.634. 192.636(a)
(b) Rupture identification and valve shut-off time. An operator must, as soon as practicable but within 30 minutes of rupture identification (see §192.615(a)(12)), fully close any RMVs or alternative equivalent technologies necessary to minimize the volume of gas released from a pipeline and mitigate the consequences of a rupture. 192.636(b)
(c) Open valves. An operator may leave an RMV or alternative equivalent technology open for more than 30 minutes, as required by paragraph (b) of this section, if the operator has previously established in its operating procedures and demonstrated within a notice submitted under §192.18 for PHMSA review, that closing the RMV or alternative equivalent technology would be detrimental to public safety. The request must have been coordinated with appropriate local emergency responders, and the operator and emergency responders must determine that it is safe to leave the valve open. Operators must have written procedures for determining whether to leave an RMV or alternative equivalent technology open, including plans to communicate with local emergency responders and minimize environmental impacts, which must be submitted as part of its notification to PHMSA. 192.636(c)
(d) Valve monitoring and operation capabilities. An RMV, as defined in §192.3, or alternative equivalent technology, must be capable of being monitored or controlled either remotely or by on-site personnel as follows: 192.636(d)
(1) Operated during normal, abnormal, and emergency operating conditions; 192.636(d)(1)
(2) Monitored for valve status (i.e., open, closed, or partial closed/ open), upstream pressure, and downstream pressure. For automatic shut-off valves (ASV), an operator does not need to monitor remotely a valve's status if the operator has the capability to monitor pressures or gas flow rate within each pipeline segment located between RMVs or alternative equivalent technologies to identify and locate a rupture. Pipeline segments that use manual valves or other alternative equivalent technologies must have the capability to monitor pressures or gas flow rates on the pipeline to identify and locate a rupture; and 192.636(d)(2)
(3) Have a back-up power source to maintain SCADA systems or other remote communications for remote-control valve (RCV) or automatic shut-off valve (ASV) operational status, or be monitored and controlled by on-site personnel. 192.636(d)(3)
(e) Monitoring of valve shut-off response status. The position and operational status of an RMV must be appropriately monitored through electronic communication with remote instrumentation or other equivalent means. An operator does not need to monitor remotely an ASV's status if the operator has the capability to monitor pressures or gas flow rate on the pipeline to identify and locate a rupture. 192.636(e)
(f) Flow modeling for automatic shut-off valves. Prior to using an ASV as an RMV, an operator must conduct flow modeling for the shutoff segment and any laterals that feed the shut-off segment, so that the valve will close within 30 minutes or less following rupture identification, consistent with the operator's procedures, and in accordance with §192.3 and this section. The flow modeling must include the anticipated maximum, normal, or any other flow volumes, pressures, or other operating conditions that may be encountered during the year, not exceeding a period of 15 months, and it must be modeled for the flow between the RMVs or alternative equivalent technologies, and any looped pipelines or gas receipt tie-ins. If operating conditions change that could affect the ASV set pressures and the 30-minute valve closure time after notification of potential rupture, as defined at §192.3, an operator must conduct a new flow model and reset the ASV set pressures prior to the next review for ASV set pressures in accordance with §192.745. The flow model must include a time/pressure chart for the segment containing the ASV if a rupture occurs. An operator must conduct this flow modeling prior to making flow condition changes in a manner that could render the 30-minute valve closure time unachievable. 192.636(f)
(g) Manual valves in non-HCA, Class 1 locations. For pipeline segments in a Class 1 location that do not meet the definition of a high consequence area (HCA), an operator submitting a notification pursuant to
§192.710 Part 192 – Minimum Federal Safety Standards
§§192.18 and 192.179 for use of manual valves as an alternative equivalent technology may also request an exemption from the requirements of §192.636(b). 192.636(g)
Subpart M – Maintenance
§192.701 Scope
This subpart prescribes minimum requirements for maintenance of pipeline facilities.
§192.703 General
(a) No person may operate a segment of pipeline, unless it is maintained in accordance with this subpart. 192.703(a)
(b) Each segment of pipeline that becomes unsafe must be replaced, repaired, or removed from service. 192.703(b)
(c) Hazardous leaks must be repaired promptly. 192.703(c)
§192.705 Transmission lines: Patrolling
(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. 192.705(a)
(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: 192.705(b)
1, 2 71⁄2 months; but at least twice each
3 41⁄2 months; but at least four times each calendar year 71 2 months; but at least twice each calendar year.
4 41⁄2 months; but at least four times each calendar year 41 2 months; but at least four times each calendar year.
(c) Methods of patrolling include walking, driving, flying or other appropriate means of traversing the right-of-way. 192.705(c)
[Amdt. 192-21, 40 FR 20283, May 9, 1975, as amended by Amdt. 192-43, 47 FR 46851, Oct. 21, 1982; Amdt. 192-78, 61 FR 28786, June 6, 1996]
§192.706
Transmission lines: Leakage surveys
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 71⁄2 months, but at least twice each calendar year; and 192.706(a)
(b) In Class 4 locations, at intervals not exceeding 41⁄2 months, but at least four times each calendar year. 192.706(b)
[Amdt. 192-21, 40 FR 20283, May 9, 1975, as amended by Amdt. 192-43, 47 FR 46851, Oct. 21, 1982; Amdt. 192-71, 59 FR 6585, Feb. 11, 1994]
§192.707
Line markers for mains and transmission lines
(a) Buried pipelines. Except as provided in paragraph (b) of this section, a line marker must be placed and maintained as close as practical over each buried main and transmission line: 192.707(a)
(1) At each crossing of a public road and railroad; and 192.707(a)(1)
(2) Wherever necessary to identify the location of the transmission line or main to reduce the possibility of damage or interference. 192.707(a)(2)
(b) Exceptions for buried pipelines. Line markers are not required for the following pipelines: 192.707(b)
(1) Mains and transmission lines located offshore, or at crossings of or under waterways and other bodies of water. 192.707(b)(1)
(2) Mains in Class 3 or Class 4 locations where a damage prevention program is in effect under §192.614. 192.707(b)(2)
(3) Transmission lines in Class 3 or 4 locations until March 20, 1996. 192.707(b)(3)
(4) Transmission lines in Class 3 or 4 locations where placement of a line marker is impractical. 192.707(b)(4)
(c) Pipelines aboveground. Line markers must be placed and maintained along each section of a main and transmission line that is located aboveground in an area accessible to the public. 192.707(c)
(d) Marker warning. The following must be written legibly on a background of sharply contrasting color on each line marker: 192.707(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 1⁄4 inch (6.4 millimeters) stroke. 192.707(d)(1)
(2) The name of the operator and the telephone number (including area code) where the operator can be reached at all times. 192.707(d)(2)
[Amdt. 192-20, 40 FR 13505, Mar. 27, 1975; Amdt. 192-27, 41 FR 39752, Sept. 16, 1976, as amended by Amdt. 19220A, 41 FR 56808, Dec. 30, 1976; Amdt. 192-44, 48 FR 25208, June 6, 1983; Amdt. 192-73, 60 FR 14650, Mar. 20, 1995; Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.709
Transmission lines: Record keeping
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. 192.709(a)
(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. 192.709(b)
(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. 192.709(c)
[Amdt. 192-78, 61 FR 28786, June 6, 1996]
§192.710 Transmission lines: Assessments outside of high consequence areas.
(a) Applicability: This section applies to onshore steel transmission pipeline segments with a maximum allowable operating pressure of greater than or equal to 30% of the specified minimum yield strength and are located in: 192.710(a)
(1) A Class 3 or Class 4 location; or 192.710(a)(1)
(2) A moderate consequence area as defined in §192.3, if the pipeline segment can accommodate inspection by means of an instrumented inline inspection tool (i.e., “smart pig”). 192.710(a)(2)
(3) This section does not apply to a pipeline segment located in a high consequence area as defined in §192.903. 192.710(a)(3)
(b) General 192.710(b)
(1) Initial assessment. An operator must perform initial assessments in accordance with this section based on a risk-based prioritization schedule and complete initial assessment for all applicable pipeline segments no later than July 3, 2034, or as soon as practicable but not to exceed 10 years after the pipeline segment first meets the conditions of §192.710(a) (e.g., due to a change in class location or the area becomes a moderate consequence area), whichever is later. 192.710(b)(1)
(2) Periodic reassessment. An operator must perform periodic reassessments at least once every 10 years, with intervals not to exceed 126 months, or a shorter reassessment interval based upon the type of anomaly, operational, material, and environmental conditions found on the pipeline segment, or as necessary to ensure public safety. 192.710(b)(2)
(3) Prior assessment. An operator may use a prior assessment conducted before July 1, 2020 as an initial assessment for the pipeline segment, if the assessment met the subpart O requirements of part 192 for in-line inspection at the time of the assessment. If an operator uses this prior assessment as its initial assessment, the operator must reassess the pipeline segment according to the reassessment interval specified in paragraph (b)(2) of this section calculated from the date of the prior assessment. 192.710(b)(3)
(4) MAOP verification. An integrity assessment conducted in accordance with the requirements of §192.624(c) for establishing MAOP may be used as an initial assessment or reassessment under this section. 192.710(b)(4)
(c) Assessment method. The initial assessments and the reassessments required by paragraph (b) of this section must be capable of identifying anomalies and defects associated with each of the threats to which the pipeline segment is susceptible and must be performed using one or more of the following methods: 192.710(c)
(1) Internal inspection. Internal inspection tool or tools capable of detecting those threats to which the pipeline is susceptible, such as corrosion, deformation and mechanical damage (e.g., dents, gouges and grooves), material cracking and crack-like defects (e.g., stress corrosion cracking, selective seam weld corrosion, environ-
mentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with §192.493; 192.710(c)(1)
(2) Pressure test. Pressure test conducted in accordance with subpart J of this part. The use of subpart J pressure testing is appropriate for threats such as internal corrosion, external corrosion, and other environmentally assisted corrosion mechanisms; manufacturing and related defect threats, including defective pipe and pipe seams; and stress corrosion cracking, selective seam weld corrosion, dents and other forms of mechanical damage; 192.710(c)(2)
(3) Spike hydrostatic pressure test. A spike hydrostatic pressure test conducted in accordance with §192.506. A spike hydrostatic pressure test is appropriate for time-dependent threats such as stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; 192.710(c)(3)
(4) Direct examination. Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded non-destructive examination results and data needed to assess all applicable threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), Inverse Wave Field Extrapolation (IWEX), radiography, and magnetic particle inspection (MPI); 192.710(c)(4)
(5) Guided Wave Ultrasonic Testing. Guided Wave Ultrasonic Testing (GWUT) as described in Appendix F; 192.710(c)(5)
(6) Direct assessment. Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in §192.923 and with the applicable requirements specified in §§192.925, 192.927 and 192.929; or 192.710(c)(6)
(7) Other technology. Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the other technology in accordance with §192.18. 192.710(c)(7)
(d) Data analysis. An operator must analyze and account for the data obtained from an assessment performed under paragraph (c) of this section to determine if a condition could adversely affect the safe operation of the pipeline using personnel qualified by knowledge, training, and experience. In addition, when analyzing inline inspection data, an operator must account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies. 192.710(d)
(e) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that 180 days is impracticable. 192.710(e)
(f) Remediation. An operator must comply with the requirements in §§192.485, 192.711, and 192.713, where applicable, if a condition that could adversely affect the safe operation of a pipeline is discovered. 192.710(f)
(g) Analysis of information. An operator must analyze and account for all available relevant information about a pipeline in complying with the requirements in paragraphs (a) through (f) of this section. 192.710(g)
§192.711 Transmission lines: General requirements for repair procedures
(a) Temporary repairs. Each operator must take immediate temporary measures to protect the public whenever: 192.711(a)
(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 192.711(a)(1)
(2) It is not feasible to make a permanent repair at the time of discovery. 192.711(a)(2)
(b) Permanent repairs. An operator must make permanent repairs on its pipeline system according to the following: 192.711(b)
(1) Non integrity management repairs: The operator must make permanent repairs as soon as feasible. 192.711(b)(1)
(2) Integrity management repairs: When an operator discovers a condition on a pipeline covered under Subpart O-Gas Transmission Pipeline Integrity Management, the operator must remediate the condition as prescribed by §192.933(d). 192.711(b)(2)
(c) Welded patch. Except as provided in §192.717(b)(3), no operator may use a welded patch as a means of repair. 192.711(c)
[Amdt. 192-114, 75 FR 48604, Aug. 11, 2010]
§192.712 Analysis of predicted failure pressure.
(a) Applicability. Whenever required by this part, operators of onshore steel transmission pipelines must analyze anomalies or defects to determine the predicted failure pressure at the location of the anomaly or defect, and the remaining life of the pipeline segment at the location of the anomaly or defect, in accordance with this section. 192.712(a)
(b) Corrosion metal loss. When analyzing corrosion metal loss under this section, an operator must use a suitable remaining strength calculation method including, ASME/ANSI B31G (incorporated by reference, see §192.7); R-STRENG (incorporated by reference, see §192.7); or an alternative equivalent method of remaining strength calculation that will provide an equally conservative result. 192.712(b)
(c) [Reserved] 192.712(c)
(d) Cracks and crack-like defects 192.712(d)
(1) Crack analysis models. When analyzing cracks and crack-like defects under this section, an operator must determine predicted failure pressure, failure stress pressure, and crack growth using a technically proven fracture mechanics model appropriate to the failure mode (ductile, brittle or both), material properties (pipe and weld properties), and boundary condition used (pressure test, ILI, or other). 192.712(d)(1)
(2) Analysis for crack growth and remaining life. If the pipeline segment is susceptible to cyclic fatigue or other loading conditions that could lead to fatigue crack growth, fatigue analysis must be performed using an applicable fatigue crack growth law (for example, Paris Law) or other technically appropriate engineering methodology. For other degradation processes that can cause crack growth, appropriate engineering analysis must be used. The above methodologies must be validated by a subject matter expert to determine conservative predictions of flaw growth and remaining life at the maximum allowable operating pressure. The operator must calculate the remaining life of the pipeline by determining the amount of time required for the crack to grow to a size that would fail at maximum allowable operating pressure. 192.712(d)(2)
(i) When calculating crack size that would fail at MAOP, and the material toughness is not documented in traceable, verifiable, and complete records, the same Charpy v-notch toughness value established in paragraph (e)(2) of this section must be used.192.712(d)(2)(i)
(ii) Initial and final flaw size must be determined using a fracture mechanics model appropriate to the failure mode (ductile, brittle or both) and boundary condition used (pressure test, ILI, or other).192.712(d)(2)(ii)
(iii) An operator must re-evaluate the remaining life of the pipeline before 50% of the remaining life calculated by this analysis has expired. The operator must determine and document if further pressure tests or use of other assessment methods are required at that time. The operator must continue to re-evaluate the remaining life of the pipeline before 50% of the remaining life calculated in the most recent evaluation has expired. 192.712(d)(2)(iii)
(3) Cracks that survive pressure testing. For cases in which the operator does not have in-line inspection crack anomaly data and is analyzing potential crack defects that could have survived a pressure test, the operator must calculate the largest potential crack defect sizes using the methods in paragraph (d)(1) of this section. If pipe material toughness is not documented in traceable, verifiable, and complete records, the operator must use one of the following for Charpy v-notch toughness values based upon minimum operational temperature and equivalent to a full-size specimen value: 192.712(d)(3)
(i) Charpy v-notch toughness values from comparable pipe with known properties of the same vintage and from the same steel and pipe manufacturer;192.712(d)(3)(i)
(ii) A conservative Charpy v-notch toughness value to determine the toughness based upon the material properties verification process specified in §192.607;192.712(d)(3)(ii)
(iii) A full size equivalent Charpy v-notch upper-shelf toughness level of 120 ft.-lbs.; or192.712(d)(3)(iii)
(iv) Other appropriate values that an operator demonstrates can provide conservative Charpy v-notch toughness values of the crack-related conditions of the pipeline segment. Operators using an assumed Charpy v-notch toughness value must notify PHMSA in accordance with §192.18.192.712(d)(3)(iv)
(e) Data. In performing the analyses of predicted or assumed anomalies or defects in accordance with this section, an operator must use data as follows. 192.712(e)
(1) An operator must explicitly analyze and account for uncertainties in reported assessment results (including tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying tool performance) in identifying and characterizing the type and dimensions of anomalies or defects used in the analyses, unless the defect dimensions have been verified using in situ direct measurements. 192.712(e)(1)
(2) The analyses performed in accordance with this section must utilize pipe and material properties that are documented in traceable, verifiable, and complete records. If documented data required for any analysis is not available, an operator must obtain the undocumented data through §192.607. Until documented material properties are available, the operator shall use conservative assumptions as follows: 192.712(e)(2)
(i) Material toughness. An operator must use one of the following for material toughness:192.712(e)(2)(i)
[A] Charpy v-notch toughness values from comparable pipe with known properties of the same vintage and from the same steel and pipe manufacturer;192.712(e)(2)(i)[A]
[B] A conservative Charpy v-notch toughness value to determine the toughness based upon the ongoing material properties verification process specified in §192.607; 192.712(e)(2)(i)[B]
[C] If the pipeline segment does not have a history of reportable incidents caused by cracking or crack-like defects, maximum Charpy v-notch toughness values of 13.0 ft.-lbs. for body cracks and 4.0 ft.-lbs. for cold weld, lack of fusion, and selective seam weld corrosion defects;192.712(e)(2)(i)[C]
[D] If the pipeline segment has a history of reportable incidents caused by cracking or crack-like defects, maximum Charpy v-notch toughness values of 5.0 ft.-lbs. for body cracks and 1.0 ft.-lbs. for cold weld, lack of fusion, and selective seam weld corrosion; or192.712(e)(2)(i)[D]
[E] Other appropriate values that an operator demonstrates can provide conservative Charpy v-notch toughness values of crack-related conditions of the pipeline segment. Operators using an assumed Charpy v-notch toughness value must notify PHMSA in advance in accordance with §192.18 and include in the notification the bases for demonstrating that the Charpy v-notch toughness values proposed are appropriate and conservative for use in analysis of crack-related conditions.192.712(e)(2)(i)[E]
(ii) Material strength. An operator must assume one of the following for material strength:192.712(e)(2)(ii)
[A] Grade A pipe (30,000 psi), or192.712(e)(2)(ii)[A]
[B] The specified minimum yield strength that is the basis for the current maximum allowable operating pressure. 192.712(e)(2)(ii)[B]
(iii) Pipe dimensions and other data. Until pipe wall thickness, diameter, or other data are determined and documented in accordance with §192.607, the operator must use values upon which the current MAOP is based.192.712(e)(2)(iii)
(f) Review. Analyses conducted in accordance with this section must be reviewed and confirmed by a subject matter expert. 192.712(f)
(g) Records. An operator must keep for the life of the pipeline records of the investigations, analyses, and other actions taken in accordance with the requirements of this section. Records must document justifications, deviations, and determinations made for the following, as applicable: 192.712(g)
(1) The technical approach used for the analysis; 192.712(g)(1)
(2) All data used and analyzed; 192.712(g)(2)
(3) Pipe and weld properties; 192.712(g)(3)
(4) Procedures used; 192.712(g)(4)
(5) Evaluation methodology used; 192.712(g)(5)
(6) Models used; 192.712(g)(6)
(7) Direct in situ examination data; 192.712(g)(7)
(8) In-line inspection tool run information evaluated, including any multiple in-line inspection tool runs; 192.712(g)(8)
(9) Pressure test data and results; 192.712(g)(9)
(10) In-the-ditch assessments; 192.712(g)(10)
(11) All measurement tool, assessment, and evaluation accuracy specifications and tolerances used in technical and operational results; 192.712(g)(11)
(12) All finite element analysis results; 192.712(g)(12)
(13) The number of pressure cycles to failure, the equivalent number of annual pressure cycles, and the pressure cycle counting method; 192.712(g)(13)
(14) The predicted fatigue life and predicted failure pressure from the required fatigue life models and fracture mechanics evaluation methods; 192.712(g)(14)
(15) Safety factors used for fatigue life and/or predicted failure pressure calculations; 192.712(g)(15)
(16) Reassessment time interval and safety factors; 192.712(g)(16)
(17) The date of the review; 192.712(g)(17)
(18) Confirmation of the results by qualified technical subject matter experts; and 192.712(g)(18)
(19) Approval by responsible operator management personnel. 192.712(g)(19)
§192.713 Transmission lines: Permanent field repair of imperfections and damages
(a) Each imperfection or damage that impairs the serviceability of pipe in a steel transmission line operating at or above 40 percent of SMYS must be — 192.713(a)
(1) Removed by cutting out and replacing a cylindrical piece of pipe; or 192.713(a)(1)
(2) Repaired by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. 192.713(a)(2)
(b) Operating pressure must be at a safe level during repair operations. 192.713(b)
[Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]
§192.715 Transmission lines: Permanent field repair of welds
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. 192.715(a)
(b) A weld may be repaired in accordance with §192.245 while the segment of transmission line is in service if: 192.715(b)
(1) The weld is not leaking; 192.715(b)(1)
(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 192.715(b)(2)
(3) Grinding of the defective area can be limited so that at least 1⁄8-inch (3.2 millimeters) thickness in the pipe weld remains. 192.715(b)(3)
(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. 192.715(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.717 Transmission lines: Permanent field repair of leaks
Each permanent field repair of a leak on a transmission line must be made by —
(a) Removing the leak by cutting out and replacing a cylindrical piece of pipe; or 192.717(a)
(b) Repairing the leak by one of the following methods: 192.717(b)
(1) Install a full encirclement welded split sleeve of appropriate design, unless the transmission line is joined by mechanical couplings and operates at less than 40 percent of SMYS. 192.717(b)(1)
(2) If the leak is due to a corrosion pit, install a properly designed bolton-leak clamp. 192.717(b)(2)
(3) If the leak is due to a corrosion pit and on pipe of not more than 40,000 psi (267 Mpa) SMYS, fillet weld over 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. 192.717(b)(3)
(4) If the leak is on a submerged offshore pipeline or submerged pipeline in inland navigable waters, mechanically apply a full encirclement split sleeve of appropriate design. 192.717(b)(4)
(5) Apply a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. 192.717(b)(5)
[Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]
§192.719 Transmission lines: Testing of repairs
(a) Testing of replacement pipe. If a segment of transmission line is repaired by cutting out the damaged portion of the pipe as a cylinder, the replacement pipe must be tested to the pressure required for a new line installed in the same location. This test may be made on the pipe before it is installed. 192.719(a)
(b) Testing of repairs made by welding. Each repair made by welding in accordance with §§192.713, 192.715, and 192.717 must be examined in accordance with §192.241. 192.719(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-54, 51 FR 41635, Nov. 18, 1986]
§192.720 Distribution systems: Leak repair
Mechanical leak repair clamps installed after January 22, 2019 may not be used as a permanent repair method for plastic pipe.
[Amdt. 192-124, 83 FR 58719, Nov. 20, 2018]
§192.721 Distribution systems: Patrolling
(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. 192.721(a)
(b) Mains in places or on structures where anticipated physical movement or external loading could cause failure or leakage must be patrolled — 192.721(b)
(1) In business districts, at intervals not exceeding 41⁄2 months, but at least four times each calendar year; and 192.721(b)(1)
(2) Outside business districts, at intervals not exceeding 71⁄2 months, but at least twice each calendar year. 192.721(b)(2)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, Oct. 21, 1982; Amdt. 192-78, 61 FR 28786, June 6, 1996]
§192.723 Distribution systems: Leakage surveys
(a) Each operator of a distribution system shall conduct periodic leakage surveys in accordance with this section. 192.723(a)
(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: 192.723(b)
(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. 192.723(b)(1)
(2) A leakage survey with leak detector equipment must be conducted outside business districts as frequently as necessary, but at least once every 5 calendar years at intervals not exceeding 63 months. However, for cathodically unprotected distribution lines subject to §192.465(e) on which electrical surveys for corrosion are impractical, a leakage survey must be conducted at least once every 3 calendar years at intervals not exceeding 39 months. 192.723(b)(2)
(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. 192.725(a)
(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. 192.725(b)
§192.727 Abandonment or deactivation of facilities
(a) Each operator shall conduct abandonment or deactivation of pipelines in accordance with the requirements of this section. 192.727(a)
(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. 192.727(b)
(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. 192.727(c)
(d) Whenever service to a customer is discontinued, one of the following must be complied with: 192.727(d)
(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. 192.727(d)(1)
(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. 192.727(d)(2)
(3) The customer's piping must be physically disconnected from the gas supply and the open pipe ends sealed. 192.727(d)(3)
(e) If air is used for purging, the operator shall insure that a combustible mixture is not present after purging. 192.727(e)
(f) Each abandoned vault must be filled with a suitable compacted material. 192.727(f)
(g) For each abandoned offshore pipeline facility or each abandoned onshore pipeline facility that crosses over, under or through a commercially navigable waterway, the last operator of that facility must file a report upon abandonment of that facility. 192.727(g)
(1) The preferred method to submit data on pipeline facilities abandoned after October 10, 2000 is to the National Pipeline Mapping System (NPMS) in accordance with the NPMS "Standards for Pipeline and Liquefied Natural Gas Operator Submissions." To obtain a copy of the NPMS Standards, please refer to the NPMS homepage at http://www.npms.phmsa.dot.gov or contact the NPMS National Repository at 703-317-3073. A digital data format is preferred, but hard copy submissions are acceptable if they comply with the NPMS Standards. In addition to the NPMS-required attributes, operators must submit the date of abandonment, diameter, method of abandonment, and certification that, to the best of the operator's knowledge, all of the reasonably available information requested was provided and, to the best of the operator's knowledge, the abandonment was completed in accordance with applicable laws. Refer to the NPMS Standards for details in preparing your data for submission. The NPMS Standards also include details of how to submit data. Alternatively, operators may submit reports by mail, fax or e-mail to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001; fax (202) 366-4566; e-mail InformationResourcesManager@phmsa.dot.gov. The information in the report must contain all reasonably available information related to the facility, including information in the possession of a third party. The report must contain the location, size, date, method of abandonment, and a certification that the facility has been abandoned in accordance with all applicable laws. 192.727(g)(1) (2) [Reserved] 192.727(g)(2)
Advisory Bulletin: Clarification of Terms Relating to Pipeline Operational Status.
Question 1: Do PHMSA regulations recognize an "idle" status for a hazardous liquid or gas pipelines?
PHMSA regulations do not recognize an "idle" status for a hazardous liquid or gas pipelines. The regulations consider pipelines to be either active and fully subject to all parts of the safety regulations or abandoned. The process and requirements for pipeline abandonment are captured in §§192.727 and 195.402(c)(10) for gas and hazardous liquid pipelines, respectively. Pipelines abandoned after the effective date of the regulations must comply with requirements to purge all combustibles and seal any facilities left in place. The last owner or operator of abandoned offshore facilities and abandoned onshore facilities that cross over, under, or through commercially navigable waterways must file a report with PHMSA. PHMSA regulations define the term "abandoned" to mean permanently removed from service.
Companies that own pipelines abandoned prior to the effective date of the abandonment regulations may not have access to records relating to where these pipelines are located or whether they were properly purged of combustibles and sealed. To the extent feasible, owners and operators have a responsibility to assure facilities for which they are responsible or last owned do not present a hazard to people, property or the environment.
Pipelines not currently in operation are sometimes informally referred to as "idled", "inactive", or "decommissioned". These pipelines may be shut down and still contain hazardous liquids or gas. Usually, the mainline valves on these pipelines are closed, isolating them from other pipeline segments. If a pipeline is not properly abandoned and may be used in the future for transportation of hazardous liquid or gas, PHMSA regulations consider it as an active pipeline. Owners and operators of pipelines that are not operating but contain hazardous liquids and gas must comply with all applicable safety requirements, including periodic maintenance, integrity management assessments, damage prevention programs, response planning, and public awareness programs.
PHMSA is aware that some owners and operators may properly purge a pipeline of combustibles with the expectation to later use that pipeline in hazardous materials transportation. A purged pipeline presents different risks, and therefore different regulatory treatment may be appropriate. Degradation of such a pipeline can occur, but is not likely to result in significant safety impacts to people, property, or the environment. PHMSA will accept deferral of certain activities for purged but active pipelines. These deferred activities might include actions impractical on most purged pipelines, such as in-line inspection. PHMSA is considering proposing procedures in a future rulemaking that would address methods owners or operators could use to notify regulators of purged but active pipelines. In the interim, owners or operators planning to defer certain
activities for purged pipelines should coordinate the deferral in advance with regulators. All deferred activities must be completed prior to, or as part of, any later return-to-service. Pipeline owners and operators are fully responsible for the safety of their pipeline facilities at all times and during all operational statuses.
§192.731 Compressor stations: Inspection and testing of relief devices
(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. 192.731(a)
(b) Any defective or inadequate equipment found must be promptly repaired or replaced. 192.731(b)
(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. 192.731(c)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, Oct. 21, 1982]
§192.735 Compressor stations: Storage of combustible materials
(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. 192.735(a)
(b) Aboveground oil or gasoline storage tanks must be protected in accordance with NFPA-30 (incorporated by reference, see §192.7). 192.735(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-119, 80 FR 181, Jan. 5, 2015; 80 FR 46847, Aug. 6, 2015]
§192.736 Compressor stations: Gas detection
(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 — 192.736(a)
(1) Constructed so that at least 50 percent of its upright side area is permanently open; or 192.736(a)(1)
(2) Located in an unattended field compressor station of 1,000 horsepower (746 kW) or less. 192.736(a)(2)
(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 — 192.736(b)
(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 192.736(b)(1)
(2) If that concentration of gas is detected, warn persons about to enter the building and persons inside the building of the danger. 192.736(b)(2)
(c) Each gas detection and alarm system required by this section must be maintained to function properly. The maintenance must include performance tests. 192.736(c)
[58 FR 48464, Sept. 16, 1993, as amended by Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.739 Pressure limiting and regulating stations: Inspection and testing
(a) Each pressure limiting station, relief device (except rupture discs), and pressure regulating station and its equipment must be subjected at intervals not exceeding 15 months, but at least once each calendar year, to inspections and tests to determine that it is — 192.739(a)
(1) In good mechanical condition; 192.739(a)(1)
(2) Adequate from the standpoint of capacity and reliability of operation for the service in which it is employed; 192.739(a)(2)
(3) Except as provided in paragraph (b) of this section, set to control or relieve at the correct pressure consistent with the pressure limits of §192.201(a); and 192.739(a)(3)
(4) Properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation. 192.739(a)(4)
(b) For steel pipelines whose MAOP is determined under §192.619(c), if the MAOP is 60 psi (414 kPa) gage or more, the control or relief pressure limit is as follows: 192.739(b)
§192.740
Pressure regulating, limiting, and overpressure protection — Individual service lines directly connected to regulated gathering or transmission pipelines.
(a) This section applies, except as provided in paragraph (c) of this section, to any service line directly connected to a transmission pipeline or regulated gathering pipeline as determined in §192.8 that is not operated as part of a distribution system. 192.740(a)
(b) Each pressure regulating or limiting device, relief device (except rupture discs), automatic shutoff device, and associated equipment must be inspected and tested at least once every 3 calendar years, not exceeding 39 months, to determine that it is: 192.740(b)
(1) In good mechanical condition; 192.740(b)(1)
(2) Adequate from the standpoint of capacity and reliability of operation for the service in which it is employed; 192.740(b)(2)
(3) Set to control or relieve at the correct pressure consistent with the pressure limits of §192.197; and to limit the pressure on the inlet of the service regulator to 60 psi (414 kPa) gauge or less in case the upstream regulator fails to function properly; and 192.740(b)(3)
(4) Properly installed and protected from dirt, liquids, or other conditions that might prevent proper operation. 192.740(b)(4)
(c) This section does not apply to equipment installed on: 192.740(c)
(1) A service line that only serves engines that power irrigation pumps; 192.740(c)(1)
(2) A service line included in a distribution integrity management plan meeting the requirements of subpart P of this part; or 192.740(c)(2)
(3) A service line directly connected to either a production or gathering pipeline other than a regulated gathering line as determined in §192.8 of this part. 192.740(c)(3)
[Amdt. 192-123, 82 FR 7998, Jan. 23, 2017]
§192.741 Pressure limiting and regulating stations:
Telemetering
or recording gauges
(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. 192.741(a)
(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. 192.741(b)
(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. 192.741(c)
§192.743 Pressure limiting and regulating stations: Capacity of relief devices
(a) Pressure relief devices at pressure limiting stations and pressure regulating stations must have sufficient capacity to protect the facilities to which they are connected. Except as provided in §192.739(b), the capacity must be consistent with the pressure limits of §192.201(a). This capacity must be determined at intervals not exceeding 15 months, but at least once each calendar year, by testing the devices in place or by review and calculations. 192.743(a)
(b) If review and calculations are used to determine if a device has sufficient capacity, the calculated capacity must be compared with the rated or experimentally determined relieving capacity of the device for the conditions under which it operates. After the initial calculations, subsequent calculations need not be made if the annual review documents that parameters have not changed to cause the rated or experimentally determined relieving capacity to be insufficient. 192.743(b)
(c) If a relief device is of insufficient capacity, a new or additional device must be installed to provide the capacity required by paragraph (a) of this section. 192.743(c)
[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003, as amended by Amdt. 192-96, 69 FR 27863, May 17, 2004]
§192.745 Valve maintenance: Transmission lines
(a) Each transmission line valve that might be required during any emergency must be inspected and partially operated at intervals not exceeding 15 months, but at least once each calendar year. 192.745(a)
(b) Each operator must take prompt remedial action to correct any valve found inoperable, unless the operator designates an alternative valve. 192.745(b)
(c) For each remote-control valve (RCV) installed in accordance with §192.179 or §192.634, an operator must conduct a point-to-point verification between SCADA system displays and the installed valves, sensors, and communications equipment, in accordance with §192.631(c) and (e). 192.745(c)
(d) For each alternative equivalent technology installed on an onshore pipeline under §192.179(e) or (f) or §192.634 that is manually or locally operated (i.e., not a rupture-mitigation valve (RMV), as that term is defined in §192.3): 192.745(d)
(1) Operators must achieve a valve closure time of 30 minutes or less, pursuant to §192.636(b), through an initial drill and through periodic validation as required in paragraph (d)(2) of this section. An operator must review and document the results of each phase of the drill response to validate the total response time, including confirming the rupture, and valve shut-off time as being less than or equal to 30 minutes after rupture identification. 192.745(d)(1)
(2) Within each pipeline system and within each operating or maintenance field work unit, operators must randomly select a valve serving as an alternative equivalent technology in lieu of an RMV for an annual 30-minute-total response time validation drill that simulates worst-case conditions for that location to ensure compliance with §192.636. Operators are not required to close the valve fully during the drill; a minimum 25 percent valve closure is sufficient to demonstrate compliance with drill requirements unless the operator has operational information that requires an additional closure percentage for maintaining reliability. The response drill must occur at least once each calendar year, with intervals not to exceed 15 months. Operators must include in their written procedures the method they use to randomly select which alternative equivalent technology is tested in accordance with this paragraph. 192.745(d)(2)
(3) If the 30-minute-maximum response time cannot be achieved during the drill, the operator must revise response efforts to achieve compliance with §192.636 as soon as practicable but no later than 12 months after the drill. Alternative valve shut-off measures must be in place in accordance with paragraph (e) of this section within 7 days of a failed drill. 192.745(d)(3)
(4) Based on the results of response-time drills, the operator must include lessons learned in: 192.745(d)(4)
(i) Training and qualifications programs; 192.745(d)(4)(i)
(ii) Design, construction, testing, maintenance, operating, and emergency procedures manuals; and 192.745(d)(4)(ii)
(iii) Any other areas identified by the operator as needing improvement. 192.745(d)(4)(iii)
(5) The requirements of this paragraph (d) do not apply to manual valves who, pursuant to §192.636(g), have been exempted from the requirements of §192.636(b). 192.745(d)(5)
(e) Each operator must develop and implement remedial measures to correct any valve installed on an onshore pipeline under §192.179(e) or (f) or §192.634 that is indicated to be inoperable or unable to maintain effective shut-off as follows: 192.745(e)
(1) Repair or replace the valve as soon as practicable but no later than 12 months after finding that the valve is inoperable or unable to maintain effective shut-off. An operator must request an extension from PHMSA in accordance with §192.18 if repair or replacement of a valve within 12 months would be economically, technically, or operationally infeasible; and 192.745(e)(1)
(2) Designate an alternative valve acting as an RMV within 7 calendar days of the finding while repairs are being made and document an interim response plan to maintain safety. Such valves are not required to comply with the valve spacing requirements of this part. 192.745(e)(2)
(f) An operator using an ASV as an RMV, in accordance with §§192.3, 192.179, 192.634, and 192.636, must document and confirm the ASV shut-in pressures, in accordance with §192.636(f), on a calendar year basis not to exceed 15 months. ASV shut-in set pressures must be proven and reset individually at each ASV, as required, on a calendar year basis not to exceed 15 months. 192.745(f)
[Amdt. 192-43, 47 FR 46851, Oct. 21, 1982, as amended by Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
§192.747 Valve maintenance:
Distribution systems
(a) Each valve, the use of which may be necessary for the safe operation of a distribution system, must be checked and serviced at intervals not exceeding 15 months, but at least once each calendar year. 192.747(a)
(b) Each operator must take prompt remedial action to correct any valve found inoperable, unless the operator designates an alternative valve. 192.747(b)
[Amdt. 192-43, 47 FR 46851, Oct. 21, 1982, as amended by Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
§192.749 Vault maintenance
(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. 192.749(a)
(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. 192.749(b)
(c) The ventilating equipment must also be inspected to determine that it is functioning properly. 192.749(c)
(d) Each vault cover must be inspected to assure that it does not present a hazard to public safety. 192.749(d)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, Oct. 21, 1982; Amdt. 192-85, 63 FR 37504, July 13, 1998]
§192.750 Launcher and receiver safety.
Any launcher or receiver used after July 1, 2021, must be equipped with a device capable of safely relieving pressure in the barrel before removal or opening of the launcher or receiver barrel closure or flange and insertion or removal of in-line inspection tools, scrapers, or spheres. An operator must use a device to either: Indicate that pressure has been relieved in the barrel; or alternatively prevent opening of the barrel closure or flange when pressurized, or insertion or removal of in-line devices (e.g. inspection tools, scrapers, or spheres), if pressure has not been relieved.
§192.751 Prevention
of accidental ignition
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. 192.751(a)
(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. 192.751(b)
(c) Post warning signs, where appropriate. 192.751(c)
§192.753 Caulked bell and spigot joints
(a) Each cast iron caulked bell and spigot joint that is subject to pressures of more than 25 psi (172kPa) gage must be sealed with: 192.753(a)
(1) A mechanical leak clamp; or 192.753(a)(1)
(2) A material or device which: 192.753(a)(2)
(i) Does not reduce the flexibility of the joint;192.753(a)(2)(i)
(ii) Permanently bonds, either chemically or mechanically, or both, with the bell and spigot metal surfaces or adjacent pipe metal surfaces; and192.753(a)(2)(ii)
(iii) Seals and bonds in a manner that meets the strength, environmental, and chemical compatibility requirements of §§192.53 (a) and (b) and 192.143.192.753(a)(2)(iii)
(b) Each cast iron caulked bell and spigot joint that is subject to pressures of 25 psi (172kPa) gage or less and is exposed for any reason must be sealed by a means other than caulking. 192.753(b)
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-25, 41 FR 23680, June 11, 1976; Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
§192.755 Protecting cast-iron pipelines
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: 192.755(a)
(1) Vibrations from heavy construction equipment, trains, trucks, buses, or blasting; 192.755(a)(1)
(2) Impact forces by vehicles; 192.755(a)(2)
(3) Earth movement; 192.755(a)(3)
(4) Apparent future excavations near the pipeline; or 192.755(a)(4)
(5) Other foreseeable outside forces which may subject that segment of the pipeline to bending stress. 192.755(a)(5)
(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). 192.755(b)
[Amdt. 192-23, 41 FR 13589, Mar. 31, 1976]
§192.756 Joining plastic pipe by heat fusion; equipment maintenance and calibration
Each operator must maintain equipment used in joining plastic pipe in accordance with the manufacturer's recommended practices or with written procedures that have been proven by test and experience to produce acceptable joints.
(a) This subpart prescribes the minimum requirements for operator qualification of individuals performing covered tasks on a pipeline facility. 192.801(a)
(b) For the purpose of this subpart, a covered task is an activity, identified by the operator, that: 192.801(b)
(1) Is performed on a pipeline facility; 192.801(b)(1)
(2) Is an operations or maintenance task; 192.801(b)(2)
(3) Is performed as a requirement of this part; and 192.801(b)(3)
(4) Affects the operation or integrity of the pipeline. 192.801(b)(4)
§192.803 Definitions
Abnormal operating condition means a condition identified by the operator that may indicate a malfunction of a component or deviation from normal operations that may:
(a) Indicate a condition exceeding design limits; or
(b) Result in a hazard(s) to persons, property, or the environment.
Evaluation means a process, established and documented by the operator, to determine an individual's ability to perform a covered task by any of the following:
(a) Written examination;
(b) Oral examination;
(c) Work performance history review;
(d) Observation during:
(1) Performance on the job, (2) On the job training, or (3) Simulations;
(e) Other forms of assessment.
Qualified means that an individual has been evaluated and can:
(a) Perform assigned covered tasks; and
(b) Recognize and react to abnormal operating conditions.
[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 66 FR 43523, Aug. 20, 2001]
§192.805 Qualification Program.
Each operator shall have and follow a written qualification program. The program shall include provisions to:
(a) Identify covered tasks; 192.805(a)
(b) Ensure through evaluation that individuals performing covered tasks are qualified; 192.805(b)
(c) Allow individuals that are not qualified pursuant to this subpart to perform a covered task if directed and observed by an individual that is qualified; 192.805(c)
(d) Evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an incident as defined in Part 191; 192.805(d)
(e) Evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task; 192.805(e)
(f) Communicate changes that affect covered tasks to individuals performing those covered tasks; 192.805(f)
(g) Identify those covered tasks and the intervals at which evaluation of the individual's qualifications is needed; 192.805(g)
(h) After December 16, 2004, provide training, as appropriate, to ensure that individuals performing covered tasks have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities; and 192.805(h)
(i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if an operator significantly modifies the program after the administrator or state agency has verified that it complies with this section. Notifications to PHMSA must be submitted in accordance with §192.18. 192.805(i)
[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-100, 70 FR 10335, Mar. 3, 2005; Amdt. 192120, 80 FR 12779, Mar. 11, 2015]
§192.807 Recordkeeping
Each operator shall maintain records that demonstrate compliance with this subpart.
(a) Qualification records shall include: 192.807(a)
(1) Identification of qualified individual(s); 192.807(a)(1)
(2) Identification of the covered tasks the individual is qualified to perform; 192.807(a)(2)
(3) Date(s) of current qualification; and 192.807(a)(3)
(4) Qualification method(s). 192.807(a)(4)
(b) Records supporting an individual's current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of five years. 192.807(b)
§192.809 General
(a) Operators must have a written qualification program by April 27, 2001. The program must be available for review by the Administrator or by a state agency participating under 49 U.S.C. Chapter 601 if the program is under the authority of that state agency. 192.809(a)
(b) Operators must complete the qualification of individuals performing covered tasks by October 28, 2002. 192.809(b)
(c) Work performance history review may be used as a sole evaluation method for individuals who were performing a covered task prior to October 26, 1999. 192.809(c)
(d) After October 28, 2002, work performance history may not be used as a sole evaluation method. 192.809(d)
(e) After December 16, 2004, observation of on-the-job performance may not be used as the sole method of evaluation. 192.809(e)
[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 66 FR 43524, Aug. 20, 2001; Amdt. 192100, 70 FR 10335, Mar. 3, 2005]
Subpart O – Gas Transmission Pipeline Integrity Management
§192.901 What do the regulations in this subpart cover?
This subpart prescribes minimum requirements for an integrity management program on any gas transmission pipeline covered under this part. For gas transmission pipelines constructed of plastic, only the requirements in §§192.917, 192.921, 192.935 and 192.937 apply.
§192.903 What definitions apply to this subpart?
The following definitions apply to this subpart:
Assessment is the use of testing techniques as allowed in this subpart to ascertain the condition of a covered pipeline segment.
Confirmatory direct assessment is an integrity assessment method using more focused application of the principles and techniques of direct assessment to identify internal and external corrosion in a covered transmission pipeline segment.
Covered segment or covered pipeline segment means a segment of gas transmission pipeline located in a high consequence area. The terms gas and transmission line are defined in §192.3.
Direct assessment is an integrity assessment method that utilizes a process to evaluate certain threats (i.e., external corrosion, internal corrosion and stress corrosion cracking) to a covered pipeline segment's integrity. The process includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of suspected corrosion, direct examination of the pipeline in these areas, and post assessment evaluation.
High consequence area means an area established by one of the methods described in paragraphs (1) or (2) as follows:
(1) An area defined as —
(i) A Class 3 location under §192.5; or
(ii) A Class 4 location under §192.5; or
(iii) Any area in a Class 1 or Class 2 location where the potential impact radius is greater than 660 feet (200 meters), and the area within a potential impact circle contains 20 or more buildings intended for human occupancy; or
(iv) Any area in a Class 1 or Class 2 location where the potential impact circle contains an identified site.
(2) The area within a potential impact circle containing — (i) 20 or more buildings intended for human occupancy, unless the exception in paragraph (4) applies; or
(ii) An identified site.
(3) Where a potential impact circle is calculated under either method (1) or (2) to establish a high consequence area, the length of the high consequence area extends axially along the length of
the pipeline from the outermost edge of the first potential impact circle that contains either an identified site or 20 or more buildings intended for human occupancy to the outermost edge of the last contiguous potential impact circle that contains either an identified site or 20 or more buildings intended for human occupancy. (See figure E.I.A. in appendix E.)
(4) If in identifying a high consequence area under paragraph (1)(iii) of this definition or paragraph (2)(i) of this definition, the radius of the potential impact circle is greater than 660 feet (200 meters), the operator may identify a high consequence area based on a prorated number of buildings intended for human occupancy with a distance of 660 feet (200 meters) from the centerline of the pipeline until December 17, 2006. If an operator chooses this approach, the operator must prorate the number of buildings intended for human occupancy based on the ratio of an area with a radius of 660 feet (200 meters) to the area of the potential impact circle (i.e., the prorated number of buildings intended for human occupancy is equal to 20 × (660 feet) [or 200 meters]/ potential impact radius in feet [or meters]2).
Identified site means each of the following areas:
(a) An outside area or open structure that is occupied by twenty (20) or more persons on at least 50 days in any twelve (12)-month period. (The days need not be consecutive.) Examples include but are not limited to, beaches, playgrounds, recreational facilities, camping grounds, outdoor theaters, stadiums, recreational areas near a body of water, or areas outside a rural building such as a religious facility; or
(b) A building that is occupied by twenty (20) or more persons on at least five (5) days a week for ten (10) weeks in any twelve (12)month period. (The days and weeks need not be consecutive.) Examples include, but are not limited to, religious facilities, office buildings, community centers, general stores, 4-H facilities, or roller skating rinks; or
(c) A facility occupied by persons who are confined, are of impaired mobility, or would be difficult to evacuate. Examples include but are not limited to hospitals, prisons, schools, day-care facilities, retirement facilities or assisted-living facilities.
Potential impact circle is a circle of radius equal to the potential impact radius (PIR).
Potential impact radius (PIR) means the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property. PIR is determined by the formula r = 0.69* (square root of (p*d2)), where 'r' is the radius of a circular area in feet surrounding the point of failure, 'p' is the maximum allowable operating pressure (MAOP) in the pipeline segment in pounds per square inch and 'd' is the nominal diameter of the pipeline in inches.
Note: 0.69 is the factor for natural gas. This number will vary for other gases depending upon their heat of combustion. An operator transporting gas other than natural gas must use section 3.2 of ASME/ANSI B31.8S (incorporated by reference, see §192.7) to calculate the impact radius formula.
Remediation is a repair or mitigation activity an operator takes on a covered segment to limit or reduce the probability of an undesired event occurring or the expected consequences from the event.
§192.905 How does an operator identify a high consequence area?
(a) General. To determine which segments of an operator's transmission pipeline system are covered by this subpart, an operator must identify the high consequence areas. An operator must use method (1) or (2) from the definition in §192.903 to identify a high consequence area. An operator may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. An operator must describe in its integrity management program which method it is applying to each portion of the operator's pipeline system. The description must include the potential impact radius when utilized to establish a high consequence area. (See appendix E.I. for guidance on identifying high consequence areas.) 192.905(a)
(b) (1) Identified sites. An operator must identify an identified site, for purposes of this subpart, from information the operator has obtained from routine operation and maintenance activities and from public officials with safety or emergency response or planning responsibilities who indicate to the operator that they know of locations that meet the identified site criteria. These public officials could include officials on a local emergency planning commission or relevant Native American tribal officials. 192.905(b)(1)
(2) If a public official with safety or emergency response or planning responsibilities informs an operator that it does not have the information to identify an identified site, the operator must use one of the following sources, as appropriate, to identify these sites. 192.905(b)(2)
(i) Visible marking (e.g., a sign); or192.905(b)(2)(i)
(ii) The site is licensed or registered by a Federal, State, or local government agency; or192.905(b)(2)(ii)
(iii) The site is on a list (including a list on an internet web site) or map maintained by or available from a Federal, State, or local government agency and available to the general public. 192.905(b)(2)(iii)
(c) Newly identified areas. When an operator has information that the area around a pipeline segment not previously identified as a high consequence area could satisfy any of the definitions in §192.903, the operator must complete the evaluation using method (1) or (2). If the segment is determined to meet the definition as a high consequence area, it must be incorporated into the operator's baseline assessment plan as a high consequence area within one year from the date the area is identified. 192.905(c)
§192.907 What must an operator do to implement this subpart?
(a) General. No later than December 17, 2004, an operator of a covered pipeline segment must develop and follow a written integrity management program that contains all the elements described in §192.911 and that addresses the risks on each covered transmission pipeline segment. The initial integrity management program must consist, at a minimum, of a framework that describes the process for implementing each program element, how relevant decisions will be made and by whom, a time line for completing the work to implement the program element, and how information gained from experience will be continuously incorporated into the program. The framework will evolve into a more detailed and comprehensive program. An operator must make continual improvements to the program. 192.907(a)
(b) Implementation Standards. In carrying out this subpart, an operator must follow the requirements of this subpart and of ASME/ANSI B31.8S (incorporated by reference, see §192.7) and its appendices, where specified. An operator may follow an equivalent standard or practice only when the operator demonstrates the alternative standard or practice provides an equivalent level of safety to the public and property. In the event of a conflict between this subpart and ASME/ANSI B31.8S, the requirements in this subpart control. 192.907(b)
§192.909 How can an operator change its integrity management program?
(a) General. An operator must document any change to its program and the reasons for the change before implementing the change. 192.909(a)
(b) Notification. An operator must notify OPS, in accordance with §192.18, of any change to the program that may substantially affect the program's implementation or may significantly modify the program or schedule for carrying out the program elements. An operator must provide notification within 30 days after adopting this type of change into its program. 192.909(b)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, Apr. 6, 2004]
§192.911 What are the elements of an integrity management program?
An operator's initial integrity management program begins with a framework (see §192.907) and evolves into a more detailed and comprehensive integrity management program, as information is gained and incorporated into the program. An operator must make continual improvements to its program. The initial program framework and subsequent program must, at minimum, contain the following elements. (When indicated, refer to ASME/ANSI B31.8S (incorporated by reference, see §192.7) for more detailed information on the listed element.)
(a) An identification of all high consequence areas, in accordance with §192.905. 192.911(a)
(b) A baseline assessment plan meeting the requirements of §192.919 and §192.921. 192.911(b)
(c) An identification of threats to each covered pipeline segment, which must include data integration and a risk assessment. An operator must use the threat identification and risk assessment to prioritize covered segments for assessment §192.917) and to evaluate the merits of additional preventive and mitigative measures §192.935) for each covered segment. 192.911(c)
(d) A direct assessment plan, if applicable, meeting the requirements of §192.923, and depending on the threat assessed, of §§192.925, 192.927, or 192.929. 192.911(d)
(e) Provisions meeting the requirements of §192.933 for remediating conditions found during an integrity assessment. 192.911(e)
(f) A process for continual evaluation and assessment meeting the requirements of §192.937. 192.911(f)
(g) If applicable, a plan for confirmatory direct assessment meeting the requirements of §192.931. 192.911(g)
(h) Provisions meeting the requirements of §192.935 for adding preventive and mitigative measures to protect the high consequence area. 192.911(h)
(i) A performance plan as outlined in ASME/ANSI B31.8S, section 9 that includes performance measures meeting the requirements of §192.945. 192.911(i)
§192.915 Part 192 – Minimum Federal Safety Standards
(j) Record keeping provisions meeting the requirements of §192.947. 192.911(j)
(k) A management of change process as outlined in ASME/ANSI B31.8S, section 11. 192.911(k)
(l) A quality assurance process as outlined in ASME/ANSI B31.8S, section 12. 192.911(l)
(m) A communication plan that includes the elements of ASME/ANSI B31.8S, section 10, and that includes procedures for addressing safety concerns raised by — 192.911(m) (1) OPS; and 192.911(m)(1)
(2) A State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement. 192.911(m)(2)
(n) Procedures for providing (when requested), by electronic or other means, a copy of the operator's risk analysis or integrity management program to — 192.911(n) (1) OPS; and 192.911(n)(1)
(2) A State or local pipeline safety authority when a covered segment is located in a State where OPS has an interstate agent agreement. 192.911(n)(2)
(o) Procedures for ensuring that each integrity assessment is being conducted in a manner that minimizes environmental and safety risks. 192.911(o)
(p) A process for identification and assessment of newly-identified high consequence areas. (See §192.905 and §192.921.) 192.911(p)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, Apr. 6, 2004]
§192.913 When may an operator deviate its program from certain requirements of this subpart?
(a) General. ASME/ANSI B31.8S (incorporated by reference, see §192.7) provides the essential features of a performance-based or a prescriptive integrity management program. An operator that uses a performance-based approach that satisfies the requirements for exceptional performance in paragraph (b) of this section may deviate from certain requirements in this subpart, as provided in paragraph (c) of this section. 192.913(a)
(b) Exceptional performance. An operator must be able to demonstrate the exceptional performance of its integrity management program through the following actions. 192.913(b)
(1) To deviate from any of the requirements set forth in paragraph (c) of this section, an operator must have a performance-based integrity management program that meets or exceed the performancebased requirements of ASME/ANSI B31.8S and includes, at a minimum, the following elements — 192.913(b)(1)
(i) A comprehensive process for risk analysis;192.913(b)(1)(i)
(ii) All risk factor data used to support the program;192.913(b)(1)(ii)
(iii) A comprehensive data integration process;192.913(b)(1)(iii)
(iv) A procedure for applying lessons learned from assessment of covered pipeline segments to pipeline segments not covered by this subpart;192.913(b)(1)(iv)
(v) A procedure for evaluating every incident, including its cause, within the operator's sector of the pipeline industry for implications both to the operator's pipeline system and to the operator's integrity management program;192.913(b)(1)(v)
(vi) A performance matrix that demonstrates the program has been effective in ensuring the integrity of the covered segments by controlling the identified threats to the covered segments; 192.913(b)(1)(vi)
(vii) Semi-annual performance measures beyond those required in §192.945 that are part of the operator's performance plan. (See §192.911(i).) An operator must submit these measures, by electronic or other means, on a semi-annual frequency to OPS in accordance with §192.951; and192.913(b)(1)(vii)
(viii) An analysis that supports the desired integrity reassessment interval and the remediation methods to be used for all covered segments.192.913(b)(1)(viii)
(2) In addition to the requirements for the performance-based plan, an operator must — 192.913(b)(2)
(i) Have completed at least two integrity assessments on each covered pipeline segment the operator is including under the performance-based approach, and be able to demonstrate that each assessment effectively addressed the identified threats on the covered segment.192.913(b)(2)(i)
(ii) Remediate all anomalies identified in the more recent assessment according to the requirements in §192.933, and incorporate the results and lessons learned from the more recent assessment into the operator's data integration and risk assessment.192.913(b)(2)(ii)
(c) Deviation. Once an operator has demonstrated that it has satisfied the requirements of paragraph (b) of this section, the operator may deviate from the prescriptive requirements of ASME/ANSI B31.8S and of this subpart only in the following instances. 192.913(c)
(1) The time frame for reassessment as provided in §192.939 except that reassessment by some method allowed under this subpart (e.g., confirmatory direct assessment) must be carried out at intervals no longer than seven years; 192.913(c)(1)
(2) The time frame for remediation as provided in §192.933 if the operator demonstrates the time frame will not jeopardize the safety of the covered segment. 192.913(c)(2)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, Apr. 6, 2004]
§192.915 What knowledge and training must personnel have to carry out an integrity management program?
(a) Supervisory personnel. The integrity management program must provide that each supervisor whose responsibilities relate to the integrity management program possesses and maintains a thorough knowledge of the integrity management program and of the elements for which the supervisor is responsible. The program must provide that any person who qualifies as a supervisor for the integrity management program has appropriate training or experience in the area for which the person is responsible. 192.915(a)
(b) Persons who carry out assessments and evaluate assessment results. The integrity management program must provide criteria for the qualification of any person — 192.915(b)
(1) Who conducts an integrity assessment allowed under this subpart; or 192.915(b)(1)
(2) Who reviews and analyzes the results from an integrity assessment and evaluation; or 192.915(b)(2)
(3) Who makes decisions on actions to be taken based on these assessments. 192.915(b)(3)
(c) Persons responsible for preventive and mitigative measures. The integrity management program must provide criteria for the qualification of any person — 192.915(c)
(1) Who implements preventive and mitigative measures to carry out this subpart, including the marking and locating of buried structures; or 192.915(c)(1)
(2) Who directly supervises excavation work carried out in conjunction with an integrity assessment. 192.915(c)(2)
Advisory Bulletin (ADB-2017-02): Guidance on Training and Qualifications for the Integrity Management Program
This rule requires operator personnel involved in the IM program to be qualified for their assigned responsibilities, including the following:
• Personnel qualification requirements must be identified for anyone involved in the IM program. This applies to both operator and contractor personnel (contractors, suppliers, vendors, etc.);
• Qualification criteria must include minimum requirements for experience or training in order to verify individuals have the knowledge and skills necessary to perform IM-related tasks; and
• The operator must determine whether qualifications are current.
• The rule requires operators to verify that the personnel who execute activities within the IM program are qualified in accordance with the quality assurance process required by §192.911(l).
• Documentation of qualification must be maintained in accordance with the operator's IM program.
Section 192.915(a)
— "Supervisory Personnel"
The regulation covers qualification and training requirements for supervisory personnel with responsibilities in an IM program. Personnel who carry out or evaluate assessment information must meet documented qualification requirements — this applies to both operator and contractor personnel.
• This rule requires operators to verify that the IM program requires supervisory personnel to have the appropriate training or experience for their assigned responsibilities, including the following:
• Personnel with supervisory authority that relates to the operator's IM process must meet documented qualification requirements for the aspects of the IM program that fall under their authority;
• Qualification requirements must include minimum requirements for experience or training to verify individuals have the knowledge to perform IM-related tasks; and
• Tracking of qualification deficiencies and requalification requirements is essential to verify that individuals in supervisory positions are qualified.
Section 192.915(b) — "Persons who Carry out Assessments and Evaluate Assessment Results"
The regulation covers qualification requirements for personnel performing certain IM tasks related to the conduct of integrity assessments, analysis of integrity assessment results, and the decisions on actions to be taken based on integrity assessments. This rule requires operators to verify the IM program requires qualification of personnel who carry out assessments and evaluate assessment results, including the following:
• Qualification requirements must include minimum requirements for experience or training to verify that individuals have the knowledge and skills necessary to perform IM-related tasks, including analysis, data integration, integrity assessments, and assessment results evaluation.
• Qualification requirements must be established for all tasks necessary to carry out integrity assessments and evaluate assessment results, including:
• Performing the integrity assessment;
• Evaluating the results of the integrity assessment;
• Integrating any other available information or data gathered in accordance with §192.917(b) that is applicable to the covered segment being assessed; and
• Deciding on actions to be taken based on these assessments.
• The operator is responsible for verifying the qualifications of contractor personnel who conduct essential tasks in performing or evaluating assessments.
Section 192.915(c) — "Persons Responsible for Preventive and Mitigative Measures"
The regulation covers qualification requirements for personnel who implement preventive and mitigative measures and who supervise excavation work carried out in conjunction with an integrity assessment. This rule mandates that operators verify their IM program requires qualification of personnel who participate in implementing preventive measures and mitigative measures, including:
(1) Personnel who mark and locate buried structures,
(2) personnel who directly supervise integrity assessment excavation work, and
(3) other personnel who participate in implementing preventive measures and mitigative measures.
Personnel who implement preventive measures and mitigative measures may hold a range of job positions, including (but not limited to): Management and technical personnel, risk evaluators, operators, excavation crews, welders, and pipeline safety engineers. With respect to these personnel, the rule requires that operators:
• Define the roles and responsibilities of personnel implementing preventive measures and mitigative measures;
• Define the qualification requirements as they relate to implementing preventive measures and mitigative measures; and
• Verify personnel satisfy the defined qualification requirements.
• The rule requires that qualification requirements be established for all tasks required to implement preventive measures and mitigative measures, including:
• Marking and locating buried structures;
• Supervising integrity assessment excavation work; and
• Applying risk assessment results to determine what additional preventive measures and mitigative measures need to be implemented for the covered segment being assessed in accordance with §192.917(c).
PHMSA inspectors will use this Advisory Bulletin to clarify the intent of existing regulatory language when evaluating operator IM program personnel training and qualification effectiveness.
§192.917 How does an operator identify potential threats to pipeline integrity and use the threat identification in its integrity program?
(a) Threat identification. An operator must identify and evaluate all potential threats to each covered pipeline segment. Potential threats that an operator must consider include, but are not limited to, the threats listed in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 2, which are grouped under the following four categories: 192.917(a)
(1) Time dependent threats such as internal corrosion, external corrosion, and stress corrosion cracking; 192.917(a)(1)
(2) Static or resident threats, such as fabrication or construction defects; 192.917(a)(2)
(3) Time independent threats such as third party damage, mechanical damage, incorrect operational procedure, weather related and outside force damage to include consideration of seismicity, geology, and soil stability of the area; and 192.917(a)(3)
(4) Human error. 192.917(a)(4)
(b) Data gathering and integration. To identify and evaluate the potential threats to a covered pipeline segment, an operator must gather and integrate existing data and information on the entire pipeline that could be relevant to the covered segment. In performing this data gathering and integration, an operator must follow the requirements in ASME/ ANSI B31.8S, section 4. At a minimum, an operator must gather and evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S, and consider both on the covered segment and similar noncovered segments, past incident history, corrosion control records, continuing surveillance records, patrolling records, maintenance history, internal inspection records and all other conditions specific to each pipeline. 192.917(b)
(c) Risk assessment. An operator must conduct a risk assessment that follows ASME/ANSI B31.8S, section 5, and considers the identified threats for each covered segment. An operator must use the risk assessment to prioritize the covered segments for the baseline and continual reassessments (§§192.919, 192.921, 192.937), and to determine what additional preventive and mitigative measures are needed §192.935) for the covered segment. 192.917(c)
(d) Plastic transmission pipeline. An operator of a plastic transmission pipeline must assess the threats to each covered segment using the information in sections 4 and 5 of ASME B31.8S, and consider any threats unique to the integrity of plastic pipe. 192.917(d)
(e) Actions to address particular threats. If an operator identifies any of the following threats, the operator must take the following actions to address the threat. 192.917(e)
(1) Third party damage. An operator must utilize the data integration required in paragraph (b) of this section and ASME/ANSI B31.8S, Appendix A7 to determine the susceptibility of each covered segment to the threat of third party damage. If an operator identifies the threat of third party damage, the operator must implement comprehensive additional preventive measures in accordance with §192.935 and monitor the effectiveness of the preventive measures. If, in conducting a baseline assessment under §192.921, or a reassessment under §192.937, an operator uses an internal inspection tool or external corrosion direct assessment, the operator must integrate data from these assessments with data related to any encroachment or foreign line crossing on the covered segment, to define where potential indications of third party damage may exist in the covered segment.
192.917(e)(1)
An operator must also have procedures in its integrity management program addressing actions it will take to respond to findings from this data integration.
(2) Cyclic fatigue. An operator must analyze and account for whether cyclic fatigue or other loading conditions (including ground movement, and suspension bridge condition) could lead to a failure of a deformation, including a dent or gouge, crack, or other defect in the covered segment. The analysis must assume the presence of threats in the covered segment that could be exacerbated by cyclic fatigue. An operator must use the results from the analysis together with the criteria used to determine the significance of the threat(s) to the covered segment to prioritize the integrity baseline assessment or reassessment. Failure stress pressure and crack growth analysis of cracks and crack-like defects must be conducted in accordance with §192.712. An operator must monitor operating pressure cycles and periodically, but at least every 7 calendar years, with intervals not to exceed 90 months, determine if the cyclic fatigue analysis remains valid or if the cyclic fatigue analysis must be revised based on changes to operating pressure cycles or other loading conditions.
192.917(e)(2)
(3) Manufacturing and construction defects. An operator must analyze the covered segment to determine and account for the risk of failure from manufacturing and construction defects (including seam defects) in the covered segment. The analysis must account for the results of prior assessments on the covered segment. An operator may consider manufacturing and construction related defects to be stable defects only if the covered segment has been subjected to
hydrostatic pressure testing satisfying the criteria of subpart J of at least 1.25 times MAOP, and the covered segment has not experienced a reportable incident attributed to a manufacturing or construction defect since the date of the most recent subpart J pressure test. If any of the following changes occur in the covered segment, an operator must prioritize the covered segment as a high-risk segment for the baseline assessment or a subsequent reassessment. 192.917(e)(3)
(i) The pipeline segment has experienced a reportable incident, as defined in §191.3, since its most recent successful subpart J pressure test, due to an original manufacturing-related defect, or a construction-, installation-, or fabrication-related defect; 192.917(e)(3)(i)
(ii) MAOP increases; or192.917(e)(3)(ii)
(iii) The stresses leading to cyclic fatigue increase.192.917(e)(3)(iii)
(4) Electric Resistance Welded (ERW) pipe. If a covered pipeline segment contains low frequency ERW pipe, lap welded pipe, pipe with longitudinal joint factor less than 1.0 as defined in §192.113, or other pipe that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices A4.3 and A4.4, and any covered or non-covered segment in the pipeline system with such pipe has experienced seam failure (including seam cracking and selective seam weld corrosion), or operating pressure on the covered segment has increased over the maximum operating pressure experienced during the preceding 5 years (including abnormal operation as defined in §192.605(c)), or MAOP has been increased, an operator must select an assessment technology or technologies with a proven application capable of assessing seam integrity and seam corrosion anomalies. The operator must prioritize the covered segment as a high-risk segment for the baseline assessment or a subsequent reassessment. Pipe with seam cracks must be evaluated using fracture mechanics modeling for failure stress pressures and cyclic fatigue crack growth analysis to estimate the remaining life of the pipe in accordance with §192.712. 192.917(e)(4)
(5) Corrosion. If an operator identifies corrosion on a covered pipeline segment that could adversely affect the integrity of the line (conditions specified in §192.933), the operator must evaluate and remediate, as necessary, all pipeline segments (both covered and noncovered) with similar material coating and environmental characteristics. An operator must establish a schedule for evaluating and remediating, as necessary, the similar segments that is consistent with the operator's established operating and maintenance procedures under part 192 for testing and repair. 192.917(e)(5)
(6) Cracks. If an operator identifies any crack or crack-like defect (e.g., stress corrosion cracking or other environmentally assisted cracking, seam defects, selective seam weld corrosion, girth weld cracks, hook cracks, and fatigue cracks) on a covered pipeline segment that could adversely affect the integrity of the pipeline, the operator must evaluate, and remediate, as necessary, all pipeline segments (both covered and non-covered) with similar characteristics associated with the crack or crack-like defect. Similar characteristics may include operating and maintenance histories, material properties, and environmental characteristics. An operator must establish a schedule for evaluating, and remediating, as necessary, the similar pipeline segments that is consistent with the operator's established operating and maintenance procedures under this part for testing and repair. 192.917(e)(6)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, Apr. 6, 2004]
§192.919 What must be in the baseline assessment plan?
An operator must include each of the following elements in its written baseline assessment plan:
(a) Identification of the potential threats to each covered pipeline segment and the information supporting the threat identification. (See §192.917.); 192.919(a)
(b) The methods selected to assess the integrity of the line pipe, including an explanation of why the assessment method was selected to address the identified threats to each covered segment. The integrity assessment method an operator uses must be based on the threats identified to the covered segment. (See §192.917.) More than one method may be required to address all the threats to the covered pipeline segment; 192.919(b)
(c) A schedule for completing the integrity assessment of all covered segments, including risk factors considered in establishing the assessment schedule; 192.919(c)
(d) If applicable, a direct assessment plan that meets the requirements of §§192.923, and depending on the threat to be addressed, of §192.925, §192.927, or §192.929; and 192.919(d)
(e) A procedure to ensure that the baseline assessment is being conducted in a manner that minimizes environmental and safety risks. 192.919(e)
§192.921 How is the baseline assessment to be conducted?
(a) Assessment methods. An operator must assess the integrity of the line pipe in each covered segment by applying one or more of the following methods for each threat to which the covered segment is susceptible. An operator must select the method or methods best suited to address the threats identified to the covered segment (See §192.917). 192.921(a)
(1) Internal inspection tool or tools capable of detecting those threats to which the pipeline is susceptible. The use of internal inspection tools is appropriate for threats such as corrosion, deformation and mechanical damage (including dents, gouges and grooves), material cracking and crack-like defects (e.g., stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible. When performing an assessment using an in-line inspection tool, an operator must comply with §192.493. In addition, an operator must analyze and account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies; 192.921(a)(1)
(2) Pressure test conducted in accordance with subpart J of this part. The use of subpart J pressure testing is appropriate for threats such as internal corrosion; external corrosion and other environmentally assisted corrosion mechanisms; manufacturing and related defects threats, including defective pipe and pipe seams; stress corrosion cracking; selective seam weld corrosion; dents; and other forms of mechanical damage. An operator must use the test pressures specified in Table 3 of section 5 of ASME/ANSI B31.8S (incorporated by reference, see §192.7) to justify an extended reassessment interval in accordance with §192.939. 192.921(a)(2)
(3) Spike hydrostatic pressure test conducted in accordance with §192.506. The use of spike hydrostatic pressure testing is appropriate for time-dependent threats such as stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; 192.921(a)(3)
(4) Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded non-destructive examination results and data needed to assess all threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX), radiography, and magnetic particle inspection (MPI); 192.921(a)(4)
(5) Guided wave ultrasonic testing (GWUT) as described in Appendix F. The use of GWUT is appropriate for internal and external pipe wall loss; 192.921(a)(5)
(6) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and the pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in §192.923 and with the applicable requirements specified in §§192.925, 192.927 and 192.929; or 192.921(a)(6)
(7) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the other technology in accordance with §192.18. 192.921(a)(7)
(b) Prioritizing segments. An operator must prioritize the covered pipeline segments for the baseline assessment according to a risk analysis that considers the potential threats to each covered segment. The risk analysis must comply with the requirements in §192.917. 192.921(b)
(c) Assessment for particular threats. In choosing an assessment method for the baseline assessment of each covered segment, an operator must take the actions required in §192.917(e) to address particular threats that it has identified. 192.921(c)
(d) Time period. An operator must prioritize all the covered segments for assessment in accordance with §192.917 (c) and paragraph (b) of this section. An operator must assess at least 50% of the covered segments beginning with the highest risk segments, by December 17, 2007. An operator must complete the baseline assessment of all covered segments by December 17, 2012. 192.921(d)
(e) Prior assessment. An operator may use a prior integrity assessment conducted before December 17, 2002 as a baseline assessment for the covered segment, if the integrity assessment meets the baseline requirements in this subpart and subsequent remedial actions to address the conditions listed in §192.933 have been carried out. In
addition, if an operator uses this prior assessment as its baseline assessment, the operator must reassess the line pipe in the covered segment according to the requirements of §192.937 and §192.939. 192.921(e)
(f) Newly identified areas. When an operator identifies a new high consequence area (see §192.905), an operator must complete the baseline assessment of the line pipe in the newly identified high consequence area within ten (10) years from the date the area is identified. 192.921(f)
(g) Newly installed pipe. An operator must complete the baseline assessment of a newly-installed segment of pipe covered by this subpart within ten (10) years from the date the pipe is installed. An operator may conduct a pressure test in accordance with paragraph (a)(2) of this section, to satisfy the requirement for a baseline assessment. 192.921(g)
(h) Plastic transmission pipeline. If the threat analysis required in §192.917(d) on a plastic transmission pipeline indicates that a covered segment is susceptible to failure from causes other than third-party damage, an operator must conduct a baseline assessment of the segment in accordance with the requirements of this section and of §192.917. The operator must justify the use of an alternative assessment method that will address the identified threats to the covered segment. 192.921(h)
(i) Baseline assessments for pipeline segments with a reconfirmed MAOP. An integrity assessment conducted in accordance with the requirements of §192.624(c) may be used as a baseline assessment under this section. 192.921(i)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18232, Apr. 6, 2004]
§192.923 How is direct assessment used and for what threats?
(a) General. An operator may use direct assessment either as a primary assessment method or as a supplement to the other assessment methods allowed under this subpart. An operator may only use direct assessment as the primary assessment method to address the identified threats of external corrosion (EC), internal corrosion (IC), and stress corrosion cracking (SCC). 192.923(a)
(b) Primary method. An operator using direct assessment as a primary assessment method must have a plan that complies with the requirements in — 192.923(b)
(1) Section 192.925 and ASME/ANSI B31.8S (incorporated by reference, see §192.7) section 6.4, and NACE SP0502 (incorporated by reference, see §192.7), if addressing external corrosion (EC). 192.923(b)(1)
(2) Section 192.927 and ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4, appendix B2, if addressing internal corrosion (IC). 192.923(b)(2)
(3) Section 192.929 and ASME/ANSI B31.8S (incorporated by reference, see §192.7), appendix A3, if addressing stress corrosion cracking (SCC). 192.923(b)(3)
(c) Supplemental method. An operator using direct assessment as a supplemental assessment method for any applicable threat must have a plan that follows the requirements for confirmatory direct assessment in §192.931. 192.923(c)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-114, 75 FR 48604, Aug. 11, 2010; Amdt. 192-119, 80 FR 178, 182, Jan. 5, 2015; 80 FR 46847, Aug. 6, 2015]
§192.925
What are the requirements for using External Corrosion Direct Assessment (ECDA)?
(a) Definition. ECDA is a four-step process that combines preassessment, indirect inspection, direct examination, and post assessment to evaluate the threat of external corrosion to the integrity of a pipeline. 192.925(a)
(b) General requirements. An operator that uses direct assessment to assess the threat of external corrosion must follow the requirements in this section, in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 6.4, and in NACE SP0502 (incorporated by reference, see §192.7). An operator must develop and implement a direct assessment plan that has procedures addressing pre-assessment, indirect inspection, direct examination, and post assessment. If the ECDA detects pipeline coating damage, the operator must also integrate the data from the ECDA with other information from the data integration §192.917(b)) to evaluate the covered segment for the threat of third party damage and to address the threat as required by §192.917(e)(1). 192.925(b)
(1) Preassessment. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502, section 3, the plan's procedures for preassessment must include — 192.925(b)(1)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment; and192.925(b)(1)(i)
(ii) The basis on which an operator selects at least two different, but complementary indirect assessment tools to assess each ECDA Region. If an operator utilizes an indirect inspection method that is not discussed in Appendix A of NACE SP0502,
the operator must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method.192.925(b)(1)(ii)
(2) Indirect inspection. In addition to the requirements in ASME/ANSI B31.8S, section 6.4 and in NACE SP0502, section 4, the plan's procedures for indirect inspection of the ECDA regions must include — 192.925(b)(2)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment;192.925(b)(2)(i)
(ii) Criteria for identifying and documenting those indications that must be considered for excavation and direct examination. Minimum identification criteria include the known sensitivities of assessment tools, the procedures for using each tool, and the approach to be used for decreasing the physical spacing of indirect assessment tool readings when the presence of a defect is suspected;192.925(b)(2)(ii)
(iii) Criteria for defining the urgency of excavation and direct examination of each indication identified during the indirect examination. These criteria must specify how an operator will define the urgency of excavating the indication as immediate, scheduled or monitored; and192.925(b)(2)(iii)
(iv) Criteria for scheduling excavation of indications for each urgency level.192.925(b)(2)(iv)
(3) Direct examination. In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE SP0502, section 5, the plan's procedures for direct examination of indications from the indirect examination must include — 192.925(b)(3)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a covered segment;192.925(b)(3)(i)
(ii) Criteria for deciding what action should be taken if either: 192.925(b)(3)(ii)
[A] Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE SP0502), or192.925(b)(3)(ii)[A]
[B] Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE SP0502); 192.925(b)(3)(ii)[B]
(iii) Criteria and notification procedures for any changes in the ECDA Plan, including changes that affect the severity classification, the priority of direct examination, and the time frame for direct examination of indications; and192.925(b)(3)(iii)
(iv) Criteria that describe how and on what basis an operator will reclassify and reprioritize any of the provisions that are specified in section 5.9 of NACE SP0502.192.925(b)(3)(iv)
(4) Post assessment and continuing evaluation. In addition to the requirements in ASME/ANSI B31.8S section 6.4 and NACE SP0502, section 6, the plan's procedures for post assessment of the effectiveness of the ECDA process must include — 192.925(b)(4) (i) Measures for evaluating the long-term effectiveness of ECDA in addressing external corrosion in covered segments; and 192.925(b)(4)(i)
(ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the covered segment at an interval less than that specified in §192.939. (See Appendix D of NACE SP0502.)192.925(b)(4)(ii)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 29904, May 26, 2004; Amdt. 192-114, 75 FR 48604, Aug. 11, 2010; Amdt. 192-119, 80 FR 178, Jan. 5, 2015; Amdt. 192-120, 80 FR 12779, Mar. 11, 2015]
§192.927
What are the requirements for using Internal Corrosion Direct Assessment (ICDA)?
(a) Definition. Internal Corrosion Direct Assessment (ICDA) is a process an operator uses to identify areas along the pipeline where fluid or other electrolyte introduced during normal operation or by an upset condition may reside, and then focuses direct examination on the locations in covered segments where internal corrosion is most likely to exist. The process identifies the potential for internal corrosion caused by microorganisms, or fluid with CO2, O2, hydrogen sulfide or other contaminants present in the gas. 192.927(a)
(b) General requirements. An operator using direct assessment as an assessment method to address internal corrosion in a covered pipeline segment must follow the requirements in this section and in ASME/ ANSI B31.8S (incorporated by reference, see §192.7), section 6.4 and appendix B2. The ICDA process described in this section applies only for a segment of pipe transporting nominally dry natural gas, and not for a segment with electrolyte nominally present in the gas stream. If an operator uses ICDA to assess a covered segment operating with electrolyte present in the gas stream, the operator must develop a plan that demonstrates how it will conduct ICDA in the segment to effectively address internal corrosion, and must provide notification in accordance with §192.921 (a)(4) or §192.937(c)(4). 192.927(b)
(c) The ICDA plan. An operator must develop and follow an ICDA plan that provides for preassessment, identification of ICDA regions and excavation locations, detailed examination of pipe at excavation locations, and post-assessment evaluation and monitoring. 192.927(c)
(1) Preassessment. In the preassessment stage, an operator must gather and integrate data and information needed to evaluate the feasibility of ICDA for the covered segment, and to support use of a model to identify the locations along the pipe segment where electrolyte may accumulate, to identify ICDA regions, and to identify areas within the covered segment where liquids may potentially be entrained. This data and information includes, but is not limited to — 192.927(c)(1)
(i) All data elements listed in appendix A2 of ASME/ANSI B31.8S; 192.927(c)(1)(i)
(ii) Information needed to support use of a model that an operator must use to identify areas along the pipeline where internal corrosion is most likely to occur. (See paragraph (a) of this section.) This information, includes, but is not limited to, location of all gas input and withdrawal points on the line; location of all low points on covered segments such as sags, drips, inclines, valves, manifolds, dead-legs, and traps; the elevation profile of the pipeline in sufficient detail that angles of inclination can be calculated for all pipe segments; and the diameter of the pipeline, and the range of expected gas velocities in the pipeline;192.927(c)(1)(ii)
(iii) Operating experience data that would indicate historic upsets in gas conditions, locations where these upsets have occurred, and potential damage resulting from these upset conditions; and192.927(c)(1)(iii)
(iv) Information on covered segments where cleaning pigs may not have been used or where cleaning pigs may deposit electrolytes.192.927(c)(1)(iv)
(2) ICDA region identification. An operator's plan must identify where all ICDA Regions are located in the transmission system, in which covered segments are located. An ICDA Region extends from the location where liquid may first enter the pipeline and encompasses the entire area along the pipeline where internal corrosion may occur and where further evaluation is needed. An ICDA Region may encompass one or more covered segments. In the identification process, an operator must use the model in GRI 02-0057, "Internal Corrosion Direct Assessment of Gas Transmission Pipelines — Methodology," (incorporated by reference, see §192.7). An operator may use another model if the operator demonstrates it is equivalent to the one shown in GRI 02-0057. A model must consider changes in pipe diameter, locations where gas enters a line (potential to introduce liquid) and locations down stream of gas draw-offs (where gas velocity is reduced) to define the critical pipe angle of inclination above which water film cannot be transported by the gas. 192.927(c)(2)
(3) Identification of locations for excavation and direct examination. An operator's plan must identify the locations where internal corrosion is most likely in each ICDA region. In the location identification process, an operator must identify a minimum of two locations for excavation within each ICDA Region within a covered segment and must perform a direct examination for internal corrosion at each location, using ultrasonic thickness measurements, radiography, or other generally accepted measurement technique. One location must be the low point (e.g., sags, drips, valves, manifolds, dead-legs, traps) within the covered segment nearest to the beginning of the ICDA Region. The second location must be further downstream, within a covered segment, near the end of the ICDA Region. If corrosion exists at either location, the operator must — 192.927(c)(3)
(i) Evaluate the severity of the defect (remaining strength) and remediate the defect in accordance with §192.933;192.927(c)(3)(i)
(ii) As part of the operator's current integrity assessment either perform additional excavations in each covered segment within the ICDA region, or use an alternative assessment method allowed by this subpart to assess the line pipe in each covered segment within the ICDA region for internal corrosion; and192.927(c)(3)(ii)
(iii) Evaluate the potential for internal corrosion in all pipeline segments (both covered and non-covered) in the operator's pipeline system with similar characteristics to the ICDA region containing the covered segment in which the corrosion was found, and as appropriate, remediate the conditions the operator finds in accordance with §192.933.192.927(c)(3)(iii)
(4) Post-assessment evaluation and monitoring. An operator's plan must provide for evaluating the effectiveness of the ICDA process and continued monitoring of covered segments where internal corrosion has been identified. The evaluation and monitoring process includes — 192.927(c)(4)
(i) Evaluating the effectiveness of ICDA as an assessment method for addressing internal corrosion and determining whether a covered segment should be reassessed at more frequent intervals than those specified in §192.939. An operator must carry out this evaluation within a year of conducting an ICDA; and 192.927(c)(4)(i)
(ii) Continually monitoring each covered segment where internal corrosion has been identified using techniques such as coupons, UT sensors or electronic probes, periodically drawing off liquids at low points and chemically analyzing the liquids for the
presence of corrosion products. An operator must base the frequency of the monitoring and liquid analysis on results from all integrity assessments that have been conducted in accordance with the requirements of this subpart, and risk factors specific to the covered segment. If an operator finds any evidence of corrosion products in the covered segment, the operator must take prompt action in accordance with one of the two following required actions and remediate the conditions the operator finds in accordance with §192.933.192.927(c)(4)(ii)
[A] Conduct excavations of covered segments at locations downstream from where the electrolyte might have entered the pipe; or192.927(c)(4)(ii)[A]
[B] Assess the covered segment using another integrity assessment method allowed by this subpart.192.927(c)(4)(ii)[B]
(5) Other requirements. The ICDA plan must also include — 192.927(c)(5)
(i) Criteria an operator will apply in making key decisions (e.g., ICDA feasibility, definition of ICDA Regions, conditions requiring excavation) in implementing each stage of the ICDA process; 192.927(c)(5)(i)
(ii) Provisions for applying more restrictive criteria when conducting ICDA for the first time on a covered segment and that become less stringent as the operator gains experience; and 192.927(c)(5)(ii)
(iii) Provisions that analysis be carried out on the entire pipeline in which covered segments are present, except that application of the remediation criteria of §192.933 may be limited to covered segments.192.927(c)(5)(iii)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18232, Apr. 6, 2004]
§192.929 What
are the requirements for using Direct Assessment for Stress Corrosion Cracking (SCCDA)?
(a) Definition. Stress Corrosion Cracking Direct Assessment (SCCDA) is a process to assess a covered pipe segment for the presence of SCC primarily by systematically gathering and analyzing excavation data for pipe having similar operational characteristics and residing in a similar physical environment. 192.929(a)
(b) General requirements. An operator using direct assessment as an integrity assessment method to address stress corrosion cracking in a covered pipeline segment must have a plan that provides, at minimum, for — 192.929(b)
(1) Data gathering and integration. An operator's plan must provide for a systematic process to collect and evaluate data for all covered segments to identify whether the conditions for SCC are present and to prioritize the covered segments for assessment. This process must include gathering and evaluating data related to SCC at all sites an operator excavates during the conduct of its pipeline operations where the criteria in ASME/ANSI B31.8S (incorporated by reference, see §192.7), appendix A3.3 indicate the potential for SCC. This data includes at minimum, the data specified in ASME/ANSI B31.8S, appendix A3. 192.929(b)(1)
(2) Assessment method. The plan must provide that if conditions for SCC are identified in a covered segment, an operator must assess the covered segment using an integrity assessment method specified in ASME/ANSI B31.8S, appendix A3, and remediate the threat in accordance with ASME/ANSI B31.8S, appendix A3, section A3.4. 192.929(b)(2)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18233, Apr. 6, 2004]
§192.931
How may Confirmatory Direct Assessment (CDA) be used?
An operator using the confirmatory direct assessment (CDA) method as allowed in §192.937 must have a plan that meets the requirements of this section and of §§192.925 (ECDA) and §192.927 (ICDA).
(a) Threats. An operator may only use CDA on a covered segment to identify damage resulting from external corrosion or internal corrosion. 192.931(a)
(b) External corrosion plan. An operator's CDA plan for identifying external corrosion must comply with §192.925 with the following exceptions. 192.931(b)
(1) The procedures for indirect examination may allow use of only one indirect examination tool suitable for the application. 192.931(b)(1)
(2) The procedures for direct examination and remediation must provide that — 192.931(b)(2)
(i) All immediate action indications must be excavated for each ECDA region; and192.931(b)(2)(i)
(ii) At least one high risk indication that meets the criteria of scheduled action must be excavated in each ECDA region. 192.931(b)(2)(ii)
(c) Internal corrosion plan. An operator's CDA plan for identifying internal corrosion must comply with §192.927 except that the plan's procedures for identifying locations for excavation may require excavation of only one high risk location in each ICDA region. 192.931(c)
(d) Defects requiring near-term remediation. If an assessment carried out under paragraph (b) or (c) of this section reveals any defect requiring remediation prior to the next scheduled assessment, the operator must schedule the next assessment in accordance with NACE SP0502 (incorporated by reference, see §192.7), section 6.2 and 6.3. If the defect requires immediate remediation, then the operator must reduce pressure consistent with §192.933 until the operator has completed reassessment using one of the assessment techniques allowed in §192.937. 192.931(d)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-114, 75 FR 48604, Aug. 11, 2010; Amdt. 192-119, 80 FR 178, Jan. 5, 2015]
§192.933 What actions must be taken to address integrity issues?
(a) General requirements. An operator must take prompt action to address all anomalous conditions the operator discovers through the integrity assessment. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity. An operator must be able to demonstrate that the remediation of the condition will ensure the condition is unlikely to pose a threat to the integrity of the pipeline until the next reassessment of the covered segment. 192.933(a)
(1) Temporary pressure reduction. If an operator is unable to respond within the time limits for certain conditions specified in this section, the operator must temporarily reduce the operating pressure of the pipeline or take other action that ensures the safety of the covered segment. An operator must determine any temporary reduction in operating pressure required by this section using ASME/ANSI B31G (incorporated by reference, see §192.7); R-STRENG (incorporated by reference, see §192.7); or by reducing the operating pressure to a level not exceeding 80 percent of the level at the time the condition was discovered. An operator must notify PHMSA in accordance with §192.18 if it cannot meet the schedule for evaluation and remediation required under paragraph (c) of this section and cannot provide safety through a temporary reduction in operating pressure or through another action. 192.933(a)(1)
(2) Long-term pressure reduction. When a pressure reduction exceeds 365 days, an operator must notify PHMSA under §192.18 and explain the reasons for the remediation delay. This notice must include a technical justification that the continued pressure reduction will not jeopardize the integrity of the pipeline. 192.933(a)(2)
(b) Discovery of condition. Discovery of a condition occurs when an operator has adequate information about a condition to determine that the condition presents a potential threat to the integrity of the pipeline. A condition that presents a potential threat includes, but is not limited to, those conditions that require remediation or monitoring listed under paragraphs (d)(1) through (d)(3) of this section. An operator must promptly, but no later than 180 days after conducting an integrity assessment, obtain sufficient information about a condition to make that determination, unless the operator demonstrates that the 180-day period is impracticable. 192.933(b)
(c) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule prioritizing the conditions for evaluation and remediation. Unless a special requirement for remediating certain conditions applies, as provided in paragraph (d) of this section, an operator must follow the schedule in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 7, Figure 4. If an operator cannot meet the schedule for any condition, the operator must explain the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety. 192.933(c)
(d) Special requirements for scheduling remediation — 192.933(d)
(1) Immediate repair conditions. An operator's evaluation and remediation schedule must follow ASME/ANSI B31.8S, section 7 in providing for immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure in accordance with paragraph (a) of this section or shut down the pipeline until the operator completes the repair of these conditions. An operator must treat the following conditions as immediate repair conditions: 192.933(d)(1)
(i) A calculation of the remaining strength of the pipe shows a predicted failure pressure less than or equal to 1.1 times the maximum allowable operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include ASME/ANSI B31G (incorporated by reference, see §192.7), PRCI PR-3-805 (R-STRENG) (incorporated by reference, see §192.7), or an alternative equivalent method of remaining strength calculation.192.933(d)(1)(i)
(ii) A dent that has any indication of metal loss, cracking or a stress riser.192.933(d)(1)(ii)
(iii) An indication or anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.192.933(d)(1)(iii)
(2) One-year conditions. Except for conditions listed in paragraph (d)(1) and (d)(3) of this section, an operator must remediate any of the following within one year of discovery of the condition:
192.933(d)(2)
(i) A smooth dent located between the 8 o'clock and 4 o'clock positions (upper 2⁄3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12). 192.933(d)(2)(i)
(ii) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or at a longitudinal seam weld.192.933(d)(2)(ii)
(3) Monitored conditions. An operator does not have to schedule the following conditions for remediation, but must record and monitor the conditions during subsequent risk assessments and integrity assessments for any change that may require remediation: 192.933(d)(3)
(i) A dent with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than NPS 12) located between the 4 o'clock position and the 8 o'clock position (bottom 1⁄3 of the pipe).192.933(d)(3)(i)
(ii) A dent located between the 8 o'clock and 4 o'clock positions (upper 2⁄3 of the pipe) with a depth greater than 6% of the pipeline diameter (greater than 0.50 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12), and engineering analyses of the dent demonstrate critical strain levels are not exceeded.192.933(d)(3)(ii)
(iii) A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld, and engineering analyses of the dent and girth or seam weld demonstrate critical strain levels are not exceeded. These analyses must consider weld properties.192.933(d)(3)(iii)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18233, Apr. 6, 2004; Amdt. 192-104, 72 FR 39016, July 17, 2007; Amdt. 192-119, 80 FR 182, Jan. 5, 2015; 80 FR 46847, Aug. 6, 2015]
§192.935 What additional preventive and mitigative measures must an operator take?
(a) General requirements. An operator must take additional measures beyond those already required by Part 192 to prevent a pipeline failure and to mitigate the consequences of a pipeline failure in a high consequence area. An operator must base the additional measures on the threats the operator has identified to each pipeline segment. (See §192.917) An operator must conduct, in accordance with one of the risk assessment approaches in ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 5, a risk analysis of its pipeline to identify additional measures to protect the high consequence area and enhance public safety. Such additional measures include, but are not limited to, installing Automatic Shut-off Valves or Remote Control Valves, installing computerized monitoring and leak detection systems, replacing pipe segments with pipe of heavier wall thickness, providing additional training to personnel on response procedures, conducting drills with local emergency responders and implementing additional inspection and maintenance programs. 192.935(a)
(b) Third party damage and outside force damage — 192.935(b)
(1) Third party damage. An operator must enhance its damage prevention program, as required under §192.614 of this part, with respect to a covered segment to prevent and minimize the consequences of a release due to third party damage. Enhanced measures to an existing damage prevention program include, at a minimum — 192.935(b)(1)
(i) Using qualified personnel (see §192.915) for work an operator is conducting that could adversely affect the integrity of a covered segment, such as marking, locating, and direct supervision of known excavation work.192.935(b)(1)(i)
(ii) Collecting in a central database information that is location specific on excavation damage that occurs in covered and non covered segments in the transmission system and the root cause analysis to support identification of targeted additional preventative and mitigative measures in the high consequence areas. This information must include recognized damage that is not required to be reported as an incident under part 191. 192.935(b)(1)(ii)
(iii) Participating in one-call systems in locations where covered segments are present.192.935(b)(1)(iii)
(iv) Monitoring of excavations conducted on covered pipeline segments by pipeline personnel. If an operator finds physical evidence of encroachment involving excavation that the operator did not monitor near a covered segment, an operator must either excavate the area near the encroachment or conduct an above ground survey using methods defined in NACE SP0502 (incorporated by reference, see §192.7). An operator must
excavate, and remediate, in accordance with ANSI/ASME B31.8S and §192.933 any indication of coating holidays or discontinuity warranting direct examination.192.935(b)(1)(iv)
(2) Outside force damage. If an operator determines that outside force (e.g., earth movement, loading, longitudinal, or lateral forces, seismicity of the area, floods, unstable suspension bridge) is a threat to the integrity of a covered segment, the operator must take measures to minimize the consequences to the covered segment from outside force damage. These measures include increasing the frequency of aerial, foot or other methods of patrols; adding external protection; reducing external stress; relocating the line; or inline inspections with geospatial and deformation tools. 192.935(b)(2)
(c) Risk analysis for gas releases and protection against ruptures. If an operator determines, based on a risk analysis, that a rupture-mitigation valve (RMV) or alternative equivalent technology would be an efficient means of adding protection to a high-consequence area (HCA) in the event of a gas release, an operator must install the RMV or alternative equivalent technology. In making that determination, an operator must, at least, evaluate the following factors — timing of leak detection and pipe shutdown capabilities, the type of gas being transported, operating pressure, the rate of potential release, pipeline profile, the potential for ignition, and location of nearest response personnel. An RMV or alternative equivalent technology installed under this paragraph must meet all of the other applicable requirements in this part. 192.935(c)
(d) Pipelines operating below 30% SMYS. An operator of a transmission pipeline operating below 30% SMYS located in a high consequence area must follow the requirements in paragraphs (d)(1) and (d)(2) of this section. An operator of a transmission pipeline operating below 30% SMYS located in a Class 3 or Class 4 area but not in a high consequence area must follow the requirements in paragraphs (d)(1), (d)(2) and (d)(3) of this section. 192.935(d)
(1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) of this section to the pipeline; and 192.935(d)(1)
(2) Either monitor excavations near the pipeline, or conduct patrols as required by §192.705 of the pipeline at bi-monthly intervals. If an operator finds any indication of unreported construction activity, the operator must conduct a follow up investigation to determine if mechanical damage has occurred. 192.935(d)(2)
(3) Perform semi-annual leak surveys (quarterly for unprotected pipelines or cathodically protected pipe where electrical surveys are impractical). 192.935(d)(3)
(e) Plastic transmission pipeline. An operator of a plastic transmission pipeline must apply the requirements in paragraphs (b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered segments of the pipeline. 192.935(e)
(f) Periodic evaluations. Risk analyses and assessments conducted under paragraph (c) of this section must be reviewed by the operator and certified by a senior executive of the company, for operational matters that could affect rupture-mitigation processes and procedures. Review and certification must occur once per calendar year, with the period between reviews not to exceed 15 months, and must also occur within 3 months of an incident or safety-related condition, as those terms are defined at §§191.3 and 191.23, respectively. 192.935(f)
§192.937 What is a continual process of evaluation and assessment to maintain a pipeline's integrity?
(a) General. After completing the baseline integrity assessment of a covered segment, an operator must continue to assess the line pipe of that segment at the intervals specified in §192.939 and periodically evaluate the integrity of each covered pipeline segment as provided in paragraph (b) of this section. An operator must reassess a covered segment on which a prior assessment is credited as a baseline under §192.921(e) by no later than December 17, 2009. An operator must reassess a covered segment on which a baseline assessment is conducted during the baseline period specified in §192.921(d) by no later than seven years after the baseline assessment of that covered segment unless the evaluation under paragraph (b) of this section indicates earlier reassessment. 192.937(a)
(b) Evaluation. An operator must conduct a periodic evaluation as frequently as needed to assure the integrity of each covered segment. The periodic evaluation must be based on a data integration and risk assessment of the entire pipeline as specified in §192.917. For plastic transmission pipelines, the periodic evaluation is based on the threat analysis specified in 192.917(d). For all other transmission pipelines, the evaluation must consider the past and present integrity assessment results, data integration and risk assessment information §192.917), and decisions about remediation §192.933) and additional preventive and mitigative actions §192.935). An operator must use the results from this evaluation to identify the threats specific to each covered segment and the risk represented by these threats. 192.937(b)
(c) Assessment methods. In conducting the integrity reassessment, an operator must assess the integrity of the line pipe in each covered segment by applying one or more of the following methods for each threat
to which the covered segment is susceptible. An operator must select the method or methods best suited to address the threats identified on the covered segment (see §192.917). 192.937(c)
(1) Internal inspection tools. When performing an assessment using an in-line inspection tool, an operator must comply with the following requirements: 192.937(c)(1)
(i) Perform the in-line inspection in accordance with §192.493; 192.937(c)(1)(i)
(ii) Select a tool or combination of tools capable of detecting the threats to which the pipeline segment is susceptible such as corrosion, deformation and mechanical damage (e.g. dents, gouges and grooves), material cracking and crack-like defects (e.g. stress corrosion cracking, selective seam weld corrosion, environmentally assisted cracking, and girth weld cracks), hard spots with cracking, and any other threats to which the covered segment is susceptible; and192.937(c)(1)(ii)
(iii) Analyze and account for uncertainties in reported results (e.g., tool tolerance, detection threshold, probability of detection, probability of identification, sizing accuracy, conservative anomaly interaction criteria, location accuracy, anomaly findings, and unity chart plots or equivalent for determining uncertainties and verifying actual tool performance) in identifying and characterizing anomalies.192.937(c)(1)(iii)
(2) Pressure test conducted in accordance with subpart J of this part. The use of pressure testing is appropriate for threats such as: Internal corrosion; external corrosion and other environmentally assisted corrosion mechanisms; manufacturing and related defects threats, including defective pipe and pipe seams; stress corrosion cracking; selective seam weld corrosion; dents; and other forms of mechanical damage. An operator must use the test pressures specified in table 3 of section 5 of ASME/ANSI B31.8S (incorporated by reference, see §192.7) to justify an extended reassessment interval in accordance with §192.939. 192.937(c)(2)
(3) Spike hydrostatic pressure test in accordance with §192.506. The use of spike hydrostatic pressure testing is appropriate for timedependent threats such as: Stress corrosion cracking; selective seam weld corrosion; manufacturing and related defects, including defective pipe and pipe seams; and other forms of defect or damage involving cracks or crack-like defects; 192.937(c)(3)
(4) Excavation and in situ direct examination by means of visual examination, direct measurement, and recorded non-destructive examination results and data needed to assess all threats. Based upon the threat assessed, examples of appropriate non-destructive examination methods include ultrasonic testing (UT), phased array ultrasonic testing (PAUT), inverse wave field extrapolation (IWEX), radiography, or magnetic particle inspection (MPI); 192.937(c)(4)
(5) Guided wave ultrasonic testing (GWUT) as described in Appendix F. The use of GWUT is appropriate for internal and external pipe wall loss; 192.937(c)(5)
(6) Direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking. The use of direct assessment to address threats of external corrosion, internal corrosion, and stress corrosion cracking is allowed only if appropriate for the threat and pipeline segment being assessed. Use of direct assessment for threats other than the threat for which the direct assessment method is suitable is not allowed. An operator must conduct the direct assessment in accordance with the requirements listed in §192.923 and with the applicable requirements specified in §§192.925, 192.927, and 192.929; 192.937(c)(6)
(7) Other technology that an operator demonstrates can provide an equivalent understanding of the condition of the line pipe for each of the threats to which the pipeline is susceptible. An operator must notify PHMSA in advance of using the other technology in accordance with §192.18; or 192.937(c)(7)
(8) Confirmatory direct assessment when used on a covered segment that is scheduled for reassessment at a period longer than 7 calendar years. An operator using this reassessment method must comply with §192.931. 192.937(c)(8)
(d) MAOP reconfirmation assessments. An integrity assessment conducted in accordance with the requirements of §192.624(c) may be used as a reassessment under this section. 192.937(d)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, Apr. 6, 2004]
§192.939 What are the required reassessment intervals?
An operator must comply with the following requirements in establishing the reassessment interval for the operator's covered pipeline segments.
(a) Pipelines operating at or above 30% SMYS. An operator must establish a reassessment interval for each covered segment operating at or above 30% SMYS in accordance with the requirements of this section. The maximum reassessment interval by an allowable reassessment method is 7 calendar years. Operators may request a 6month extension of the 7-calendar-year reassessment interval if the operator submits written notice to OPS, in accordance with §192.18,
with sufficient justification of the need for the extension. If an operator establishes a reassessment interval that is greater than 7 calendar years, the operator must, within the 7-calendar-year period, conduct a confirmatory direct assessment on the covered segment, and then conduct the follow-up reassessment at the interval the operator has established. A reassessment carried out using confirmatory direct assessment must be done in accordance with §192.931. The table that follows this section sets forth the maximum allowed reassessment intervals. 192.939(a)
(1) Pressure test or internal inspection or other equivalent technology. An operator that uses pressure testing or internal inspection as an assessment method must establish the reassessment interval for a covered pipeline segment by — 192.939(a)(1)
(i) Basing the interval on the identified threats for the covered segment (see §192.917) and on the analysis of the results from the last integrity assessment and from the data integration and risk assessment required by §192.917; or192.939(a)(1)(i)
(ii) Using the intervals specified for different stress levels of pipeline (operating at or above 30% SMYS) listed in ASME B31.8S (incorporated by reference, see §192.7), section 5, Table 3. 192.939(a)(1)(ii)
(2) External Corrosion Direct Assessment. An operator that uses ECDA that meets the requirements of this subpart must determine the reassessment interval according to the requirements in paragraphs 6.2 and 6.3 of NACE SP0502 (incorporated by reference, see §192.7). 192.939(a)(2)
(3) Internal Corrosion or SCC Direct Assessment. An operator that uses ICDA or SCCDA in accordance with the requirements of this subpart must determine the reassessment interval according to the following method. However, the reassessment interval cannot exceed those specified for direct assessment in ASME/ANSI B31.8S, section 5, Table 3. 192.939(a)(3)
(i) Determine the largest defect most likely to remain in the covered segment and the corrosion rate appropriate for the pipe, soil and protection conditions;192.939(a)(3)(i)
(ii) Use the largest remaining defect as the size of the largest defect discovered in the SCC or ICDA segment; and 192.939(a)(3)(ii)
(iii) Estimate the reassessment interval as half the time required for the largest defect to grow to a critical size.192.939(a)(3)(iii)
(b) Pipelines Operating below 30% SMYS. An operator must establish a reassessment interval for each covered segment operating below 30% SMYS in accordance with the requirements of this section. The maximum reassessment interval by an allowable reassessment method is 7 calendar years. Operators may request a 6-month extension of the 7-calendar-year reassessment interval if the operator submits written notice to OPS in accordance with §192.18. The notice must include sufficient justification of the need for the extension. An operator must establish reassessment by at least one of the following
— 192.939(b)
(1) Reassessment by pressure test, internal inspection or other equivalent technology following the requirements in paragraph (a)(1) of this section except that the stress level referenced in paragraph (a)(1)(ii) of this section would be adjusted to reflect the lower operating stress level. If an established interval is more than 7 calendar years, an operator must conduct by the seventh calendar year of the interval either a confirmatory direct assessment in accordance with §192.931, or a low stress reassessment in accordance with §192.941. 192.939(b)(1)
(2) Reassessment by ECDA following the requirements in paragraph (a)(2) of this section. 192.939(b)(2)
(3) Reassessment by ICDA or SCCDA following the requirements in paragraph (a)(3) of this section. 192.939(b)(3)
(4) Reassessment by confirmatory direct assessment at 7-year intervals in accordance with §192.931, with reassessment by one of the methods listed in paragraphs (b)(1) through (b)(3) of this section by year 20 of the interval. 192.939(b)(4)
(5) Reassessment by the low stress assessment method at 7-year intervals in accordance with §192.941 with reassessment by one of the methods listed in paragraphs (b)(1) through (b)(3) of this section by year 20 of the interval. 192.939(b)(5)
(6) The following table sets forth the maximum reassessment intervals. Also refer to Appendix E.II for guidance on Assessment Methods and Assessment Schedule for Transmission Pipelines Operating Below 30% SMYS. In case of conflict between the rule and the guid-
ance in the Appendix, the requirements of the rule control. An operator must comply with the following requirements in establishing a reassessment interval for a covered segment: 192.939(b)(6)
Maximum Reassessment Interval
Assessment method
Pipeline operating at or above 50% SMYS
Pipeline operating at or above 30% SMYS, up to 50% SMYS
Pipeline operating below 30% SMYS
Internal Inspection Tool, Pressure Test or Direct Assessment 10 years(*)15 years(*)20 years.(**)
Confirmatory Direct Assessment 7 years 7 years 7 years.
Low Stress ReassessmentNot applicableNot applicable 7 years + ongoing actions specified in §192.941.
(*) A Confirmatory direct assessment as described in §192.931 must be conducted by year 7 in a 10-year interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the interval.
(a) General. An operator of a transmission line that operates below 30% SMYS may use the following method to reassess a covered segment in accordance with §192.939. This method of reassessment addresses the threats of external and internal corrosion. The operator must have conducted a baseline assessment of the covered segment in accordance with the requirements of §§192.919 and 192.921. 192.941(a)
(b) External corrosion. An operator must take one of the following actions to address external corrosion on the low stress covered segment. 192.941(b)
(1) Cathodically protected pipe. To address the threat of external corrosion on cathodically protected pipe in a covered segment, an operator must perform an electrical survey (i.e. indirect examination tool/ method) at least every 7 years on the covered segment. An operator must use the results of each survey as part of an overall evaluation of the cathodic protection and corrosion threat for the covered segment. This evaluation must consider, at minimum, the leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. 192.941(b)(1)
(2) Unprotected pipe or cathodically protected pipe where electrical surveys are impractical. If an electrical survey is impractical on the covered segment an operator must — 192.941(b)(2)
(i) Conduct leakage surveys as required by §192.706 at 4-month intervals; and192.941(b)(2)(i)
(ii) Every 18 months, identify and remediate areas of active corrosion by evaluating leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment.192.941(b)(2)(ii)
(c) Internal corrosion. To address the threat of internal corrosion on a covered segment, an operator must — 192.941(c)
(1) Conduct a gas analysis for corrosive agents at least once each calendar year; 192.941(c)(1)
(2) Conduct periodic testing of fluids removed from the segment. At least once each calendar year test the fluids removed from each storage field that may affect a covered segment; and 192.941(c)(2)
(3) At least every seven (7) years, integrate data from the analysis and testing required by paragraphs (c)(1)-(c)(2) with applicable internal corrosion leak records, incident reports, safety-related condition reports, repair records, patrol records, exposed pipe reports, and test records, and define and implement appropriate remediation actions. 192.941(c)(3)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, Apr. 6, 2004]
§192.943 When can an operator deviate from
these reassessment intervals?
(a) Waiver from reassessment interval in limited situations. In the following limited instances, OPS may allow a waiver from a reassessment interval required by §192.939 if OPS finds a waiver would not be inconsistent with pipeline safety. 192.943(a)
(1) Lack of internal inspection tools. An operator who uses internal inspection as an assessment method may be able to justify a longer reassessment period for a covered segment if internal inspection tools are not available to assess the line pipe. To justify this, the operator must demonstrate that it cannot obtain the internal inspection tools within the required reassessment period and that the actions the operator is taking in the interim ensure the integrity of the covered segment. 192.943(a)(1)
(2) Maintain product supply. An operator may be able to justify a longer reassessment period for a covered segment if the operator demonstrates that it cannot maintain local product supply if it conducts the reassessment within the required interval. 192.943(a)(2)
(b) How to apply. If one of the conditions specified in paragraph (a) (1) or (a) (2) of this section applies, an operator may seek a waiver of the required reassessment interval. An operator must apply for a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days before the end of the required reassessment interval, unless local product supply issues make the period impractical. If local product supply issues make the period impractical, an operator must apply for the waiver as soon as the need for the waiver becomes known. 192.943(b)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, Apr. 6, 2004]
§192.945 What methods must an operator use to measure program effectiveness?
(a) General. An operator must include in its integrity management program methods to measure whether the program is effective in assessing and evaluating the integrity of each covered pipeline segment and in protecting the high consequence areas. These measures must include the four overall performance measures specified in ASME/ ANSI B31.8S (incorporated by reference, see §192.7 of this part), section 9.4, and the specific measures for each identified threat specified in ASME/ANSI B31.8S, Appendix A. An operator must submit the four overall performance measures as part of the annual report required by §191.17 of this subchapter. 192.945(a)
(b) External Corrosion Direct assessment. In addition to the general requirements for performance measures in paragraph (a) of this section, an operator using direct assessment to assess the external corrosion threat must define and monitor measures to determine the effectiveness of the ECDA process. These measures must meet the requirements of §192.925. 192.945(b)
An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At minimum, an operator must maintain the following records for review during an inspection.
(a) A written integrity management program in accordance with §192.907; 192.947(a)
(b) Documents supporting the threat identification and risk assessment in accordance with §192.917; 192.947(b)
(c) A written baseline assessment plan in accordance with §192.919; 192.947(c)
(d) Documents to support any decision, analysis and process developed and used to implement and evaluate each element of the baseline assessment plan and integrity management program. Documents include those developed and used in support of any identification, calculation, amendment, modification, justification, deviation and determination made, and any action taken to implement and evaluate any of the program elements; 192.947(d)
(e) Documents that demonstrate personnel have the required training, including a description of the training program, in accordance with §192.915; 192.947(e)
(f) Schedule required by §192.933 that prioritizes the conditions found during an assessment for evaluation and remediation, including technical justifications for the schedule. 192.947(f)
(g) Documents to carry out the requirements in §§192.923 through 192.929 for a direct assessment plan; 192.947(g)
(h) Documents to carry out the requirements in §192.931 for confirmatory direct assessment; 192.947(h)
(i) Verification that an operator has provided any documentation or notification required by this subpart to be provided to OPS, and when applicable, a State authority with which OPS has an interstate agent agreement, and a State or local pipeline safety authority that regulates a covered pipeline segment within that State. 192.947(i)
[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, Apr. 6, 2004]
§192.949 §192.951 Where does an operator file a report?
An operator must file any report required by this subpart electronically to the Pipeline and Hazardous Materials Safety Administration in accordance with §191.7 of this subchapter.
[Amdt. No. 192 — 115, 75 FR 72906, Nov. 26, 2010]
Subpart P – Gas Distribution Pipeline Integrity Management (IM)
§192.1001 What definitions apply to this subpart?
The following definitions apply to this subpart:
Excavation Damage means any impact that results in the need to repair or replace an underground facility due to a weakening, or the partial or complete destruction, of the facility, including, but not limited to, the protective coating, lateral support, cathodic protection or the housing for the line device or facility.
Hazardous Leak means a leak that represents an existing or probable hazard to persons or property and requires immediate repair or continuous action until the conditions are no longer hazardous.
Integrity Management Plan or IM Plan means a written explanation of the mechanisms or procedures the operator will use to implement its integrity management program and to ensure compliance with this subpart.
Integrity Management Program or IM Program means an overall approach by an operator to ensure the integrity of its gas distribution system.
Mechanical fitting means a mechanical device used to connect sections of pipe. The term "Mechanical fitting" applies only to:
(1) Stab Type fittings;
(2) Nut Follower Type fittings;
(3) Bolted Type fittings; or
(4) Other Compression Type fittings.
Small LPG Operator means an operator of a liquefied petroleum gas (LPG) distribution pipeline that serves fewer than 100 customers from a single source.
[74 FR 63934, Dec. 4, 2009, as amended at 76 FR 5499, Feb. 1, 2011]
§192.1003 What do the regulations in this subpart cover?
(a) General. Unless exempted in paragraph (b) of this section, this subpart prescribes minimum requirements for an IM program for any gas distribution pipeline covered under this part, including liquefied petroleum gas systems. A gas distribution operator must follow the requirements in this subpart. 192.1003(a)
(b) Exceptions. This subpart does not apply to: 192.1003(b)
(1) Individual service lines directly connected to a production line or a gathering line other than a regulated onshore gathering line as determined in §192.8; 192.1003(b)(1)
(2) Individual service lines directly connected to either a transmission or regulated gathering pipeline and maintained in accordance with §192.740(a) and (b); and 192.1003(b)(2)
(3) Master meter systems. 192.1003(b)(3)
[Amdt. 192-123, 82 FR 7998, Jan. 23, 2017]
§192.1005 What must a gas distribution operator (other than a small LPG operator) do to implement this subpart?
No later than August 2, 2011 a gas distribution operator must develop and implement an integrity management program that includes a written integrity management plan as specified in §192.1007.
§192.1007 What are the required elements of an integrity management plan?
A written integrity management plan must contain procedures for developing and implementing the following elements:
(a) Knowledge. An operator must demonstrate an understanding of its gas distribution system developed from reasonably available information. 192.1007(a)
(1) Identify the characteristics of the pipeline's design and operations and the environmental factors that are necessary to assess the applicable threats and risks to its gas distribution pipeline. 192.1007(a)(1)
(2) Consider the information gained from past design, operations, and maintenance. 192.1007(a)(2)
(3) Identify additional information needed and provide a plan for gaining that information over time through normal activities conducted on the pipeline (for example, design, construction, operations or maintenance activities). 192.1007(a)(3)
(4) Develop and implement a process by which the IM program will be reviewed periodically and refined and improved as needed. 192.1007(a)(4)
(5) Provide for the capture and retention of data on any new pipeline installed. The data must include, at a minimum, the location where the new pipeline is installed and the material of which it is constructed. 192.1007(a)(5)
(b) Identify threats. The operator must consider the following categories of threats to each gas distribution pipeline: Corrosion (including atmospheric corrosion), natural forces, excavation damage, other outside force damage, material or welds, equipment failure, incorrect operations, and other issues that could threaten the integrity of its pipeline. An operator must consider reasonably available information to identify existing and potential threats. Sources of data may include incident and
leak history, corrosion control records (including atmospheric corrosion records), continuing surveillance records, patrolling records, maintenance history, and excavation damage experience. 192.1007(b)
(c) Evaluate and rank risk. An operator must evaluate the risks associated with its distribution pipeline. In this evaluation, the operator must determine the relative importance of each threat and estimate and rank the risks posed to its pipeline. This evaluation must consider each applicable current and potential threat, the likelihood of failure associated with each threat, and the potential consequences of such a failure. An operator may subdivide its pipeline into regions with similar characteristics (e.g., contiguous areas within a distribution pipeline consisting of mains, services and other appurtenances; areas with common materials or environmental factors), and for which similar actions likely would be effective in reducing risk. 192.1007(c)
(d) Identify and implement measures to address risks. Determine and implement measures designed to reduce the risks from failure of its gas distribution pipeline. These measures must include an effective leak management program (unless all leaks are repaired when found). 192.1007(d)
(e) Measure performance, monitor results, and evaluate effectiveness. 192.1007(e)
(1) Develop and monitor performance measures from an established baseline to evaluate the effectiveness of its IM program. An operator must consider the results of its performance monitoring in periodically re-evaluating the threats and risks. These performance measures must include the following: 192.1007(e)(1)
(i) Number of hazardous leaks either eliminated or repaired as required by §192.703(c) of this subchapter (or total number of leaks if all leaks are repaired when found), categorized by cause;192.1007(e)(1)(i)
(ii) Number of excavation damages;192.1007(e)(1)(ii)
(iii) Number of excavation tickets (receipt of information by the underground facility operator from the notification center); 192.1007(e)(1)(iii)
(iv) Total number of leaks either eliminated or repaired, categorized by cause;192.1007(e)(1)(iv)
(v) Number of hazardous leaks either eliminated or repaired as required by §192.703(c) (or total number of leaks if all leaks are repaired when found), categorized by material; and 192.1007(e)(1)(v)
(vi) Any additional measures the operator determines are needed to evaluate the effectiveness of the operator's IM program in controlling each identified threat.192.1007(e)(1)(vi)
(f) Periodic Evaluation and Improvement. An operator must re-evaluate threats and risks on its entire pipeline and consider the relevance of threats in one location to other areas. Each operator must determine the appropriate period for conducting complete program evaluations based on the complexity of its system and changes in factors affecting the risk of failure. An operator must conduct a complete program reevaluation at least every five years. The operator must consider the results of the performance monitoring in these evaluations. 192.1007(f)
(g) Report results. Report, on an annual basis, the four measures listed in paragraphs (e)(1)(i) through (e)(1)(iv) of this section, as part of the annual report required by §191.11. An operator also must report the four measures to the state pipeline safety authority if a state exercises jurisdiction over the operator's pipeline. 192.1007(g)
[74 FR 63934, Dec. 4, 2009, as amended at 76 FR 5499, Feb. 1, 2011]
§192.1009 [Reserved]
§192.1011 What records must an operator keep?
An operator must maintain records demonstrating compliance with the requirements of this subpart for at least 10 years. The records must include copies of superseded integrity management plans developed under this subpart.
§192.1013 When may an operator deviate from required periodic inspections under this part?
(a) An operator may propose to reduce the frequency of periodic inspections and tests required in this part on the basis of the engineering analysis and risk assessment required by this subpart. 192.1013(a)
(b) An operator must submit its proposal to the PHMSA Associate Administrator for Pipeline Safety or, in the case of an intrastate pipeline facility regulated by the State, the appropriate State agency. The applicable oversight agency may accept the proposal on its own authority, with or without conditions and limitations, on a showing that the operator's proposal, which includes the adjusted interval, will provide an equal or greater overall level of safety. 192.1013(b)
(c) An operator may implement an approved reduction in the frequency of a periodic inspection or test only where the operator has developed and implemented an integrity management program that provides an equal or improved overall level of safety despite the reduced frequency of periodic inspections. 192.1013(c)
§192.1015 What must a small LPG operator do to implement this subpart?
(a) General. No later than August 2, 2011, a small LPG operator must develop and implement an IM program that includes a written IM plan as specified in paragraph (b) of this section. The IM program for these pipelines should reflect the relative simplicity of these types of pipelines. 192.1015(a)
(b) Elements. A written integrity management plan must address, at a minimum, the following elements: 192.1015(b)
(1) Knowledge. The operator must demonstrate knowledge of its pipeline, which, to the extent known, should include the approximate location and material of its pipeline. The operator must identify additional information needed and provide a plan for gaining knowledge over time through normal activities conducted on the pipeline (for example, design, construction, operations or maintenance activities). 192.1015(b)(1)
(2) Identify threats. The operator must consider, at minimum, the following categories of threats (existing and potential): Corrosion (including atmospheric corrosion), natural forces, excavation damage, other outside force damage, material or weld failure, equipment failure, and incorrect operation. 192.1015(b)(2)
(3) Rank risks. The operator must evaluate the risks to its pipeline and estimate the relative importance of each identified threat. 192.1015(b)(3)
(4) Identify and implement measures to mitigate risks. The operator must determine and implement measures designed to reduce the risks from failure of its pipeline. 192.1015(b)(4)
(5) Measure performance, monitor results, and evaluate effectiveness. The operator must monitor, as a performance measure, the number of leaks eliminated or repaired on its pipeline and their causes. 192.1015(b)(5)
(6) Periodic evaluation and improvement. The operator must determine the appropriate period for conducting IM program evaluations based on the complexity of its pipeline and changes in factors affecting the risk of failure. An operator must re-evaluate its entire program at least every 5 years. The operator must consider the results of the performance monitoring in these evaluations. 192.1015(b)(6)
(c) Records. The operator must maintain, for a period of at least 10 years, the following records: 192.1015(c)
(1) A written IM plan in accordance with this section, including superseded IM plans; 192.1015(c)(1)
(2) Documents supporting threat identification; and 192.1015(c)(2)
(3) Documents showing the location and material of all piping and appurtenances that are installed after the effective date of the operator's IM program and, to the extent known, the location and material of all pipe and appurtenances that were existing on the effective date of the operator's program. 192.1015(c)(3)
Appendix A Part 192 [Reserved]
Appendix B Part 192 — Qualification of Pipe and Components
I. List of Specifications
A. Listed Pipe Specifications
API Spec 5L — Steel pipe, "API Specification for Line Pipe" (incorporated by reference, see §192.7).
ASTM A53/A53M — Steel pipe, "Standard Specification for Pipe, Steel Black and Hot-Dipped, Zinc-Coated, Welded and Seamless" (incorporated by reference, see §192.7).
ASTM A106/A-106M — Steel pipe, "Standard Specification for Seamless Carbon Steel Pipe for High Temperature Service" (incorporated by reference, see §192.7).
ASTM A333/A333M — Steel pipe, "Standard Specification for Seamless and Welded Steel Pipe for Low Temperature Service" (incorporated by reference, see §192.7).
ASTM A381 — Steel pipe, "Standard Specification for Metal-ArcWelded Steel Pipe for Use with High-Pressure Transmission Systems" (incorporated by reference, see §192.7).
ASTM A671/A671M — Steel pipe, "Standard Specification for Electric-Fusion-Welded Pipe for Atmospheric and Lower Temperatures" (incorporated by reference, see §192.7).
ASTM A672/A672M-09 — Steel pipe, "Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures" (incorporated by reference, see §192.7).
ASTM A691/A691M-09 — Steel pipe, "Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High Pressure Service at High Temperatures" (incorporated by reference, see §192.7).
ASTM D2513 "Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings" (incorporated by reference, see §192.7).
ASTM D 2517-00 — Thermosetting plastic pipe and tubing, "Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by reference, see §192.7).
ASTM F2785-12 "Standard Specification for Polyamide 12 Gas Pressure Pipe, Tubing, and Fittings" (PA-12) (incorporated by reference, see §192.7).
ASTM F2817-10 "Standard Specification for Poly (Vinyl Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or Repair" (incorporated by reference, see §192.7).
ASTM F2945-12a "Standard Specification for Polyamide 11 Gas Pressure Pipe, Tubing, and Fittings" (PA-11) (incorporated by reference, see §192.7).
B. Other Listed Specifications for Components
ASME B16.40-2008 "Manually Operated Thermoplastic Gas Shutoffs and Valves in Gas Distribution Systems" (incorporated by reference, see §192.7).
ASTM D2513 "Standard Specification for Polyethylene (PE) Gas Pressure Pipe, Tubing, and Fittings" (incorporated by reference, see §192.7).
ASTM D 2517-00 — Thermosetting plastic pipe and tubing, "Standard Specification for Reinforced Epoxy Resin Gas Pressure Pipe and Fittings" (incorporated by reference, see §192.7).
ASTM F2785-12 "Standard Specification for Polyamide 12 Gas Pressure Pipe, Tubing, and Fittings" (PA-12) (incorporated by reference, see §192.7).
ASTM F2945-12a "Standard Specification for Polyamide 11 Gas Pressure Pipe, Tubing, and Fittings" (PA-11) (incorporated by reference, see §192.7).
ASTM F1055-98 (2006) "Standard Specification for Electrofusion Type Polyethylene Fittings for Outside Diameter Controlled Polyethylene Pipe and Tubing" (incorporated by reference, see §192.7).
ASTM F1924-12 "Standard Specification for Plastic Mechanical Fittings for Use on Outside Diameter Controlled Polyethylene Gas Distribution Pipe and Tubing" (incorporated by reference, see §192.7).
ASTM F1948-12 "Standard Specification for Metallic Mechanical Fittings for Use on Outside Diameter Controlled Thermoplastic Gas Distribution Pipe and Tubing" (incorporated by reference, see §192.7).
ASTM F1973-13 "Standard Specification for Factory Assembled Anodeless Risers and Transition Fittings in Polyethylene (PE) and Polyamide 11 (PA 11) and Polyamide 12 (PA 12) Fuel Gas Distribution Systems" (incorporated by reference, see §192.7).
ASTM F 2600-09 "Standard Specification for Electrofusion Type Polyamide-11 Fittings for Outside Diameter Controlled Polyamide-11 Pipe and Tubing" (incorporated by reference, see §192.7).
ASTM F2145-13 "Standard Specification for Polyamide 11 (PA 11) and Polyamide 12 (PA12) Mechanical Fittings for Use on Outside Diameter Controlled Polyamide 11 and Polyamide 12 Pipe and Tubing" (incorporated by reference, see §192.7).
ASTM F2767-12 "Specification for Electrofusion Type Polyamide-12 Fittings for Outside Diameter Controlled Polyamide-12 Pipe and Tubing for Gas Distribution" (incorporated by reference, see §192.7).
ASTM F2817-10 "Standard Specification for Poly (Vinyl Chloride) (PVC) Gas Pressure Pipe and Fittings for Maintenance or Repair" (incorporated by reference, see §192.7).
II. Steel pipe of unknown or unlisted specification.
A. Bending Properties. For pipe 2 inches (51 millimeters) or less in diameter, a length of pipe must be cold bent through at least 90 degrees around a cylindrical mandrel that has a diameter 12 times the diameter of the pipe, without developing cracks at any portion and without opening the longitudinal weld. 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/A53M (incorporated by reference, see §192.7), 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. Weldability. A girth weld must be made in the pipe by a welder who is qualified under subpart E of this part. The weld must be made under the most severe conditions under which welding will be allowed in the field and by means of the same procedure that will be used in the field. On pipe more than 4 inches (102 millimeters) in diameter, at least one test weld must be made for each 100 lengths of pipe. On pipe 4 inches (102 millimeters) or less in diameter, at least one test weld must be made for each 400 lengths of pipe. The weld must be tested in accordance with API Standard 1104 (incorporated by reference, see §192.7). If the requirements of API Standard 1104 cannot be met, weldability may be established by making chemical tests
for carbon and manganese, and proceeding in accordance with section IX of the ASME Boiler and Pressure Vessel Code (ibr, see 192.7). The same number of chemical tests must be made as are required for testing a girth weld.
C. Inspection. The pipe must be clean enough to permit adequate inspection. It must be visually inspected to ensure that it is reasonably round and straight and there are no defects which might impair the strength or tightness of the pipe.
D. Tensile Properties. If the tensile properties of the pipe are not known, the minimum yield strength may be taken as 24,000 p.s.i. (165 MPa) or less, or the tensile properties may be established by performing tensile tests as set forth in API Specification 5L (incorporated by reference, see §192.7). All test specimens shall be selected at random and the following number of tests must be performed:
Number of Tensile Tests — All Sizes
10 lengths or less
1 set of tests for each length.
11 to 100 lengths 1 set of tests for each 5 lengths, but not less than 10 tests.
Over 100 lengths 1 set of tests for each 10 lengths, but not less than 20 tests.
If the yield-tensile ratio, based on the properties determined by those tests, exceeds 0.85, the pipe may be used only as provided in §192.55(c).
III. Steel pipe manufactured before November 12, 1970, to earlier editions of listed specifications. Steel pipe manufactured before November 12, 1970, in accordance with a specification of which a later edition is listed in section I of this appendix, is qualified for use under this part if the following requirements are met:
A. Inspection. The pipe must be clean enough to permit adequate inspection. It must be visually inspected to ensure that it is reasonably round and straight and that there are no defects which might impair the strength or tightness of the pipe.
B. Similarity of specification requirements. The edition of the listed specification under which the pipe was manufactured must have substantially the same requirements with respect to the following properties as a later edition of that specification listed in section I of this appendix:
(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. Inspection or test of welded pipe. On pipe with welded seams, one of the following requirements must be met:
(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.
[35 FR 13257, Aug. 19, 1970]
Editorial Note: For Federal Register citations affecting appendix B to part 192, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and on GPO Access.
Appendix C Part 192 — Qualification of Welders for Low Stress Level Pipe
I. Basic test. The test is made on pipe 12 inches (305 millimeters) or less in diameter. The test weld must be made with the pipe in a horizontal fixed position so that the test weld includes at least one section of overhead position welding. The beveling, root opening, and other details must conform to the specifications of the procedure under which the welder is being qualified. Upon completion, the test weld is cut into four coupons and subjected to a root bend test. If, as a result of this test, two or more of the four coupons develop a crack in the weld material, or between the weld material and base metal, that is more than 1⁄8-inch (3.2 millimeters) long in any direction, the weld is unacceptable. Cracks that occur on the corner of the specimen during testing are not considered. A welder who successfully passes a butt-weld qualification test under this section shall be qualified to weld on all pipe diameters less than or equal to 12 inches.
II. Additional tests for welders of service line connections to mains. A service line connection fitting is welded to a pipe section with the same diameter as a typical main. The weld is made in the same position as it is made in the field. The weld is unacceptable if
it shows a serious undercutting or if it has rolled edges. The weld is tested by attempting to break the fitting off the run pipe. The weld is unacceptable if it breaks and shows incomplete fusion, overlap, or poor penetration at the junction of the fitting and run pipe.
III. Periodic tests for welders of small service lines. Two samples of the welder's work, each about 8 inches (203 millimeters) long with the weld located approximately in the center, are cut from steel service line and tested as follows:
(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.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-94, 69 FR 32896, June 14, 2004]
Appendix D Part 192 — Criteria for Cathodic Protection and Determination of Measurements
I. Criteria for cathodic protection —
A. Steel, cast iron, and ductile iron structures.
(1) A negative (cathodic) voltage of at least 0.85 volt, with reference to a saturated copper-copper sulfate half cell. Determination of this voltage must be made with the protective current applied, and in accordance with sections II and IV of this appendix.
(2) A negative (cathodic) voltage shift of at least 300 millivolts. Determination of this voltage shift must be made with the protective current applied, and in accordance with sections II and IV of this appendix. This criterion of voltage shift applies to structures not in contact with metals of different anodic potentials.
(3) A minimum negative (cathodic) polarization voltage shift of 100 millivolts. This polarization voltage shift must be determined in accordance with sections III and IV of this appendix.
(4) A voltage at least as negative (cathodic) as that originally established at the beginning of the Tafel segment of the Elog-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. Aluminum structures.
(1) Except as provided in paragraphs (3) and (4) of this paragraph, a minimum negative (cathodic) voltage shift of 150 millivolts, produced by the application of protective current. The voltage shift must be determined in accordance with sections II and IV of this appendix.
(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 buildup 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. Copper structures. 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.
D. Metals of different anodic potentials. A negative (cathodic) voltage, measured in accordance with section IV of this appendix, equal to that required for the most anodic metal in the system must be maintained. If amphoteric structures are involved that could be damaged by high alkalinity covered by paragraphs (3) and (4) of paragraph B
of this section, they must be electrically isolated with insulating flanges, or the equivalent.
II. Interpretation of voltage measurement. Voltage (IR) drops other than those across the structure-electrolyte boundary must be considered for valid interpretation of the voltage measurement in paragraphs A(1) and (2) and paragraph B(1) of section I of this appendix.
III. Determination of polarization voltage shift. The polarization voltage shift must be determined by interrupting the protective current and measuring the polarization decay. When the current is initially interrupted, an immediate voltage shift occurs. The voltage reading after the immediate shift must be used as the base reading from which to measure polarization decay in paragraphs A(3), B(2), and C of section I of this appendix.
IV. Reference half cells.
A. Except as provided in paragraphs B and C of this section, negative (cathodic) voltage must be measured between the structure surface and a saturated copper-copper sulfate half cell contacting the electrolyte.
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.
[Amdt. 192-4, 36 FR 12305, June 30, 1971]
Appendix E Part 192 — Guidance on Determining High Consequence Areas and on Carrying out
Requirements in the Integrity Management Rule
I. Guidance on Determining a High Consequence Area
To determine which segments of an operator's transmission pipeline system are covered for purposes of the integrity management program requirements, an operator must identify the high consequence areas. An operator must use method (1) or (2) from the definition in §192.903 to identify a high consequence area. An operator may apply one method to its entire pipeline system, or an operator may apply one method to individual portions of the pipeline system. (Refer to figure E.I.A for a diagram of a high consequence area).
Determining High Consequence Area
II. Guidance on Assessment Methods and Additional Preventive and Mitigative Measures for Transmission Pipelines
(a) Table E.II.1 gives guidance to help an operator implement requirements on additional preventive and mitigative measures for addressing time dependent and independent threats for a transmission pipeline operating below 30% SMYS not in an HCA (i.e. outside of potential impact circle) but located within a Class 3 or Class 4 Location.
(b) Table E.II.2 gives guidance to help an operator implement requirements on assessment methods for addressing time dependent and independent threats for a transmission pipeline in an HCA.
Appendix E Part 192 – Minimum Federal Safety Standards
(c) Table E.II.3 gives guidance on preventative & mitigative measures addressing time dependent and independent threats for transmission pipelines that operate below 30% SMYS, in HCAs.
E II.1: Preventive Mitigative Measures for Transmission Pipelines Operating Below 30% SMYS not in an HCA but in a Class 3 or Class 4 Location (Column 1)
Existing 192 Requirements (Column 4)
Threat (Column 2) (Column 3)
External Corrosion
Internal Corrosion
3rd Party Damage
Additional (to 192 Requirements)
Primary Secondary Preventive and Mitigative Measures
455-(Gen. Post 1971), 457-Gen. Pre-1971) 459-(Examination), 461-(Ext. Coating)
For Unprotected Transmission Pipelines or for Carthodically Protected Pipe where Electrical Surveys are Impractical:
•Perform quarterly leak surveys
•Perform semi-annual leak surveys
•Participation in state one-call system,
•Use of qualified operator employees and contractors to perform marking and locating of buried structures and indirect supervision of excavation work, AND
•Either monitoring of excavations near operator's transmission pipelines, or bi-monthly patrol of transmission pipelines in class 3 and 4 locations. Any indications of unreported construction activity would require a follow up investigation to determine if mechanical damage occurred.
Table E.II.2 Assessment Requirements for Transmission Pipelines in HCAs (re-assessment intervals are maximum allowed)
Re-Assessment Requirements (see note 3)
Note 1:Operator may choose to utilize CDA at year 14, then utilize II.1, Pressure Test, or DA at year 15 as allowed under ASME B31.8S
Note 2:Operator may choose to utilize CDA at year 7 and 14 in lieu of P&M
Note 3:Operator may utilize "other technology that an operator demonstrates can provide an equivalent understanding of the condition of
Table E.II.3 Preventative & Mitigative Measures addressing Time Dependent and Independent Threats for Transmission Pipelines that Operate Below 30%
[Amdt. 192-95, 69 FR 18234, Apr. 6, 2004, as amended by Amdt. 192-95, May 26, 2004]
603-(Gen Oper) 613-(Surveil)
53(a)-(Materials)
603-(Gen Oper) 613-(Surveil)
615 — (Emerg Plan)
Appendix F Part 192-Criteria for Conducting Integrity Assessments Using Guided Wave Ultrasonic Testing (GWUT)
This appendix defines criteria which must be properly implemented for use of guided wave ultrasonic testing (GWUT) as an integrity assessment method. Any application of GWUT that does not conform to these criteria is considered “other technology” as described by §§192.710(c)(7), 192.921(a)(7), and 192.937(c)(7), for which OPS must be notified 90 days prior to use in accordance with §§192.921(a)(7) or 192.937(c)(7). GWUT in the “Go-No Go” mode means that all indications (wall loss anomalies) above the testing threshold (a maximum of 5% of cross sectional area (CSA) sensitivity) be directly examined, in-line tool inspected, pressure tested, or replaced prior to completing the integrity assessment on the carrier pipe.
I. Equipment and Software: Generation. The equipment and the computer software used are critical to the success of the inspection. Computer software for the inspection equipment must be reviewed and updated, as required, on an annual basis, with intervals not to exceed 15 months, to support sensors, enhance functionality, and resolve any technical or operational issues identified. Appendix F I.
II. Inspection Range. The inspection range and sensitivity are set by the signal to noise (S/N) ratio but must still keep the maximum threshold sensitivity at 5% cross sectional area (CSA). A signal that has an amplitude that is at least twice the noise level can be reliably interpreted. The greater the S/N ratio the easier it is to identify and interpret signals from small changes. The signal to noise ratio is dependent on several variables such as surface roughness, coating, coating condition, associated pipe fittings (T's, elbows, flanges), soil compaction, and environment. Each of these affects the propagation of sound waves and influences the range of the test. It may be necessary to inspect from both ends of the pipeline segment to achieve a full inspection. In general, the inspection range can approach 60 to 100 feet for a 5% CSA, depending on field conditions. Appendix F II.
III. Complete Pipe Inspection. To ensure that the entire pipeline segment is assessed there should be at least a 2 to 1 signal to noise ratio across the entire pipeline segment that is inspected. This may require multiple GWUT shots. Double-ended inspections are expected. These two inspections are to be overlaid to show the minimum 2 to 1 S/N ratio is met in the middle. If possible, show the same near or midpoint feature from both sides and show an approximate 5% distance overlap. Appendix F III.
•Perform an electrical survey (i.e. indirect examination tool/method) at least every 7 years. Results are to be utilized as part of an overall evaluation of the CP system and corrosion threat for the covered segment. Evaluation shall include consideration of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment.
For Unprotected Trmn. Pipelines or for Cathodically Protected Pipe where Electrical Surveys are Impracticable •Conduct quarterly leak surveys AND •Every 1-1/2 years, determine areas of active corrosion by evaluation of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment.
•Obtain and review gas analysis data each calendar year for corrosive agents from transmission pipelines in HCAs,
•Periodic testing of fluid removed from pipelines. Specifically, once each calendar year from each storage field that may affect transmission pipelines in HCAs, AND
•At least every 7 years, integrate data obtained with applicable internal corrosion leak records, incident reports, safety related condition reports, repair records, patrol records, patrol records, exposed pipe reports, and test records.
•Participation in state one-call system, •Use of qualified operator employees and contractors to perform marking and locating of buried structures and in direct supervision of excavation work, AND
•Either monitoring of excavations near operator's transmission pipelines, or bi-monthly patrol of transmission pipelines in HCAs or class 3 and 4 locations. Any indications of unreported construction activity would require a follow up investigation to determine if mechanical damage occurred.
IV. Sensitivity. The detection sensitivity threshold determines the ability to identify a cross sectional change. The maximum threshold sensitivity cannot be greater than 5% of the cross sectional area (CSA). Appendix F IV.
The locations and estimated CSA of all metal loss features in excess of the detection threshold must be determined and documented.
All defect indications in the “Go-No Go” mode above the 5% testing threshold must be directly examined, in-line inspected, pressure tested, or replaced prior to completing the integrity assessment.
V. Wave Frequency. Because a single wave frequency may not detect certain defects, a minimum of three frequencies must be run for each inspection to determine the best frequency for characterizing indications. The frequencies used for the inspections must be documented and must be in the range specified by the manufacturer of the equipment. Appendix F V.
VI. Signal or Wave Type: Torsional and Longitudinal. Both torsional and longitudinal waves must be used and use must be documented. Appendix F VI.
VII. Distance Amplitude Correction (DAC) Curve and Weld Calibration. The distance amplitude correction curve accounts for coating, pipe diameter, pipe wall and environmental conditions at the assessment location. The DAC curve must be set for each inspection as part of establishing the effective range of a GWUT inspection. DAC curves provide a means for evaluating the cross-sectional area change of reflections at various distances in the test range by assessing signal to noise ratio. A DAC curve is a means of taking apparent attenuation into account along the time base of a test signal. It is a line of equal sensitivity along the trace which allows the amplitudes of signals at different axial distances from the collar to be compared. Appendix F VII.
VIII. Dead Zone. The dead zone is the area adjacent to the collar in which the transmitted signal blinds the received signal, making it impossible to obtain reliable results. Because the entire line must be inspected, inspection procedures must account for the dead zone by requiring the movement of the collar for additional inspections. An alternate method of obtaining valid readings in the dead zone is to use Bscan ultrasonic equipment and visual examination of the external surface. The length of the dead zone and the near field for each inspection must be documented. Appendix F VIII.
IX. Near Field Effects. The near field is the region beyond the dead zone where the receiving amplifiers are increasing in power, before the wave is properly established. Because the entire line must be inspected, inspection procedures must account for the near field by requiring the movement of the collar for additional inspections. An alternate method of obtaining valid readings in the near field is to use B-
Appendix F Part 192 –
scan ultrasonic equipment and visual examination of the external surface. The length of the dead zone and the near field for each inspection must be documented. Appendix F IX.
X. Coating Type. Coatings can have the effect of attenuating the signal. Their thickness and condition are the primary factors that affect the rate of signal attenuation. Due to their variability, coatings make it difficult to predict the effective inspection distance. Several coating types may affect the GWUT results to the point that they may reduce the expected inspection distance. For example, concrete coated pipe may be problematic when well bonded due to the attenuation effects. If an inspection is done and the required sensitivity is not achieved for the entire length of the pipe, then another type of assessment method must be utilized. Appendix F X.
XI. End Seal. When assessing cased carrier pipe with GWUT, operators must remove the end seal from the casing at each GWUT test location to facilitate visual inspection. Operators must remove debris and water from the casing at the end seals. Any corrosion material observed must be removed, collected and reviewed by the operator's corrosion technician. The end seal does not interfere with the accuracy of the GWUT inspection but may have a dampening effect on the range. Appendix F XI.
XII. Weld Calibration to set DAC Curve. Accessible welds, along or outside the pipeline segment to be inspected, must be used to set the DAC curve. A weld or welds in the access hole (secondary area) may be used if welds along the pipeline segment are not accessible. In order to use these welds in the secondary area, sufficient distance must be allowed to account for the dead zone and near field. There must not be a weld between the transducer collar and the calibration weld. A conservative estimate of the predicted amplitude for the weld is 25% CSA (cross sectional area) and can be used if welds are not accessible. Calibrations (setting of the DAC curve) should be on pipe with similar properties such as wall thickness and coating. If the actual weld cap height is different from the assumed weld cap height, the estimated CSA may be inaccurate and adjustments to the DAC curve may be required. Alternative means of calibration can be used if justified by a documented engineering analysis and evaluation. Appendix F XII.
XIII. Validation of Operator Training. Pipeline operators must require all guided wave service providers to have equipment-specific training and experience for all GWUT Equipment Operators which includes training for: Appendix F XIII.
A. Equipment operation, Appendix F XIII.A.
B. field data collection, and Appendix F XIII.B.
C. data interpretation on cased and buried pipe. Appendix F XIII.C.
Only individuals who have been qualified by the manufacturer or an independently assessed evaluation procedure similar to ISO 9712 (Sections: 5 Responsibilities; 6 Levels of Qualification; 7 Eligibility; and 10 Certification), as specified above, may operate the equipment. A senior-level GWUT equipment operator with pipeline specific experience must provide onsite oversight of the inspection and approve the final reports. A seniorlevel GWUT equipment operator must have additional training and experience, including training specific to cased and buried pipe, with a quality control program which that conforms to Section 12 of ASME B31.8S (for availability, see §192.7).
XIV. Training and Experience Minimums for Senior Level GWUT Equipment Operators: Appendix F XIV.
• Equipment Manufacturer's minimum qualification for equipment operation and data collection with specific endorsements for casings and buried pipe
• Training, qualification and experience in testing procedures and frequency determination
• Training, qualification and experience in conversion of guided wave data into pipe features and estimated metal loss (estimated cross-sectional area loss and circumferential extent)
• Equipment Manufacturer's minimum qualification with specific endorsements for data interpretation of anomaly features for pipe within casings and buried pipe.
XV. Equipment: Traceable from vendor to inspection company. An operator must maintain documentation of the version of the GWUT software used and the serial number of the other equipment such as collars, cables, etc., in the report. Appendix F XV.
XVI. Calibration Onsite. The GWUT equipment must be calibrated for performance in accordance with the manufacturer's requirements and specifications, including the frequency of calibrations. A diagnostic check and system check must be performed on-site each time the equipment is relocated to a different casing or pipeline segment. If onsite diagnostics show a discrepancy with the manufacturer's requirements and specifications, testing must cease until the equipment can be restored to manufacturer's specifications. Appendix F XVI.
XVII. Use on Shorted Casings (direct or electrolytic). GWUT may not be used to assess shorted casings. GWUT operators must have operations and maintenance procedures (see §192.605) to address the effect of shorted casings on the GWUT signal. The equipment operator must clear any evidence of interference, other than some slight dampening of the GWUT signal from the shorted casing, according to their operating and maintenance procedures. All shorted casings found while conducting GWUT inspections must be addressed by the operator's standard operating procedures. Appendix F XVII.
XVIII. Direct examination of all indications above the detection sensitivity threshold. The use of GWUT in the “Go-No Go” mode requires that all indications (wall loss anomalies) above the testing threshold (5% of CSA sensitivity) be directly examined (or replaced) prior to completing the integrity assessment on the cased carrier pipe or other GWUT application. If this cannot be accomplished, then alternative methods of assessment (such as hydrostatic pressure tests or ILI) must be utilized. Appendix F XVIII.
XIV. Timing of direct examination of all indications above the detection sensitivity threshold. Operators must either replace or conduct direct examinations of all indications identified above the detection sensitivity threshold according to the table below. Operators must conduct leak surveys and reduce operating pressure as specified until the pipe is replaced or direct examinations are completed.
the
Replace or direct examination within 12 months, and instrumented leak survey once every 30 calendar days
Replace or direct examination within 6 months, instrumented leak survey once every 30 calendar days, and maintain MAOP below the operating pressure at time of discovery
Replace or direct examination within 6 months, instrumented leak survey once every 30 calendar days, and reduce MAOP to 80% of operating pressure at time of discovery.
detection sensitivity threshold (maximum of 5% CSA)
Part 193 –
Subpart A – General
§193.2001 Scope of part
(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 et seq.) and Part 192 of this chapter. 193.2001(a)
(b) This part does not apply to: 193.2001(b)
(1) LNG facilities used by ultimate consumers of LNG or natural gas. 193.2001(b)(1)
(2) LNG facilities used in the course of natural gas treatment or hydrocarbon extraction which do not store LNG. 193.2001(b)(2)
(3) In the case of a marine cargo transfer system and associated facilities, any matter other than siting pertaining to the system or facilities between the marine vessel and the last manifold (or in the absence of a manifold, the last valve) located immediately before a storage tank. 193.2001(b)(3)
(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)). 193.2001(b)(4)
§193.2003
[Reserved]
§193.2005 Applicability
(a) Regulations in this part governing siting, design, installation, or construction of LNG facilities (including material incorporated by reference in these regulations) do not apply to LNG facilities in existence or under construction when the regulations go into effect. 193.2005(a)
(b) If an existing LNG facility (or facility under construction before March 31, 2000 is replaced, relocated or significantly altered after March 31, 2000, the facility must comply with the applicable requirements of this part governing, siting, design, installation, and construction, except that: 193.2005(b)
(1) The siting requirements apply only to LNG storage tanks that are significantly altered by increasing the original storage capacity or relocated, and 193.2005(b)(1)
(2) To the extent compliance with the design, installation, and construction requirements would make the replaced, relocated, or altered facility incompatible with the other facilities or would otherwise be impractical, the replaced, relocated, or significantly altered facility may be designed, installed, or constructed in accordance with the original specifications for the facility, or in another manner subject to the approval of the Administrator. 193.2005(b)(2)
§193.2007 Definitions
As used in this part:
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Ambient vaporizer means a vaporizer which derives heat from naturally occurring heat sources, such as the atmosphere, sea water, surface waters, or geothermal waters.
Cargo transfer system means a component, or system of components functioning as a unit, used exclusively for transferring hazardous fluids in bulk between a tank car, tank truck, or marine vessel and a storage tank.
Component means any part, or system of parts functioning as a unit, including, but not limited to, piping, processing equipment, containers, control devices, impounding systems, lighting, security devices, fire control equipment, and communication equipment, whose integrity or reliability is necessary to maintain safety in controlling, processing, or containing a hazardous fluid.
Container means a component other than piping that contains a hazardous fluid.
Control system means a component, or system of components functioning as a unit, including control valves and sensing, warning, relief, shutdown, and other control devices, which is activated either manually or automatically to establish or maintain the performance of another component.
Controllable emergency means an emergency where reasonable and prudent action can prevent harm to people or property.
Design pressure means the pressure used in the design of components for the purpose of determining the minimum permissible thickness or physical characteristics of its various parts. When applicable,
static head shall be included in the design pressure to determine the thickness of any specific part.
Determine means make an appropriate investigation using scientific methods, reach a decision based on sound engineering judgment, and be able to demonstrate the basis of the decision.
Dike means the perimeter of an impounding space forming a barrier to prevent liquid from flowing in an unintended direction.
Emergency means a deviation from normal operation, a structural failure, or severe environmental conditions that probably would cause harm to people or property.
Exclusion zone means an area surrounding an LNG facility in which an operator or government agency legally controls all activities in accordance with §193.2057 and §193.2059 for as long as the facility is in operation.
Fail-safe means a design feature which will maintain or result in a safe condition in the event of malfunction or failure of a power supply, component, or control device.
g means the standard acceleration of gravity of 9.806 meters per second2 (32.17 feet per second2).
Gas, except when designated as inert, means natural gas, other flammable gas, or gas which is toxic or corrosive.
Hazardous fluid means gas or hazardous liquid.
Hazardous liquid means LNG or a liquid that is flammable or toxic.
Heated vaporizer means a vaporizer which derives heat from other than naturally occurring heat sources.
Impounding space means a volume of space formed by dikes and floors which is designed to confine a spill of hazardous liquid.
Impounding system includes an impounding space, including dikes and floors for conducting the flow of spilled hazardous liquids to an impounding space.
Liquefied natural gas or LNG means natural gas or synthetic gas having methane (CH4) as its major constituent which has been changed to a liquid.
LNG facility means a pipeline facility that is used for liquefying natural gas or synthetic gas or transferring, storing, or vaporizing liquefied natural gas.
LNG plant means an LNG facility or system of LNG facilities functioning as a unit.
m3 means a volumetric unit which is one cubic metre, 6.2898 barrels, 35.3147 ft.3, or 264.1720 U.S. gallons, each volume being considered as equal to the other.
Maximum allowable working pressure means the maximum gage pressure permissible at the top of the equipment, containers or pressure vessels while operating at design temperature.
Normal operation means functioning within ranges of pressure, temperature, flow, or other operating criteria required by this part.
Operator means a person who owns or operates an LNG facility.
Person means any individual, firm, joint venture, partnership, corporation, association, state, municipality, cooperative association, or joint stock association and includes any trustee, receiver, assignee, or personal representative thereof.
Pipeline facility means new and existing piping, rights-of-way, and any equipment, facility, or building used in the transportation of gas or in the treatment of gas during the course of transportation.
Piping means pipe, tubing, hoses, fittings, valves, pumps, connections, safety devices or related components for containing the flow of hazardous fluids.
Storage tank means a container for storing a hazardous fluid.
Transfer piping means a system of permanent and temporary piping used for transferring hazardous fluids between any of the following: Liquefaction process facilities, storage tanks, vaporizers, compressors, cargo transfer systems, and facilities other than pipeline facilities.
Transfer system includes transfer piping and cargo transfer system.
Vaporization means an addition of thermal energy changing a liquid to a vapor or gaseous state.
Vaporizer means a heat transfer facility designed to introduce thermal energy in a controlled manner for changing a liquid to a vapor or gaseous state.
Waterfront LNG plant means an LNG plant with docks, wharves, piers, or other structures in, on, or immediately adjacent to the navigable waters of the United States or Puerto Rico and any shore area immediately adjacent to those waters to which vessels may be secured and at which LNG cargo operations may be conducted.
§193.2009
Rules of regulatory construction
(a) As used in this part: 193.2009(a)
(1) Includes means including but not limited to;
(2) May means is permitted to or is authorized to;
(3) May not means is not permitted to or is not authorized to; and
(4) Shall or must is used in the mandatory and imperative sense.
(b) In this part: 193.2009(b)
(1) Words importing the singular include the plural; and 193.2009(b)(1)
(2) Words importing the plural include the singular. 193.2009(b)(2)
§193.2011 Reporting
Incidents, safety-related conditions, and annual pipeline summary data for LNG plants or facilities must be reported in accordance with the requirements of Part 191 of this subchapter.
§193.2013 What documents are incorporated by reference partly or wholly in this part?
(a) This part prescribes standards, or portions thereof, incorporated by reference into this part with the approval of the Director of the Federal Register in 5 U.S.C. 552(a) and 1 CFR part 51. The materials listed in this section have the full force of law. To enforce any edition other than that specified in this section, PHMSA must publish a notice of change in the Federal Register. 193.2013(a)
(1) Availability of standards incorporated by reference. All of the materials incorporated by reference are available for inspection from several sources, including the following: 193.2013(a)(1)
(i) The Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590. For more information contact 202-366-4046 or go to the PHMSA Web site at: http://www.phmsa.dot.gov/pipeline/regs.193.2013(a)(1)(i)
(ii) The National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202741-6030 or go to the NARA Web site at: http:// www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.193.2013(a)(1)(ii)
(iii) Copies of standards incorporated by reference in this part can also be purchased or are otherwise made available from the respective standards-developing organization at the addresses provided in the centralized IBR section below.193.2013(a)(1)(iii)
(b) American Gas Association (AGA), 400 North Capitol Street NW., Washington, DC 20001, and phone: 202-824-7000, Web site: http:// www.aga.org/. 193.2013(b)
(1) American Gas Association, "Purging Principles and Practices," 3rd edition, June 2001, (Purging Principles and Practices), IBR approved for §§193.2513(b) and (c), 193.2517, and 193.2615(a). 193.2013(b)(1)
(2) [Reserved] 193.2013(b)(2)
(c) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005, and phone: 202-682-8000, Web site: http://api.org/. 193.2013(c)
(1) API Standard 620, "Design and Construction of Large, Welded, Low-pressure Storage Tanks," 11th edition, February 2008 (including addendum 1 (March 2009), addendum 2 (August 2010), and addendum 3 (March 2012)), (API Std 620), IBR approved for §§193.2101(b); 193.2321(b). 193.2013(c)(1)
(2) [Reserved] 193.2013(c)(2)
(d) American Society of Civil Engineers (ASCE), 1801 Alexander Bell Drive, Reston, VA 20191, (800) 548-2723, 703 295-6300 (international), Web site: http://www.asce.org. 193.2013(d)
(1) ASCE/SEI 7-05, "Minimum Design Loads for Buildings and Other Structures" 2005 edition (including supplement No. 1 and Errata), (ASCE/SEI 7-05), IBR approved for §193.2067(b). 193.2013(d)(1)
(2) [Reserved] 193.2013(d)(2)
(e) ASME International (ASME), Three Park Avenue, New York, NY 10016. 800-843-2763 (U.S/Canada), Web site: http://www.asme.org/. 193.2013(e)
(1) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1: "Rules for Construction of Pressure Vessels," 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 1), IBR approved for §193.2321(a). 193.2013(e)(1)
(2) [Reserved] 193.2013(e)(2)
(f) Gas Technology Institute (GTI), formerly the Gas Research Institute (GRI), 1700 S. Mount Prospect Road, Des Plaines, IL 60018, phone: 847-768-0500, Web site: www.gastechnology.org. 193.2013(f)
(1) GRI-96/0396.5, "Evaluation of Mitigation Methods for Accidental LNG Releases, Volume 5: Using FEM3A for LNG Accident Consequence Analyses," April 1997, (GRI-96/0396.5), IBR approved for §193.2059(a). 193.2013(f)(1)
(2) GTI-04/0032 LNGFIRE3: "A Thermal Radiation Model for LNG Fires" March 2004, (GTI-04/0032 LNGFIRE3), IBR approved for §193.2057(a). 193.2013(f)(2)
(3) GTI-04/0049 "LNG Vapor Dispersion Prediction with the DEGADIS 2.1: Dense Gas Dispersion Model for LNG Vapor Dispersion," April 2004, (GTI-04/0049), IBR approved for §193.2059(a). 193.2013(f)(3)
(g) National Fire Protection Association (NFPA), 1 Batterymarch Park, Quincy, MA, 02169 phone: 617-984-7275, Web site: http:// www.nfpa.org/. 193.2013(g)
(1) NFPA-59A (2001), "Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)," (NFPA-59A-2001), IBR approved for §§193.2019(a), 193.2051, 193.2057, 193.2059 introductory text and (c), 193.2101(a), 193.2301, 193.2303, 193.2401, 193.2521, 193.2639(a), and 193.2801. 193.2013(g)(1)
(2) NFPA 59A (2006), "Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)," 2006 edition, approved August 18, 2005, (NFPA-59A-2006), IBR approved for §§193.2101(b) and 193.2321(b). 193.2013(g)(2)
§193.2015 [Reserved]
§193.2017 Plans and procedures
(a) Each operator shall maintain at each LNG plant the plans and procedures required for that plant by this part. The plans and procedures must be available upon request for review and inspection by the Administrator or any State Agency that has submitted a current certification or agreement with respect to the plant under the pipeline safety laws (49 U.S.C. 60101 et seq.). In addition, each change to the plans or procedures must be available at the LNG plant for review and inspection within 20 days after the change is made. 193.2017(a)
(b) The Associate 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 190.206 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety. 193.2017(b)
(c) Each operator must review and update the plans and procedures required by this part — 193.2017(c)
(1) When a component is changed significantly or a new component is installed; and 193.2017(c)(1)
(2) At intervals not exceeding 27 months, but at least once every 2 calendar years. 193.2017(c)(2)
§193.2019
Mobile and temporary LNG facilities
(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 NFPA59A-2001 (incorporated by reference, see §193.2013). 193.2019(a)
(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. 193.2019(b)
Subpart B – Siting Requirements
§193.2051 Scope
Each LNG facility designed, constructed, replaced, relocated or significantly altered after March 31, 2000 must be provided with siting requirements in accordance with the requirements of this part and of NFPA 59A (incorporated by reference, see §193.2013). In the event of a conflict between this part and NFPA-59A-2001, this part prevails.
§193.2055 [Reserved]
§193.2057 Thermal radiation protection
Each LNG container and LNG transfer system must have a thermal exclusion zone in accordance with section 2.2.3.2 of NFPA-59A-2001 (incorporated by reference, see §193.2013) with the following exceptions:
(a) The thermal radiation distances must be calculated using Gas Technology Institute's (GTI) report or computer model GTI-04/0032 LNGFIRE3: A Thermal Radiation Model for LNG Fires (incorporated by reference, see §193.2013). The use of other alternate models which take into account the same physical factors and have been validated by experimental test data may be permitted subject to the Administrator's approval. 193.2057(a)
(b) In calculating exclusion distances, the wind speed producing the maximum exclusion distances shall be used except for wind speeds that occur less than 5 percent of the time based on recorded data for the area. 193.2057(b)
(c) In calculating exclusion distances, the ambient temperature and relative humidity that produce the maximum exclusion distances shall be used except for values that occur less than five percent of the time based on recorded data for the area. 193.2057(c)
Each LNG container and LNG transfer system must have a dispersion exclusion zone in accordance with sections 2.2.3.3 and 2.2.3.4 of NFPA59A-2001 (incorporated by reference, see §193.2013) with the following exceptions:
(a) Flammable vapor-gas dispersion distances must be determined in accordance with the model described in the GTI-04/0049, "LNG Vapor Dispersion Prediction with the DEGADIS 2.1 Dense Gas Dispersion Model"" (incorporated by reference, see §193.2013)." Alternatively, in order to account for additional cloud dilution which may be caused by the complex flow patterns induced by tank and dike structure, dispersion distances may be calculated in accordance with the model described in the Gas Research Institute report GRI-96/0396.5 (incorporated by reference, see §193.2013), "Evaluation of Mitigation Methods for Accidental LNG Releases. Volume 5: Using FEM3A for LNG Accident Consequence Analyses". The use of alternate models which take into account the same physical factors and have been validated by experimental test data shall be permitted, subject to the Administrator's approval. 193.2059(a)
(b) The following dispersion parameters must be used in computing dispersion distances: 193.2059(b)
(1) Average gas concentration in air = 2.5 percent. 193.2059(b)(1)
(2) Dispersion conditions are a combination of those which result in longer predicted downwind dispersion distances than other weather conditions at the site at least 90 percent of the time, based on figures maintained by National Weather Service of the U.S. Department of Commerce, or as an alternative where the model used gives longer distances at lower wind speeds, Atmospheric Stability (Pasquill Class) F, wind speed = 4.5 miles per hour (2.01 meters/ sec) at reference height of 10 meters, relative humidity = 50.0 percent, and atmospheric temperature = average in the region. 193.2059(b)(2)
(3) The elevation for contour (receptor) output H = 0.5 meters. 193.2059(b)(3)
(4) A surface roughness factor of 0.03 meters shall be used. Higher values for the roughness factor may be used if it can be shown that the terrain both upwind and downwind of the vapor cloud has dense vegetation and that the vapor cloud height is more than ten times the height of the obstacles encountered by the vapor cloud. 193.2059(b)(4)
(c) The design spill shall be determined in accordance with section 2.2.3.5 of NFPA-59A-2001 (incorporated by reference, see §193.2013). 193.2059(c)
§193.2061
§193.2067
— 2065 [Reserved]
Wind forces
(a) LNG facilities must be designed to withstand without loss of structural or functional integrity: 193.2067(a)
(1) The direct effect of wind forces; 193.2067(a)(1)
(2) The pressure differential between the interior and exterior of a confining, or partially confining, structure; and 193.2067(a)(2)
(3) In the case of impounding systems for LNG storage tanks, impact forces and potential penetrations by wind borne missiles. 193.2067(a)(3)
(b) The wind forces at the location of the specific facility must be based on one of the following: 193.2067(b)
(1) For shop fabricated containers of LNG or other hazardous fluids with a capacity of not more than 70,000 gallons, applicable wind load data in ASCE/SEI 7 (incorporated by reference, see §193.2013). 193.2067(b)(1)
(2) For all other LNG facilities: 193.2067(b)(2)
(i) An assumed sustained wind velocity of not less than 150 miles per hour, unless the Administrator finds a lower velocity is justified by adequate supportive data; or193.2067(b)(2)(i)
(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.193.2067(b)(2)(ii)
§193.2069 — 2073 [Reserved]
Subpart C – Design
§193.2101 Scope
(a) Each LNG facility designed after March 31, 2000 must comply with the requirements of this part and of NFPA-59A-2001 (incorporated by reference, see §193.2013). If there is a conflict between this Part and NFPA-59A-2001, the requirements in this part prevail. 193.2101(a)
(b) Each stationary LNG storage tank must comply with Section 7.2.2 of NFPA-59A-2006 (incorporated by reference, see §193.2013) for seismic design of field fabricated tanks. All other LNG storage tanks must comply with API Std-620 (incorporated by reference, see §193.2013) for seismic design. 193.2101(b)
§193.2103 193.2117 [Reserved]
§193.2119 Records
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.
§193.2121 193.2153 [Reserved]
IMPOUNDMENT DESIGN AND CAPACITY
§193.2155 Structural requirements
(a) The structural members of an impoundment system must be designed and constructed to prevent impairment of the system's performance reliability and structural integrity as a result of the following: 193.2155(a)
(1) The imposed loading from — 193.2155(a)(1)
(i) Full hydrostatic head of impounded LNG;193.2155(a)(1)(i)
(ii) Hydrodynamic action, including the effect of any material injected into the system for spill control;193.2155(a)(1)(ii)
(iii) The impingement of the trajectory of an LNG jet discharged at any predictable angle; and193.2155(a)(1)(iii)
(iv) Anticipated hydraulic forces from a credible opening in the component or item served, assuming that the discharge pressure equals design pressure.193.2155(a)(1)(iv)
(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. 193.2155(a)(2)
(3) The effect of the temperature, any thermal gradient, and any other anticipated degradation resulting from sudden or localized contact with LNG. 193.2155(a)(3)
(4) Exposure to fire from impounded LNG or from sources other than impounded LNG. 193.2155(a)(4)
(5) If applicable, the potential impact and loading on the dike due to — 193.2155(a)(5)
(i) Collapse of the component or item served or adjacent components; and193.2155(a)(5)(i)
(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.193.2155(a)(5)(ii)
(b) An LNG storage tank must not be located within a horizontal distance of one mile (1.6 km) from the ends, or 1⁄4 mile (0.4 km) from the nearest point of a runway, whichever is longer. The height of LNG structures in the vicinity of an airport must also comply with Federal Aviation Administration requirements in 14 CFR Section 1.1. 193.2155(b)
§193.2157 193.2159 [Reserved]
§193.2161 Dikes, general
An outer wall of a component served by an impounding system may not be used as a dike unless the outer wall is constructed of concrete.
§193.2163 193.2165 [Reserved]
§193.2167 Covered systems
A covered impounding system is prohibited except for concrete wall designed tanks where the concrete wall is an outer wall serving as a dike.
§193.2169 193.2171 [Reserved]
§193.2173 Water removal
(a) Impoundment areas must be constructed such that all areas drain completely to prevent water collection. Drainage pumps and piping must be provided to remove water from collecting in the impoundment area. Alternative means of draining may be acceptable subject to the Administrator's approval. 193.2173(a)
(b) The water removal system must have adequate capacity to remove water at a rate equal to 25% of the maximum predictable collection rate from a storm of 10-year frequency and 1-hour duration, and other natu-
ral causes. For rainfall amounts, operators must use the "Rainfall Frequency Atlas of the United States" published by the National Weather Service of the U.S. Department of Commerce. 193.2173(b)
(c) Sump pumps for water removal must — 193.2173(c)
(1) Be operated as necessary to keep the impounding space as dry as practical; and 193.2173(c)(1)
(2) If sump pumps are designed for automatic operation, have redundant automatic shutdown controls to prevent operation when LNG is present. 193.2173(c)(2)
§193.2175 193.2179 [Reserved]
§193.2181 Impoundment capacity: LNG storage tanks
Each impounding system serving an LNG storage tank must have a minimum volumetric liquid impoundment capacity of:
(a) 110 percent of the LNG tank's maximum liquid capacity for an impoundment serving a single tank; 193.2181(a)
(b) 100 percent of all tanks or 110 percent of the largest tank's maximum liquid capacity, whichever is greater, for the impoundment serving more than one tank; or 193.2181(b)
(c) If the dike is designed to account for a surge in the event of catastrophic failure, then the impoundment capacity may be reduced to 100 percent in lieu of 110 percent. 193.2181(c)
§193.2183 193.2185 [Reserved]
LNG STORAGE TANKS
§193.2187 Nonmetallic membrane liner
A flammable nonmetallic membrane liner may not be used as an inner container in a storage tank.
§193.2189 193.2233 [Reserved]
Subpart D – Construction
§193.2301 Scope
Each LNG facility constructed after March 31, 2000 must comply with requirements of this part and of NFPA-59A-2001 (incorporated by reference see §193.2013). In the event of a conflict between this part and NFPA 59A, this part prevails.
§193.2303 Construction acceptance
No person may place in service any component until it passes all applicable inspections and tests prescribed by this subpart and NFPA-59A-2001 (incorporated by reference, see §193.2013).
§193.2304 Corrosion control overview
(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. 193.2304(a)
(b) The repair, replacement, or significant alteration of components must be reviewed only if the action to be taken — 193.2304(b)
(1) Involves a change in the original materials specified; 193.2304(b)(1)
(2) Is due to a failure caused by corrosion; or 193.2304(b)(2)
(3) Is occasioned by inspection revealing a significant deterioration of the component due to corrosion. 193.2304(b)(3)
§§193.2305-193.2319 — [Reserved]
§193.2321 Nondestructive tests
(a) The butt welds in metal shells of storage tanks with internal design pressure above 15 psig must be nondestructively examined in accordance with the ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1)(incorporated by reference, see §193.2013), except that 100 percent of welds that are both longitudinal (or meridional) and circumferential (or latitudinal) of hydraulic load bearing shells with curved surfaces that are subject to cryogenic temperatures must be nondestructively examined in accordance with the ASME BPVC (Section VIII, Division 1). 193.2321(a)
(b) For storage tanks with internal design pressures at 15 psig or less, ultrasonic examinations of welds on metal containers must comply with the following: 193.2321(b)
(1) Section 7.3.1.2 of NFPA Std-59A-2006, (incorporated by reference, see §193. 2013); 193.2321(b)(1)
(2) Appendices C and Q of API Std 620, (incorporated by reference, see §193.2013); 193.2321(b)(2)
(c) Ultrasonic examination records must be retained for the life of the facility. If electronic records are kept, they must be retained in a manner so that they cannot be altered by any means; and 193.2321(c)
(d) The ultrasonic equipment used in the examination of welds must be calibrated at a frequency no longer than eight hours. Such calibrations must verify the examination of welds against a calibration standard. If the ultrasonic equipment is found to be out of calibration, all previous weld inspections that are suspect must be reexamined. 193.2321(d)
§§193.2323-193.2329 — [Reserved]
Subpart E – Equipment
§193.2401 Scope
After March 31, 2000, each new, replaced, relocated or significantly altered vaporization equipment, liquefaction equipment, and control systems must be designed, fabricated, and installed in accordance with requirements of this part and of NFPA-59A-2001. In the event of a conflict between this part and NFPA 59A (incorporated by reference, see §193.2013), this part prevails.
§193.2403 — §193.2439 [Reserved]
§193.2441 Control center
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. 193.2441(a)
(b) Each remotely actuated control system and each automatic shutdown control system required by this part must be operable from the control center. 193.2441(b)
(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. 193.2441(c)
(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. 193.2441(d)
(e) Each control center must have a means of communicating a warning of hazardous conditions to other locations within the plant frequented by personnel. 193.2441(e)
§193.2443 [Reserved]
§193.2445 Sources of power
(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. 193.2445(a)
(b) Where auxiliary generators are used as a second source of electrical power: 193.2445(b)
(1) They must be located apart or protected from components so that they are not unusable during a controllable emergency; and 193.2445(b)(1)
(2) Fuel supply must be protected from hazards. 193.2445(b)(2)
Subpart F – Operations
§193.2501 Scope
This subpart prescribes requirements for the operation of LNG facilities.
§193.2503 Operating procedures
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. 193.2503(a)
(b) Startup and shutdown, including for initial startup, performance testing to demonstrate that components will operate satisfactory in service. 193.2503(b)
(d) Purging and inerting components according to the requirements of §193.2517. 193.2503(d)
(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. 193.2503(e)
(f) In the case of liquefaction, maintaining temperatures, pressures, pressure differentials and flow rates, as applicable, within their design limits for: 193.2503(f)
(1) Boilers; 193.2503(f)(1)
(2) Turbines and other prime movers; 193.2503(f)(2)
(3) Pumps, compressors, and expanders; 193.2503(f)(3)
(4) Purification and regeneration equipment; and 193.2503(f)(4)
(5) Equipment within cold boxes. 193.2503(f)(5)
(g) Cooldown of components according to the requirements of §193.2505. 193.2503(g)
§193.2505 Cooldown
(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. 193.2505(a)
(b) After cooldown stabilization is reached, cryogenic piping systems must be checked for leaks in areas of flanges, valves, and seals. 193.2505(b)
§193.2507 Monitoring operations
Each component in operation or building in which a hazard to persons or property could exist must be monitored to detect fire or any malfunction or flammable fluid that could cause a hazardous condition. Monitoring must be accomplished by watching or listening from an attended control center for 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.
§193.2509 Emergency 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. 193.2509(a)
(b) To adequately handle each type of emergency identified under paragraph (a) of this section and each fire emergency, each operator must follow one or more manuals of written procedures. The procedures must provide for the following: 193.2509(b)
(1) Responding to controllable emergencies, including notifying personnel and using equipment appropriate for handling the emergency. 193.2509(b)(1)
(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. 193.2509(b)(2)
(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. 193.2509(b)(3)
(4) Cooperating with appropriate local officials in evacuations and emergencies requiring mutual assistance and keeping these officials advised of: 193.2509(b)(4)
(i) The LNG plant fire control equipment, its location, and quantity of units located throughout the plant; 193.2509(b)(4)(i)
(ii) Potential hazards at the plant, including fires; 193.2509(b)(4)(ii)
(iii) Communication and emergency control capabilities at the LNG plant; and 193.2509(b)(4)(iii)
(iv) The status of each emergency. 193.2509(b)(4)(iv)
§193.2511 Personnel safety
(a) Each operator shall provide any special protective clothing and equipment necessary for the safety of personnel while they are performing emergency response duties. 193.2511(a)
(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. 193.2511(b)
(c) Each LNG plant must be equipped with suitable first-aid material, the location of which is clearly marked and readily available to personnel. 193.2511(c)
§193.2513 Transfer procedures
(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. 193.2513(a)
(b) The transfer procedures must include provisions for personnel to: 193.2513(b)
(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 "Purging Principles and Practices (incorporated by reference, see §193.2013)"; 193.2513(b)(1)
(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; 193.2513(b)(2)
(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; 193.2513(b)(3)
(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. 193.2513(b)(4)
(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. 193.2513(b)(5)
(6) Manually terminate the flow before overfilling or overpressure occurs; and 193.2513(b)(6)
(7) Deactivate cargo transfer systems in a safe manner by depressurizing, venting, and disconnecting lines and conducting any other appropriate operations. 193.2513(b)(7)
(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: 193.2513(c)
(1) Be in constant attendance during all cargo transfer operations; 193.2513(c)(1)
(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; 193.2513(c)(2)
(3) Before transfer, verify that: 193.2513(c)(3)
(i) Each tank car or tank truck complies with applicable regulations governing its use; 193.2513(c)(3)(i)
(ii) All transfer hoses have been visually inspected for damage and defects; 193.2513(c)(3)(ii)
(iii) Each tank truck is properly immobilized with chock wheels, and electrically grounded; and 193.2513(c)(3)(iii)
(iv) Each tank truck engine is shut off unless it is required for transfer operations; 193.2513(c)(3)(iv)
(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; 193.2513(c)(4)
(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 "Purging Principles and Practices (incorporated by reference, see §193.2013)". 193.2513(c)(5)
(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 193.2513(c)(6)
(7) Verify that transfers into a pipeline system will not exceed the pressure or temperature limits of the system. 193.2513(c)(7)
§193.2515
Investigations of failures
(a) Each operator shall investigate the cause of each explosion, fire, or LNG spill or leak which results in: 193.2515(a)
(1) Death or injury requiring hospitalization; or 193.2515(a)(1)
(b) As a result of the investigation, appropriate action must be taken to minimize recurrence of the incident. 193.2515(b)
(c) If the Administrator or relevant state agency under the pipeline safety laws (49 U.S.C. 60101 et seq.) investigates an incident, the operator involved shall make available all relevant information and provide reasonable assistance in conducting the investigation. Unless necessary to restore or maintain service, or for safety, no component involved in the incident may be moved from its location or otherwise altered until the investigation is complete or the investigating agency otherwise provides. Where components must be moved for operational
or safety reasons, they must not be removed from the plant site and must be maintained intact to the extent practicable until the investigation is complete or the investigating agency otherwise provides. 193.2515(c)
§193.2517
Purging
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 "Purging Principles and Practices (incorporated by reference, see §193.2013)" after being taken out of service and before being returned to service.
§193.2519
Communication systems
(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. 193.2519(a)
(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. 193.2519(b)
(c) Each communication system required by this part must have an auxiliary source of power, except sound-powered equipment. 193.2519(c)
§193.2521 Operating records
Each operator shall maintain a record of results of each inspection, test and investigation required by this subpart. For each LNG facility that is designed and constructed after March 31, 2000 the operator shall also maintain related inspection, testing, and investigation records that NFPA59A-2001 (incorporated by reference, see §193.2013) requires. Such records, whether required by this part or NFPA-59A-2001, must be kept for a period of not less than five years.
Subpart G – Maintenance
§193.2601 Scope
This subpart prescribes requirements for maintaining components at LNG plants.
§193.2603 General
(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. 193.2603(a)
(b) An operator may not place, return, or continue in service any component which is not maintained in accordance with this subpart. 193.2603(b)
(c) Each component taken out of service must be identified in the records kept under §193.2639. 193.2603(c)
(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. 193.2603(d)
(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. 193.2603(e)
§193.2605
Maintenance procedures
(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. 193.2605(a)
(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: 193.2605(b)
(1) The details of the inspections or tests determined under paragraph (a) of this section and their frequency of performance; and 193.2605(b)(1)
(2) A description of other actions necessary to maintain the LNG plant according to the requirements of this subpart. 193.2605(b)(2)
(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. 193.2605(c)
§193.2607 Foreign material
(a) The presence of foreign material, contaminants, or ice shall be avoided or controlled to maintain the operational safety of each component. 193.2607(a)
(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. 193.2607(b)
§193.2609 Support systems
Each support system or foundation of each component must be inspected for any detrimental change that could impair support.
§193.2611 Fire protection
(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. 193.2611(a)
(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. 193.2611(b)
§193.2613 Auxiliary power sources
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.
§193.2615 Isolating and purging
(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 "Purging Principles and Practices (incorporated by reference, see §193.2013)"; unless the maintenance procedures under §193.2605 provide that the activity can be safely performed without purging. 193.2615(a)
(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. 193.2615(b)
§193.2617 Repairs
(a) Repair work on components must be performed and tested in a manner which: 193.2617(a)
(1) As far as practicable, complies with the applicable requirements of Subpart D of this part; and 193.2617(a)(1)
(2) Assures the integrity and operational safety of the component being repaired. 193.2617(a)(2)
(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. 193.2617(b)
§193.2619 Control systems
(a) Each control system must be properly adjusted to operate within design limits. 193.2619(a)
(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. 193.2619(b)
(c) Control systems in service, but not normally in operation, such as relief valves and automatic shutdown devices, and control systems for internal shutoff valves for bottom penetration tanks must be inspected and tested once each calendar year, not exceeding 15 months, with the following exceptions: 193.2619(c)
(1) Control systems used seasonally, such as for liquefaction or vaporization, must be inspected and tested before use each season. 193.2619(c)(1)
(2) Control systems that are intended for fire protection must be inspected and tested at regular intervals not to exceed 6 months. 193.2619(c)(2)
(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. 193.2619(d)
(e) Relief valves must be inspected and tested for verification of the valve seat lifting pressure and reseating. 193.2619(e)
§193.2621 Testing transfer hoses
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 193.2621(a)
(b) Visually inspected for damage or defects before each use. 193.2621(b)
§193.2623
Inspecting LNG storage tanks
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. 193.2623(a)
(b) Inner tank leakage. 193.2623(b)
(c) Effectiveness of insulation. 193.2623(c)
(d) Frost heave. 193.2623(d)
§193.2625 Corrosion protection
(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. 193.2625(a)
(b) Components whose integrity or reliability could be adversely affected by corrosion must be either — 193.2625(b)
(1) Protected from corrosion in accordance with §§193.2627 through 193.2635, as applicable; or 193.2625(b)(1)
(2) Inspected and replaced under a program of scheduled maintenance in accordance with procedures established under §193.2605. 193.2625(b)(2)
§193.2627
Atmospheric corrosion control
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 193.2627(a)
(b) Suitable coating or jacketing. 193.2627(b)
§193.2629 External corrosion control: buried or submerged components
(a) Each buried or submerged component that is subject to external corrosive attack must be protected from external corrosion by — 193.2629(a)
(1) Material that has been designed and selected to resist the corrosive environment involved; or 193.2629(a)(1)
(2) The following means: 193.2629(a)(2)
(i) An external protective coating designed and installed to prevent corrosion attack and to meet the requirements of §192.461 of this chapter; and193.2629(a)(2)(i)
(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.193.2629(a)(2)(ii)
(b) Where cathodic protection is applied, components that are electrically interconnected must be protected as a unit. 193.2629(b)
§193.2631 Internal corrosion control
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 193.2631(a)
(b) Suitable coating, inhibitor, or other means. 193.2631(b)
§193.2633 Interference currents
(a) Each component that is subject to electrical current interference must be protected by a continuing program to minimize the detrimental effects of currents. 193.2633(a)
(b) Each cathodic protection system must be designed and installed so as to minimize any adverse effects it might cause to adjacent metal components. 193.2633(b)
(c) Each impressed current power source must be installed and maintained to prevent adverse interference with communications and control systems. 193.2633(c)
§193.2635 Monitoring corrosion control
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. 193.2635(a)
(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 21⁄2 months, to ensure that it is operating properly. 193.2635(b)
(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 21⁄2 months. Each other interference bond must be checked at least once each calendar year, but with intervals not exceeding 15 months. 193.2635(c)
(d) Each component that is protected from atmospheric corrosion must be inspected at intervals not exceeding 3 years. 193.2635(d)
(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 71⁄2 months. 193.2635(e)
§193.2637
Remedial measures
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.
§193.2639
Maintenance records
(a) Each operator shall keep a record at each LNG plant of the date and type of each maintenance activity performed on each component to meet the requirements of this part. For each LNG facility that is designed and constructed after March 31, 2000 the operator shall also maintain related periodic inspection and testing records that NFPA59A-2001 (incorporated by reference, see §193.2013) requires. Maintenance records, whether required by this part or NFPA-59A-2001, must be kept for a period of not less than five years. 193.2639(a)
(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. 193.2639(b)
(c) Each of the following records must be retained for as long as the LNG facility remains in service: 193.2639(c)
(1) Each record or map required by paragraph (b) of this section. 193.2639(c)(1)
(2) Records of each test, survey, or inspection required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures. 193.2639(c)(2)
Subpart H – Personnel Qualifications and Training
§193.2701 Scope
This subpart prescribes requirements for personnel qualifications and training.
§193.2703 Design and fabrication
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. 193.2703(a)
(b) With respect to fabrication, persons who have demonstrated competence by training or experience in the fabrication of comparable components. 193.2703(b)
§193.2705
Construction,
installation, inspection, and testing
(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. 193.2705(a)
(b) Each operator must periodically determine whether inspectors performing construction, installation, and testing duties required by this part are satisfactorily performing their assigned functions. 193.2705(b)
§193.2707
Operations and maintenance
(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 — 193.2707(a)
(1) Successful completion of the training required by §§193.2713 and 193.2717; and 193.2707(a)(1)
(2) Experience related to the assigned operation or maintenance function; and 193.2707(a)(2)
(3) Acceptable performance on a proficiency test relevant to the assigned function. 193.2707(a)(3)
(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. 193.2707(b)
(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. 193.2707(c)
§193.2709 Security
Personnel having security duties must be qualified to perform their assigned duties by successful completion of the training required under §193.2715.
§193.2711 Personnel health
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.
§193.2713 Training: operations and maintenance
(a) Each operator shall provide and implement a written plan of initial training to instruct — 193.2713(a)
(1) All permanent maintenance, operating, and supervisory personnel — 193.2713(a)(1)
(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;193.2713(a)(1)(i)
(ii) About the potential hazards involved in operating and maintenance activities; and193.2713(a)(1)(ii)
(iii) To carry out aspects of the operating and maintenance procedures under §§193.2503 and 193.2605 that relate to their assigned functions; and193.2713(a)(1)(iii)
(2) All personnel — 193.2713(a)(2)
(i) To carry out the emergency procedures under §193.2509 that relate to their assigned functions; and193.2713(a)(2)(i)
(ii) To give first-aid; and 193.2713(a)(2)(ii)
(3) All operating and appropriate supervisory personnel — 193.2713(a)(3)
(i) To understand detailed instructions on the facility operations, including controls, functions, and operating procedures; and 193.2713(a)(3)(i)
(ii) To understand the LNG transfer procedures provided under §193.2513.193.2713(a)(3)(ii)
(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. 193.2713(b)
§193.2715 Training: security
(a) Personnel responsible for security at an LNG plant must be trained in accordance with a written plan of initial instruction to: 193.2715(a)
(1) Recognize breaches of security; 193.2715(a)(1)
(2) Carry out the security procedures under §193.2903 that relate to their assigned duties; 193.2715(a)(2)
(3) Be familiar with basic plant operations and emergency procedures, as necessary to effectively perform their assigned duties; and 193.2715(a)(3)
(4) Recognize conditions where security assistance is needed. 193.2715(a)(4)
(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. 193.2715(b)
§193.2717 Training: fire protection
(a) All personnel involved in maintenance and operations of an LNG plant, including their immediate supervisors, must be trained according to a written plan of initial instruction, including plant fire drills, to: 193.2717(a)
(1) Know the potential causes and areas of fire; 193.2717(a)(1)
(2) Know the types, sizes, and predictable consequences of fire; and 193.2717(a)(2)
(3) Know and be able to perform their assigned fire control duties according to the procedures established under §193.2509 and by proper use of equipment provided under §193.2801. 193.2717(a)(3)
(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. 193.2717(b)
(c) Plant fire drills must provide personnel hands-on experience in carrying out their duties under the fire emergency procedures required by §193.2509. 193.2717(c)
§193.2719 Training: records
(a) Each operator shall maintain a system of records which — 193.2719(a)
(1) Provide evidence that the training programs required by this subpart have been implemented; and 193.2719(a)(1)
(2) Provide evidence that personnel have undergone and satisfactorily completed the required training programs. 193.2719(a)(2)
(b) Records must be maintained for one year after personnel are no longer assigned duties at the LNG plant. 193.2719(b)
Subpart I – Fire Protection
§193.2801 Fire protection
Each operator must provide and maintain fire protection at LNG plants according to sections 9.1 through 9.7 and section 9.9 of NFPA-59A-2001 (incorporated by reference, see §193.2013). However, LNG plants existing on March 31, 2000, need not comply with provisions on emergency shutdown systems, water delivery systems, detection systems, and personnel qualification and training until September 12, 2005.
§§193.2803-193.2821 — [Reserved]
Subpart J – Security
§193.2901 Scope
This subpart prescribes requirements for security at LNG plants. However, the requirements do not apply to existing LNG plants that do not contain LNG.
§193.2903 Security procedures
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; 193.2903(a)
(b) A list of security personnel positions or responsibilities utilized at the LNG plant; 193.2903(b)
(c) A brief description of the duties associated with each security personnel position or responsibility; 193.2903(c)
(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; 193.2903(d)
(e) Methods for determining which persons are allowed access to the LNG plant; 193.2903(e)
(f) Positive identification of all persons entering the plant and on the plant, including methods at least as effective as picture badges; and 193.2903(f)
(g) Liaison with local law enforcement officials to keep them informed about current security procedures under this section. 193.2903(g)
§193.2905 Protective enclosures
(a) The following facilities must be surrounded by a protective enclosure: 193.2905(a)
(1) Storage tanks; 193.2905(a)(1)
(2) Impounding systems; 193.2905(a)(2)
(3) Vapor barriers; 193.2905(a)(3)
(4) Cargo transfer systems; 193.2905(a)(4)
(5) Process, liquefaction, and vaporization equipment; 193.2905(a)(5)
(6) Control rooms and stations; 193.2905(a)(6)
(7) Control systems; 193.2905(a)(7)
(8) Fire control equipment; 193.2905(a)(8)
(9) Security communications systems; and 193.2905(a)(9)
(10) Alternative power sources. 193.2905(a)(10)
The protective enclosure may be one or more separate enclosures surrounding a single facility or multiple facilities.
(b) Ground elevations outside a protective enclosure must be graded in a manner that does not impair the effectiveness of the enclosure. 193.2905(b)
(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. 193.2905(c)
(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. 193.2905(d)
(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. 193.2905(e)
§193.2907 Protective enclosure construction
(a) Each protective enclosure must have sufficient strength and configuration to obstruct unauthorized access to the facilities enclosed. 193.2907(a)
(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. 193.2907(b)
§193.2909 Security communications
A means must be provided for:
(a) Prompt communications between personnel having supervisory security duties and law enforcement officials; and 193.2909(a)
(b) Direct communications between all on-duty personnel having security duties and all control rooms and control stations. 193.2909(b)
§193.2911
Security lighting
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 ftc) between sunset and sunrise.
§193.2913 Security monitoring
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 m3 (250,000 bbl) of storage capacity, only the protective enclosure must be monitored.
§193.2915 Alternative power sources
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.
§193.2917 Warning signs
(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. 193.2917(a)
(b) Signs must be marked with at least the following on a background of sharply contrasting color: 193.2917(b) THE WORDS "NO TRESPASSING," OR WORDS OF COMPARABLE MEANING.
Insights
Part
Part 194 – Response Plans For Onshore
Section
Section
Section
Section
Appendix
Subpart A – General
§194.1
Purpose
This part contains requirements for oil spill response plans to reduce the environmental impact of oil discharged from onshore oil pipelines.
§194.3
Applicability
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.
§194.5
Definitions
Adverse weather means the weather conditions that the operator will consider when identifying response systems and equipment to be deployed in accordance with a response plan. Factors to consider include ice conditions, temperature ranges, weather-related visibility, significant wave height as specified in 33 CFR Part 154, Appendix C, Table 1, and currents within the areas in which those systems or equipment are intended to function.
Barrel means 42 United States gallons (159 liters) at 60 °Fahrenheit (15.6 °Celsius).
Breakout tank means a tank used to:
(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.
Contract or other approved means is:
(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.
Environmentally sensitive area means an area of environmental importance which is in or adjacent to navigable waters.
High volume area means an area which an oil pipeline having a nominal outside diameter of 20 inches (508 millimeters) or more crosses a major river or other navigable waters, which, because of the velocity of the river flow and vessel traffic on the river, would require a more rapid response in case of a worst case discharge or substantial threat of such a discharge. Appendix B to this part contains a list of some of the high volume areas in the United States.
Line section means a continuous run of pipe that is contained between adjacent pressure pump stations, between a pressure pump station and a terminal or breakout tank, between a pressure pump station and a block valve, or between adjacent block valves.
Major river means a river that, because of its velocity and vessel traffic, would require a more rapid response in case of a worst case discharge. For a list of rivers see "Rolling Rivers, An Encyclopedia of America's Rivers," Richard A. Bartlett, Editor, McGraw-Hill Book Company, 1984.
Maximum extent practicable means the limits of available technology and the practical and technical limits on a pipeline operator in planning the response resources required to provide the on-water recovery capability and the shoreline protection and cleanup capability to conduct response activities for a worst case discharge from a pipeline in adverse weather.
Navigable waters means the waters of the United States, including the territorial sea and such waters as lakes, rivers, streams; waters which are used for recreation; and waters from which fish or shellfish are taken and sold in interstate or foreign commerce.
Oil means oil of any kind or in any form, including, but not limited to, petroleum, fuel oil, vegetable oil, animal oil, sludge, oil refuse, oil mixed with wastes other than dredged spoil.
Oil spill removal organization means an entity that provides response resources.
On-Scene Coordinator (OSC) means the federal official designated by the Administrator of the EPA or by the Commandant of the USCG to coordinate and direct federal response under subpart D of the National Contingency Plan (40 CFR part 300).
Onshore oil pipeline facilities means new and existing pipe, rights-ofway and any equipment, facility, or building used in the transportation of oil located in, on, or under, any land within the United States other than submerged land.
Operator means a person who owns or operates onshore oil pipeline facilities.
Pipeline means all parts of an onshore pipeline facility through which oil moves including, but not limited to, line pipe, valves, and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with pumping units, metering and delivery stations and fabricated assemblies therein, and breakout tanks.
Qualified individual means an English-speaking representative of an operator, located in the United States, available on a 24-hour basis, with full authority to: activate and contract with required oil spill removal organization(s); activate personnel and equipment maintained by the operator; act as liaison with the OSC; and obligate any funds required to carry out all required or directed oil response activities.
Response activities means the containment and removal of oil from the water and shorelines, the temporary storage and disposal of recovered oil, or the taking of other actions as necessary to minimize or mitigate damage to the environment.
Response plan means the operator's core plan and the response zone appendices for responding, to the maximum extent practicable, to a worse case discharge of oil, or the substantial threat of such a discharge.
Response resources means the personnel, equipment, supplies, and other resources necessary to conduct response activities.
Response zone means a geographic area either along a length of pipeline or including multiple pipelines, containing one or more adjacent line sections, for which the operator must plan for the deployment of, and provide, spill response capabilities. The size of the zone is determined by the operator after considering available capability, resources, and geographic characteristics.
Specified minimum yield strength means the minimum yield strength, expressed in pounds per square inch, prescribed by the specification under which the material is purchased from the manufacturer.
Stress level means the level of tangential or hoop stress, usually expressed as a percentage of specified minimum yield strength.
Worst case discharge means the largest foreseeable discharge of oil, including a discharge from fire or explosion, in adverse weather conditions. This volume will be determined by each pipeline operator for each response zone and is calculated according to §194.105.
§194.7 Operating restrictions and interim operating authorization
(a) An operator of a pipeline for which a response plan is required under §194.101, may not handle, store, or transport oil in that pipeline unless the operator has submitted a response plan meeting the requirements of this part. 194.7(a)
(b) An operator must operate its onshore pipeline facilities in accordance with the applicable response plan. 194.7(b)
(c) The operator of a pipeline line section described in §194.103(c), may continue to operate the pipeline for two years after the date of submission of a response plan, pending approval or disapproval of that plan, only if the operator has submitted the certification required by §194.119(e). 194.7(c)
Subpart B – Response Plans
§194.101 Operators required to submit plans
(a) Except as provided in paragraph (b) of this section, unless OPS grants a request from an Federal On-Scene Coordinator (FOSC) to require an operator of a pipeline in paragraph (b) to submit a response plan, each operator of an onshore pipeline facility shall prepare and submit a response plan to PHMSA as provided in §194.119. A pipeline which does not meet the criteria for significant and substantial harm as defined in §194.103(c) and is not eligible for an exception under §194.101(b), can be expected to cause substantial harm. Operators of substantial harm pipeline facilities must prepare and submit plans to PHMSA for review. 194.101(a)
(b) Exception. An operator need not submit a response plan for: 194.101(b)
(1) A pipeline that is 65⁄8 inches (168 millimeters) or less in outside nominal diameter, is 10 miles (16 kilometers) or less in length, and all of the following conditions apply to the pipeline: 194.101(b)(1)
(i) The pipeline has not experienced a release greater than 1,000 barrels (159 cubic meters) within the previous five years, 194.101(b)(1)(i)
(ii) The pipeline has not experienced at least two reportable releases, as defined in §195.50, within the previous five years, 194.101(b)(1)(ii)
(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, and194.101(b)(1)(iii)
(iv) The pipeline is not in proximity to navigable waters, public drinking water intakes, or environmentally sensitive areas. 194.101(b)(1)(iv)
(2) (i) A line section that is greater than 65⁄8 inches in outside nominal diameter and is greater than 10 miles in length, where the operator determines that it is unlikely that the worst case discharge from any point on the line section would adversely affect, within 12 hours after the initiation of the discharge, any navigable waters, public drinking water intake, or environmentally sensitive areas.194.101(b)(2)(i)
(ii) A line section that is 65⁄8 inches (168 millimeters) or less in outside nominal diameter and is 10 miles (16 kilometers) or less in length, where the operator determines that it is unlikely that the worst case discharge from any point on the line section would adversely affect, within 4 hours after the initiation of the discharge, any navigable waters, public drinking water intake, or environmentally sensitive areas.194.101(b)(2)(ii)
§194.103 Significant and substantial harm; operator's statement
(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. 194.103(a)
(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. 194.103(b)
(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 65⁄8 inches (168 millimeters) in outside nominal diameter, greater than 10 miles (16 kilometers) in length, and the line section — 194.103(c)
(1) Has experienced a release greater than 1,000 barrels (159 cubic meters) within the previous five years, 194.103(c)(1)
(2) Has experienced two or more reportable releases, as defined in §195.50, within the previous five years, 194.103(c)(2)
(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, 194.103(c)(3)
(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 194.103(c)(4)
(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. 194.103(c)(5)
§194.105 Worst case discharge
(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. 194.105(a)
(b) The worst case discharge is the largest volume, in barrels (cubic meters), of the following: 194.105(b)
(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 194.105(b)(1)
(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 194.105(b)(2)
(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). 194.105(b)(3)
(4) Operators may claim prevention credits for breakout tank secondary containment and other specific spill prevention measures as follows: 194.105(b)(4)
§194.107 General response plan requirements
(a) Each response plan must include procedures and a list of resources for responding, to the maximum extent practicable, to a worst case discharge and to a substantial threat of such a discharge. The "substantial threat" term is equivalent to abnormal operations outlined in 49 CFR 195.402(d). To comply with this requirement, an operator can incorporate by reference into the response plan the appropriate procedures from its manual for operations, maintenance, and emergencies, which is prepared in compliance with 49 CFR 195.402. 194.107(a)
(b) An operator must certify in the response plan that it reviewed the NCP and each applicable ACP and that its response plan is consistent with the NCP and each applicable ACP as follows: 194.107(b)
(1) As a minimum to be consistent with the NCP a facility response plan must: 194.107(b)(1)
(i) Demonstrate an operator's clear understanding of the function of the Federal response structure, including procedures to notify the National Response Center reflecting the relationship between the operator's response organization's role and the Federal On Scene Coordinator's role in pollution response; 194.107(b)(1)(i)
(ii) Establish provisions to ensure the protection of safety at the response site; and194.107(b)(1)(ii)
(iii) Identify the procedures to obtain any required Federal and State permissions for using alternative response strategies such as in-situ burning and dispersants as provided for in the applicable ACPs; and194.107(b)(1)(iii)
(2) As a minimum, to be consistent with the applicable ACP the plan must: 194.107(b)(2)
(i) Address the removal of a worst case discharge and the mitigation or prevention of a substantial threat of a worst case discharge;194.107(b)(2)(i)
(ii) Identify environmentally and economically sensitive areas; 194.107(b)(2)(ii)
(iii) Describe the responsibilities of the operator and of Federal, State and local agencies in removing a discharge and in mitigating or preventing a substantial threat of a discharge; and 194.107(b)(2)(iii)
(iv) Establish the procedures for obtaining an expedited decision on use of dispersants or other chemicals.194.107(b)(2)(iv)
(c) Each response plan must include: 194.107(c)
(1) A core plan consisting of — 194.107(c)(1)
(i) An information summary as required in §194.113,194.107(c)(1)(i)
(ii) Immediate notification procedures,194.107(c)(1)(ii)
(iii) Spill detection and mitigation procedures,194.107(c)(1)(iii)
(iv) The name, address, and telephone number of the oil spill response organization, if appropriate,194.107(c)(1)(iv)
(v) Response activities and response resources,194.107(c)(1)(v)
(vi) Names and telephone numbers of Federal, State and local agencies which the operator expects to have pollution control responsibilities or support,194.107(c)(1)(vi)
(vii) Training procedures,194.107(c)(1)(vii)
(viii) Equipment testing,194.107(c)(1)(viii)
(ix) Drill program — an operator will satisfy the requirement for a drill program by following the National Preparedness for Response Exercise Program (PREP) guidelines. An operator choosing not to follow PREP guidelines must have a drill program that is equivalent to PREP. The operator must describe the drill program in the response plan and OPS will determine if the program is equivalent to PREP.194.107(c)(1)(ix)
(x) Plan review and update procedures;194.107(c)(1)(x)
(2) An appendix for each response zone that includes the information required in paragraph (c)(1)(i)-(ix) of this section and the worst case discharge calculations that are specific to that response zone. An operator submitting a response plan for a single response zone does not need to have a core plan and a response zone appendix. The operator of a single response zone onshore pipeline shall have a single summary in the plan that contains the required information in §194.113.7; and 194.107(c)(2)
(3) A description of the operator's response management system including the functional areas of finance, logistics, operations, planning, and command. The plan must demonstrate that the operator's response management system uses common terminology and has a manageable span of control, a clearly defined chain of command, and sufficient trained personnel to fill each position. 194.107(c)(3)
§194.109
Submission of state response plans
(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. 194.109(a)
(b) A plan submitted under this section must 194.109(b)
(1) Have an information summary required by §194.113; 194.109(b)(1)
(2) List the names or titles and 24-hour telephone numbers of the qualified individual(s) and at least one alternate qualified individual(s); and 194.109(b)(2)
(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. 194.109(b)(3)
§194.111 Response plan retention
(a) Each operator shall maintain relevant portions of its response plan at the operator's headquarters and at other locations from which response activities may be conducted, for example, in field offices, supervisors' vehicles, or spill response trailers. 194.111(a)
(b) Each operator shall provide a copy of its response plan to each qualified individual. 194.111(b)
§194.113
Information summary
(a) The information summary for the core plan, required by §194.107, must include: 194.113(a)
(1) The name and address of the operator; and194.113(a)(1)
(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). 194.113(a)(2)
(b) The information summary for the response zone appendix, required in §194.107, must include: 194.113(b)
(1) The information summary for the core plan;194.113(b)(1)
(2) The names or titles and 24-hour telephone numbers of the qualified individual(s) and at least one alternate qualified individual(s); 194.113(b)(2)
(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; 194.113(b)(3)
(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; 194.113(b)(4)
(5) The basis for the operator's determination of significant and substantial harm; and 194.113(b)(5)
(6) The type of oil and volume of the worst case discharge.194.113(b)(6)
§194.115 Response resources
(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. 194.115(a)
(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: 194.115(b)
§194.117 Training
(a) Each operator shall conduct training to ensure that: 194.117(a)
(1) All personnel know — 194.117(a)(1)
(i) Their responsibilities under the response plan,194.117(a)(1)(i)
(ii) The name and address of, and the procedure for contacting, the operator on a 24-hour basis, and194.117(a)(1)(ii)
(iii) The name of, and procedures for contacting, the qualified individual on a 24-hour basis;194.117(a)(1)(iii)
(2) Reporting personnel know — 194.117(a)(2)
(i) The content of the information summary of the response plan, 194.117(a)(2)(i)
(ii) The toll-free telephone number of the National Response Center, and194.117(a)(2)(ii)
(iii) The notification process; and194.117(a)(2)(iii)
(3) Personnel engaged in response activities know — 194.117(a)(3)
(i) The characteristics and hazards of the oil discharged, 194.117(a)(3)(i)
(ii) The conditions that are likely to worsen emergencies, including the consequences of facility malfunctions or failures, and the appropriate corrective actions,194.117(a)(3)(ii)
(iii) The steps necessary to control any accidental discharge of oil and to minimize the potential for fire, explosion, toxicity, or environmental damage, and194.117(a)(3)(iii)
(iv) The proper firefighting procedures and use of equipment, fire suits, and breathing apparatus.194.117(a)(3)(iv)
(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: 194.117(b)
(1) Records for operator personnel must be maintained at the operator's headquarters; and 194.117(b)(1)
(2) Records for personnel engaged in response, other than operator personnel, shall be maintained as determined by the operator. 194.117(b)(2)
(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. 194.117(c)
§194.119 Submission and approval procedures
(a) Each operator shall submit two copies of the response plan required by this part. Copies of the response plan shall be submitted to: Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, Department of Transportation, PHP 80, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. Note: Submission of plans in electronic format is preferred. 194.119(a)
(b) If PHMSA determines that a response plan requiring approval does not meet all the requirements of this part, PHMSA will notify the operator of any alleged deficiencies, and to provide the operator an opportunity to respond, including the opportunity for an informal conference, on any proposed plan revisions and an opportunity to correct any deficiencies. 194.119(b)
(c) An operator who disagrees with the PHMSA determination that a plan contains alleged deficiencies may petition PHMSA for reconsideration within 30 days from the date of receipt of PHMSA's notice. After considering all relevant material presented in writing or at an informal conference, PHMSA will notify the operator of its final decision. The operator must comply with the final decision within 30 days of issuance unless PHMSA allows additional time. 194.119(c)
Section 3
(d) For response zones of pipelines described in §194.103(c) OPS will approve the response plan if OPS determines that the response plan meets all requirements of this part. OPS may consult with the U.S. Environmental Protection Agency (EPA) or the U.S. Coast Guard (USCG) if a Federal on-scene coordinator (FOSC) has concerns about the operator's ability to respond to a worst case discharge. 194.119(d)
(e) If OPS has not approved a response plan for a pipeline described in §194.103(c), the operator may submit a certification to OPS that the operator has obtained, through contract or other approved means, the necessary personnel and equipment to respond, to the maximum extent practicable, to a worst case discharge or a substantial threat of such a discharge. The certificate must be signed by the qualified individual or an appropriate corporate officer. 194.119(e)
(f) If OPS receives a request from a FOSC to review a response plan, OPS may require an operator to give a copy of the response plan to the FOSC. OPS may consider FOSC comments on response techniques, protecting fish, wildlife and sensitive environments, and on consistency with the ACP. OPS remains the approving authority for the response plan. 194.119(f)
§194.121 Response plan review and update procedures
(a) Each operator shall update its response plan to address new or different operating conditions or information. In addition, each operator shall review its response plan in full at least every 5 years from the date of the last submission or the last approval as follows: 194.121(a)
(1) For substantial harm plans, an operator shall resubmit its response plan to OPS every 5 years from the last submission date. 194.121(a)(1)
(2) For significant and substantial harm plans, an operator shall resubmit every 5 years from the last approval date. 194.121(a)(2)
(b) If a new or different operating condition or information would substantially affect the implementation of a response plan, the operator must immediately modify its response plan to address such a change and, within 30 days of making such a change, submit the change to PHMSA. Examples of changes in operating conditions that would cause a significant change to an operator's response plan are: 194.121(b)
(1) An extension of the existing pipeline or construction of a new pipeline in a response zone not covered by the previously approved plan; 194.121(b)(1)
(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; 194.121(b)(2)
(3) The type of oil transported, if the type affects the required response resources, such as a change from crude oil to gasoline; 194.121(b)(3)
(4) The name of the oil spill removal organization; 194.121(b)(4)
(5) Emergency response procedures;194.121(b)(5)
(6) The qualified individual;194.121(b)(6)
(7) A change in the NCP or an ACP that has significant impact on the equipment appropriate for response activities; and 194.121(b)(7)
(8) Any other information relating to circumstances that may affect full implementation of the plan. 194.121(b)(8)
(c) If PHMSA determines that a change to a response plan does not meet the requirements of this part, PHMSA will notify the operator of any alleged deficiencies, and provide the operator an opportunity to respond, including an opportunity for an informal conference, to any proposed plan revisions and an opportunity to correct any deficiencies. 194.121(c)
(d) An operator who disagrees with a determination that proposed revisions to a plan are deficient may petition PHMSA for reconsideration, within 30 days from the date of receipt of PHMSA's notice. After considering all relevant material presented in writing or at the conference, PHMSA will notify the operator of its final decision. The operator must comply with the final decision within 30 days of issuance unless PHMSA allows additional time. 194.121(d)
Appendix A to Part 194 — Guidelines for the Preparation of Response Plans
This appendix provides a recommended format for the preparation and submission of the response plans required by 49 CFR Part 194. Operators are referenced to the most current version of the guidance documents listed below. Although these documents contain guidance to assist in preparing response plans, their use is not mandatory:
(1) The "National Preparedness for Response Exercise Program (PREP) Guidelines" (PREP), which can be found using the search function on the USCG's PREP Web page, http://www.uscg.mil;
(2) The National Response Team's "Integrated Contingency Plan Guidance," which can be found using the search function at the National Response Center's Web site, http://www.nrt.org and;
(3) 33 CFR Part 154, Appendix C, "Guidelines for Determining and Evaluating Required Response Resources for Facility Response Plans."
Response Plan: Section 1. Information Summary
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.
Response Plan: Section 2. Notification Procedures
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);
(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.
Response Plan: Section 4. Response Activities
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.
Response Plan: Section 5. List of Contacts
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.
Response plan: Section 6. Training Procedures
Section 6 would include a description of the training procedures and programs of the operator
Response plan: Section 7. Drill Procedures
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:
(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.
(5) A drill that exercises the entire response plan for each response zone, would be conducted at least once every 3 years.
Response
plan:
Section 8. Response Plan Review and Update Procedures
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.
Response plan: Section 9. Response Zone Appendices.
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.
Appendix B Part 194 — High Volume Areas
As of January 5, 1993 the following areas are high volume areas:
Arkansas River N. Little Rock, AR.
Arkansas River Jenks, OK.
Arkansas River Little Rock, AR.
Black Warrior River Moundville, AL.
Black Warrior River Akron, AL.
Brazos River Glen Rose, TX.
Brazos River Sealy, TX.
Catawba River Mount Holly, NC.
Chattahoochee River Sandy Springs, GA.
Colorado River Yuma, AZ.
Colorado River LaPaz, AZ.
Connecticut River Lancaster, NH.
Coosa River Vincent, AL.
Cumberland River Clarksville, TN.
Delaware River Frenchtown, NJ.
Delaware River Lower Chichester, NJ.
Gila River Gila Bend, AZ.
Grand River Bosworth, MO.
Illinois River Chillicothe, IL.
Illinois River Havanna, IL.
James River Arvonia, VA.
Kankakee River Kankakee, IL.
Kankakee River South Bend, IN.
Kankakee River Wilmington, IL.
Kentucky River Salvisa, KY.
Kentucky River Worthville, KY.
Maumee River Defiance, OH.
Maumee River Toledo, OH.
Mississippi River Myrtle Grove, LA.
Mississippi River Woodriver, IL.
Mississippi River Chester, IL.
Mississippi River Cape Girardeau, MO.
Mississippi River Woodriver, IL.
Mississippi River St. James, LA.
Mississippi River New Roads, LA.
Mississippi River Ball Club, MN.
Mississippi River Mayersville, MS.
Mississippi River New Roads, LA.
Mississippi River Quincy, IL.
Mississippi River Ft. Madison, IA.
Missouri River Waverly, MO.
Missouri River St. Joseph, MO.
Missouri River Weldon Springs, MO.
Missouri River New Frankfort, MO.
Naches River Beaumont, TX.
Ohio River Joppa, IL.
Ohio River Cincinnati, OH.
Ohio River Owensboro, KY.
Pascagoula River Lucedale, MS.
Pascagoula River Wiggins, MS.
Pearl River Columbia, MS.
Pearl River Oria, TX.
Platte River Ogaliala, NE.
Potomac River Reston, VA.
Rappahannock River Midland, VA.
Raritan River South Bound Brook, NJ.
Raritan River Highland Park, NJ.
Red River (of the South) Hanna, LA.
Red River (of the South) Bonham, TX.
Red River (of the South) Dekalb, TX.
Red River (of the South) Sentell Plantation, LA.
Red River (of the North) Wahpeton, ND.
Rio Grande Anthony, NM.
Sabine River Edgewood, TX.
Sabine River Leesville, LA.
Sabine River Orange, TX.
Sabine River Echo, TX.
Savannah River Hartwell, GA.
Smokey Hill River Abilene, KS.
Susquehanna River Darlington, MD.
Tenessee River New Johnsonville, TN.
Wabash River Harmony, IN.
Wabash River Terre Haute, IN.
Wabash River Mt. Carmel, IL.
White River Batesville, AR.
White River Grand Glaise, AR.
Wisconsin River Wisconsin Rapids, WI.
Yukon River Fairbanks, AK.
Other Navigable Waters
Arthur Kill Channel, NY
Cook Inlet, AK
Freeport, TX
Los Angeles/Long Beach Harbor, CA
Port Lavaca, TX
San Fransico/San Pablo Bay, CA
Major rivers Nearest town and state
Part 195 – Transportation Of
Integrity Management Program141
Subpart A – General
§195.0
Scope
This part prescribes safety standards and reporting requirements for pipeline facilities used in the transportation of hazardous liquids or carbon dioxide.
§195.1 Which pipelines are covered by this part?(a) Covered. Except for the pipelines listed 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 (OCS). Covered pipelines include, but are not limited to: 195.1(a)
(1) Any pipeline that transports a highly volatile liquid; 195.1(a)(1)
(2) Any pipeline segment that crosses a waterway currently used for commercial navigation; 195.1(a)(2)
(3) Except for a gathering line not covered by paragraph (a)(4) of this Section, any pipeline located in a rural or non-rural area of any diameter regardless of operating pressure; 195.1(a)(3)
(4) Any of the following onshore gathering lines used for transportation of petroleum: 195.1(a)(4)
(i) A pipeline located in a non-rural area;195.1(a)(4)(i)
(ii) A regulated rural gathering line as provided in §195.11; or 195.1(a)(4)(ii)
(iii) A pipeline located in an inlet of the Gulf of Mexico as provided in §195.413.195.1(a)(4)(iii)
(5) For purposes of the reporting requirements in subpart B of this part, any gathering line not already covered under paragraphs (a)(1), (2), (3) or (4) of this section. 195.1(a)(5)
(b) Excepted. This Part does not apply to any of the following: 195.1(b)
(1) Transportation of a hazardous liquid transported in a gaseous state; 195.1(b)(1)
(2) Except for the reporting requirements of subpart B of this part, see §195.13, transportation of a hazardous liquid through a pipeline by gravity. 195.1(b)(2)
(3) Transportation of a hazardous liquid through any of the following low-stress pipelines: 195.1(b)(3)
(i) A pipeline subject to safety regulations of the U.S. Coast Guard; or195.1(b)(3)(i)
(ii) A pipeline that serves refining, manufacturing, or truck, rail, or vessel terminal facilities, if the pipeline is less than one mile long (measured outside facility grounds) and does not cross an offshore area or a waterway currently used for commercial navigation;195.1(b)(3)(ii)
(4) Except for the reporting requirements of subpart B of this part, see §195.15, transportation of petroleum through an onshore rural gathering line that does not meet the definition of a “regulated rural gathering line” as provided in §195.11. This exception does not apply to gathering lines in the inlets of the Gulf of Mexico subject to §195.413. 195.1(b)(4)
(5) Transportation of hazardous liquid or carbon dioxide in an offshore pipeline in state waters where the pipeline is located upstream from the outlet flange of the following farthest downstream facility: The facility where hydrocarbons or carbon dioxide are produced or the facility where produced hydrocarbons or carbon dioxide are first separated, dehydrated, or otherwise processed; 195.1(b)(5)
(6) Transportation of hazardous liquid or carbon dioxide in a pipeline on the OCS where the pipeline is located upstream of the point at which operating responsibility transfers from a producing operator to a transporting operator; 195.1(b)(6)
(7) A pipeline segment upstream (generally seaward) of the last valve on the last production facility on the OCS where a pipeline on the OCS is producer-operated and crosses into state waters without first connecting to a transporting operator's facility on the OCS. Safety equipment protecting PHMSA-regulated pipeline segments is not excluded. A producing operator of a segment falling within this exception may petition the Administrator, under §190.9 of this chapter, for approval to operate under PHMSA regulations governing pipeline design, construction, operation, and maintenance; 195.1(b)(7)
(8) Transportation of 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; 195.1(b)(8)
(9) Transportation of hazardous liquid or carbon dioxide: 195.1(b)(9)
(i) By vessel, aircraft, tank truck, tank car, or other non-pipeline mode of transportation; or195.1(b)(9)(i)
(ii) Through facilities located on the grounds of a materials transportation terminal if the facilities are used exclusively to transfer hazardous liquid or carbon dioxide between non-pipeline modes of transportation or between a non-pipeline mode and a pipeline. These facilities do not include any device and associated piping that are necessary to control pressure in the pipeline under §195.406(b); or195.1(b)(9)(ii)
(10) Transportation of carbon dioxide downstream from the applicable following point: 195.1(b)(10)
(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; or195.1(b)(10)(i)
(ii) The connection of the first branch pipeline in the production field where the pipeline transports carbon dioxide to an injection well or to a header or manifold from which a pipeline branches to an injection well.195.1(b)(10)(ii)
(c) Breakout tanks. Breakout tanks subject to this Part must comply with requirements that apply specifically to breakout tanks and, to the extent applicable, with requirements that apply to pipeline systems and pipeline facilities. If a conflict exists between a requirement that applies specifically to breakout tanks and a requirement that applies to pipeline systems or pipeline facilities, the requirement that applies specifically to breakout tanks prevails. Anhydrous ammonia breakout tanks need not comply with §§195.132(b), 195.205(b), 195.242(c) and (d), 195.264(b) and (e), 195.307, 195.428(c) and (d), and 195.432(b) and (c). 195.1(c)
§195.2 Definitions
As used in this part —
Abandoned means permanently removed from service.
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safetyrelated parameters.
Barrel means a unit of measurement equal to 42 U.S. standard gallons.
Breakout tank means a tank used to (a) relieve surges in a hazardous liquid pipeline system or (b) receive and store hazardous liquid transported by a pipeline for reinjection and continued transportation by pipeline.
Carbon dioxide means a fluid consisting of more than 90 percent carbon dioxide molecules compressed to a supercritical state.
Component means any part of a pipeline which may be subjected to pump pressure including, but not limited to, pipe, valves, elbows, tees, flanges, and closures.
Computation Pipeline Monitoring (CPM) means a software-based monitoring tool that alerts the pipeline dispatcher of a possible pipeline operating anomaly that may be indicative of a commodity release.
Confirmed Discovery means when it can be reasonably determined, based on information available to the operator at the time a reportable event has occurred, even if only based on a preliminary evaluation.
Control room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility.
Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a SCADA system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility.
Corrosive product means "corrosive material" as defined by §173.136 Class 8-Definitions of this chapter.
Entirely replaced onshore hazardous liquid or carbon dioxide pipeline segments, for the purposes of §§195.258, 195.260, and 195.418, means where 2 or more miles of pipe, in the aggregate, have been replaced within any 5 contiguous miles within any 24month period.
Exposed underwater pipeline means an underwater pipeline where the top of the pipe protrudes above the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from mean low water.
Flammable product means "flammable liquid" as defined by §173.120 Class 3-Definitions of this chapter.
Gathering line means a pipeline 219.1 mm (85⁄8 in) or less nominal outside diameter that transports petroleum from a production facility.
Gulf of Mexico and its inlets means the waters from the mean high water mark of the coast of the Gulf of Mexico and its inlets open to the sea (excluding rivers, tidal marshes, lakes, and canals) seaward to include the territorial sea and Outer Continental Shelf to a depth of 15 feet (4.6 meters), as measured from the mean low water.
Hazard to navigation means, for the purposes of this part, a pipeline where the top of the pipe is less than 12 inches (305 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 feet (4.6 meters) deep, as measured from the mean low water.
Hazardous liquid means petroleum, petroleum products, anhydrous ammonia, and ethanol or other non-petroleum fuel, including biofuel, which is flammable, toxic, or would be harmful to the environment if released in significant quantities.
Highly volatile liquid or HVL means a hazardous liquid which will form a vapor cloud when released to the atmosphere and which has a vapor pressure exceeding 276 kPa (40 psia) at 37.8 °C (100 °F).
In-Line Inspection (ILI) means the inspection of a pipeline from the interior of the pipe using an in-line inspection tool. Also called intelligent or smart pigging.
In-Line Inspection Tool or Instrumented Internal Inspection Device means a device or vehicle that uses a non-destructive testing technique to inspect the pipeline from the inside. Also known as intelligent or smart pig.
In-plant piping system means piping that is located on the grounds of a plant and used to transfer hazardous liquid or carbon dioxide between plant facilities or between plant facilities and a pipeline or other mode of transportation, not including any device and associated piping that are necessary to control pressure in the pipeline under §195.406(b).
Interstate pipeline means a pipeline or that part of a pipeline that is used in the transportation of hazardous liquids or carbon dioxide in interstate or foreign commerce.
Intrastate pipeline means a pipeline or that part of a pipeline to which this part applies that is not an interstate pipeline.
Line section means a continuous run of pipe between adjacent pressure pump stations, between a pressure pump station and terminal or breakout tanks, between a pressure pump station and a block valve, or between adjacent block valves.
Low-stress pipeline means a hazardous liquid pipeline that is operated in its entirety at a stress level of 20 percent or less of the specified minimum yield strength of the line pipe.
Maximum operating pressure (MOP) means the maximum pressure at which a pipeline or segment of a pipeline may be normally operated under this part.
Nominal wall thickness means the wall thickness listed in the pipe specifications.
Notification of Potential Rupture means the notification to, or observation by, an operator of indicia identified in §195.417 of a potential unintentional or uncontrolled release of a large volume of commodity from a pipeline.
Offshore means beyond the line of ordinary low water along that portion of the coast of the United States that is in direct contact with the open seas and beyond the line marking the seaward limit of inland waters.
Operator means a person who owns or operates pipeline facilities.
Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Person means any individual, firm, joint venture, partnership, corporation, association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof.
Petroleum means crude oil, condensate, natural gasoline, natural gas liquids, and liquefied petroleum gas.
Petroleum product means flammable, toxic, or corrosive products obtained from distilling and processing of crude oil, unfinished oils, natural gas liquids, blend stocks and other miscellaneous hydrocarbon compounds.
Pipe or line pipe means a tube, usually cylindrical, through which a hazardous liquid or carbon dioxide flows from one point to another.
Pipeline or pipeline system means all parts of a pipeline facility through which a hazardous liquid or carbon dioxide moves in transportation, including, but not limited to, line pipe, valves, and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with pumping units, metering and delivery stations and fabricated assemblies therein, and breakout tanks.
Pipeline facility means new and existing pipe, rights-of-way and any equipment, facility, or building used in the transportation of hazardous liquids or carbon dioxide.
Production facility means piping or equipment used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum or carbon dioxide, or associated storage or measurement. (To be a production facility under this definition, piping or equipment must be used in the process of extracting petroleum or carbon dioxide from the ground or from facilities where CO2 is produced, and preparing it for transportation by pipeline. This includes piping between treatment plants which extract carbon dioxide, and facilities utilized for the injection of carbon dioxide for recovery operations.)
Rupture-mitigation valve (RMV) means an automatic shut-off valve (ASV) or a remote-control valve (RCV) that a pipeline operator uses to minimize the volume of hazardous liquid or carbon dioxide released from the pipeline and to mitigate the consequences of a rupture.
Rural area means outside the limits of any incorporated or unincorpated city, town, village, or any other designated residential or commercial area such as a subdivision, a business or shopping center, or community development.
Significant Stress Corrosion Cracking means a stress corrosion cracking (SCC) cluster in which the deepest crack, in a series of interacting cracks, is greater than 10% of the wall thickness and the total interacting length of the cracks is equal to or greater than 75% of the critical length of a 50% through-wall flaw that would fail at a stress level of 110% of SMYS.
Specified minimum yield strength means the minimum yield strength, expressed in p.s.i. (kPa) gage, prescribed by the specification under which the material is purchased from the manufacturer.
Stress level means the level of tangential or hoop stress, usually expressed as a percentage of specified minimum yield strength.
Supervisory Control and Data Acquisition (SCADA) system means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility.
Surge pressure means pressure produced by a change in velocity of the moving stream that results from shutting down a pump station or
pumping unit, closure of a valve, or any other blockage of the moving stream.
Toxic product means "poisonous material" as defined by §173.132 Class 6, Division 6.1-Definitions of this chapter.
Unusually Sensitive Area (USA) means a drinking water or ecological resource area that is unusually sensitive to environmental damage from a hazardous liquid pipeline release, as identified under §195.6.
Welder means a person who performs manual or semi-automatic welding.
Welding operator means a person who operates machine or automatic welding equipment.
§195.3 What documents are incorporated by reference partly or wholly in this part?
(a) This part prescribes standards, or portions thereof, incorporated by reference into this part with the approval of the Director of the Federal Register in 5 U.S.C. 552(a) and 1 CFR part 51. The materials listed in this section have the full force of law. To enforce any edition other than that specified in this section, PHMSA must publish a notice of change in the Federal Register. 195.3(a)
(1) Availability of standards incorporated by reference. All of the materials incorporated by reference are available for inspection from several sources, including the following: 195.3(a)(1)
(i) The Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590. For more information contact 202-366-4046 or go to the PHMSA Web site at: http://www.phmsa.dot.gov/pipeline/regs.195.3(a)(1)(i)
(ii) The National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202741-6030 or go to the NARA Web site at: http:// www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.195.3(a)(1)(ii)
(iii) Copies of standards incorporated by reference in this part can also be purchased from the respective standards-developing organization at the addresses provided in the centralized IBR section below.195.3(a)(1)(iii)
(b) American Petroleum Institute (API), 1220 L Street NW., Washington, DC 20005, and phone: 202-682-8000, Web site: http://api.org/. 195.3(b)
(1) API Publication 2026, "Safe Access/Egress Involving Floating Roofs of Storage Tanks in Petroleum Service," 2nd edition, April 1998 (reaffirmed June 2006) (API Pub 2026), IBR approved for §195.405(b). 195.3(b)(1)
(2) API Recommended Practice 5L1, "Recommended Practice for Railroad Transportation of Line Pipe," 7th edition, September 2009, (API RP 5L1), IBR approved for §195.207(a). 195.3(b)(2)
(3) API Recommended Practice 5LT, "Recommended Practice for Truck Transportation of Line Pipe," First edition, March 12, 2012, (API RP 5LT), IBR approved for §195.207(c). 195.3(b)(3)
(4) API Recommended Practice 5LW, "Recommended Practice Transportation of Line Pipe on Barges and Marine Vessels," 3rd edition, September 2009, (API RP 5LW), IBR approved for §195.207(b). 195.3(b)(4)
(5) ANSI/API Recommended Practice 651, "Cathodic Protection of Aboveground Petroleum Storage Tanks," 3rd edition, January 2007, (ANSI/API RP 651), IBR approved for §§195.565 and 195.573(d). 195.3(b)(5)
(6) ANSI/API Recommended Practice 652, "Linings of Aboveground Petroleum Storage Tank Bottoms," 3rd edition, October 2005, (API RP 652), IBR approved for §195.579(d). 195.3(b)(6)
(7) API Recommended Practice 1130, "Computational Pipeline Monitoring for Liquids: Pipeline Segment," 3rd edition, September 2007, (API RP 1130), IBR approved for §§195.134 and 195.444. 195.3(b)(7)
(8) API Recommended Practice 1162, "Public Awareness Programs for Pipeline Operators," 1st edition, December 2003, (API RP 1162), IBR approved for §195.440(a), (b), and (c). 195.3(b)(8)
(9) API Recommended Practice 1165, "Recommended Practice for Pipeline SCADA Displays," First edition, January 2007, (API RP 1165), IBR approved for §195.446(c). 195.3(b)(9)
(10) API Recommended Practice 1168, "Pipeline Control Room Management," First edition, September 2008, (API RP 1168), IBR approved for §195.446(c) and (f). 195.3(b)(10)
(11) API Recommended Practice 2003, "Protection against Ignitions Arising out of Static, Lightning, and Stray Currents," 7th edition, January 2008, (API RP 2003), IBR approved for §195.405(a). 195.3(b)(11)
(12) API Recommended Practice 2350, "Overfill Protection for Storage Tanks in Petroleum Facilities," 3rd edition, January 2005, (API RP 2350), IBR approved for §195.428(c). 195.3(b)(12)
(13) API Specification 5L, "Specification for Line Pipe," 45th edition, effective July 1, 2013, (ANSI/API Spec 5L), IBR approved for §195.106(b) and (e). 195.3(b)(13)
(15) API Specification 12F, "Specification for Shop Welded Tanks for Storage of Production Liquids," 12th edition, October 2008, effective April 1, 2009, (API Spec 12F), IBR approved for §§195.132(b); 195.205(b); 195.264(b) and (e); 195.307(a); 195.565; 195.579(d). 195.3(b)(15)
(16) API Standard 510, "Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration," 9th edition, June 2006, (API Std 510), IBR approved for §§195.205(b); 195.432(c). 195.3(b)(16)
(17) API Standard 620, "Design and Construction of Large, Welded, Low-Pressure Storage Tanks," 11th edition February 2008 (including addendum 1 (March 2009), addendum 2 (August 2010), and addendum 3 (March 2012)), (API Std 620), IBR approved for §§195.132(b); 195.205(b); 195.264(b) and (e); 195.307(b); 195.565, 195.579(d). 195.3(b)(17)
(18) API Standard 650, "Welded Steel Tanks for Oil Storage," 11th edition, June 2007, effective February 1, 2012, (including addendum 1 (November 2008), addendum 2 (November 2009), addendum 3 (August 2011), and errata (October 2011)), (API Std 650), IBR approved for §§195.132(b); 195.205(b); 195.264(b), (e); 195.307(c) and (d); 195.565; 195.579(d). 195.3(b)(18)
(19) API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," 3rd edition, December 2001, (including addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008)), (API Std 653), IBR approved for §§195.205(b), 195.307(d), and 195.432(b). 195.3(b)(19)
(20) API Standard 1104, "Welding of Pipelines and Related Facilities," 20th edition, October 2005, (including errata/addendum (July 2007) and errata 2 (2008), (API Std 1104)), IBR approved for §§195.214(a), 195.222(a) and (b), 195.228(b). 195.3(b)(20)
(21) ANSI/API Standard 2000, "Venting Atmospheric and Low-pressure Storage Tanks," 6th edition, November 2009, (ANSI/API Std 2000), IBR approved for §195.264(e). 195.3(b)(21)
(22) API Standard 2510, "Design and Construction of LPG Installations," 8th edition, 2001, (API Std 2510), IBR approved for §§195.132(b), 195.205(b), 195.264 (b), (e); 195.307 (e), 195.428 (c); and 195.432 (c). 195.3(b)(22)
(23) API Standard 1163, "In-Line Inspection Systems Qualification" Second edition, April 2013, (API Std 1163), IBR approved for §195.591. 195.3(b)(23)
(c) ASME International (ASME), Two Park Avenue, New York, NY 10016, 800-843-2763 (U.S/Canada), Web site: http://www.asme.org/. 195.3(c)
(1) ASME/ANSI B16.9-2007, "Factory-Made Wrought Buttwelding Fittings," December 7, 2007, (ASME/ANSI B16.9), IBR approved for §195.118(a). 195.3(c)(1)
(2) ASME/ANSI B31G-1991 (Reaffirmed 2004), "Manual for Determining the Remaining Strength of Corroded Pipelines," 2004, (ASME/ANSI B31G), IBR approved for §§195.452(h); 195.587; and 195.588(c). 195.3(c)(2)
(3) ASME/ANSI B31.4-2006, "Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids" October 20, 2006, (ASME/ANSI B31.4), IBR approved for §§195.110(a); 195.452(h). 195.3(c)(3)
(4) ASME/ANSI B31.8-2007, "Gas Transmission and Distribution Piping Systems," November 30, 2007, (ASME/ANSI B31.8), IBR approved for §§195.5(a) and 195.406(a). 195.3(c)(4)
(5) ASME Boiler & Pressure Vessel Code, Section VIII, Division 1, "Rules for Construction of Pressure Vessels," 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 1), IBR approved for §§195.124 and 195.307(e). 195.3(c)(5)
(6) ASME Boiler & Pressure Vessel Code, Section VIII, Division 2, "Alternate Rules, Rules for Construction of Pressure Vessels," 2007 edition, July 1, 2007, (ASME BPVC, Section VIII, Division 2), IBR approved for §195.307(e). 195.3(c)(6)
(7) ASME Boiler & Pressure Vessel Code, Section IX: "Qualification Standard for Welding and Brazing Procedures, Welders, Brazers, and Welding and Brazing Operators," 2007 edition, July 1, 2007, (ASME BPVC, Section IX), IBR approved for §195.222(a). 195.3(c)(7)
(d) American Society for Nondestructive Testing, P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228. https://asnt.org. 195.3(d)
(1) ANSI/ASNT ILI-PQ-2005(2010), "In-line Inspection Personnel Qualification and Certification" reapproved October 11, 2010, (ANSI/ASNT ILI-PQ), IBR approved for §195.591. 195.3(d)(1)
(2) [Reserved]195.3(d)(2)
(e) American Society for Testing and Materials (ASTM), 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, PA 119428, phone: 610-832-9585, Web site: http://www.astm.org/. 195.3(e)
(1) ASTM A53/A53M-10, "Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless," approved October 1, 2010, (ASTM A53/A53M), IBR approved for §195.106(e). 195.3(e)(1)
(2) ASTM A106/A106M-10, "Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service," approved April 1, 2010, (ASTM A106/A106M), IBR approved for §195.106(e). 195.3(e)(2)
(3) ASTM A333/A333M-11, "Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service," approved April 1, 2011, (ASTM A333/A333M), IBR approved for §195.106(e). 195.3(e)(3)
(4) ASTM A381-96 (Reapproved 2005), "Standard Specification for Metal-Arc Welded Steel Pipe for Use with High-Pressure Transmission Systems," approved October 1, 2005, (ASTM A381), IBR approved for §195.106(e). 195.3(e)(4)
(5) ASTM A671/A671M-10, "Standard Specification for ElectricFusion-Welded Steel Pipe for Atmospheric and Lower Temperatures," approved April 1, 2010, (ASTM A671/A671M), IBR approved for §195.106(e). 195.3(e)(5)
(6) ASTM A672/A672M-09, "Standard Specification for ElectricFusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures," approved October 1, 2009, (ASTM A672/A672M), IBR approved for §195.106(e). 195.3(e)(6)
(7) ASTM A691/A691M-09, "Standard Specification for Carbon and Alloy Steel Pipe, Electric-Fusion-Welded for High-Pressure Service at High Temperatures," approved October 1, 2009, (ASTM A691), IBR approved for §195.106(e). 195.3(e)(7)
(f) Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park St. NE., Vienna, VA 22180, phone: 703281-6613, Web site: http://www.mss-hq.org/ 195.3(f)
(1) MSS SP-75-2008 Standard Practice, "Specification for High-Test, Wrought, Butt-Welding Fittings," 2008 edition, (MSS SP 75), IBR approved for §195.118(a). 195.3(f)(1)
(2) [Reserved]195.3(f)(2)
(g) NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084, phone: 281-228-6223 or 800-797-6223, Web site: http:// www.nace.org/Publications/. 195.3(g)
(1) NACE SP0169-2007, Standard Practice, "Control of External Corrosion on Underground or Submerged Metallic Piping Systems" reaffirmed March 15, 2007, (NACE SP0169), IBR approved for §§195.571 and 195.573(a). 195.3(g)(1)
(2) ANSI/NACE SP0502-2010, Standard Practice, "Pipeline External Corrosion Direct Assessment Methodology," June 24, 2010, (NACE SP0502), IBR approved for §195.588(b). 195.3(g)(2)
(3) NACE SP0102-2010, "Standard Practice, Inline Inspection of Pipelines" revised March 13, 2010, (NACE SP0102), IBR approved for §195.120 and 195.591. 195.3(g)(3)
(4) NACE SP0204-2008, "Standard Practice, Stress Corrosion Cracking (SSC) Direct Assessment Methodology" reaffirmed September 18, 2008, (NACE SP0204), IBR approved for §195.588(c). 195.3(g)(4)
(h) National Fire Protection Association (NFPA), 1 Batterymarch Park, Quincy, MA 02169, phone: 617-984-7275, Web site: http:// www.nfpa.org/. 195.3(h)
(1) NFPA-30 (2012), "Flammable and Combustible Liquids Code," including Errata 30-12-1 (9/27/11), and Errata 30-12-2 (11/14/11), 2012 edition, copyright 2011, (NFPA-30), IBR approved for §195.264(b). 195.3(h)(1)
(2) [Reserved]195.3(h)(2)
(i) Pipeline Research Council International, Inc. (PRCI), c/o Technical Toolboxes, 3801 Kirby Drive, Suite 520, P.O. Box 980550, Houston, TX 77098, phone: 713-630-0505, toll free: 866-866-6766, Web site: http:// www.ttoolboxes.com/. 195.3(i)
(1) AGA Pipeline Research Committee, Project PR-3-805 "A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe," December 22, 1989, (PR-3-805 (RSTRING)). IBR approved for §§195.452(h); 195.587; and 195.588(c). 195.3(i)(1)
(2) [Reserved]195.3(i)(2)
§195.4 Compatibility necessary for transportation of hazardous liquids or carbon dioxide
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.
§195.5 Conversion to service subject to 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 accomplish the following: 195.5(a)
(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 — 195.5(a)(1)
(i) Testing the pipeline in accordance with ASME/ANSI B31.8 (incorporated by reference, see §195.3), Appendix N, to produce a stress equal to the yield strength; and195.5(a)(1)(i)
(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).195.5(a)(1)(ii)
(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. 195.5(a)(2)
(3) All known unsafe defects and conditions must be corrected in accordance with this part. 195.5(a)(3)
(4) The pipeline must be tested in accordance with subpart E of this part to substantiate the maximum operating pressure permitted by §195.406. 195.5(a)(4)
(b) A pipeline that qualifies for use under this section need not comply with the corrosion control requirements of subpart H of this part until 12 months after it is placed into service, notwithstanding any previous deadlines for compliance. 195.5(b)
(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. 195.5(c)
(d) An operator converting a pipeline from service not previously covered by this part must notify PHMSA 60 days before the conversion occurs as required by §195.64. 195.5(d)
§195.6 Unusually Sensitive Areas
As used in this part, a USA means a drinking water or ecological resource area that is unusually sensitive to environmental damage from a hazardous liquid pipeline release.
(a) An USA drinking water resource is: 195.6(a)
(1) The water intake for a Community Water System (CWS) or a Nontransient Non-community Water System (NTNCWS) that obtains its water supply primarily from a surface water source and does not have an adequate alternative drinking water source; 195.6(a)(1)
(2) The Source Water Protection Area (SWPA) for a CWS or a NTNCWS that obtains its water supply from a Class I or Class IIA aquifer and does not have an adequate alternative drinking water source. Where a state has not yet identified the SWPA, the Wellhead Protection Area (WHPA) will be used until the state has identified the SWPA; or 195.6(a)(2)
(3) The sole source aquifer recharge area where the sole source aquifer is a karst aquifer in nature. 195.6(a)(3)
(b) An USA ecological resource is: 195.6(b)
(1) An area containing a critically imperiled species or ecological community; 195.6(b)(1)
(2) A multi-species assemblage area;195.6(b)(2)
(3) A migratory waterbird concentration area;195.6(b)(3)
(4) An area containing an imperiled species, threatened or endangered species, depleted marine mammal species, or an imperiled ecological community where the species or community is aquatic, aquatic dependent, or terrestrial with a limited range; 195.6(b)(4)
(5) An area containing an imperiled species, threatened or endangered species, depleted marine mammal species, or imperiled ecological community where the species or community occurrence is considered to be one of the most viable, highest quality, or in the best condition, as identified by an element occurrence ranking (EORANK) of A (excellent quality) or B (good quality); or 195.6(b)(5)
(6) A coastal beach; or195.6(b)(6)
(7) Certain coastal waters.195.6(b)(7)
(c) Definitions used in this part — 195.6(c)
Adequate Alternative Drinking Water Source means a source of water that currently exists, can be used almost immediately with a minimal amount of effort and cost, involves no decline in water quality, and will meet the consumptive, hygiene, and fire fighting requirements of the existing population of impacted customers for at least one month for a surface water source of water and at least six months for a groundwater source.
Aquatic or Aquatic Dependent Species or Community means a species or community that primarily occurs in aquatic, marine, or wetland habitats, as well as species that may use terrestrial habitats during all or some portion of their life cycle, but that are still closely associated with or dependent upon aquatic, marine, or wetland habitats for some critical component or portion of their life-history (i.e., reproduction, rearing and development, feeding, etc).
Certain coastal waters means the territorial sea of the United States; the Great Lakes and their connecting waters; and the marine and estuarine waters of the United States up to the head of tidal influence.
Class I Aquifer means an aquifer that is surficial or shallow, permeable, and is highly vulnerable to contamination. Class I aquifers include:
(1) Unconsolidated Aquifers (Class Ia) that consist of surficial, unconsolidated, and permeable alluvial, terrace, outwash, beach, dune and other similar deposits. These aquifers generally contain layers of sand and gravel that, commonly, are interbedded to some degree with silt and clay. Not all Class Ia aquifers are important water-bearing units, but they are likely to be both permeable and vulnerable. The only natural protection of these aquifers is the thickness of the unsaturated zone and the presence of fine-grained material;
(2) Soluble and Fractured Bedrock Aquifers (Class Ib). Lithologies in this class include limestone, dolomite, and, locally, evaporitic units that contain documented karst features or solution channels, regardless of size. Generally these aquifers have a wide range of permeability. Also included in this class are sedimentary strata, and metamorphic and igneous (intrusive and extrusive) rocks that are significantly faulted, fractured, or jointed. In all cases groundwater movement is largely controlled by secondary openings. Well yields range widely, but the important feature is the potential for rapid vertical and lateral ground water movement along preferred pathways, which result in a high degree of vulnerability;
(3) Semiconsolidated Aquifers (Class Ic) that generally contain poorly to moderately indurated sand and gravel that is interbedded with clay and silt. This group is intermediate to the unconsolidated and consolidated end members. These systems are common in the Tertiary age rocks that are exposed throughout the Gulf and Atlantic coastal states. Semiconsolidated conditions also arise from the presence of intercalated clay and caliche within primarily unconsolidated to poorly consolidated units, such as occurs in parts of the High Plains Aquifer; or
(4) Covered Aquifers (Class Id) that are any Class I aquifer overlain by less than 50 feet of low permeability, unconsolidated material, such as glacial till, lacustrian, and loess deposits.
Class IIa aquifer means a Higher Yield Bedrock Aquifer that is consolidated and is moderately vulnerable to contamination. These aquifers generally consist of fairly permeable sandstone or conglomerate that contain lesser amounts of interbedded fine grained clastics (shale, siltstone, mudstone) and occasionally carbonate units. In general, well yields must exceed 50 gallons per minute to be included in this class. Local fracturing may contribute to the dominant primary porosity and permeability of these systems.
Community Water System (CWS) means a public water system that serves at least 15 service connections used by year-round residents of the area or regularly serves at least 25 year-round residents.
Coastal beach means any land between the high- and low-water marks of certain coastal waters.
Critically imperiled species or ecological community (habitat) means an animal or plant species or an ecological community of extreme rarity, based on The Nature Conservancy's Global Conservation Status Rank. There are generally 5 or fewer occurrences, or very few remaining individuals (less than 1,000) or acres (less than 2,000). These species and ecological communities are extremely vulnerable to extinction due to some natural or man-made factor.
Depleted marine mammal species means a species that has been identified and is protected under the Marine Mammal Protection Act of 1972, as amended (MMPA) (16 U.S.C. 1361 et seq.). The term "depleted" refers to marine mammal species that are listed as threatened or endangered, or are below their optimum sustainable populations (16 U.S.C. 1362). The term "marine mammal" means "any mammal which is morphologically adapted to the marine environment (including sea otters and members of the orders Sirenia, Pinnipedia, and Cetacea), or primarily inhabits the marine environment (such as the polar bear)" (16 U.S.C. 1362). The order Sirenia includes manatees, the order Pinnipedia includes seals, sea lions,
and walruses, and the order Cetacea includes dolphins, porpoises, and whales.
Ecological community means an interacting assemblage of plants and animals that recur under similar environmental conditions across the landscape.
Element occurrence rank (EORANK) means the condition or viability of a species or ecological community occurrence, based on a population's size, condition, and landscape context. EORANKs are assigned by the Natural Heritage Programs. An EORANK of A means an excellent quality and an EORANK of B means good quality.
Imperiled species or ecological community (habitat) means a rare species or ecological community, based on The Nature Conservancy's Global Conservation Status Rank. There are generally 6 to 20 occurrences, or few remaining individuals (1,000 to 3,000) or acres (2,000 to 10,000). These species and ecological communities are vulnerable to extinction due to some natural or man-made factor.
Karst aquifer means an aquifer that is composed of limestone or dolomite where the porosity is derived from connected solution cavities. Karst aquifers are often cavernous with high rates of flow.
Migratory waterbird concentration area means a designated Ramsar site or a Western Hemisphere Shorebird Reserve Network site.
Multi-species assemblage area means an area where three or more different critically imperiled or imperiled species or ecological communities, threatened or endangered species, depleted marine mammals, or migratory waterbird concentrations co-occur.
Non-transient Non-community Water System (NTNCWS) means a public water system that regularly serves at least 25 of the same persons over six months per year. Examples of these systems include schools, factories, and hospitals that have their own water supplies.
Public Water System (PWS) means a system that provides the public water for human consumption through pipes or other constructed conveyances, if such system has at least 15 service connections or regularly serves an average of at least 25 individuals daily at least 60 days out of the year. These systems include the sources of the water supplies — i.e., surface or ground. PWS can be community, non-transient non-community, or transient non-community systems.
Ramsar site means a site that has been designated under The Convention on Wetlands of International Importance Especially as Waterfowl Habitat program. Ramsar sites are globally critical wetland areas that support migratory waterfowl. These include wetland areas that regularly support 20,000 waterfowl; wetland areas that regularly support substantial numbers of individuals from particular groups of waterfowl, indicative of wetland values, productivity, or diversity; and wetland areas that regularly support 1% of the individuals in a population of one species or subspecies of waterfowl.
Sole source aquifer (SSA) means an area designated by the U.S. Environmental Protection Agency under the Sole Source Aquifer program as the "sole or principal" source of drinking water for an area. Such designations are made if the aquifer's ground water supplies 50% or more of the drinking water for an area, and if that aquifer were to become contaminated, it would pose a public health hazard. A sole source aquifer that is karst in nature is one composed of limestone where the porosity is derived from connected solution cavities. They are often cavernous, with high rates of flow.
Source Water Protection Area (SWPA) means the area delineated by the state for a public water supply system (PWS) or including numerous PWSs, whether the source is ground water or surface water or both, as part of the state source water assessment program (SWAP) approved by EPA under section 1453 of the Safe Drinking Water Act.
Species means species, subspecies, population stocks, or distinct vertebrate populations.
Terrestrial ecological community with a limited range means a non-aquatic or non-aquatic dependent ecological community that covers less than five (5) acres.
Terrestrial species with a limited range means a non-aquatic or non-aquatic dependent animal or plant species that has a range of no more than five (5) acres.
Threatened and endangered species (T&E) means an animal or plant species that has been listed and is protected under the Endangered Species Act of 1973, as amended (ESA73) (16 U.S.C. 1531 et seq.). "Endangered species" is defined as "any species which is in danger of extinction throughout all or a significant portion of its range" (16 U.S.C. 1532). "Threatened species" is defined as "any species which is likely to become an endangered species within the foreseeable future throughout all or a significant portion of its range" (16 U.S.C. 1532).
Transient Non-community Water System (TNCWS) means a public water system that does not regularly serve at least 25 of the same persons over six months per year. This type of water system serves a transient population found at rest stops, campgrounds, restaurants, and parks with their own source of water.
Wellhead Protection Area (WHPA) means the surface and subsurface area surrounding a well or well field that supplies a public water
system through which contaminants are likely to pass and eventually reach the water well or well field.
Western Hemisphere Shorebird Reserve Network (WHSRN) site means an area that contains migratory shorebird concentrations and has been designated as a hemispheric reserve, international reserve, regional reserve, or endangered species reserve. Hemispheric reserves host at least 500,000 shorebirds annually or 30% of a species flyway population. International reserves host 100,000 shorebirds annually or 15% of a species flyway population. Regional reserves host 20,000 shorebirds annually or 5% of a species flyway population. Endangered species reserves are critical to the survival of endangered species and no minimum number of birds is required.
§195.8 Transportation of hazardous liquid or carbon dioxide in pipelines constructed with other than steel pipe
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.
§195.9 Outer continental shelf pipelines
Operators of transportation pipelines on the Outer Continental Shelf must identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 1998 to identify the transfer points. If it is not practicable to durably mark a transfer point and the transfer point is located above water, the operator must depict the transfer point on a schematic maintained near the transfer point. If a transfer point is located subsea, the operator must identify the transfer point on a schematic which must be maintained at the nearest upstream facility and provided to PHMSA upon request. For those cases in which adjoining operators have not agreed on a transfer point by September 15, 1998 the Regional Director and the MMS Regional Supervisor will make a joint determination of the transfer point.
§195.10 Responsibility of operator for compliance with this part
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.
§195.11
What is a regulated rural gathering line and what requirements apply?
Each operator of a regulated rural gathering line, as defined in paragraph (a) of this section, must comply with the safety requirements described in paragraph (b) of this section.
(a) Definition. As used in this section, a regulated rural gathering line means an onshore gathering line in a rural area that meets all of the following criteria — 195.11(a)
(1) Has a nominal diameter from 65⁄8 inches (168 mm) to 85⁄8 inches (219.1 mm); 195.11(a)(1)
(2) Is located in or within one-quarter mile (.40 km) of an unusually sensitive area as defined in §195.6; and 195.11(a)(2)
(3) Operates at a maximum pressure established under §195.406 corresponding to — 195.11(a)(3)
(i) A stress level greater than 20-percent of the specified minimum yield strength of the line pipe; or195.11(a)(3)(i)
(ii) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure of more than 125 psi (861 kPa) gage. 195.11(a)(3)(ii)
(b) Safety requirements. Each operator must prepare, follow, and maintain written procedures to carry out the requirements of this section. Except for the requirements in paragraphs (b)(2), (b)(3), (b)(9) and (b)(10) of this section, the safety requirements apply to all materials of construction. 195.11(b)
(1) Identify all segments of pipeline meeting the criteria in paragraph (a) of this section before April 3, 2009. 195.11(b)(1)
(2) For steel pipelines contracted, replaced, relocated, or otherwise changed after July 3, 2009: 195.11(b)(2)
(i) Design, install, construct, initially inspect, and initially test the pipeline in compliance with this part, unless the pipeline is converted under §195.5.195.11(b)(2)(i)
(ii) Except for pipelines subject to §195.260(e), such pipelines are not subject to the rupture-mitigation valve (RMV) and alternative equivalent technology requirements in §§195.258(c) and (d), 195.418, and 195.419.195.11(b)(2)(ii)
(3) For non-steel pipelines constructed after July 3, 2009, notify the Administrator according to §195.8. 195.11(b)(3)
(4) Beginning no later than January 3, 2009, comply with the reporting requirements in subpart B of this part. 195.11(b)(4)
(5) Establish the maximum operating pressure of the pipeline according to §195.406 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. 195.11(b)(5)
(6) Install line markers according to §195.410 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. Continue to maintain line markers in compliance with §195.410. 195.11(b)(6)
(7) Establish a continuing public education program in compliance with §195.440 before transportation begins, or if the pipeline exists on July 3, 2008, before January 3, 2010. Continue to carry out such program in compliance with §195.440. 195.11(b)(7)
(8) Establish a damage prevention program in compliance with §195.442 before transportation begins, or if the pipeline exists on July 3, 2008, before July 3, 2009. Continue to carry out such program in compliance with §195.442. 195.11(b)(8)
(9) For steel pipelines, comply with subpart H of this part, except corrosion control is not required for pipelines existing on July 3, 2008 before July 3, 2011. 195.11(b)(9)
(10) For steel pipelines, establish and follow a comprehensive and effective program to continuously identify operating conditions that could contribute to internal corrosion. The program must include measures to prevent and mitigate internal corrosion, such as cleaning the pipeline and using inhibitors. This program must be established before transportation begins or if the pipeline exists on July 3, 2008, before July 3, 2009. 195.11(b)(10)
(11) To comply with the Operator Qualification program requirements in subpart G of this part, have a written description of the processes used to carry out the requirements in §195.505 to determine the qualification of persons performing operations and maintenance tasks. These processes must be established before transportation begins or if the pipeline exists on July 3, 2008, before July 3, 2009. 195.11(b)(11)
(c) New unusually sensitive areas. If, after July 3, 2008, a new unusually sensitive area is identified and a segment of pipeline becomes regulated as a result, except for the requirements of paragraphs (b)(9) and (b)(10) of this section, the operator must implement the requirements in paragraphs (b)(2) through (b)(11) of this section for the affected segment within 6 months of identification. For steel pipelines, comply with the deadlines in paragraph (b)(9) and (b)(10). 195.11(c)
(d) Record Retention. An operator must maintain records demonstrating compliance with each requirement according to the following schedule. 195.11(d)
(1) An operator must maintain the segment identification records required in paragraph (b)(1) of this section and the records required to comply with (b)(10) of this section, for the life of the pipe. 195.11(d)(1)
(2) An operator must maintain the records necessary to demonstrate compliance with each requirement in paragraphs (b)(2) through (b)(9), and (b)(11) of this section according to the record retention requirements of the referenced section or subpart. 195.11(d)(2)
§195.12 What requirements apply to low-stress pipelines in rural areas?
(a) General. This Section sets forth the requirements for each category of low-stress pipeline in a rural area set forth in paragraph (b) of this Section. This Section does not apply to a rural low-stress pipeline regulated under this Part as a low-stress pipeline that crosses a waterway currently used for commercial navigation; these pipelines are regulated pursuant to §195.1(a)(2). 195.12.(a)
(b) Categories. An operator of a rural low-stress pipeline must meet the applicable requirements and compliance deadlines for the category of pipeline set forth in paragraph (c) of this Section. For purposes of this Section, a rural low-stress pipeline is a Category 1, 2, or 3 pipeline based on the following criteria: 195.12.(b)
(1) A Category 1 rural low-stress pipeline: 195.12.(b)(1)
(i) Has a nominal diameter of 85⁄8 inches (219.1 mm) or more; 195.12.(b)(1)(i)
(ii) Is located in or within one-half mile (.80 km) of an unusually sensitive area (USA) as defined in §195.6; and195.12.(b)(1)(ii)
(iii) Operates at a maximum pressure established under §195.406 corresponding to:195.12.(b)(1)(iii)
[A] A stress level equal to or less than 20-percent of the specified minimum yield strength of the line pipe; or 195.12.(b)(1)(iii)[A]
[B] If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure equal to or less than 125 psi (861 kPa) gauge.195.12.(b)(1)(iii)[B]
(2) A Category 2 rural pipeline:195.12.(b)(2)
(i) Has a nominal diameter of less than 85⁄8 inches (219.1mm); 195.12.(b)(2)(i)
(ii) Is located in or within one-half mile (.80 km) of an unusually sensitive area (USA) as defined in §195.6; and195.12.(b)(2)(ii)
(iii) Operates at a maximum pressure established under §195.406 corresponding to:195.12.(b)(2)(iii)
[A] A stress level equal to or less than 20-percent of the specified minimum yield strength of the line pipe; or 195.12.(b)(2)(iii)[A]
[B] If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure equal to or less than 125 psi (861 kPa) gage.195.12.(b)(2)(iii)[B]
(3) A Category 3 rural low-stress pipeline: 195.12.(b)(3)
(i) Has a nominal diameter of any size and is not located in or within one-half mile (.80 km) of an unusually sensitive area (USA) as defined in §195.6; and195.12.(b)(3)(i)
(ii) Operates at a maximum pressure established under §195.406 corresponding to a stress level equal to or less than 20-percent of the specified minimum yield strength of the line pipe; or 195.12.(b)(3)(ii)
(iii) If the stress level is unknown or the pipeline is not constructed with steel pipe, a pressure equal to or less than 125 psi (861 kPa) gage.195.12.(b)(3)(iii)
(c) Applicable requirements and deadlines for compliance. An operator must comply with the following compliance dates depending on the category of pipeline determined by the criteria in paragraph (b): 195.12.(c)
(1) An operator of a Category 1 pipeline must:195.12.(c)(1)
(i) Identify all segments of pipeline meeting the criteria in paragraph (b)(1) of this Section before April 3, 2009.195.12.(c)(1)(i)
(ii) Beginning no later than January 3, 2009, comply with the reporting requirements of Subpart B for the identified segments. 195.12.(c)(1)(ii)
(iii) IM requirements — 195.12.(c)(1)(iii)
[A] Establish a written program that complies with §195.452 before July 3, 2009, to assure the integrity of the pipeline segments. Continue to carry out such program in compliance with §195.452.195.12.(c)(1)(iii)[A]
[B] An operator may conduct a determination per §195.452(a) in lieu of the one-half mile buffer.195.12.(c)(1)(iii)[B]
[C] Complete the baseline assessment of all segments in accordance with §195.452(c) before July 3, 2015, and complete at least 50-percent of the assessments, beginning with the highest risk pipe, before January 3, 2012.195.12.(c)(1)(iii)[C]
(iv) Comply with all other safety requirements of this Part, except Subpart H, before July 3, 2009. Comply with the requirements of Subpart H before July 3, 2011.195.12.(c)(1)(iv)
(2) An operator of a Category 2 pipeline must:195.12.(c)(2)
(i) Identify all segments of pipeline meeting the criteria in paragraph (b)(2) of this Section before July 1, 2012.195.12.(c)(2)(i)
(ii) Beginning no later than January 3, 2009, comply with the reporting requirements of Subpart B for the identified segments. 195.12.(c)(2)(ii)
(iii) IM — 195.12.(c)(2)(iii)
[A] Establish a written IM program that complies with §195.452 before October 1, 2012 to assure the integrity of the pipeline segments. Continue to carry out such program in compliance with §195.452.195.12.(c)(2)(iii)[A]
[B] An operator may conduct a determination per §195.452(a) in lieu of the one-half mile buffer.195.12.(c)(2)(iii)[B]
[C] Complete the baseline assessment of all segments in accordance with §195.452(c) before October 1, 2016 and complete at least 50-percent of the assessments, beginning with the highest risk pipe, before April 1, 2014.195.12.(c)(2)(iii)[C]
(iv) Comply with all other safety requirements of this Part, except Subpart H, before October 1, 2012. Comply with Subpart H of this Part before October 1, 2014.195.12.(c)(2)(iv)
(3) An operator of a Category 3 pipeline must:195.12.(c)(3)
(i) Identify all segments of pipeline meeting the criteria in paragraph (b)(3) of this Section before July 1, 2012.195.12.(c)(3)(i)
(ii) Beginning no later than January 3, 2009, comply with the reporting requirements of Subpart B for the identified segments. 195.12.(c)(3)(ii)
§195.49 Part 195 – Transportation of
[A] (iii) Comply with all safety requirements of this Part, except the requirements in §195.452, Subpart B, and the requirements in Subpart H, before October 1, 2012. Comply with Subpart H of this Part before October 1, 2014.195.12.(c)(3)[A](iii)
Editor's Note: The CFR displays paragraph 195.12(c)(3)(A)(iii). This numbering scheme does not conform with paragraphs (i) and (ii) of regulation 195.12(c)(3).
(d) Economic compliance burden. 195.12.(d)
(1) An operator may notify PHMSA in accordance with §195.452(m) of a situation meeting the following criteria: 195.12.(d)(1)
(i) The pipeline is a Category 1 rural low-stress pipeline; 195.12.(d)(1)(i)
(ii) The pipeline carries crude oil from a production facility; 195.12.(d)(1)(ii)
(iii) The pipeline, when in operation, operates at a flow rate less than or equal to 14,000 barrels per day; and195.12.(d)(1)(iii)
(iv) The operator determines it would abandon or shut-down the pipeline as a result of the economic burden to comply with the assessment requirements in §195.452(d) or 195.452(j). 195.12.(d)(1)(iv)
(2) A notification submitted under this provision must include, at minimum, the following information about the pipeline: its operating, maintenance and leak history; the estimated cost to comply with the integrity assessment requirements (with a brief description of the basis for the estimate); the estimated amount of production from affected wells per year, whether wells will be shut in or alternate transportation used, and if alternate transportation will be used, the estimated cost to do so. 195.12.(d)(2)
(3) When an operator notifies PHMSA in accordance with paragraph (d)(1) of this Section, PHMSA will stay compliance with §§195.452(d) and 195.452(j)(3) until it has completed an analysis of the notification. PHMSA will consult the Department of Energy, as appropriate, to help analyze the potential energy impact of loss of the pipeline. Based on the analysis, PHMSA may grant the operator a special permit to allow continued operation of the pipeline subject to alternative safety requirements. 195.12.(d)(3)
(e) Changes in unusually sensitive areas. 195.12.(e)
(1) If, after June 3, 2008, for Category 1 rural low-stress pipelines or October 1, 2011 for Category 2 rural low-stress pipelines, an operator identifies a new USA that causes a segment of pipeline to meet the criteria in paragraph (b) of this Section as a Category 1 or Category 2 rural low-stress pipeline, the operator must: 195.12.(e)(1)
(i) Comply with the IM program requirement in paragraph (c)(1)(iii)(A) or (c)(2)(iii)(A) of this Section, as appropriate, within 12 months following the date the area is identified regardless of the prior categorization of the pipeline; and195.12.(e)(1)(i)
(ii) Complete the baseline assessment required by paragraph (c)(1)(iii)(C) or (c)(2)(iii)(C) of this Section, as appropriate, according to the schedule in §195.452(d)(3).195.12.(e)(1)(ii)
(2) If a change to the boundaries of a USA causes a Category 1 or Category 2 pipeline segment to no longer be within one-half mile of a USA, an operator must continue to comply with paragraph (c)(1)(iii) or paragraph (c)(2)(iii) of this section, as applicable, with respect to that segment unless the operator determines that a release from the pipeline could not affect the USA. 195.12.(e)(2)
(f) Record Retention. An operator must maintain records demonstrating compliance with each requirement applicable to the category of pipeline according to the following schedule. 195.12.(f)
(1) An operator must maintain the segment identification records required in paragraph (c)(1)(i), (c)(2)(i) or (c)(3)(i) of this Section for the life of the pipe. 195.12.(f)(1)
(2) Except for the segment identification records, an operator must maintain the records necessary to demonstrate compliance with each applicable requirement set forth in paragraph (c) of this section according to the record retention requirements of the referenced section or subpart. 195.12.(f)(2)
§195.13 What requirements apply to pipelines transporting hazardous liquids by gravity?
(a) Scope. Pipelines transporting hazardous liquids by gravity must comply with the reporting requirements of subpart B of this part. 195.13(a)
(b) Implementation period 195.13(b)
(1) Annual reporting. Comply with the annual reporting requirements in subpart B of this part by March 31, 2021. 195.13(b)(1)
(2) Accident and safety-related reporting. Comply with the accident and safety-related condition reporting requirements in subpart B of this part by January 1, 2021. 195.13(b)(2)
(c) Exceptions. 195.13(c)
(1) This section does not apply to the transportation of a hazardous liquid in a gravity line that meets the definition of a low-stress pipeline, travels no farther than 1 mile from a facility boundary, and does not cross any waterways used for commercial navigation. 195.13(c)(1)
(2) The reporting requirements in §§195.52, 195.61, and 195.65 do not apply to the transportation of a hazardous liquid in a gravity line. 195.13(c)(2)
(3) The drug and alcohol testing requirements in part 199 of this subchapter do not apply to the transportation of a hazardous liquid in a gravity line. 195.13(c)(3)
§195.15 What requirements apply to reportingregulated-only gathering lines?
(a) Scope. Gathering lines that do not otherwise meet the definition of a regulated rural gathering line in §195.11 and any gathering line not already covered under §195.1(a)(1), (2), (3) or (4) must comply with the reporting requirements of subpart B of this part. 195.15(a)
(b) Implementation period 195.15(b)
(1) Annual reporting. Operators must comply with the annual reporting requirements in subpart B of this part by March 31, 2021. 195.15(b)(1)
(2) Accident and safety-related condition reporting. Operators must comply with the accident and safety-related condition reporting requirements in subpart B of this part by January 1, 2021. 195.15(b)(2)
(c) Exceptions. 195.15(c)
(1) This section does not apply to those gathering lines that are otherwise excepted under §195.1(b)(3), (7), (8), (9), or (10). 195.15(c)(1)
(2) The reporting requirements in §§195.52, 195.61, and 195.65 do not apply to the transportation of a hazardous liquid in a gathering line that is specified in paragraph (a) of this section. 195.15(c)(2)
(3) The drug and alcohol testing requirements in part 199 of this subchapter do not apply to the transportation of a hazardous liquid in a gathering line that is specified in paragraph (a) of this section. 195.15(c)(3)
§195.18
How to notify PHMSA
(a) An operator must provide any notification required by this part by: 195.18(a)
(1) Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or 195.18(a)(1)
(2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE, Washington, DC 20590. 195.18(a)(2)
(b) An operator must also notify the appropriate State or local pipeline safety authority when an applicable pipeline segment is located in a State where OPS has an interstate agent agreement, or an intrastate pipeline segment is regulated by that State. 195.18(b)
(c) Unless otherwise specified, if an operator submits, pursuant to §195.258, §195.260, §195.418, §195.419, §195.420 or §195.452 a notification requesting use of a different integrity assessment method, analytical method, sampling approach, compliance timeline, or technique (e.g., “other technology” or “alternative equivalent technology”) than otherwise prescribed in those sections, that notification must be submitted to PHMSA for review at least 90 days in advance of using that other method, approach, compliance timeline, or technique. An operator may proceed to use the other method, approach, compliance timeline, or technique 91 days after submittal of the notification unless it receives a letter from the Associate Administrator of Pipeline Safety informing the operator that PHMSA objects to the proposal, or that PHMSA requires additional time and/or information to conduct its review. 195.18(c)
Subpart B – Annual, Accident, and SafetyRelated Condition Reporting
§195.48
Scope
This Subpart prescribes requirements for periodic reporting and for reporting of accidents and safety-related conditions. This Subpart applies to all pipelines subject to this Part. An operator of a Category 3 rural lowstress pipeline meeting the criteria in §195.12 is not required to complete those parts of the hazardous liquid annual report form PHMSA F 70001.1 associated with IM or high consequence areas.
§195.49
Annual report
Each operator must annually complete and submit DOT Form PHMSA F 7000-1.1 for each type of hazardous liquid pipeline facility operated at the end of the previous year. An operator must submit the annual report by June 15 each year, except that for the 2010 reporting year the report must be submitted by August 15, 2011. A separate report is required for crude oil, HVL (including anhydrous ammonia), petroleum products, car-
bon dioxide pipelines, and fuel grade ethanol pipelines. For each state a pipeline traverses, an operator must separately complete those sections on the form requiring information to be reported for each state.
§195.50 Reporting accidents
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. 195.50(a)
(b) Release of 5 gallons (19 liters) or more of hazardous liquid or carbon dioxide, except that no report is required for a release of less than 5 barrels (0.8 cubic meters) resulting from a pipeline maintenance activity if the release is: 195.50(b)
(1) Not otherwise reportable under this section;195.50(b)(1)
(2) Not one described in §195.52(a)(4);195.50(b)(2)
(3) Confined to company property or pipeline right-of-way; and 195.50(b)(3)
(4) Cleaned up promptly;195.50(b)(4)
(c) Death of any person; 195.50(c)
(d) Personal injury necessitating hospitalization; 195.50(d)
(e) Estimated property damage, including cost of clean-up and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding $50,000. 195.50(e)
§195.52 Immediate notice of certain accidents
(a) Notice requirements. 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, but no later than one hour after confirmed discovery, the operator of the system must give notice, in accordance with paragraph (b) of this section of any failure that: 195.52(a)
(1) Caused a death or a personal injury requiring hospitalization; 195.52(a)(1)
(2) Resulted in either a fire or explosion not intentionally set by the operator; 195.52(a)(2)
(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; 195.52(a)(3)
(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 195.52(a)(4)
(5) In the judgment of the operator was significant even though it did not meet the criteria of any other paragraph of this section. 195.52(a)(5)
(b) Information required. Each notice required by paragraph (a) of this section must be made to the National Response Center either by telephone to 800-424-8802 (in Washington, DC, 202-267-2675) or electronically at http://www.nrc.uscg.mil and must include the following information: 195.52(b)
(1) Name, address and identification number of the operator. 195.52(b)(1)
(2) Name and telephone number of the reporter. 195.52(b)(2)
(3) The location of the failure.195.52(b)(3)
(4) The time of the failure.195.52(b)(4)
(5) The fatalities and personal injuries, if any.195.52(b)(5)
(6) Initial estimate of amount of product released in accordance with paragraph (c) of this section. 195.52(b)(6)
(7) All other significant facts known by the operator that are relevant to the cause of the failure or extent of the damages. 195.52(b)(7)
(c) Calculation. A pipeline operator must have a written procedure to calculate and provide a reasonable initial estimate of the amount of released product. 195.52(c)
(d) New information. Within 48 hours after the confirmed discovery of an accident, to the extent practicable, an operator must revise or confirm its initial telephonic notice required in paragraph (b) of this section with a revised estimate of the amount of product released, location of the failure, time of the failure, a revised estimate of the number of fatalities and injuries, and all other significant facts that are known by the operator that are relevant to the cause of the accident or extent of the damages. If there are no changes or revisions to the initial report, the operator must confirm the estimates in its initial report. 195.52(d)
§195.54 Accident reports
(a) Each operator that experiences an accident that is required to be reported under §195.50 must, as soon as practicable, but not later than 30 days after discovery of the accident, file an accident report on DOT Form 7000-1. 195.54(a)
(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. 195.54(b)
§195.55
Reporting safety-related conditions
(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: 195.55(a)
(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. 195.55(a)(1)
(2) Unintended movement or abnormal loading of a pipeline by environmental causes, such as an earthquake, landslide, or flood, that impairs its serviceability. 195.55(a)(2)
(3) Any material defect or physical damage that impairs the serviceability of a pipeline. 195.55(a)(3)
(4) Any malfunction or operating error that causes the pressure of a pipeline to rise above 110 percent of its maximum operating pressure. 195.55(a)(4)
(5) A leak in a pipeline that constitutes an emergency.195.55(a)(5)
(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. 195.55(a)(6)
(b) A report is not required for any safety-related condition that — 195.55(b)
(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; 195.55(b)(1)
(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 safetyrelated condition report; or 195.55(b)(2)
(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. 195.55(b)(3)
§195.56 Filing safety-related condition
reports
(a) Each report of a safety-related condition under §195.55(a) must be filed (received by OPS) 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 electronic mail to InformationResourcesManager@dot.gov, or by facsimile at (202) 366-7128. 195.56(a)
(b) The report must be headed "Safety-Related Condition Report" and provide the following information: 195.56(b)
(1) Name and principal address of operator.195.56(b)(1)
(2) Date of report.195.56(b)(2)
(3) Name, job title, and business telephone number of person submitting the report. 195.56(b)(3)
(4) Name, job title, and business telephone number of person who determined that the condition exists. 195.56(b)(4)
(5) Date condition was discovered and date condition was first determined to exist. 195.56(b)(5)
(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. 195.56(b)(6)
(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. 195.56(b)(7)
(8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted and the planned followup or future corrective action, including the anticipated schedule for starting and concluding such action. 195.56(b)(8)
§195.58 Report submission requirements
(a) General. Except as provided in paragraphs (b) and (e) of this section, an operator must submit each report required by this part electronically to PHMSA at http://opsweb.phmsa.dot.gov unless an alternative reporting method is authorized in accordance with paragraph (d) of this section. 195.58(a)
(b) Exceptions: An operator is not required to submit a safety-related condition report §195.56) electronically. 195.58(b)
(c) Safety-related conditions. An operator must submit concurrently to the applicable State agency a safety-related condition report required by §195.55 for an intrastate pipeline or when the State agency acts as an agent of the Secretary with respect to interstate pipelines. 195.58(c)
(d) Alternate Reporting Method. If electronic reporting imposes an undue burden and hardship, the operator may submit a written request for an alternative reporting method to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, PHP-20, 1200 New Jersey Avenue, SE., Washington DC 20590. The request must describe the undue burden and hardship. PHMSA will review the request and may authorize, in writing, an alternative reporting method. An authorization will state the period for which it is valid, which may be indefinite. An operator must contact PHMSA at 202-366-8075, or electronically to "informationresourcesmanager@dot.gov" to make arrangements for submitting a report that is due after a request for alternative reporting is submitted but before an authorization or denial is received. 195.58(d)
(e) National Pipeline Mapping System (NPMS). An operator must provide NPMS data to the address identified in the NPMS Operator Standards Manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 3664595. 195.58(e)
§195.59 Abandonment or deactivation of facilities
For each abandoned offshore pipeline facility or each abandoned onshore pipeline facility that crosses over, under or through a commercially navigable waterway, the last operator of that facility must file a report upon abandonment of that facility.
(a) The preferred method to submit data on pipeline facilities abandoned after October 10, 2000 is to the National Pipeline Mapping System (NPMS) in accordance with the NPMS "Standards for Pipeline and Liquefied Natural Gas Operator Submissions." To obtain a copy of the NPMS Standards, please refer to the NPMS homepage at http:// www.npms.phmsa.dot.gov or contact the NPMS National Repository at 703-317-3073. A digital data format is preferred, but hard copy submissions are acceptable if they comply with the NPMS Standards. In addition to the NPMS-required attributes, operators must submit the date of abandonment, diameter, method of abandonment, and certification that, to the best of the operator's knowledge, all of the reasonably available information requested was provided and, to the best of the operator's knowledge, the abandonment was completed in accordance with applicable laws. Refer to the NPMS Standards for details in preparing your data for submission. The NPMS Standards also include details of how to submit data. Alternatively, operators may submit reports by mail, fax or e-mail to the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001; fax (202) 366-4566; email, "InformationResourcesManager@phmsa.dot.gov. The information in the report must contain all reasonably available information related to the facility, including information in the possession of a third party. The report must contain the location, size, date, method of abandonment, and a certification that the facility has been abandoned in accordance with all applicable laws. 195.59(a)
(b) [Reserved] 195.59(b)
§195.60 Operator assistance in investigation
If the Department of Transportation investigates an accident, the operator involved shall make available to the representative of the Department all records and information that in any way pertain to the accident, and shall afford all reasonable assistance in the investigation of the accident.
§195.61 National Pipeline Mapping System
(a) Each operator of a hazardous liquid pipeline facility must provide the following geospatial data to PHMSA for that facility: 195.61(a)
(1) Geospatial data, attributes, metadata and transmittal letter appropriate for use in the National Pipeline Mapping System. Acceptable formats and additional information are specified in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or by contacting the PHMSA Geographic Information Systems Manager at (202) 366-4595. 195.61(a)(1)
(2) The name of and address for the operator.195.61(a)(2)
(3) The name and contact information of a pipeline company employee, to be displayed on a public Web site, who will serve as a contact for questions from the general public about the operator's NPMS data. 195.61(a)(3)
(b) This information must be submitted each year, on or before June 15, representing assets as of December 31 of the previous year. If no changes have occurred since the previous year's submission, the operator must refer to the information provided in the NPMS Operator Standards manual available at www.npms.phmsa.dot.gov or contact the PHMSA Geographic Information Systems Manager at (202) 3664595. 195.61(b)
§195.63 OMB control number assigned to information collection
The control numbers assigned by the Office of Management and Budget to the hazardous liquid pipeline information collection pursuant to the Paperwork Reduction Act are 2137-0047, 2137-0601, 2137-0604, 21370605, 2137-0618, and 2137-0622.
§195.64 National Registry of Operators
(a) OPID Request. Effective January 1, 2012, each operator of a hazardous liquid or carbon dioxide pipeline or pipeline facility must obtain from PHMSA an Operator Identification Number (OPID). An OPID is assigned to an operator for the pipeline or pipeline system for which the operator has primary responsibility. To obtain an OPID or a change to an OPID, an operator must complete an OPID Assignment Request DOT Form PHMSA F 1000.1 through the National Registry of Operators in accordance with §195.58. 195.64(a)
(b) OPID validation. Each operator must notify PHMSA electronically through the National Registry of Operators at https://portal.phmsa.dot.gov, of certain events. 195.64(b)
(c) Changes. Each operator must notify PHMSA electronically through the National Registry of Operators at https://portal.phmsa.dot.gov, of certain events. 195.64(c)
(1) An operator must notify PHMSA of any of the following events not later than 60 days before the event occurs: 195.64(c)(1)
(i) Construction or any planned rehabilitation, replacement, modification, upgrade, uprate, or update of a facility, other than a section of line pipe, that costs $10 million or more. If 60 day notice is not feasible because of an emergency, an operator must notify PHMSA as soon as practicable;195.64(c)(1)(i)
(ii) Construction of 10 or more miles of a new or replacement hazardous liquid or carbon dioxide pipeline;195.64(c)(1)(ii)
(iii) Reversal of product flow direction when the reversal is expected to last more than 30 days. This notification is not required for pipeline systems already designed for bi-directional flow; or195.64(c)(1)(iii)
(iv) A pipeline converted for service under §195.5, or a change in commodity as reported on the annual report as required by §195.49.195.64(c)(1)(iv)
(2) An operator must notify PHMSA of any following event not later than 60 days after the event occurs: 195.64(c)(2)
(i) A change in the primary entity responsible (i.e., with an assigned OPID) for managing or administering a safety program required by this part covering pipeline facilities operated under multiple OPIDs.195.64(c)(2)(i)
(ii) A change in the name of the operator;195.64(c)(2)(ii)
(iii) A change in the entity (e.g., company, municipality) responsible for operating an existing pipeline, pipeline segment, or pipeline facility;195.64(c)(2)(iii)
(iv) The acquisition or divestiture of 50 or more miles of pipeline or pipeline system subject to this part; or195.64(c)(2)(iv)
(v) The acquisition or divestiture of an existing pipeline facility subject to this part.195.64(c)(2)(v)
(d) Reporting. An operator must use the OPID issued by PHMSA for all reporting requirements covered under this subchapter and for submissions to the National Pipeline Mapping System. 195.64(d)
§195.65 Safety data sheets
(a) Each owner or operator of a hazardous liquid pipeline facility, following an accident involving a pipeline facility that results in a hazardous liquid spill, must provide safety data sheets on any spilled hazardous liquid to the designated Federal On-Scene Coordinator and appropriate State and local emergency responders within 6 hours of a telephonic or electronic notice of the accident to the National Response Center. 195.65(a)
(b) Definitions. In this section: 195.65(b)
(1) Federal On-Scene Coordinator. The term “Federal On-Scene Coordinator” has the meaning given such term in section 311(a) of the Federal Water Pollution Control Act (33 U.S.C. 1321(a)).
(2) National Response Center. The term “National Response Center” means the center described under 40 CFR 300.125(a).
(3) Safety data sheet. The term “safety data sheet” means a safety data sheet required under 29 CFR 1910.1200.
Subpart C – Design Requirements
§195.100 Scope
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.
§195.101 Qualifying metallic components other than pipe
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 195.101(a)
(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: 195.101(b)
(1) Pressure testing;195.101(b)(1)
(2) Materials; and195.101(b)(2)
(3) Pressure and temperature ratings.195.101(b)(3)
§195.102 Design temperature
(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. 195.102(a)
(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. 195.102(b)
§195.104 Variations in pressure
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.
§195.106 Internal design pressure
(a) Internal design pressure for the pipe in a pipeline is determined in accordance with the following formula: 195.106(a)
P = (2St/D) × E × F
P = Internal design pressure in p.s.i. (kPa) gage.
S = Yield strength in pounds per square inch (kPa) determined in accordance with paragraph (b) of this section.
t = Nominal wall thickness of the pipe in inches (millimeters). If this is unknown, it is determined in accordance with paragraph (c) of this section.
D = Nominal outside diameter of the pipe in inches (millimeters).
E = Seam joint factor determined in accordance with paragraph (e) of this section.
F = A design factor of 0.72, except that a design factor of 0.60 is used for pipe, including risers, on a platform located offshore or on a platform in inland navigable waters, and 0.54 is used for pipe that has been subjected to cold expansion to meet the specified minimum yield strength and is subsequently heated, other than by welding or stress relieving as a part of welding, to a temperature higher than 900 °F (482 °C) for any period of time or over 600 °F (316 °C) for more than 1 hour.
(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: 195.106(b)
(1) (i) The yield strength determined by performing all of the tensile tests of ANSI/API Spec 5L (incorporated by reference, see §195.3) on randomly selected specimens with the following number of tests:195.106(b)(1)(i)
(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:195.106(b)(1)(ii)
[A] Eighty percent of the average yield strength determined by the tensile tests.195.106(b)(1)(ii)[A]
[B] The lowest yield strength determined by the tensile tests. 195.106(b)(1)(ii)[B]
(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). 195.106(b)(2)
(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. 195.106(c)
(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. 195.106(d)
(e) (1) The seam joint factor used in paragraph (a) of this section is determined in accordance with the following standards incorporated by reference (see §195.3): 195.106(e)(1)
ASTM A671/A671MElectric-fusion-welded 1.00
ASTM A672/A672M Electric-fusion-welded 1.00
ASTM A691/A691MElectric-fusion-welded 1.00
ANSI/API Spec 5L
(2) The seam joint factor for pipe that is not covered by this paragraph must be approved by the Administrator. 195.106(e)(2)
§195.108 External pressure
Any external pressure that will be exerted on the pipe must be provided for in designing a pipeline system.
§195.110 External loads
(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. 195.110(a)
(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. 195.110(b)
§195.111 Fracture propagation
A carbon dioxide pipeline system must be designed to mitigate the effects of fracture propagation.
§195.112
New pipe
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. 195.112(a)
(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. 195.112(b)
(c) Each length of pipe with a nominal outside diameter of 4 1⁄2 in (114.3 mm) or more must be marked on the pipe or pipe coating with the specification to which it was made, the specified minimum yield strength or grade, and the pipe size. The marking must be applied in a manner that does not damage the pipe or pipe coating and must remain visible until the pipe is installed. 195.112(c)
§195.114
Used pipe
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. 195.114(a)
(b) There may not be any: 195.114(b)
(1) Buckles;195.114(b)(1)
(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 195.114(b)(2)
(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. 195.114(b)(3) However, pipe that does not meet the requirements of paragraph (b)(3) of this section may be used if the operating pressure is reduced to be commensurate with the remaining wall thickness.
§195.116 Valves
Each valve installed in a pipeline system must comply with the following:
(a) The valve must be of a sound engineering design. 195.116(a)
(b) Materials subject to the internal pressure of the pipeline system, including welded and flanged ends, must be compatible with the pipe or fittings to which the valve is attached. 195.116(b)
(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. 195.116(c)
(d) Each valve must be both hydrostatically shell tested and hydrostatically seat tested without leakage to at least the requirements set forth in Section 11 of ANSI/API Spec 6D (incorporated by reference, see §195.3). 195.116(d)
(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.). 195.116(e)
(f) Each valve must be marked on the body or the nameplate, with at least the following: 195.116(f)
(1) Manufacturer's name or trademark.195.116(f)(1)
(2) Class designation or the maximum working pressure to which the valve may be subjected. 195.116(f)(2)
(3) Body material designation (the end connection material, if more than one type is used). 195.116(f)(3)
(4) Nominal valve size.195.116(f)(4)
§195.118
Fittings
(a) Butt-welding type fittings must meet the marking, end preparation, and the bursting strength requirements of ASME/ANSI B16.9 or MSS SP-75 (incorporated by reference, see §195.3). 195.118(a)
(b) There may not be any buckles, dents, cracks, gouges, or other defects in the fitting that might reduce the strength of the fitting. 195.118(b)
(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. 195.118(c)
§195.120
Passage of internal inspection devices
(a) General. Except as provided in paragraphs (b) and (c) of this section, each new pipeline and each main 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 in accordance with NACE SP0102 (incorporated by reference, see §195.3). 195.120(a)
(b) Exceptions. This section does not apply to: 195.120(b)
(1) Manifolds;195.120(b)(1)
(2) Station piping such as at pump stations, meter stations, or pressure reducing stations; 195.120(b)(2)
(3) Piping associated with tank farms and other storage facilities; 195.120(b)(3)
(4) Cross-overs;195.120(b)(4)
(5) Pipe for which an instrumented internal inspection device is not commercially available; and 195.120(b)(5)
(6) Offshore pipelines, other than lines 10 inches (254 millimeters) or greater in nominal diameter, that transport liquids to onshore facilities. 195.120(b)(6)
(c) Impracticability. An operator may file a petition under §190.9 for a finding that the requirements in paragraph (a) of this section should not be applied to a pipeline for reasons of impracticability. 195.120(c)
(d) Emergencies. An operator need not comply with paragraph (a) of this section in constructing a new or replacement segment of a pipeline in an emergency. Within 30 days after discovering the emergency, the operator must file a petition under §190.9 for a finding that requiring the design and construction of the new or replacement pipeline segment to accommodate passage of instrumented internal inspection devices would be impracticable as a result of the emergency. If PHMSA denies the petition, within 1 year after the date of the notice of the denial, the operator must modify the new or replacement pipeline segment to allow passage of instrumented internal inspection devices. 195.120(d)
§195.122 Fabricated branch connections
Each pipeline system must be designed so that the addition of any fabricated branch connections will not reduce the strength of the pipeline system.
§195.124 Closures
Each closure to be installed in a pipeline system must comply with the 2007 ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1) (incorporated by reference, see §195.3) and must have pressure and temperature ratings at least equal to those of the pipe to which the closure is attached.
§195.126 Flange connection
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.
§195.128 Station piping
Any pipe to be installed in a station that is subject to system pressure must meet the applicable requirements of this subpart.
§195.130 Fabricated assemblies
Each fabricated assembly to be installed in a pipeline system must meet the applicable requirements of this subpart.
§195.132 Design and construction of aboveground breakout tanks
(a) Each aboveground breakout tank must be designed and constructed to withstand the internal pressure produced by the hazardous liquid to be stored therein and any anticipated external loads. 195.132(a)
(b) For aboveground breakout tanks first placed in service after October 2, 2000, compliance with paragraph (a) of this section requires one of the following: 195.132(b)
(1) Shop-fabricated, vertical, cylindrical, closed top, welded steel tanks with nominal capacities of 90 to 750 barrels (14.3 to 119.2 m3) and with internal vapor space pressures that are approximately atmospheric must be designed and constructed in accordance with API Spec 12F (incorporated by reference, see §195.3). 195.132(b)(1)
(2) Welded, low-pressure (i.e., internal vapor space pressure not greater than 15 psig (103.4 kPa)), carbon steel tanks that have wall shapes that can be generated by a single vertical axis of revolution must be designed and constructed in accordance with API Std 620 (incorporated by reference, see §195.3). 195.132(b)(2)
(3) Vertical, cylindrical, welded steel tanks with internal pressures at the tank top approximating atmospheric pressures (i.e., internal vapor space pressures not greater than 2.5 psig (17.2 kPa), or not greater than the pressure developed by the weight of the tank roof) must be designed and constructed in accordance with API Std 650 (incorporated by reference, see §195.3). 195.132(b)(3)
(4) High pressure steel tanks (i.e., internal gas or vapor space pressures greater than 15 psig (103.4 kPa)) with a nominal capacity of 2000 gallons (7571 liters) or more of liquefied petroleum gas (LPG) must be designed and constructed in accordance with API Std 2510 (incorporated by reference, see §195.3). 195.132(b)(4)
§195.134 Leak detection
(a) Scope. This section applies to each hazardous liquid pipeline transporting liquid in single phase (without gas in the liquid).
(b) General.
(1) For each pipeline constructed prior to October 1, 2019. Each pipeline must have a system for detecting leaks that complies with the requirements in §195.444 by October 1, 2024.
(2) For each pipeline constructed on or after October 1, 2019. Each pipeline must have a system for detecting leaks that complies with the requirements in §195.444 by October 1, 2020.
(c) CPM leak detection systems. A new computational pipeline monitoring (CPM) leak detection system or replaced component of an existing CPM system must be designed in accordance with the requirements in section 4.2 of API RP 1130 (incorporated by reference, see §195.3) and any other applicable design criteria in that standard.
(d) Exception. The requirements of paragraph (b) of this section do not apply to offshore gathering or regulated rural gathering lines.
Subpart D – Construction
§195.200 Scope
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.
§195.202 Compliance with specifications or standards
Each pipeline system must be constructed in accordance with comprehensive written specifications or standards that are consistent with the requirements of this part.
§195.204 Inspection — general
Inspection must be provided to ensure that the installation of pipe or pipeline systems is in accordance with the requirements of this subpart. Any operator personnel used to perform the inspection must be trained and qualified in the phase of construction to be inspected. An operator must not use operator personnel to perform a required inspection if the operator personnel performed the construction task requiring inspection. Nothing in this section prohibits the operator from inspecting construction tasks with operator personnel who are involved in other construction tasks.
§195.205 Repair, alteration and reconstruction of aboveground breakout tanks that have been in service
(a) Aboveground breakout tanks that have been repaired, altered, or reconstructed and returned to service must be capable of withstanding the internal pressure produced by the hazardous liquid to be stored therein and any anticipated external loads. 195.205(a)
(b) After October 2, 2000, compliance with paragraph (a) of this section requires the following: 195.205(b)
(1) For tanks designed for approximate atmospheric pressure, constructed of carbon and low alloy steel, welded or riveted, and nonrefrigerated; and for tanks built to API Std 650 (incorporated by reference, see §195.3) or its predecessor Standard 12C; repair, alteration; and reconstruction must be in accordance with API Std 653 (except section 6.4.3) (incorporated by reference, see §195.3). 195.205(b)(1)
(2) For tanks built to API Spec 12F (incorporated by reference, see §195.3) or API Std 620 (incorporated by reference, see §195.3), repair, alteration, and reconstruction must be in accordance with the design, welding, examination, and material requirements of those respective standards. 195.205(b)(2)
(3) For high-pressure tanks built to API Std 2510 (incorporated by reference, see §195.3), repairs, alterations, and reconstruction must be in accordance with API Std 510 (incorporated by reference, see §195.3). 195.205(b)(3)
§195.206 Material inspection
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.
§195.207 Transportation of pipe
(a) Railroad. In a pipeline 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 the transportation is performed in accordance with API RP 5L1 (incorporated by reference, see §195.3). 195.207(a)
(b) Ship or barge. In a pipeline 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 ship or barge on both inland and marine waterways, unless the transportation is performed in accordance with API RP 5LW (incorporated by reference, see §195.3). 195.207(b)
(c) Truck. 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 truck unless the transportation is performed in accordance with API RP 5LT (incorporated by reference, see §195.3). 195.207(c)
§195.208 Welding of supports and braces
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.
§195.210 Pipeline location
(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. 195.210(a)
(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. 195.210(b)
§195.212 Bending of pipe
(a) Pipe must not have a wrinkle bend. 195.212(a)
(b) Each field bend must comply with the following: 195.212(b)
(1) A bend must not impair the serviceability of the pipe.195.212(b)(1) (2) Each bend must have a smooth contour and be free from buckling, cracks, or any other mechanical damage. 195.212(b)(2) (3) On pipe containing a longitudinal weld, the longitudinal weld must be as near as practicable to the neutral axis of the bend unless — 195.212(b)(3)
(i) The bend is made with an internal bending mandrel; or 195.212(b)(3)(i)
(ii) The pipe is 123⁄4 in (324 mm) or less nominal outside diameter or has a diameter to wall thickness ratio less than 70. 195.212(b)(3)(ii)
(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. 195.212(c)
§195.214 Welding procedures
(a) Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see §195.3), or Section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC) (incorporated by reference, see §195.3). The quality of the test welds used to qualify the welding procedures must be determined by destructive testing. 195.214(a)
(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. 195.214(b)
§195.216
Welding: Miter joints
A miter joint is not permitted (not including deflections up to 3 degrees that are caused by misalignment).
§195.222
Welders and welding operators: Qualification of welders and welding operators
(a) Each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A or Appendix B of API Std 1104 (incorporated by reference, see §195.3), or section IX of the ASME Boiler and Pressure Vessel Code (ASME BPVC), (incorporated by ref-
erence, see §195.3) except that a welder or welding operator qualified under an earlier edition than listed in §195.3, may weld but may not requalify under that earlier edition. 195.222(a)
(b) No welder or welding operator may weld with a welding process unless, within the preceding 6 calendar months, the welder or welding operator has — 195.222(b)
(1) Engaged in welding with that process; and195.222(b)(1)
(2) Had one weld tested and found acceptable under section 9 or Appendix A of API Std 1104 (incorporated by reference, see §195.3). 195.222(b)(2)
§195.224 Welding: Weather
Welding must be protected from weather conditions that would impair the quality of the completed weld.
§195.226 Welding: Arc burns
(a) Each arc burn must be repaired. 195.226(a)
(b) An arc burn may be repaired by completely removing the notch by grinding, if the grinding does not reduce the remaining wall thickness to less than the minimum thickness required by the tolerances in the specification to which the pipe is manufactured. If a notch is not repairable by grinding, a cylinder of the pipe containing the entire notch must be removed. 195.226(b)
(c) A ground may not be welded to the pipe or fitting that is being welded. 195.226(c)
§195.228 Welds and welding inspection: Standards of acceptability
(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. 195.228(a)
(b) The acceptability of a weld is determined according to the standards in section 9 or Appendix A of API Std 1104 (incorporated by reference, see §195.3). Appendix A of API Std 1104 may not be used to accept cracks. 195.228(b)
§195.230 Welds: Repair or removal of defects
(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. 195.230(a)
(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. 195.230(b)
(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. 195.230(c)
§195.234 Welds: Nondestructive testing
(a) A weld may be nondestructively tested by any process that will clearly indicate any defects that may affect the integrity of the weld. 195.234(a)
(b) Any nondestructive testing of welds must be performed — 195.234(b)
(1) In accordance with a written set of procedures for nondestructive testing; and 195.234(b)(1)
(2) With personnel that have been trained in the established procedures and in the use of the equipment employed in the testing. 195.234(b)(2)
(c) Procedures for the proper interpretation of each weld inspection must be established to ensure the acceptability of the weld under §195.228. 195.234(c)
(d) During construction, at least 10 percent of the girth welds made by each welder and welding operator during each welding day must be nondestructively tested over the entire circumference of the weld. 195.234(d)
(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: 195.234(e)
(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; 195.234(e)(1)
(2) Within railroad or public road rights-of-way; 195.234(e)(2)
(3) At overhead road crossings and within tunnels; 195.234(e)(3)
(4) Within the limits of any incorporated subdivision of a State government; and 195.234(e)(4)
(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. 195.234(e)(5)
(f) When installing used pipe, 100 percent of the old girth welds must be nondestructively tested. 195.234(f)
(g) At pipeline tie-ins, including tie-ins of replacement sections, 100 percent of the girth welds must be nondestructively tested. 195.234(g)
§§195.236-195.244 —
[Reserved]
§195.246 Installation of pipe in a ditch
(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. 195.246(a)
(b) Except for pipe in the Gulf of Mexico and its inlets in waters less than 15 feet deep, all offshore pipe in water at least 12 feet deep (3.7 meters) but not more than 200 feet deep (61 meters) deep as measured from the mean low water must be installed so that the top of the pipe is below the underwater natural bottom (as determined by recognized and generally accepted practices) unless the pipe is supported by stanchions held in place by anchors or heavy concrete coating or protected by an equivalent means. 195.246(b)
§195.248 Cover over buried pipeline
(a) Unless specifically exempted in this subpart, all pipe must be buried so that it is below the level of cultivation. Except as provided in paragraph (b) of this section, the pipe must be installed so that the cover between the top of the pipe and the ground level, road bed, river bottom, or underwater natural bottom (as determined by recognized and generally accepted practices), as applicable, complies with the following table: 195.248(a)
Drainage ditches at public roads and railroads 36 (914)
(914) Deepwater port safety zones
Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water
(1219) 24 (610)
1Rock excavation is any excavation that requires blasting or removal by equivalent means.
(b) Except for the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep, less cover than the minimum required by paragraph (a) of this section and §195.210 may be used if — 195.248(b) (1) It is impracticable to comply with the minimum cover requirements; and 195.248(b)(1) (2) Additional protection is provided that is equivalent to the minimum required cover. 195.248(b)(2)
§195.250
Clearance
between pipe and underground structures
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.
§195.252 Backfilling
When a ditch for a pipeline is backfilled, it must be backfilled in a manner that:
(a) Provides firm support under the pipe; and 195.252(a)
(b) Prevents damage to the pipe and pipe coating from equipment or from the backfill material. 195.252(b)
§195.254
Above ground components
(a) Any component may be installed above ground in the following situations, if the other applicable requirements of this part are complied with: 195.254(a)
(1) Overhead crossings of highways, railroads, or a body of water. 195.254(a)(1)
(2) Spans over ditches and gullies.195.254(a)(2)
(3) Scraper traps or block valves.195.254(a)(3)
(4) Areas under the direct control of the operator. 195.254(a)(4)
(5) In any area inaccessible to the public.195.254(a)(5)
(b) Each component covered by this section must be protected from the forces exerted by the anticipated loads. 195.254(b)
§195.256 Crossing of railroads and highways
The pipe at each railroad or highway crossing must be installed so as to adequately withstand the dynamic forces exerted by anticipated traffic loads.
§195.258
Valves: General
(a) Each valve must be installed in a location that is accessible to authorized employees and that is protected from damage or tampering. 195.258(a)
(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. 195.258(b)
(c)For all onshore hazardous liquid or carbon dioxide pipeline segments with diameters greater than or equal to 6 inches that are constructed after April 10, 2023, the operator must install rupture-mitigation valves (RMV) or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section and §195.260. An operator using alternative equivalent technology must notify PHMSA in accordance with the procedure in paragraph (e) of this section. All RMVs and alternative equivalent technology installed as required by this section must meet the requirements of §195.419. An operator may request an extension of the installation compliance deadline requirements of this paragraph if it can demonstrate to PHMSA, in accordance with the notification procedures in §195.18, that those installation deadline requirements would be economically, technically, or operationally infeasible for a particular new pipeline.195.258(c)
(d)For all entirely replaced onshore hazardous liquid or carbon dioxide pipeline segments with diameters greater than or equal to 6 inches that have been replaced after April 10, 2023, the operator must install RMVs or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this section. An operator using alternative equivalent technology must notify PHMSA in accordance with the procedure in paragraph (e) of this section. All valves installed as required by this section must meet the requirements of §195.419. The requirements of this paragraph (d) apply when the applicable pipeline replacement project involves a valve, either through addition, replacement, or removal. An operator may request an extension of the installation compliance deadline requirements of this paragraph if it can demonstrate to PHMSA, in accordance with the notification procedures in §195.18, that those installation deadline requirements would be economically, technically, or operationally infeasible for a particular pipeline replacement project. 195.258(d)
(e)If an operator elects to use alternative equivalent technology in accordance with paragraph (c) or (d) of this section, the operator must notify PHMSA in accordance with §195.18. The operator must include a technical and safety evaluation in its notice to PHMSA. Valves that are installed as alternative equivalent technology must comply with §§195.418, 195.419, and 195.420. An operator requesting use of manual valves as an alternative equivalent technology must also include within the notification submitted to PHMSA a demonstration that installation of an RMV as otherwise required would be economically, technically, or operationally infeasible. An operator may use a manual compressor station valve at a continuously manned station as an alternative equivalent technology. Such a valve used as an alternative equivalent technology would not require a notification to PHMSA in accordance with §195.18, but it must comply with §§195.419 and 195.420.195.258(e)
§195.260 Valves: Location
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. 195.260(a)
(b) On each pipeline entering or leaving a breakout storage tank area in a manner that permits isolation of the tank from other facilities. 195.260(b)
(c) On each pipeline at locations along the pipeline system that will minimize or prevent safety risks, property damage, or environmental harm from accidental hazardous liquid or carbon dioxide discharges, as appropriate for onshore areas, offshore areas, and highconsequence areas (HCA). For newly constructed or entirely replaced onshore hazardous liquid or carbon dioxide pipeline segments, as that term is defined at §195.2, that are installed after April 10, 2023, valve spacing must not exceed 15 miles for pipeline segments that could affect or are in HCAs, as defined in §195.450, and 20 miles for pipeline segments that could not affect HCAs. Valves on pipeline segments that are located in HCAs or which could affect HCAs must be installed at locations as determined by the operator's process for identifying preventive and mitigative measures established pursuant to §195.452(i) and by using the selection process in section I.B of appendix C of part 195, but with a maximum distance that does not exceed 71⁄2 miles from the endpoints of the HCA segment or the segment that could affect an HCA. An operator may request an exemption from the compliance deadline requirements of this section for valve installation at the specified valve spacing if it can demonstrate to PHMSA, in accordance with the notification procedures in §195.18, that those compliance deadline requirements would be economically, technically, or operationally infeasible. 195.260(c)
(d) On each lateral takeoff from a pipeline in a manner that permits shutting off the lateral without interrupting flow in the pipeline. 195.260(d)
(e) On each side of one or more adjacent water crossings that are more than 100 feet (30 meters) wide from high water mark to high water mark, as follows: 195.260(e)
(1) Valves must be installed at locations outside of the 100-year flood plain or be equipped with actuators or other control equipment that is installed so as not to be impacted by flood conditions; and 195.260(e)(1)
(2) The maximum spacing interval between valves that protect multiple adjacent water crossings cannot exceed 1 mile in length. 195.260(e)(2)
(f) On each side of a reservoir holding water for human consumption.195.260(f)
(g)On each highly volatile liquid (HVL) pipeline that is located in a high-population area or other populated area, as defined in §195.450, and that is constructed, or where 2 or more miles of pipe have been replaced within any 5 contiguous miles within any 24-month period, after April 10, 2023, with a maximum valve spacing of 71⁄2 miles. The maximum valve spacing intervals may be increased by 1.25 times the distance up to a 9 3⁄8-mile spacing, provided the operator:195.260(g)
(1) Submits for PHMSA review a notification pursuant to §195.18 requesting alternative spacing because installation of a valve at a particular location between a 7-mile to a 71⁄2-mile spacing would be economically, technically, or operationally infeasible, and that an alternative spacing would not adversely impact safety; and 195.260(g)(1)
(2) Keeps the records necessary to support that determination for the useful life of the pipeline.195.260(g)(2)
(h) An operator may submit for PHMSA review, in accordance with §195.18, a notification requesting site-specific exemption from the valve installation requirements or valve spacing requirements of paragraph (c), (e), or (f) of this section and demonstrating such exemption would not adversely affect safety. An operator may also submit for PHMSA review, in accordance with §195.18, a notification requesting an extension of the compliance deadline requirements for valve installation and spacing of this section because those compliance deadline requirements would be economically, technically, or operationally infeasible for a particular new construction or pipeline replacement project. 195.260(h)
§195.262 Pumping equipment
(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. 195.262(a)
(b) The following must be provided in each pump station: 195.262(b)
(1) Safety devices that prevent overpressuring of pumping equipment, including the auxiliary pumping equipment within the pumping station. 195.262(b)(1)
(2) A device for the emergency shutdown of each pumping station. 195.262(b)(2)
(3) If power is necessary to actuate the safety devices, an auxiliary power supply. 195.262(b)(3)
(c) Each safety device must be tested under conditions approximating actual operations and found to function properly before the pumping station may be used. 195.262(c)
(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. 195.262(d)
(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. 195.262(e)
§195.264 Impoundment, protection against entry, normal/emergency venting or pressure/ vacuum relief for aboveground breakout tanks
(a) A means must be provided for containing hazardous liquids in the event of spillage or failure of an aboveground breakout tank. 195.264(a)
(b) After October 2, 2000, compliance with paragraph (a) of this section requires the following for the aboveground breakout tanks specified: 195.264(b)
(1) For tanks built to API Spec 12F, API Std 620, and others (such as API Std 650 (or its predecessor Standard 12C)), the installation of impoundment must be in accordance with the following sections of NFPA-30 (incorporated by reference, see §195.3); 195.264(b)(1)
(i) Impoundment around a breakout tank must be installed in accordance with section 22.11.2; and195.264(b)(1)(i)
(ii) Impoundment by drainage to a remote impounding area must be installed in accordance with section 22.11.1.195.264(b)(1)(ii)
(2) For tanks built to API Std 2510 (incorporated by reference, see §195.3), the installation of impoundment must be in accordance with section 5 or 11 of API Std 2510. 195.264(b)(2)
(c) Aboveground breakout tank areas must be adequately protected against unauthorized entry. 195.264(c)
(d) Normal/emergency relief venting must be provided for each atmospheric pressure breakout tank. Pressure/vacuum-relieving devices must be provided for each low-pressure and high-pressure breakout tank. 195.264(d)
(e) For normal/emergency relief venting and pressure/vacuum-relieving devices installed on aboveground breakout tanks after October 2, 2000, compliance with paragraph (d) of this section requires the following for the tanks specified: 195.264(e)
(1) Normal/emergency relief venting installed on atmospheric pressure tanks built to API Spec 12F must be in accordance with section 4 and Appendices B and C of API Spec 12F (incorporated by reference, see §195.3). 195.264(e)(1)
(2) Normal/emergency relief venting installed on atmospheric pressure tanks (such as those built to API Std 650 or its predecessor Standard 12C) must be in accordance with API Std 2000 (incorporated by reference, see §195.3). 195.264(e)(2)
(3) Pressure-relieving and emergency vacuum-relieving devices installed on low-pressure tanks built to API Std 620 must be in accordance with Section 9 of API Std 620 (incorporated by reference, see §195.3) and its references to the normal and emergency venting requirements in API Std 2000 (incorporated by reference, see §195.3). 195.264(e)(3)
(4) Pressure and vacuum-relieving devices installed on high-pressure tanks built to API Std 2510 must be in accordance with sections 7 or 11 of API Std 2510 (incorporated by reference, see §195.3). 195.264(e)(4)
§195.266 Construction records
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. 195.266(a)
(b) The amount, location; and cover of each size of pipe installed. 195.266(b)
(c) The location of each crossing of another pipeline. 195.266(c)
(d) The location of each buried utility crossing. 195.266(d)
(e) The location of each overhead crossing. 195.266(e)
(f) The location of each valve and corrosion test station. 195.266(f)
Subpart E – Pressure Testing
§195.300
Scope
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.
§195.302 General requirements
(a) Except as otherwise provided in this section and in §195.305(b), no operator may operate a pipeline unless it has been pressure tested under this subpart without leakage. In addition, no operator may return to service a segment of pipeline that has been replaced, relocated, or otherwise changed until it has been pressure tested under this subpart without leakage. 195.302(a)
(b) Except for pipelines converted under §195.5, the following pipelines may be operated without pressure testing under this subpart: 195.302(b)
(1) Any hazardous liquid pipeline whose maximum operating pressure is established under §195.406(a)(5) that is — 195.302(b)(1)
(i) An interstate pipeline constructed before January 8, 1971; 195.302(b)(1)(i)
(ii) An interstate offshore gathering line constructed before August 1, 1977;195.302(b)(1)(ii)
(iii) An intrastate pipeline constructed before October 21, 1985; or 195.302(b)(1)(iii)
(iv) A low-stress pipeline constructed before August 11, 1994 that transports HVL.195.302(b)(1)(iv)
(2) Any carbon dioxide pipeline constructed before July 12, 1991, that — 195.302(b)(2)
(i) Has its maximum operating pressure established under §195.406(a)(5); or195.302(b)(2)(i)
(ii) Is located in a rural area as part of a production field distribution system.195.302(b)(2)(ii)
(3) Any low-stress pipeline constructed before August 11, 1994 that does not transport HVL. 195.302(b)(3)
(4) Those portions of older hazardous liquid and carbon dioxide pipelines for which an operator has elected the risk-based alternative under §195.303 and which are not required to be tested based on the risk-based criteria. 195.302(b)(4)
(c) Except for pipelines that transport HVL onshore, low-stress pipelines, and pipelines covered under §195.303, the following compliance deadlines apply to pipelines under paragraphs (b)(1) and (b)(2)(i) of this section that have not been pressure tested under this subpart: 195.302(c)
(1) Before December 7, 1998, for each pipeline each operator shall — 195.302(c)(1)
(i) Plan and schedule testing according to this paragraph; or 195.302(c)(1)(i)
(ii) Establish the pipeline's maximum operating pressure under §195.406(a)(5).195.302(c)(1)(ii)
(2) For pipelines scheduled for testing, each operator shall — 195.302(c)(2)
(i) Before December 7, 2000, pressure test — 195.302(c)(2)(i)
[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; and195.302(c)(2)(i)[A]
[B] At least 50 percent of the mileage (length) of all other pipelines; and195.302(c)(2)(i)[B]
(ii) Before December 7, 2003, pressure test the remainder of the pipeline mileage (length).195.302(c)(2)(ii)
§195.303
Risk-based alternative to pressure testing older hazardous liquid and carbon dioxide pipelines
(a) An operator may elect to follow a program for testing a pipeline on risk-based criteria as an alternative to the pressure testing in §195.302(b)(1)(i)-(iii) and §195.302(b)(2)(i) of this subpart. Appendix B provides guidance on how this program will work. An operator electing such a program shall assign a risk classification to each pipeline segment according to the indicators described in paragraph (b) of this section as follows: 195.303(a)
(1) Risk Classification A if the location indicator is ranked as low or medium risk, the product and volume indicators are ranked as low risk, and the probability of failure indicator is ranked as low risk; 195.303(a)(1)
(2) Risk Classification C if the location indicator is ranked as high risk; or 195.303(a)(2)
(3) Risk Classification B.195.303(a)(3)
(b) An operator shall evaluate each pipeline segment in the program according to the following indicators of risk: 195.303(b)
(1) The location indicator is — 195.303(b)(1)
(i) High risk if an area is non-rural or environmentally sensitive1; or 195.303(b)(1)(i)
(ii) Medium risk; or195.303(b)(1)(ii)
(iii) Low risk if an area is not high or medium risk.195.303(b)(1)(iii)
(2) The product indicator is1195.303(b)(2)
1(See Appendix B, Table C).
(i) High risk if the product transported is highly toxic or is both highly volatile and flammable;195.303(b)(2)(i)
(ii) Medium risk if the product transported is flammable with a flashpoint of less than 100 °F, but not highly volatile; or195.303(b)(2)(ii)
(iii) Low risk if the product transported is not high or medium risk. 195.303(b)(2)(iii)
(3) The volume indicator is — 195.303(b)(3)
(i) High risk if the line is at least 18 inches in nominal diameter; 195.303(b)(3)(i)
(ii) Medium risk if the line is at least 10 inches, but less than 18 inches, in nominal diameter; or195.303(b)(3)(ii)
(iii) Low risk if the line is not high or medium risk.195.303(b)(3)(iii)
(4) The probability of failure indicator is — 195.303(b)(4)
(i) High risk if the segment has experienced more than three failures in the last 10 years due to time-dependent defects (e.g., corrosion, gouges, or problems developed during manufacture, construction or operation, etc.); or195.303(b)(4)(i)
(ii) Low risk if the segment has experienced three failures or less in the last 10 years due to time-dependent defects.195.303(b)(4)(ii)
(c) The program under paragraph (a) of this section shall provide for pressure testing for a segment constructed of electric resistancewelded (ERW) pipe and lapwelded pipe manufactured prior to 1970 susceptible to longitudinal seam failures as determined through paragraph (d) of this section. The timing of such pressure test may be determined based on risk classifications discussed under paragraph (b) of this section. For other segments, the program may provide for use of a magnetic flux leakage or ultrasonic internal inspection survey as an alternative to pressure testing and, in the case of such segments in Risk Classification A, may provide for no additional measures under this subpart. 195.303(c)
(d) All pre-1970 ERW pipe and lapwelded pipe is deemed susceptible to longitudinal seam failures unless an engineering analysis shows otherwise. In conducting an engineering analysis an operator must consider the seam-related leak history of the pipe and pipe manufacturing information as available, which may include the pipe steel's mechanical properties, including fracture toughness; the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-making process; and other factors pertinent to seam properties and quality. 195.303(d)
(e) Pressure testing done under this section must be conducted in accordance with this subpart. Except for segments in Risk Classification B which are not constructed with pre-1970 ERW pipe, water must be the test medium. 195.303(e)
(f) An operator electing to follow a program under paragraph (a) must develop plans that include the method of testing and a schedule for the testing by December 7, 1998. The compliance deadlines for completion of testing are as shown in the table below: 195.303(f)
— Test Deadlines
(g) An operator must review the risk classifications for those pipeline segments which have not yet been tested under paragraph (a) of this section or otherwise inspected under paragraph (c) of this section at intervals not to exceed 15 months. If the risk classification of an untested or uninspected segment changes, an operator must take appropriate action within two years, or establish the maximum operating pressure under §195.406(a)(5). 195.303(g)
(h) An operator must maintain records establishing compliance with this section, including records verifying the risk classifications, the plans and schedule for testing, the conduct of the testing, and the review of the risk classifications. 195.303(h)
(i) An operator may discontinue a program under this section only after written notification to the Administrator and approval, if needed, of a schedule for pressure testing. 195.303(i)
§195.304 Test pressure
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.
§195.305 Testing of components
(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. 195.305(a)
(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 — 195.305(b)
(1) The component was hydrostatically tested at the factory; or 195.305(b)(1)
(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. 195.305(b)(2)
§195.306 Test medium
(a) Except as provided in paragraphs (b), (c), and (d) of this section, water must be used as the test medium. 195.306(a)
(b) Except for offshore pipelines, liquid petroleum that does not vaporize rapidly may be used as the test medium if — 195.306(b)
(1) The entire pipeline section under test is outside of cities and other populated areas; 195.306(b)(1)
(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; 195.306(b)(2)
(3) The test section is kept under surveillance by regular patrols during the test; and 195.306(b)(3)
(4) Continuous communication is maintained along entire test section. 195.306(b)(4)
(c) Carbon dioxide pipelines may use inert gas or carbon dioxide as the test medium if — 195.306(c)
(1) The entire pipeline section under test is outside of cities and other populated areas; 195.306(c)(1)
(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; 195.306(c)(2)
(3) The maximum hoop stress during the test does not exceed 80 percent of specified minimum yield strength; 195.306(c)(3)
(4) Continuous communication is maintained along entire test section; and 195.306(c)(4)
(5) The pipe involved is new pipe having a longitudinal joint factor of 1.00. 195.306(c)(5)
(d) Air or inert gas may be used as the test medium in low-stress pipelines. 195.306(d)
(a) For aboveground breakout tanks built to API Spec 12F (incorporated by reference, see §195.3) and first placed in service after October 2, 2000, pneumatic testing must be performed in accordance with section 5.3 of API Spec 12 F. 195.307(a)
(b) For aboveground breakout tanks built to API Std 620 (incorporated by reference, see §195.3) and first placed in service after October 2, 2000, hydrostatic and pneumatic testing must be performed in accordance with section 7.18 of API Std 620. 195.307(b)
(c) For aboveground breakout tanks built to API Std 650 (incorporated by reference, see §195.3) and first placed in service after October 2, 2000, testing must be in accordance with sections 7.3.5 and 7.3.6 of API Standard 650 (incorporated by reference, see §195.3). 195.307(c)
(d) For aboveground atmospheric pressure breakout tanks constructed of carbon and low alloy steel, welded or riveted, and nonrefrigerated tanks built to API Std 650 or its predecessor Standard 12 C that are returned to service after October 2, 2000, the necessity for the hydrostatic testing of repair, alteration, and reconstruction is covered in section 12.3 of API Standard 653 (incorporated by reference, see §195.3). 195.307(d)
(e) For aboveground breakout tanks built to API Std 2510 (incorporated by reference, see §195.3) and first placed in service after October 2, 2000, pressure testing must be performed in accordance with 2007 ASME Boiler and Pressure Vessel Code (BPVC) (Section VIII, Division 1 or 2). 195.307(e)
§195.308 Testing of tie-ins
Pipe associated with tie-ins must be pressure tested, either with the section to be tied in or separately.
§195.310 Records
(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. 195.310(a)
Part 195 – Transportation of Hazardous Liquids
(b) The record required by paragraph (a) of this section must include:
195.310(b)
(1) The pressure recording charts;195.310(b)(1)
(2) Test instrument calibration data;195.310(b)(2)
(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; 195.310(b)(3)
(4) The date and time of the test;195.310(b)(4)
(5) The minimum test pressure;195.310(b)(5)
(6) The test medium;195.310(b)(6)
(7) A description of the facility tested and the test apparatus; 195.310(b)(7)
(8) An explanation of any pressure discontinuities, including test failures, that appear on the pressure recording charts; 195.310(b)(8)
(9) Where elevation differences in the section under test exceed 100 feet (30 meters), a profile of the pipeline that shows the elevation and test sites over the entire length of the test section; and 195.310(b)(9)
(10) Temperature of the test medium or pipe during the test period. 195.310(b)(10)
Subpart F – Operation and Maintenance
§195.400 Scope
This subpart prescribes minimum requirements for operating and maintaining pipeline systems constructed with steel pipe.
§195.401 General requirements
(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. 195.401(a)
(b) An operator must make repairs on its pipeline system according to the following requirements: 195.401(b)
(1) Non Integrity management repairs. Whenever an operator discovers any condition that could adversely affect the safe operation of its pipeline system, it must correct the condition 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. 195.401(b)(1)
(2) Integrity management repairs. When an operator discovers a condition on a pipeline covered under §195.452, the operator must correct the condition as prescribed in §195.452(h). 195.401(b)(2)
(3) Prioritizing repairs. An operator must consider the risk to people, property, and the environment in prioritizing the correction of any conditions referenced in paragraphs (b)(1) and (2) of this section. 195.401(b)(3)
(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: 195.401(c)
(1) An interstate pipeline, other than a low-stress pipeline, on which construction was begun after March 31, 1970, that transports hazardous liquid. 195.401(c)(1)
(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. 195.401(c)(2)
(3) An intrastate pipeline, other than a low-stress pipeline, on which construction was begun after October 20, 1985, that transports hazardous liquid. 195.401(c)(3)
(4) A pipeline on which construction was begun after July 11, 1991, that transports carbon dioxide. 195.401(c)(4)
(5) A low-stress pipeline on which construction was begun after August 10, 1994. 195.401(c)(5)
§195.402 Procedural manual for operations, maintenance, and emergencies
(a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for conducting normal operations and maintenance activities and handling abnormal operations and emergencies. This manual shall be reviewed at intervals not exceeding 15 months, but at least once each calendar year, and appropriate changes made as necessary to insure that the manual is effective. This manual shall be prepared before initial operations of a pipeline system commence, and appropriate parts shall be kept at locations where operations and maintenance activities are conducted. 195.402(a)
(b) The Associate Administrator or the State Agency that has submitted a current certification under the pipeline safety laws (49 U.S.C. 60101 et seq.) with respect to the pipeline facility governed by an operator's plans and procedures may, after notice and opportunity for hear-
ing as provided in 49 CFR 190.206 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety. 195.402(b)
(c) Maintenance and normal operations. The manual required by paragraph (a) of this section must include procedures for the following to provide safety during maintenance and normal operations: 195.402(c)
(1) Making construction records, maps, and operating history available as necessary for safe operation and maintenance. 195.402(c)(1)
(2) Gathering of data needed for reporting accidents under subpart B of this part in a timely and effective manner. 195.402(c)(2)
(3) Operating, maintaining, and repairing the pipeline system in accordance with each of the requirements of this subpart and subpart H of this part. 195.402(c)(3)
(4) Determining which pipeline facilities are in areas that would require an immediate response by the operator to prevent hazards to the public, property, or the environment if the facilities failed or malfunctioned, including segments that could affect high-consequence areas (HCA) or are in HCAs, and valves specified in §195.418 or §195.452(i)(4). 195.402(c)(4)
(5) Investigating and analyzing pipeline accidents and failures, including sending the failed pipe, component, or equipment for laboratory testing or examination where appropriate, to determine the cause(s) and contributing factors of the failure and to minimize the possibility of a recurrence. 195.402(c)(5)
(i) Post-failure and -accident lessons learned. Each operator must develop, implement, and incorporate lessons learned from a post-failure and accident review into its written procedures, including in pertinent operator personnel training and qualifications programs, and in design, construction, testing, maintenance, operations, and emergency procedure manuals and specifications.195.402(c)(5)(i)
(ii) Analysis of rupture and valve shut-offs; preventive and mitigative measures. If a failure or accident on an onshore hazardous liquid or carbon dioxide pipeline involves the closure of a rupture-mitigation valve (RMV), as defined in §195.2, or the closure of an alternative equivalent technology, the operator of the pipeline must also conduct a post-failure or -accident analysis of all of the factors that may have impacted the release volume and the consequences of the release and identify and implement operations and maintenance measures to minimize the consequences of a future failure or incident. The analysis must include all relevant factors impacting the release volume and consequences, including, but not limited to, the following: 195.402(c)(5)(ii)
[A] Detection, identification, operational response, system shutoff, and emergency-response communications, based on the type and volume of the release or failure event; 195.402(c)(5)(ii)[A]
[B] Appropriateness and effectiveness of procedures and pipeline systems, including supervisory control and data acquisition (SCADA), communications, valve shut-off, and operator personnel;195.402(c)(5)(ii)[B]
[C] Actual response time from identifying a rupture following a notification of potential rupture, as defined at §195.2, to initiation of mitigative actions and isolation of the segment, and the appropriateness and effectiveness of the mitigative actions taken;195.402(c)(5)(ii)[C]
[D] Location and timeliness of actuation of all RMVs or alternative equivalent technologies; and195.402(c)(5)(ii)[D]
[E] All other factors the operator deems appropriate. 195.402(c)(5)(ii)[E]
(iii) Rupture post-failure and accident summary. If a failure or accident on an onshore hazardous liquid or carbon dioxide pipeline involves the identification of a rupture following a notification of potential rupture; the closure of an RMV, as those terms are defined in §195.2; or the closure of an alternative equivalent technology, the operator must complete a summary of the postfailure or -accident review required by paragraph (c)(5)(ii) of this section within 90 days of the failure or accident. While the investigation is pending, the operator must conduct quarterly status reviews until the investigation is completed and a final post-failure or -accident review is prepared. The final post-failure oraccident summary and all other reviews and analyses produced under the requirements of this section must be reviewed, dated, and signed by the operator's appropriate senior executive officer. An operator must keep, for the useful life of the pipeline, the final post-failure or -accident summary, all investigation and analysis documents used to prepare it, and records of lessons learned.195.402(c)(5)(iii)
(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. 195.402(c)(6)
(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. 195.402(c)(7)
(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. 195.402(c)(8)
(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. 195.402(c)(9)
(10) Abandoning pipeline facilities, including safe disconnection from an operating pipeline system, purging of combustibles, and sealing abandoned facilities left in place to minimize safety and environmental hazards. For each abandoned offshore pipeline facility or each abandoned onshore pipeline facility that crosses over, under or through commercially navigable waterways the last operator of that facility must file a report upon abandonment of that facility in accordance with §195.59 of this part. 195.402(c)(10)
(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. 195.402(c)(11)
(12) Establishing and maintaining adequate means of communication with the appropriate public safety answering point (i.e., 9-1-1 emergency call center), where direct access to a 9-1-1 emergency call center is available from the location of the pipeline, and fire, police, and other public officials. Operators must determine the responsibilities, resources, jurisdictional area(s), and emergency contact telephone numbers for both local and out-of-area calls of each Federal, State, and local government organization that may respond to a pipeline emergency, and inform the officials about the operator's ability to respond to the pipeline emergency and means of communication during emergencies. Operators may establish liaison with the appropriate local emergency coordinating agencies, such as 9-1-1 emergency call centers or county emergency managers, in lieu of communicating individually with each fire, police, or other public entity. 195.402(c)(12)
(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. 195.402(c)(13)
(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. 195.402(c)(14)
(15) Implementing the applicable control room management procedures required by §195.446. 195.402(c)(15)
(d) Abnormal operation. The manual required by paragraph (a) of this section must include procedures for the following to provide safety when operating design limits have been exceeded: 195.402(d)
(1) Responding to, investigating, and correcting the cause of: 195.402(d)(1)
(i) Unintended closure of valves or shutdowns;195.402(d)(1)(i)
(ii) Increase or decrease in pressure or flow rate outside normal operating limits;195.402(d)(1)(ii)
(iii) Loss of communications;195.402(d)(1)(iii)
(iv) Operation of any safety device;195.402(d)(1)(iv)
(v) Any other malfunction of a component, deviation from normal operation, or personnel error which could cause a hazard to persons or property.195.402(d)(1)(v)
(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. 195.402(d)(2)
(3) Correcting variations from normal operation of pressure and flow equipment and controls. 195.402(d)(3)
(4) Notifying responsible operator personnel when notice of an abnormal operation is received. 195.402(d)(4)
(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. 195.402(d)(5)
(e) Emergencies. The manual required by paragraph (a) of this section must include procedures for the following to provide safety when an emergency condition occurs: 195.402(e)
(1) Receiving, identifying, and classifying notices of events that need immediate response by the operator or notice to the appropriate public safety answering point (i.e., 9-1-1 emergency call center), where direct access to a 9-1-1 emergency call center is available from the location of the pipeline, and fire, police, and other appropriate public officials, and communicating this information to appropriate operator personnel for prompt corrective action. Operators may establish liaison with the appropriate local emergency coordinating agencies, such as 9-1-1 emergency call centers or county emergency managers, in lieu of communicating individually with each fire, police, or other public entity. 195.402(e)(1)
(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. 195.402(e)(2)
(3) Having personnel, equipment, instruments, tools, and material available as needed at the scene of an emergency. 195.402(e)(3)
(4) Taking necessary actions, including but not limited to, emergency shutdown, valve shut-off, or pressure reduction, in any section of the operator's pipeline system, to minimize hazards of released hazardous liquid or carbon dioxide to life, property, or the environment. Each operator must also develop written rupture identification procedures to evaluate and identify whether a notification of potential rupture, as defined in §195.2, is an actual rupture event or non-rupture event. These procedures must, at a minimum, specify the sources of information, operational factors, and other criteria that operator personnel use to evaluate a notification of potential rupture, as defined at §195.2. For operators installing valves in accordance with §195.258(c), §195.258(d), or that are subject to the requirements in §195.418, those procedures should provide for rupture identification as soon as practicable. 195.402(e)(4)
(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. 195.402(e)(5)
(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. 195.402(e)(6)
(7) Notifying the appropriate public safety answering point (i.e., 91-1 emergency call center), where direct access to a 9-1-1 emergency call center is available from the location of the pipeline, and fire, police, and other public officials, of hazardous liquid or carbon dioxide pipeline emergencies to coordinate and share information to determine the location of the release, including both planned responses and actual responses during an emergency, and any additional precautions necessary for an emergency involving a pipeline transporting a highly volatile liquid (HVL). The operator must immediately and directly notify the appropriate public safety answering point or other coordinating agency for the communities and jurisdiction(s) in which the pipeline is located after notification of potential rupture, as defined at §195.2, has occurred to coordinate and share information to determine the location of the release, regardless of whether the segment is subject to the requirements of §195.258 (c) or (d), §195.418, or §195.419. 195.402(e)(7)
(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. 195.402(e)(8)
(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. 195.402(e)(9)
(10) Actions required to be taken by a controller during an emergency, in accordance with the operator's emergency plans and §§195.418 and 195.446. 195.402(e)(10)
(f) Safety-related condition reports. The manual required by paragraph (a) of this section must include 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 §195.55. 195.402(f)
Advisory Bulletin: Clarification of Terms Relating to Pipeline Operational Status.
Question 1: Do PHMSA regulations recognize an "idle" status for a hazardous liquid or gas pipelines?
PHMSA regulations do not recognize an "idle" status for a hazardous liquid or gas pipelines. The regulations consider pipelines to be
either active and fully subject to all parts of the safety regulations or abandoned. The process and requirements for pipeline abandonment are captured in §§192.727 and 195.402(c)(10) for gas and hazardous liquid pipelines, respectively. Pipelines abandoned after the effective date of the regulations must comply with requirements to purge all combustibles and seal any facilities left in place. The last owner or operator of abandoned offshore facilities and abandoned onshore facilities that cross over, under, or through commercially navigable waterways must file a report with PHMSA. PHMSA regulations define the term "abandoned" to mean permanently removed from service.
Companies that own pipelines abandoned prior to the effective date of the abandonment regulations may not have access to records relating to where these pipelines are located or whether they were properly purged of combustibles and sealed. To the extent feasible, owners and operators have a responsibility to assure facilities for which they are responsible or last owned do not present a hazard to people, property or the environment.
Pipelines not currently in operation are sometimes informally referred to as "idled", "inactive", or "decommissioned". These pipelines may be shut down and still contain hazardous liquids or gas. Usually, the mainline valves on these pipelines are closed, isolating them from other pipeline segments. If a pipeline is not properly abandoned and may be used in the future for transportation of hazardous liquid or gas, PHMSA regulations consider it as an active pipeline. Owners and operators of pipelines that are not operating but contain hazardous liquids and gas must comply with all applicable safety requirements, including periodic maintenance, integrity management assessments, damage prevention programs, response planning, and public awareness programs.
PHMSA is aware that some owners and operators may properly purge a pipeline of combustibles with the expectation to later use that pipeline in hazardous materials transportation. A purged pipeline presents different risks, and therefore different regulatory treatment may be appropriate. Degradation of such a pipeline can occur, but is not likely to result in significant safety impacts to people, property, or the environment. PHMSA will accept deferral of certain activities for purged but active pipelines. These deferred activities might include actions impractical on most purged pipelines, such as in-line inspection. PHMSA is considering proposing procedures in a future rulemaking that would address methods owners or operators could use to notify regulators of purged but active pipelines. In the interim, owners or operators planning to defer certain activities for purged pipelines should coordinate the deferral in advance with regulators. All deferred activities must be completed prior to, or as part of, any later return-to-service. Pipeline owners and operators are fully responsible for the safety of their pipeline facilities at all times and during all operational statuses.
§195.403 Emergency response training
(a) Each operator shall establish and conduct a continuing training program to instruct emergency response personnel to: 195.403(a)
(1) Carry out the emergency procedures established under 195.402 that relate to their assignments; 195.403(a)(1)
(2) Know the characteristics and hazards of the hazardous liquids or carbon dioxide transported, including, in case of flammable HVL, flammability of mixtures with air, odorless vapors, and water reactions; 195.403(a)(2)
(3) Recognize conditions that are likely to cause emergencies, predict the consequences of facility malfunctions or failures and hazardous liquids or carbon dioxide spills, and take appropriate corrective action; 195.403(a)(3)
(4) Take steps necessary to control any accidental release of hazardous liquid or carbon dioxide and to minimize the potential for fire, explosion, toxicity, or environmental damage; and 195.403(a)(4)
(5) Learn the potential causes, types, sizes, and consequences of fire and the appropriate use of portable fire extinguishers and other on-site fire control equipment, involving, where feasible, a simulated pipeline emergency condition. 195.403(a)(5)
(b) At the intervals not exceeding 15 months, but at least once each calendar year, each operator shall: 195.403(b)
(1) Review with personnel their performance in meeting the objectives of the emergency response training program set forth in paragraph (a) of this section; and 195.403(b)(1)
(2) Make appropriate changes to the emergency response training program as necessary to ensure that it is effective. 195.403(b)(2)
(c) Each operator shall require and verify that its supervisors maintain a thorough knowledge of that portion of the emergency response procedures established under 195.402 for which they are responsible to ensure compliance. 195.403(c)
§195.404 Maps and records
(a) Each operator shall maintain current maps and records of its pipeline systems that include at least the following information: 195.404(a)
(1) Location and identification of the following pipeline facilities: 195.404(a)(1)
(i) Breakout tanks;195.404(a)(1)(i)
(ii) Pump stations;195.404(a)(1)(ii)
(iii) Scraper and sphere facilities;195.404(a)(1)(iii)
(iv) Pipeline valves;195.404(a)(1)(iv)
(v) Facilities to which §195.402(c)(9) applies;195.404(a)(1)(v)
(vi) Rights-of-way; and195.404(a)(1)(vi)
(vii) Safety devices to which §195.428 applies.195.404(a)(1)(vii)
(2) All crossings of public roads, railroads, rivers, buried utilities, and foreign pipelines. 195.404(a)(2)
(3) The maximum operating pressure of each pipeline. 195.404(a)(3)
(4) The diameter, grade, type, and nominal wall thickness of all pipe. 195.404(a)(4)
(b) Each operator shall maintain for at least 3 years daily operating records that indicate — 195.404(b)
(1) The discharge pressure at each pump station; and195.404(b)(1)
(2) Any emergency or abnormal operation to which the procedures under §195.402 apply. 195.404(b)(2)
(c) Each operator shall maintain the following records for the periods specified: 195.404(c)
(1) The date, location, and description of each repair made to pipe shall be maintained for the useful life of the pipe. 195.404(c)(1)
(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. 195.404(c)(2)
(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. 195.404(c)(3)
§195.405 Protection against ignitions and safe access/ egress involving floating roofs
(a) After October 2, 2000, protection provided against ignitions arising out of static electricity, lightning, and stray currents during operation and maintenance activities involving aboveground breakout tanks must be in accordance with API RP 2003 (incorporated by reference, see §195.3), unless the operator notes in the procedural manual §195.402(c)) why compliance with all or certain provisions of API RP 2003 is not necessary for the safety of a particular breakout tank. 195.405(a)
(b) The hazards associated with access/egress onto floating roofs of in-service aboveground breakout tanks to perform inspection, service, maintenance, or repair activities (other than specified general considerations, specified routine tasks or entering tanks removed from service for cleaning) are addressed in API Pub 2026 (incorporated by reference, see §195.3). After October 2, 2000, the operator must review and consider the potentially hazardous conditions, safety practices, and procedures in API Pub 2026 for inclusion in the procedure manual §195.402(c)). 195.405(b)
§195.406 Maximum operating pressure
(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: 195.406(a)
(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: 195.406(a)(1)
(i) Eighty percent of the first test pressure that produces yield under section N5.0 of appendix N of ASME/ANSI B31.8 (incorporated by reference, see §195.3), reduced by the appropriate factors in §§195.106 (a) and (e); or195.406(a)(1)(i)
(ii) If the pipe is 12 3⁄4 inch (324 mm) or less outside diameter and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa) gage.195.406(a)(1)(ii)
(2) The design pressure of any other component of the pipeline. 195.406(a)(2)
(3) Eighty percent of the test pressure for any part of the pipeline which has been pressure tested under subpart E of this part. 195.406(a)(3)
(4) Eighty percent of the factory test pressure or of the prototype test pressure for any individually installed component which is excepted from testing under §195.305. 195.406(a)(4)
(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 pipe-
line 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. 195.406(a)(5)
(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. 195.406(b)
§195.408 Communications
(a) Each operator must have a communication system to provide for the transmission of information needed for the safe operation of its pipeline system. 195.408(a)
(b) The communication system required by paragraph (a) of this section must, as a minimum, include means for: 195.408(b)
(1) Monitoring operational data as required by §195.402(c)(9); 195.408(b)(1)
(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; 195.408(b)(2)
(3) Conducting two-way vocal communication between a control center and the scene of abnormal operations and emergencies; and 195.408(b)(3)
(4) Providing communication with fire, police, and other appropriate public officials during emergency conditions, including a natural disaster. 195.408(b)(4)
§195.410
Line markers
(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: 195.410(a)
(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. 195.410(a)(1)
(2) The marker must state at least the following on a background of sharply contrasting color: 195.410(a)(2)
(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 1⁄4 inch (6.4 millimeters).195.410(a)(2)(i)
(ii) The name of the operator and a telephone number (including area code) where the operator can be reached at all times. 195.410(a)(2)(ii)
(b) Line markers are not required for buried pipelines located — 195.410(b)
(1) Offshore or at crossings of or under waterways and other bodies of water; or 195.410(b)(1)
(2) In heavily developed urban areas such as downtown business centers where — 195.410(b)(2)
(i) The placement of markers is impractical and would not serve the purpose for which markers are intended; and195.410(b)(2)(i)
(ii) The local government maintains current substructure records. 195.410(b)(2)(ii)
(c) Each operator shall provide line marking at locations where the line is above ground in areas that are accessible to the public. 195.410(c)
§195.412 Inspection of rights-of-way and crossings under navigable waters
(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-ofway. 195.412(a)
(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. 195.412(b)
§195.413
Underwater inspection and reburial of pipelines in the Gulf of Mexico and its inlets
(a) Except for gathering lines of 41⁄2 inches (114mm) nominal outside diameter or smaller, each operator shall prepare and follow a procedure to identify its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water that are at risk of being an exposed underwater pipeline or a hazard to navigation. The procedures must be in effect August 10, 2005. 195.413(a)
(b) Each operator shall conduct appropriate periodic underwater inspections of its pipelines in the Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from mean low water based on the identified risk. 195.413(b)
(c) If an operator discovers that its pipeline is an exposed underwater pipeline or poses a hazard to navigation, the operator shall — 195.413(c)
(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. 195.413(c)(1)
(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 195.413(c)(2)
(3) Within 6 months after discovery, or not later than November 1 of the following year if the 6 month period is later than November 1 of the year of discovery, bury the pipeline so that the top of the pipe is 36 inches (914 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) for normal excavation or 18 inches (457 millimeters) for rock excavation. 195.413(c)(3)
(i) An operator may employ engineered alternatives to burial that meet or exceed the level of protection provided by burial. 195.413(c)(3)(i)
(ii) If an operator cannot obtain required state or Federal permits in time to comply with this section, it must notify OPS; specify whether the required permit is State or Federal; and, justify the delay.195.413(c)(3)(ii)
§195.414 Inspections of pipelines in areas affected by extreme weather and natural disasters
(a) General. Following an extreme weather event or natural disaster that has the likelihood of damage to infrastructure by the scouring or movement of the soil surrounding the pipeline, such as a named tropical storm or hurricane; a flood that exceeds the river, shoreline, or creek high-water banks in the area of the pipeline; a landslide in the area of the pipeline; or an earthquake in the area of the pipeline, an operator must inspect all potentially affected pipeline facilities to detect conditions that could adversely affect the safe operation of that pipeline. 195.414(a)
(b) Inspection method. An operator must consider the nature of the event and the physical characteristics, operating conditions, location, and prior history of the affected pipeline in determining the appropriate method for performing the initial inspection to determine the extent of any damage and the need for the additional assessments required under paragraph (a) of this section. 195.414(b)
(c) Time period. The inspection required under paragraph (a) of this section must commence within 72 hours after the cessation of the event, defined as the point in time when the affected area can be safely accessed by the personnel and equipment required to perform the inspection as determined under paragraph (b) of this section. In the event that the operator is unable to commence the inspection due to the unavailability of personnel or equipment, the operator must notify the appropriate PHMSA Region Director as soon as practicable. 195.414(c)
(d) Remedial action. An operator must take prompt and appropriate remedial action to ensure the safe operation of a pipeline based on the information obtained as a result of performing the inspection required under paragraph (a) of this section. Such actions might include, but are not limited to: 195.414(d)
(1) Reducing the operating pressure or shutting down the pipeline; 195.414(d)(1)
(2) Modifying, repairing, or replacing any damaged pipeline facilities; 195.414(d)(2)
(3) Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right-of-way; 195.414(d)(3)
(4) Performing additional patrols, surveys, tests, or inspections; 195.414(d)(4)
(5) Implementing emergency response activities with Federal, State, or local personnel; and 195.414(d)(5)
(6) Notifying affected communities of the steps that can be taken to ensure public safety. 195.414(d)(6)
§195.415 [Reserved]
§195.416 Pipeline assessments
(a) Scope. This section applies to onshore line pipe that can accommodate inspection by means of in-line inspection tools and is not subject to the integrity management requirements in §195.452. 195.416(a)
(b) General. An operator must perform an initial assessment of each of its pipeline segments by October 1, 2029, and perform periodic assessments of its pipeline segments at least once every 10 calendar years from the year of the prior assessment or as otherwise necessary to ensure public safety or the protection of the environment. 195.416(b)
(c) Method. Except as specified in paragraph (d) of this section, an operator must perform the integrity assessment for the range of relevant threats to the pipeline segment by the use of an appropriate in-line inspection tool(s). When performing an assessment using an in-line inspection tool, an operator must comply with §195.591. An operator must explicitly consider uncertainties in reported results (including tool tolerance, anomaly findings, and unity chart plots or other equivalent methods for determining uncertainties) in identifying anomalies. If this is impracticable based on operational limits, including operating pressure, low flow, and pipeline length or availability of in-line inspection tool technology for the pipe diameter, then the operator must perform the assessment using the appropriate method(s) in paragraphs (c)(1), (2), or (3) of this section for the range of relevant threats being assessed. The methods an operator selects to assess low-frequency electric resistance welded pipe, pipe with a seam factor less than 1.0 as defined in §195.106(e) or lap-welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity, cracking, and of detecting corrosion and deformation anomalies. The following alternative assessment methods may be used as specified in this paragraph: 195.416(c)
(1) A pressure test conducted in accordance with subpart E of this part; 195.416(c)(1)
(2) External corrosion direct assessment in accordance with §195.588; or 195.416(c)(2)
(3) Other technology in accordance with paragraph (d).195.416(c)(3)
(d) Other technology. Operators may elect to use other technologies if the operator can demonstrate the technology can provide an equivalent understanding of the condition of the line pipe for threat being assessed. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 90 days before conducting the assessment by: 195.416(d)
(1) Sending the notification, along with the information required to demonstrate compliance with this paragraph, to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590; or 195.416(d)(1)
(2) Sending the notification, along with the information required to demonstrate compliance with this paragraph, to the Information Resources Manager by facsimile to (202) 366-7128. 195.416(d)(2)
(3) Prior to conducting the “other technology” assessments, the operator must receive a notice of “no objection” from the PHMSA Information Services Manager or Designee. 195.416(d)(3)
(e) Data analysis. A person qualified by knowledge, training, and experience must analyze the data obtained from an assessment performed under paragraph (b) of this section to determine if a condition could adversely affect the safe operation of the pipeline. Operators must consider uncertainties in any reported results (including tool tolerance) as part of that analysis. 195.416(e)
(f) Discovery of condition. For purposes of §195.401(b)(1), discovery of a condition occurs when an operator has adequate information to determine that a condition presenting a potential threat to the integrity of the pipeline exists. An operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition to make that determination required under paragraph (e) of this section, unless the operator can demonstrate the 180-day interval is impracticable. If the operator believes that 180 days are impracticable to make a determination about a condition found during an assessment, the pipeline operator must notify PHMSA and provide an expected date when adequate information will become available. This notification must be made in accordance with §195.452 (m). 195.416(f)
(g) Remediation. An operator must comply with the requirements in §195.401 if a condition that could adversely affect the safe operation of a pipeline is discovered in complying with paragraphs (e) and (f) of this section. 195.416(g)
(h) Consideration of information. An operator must consider all relevant information about a pipeline in complying with the requirements in paragraphs (a) through (g) of this section. 195.416(h)
§195.417 Notification of potential rupture
(a) As used in this part, a notification of potential rupture means refers to the notification to, or observation by, an operator (e.g., by or to its controller(s) in a control room, field personnel, nearby pipeline or utility personnel, the public, local responders, or public authorities) of one or more of the below indicia of a potential unintentional or uncontrolled release of a large volume of hazardous liquids from a pipeline: 195.417(a)
(1) An unanticipated or unexplained pressure loss outside of the pipeline's normal operating pressures, as defined in the operator's written procedures. The operator must establish in its written procedures that an unanticipated or unplanned pressure loss is outside of the pipeline's normal operating pressures when there is a
pressure loss greater than 10 percent occurring within a time interval of 15 minutes or less, unless the operator has documented in its written procedures the operational need for a greater pressurechange threshold due to pipeline flow dynamics (including changes in operating pressure, flow rate, or volume), that are caused by fluctuations in product demand, receipts, or deliveries; 195.417(a)(1)
(2) An unanticipated or unexplained flow rate change, pressure change, equipment function, or other pipeline instrumentation indication at the upstream or downstream station that may be representative of an event meeting paragraph (a)(1) of this section; or 195.417(a)(2)
(3) Any unanticipated or unexplained rapid release of a large volume of hazardous liquid, a fire, or an explosion, in the immediate vicinity of the pipeline. 195.417(a)(3)
(b) A notification of potential rupture occurs when an operator first receives notice of or observes an event specified in paragraph (a) of this section. 195.417(b)
§195.418 Valves: Onshore valve shut-off for rupture mitigation.
(a) Applicability. For newly constructed and entirely replaced onshore hazardous liquid or carbon dioxide pipeline segments, as defined at §195.2, with diameters of 6 inches or greater that could affect high-consequence areas or are located in high consequence areas (HCA), and that have been installed after April 10, 2023, an operator must install or use existing rupture-mitigation valves (RMV), as defined at §195.2, or alternative equivalent technologies according to the requirements of this section and §195.419. RMVs and alternative equivalent technologies must be operational within 14 days of placing the new or replaced pipeline segment in service. An operator may request an extension of this 14-day operation requirement if it can demonstrate to PHMSA, in accordance with the notification procedures in §195.18, that application of that requirement would be economically, technically, or operationally infeasible. The requirements of this section apply to all applicable pipe replacements, even those that do not otherwise directly involve the addition or replacement of a valve. 195.418(a)
(b) Maximum spacing between valves. RMVs and alternative equivalent technology must be installed in accordance with the following requirements: 195.418(b)
(1) Shut-off Segment. For purposes of this section, a “shut-off segment” means the segment of pipeline located between the upstream valve closest to the upstream endpoint of the replaced pipeline segment in the HCA or the pipeline segment that could affect an HCA and the downstream valve closest to the downstream endpoint of the replaced pipeline segment of the HCA or the pipeline segment that could affect an HCA so that the entirety of the segment that could affect the HCA or the segment within the HCA is between at least two RMVs or alternative equivalent technologies. If any crossover or lateral pipe for commodity receipts or deliveries connects to the replaced segment between the upstream and downstream valves, the shut-off segment also extends to a valve on the crossover connection(s) or lateral(s), such that, when all valves are closed, there is no flow path for commodity to be transported to the rupture site (except for residual liquids already in the shut-off segment). Multiple segments that could affect HCAs or are in HCAs may be contained within a single shut-off segment. All entirely replaced onshore hazardous liquid or carbon dioxide pipeline segments, as defined in §195.2, that could affect or are in an HCA must include a minimum of one valve that meets the requirements of this section and section 195.419. The operator is not required to select the closest valve to the shut-off segment as the RMV or alternative equivalent technology. An operator may use a manual pump station valve at a continuously manned station as an alternative equivalent technology. Such a manual valve used as an alternative equivalent technology would not require a notification to PHMSA in accordance with §195.18. 195.418(b)(1)
(2) Shut-off segment valve spacing. Pipeline segments subject to paragraph (a) of this section must be protected on the upstream and downstream side with RMVs or alternative equivalent technologies. The distance between RMVs or alternative equivalent technologies must not exceed: 195.418(b)(2)
(i) For pipeline segments carrying non-highly volatile liquids (HVL): 15 miles, with a maximum distance not to exceed 71⁄2 miles from the endpoints of a shut-off segment: or 195.418(b)(2)(i)
(ii) For pipeline segments carrying HVLs: 71⁄2 miles. The maximum valve spacing intervals for these valves may be increased by 1.25 times the spacing distance, up to a 93⁄8-mile spacing at an endpoint, provided the operator notify PHMSA in accordance with §195.260 (g). 195.418(b)(2)(ii)
(3) Laterals. Laterals extending from shut-off segments that contribute less than 5 percent of the total shut-off segment volume may have RMVs or alternative equivalent technologies that meet the actuation requirements of this section at locations other than main-
line receipt/delivery points, as long as all of these laterals contributing hazardous liquid volumes to the shut-off segment do not contribute more than 5 percent of the total shut-off segment volume, based upon maximum flow volume at the operating pressure. A check valve may be used as an alternative equivalent technology where it is positioned to stop flow into the lateral. Check valves used as an alternative equivalent technology in accordance with this paragraph are not subject to §195.419 but must be inspected, operated, and remediated in accordance with §195.420, including for closure and leakage, to ensure operational reliability. An operator using a such a valve as an alternative equivalent technology must submit a request to PHMSA in accordance with §195.18. 195.418(b)(3)
(4) Crossovers. An operator may use a manual valve as an alternative equivalent technology for a crossover connection if, during normal operations, the valve is closed to prevent the flow of hazardous liquid or carbon dioxide with a locking device or other means designed to prevent the opening of the valve by persons other than those authorized by the operator. The operator must document that the valve has been closed and locked in accordance with the operator's lock-out and tag-out procedures to prevent the flow of hazardous liquid or carbon dioxide. An operator using a such a valve as an alternative equivalent technology must submit a request to PHMSA in accordance with §195.18. 195.418(b)(4)
(c) Manual operation upon identification of a rupture. Operators using a manual valve as an alternative equivalent technology pursuant to paragraph (a) of this section must develop and implement operating procedures and appropriately designate and locate nearby personnel to ensure valve shut-off in accordance with this section and §195.419. Manual operation of valves must include time for the assembly of necessary operating personnel, the acquisition of necessary tools and equipment, driving time under heavy traffic conditions and at the posted speed limit, walking time to access the valve, and time to manually shut off all valves, not to exceed the response time in §195.419(b). 195.418(c)
§195.419
Valve capabilities
(a) Scope. The requirements in this section apply to rupture-mitigation valves (RMV), as defined in §195.2, or alternative equivalent technology, installed pursuant to §§195.258 and 195.418. 195.419(a)
(b) Rupture identification and valve shut-off time. If an operator observes or is notified of a release of hazardous liquid or carbon dioxide that may be representative of an unintentional or uncontrolled release event meeting a notification of potential rupture (see §§195.2 and 195.417), including any unexplained flow rate changes, pressure changes, equipment functions, or other pipeline instrumentation indications observed by the operator, the operator must, as soon as practicable but within 30 minutes of rupture identification (see §195.402(e)(4)), identify the rupture and fully close any RMVs or alternative equivalent technologies necessary to minimize the volume of hazardous liquid or carbon dioxide released from a pipeline and mitigate the consequences of a rupture. 195.419(b)
(c) Valve shut-off capability. A valve must have the actuation capability necessary to close an RMV or alternative equivalent technology to mitigate the consequences of a rupture in accordance with the requirements of this section. 195.419(c)
(d) Valve monitoring and operational capabilities. An RMV, as defined in §195.2, or alternative equivalent technology, must be capable of being monitored or controlled by either remote or onsite personnel as follows: 195.419(d)
(1) Operated during normal, abnormal, and emergency operating conditions; 195.419(d)(1)
(2) Monitored for valve status (i.e., open, closed, or partial closed/ open), upstream pressure, and downstream pressure. For automatic shut-off valves (ASV), an operator does not need to monitor remotely a valve's status if the operator has the capability to monitor pressures or flow rate within each pipeline segment located between RMVs or alternative equivalent technologies to identify and locate a rupture. Pipeline segments that use an alternative equivalent technology must have the capability to monitor pressures and hazardous liquid or carbon dioxide flow rates on the pipeline in order to identify and locate a rupture; and 195.419(d)(2)
(3) Have a back-up power source to maintain supervisory control and data acquisition (SCADA) systems or other remote communications for remote-control valve (RCV) or ASV operational status or be monitored and controlled by on-site personnel. 195.419(d)(3)
(e) Monitoring of valve shut-off response status. The position and operational status of an RMV must be appropriately monitored through electronic communication with remote instrumentation or other equivalent means. An operator does not need to monitor remotely an ASV's status if the operator has the capability to monitor pressures or hazardous liquid or carbon dioxide s flow rate on the pipeline to identify and locate a rupture. 195.419(e)
(f) Flow modeling for automatic shut-off valves. Prior to using an ASV as an RMV, the operator must conduct flow modeling for the shutoff segment and any laterals that feed the shut-off segment, so that the valve will close within 30 minutes or less following rupture identification, consistent with the operator's procedures, and in accordance with §195.2 and this section. The flow modeling must include the anticipated maximum, normal, or any other flow volumes, pressures, or other operating conditions that may be encountered during the year, not to exceed a period of 15 months, and it must be modeled for the flow between the RMVs or alternative equivalent technologies, and any looped pipelines or hazardous liquid or carbon dioxide receipt tie-ins. If operating conditions change that could affect the ASV set pressures and the 30-minute valve closure time following a notification of potential rupture, as defined at §195.2, an operator must conduct a new flow model and reset the ASV set pressures prior to the next review for ASV set pressures in accordance with §195.420. The flow model must include a time/pressure chart for the segment containing the ASV if a rupture event occurs. An operator must conduct this flow modeling prior to making flow condition changes in a manner that could render the 30-minute valve closure time unachievable. 195.419(f)
(g) Pipelines not affecting HCAs. For pipeline segments that are not in a high-consequence area (HCA) or that could not affect an HCA, an operator submitting a notification pursuant to §§195.18 and 195.258 for use of manual valves as an alternative equivalent technology may also request an exemption from the valve operation requirements of §195.419(b). 195.419(g)
§195.420 Valve maintenance
(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. 195.420(a)
(b) Each operator must, at least twice each calendar year, but at intervals not exceeding 71⁄2 months, inspect each valve to determine that it is functioning properly. Each rupture-mitigation valve (RMV), as defined in §195.2, or alternative equivalent technology that is installed under §195.258(c) or §195.418, must also be partially operated. Operators are not required to close the valve fully during the drill; a minimum 25 percent valve closure is sufficient to demonstrate compliance, unless the operator has operational information that requires an additional closure percentage for maintaining reliability. 195.420(b)
(c) Each operator shall provide protection for each valve from unauthorized operation and from vandalism. 195.420(c)
(d) For each remote-control valve (RCV) installed in accordance with §195.258(c) or §195.418, an operator must conduct a point-to-point verification between SCADA system displays and the installed valves, sensors, and communications equipment, in accordance with §195.446(c) and (e). 195.420(d)
(e) For each alternative equivalent technology installed under §195.258(c) or (d) or §195.418(a) that is manually or locally operated (i.e., not an RMV, as that term is defined in §195.2): 195.420(e)
(1) Operators must achieve a response time of 30 minutes or less, as required by §195.419(b), through an initial drill and through periodic validation as required by paragraph (e)(2) of this section. An operator must review each phase of the drill response and document the results to validate the total response time, including the identification of a rupture, and valve shut-off time as being less than or equal to 30 minutes after rupture identification. 195.420(e)(1)
(2) Within each pipeline system, and within each operating or maintenance field work unit, operators must randomly select an authorized rupture-mitigation alternative equivalent technology for an annual 30-minute-total response time validation drill simulating worst-case conditions for that location to ensure compliance with §195.419. Operators are not required to close the alternative equivalent technology fully during the drill; a minimum 25 percent valve closure is sufficient to demonstrate compliance with the drill requirements unless the operator has operational information that requires an additional closure percentage for maintaining reliability. The response drill must occur at least once each calendar year, at intervals not to exceed 15 months. Operators must include in their written procedures the method they use to randomly select which alternative equivalent technology is tested in accordance with this paragraph. 195.420(e)(2)
(3) If the 30-minute-maximum response time cannot be achieved in the drill, the operator must revise response efforts to achieve compliance with §195.419 no later than 12 months after the drill. Alternative valve shut-off measures must be in accordance with paragraph (f) of this section within 7 days of the drill. 195.420(e)(3)
(4) Based on the results of the response-time drills, the operator must include lessons learned in: 195.420(e)(4)
(i) Training and qualifications programs; 195.420(e)(4)(i)
(ii) Design, construction, testing, maintenance, operating, and emergency procedures manuals; and 195.420(e)(4)(ii)
(iii) Any other areas identified by the operator as needing improvement. 195.420(e)(4)(iii)
(f) Each operator must implement remedial measures as follows to correct any valve installed on an onshore pipeline in accordance with §195.258(c), or an RMV or alternative equivalent technology installed in accordance with §195.418, that is indicated to be inoperable or unable to maintain effective shut-off: 195.420(f)
(1) Repair or replace the valve as soon as practicable but no later than 12 months after finding that the valve is inoperable or unable to maintain shut-off. An operator may request an extension of the compliance deadline requirements of this section if it can demonstrate to PHMSA, in accordance with the notification procedures in §195.18, that repairing or replacing a valve within 12 months would be economically, technically, or operationally infeasible; and 195.420(f)(1)
(2) Designate an alternative compliant valve within 7 calendar days of the finding while repairs are being made and document an interim response plan to maintain safety. Alternative compliant valves are not required to comply with valve spacing requirements of this part. 195.420(f)(2)
(g) An operator using an ASV as an RMV, in accordance with §§195.2, 195.260, 195.418, and 195.419, must document, in accordance with §195.419(f), and confirm the ASV shut-in pressures on a calendar year basis not to exceed 15 months. ASV shut-in set pressures must be proven and reset individually at each ASV, as required by §195.419(f), at least each calendar year, but at intervals not to exceed 15 months. 195.420(g)
§195.422 Pipeline repairs
(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. 195.422(a)
(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. 195.422(b)
§195.424 Pipe movement
(a) No operator may move any line pipe, unless the pressure in the line section involved is reduced to not more than 50 percent of the maximum operating pressure. 195.424(a)
(b) No operator may move any pipeline containing highly volatile liquids where materials in the line section involved are joined by welding unless — 195.424(b)
(1) Movement when the pipeline does not contain highly volatile liquids is impractical; 195.424(b)(1)
(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 195.424(b)(2)
(3) The pressure in that line section is reduced to the lower of the following: 195.424(b)(3)
(i) Fifty percent or less of the maximum operating pressure; or 195.424(b)(3)(i)
(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.195.424(b)(3)(ii)
(c) No operator may move any pipeline containing highly volatile liquids where materials in the line section involved are not joined by welding unless — 195.424(c)
(1) The operator complies with paragraphs (b) (1) and (2) of this section; and 195.424(c)(1)
(2) That line section is isolated to prevent the flow of highly volatile liquid. 195.424(c)(2)
§195.426 Scraper and sphere facilities
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.
§195.428 Overpressure safety devices and overfill protection systems
(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 71⁄2 months, but at least twice each calendar year, inspect and test each pressure limiting device, relief valve, pressure regulator, or other item of pressure control equipment
to determine that it is functioning properly, is in good mechanical condition, and is adequate from the standpoint of capacity and reliability of operation for the service in which it is used. 195.428(a)
(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. 195.428(b)
(c) Aboveground breakout tanks that are constructed or significantly altered according to API Std 2510 (incorporated by reference, see §195.3) after October 2, 2000, must have an overfill protection system installed according to API Std 2510, section 7.1.2. Other aboveground breakout tanks with 600 gallons (2271 liters) or more of storage capacity that are constructed or significantly altered after October 2, 2000, must have an overfill protection system installed according to API RP 2350 (incorporated by reference, see §195.3). However, an operator need not comply with any part of API RP 2350 for a particular breakout tank if the operator describes in the manual required by §195.402 why compliance with that part is not necessary for safety of the tank. 195.428(c)
(d) After October 2, 2000, the requirements of paragraphs (a) and (b) of this section for inspection and testing of pressure control equipment apply to the inspection and testing of overfill protection systems. 195.428(d)
§195.430
Firefighting equipment
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; 195.430(a)
(b) Plainly marked so that its identity as firefighting equipment is clear; and 195.430(b)
(c) Located so that it is easily accessible during a fire. 195.430(c)
§195.432 Inspection of in-service breakout tanks
(a) Except for breakout tanks inspected under paragraphs (b) and (c) of this section, each operator shall, at intervals not exceeding 15 months, but at least once each calendar year, inspect each in-service breakout tank. 195.432(a)
(b) Each operator must inspect the physical integrity of in-service atmospheric and low-pressure steel above-ground breakout tanks according to API Std 653 (except section 6.4.3, Alternative Internal Inspection Interval) (incorporated by reference, see §195.3). However, if structural conditions prevent access to the tank bottom, its integrity may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3). The risk-based internal inspection procedures in API Std 653, section 6.4.3 cannot be used to determine the internal inspection interval. 195.432(b)
(1) Operators who established internal inspection intervals based on risk-based inspection procedures prior to March 6, 2015 must reestablish internal inspection intervals based on API Std 653, section 6.4.2 (incorporated by reference, see §195.3). 195.432(b)(1)
(i) If the internal inspection interval was determined by the prior risk-based inspection procedure using API Std 653, section 6.4.3 and the resulting calculation exceeded 20 years, and it has been more than 20 years since an internal inspection was performed, the operator must complete a new internal inspection in accordance with §195.432(b)(1) by January 5, 2017. 195.432(b)(1)(i)
(ii) If the internal inspection interval was determined by the prior risk-based inspection procedure using API Std 653, section 6.4.3 and the resulting calculation was less than or equal to 20 years, and the time since the most recent internal inspection exceeds the re-established inspection interval in accordance with §195.432(b)(1), the operator must complete a new internal inspection by January 5, 2017.195.432(b)(1)(ii)
(iii) If the internal inspection interval was not based upon current engineering and operational information (i.e., actual corrosion rate of floor plates, actual remaining thickness of the floor plates, etc.), the operator must complete a new internal inspection by January 5, 2017 and re-establish a new internal inspection interval in accordance with §195.432(b)(1).195.432(b)(1)(iii)
(2) [Reserved]195.432(b)(2)
(c) Each operator must inspect the physical integrity of in-service steel aboveground breakout tanks built to API Std 2510 (incorporated by reference, see §195.3) according to section 6 of API Std 510 (incorporated by reference, see §195.3). 195.432(c)
(d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin on May 3, 1999, or on the operator's last recorded date of the inspection, whichever is earlier. 195.432(d)
§195.434 Signs
Each operator must maintain signs visible to the public around each pumping station and breakout tank area. Each sign must contain the name of the operator and a telephone number (including area code) where the operator can be reached at all times.
§195.436
Security of facilities
Each operator shall provide protection for each pumping station and breakout tank area and other exposed facility (such as scraper traps) from vandalism and unauthorized entry.
§195.438 Smoking or open flames
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.
§195.440
Public awareness
(a) Each pipeline operator must develop and implement a written continuing public education program that follows the guidance provided in the American Petroleum Institute's (API) Recommended Practice (RP) 1162 (incorporated by reference, see §195.3). 195.440(a)
(b) The operator's program must follow the general program recommendations of API RP 1162 and assess the unique attributes and characteristics of the operator's pipeline and facilities. 195.440(b)
(c) The operator must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162, unless the operator provides justification in its program or procedural manual as to why compliance with all or certain provisions of the recommended practice is not practicable and not necessary for safety. 195.440(c)
(d) The operator's program must specifically include provisions to educate the public, appropriate government organizations, and persons engaged in excavation related activities on: 195.440(d)
(1) Use of a one-call notification system prior to excavation and other damage prevention activities; 195.440(d)(1)
(2) Possible hazards associated with unintended releases from a hazardous liquid or carbon dioxide pipeline facility; 195.440(d)(2)
(3) Physical indications that such a release may have occurred; 195.440(d)(3)
(4) Steps that should be taken for public safety in the event of a hazardous liquid or carbon dioxide pipeline release; and 195.440(d)(4)
(5) Procedures to report such an event.195.440(d)(5)
(e) The program must include activities to advise affected municipalities, school districts, businesses, and residents of pipeline facility locations. 195.440(e)
(f) The program and the media used must be as comprehensive as necessary to reach all areas in which the operator transports hazardous liquid or carbon dioxide. 195.440(f)
(g) The program must be conducted in English and in other languages commonly understood by a significant number and concentration of the non-English speaking population in the operator's area. 195.440(g)
(h) Operators in existence on June 20, 2005, must have completed their written programs no later than June 20, 2006. Upon request, operators must submit their completed programs to PHMSA or, in the case of an intrastate pipeline facility operator, the appropriate State agency. 195.440(h)
(i) The operator's program documentation and evaluation results must be available for periodic review by appropriate regulatory agencies. 195.440(i)
§195.442 Damage prevention program
(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. 195.442(a)
(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. 195.442(b)
(1) The state has adopted a one-call damage prevention program under §198.37 of this chapter; or 195.442(b)(1)
(2) The one-call system:195.442(b)(2)
(i) Is operated in accordance with §198.39 of this chapter; 195.442(b)(2)(i)
(ii) Provides a pipeline operator an opportunity similar to a voluntary participant to have a part in management responsibilities; and195.442(b)(2)(ii)
(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.195.442(b)(2)(iii)
(c) The damage prevention program required by paragraph (a) of this section must, at a minimum: 195.442(c)
(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. 195.442(c)(1)
(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: 195.442(c)(2)
(i) The program's existence and purpose; and195.442(c)(2)(i)
(ii) How to learn the location of underground pipelines before excavation activities are begun.195.442(c)(2)(ii)
(3) Provide a means of receiving and recording notification of planned excavation activities. 195.442(c)(3)
(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. 195.442(c)(4)
(5) Provide for temporary marking of buried pipelines in the area of excavation activity before, as far as practical, the activity begins. 195.442(c)(5)
(6) Provide as follows for inspection of pipelines that an operator has reason to believe could be damaged by excavation activities: 195.442(c)(6)
(i) The inspection must be done as frequently as necessary during and after the activities to verify the integrity of the pipeline; and 195.442(c)(6)(i)
(ii) In the case of blasting, any inspection must include leakage surveys.195.442(c)(6)(ii)
(d) A damage prevention program under this section is not required for the following pipelines: 195.442(d)
(1) Pipelines located offshore.195.442(d)(1)
(2) Pipelines to which access is physically controlled by the operator. 195.442(d)(2)
§195.444 Leak detection
(a) Scope. Except for offshore gathering and regulated rural gathering pipelines, this section applies to all hazardous liquid pipelines transporting liquid in single phase (without gas in the liquid).
(b) General. A pipeline must have an effective system for detecting leaks in accordance with §§195.134 or 195.452, as appropriate. An operator must evaluate the capability of its leak detection system to protect the public, property, and the environment and modify it as necessary to do so. At a minimum, an operator's evaluation must consider the following factors — length and size of the pipeline, type of product carried, the swiftness of leak detection, location of nearest response personnel, and leak history.
(c) CPM leak detection systems. Each computational pipeline monitoring (CPM) leak detection system installed on a hazardous liquid pipeline must comply with API RP 1130 (incorporated by reference, see §195.3) in operating, maintaining, testing, record keeping, and dispatcher training of the system.
§195.446 Control room management
(a) General. This section applies to each operator of a pipeline facility with a controller working in a control room who monitors and controls all or part of a pipeline facility through a SCADA system. Each operator must have and follow written control room management procedures that implement the requirements of this section. The procedures required by this section must be integrated, as appropriate, with the operator's written procedures required by §195.402. An operator must develop the procedures no later than August 1, 2011, and must implement the procedures according to the following schedule. The procedures required by paragraphs (b), (c)(5), (d)(2) and (d)(3), (f) and (g) of this section must be implemented no later than October 1, 2011. The procedures required by paragraphs (c)(1) through (4), (d)(1), (d)(4), and (e) must be implemented no later than August 1, 2012. The training procedures required by paragraph (h) must be implemented no later than August 1, 2012, except that any training required by another paragraph of this section must be implemented no later than the deadline for that paragraph. 195.446(a)
(b) Roles and responsibilities. Each operator must define the roles and responsibilities of a controller during normal, abnormal, and emergency operating conditions. To provide for a controller's prompt and appropriate response to operating conditions, an operator must define each of the following: 195.446(b)
(1) A controller's authority and responsibility to make decisions and take actions during normal operations; 195.446(b)(1)
(2) A controller's role when an abnormal operating condition is detected, even if the controller is not the first to detect the condition, including the controller's responsibility to take specific actions and to communicate with others; 195.446(b)(2)
(3) A controller's role during an emergency, even if the controller is not the first to detect the emergency, including the controller's responsibility to take specific actions and to communicate with others; 195.446(b)(3)
(4) A method of recording controller shift-changes and any hand-over of responsibility between controllers; and 195.446(b)(4)
(5) The roles, responsibilities and qualifications of others who have the authority to direct or supersede the specific technical actions of controllers. 195.446(b)(5)
(c) Provide adequate information. Each operator must provide its controllers with the information, tools, processes and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined by performing each of the following: 195.446(c)
(1) Implement API RP 1165 (incorporated by reference, see §195.3) whenever a SCADA system is added, expanded or replaced, unless the operator demonstrates that certain provisions of API RP 1165 are not practical for the SCADA system used; 195.446(c)(1)
(2) Conduct a point-to-point verification between SCADA displays and related field equipment when field equipment is added or moved and when other changes that affect pipeline safety are made to field equipment or SCADA displays; 195.446(c)(2)
(3) Test and verify an internal communication plan to provide adequate means for manual operation of the pipeline safely, at least once each calendar year, but at intervals not to exceed 15 months; 195.446(c)(3)
(4) Test any backup SCADA systems at least once each calendar year, but at intervals not to exceed 15 months; and 195.446(c)(4)
(5) Implement section 5 of API RP 1168 (incorporated by reference, see §195.3) to establish procedures for when a different controller assumes responsibility, including the content of information to be exchanged. 195.446(c)(5)
(d) Fatigue mitigation. Each operator must implement the following methods to reduce the risk associated with controller fatigue that could inhibit a controller's ability to carry out the roles and responsibilities the operator has defined: 195.446(d)
(1) Establish shift lengths and schedule rotations that provide controllers off-duty time sufficient to achieve eight hours of continuous sleep; 195.446(d)(1)
(2) Educate controllers and supervisors in fatigue mitigation strategies and how off-duty activities contribute to fatigue; 195.446(d)(2)
(3) Train controllers and supervisors to recognize the effects of fatigue; and 195.446(d)(3)
(4) Establish a maximum limit on controller hours-of-service, which may provide for an emergency deviation from the maximum limit if necessary for the safe operation of a pipeline facility. 195.446(d)(4)
(e) Alarm management. Each operator using a SCADA system must have a written alarm management plan to provide for effective controller response to alarms. An operator's plan must include provisions to: 195.446(e)
(1) Review SCADA safety-related alarm operations using a process that ensures alarms are accurate and support safe pipeline operations; 195.446(e)(1)
(2) Identify at least once each calendar month points affecting safety that have been taken off scan in the SCADA host, have had alarms inhibited, generated false alarms, or that have had forced or manual values for periods of time exceeding that required for associated maintenance or operating activities; 195.446(e)(2)
(3) Verify the correct safety-related alarm set-point values and alarm descriptions when associated field instruments are calibrated or changed and at least once each calendar year, but at intervals not to exceed 15 months; 195.446(e)(3)
(4) Review the alarm management plan required by this paragraph at least once each calendar year, but at intervals not exceeding 15 months, to determine the effectiveness of the plan; 195.446(e)(4)
(5) Monitor the content and volume of general activity being directed to and required of each controller at least once each calendar year, but at intervals not exceeding 15 months, that will assure controllers have sufficient time to analyze and react to incoming alarms; and 195.446(e)(5)
(6) Address deficiencies identified through the implementation of paragraphs (e)(1) through (e)(5) of this section. 195.446(e)(6)
(f) Change management. Each operator must assure that changes that could affect control room operations are coordinated with the control room personnel by performing each of the following: 195.446(f)
(1) Implement section 7 of API RP 1168 (incorporated by reference, see §195.3) for control room management change and require coordination between control room representatives, operator's
management, and associated field personnel when planning and implementing physical changes to pipeline equipment or configuration; and 195.446(f)(1)
(2) Require its field personnel to contact the control room when emergency conditions exist and when making field changes that affect control room operations. 195.446(f)(2)
(g) Operating experience. Each operator must assure that lessons learned from its operating experience are incorporated, as appropriate, into its control room management procedures by performing each of the following: 195.446(g)
(1) Review accidents that must be reported pursuant to §195.50 and 195.52 to determine if control room actions contributed to the event and, if so, correct, where necessary, deficiencies related to: 195.446(g)(1)
(i) Controller fatigue;195.446(g)(1)(i)
(ii) Field equipment;195.446(g)(1)(ii)
(iii) The operation of any relief device;195.446(g)(1)(iii)
(iv) Procedures;195.446(g)(1)(iv)
(v) SCADA system configuration; and195.446(g)(1)(v)
(vi) SCADA system performance.195.446(g)(1)(vi)
(2) Include lessons learned from the operator's experience in the training program required by this section. 195.446(g)(2)
(h) Training. Each operator must establish a controller training program and review the training program content to identify potential improvements at least once each calendar year, but at intervals not to exceed 15 months. An operator's program must provide for training each controller to carry out the roles and responsibilities defined by the operator. In addition, the training program must include the following elements: 195.446(h)
(1) Responding to abnormal operating conditions likely to occur simultaneously or in sequence; 195.446(h)(1)
(2) Use of a computerized simulator or non-computerized (tabletop) method for training controllers to recognize abnormal operating conditions; 195.446(h)(2)
(3) Training controllers on their responsibilities for communication under the operator's emergency response procedures; 195.446(h)(3)
(4) Training that will provide a controller a working knowledge of the pipeline system, especially during the development of abnormal operating conditions; 195.446(h)(4)
(5) For pipeline operating setups that are periodically, but infrequently used, providing an opportunity for controllers to review relevant procedures in advance of their application; and 195.446(h)(5)
(6) Control room team training and exercises that include both controllers and other individuals, defined by the operator, who would reasonably be expected to operationally collaborate with controllers (control room personnel) during normal, abnormal or emergency situations. Operators must comply with the team training requirements under this paragraph no later than January 23, 2018. 195.446(h)(6)
(i) Compliance validation. Upon request, operators must submit their procedures to PHMSA or, in the case of an intrastate pipeline facility regulated by a State, to the appropriate State agency. 195.446(i)
(j) Compliance and deviations. An operator must maintain for review during inspection: 195.446(j)
(1) Records that demonstrate compliance with the requirements of this section; and 195.446(j)(1)
(2) Documentation to demonstrate that any deviation from the procedures required by this section was necessary for the safe operation of the pipeline facility. 195.446(j)(2)
HIGH CONSEQUENCE AREAS
§195.450 Definitions
The following definitions apply to this section and §195.452:
Emergency flow restricting device or EFRD means a check valve or remote control valve as follows:
(1) Check valve means a valve that permits fluid to flow freely in one direction and contains a mechanism to automatically prevent flow in the other direction.
(2) Remote control valve or RCV means any valve that is operated from a location remote from where the valve is installed. The RCV is usually operated by the supervisory control and data acquisition (SCADA) system. The linkage between the pipeline control center and the RCV may be by fiber optics, microwave, telephone lines, or satellite.
High consequence area means:
(1) A commercially navigable waterway, which means a waterway where a substantial likelihood of commercial navigation exists;
(2) A high population area, which means an urbanized area, as defined and delineated by the Census Bureau, that contains 50,000 or more people and has a population density of at least 1,000 people per square mile;
(3) An other populated area, which means a place, as defined and delineated by the Census Bureau, that contains a concentrated population, such as an incorporated or unincorporated city, town, village, or other designated residential or commercial area;
(4) An unusually sensitive area, as defined in §195.6.
§195.452 Pipeline integrity management in high consequence areas.
(a) Which pipelines are covered by this section? This section applies to each hazardous liquid pipeline and carbon dioxide pipeline that could affect a high consequence area, including any pipeline located in a high consequence area unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. (Appendix C of this part provides guidance on determining if a pipeline could affect a high consequence area.) Covered pipelines are categorized as follows: 195.452(a)
(1) Category 1 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated a total of 500 or more miles of pipeline subject to this part. 195.452(a)(1)
(2) Category 2 includes pipelines existing on May 29, 2001, that were owned or operated by an operator who owned or operated less than 500 miles of pipeline subject to this part. 195.452(a)(2)
(3) Category 3 includes pipelines constructed or converted after May 29, 2001, and low-stress pipelines in rural areas under §195.12. 195.452(a)(3)
(4) Low stress pipelines as specified in §195.12.195.452(a)(4)
(b) What program and practices must operators use to manage pipeline integrity? Each operator of a pipeline covered by this section must: 195.452(b)
(1) Develop a written integrity management program that addresses the risks on each segment of pipeline in the first column of the following table no later than the date in the second column: 195.452(b)(1)
Pipeline Date
Category 1 March 31, 2002.
Category 2 February 18, 2003.
Category 3
Date the pipeline begins operation or as provided in §195.12 for low stress pipelines in rural areas.
(2) Include in the program an identification of each pipeline or pipeline segment in the first column of the following table not later than the date in the second column: 195.452(b)(2)
Pipeline Date
Category 1 December 31, 2001.
Category 2 November 18, 2002.
Category 3
Date the pipeline begins operation.
(3) Include in the program a plan to carry out baseline assessments of line pipe as required by paragraph (c) of this section. 195.452(b)(3)
(4) Include in the program a framework that — 195.452(b)(4)
(i) Addresses each element of the integrity management program under paragraph (f) of this section, including continual integrity assessment and evaluation under paragraph (j) of this section; and195.452(b)(4)(i)
(ii) Initially indicates how decisions will be made to implement each element.195.452(b)(4)(ii)
(5) Implement and follow the program.195.452(b)(5)
(6) Follow recognized industry practices in carrying out this section, unless — 195.452(b)(6)
(i) This section specifies otherwise; or195.452(b)(6)(i)
(ii) The operator demonstrates that an alternative practice is supported by a reliable engineering evaluation and provides an equivalent level of public safety and environmental protection. 195.452(b)(6)(ii)
(c) What must be in the baseline assessment plan? 195.452(c)
(1) An operator must include each of the following elements in its written baseline assessment plan: 195.452(c)(1)
(i) The methods selected to assess the integrity of the line pipe. An operator must assess the integrity of the line pipe by in-line inspection tool(s) described in paragraph (c)(1)(i)(A) of this section for the range of relevant threats to the pipeline segment. If it is impracticable based upon the construction of the pipeline (e.g., diameter changes, sharp bends, and elbows) or operational limits including operating pressure, low flow, pipeline length, or availability of in-line inspection tool technology for the pipe diameter, then the operator must use the appropriate method(s) in paragraphs (c)(1)(i)(B), (C), or (D) of this section
for the range of relevant threats to the pipeline segment. The methods an operator selects to assess low-frequency electric resistance welded pipe, pipe with a seam factor less than 1.0 as defined in §195.106(e) or lap-welded pipe susceptible to longitudinal seam failure, must be capable of assessing seam integrity, cracking, and of detecting corrosion and deformation anomalies.195.452(c)(1)(i)
[A] In-line inspection tool or tools capable of detecting corrosion and deformation anomalies including dents, gouges, and grooves. For pipeline segments with an identified or probable risk or threat related to cracks (such as at pipe body or weld seams) based on the risk factors specified in paragraph (e), an operator must use an in-line inspection tool or tools capable of detecting crack anomalies. When performing an assessment using an in-line inspection tool, an operator must comply with §195.591. An operator using this method must explicitly consider uncertainties in reported results (including tool tolerance, anomaly findings, and unity chart plots or equivalent for determining uncertainties) in identifying anomalies;195.452(c)(1)(i)[A]
[B] Pressure test conducted in accordance with subpart E of this part;195.452(c)(1)(i)[B]
[C] External corrosion direct assessment in accordance with §195.588; or195.452(c)(1)(i)[C]
[D] Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify the Office of Pipeline Safety (OPS) 90 days before conducting the assessment, by sending a notice to the address or facsimile number specified in paragraph (m) of this section. 195.452(c)(1)(i)[D]
(ii) A schedule for completing the integrity assessment; 195.452(c)(1)(ii)
(iii) An explanation of the assessment methods selected and evaluation of risk factors considered in establishing the assessment schedule.195.452(c)(1)(iii)
(2) An operator must document, prior to implementing any changes to the plan, any modification to the plan, and reasons for the modification. 195.452(c)(2)
(d) When must operators complete baseline assessments?
195.452(d)
(1) All pipelines. An operator must complete the baseline assessment before a new or conversion-to-service pipeline begins operation through the development of procedures, identification of high consequence areas, and pressure testing of could-affect high consequence areas in accordance with §195.304. 195.452(d)(1)
(2) Newly identified areas. If an operator obtains information (whether from the information analysis required under paragraph (g) of this section, Census Bureau maps, or any other source) demonstrating that the area around a pipeline segment has changed to meet the definition of a high consequence area (see §195.450), that area must be incorporated into the operator's baseline assessment plan within 1 year from the date that the information is obtained. An operator must complete the baseline assessment of any pipeline segment that could affect a newly identified high consequence area within 5 years from the date an operator identifies the area. 195.452(d)(2)
Category 1 January 1, 1996.
Category 2 February 15, 1997.
(3) Newly-identified areas.195.452(d)(3)
(i) When information is available from the information analysis (see paragraph (g) of this section), or from Census Bureau maps, that the population density around a pipeline segment has changed so as to fall within the definition in §195.450 of a high population area or other populated area, the operator must incorporate the area into its baseline assessment plan as a high consequence area within one year from the date the area is identified. An operator must complete the baseline assessment of any line pipe that could affect the newly-identified high consequence area within five years from the date the area is identified.195.452(d)(3)(i)
(ii) An operator must incorporate a new unusually sensitive area into its baseline assessment plan within one year from the date the area is identified. An operator must complete the baseline assessment of any line pipe that could affect the newly-identified high consequence area within five years from the date the area is identified.195.452(d)(3)(ii)
(e) What are the risk factors for establishing an assessment schedule (for both the baseline and continual integrity assessments)? 195.452(e)
(1) An operator must establish an integrity assessment schedule that prioritizes pipeline segments for assessment (see paragraphs (d)(1) and (j)(3) of this section). An operator must base the assessment schedule on all risk factors that reflect the risk conditions on the pipeline segment. The factors an operator must consider include, but are not limited to: 195.452(e)(1)
(i) Results of the previous integrity assessment, defect type and size that the assessment method can detect, and defect growth rate;195.452(e)(1)(i)
(ii) Pipe size, material, manufacturing information, coating type and condition, and seam type;195.452(e)(1)(ii)
(iii) Leak history, repair history and cathodic protection history; 195.452(e)(1)(iii)
(iv) Product transported;195.452(e)(1)(iv)
(v) Operating stress level;195.452(e)(1)(v)
(vi) Existing or projected activities in the area;195.452(e)(1)(vi)
(vii) Local environmental factors that could affect the pipeline (e.g., seismicity, corrosivity of soil, subsidence, climatic); 195.452(e)(1)(vii)
(ix) Physical support of the segment such as by a cable suspension bridge.195.452(e)(1)(ix)
(2) Appendix C of this part provides further guidance on risk factors. 195.452(e)(2)
(f) What are the elements of an integrity management program?
An integrity management program begins with the initial framework. An operator must continually change the program to reflect operating experience, conclusions drawn from results of the integrity assessments, and other maintenance and surveillance data, and evaluation of consequences of a failure on the high consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: 195.452(f)
(1) A process for identifying which pipeline segments could affect a high consequence area; 195.452(f)(1)
(2) A baseline assessment plan meeting the requirements of paragraph (c) of this section; 195.452(f)(2)
(3) An analysis that integrates all available information about the integrity of the entire pipeline and the consequences of a failure (see paragraph (g) of this section); 195.452(f)(3)
(4) Criteria for remedial actions to address integrity issues raised by the assessment methods and information analysis (see paragraph (h) of this section); 195.452(f)(4)
(5) A continual process of assessment and evaluation to maintain a pipeline's integrity (see paragraph (j) of this section); 195.452(f)(5)
(6) Identification of preventive and mitigative measures to protect the high consequence area (see paragraph (i) of this section); 195.452(f)(6)
(7) Methods to measure the program's effectiveness (see paragraph (k) of this section); 195.452(f)(7)
(8) A process for review of integrity assessment results and information analysis by a person qualified to evaluate the results and information (see paragraph (h)(2) of this section). 195.452(f)(8)
(g) What is an information analysis? In periodically evaluating the integrity of each pipeline segment (see paragraph (j) of this section), an operator must analyze all available information about the integrity of its entire pipeline and the consequences of a possible failure along the pipeline. Operators must continue to comply with the data integration elements specified in §195.452(g) that were in effect on October 1, 2018, until October 1, 2022. Operators must begin to integrate all the data elements specified in this section starting October 1, 2020, with all attributes integrated by October 1, 2022. This analysis must: 195.452(g)
(1) Integrate information and attributes about the pipeline that include, but are not limited to: 195.452(g)(1)
(i) Pipe diameter, wall thickness, grade, and seam type; 195.452(g)(1)(i)
(ii) Pipe coating, including girth weld coating;195.452(g)(1)(ii)
(iii) Maximum operating pressure (MOP) and temperature; 195.452(g)(1)(iii)
(iv) Endpoints of segments that could affect high consequence areas (HCAs);195.452(g)(1)(iv)
(v) Hydrostatic test pressure including any test failures or leaks — if known;195.452(g)(1)(v)
(vi) Location of casings and if shorted;195.452(g)(1)(vi)
(vii) Any in-service ruptures or leaks — including identified causes; 195.452(g)(1)(vii)
(viii) Data gathered through integrity assessments required under this section;195.452(g)(1)(viii)
(ix) Close interval survey (CIS) survey results;195.452(g)(1)(ix)
(xii) CP test point survey readings and locations;195.452(g)(1)(xii)
(xiii) AC/DC and foreign structure interference surveys; 195.452(g)(1)(xiii)
(xiv) Pipe coating surveys and cathodic protection surveys. 195.452(g)(1)(xiv)
(xv) Results of examinations of exposed portions of buried pipelines (i.e., pipe and pipe coating condition, see §195.569); 195.452(g)(1)(xv)
(xvi) Stress corrosion cracking (SCC) and other cracking (pipe body or weld) excavations and findings, including in-situ nondestructive examinations and analysis results for failure stress pressures and cyclic fatigue crack growth analysis to estimate the remaining life of the pipeline;195.452(g)(1)(xvi)
(xvii) Aerial photography;195.452(g)(1)(xvii)
(xviii) Location of foreign line crossings;195.452(g)(1)(xviii)
(xix) Pipe exposures resulting from repairs and encroachments; 195.452(g)(1)(xix)
(xx) Seismicity of the area; and195.452(g)(1)(xx)
(xxi) Other pertinent information derived from operations and maintenance activities and any additional tests, inspections, surveys, patrols, or monitoring required under this part.195.452(g)(1)(xxi)
(2) Consider information critical to determining the potential for, and preventing, damage due to excavation, including current and planned damage prevention activities, and development or planned development along the pipeline; 195.452(g)(2)
(3) Consider how a potential failure would affect high consequence areas, such as location of a water intake. 195.452(g)(3)
(4) Identify spatial relationships among anomalous information (e.g., corrosion coincident with foreign line crossings; evidence of pipeline damage where aerial photography shows evidence of encroachment). Storing the information in a geographic information system (GIS), alone, is not sufficient. An operator must analyze for interrelationships among the data. 195.452(g)(4)
(h) What actions must an operator take to address integrity issues?
— 195.452(h)
(1) General requirements. An operator must take prompt action to address all anomalous conditions in the pipeline that the operator discovers through the integrity assessment or information analysis. In addressing all conditions, an operator must evaluate all anomalous conditions and remediate those that could reduce a pipeline's integrity, as required by this part. An operator must be able to demonstrate that the remediation of the condition will ensure that the condition is unlikely to pose a threat to the longterm integrity of the pipeline. An operator must comply with all other applicable requirements in this part in remediating a condition. Each operator must, in repairing its pipeline systems, ensure that the repairs are made in a safe and timely manner and are made so as to prevent damage to persons, property, or the environment. The calculation method(s) used for anomaly evaluation must be applicable for the range of relevant threats. 195.452(h)(1)
(i) Temporary pressure reduction. An operator must notify PHMSA, in accordance with paragraph (m) of this section, if the operator cannot meet the schedule for evaluation and remediation required under paragraph (h)(3) of this section and cannot provide safety through a temporary reduction in operating pressure.195.452(h)(1)(i)
(ii) Long-term pressure reduction. When a pressure reduction exceeds 365 days, the operator must notify PHMSA in accordance with paragraph (m) of this section and explain the reasons for the delay. An operator must also take further remedial action to ensure the safety of the pipeline.195.452(h)(1)(ii)
(2) Discovery of condition. Discovery of a condition occurs when an operator has adequate information to determine that a condition presenting a potential threat to the integrity of the pipeline exists. An operator must promptly, but no later than 180 days after an assessment, obtain sufficient information about a condition to make that determination, unless the operator can demonstrate the 180-day interval is impracticable. If the operator believes that 180 days are impracticable to make a determination about a condition found during an assessment, the pipeline operator must notify PHMSA in accordance with paragraph (m) of this section and provide an expected date when adequate information will become available. 195.452(h)(2)
(3) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a schedule prioritizing the conditions for evaluation and remediation. If an operator cannot meet the schedule for any condition, the operator must explain the reasons why it cannot meet the schedule and how the changed schedule will not jeopardize public safety or environmental protection. 195.452(h)(3)
(4) Special requirements for scheduling remediation — 195.452(h)(4)
(i) Immediate repair conditions. An operator's evaluation and remediation schedule must provide for immediate repair conditions. To maintain safety, an operator must temporarily reduce the operating pressure or shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the temporary reduction in operating pressure using
the formulas referenced in paragraph (h)(4)(i)(B) of this section. If no suitable remaining strength calculation method can be identified, an operator must implement a minimum 20 percent or greater operating pressure reduction, based on actual operating pressure for two months prior to the date of inspection, until the anomaly is repaired. An operator must treat the following conditions as immediate repair conditions:195.452(h)(4)(i)
[A] Metal loss greater than 80% of nominal wall regardless of dimensions.195.452(h)(4)(i)[A]
[B] A calculation of the remaining strength of the pipe shows a predicted burst pressure less than the established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (incorporated by reference, see §195.3) and PRCI PR-3-805 (R-STRENG) (incorporated by reference, see §195.3).195.452(h)(4)(i)[B]
[C] A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) that has any indication of metal loss, cracking or a stress riser.195.452(h)(4)(i)[C]
[D] A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 6% of the nominal pipe diameter.195.452(h)(4)(i)[D]
[E] An anomaly that in the judgment of the person designated by the operator to evaluate the assessment results requires immediate action.195.452(h)(4)(i)[E]
(ii) 60-day conditions. Except for conditions listed in paragraph (h)(4)(i) of this section, an operator must schedule evaluation and remediation of the following conditions within 60 days of discovery of condition.195.452(h)(4)(ii)
[A] A dent located on the top of the pipeline (above the 4 and 8 o'clock positions) with a depth greater than 3% of the pipeline diameter (greater than 0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size (NPS) 12).
195.452(h)(4)(ii)[A]
[B] A dent located on the bottom of the pipeline that has any indication of metal loss, cracking or a stress riser. 195.452(h)(4)(ii)[B]
(iii) 180-day conditions. Except for conditions listed in paragraph (h)(4)(i) or (ii) of this section, an operator must schedule evaluation and remediation of the following within 180 days of discovery of the condition:195.452(h)(4)(iii)
[A] A dent with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal seam weld.195.452(h)(4)(iii)[A]
[B] A dent located on the top of the pipeline (above 4 and 8 o'clock position) with a depth greater than 2% of the pipeline's diameter (0.250 inches in depth for a pipeline diameter less than NPS 12).195.452(h)(4)(iii)[B]
[C] A dent located on the bottom of the pipeline with a depth greater than 6% of the pipeline's diameter.195.452(h)(4)(iii)[C]
[D] A calculation of the remaining strength of the pipe shows an operating pressure that is less than the current established maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G and PRCI PR-3-805 (R-STRENG).195.452(h)(4)(iii)[D]
[E] An area of general corrosion with a predicted metal loss greater than 50% of nominal wall.195.452(h)(4)(iii)[E]
[F] Predicted metal loss greater than 50% of nominal wall that is located at a crossing of another pipeline, or is in an area with widespread circumferential corrosion, or is in an area that could affect a girth weld.195.452(h)(4)(iii)[F]
[G] A potential crack indication that when excavated is determined to be a crack.195.452(h)(4)(iii)[G]
[H] Corrosion of or along a longitudinal seam weld. 195.452(h)(4)(iii)[H]
[I] A gouge or groove greater than 12.5% of nominal wall. 195.452(h)(4)(iii)[I]
(iv) Other conditions. In addition to the conditions listed in paragraphs (h)(4)(i) through (iii) of this section, an operator must evaluate any condition identified by an integrity assessment or information analysis that could impair the integrity of the pipeline, and as appropriate, schedule the condition for remediation. Appendix C of this part contains guidance concerning other conditions that an operator should evaluate.195.452(h)(4)(iv)
(i) What preventive and mitigative measures must an operator take to protect the high consequence area? — 195.452(i)
(1) General requirements. An operator must take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. These measures include conducting a risk analysis of the pipeline segment to identify additional actions to enhance public safety or environmental protection. Such
actions may include, but are not limited to, implementing damage prevention best practices, better monitoring of cathodic protection where corrosion is a concern, establishing shorter inspection intervals, installing EFRDs on the pipeline segment, modifying the systems that monitor pressure and detect leaks, providing additional training to personnel on response procedures, conducting drills with local emergency responders and adopting other management controls. 195.452(i)(1)
(2) Risk analysis criteria. In identifying the need for additional preventive and mitigative measures, an operator must evaluate the likelihood of a pipeline release occurring and how a release could affect the high consequence area. This determination must consider all relevant risk factors, including, but not limited to: 195.452(i)(2)
(i) Terrain surrounding the pipeline segment, including drainage systems such as small streams and other smaller waterways that could act as a conduit to the high consequence area; 195.452(i)(2)(i)
(ii) Elevation profile;195.452(i)(2)(ii)
(iii) Characteristics of the product transported;195.452(i)(2)(iii)
(iv) Amount of product that could be released;195.452(i)(2)(iv)
(v) Possibility of a spillage in a farm field following the drain tile into a waterway;195.452(i)(2)(v)
(vi) Ditches along side a roadway the pipeline crosses; 195.452(i)(2)(vi)
(vii) Physical support of the pipeline segment such as by a cable suspension bridge;195.452(i)(2)(vii)
(viii) Exposure of the pipeline to operating pressure exceeding established maximum operating pressure;195.452(i)(2)(viii)
(ix) Seismicity of the area.195.452(i)(2)(ix)
(3) Leak detection. An operator must have a means to detect leaks on its pipeline system. An operator must evaluate the capability of its leak detection means and modify, as necessary, to protect the high consequence area. An operator's evaluation must, at least, consider, the following factors — length and size of the pipeline, type of product carried, the pipeline's proximity to the high consequence area, the swiftness of leak detection, location of nearest response personnel, leak history, and risk assessment results. 195.452(i)(3)
(4) Emergency Flow Restricting Devices (EFRD). If an operator determines that an EFRD is needed on a pipeline segment that is located in, or which could affect, a high-consequence area (HCA) in the event of a hazardous liquid pipeline release, an operator must install the EFRD. In making this determination, an operator must, at least, evaluate the following factors — the swiftness of leak detection and pipeline shutdown capabilities, the type of commodity carried, the rate of potential leakage, the volume that can be released, topography or pipeline profile, the potential for ignition, proximity to power sources, location of nearest response personnel, specific terrain within the HCA or between the pipeline segment and the HCA it could affect, and benefits expected by reducing the spill size. An RMV installed under this paragraph must meet all of the other applicable requirements in this part.
195.452(i)(4)
(i) Where EFRDs are installed on pipeline segments in HCAs and that could affect HCAs with diameters of 6 inches or greater and that are placed into service or that have had 2 or more miles of pipe replaced within 5 contiguous miles within a 24-month period after April 10, 2023, the location, installation, actuation, operation, and maintenance of such EFRDs (including valve actuators, personnel response, operational control centers, supervisory control and data acquisition (SCADA), communications, and procedures) must meet the design, operation, testing, maintenance, and rupture-mitigation requirements of §§195.258, 195.260, 195.402, 195.418, 195.419, and 195.420. 195.452(i)(4)(i)
(ii) The EFRD analysis and assessments specified in this paragraph (i)(4) must be completed prior to placing into service all onshore pipelines with diameters of 6 inches or greater and that are constructed or that have had 2 or more miles of pipe within any 5 contiguous miles within any 24-month period replaced after April 10, 2023. Implementation of EFRD findings for RMVs must meet §195.418. 195.452(i)(4)(ii)
(iii) An operator may request an exemption from the compliance deadline requirements of this section if it can demonstrate to PHMSA, in accordance with the notification procedures in §195.18, that installing an EFRD by that compliance deadline would be economically, technically, or operationally infeasible. 195.452(i)(4)(iii)
(j) What is a continual process of evaluation and assessment to maintain a pipeline's integrity? — 195.452(j)
(1) General. After completing the baseline integrity assessment, an operator must continue to assess the line pipe at specified intervals and periodically evaluate the integrity of each pipeline segment that could affect a high consequence area. 195.452(j)(1)
(2) Verifying covered segments. An operator must verify the risk factors used in identifying pipeline segments that could affect a high consequence area on at least an annual basis not to exceed 15 months (Appendix C of this part provides additional guidance on factors that can influence whether a pipeline segment could affect a high consequence area). If a change in circumstance indicates that the prior consideration of a risk factor is no longer valid or that an operator should consider new risk factors, an operator must perform a new integrity analysis and evaluation to establish the endpoints of any previously identified covered segments. The integrity analysis and evaluation must include consideration of the results of any baseline and periodic integrity assessments (see paragraphs (b), (c), (d), and (e) of this section), information analyses (see paragraph (g) of this section), and decisions about remediation and preventive and mitigative actions (see paragraphs (h) and (i) of this section). An operator must complete the first annual verification under this paragraph no later than July 1, 2021. 195.452(j)(2)
(3) Assessment intervals. An operator must establish five-year intervals, not to exceed 68 months, for continually assessing the line pipe's integrity. An operator must base the assessment intervals on the risk the line pipe poses to the high consequence area to determine the priority for assessing the pipeline segments. An operator must establish the assessment intervals based on the factors specified in paragraph (e) of this section, the analysis of the results from the last integrity assessment, and the information analysis required by paragraph (g) of this section. 195.452(j)(3)
(4) Variance from the 5-year intervals in limited situations — 195.452(j)(4)
(i) Engineering basis. An operator may be able to justify an engineering basis for a longer assessment interval on a segment of line pipe. The justification must be supported by a reliable engineering evaluation combined with the use of other technology, such as external monitoring technology, that provides an understanding of the condition of the line pipe equivalent to that which can be obtained from the assessment methods allowed in paragraph (j)(5) of this section. An operator must notify OPS 270 days before the end of the five-year (or less) interval of the justification for a longer interval, and propose an alternative interval. An operator must send the notice to the address specified in paragraph (m) of this section.195.452(j)(4)(i)
(ii) Unavailable technology. An operator may require a longer assessment period for a segment of line pipe (for example, because sophisticated internal inspection technology is not available). An operator must justify the reasons why it cannot comply with the required assessment period and must also demonstrate the actions it is taking to evaluate the integrity of the pipeline segment in the interim. An operator must notify OPS 180 days before the end of the five-year (or less) interval that the operator may require a longer assessment interval, and provide an estimate of when the assessment can be completed. An operator must send a notice to the address specified in paragraph (m) of this section.195.452(j)(4)(ii)
(5) Assessment methods. An operator must assess the integrity of the line pipe by any of the following methods. The methods an operator selects to assess low frequency electric resistance welded pipe or lap welded pipe susceptible to longitudinal seam failure must be capable of assessing seam integrity and of detecting corrosion and deformation anomalies. 195.452(j)(5)
(i) In-Line Inspection tool or tools capable of detecting corrosion and deformation anomalies, including dents, gouges, and grooves. For pipeline segments that are susceptible to cracks (pipe body and weld seams), an operator must use an in-line inspection tool or tools capable of detecting crack anomalies. When performing an assessment using an In-Line Inspection tool, an operator must comply with §195.591;195.452(j)(5)(i)
(ii) Pressure test conducted in accordance with subpart E of this part;195.452(j)(5)(ii)
(iii) External corrosion direct assessment in accordance with §195.588; or195.452(j)(5)(iii)
(iv) Other technology that the operator demonstrates can provide an equivalent understanding of the condition of the line pipe. An operator choosing this option must notify OPS 90 days before conducting the assessment, by sending a notice to the address or facsimile number specified in paragraph (m) of this section. 195.452(j)(5)(iv)
(k) What methods to measure program effectiveness must be used? An operator's program must include methods to measure whether the program is effective in assessing and evaluating the integrity of each pipeline segment and in protecting the high consequence areas. See Appendix C of this part for guidance on methods that can be used to evaluate a program's effectiveness. 195.452(k)
(l) What records must an operator keep to demonstrate compliance? 195.452(l)
(1) An operator must maintain, for the useful life of the pipeline, records that demonstrate compliance with the requirements of this subpart. At a minimum, an operator must maintain the following records for review during an inspection: 195.452(l)(1)
(i) A written integrity management program in accordance with paragraph (b) of this section.195.452(l)(1)(i)
(ii) Documents to support the decisions and analyses, including any modifications, justifications, deviations and determinations made, variances, and actions taken, to implement and evaluate each element of the integrity management program listed in paragraph (f) of this section.195.452(l)(1)(ii)
(2) See Appendix C of this part for examples of records an operator would be required to keep. 195.452(l)(2)
(m) How does an operator notify PHMSA? An operator must provide any notification required by this section by: 195.452(m)
(1) Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or 195.452(m)(1)
(2) Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave SE., Washington, DC 20590. 195.452(m)(2)
(n) Accommodation of instrumented internal inspection devices
— 195.452(n)
(1) Scope. This paragraph does not apply to any pipeline facilities listed in §195.120(b). 195.452(n)(1)
(2) General. An operator must ensure that each pipeline is modified to accommodate the passage of an instrumented internal inspection device by July 2, 2040. 195.452(n)(2)
(3) Newly identified areas. If a pipeline could affect a newly identified high consequence area (see paragraph (d)(2) of this section) after July 2, 2035, an operator must modify the pipeline to accommodate the passage of an instrumented internal inspection device within 5 years of the date of identification or before performing the baseline assessment, whichever is sooner. 195.452(n)(3)
(4) Lack of accommodation. An operator may file a petition under §190.9 of this chapter for a finding that the basic construction (i.e., length, diameter, operating pressure, or location) of a pipeline cannot be modified to accommodate the passage of an instrumented internal inspection device or that the operator determines it would abandon or shut-down a pipeline as a result of the cost to comply with the requirement of this section. 195.452(n)(4)
(5) Emergencies. An operator may file a petition under §190.9 of this chapter for a finding that a pipeline cannot be modified to accommodate the passage of an instrumented internal inspection device as a result of an emergency. An operator must file such a petition within 30 days after discovering the emergency. If the petition is denied, the operator must modify the pipeline to allow the passage of an instrumented internal inspection device within 1 year after the date of the notice of the denial.
195.452(n)(5)
§195.454 Integrity assessments for certain underwater hazardous liquid pipeline facilities located in high consequence areas.
Notwithstanding any pipeline integrity management program or integrity assessment schedule otherwise required under §195.452, each operator of any underwater hazardous liquid pipeline facility located in a high consequence area that is not an offshore pipeline facility and any portion of which is located at depths greater than 150 feet under the surface of the water must ensure that:
(a) Pipeline integrity assessments using internal inspection technology appropriate for the integrity threats to the pipeline are completed not less often than once every 12 months, and; 195.454(a)
(b) Pipeline integrity assessments using pipeline route surveys, depth of cover surveys, pressure tests, external corrosion direct assessment, or other technology that the operator demonstrates can further the understanding of the condition of the pipeline facility, are completed on a schedule based on the risk that the pipeline facility poses to the high consequence area in which the pipeline facility is located. 195.454(b)
Subpart G – Qualification of Pipeline Personnel
§195.501 Scope
(a) This subpart prescribes the minimum requirements for operator qualification of individuals performing covered tasks on a pipeline facility.
(b) For the purpose of this subpart, a covered task is an activity, identified by the operator, that:
(1) Is performed on a pipeline facility;
(2) Is an operations or maintenance task;
(3) Is performed as a requirement of this part; and
(4) Affects the operation or integrity of the pipeline.
§195.503 Definitions
Abnormal operating condition means a condition identified by the operator that may indicate a malfunction of a component or deviation from normal operations that may:
(a) Indicate a condition exceeding design limits; or
(b) Result in a hazard(s) to persons, property, or the environment.
Evaluation means a process, established and documented by the operator, to determine an individual's ability to perform a covered task by any of the following:
(a) Written examination;
(b) Oral examination;
(c) Work performance history review;
(d) Observation during:
(1) performance on the job, (2) on the job training, or (3) simulations;
(e) Other forms of assessment.
Qualified means that an individual has been evaluated and can:
(a) Perform assigned covered tasks and
(b) Recognize and react to abnormal operating conditions.
§195.505
Qualification program
Each operator shall have and follow a written qualification program. The program shall include provisions to:
(a) Identify covered tasks;
(b) Ensure through evaluation that individuals performing covered tasks are qualified;
(c) Allow individuals that are not qualified pursuant to this subpart to perform a covered task if directed and observed by an individual that is qualified;
(d) Evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an accident as defined in Part 195;
(e) Evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task;
(f) Communicate changes that affect covered tasks to individuals performing those covered tasks;
(g) Identify those covered tasks and the intervals at which evaluation of the individual's qualifications is needed;
(h) After December 16, 2004, provide training, as appropriate, to ensure that individuals performing covered tasks have the necessary knowledge and skills to perform the tasks in a manner that ensures the safe operation of pipeline facilities; and
(i) After December 16, 2004, notify the Administrator or a state agency participating under 49 U.S.C. Chapter 601 if the operator significantly modifies the program after the administrator or state agency has verified that it complies with this section. Notifications to PHMSA may be submitted by electronic mail to InformationResourcesManager@dot.gov, or by mail to ATTN: Information Resources Manager DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, New Jersey Avenue SE., Washington, DC 20590.
§195.507 Recordkeeping
Each operator shall maintain records that demonstrate compliance with this subpart.
(a) Qualification records shall include:
(1) Identification of qualified individual(s);
(2) Identification of the covered tasks the individual is qualified to perform;
(3) Date(s) of current qualification; and
(4) Qualification method(s).
(b) Records supporting an individual's current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of five years.
§195.509 General
(a) Operators must have a written qualification program by April 27, 2001. The program must be available for review by the Administrator or by a state agency participating under 49 U.S.C. Chapter 601 if the program is under the authority of that state agency.
(b) Operators must complete the qualification of individuals performing covered tasks by October 28, 2002.
(c) Work performance history review may be used as a sole evaluation method for individuals who were performing a covered task prior to October 26, 1999.
(d) After October 28, 2002, work performance history may not be used as a sole evaluation method.
(e) After December 16, 2004, observation of on-the-job performance may not be used as the sole method of evaluation.
Subpart H – Corrosion Control
§195.551 What do the regulations in this subpart cover?
This subpart prescribes minimum requirements for protecting steel pipelines against corrosion.
§195.553 What special definitions apply to this subpart?
As used in this subpart —
Active corrosion means continuing corrosion which, unless controlled, could result in a condition that is detrimental to public safety or the environment.
Buried means covered or in contact with soil.
Direct assessment means an integrity assessment method that utilizes a process to evaluate certain threats (i.e., external corrosion, internal corrosion and stress corrosion cracking) to a pipeline segment's integrity. The process includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of suspected corrosion, direct examination of the pipeline in these areas, and post assessment evaluation.
Electrical survey means a series of closely spaced pipe-to-soil readings over a pipeline that are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline.
External corrosion direct assessment (ECDA) means a four-step process that combines pre-assessment, indirect inspection, direct examination, and post-assessment to evaluate the threat of external corrosion to the integrity of a pipeline.
Pipeline environment includes soil resistivity (high or low), soil moisture (wet or dry), soil contaminants that may promote corrosive activity, and other known conditions that could affect the probability of active corrosion.
You means operator.
§195.555 What are the qualifications for supervisors?
You must require and verify that supervisors maintain a thorough knowledge of that portion of the corrosion control procedures established under §195.402(c)(3) for which they are responsible for insuring compliance.
§195.557 Which pipelines must have coating for external corrosion control?
Except bottoms of aboveground breakout tanks, each buried or submerged pipeline must have an external coating for external corrosion control if the pipeline is —
(a) Constructed, relocated, replaced, or otherwise changed after the applicable date in §195.401(c), not including the movement of pipe covered by §195.424; or 195.557(a)
(b) Converted under §195.5 and — 195.557(b)
(1) Has an external coating that substantially meets §195.559 before the pipeline is placed in service; or 195.557(b)(1)
(2) Is a segment that is relocated, replaced, or substantially altered. 195.557(b)(2)
§195.559 What coating material may I use for external corrosion control?
Coating material for external corrosion control under §195.557 must —
(a) Be designed to mitigate corrosion of the buried or submerged pipeline; 195.559(a)
(b) Have sufficient adhesion to the metal surface to prevent under film migration of moisture; 195.559(b)
(c) Be sufficiently ductile to resist cracking; 195.559(c)
(d) Have enough strength to resist damage due to handling and soil stress; 195.559(d)
(e) Support any supplemental cathodic protection; and 195.559(e)
(f) If the coating is an insulating type, have low moisture absorption and provide high electrical resistance. 195.559(f)
§195.561 When must I inspect pipe coating used for external corrosion control?
(a) You must inspect all external pipe coating required by §195.557 just prior to lowering the pipe into the ditch or submerging the pipe. 195.561(a)
(b) You must repair any coating damage discovered. 195.561(b)
§195.563 Which pipelines must have cathodic protection?
(a) Each buried or submerged pipeline that is constructed, relocated, replaced, or otherwise changed after the applicable date in §195.401(c) must have cathodic protection. The cathodic protection must be in operation not later than 1 year after the pipeline is constructed, relocated, replaced, or otherwise changed, as applicable. 195.563(a)
(b) Each buried or submerged pipeline converted under §195.5 must have cathodic protection if the pipeline — 195.563(b)
(1) Has cathodic protection that substantially meets §195.571 before the pipeline is placed in service; or 195.563(b)(1)
(2) Is a segment that is relocated, replaced, or substantially altered. 195.563(b)(2)
(c) All other buried or submerged pipelines that have an effective external coating must have cathodic protection.1 Except as provided by paragraph (d) of this section, this requirement does not apply to breakout tanks and does not apply to buried piping in breakout tank areas and pumping stations until December 29, 2003. 195.563(c)
1A pipeline does not have an effective external coating material if the current required to cathodically protect the pipeline is substantially the same as if the pipeline were bare.
(d) Bare pipelines, breakout tank areas, and buried pumping station piping must have cathodic protection in places where regulations in effect before January 28, 2002 required cathodic protection as a result of electrical inspections. See previous editions of this part in 49 CFR, parts 186 to 199. 195.563(d)
(e) Unprotected pipe must have cathodic protection if required by §195.573(b). 195.563(e)
§195.565 How do I install cathodic protection on breakout tanks?
After October 2, 2000, when you install cathodic protection under §195.563(a) to protect the bottom of an aboveground breakout tank of more than 500 barrels 79.49m3 capacity built to API Spec 12F (incorporated by reference, see §195.3), API Std 620 (incorporated by reference, see §195.3), API Std 650 (incorporated by reference, see §195.3), or API Std 650's predecessor, Standard 12C, you must install the system in accordance with ANSI/API RP 651 (incorporated by reference, see §195.3). However, you don't need to comply with ANSI/API RP 651 when installing any tank for which you note in the corrosion control procedures established under §195.402(c)(3) why complying with all or certain provisions of ANSI/API RP 651 is not necessary for the safety of the tank.
§195.567 Which pipelines must have test leads and what must I do to install and maintain the leads?
(a) General. Except for offshore pipelines, each buried or submerged pipeline or segment of pipeline under cathodic protection required by this subpart must have electrical test leads for external corrosion control. However, this requirement does not apply until December 27, 2004 to pipelines or pipeline segments on which test leads were not required by regulations in effect before January 28, 2002. 195.567(a)
(b) Installation. You must install test leads as follows: 195.567(b)
(1) Locate the leads at intervals frequent enough to obtain electrical measurements indicating the adequacy of cathodic protection. 195.567(b)(1)
(2) Provide enough looping or slack so backfilling will not unduly stress or break the lead and the lead will otherwise remain mechanically secure and electrically conductive. 195.567(b)(2)
(3) Prevent lead attachments from causing stress concentrations on pipe. 195.567(b)(3)
(4) For leads installed in conduits, suitably insulate the lead from the conduit. 195.567(b)(4)
(5) At the connection to the pipeline, coat each bared test lead wire and bared metallic area with an electrical insulating material compatible with the pipe coating and the insulation on the wire. 195.567(b)(5)
(c) Maintenance. You must maintain the test lead wires in a condition that enables you to obtain electrical measurements to determine whether cathodic protection complies with §195.571. 195.567(c)
§195.569 Do I have to examine exposed portions of buried pipelines?
Whenever you have knowledge that any portion of a buried pipeline is exposed, you must examine the exposed portion for evidence of external corrosion if the pipe is bare, or if the coating is deteriorated. If you find external corrosion requiring corrective action under §195.585, you must investigate circumferentially and longitudinally beyond the exposed portion (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the exposed portion.
§195.571 What criteria must I use to determine the adequacy of cathodic protection?
Cathodic protection required by this subpart must comply with one or more of the applicable criteria and other considerations for cathodic protection contained paragraphs 6.2.2, 6.2.3, 6.2.4, 6.2.5 and 6.3 in NACE SP 0169 (incorporated by reference, see §195.3).
§195.573 What must I do to monitor external corrosion control?
(a) Protected pipelines. You must do the following to determine whether cathodic protection required by this subpart complies with §195.571: 195.573(a)
(1) Conduct tests on the protected pipeline at least once each calendar year, but with intervals not exceeding 15 months. However, if tests at those intervals are impractical for separately protected short sections of bare or ineffectively coated pipelines, testing may be done at least once every 3 calendar years, but with intervals not exceeding 39 months. 195.573(a)(1)
(2) Identify not more than 2 years after cathodic protection is installed, the circumstances in which a close-interval survey or comparable technology is practicable and necessary to accomplish the objectives of paragraph 10.1.1.3 of NACE SP 0169 (incorporated by reference, see §195.3). 195.573(a)(2)
(b) Unprotected pipe. You must reevaluate your unprotected buried or submerged pipe and cathodically protect the pipe in areas in which active corrosion is found, as follows: 195.573(b)
(1) Determine the areas of active corrosion by electrical survey, or where an electrical survey is impractical, by other means that include review and analysis of leak repair and inspection records, corrosion monitoring records, exposed pipe inspection records, and the pipeline environment. 195.573(b)(1)
(2) For the period in the first column, the second column prescribes the frequency of evaluation. 195.573(b)(2)
Period
Before December 29, 2003
Evaluation frequency
At least once every 5 calendar years, but with intervals not exceeding 63 months.
Beginning December 29, 2003 At least once every 3 calendar years, but with intervals not exceeding 39 months.
(c) Rectifiers and other devices. You must electrically check for proper performance each device in the first column at the frequency stated in the second column. 195.573(c)
Device Check frequency
Rectifier
Reverse
At least six times each calendar year, but with intervals not exceeding 21⁄2 months.
At least once each calendar year, but with intervals not exceeding 15 months.
(d) Breakout tanks. You must inspect each cathodic protection system used to control corrosion on the bottom of an aboveground breakout tank to ensure that operation and maintenance of the system are in accordance with API RP 651 (incorporated by reference, see §195.3). However, this inspection is not required if you note in the corrosion control procedures established under §195.402(c)(3) why complying with all or certain operation and maintenance provisions of API RP 651 is not necessary for the safety of the tank. 195.573(d)
(e) Corrective action. You must correct any identified deficiency in corrosion control as required by §195.401(b). However, if the deficiency involves a pipeline in an integrity management program under §195.452, you must correct the deficiency as required by §195.452(h). 195.573(e)
§195.575 Which facilities must I electrically isolate and what inspections, tests, and safeguards are required?
(a) You must electrically isolate each buried or submerged pipeline from other metallic structures, unless you electrically interconnect and cathodically protect the pipeline and the other structures as a single unit. 195.575(a)
(b) You must install one or more insulating devices where electrical isolation of a portion of a pipeline is necessary to facilitate the application of corrosion control. 195.575(b)
(c) You must inspect and electrically test each electrical isolation to assure the isolation is adequate. 195.575(c)
(d) If you install an insulating device in an area where a combustible atmosphere is reasonable to foresee, you must take precautions to prevent arcing. 195.575(d)
(e) If a pipeline is in close proximity to electrical transmission tower footings, ground cables, or counterpoise, or in other areas where it is reasonable to foresee fault currents or an unusual risk of lightning, you must protect the pipeline against damage from fault currents or lightning and take protective measures at insulating devices. 195.575(e)
§195.577 What must I do to alleviate interference currents?
(a) For pipelines exposed to stray currents, you must have a program to identify, test for, and minimize the detrimental effects of such currents. 195.577(a)
(b) You must design and install each impressed current or galvanic anode system to minimize any adverse effects on existing adjacent metallic structures. 195.577(b)
§195.579 What must I do to mitigate internal corrosion?
(a) General. If you transport any hazardous liquid or carbon dioxide that would corrode the pipeline, you must investigate the corrosive effect of the hazardous liquid or carbon dioxide on the pipeline and take adequate steps to mitigate internal corrosion. 195.579(a)
(b) Inhibitors. If you use corrosion inhibitors to mitigate internal corrosion, you must — 195.579(b)
(1) Use inhibitors in sufficient quantity to protect the entire part of the pipeline system that the inhibitors are designed to protect; 195.579(b)(1)
(2) Use coupons or other monitoring equipment to determine the effectiveness of the inhibitors in mitigating internal corrosion; and 195.579(b)(2)
(3) Examine the coupons or other monitoring equipment at least twice each calendar year, but with intervals not exceeding 71⁄2 months. 195.579(b)(3)
(c) Removing pipe. Whenever you remove pipe from a pipeline, you must inspect the internal surface of the pipe for evidence of corrosion. If you find internal corrosion requiring corrective action under §195.585, you must investigate circumferentially and longitudinally beyond the removed pipe (by visual examination, indirect method, or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the removed pipe. 195.579(c)
(d) Breakout tanks. After October 2, 2000, when you install a tank bottom lining in an aboveground breakout tank built to API Spec 12F (incorporated by reference, see §195.3), API Std 620 (incorporated by reference, see §195.3), API Std 650 (incorporated by reference, see §195.3), or API Std 650's predecessor, Standard 12C, you must install the lining in accordance with API RP 652 (incorporated by reference, see §195.3). However, you don't need to comply with API RP 652 when installing any tank for which you note in the corrosion control procedures established under §195.402(c)(3) why compliance with all or certain provisions of API RP 652 is not necessary for the safety of the tank. 195.579(d)
§195.581 Which pipelines must I protect against atmospheric corrosion and what coating material may I use?
(a) You must clean and coat each pipeline or portion of pipeline that is exposed to the atmosphere, except pipelines under paragraph (c) of this section. 195.581(a)
(b) Coating material must be suitable for the prevention of atmospheric corrosion. 195.581(b)
(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you need not protect against atmospheric corrosion any pipeline for which you demonstrate by test, investigation, or experience appropriate to the environment of the pipeline that corrosion will — 195.581(c)
(1) Only be a light surface oxide; or195.581(c)(1)
(2) Not affect the safe operation of the pipeline before the next scheduled inspection. 195.581(c)(2)
§195.583 What must I do to monitor atmospheric corrosion control?
(a) You must inspect each pipeline or portion of pipeline that is exposed to the atmosphere for evidence of atmospheric corrosion, as follows: 195.583(a)
If the pipeline is located: Then the frequency of inspection is:
At least once each calendar year, but with intervals not exceeding 15 months.
(b) During inspections you must give particular attention to pipe at soil-to-air interfaces, under thermal insulation, under disbonded coatings, at pipe supports, in splash zones, at deck penetrations, and in spans over water. 195.583(b)
(c) If you find atmospheric corrosion during an inspection, you must provide protection against the corrosion as required by §195.581. 195.583(c)
§195.585 What must I do to correct corroded pipe?
(a) General corrosion. If you find pipe so generally corroded that the remaining wall thickness is less than that required for the maximum operating pressure of the pipeline, you must replace the pipe. However, you need not replace the pipe if you — 195.585(a)
(1) Reduce the maximum operating pressure commensurate with the strength of the pipe needed for serviceability based on actual remaining wall thickness; or 195.585(a)(1)
(2) Repair the pipe by a method that reliable engineering tests and analyses show can permanently restore the serviceability of the pipe. 195.585(a)(2)
(b) Localized corrosion pitting. If you find pipe that has localized corrosion pitting to a degree that leakage might result, you must replace or repair the pipe, unless you reduce the maximum operating pressure commensurate with the strength of the pipe based on actual remaining wall thickness in the pits. 195.585(b)
§195.587 What methods are available to determine the strength of corroded pipe?
Under §195.585, you may use the procedure in ASME/ANSI B31G (incorporated by reference, see §195.3) or in PRCI PR-3-805 (RSTRENG) (incorporated by reference, see §195.3) to determine the strength of corroded pipe based on actual remaining wall thickness. These procedures apply to corroded regions that do not penetrate the pipe wall, subject to the limitations set out in the respective procedures.
§195.588 What standards apply to direct assessment?
(a) If you use direct assessment on an onshore pipeline to evaluate the effects of external corrosion or stress corrosion cracking, you must follow the requirements of this section. This section does not apply to methods associated with direct assessment, such as close interval surveys, voltage gradient surveys, or examination of exposed pipelines, when used separately from the direct assessment process. 195.588(a)
(b) The requirements for performing external corrosion direct assessment are as follows: 195.588(b)
(1) General. You must follow the requirements of NACE SP0502 (incorporated by reference, see §195.3). Also, you must develop and implement a External Corrosion Direct Assessment (ECDA) plan that includes procedures addressing pre-assessment, indirect examination, direct examination, and post-assessment. 195.588(b)(1)
(2) Pre-assessment. In addition to the requirements in Section 3 of NACE SP0502 (incorporated by reference, see §195.3), the ECDA plan procedures for pre-assessment must include — 195.588(b)(2)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a pipeline segment;195.588(b)(2)(i)
(ii) The basis on which you select at least two different, but complementary, indirect assessment tools to assess each ECDA region; and195.588(b)(2)(ii)
(iii) If you utilize an indirect inspection method not described in Appendix A of NACE SP0502 (incorporated by reference, see §195.3), you must demonstrate the applicability, validation basis, equipment used, application procedure, and utilization of data for the inspection method.195.588(b)(2)(iii)
(3) Indirect examination. In addition to the requirements in Section 4 of NACE SP0502 (incorporated by reference, see §195.3), the procedures for indirect examination of the ECDA regions must include — 195.588(b)(3)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a pipeline segment;195.588(b)(3)(i)
(ii) Criteria for identifying and documenting those indications that must be considered for excavation and direct examination, including at least the following:195.588(b)(3)(ii)
[A] The known sensitivities of assessment tools;195.588(b)(3)(ii)[A]
[B] The procedures for using each tool; and195.588(b)(3)(ii)[B]
[C] The approach to be used for decreasing the physical spacing of indirect assessment tool readings when the presence of a defect is suspected;195.588(b)(3)(ii)[C]
(iii) For each indication identified during the indirect examination, criteria for — 195.588(b)(3)(iii)
[A] Defining the urgency of excavation and direct examination of the indication; and195.588(b)(3)(iii)[A]
[B] Defining the excavation urgency as immediate, scheduled, or monitored; and195.588(b)(3)(iii)[B]
(iv) Criteria for scheduling excavations of indications in each urgency level.195.588(b)(3)(iv)
(4) Direct examination. In addition to the requirements in Section 5 of NACE SP0502 (incorporated by reference, see §195.3), the procedures for direct examination of indications from the indirect examination must include — 195.588(b)(4)
(i) Provisions for applying more restrictive criteria when conducting ECDA for the first time on a pipeline segment;195.588(b)(4)(i)
(ii) Criteria for deciding what action should be taken if either: 195.588(b)(4)(ii)
[A] Corrosion defects are discovered that exceed allowable limits (Section 5.5.2.2 of NACE SP0502 (incorporated by reference, see §195.3) provides guidance for criteria); or 195.588(b)(4)(ii)[A]
[B] Root cause analysis reveals conditions for which ECDA is not suitable (Section 5.6.2 of NACE SP0502 (incorporated by reference, see §195.3) provides guidance for criteria); 195.588(b)(4)(ii)[B]
(iii) Criteria and notification procedures for any changes in the ECDA plan, including changes that affect the severity classification, the priority of direct examination, and the time frame for direct examination of indications; and195.588(b)(4)(iii)
(iv) Criteria that describe how and on what basis you will reclassify and re-prioritize any of the provisions specified in Section 5.9 of NACE SP0502 (incorporated by reference, see §195.3). 195.588(b)(4)(iv)
(5) Post assessment and continuing evaluation. In addition to the requirements in Section 6 of NACE SP 0502 (incorporated by reference, see §195.3), the procedures for post assessment of the effectiveness of the ECDA process must include — 195.588(b)(5)
(i) Measures for evaluating the long-term effectiveness of ECDA in addressing external corrosion in pipeline segments; and 195.588(b)(5)(i)
(ii) Criteria for evaluating whether conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment of the pipeline segment at an interval less than that specified in Sections 6.2 and 6.3 of NACE SP0502 (see appendix D of NACE SP0502) (incorporated by reference, see §195.3).195.588(b)(5)(ii)
(c) If you use direct assessment on an onshore pipeline to evaluate the effects of stress corrosion cracking, you must develop and follow a Stress Corrosion Cracking Direct Assessment plan that meets all requirements and recommendations of NACE SP0204-2008 (incorporated by reference, see §195.3) and that implements all four steps of the Stress Corrosion Cracking Direct Assessment process including pre-assessment, indirect inspection, detailed examination and postassessment. As specified in NACE SP0204-2008, Section 1.1.7, Stress Corrosion Cracking Direct Assessment is complementary with
other inspection methods such as in-line inspection or hydrostatic testing and is not necessarily an alternative or replacement for these methods in all instances. In addition, the plan must provide for — 195.588(c)
(1) Data gathering and integration. An operator's plan must provide for a systematic process to collect and evaluate data to identify whether the conditions for stress corrosion cracking are present and to prioritize the segments for assessment in accordance with NACE SP0204-2008, Sections 3 and 4, and Table 1. This process must also include gathering and evaluating data related to SCC at all sites an operator excavates during the conduct of its pipeline operations (both within and outside covered segments) where the criteria in NACE SP0204-2008 indicate the potential for Stress Corrosion Cracking Direct Assessment. This data gathering process must be conducted in accordance with NACE SP0204-2008, Section 5.3, and must include, at a minimum, all data listed in NACE SP0204-2008, Table 2. Further, an operator must analyze the following factors as part of this evaluation: 195.588(c)(1)
(i) The effects of a carbonate-bicarbonate environment, including the implications of any factors that promote the production of a carbonate-bicarbonate environment such as soil temperature, moisture, factors that affect the rate of carbon dioxide generation, and/or cathodic protection.195.588(c)(1)(i)
(ii) The effects of cyclic loading conditions on the susceptibility and propagation of SCC in both high-pH and near-neutral-pH environments.195.588(c)(1)(ii)
(iii) The effects of variations in applied cathodic protection such as overprotection, cathodic protection loss for extended periods, and high negative potentials.195.588(c)(1)(iii)
(iv) The effects of coatings that shield cathodic protection when disbonded from the pipe.195.588(c)(1)(iv)
(v) Other factors that affect the mechanistic properties associated with SCC including but not limited to operating pressures, high tensile residual stresses, and the presence of sulfides. 195.588(c)(1)(v)
(2) Indirect inspection. In addition to the requirements and recommendations of NACE SP0204-2008, Section 4, the plan's procedures for indirect inspection must include provisions for conducting at least two different, but complementary, indirect assessment electrical surveys, and the basis on the selections as the most appropriate for the pipeline segment based on the data gathering and integration step. 195.588(c)(2)
(3) Direct examination. In addition to the requirements and recommendations of NACE SP0204-2008, Section 5, the plan's procedures for direct examination must provide for conducting a minimum of four direct examinations within the SCC segment at locations determined to be the most likely for SCC to occur. 195.588(c)(3)
(4) Remediation and mitigation. If any indication of SCC is discovered in a segment, an operator must mitigate the threat in accordance with one of the following applicable methods: 195.588(c)(4)
(i) Non-significant SCC, as defined by NACE SP0204-2008, may be mitigated by either hydrostatic testing in accordance with paragraph (b)(4)(ii) of this section, or by grinding out with verification by Non-Destructive Examination (NDE) methods that the SCC defect is removed and repairing the pipe. If grinding is used for repair, the remaining strength of the pipe at the repair location must be determined using ASME/ANSI B31G or RSTRENG (incorporated by reference, see §195.3) and must be sufficient to meet the design requirements of subpart C of this part.195.588(c)(4)(i)
(ii) Significant SCC must be mitigated using a hydrostatic testing program with a minimum test pressure between 100% up to 110% of the specified minimum yield strength for a 30-minute spike test immediately followed by a pressure test in accordance with subpart E of this part. The test pressure for the entire sequence must be continuously maintained for at least 8 hours, in accordance with subpart E of this part. Any test failures due to SCC must be repaired by replacement of the pipe segment, and the segment retested until the pipe passes the complete test without leakage. Pipe segments that have SCC present, but that pass the pressure test, may be repaired by grinding in accordance with paragraph (c)(4)(i) of this section.195.588(c)(4)(ii)
(5) Post assessment. In addition to the requirements and recommendations of NACE SP0204-2008, sections 6.3, periodic reassessment, and 6.4, effectiveness of Stress Corrosion Cracking Direct Assessment, the plan's procedures for post assessment must include development of a reassessment plan based on the susceptibility of the operator's pipe to Stress Corrosion Cracking as well as on the behavior mechanism of identified cracking. Factors to be considered include, but are not limited to: 195.588(c)(5)
(i) Evaluation of discovered crack clusters during the direct examination step in accordance with NACE SP0204-2008, sections 5.3.5.7, 5.4, and 5.5;195.588(c)(5)(i)
(ii) Conditions conducive to creation of the carbonate-bicarbonate environment;195.588(c)(5)(ii)
(iii) Conditions in the application (or loss) of cathodic protection that can create or exacerbate SCC;195.588(c)(5)(iii)
(iv) Operating temperature and pressure conditions;195.588(c)(5)(iv)
(v) Cyclic loading conditions;195.588(c)(5)(v)
(vi) Conditions that influence crack initiation and growth rates; 195.588(c)(5)(vi)
(vii) The effects of interacting crack clusters;195.588(c)(5)(vii)
(viii) The presence of sulfides; and195.588(c)(5)(viii)
(ix) Disbonded coatings that shield CP from the pipe.195.588(c)(5)(ix)
§195.589 What corrosion control information do I have to maintain?
(a)You must maintain current records or maps to show the location of — 195.589(a)
(2) Cathodic protection facilities, including galvanic anodes, installed after January 28, 2002; and 195.589(a)(2)
(3) Neighboring structures bonded to cathodic protection systems. 195.589(a)(3)
(b)Records or maps showing a stated number of anodes, installed in a stated manner or spacing, need not show specific distances to each buried anode. 195.589(b)
(c)You must maintain a record of each analysis, check, demonstration, examination, inspection, investigation, review, survey, and test required by this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist. You must retain these records for at least 5 years, except that records related to §§195.569, 195.573(a) and (b), and 195.579(b)(3) and (c) must be retained for as long as the pipeline remains in service. 195.589(c)
§195.591
In-Line inspection of pipelines
When conducting in-line inspection of pipelines required by this part, each operator must comply with the requirements and recommendations of API Std 1163, Inline Inspection Systems Qualification Standard; ANSI/ ASNT ILI-PQ, Inline Inspection Personnel Qualification and Certification; and NACE SP0102-2010, Inline Inspection of Pipelines (incorporated by reference, see §195.3). An in-line inspection may also be conducted using tethered or remote control tools provided they generally comply with those sections of NACE SP0102-2010 that are applicable.
Appendix A to Part 195 — Delineation Between Federal and State Jurisdiction — Statement of Agency Policy and Interpretation
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 et seq. (HLPSA). The HLPSA expanded the existing statutory authority for safety regulation, which was limited to transportation by common carriers in interstate and foreign commerce, to transportation through facilities used in or affecting interstate or foreign commerce. It also added civil penalty, compliance order, and injunctive enforcement authorities to the existing criminal sanctions. Modeled largely on the Natural Gas Pipeline Safety Act of 1968, 49 U.S.C. 1671 et seq. (NGPSA), the HLPSA provides for a national hazardous liquid pipeline safety program with nationally uniform minimal standards and with enforcement administered through a Federal-State partnership. The HLPSA leaves to exclusive Federal regulation and enforcement the "interstate pipeline facilities," those used for the pipeline transportation of hazardous liquids in interstate or foreign commerce. For the remainder of the pipeline facilities, denominated "intrastate pipeline facilities," the HLPSA provides that the same Federal regulation and enforcement will apply unless a State certifies that it will assume those responsibilities. A certified State must adopt the same minimal standards but may adopt additional more stringent standards so long as they are compatible. Therefore, in States which participate in the hazardous liquid pipeline safety program through certification, it is necessary to distinguish the interstate from the intrastate pipeline facilities. 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 liq-
uids by pipeline is defined in much the same way. In implementing the HLPSA DOT has sought a practicable means of distinguishing between interstate and intrastate pipeline facilities that provide the requisite degree of certainty to Federal and State enforcement personnel and to the regulated entities. DOT intends that this statement of agency policy and interpretation provide that certainty.
In 1981, DOT decided that the inventory of liquid pipeline facilities identified as subject to the jurisdiction of FERC approximates the HLPSA category of "interstate pipeline facilities." Administrative use of the FERC inventory has the added benefit of avoiding the creation of a separate Federal scheme for determination of jurisdiction over the same regulated entities. DOT recognizes that the FERC inventory is only an approximation and may not be totally satisfactory without some modification. The difficulties stem from some significant differences in the economic regulation of liquid and of natural gas pipelines. There is an affirmative assertion of jurisdiction by FERC over natural gas pipelines through the issuance of certificates of public convenience and necessity prior to commencing operations. With liquid pipelines, there is only a rebuttable presumption of jurisdiction created by the filing by pipeline operators of tariffs (or concurrences) for movement of liquids through existing facilities. Although FERC does police the filings for such matters as compliance with the general duties of common carriers, the question of jurisdiction is normally only aired upon complaint. While any person, including State or Federal agencies, can avail themselves of the FERC forum by use of the complaint process, that process has only been rarely used to review jurisdictional matters (probably because of the infrequency of real disputes on the issue). Where the issue has arisen, the reviewing body has noted the need to examine various criteria primarily of an economic nature. DOT believes that, in most cases, the formal FERC forum can better receive and evaluate the type of information that is needed to make decisions of this nature than can DOT.
In delineating which liquid pipeline facilities are interstate pipeline facilities within the meaning of the HLPSA, DOT will generally rely on the FERC filings; that is, if there is a tariff or concurrence filed with FERC governing the transportation of hazardous liquids over a pipeline facility or if there has been an exemption from the obligation to file tariffs obtained from FERC, then DOT will, as a general rule, consider the facility to be an interstate pipeline facility within the meaning of the HLPSA. The types of situations in which DOT will ignore the existence or nonexistence 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.
Example 1. Pipeline company P operates a pipeline from "Point A" located in State X to "Point B" (alsoinX).Thephysicalfacilitiesnevercrossastatelineanddonotconnectwithanyotherpipelinewhichdoescrossastateline.PipelinecompanyPalsooperatesanotherpipelinebetween "PointC"inStateXand"PointD"inanadjoiningStateY.PipelinecompanyPfilesatariffwith FERCfortransportationfrom"PointA"to"PointB"aswellasfortransportationfrom"PointC"to "PointD."DOTwillignorefilingforthelinefrom"PointA"to"PointB"andconsiderthelinetobe intrastate.
Example 2. Same as in example 1 except that P does not file any tariffs with FERC. DOT will assumejurisdictionofthelinebetween"PointC"and"PointD."
Example 3. Same as in example 1 except that P files its tariff for the line between "Point C" and "PointD"notonlywithFERCbutalsowithStateX.DOTwillrelyontheFERCfilingasindication ofinterstatecommerce.
Example 4. Same as in example 1 except that the pipeline from "Point A" to "Point B" (in State X) connectswithapipelineoperatedbyanothercompanytransportsliquidbetween"PointB"(in StateX)and"PointD"(inStateY).DOTwillrelyontheFERCfilingasindicationofinterstatecommerce.
Example 5. Same as in example 1 except that the line between "Point C" and "Point D" has a laterallineconnectedtoit.ThelateralislocatedentirelywithStateX.DOTwillrelyontheexistence ornon-existenceofaFERCfilingcoveringtransportationoverthatlateralasdeterminativeof interstatecommerce.
Example 6. Same as in example 1 except that the certified agency in State X has brought an enforcementaction(underthepipelinesafetylaws)againstPbecauseofitsoperationoftheline between"PointA"and"PointB".Phassuccessfullydefendedagainsttheactiononjurisdictional grounds.DOTwillassumejurisdictionifnecessarytoavoidtheanomalyofapipelinesubjectto neitherStateorFederalsafetyenforcement.DOT'sassertionofjurisdictioninsuchacasewould bebasedonthegapinthestate'senforcementauthorityratherthanaDOTdecisionthatthepipelineisaninterstatepipelinefacility.
Example 7. Pipeline Company P operates a pipeline that originates on the Outer Continental Shelf.PdoesnotfileanytariffforthatlinewithFERC.DOTwillconsiderthepipelinetobean interstatepipelinefacility.
Example 8. Pipeline Company P is constructing a pipeline from "Point C" (in State X) to "Point D" (inStateY).DOTwillconsiderthepipelinetobeaninterstatepipelinefacility.
Example 9. Pipeline company P is constructing a pipeline from "Point C" to "Point E" (both in StateX)butintendstofiletariffswithFERCinthetransportationofhazardousliquidininterstate commerce.Assumingthereissomeconnectiontoaninterstatepipelinefacility,DOTwillconsider thislinetobeaninterstatepipelinefacility.
Example 10. Pipeline Company P has operated a pipeline subject to FERC economic regulation. Solelybecauseofsomestatutoryeconomicderegulation,thatpipelineisnolongerregulatedby FERC.DOTwillcontinuetoconsiderthatpipelinetobeaninterstatepipelinefacility.
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.
Appendix B to Part 195 — Risk-Based Alternative to Pressure Testing Older Hazardous Liquid and Carbon Dioxide Pipelines
Risk-Based Alternative This Appendix provides guidance on how a risk-based alternative to pressure testing older hazardous liquid and carbon dioxide pipelines rule allowed by §195.303 will work. This risk-based alternative establishes test priorities for older pipelines, not previously pressure tested, based on the inherent risk of a given pipeline segment. The first step is to determine the classification based on the type of pipe or on the pipeline segment's proximity to populated or environmentally sensitive area. Secondly, the classifications must be adjusted based on the pipeline failure history, product transported, and the release volume potential.
Tables 2-6 give definitions of risk classification A, B, and C facilities. For the purposes of this rule, pipeline segments containing high risk electric resistance-welded pipe (ERW pipe) and lapwelded pipe manufactured prior to 1970 and considered a risk classification C or B facility shall be treated as the top priority for testing because of the higher risk associated with the susceptibility of this pipe to longitudinal seam failures. In all cases, operators shall annually, at intervals not to exceed 15 months, review their facilities to reassess the classification and shall take appropriate action within two years or operate the pipeline system at a lower pressure. Pipeline failures, changes in the characteristics of the pipeline route, or changes in service should all trigger a reassessment of the originally classification.
Table 1 explains different levels of test requirements depending on the inherent risk of a given pipeline segment. The overall risk classification is determined based on the type of pipe involved, the facility's location, the product transported, the relative volume of flow and pipeline failure history as determined from Tables 2-6.
Table 1. Test Requirements — Mainline Segments Outside of Terminals, Stations, and Tank Farms
overall risk, with the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators used to adjust to a higher or lower overall risk classification per the following table.
Table 2 — Risk Classification
1If operational experience indicates a history of past failures for a particular pipeline segment, failure causes (time-dependent defects due to corrosion, construction, manufacture, or transmission problems, etc.) shall be reviewed in determining risk classification (See Table 6) and the timing of the pressure test should be accelerated.
2All pre-1970 ERW pipeline segments may not require testing. In determining which ERW pipeline segments should be included in this category, an operator must consider the seamrelated leak history of the pipe and pipe manufacturing information as available, which may include the pipe steel's mechanical properties, including fracture toughness; the manufacturing process and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality control of the steel-making process; and other factors pertinent to seam properties and quality.
3For those pipeline operators with extensive mileage of pre-1970 ERW pipe, any waiver requests for timing relief should be supported by an assessment of hazards in accordance with location, product, volume, and probability of failure considerations consistent with Tables 3, 4, 5, and 6.
4A magnetic flux leakage or ultrasonic internal inspection survey may be utilized as an alternative to pressure testing where leak history and operating experience do not indicate leaks caused by longitudinal cracks or seam failures.
5Pressure tests utilizing a hydrocarbon liquid may be conducted, but only with a liquid which does not vaporize rapidly.
Using LOCATION, PRODUCT, VOLUME, and FAILURE HISTORY "Indicators" from Tables 3, 4, 5, and 6 respectively, the overall risk classification of a given pipeline or pipeline segment can be established from Table 2. The LOCATION Indicator is the primary factor which determines
H=High M=Moderate L=Low.
Note: For Location, Product, Volume, and Probability of Failure Indicators, see Tables 3, 4, 5, and 6.
Table 3 is used to establish the LOCATION Indicator used in Table 2. Based on the population and environment characteristics associated with a pipeline facility's location, a LOCATION Indicator of H, M or L is selected.
Table 3 — Location Indicators — Pipeline Segments
1The effects of potential vapor migration should be considered for pipeline segments transporting highly volatile or toxic products.
2We expect operators to use their best judgment in applying this factor.
Tables 4, 5 and 6 are used to establish the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators respectively, in Table 2. The PRODUCT Indicator is selected from Table 4 as H, M, or L based on the acute and chronic hazards associated with the product transported. The VOLUME Indicator is selected from Table 5 as H, M, or L based on the nominal diameter of the pipeline. The Probability of Failure Indicator is selected from Table 6.
Table 4 — Product Indicators
Considerations: The degree of acute and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and, volatility, flammability, and water solubility determine the Product Indicator. Comprehensive Environmental Response, Compensation and Liability Act Reportable Quantity values can be used as an indication of chronic toxicity. National Fire Protection Association health factors can be used for rating acute hazards.
Table 5 — Volume Indicators
H=High M=Moderate L=Low.
Table 6 is used to establish the PROBABILITY OF FAILURE Indicator used in Table 2. The "Probability of Failure" Indicator is selected from Table 6 as H or L.
Table 6 — Probability of Failure Indicators [in each haz. location]
1Pipeline segments with greater than three product spills in the last 10 years should be reviewed for
2Time-Dependent Defects are defects that result in spills due to corrosion, gouges, or prob-
H=High L=Low.
Appendix C Part 195 — Guidance for Implementation of an Integrity Management Program
This Appendix gives guidance to help an operator implement the requirements of the integrity management program rule in §§195.450 and 195.452. Guidance is provided on:
(1) Information an operator may use to identify a high consequence area and factors an operator can use to consider the potential impacts of a release on an area;
(2) Risk factors an operator can use to determine an integrity assessment schedule;
(3) Safety risk indicator tables for leak history, volume or line size, age of pipeline, and product transported, an operator may use to determine if a pipeline segment falls into a high, medium or low risk category;
(4) Types of internal inspection tools an operator could use to find pipeline anomalies;
(5) Measures an operator could use to measure an integrity management program's performance; and
(6) Types of records an operator will have to maintain.
(7) Types of conditions that an integrity assessment may identify that an operator should include in its required schedule for evaluation and remediation.
I. Identifying a high consequence area and factors for considering a pipeline segment's potential impact on a high consequence area.
A. The rule defines a High Consequence Area as a high population area, an other populated area, an unusually sensitive area, or a commercially navigable waterway. The Office of Pipeline Safety (OPS) will map these areas on the National Pipeline Mapping System (NPMS). An operator, member of the public or other government agency may view and download the data from the NPMS home page http://www.npms.phmsa.gov/. OPS will maintain the NPMS and update it periodically. However, it is an operator's responsibility to ensure that it has identified all high consequence areas that could be affected by a pipeline segment. An operator is also responsible for periodically evaluating its pipeline segments to look for population or environmental changes that may have occurred around the pipeline and to keep its program current with this information. (Refer to §195.452(d)(3).)
(1) Digital Data on populated areas available on U.S. Census Bureau maps.
(2) Geographic Database on the commercial navigable waterways available on http://www.bts.gov/gis/ntatlas/networks.html.
(3) The Bureau of Transportation Statistics database that includes commercially navigable waterways and non-commercially navigable waterways. The database can be downloaded from the BTS website at http://www.bts.gov/gis/ntatlas/networks.html.
B. The rule requires an operator to include a process in its program for identifying which pipeline segments could affect a high consequence area and to take measures to prevent and mitigate the consequences of a pipeline failure that could affect a high consequence area. (See §§195.452 (f) and (i).) Thus, an operator will need to consider how each pipeline segment could affect a high consequence area. The primary source for the listed risk factors is a US DOT study on instrumented Internal Inspection devices (November 1992). Other sources include the National Transportation Safety Board, the Environmental Protection Agency and the Technical Hazardous Liquid Pipeline Safety Standards Committee. The following list provides guidance to an operator on both the mandatory and additional factors:
(1) Terrain surrounding the pipeline. An operator should consider the contour of the land profile and if it could allow the liquid from a release to enter a high consequence area. An operator can get this information from topographical maps such as U.S. Geological Survey quadrangle maps.
(2) Drainage systems such as small streams and other smaller waterways that could serve as a conduit to a high consequence area.
(3) Crossing of farm tile fields. An operator should consider the possibility of a spillage in the field following the drain tile into a waterway.
(4) Crossing of roadways with ditches along the side. The ditches could carry a spillage to a waterway.
(5) The nature and characteristics of the product the pipeline is transporting (refined products, crude oils, highly volatile liquids, etc.) Highly volatile liquids becomes gaseous when exposed to the atmosphere. A spillage could create a vapor cloud that could settle into the lower elevation of the ground profile.
(6) Physical support of the pipeline segment such as by a cable suspension bridge. An operator should look for stress indicators on the pipeline (strained supports, inadequate support at towers),
atmospheric corrosion, vandalism, and other obvious signs of improper maintenance.
(7) Operating conditions of the pipeline (pressure, flow rate, etc.). Exposure of the pipeline to an operating pressure exceeding the established maximum operating pressure.
(8) The hydraulic gradient of the pipeline.
(9) The diameter of the pipeline, the potential release volume, and the distance between the isolation points.
(10)Potential physical pathways between the pipeline and the high consequence area.
(11)Response capability (time to respond, nature of response).
(12)Potential natural forces inherent in the area (flood zones, earthquakes, subsidence areas, etc.)
II.Risk factors for establishing frequency of assessment.
A. By assigning weights or values to the risk factors, and using the risk indicator tables, an operator can determine the priority for assessing pipeline segments, beginning with those segments that are of highest risk, that have not previously been assessed. This list provides some guidance on some of the risk factors to consider (see §195.452(e)). An operator should also develop factors specific to each pipeline segment it is assessing, including:
(1) Populated areas, unusually sensitive environmental areas, National Fish Hatcheries, commercially navigable waters, areas where people congregate.
(2) Results from previous testing/inspection. (See §195.452(h).)
(3) Leak History. (See leak history risk table.)
(4) Known corrosion or condition of pipeline. (See §195.452(g).)
(5) Cathodic protection history.
(6) Type and quality of pipe coating (disbonded coating results in corrosion).
(7) Age of pipe (older pipe shows more corrosion — may be uncoated or have an ineffective coating) and type of pipe seam. (See Age of Pipe risk table.)
(8) Product transported (highly volatile, highly flammable and toxic liquids present a greater threat for both people and the environment) (see Product transported risk table.)
(9) Pipe wall thickness (thicker walls give a better safety margin)
(10)Size of pipe (higher volume release if the pipe ruptures).
(11)Location related to potential ground movement (e.g., seismic faults, rock quarries, and coal mines); climatic (permafrost causes settlement — Alaska); geologic (landslides or subsidence).
(12)Security of throughput (effects on customers if there is failure requiring shutdown).
(13)Time since the last internal inspection/pressure testing.
(14)With respect to previously discovered defects/anomalies, the type, growth rate, and size.
(15)Operating stress levels in the pipeline.
(16)Location of the pipeline segment as it relates to the ability of the operator to detect and respond to a leak. (e.g., pipelines deep underground, or in locations that make leak detection difficult without specific sectional monitoring and/or significantly impede access for spill response or any other purpose).
(17)Physical support of the segment such as by a cable suspension bridge.
(18)Non-standard or other than recognized industry practice on pipeline installation (e.g., horizontal directional drilling).
B. Example: This example illustrates a hypothetical model used to establish an integrity assessment schedule for a hypothetical pipeline segment. After we determine the risk factors applicable to the pipeline segment, we then assign values or numbers to each factor, such as, high (5), moderate (3), or low (1). We can determine an overall risk classification (A, B, C) for the segment using the risk tables and a sliding scale (values 5 to 1) for risk factors for which tables are not provided. We would classify a segment as C if it fell above 2⁄3 of maximum value (highest overall risk value for any one segment when compared with other segments of a pipeline), a segment as B if it fell between 1⁄3 to 2⁄3 of maximum value, and the remaining segments as A.
i. For the baseline assessment schedule, we would plan to assess 50% of all pipeline segments covered by the rule, beginning with the highest risk segments, within the first 31⁄2 years and the remaining segments within the seven-year period. For the continuing integrity assessments, we would plan to assess the C segments within the first two (2) years of the schedule, the segments classified as moderate risk no later than year three or four and the remaining lowest risk segments no later than year five (5).
ii. For our hypothetical pipeline segment, we have chosen the following risk factors and obtained risk factor values from the appropriate table. The values assigned to the risk factors are for illustration only.
Appendix C Part 195 – Transportation of
Age of pipeline: assume 30 years old (refer to "Age of Pipeline" risk table) — Risk Value=5
Pressure tested: tested once during construction — Risk Value=5
Coated: (yes/no) — yes
Coating Condition: Recent excavation of suspected areas showed holidays in coating (potential corrosion risk) — Risk Value=5
Date cathodic protection installed: five years after pipeline was constructed (Cathodic protection installed within one year of the pipeline's construction is generally considered low risk.) — Risk Value=3
Close interval survey: (yes/no) — no — Risk Value=5
Internal Inspection tool used: (yes/no) — yes. Date of pig run? In last five years — Risk Value=1
Anomalies found: (yes/no) — yes, but do not pose an immediate safety risk or environmental hazard — Risk Value=3
Leak History: yes, one spill in last 10 years. (refer to "Leak History" risk table) — Risk Value=2
iii. Overall risk value for this hypothetical segment of pipe is 34. Assume we have two other pipeline segments for which we conduct similar risk rankings. The second pipeline segment has an overall risk value of 20, and the third segment, 11. For the baseline assessment we would establish a schedule where we assess the first segment (highest risk segment) within two years, the second segment within five years and the third segment within seven years. Similarly, for the continuing integrity assessment, we could establish an assessment schedule where we assess the highest risk segment no later than the second year, the second segment no later than the third year, and the third segment no later than the fifth year.
III. Safety risk indicator tables for leak history, volume or line size, age of pipeline, and product transported.
An operator should consider at least two types of internal inspection tools for the integrity assessment from the following list. The type of tool or tools an operator selects will depend on the results from previous internal inspection runs, information analysis and risk factors specific to the pipeline segment:
(1) Geometry Internal inspection tools for detecting changes to ovality, e.g., bends, dents, buckles or wrinkles, due to construction flaws or soil movement, or other outside force damage;
(2) Metal Loss Tools (Ultrasonic and Magnetic Flux Leakage) for determining pipe wall anomalies, e.g., wall loss due to corrosion.
(3) Crack Detection Tools for detecting cracks and crack-like features, e.g., stress corrosion cracking (SCC), fatigue cracks, narrow axial corrosion, toe cracks, hook cracks, etc.
V. Methods to measure performance.
A. General.
(1) This guidance is to help an operator establish measures to evaluate the effectiveness of its integrity management program. The performance measures required will depend on the details of each integrity management program and will be based on an understanding and analysis of the failure mechanisms or threats to integrity of each pipeline segment.
(2) An operator should select a set of measurements to judge how well its program is performing. An operator's objectives for its program are to ensure public safety, prevent or minimize leaks and spills and prevent property and environmental damage. A typical integrity management program will be an ongoing program and it may contain many elements. Therefore, several performance measure are likely to be needed to measure the effectiveness of an ongoing program.
B. Performance measures. These measures show how a program to control risk on pipeline segments that could affect a high consequence area is progressing under the integrity management requirements. Performance measures generally fall into three categories:
(1) Selected Activity Measures — Measures that monitor the surveillance and preventive activities the operator has implemented. These measure indicate how well an operator is implementing the various elements of its integrity management program.
(2) Deterioration Measures — Operation and maintenance trends that indicate when the integrity of the system is weakening despite preventive measures. This category of performance measure may indicate that the system condition is deteriorating despite well executed preventive activities.
to corrosion, gouges, or problems developed during manufacture, construction or operation, etc.
1The degree of acute and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and, volatility, flammability, and water solubility determine the Product Indicator. Comprehensive Environmental Response, Compensation and Liability Act Reportable Quantity values may be used as an indication of chronic toxicity. National Fire Protection Association health factors may be used for rating acute hazards.
IV. Types of internal inspection tools to use.
(3) Failure Measures — Leak History, incident response, product loss, etc. These measures will indicate progress towards fewer spills and less damage.
C. Internal vs. External Comparisons. These comparisons show how a pipeline segment that could affect a high consequence area is progressing in comparison to the operator's other pipeline segments that are not covered by the integrity management requirements and how that pipeline segment compares to other operators' pipeline segments.
(1) Internal — Comparing data from the pipeline segment that could affect the high consequence area with data from pipeline segments in other areas of the system may indicate the effects from the attention given to the high consequence area.
(2) External — Comparing data external to the pipeline segment (e.g., OPS incident data) may provide measures on the frequency and size of leaks in relation to other companies.
D. Examples. Some examples of performance measures an operator could use include
(1) A performance measurement goal to reduce the total volume from unintended releases by -% (percent to be determined by operator) with an ultimate goal of zero.
(2) A performance measurement goal to reduce the total number of unintended releases (based on a threshold of 5 gallons) by __-% (percent to be determined by operator) with an ultimate goal of zero.
(3) A performance measurement goal to document the percentage of integrity management activities completed during the calendar year.
(4) A performance measurement goal to track and evaluate the effectiveness of the operator's community outreach activities.
(5) A narrative description of pipeline system integrity, including a summary of performance improvements, both qualitative and quantitative, to an operator's integrity management program prepared periodically.
(6) A performance measure based on internal audits of the operator's pipeline system per 49 CFR Part 195.
(7) A performance measure based on external audits of the operator's pipeline system per 49 CFR Part 195.
1 Time-dependent defects are those that result in spills due
1 Depends on pipeline's coating & corrosion condition, and steel quality, toughness, welding.
(8) A performance measure based on operational events (for example: relief occurrences, unplanned valve closure, SCADA outages, etc.) that have the potential to adversely affect pipeline integrity.
(9) A performance measure to demonstrate that the operator's integrity management program reduces risk over time with a focus on high risk items.
(10) A performance measure to demonstrate that the operator's integrity management program for pipeline stations and terminals reduces risk over time with a focus on high risk items.
VI. Examples of types of records an operator must maintain. The rule requires an operator to maintain certain records. (See §195.452(l)). This section provides examples of some records that an operator would have to maintain for inspection to comply with the requirement. This is not an exhaustive list.
(1) a process for identifying which pipelines could affect a high consequence area and a document identifying all pipeline segments that could affect a high consequence area;
(2) a plan for baseline assessment of the line pipe that includes each required plan element;
(3) modifications to the baseline plan and reasons for the modification;
(4) use of and support for an alternative practice;
(5) a framework addressing each required element of the integrity management program, updates and changes to the initial framework and eventual program;
(6) a process for identifying a new high consequence area and incorporating it into the baseline plan, particularly, a process for identifying population changes around a pipeline segment;
(7) an explanation of methods selected to assess the integrity of line pipe;
(8) a process for review of integrity assessment results and data analysis by a person qualified to evaluate the results and data;
(9) the process and risk factors for determining the baseline assessment interval;
(10) results of the baseline integrity assessment;
(11) the process used for continual evaluation, and risk factors used for determining the frequency of evaluation;
(12) process for integrating and analyzing information about the integrity of a pipeline, information and data used for the information analysis;
(13) results of the information analyses and periodic evaluations;
(14) the process and risk factors for establishing continual reassessment intervals;
(15) justification to support any variance from the required reassessment intervals;
(16) integrity assessment results and anomalies found, process for evaluating and remediating anomalies, criteria for remedial actions and actions taken to evaluate and remediate the anomalies;
(17) other remedial actions planned or taken;
(18) schedule for evaluation and remediation of anomalies, justification to support deviation from required remediation times;
(19) risk analysis used to identify additional preventive or mitigative measures, records of preventive and mitigative actions planned or taken;
(20) criteria for determining EFRD installation;
(21) criteria for evaluating and modifying leak detection capability;
(22) methods used to measure the program's effectiveness.
VII. Conditions that may impair a pipeline's integrity.
Section 195.452(h) requires an operator to evaluate and remediate all pipeline integrity issues raised by the integrity assessment or information analysis. An operator must develop a schedule that prioritizes conditions discovered on the pipeline for evaluation and remediation. The following are some examples of conditions that an operator should schedule for evaluation and remediation.
A. Any change since the previous assessment.
B. Mechanical damage that is located on the top side of the pipe.
C. An anomaly abrupt in nature.
D. An anomaly longitudinal in orientation.
E. An anomaly over a large area.
F. An anomaly located in or near a casing, a crossing of another pipeline, or an area with suspect cathodic protection.
Part 196 – Protection Of Underground Pipelines From Excavation Activity
Subpart
§196.1
Subpart
Subpart A – General
§196.1
What is the purpose and scope of this part?
This part prescribes the minimum requirements that excavators must follow to protect underground pipelines from excavation-related damage. It also establishes an enforcement process for violations of these requirements.
§196.3 Definitions
Damage or excavation damage means any excavation activity that results in the need to repair or replace a pipeline due to a weakening, or the partial or complete destruction, of the pipeline, including, but not limited to, the pipe, appurtenances to the pipe, protective coatings, support, cathodic protection or the housing for the line device or facility.
Excavation refers to excavation activities as defined in §192.614, and covers all excavation activity involving both mechanized and non-mechanized equipment, including hand tools.
Excavator means any person or legal entity, public or private, proposing to or engaging in excavation.
One-call means a notification system through which a person can notify pipeline operators of planned excavation to facilitate the locating and marking of any pipelines in the excavation area.
Pipeline means all parts of those physical facilities through which gas, carbon dioxide, or a hazardous liquid moves in transportation, including, but not limited to, pipe, valves, and other appurtenances attached or connected to pipe (including, but not limited to, tracer wire, radio frequency identification or other electronic marking system devices), pumping units, compressor units, metering stations, regulator stations, delivery stations, holders, fabricated assemblies, and breakout tanks.
Subpart B – Damage Prevention Requirements
§196.101 What is the purpose and scope of this subpart?
This subpart prescribes the minimum requirements that excavators must follow to protect pipelines subject to PHMSA or State pipeline safety regulations from excavation-related damage.
§196.103 What must an excavator do to protect underground pipelines from excavation-related damage?
Prior to and during excavation activity, the excavator must:
(a) Use an available one-call system before excavating to notify operators of underground pipeline facilities of the timing and location of the intended excavation; 196.103(a)
(b) If underground pipelines exist in the area, wait for the pipeline operator to arrive at the excavation site and establish and mark the location of its underground pipeline facilities before excavating; 196.103(b)
(c) Excavate with proper regard for the marked location of pipelines an operator has established by taking all practicable steps to prevent excavation damage to the pipeline; 196.103(c)
(d) Make additional use of one-call as necessary to obtain locating and marking before excavating to ensure that underground pipelines are not damaged by excavation. 196.103(d)
§196.105 [Reserved]
§196.107 What must an excavator do if a pipeline is damaged by excavation activity?
If a pipeline is damaged in any way by excavation activity, the excavator must promptly report such damage to the pipeline operator, whether or not a leak occurs, at the earliest practicable moment following discovery of the damage.
§196.109
What must an excavator do if damage to a pipeline from excavation activity causes a leak where product is released from the pipeline?
If damage to a pipeline from excavation activity causes the release of any PHMSA regulated natural and other gas or hazardous liquid as defined in part 192, 193, or 195 of this chapter from the pipeline, the excavator must promptly report the release to appropriate emergency response authorities by calling the 911 emergency telephone number.
§196.111
What if a pipeline operator fails to respond to a locate request or fails to accurately locate and mark its pipeline?
PHMSA may enforce existing requirements applicable to pipeline operators, including those specified in 49 CFR 192.614 and 195.442 and 49 U.S.C. 60114 if a pipeline operator fails to properly respond to a locate request or fails to accurately locate and mark its pipeline. The limitation in 49 U.S.C. 60114(f) does not apply to enforcement taken against pipeline operators and excavators working for pipeline operators.
Subpart C – Administrative Enforcement Process
§196.201 What is the purpose and scope of this subpart?
This subpart describes the enforcement authority and sanctions exercised by the Associate Administrator for Pipeline Safety for achieving and maintaining pipeline safety under this part. It also prescribes the procedures governing the exercise of that authority and the imposition of those sanctions.
§196.203 What is the administrative process PHMSA will use to conduct enforcement proceedings for alleged violations of excavation damage prevention requirements?
PHMSA will use the existing administrative adjudication process for alleged pipeline safety violations set forth in 49 CFR part 190, subpart B. This process provides for notification that a probable violation has been committed, a 30-day period to respond including the opportunity to request an administrative hearing, the issuance of a final order, and the opportunity to petition for reconsideration.
§196.205 Can PHMSA assess administrative civil penalties for violations?
Yes. When the Associate Administrator for Pipeline Safety has reason to believe that a person has violated any provision of the 49 U.S.C. 60101 et seq. or any regulation or order issued thereunder, including a violation of excavation damage prevention requirements under this part and 49 U.S.C. 60114(d) in a State with an excavation damage prevention law enforcement program PHMSA has deemed inadequate under 49 CFR part 198, subpart D, PHMSA may conduct a proceeding to determine the nature and extent of the violation and to assess a civil penalty.
§196.207 What are the maximum administrative civil penalties for violations?
The maximum administrative civil penalties that may be imposed are specified in 49 U.S.C. 60122.
§196.209 May other civil enforcement actions be taken?
Whenever the Associate Administrator has reason to believe 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 et seq., or any regulations issued thereunder, PHMSA, or the person to whom the authority has been delegated, may request the Attorney General to bring an action in the appropriate U.S. District Court for such relief as is necessary or appropriate, including mandatory or prohibitive injunctive relief, interim equitable relief, civil penalties, and punitive damages as provided under 49 U.S.C. 60120.
§196.211 May criminal penalties be imposed?
Yes. Criminal penalties may be imposed as specified in 49 U.S.C. 60123.
198 – Regulations For Grants To Aid State
Subpart A – General
§198.1 Scope
This part prescribes
§198.3 Definitions
As used in this part:
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Adopt means establish under State law by statute, regulation, license, certification, order, or any combination of these legal means.
Excavation activity means an excavation activity defined in §192.614(a) of this chapter, other than a specific activity the State determines would not be expected to cause physical damage to underground facilities.
Excavator means any person intending to engage in an excavation activity.
One-call notification system means a communication system that qualifies under this part and the one-call damage prevention program of the State concerned in which an operational center receives notices from excavators of intended excavation activities and transmits the notices to operators of underground pipeline facilities and other underground facilities that participate in the system.
Person means any individual, firm, joint venture, partnership, corporation, association, state, municipality, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative thereof.
Underground pipeline facilities means buried pipeline facilities used in the transportation of gas or hazardous liquid subject to the pipeline safety laws (49 U.S.C. 60101 et seq.).
Secretary means the Secretary of Transportation or any person to whom the Secretary of Transportation has delegated authority in the matter concerned.
Seeking to adopt means actively and effectively proceeding toward adoption.
State means each of the several States, the District of Columbia, and the Commonwealth of Puerto Rico.
Subpart B – Grant Allocation
§198.11
Grant authority
The pipeline safety laws (49 U.S.C. 60101 et seq.) authorize the Administrator to pay out funds appropriated or otherwise make available up to 80 percent of the cost of the personnel, equipment, and activities reasonably required for each state agency to carry out a safety program for intrastate pipeline facilities under a certification or agreement with the Administrator or to act as an agent of the Administrator with respect to interstate pipeline facilities.
§198.13
Grant allocation formula
(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. 198.13(a)
(b) A state's annual grant allocation is based on maximum of 100 performance points derived as follows: 198.13(b)
(1) Fifty points based on information provided in the state's annual certification/agreement attachments which document its activities for the past year; and 198.13(b)(1)
(2) Fifty points based on the annual state program evaluation. 198.13(b)(2)
(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: 198.13(c)
(1) Adequacy of state operating practices;198.13(c)(1)
(2) Quality of state inspections, investigations, and enforcement/compliance actions; 198.13(c)(2)
(3) Adequacy of state recordkeeping;198.13(c)(3)
(4) Extent of state safety regulatory jurisdiction over pipeline facilities; 198.13(c)(4)
(5) Qualifications of state inspectors;198.13(c)(5)
(6) Number of state inspection person-days;198.13(c)(6)
(7) State adoption of applicable federal pipeline safety standards; and 198.13(c)(7)
(8) Any other factor the Administrator deems necessary to measure performance. 198.13(c)(8)
(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. 198.13(d)
(e) The Administrator notifies each state agency in writing of the specific performance factors to be used and the weights to be assigned to each factor at least 9 months prior to allocating funds. Prior to notification, PHMSA seeks state agency comments on any proposed changes to the allocation formula. 198.13(e)
(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. 198.13(f)
Subpart C – Adoption of One-Call Damage Prevention Program
§198.31 Scope
This subpart implements parts of the pipeline safety laws (49 U.S.C. 60101 et seq.), which direct the Secretary to require each State to adopt a one-call damage prevention program as a condition to receiving a full grant-in-aid for its pipeline safety compliance program.
§198.33 [Reserved]
§198.35 Grants conditioned on adoption of one-call damage prevention program
In allocating grants to State agencies under the pipeline safety laws, (49 U.S.C. 60101 et seq.), the Secretary considers whether a State has adopted or is seeking to adopt a one-call damage prevention program in accordance with §198.37. If a State has not adopted or is not seeking to adopt such program, the State agency may not receive the full reimbursement to which it would otherwise be entitled.
§198.37
State one-call damage prevention program
A State must adopt a one-call damage prevention program that requires each of the following at a minimum:
(a) Each area of the State that contains underground pipeline facilities must be covered by a one-call notification system. 198.37(a)
(b) Each one-call notification system must be operated in accordance with §198.39. 198.37(b)
(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: 198.37(c)
(1) Name of the person notifying the system.198.37(c)(1)
(2) Name, address and telephone number of the excavator. 198.37(c)(2)
(3) Specific location, starting date, and description of the intended excavation activity. 198.37(c)(3)
However, an excavator must be allowed to begin an excavation activity in an emergency but, in doing so, required to notify the operational center at the earliest practicable moment.
(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. 198.37(d)
(e) Except with respect to interstate transmission facilities as defined in the pipeline safety laws (49 U.S.C. 60101 et seq.), operators of underground pipeline facilities must be required to participate in the one-call notification systems that cover the areas of the State in which those pipeline facilities are located. 198.37(e)
(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 (c)(4) through (c)(6) of this chapter to notices of intended excavation activity received from the operational center of a one-call notification system. 198.37(f)
(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. 198.37(g)
(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 et seq.), and interstate pipelines as defined in §195.2 of this chapter), excavators and persons who operate one-call notification systems who violate the applicable requirements of this subpart must be subject to civil penalties and injunctive relief that are substantially the same as are provided under the pipeline safety laws (49 U.S.C. 60101 et seq.). 198.37(h)
§198.39 Qualifications for operation of one-call notification system
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: 198.39(a)
(1) A person who operates underground pipeline facilities or other underground facilities. 198.39(a)(1)
(2) A private contractor.198.39(a)(2)
(3) A State or local government agency.198.39(a)(3)
(4) A person who is otherwise eligible under State law to operate a one-call notification system. 198.39(a)(4)
(b) It receives and records information from excavators about intended excavation activities. 198.39(b)
(c) It promptly transmits to the appropriate operators of underground pipeline facilities the information received from excavators about intended excavation activities. 198.39(c)
(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. 198.39(d)
(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. 198.39(e)
Subpart D – State Damage Prevention Enforcement Programs
§198.51 What is the purpose and scope of this subpart?
This subpart establishes standards for effective State damage prevention enforcement programs and prescribes the administrative procedures available to a State that elects to contest a notice of inadequacy.
§198.53 When and how will PHMSA evaluate State damage prevention enforcement programs?
PHMSA conducts annual program evaluations and certification reviews of State pipeline safety programs. PHMSA will also conduct annual reviews of State excavation damage prevention law enforcement programs. PHMSA will use the criteria described in §198.55 as the basis for the enforcement program reviews, utilizing information obtained from any State agency or office with a role in the State's excavation damage prevention law enforcement program. If PHMSA finds a State's enforcement program inadequate, PHMSA may take immediate enforcement against excavators in that State. The State will have five years from the date of the finding to make program improvements that meet PHMSA's criteria for minimum adequacy. A State that fails to establish an adequate enforcement program in accordance with §198.55 within five years of the
finding of inadequacy may be subject to reduced grant funding established under 49 U.S.C. 60107. PHMSA will determine the amount of the reduction using the same process it uses to distribute the grant funding; PHMSA will factor the findings from the annual review of the excavation damage prevention enforcement program into the 49 U.S.C. 60107 grant funding distribution to State pipeline safety programs. The amount of the reduction in 49 U.S.C. 60107 grant funding will not exceed four percent (4%) of prior year funding (not cumulative). If a State fails to implement an adequate enforcement program within five years of a finding of inadequacy, the Governor of that State may petition the Administrator of PHMSA, in writing, for a temporary waiver of the penalty, provided the petition includes a clear plan of action and timeline for achieving program adequacy.
§198.55 What criteria will PHMSA use in evaluating the effectiveness of State damage prevention enforcement programs?
(a) PHMSA will use the following criteria to evaluate the effectiveness of a State excavation damage prevention enforcement program: 198.55(a)
(1) Does the State have the authority to enforce its State excavation damage prevention law using civil penalties and other appropriate sanctions for violations? 198.55(a)(1)
(2) Has the State designated a State agency or other body as the authority responsible for enforcement of the State excavation damage prevention law? 198.55(a)(2)
(3) Is the State assessing civil penalties and other appropriate sanctions for violations at levels sufficient to deter noncompliance and is the State making publicly available information that demonstrates the effectiveness of the State's enforcement program?
198.55(a)(3)
(4) Does the enforcement authority (if one exists) have a reliable mechanism (e.g., mandatory reporting, complaint-driven reporting) for learning about excavation damage to underground facilities?
198.55(a)(4)
(5) Does the State employ excavation damage investigation practices that are adequate to determine the responsible party or parties when excavation damage to underground facilities occurs?
198.55(a)(5)
(6) At a minimum, do the State's excavation damage prevention requirements include the following: 198.55(a)(6)
(i) Excavators may not engage in excavation activity without first using an available one-call notification system to establish the location of underground facilities in the excavation area. 198.55(a)(6)(i)
(ii) Excavators may not engage in excavation activity in disregard of the marked location of a pipeline facility as established by a pipeline operator.198.55(a)(6)(ii)
(iii) An excavator who causes damage to a pipeline facility: 198.55(a)(6)(iii)
[A] Must report the damage to the operator of the facility at the earliest practical moment following discovery of the damage; and198.55(a)(6)(iii)[A]
[B] If the damage results in the escape of any PHMSA regulated natural and other gas or hazardous liquid, must promptly report to other appropriate authorities by calling the 911 emergency telephone number or another emergency telephone number.198.55(a)(6)(iii)[B]
(7) Does the State limit exemptions for excavators from its excavation damage prevention law? A State must provide to PHMSA a written justification for any exemptions for excavators from State damage prevention requirements. PHMSA will make the written justifications available to the public. 198.55(a)(7)
(b) PHMSA may consider individual enforcement actions taken by a State in evaluating the effectiveness of a State's damage prevention enforcement program. 198.55(b)
§198.57 What is the process PHMSA will use to notify a State that its damage prevention enforcement program appears to be inadequate?
PHMSA will issue a notice of inadequacy to the State in accordance with 49 CFR 190.5. The notice will state the basis for PHMSA's determination that the State's damage prevention enforcement program appears inadequate for purposes of this subpart and set forth the State's response options.
§198.59 How may a State respond to a notice of inadequacy?
A State receiving a notice of inadequacy will have 30 days from receipt of the notice to submit a written response to the PHMSA official who issued the notice. In its response, the State may include information and explanations concerning the alleged inadequacy or contest the allegation of inadequacy and request the notice be withdrawn.
§198.61 How is a State notified of PHMSA's final decision?
PHMSA will issue a final decision on whether the State's damage prevention enforcement program has been found inadequate in accordance with 49 CFR 190.5.
§198.63 How may a State with an inadequate damage prevention enforcement program seek reconsideration by PHMSA?
At any time following a finding of inadequacy, the State may petition PHMSA to reconsider such finding based on changed circumstances including improvements in the State's enforcement program. Upon receiving a petition, PHMSA will reconsider its finding of inadequacy promptly and will notify the State of its decision on reconsideration promptly but no later than the time of the next annual certification review.
Subpart A – General
§199.1 Scope
This part requires operators of pipeline facilities subject to part 192, 193, or 195 of this chapter to test covered employees for the presence of prohibited drugs and alcohol.
§199.2 Applicability
(a) This part applies to pipeline operators only with respect to employees located within the territory of the United States, including those employees located within the limits of the "Outer Continental Shelf" as that term is defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331). 199.2(a)
(b) This part does not apply to any person for whom compliance with this part would violate the domestic laws or policies of another country. 199.2(b)
(c) This part does not apply to covered functions performed on — 199.2(c)
(1) Master meter systems, as defined in §191.3 of this chapter; or 199.2(c)(1)
(2) Pipeline systems that transport only petroleum gas or petroleum gas/air mixtures. 199.2(c)(2)
§199.3 Definitions
As used in this part —
Accident means an incident reportable under part 191 of this chapter involving gas pipeline facilities or LNG facilities, or an accident reportable under part 195 of this chapter involving hazardous liquid pipeline facilities.
Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or her delegate.
Covered employee, employee, or individual to be tested means a person who performs a covered function, including persons employed by operators, contractors engaged by operators, and persons employed by such contractors.
Covered function means an operations, maintenance, or emergencyresponse function regulated by part 192, 193, or 195 of this chapter that is performed on a pipeline or on an LNG facility.
DOT Procedures means the Procedures for Transportation Workplace Drug and Alcohol Testing Programs published by the Office of the Secretary of Transportation in part 40 of this title.
Fail a drug test means that the confirmation test result shows positive evidence of the presence under DOT Procedures of a prohibited drug in an employee's system.
Operator means a person who owns or operates pipeline facilities subject to part 192, 193, or 195 of this chapter.
Pass a drug test means that initial testing or confirmation testing under DOT Procedures does not show evidence of the presence of a prohibited drug in a person's system.
Performs a covered function includes actually performing, ready to perform, or immediately available to perform a covered function.
Positive rate for random drug testing means the number of verified positive results for random drug tests conducted under this part plus the number of refusals of random drug tests required by this part, divided by the total number of random drug tests results (i.e., positives, negatives, and refusals) under this part.
Prohibited drug means any of the substances specified in 49 CFR part 40.
Refuse to submit, refuse, or refuse to take means behavior consistent with DOT Procedures concerning refusal to take a drug test or refusal to take an alcohol test.
State agency means an agency of any of the several states, the District of Columbia, or Puerto Rico that participates under the pipeline safety laws (49 U.S.C. 60101 et seq.)
§199.5 DOT procedures
The anti-drug and alcohol programs required by this part must be conducted according to the requirements of this part and DOT Procedures. Terms and concepts used in this part have the same meaning as in DOT Procedures. Violations of DOT Procedures with respect to anti-drug and alcohol programs required by this part are violations of this part.
§199.7
Stand-down waivers
(a) Each operator who seeks a waiver under §40.21 of this title from the stand-down restriction must submit an application for waiver in duplicate to the Associate Administrator for Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue, SE, Washington, DC 20590-0001. 199.7(a)
(b) Each application must — 199.7(b)
(1) Identify §40.21 of this title as the rule from which the waiver is sought; 199.7(b)(1)
(2) Explain why the waiver is requested and describe the employees to be covered by the waiver; 199.7(b)(2)
(3) Contain the information required by §40.21 of this title and any other information or arguments available to support the waiver requested; and 199.7(b)(3)
(4) Unless good cause is shown in the application, be submitted at least 60 days before the proposed effective date of the waiver. 199.7(b)(4)
(c) No public hearing or other proceeding is held directly on an application before its disposition under this section. If the Associate Administrator determines that the application contains adequate justification, he or she grants the waiver. If the Associate Administrator determines that the application does not justify granting the waiver, he or she denies the application. The Associate Administrator notifies each applicant of the decision to grant or deny an application. 199.7(c)
§199.9 Preemption of State and local laws
(a) Except as provided in paragraph (b) of this section, this part preempts any State or local law, rule, regulation, or order to the extent that: 199.9(a)
(1) Compliance with both the State or local requirement and this part is not possible; 199.9(a)(1)
(2) Compliance with the State or local requirement is an obstacle to the accomplishment and execution of any requirement in this part; or 199.9(a)(2)
(3) The State or local requirement is a pipeline safety standard applicable to interstate pipeline facilities. 199.9(a)(3)
(b) This part shall not be construed to preempt provisions of State criminal law that impose sanctions for reckless conduct leading to actual loss of life, injury, or damage to property, whether the provisions apply specifically to transportation employees or employers or to the general public. 199.9(b)
Subpart B – Drug Testing
§199.100 Purpose
The purpose of this subpart is to establish programs designed to help prevent accidents and injuries resulting from the use of prohibited drugs by employees who perform covered functions for operators of certain pipeline facilities subject to part 192, 193, or 195 of this chapter.
§199.107 Drug testing laboratory
§199.101 Anti-drug plan
(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 — 199.101(a)
(1) Methods and procedures for compliance with all the requirements of this part, including the employee assistance program; 199.101(a)(1)
(2) The name and address of each laboratory that analyzes the specimens collected for drug testing; 199.101(a)(2)
(3) The name and address of the operator's Medical Review Officer, and Substance Abuse Professional; and 199.101(a)(3)
(4) Procedures for notifying employees of the coverage and provisions of the plan. 199.101(a)(4)
(b) The Associate Administrator or the State Agency that has submitted a current certification under the pipeline safety laws (49 U.S.C. 60101 et seq.) 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 190.206 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety. 199.101(b)
§199.103 Use of persons who fail or refuse a drug test
(a) An operator may not knowingly use as an employee any person who — 199.103(a)
(1) Fails a drug test required by this part and the medical review officer makes a determination under DOT Procedures; or 199.103(a)(1)
(2) Refuses to take a drug test required by this part. 199.103(a)(2)
(b) Paragraph (a)(1) of this section does not apply to a person who has — 199.103(b)
(1) Passed a drug test under DOT Procedures; 199.103(b)(1)
(2) Been considered by the medical review officer in accordance with DOT Procedures and been determined by a substance abuse professional to have successfully completed required education or treatment; and 199.103(b)(2)
(3) Not failed a drug test required by this part after returning to duty. 199.103(b)(3)
§199.105 Drug tests required
Each operator shall conduct the following drug tests for the presence of a prohibited drug:
(a) Pre-employment testing. No operator may hire or contract for the use of any person as an employee unless that person passes a drug test or is covered by an anti-drug program that conforms to the requirements of this part. 199.105(a)
(b) Post-accident testing. 199.105(b)
(1) As soon as possible but no later than 32 hours after an accident, an operator must drug test each surviving covered employee whose performance of a covered function either contributed to the accident or cannot be completely discounted as a contributing factor to the accident. An operator may decide not to test under this paragraph but such a decision must be based on specific information that the covered employee's performance had no role in the cause(s) or severity of the accident. 199.105(b)(1)
(2) If a test required by this section is not administered within the 32 hours following the accident, the operator must prepare and maintain its decision stating the reasons why the test was not promptly administered. If a test required by paragraph (b)(1) of this section is not administered within 32 hours following the accident, the operator must cease attempts to administer a drug test and must state in the record the reasons for not administering the test. 199.105(b)(2)
(c) Random testing. 199.105(c)
(1) Except as provided in paragraphs (c)(2) through (4) of this section, the minimum annual percentage rate for random drug testing shall be 50 percent of covered employees. 199.105(c)(1)
(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 Federal Register the minimum annual percentage rate for random drug testing of covered employees. The new minimum annual percentage rate for random drug testing will be applicable starting January 1 of the calendar year following publication. 199.105(c)(2)
(3) When the minimum annual percentage rate for random drug testing is 50 percent, the Administrator may lower this rate to 25 percent of all covered employees if the Administrator determines that
the data received under the reporting requirements of §199.119 for two consecutive calendar years indicate that the reported positive rate is less than 1.0 percent. 199.105(c)(3)
(4) When the minimum annual percentage rate for random drug testing is 25 percent, and the data received under the reporting requirements of §199.119 for any calendar year indicate that the reported positive rate is equal to or greater than 1.0 percent, the Administrator will increase the minimum annual percentage rate for random drug testing to 50 percent of all covered employees. 199.105(c)(4)
(5) The selection of employees for random drug testing shall be made by a scientifically valid method, such as a random number table or a computer-based random number generator that is matched with employees' Social Security numbers, payroll identification numbers, or other comparable identifying numbers. Under the selection process used, each covered employee shall have an equal chance of being tested each time selections are made. 199.105(c)(5)
(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. 199.105(c)(6)
(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. 199.105(c)(7)
(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. 199.105(c)(8)
(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 — 199.105(c)(9)
(i) Establish separate pools for random selection, with each pool containing the covered employees who are subject to testing at the same required rate; or199.105(c)(9)(i)
(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.199.105(c)(9)(ii)
(d) Testing based on reasonable cause. Each operator shall drug test each employee when there is reasonable cause to believe the employee is using a prohibited drug. The decision to test must be based on a reasonable and articulable belief that the employee is using a prohibited drug on the basis of specific, contemporaneous physical, behavioral, or performance indicators of probable drug use. At least two of the employee's supervisors, one of whom is trained in detection of the possible symptoms of drug use, shall substantiate and concur in the decision to test an employee. The concurrence between the two supervisors may be by telephone. However, in the case of operators with 50 or fewer employees subject to testing under this part, only one supervisor of the employee trained in detecting possible drug use symptoms shall substantiate the decision to test. 199.105(d)
(e) Return-to-duty testing. A covered employee who refuses to take or has a positive drug test may not return to duty in the covered function until the covered employee has complied with applicable provisions of DOT Procedures concerning substance abuse professionals and the return-to-duty process. 199.105(e)
(f) Follow-up testing. A covered employee who refuses to take or has a positive drug test shall be subject to unannounced follow-up drug tests administered by the operator following the covered 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 covered employee's return to duty. In addition, followup testing may include testing for alcohol 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 covered 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. 199.105(f)
§199.107 Drug testing laboratory
(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. 199.107(a)
(b) The drug testing laboratory must permit — 199.107(b)
(1) Inspections by the operator before the laboratory is awarded a testing contract; and 199.107(b)(1)
(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. 199.107(b)(2)
§199.109 Review of drug testing results
(a) MRO appointment. Each operator shall designate or appoint a medical review officer (MRO). If an operator does not have a qualified individual on staff to serve as MRO, the operator may contract for the provision of MRO services as part of its anti-drug program. 199.109(a)
(b) MRO qualifications. Each MRO must be a licensed physician who has the qualifications required by DOT Procedures. 199.109(b)
(c) MRO duties. The MRO must perform functions for the operator as required by DOT Procedures. 199.109(c)
(d) MRO reports. The MRO must report all drug test results to the operator in accordance with DOT Procedures. 199.109(d)
(e) Evaluation and rehabilitation may be provided by the operator, by a substance abuse professional under contract with the operator, or by a substance abuse professional not affiliated with the operator. The choice of substance abuse professional and assignment of costs shall be made in accordance with the operator/ employee agreements and operator/employee policies. 199.109(e)
(f) The operator shall ensure that a substance abuse professional, who determines that a covered employee requires assistance in resolving problems with drug abuse, does not refer the covered employee to the substance abuse professional's private practice or to a person or organization from which the substance abuse professional receives remuneration or in which the substance abuse professional has a financial interest. This paragraph does not prohibit a substance abuse professional from referring a covered employee for assistance provided through: 199.109(f)
(1) A public agency, such as a State, county, or municipality; 199.109(f)(1)
(2) The operator or a person under contract to provide treatment for drug problems on behalf of the operator; 199.109(f)(2)
(3) The sole source of therapeutically appropriate treatment under the employee's health insurance program; or 199.109(f)(3)
(4) The sole source of therapeutically appropriate treatment reasonably accessible to the employee. 199.109(f)(4)
§199.111 [Reserved]
§199.113
Employee assistance program
(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. 199.113(a)
(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. 199.113(b)
(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. 199.113(c)
§199.115
Contractor employees
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 199.115(a)
(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. 199.115(b)
§199.117 Recordkeeping
(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: 199.117(a)
(1) Records that demonstrate the collection process conforms to this part must be kept for at least 3 years. 199.117(a)(1)
(2) Records of employee drug test that indicate a verified positive result, records that demonstrate compliance with the recommendations of a substance abuse professional, and MIS annual report data shall be maintained for a minimum of five years. 199.117(a)(2)
(3) Records of employee drug test results that show employees passed a drug test must be kept for at least 1 year. 199.117(a)(3)
(4) Records confirming that supervisors and employees have been trained as required by this part must be kept for at least 3 years. 199.117(a)(4)
(5) Records of decisions not to administer post-accident employee drug tests must be kept for at least 3 years. 199.117(a)(5)
(b) Information regarding an individual's drug testing results or rehabilitation must be released upon the written consent of the individual and as provided by DOT Procedures. Statistical data related to drug testing and rehabilitation that is not name-specific and training records must be made available to the Administrator or the representative of a state agency upon request. 199.117(b)
§199.119 Reporting of anti-drug testing results
(a) Each large operator (having more than 50 covered employees) must submit an annual Management Information System (MIS) report to PHMSA of its anti-drug testing using the MIS form and instructions as required by 49 CFR part 40 (at §40.26 and appendix H to part 40), not later than March 15 of each year for the prior calendar year (January 1 through December 31). The Administrator may require by notice in the PHMSA Portal (https://portal.phmsa.dot.gov/phmsaportallanding) that small operators (50 or fewer covered employees), not otherwise required to submit annual MIS reports, to prepare and submit such reports to PHMSA. 199.119(a)
(b) Each report required under this section must be submitted electronically at http://damis.dot.gov. An operator may obtain the user name and password needed for electronic reporting from the PHMSA Portal (https://portal.phmsa.dot.gov/phmsaportallanding). If electronic reporting imposes an undue burden and hardship, the operator may submit a written request for an alternative reporting method to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590. The request must describe the undue burden and hardship. PHMSA will review the request and may authorize, in writing, an alternative reporting method. An authorization will state the period for which it is valid, which may be indefinite. An operator must contact PHMSA at 202-366-8075, or electronically to informationresourcesmanager@dot.gov to make arrangements for submitting a report that is due after a request for alternative reporting is submitted but before an authorization or denial is received. 199.119(b)
(c) To calculate the total number of covered employees eligible for random testing throughout the year, as an operator, you must add the total number of covered employees eligible for testing during each random testing period for the year and divide that total by the number of random testing periods. Covered employees, and only covered employees, are to be in an employer's random testing pool, and all covered employees must be in the random pool. If you are an employer conducting random testing more often than once per month (e.g., you select daily, weekly, bi-weekly), you do not need to compute this total number of covered employees rate more than on a once per month basis. 199.119(c)
(d) As an employer, you may use a service agent (e.g., C/TPA) to perform random selections for you; and your covered employees may be part of a larger random testing pool of covered employees. However, you must ensure that the service agent you use is testing at the appropriate percentage established for your industry and that only covered employees are in the random testing pool. 199.119(d)
(e) Each operator that has a covered employee who performs multiDOT agency functions (e.g., an employee performs pipeline maintenance duties and drives a commercial motor vehicle), count the employee only on the MIS report for the DOT agency under which he or she is randomly tested. Normally, this will be the DOT agency under which the employee performs more than 50% of his or her duties. Operators may have to explain the testing data for these employees in the event of a DOT agency inspection or audit. 199.119(e)
(f) A service agent (e.g., Consortia/Third Party Administrator as defined in 49 CFR part 40) may prepare the MIS report on behalf of an operator. However, each report shall be certified by the operator's anti-drug manager or designated representative for accuracy and completeness. 199.119(f)
Subpart C – Alcohol Misuse Prevention Program
§199.200 Purpose
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.
§199.201 [Reserved]
§199.202 Alcohol misuse plan
Each operator must maintain and follow a written alcohol misuse plan that conforms to the requirements of this part and DOT Procedures concerning alcohol testing programs. The plan shall contain methods and procedures for compliance with all the requirements of this subpart, including required testing, recordkeeping, reporting, education and training elements.
§§199.203-199.205 — [Reserved]
§199.209 Other requirements imposed by operators
(a) Except as expressly provided in this subpart, nothing in this subpart shall be construed to affect the authority of operators, or the rights of employees, with respect to the use or possession of alcohol, including authority and rights with respect to alcohol testing and rehabilitation. 199.209(a)
(b) Operators may, but are not required to, conduct pre-employment alcohol testing under this subpart. Each operator that conducts pre-employment alcohol testing must — 199.209(b)
(1) Conduct a pre-employment alcohol test before the first performance of covered functions by every covered employee (whether a new employee or someone who has transferred to a position involving the performance of covered functions); 199.209(b)(1)
(2) Treat all covered employees the same for the purpose of preemployment alcohol testing (i.e., you must not test some covered employees and not others); 199.209(b)(2)
(3) Conduct the pre-employment tests after making a contingent offer of employment or transfer, subject to the employee passing the pre-employment alcohol test; 199.209(b)(3)
(4) Conduct all pre-employment alcohol tests using the alcohol testing procedures in DOT Procedures; and 199.209(b)(4)
(5) Not allow any covered employee to begin performing covered functions unless the result of the employee's test indicates an alcohol concentration of less than 0.04. 199.209(b)(5)
§199.211 Requirement for notice
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.
§199.213 [Reserved]
§199.215 Alcohol concentration
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.
§199.217 On-duty use
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.
§199.219 Pre-duty use
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.
§199.221 Use following an accident
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.
§199.223
Refusal to submit to a required alcohol test
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.
§199.225 Alcohol tests required
Each operator must conduct the following types of alcohol tests for the presence of alcohol:
(a) Post-accident. 199.225(a)
(1) As soon as practicable following an accident, each operator must test each surviving covered employee for alcohol if that employee's performance of a covered function either contributed to the accident or cannot be completely discounted as a contributing factor to the accident. The decision not to administer a test under this section must be based on specific information that the covered employee's performance had no role in the cause(s) or severity of the accident. 199.225(a)(1)
(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.
199.225(a)(2)(i)
(ii) [Reserved]199.225(a)(2)(ii)
(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. 199.225(a)(3)
(b) Reasonable suspicion testing. 199.225(b)
(1) Each operator shall require a covered employee to submit to an alcohol test when the operator has reasonable suspicion to believe that the employee has violated the prohibitions in this subpart. 199.225(b)(1)
(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. 199.225(b)(2)
(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. 199.225(b)(3)
(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 sec-
tion, the operator shall cease attempts to administer an alcohol test and shall state in the record the reasons for not administering the test. Records shall be submitted to PHMSA upon request of the Administrator.199.225(b)(4)(i)
(ii) [Reserved]199.225(b)(4)(ii)
(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:199.225(b)(4)(iii)
[A] An alcohol test is administered and the employee's alcohol concentration measures less than 0.02; or199.225(b)(4)(iii)[A]
[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.199.225(b)(4)(iii)[B]
(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.199.225(b)(4)(iv)
(c) Return-to-duty testing. Each operator shall ensure that 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, the employee shall undergo a returnto-duty alcohol test with a result indicating an alcohol concentration of less than 0.02. 199.225(c)
(d) Follow-up testing. 199.225(d)
(1) Following a determination under §199.243(b) that a covered employee is in need of assistance in resolving problems associated with alcohol misuse, each operator shall ensure that the employee is subject to unannounced follow-up alcohol testing as directed by a substance abuse professional in accordance with the provisions of §199.243(c)(2)(ii). 199.225(d)(1)
(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. 199.225(d)(2)
(e) Retesting of covered employees with an alcohol concentration of 0.02 or greater but less than 0.04. Each operator shall retest a covered employee to ensure compliance with the provisions of §199.237, if an operator chooses to permit the employee to perform a covered function within 8 hours following the administration of an alcohol test indicating an alcohol concentration of 0.02 or greater but less than 0.04. 199.225(e)
§199.227 Retention of records
(a) General requirement. Each operator shall maintain records of its alcohol misuse prevention program as provided in this section. The records shall be maintained in a secure location with controlled access. 199.227(a)
(b) Period of retention. Each operator shall maintain the records in accordance with the following schedule: 199.227(b)
(1) Five years. Records of employee alcohol test results with results indicating an alcohol concentration of 0.02 or greater, documentation of refusals to take required alcohol tests, calibration documentation, employee evaluation and referrals, and MIS annual report data shall be maintained for a minimum of five years. 199.227(b)(1)
(2) Two years. Records related to the collection process (except calibration of evidential breath testing devices), and training shall be maintained for a minimum of two years. 199.227(b)(2)
(3) One year. Records of all test results below 0.02 (as defined in 49 CFR part 40) shall be maintained for a minimum of one year. 199.227(b)(3)
(4) Three years. Records of decisions not to administer post-accident employee alcohol tests must be kept for a minimum of three years. 199.227(b)(4)
(c) Types of records. The following specific records shall be maintained: 199.227(c)
(1) Records related to the collection process:199.227(c)(1)
(i) Collection log books, if used.199.227(c)(1)(i)
(ii) Calibration documentation for evidential breath testing devices. 199.227(c)(1)(ii)
(iii) Documentation of breath alcohol technician training. 199.227(c)(1)(iii)
(iv) Documents generated in connection with decisions to administer reasonable suspicion alcohol tests.199.227(c)(1)(iv)
(v) Documents generated in connection with decisions on postaccident tests.199.227(c)(1)(v)
(vi) Documents verifying existence of a medical explanation of the inability of a covered employee to provide adequate breath for testing.199.227(c)(1)(vi)
(2) Records related to test results:199.227(c)(2)
(i) The operator's copy of the alcohol test form, including the results of the test.199.227(c)(2)(i)
(ii) Documents related to the refusal of any covered employee to submit to an alcohol test required by this subpart.199.227(c)(2)(ii)
(iii) Documents presented by a covered employee to dispute the result of an alcohol test administered under this subpart. 199.227(c)(2)(iii)
(3) Records related to other violations of this subpart. 199.227(c)(3)
(4) Records related to evaluations:199.227(c)(4)
(i) Records pertaining to a determination by a substance abuse professional concerning a covered employee's need for assistance.199.227(c)(4)(i)
(ii) Records concerning a covered employee's compliance with the recommendations of the substance abuse professional. 199.227(c)(4)(ii)
(5) Record(s) related to the operator's MIS annual testing data. 199.227(c)(5)
(6) Records related to education and training:199.227(c)(6)
(i) Materials on alcohol misuse awareness, including a copy of the operator's policy on alcohol misuse.199.227(c)(6)(i)
(ii) Documentation of compliance with the requirements of §199.231.199.227(c)(6)(ii)
(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.199.227(c)(6)(iii)
(iv) Certification that any training conducted under this subpart complies with the requirements for such training.199.227(c)(6)(iv)
§199.229 Reporting of alcohol testing results
(a) Each large operator (having more than 50 covered employees) must submit an annual MIS report to PHMSA of its alcohol testing results using the MIS form and instructions as required by 49 CFR part 40 (at §40.26 and appendix H to part 40), not later than March 15 of each year for the prior calendar year (January 1 through December 31). The Administrator may require by notice in the PHMSA Portal (https://portal.phmsa.dot.gov/phmsaportallanding) that small operators (50 or fewer covered employees), not otherwise required to submit annual MIS reports, to prepare and submit such reports to PHMSA. 199.229(a)
(b) Each operator that has a covered employee who performs multiDOT agency functions (e.g., an employee performs pipeline maintenance duties and drives a commercial motor vehicle), count the employee only on the MIS report for the DOT agency under which he or she is tested. Normally, this will be the DOT agency under which the employee performs more than 50% of his or her duties. Operators may have to explain the testing data for these employees in the event of a DOT agency inspection or audit. 199.229(b)
(c) Each report required under this section must be submitted electronically at http://damis.dot.gov. An operator may obtain the user name and password needed for electronic reporting from the PHMSA Portal (https://portal.phmsa.dot.gov/phmsaportallanding). If electronic reporting imposes an undue burden and hardship, the operator may submit a written request for an alternative reporting method to the Information Resources Manager, Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE., Washington, DC 20590. The request must describe the undue burden and hardship. PHMSA will review the request and may authorize, in writing, an alternative reporting method. An authorization will state the period for which it is valid, which may be indefinite. An operator must contact PHMSA at 202-366-8075, or electronically to informationresourcesmanager@dot.gov to make arrangements for submitting a report that is due after a request for alternative reporting is submitted but before an authorization or denial is received. 199.229(c)
(d) A service agent (e.g., Consortia/Third Party Administrator as defined in part 40) may prepare the MIS report on behalf of an operator. However, each report shall be certified by the operator's anti-drug manager or designated representative for accuracy and completeness. 199.229(d)
§199.231 Access to facilities and records
(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. 199.231(a)
(b) A covered employee is entitled, upon written request, to obtain copies of any records pertaining to the employee's use of alcohol, including any records pertaining to his or her alcohol tests. The operator shall promptly provide the records requested by the employee. Access to an employee's records shall not be contingent upon payment for records other than those specifically requested. 199.231(b)
(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. 199.231(c)
(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. 199.231(d)
(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 postaccident alcohol tests administered following the accident under investigation. 199.231(e)
(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. 199.231(f)
(g) An operator may disclose information without employee consent as provided by DOT Procedures concerning certain legal proceedings. 199.231(g)
(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. 199.231(h)
§199.233 Removal from covered function
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.
§199.235 Required evaluation and testing
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.
§199.237 Other alcohol-related conduct
(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: 199.237(a)
(1) The employee's alcohol concentration measures less than 0.02 in accordance with a test administered under §199.225(e); or 199.237(a)(1)
(2) The start of the employee's next regularly scheduled duty period, but not less than eight hours following administration of the test. 199.237(a)(2)
(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. 199.237(b)
§199.239 Operator obligation to promulgate a policy on the misuse of alcohol
(a) General requirements. Each operator shall provide educational materials that explain these alcohol misuse requirements and the operator's policies and procedures with respect to meeting those requirements. 199.239(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. 199.239(a)(1)
(2) Each operator shall provide written notice to representatives of employee organizations of the availability of this information. 199.239(a)(2)
(b) Required content. The materials to be made available to covered employees shall include detailed discussion of at least the following: 199.239(b)
(1) The identity of the person designated by the operator to answer covered employee questions about the materials. 199.239(b)(1)
(2) The categories of employees who are subject to the provisions of this subpart. 199.239(b)(2)
(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. 199.239(b)(3)
(4) Specific information concerning covered employee conduct that is prohibited by this subpart. 199.239(b)(4)
(5) The circumstances under which a covered employee will be tested for alcohol under this subpart. 199.239(b)(5)
(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. 199.239(b)(6)
(7) The requirement that a covered employee submit to alcohol tests administered in accordance with this subpart. 199.239(b)(7)
(8) An explanation of what constitutes a refusal to submit to an alcohol test and the attendant consequences. 199.239(b)(8)
(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. 199.239(b)(9)
(10) The consequences for covered employees found to have an alcohol concentration of 0.02 or greater but less than 0.04. 199.239(b)(10)
(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. 199.239(b)(11)
(c) Optional provisions. The materials supplied to covered employees may also include information on additional operator policies with respect to the use or possession of alcohol, including any consequences for an employee found to have a specified alcohol level, that are based on the operator's authority independent of this subpart. Any such additional policies or consequences shall be clearly described as being based on independent authority. 199.239(c)
§199.241
Training for supervisors
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.
§199.243 Referral, evaluation, and treatment
(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. 199.243(a)
(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. 199.243(b)
(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. 199.243(c)(1)
(2) In addition, each covered employee identified as needing assistance in resolving problems associated with alcohol misuse — 199.243(c)(2)
(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 199.243(c)(2)(i)
(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.199.243(c)(2)(ii)
(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. 199.243(d)
(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 — 199.243(e)
(1) A public agency, such as a State, county, or municipality; 199.243(e)(1)
(2) The operator or a person under contract to provide treatment for alcohol problems on behalf of the operator; 199.243(e)(2)
(3) The sole source of therapeutically appropriate treatment under the employee's health insurance program; or 199.243(e)(3)
(4) The sole source of therapeutically appropriate treatment reasonably accessible to the employee. 199.243(e)(4)
§199.245 Contractor employees
(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: 199.245(a)
(b) The operator remains responsible for ensuring that the requirements of this subpart and part 40 of this title are complied with; and 199.245(b)
(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. 199.245(c)
Operator Qualification: Protocols
The following protocols have been written to assist federal and state pipeline inspectors who are evaluating operator's OQ programs. The protocols are not intended as enforcement instruments or to provide inspectors with additional enforcement authority, but rather are intended to provide inspectors with a template that they can use in the course of their inspections to ensure that operators comply with all elements of the OQ rule. The objective of the protocols is to ensure that the prescriptive requirements of the rule have been followed by operators. This objective will be accomplished by rigorously inspecting each operator's records to ensure that all persons performing covered tasks on pipeline facilities are properly qualified and that sufficient documentation is maintained for these individuals. Proper recordkeeping is a key component of the OQ rule. It is therefore important that inspectors be able to verify that records are maintained for all individuals performing covered tasks.
The OQ inspection form is organized around nine elements, including one for field verification. Each element has one or more associated protocol. Each protocol consists of 3 aspects:
(1) a protocol number accompanied by the protocol subject or topic;
(2) a protocol question(s) (sometimes followed by 'Verify' statements); and
(3) guidance topics.
The protocol topics have been structured into 'Protocol Question(s)' to guide inspectors through the OQ inspection process. Each protocol question is followed by 'Guidance Topics.' The guidance topics list characteristics that the regulator would typically expect to find in an effective OQ Program, and that are consistent with the intent of the regulatory language that accompanies each protocol. Some, all, or none of these characteristics may be appropriate depending on factors unique to each operator's OQ Program and pipeline assets. Operators should be prepared to demonstrate that their programs address each of these characteristics or to describe how their program will be effective in their absence.
Many of the protocol questions are followed by 'Verify' statements. These statements have been included because they can be directly traced to specific rule language. Therefore, compliance with each 'verify' statement should be confirmed. Many 'verify' statements (and protocol questions) are followed by a parenthetical statement that indicates that the statement or question is either 'enforceable' or 'nonenforceable'. If the 'verify' statement or protocol question is listed as non-enforceable, the statement or question is not enforceable under the rule, but is nonetheless an important consideration for the operator. Finally, should the inspection process reveal violations of prescriptive requirements of the rule, regulators will take appropriate enforcement actions. Should deficiencies be identified in how operators address program characteristics, inspectors will seek evidence of violations related to these deficiencies. Significant inquiries seeking further information related to program characteristics will be communicated to the operator as an integral part of the inspection process.
performed by a non-qualified individual under the direction and observation of a qualified individual. [Enforceable]
1.03 Management of Other Entities Performing Covered Tasks
Has the operator's OQ program included provisions that require individuals from any other entity performing covered task(s) on behalf of the operator (e.g., through mutual assistance agreements) be evaluated and qualified prior to task performance?
• Verify that other entities that perform covered task(s) on behalf of the operator are addressed under the operator's OQ program and that individuals from such other entities performing covered tasks on behalf of the operator are evaluated and qualified consistent with the operator's program requirements. [Enforceable]
1.04 Training Requirements (Initial Qualification, Remedial if Initial Failure, and Reevaluation)
Does the operator's OQ program plan contain policy and criteria for the use of training in initial qualification of individuals performing covered tasks, and are criteria in existence for retraining and reevaluation of individuals if qualifications are questioned? [Enforceable]
1.05 Written Qualification Program
Did the operator meet the OQ Rule requirements for establishing a written operator qualification program and completing qualification of individuals performing covered tasks?
• Verify that the operator's written qualification program was established by April 27, 2001. [Enforceable]
• Verify that the written qualification program identified all covered tasks for the operator's operations and maintenance functions being conducted as of October 28, 2002. [Enforceable]
• Verify that the written qualification program established an evaluation method(s) to be used in the initial qualification of individuals performing covered tasks as of October 28, 2002. [Enforceable]
• Verify that all individuals performing covered tasks as of October 28, 2002, and not otherwise directed or observed by a qualified individual were qualified in accordance with the operator's written qualification program. [Enforceable]
Element 2 - Identify Covered Tasks and Related Evaluation Methods
2.01 Development of Covered Task List
How did the operator develop its covered task list?
• Verify that the operator applied the four-part test to determine whether 49 CFR Part 192 or 49 CFR Part 195 O&M activities applicable to the operator are covered tasks. [Enforceable]
• Verify that the operator has identified and documented all applicable covered tasks. [Enforceable]
2.02 Evaluation Method(s) (Demonstration of Knowledge, Skill and Ability) and Relationship to Covered Tasks
Has the operator established and documented the evaluation method(s) appropriate to each covered task?
• Verify what evaluation method(s) has been established and documented for each covered task. [Enforceable]
• Verify that the operator's evaluation program ensures that individuals can perform assigned covered tasks. [Enforceable]
• Verify that the evaluation method is not limited to observation of on-the-job performance, except with respect to tasks for which OPS has determined that such observation is the best method of examining or testing qualifications. The results of any such observations shall be documented in writing. [Enforceable]
2.03 Planning for Mergers and Acquisitions (Due Diligence re: Acquiring Qualified Individuals)
Does the operator have a process for managing qualifications of individuals performing covered tasks during program integration following a merger or acquisition (applicable only to operators engaged in merger and acquisition activities)?
• Verify that the OQ program describes the process for ensuring OQ qualifications, evaluations, assignment and performance of covered tasks during the merger with or acquisition of other entities. [Enforceable]
Element 3 - Identify Individuals Performing Covered Tasks
Element 1 - Document Program Plan, Implementing Procedures and Qualification Criteria
1.01 Application and Customization of 'Off-the-Shelf Programs' Does the operator's plan identify covered tasks and does it specify task-specific reevaluation intervals for individuals performing covered tasks? [Enforceable]
1.02 Contractor Qualification
Does the operator employ contractor organizations to provide individuals to perform covered tasks? If so, what are the methods used to qualify these individuals and how does the operator ensure that contractor individuals are qualified in accordance with the operator's OQ program plan?
• Verify that the operator's written program includes provisions that require all contractor and subcontractor individuals be evaluated and qualified prior to performing covered tasks, unless the covered task is
3.01 Development and Documentation of Areas of Qualification for Individuals Performing Covered Tasks
Does the operator's program document the evaluation and qualifications of individuals performing covered tasks, and can the qualification of individuals performing covered tasks be verified at the job site?
• Verify that the operator's qualification program has documented the evaluation of individuals performing covered tasks. [Enforceable]
• Verify that the operator's qualification program has documented the qualifications of individuals performing covered tasks. [Enforceable]
3.02 Covered Task Performed by Non-Qualified Individual
Has the operator established provisions to allow non-qualified individuals to perform covered tasks while being directed and observed by a qualified individual, and are there restrictions and limitations placed on such activities?
• Verify that the operator's program includes provisions for the performance of a covered task by a non-qualified individual under the direction and observation by a qualified individual. [Enforceable]
Element 4 - Evaluate and Qualify Individuals Performing Covered Tasks
4.01 Role of and Approach to 'Work Performance History Review'
Does the operator use work performance history review as the sole method of qualification for individuals performing covered tasks prior to October 26, 1999, and does the operator's program specify that work performance history review will not be used as the sole method of evaluation for qualification after October 28, 2002?
• Verify that after October 28, 2002, work performance history is not used as a sole evaluation method. [Enforceable]
• Verify that individuals beginning work on covered tasks after October 26, 1999 have not been qualified using work performance history review as the sole method of evaluation. [Enforceable]
4.02 Evaluation of Individual's Capability to Recognize and React to AOCs
Are all qualified individuals able to recognize and react to AOCs? Has the operator evaluated and qualified individuals for their capability to recognize and react to AOCs? Are the AOCs identified those that the individual may reasonably anticipate and appropriately react to during the performance of the covered task? Has the operator established provisions for communicating AOCs for the purpose of qualifying individuals?
• Verify that individuals performing covered tasks have been qualified in recognizing and reacting to AOCs they may encounter in performing such tasks. [Enforceable]
Element 5 - Continued/Periodic Evaluation of Individuals Performing Covered Tasks
5.01 Personnel Performance Monitoring
Does the operator's program include provisions to evaluate an individual if the operator has reason to believe the individual is no longer qualified to perform a covered task based on:
- Covered task performance by an individual contributed to an incident or accident.
- Other factors affecting the performance of covered tasks.
• Verify that the operator's program ensures evaluation of individuals whose performance of a covered task may have contributed to an incident or accident. [Enforceable]
• Verify that the operator has established provisions for determining whether an individual is no longer qualified to perform a covered task, and requires reevaluation [Enforceable]
5.02 Reevaluation Interval and Methodology for Determining the Interval
Has the operator established and justified requirements for reevaluation of individuals performing covered tasks?
• Verify that the operator has established intervals for reevaluating individuals performing covered tasks. [Enforceable]
Element 6 - Monitor Program Performance; Seek Improvement Opportunities
6.01 Program Performance and Improvement
Does the operator have provisions to evaluate performance of its OQ program and implement improvements to enhance the effectiveness of its program? [Non-Enforceable]
Does the operator maintain records in accordance with the requirements of 49 CFR 192, subpart N, and 49 CFR 195, subpart G, for all individuals performing covered tasks, including contractor individuals?
• Verify that qualification records for all individuals performing covered tasks include the information identified in the regulations. [Enforceable]
• Verify that the operator's program ensures the retention of records of prior qualification and records of individuals no longer performing covered tasks for at least five years. [Enforceable]
• Verify that the operator's program ensures the availability of qualification records of individuals (employees and contractors) currently performing covered tasks, or who have previously performed covered tasks. [Enforceable]
Element 8 - Manage Change
8.01 Management of Changes (to Procedures, Tools, Standards, etc.)
Does the operator's OQ program identify how changes to procedures, tools standards and other elements used by individuals in performing covered tasks are communicated to the individuals, including contractor individuals, and how these changes are implemented in the evaluation method(s)?
• Verify that the operator's program identifies changes that affect covered tasks and how those changes are communicated, when appropriate, to affected individuals. [Enforceable]
• Verify that the operator's program identifies and incorporates changes that affect covered tasks. [Enforceable]
• Verify that the operator's program includes provisions for the communication of changes (e.g., who, what, when, where, why) in the qualification program to the affected individuals. [Enforceable]
• Verify that the operator incorporates changes into initial and subsequent evaluations. [Enforceable]
• Verify that contractors supplying individuals to perform covered tasks for the operator are notified of changes that affect task performance and thereby the qualification of these individuals. [Enforceable]
8.02
Notification of Significant Program Changes
Does the operator have a process for identifying significant OQ written program changes and notifying the appropriate regulatory agency of these changes once the program has been reviewed?
• Verify that the operator's written program contains provisions to notify OPS or the appropriate regulatory agency of significant modifications to a program that has been reviewed for compliance. [Enforceable]
Element 9 - Field Verification
9.01 Are field/job supervisors aware of their responsibilities as defined under the operator's OQ program?
9.02 Are the observed covered task(s) performed in accordance with appropriate operator-approved procedures, and are the procedures present at the job site?
9.03 Are the individuals performing the observed covered task(s) adhering to the operator-approved procedures as written?
9.04 Are the proper tools, techniques and processes detailed in the operator-approved procedures employed in the performance of the observed covered task(s)?
9.05 Are the qualifications of all individuals involved in performing the covered task(s) verified at the job site? Is this verification process performed as detailed in the operator's OQ program plan? Is this verification process applied to employees and contractors alike?
9.06 Are the qualified individuals performing the observed covered task(s) knowledgeable of how to recognize the applicable AOCs and what their expected reaction to the AOCs should be?
9.07 Are individuals not qualified to perform a covered task performing a covered task? If so, are the non-qualified individuals being directly observed by a qualified individual in accordance with the requirements of the regulation?
9.08 How are field/job supervisors informed of changes that affect the performance of covered tasks under their responsibility?
9.09 In cases where the field office is part of a subsidiary or separate district, is implementation of OQ program requirements consistent with other districts and the overall organization's OQ program?
9.10 How is performance of the covered task(s) reviewed/inspected in the field by internal auditors or third party inspectors?
9.11 What problems have been experienced in the field in implementing the operator's OQ program? If problems have been experienced, how have they been communicated back to the individual responsible for the OQ program?
9.12 How are Control Center operations coordinated with remote operations that are conducted with other operations personnel? Are these 'other operations personnel' qualified to perform the covered tasks being performed?
Operator Qualification: FAQs
These FAQs are intended to provide guidance only; they are not a substitute for regulatory requirements or other obligations placed on the operator by the Pipeline Safety Law (see FAQ #1.11). They represent OPS's best judgment as of the date issued. In addition, they specifically do not address compliance with more stringent state laws that may exist. Please consult the appropriate state agency(ies) for additional guidance.
Application and Customization of 'Off-the-Shelf' Programs
1.1 What responsibility does an operator have if it chooses to use an 'off-the-shelf' OQ program?
An operator choosing to use an 'off-the-shelf' OQ program (e.g., MEA, Northeast Gas Association, and Consortium on Operator Qualification/NCCER) is still fully responsible to understand and meet the provisions of the OQ Rule. For example, the operator must make sure that tasks performed in its unique operating environment by its employees or contractors are evaluated to determine whether they are covered or not. The operator must also determine which of its employees and contractors perform the covered tasks, and ensure that they are qualified to perform the tasks. Additionally, the operator must understand the basis on which reevaluation intervals have been specified and implement any performance monitoring activities needed to make sure qualified persons are performing covered tasks in an acceptable manner (according to the evaluation criteria established or accepted by the operator). If an operator identifies reevaluation intervals that it believes should either be lengthened or shortened, it should modify the reevaluation interval and document justification for the changes. In addition, it should notify the 'program sponsor' of the changes so further consideration can be given to programmatic changes.
Contractor Qualification
1.2 Do contractor employees have to be in compliance by the same date as employees of operators?
It is the operator's responsibility to ensure that every individual, whether employed by the operator or by a contractor who performs a covered task on an operator's pipeline facility on or after the compliance date (October 28, 2002), must either be qualified to perform those tasks or be directed and observed by a qualified person.
1.3 Will contractors be required to have a written OQ Program?
Only pipeline operators are subject to the requirements of the DOT Rules. Individuals performing covered tasks on an operator's pipeline facility, including its own employees, contractors, sub-contractors, original equipment manufacturer's (OEM) representatives, temporary help, etc., must be qualified or perform covered tasks under the direct supervision of a qualified individual. Operators may require contractors which supply individuals to perform covered tasks to:
Have their own OQ Program and provide documentation that these individuals are currently qualified to perform the assigned covered tasks.
Belong to a Consortium which provides the required qualification evaluations and documentation, or
Qualify those individuals under the Operator's own OQ Program; or Have an independent third party evaluate their qualification and provide the required documentation.
Whichever alternative is chosen, the contractor must be operating under an OQ Program that the operator has verified as being compatible with its own qualification procedures, including the recognition of and reaction to AOCs identified by the operator.
1.4 How might an operator ensure that individuals employed by contractors are qualified to perform covered tasks?
An operator has a number of options for ensuring that contractor personnel are qualified (see 1.3 above), including:
a. Requiring the contractor to develop, maintain and implement a qualification process that is equivalent to the operator's own qualification procedures. The operator must take positive steps to ensure the contractor's program is compliant and that the program is being implemented and administered as described;
b. Requiring the contractor personnel to participate in the operator's program; or
c. Requiring the contractor to participate in an operator-approved consortium.
1.5 Does the operator have to maintain records that show it has verified acceptable implementation of the OQ program of contractors performing covered tasks?
The operator shall assure maintenance of records that demonstrate compliance with the regulation. Depending on the operator's approach to qualification of contractor personnel, the operator may maintain records related to the qualification of contractor personnel, rely on the records maintained by the contractor, or rely on records administered by a third party or consortium. The Operator's OQ Plan should also sufficiently describe the processes used for qualifying contractors and accepting qualification from other programs.
1.6 Are contractors required to utilize the operator's procedures for performing covered tasks?
Contractors are not required to use the operator's procedures for performing covered tasks. However, if a contractor uses different procedures, the operator is responsible to ensure that these procedures are acceptable and documented in their O&M manual, and for ensuring that the contract individuals are qualified in performance of covered tasks using these procedures.
Contractors are required to perform covered tasks in a manner determined by the operator to be consistent with the operator's procedures. The operator is responsible for ensuring that contractor procedure or evaluation criteria and reevaluation intervals are acceptable.
1.7 Will OPS grant contractors any extension for the compliance date of October 28, 2002?
No, individuals performing covered tasks are required to be qualified on 10/28/02 or by the date following 10/28/02 when they first perform a covered task.
1.8 Are contractors hired by local distribution companies (LDCs) responsible for qualifying individuals, or are the LDCs responsible for qualifying individuals who perform covered tasks on its behalf?
Each operator is responsible for assuring that individuals performing covered tasks on their pipeline facilities are qualified. This is true whether it operates distribution (mains and services) or jurisdictional gathering or transmission lines, and is true whether the individual is an employee or a contractor. An Operator may require the contractor to qualify (or have an independent third party or consortium approved by the operator qualify) their employees and provide the required documentation before sending them to perform covered tasks on their pipeline.
Management of Other Entities Performing Covered Tasks
1.9 What requirements exist related to the qualification of persons participating in mutual assistance agreements?
Mutual assistance agreements are typically designed to clarify the conditions under which pipeline operators support each other in the safe restoration of services following a significant outage. It is the responsibility of the operator whose system is being restored to ensure that all individuals performing covered tasks pursuant to mutual assistance agreements are qualified in a manner consistent with the operator's OQ Program requirements (also see FAQs 1.6 and 1.8).
Training Requirements
1.10 Can individuals be qualified without being required to undergo training?
Yes. The purpose of this rule is to ensure that those persons performing covered tasks on the pipeline have been evaluated and determined to be qualified both to perform covered tasks and to recognize and react to abnormal operating conditions. Training may be an integral step in preparing for evaluation; however, it is not required under the current provisions of this rule (but - see FAQ 1.11).
1.11 How should training be incorporated in an operator's program plan?
Training is a means to ensure that a person performing a covered task has the knowledge and skills needed to perform the task. As such, it should be incorporated in practices leading to the development and qualification of new employees, as well as in refreshing the knowledge and skills of persons with considerable experience. In particular, any significant change in the procedures on which covered tasks are based should be the subject of new training for all persons performing covered tasks. In addition, qualified persons who fail initial evaluation or reevaluation testing may be provided with remedial training in their areas of deficiency. While training is not required, the Pipeline Safety Law (as amended December 17, 2002 by Public Law No. 107-355) does require operators to include "training, as appropriate, to ensure that individuals performing covered tasks have the necessary knowledge and skills to perform" covered tasks as an element of their OQ program. Consequently, a future amendment to the OQ regulations will incorporate language very similar to that contained in the Pipeline Safety Law. Furthermore, the law requires operators to act to fulfill this requirement no later than December 17, 2005 should OPS fail to issue a Final Rule addressing training requirements in a timely manner.
1.12 What is the role of computer-based or web-based training in complying with the OQ Rule?
Training is a means to the end result, qualification. Under the OQ rule, operators are free to choose from several different types of training. Computer-based and web-based training represent just two choices available to operators. Training is not required, but must be considered, and should be utilized, where appropriate. Any computer-based or web-based training must be tailored to:
(1) determine if the individual is able to perform the covered task(s); and
(2) recognize and react to any AOC which may be reasonably anticipated to occur during the performance of that covered task. If computer-based or web-based training accomplishes these objectives and is accepted by the Operator and regulator(s), then it has a role in complying with the OQ Rule. Training programs will be reviewed by regulators for adequacy during inspections (also see FAQ 1.11).
Written Qualification Program
1.13 Should an operator document the date on which full compliance with provisions of the OQ Rule was achieved?
Full compliance with provisions of the operator qualification rule is required by October 28, 2002. Operators should have documentation supporting attainment of full compliance by that date. Full compliance by an operator includes its commitment to the requirement that covered tasks may be performed only by qualified individuals or nonqualified individuals who are under the direction and observation of qualified individuals. An operator should be able to demonstrate through documentation that it has fulfilled this requirement.
1.14 Should an operator ensure that implementation of its OQ program plan is consistent throughout its organization?
In general, operators should provide some means to ensure that all organizational units covered by a single OQ program plan are interpreting and implementing the plan consistently. To this end, sufficient specificity must be provided to eliminate ambiguity and provide substantive guidance. Operators should strive to have plans that are consistent throughout the operator's organization and that contain superior practices.
1.15 Should operators develop OQ program provisions in anticipation of future industry mergers and acquisitions?
While industry consolidation by mergers and acquisitions is a current fact of life, an operator need not anticipate how its programs might change if it is involved in such consolidations. However, specific provisions for addressing OQ requirements following mergers or acquisitions should be developed and documented as soon as practical after such business transactions have been negotiated (e.g., provisions for either combining the programs or maintaining distinct programs, so long as compatibility issues are reviewed and resolved).
Development of Covered Task List (Process)
2.1 What O & M activities must be included in a compliant OQ program?
For the purposes of the OQ rule, an O & M activity is only subject to the requirements of the OQ rule if the activity is an operations or maintenance activity and also meets the other three requirements that make up a covered task. [The four elements that make an activity a covered task are:
(1) the activity must be performed on a pipeline facility;
(2) the activity must be an operations or maintenance task;
(3) the activity must be performed as a requirement of the applicable part (i.e., part 192 or 195); and
(4) the activity must affect the operation or integrity of the pipeline.] Guidance on the other three requirements can be found in the Federal Register notice that announced the Operator Qualification Final Rule (64 FR 46853; August 27, 1999).
Most of the operations and maintenance activities on pipeline facilities are found in 49 CFR Part 192, Subparts L and M, or in 49 CFR Part 195, Subpart F. In addition, the regulations contain other subparts that include requirements for conducting operations and maintenance activities. For example, Part 192, Subpart I and Part 195, Subpart H establishes requirements for protecting metallic pipelines from external, internal, and atmospheric corrosion. The requirements to monitor corrosion control systems are operations activities. The requirements to take corrective action when deficiencies are found in a corrosion control program are maintenance activities. Therefore, repairing pipelines affected by corrosion is also a maintenance activity. Other O&M provisions of the code may be identified by comparing the code requirements against the common dictionary definitions of "operation" (starting, stopping and/or monitoring and controlling devices or systems) and "maintenance" (the act of maintaining; the work of keeping something in proper condition; upkeep).
2.2 Where are O & M activities found in the pipeline safety regulations and how are they defined?
The pipeline safety regulations contain several provisions that require operators to perform certain operations and maintenance activities. Most O & M requirements are found in Subparts L and M of 49 CFR Part 192 for natural gas pipelines and Subpart F of 49 CFR Part 195 for hazardous liquid pipelines. A few other O & M activities are covered in other parts of the regulations. Operations and maintenance activities are not formally defined in the pipeline safety regulations. However the common dictionary definitions of "operation" (starting, stopping and/or monitoring and controlling devices or systems) and "maintenance" (the act of maintaining; the work of keeping something in proper condition; upkeep) can be referred to for further guidance. In addition, further guidance can be found elsewhere in this document
and in the Federal Register notice that announced the Operator Qualification Final Rule (64 FR 46853; August 27, 1999).
2.3 How should an operator differentiate between O&M tasks and new construction tasks?
The purpose of maintenance is to preserve the serviceability of existing pipelines. If a pipeline segment cannot fully and safely operate as designed without the completion of a certain task, then that task should be considered maintenance. Repairs to a pipeline, including replacement of one or more pipe joints, necessitated by threats such as corrosion or third party damage, should be considered maintenance.
New construction is the act of building a pipeline facility, or expanding an existing pipeline segment (as in looping a pipeline segment, which may also be done to meet increased load requirements or to enhance reliability of the system) in order to provide new service to a customer(s) or in order to meet increased demand. The tie-in of a new pipeline or segment to an existing pipeline is an O&M task; any task carried out on that new pipeline or segment thereafter is also an O&M task. Company accounting practices that differentiate between capital projects and O&M expenditures are irrelevant in the determination of whether a task is covered.
2.4 Does the location where a task is performed affect whether it is a covered task?
Yes, for example, if an individual performs a bench test on a regulator at the manufacturer's shop, the activity is not a covered task because the test was not "performed on a pipeline facility" as specified in the rule. However, if an individual were to perform the same bench test on a regulator at a compressor station, which is a "pipeline facility," the task is "covered" and the individual would have to be qualified.
2.5 Can certain tasks be either covered or non-covered depending on when and where they are performed?
Yes; the "where" was addressed in FAQ 2.3. "When" may also impact certain tasks performed on pipeline facilities. Tasks may be covered tasks when performed in the course of operation and maintenance activities, but may not be covered tasks when performed in the course of other activities. For example, "welding" would be a covered task when performed as an operations and maintenance activity on a pipeline, such as when installing a weld-over sleeve to repair an anomaly. However, "welding" is not a covered task under this subpart when performed during the fabrication of
(a) new installations (because new construction is not an operations and maintenance task) or
(b) replacement components where the work is performed away from the pipeline facility (because this activity would fail one part of the four-part test).
2.6 Under emergency conditions, sometimes a manager is the first to arrive and knows how to respond. Can he/she take action (e.g., close an isolation valve) if the required action is a covered task and she/he is not qualified to perform that task?
In an emergency, qualified persons shall be used to perform those tasks that normally must be performed by a qualified person. Operators should identify those individuals (employees, contractors, and possibly others not under the direct control of the operator) whose normal job responsibilities place them in a position where they may need to respond to an emergency condition, and qualify these people in how to terminate anticipated emergency conditions. For example:
a. Meter readers may encounter gas leaks; they should be qualified to take appropriate action.
b. Individuals supplied through a mutual aid agreement may be called upon to perform covered tasks during a protracted emergency (e.g., restoration of service following a weather-related outage) and should be qualified to the operator's OQ program requirements.
c. Professional emergency responders, such as fire fighters, need not be qualified by the operator to perform their jobs; however, if there is any reasonable expectation that they may be called upon to perform a covered task (e.g., close a specific valve located remotely from the operator's closest field office), those persons should be included within the coverage of the operator's OQ program and qualified to perform that task.
2.7 Will OPS urge, strongly recommend, or encourage inspectors to utilize a master list of covered tasks to inspect operators?
No, OPS will not urge inspectors to refer to a master list of covered tasks when conducting OQ compliance inspections. Initially, inspectors will be strongly encouraged to evaluate the strength of the process an operator has used to identify covered tasks, rather than focus exclusively on the covered task list itself. As experience is gained in operator positions on covered tasks where unanimity doesn't exist, there will likely be a tendency to focus inspection resources on reviewing the operator's justification or basis for excluding tasks from their covered task list. Also, when published, the consensus standard on OQ ("B31Q") is expected to provide additional guidance to operators in this area.
Evaluation Method(s) (Demonstration of Knowledge, Skill, & Ability or "KSA") and Relationship to Covered Tasks
2.8 What are acceptable evaluation methods?
Acceptable evaluation methods are listed in the rule, and include:
a. written examination;
b. oral examination;
c. work performance history review*;
d. observation** during on-the-job performance, during on-the-job training, or in simulations; or e. other forms of assessment.
* Note that work performance history review may no longer be used as a sole evaluation method after October 28, 2002.
** "Observation," when used in conjunction with on-the-job performance, must include methods of assessing the individual's knowledge of the procedure as well as the skill and ability to perform it. That is, the evaluation must include appropriate questions and responses for the observation to be considered valid. The mere act of "watching" without any interaction between the observer and the observed is considered to be inadequate.
The evaluation methods selected should be appropriate for the covered task. Operators should be prepared to discuss their rationale for selecting the evaluation method (s) associated with each task in their written plan, particularly the knowledge and skill component to evaluations.
2.9 What capabilities should be evaluated to qualify an individual to perform covered tasks?
The qualification process should include the following factors:
(1) the individual's knowledge of the task (e.g., information imparted through self-study, classroom training or CBT);
(2) her or his skill in performance of the task (e.g., craftsmanship in performing the steps of the task); and
(3) his or her ability (proficiency, comprised of "physical capability"; e.g., vision, strength, agility, or "mental ability"; e.g., comprehension and understanding) is to perform the covered task. The rule addresses acceptable means for evaluating these capabilities.
2.10 Under what conditions will candidates be considered to pass their evaluation testing? What will be considered a passing score for evaluation tests?
The rule addresses acceptable methods of evaluation. It does not address scoring methods or criteria for passing testing. The Final Rule preamble (64 FR 46853, 46861; August 27, 1999) states that the operator should establish the acceptance criteria for the evaluation method used. Thus, the establishment of a pass/fail criterion of 70% on a comprehensive balanced written test may be acceptable. However, a significant number of these questions should relate to those portions of the task considered to be critical to its successful performance. A score of 100% correct on these critical questions should be required in order to demonstrate mastery of the task requirements.
2.11 If an individual seeking qualification to perform a covered task fails the evaluation process, how many times can he/she be reevaluated?
Determining the number of times an individual can be reevaluated is up to the operator. An operator must not permit a candidate who fails the reevaluation process to perform the covered task until that person has passed the evaluation or is directly observed by a person who is qualified to perform the covered task. The Operator's OQ Program should describe, in sufficient detail to avoid ambiguity or misinterpretation, how it will address failure to pass the evaluation process. If appropriate, remedial training and subsequent reevaluations can be offered. If reevaluation is offered, the operator should require the individual to go through a "cooling off" period following a failure to pass, in order to ensure that the individual is not relying entirely on short-term memory to pass the reevaluation process. Additionally, the operator should specify the number of failures that are acceptable before discontinuing evaluation efforts.
2.12 What is a reasonable time between failure to pass an evaluation and reevaluation?
The time between failure and re-evaluation may be affected by several considerations. The most important of these is ensuring that the reason for failure is recognized and addressed prior to reevaluation. If fundamental knowledge, skill or ability gaps are disclosed by the failure, additional training should be provided prior to reevaluation. The operator's written program should describe how the operator identifies and corrects the cause(s) of failure before reevaluation.
2.13 Should operators implement measures to ensure that the procedures on which qualification is based are consistent with the actual practices implemented in the field?
A major purpose of the operator qualification rule is to eliminate job performance errors that might affect the integrity of pipeline systems. Such errors can be inadvertent (e.g., forgetting a step in implementation of a procedure) or systemic (e.g., practices that are inconsistent with written procedures, such as purposely ignoring SCADA system alarms because they are known to be inaccurate).
Elimination of systemic errors is as important as eliminating inadvertent ones. Therefore, operators should incorporate into their qualification program provisions for ensuring that practices in the field are the same as those documented in the operator's O&M Plan, which provide the basis on which persons are qualified. Such provisions might include field audits of on-the-job performance by separate audit units within the company.
2.14 What credentials must a person have to be an evaluator?
Operators may, but are not required to, establish criteria that an individual must meet to be an evaluator. Evaluators should, however, possess the required knowledge to ascertain an individual's ability to perform covered tasks and to substantiate an individual's ability to recognize and react appropriately to abnormal operating conditions that might occur while performing these activities. The evaluation process should be objective and consistent. To ensure this, evaluators should be knowledgeable about the subject tasks in order to conduct effective evaluations.
2.15 Must records be maintained documenting evaluator credentials?
The generation and retention of records to substantiate an evaluator's knowledge is a good practice. It demonstrates to regulators a good faith effort to comply with the spirit of the OQ rule. The generation and maintenance of records to substantiate an evaluator's knowledge is ultimately, however, at the operator's discretion.
2.16 Will the use of third party evaluation become a mandatory method of evaluation?
The OQ rule does not currently require the use of third party evaluators, nor is such a requirement anticipated.
Development and Documentation of Areas of Qualification for Individuals Performing Covered Tasks
3.1 Will qualified persons be required to carry cards to document the covered tasks for which they are qualified?
Carrying ID cards to document covered tasks that a person is qualified to perform is permissible but not required. Some means is needed to allow a supervisor or foreman to determine the covered tasks for which persons under his/her supervision are qualified. The issuance and possession of ID cards is one means by which a supervisor or foreman can make this determination. Other means could include an electronic database accessible to the appropriate personnel that contains qualification records of all persons qualified to perform covered tasks for the operator. Paper ("hardcopy") records may also be appropriate.
Positive identification of the individual performing the covered task may also be required in cases where the individual and his or her qualifications are unknown to the job supervisor. The operator should require a government-issued identification in order to confirm that the correct individual has reported to the job site for the performance of the covered task.
3.2 How should operators document the covered tasks for which a person has been qualified?
Operators should have some means in place to make sure that field supervisors can verify that individuals are currently qualified for the tasks that they are performing. Some means is needed to allow a supervisor or foreman to determine the covered tasks for which persons under his/her supervision are qualified. FAQ #3.1 discusses some of these methods.
3.3 Must plumbers and independent installers performing covered tasks on customer-owned service lines, curb-to-meter be qualified?
If the piping under consideration is jurisdictional (i.e., the piping is subject to regulation by Part 192 or 195), the plumber or anyone else performing the task for the operator must be qualified based on the operator's OQ requirements.
3.4 Does the supervisor or foreman need to be qualified for all the tasks being carried out under his/her management?
The OQ Rule does not require the supervisor or foreman to be qualified to perform the tasks carried out under her or his supervision. However, they must be qualified if they are performing that task or if they are the individual assigned to direct and observe an unqualified person performing the task.
Covered Task Performed by Non-Qualified Person
3.5 Can new employees work under the 'guidance' of other crew members who are qualified for a period of time? If so, how long?
There is no set time limit on how long a non-qualified employee may work under the supervision of a qualified worker. The Rule stipulates that non-qualified individuals (new employees, or employees that are no longer qualified) can perform covered tasks only if they are directed and observed by another qualified individual. The operators' written program shall include provisions that demonstrate the operator has control mechanisms or processes in place regarding
the utilization of non-qualified personnel to perform covered tasks. The control mechanisms may include:
a. Identification of covered tasks (if any) that can only be performed by qualified personnel;
b. The appropriate ratio (span of control) of qualified to non-qualified personnel for each covered task;
c. Other reasonable methods of exercising appropriate control.
3.6 Should an OQ program specify the maximum distance, and the maximum number of non-qualified individuals performing a covered task that a qualified individual can supervise?
The preamble discusses the need for having a qualified individual direct and observe a non-qualified person performing a covered task, and for the qualified individual to be in position to take immediate action to correct deficiencies. Since the maximum distance and number of non-qualified persons being observed may vary from task to task, the operator should provide written guidance, applicable to each covered task, for qualified individuals directing and observing nonqualified persons.
Role of and Approach to 'Work Performance History Review'
4.1 What constitutes a Work Performance History Review?
The OQ Final Rule preamble (64 FR 46853; August 27, 1999) states that the operator must establish the parameters for a Work Performance History Review. Such a review should include, as a minimum:
a. A search of existing records for documentation of an individual's past satisfactory performance of a covered task(s);
b. Verification that the individual's work performance history contains no indications of substandard work or involvement in an incident (Part 192) or accident (Part 195), caused by an error in performing a covered task; and
c. Verification that the individual successfully performed the task on a regular basis prior to October 26, 1999.
4.2 Under what conditions can Work Performance History Review (WPHR) be used for qualification of persons performing covered tasks?
As of October 28, 2002, work performance history review (WPHR) may no longer be used as the sole evaluation method for evaluating individuals performing covered tasks. Individuals who were qualified by WPHR as the sole method prior to October 28, 2002 may continue to work under that evaluation until the next scheduled evaluation. As stated above, any individual who was qualified based on WPHR must have been performing that task in the organization on a regular basis prior to October 26, 1999. Of course, operators are free to use WPHR in conjunction with other permissible evaluation methods. Maintenance of records that carefully and thoroughly document the work performance history review process, if used, is valuable in support of that evaluation process and must be described in the written OQ Program (also see FAQ #4.1).
Treatment of Abnormal Operating Conditions (AOCS)
4.3 What role do abnormal operating conditions (AOCs) play in the OQ rule?
To be qualified to perform a covered task, individuals must not only demonstrate the knowledge, skill and ability (KSA) to perform the task, but also be able to recognize and react to AOCs that the individual may reasonably be expected to encounter while performing a covered task. Operators are expected to develop a thorough listing of AOCs, both task-specific and generic. The task-specific AOCs may be included within the evaluation criteria for the specific task, but the generic AOCs should be maintained in a separate list and reviewed periodically.
Operators must demonstrate that their evaluation methods and processes include an evaluation of the individual's ability to recognize and appropriately react to AOCs. Since this regulatory requirement applies to both task-specific and generic AOCs, it is strongly recommended that all qualified individuals be provided training in the recognition of, and appropriate reaction to, generic AOCs.
The operator should utilize incident/accident investigations, employee feedback programs, or other approaches to ensure that the AOCs identified and used in evaluating individuals are current and representative of those that could reasonably be anticipated during performance of covered tasks.
Personnel Performance Monitoring (e.g., Determination of Role in Incident)
5.1 Are operators required to continuously monitor the performance of individuals qualified to perform covered tasks?
While operators are not required to continuously monitor the performance of individuals qualified to perform covered tasks, the rule does require operators to:
(a) evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an incident (as defined in Part 191) or accident (as defined in Part 195); and
(b) evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task. The operator should document in its OQ Program how it intends to satisfy these requirements.
5.2 Should operators incorporate criteria in their program plans for termination of an individual's qualification to perform covered tasks?
The Rule includes requirements for operators to
(a) evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an incident (as defined in Part 191) or accident (as defined in Part 195); and
(b) evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task. The Operator's written OQ Program should describe the process for determining if an individual is no longer qualified to perform a covered task, under what circumstances that process will be used, and what the process result will be if an individual is found to be not qualified to perform a covered task. Options available to the operator when an individual is found to be no longer qualified include:
a. the individual may be re-evaluated (subsequent to any required remedial training);
b. the individual must be observed by a qualified individual during the performance of the covered task;
c. the individual may be re-assigned to a job that does not require that qualification; or
d. the individual may be terminated.
5.3 How should an operator address a situation in which an individual who is qualified to perform a covered task is found to be performing that covered task incorrectly at the job site?
An individual who is found to be incorrectly performing a covered task for which the individual is qualified should be immediately taken off the job pending reevaluation. Next, the reason(s) behind the incorrect task performance should be ascertained, and then action(s) should be designed to correct the inadequacy. For example, if the reason is an incorrect procedure requirement in the O & M manual, then a systematic process for reviewing the procedure, making needed corrections, and training qualified individuals in the performance of the revised procedure should be undertaken. If the reason is a lack of knowledge on the individual's part, or an exceedingly long time interval between the individual's performance of the task, or a general pattern of careless performance, or deterioration in the individual's physical or mental capabilities, then appropriate corrective actions should be identified and taken.
Each operator should develop procedures for dealing with performance deficiencies and for suspending and/or revoking an individual's status as qualified to perform a task. These procedures should be communicated with interested parties (e.g., employees, bargaining unit, supervisory people) to ensure that ad hoc criteria are not used for decisions that are critical to the success of the OQ program. Also see FAQs 2.13 and 5.2.
5.4 What must an operator consider in its incident (or accident) investigation and analysis to satisfy provisions of the OQ Rule?
The OQ rule requires that an operator must have provisions to "evaluate an individual if the operator has reason to believe that the individual's performance of a covered task contributed to an incident (or accident)". Therefore, an operator must have a process for investigating incidents (or accidents) that identifies factors contributing to the incident in sufficient detail to determine whether or not performance of a covered task may have contributed to that incident or accident. If the answer is in the affirmative, the process must be able to identify the individual(s) that performed that task and provide for the appropriate corrective action (reevaluation) to be taken. If WPHR is to be used as one possible reevaluation method, consideration must be given to the individual(s) contributing to an incident through the performance of a covered task in subsequent reevaluations of that individual.
5.5 How should operators monitor individuals between reevaluation intervals to ensure that the individuals continue to remain properly qualified?
The rule requires that an operator must "evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task". Therefore, the operator must, in addition to a schedule of covered task-specific required reevaluation intervals (see FAQ 5.6), have some method of monitoring the performance of individuals performing covered tasks. The method may be as simple as a periodic performance review that is documented by the individual's supervisor, signed by both the individual and his/her supervisor, and in which the individual's performance strengths and limitations are discussed. The continuing evaluation method might also include specific job performance measures, or audit reports on the individual's performance developed by an independent internal audit group.
Re-evaluation Interval and Methodology for Determining Same
5.6 How should an operator determine the reevaluation interval for individuals performing covered tasks?
The rule requires the operator to "have and follow a written qualification program" that includes a provision to '"identify those covered tasks and the intervals at which subsequent evaluation of the individual's qualifications is needed". It is the responsibility of the operator to determine and document the basis for scheduling subsequent evaluations. The time period between required reevaluations may be derived through the performance of a "DIF" analysis. The components (factors) to be considered are:
a. Task Difficulty (or complexity),
b. Task Importance (or safety sensitivity), and
c. Frequency that the task is performed.
The time period between required reevaluations may also be affected by the extent of measures taken by the operator to provide continuing assurance of the performance of qualified individuals. For example, an operator may wish to require qualified individuals to perform tasks for which they are qualified at least monthly to maintain qualification, or it may institute a quality assurance process in which each individual performing covered tasks is observed randomly by an independent auditor in the performance of each task. Finally, determination and justification of the reevaluation interval should consider existing consensus standards and industry practice (e.g., OSHA standards, non-mandatory consensus standards). For infrequently performed tasks, such as hot tapping, an operator may choose to evaluate and qualify individuals immediately before the task is to be performed.
5.7 What date should be used as the starting point for reevaluation intervals?
For any person qualified prior to October 28, 2002 (the deadline for qualifying individuals under the OQ rule), the reevaluation clock for each qualified individual should begin on his/her qualification date; alternatively, if an operator wishes to have consistent evaluation dates, the reevaluation clock could be set for 10/28/02 for all such individuals, for ease of tracking. For individuals qualified after 10/28/ 02, the date should coincide with the Evaluation/Qualification date and the re-evaluation interval established by the operator.
Program Performance and Improvement
6.1 What continuing process of performance monitoring and improvement is expected of operators?
Given that the OQ rule is largely a performance rule with a limited set of specific prescriptive requirements, operators are expected to monitor the effectiveness of implementation of their programs, and to seek out opportunities for improving that performance. Improvements can be identified from sources such as:
(a) internal innovation;
(b) practices of other operators;
(c) practices developed by industry consortia that are generally recognized as effective; or
(d) provided in the forthcoming consensus standard, B31Q. Qualification 'Trail' (i.e., Covered Task, Person Performing; Evaluation Method(s); Continuing Performance Evaluation; Re-evaluation Interval; Re-evaluation Records)
7.1 How should an operator treat documentation requirements?
The OQ rule requires, at a minimum, that the following records be retained:
a. identification of qualified individual(s);
b. identification of the covered tasks the individual is qualified to perform;
c. date(s) of current qualification; and
d. qualification method(s).
Records supporting an individual's current qualification shall be maintained while the individual is performing the covered task. Records of prior qualification and records of individuals no longer performing covered tasks shall be retained for a period of at least five years.
All records and documents referenced in the operator's program plan and necessary to verify compliance with provisions of the rule must be available and retained for the time period specified in that program plan, consistent with rule requirements. In addition, the various processes used to manage the Operator Qualification Program (i.e., Contractor Qualification Process, Communication of Change, Identification of Covered Tasks, etc.) should also be documented and retained.
7.2 Is it necessary for an operator to be able to document in one source the 'qualification trail' from definition of covered tasks through reevaluation of individuals who have been qualified to perform these tasks?
While there is no requirement for operators to document the 'qualification trail' in a single document, it is reasonable to expect that:
(a) such documentation is readily available;
(b) the operator can use this documentation to explain its compliance with the elements of the OQ Rule; and (c) the operator can and will use said documentation to evaluate the completeness of its process and its consistency with the program plan. Operators are, of course, encouraged to maintain their records in one document or database.
7.3 Are there records other than the four specified in §192.807(a)/ Sec. 195.507(a) that must be maintained?
While the rule does not specify particular additional records to be retained, it does require operators to maintain records that demonstrate compliance with the rule and with its written program. To demonstrate compliance, operators need to identify appropriate records to be maintained. For example, operators need to retain their written program and an index of changes made to it as a record.
7.4 Must records be maintained on the means used to identify which tasks are covered tasks?
The operator is required to maintain records that demonstrate compliance with the rule. The operator must include provisions in its OQ Program to identify covered tasks. The operator's OQ Program should describe its covered task identification process and show how the 4-part test was applied to each task considered.
7.5 Must records be maintained that show how the operator has determined the intervals at which an individual performing a covered task will need to be reevaluated?
The operator must retain records that demonstrate compliance with the regulation. Identification of reevaluation intervals for covered tasks is a key provision of the rule. The operator should also describe in its program plan the nature of records describing its basis for reevaluation intervals for each covered task, and the retention policy for these records.
7.6 Will operators be required to maintain training records in addition to other required records to prove operator qualifications from the date the rule was adopted (12/26/99) or from the compliance date of (10/28/02)?
According to §192.807(b)/Sec. 195.507(b), records of prior qualification and records of individuals no longer performing covered tasks must be retained for a period of five years. If qualification was completed during the interval from 12/26/99 to 10/28/02 (as it has been in most cases) then the applicable qualification records must be available for a period of at least five years from the date of the first qualification. If the operator believes that records documenting training of individuals are necessary to support qualification, then these records must also be maintained.
7.7 What documentation must the operator possess for contractor employees prior to or by October 28, 2002?
Each operator is required to assure itself that all individuals, including contractors, performing covered tasks on or after 10/28/02 are qualified to perform those tasks. Operators can choose from several methods of record retention, but must demonstrate that individuals performing covered tasks have been qualified. The operator may chose to maintain records; may rely on the records maintained by the contractor (in which case a prudent operator should perform periodic audits of such records, or provide by contract that such records must be turned over to the operator in the event that the contractor ceases doing business for any reason); or may rely on records maintained and administered by a third party.
Management of Changes
8.1 What types of changes should be communicated to persons performing covered tasks?
Numerous changes may occur that impact how a covered task is performed. Changes that need to be communicated to individuals performing covered tasks may include:
a. Modifications to company policies or procedures;
b. Changes in state or Federal regulations;
c. Utilization of new equipment and/or technology;
d. New information from equipment or product manufacturers. The operator should document provisions in its program plan (depending on their relative importance to the performance of covered tasks) describing what changes must be communicated, how these changes are to be communicated, to whom they are to be communicated, and within what time frame communication is required. The program plan should also describe conditions under which changes are sufficiently substantive to require persons performing covered tasks to be retrained and reevaluated prior to performing the task subject to the change.
Field Inspection
9.1 Will Inspectors conduct field verification of operator program implementation?
Yes, OPS intends to conduct field verifications of operator program implementation. Protocol 9 has been developed to support this verification process.
Inspection Process
10.1 Will state or Federal regulators disseminate OQ Program review criteria to operators?
OPS plans to maintain a web site on which OQ inspection protocols will be available to all states and operators, and on which frequently
asked questions (FAQs) relevant to effective OQ programs can be posted (and addressed) for all interested parties.
10.2 What will be the role of the inspector in evaluating the validity of written examinations and the associated answer keys?
Written examinations should be designed to objectively evaluate the knowledge of the individual seeking qualification to perform a covered task in performance of that task. These examinations will not necessarily evaluate their skills and abilities. Testing should cover key information needed to perform a task, possibly including the reasons behind basic steps in a particular procedure. Inspectors will evaluate the effectiveness of all evaluation methods, including written examinations, in filling these functions (also see FAQ 2.10).
10.3 Are the state or Federal regulators going to be publishing any lessons learned (positive as well as negative) based on their inspections of the operators?
Consideration is being given to periodic workshops at which OQ results would be summarized and lessons discussed. In addition, inspectors have been invited (and have accepted, to the extent that their participation does not affect their inspections schedules) to state and industry sponsored seminars to present such material.
10.4 Is there any coordination at the Federal level with the states to establish a standard objective set of OQ inspection criteria?
A concerted effort has been made by an OQ working group composed of state and Federal inspectors and regulatory representatives to develop inspection protocols, supplementary guidance, definitions
and frequently asked questions (FAQs) for use by the industry and the various inspection agencies. TSI will develop and distribute CBTbased training to provide consistency to the inspection process for State and Federal inspectors. State and Federal regulatory authorities will be using the inspection protocols consistent with all applicable laws (see disclaimer at the beginning of this paper) and are strongly encouraged to utilize the additional guidance developed by the working group.
10.5 What will happen with small operators (e.g., municipalities) that do not meet the standard?
All operators are expected to meet the 'standard'. Size and resource limitations will be considered in evaluating program approaches, and small operators will be offered assistance if necessary, but performance effectiveness of all programs is expected.
10.6 What efforts are being made to promote consistent inspections by all regulatory agencies?
The protocols will ensure greater consistency in inspections. OPS plans to provide training (see FAQ 10.4) for inspectors from all regions and states. In addition, consideration is being given to making information on operator headquarters OQ inspection findings and enforcement actions available to appropriate Federal and state agencies to both further the effectiveness of field inspections and promote consistency in rule interpretation among state and Federal inspectors.
A
Alcohol Testing, see also Drug and Alcohol Testing.
Amendment, Plans or Procedures 190.206 3
Anchors 192.161 35
Annual Report
Distribution Systems 191.11 16
Gathering Systems 191.17 16
Liquefied Natural Gas 191.17 16
Transmission Systems 191.17 16
Transportation by Pipeline, Hazardous Liquids 195.49 112 195.58 113
