[Title 49 CFR ]
[Code of Federal Regulations (annual edition) - October 1, 2009 Edition]
[From the U.S. Government Printing Office]
[[Page i]]
49
Parts 186 to 199
Revised as of October 1, 2009
Transportation
________________________
Containing a codification of documents of general
applicability and future effect
As of October 1, 2009
With Ancillaries
Published by
Office of the Federal Register
National Archives and Records
Administration
A Special Edition of the Federal Register
[[Page ii]]
U.S. GOVERNMENT OFFICIAL EDITION NOTICE
Legal Status and Use of Seals and Logos
The seal of the National Archives and Records Administration
(NARA) authenticates the Code of Federal Regulations (CFR) as
the official codification of Federal regulations established
under the Federal Register Act. Under the provisions of 44
U.S.C. 1507, the contents of the CFR, a special edition of the
Federal Register, shall be judicially noticed. The CFR is
prima facie evidence of the original documents published in
the Federal Register (44 U.S.C. 1510).
It is prohibited to use NARA's official seal and the stylized Code
of Federal Regulations logo on any republication of this
material without the express, written permission of the
Archivist of the United States or the Archivist's designee.
Any person using NARA's official seals and logos in a manner
inconsistent with the provisions of 36 CFR part 1200 is
subject to the penalties specified in 18 U.S.C. 506, 701, and
1017.
Use of ISBN Prefix
This is the Official U.S. Government edition of this publication
and is herein identified to certify its authenticity. Use of
the 0-16 ISBN prefix is for U.S. Government Printing Office
Official Editions only. The Superintendent of Documents of the
U.S. Government Printing Office requests that any reprinted
edition clearly be labeled as a copy of the authentic work
with a new ISBN.
U . S . G O V E R N M E N T P R I N T I N G O F F I C E
------------------------------------------------------------------
U.S. Superintendent of Documents Washington, DC
20402-0001
http://bookstore.gpo.gov
Phone: toll-free (866) 512-1800; DC area (202) 512-1800
[[Page iii]]
Table of Contents
Page
Explanation................................................. v
Title 49:
SUBTITLE B--Other Regulations Relating to Transportation
(Continued)
Chapter I--Pipeline and Hazardous Materials Safety
Administration, Department of Transportation
(Continued) 5
Finding Aids:
Table of CFR Titles and Chapters........................ 255
Alphabetical List of Agencies Appearing in the CFR...... 275
List of CFR Sections Affected........................... 285
[[Page iv]]
----------------------------
Cite this Code: CFR
To cite the regulations in
this volume use title,
part and section number.
Thus, 49 CFR 190.1 refers
to title 49, part 190,
section 1.
----------------------------
[[Page v]]
EXPLANATION
The Code of Federal Regulations is a codification of the general and
permanent rules published in the Federal Register by the Executive
departments and agencies of the Federal Government. The Code is divided
into 50 titles which represent broad areas subject to Federal
regulation. Each title is divided into chapters which usually bear the
name of the issuing agency. Each chapter is further subdivided into
parts covering specific regulatory areas.
Each volume of the Code is revised at least once each calendar year
and issued on a quarterly basis approximately as follows:
Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1
The appropriate revision date is printed on the cover of each
volume.
LEGAL STATUS
The contents of the Federal Register are required to be judicially
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie
evidence of the text of the original documents (44 U.S.C. 1510).
HOW TO USE THE CODE OF FEDERAL REGULATIONS
The Code of Federal Regulations is kept up to date by the individual
issues of the Federal Register. These two publications must be used
together to determine the latest version of any given rule.
To determine whether a Code volume has been amended since its
revision date (in this case, October 1, 2009), consult the ``List of CFR
Sections Affected (LSA),'' which is issued monthly, and the ``Cumulative
List of Parts Affected,'' which appears in the Reader Aids section of
the daily Federal Register. These two lists will identify the Federal
Register page number of the latest amendment of any given rule.
EFFECTIVE AND EXPIRATION DATES
Each volume of the Code contains amendments published in the Federal
Register since the last revision of that volume of the Code. Source
citations for the regulations are referred to by volume number and page
number of the Federal Register and date of publication. Publication
dates and effective dates are usually not the same and care must be
exercised by the user in determining the actual effective date. In
instances where the effective date is beyond the cut-off date for the
Code a note has been inserted to reflect the future effective date. In
those instances where a regulation published in the Federal Register
states a date certain for expiration, an appropriate note will be
inserted following the text.
OMB CONTROL NUMBERS
The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires
Federal agencies to display an OMB control number with their information
collection request.
[[Page vi]]
Many agencies have begun publishing numerous OMB control numbers as
amendments to existing regulations in the CFR. These OMB numbers are
placed as close as possible to the applicable recordkeeping or reporting
requirements.
OBSOLETE PROVISIONS
Provisions that become obsolete before the revision date stated on
the cover of each volume are not carried. Code users may find the text
of provisions in effect on a given date in the past by using the
appropriate numerical list of sections affected. For the period before
January 1, 2001, consult either the List of CFR Sections Affected, 1949-
1963, 1964-1972, 1973-1985, or 1986-2000, published in eleven separate
volumes. For the period beginning January 1, 2001, a ``List of CFR
Sections Affected'' is published at the end of each CFR volume.
INCORPORATION BY REFERENCE
What is incorporation by reference? Incorporation by reference was
established by statute and allows Federal agencies to meet the
requirement to publish regulations in the Federal Register by referring
to materials already published elsewhere. For an incorporation to be
valid, the Director of the Federal Register must approve it. The legal
effect of incorporation by reference is that the material is treated as
if it were published in full in the Federal Register (5 U.S.C. 552(a)).
This material, like any other properly issued regulation, has the force
of law.
What is a proper incorporation by reference? The Director of the
Federal Register will approve an incorporation by reference only when
the requirements of 1 CFR part 51 are met. Some of the elements on which
approval is based are:
(a) The incorporation will substantially reduce the volume of
material published in the Federal Register.
(b) The matter incorporated is in fact available to the extent
necessary to afford fairness and uniformity in the administrative
process.
(c) The incorporating document is drafted and submitted for
publication in accordance with 1 CFR part 51.
What if the material incorporated by reference cannot be found? If
you have any problem locating or obtaining a copy of material listed as
an approved incorporation by reference, please contact the agency that
issued the regulation containing that incorporation. If, after
contacting the agency, you find the material is not available, please
notify the Director of the Federal Register, National Archives and
Records Administration, Washington DC 20408, or call 202-741-6010.
CFR INDEXES AND TABULAR GUIDES
A subject index to the Code of Federal Regulations is contained in a
separate volume, revised annually as of January 1, entitled CFR Index
and Finding Aids. This volume contains the Parallel Table of Authorities
and Rules. A list of CFR titles, chapters, subchapters, and parts and an
alphabetical list of agencies publishing in the CFR are also included in
this volume.
An index to the text of ``Title 3--The President'' is carried within
that volume.
The Federal Register Index is issued monthly in cumulative form.
This index is based on a consolidation of the ``Contents'' entries in
the daily Federal Register.
A List of CFR Sections Affected (LSA) is published monthly, keyed to
the revision dates of the 50 CFR titles.
[[Page vii]]
REPUBLICATION OF MATERIAL
There are no restrictions on the republication of material appearing
in the Code of Federal Regulations.
INQUIRIES
For a legal interpretation or explanation of any regulation in this
volume, contact the issuing agency. The issuing agency's name appears at
the top of odd-numbered pages.
For inquiries concerning CFR reference assistance, call 202-741-6000
or write to the Director, Office of the Federal Register, National
Archives and Records Administration, Washington, DC 20408 or e-mail
[email protected].
SALES
The Government Printing Office (GPO) processes all sales and
distribution of the CFR. For payment by credit card, call toll-free,
866-512-1800, or DC area, 202-512-1800, M-F 8 a.m. to 4 p.m. e.s.t. or
fax your order to 202-512-2250, 24 hours a day. For payment by check,
write to: US Government Printing Office - New Orders, P.O. Box 979050,
St. Louis, MO 63197-9000. For GPO Customer Service call 202-512-1803.
ELECTRONIC SERVICES
The full text of the Code of Federal Regulations, the LSA (List of
CFR Sections Affected), The United States Government Manual, the Federal
Register, Public Laws, Public Papers, Daily Compilation of Presidential
Documents and the Privacy Act Compilation are available in electronic
format via Federalregister.gov. For more information, contact Electronic
Information Dissemination Services, U.S. Government Printing Office.
Phone 202-512-1530, or 888-293-6498 (toll-free). E-mail,
[email protected].
The Office of the Federal Register also offers a free service on the
National Archives and Records Administration's (NARA) World Wide Web
site for public law numbers, Federal Register finding aids, and related
information. Connect to NARA's web site at www.archives.gov/federal-
register. The NARA site also contains links to GPO Access.
Raymond A. Mosley,
Director,
Office of the Federal Register.
October 1, 2009.
[[Page ix]]
THIS TITLE
Title 49--Transportation is composed of nine volumes. The parts in
these volumes are arranged in the following order: Parts 1-99, parts
100-185, parts 186-199, parts 200-299, parts 300-399, parts 400-571,
parts 572-999, parts 1000-1199, and part 1200 to end. The first volume
(parts 1-99) contains current regulations issued under subtitle A--
Office of the Secretary of Transportation; the second volume (parts 100-
185) and the third volume (parts 186-199) contain the current
regulations issued under chapter I--Pipeline and Hazardous Materials
Safety Administration (DOT); the fourth volume (parts 200-299) contains
the current regulations issued under chapter II--Federal Railroad
Administration (DOT); the fifth volume (parts 300-399) contains the
current regulations issued under chapter III--Federal Motor Carrier
Safety Administration (DOT); the sixth volume (parts 400-571) contains
the current regulations issued under chapter IV--Coast Guard (DHS), and
some of chapter V--National Highway Traffic Safety Administration (DOT);
the seventh volume (parts 572-999) contains the rest of the regulations
issued under chapter IV, and the current regulations issued under
chapter VI--Federal Transit Administration (DOT), chapter VII--National
Railroad Passenger Corporation (AMTRAK), and chapter VIII--National
Transportation Safety Board; the eighth volume (parts 1000-1199)
contains the current regulations issued under chapter X--Surface
Transportation Board and the ninth volume (part 1200 to end) contains
the current regulations issued under chapter X--Surface Transportation
Board, chapter XI--Research and Innovative Technology Administration,
and chapter XII--Transportation Security Administration, Department of
Transportation. The contents of these volumes represent all current
regulations codified under this title of the CFR as of October 1, 2009.
In the volume containing parts 100-185, see Sec. 172.101 for the
Hazardous Materials Table. The Federal Motor Vehicle Safety Standards
appear in part 571.
Redesignation tables for chapter III--Federal Motor Carrier Safety
Administration, Department of Transportation and chapter XII--
Transportation Security Administration, Department of Transportation
appear in the Finding Aids section of the fifth and ninth volumes.
For this volume, Susannah C. Hurley was Chief Editor. The Code of
Federal Regulations publication program is under the direction of
Michael L. White, assisted by Ann Worley.
[[Page 1]]
TITLE 49--TRANSPORTATION
(This book contains parts 186 to 199)
--------------------------------------------------------------------
Editorial Note: Other regulations issued by the Department of
Transportation appear in 14 CFR chapters I and II, 23 CFR, 33 CFR
chapters I and IV, 44 CFR chapter IV, 46 CFR chapters I through III, 48
CFR chapter 12, and 49 CFR chapters I through VI.
SUBTITLE B--Other Regulations Relating to Transportation (Continued)
Part
chapter I--Research and Special Programs Administration,
Department of Transportation (Continued).................. 190
[[Page 3]]
Subtitle B--Other Regulations Relating to Transportation (Continued)
[[Page 5]]
CHAPTER I--PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION,
DEPARTMENT OF TRANSPORTATION (CONTINUED)
--------------------------------------------------------------------
SUBCHAPTER D--PIPELINE SAFETY
Part Page
186-189
[Reserved]
190 Pipeline safety programs and rulemaking
procedures.............................. 7
191 Transportation of natural and other gas by
pipeline; annual reports, incident
reports, and safety-related condition
reports................................. 28
192 Transportation of natural and other gas by
pipeline: minimum Federal safety
standards............................... 33
193 Liquefied natural gas facilities: Federal
safety standards........................ 142
194 Response plans for onshore oil pipelines.... 161
195 Transportation of hazardous liquids by
pipeline................................ 171
196-197
[Reserved]
198 Regulations for grants to aid State pipeline
safety programs......................... 235
199 Drug and alcohol testing.................... 238
[[Page 7]]
SUBCHAPTER D_PIPELINE SAFETY
PARTS 186 189 [RESERVED]
PART 190_PIPELINE SAFETY PROGRAMS AND RULEMAKING PROCEDURES--Table of
Contents
Subpart A_General
Sec.
190.1 Purpose and scope.
190.3 Definitions.
190.5 Service.
190.7 Subpoenas; witness fees.
190.9 Petitions for finding or approval.
190.11 Availability of informal guidance and interpretive assistance.
Subpart B_Enforcement
190.201 Purpose and scope.
190.203 Inspections and investigations.
190.205 Warning letters.
190.207 Notice of probable violation.
190.209 Response options.
190.211 Hearing.
190.213 Final order.
190.215 Petitions for reconsideration.
Compliance Orders
190.217 Compliance orders generally.
190.219 Consent order.
Civil Penalties
190.221 Civil penalties generally.
190.223 Maximum penalties.
190.225 Assessment considerations.
190.227 Payment of penalty.
Criminal Penalties
190.229 Criminal penalties generally.
190.231 Referral for prosecution.
Specific Relief
190.233 Corrective action orders.
190.235 Injunctive action.
190.237 Amendment of plans or procedures.
190.239 Safety orders.
Subpart C_Procedures for Adoption of Rules
190.301 Scope.
190.303 Delegations.
190.305 Regulatory dockets.
190.307 Records.
190.309 Where to file petitions.
190.311 General.
190.313 Initiation of rulemaking.
190.315 Contents of notices of proposed rulemaking.
190.317 Participation by interested persons.
190.319 Petitions for extension of time to comment.
190.321 Contents of written comments.
190.323 Consideration of comments received.
190.325 Additional rulemaking proceedings.
190.327 Hearings.
190.329 Adoption of final rules.
190.331 Petitions for rulemaking.
190.333 Processing of petition.
190.335 Petitions for reconsideration.
190.337 Proceedings on petitions for reconsideration.
190.338 Appeals.
190.339 Direct final rulemaking.
190.341 Special permits.
Authority: 33 U.S.C. 1321; 49 U.S.C. 5101-5127, 60101 et seq.; 49
CFR 1.53.
Source: 45 FR 20413, Mar. 27, 1980, unless otherwise noted.
Subpart A_General
Sec. 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 49 U.S.C. 5101 et seq. (the hazardous material
transportation laws).
(b) This subpart defines certain terms and prescribes procedures
that are applicable to each proceeding described in this part.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18512,
Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005]
Sec. 190.3 Definitions.
As used in this part:
Administrator means the Administrator, Pipeline and Hazardous
Materials Safety Administration or his or her delegate.
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.
OPS means the Office of Pipeline Safety, which is part of the
Pipeline and Hazardous Materials Safety Administration, U.S. Department
of Transportation.
[[Page 8]]
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.
Presiding Official means the person who conducts any hearing
relating to civil penalty assessments, compliance orders or hazardous
facility orders.
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 Washington, DC
(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 the OPS has served a notice of
probable violation.
PHMSA means the Pipeline and Hazardous Materials Safety
Administration of the United States Department of Transportation.
State means a State of the United States, the District of Columbia
and the Commonwealth of Puerto Rico.
[Amdt. 190-6, 61 FR 18513, Apr. 26, 1996, as amended at 68 FR 11749,
Mar. 12, 2003; 70 FR 11137, Mar. 8, 2005]
Sec. 190.5 Service.
(a) Each order, notice, or other document required to be served
under this part shall be served personally, by registered or certified
mail, overnight courier, or electronic transmission by facsimile or
other electronic means that includes reliable acknowledgement of actual
receipt.
(b) Service upon a person's duly authorized representative or agent
constitutes service upon that person.
(c) Service by registered or certified mail or overnight courier is
complete upon mailing. Service by electronic transmission is complete
upon transmission and acknowledgement of receipt. An official receipt
for the mailing from the U.S. Postal Service or overnight courier, or a
facsimile or other electronic transmission confirmation, constitutes
prima facie evidence of service.
[45 FR 20413, Mar. 27, 1980, as amended at 73 FR 16567, Mar. 28, 2008]
Sec. 190.7 Subpoenas; witness fees.
(a) The Administrator, PHMSA, the Chief Counsel, PHMSA, or the
official designated by the Administrator, PHMSA, to preside over a
hearing convened in accordance with this part, may sign and issue
subpoenas individually on their own initiative or, upon request and
adequate showing by any person participating in the proceeding that the
information sought will materially advance the proceeding.
(b) A subpoena may require the attendance of a witness, or the
production of documentary or other tangible evidence in the possession
or under the control of person served, or both.
(c) A subpoena may be served personally by any person who is not an
interested person and is not less than 18 years of age, or by certified
or registered mail.
(d) Service of a subpoena upon the person named therein shall be
made by delivering a copy of the subpoena to such person and by
tendering the fees for one day's attendance and mileage as specified by
paragraph (g) of this section. When a subpoena is issued at the instance
of any officer or agency of the United States, fees and mileage need not
be tendered at the time of service. Delivery of a copy of a subpoena and
tender of the fees to a natural person may be made by handing them to
the person, leaving them at the person's office with the person in
charge thereof, leaving them at the person's dwelling place or usual
place of abode with some person of suitable age and discretion then
residing therein, by mailing them by registered or certified mail to the
person at the last known address, or by any method whereby actual notice
is given to the person and the fees are made available prior to the
return date.
(e) When the person to be served is not a natural person, delivery
of a copy of the subpoena and tender of the fees may be effected by
handing them to a designated agent or representative for service, or to
any officer, director, or
[[Page 9]]
agent in charge of any office of the person, or by mailing them by
registered or certified mail to that agent or representative and the
fees are made available prior to the return date.
(f) The original subpoena bearing a certificate of service shall be
filed with the official having responsibility for the proceeding in
connection with which the subpoena was issued.
(g) A subpoenaed witness shall be paid the same fees and mileage as
would be paid to a witness in a proceeding in the district courts of the
United States. The witness fees and mileage shall be paid by the person
at whose instance the subpoena was issued.
(h) Notwithstanding the provisions of paragraph (g) of this section,
and upon request, the witness fees and mileage may be paid by the PHMSA
if the official who issued the subpoena determines on the basis of good
cause shown, that:
(1) The presence of the subpoenaed witness will materially advance
the proceeding; and
(2) The person at whose instance the subpoena was issued would
suffer a serious hardship if required to pay the witness fees and
mileage.
(i) Any person to whom a subpoena is directed may, prior to the time
specified therein for compliance, but in no event more than 10 days
after the date of service of such subpoena, apply to the official who
issued the subpoena, or if the person is unavailable, to the
Administrator, PHMSA to quash or modify the subpoena. The application
shall contain a brief statement of the reasons relied upon in support of
the action sought therein. The Administrator, PHMSA, or this issuing
official, as the case may be, may:
(1) Deny the application;
(2) Quash or modify the subpoena; or
(3) Condition a grant or denial of the application to quash or
modify the subpoena upon the satisfaction of certain just and reasonable
requirements. The denial may be summary.
(j) Upon refusal to obey a subpoena served upon any person under the
provisions of this section, the PHMSA may request the Attorney General
to seek the aid of the U. S. District Court for any District in which
the person is found to compel that person, after notice, to appear and
give testimony, or to appear and produce the subpoenaed documents before
the PHMSA, or both.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513,
Apr. 26, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 70 FR 11137, Mar.
8, 2005]
Sec. 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.
(b) Each petition must refer to the rule authorizing the action
sought and contain information or arguments that justify the action.
Unless otherwise specified, no public proceeding is held on a petition
before it is granted or denied. After a petition is received, the
Administrator or participating state agency notifies the petitioner of
the disposition of the petition or, if the request requires more
extensive consideration or additional information or comments are
requested and delay is expected, of the date by which action will be
taken.
(1) For operators seeking a finding or approval involving intrastate
pipeline transportation, petitions must be sent to:
(i) The State agency certified to participate under 49 U.S.C. 60105.
(ii) Where there is no state agency certified to participate, the
Administrator, Pipeline and Hazardous Materials Safety Administration,
1200 New Jersey Avenue, SE, Washington, DC 20590.
(2) For operators seeking a finding or approval involving interstate
pipeline transportation, petitions must be sent to the Administrator,
Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey
Avenue, SE, Washington, DC 20590.
(c) All petitions must be received at least 90 days prior to the
date by which the operator requests the finding or approval to be made.
(d) The Administrator will make all findings or approvals of
petitions initiated under this section. A participating
[[Page 10]]
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.
[Amdt. 190-5, 59 FR 17280, Apr. 12, 1994, as amended by Amdt. 190-6, 61
FR 18513, Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005; 73 FR 16566, Mar.
28, 2008]
Sec. 190.11 Availability of informal guidance and interpretive
assistance.
(a) Availability of telephonic and Internet assistance. (1) PHMSA
has established a website on the Internet and a telephone line at the
Office of Pipeline Safety headquarters where small operators and others
can obtain information on and advice about compliance with pipeline
safety regulations, 49 CFR parts 190-199. The website and telephone line
are staffed by personnel from PHMSA's Office of Pipeline Safety from
9:00 a.m. through 5:00 p.m., Eastern time, Monday through Friday, except
Federal holidays. When the lines are not staffed, individuals may leave
a recorded voicemail message, or post a message at the OPS website. All
messages will receive a response by the following business day. The
telephone number for the OPS information line is (202) 366-4595 and the
OPS website can be accessed via the Internet at http://ops.dot.gov.
(2) PHMSA's Office of the Chief Counsel (OCC) is available to answer
questions concerning Federal pipeline safety law, 49 U.S.C. 60101 et
seq. OCC may be contacted by telephone (202-366-4400) from 9:00 a.m. to
4:00 p.m. Eastern time, Monday through Friday, except Federal holidays.
Information and guidance concerning Federal pipeline safety law may also
be obtained by contacting OCC via the Internet at http://rspa-
atty.dot.gov.
(b) Availability of Written Interpretations. (1) 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 the
response.
(2) A written interpretation regarding Federal pipeline safety law,
49 U.S.C 60101 et seq., may be obtained from the Office of the Chief
Counsel, 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.
[62 FR 24057, May 2, 1997; 62 FR 34415, June 26, 1997, as amended at 70
FR 11137, Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008; 73 FR 16567, Mar.
28, 2008]
Subpart B_Enforcement
Sec. 190.201 Purpose and scope.
(a) This subpart describes the enforcement authority and sanctions
exercised by the Associate Administrator, OPS for achieving and
maintaining pipeline safety. It also prescribes the procedures governing
the exercise of that authority and the imposition of those sanctions.
(b) A person who is the subject of action pursuant to this subpart
may be represented by legal counsel at all stages of the proceeding.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513,
Apr. 26, 1996]
Sec. 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.
[[Page 11]]
(b) Inspections are ordinarily conducted pursuant to one of the
following:
(1) Routine scheduling by the Regional Director of the Region in
which the facility is located;
(2) A complaint received from a member of the public;
(3) Information obtained from a previous inspection;
(4) Report from a State Agency participating in the Federal Program
under 49 U.S.C. 60105;
(5) Pipeline accident or incident; or
(6) Whenever deemed appropriate by the Administrator, PHMSA or his
designee.
(c) If, after an inspection, the Associate Administrator, OPS
believes that further information is needed to determine appropriate
action, the Associate Administrator, OPS may send the owner or operator
a ``Request for Specific Information'' to be answered within 45 days
after receipt of the letter.
(d) To the extent necessary to carry out the responsibilities under
49 U.S.C. 60101 et seq., the Administrator, PHMSA or the Associate
Administrator, OPS 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, PHMSA or
the Associate Administrator, OPS 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.
(e) If a representative of the DOT investigates an incident
involving a pipeline facility, OPS may request that the operator make
available to the representative all records and information that pertain
to the incident in any way, including integrity management plans and
test results, and that the operator afford all reasonable assistance in
the investigation.
(f) When the information obtained from an inspection or from other
appropriate sources indicates that further OPS action is warranted, the
OPS may issue a warning letter under Sec. 190.205 or initiate one or
more of the enforcement proceedings prescribed in Sec. Sec. 190.207
through 190.235.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-3, 56 FR 31090,
July 9, 1991; Amdt. 190-6, 61 FR 18513, Apr. 26, 1996; Amdt. 190-7, 61
FR 27792, June 3, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 70 FR
11137, Mar. 8, 2005]
Sec. 190.205 Warning letters.
Upon determining that a probable violation of 49 U.S.C. 60101 et
seq. or any regulation or order issued thereunder has occurred, the
Associate Administrator, OPS, may issue a Warning Letter notifying the
owner or operator of the probable violation and advising the owner or
operator to correct it or be subject to enforcement action under
Sec. Sec. 190.207 through 190.235.
[Amdt. 190-6, 61 FR 38403, July 24, 1996]
Sec. 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. or any regulation or order issued
thereunder.
(b) A notice of probable violation issued under this section shall
include:
(1) Statement of the provisions of the laws, regulations or orders
which the respondent is alleged to have violated and a statement of the
evidence upon which the allegations are based;
(2) Notice of response options available to the respondent under
Sec. 190.209;
(3) If a civil penalty is proposed under Sec. 190.221, the amount
of the proposed civil penalty and the maximum civil penalty for which
respondent is liable under law; and
(4) If a compliance order is proposed under Sec. 190.217, a
statement of the remedial action being sought in the form of a proposed
compliance order.
(c) The Associate Administrator, OPS may amend a notice of probable
violation at any time prior to issuance of a final order under Sec.
190.213. If an amendment includes any new material allegations of fact
or proposes an increased civil penalty amount or new or additional
remedial action under
[[Page 12]]
Sec. 190.217, the respondent shall have the opportunity to respond
under Sec. 190.209.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513,
Apr. 26, 1996]
Sec. 190.209 Response options.
Within 30 days of receipt of a notice of probable violation, the
respondent shall respond to the Regional Director who issued the notice
in the following way:
(a) When the notice contains a proposed civil penalty--
(1) Pay the proposed civil penalty as provided in Sec. 190.227 and
close the case with prejudice to the respondent;
(2) Submit written explanations, information or other materials in
answer to the allegations or in mitigation of the proposed civil
penalty; or
(3) Request a hearing under Sec. 190.211.
(b) When the notice contains a proposed compliance order--
(1) Agree to the proposed compliance order;
(2) Request the execution of a consent order under Sec. 190.219;
(3) Object to the proposed compliance order and submit written
explanations, information or other materials in answer to the
allegations in the notice of probable violation; or
(4) Request a hearing under Sec. 190.211.
(c) Failure of the respondent to respond in accordance with
paragraph (a) of this section or, when applicable, paragraph (c) of this
section, constitutes a waiver of the right to contest the allegations in
the notice of probable violation and authorizes the Associate
Administrator, OPS, without further notice to the respondent, to find
facts to be as alleged in the notice of probable violation and to issue
a final order under Sec. 190.213.
(d) All materials submitted by operators in response to enforcement
actions may be placed on publicly accessible Web sites. A Respondent
that seeks confidential treatment under 5 U.S.C. 552(b) for any portion
of its responsive materials must provide a second copy of such materials
along with the complete original document. A Respondent may redact the
portions it believes qualify for confidential treatment in the second
copy but must provide an explanation for each redaction.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-1, 53 FR 1635, Jan.
21, 1988; Amdt. 190-6, 61 FR 18513, Apr. 26, 1996; Amdt. 190-7, 61 FR
27792, June 3, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 73 FR
16567, Mar. 28, 2008]
Sec. 190.211 Hearing.
(a) A request for a hearing provided for in this part must be
accompanied by a statement of the issues that the respondent intends to
raise at the hearing. The issues may relate to the allegations in the
notice, the proposed corrective action (including a proposed amendment,
a proposed compliance order, or a proposed hazardous facility order), or
the proposed civil penalty amount. A respondent's failure to specify an
issue may result in waiver of the respondent's right to raise that issue
at the hearing. The respondent's request must also indicate whether or
not the respondent will be represented by counsel at the hearing.
(b) A telephone hearing will be held if the amount of the proposed
civil penalty or the cost of the proposed corrective action is less than
$10,000, unless the respondent submits a written request for an in-
person hearing. Hearings are held in a location agreed upon by the
presiding official, OPS and the respondent.
(c) An attorney from the Office of the Chief Counsel, Pipeline and
Hazardous Materials Safety Administration, serves as the presiding
official at the hearing.
(d) The hearing is conducted informally without strict adherence to
rules of evidence. The respondent may submit any relevant information
and material and call witnesses on the respondent's behalf. The
respondent may also examine the evidence and witnesses presented by the
government. No detailed record of a hearing is prepared.
(e) Upon request by respondent, and whenever practicable, the
material in the case file pertinent to the issues to be determined is
provided to the respondent 30 days before the hearing. The respondent
may respond to or rebut this material at the hearing.
(f) During the hearing, the respondent may offer any facts,
statements,
[[Page 13]]
explanations, documents, testimony or other items which are relevant to
the issues under consideration.
(g) At the close of the respondent's presentation, the presiding
official may present or allow the presentation of any OPS rebuttal
information. The respondent may then respond to that information.
(h) After the evidence in the case has been presented, the presiding
official shall permit argument on the issues under consideration.
(i) The respondent may also request an opportunity to submit further
written materal for inclusion in the case file. The presiding official
shall allow a reasonable time for the submission of the material and
shall specify the date by which it must be submitted. If the material is
not submitted within the time prescribed, the case shall proceed to
final action without the material.
(j) After submission of all materials during and after the hearing,
the presiding official shall prepare a written recommendation as to
final action in the case. This recommendation, along with any material
submitted during and after the hearing, shall be included in the case
file which is forwarded to the Associate Administrator, OPS for final
administrative action.
[45 FR 20413, Mar. 17, 1980, as amended by Amdt. 190-3, 56 FR 31090,
July 9, 1991; Amdt. 190-6, 61 FR 18514, Apr. 26, 1996; Amdt. 190-7, 61
FR 27792, June 3, 1996; 70 FR 11137, Mar. 8, 2005]
Sec. 190.213 Final order.
(a) After a hearing under Sec. 190.211 or, if no hearing has been
held, after expiration of the 30 day response period prescribed in Sec.
190.209, the case file of an enforcement proceeding commenced under
Sec. 190.207 is forwarded to the Associate Administrator, OPS for
issuance of a final order.
(b) The case file of an enforcement proceeding commenced under Sec.
190.207 includes:
(1) The inspection reports and any other evidence of alleged
violations;
(2) A copy of the notice of probable violation issued under Sec.
190.207;
(3) Material submitted by the respondent in accord with Sec.
190.209 in response to the notice of probable violation;
(4) The Regional Director's evaluation of response material
submitted by the respondent and recommendation for final action to be
taken under this section; and
(5) In cases involving a Sec. 190.211 hearing, any material
submitted during and after the hearing and the presiding official's
recommendation for final action to be taken under this section.
(c) Based on a review of a case file described in paragraph (b) of
this section, the Associate Administrator, OPS shall issue a final order
that includes--
(1) A statement of findings and determinations on all material
issues, including a determination as to whether each alleged violation
has been proved;
(2) If a civil penalty is assessed, the amount of the penalty and
the procedures for payment of the penalty, provided that the assessed
civil penalty may not exceed the penalty proposed in the notice of
probable violation; and
(3) If a compliance order is issued, a statement of the actions
required to be taken by the respondent and the time by which such
actions must be accomplished.
(d) Except as provided by Sec. 190.215, an order issued under this
section regarding an enforcement proceeding is considered final
administrative action on that enforcement proceeding.
(e) It is the policy of the Associate Administrator, OPS to issue a
final order under this section expeditiously. In cases where a
substantial delay is expected, notice of that fact and the date by which
it is expected that action will be taken is provided to the respondent
upon request and whenever practicable.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18514,
Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005]
Sec. 190.215 Petitions for reconsideration.
(a) A respondent may petition the Associate Administrator, OPS for
reconsideration of a final order issued under Sec. 190.213. It is
requested, but not required, that three copies be submitted. The
petition must be received no later than 20 days after service of the
final order upon the respondent. Petitions received after that time will
not be considered. The petition must
[[Page 14]]
contain a brief statement of the complaint and an explanation as to why
the effectiveness of the final order should be stayed.
(b) If the respondent requests the consideration of additional facts
or arguments, the respondent must submit the reasons they were not
presented prior to issuance of the final order.
(c) The Associate Administrator, OPS does not consider repetitious
information, arguments, or petitions.
(d) The filing of a petition under this section stays the payment of
any civil penalty assessed. However, unless the Associate Administrator,
OPS otherwise provides, the order, including any required corrective
action, is not stayed.
(e) The Associate Administrator, OPS may grant or deny, in whole or
in part, any petition for reconsideration without further proceedings.
In the event the Associate Administrator, OPS reconsiders a final order,
a final decision on reconsideration may be issued without further
proceedings, or, in the alternative, additional information, data, and
comment may be requested by the Associate Administrator, OPS as deemed
appropriate.
(f) It is the policy of the Associate Administrator, OPS to issue
notice of the action taken on a petition for reconsideration
expeditiously. In cases where a substantial delay is expected, notice of
that fact and the date by which it is expected that action will be taken
is provided to the respondent upon request and whenever practicable.
[Amdt. 190-6, 61 FR 18514, Apr. 26, 1996, as amended by Amdt 190-7, 61
FR 27792, June 3, 1996; 70 FR 11137, Mar. 8, 2005]
Compliance Orders
Sec. 190.217 Compliance orders generally.
When the Associate Administrator, OPS has reason to believe that a
person is engaging in conduct which involves a violation of the 49
U.S.C. 60101 et seq. or any regulation issued thereunder, and if the
nature of the violation, and the public interest warrant, the Associate
Administrator, OPS may conduct proceedings under Sec. Sec. 190.207
through 190.213 of this part to determine the nature and extent of the
violations and to issue an order directing compliance.
[Amdt. 190-6, 61 FR 18514, Apr. 26, 1996]
Sec. 190.219 Consent order.
(a) At any time before the issuance of a compliance order under
Sec. 190.213 the Associate Administrator, OPS and the respondent may
agree to dispose of the case by joint execution of a consent order. Upon
such joint execution, the consent order shall be considered a final
order under Sec. 190.213.
(b) A consent order executed under paragraph (a) of this section
shall include:
(1) An admission by the respondent of all jurisdictional facts;
(2) An express waiver of further procedural steps and of all right
to seek judicial review or otherwise challenge or contest the validity
of that order;
(3) An acknowledgement that the notice of probable violation may be
used to construe the terms of the consent order; and
(4) A statement of the actions required of the respondent and the
time by which such actions shall be accomplished.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18514,
Apr. 26, 1996]
Civil Penalties
Sec. 190.221 Civil penalties generally.
When the Associate Administrator, OPS has reason to believe that a
person has committed an act which is a violation of any provision of the
49 U.S.C. 60101 et seq. or any regulation or order issued thereunder,
proceedings under Sec. Sec. 190.207 through 190.213 may be conducted to
determine the nature and extent of the violations and to assess and, if
appropriate, compromise a civil penalty.
[Amdt. 190-6, 61 FR 18515, Apr. 26, 1996]
Sec. 190.223 Maximum penalties.
(a) Any person who is determined to have violated a provision of 49
U.S.C. 60101 et seq., or any regulation or order issued thereunder, is
subject to a civil penalty not to exceed $100,000 for each violation for
each day the violation continues except that the maximum
[[Page 15]]
civil penalty may not exceed $1,000,000 for any related series of
violations.
(b) Any person who knowingly violates a regulation or order under
this subchapter applicable to offshore gas gathering lines issued under
the authority of 49 U.S.C. 5101 et seq is liable for a civil penalty of
not more than $25,000 for each violation, and if any such violation is a
continuing one, each day of violation constitutes a separate offense.
(c) Any person who is determined to have violated any standard or
order under 49 U.S.C. 60103 shall be subjected to a civil penalty of not
to exceed $50,000, which penalty shall be in addition to any other
penalties to which such person may be subject under paragraph (a) of
this section.
(d) Any person who is determined to have violated any standard or
order under 49 U.S.C. 60129 shall be subject to a civil penalty not to
exceed $1,000, which shall be in addition to any other penalties to
which such person may be subject under paragraph (a) of this section.
(e) No person shall be subject to a civil penalty under this section
for the violation of any requirement of this subchapter and an order
issued under Sec. 190.217, Sec. 190.219 or Sec. 190.233 if both
violations are based on the same act.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-2, 54 FR 32344,
Aug. 7, 1989; Amdt. 190-6, 61 FR 18515, Apr. 26, 1996; 61 FR 38403, July
24, 1996; 70 FR 11137, Mar. 8, 2005]
Sec. 190.225 Assessment considerations.
In determining the amount of a civil penalty under this part,
(a) The Associate Administrator, OPS shall consider:
(1) The nature, circumstances and gravity of the violation,
including adverse impact on the environment;
(2) The degree of the respondent's culpability;
(3) The respondent's history of prior offenses;
(4) The respondent's ability to pay;
(5) Any good faith by the respondent in attempting to achieve
compliance;
(6) The effect on the respondent's ability to continue in business;
and
(b) The Associate Administrator, OPS may consider:
(1) The economic benefit gained from violation, if readily
ascertainable, without any reduction because of subsequent damages; and
(2) Such other matters as justice may require.
[70 FR 11137, Mar. 8, 2005]
Sec. 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. Payments exceeding $10,000 must be
made by wire transfer.
(b) Payment of a civil penalty assessed in a final order issued
under Sec. 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.
[Amdt. 190-7, 61 FR 27792, June 3, 1996, as amended at 70 FR 11138, Mar.
8, 2005; 73 FR 16567, Mar. 28, 2008]
Criminal Penalties
Sec. 190.229 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
shall upon conviction be subject for each offense to a fine of not more
than $25,000 and imprisonment for not more than five years, or both.
(b) Any person who willfully violates a regulation or order under
this subchapter issued under the authority of 49 U.S.C. 5101 et seq. as
applied to offshore gas gathering lines shall upon conviction be subject
for each offense to a fine of not more than $25,000, imprisonment for a
term not to exceed 5 years, or both.
[[Page 16]]
(c) Any person who willfully and knowingly injures or destroys, or
attempts to injure or destroy, any interstate transmission facility, any
interstate pipeline facility, or any intrastate pipeline facility used
in interstate or foreign commerce or in any activity affecting
interstate or foreign commerce (as those terms are defined in 49 U.S.C.
60101 et seq.) shall, upon conviction, be subject for each offense to a
fine of not more than $25,000, imprisonment for a term not to exceed 15
years, or both.
(d) Any person who willfully and knowingly defaces, damages,
removes, destroys any pipeline sign, right-of-way marker, or marine buoy
required by 49 U.S.C. 60101 et seq. or 49 U.S.C. 5101 et seq., or any
regulation or order issued thereunder shall, upon conviction, be subject
for each offense to a fine of not more than $5,000, imprisonment for a
term not to exceed 1 year, or both.
(e) Any person who willfully and knowingly engages in excavation
activity without first using an available one-call notification system
to establish the location of underground facilities in the excavation
area; or without considering location information or markings
established by a pipeline facility operator; and
(1) Subsequently damages a pipeline facility resulting in death,
serious bodily harm, or property damage exceeding $50,000;
(2) Subsequently damages a pipeline facility and knows or has reason
to know of the damage but fails to promptly report the damage to the
operator and to the appropriate authorities; or
(3) Subsequently damages a hazardous liquid pipeline facility that
results in the release of more than 50 barrels of product; shall, upon
conviction, be subject for each offense to a fine of not more than
$5,000, imprisonment for a term not to exceed 5 years, or both.
(f) No person shall be subject to criminal penalties under paragraph
(a) of this section for violation of any regulation and the violation of
any order issued under Sec. 190.217, Sec. 190.219 or Sec. 190.229 if
both violations are based on the same act.
[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-2, 54 FR 32344,
Aug. 7, 1989; Amdt. 190-4, 56 FR 63770, Dec. 5, 1991; Amdt. 190-6, 61 FR
18515, Apr. 26, 1996; 70 FR 11138, Mar. 8, 2005]
Sec. 190.231 Referral for prosecution.
If an employee of the Pipeline and Hazardous Materials Safety
Administration becomes aware of any actual or possible activity subject
to criminal penalties under Sec. 190.229, the employee reports it to
the Office of the Chief Counsel, Pipeline and Hazardous Materials Safety
Administration, U.S. Department of Transportation, Washington, DC 20590.
The Chief Counsel refers the report to OPS for investigation. Upon
completion of the investigation and if appropriate, the Chief Counsel
refers the report to the Department of Justice for criminal prosecution
of the offender.
[Amdt. 190-6, 61 FR 18515, Apr. 26, 1996, as amended at 70 FR 11137,
Mar. 8, 2005]
Specific Relief
Sec. 190.233 Corrective action orders.
(a) Except as provided by paragraph (b) of this section, if the
Associate Administrator, OPS finds, after reasonable notice and
opportunity for hearing in accord with paragraph (c) of this section and
Sec. 190.211(a), a particular pipeline facility to be hazardous to
life, property, or the environment, the Associate Administrator, OPS
shall issue an order pursuant to this section requiring the owner or
operator of the facility to take corrective action. Corrective action
may include suspended or restricted use of the facility, physical
inspection, testing, repair, replacement, or other appropriate action.
(b) The Associate Administrator, OPS may waive the requirement for
notice and opportunity for hearing under paragraph (a) of this section
before issuing an order pursuant to this section when the Associate
Administrator, OPS determines that the failure to do so would result in
the likelihood of serious harm to life, property, or the environment.
However, the Associate Administrator, OPS shall provide an opportunity
for a hearing as soon as is
[[Page 17]]
practicable after the issuance of a compliance order. The provisions of
paragraph (c)(2) of this section apply to an owner or operator's
decision to exercise its opportunity for a hearing. The purpose of such
a post-order hearing is for the Associate Administrator, OPS to
determine whether a compliance order should remain in effect or be
rescinded or suspended in accord with paragraph (g) of this section.
(c) Notice and hearing:
(1) Written notice that OPS intends to issue an order under this
section shall be served upon the owner or operator of an alleged
hazardous facility in accordance with Sec. 190.5. The notice shall
allege the existence of a hazardous facility and state the facts and
circumstances supporting the issuance of a corrective action order. The
notice shall also provide the owner or operator with the opportunity for
a hearing and shall identify a time and location where a hearing may be
held.
(2) An owner or operator that elects to exercise its opportunity for
a hearing under this section must notify the Associate Administrator,
OPS of that election in writing within 10 days of service of the notice
provided under paragraph (c)(1) of this section, or under paragraph (b)
of this section when applicable. The absence of such written
notification waives an owner or operator's opportunity for a hearing and
allows the Associate Administrator, OPS to issue a corrective action
order in accordance with paragraphs (d) through (h) of this section.
(3) A hearing under this section shall be presided over by an
attorney from the Office of Chief Counsel, Pipeline and Hazardous
Materials Safety Administration, acting as Presiding Official, and
conducted without strict adherence to formal rules of evidence. The
Presiding Official presents the allegations contained in the notice
issued under this section. The owner or operator of the alleged
hazardous facility may submit any relevant information or materials,
call witnesses, and present arguments on the issue of whether or not a
corrective action order should be issued.
(4) Within 48 hours after conclusion of a hearing under this
section, the Presiding Official shall submit a recommendation to the
Associate Administrator, OPS as to whether or not a corrective action
order is required. Upon receipt of the recommendation, the Associate
Administrator, OPS shall proceed in accordance with paragraphs (d)
through (h) of this section. If the Associate Administrator, OPS finds
the facility is or would be hazardous to life, property, or the
environment, the Associate Administrator, OPS shall issue a corrective
action order in accordance with this section. If the Associate
Administrator, OPS does not find the facility is or would be hazardous
to life, property, or the environment, the Associate Administrator shall
withdraw the allegation of the existence of a hazardous facility
contained in the notice, and promptly notify the owner or operator in
writing by service as prescribed in Sec. 190.5.
(d) The Associate Administrator, OPS may find a pipeline facility to
be hazardous under paragraph (a) of this section:
(1) If under the facts and circumstances the Associate
Administrator, OPS determines the particular facility is hazardous to
life, property, or the environment; or
(2) If the pipeline facility or a component thereof has been
constructed or operated with any equipment, material, or technique which
the Associate Administrator, OPS determines is hazardous to life,
property, or the environment, unless the operator involved demonstrates
to the satisfaction of the Associate Administrator, OPS that, under the
particular facts and circumstances involved, such equipment, material,
or technique is not hazardous.
(e) In making a determination under paragraph (d) of this section,
the Associate Administrator, OPS shall consider, if relevant:
(1) The characteristics of the pipe and other equipment used in the
pipeline facility involved, including its age, manufacturer, physical
properties (including its resistance to corrosion and deterioration),
and the method of its manufacture, construction or assembly;
(2) The nature of the materials transported by such facility
(including their corrosive and deteriorative qualities),
[[Page 18]]
the sequence in which such materials are transported, and the pressure
required for such transportation;
(3) The characteristics of the geographical areas in which the
pipeline facility is located, in particular the climatic and geologic
conditions (including soil characteristics) associated with such areas,
and the population density and population and growth patterns of such
areas;
(4) Any recommendation of the National Transportation Safety Board
issued in connection with any investigation conducted by the Board; and
(5) Such other factors as the Associate Administrator, OPS may
consider appropriate.
(f) A corrective action order shall contain the following
information:
(1) A finding that the pipeline facility is hazardous to life,
property, or the environment.
(2) The relevant facts which form the basis of that finding.
(3) The legal basis for the order.
(4) The nature and description of any particular corrective action
required of the respondent.
(5) The date by which the required corrective action must be taken
or completed and, where appropriate, the duration of the order.
(6) If the opportunity for a hearing was waived pursuant to
paragraph (b) of this section, a statement that an opportunity for a
hearing will be available at a particular time and location after
issuance of the order.
(g) The Associate Administrator, OPS shall rescind or suspend a
corrective action order whenever the Associate Administrator, OPS
determines that the facility is no longer hazardous to life, property,
or the environment. When appropriate, however, such a rescission or
suspension may be accompanied by a notice of probable violation issued
under Sec. 190.207.
(h) At any time after a corrective action order issued under this
section has become effective, the Associate Administrator, OPS may
request the Attorney General to bring an action for appropriate relief
in accordance with Sec. 190.235.
(i) Upon petition by the Attorney General, the District Courts of
the United States shall have jurisdiction to enforce orders issued under
this section by appropriate means.
[70 FR 11138, Mar. 8, 2005]
Sec. 190.235 Civil actions generally.
Whenever it appears to the Associate Administrator, OPS that a
person has engaged, is engaged, or is about to engage in any act or
practice constituting a violation of any provision of 49 U.S.C. 60101 et
seq., or any regulations issued thereunder, the Administrator, 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
and 49 U.S.C. 5123.
[70 FR 11139, Mar. 8, 2005]
Sec. 190.237 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 shall
provide an opportunity for a hearing under Sec. 190.211 of this part
and shall specify the alleged inadequacies and the proposed action for
revision of the plans or procedures. The notice shall allow the operator
30 days after receipt of the notice to submit written comments or
request a hearing. After considering all material presented in writing
or at the hearing, the Associate Administrator, OPS shall determine
whether the plans or procedures are inadequate as alleged and order the
required amendment if they are inadequate, or withdraw the notice if
they are not. In determining the adequacy of an operator's plans or
procedures, the Associate Administrator, OPS shall consider:
(1) Relevant available pipeline safety data;
(2) Whether the plans or procedures are appropriate for the
particular type of pipeline transportation or facility, and for the
location of the facility;
[[Page 19]]
(3) The reasonableness of the plans or procedures; and
(4) The extent to which the plans or procedures contribute to public
safety.
(b) The amendment of an operator's plans or procedures prescribed in
paragraph (a) of this section is in addition to, and may be used in
conjunction with, the appropriate enforcement actions prescribed in this
subpart.
[Amdt. 190-3, 56 FR 31090, July 9, 1991, as amended by Amdt. 190-6, 61
FR 18516, Apr. 26, 1996]
Subpart C_Procedures for Adoption of Rules
Source: Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, unless otherwise
noted.
Sec. 190.239 Safety orders.
(a) When may PHMSA issue a safety order? If the Associate
Administrator, OPS finds, after notice and an opportunity for hearing
under paragraph (b) of this section, that a particular pipeline facility
has a condition or conditions that pose a pipeline integrity risk to
public safety, property, or the environment, the Associate Administrator
may issue an order requiring the operator of the facility to take
necessary corrective action. Such action may include physical
inspection, testing, repair or other appropriate action to remedy the
identified risk condition.
(b) How is an operator notified of the proposed issuance of a safety
order and what are its response options? (1) Notice of proposed safety
order. PHMSA will serve written notice of a proposed safety order under
Sec. 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.
(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.
(3) Hearing. An operator receiving a notice of proposed safety order
may
[[Page 20]]
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.
(4) Conduct of hearing. An attorney from the Office of Chief
Counsel, PHMSA, 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 Sec. 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.
(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
Sec. 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.
(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.
(c) How is the determination made that a pipeline facility has a
condition that poses an integrity risk? The Associate Administrator, OPS
may find a pipeline facility to have a condition that poses a pipeline
integrity risk to public safety, property, or the environment under
paragraph (a) of this section:
(1) If under the facts and circumstances the Associate Administrator
determines the particular facility has such a condition; or
(2) If the pipeline facility or a component thereof has been
constructed or operated with any equipment, material, or technique with
a history of being susceptible to failure when used in pipeline service,
unless the operator involved demonstrates that such equipment, material,
or technique is not susceptible to failure given the manner it is being
used for a particular facility.
(d) What factors must PHMSA consider in making a determination that
a risk condition is present? In making a determination under paragraph
(c) of this section, the Associate Administrator, OPS shall consider, if
relevant:
(1) The characteristics of the pipe and other equipment used in the
pipeline facility involved, including its age, manufacturer, physical
properties (including its resistance to corrosion and deterioration),
and the method of its manufacture, construction or assembly;
(2) The nature of the materials transported by such facility
(including their corrosive and deteriorative qualities), the sequence in
which such materials are transported, and the pressure required for such
transportation;
[[Page 21]]
(3) The characteristics of the geographical areas where the pipeline
facility is located, in particular the climatic and geologic conditions
(including soil characteristics) associated with such areas;
(4) For hazardous liquid pipelines, the proximity of the pipeline to
an unusually sensitive area;
(5) The population density and growth patterns of the area in which
the pipeline facility is located;
(6) Any relevant recommendation of the National Transportation
Safety Board issued in connection with any investigation conducted by
the Board;
(7) The likelihood that the condition will impair the serviceability
of the pipeline;
(8) The likelihood that the condition will worsen over time; and
(9) The likelihood that the condition is present or could develop on
other areas of the pipeline.
(e) What information will be included in a safety order? A safety
order shall contain the following:
(1) A finding that the pipeline facility has a condition that poses
a pipeline integrity risk to public safety, property, or the
environment;
(2) The relevant facts which form the basis of that finding;
(3) The legal basis for the order;
(4) The nature and description of any particular corrective actions
to be required of the operator; and
(5) The date(s) by which the required corrective actions must be
taken or completed and, where appropriate, the duration of the order.
(f) Can PHMSA take other enforcement actions on the affected
facilities? Nothing in this section precludes PHMSA from issuing a
Notice of Probable Violation under Sec. 190.207 or taking other
enforcement action if noncompliance is identified at the facilities that
are the subject of a safety order proceeding.
[73 FR 16567, Mar. 28, 2008, as amended at 74 FR 2893, Jan. 16, 2009]
Sec. 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.
[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137,
Mar. 8, 2005]
Sec. 190.303 Delegations.
For the purposes of this subpart, Administrator means the
Administrator, Pipeline and Hazardous Materials Safety Administration,
or his or her delegate.
[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137,
Mar. 8, 2005]
Sec. 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
Sec. 190.325; and final regulations are maintained by the Pipeline and
Hazardous Materials Safety Administration at 1200 New Jersey Avenue, SE,
Washington, D.C. 20590-0001.
(b) Once a public docket is established, docketed material may be
accessed at 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.
[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137 and
11139, Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008; 73 FR 16568, Mar. 28,
2008]
[[Page 22]]
Sec. 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).
[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137,
Mar. 8, 2005]
Sec. 190.309 Where to file petitions.
Petitions for extension of time to comment submitted under Sec.
190.319, petitions for hearings submitted under Sec. 190.327, petitions
for rulemaking submitted under Sec. 190.331, and petitions for
reconsideration submitted under Sec. 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.
[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137,
Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008]
Sec. 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.
Sec. 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.
Sec. 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.
(b) Each notice, whether published in the Federal Register or
personally served, includes:
(1) A statement of the time, place, and nature of the proposed
rulemaking proceeding;
(2) A reference to the authority under which it is issued;
(3) A description of the subjects and issues involved or the
substance and terms of the proposed regulation;
(4) A statement of the time within which written comments must be
submitted; and
(5) A statement of how and to what extent interested persons may
participate in the proceeding.
Sec. 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.
(b) The Administrator may invite any interested person to
participate in the rulemaking proceedings described in Sec. 190.325.
(c) For the purposes of this subpart, an interested person includes
any Federal or State government agency or any political subdivision of a
State.
Sec. 190.319 Petitions for extension of time to comment.
A petition for extension of the time to submit comments must be
received not later than 10 days before expiration of the time stated in
the notice. It is requested, but not required, that three copies be
submitted. The filing of the petition does not automatically extend the
time for petitioner's comments. A petition is granted only if the
petitioner shows good cause for the extension, and if the extension is
consistent with the public interest. If an extension is granted, it is
granted to all persons, and it is published in the Federal Register.
[[Page 23]]
Sec. 190.321 Contents of written comments.
All written comments must be in English. It is requested, but not
required, that five copies be submitted. Any interested person should
submit as part of written comments all material considered relevant to
any statement of fact. Incorporation of material by reference should be
avoided; however, where necessary, such incorporated material shall be
identified by document title and page.
Sec. 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.
Sec. 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.
Sec. 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.
(b) Sections 556 and 557 of title 5, United States Code, do not
apply to hearings held under this part. Unless otherwise specified,
hearings held under this part are informal, nonadversary fact-finding
proceedings, at which there are no formal pleadings or adverse parties.
Any regulation issued in a case in which an informal hearing is held is
not necessarily based exclusively on the record of the hearing.
(c) The Administrator designates a representative to conduct any
hearing held under this subpart. The Chief Counsel designates a member
of his or her staff to serve as legal officer at the hearing.
Sec. 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.
Sec. 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.
(b) Each petition filed under this section must--
(1) Summarize the proposed action and explain its purpose;
(2) State the text of the proposed rule or amendment, or specify the
rule proposed to be repealed;
(3) Explain the petitioner's interest in the proposed action and the
interest of any party the petitioner represents; and
(4) Provide information and arguments that support the proposed
action, including relevant technical, scientific or other data as
available to the petitioner, and any specific known cases that
illustrate the need for the proposed action.
[[Page 24]]
(c) If the potential impact of the proposed action is substantial,
and information and data related to that impact are available to the
petitioner, the Associate Administrator or the Chief Counsel may request
the petitioner to provide--
(1) The costs and benefits to society and identifiable groups within
society, quantifiable and otherwise;
(2) The direct effects (including preemption effects) of the
proposed action on States, on the relationship between the Federal
Government and the States, and on the distribution of power and
responsibilities among the various levels of government;
(3) The regulatory burden on small businesses, small organizations
and small governmental jurisdictions;
(4) The recordkeeping and reporting requirements and to whom they
would apply; and
(5) Impacts on the quality of the natural and social environments.
(d) The Associate Administrator or Chief Counsel may return a
petition that does not comply with the requirements of this section,
accompanied by a written statement indicating the deficiencies in the
petition.
Sec. 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.
(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.
(c) Denials. If the Associate Administrator or the Chief Counsel
determines that the petition does not justify rulemaking, the petition
is denied.
(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.
Sec. 190.335 Petitions for reconsideration.
(a) Except as provided in Sec. 190.339(d), any interested person
may petition the Associate Administrator for reconsideration of any
regulation issued under this subpart, or may petition the Chief Counsel
for reconsideration of any procedural regulation issued under this
subpart and contained in this subpart. It is requested, but not
required, that three copies be submitted. The petition must be received
not later than 30 days after publication of the rule in the Federal
Register. Petitions filed after that time will be considered as
petitions filed under Sec. 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.
(b) If the petitioner requests the consideration of additional
facts, the petitioner must state the reason they were not presented to
the Associate Administrator or the Chief Counsel within the prescribed
time.
(c) The Associate Administrator or the Chief Counsel does not
consider repetitious petitions.
(d) Unless the Associate Administrator or the Chief Counsel
otherwise provides, the filing of a petition under this section does not
stay the effectiveness of the rule.
Sec. 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.
[[Page 25]]
(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.
Sec. 190.338 Appeals.
(a) Any interested person may appeal a denial of the Associate
Administrator or the Chief Counsel, issued under Sec. 190.333 or Sec.
190.337, to the Administrator.
(b) An appeal must be received within 20 days of service of written
notice to petitioner of the Associate Administrator's or the Chief
Counsel's decision, or within 20 days from the date of publication of
the decision in the Federal Register, and should set forth the contested
aspects of the decision as well as any new arguments or information.
(c) It is requested, but not required, that three copies of the
appeal be submitted to the Administrator.
(d) Unless the Administrator otherwise provides, the filing of an
appeal under this section does not stay the effectiveness of any rule.
Sec. 190.339 Direct final rulemaking.
(a) Where practicable, the Administrator will use direct final
rulemaking to issue the following types of rules:
(1) Minor, substantive changes to regulations;
(2) Incorporation by reference of the latest edition of technical or
industry standards;
(3) Extensions of compliance dates; and
(4) Other noncontroversial rules where the Administrator determines
that use of direct final rulemaking is in the public interest, and that
a regulation is unlikely to result in adverse comment.
(b) The direct final rule will state an effective date. The direct
final rule will also state that unless an adverse comment or notice of
intent to file an adverse comment is received within the specified
comment period, generally 60 days after publication of the direct final
rule in the 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.
(c) For purposes of this section, an adverse comment is one which
explains why the rule would be inappropriate, including a challenge to
the rule's underlying premise or approach, or would be ineffective or
unacceptable without a change. Comments that are frivolous or
insubstantial will not be considered adverse under this procedure. A
comment recommending a rule change in addition to the rule will not be
considered an adverse comment, unless the commenter states why the rule
would be ineffective without the additional change.
(d) Only parties who filed comments to a direct final rule issued
under this section may petition under Sec. 190.335 for reconsideration
of that direct final rule.
(e) If an adverse comment or notice of intent to file an adverse
comment is received, a timely document will be published in the 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 Sec. Sec. 190.311-190.329.
Sec. 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
[[Page 26]]
(or prospective operator) for specified facilities that are or, absent
waiver, would be subject to the regulation.
(b) How do I apply for a special permit? Applications for special
permits must be submitted at least 120 days before the requested
effective date using any of the following methods:
(1) Direct fax to PHMSA at: 202-366-4566; or
(2) Mail, express mail, or overnight courier to the Associate
Administrator for Pipeline Safety, Pipeline and Hazardous Materials
Safety Administration, 1200 New Jersey Avenue, SE., East Building,
Washington, DC 20590.
(c) What information must be contained in the application?
Applications must contain the following information:
(1) The name, mailing address, and telephone number of the applicant
and whether the applicant is an operator;
(2) A detailed description of the pipeline facilities for which the
special permit is sought, including:
(i) The beginning and ending points of the pipeline mileage to be
covered and the Counties and States in which it is located;
(ii) Whether the pipeline is interstate or intrastate and a general
description of the right-of-way including proximity of the affected
segments to populated areas and unusually sensitive areas;
(iii) Relevant pipeline design and construction information
including the year of installation, the material, grade, diameter, wall
thickness, and coating type; and
(iv) Relevant operating information including operating pressure,
leak history, and most recent testing or assessment results;
(3) A list of the specific regulation(s) from which the applicant
seeks relief;
(4) An explanation of the unique circumstances that the applicant
believes make the applicability of that regulation or standard (or
portion thereof) unnecessary or inappropriate for its facility;
(5) A description of any measures or activities the applicant
proposes to undertake as an alternative to compliance with the relevant
regulation, including an explanation of how such measures will mitigate
any safety or environmental risks;
(6) A description of any positive or negative impacts on affected
stakeholders and a statement indicating how operating the pipeline
pursuant to a special permit would be in the public interest;
(7) A certification that operation of the applicant's pipeline under
the requested special permit would not be inconsistent with pipeline
safety;
(8) If the application is for a renewal of a previously granted
waiver or special permit, a copy of the original grant of the waiver or
permit; and
(9) Any other information PHMSA may need to process the application
including environmental analysis where necessary.
(d) How does PHMSA handle special permit applications? (1) Public
notice. Upon receipt of an application for 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 on matters that PHMSA
believes may have significance for proceedings under their areas of
responsibility.
(2) Grants 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, on a temporary or permanent basis.
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/.
(e) Can a special permit be requested on an emergency basis? Yes.
PHMSA may grant an application for an emergency special permit without
notice
[[Page 27]]
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
biological 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.
(f) How do I apply for an emergency special permit? Applications for
emergency special permits may be submitted to PHMSA using any of the
following methods:
(1) Direct fax to the Crisis Management Center at: 202-366-3768;
(2) Direct e-mail to PHMSA at: phmsa.pipeline-
[email protected]; or
(3) Express mail/overnight courier to the Associate Administrator
for Pipeline Safety, Pipeline and Hazardous Materials Safety
Administration, 1200 New Jersey Avenue, SE., East Building, Washington,
DC 20590.
(g) What must be contained in an application for an emergency
special permit? In addition to the information required under paragraph
(c) of this section, applications for emergency special permits must
include:
(1) An explanation of the actual or impending emergency and how the
applicant is affected;
(2) A citation of the regulations that are implicated and the
specific reasons the permit is necessary to address the emergency (e.g.,
lack of accessibility, damaged equipment, insufficient manpower);
(3) A statement indicating how operating the pipeline pursuant to an
emergency special permit is in the public interest (e.g., continuity of
service, service restoration);
(4) A description of any proposed alternatives to compliance with
the regulation (e.g., additional inspections and tests, shortened
reassessment intervals); and
(5) A description of any measures to be taken after the emergency
situation or permit expires--whichever comes first--to confirm long-term
operational reliability of the pipeline facility.
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.
(h) In what circumstances will PHMSA revoke, suspend, or modify a
special permit?
(1) PHMSA may revoke, suspend, or modify a special permit on a
finding that:
(i) Intervening changes in Federal law mandate revocation,
suspension, or modification of the special permit;
(ii) Based on a material change in conditions or circumstances,
continued adherence to the terms of the special permit would be
inconsistent with safety;
(iii) The application contained inaccurate or incomplete
information, and the special permit would not have been granted had the
application been accurate and complete;
(iv) The application contained deliberately inaccurate or incomplete
information; or
(v) The holder has failed to comply with any material term or
condition of the special permit.
(2) Except as provided in paragraph (h)(3) of this section, before a
special permit is modified, suspended or revoked, PHMSA will notify the
holder in writing of the proposed action and the reasons for it, and
provide an opportunity to show cause why the proposed action should not
be taken.
[[Page 28]]
(i) The holder may file a written response that shows cause why the
proposed action should not be taken within 30 days of receipt of notice
of the proposed action.
(ii) After considering the holder's written response, or after 30
days have passed without response since receipt of the notice, PHMSA
will notify the holder in writing of the final decision with a brief
statement of reasons.
(3) If necessary to avoid a risk of significant harm to persons,
property, or the environment, PHMSA may in the notification declare the
proposed action immediately effective.
(4) Unless otherwise specified, the terms and conditions of a
corrective action order, compliance order, or other order applicable to
a pipeline facility covered by a special permit will take precedence
over the terms of the special permit.
(5) A special permit holder may seek reconsideration of a decision
under paragraph (h) of this section as provided in paragraph (i) of this
section.
(i) Can a denial of a request for a special permit or a revocation
of an existing special permit be appealed? Reconsideration of the denial
of an application for a special permit or a revocation of an existing
special permit may be sought by petition to the Associate Administrator.
Petitions for reconsideration must be received by PHMSA within 20
calendar days of the notice of the grant or denial and must contain a
brief statement of the issue and an explanation of why the petitioner
believes that the decision being appealed is not in the public interest.
The Associate Administrator may grant or deny, in whole or in part, any
petition for reconsideration without further proceedings. The Associate
Administrator's decision is the final administrative action.
(j) Are documents related to an application for a special permit
available for public inspection? Documents related to an application,
including the application itself, are available for public inspection on
regulations.gov or the Docket Operations Facility to the extent such
documents do not include information exempt from public disclosure under
5 U.S.C. 552(b). Applicants may request confidential treatment under
part 7 of this title.
[73 FR 16568, Mar. 28, 2008, as amended at 74 FR 2893, Jan. 16, 2009]
PART 191_TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; ANNUAL
REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS--Table
of Contents
Sec.
191.1 Scope.
191.3 Definitions.
191.5 Telephonic notice of certain incidents.
191.7 Addressee for written reports.
191.9 Distribution system: Incident report.
191.11 Distribution system: Annual report.
191.13 Distribution systems reporting transmission pipelines;
transmission or gathering systems reporting distribution
pipelines.
191.15 Transmission and gathering systems: Incident report.
191.17 Transmission and gathering systems: Annual report.
191.19 Report forms.
191.21 OMB control number assigned to information collection.
191.23 Reporting safety-related conditions.
191.25 Filing safety-related condition reports.
191.27 Filing offshore pipeline condition reports.
Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118,
and 60124; and 49 CFR 1.53.
Sec. 191.1 Scope.
(a) This part prescribes requirements for the reporting of
incidents, safety-related conditions, and annual pipeline summary data
by operators of gas pipeline facilities located in the United States or
Puerto Rico, including pipelines within the limits of the Outer
Continental Shelf as that term is defined in the Outer Continental Shelf
Lands Act (43 U.S.C. 1331).
(b) This part does not apply to--
(1) Offshore gathering of gas in State waters upstream from the
outlet flange of each facility where hydrocarbons are produced or where
produced hydrocarbons are first separated, dehydrated, or otherwise
processed, whichever facility is farther downstream;
(2) Pipelines on the Outer Continental Shelf (OCS) that are
producer-operated and cross into State waters
[[Page 29]]
without first connecting to a transporting operator's facility on the
OCS, upstream (generally seaward) of the last valve on the last
production facility on the OCS. Safety equipment protecting PHMSA-
regulated pipeline segments is not excluded. Producing operators for
those pipeline segments upstream of the last valve of the last
production facility on the OCS may petition the Administrator, or
designee, for approval to operate under PHMSA regulations governing
pipeline design, construction, operation, and maintenance under 49 CFR
190.9.
(3) Pipelines on the Outer Continental Shelf upstream of the point
at which operating responsibility transfers from a producing operator to
a transporting operator; or
(4) Onshore gathering of gas outside of the following areas:
(i) An area within the limits of any incorporated or unincorporated
city, town, or village.
(ii) Any designated residential or commercial area such as a
subdivision, business or shopping center, or community development.
[Amdt. 191-5, 49 FR 18960, May 3, 1984, as amended by Amdt. 191-6, 53 FR
24949, July 1, 1988; Amdt. 191-11, 61 FR 27793, June 3, 1996; Amdt. 191-
12, 62 FR 61695, Nov. 19, 1997; Amdt. 191-15, 68 FR 46111, Aug. 5, 2003;
70 FR 11139, Mar. 8, 2005]
Sec. 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
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 or of
liquefied natural gas or gas from an LNG facility and
(i) A death, or personal injury necessitating in-patient
hospitalization; or
(ii) Estimated property damage, including cost of gas lost, of the
operator or others, or both, of $50,000 or more.
(2) An event that results in an emergency shutdown of an LNG
facility.
(3) An event that is significant, in the judgement of the operator,
even though it did not meet the criteria of paragraphs (1) or (2).
LNG facility means a liquefied natural gas facility as defined in
Sec. 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.
State includes each of the several States, the District of Columbia,
and the Commonwealth of Puerto Rico;
[[Page 30]]
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.
[35 FR 320, Jan. 8, 1970, as amended by Amdt. 191-5, 49 FR 18960, May 3,
1984; Amdt. 191-10, 61 FR 18516, Apr. 26, 1996; Amdt. 191-12, 62 FR
61695, Nov. 19, 1997; 68 FR 11749, Mar. 12, 2003; 70 FR 11139, Mar. 8,
2005]
Sec. 191.5 Telephonic notice of certain incidents.
(a) At the earliest practicable moment following discovery, each
operator shall give notice in accordance with paragraph (b) of this
section of each incident as defined in Sec. 191.3.
(b) Each notice required by paragraph (a) of this section shall be
made by telephone to 800-424-8802 (in Washington, DC, 267-2675) and
shall include the following information.
(1) Names of operator and person making report and their telephone
numbers.
(2) The location of the incident.
(3) The time of the incident.
(4) The number of fatalities and personal injuries, if any.
(5) All other significant facts that are known by the operator that
are relevant to the cause of the incident or extent of the damages.
[Amdt. 191-4, 47 FR 32720, July 29, 1982, as amended by Amdt. 191-5, 49
FR 18960, May 3, 1984; Amdt. 191-8, 54 FR 40878, Oct. 4, 1989]
Sec. 191.7 Addressee for written reports.
Each written report required by this part must be made to Office of
Pipeline Safety, Pipeline and Hazardous Materials Safety Administration,
U.S. Department of Transportation, the Information Resources Manager,
PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. However,
incident and annual reports for intrastate pipeline transportation
subject to the jurisdiction of a State agency pursuant to a
certification under section 5(a) of the Natural Gas Pipeline Safety Act
of 1968 may be submitted in duplicate to that State agency if the
regulations of that agency require submission of these reports and
provide for further transmittal of one copy within 10 days of receipt
for incident reports and not later than March 15 for annual reports to
the Information Resources Manager. Safety-related condition reports
required by Sec. 191.23 for intrastate pipeline transportation must be
submitted concurrently to that State agency, and if that agency acts as
an agent of the Secretary with respect to interstate transmission
facilities, safety-related condition reports for these facilities must
be submitted concurrently to that agency.
[Amdt. 191-6, 53 FR 24949, July 1, 1988, as amended by Amdt. 191-16, 69
FR 32892, June 14, 2004; 70 FR 11139, Mar. 8, 2005; 73 FR 16570, Mar.
28, 2008; 74 FR 2894, Jan. 16, 2009]
Sec. 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 Sec. 191.5.
(b) When additional relevant information is obtained after the
report is submitted under paragraph (a) of this section, the operator
shall make supplementary reports as deemed necessary with a clear
reference by date and subject to the original report.
(c) The incident report required by this section need not be
submitted with respect to master meter systems or LNG facilities.
[Amdt. 191-5, 49 FR 18960, May 3, 1984]
Sec. 191.11 Distribution system: Annual report.
(a) Except as provided in paragraph (b) of this section, each
operator of a distribution pipeline system shall submit an annual report
for that system on Department of Transportation Form RSPA F 7100.1-1.
This report must be submitted each year, not later than March 15, for
the preceding calendar year.
(b) The annual report required by this section need not be submitted
with respect to:
(1) Petroleum gas systems which serve fewer than 100 customers from
a single source;
(2) Master meter systems; or
[[Page 31]]
(3) LNG facilities.
[Amdt. 191-5, 49 FR 18960, May 3, 1984]
Sec. 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 Sec. Sec. 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 Sec. Sec. 191.9 and 191.11.
[Amdt. 191-5, 49 FR 18961, May 3, 1984]
Sec. 191.15 Transmission and gathering systems: Incident report.
(a) Except as provided in paragraph (c) of this section, each
operator of a transmission or a gathering pipeline system shall submit
Department of Transportation Form RSPA F 7100.2 as soon as practicable
but not more than 30 days after detection of an incident required to be
reported under Sec. 191.5.
(b) Where additional related information is obtained after a report
is submitted under paragraph (a) of this section, the operator shall
make a supplemental report as soon as practicable with a clear reference
by date and subject to the original report.
(c) The incident report required by paragraph (a) of this section
need not be submitted with respect to LNG facilities.
[35 FR 320, Jan. 8, 1970, as amended by Amdt. 191-5, 49 FR 18961, May 3,
1984]
Sec. 191.17 Transmission and gathering systems: Annual report.
(a) Except as provided in paragraph (b) of this section, each
operator of a transmission or a gathering pipeline system shall submit
an annual report for that system on Department of Transportation Form
RSPA 7100.2-1. This report must be submitted each year, not later than
March 15, for the preceding calendar year.
(b) The annual report required by paragraph (a) of this section need
not be submitted with respect to LNG facilities.
[Amdt. 191-5, 49 FR 18961, May 3, 1984]
Sec. 191.19 Report forms.
Copies of the prescribed report forms are available without charge
upon request from the address given in Sec. 191.7. Additional copies in
this prescribed format may be reproduced and used if in the same size
and kind of paper. In addition, the information required by these forms
may be submitted by any other means that is acceptable to the
Administrator.
[Amdt. 191-10, 61 FR 18516, Apr. 26, 1996]
Sec. 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 gas pipeline information collection
requirements of the Office of Pipeline Safety pursuant to the Paperwork
Reduction Act of 1980, Public Law 96-511. It is the intent of this
section to comply with the requirements of section 3507(f) of the
Paperwork Reduction Act which requires that agencies display a current
control number assigned by the Director of OMB for each agency
information collection requirement.
OMB Control Number 2137-0522
------------------------------------------------------------------------
Section of 49 CFR part 191 where
identified Form No.
------------------------------------------------------------------------
191.5.................................. Telephonic.
191.9.................................. RSPA 7100.1
191.11................................. RSPA 7100.1-1
191.15................................. RSPA 7100.2
191.17................................. RSPA 7100.2-1.
------------------------------------------------------------------------
[Amdt. 191-5, 49 FR 18961, May 3, 1984, as amended by Amdt.191-13, 63 FR
7723, Feb. 17, 1998]
Sec. 191.23 Reporting safety-related conditions.
(a) Except as provided in paragraph (b) of this section, each
operator shall report in accordance with Sec. 191.25 the existence of
any of the following safety-related conditions involving facilities in
service:
(1) In the case of a pipeline (other than an LNG facility) that
operates at a hoop stress of 20 percent or more of its specified minimum
yield strength,
[[Page 32]]
general corrosion that has reduced the wall thickness to less than that
required for the maximum allowable operating pressure, and localized
corrosion pitting to a degree where leakage might result.
(2) Unintended movement or abnormal loading by environmental causes,
such as an earthquake, landslide, or flood, that impairs the
serviceability of a pipeline or the structural integrity or reliability
of an LNG facility that contains, controls, or processes gas or LNG.
(3) Any crack or other material defect that impairs the structural
integrity or reliability of an LNG facility that contains, controls, or
processes gas or LNG.
(4) Any material defect or physical damage that impairs the
serviceability of a pipeline that operates at a hoop stress of 20
percent or more of its specified minimum yield strength.
(5) Any malfunction or operating error that causes the pressure of a
pipeline or LNG facility that contains or processes gas or LNG to rise
above its maximum allowable operating pressure (or working pressure for
LNG facilities) plus the build-up allowed for operation of pressure
limiting or control devices.
(6) A leak in a pipeline or LNG facility that contains or processes
gas or LNG that constitutes an emergency.
(7) Inner tank leakage, ineffective insulation, or frost heave that
impairs the structural integrity of an LNG storage tank.
(8) Any safety-related condition that could lead to an imminent
hazard and causes (either directly or indirectly by remedial action of
the operator), for purposes other than abandonment, a 20 percent or more
reduction in operating pressure or shutdown of operation of a pipeline
or an LNG facility that contains or processes gas or LNG.
(b) A report is not required for any safety-related condition that--
(1) Exists on a master meter system or a customer-owned service
line;
(2) Is an incident or results in an incident before the deadline for
filing the safety-related condition report;
(3) Exists on a pipeline (other than an LNG facility) that is more
than 220 yards (200 meters) from any building intended for human
occupancy or outdoor place of assembly, except that reports are required
for conditions within the right-of-way of an active railroad, paved
road, street, or highway; or
(4) Is corrected by repair or replacement in accordance with
applicable safety standards before the deadline for filing the safety-
related condition report, except that reports are required for
conditions under paragraph (a)(1) of this section other than localized
corrosion pitting on an effectively coated and cathodically protected
pipeline.
[Amdt. 191-6, 53 FR 24949, July 1, 1988, as amended by Amdt. 191-14, 63
FR 37501, July 13, 1998]
Sec. 191.25 Filing safety-related condition reports.
(a) Each report of a safety-related condition under Sec. 191.23(a)
must be filed (received by the Associate Administrator, OPS) in writing
within five working days (not including Saturday, Sunday, or Federal
Holidays) after the day a representative of the operator first
determines that the condition exists, but not later than 10 working days
after the day a representative of the operator discovers the condition.
Separate conditions may be described in a single report if they are
closely related. Reports may be transmitted by facsimile at (202) 366-
7128.
(b) The report must be headed ``Safety-Related Condition Report''
and provide the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person
submitting the report.
(4) Name, job title, and business telephone number of person who
determined that the condition exists.
(5) Date condition was discovered and date condition was first
determined to exist.
(6) Location of condition, with reference to the State (and town,
city, or county) or offshore site, and as appropriate, nearest street
address, offshore platform, survey station number, milepost, landmark,
or name of pipeline.
(7) Description of the condition, including circumstances leading to
its discovery, any significant effects of the
[[Page 33]]
condition on safety, and the name of the commodity transported or
stored.
(8) The corrective action taken (including reduction of pressure or
shutdown) before the report is submitted and the planned follow-up or
future corrective action, including the anticipated schedule for
starting and concluding such action.
[Amdt. 191-6, 53 FR 24949, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as
amended by Amdt. 191-7, 54 FR 32344, Aug. 7, 1989; Amdt. 191-8, 54 FR
40878, Oct. 4, 1989; Amdt. 191-10, 61 FR 18516, Apr. 26, 1996]
Sec. 191.27 Filing offshore pipeline condition reports.
(a) Each operator shall, within 60 days after completion of the
inspection of all its underwater pipelines subject to Sec. 192.612(a),
report the following information:
(1) Name and principal address of operator.
(2) Date of report.
(3) Name, job title, and business telephone number of person
submitting the report.
(4) Total length of pipeline inspected.
(5) Length and date of installation of each exposed pipeline
segment, and location, including, if available, the location according
to the Minerals Management Service or state offshore area and block
number tract.
(6) Length and date of installation of each pipeline segment, if
different from a pipeline segment identified under paragraph (a)(5) of
this section, that is a hazard to navigation, and the location,
including, if available, the location according to the Minerals
Management Service or state offshore area and block number tract.
(b) The report shall be mailed to the Office of Pipeline Safety,
Pipeline and Hazardous Materials Safety Administration, Department of
Transportation, Information Resources Manager, PHP-10, 1200 New Jersey
Avenue SE., Washington, DC 20590-0001.
[Amdt. 191-9, 56 FR 63770, Dec. 5, 1991, as amended by Amdt. 191-14, 63
FR 37501, July 13, 1998; 70 FR 11139, Mar. 8, 2005; 73 FR 16570, Mar.
28, 2008; 74 FR 2894, Jan. 16, 2009]
PART 192_TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM
FEDERAL SAFETY STANDARDS--Table of Contents
Subpart A_General
Sec.
192.1 What is the scope of this part?
192.3 Definitions.
192.5 Class locations.
192.7 What documents are incorporated by reference partly or wholly in
this part?
192.8 How are onshore gathering lines and regulated onshore gathering
lines determined?
192.9 What requirements apply to gathering lines?
192.10 Outer continental shelf pipelines.
192.11 Petroleum gas systems.
192.13 What general requirements apply to pipelines regulated under this
part?
192.14 Conversion to service subject to this part.
192.15 Rules of regulatory construction.
192.16 Customer notification.
Subpart B_Materials
192.51 Scope.
192.53 General.
192.55 Steel pipe.
192.57 [Reserved]
192.59 Plastic pipe.
192.61 [Reserved]
192.63 Marking of materials.
192.65 Transportation of pipe.
Subpart C_Pipe Design
192.101 Scope.
192.103 General.
192.105 Design formula for steel pipe.
192.107 Yield strength (S) for steel pipe.
192.109 Nominal wall thickness (t) for steel pipe.
192.111 Design factor (F) for steel pipe.
192.112 Additional design requirements for steel pipe using alternative
maximum allowable operating pressure.
192.113 Longitudinal joint factor (E) for steel pipe.
192.115 Temperature derating factor (T) for steel pipe.
192.117 [Reserved]
192.119 [Reserved]
192.121 Design of plastic pipe.
192.123 Design limitations for plastic pipe.
192.125 Design of copper pipe.
Subpart D_Design of Pipeline Components
192.141 Scope.
192.143 General requirements.
192.144 Qualifying metallic components.
192.145 Valves.
[[Page 34]]
192.147 Flanges and flange accessories.
192.149 Standard fittings.
192.150 Passage of internal inspection devices.
192.151 Tapping.
192.153 Components fabricated by welding.
192.155 Welded branch connections.
192.157 Extruded outlets.
192.159 Flexibility.
192.161 Supports and anchors.
192.163 Compressor stations: Design and construction.
192.165 Compressor stations: Liquid removal.
192.167 Compressor stations: Emergency shutdown.
192.169 Compressor stations: Pressure limiting devices.
192.171 Compressor stations: Additional safety equipment.
192.173 Compressor stations: Ventilation.
192.175 Pipe-type and bottle-type holders.
192.177 Additional provisions for bottle-type holders.
192.179 Transmission line valves.
192.181 Distribution line valves.
192.183 Vaults: Structural design requirements.
192.185 Vaults: Accessibility.
192.187 Vaults: Sealing, venting, and ventilation.
192.189 Vaults: Drainage and waterproofing.
192.191 Design pressure of plastic fittings.
192.193 Valve installation in plastic pipe.
192.195 Protection against accidental overpressuring.
192.197 Control of the pressure of gas delivered from high-pressure
distribution systems.
192.199 Requirements for design of pressure relief and limiting devices.
192.201 Required capacity of pressure relieving and limiting stations.
192.203 Instrument, control, and sampling pipe and components.
Subpart E_Welding of Steel in Pipelines
192.221 Scope.
192.225 Welding procedures.
192.227 Qualification of welders.
192.229 Limitations on welders.
192.231 Protection from weather.
192.233 Miter joints.
192.235 Preparation for welding.
192.241 Inspection and test of welds.
192.243 Nondestructive testing.
192.245 Repair or removal of defects.
Subpart F_Joining of Materials Other Than by Welding
192.271 Scope.
192.273 General.
192.275 Cast iron pipe.
192.277 Ductile iron pipe.
192.279 Copper pipe.
192.281 Plastic pipe.
192.283 Plastic pipe: Qualifying joining procedures.
192.285 Plastic pipe: Qualifying persons to make joints.
192.287 Plastic pipe: Inspection of joints.
Subpart G_General Construction Requirements for Transmission Lines and
Mains
192.301 Scope.
192.303 Compliance with specifications or standards.
192.305 Inspection: General.
192.307 Inspection of materials.
192.309 Repair of steel pipe.
192.311 Repair of plastic pipe.
192.313 Bends and elbows.
192.315 Wrinkle bends in steel pipe.
192.317 Protection from hazards.
192.319 Installation of pipe in a ditch.
192.321 Installation of plastic pipe.
192.323 Casing.
192.325 Underground clearance.
192.327 Cover.
192.328 Additional construction requirements for steel pipe using
alternative maximum allowable operating pressure.
Subpart H_Customer Meters, Service Regulators, and Service Lines
192.351 Scope.
192.353 Customer meters and regulators: Location.
192.355 Customer meters and regulators: Protection from damage.
192.357 Customer meters and regulators: Installation.
192.359 Customer meter installations: Operating pressure.
192.361 Service lines: Installation.
192.363 Service lines: Valve requirements.
192.365 Service lines: Location of valves.
192.367 Service lines: General requirements for connections to main
piping.
192.369 Service lines: Connections to cast iron or ductile iron mains.
192.371 Service lines: Steel.
192.373 Service lines: Cast iron and ductile iron.
192.375 Service lines: Plastic.
192.377 Service lines: Copper.
192.379 New service lines not in use.
192.381 Service lines: Excess flow valve performance standards.
192.383 Excess flow valve customer notification.
Subpart I_Requirements for Corrosion Control
192.451 Scope.
192.452 How does this subpart apply to converted pipelines and regulated
onshore gathering lines?
192.453 General.
[[Page 35]]
192.455 External corrosion control: Buried or submerged pipelines
installed after July 31, 1971.
192.457 External corrosion control: Buried or submerged pipelines
installed before August 1, 1971.
192.459 External corrosion control: Examination of buried pipeline when
exposed.
192.461 External corrosion control: Protective coating.
192.463 External corrosion control: Cathodic protection.
192.465 External corrosion control: Monitoring.
192.467 External corrosion control: Electrical isolation.
192.469 External corrosion control: Test stations.
192.471 External corrosion control: Test leads.
192.473 External corrosion control: Interference currents.
192.475 Internal corrosion control: General.
192.476 Internal corrosion control: Design and construction of
transmission line.
192.477 Internal corrosion control: Monitoring.
192.479 Atmospheric corrosion control: General.
192.481 Atmospheric corrosion control: Monitoring.
192.483 Remedial measures: General.
192.485 Remedial measures: Transmission lines.
192.487 Remedial measures: Distribution lines other than cast iron or
ductile iron lines.
192.489 Remedial measures: Cast iron and ductile iron pipelines.
192.490 Direct assessment.
192.491 Corrosion control records.
Subpart J_Test Requirements
192.501 Scope.
192.503 General requirements.
192.505 Strength test requirements for steel pipeline to operate at a
hoop stress of 30 percent or more of SMYS.
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.
192.509 Test requirements for pipelines to operate below 100 p.s.i. (689
kPa) gage.
192.511 Test requirements for service lines.
192.513 Test requirements for plastic pipelines.
192.515 Environmental protection and safety requirements.
192.517 Records.
Subpart K_Uprating
192.551 Scope.
192.553 General requirements.
192.555 Uprating to a pressure that will produce a hoop stress of 30
percent or more of SMYS in steel pipelines.
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.
Subpart L_Operations
192.601 Scope.
192.603 General provisions.
192.605 Procedural manual for operations, maintenance, and emergencies.
192.607 [Reserved]
192.609 Change in class location: Required study.
192.611 Change in class location: Confirmation or revision of maximum
allowable operating pressure.
192.612 Underwater inspection and reburial of pipelines in the Gulf of
Mexico and its inlets.
192.613 Continuing surveillance.
192.614 Damage prevention program.
192.615 Emergency plans.
192.616 Public awareness.
192.617 Investigation of failures.
192.619 What is the maximum allowable operating pressure for steel or
plastic pipelines?
192.620 Alternative maximum allowable operating pressure for certain
steel pipelines.
192.621 Maximum allowable operating pressure: High-pressure distribution
systems.
192.623 Maximum and minimum allowable operating pressure; Low-pressure
distribution systems.
192.625 Odorization of gas.
192.627 Tapping pipelines under pressure.
192.629 Purging of pipelines.
Subpart M_Maintenance
192.701 Scope.
192.703 General.
192.705 Transmission lines: Patrolling.
192.706 Transmission lines: Leakage surveys.
192.707 Line markers for mains and transmission lines.
192.709 Transmission lines: Record keeping.
192.711 Transmission lines: General requirements for repair procedures.
192.713 Transmission lines: Permanent field repair of imperfections and
damages.
192.715 Transmission lines: Permanent field repair of welds.
192.717 Transmission lines: Permanent field repair of leaks.
192.719 Transmission lines: Testing of repairs.
192.721 Distribution systems: Patrolling.
192.723 Distribution systems: Leakage surveys.
192.725 Test requirements for reinstating service lines.
[[Page 36]]
192.727 Abandonment or deactivation of facilities.
192.731 Compressor stations: Inspection and testing of relief devices.
192.735 Compressor stations: Storage of combustible materials.
192.736 Compressor stations: Gas detection.
192.739 Pressure limiting and regulating stations: Inspection and
testing.
192.741 Pressure limiting and regulating stations: Telemetering or
recording gauges.
192.743 Pressure limiting and regulating stations: Capacity of relief
devices.
192.745 Valve maintenance: Transmission lines.
192.747 Valve maintenance: Distribution systems.
192.749 Vault maintenance.
192.751 Prevention of accidental ignition.
192.753 Caulked bell and spigot joints.
192.755 Protecting cast-iron pipelines.
Subpart N_Qualification of Pipeline Personnel
192.801 Scope.
192.803 Definitions.
192.805 Qualification Program.
192.807 Recordkeeping.
192.809 General.
Subpart O_Gas Transmission Pipeline Integrity Management
192.901 What do the regulations in this subpart cover?
192.903 What definitions apply to this subpart?
192.905 How does an operator identify a high consequence area?
192.907 What must an operator do to implement this subpart?
192.909 How can an operator change its integrity management program?
192.911 What are the elements of an integrity management program?
192.913 When may an operator deviate its program from certain
requirements of this subpart?
192.915 What knowledge and training must personnel have to carry out an
integrity management program?
192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity
program?
192.919 What must be in the baseline assessment plan?
192.921 How is the baseline assessment to be conducted?
192.923 How is direct assessment used and for what threats?
192.925 What are the requirements for using External Corrosion Direct
Assessment (ECDA)?
192.927 What are the requirements for using Internal Corrosion Direct
Assessment (ICDA)?
192.929 What are the requirements for using Direct Assessment for Stress
Corrosion Cracking (SCCDA)?
192.931 How may Confirmatory Direct Assessment (CDA) be used?
192.933 What actions must be taken to address integrity issues?
192.935 What additional preventive and mitigative measures must an
operator take?
192.937 What is a continual process of evaluation and assessment to
maintain a pipeline's integrity?
192.939 What are the required reassessment intervals?
192.941 What is a low stress reassessment?
192.943 When can an operator deviate from these reassessment intervals?
192.945 What methods must an operator use to measure program
effectiveness?
192.947 What records must an operator keep?
192.949 How does an operator notify PHMSA?
192.951 Where does an operator file a report?
Appendix A to Part 192 [Reserved]
Appendix B to Part 192--Qualification of Pipe
Appendix C to Part 192--Qualification of Welders for Low Stress Level
Pipe
Appendix D to Part 192--Criteria for Cathodic Protection and
Determination of Measurements
Appendix E to Part 192--Guidance on Determining High Consequence Areas
and on Carrying out Requirements in the Integrity Management
Rule
Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113,
and 60118; and 49 CFR 1.53.
Source: 35 FR 13257, Aug. 19, 1970, unless otherwise noted.
Editorial Note: Nomenclature changes to part 192 appear at 71 FR
33406, June 9, 2006.
Subpart A_General
Sec. 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).
(b) This part does not apply to--
(1) Offshore gathering of gas in State waters upstream from the
outlet flange of each facility where hydrocarbons are
[[Page 37]]
produced or where produced hydrocarbons are first separated, dehydrated,
or otherwise processed, whichever facility is farther downstream;
(2) Pipelines on the Outer Continental Shelf (OCS) that are
producer-operated and cross into State waters without first connecting
to a transporting operator's facility on the OCS, upstream (generally
seaward) of the last valve on the last production facility on the OCS.
Safety equipment protecting PHMSA-regulated pipeline segments is not
excluded. Producing operators for those pipeline segments upstream of
the last valve of the last production facility on the OCS may petition
the Administrator, or designee, for approval to operate under PHMSA
regulations governing pipeline design, construction, operation, and
maintenance under 49 CFR 190.9;
(3) Pipelines on the Outer Continental Shelf upstream of the point
at which operating responsibility transfers from a producing operator to
a transporting operator;
(4) Onshore gathering of gas--
(i) Through a pipeline that operates at less than 0 psig (0 kPa);
(ii) Through a pipeline that is not a regulated onshore gathering
line (as determined in Sec. 192.8); and
(iii) Within inlets of the Gulf of Mexico, except for the
requirements in Sec. 192.612; or
(5) Any pipeline system that transports only petroleum gas or
petroleum gas/air mixtures to--
(i) Fewer than 10 customers, if no portion of the system is located
in a public place; or
(ii) A single customer, if the system is located entirely on the
customer's premises (no matter if a portion of the system is located in
a public place).
[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]
Sec. 192.3 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.
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.
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
[[Page 38]]
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.
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 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 [deg]F (38 [deg]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 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.
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
Sec. 192.107(b).
State means each of the several States, the District of Columbia,
and the Commonwealth of Puerto Rico.
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
[[Page 39]]
or affecting interstate or foreign commerce.
[Amdt. 192-13, 38 FR 9084, Apr. 10, 1973, as amended by Amdt. 192-27, 41
FR 34605, Aug. 16, 1976; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt.
192-67, 56 FR 63771, Dec. 5, 1991; Amdt. 192-72, 59 FR 17281, Apr. 12,
1994; Amdt. 192-78, 61 FR 28783, June 6, 1996; Amdt. 192-81, 62 FR
61695, Nov. 19, 1997; Amdt. 192-85, 63 FR 37501, July 13, 1998; Amdt.
192-89, 65 FR 54443, Sept. 8, 2000; 68 FR 11749, Mar. 12, 2003; Amdt.
192-93, 68 FR 53900, Sept. 15, 2003; Amdt. 192-98, 69 FR 48406, Aug. 10,
2004; Amdt. 192-94, 69 FR 54592, Sept. 9, 2004; 70 FR 3148, Jan. 21,
2005; 70 FR 11139, Mar. 8, 2005]
Sec. 192.5 Class locations.
(a) This section classifies pipeline locations for purposes of this
part. The following criteria apply to classifications under this
section.
(1) A ``class location unit'' is an onshore area that extends 220
yards (200 meters) on either side of the centerline of any continuous 1-
mile (1.6 kilometers) length of pipeline.
(2) Each separate dwelling unit in a multiple dwelling unit building
is counted as a separate building intended for human occupancy.
(b) Except as provided in paragraph (c) of this section, pipeline
locations are classified as follows:
(1) A Class 1 location is:
(i) An offshore area; or
(ii) Any class location unit that has 10 or fewer buildings intended
for human occupancy.
(2) A Class 2 location is any class location unit that has more than
10 but fewer than 46 buildings intended for human occupancy.
(3) A Class 3 location is:
(i) Any class location unit that has 46 or more buildings intended
for human occupancy; or
(ii) An area where the pipeline lies within 100 yards (91 meters) of
either a building or a small, well-defined outside area (such as a
playground, recreation area, outdoor theater, or other place of public
assembly) that is occupied by 20 or more persons on at least 5 days a
week for 10 weeks in any 12-month period. (The days and weeks need not
be consecutive.)
(4) A Class 4 location is any class location unit where buildings
with four or more stories above ground are prevalent.
(c) The length of Class locations 2, 3, and 4 may be adjusted as
follows:
(1) A Class 4 location ends 220 yards (200 meters) from the nearest
building with four or more stories above ground.
(2) When a cluster of buildings intended for human occupancy
requires a Class 2 or 3 location, the class location ends 220 yards (200
meters) from the nearest building in the cluster.
[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]
Sec. 192.7 What documents are incorporated by reference partly or
wholly in this part?
(a) Any documents or portions thereof incorporated by reference in
this part are included in this part as though set out in full. When only
a portion of a document is referenced, the remainder is not incorporated
in this part.
(b) All incorporated materials are available for inspection in the
Office of Pipeline Safety, Pipeline and Hazardous Materials Safety
Administration, 1200 New Jersey Avenue, SE., Washington, DC, 20590-0001,
or at the National Archives and Records Administration (NARA). For
information on the availability of this material at NARA, call 202-741-
6030 or go to: http://www.archives.gov/federal--register/code--of--
federal--regulations/ibr--locations.html. These materials have been
approved for incorporation by reference by the Director of the Federal
Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. In
addition, the incorporated materials are available from the respective
organizations listed in paragraph (c) (1) of this section.
(c) The full titles of documents incorporated by reference, in whole
or in part, are provided herein. The numbers in parentheses indicate
applicable editions. For each incorporated document, citations of all
affected sections are provided. Earlier editions of currently listed
documents or editions of documents listed in previous editions of 49 CFR
part 192 may be used for materials and components designed,
manufactured, or installed in accordance with these earlier documents at
the time they were listed. The user must refer to the appropriate
previous edition of
[[Page 40]]
49 CFR part 192 for a listing of the earlier listed editions or
documents.
(1) Incorporated by reference (IBR).
List of Organizations and Addresses:
A. Pipeline Research Council International, Inc. (PRCI), c/o
Technical Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX 77098.
B. American Petroleum Institute (API), 1220 L Street, NW.,
Washington, DC 20005.
C. American Society for Testing and Materials (ASTM), 100 Barr
Harbor Drive, West Conshohocken, PA 19428.
D. ASME International (ASME), Three Park Avenue, New York, NY 10016-
5990.
E. Manufacturers Standardization Society of the Valve and Fittings
Industry, Inc. (MSS), 127 Park Street, NE., Vienna, VA 22180.
F. National Fire Protection Association (NFPA), 1 Batterymarch Park,
P.O. Box 9101, Quincy, MA 02269-9101.
G. Plastics Pipe Institute, Inc. (PPI), 1825 Connecticut Avenue,
NW., Suite 680, Washington, DC 20009.
H. NACE International (NACE), 1440 South Creek Drive, Houston, TX
77084.
I. Gas Technology Institute (GTI), 1700 South Mount Prospect Road,
Des Plaines, IL 60018.
(2) Documents incorporated by reference.
------------------------------------------------------------------------
Source and name of referenced material 49 CFR reference
------------------------------------------------------------------------
A. Pipeline Research Council International
(PRCI):
(1) AGA Pipeline Research Committee, Sec. Sec. 192.933(a);
Project PR-3-805, ``A Modified Criterion 192.485(c).
for Evaluating the Remaining Strength of
Corroded Pipe,'' (December 22, 1989). The
RSTRENG program may be used for
calculating remaining strength.
B. American Petroleum Institute (API):
(1) ANSI/API Specification 5L/ISO 3183 Sec. Sec. 192.55(e);
``Specification for Line Pipe'' (43rd 192.112; 192.113; Item I
edition and errata, 2004, and 44th of Appendix B.
edition, 2007).
(2) API Recommended Practice 5L1 Sec. 192.65(a).
``Recommended Practice for Railroad
Transportation of Line Pipe,'' (6th
edition, 2002).
(3) API Specification 6D ``Pipeline Sec. 192.145(a).
Valves,'' (22nd edition, January 2002).
(4) API Recommended Practice 80, Sec. 192.8(a);
``Guidelines for the Definition of 192.8(a)(1);
Onshore Gas Gathering Lines,'' (1st 192.8(a)(2);
edition, April 2000). 192.8(a)(3);
192.8(a)(4).
(5) API 1104 ``Welding of Pipelines and Sec. Sec. 192.227(a);
Related Facilities'' (19th edition 1999, 192.229(c)(1);
including errata October 31, 2001; and 192.241(c); Item II, and
20th edition 2007, including errata Appendix B.
2008).
(6) API Recommended Practice 1162 Sec. Sec. 192.616(a);
``Public Awareness Programs for Pipeline 192.616(b); 192.616(c).
Operators,'' (1st edition, December
2003).
C. American Society for Testing and Materials
(ASTM):
(1) ASTM A53/A53M-04a (2004) ``Standard Sec. Sec. 192.113;
Specification for Pipe, Steel, Black and Item I, Appendix B.
Hot-Dipped, Zinc-Coated, Welded and
Seamless.''.
(2) ASTM A106/A106M-04b (2004) ``Standard Sec. Sec. 192.113;
Specification for Seamless Carbon Steel Item I, Appendix B.
Pipe for High-Temperature Service.''.
(3) ASTM A333/A333M-05 (2005) ``Standard Sec. Sec. 192.113;
Specification for Seamless and Welded Item I, Appendix B.
Steel Pipe for Low-Temperature Service.''.
(4) ASTM A372/A372M-03 (2003) ``Standard Sec. 192.177(b)(1).
Specification for Carbon and Alloy Steel
Forgings for Thin-Walled Pressure
Vessels.''.
(5) ASTM A381-96 (Reapproved 2001) Sec. Sec. 192.113;
``Standard Specification for Metal-Arc Item I, Appendix B.
Welded Steel Pipe for Use With High-
Pressure Transmission Systems.''.
(6) ASTM Designation: A 578/A578M-96 (Re- Sec. Sec.
approved 2001) ``Standard Specification for 192.112(c)(2)(iii).
Straight-Beam Ultrasonic Examination of
Plain and Clad Steel Plates for Special
Applications''.
(7) ASTM A671-04 (2004) ``Standard Sec. Sec. 192.113;
Specification for Electric-Fusion-Welded Item I, Appendix B.
Steel Pipe for Atmospheric and Lower
Temperatures.''.
(8) ASTM A672-96 (Reapproved 2001) Sec. Sec. 192.113;
``Standard Specification for Electric- Item I, Appendix B.
Fusion-Welded Steel Pipe for High-Pressure
Service at Moderate Temperatures.''.
(9) ASTM A691-98 (Reapproved 2002) Sec. Sec. 192.113;
``Standard Specification for Carbon and Item I, Appendix B.
Alloy Steel Pipe, Electric-Fusion-Welded
for High-Pressure Service at High
Temperatures.''.
(10) ASTM D638-03 ``Standard Test Method Sec. Sec.
for Tensile Properties of Plastics.''. 192.283(a)(3);
192.283(b)(1).
(11) ASTM D2513-87 ``Standard Specification Sec. 192.63(a)(1).
for Thermoplastic Gas Pressure Pipe,
Tubing, and Fittings.''.
(12) ASTM D2513-99 ``Standard Specification Sec. Sec. 192.191(b);
for Thermoplastic Gas Pressure Pipe, 192.281(b)(2);
Tubing, and Fittings.''. 192.283(a)(1)(i); Item
1, Appendix B.
(13) ASTM D2517-00 ``Standard Specification Sec. Sec. 192.191(a);
for Reinforced Epoxy Resin Gas Pressure 192.281(d)(1);
Pipe and Fittings.''. 192.283(a)(1)(ii); Item
I, Appendix B.
(14) ASTM F1055-1998 ``Standard Sec.
Specification for Electrofusion Type 192.283(a)(1)(iii).
Polyethylene Fittings for Outside Diameter
Controller Polyethylene Pipe and Tubing.''.
[[Page 41]]
D. ASME International (ASME):
(1) ASME B16.1-1998 ``Cast Iron Pipe Sec. 192.147(c).
Flanges and Flanged Fittings.''.
(2) ASME B16.5-2003 (October 2004) ``Pipe Sec. Sec. 192.147(a);
Flanges and Flanged Fittings.''. 192.279.
(3) ASME B31G-1991 (Reaffirmed; 2004) Sec. Sec. 192.485(c);
``Manual for Determining the Remaining 192.933(a).
Strength of Corroded Pipelines.''.
(4) ASME B31.8-2003 (February 2004) ``Gas Sec. 192.619(a)(1)(i).
Transmission and Distribution Piping
Systems.''.
(5) ASME B31.8S-2004 ``Supplement to B31.8 Sec. Sec. 192.903(c);
on Managing System Integrity of Gas 192.907(b); 192.911,
Pipelines.''. Introductory text;
192.911(i); 192.911(k);
192.911(l); 192.911(m);
192.913(a) Introductory
text; 192.913(b)(1);
192.917(a) Introductory
text; 192.917(b);
192.917(c);
192.917(e)(1);
192.917(e)(4);
192.921(a)(1);
192.923(b)(2);
192.923(b)(3);
192.925(b) Introductory
text; 102.925(b)(1);
192.925(b)(2);
192.925(b)(3);
192.925(b)(4);
192.927(b);
192.927(c)(1)(i);
192.929(b)(1);
192.929(b)(2);
192.933(a);
192.933(d)(1);
192.933(d)(1)(i);
192.935(a);
192.935(b)(1)(iv);
192.937(c)(1);
192.939(a)(1)(i);
192.939(a)(1)(ii);
192.939(a)(3);
192.945(a).
(6) ASME Boiler and Pressure Vessel Code, Sec. 192.153(a).
Section I, ``Rules for Construction of
Power Boilers,'' (2004 edition, including
addenda through July 1, 2005).
(7) ASME Boiler and Pressure Vessel Code, Sec. Sec. 192.153(a);
Section VIII, Division 1, ``Rules for 192.153(b); 192.153(d);
Construction of Pressure Vessels,'' (2004 192.165(b)(3).
edition, including addenda through July 1,
2005).
(8) ASME Boiler and Pressure Vessel Code, Sec. Sec. 192.153(b);
Section VIII, Division 2, ``Rules for 192.165(b)(3).
Construction of Pressure Vessels--
Alternative Rules,'' (2004 edition,
including addenda through July 1, 2005).
(9) ASME Boiler and Pressure Vessel Code, Sec. Sec. 192.227(a);
Section IX, ``Welding and Brazing Item II, Appendix B.
Qualifications,'' (2004 edition, including
addenda through July 1, 2005).
E. Manufacturers Standardization Society of
the Valve and Fittings Industry, Inc. (MSS):
(1) MSS SP-44-1996 (Reaffirmed; 2001) Sec. 192.147(a).
``Steel Pipe Line Flanges.''.
(2) [Reserved]............................. .........................
F. National Fire Protection Association
(NFPA):
(1) NFPA 30 (2003) ``Flammable and Sec. 192.735(b).
Combustible Liquids Code.''.
(2) NFPA 58 (2004) ``Liquefied Petroleum Sec. 192.11(a);
Gas Code (LP-Gas Code).''. 192.11(b); 192.11(c).
(3) NFPA 59 (2004) ``Utility LP-Gas Plant Sec. Sec. 192.11(a);
Code.''. 192.11(b); 192.11(c).
(4) NFPA 70 (2005) ``National Electrical Sec. Sec. 192.163(e);
Code.''. 192.189(c).
G. Plastics Pipe Institute, Inc. (PPI):
(1) PPI TR-3/2004 (2004) ``Policies and Sec. 192.121.
Procedures for Developing Hydrostatic
Design Basis (HDB), Pressure Design Basis
(PDB), Strength Design Basis (SDB), and
Minimum Required Strength (MRS) Ratings
for Thermoplastic Piping Materials or
Pipe.''.
H. NACE International (NACE):
(1) NACE Standard RP0502-2002 ``Pipeline Sec. Sec.
External Corrosion Direct Assessment 192.923(b)(1);
Methodology.''. 192.925(b) Introductory
text; 192.925(b)(1);
192.925(b)(1)(ii);
192.925(b)(2)
Introductory text;
192.925(b)(3)
Introductory text;
192.925(b)(3)(ii);
192.925(b)(iv);
192.925(b)(4)
Introductory text;
192.925(b)(4)(ii);
192.931(d);
192.935(b)(1)(iv);
192.939(a)(2).
I. Gas Technology Institute (GTI):
(1) GRI 02/0057 (2002) ``Internal Corrosion Sec. 192.927(c)(2).
Direct Assessment of Gas Transmission
Pipelines Methodology.''.
------------------------------------------------------------------------
[[Page 42]]
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10159,
Feb. 2, 1981; Amdt 192-51, 51 FR 15334, Apr. 23, 1986; 58 FR 14521, Mar.
18, 1993; Amdt. 192-78, 61 FR 28783, June 6, 1996; 69 FR 18803, Apr. 9,
2004; Amdt. 192-94, 69 FR 32892, June 14, 2004; Amdt. 192-94, 69 FR
54592, Sept. 9, 2004; 70 FR 11139, Mar. 8, 2005; Amdt. 192-100, 70 FR
28842, May 19, 2005; Amdt. 192-102, 71 FR 13301, Mar. 15, 2006; Amdt.
192-103, 71 FR 33406, June 9, 2006; Amdt. 192-103, 72 FR 4656, Feb. 1,
2007; 73 FR 16570, Mar. 28, 2008; 73 FR 62174, Oct. 17, 2008; 74 FR
2894, Jan. 16, 2009; 74 FR 17101, Apr. 14, 2009]
Sec. 192.8 How are onshore gathering lines and regulated onshore
gathering lines determined?
(a) An operator must use API RP 80 (incorporated by reference, see
Sec. 192.7), to determine if an onshore pipeline (or part of a
connected series of pipelines) is an onshore gathering line. The
determination is subject to the limitations listed below. After making
this determination, an operator must determine if the onshore gathering
line is a regulated onshore gathering line under paragraph (b) of this
section.
(1) The beginning of gathering, under section 2.2(a)(1) of API RP
80, may not extend beyond the furthermost downstream point in a
production operation as defined in section 2.3 of API RP 80. This
furthermost downstream point does not include equipment that can be used
in either production or transportation, such as separators or
dehydrators, unless that equipment is involved in the processes of
``production and preparation for transportation or delivery of
hydrocarbon gas'' within the meaning of ``production operation.''
(2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP
80, may not extend beyond the first downstream natural gas processing
plant, unless the operator can demonstrate, using sound engineering
principles, that gathering extends to a further downstream plant.
(3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API
RP 80, is determined by the commingling of gas from separate production
fields, the fields may not be more than 50 miles from each other, unless
the Administrator finds a longer separation distance is justified in a
particular case (see 49 CFR Sec. 190.9).
(4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP
80, may not extend beyond the furthermost downstream compressor used to
increase gathering line pressure for delivery to another pipeline.
(b) For purposes of Sec. 192.9, ``regulated onshore gathering
line'' means:
(1) Each onshore gathering line (or segment of onshore gathering
line) with a feature described in the second column that lies in an area
described in the third column; and
(2) As applicable, additional lengths of line described in the
fourth column to provide a safety buffer:
----------------------------------------------------------------------------------------------------------------
Type Feature Area Safety buffer
----------------------------------------------------------------------------------------------------------------
A.................................... --Metallic and the MAOP Class 2, 3, or 4 None.
produces a hoop stress location (see Sec.
of 20 percent or more 192.5).
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).
[[Page 43]]
B.................................... --Metallic and the MAOP Area 1. Class 3 or 4 If the gathering line
produces a hoop stress location. is in Area 2(b) or
of less than 20 Area 2. An area within 2(c), the additional
percent of SMYS. If a Class 2 location the lengths of line extend
the stress level is operator determines by upstream and
unknown, an operator using any of the downstream from the
must determine the following three area to a point where
stress level according methods:. the line is at least
to the applicable (a) A Class 2 location. 150 feet (45.7 m) from
provisions in subpart (b) An area extending the nearest dwelling
C of this part. 150 feet (45.7 m) on in the area. However,
--Non-metallic and the each side of the if a cluster of
MAOP is 125 psig (862 centerline of any dwellings in Area 2
kPa) or less. continuous 1 mile (1.6 (b) or 2(c) qualifies
km) of pipeline and a line as Type B, the
including more than 10 Type B classification
but fewer than 46 ends 150 feet (45.7 m)
dwellings. from the nearest
(c) An area extending dwelling in the
150 feet (45.7 m) on cluster.
each side of the
centerline of any
continous 1000 feet
(305 m) of pipeline
and including 5 or
more dwellings.
----------------------------------------------------------------------------------------------------------------
[Amdt. 192-102, 71 FR 13302, Mar. 15, 2006]
Sec. 192.9 What requirements apply to gathering lines?
(a) Requirements. An operator of a gathering line must follow the
safety requirements of this part as prescribed by this section.
(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 Sec. 192.150 and in subpart O of this part.
(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 Sec. 192.150 and in
subpart O of this part. However, an operator of a Type A regulated
onshore gathering line 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.
(d) Type B lines. An operator of a Type B regulated onshore
gathering line must comply with the following requirements:
(1) If a line is new, replaced, relocated, or otherwise changed, the
design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines;
(2) If the pipeline is metallic, control corrosion according to
requirements of subpart I of this part applicable to transmission lines;
(3) Carry out a damage prevention program under Sec. 192.614;
(4) Establish a public education program under Sec. 192.616;
(5) Establish the MAOP of the line under Sec. 192.619; and
(6) Install and maintain line markers according to the requirements
for transmission lines in Sec. 192.707.
(e) Compliance deadlines. An operator of a regulated onshore
gathering line must comply with the following deadlines, as applicable.
(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
Sec. 192.13 applies.
(2) If a regulated onshore gathering line existing on April 14, 2006
was not previously subject to this part, an operator has until the date
stated in the second column to comply with the applicable requirement
for the line listed in the first column, unless the Administrator finds
a later deadline is justified in a particular case:
------------------------------------------------------------------------
Requirement Compliance deadline
------------------------------------------------------------------------
Control corrosion according to Subpart I April 15, 2009.
requirements for transmission lines.
Carry out a damage prevention program October 15, 2007.
under Sec. 192.614.
Establish MAOP under Sec. 192.619....... October 15, 2007.
Install and maintain line markers under April 15, 2008.
Sec. 192.707.
Establish a public education program under April 15, 2008.
Sec. 192.616.
[[Page 44]]
Other provisions of this part as required April 15, 2009.
by paragraph (c) of this section for Type
A lines.
------------------------------------------------------------------------
(3) If, after April 14, 2006, a change in class location or increase
in dwelling density causes an onshore gathering line to be a regulated
onshore gathering line, the operator has 1 year for Type B lines and 2
years for Type A lines after the line becomes a regulated onshore
gathering line to comply with this section.
[Amdt. 192-102, 71 FR 13301, Mar. 15, 2006]
Sec. 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]
Sec. 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
ANSI/NFPA 58 and 59.
(b) Each pipeline system subject to this part that transports only
petroleum gas or petroleum gas/air mixtures must meet the requirements
of this part and of ANSI/NFPA 58 and 59.
(c) In the event of a conflict between this part and ANSI/NFPA 58
and 59, ANSI/NFPA 58 and 59 prevail.
[Amdt. 192-78, 61 FR 28783, June 6, 1996]
Sec. 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 that is readied for service after the date in the second column,
unless:
(1) The pipeline has been designed, installed, constructed,
initially inspected, and initially tested in accordance with this part;
or
(2) The pipeline qualifies for use under this part according to the
requirements in Sec. 192.14.
------------------------------------------------------------------------
Pipeline Date
------------------------------------------------------------------------
Offshore gathering line................... July 31, 1977.
Regulated onshore gathering line to which March 15 2007.
this part did not apply until April 14,
2006.
All other pipelines....................... March 12, 1971.
------------------------------------------------------------------------
(b) No person may operate a segment of pipeline listed in the first
column that is replaced, relocated, or otherwise changed after the date
in the second column, unless the replacement, relocation or change has
been made according to the requirements in this part.
------------------------------------------------------------------------
Pipeline Date
------------------------------------------------------------------------
Offshore gathering line................... July 31, 1977.
Regulated onshore gathering line to which March 15, 2007.
this part did not apply until April 14,
2006.
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.
[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]
[[Page 45]]
Sec. 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:
(1) The design, construction, operation, and maintenance history of
the pipeline must be reviewed and, where sufficient historical records
are not available, appropriate tests must be performed to determine if
the pipeline is in a satisfactory condition for safe operation.
(2) The pipeline right-of-way, all aboveground segments of the
pipeline, and appropriately selected underground segments must be
visually inspected for physical defects and operating conditions which
reasonably could be expected to impair the strength or tightness of the
pipeline.
(3) All known unsafe defects and conditions must be corrected in
accordance with this part.
(4) The pipeline must be tested in accordance with subpart J of this
part to substantiate the maximum allowable operating pressure permitted
by subpart L of this part.
(b) Each operator must keep for the life of the pipeline a record of
the investigations, tests, repairs, replacements, and alterations made
under the requirements of paragraph (a) of this section.
[Amdt. 192-30, 42 FR 60148, Nov. 25, 1977]
Sec. 192.15 Rules of regulatory construction.
(a) As used in this part:
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:
(1) Words importing the singular include the plural;
(2) Words importing the plural include the singular; and
(3) Words importing the masculine gender include the feminine.
Sec. 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
Sec. 192.465 if the customer's buried piping is metallic, survey for
leaks according to Sec. 192.723, and if an unsafe condition is found,
shut off the flow of gas, advise the customer of the need to repair the
unsafe condition, or repair the unsafe condition.
(b) Each operator shall notify each customer once in writing of the
following information:
(1) The operator does not maintain the customer's buried piping.
(2) If the customer's buried piping is not maintained, it may be
subject to the potential hazards of corrosion and leakage.
(3) Buried gas piping should be--
(i) Periodically inspected for leaks;
(ii) Periodically inspected for corrosion if the piping is metallic;
and
(iii) Repaired if any unsafe condition is discovered.
(4) When excavating near buried gas piping, the piping should be
located in advance, and the excavation done by hand.
(5) The operator (if applicable), plumbing contractors, and heating
contractors can assist in locating, inspecting, and repairing the
customer's buried piping.
(c) Each operator shall notify each customer not later than August
14, 1996, or 90 days after the customer first receives gas at a
particular location, whichever is later. However, operators of master
meter systems may continuously post a general notice in a prominent
location frequented by customers.
(d) Each operator must make the following records available for
inspection by the Administrator or a State agency
[[Page 46]]
participating under 49 U.S.C. 60105 or 60106:
(1) A copy of the notice currently in use; and
(2) Evidence that notices have been sent to customers within the
previous 3 years.
[Amdt. 192-74, 60 FR 41828, Aug. 14, 1995, as amended by Amdt. 192-74A,
60 FR 63451, Dec. 11, 1995; Amdt. 192-83, 63 FR 7723, Feb. 17, 1998]
Subpart B_Materials
Sec. 192.51 Scope.
This subpart prescribes minimum requirements for the selection and
qualification of pipe and components for use in pipelines.
Sec. 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;
(b) Chemically compatible with any gas that they transport and with
any other material in the pipeline with which they are in contact; and
(c) Qualified in accordance with the applicable requirements of this
subpart.
Sec. 192.55 Steel pipe.
(a) New steel pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification;
(2) It meets the requirements of--
(i) Section II of appendix B to this part; or
(ii) If it was manufactured before November 12, 1970, either section
II or III of appendix B to this part; or
(3) It is used in accordance with paragraph (c) or (d) of this
section.
(b) Used steel pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification
and it meets the requirements of paragraph II-C of appendix B to this
part;
(2) It meets the requirements of:
(i) Section II of appendix B to this part; or
(ii) If it was manufactured before November 12, 1970, either section
II or III of appendix B to this part;
(3) It has been used in an existing line of the same or higher
pressure and meets the requirements of paragraph II-C of appendix B to
this part; or
(4) It is used in accordance with paragraph (c) of this section.
(c) New or used steel pipe may be used at a pressure resulting in a
hoop stress of less than 6,000 p.s.i. (41 MPa) where no close coiling or
close bending is to be done, if visual examination indicates that the
pipe is in good condition and that it is free of split seams and other
defects that would cause leakage. If it is to be welded, steel pipe that
has not been manufactured to a listed specification must also pass the
weldability tests prescribed in paragraph II-B of appendix B to this
part.
(d) Steel pipe that has not been previously used may be used as
replacement pipe in a segment of pipeline if it has been manufactured
prior to November 12, 1970, in accordance with the same specification as
the pipe used in constructing that segment of pipeline.
(e) New steel pipe that has been cold expanded must comply with the
mandatory provisions of API Specification 5L.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 191-1, 35 FR 17660,
Nov. 17, 1970; Amdt. 192-12, 38 FR 4761, Feb. 22, 1973; Amdt. 192-51, 51
FR 15335, Apr. 23, 1986; 58 FR 14521, Mar. 18, 1993; Amdt. 192-85, 63 FR
37502, July 13, 1998]
Sec. 192.57 [Reserved]
Sec. 192.59 Plastic pipe.
(a) New plastic pipe is qualified for use under this part if:
(1) It is manufactured in accordance with a listed specification;
and
(2) It is resistant to chemicals with which contact may be
anticipated.
(b) Used plastic pipe is qualified for use under this part if:
(1) It was manufactured in accordance with a listed specification;
(2) It is resistant to chemicals with which contact may be
anticipated;
(3) It has been used only in natural gas service;
(4) Its dimensions are still within the tolerances of the
specification to which it was manufactured; and
[[Page 47]]
(5) It is free of visible defects.
(c) For the purpose of paragraphs (a)(1) and (b)(1) of this section,
where pipe of a diameter included in a listed specification is
impractical to use, pipe of a diameter between the sizes included in a
listed specification may be used if it:
(1) Meets the strength and design criteria required of pipe included
in that listed specification; and
(2) Is manufactured from plastic compounds which meet the criteria
for material required of pipe included in that listed specification.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-19, 40 FR 10472,
Mar. 6, 1975; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988]
Sec. 192.61 [Reserved]
Sec. 192.63 Marking of materials.
(a) Except as provided in paragraph (d) of this section, each valve,
fitting, length of pipe, and other component must be marked--
(1) As prescribed in the specification or standard to which it was
manufactured, except that thermoplastic fittings must be marked in
accordance with ASTM D 2513; or
(2) To indicate size, material, manufacturer, pressure rating, and
temperature rating, and as appropriate, type, grade, and model.
(b) Surfaces of pipe and components that are subject to stress from
internal pressure may not be field die stamped.
(c) If any item is marked by die stamping, the die must have blunt
or rounded edges that will minimize stress concentrations.
(d) Paragraph (a) of this section does not apply to items
manufactured before November 12, 1970, that meet all of the following:
(1) The item is identifiable as to type, manufacturer, and model.
(2) Specifications or standards giving pressure, temperature, and
other appropriate criteria for the use of items are readily available.
[Amdt. 192-1, 35 FR 17660, Nov. 17, 1970, as amended by Amdt. 192-31, 43
FR 883, Apr. 3, 1978; Amdt. 192-61, 53 FR 36793, Sept. 22, 1988; Amdt.
192-62, 54 FR 5627, Feb. 6, 1989; Amdt. 192-61A, 54 FR 32642, Aug. 9,
1989; 58 FR 14521, Mar. 18, 1993; Amdt. 192-76, 61 FR 26122, May 24,
1996; 61 FR 36826, July 15, 1996]
Sec. 192.65 Transportation of pipe.
In a pipeline to be operated at a hoop stress of 20 percent or more
of SMYS, an operator may not use pipe having an outer diameter to wall
thickness ratio of 70 to 1, or more, that is transported by railroad
unless:
(a) The transportation is performed in accordance with API RP 5L1.
(b) In the case of pipe transported before November 12, 1970, the
pipe is tested in accordance with subpart J of this part to at least
1.25 times the maximum allowable operating pressure if it is to be
installed in a class 1 location and to at least 1.5 times the maximum
allowable operating pressure if it is to be installed in a class 2, 3,
or 4 location. Notwithstanding any shorter time period permitted under
subpart J of this part, the test pressure must be maintained for at
least 8 hours.
[Amdt. 192-12, 38 FR 4761, Feb. 22, 1973, as amended by Amdt. 192-17, 40
FR 6346, Feb. 11, 1975; 58 FR 14521, Mar. 18, 1993]
Subpart C_Pipe Design
Sec. 192.101 Scope.
This subpart prescribes the minimum requirements for the design of
pipe.
Sec. 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.
Sec. 192.105 Design formula for steel pipe.
(a) The design pressure for steel pipe is determined in accordance
with the following formula:
P=(2 St/D)xFxExT
P=Design pressure in pounds per square inch (kPa) gauge.
S=Yield strength in pounds per square inch (kPa) determined in
accordance with Sec. 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 Sec. 192.109. Additional
wall thickness required for concurrent external loads in accordance with
Sec. 192.103 may not be included in computing design pressure.
[[Page 48]]
F=Design factor determined in accordance with Sec. 192.111.
E=Longitudinal joint factor determined in accordance with Sec. 192.113.
T=Temperature derating factor determined in accordance with Sec.
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 [deg]F (482 [deg]C) at any
time or is held above 600 [deg]F (316 [deg]C) for more than 1 hour.
[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]
Sec. 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 Sec. 192.105 is the SMYS stated in the
listed specification, if that value is known.
(b) For pipe that is manufactured in accordance with a specification
not listed in section I of appendix B to this part or whose
specification or tensile properties are unknown, the yield strength to
be used in the design formula in Sec. 192.105 is one of the following:
(1) If the pipe is tensile tested in accordance with section II-D of
appendix B to this part, the lower of the following:
(i) 80 percent of the average yield strength determined by the
tensile tests.
(ii) The lowest yield strength determined by the tensile tests.
(2) If the pipe is not tensile tested as provided in paragraph
(b)(1) of this section, 24,000 p.s.i. (165 MPa).
[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]
Sec. 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.
(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 Sec. 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.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502,
July 13, 1998]
Sec. 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
Sec. 192.105 is determined in accordance with the following table:
------------------------------------------------------------------------
Design
Class location factor (F)
------------------------------------------------------------------------
1........................................................... 0.72
2........................................................... 0.60
3........................................................... 0.50
4........................................................... 0.40
------------------------------------------------------------------------
(b) A design factor of 0.60 or less must be used in the design
formula in Sec. 192.105 for steel pipe in Class 1 locations that:
(1) Crosses the right-of-way of an unimproved public road, without a
casing;
(2) Crosses without a casing, or makes a parallel encroachment on,
the right-of-way of either a hard surfaced road, a highway, a public
street, or a railroad;
(3) Is supported by a vehicular, pedestrian, railroad, or pipeline
bridge; or
(4) Is used in a fabricated assembly, (including separators,
mainline valve assemblies, cross-connections, and
[[Page 49]]
river crossing headers) or is used within five pipe diameters in any
direction from the last fitting of a fabricated assembly, other than a
transition piece or an elbow used in place of a pipe bend which is not
associated with a fabricated assembly.
(c) For Class 2 locations, a design factor of 0.50, or less, must be
used in the design formula in Sec. 192.105 for uncased steel pipe that
crosses the right-of-way of a hard surfaced road, a highway, a public
street, or a railroad.
(d) For Class 1 and Class 2 locations, a design factor of 0.50, or
less, must be used in the design formula in Sec. 192.105 for--
(1) Steel pipe in a compressor station, regulating station, or
measuring station; and
(2) Steel pipe, including a pipe riser, on a platform located
offshore or in inland navigable waters.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605,
Aug. 16, 1976]
Sec. 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 Sec. 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
To address this design issue: additional requirements:
------------------------------------------------------------------------
(a) General standards for the (1) The plate, skelp, or coil used
steel pipe. 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 Specification 5L, product
specification level 2 (incorporated
by reference, see Sec. 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 Specification 5L
(incorporated by reference, see
Sec. 192.7); or
(ii) American Society of Mechanical
Engineers (ASME) B31.8
(incorporated by reference, see
Sec. 192.7); and
(iii) Any correction factors needed
to address pipe grades, pressures,
temperatures, or gas compositions
not expressly addressed in API
Specification 5L, product
specification level 2 or ASME B31.8
(incorporated by reference, see
Sec. 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 Sec. 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.
[[Page 50]]
(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 [the effective date
of the final rule], the test must
be done in accordance with ASTM
A578/A578M Level B, or API 5L
Paragraph 7.8.10 (incorporated by
reference, see Sec. 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 Specification 5L
(incorporated by reference, see
Sec. 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).
(3) All of the seams must be
ultrasonically tested after cold
expansion and mill hydrostatic
testing.
(e) Mill hydrostatic test......... (1) All pipe to be used in a new
pipeline segment must be
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 API Specification 5L,
Appendix K (incorporated by
reference, see Sec. 192.7).
(2) Pipe in operation prior to
November 17, 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.
(f) Coating....................... (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.
(g) Fittings and flanges.......... (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.
(h) Compressor stations........... (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.
[[Page 51]]
(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.
------------------------------------------------------------------------
[73 FR 62175, Oct. 17, 2008]
Sec. 192.113 Longitudinal joint factor (E) for steel pipe.
The longitudinal joint factor to be used in the design formula in
Sec. 192.105 is determined in accordance with the following table:
------------------------------------------------------------------------
Longitudinal
Specification Pipe class joint factor (E)
------------------------------------------------------------------------
ASTM A 53/A53M................. Seamless............ 1.00
Electric resistance 1.00
welded.
Furnace butt welded. .60
ASTM A 106..................... Seamless............ 1.00
ASTM A 333/A 333M.............. Seamless............ 1.00
Electric resistance 1.00
welded.
ASTM A 381..................... Double submerged arc 1.00
welded.
ASTM A 671..................... Electric-fusion- 1.00
welded.
ASTM A 672..................... Electric-fusion- 1.00
welded.
ASTM A 691..................... Electric-fusion- 1.00
welded.
API 5 L........................ Seamless............ 1.00
Electric resistance 1.00
welded.
Electric flash 1.00
welded.
Submerged arc welded 1.00
Furnace butt welded. .60
Other.......................... Pipe over 4 inches .80
(102 millimeters).
Other.......................... Pipe 4 inches (102 .60
millimeters) or
less.
------------------------------------------------------------------------
If the type of longitudinal joint cannot be determined, the joint factor
to be used must not exceed that designated for ``Other.''
[Amdt. 192-37, 46 FR 10159, Feb. 2, 1981, as amended by Amdt. 192-51, 51
FR 15335, Apr. 23, 1986; Amdt. 192-62, 54 FR 5627, Feb. 6, 1989; 58 FR
14521, Mar. 18, 1993; Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt.
192-94, 69 FR 32894, June 14, 2004]
Sec. 192.115 Temperature derating factor (T) for steel pipe.
The temperature derating factor to be used in the design formula in
Sec. 192.105 is determined as follows:
------------------------------------------------------------------------
Temperature
Gas temperature in degrees Fahrenheit (Celsius) derating
factor (T)
------------------------------------------------------------------------
250 [deg]F (121 [deg]C) or less............................ 1.000
300 [deg]F (149 [deg]C).................................... 0.967
350 [deg]F (177 [deg]C).................................... 0.933
400 [deg]F (204 [deg]C).................................... 0.900
450 [deg]F (232 [deg]C).................................... 0.867
------------------------------------------------------------------------
For intermediate gas temperatures, the derating factor is determined by
interpolation.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502,
July 13, 1998]
Sec. 192.117 [Reserved]
Sec. 192.119 [Reserved]
Sec. 192.121 Design of plastic pipe.
Subject to the limitations of Sec. 192.123, the design pressure for
plastic pipe is
[[Page 52]]
determined by either of the following formulas:
[GRAPHIC] [TIFF OMITTED] TR24DE08.014
Where:
P = Design pressure, gauge, psig (kPa).
S = For thermoplastic pipe, the HDB is determined in accordance with the
listed specification at a temperature equal to 73F[deg] (23C[deg]), 100
[deg]F (38 [deg]C), 120 [deg]F (49 [deg]C), or 140 [deg]F (60 [deg]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-3/2004, HDB/PDB/SDB/MRS Policies
(incorporated by reference, see Sec. 192.7). For reinforced
thermosetting plastic pipe, 11,000 psig (75,842 kPa). [Note: Arithmetic
interpolation is not allowed for PA-11 pipe.]
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 preferred number series 10.
D F = 0.32 or
= 0.40 for nominal pipe size (IPS or CTS) 4-inch or less, SDR-11 or
greater (i.e. thicker pipe wall), PA-11 pipe produced after January 23,
2009.
[73 FR 79005, Dec. 24, 2008]
Sec. 192.123 Design limitations for plastic pipe.
(a) Except as provided in paragraph (e) and paragraph (f) of this
section, the design pressure may not exceed a gauge pressure of 100 psig
(689 kPa) for plastic pipe used in:
(1) Distribution systems; or
(2) Classes 3 and 4 locations.
(b) Plastic pipe may not be used where operating temperatures of the
pipe will be:
(1) Below -20[deg]F (-20[deg]C), or -40[deg]F (-40[deg]C) if all
pipe and pipeline components whose operating temperature will be below -
29[deg]C (-20[deg]F) have a temperature rating by the manufacturer
consistent with that operating temperature; or
(2) Above the following applicable temperatures:
(i) For thermoplastic pipe, the temperature at which the HDB used in
the design formula under Sec. 192.121 is determined.
(ii) For reinforced thermosetting plastic pipe, 150[deg]F
(66[deg]C).
(c) The wall thickness for thermoplastic pipe may not be less than
0.062 inches (1.57 millimeters).
(d) The wall thickness for reinforced thermosetting plastic pipe may
not be less than that listed in the following table:
------------------------------------------------------------------------
Minimum wall
thickness
Nominal size in inches (millimeters). inches
(millimeters).
------------------------------------------------------------------------
2 (51).................................................. 0.060 (1.52)
3 (76).................................................. 0.060 (1.52)
4 (102)................................................. 0.070 (1.78)
6 (152)................................................. 0.100 (2.54)
------------------------------------------------------------------------
(e) The design pressure for thermoplastic pipe produced after July
14, 2004 may exceed a gauge pressure of 100 psig (689 kPa) provided
that:
(1) The design pressure does not exceed 125 psig (862 kPa);
(2) The material is a PE2406 or a PE3408 as specified within ASTM
D2513 (incorporated by reference, see Sec. 192.7);
(3) The pipe size is nominal pipe size (IPS) 12 or less; and
(4) The design pressure is determined in accordance with the design
equation defined in Sec. 192.121.
(f) The design pressure for polyamide-11 (PA-11) pipe produced after
January 23, 2009 may exceed a gauge pressure of 100 psig (689 kPa)
provided that:
(1) The design pressure does not exceed 200 psig (1379 kPa);
(2) The pipe size is nominal pipe size (IPS or CTS) 4-inch or less;
and
(3) The pipe has a standard dimension ratio of SDR-11 or greater
(i.e., thicker pipe wall).
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-31, 43 FR 13883,
Apr. 3, 1978; Amdt. 192-78, 61 FR 28783, June 6, 1996; Amdt. 192-85, 63
FR 37502, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003; 69
FR 32894, June 14, 2004; Amdt. 192-94, 69 FR 54592, Sept. 9, 2004; Amdt.
192-103, 71 FR 33407, June 9, 2006; 73 FR 79005, Dec. 24, 2008]
[[Page 53]]
Sec. 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.
(b) Copper pipe used in service lines must have wall thickness not
less than that indicated in the following table:
------------------------------------------------------------------------
Wall thickness inch (millimeter)
Standard size inch Nominal O.D. inch ---------------------------------
(millimeter) (millimeter) Nominal Tolerance
------------------------------------------------------------------------
\1/2\ (13) .625 (16) .040 (1.06) .0035 (.0889)
\5/8\ (16) .750 (19) .042 (1.07) .0035 (.0889)
\3/4\ (19) .875 (22) .045 (1.14) .004 (.102)
1 (25) 1.125 (29) .050 (1.27) .004 (.102)
1\1/4\ (32) 1.375 (35) .055 (1.40) .0045 (.1143)
1\1/2\ (38) 1.625 (41) .060 (1.52) .0045 (.1143)
------------------------------------------------------------------------
(c) Copper pipe used in mains and service lines may not be used at
pressures in excess of 100 p.s.i. (689 kPa) gage.
(d) Copper pipe that does not have an internal corrosion resistant
lining may not be used to carry gas that has an average hydrogen sulfide
content of more than 0.3 grains/100 ft\3\ (6.9/m\3\) under standard
conditions. Standard conditions refers to 60[deg]F and 14.7 psia
(15.6[deg]C and one atmosphere) of gas.
[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]
Subpart D_Design of Pipeline Components
Sec. 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.
Sec. 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.
(b) The design and installation of pipeline components and
facilities must meet applicable requirements for corrosion control found
in subpart I of this part.
[Amdt. 48, 49 FR 19824, May 10, 1984 as amended at 72 FR 20059, Apr. 23,
2007]
Sec. 192.144 Qualifying metallic components.
Notwithstanding any requirement of this subpart which incorporates
by reference an edition of a document listed in Sec. 192.7 or Appendix
B of this part, a metallic component manufactured in accordance with any
other edition of that document is qualified for use under this part if--
(a) It can be shown through visual inspection of the cleaned
component that no defect exists which might impair the strength or
tightness of the component; and
(b) The edition of the document under which the component was
manufactured has equal or more stringent requirements for the following
as an edition of that document currently or previously listed in Sec.
192.7 or appendix B of this part:
(1) Pressure testing;
(2) Materials; and
(3) Pressure and temperature ratings.
[Amdt. 192-45, 48 FR 30639, July 5, 1983, as amended by Amdt. 192-94, 69
FR 32894, June 14, 2004]
Sec. 192.145 Valves.
(a) Except for cast iron and plastic valves, each valve must meet
the minimum requirements of API 6D (incorporated by reference, see Sec.
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.
(b) Each cast iron and plastic valve must comply with the following:
(1) The valve must have a maximum service pressure rating for
temperatures that equal or exceed the maximum service temperature.
(2) The valve must be tested as part of the manufacturing, as
follows:
[[Page 54]]
(i) With the valve in the fully open position, the shell must be
tested with no leakage to a pressure at least 1.5 times the maximum
service rating.
(ii) After the shell test, the seat must be tested to a pressure not
less than 1.5 times the maximum service pressure rating. Except for
swing check valves, test pressure during the seat test must be applied
successively on each side of the closed valve with the opposite side
open. No visible leakage is permitted.
(iii) After the last pressure test is completed, the valve must be
operated through its full travel to demonstrate freedom from
interference.
(c) Each valve must be able to meet the anticipated operating
conditions.
(d) No valve having shell components made of ductile iron may be
used at pressures exceeding 80 percent of the pressure ratings for
comparable steel valves at their listed temperature. However, a valve
having shell components made of ductile iron may be used at pressures up
to 80 percent of the pressure ratings for comparable steel valves at
their listed temperature, if:
(1) The temperature-adjusted service pressure does not exceed 1,000
p.s.i. (7 Mpa) gage; and
(2) Welding is not used on any ductile iron component in the
fabrication of the valve shells or their assembly.
(e) No valve having pressure containing parts made of ductile iron
may be used in the gas pipe components of compressor stations.
[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; Amdt. 192-94, 69
FR 32894, June 14, 2004]
Sec. 192.147 Flanges and flange accessories.
(a) Each flange or flange accessory (other than cast iron) must meet
the minimum requirements of ASME/ANSI B16.5, MSS SP-44, or the
equivalent.
(b) Each flange assembly must be able to withstand the maximum
pressure at which the pipeline is to be operated and to maintain its
physical and chemical properties at any temperature to which it is
anticipated that it might be subjected in service.
(c) Each flange on a flanged joint in cast iron pipe must conform in
dimensions, drilling, face and gasket design to ASME/ANSI B16.1 and be
cast integrally with the pipe, valve, or fitting.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628,
Feb. 6, 1989; 58 FR 14521, Mar. 18, 1993]
Sec. 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.
(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.
Sec. 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.
(b) This section does not apply to: (1) Manifolds;
(2) Station piping such as at compressor stations, meter stations,
or regulator stations;
(3) Piping associated with storage facilities, other than a
continuous run of transmission line between a compressor station and
storage facilities;
(4) Cross-overs;
(5) Sizes of pipe for which an instrumented internal inspection
device is not commercially available;
(6) Transmission lines, operated in conjunction with a distribution
system which are installed in Class 4 locations;
(7) Offshore transmission lines, except transmission lines 10\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--
[[Page 55]]
(i) Platform space or configuration is incompatible with launching
or retrieving instrumented internal inspection devices; or
(ii) If the design includes taps for lateral connections, the
operator can demonstrate, based on investigation or experience, that
there is no reasonably practical alternative under the design
circumstances to the use of a tap that will obstruct the passage of
instrumented internal inspection devices; and
(8) Other piping that, under Sec. 190.9 of this chapter, the
Administrator finds in a particular case would be impracticable to
design and construct to accommodate the passage of instrumented internal
inspection devices.
(c) An operator encountering emergencies, construction time
constraints or other unforeseen construction problems need not construct
a new or replacement segment of a transmission line to meet paragraph
(a) of this section, if the operator determines and documents why an
impracticability prohibits compliance with paragraph (a) of this
section. Within 30 days after discovering the emergency or construction
problem the operator must petition, under Sec. 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.
[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]
Sec. 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.
(b) Where a ductile iron pipe is tapped, the extent of full-thread
engagement and the need for the use of outside-sealing service
connections, tapping saddles, or other fixtures must be determined by
service conditions.
(c) Where a threaded tap is made in cast iron or ductile iron pipe,
the diameter of the tapped hole may not be more than 25 percent of the
nominal diameter of the pipe unless the pipe is reinforced, except that
(1) Existing taps may be used for replacement service, if they are
free of cracks and have good threads; and
(2) A 1\1/4\-inch (32 millimeters) tap may be made in a 4-inch (102
millimeters) cast iron or ductile iron pipe, without reinforcement.
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]
Sec. 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 UG-101 of
section VIII, Division 1, of the ASME Boiler and Pressure Vessel Code.
(b) Each prefabricated unit that uses plate and longitudinal seams
must be designed, constructed, and tested in accordance with section I,
section VIII, Division 1, or section VIII, Division 2 of the ASME Boiler
and Pressure Vessel Code, except for the following:
(1) Regularly manufactured butt-welding fittings.
(2) Pipe that has been produced and tested under a specification
listed in appendix B to this part.
(3) Partial assemblies such as split rings or collars.
(4) Prefabricated units that the manufacturer certifies have been
tested to at least twice the maximum pressure to which they will be
subjected under the anticipated operating conditions.
(c) Orange-peel bull plugs and orange-peel swages may not be used on
pipelines that are to operate at a hoop stress of 20 percent or more of
the SMYS of the pipe.
(d) Except for flat closures designed in accordance with section
VIII of the ASME Boiler and Pressure Code, flat
[[Page 56]]
closures and fish tails may not be used on pipe that either operates at
100 p.s.i. (689 kPa) gage, or more, or is more than 3 inches (76
millimeters) nominal diameter.
[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]
Sec. 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.
Sec. 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.
Sec. 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.
Sec. 192.161 Supports and anchors.
(a) Each pipeline and its associated equipment must have enough
anchors or supports to:
(1) Prevent undue strain on connected equipment;
(2) Resist longitudinal forces caused by a bend or offset in the
pipe; and
(3) Prevent or damp out excessive vibration.
(b) Each exposed pipeline must have enough supports or anchors to
protect the exposed pipe joints from the maximum end force caused by
internal pressure and any additional forces caused by temperature
expansion or contraction or by the weight of the pipe and its contents.
(c) Each support or anchor on an exposed pipeline must be made of
durable, noncombustible material and must be designed and installed as
follows:
(1) Free expansion and contraction of the pipeline between supports
or anchors may not be restricted.
(2) Provision must be made for the service conditions involved.
(3) Movement of the pipeline may not cause disengagement of the
support equipment.
(d) Each support on an exposed pipeline operated at a stress level
of 50 percent or more of SMYS must comply with the following:
(1) A structural support may not be welded directly to the pipe.
(2) The support must be provided by a member that completely
encircles the pipe.
(3) If an encircling member is welded to a pipe, the weld must be
continuous and cover the entire circumference.
(e) Each underground pipeline that is connected to a relatively
unyielding line or other fixed object must have enough flexibility to
provide for possible movement, or it must have an anchor that will limit
the movement of the pipeline.
(f) Except for offshore pipelines, each underground pipeline that is
being connected to new branches must have a firm foundation for both the
header and the branch to prevent detrimental lateral and vertical
movement.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635,
Jan. 21, 1988]
Sec. 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
[[Page 57]]
space around the main compressor building to allow the free movement of
fire-fighting equipment.
(b) Building construction. Each building on a compressor station
site must be made of noncombustible materials if it contains either--
(1) Pipe more than 2 inches (51 millimeters) in diameter that is
carrying gas under pressure; or
(2) Gas handling equipment other than gas utilization equipment used
for domestic purposes.
(c) 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.
(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.
(e) Electrical facilities. Electrical equipment and wiring installed
in compressor stations must conform to the National Electrical Code,
ANSI/NFPA 70, so far as that code is applicable.
[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]
Sec. 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.
(b) Each liquid separator used to remove entrained liquids at a
compressor station must:
(1) Have a manually operable means of removing these liquids.
(2) Where slugs of liquid could be carried into the compressors,
have either automatic liquid removal facilities, an automatic compressor
shutdown device, or a high liquid level alarm; and
(3) Be manufactured in accordance with section VIII of the ASME
Boiler and Pressure Vessel Code, except that liquid separators
constructed of pipe and fittings without internal welding must be
fabricated with a design factor of 0.4, or less.
Sec. 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:
(1) It must be able to block gas out of the station and blow down
the station piping.
(2) It must discharge gas from the blowdown piping at a location
where the gas will not create a hazard.
(3) It must provide means for the shutdown of gas compressing
equipment, gas fires, and electrical facilities in the vicinity of gas
headers and in the compressor building, except that:
(i) Electrical circuits that supply emergency lighting required to
assist station personnel in evacuating the compressor building and the
area in the vicinity of the gas headers must remain energized; and
(ii) Electrical circuits needed to protect equipment from damage may
remain energized.
(4) It must be operable from at least two locations, each of which
is:
(i) Outside the gas area of the station;
(ii) Near the exit gates, if the station is fenced, or near
emergency exits, if not fenced; and
(iii) Not more than 500 feet (153 meters) from the limits of the
station.
(b) If a compressor station supplies gas directly to a distribution
system with no other adequate source of gas available, the emergency
shutdown system must be designed so that it will not function at the
wrong time and cause an unintended outage on the distribution system.
[[Page 58]]
(c) On a platform located offshore or in inland navigable waters,
the emergency shutdown system must be designed and installed to actuate
automatically by each of the following events:
(1) In the case of an unattended compressor station:
(i) When the gas pressure equals the maximum allowable operating
pressure plus 15 percent; or
(ii) When an uncontrolled fire occurs on the platform; and
(2) In the case of a compressor station in a building:
(i) When an uncontrolled fire occurs in the building; or
(ii) When the concentration of gas in air reaches 50 percent or more
of the lower explosive limit in a building which has a source of
ignition.
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]
Sec. 192.169 Compressor stations: Pressure limiting devices.
(a) Each compressor station must have pressure relief or other
suitable protective devices of sufficient capacity and sensitivity to
ensure that the maximum allowable operating pressure of the station
piping and equipment is not exceeded by more than 10 percent.
(b) Each vent line that exhausts gas from the pressure relief valves
of a compressor station must extend to a location where the gas may be
discharged without hazard.
Sec. 192.171 Compressor stations: Additional safety equipment.
(a) Each compressor station must have adequate fire protection
facilities. If fire pumps are a part of these facilities, their
operation may not be affected by the emergency shutdown system.
(b) Each compressor station prime mover, other than an electrical
induction or synchronous motor, must have an automatic device to shut
down the unit before the speed of either the prime mover or the driven
unit exceeds a maximum safe speed.
(c) Each compressor unit in a compressor station must have a
shutdown or alarm device that operates in the event of inadequate
cooling or lubrication of the unit.
(d) Each compressor station gas engine that operates with pressure
gas injection must be equipped so that stoppage of the engine
automatically shuts off the fuel and vents the engine distribution
manifold.
(e) Each muffler for a gas engine in a compressor station must have
vent slots or holes in the baffles of each compartment to prevent gas
from being trapped in the muffler.
Sec. 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.
Sec. 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.
(b) Each pipe-type or bottle-type holder must have minimum clearance
from other holders in accordance with the following formula:
C=(DxPxF)/48.33) (C=(3DxPxF/1,000))
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, p.s.i. (kPa) gage.
F=Design factor as set forth in Sec. 192.111 of this part.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503,
July 13, 1998]
Sec. 192.177 Additional provisions for bottle-type holders.
(a) Each bottle-type holder must be--
(1) Located on a site entirely surrounded by fencing that prevents
access by unauthorized persons and with
[[Page 59]]
minimum clearance from the fence as follows:
------------------------------------------------------------------------
Minimum
Maximum allowable operating pressure clearance feet
(meters)
------------------------------------------------------------------------
Less than 1,000 p.s.i. (7 MPa) gage.................... 25 (7.6)
1,000 p.s.i. (7 MPa) gage or more...................... 100 (31)
------------------------------------------------------------------------
(2) Designed using the design factors set forth in Sec. 192.111;
and
(3) Buried with a minimum cover in accordance with Sec. 192.327.
(b) Each bottle-type holder manufactured from steel that is not
weldable under field conditions must comply with the following:
(1) A bottle-type holder made from alloy steel must meet the
chemical and tensile requirements for the various grades of steel in
ASTM A 372/A 372M.
(2) The actual yield-tensile ratio of the steel may not exceed 0.85.
(3) Welding may not be performed on the holder after it has been
heat treated or stress relieved, except that copper wires may be
attached to the small diameter portion of the bottle end closure for
cathodic protection if a localized thermit welding process is used.
(4) The holder must be given a mill hydrostatic test at a pressure
that produces a hoop stress at least equal to 85 percent of the SMYS.
(5) The holder, connection pipe, and components must be leak tested
after installation as required by subpart J of this part.
[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]
Sec. 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:
(1) Each point on the pipeline in a Class 4 location must be within
2\1/2\ miles (4 kilometers)of a valve.
(2) Each point on the pipeline in a Class 3 location must be within
4 miles (6.4 kilometers) of a valve.
(3) Each point on the pipeline in a Class 2 location must be within
7\1/2\ miles (12 kilometers) of a valve.
(4) Each point on the pipeline in a Class 1 location must be within
10 miles (16 kilometers) of a valve.
(b) Each sectionalizing block valve on a transmission line, other
than offshore segments, must comply with the following:
(1) The valve and the operating device to open or close the valve
must be readily accessible and protected from tampering and damage.
(2) The valve must be supported to prevent settling of the valve or
movement of the pipe to which it is attached.
(c) Each section of a transmission line, other than offshore
segments, between main line valves must have a blowdown valve with
enough capacity to allow the transmission line to be blown down as
rapidly as practicable. Each blowdown discharge must be located so the
gas can be blown to the atmosphere without hazard and, if the
transmission line is adjacent to an overhead electric line, so that the
gas is directed away from the electrical conductors.
(d) Offshore segments of transmission lines must be equipped with
valves or other components to shut off the flow of gas to an offshore
platform in an emergency.
[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]
Sec. 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.
(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.
[[Page 60]]
(c) Each valve on a main installed for operating or emergency
purposes must comply with the following:
(1) The valve must be placed in a readily accessible location so as
to facilitate its operation in an emergency.
(2) The operating stem or mechanism must be readily accessible.
(3) If the valve is installed in a buried box or enclosure, the box
or enclosure must be installed so as to avoid transmitting external
loads to the main.
Sec. 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.
(b) There must be enough working space so that all of the equipment
required in the vault or pit can be properly installed, operated, and
maintained.
(c) Each pipe entering, or within, a regulator vault or pit must be
steel for sizes 10 inch (254 millimeters), and less, except that control
and gage piping may be copper. Where pipe extends through the vault or
pit structure, provision must be made to prevent the passage of gases or
liquids through the opening and to avert strains in the pipe.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503,
July 13, 1998]
Sec. 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;
(b) Points of minimum elevation, catch basins, or places where the
access cover will be in the course of surface waters; and
(c) Water, electric, steam, or other facilities.
Sec. 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):
(1) The vault or pit must be ventilated with two ducts, each having
at least the ventilating effect of a pipe 4 inches (102 millimeters) in
diameter;
(2) The ventilation must be enough to minimize the formation of
combustible atmosphere in the vault or pit; and
(3) The ducts must be high enough above grade to disperse any gas-
air mixtures that might be discharged.
(b) When the internal volume is more than 75 cubic feet (2.1 cubic
meters) but less than 200 cubic feet (5.7 cubic meters):
(1) If the vault or pit is sealed, each opening must have a tight
fitting cover without open holes through which an explosive mixture
might be ignited, and there must be a means for testing the internal
atmosphere before removing the cover;
(2) If the vault or pit is vented, there must be a means of
preventing external sources of ignition from reaching the vault
atmosphere; or
(3) If the vault or pit is ventilated, paragraph (a) or (c) of this
section applies.
(c) If a vault or pit covered by paragraph (b) of this section is
ventilated by openings in the covers or gratings and the ratio of the
internal volume, in cubic feet, to the effective ventilating area of the
cover or grating, in square feet, is less than 20 to 1, no additional
ventilation is required.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503,
July 13, 1998]
Sec. 192.189 Vaults: Drainage and waterproofing.
(a) Each vault must be designed so as to minimize the entrance of
water.
(b) A vault containing gas piping may not be connected by means of a
drain connection to any other underground structure.
(c) Electrical equipment in vaults must conform to the applicable
requirements of Class 1, Group D, of the National Electrical Code, ANSI/
NFPA 70.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-76, 61 FR 26122,
May 24, 1996]
[[Page 61]]
Sec. 192.191 Design pressure of plastic fittings.
(a) Thermosetting fittings for plastic pipe must conform to ASTM D
2517.
(b) Thermoplastic fittings for plastic pipe must conform to ASTM D
2513.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635,
Jan. 21, 1988]
Sec. 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.
Sec. 192.195 Protection against accidental overpressuring.
(a) General requirements. Except as provided in Sec. 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 Sec. Sec.
192.199 and 192.201.
(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--
(1) Have pressure regulation devices capable of meeting the
pressure, load, and other service conditions that will be experienced in
normal operation of the system, and that could be activated in the event
of failure of some portion of the system; and
(2) Be designed so as to prevent accidental overpressuring.
Sec. 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:
(1) A regulator capable of reducing distribution line pressure to
pressures recommended for household appliances.
(2) A single port valve with proper orifice for the maximum gas
pressure at the regulator inlet.
(3) A valve seat made of resilient material designed to withstand
abrasion of the gas, impurities in gas, cutting by the valve, and to
resist permanent deformation when it is pressed against the valve port.
(4) Pipe connections to the regulator not exceeding 2 inches (51
millimeters) in diameter.
(5) A regulator that, under normal operating conditions, is able to
regulate the downstream pressure within the necessary limits of accuracy
and to limit the build-up of pressure under no-flow conditions to
prevent a pressure that would cause the unsafe operation of any
connected and properly adjusted gas utilization equipment.
(6) A self-contained service regulator with no external static or
control lines.
(b) If the maximum actual operating pressure of the distribution
system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator
that does not have all of the characteristics listed in paragraph (a) of
this section is used, or if the gas contains materials that seriously
interfere with the operation of service regulators, there must be
suitable protective devices to prevent unsafe overpressuring of the
customer's appliances if the service regulator fails.
(c) If the maximum actual operating pressure of the distribution
system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods
must be used to regulate and limit, to the maximum safe value, the
pressure of gas delivered to the customer:
(1) A service regulator having the characteristics listed in
paragraph (a) of this section, and another regulator located upstream
from the service regulator. The upstream regulator may not be set to
maintain a pressure higher than 60 p.s.i. (414 kPa) gage. A device must
be installed between the upstream regulator and the service regulator to
limit the pressure on the inlet of the service regulator to 60 p.s.i.
(414 kPa) gage or less in case the upstream regulator fails to function
properly.
[[Page 62]]
This device may be either a relief valve or an automatic shutoff that
shuts, if the pressure on the inlet of the service regulator exceeds the
set pressure (60 p.s.i. (414 kPa) gage or less), and remains closed
until manually reset.
(2) A service regulator and a monitoring regulator set to limit, to
a maximum safe value, the pressure of the gas delivered to the customer.
(3) A service regulator with a relief valve vented to the outside
atmosphere, with the relief valve set to open so that the pressure of
gas going to the customer does not exceed a maximum safe value. The
relief valve may either be built into the service regulator or it may be
a separate unit installed downstream from the service regulator. This
combination may be used alone only in those cases where the inlet
pressure on the service regulator does not exceed the manufacturer's
safe working pressure rating of the service regulator, and may not be
used where the inlet pressure on the service regulator exceeds 125
p.s.i. (862 kPa) gage. For higher inlet pressures, the methods in
paragraph (c) (1) or (2) of this section must be used.
(4) A service regulator and an automatic shutoff device that closes
upon a rise in pressure downstream from the regulator and remains closed
until manually reset.
[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]
Sec. 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;
(b) Have valves and valve seats that are designed not to stick in a
position that will make the device inoperative;
(c) Be designed and installed so that it can be readily operated to
determine if the valve is free, can be tested to determine the pressure
at which it will operate, and can be tested for leakage when in the
closed position;
(d) Have support made of noncombustible material;
(e) Have discharge stacks, vents, or outlet ports designed to
prevent accumulation of water, ice, or snow, located where gas can be
discharged into the atmosphere without undue hazard;
(f) Be designed and installed so that the size of the openings,
pipe, and fittings located between the system to be protected and the
pressure relieving device, and the size of the vent line, are adequate
to prevent hammering of the valve and to prevent impairment of relief
capacity;
(g) Where installed at a district regulator station to protect a
pipeline system from overpressuring, be designed and installed to
prevent any single incident such as an explosion in a vault or damage by
a vehicle from affecting the operation of both the overpressure
protective device and the district regulator; and
(h) Except for a valve that will isolate the system under protection
from its source of pressure, be designed to prevent unauthorized
operation of any stop valve that will make the pressure relief valve or
pressure limiting device inoperative.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660,
Nov. 17, 1970]
Sec. 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:
(1) In a low pressure distribution system, the pressure may not
cause the unsafe operation of any connected and properly adjusted gas
utilization equipment.
(2) In pipelines other than a low pressure distribution system:
(i) If the maximum allowable operating pressure is 60 p.s.i. (414
kPa) gage or more, the pressure may not exceed the maximum allowable
operating pressure plus 10 percent, or the pressure that produces a hoop
stress of 75 percent of SMYS, whichever is lower;
(ii) If the maximum allowable operating pressure is 12 p.s.i. (83
kPa) gage or more, but less than 60 p.s.i. (414 kPa) gage, the pressure
may not exceed the
[[Page 63]]
maximum allowable operating pressure plus 6 p.s.i. (41 kPa) gage; or
(iii) If the maximum allowable operating pressure is less than 12
p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable
operating pressure plus 50 percent.
(b) When more than one pressure regulating or compressor station
feeds into a pipeline, relief valves or other protective devices must be
installed at each station to ensure that the complete failure of the
largest capacity regulator or compressor, or any single run of lesser
capacity regulators or compressors in that station, will not impose
pressures on any part of the pipeline or distribution system in excess
of those for which it was designed, or against which it was protected,
whichever is lower.
(c) Relief valves or other pressure limiting devices must be
installed at or near each regulator station in a low-pressure
distribution system, with a capacity to limit the maximum pressure in
the main to a pressure that will not exceed the safe operating pressure
for any connected and properly adjusted gas utilization equipment.
[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]
Sec. 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.
(b) Materials and design. All materials employed for pipe and
components must be designed to meet the particular conditions of service
and the following:
(1) Each takeoff connection and attaching boss, fitting, or adapter
must be made of suitable material, be able to withstand the maximum
service pressure and temperature of the pipe or equipment to which it is
attached, and be designed to satisfactorily withstand all stresses
without failure by fatigue.
(2) Except for takeoff lines that can be isolated from sources of
pressure by other valving, a shutoff valve must be installed in each
takeoff line as near as practicable to the point of takeoff. Blowdown
valves must be installed where necessary.
(3) Brass or copper material may not be used for metal temperatures
greater than 400[deg] F (204[deg]C).
(4) Pipe or components that may contain liquids must be protected by
heating or other means from damage due to freezing.
(5) Pipe or components in which liquids may accumulate must have
drains or drips.
(6) Pipe or components subject to clogging from solids or deposits
must have suitable connections for cleaning.
(7) The arrangement of pipe, components, and supports must provide
safety under anticipated operating stresses.
(8) Each joint between sections of pipe, and between pipe and valves
or fittings, must be made in a manner suitable for the anticipated
pressure and temperature condition. Slip type expansion joints may not
be used. Expansion must be allowed for by providing flexibility within
the system itself.
(9) Each control line must be protected from anticipated causes of
damage and must be designed and installed to prevent damage to any one
control line from making both the regulator and the over-pressure
protective device inoperative.
[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]
Subpart E_Welding of Steel in Pipelines
Sec. 192.221 Scope.
(a) This subpart prescribes minimum requirements for welding steel
materials in pipelines.
(b) This subpart does not apply to welding that occurs during the
manufacture of steel pipe or steel pipeline components.
Sec. 192.225 Welding procedures.
(a) Welding must be performed by a qualified welder in accordance
with welding procedures qualified under section 5 of API 1104
(incorporated by reference, see Sec. 192.7) or section IX of the
[[Page 64]]
ASME Boiler and Pressure Vessel Code `` Welding and Brazing
Qualifications'' (incorporated by reference, see Sec. 192.7) to produce
welds meeting the requirements of this subpart. The quality of the test
welds used to qualify welding procedures shall be determined by
destructive testing in accordance with the applicable welding
standard(s).
(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.
[Amdt. 192-52, 51 FR 20297, June 4, 1986; Amdt. 192-94, 69 FR 32894,
June 14, 2004]
Sec. 192.227 Qualification of welders.
(a) Except as provided in paragraph (b) of this section, each welder
must be qualified in accordance with section 6 of API 1104 (incorporated
by reference, see Sec. 192.7) or section IX of the ASME Boiler and
Pressure Vessel Code (incorporated by reference, see Sec. 192.7).
However, a welder qualified under an earlier edition than listed in
Sec. 192.7 of this part may weld but may not requalify under that
earlier edition.
(b) A welder may qualify to perform welding on pipe to be operated
at a pressure that produces a hoop stress of less than 20 percent of
SMYS by performing an acceptable test weld, for the process to be used,
under the test set forth in section I of Appendix C of this part. Each
welder who is to make a welded service line connection to a main must
first perform an acceptable test weld under section II of Appendix C of
this part as a requirement of the qualifying test.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851,
Oct. 21, 1982; Amdt. 192-52, 51 FR 20297, June 4, 1986; Amdt. 192-78, 61
FR 28784, June 6, 1996; Amdt. 192-94, 69 FR 32894, June 14, 2004; Amdt.
192-103, 72 FR 4656, Feb. 1, 2007]
Sec. 192.229 Limitations on welders.
(a) No welder whose qualification is based on nondestructive testing
may weld compressor station pipe and components.
(b) No welder may weld with a particular welding process unless,
within the preceding 6 calendar months, he has engaged in welding with
that process.
(c) A welder qualified under Sec. 192.227(a)--
(1) May not weld on pipe to be operated at a pressure that produces
a hoop stress of 20 percent or more of SMYS unless within the preceding
6 calendar months the welder has had one weld tested and found
acceptable under the sections 6 or 9 of API Standard 1104 (incorporated
by reference, see Sec. 192.7). Alternatively, welders may maintain an
ongoing qualification status by performing welds tested and found
acceptable under the above acceptance criteria at least twice each
calendar year, but at intervals not exceeding 7\1/2\ months. A welder
qualified under an earlier edition of a standard listed in Sec. 192.7
of this part may weld but may not requalify under that earlier edition;
and
(2) May not weld on pipe to be operated at a pressure that produces
a hoop stress of less than 20 percent of SMYS unless the welder is
tested in accordance with paragraph (c)(1) of this section or
requalifies under paragraph (d)(1) or (d)(2) of this section.
(d) A welder qualified under Sec. 192.227(b) may not weld unless--
(1) Within the preceding 15 calendar months, but at least once each
calendar year, the welder has requalified under Sec. 192.227(b); or
(2) Within the preceding 7\1/2\ calendar months, but at least twice
each calendar year, the welder has had--
(i) A production weld cut out, tested, and found acceptable in
accordance with the qualifying test; or
(ii) For welders who work only on service lines 2 inches (51
millimeters) or smaller in diameter, two sample welds tested and found
acceptable in accordance with the test in section III of Appendix C of
this part.
[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]
Sec. 192.231 Protection from weather.
The welding operation must be protected from weather conditions that
would impair the quality of the completed weld.
[[Page 65]]
Sec. 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[deg].
(b) A miter joint on steel pipe to be operated at a pressure that
produces a hoop stress of less than 30 percent, but more than 10
percent, of SMYS may not deflect the pipe more than 12\1/2\[deg] 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.
(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[deg].
Sec. 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.
Sec. 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:
(1) The welding is performed in accordance with the welding
procedure; and
(2) The weld is acceptable under paragraph (c) of this section.
(b) The welds on a pipeline to be operated at a pressure that
produces a hoop stress of 20 percent or more of SMYS must be
nondestructively tested in accordance with Sec. 192.243, except that
welds that are visually inspected and approved by a qualified welding
inspector need not be nondestructively tested if:
(1) The pipe has a nominal diameter of less than 6 inches (152
millimeters); or
(2) The pipeline is to be operated at a pressure that produces a
hoop stress of less than 40 percent of SMYS and the welds are so limited
in number that nondestructive testing is impractical.
(c) The acceptability of a weld that is nondestructively tested or
visually inspected is determined according to the standards in Section 9
of API Standard 1104 (incorporated by reference, see Sec. 192.7).
However, if a girth weld is unacceptable under those standards for a
reason other than a crack, and if Appendix A to API 1104 applies to the
weld, the acceptability of the weld may be further determined under that
appendix.
[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]
Sec. 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.
(b) Nondestructive testing of welds must be performed:
(1) In accordance with written procedures; and
(2) By persons who have been trained and qualified in the
established procedures and with the equipment employed in testing.
(c) Procedures must be established for the proper interpretation of
each nondestructive test of a weld to ensure the acceptability of the
weld under Sec. 192.241(c).
(d) When nondestructive testing is required under Sec. 192.241(b),
the following percentages of each day's field butt welds, selected at
random by the operator, must be nondestructively tested over their
entire circumference:
(1) In Class 1 locations, except offshore, at least 10 percent.
(2) In Class 2 locations, at least 15 percent.
(3) In Class 3 and Class 4 locations, at crossings of major or
navigable rivers, offshore, and within railroad or public highway
rights-of-way, including tunnels, bridges, and overhead road crossings,
100 percent unless impracticable, in which case at least 90 percent.
Nondestructive testing must be impracticable for each girth weld not
tested.
(4) At pipeline tie-ins, including tie-ins of replacement sections,
100 percent.
[[Page 66]]
(e) Except for a welder whose work is isolated from the principal
welding activity, a sample of each welder's work for each day must be
nondestructively tested, when nondestructive testing is required under
Sec. 192.241(b).
(f) When nondestructive testing is required under Sec. 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.
[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]
Sec. 192.245 Repair or removal of defects.
(a) Each weld that is unacceptable under Sec. 192.241(c) must be
removed or repaired. Except for welds on an offshore pipeline being
installed from a pipeline vessel, a weld must be removed if it has a
crack that is more than 8 percent of the weld length.
(b) Each weld that is repaired must have the defect removed down to
sound metal and the segment to be repaired must be preheated if
conditions exist which would adversely affect the quality of the weld
repair. After repair, the segment of the weld that was repaired must be
inspected to ensure its acceptability.
(c) Repair of a crack, or of any defect in a previously repaired
area must be in accordance with written weld repair procedures that have
been qualified under Sec. 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.
[Amdt. 192-46, 48 FR 48674, Oct. 20, 1983]
Subpart F_Joining of Materials Other Than by Welding
Sec. 192.271 Scope.
(a) This subpart prescribes minimum requirements for joining
materials in pipelines, other than by welding.
(b) This subpart does not apply to joining during the manufacture of
pipe or pipeline components.
Sec. 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.
(b) Each joint must be made in accordance with written procedures
that have been proven by test or experience to produce strong gastight
joints.
(c) Each joint must be inspected to insure compliance with this
subpart.
Sec. 192.275 Cast iron pipe.
(a) Each caulked bell and spigot joint in cast iron pipe must be
sealed with mechanical leak clamps.
(b) Each mechanical joint in cast iron pipe must have a gasket made
of a resilient material as the sealing medium. Each gasket must be
suitably confined and retained under compression by a separate gland or
follower ring.
(c) Cast iron pipe may not be joined by threaded joints.
(d) Cast iron pipe may not be joined by brazing.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628,
Feb. 6, 1989]
Sec. 192.277 Ductile iron pipe.
(a) Ductile iron pipe may not be joined by threaded joints.
(b) Ductile iron pipe may not be joined by brazing.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628,
Feb. 6, 1989]
Sec. 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]
Sec. 192.281 Plastic pipe.
(a) General. A plastic pipe joint that is joined by solvent cement,
adhesive,
[[Page 67]]
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.
(b) Solvent cement joints. Each solvent cement joint on plastic pipe
must comply with the following:
(1) The mating surfaces of the joint must be clean, dry, and free of
material which might be deterimental to the joint.
(2) The solvent cement must conform to ASTM Designation D 2513.
(3) The joint may not be heated to accelerate the setting of the
cement.
(c) Heat-fusion joints. Each heat-fusion joint on plastic pipe must
comply with the following:
(1) A butt heat-fusion joint must be joined by a device that holds
the heater element square to the ends of the piping, compresses the
heated ends together, and holds the pipe in proper alignment while the
plastic hardens.
(2) A socket heat-fusion joint must be joined by a device that heats
the mating surfaces of the joint uniformly and simultaneously to
essentially the same temperature.
(3) An electrofusion joint must be joined utilizing the equipment
and techniques of the fittings manufacturer or equipment and techniques
shown, by testing joints to the requirements of Sec.
192.283(a)(1)(iii), to be at least equivalent to those of the fittings
manufacturer.
(4) Heat may not be applied with a torch or other open flame.
(d) Adhesive joints. Each adhesive joint on plastic pipe must comply
with the following:
(1) The adhesive must conform to ASTM Designation D 2517.
(2) The materials and adhesive must be compatible with each other.
(e) Mechanical joints. Each compression type mechanical joint on
plastic pipe must comply with the following:
(1) The gasket material in the coupling must be compatible with the
plastic.
(2) A rigid internal tubular stiffener, other than a split tubular
stiffener, must be used in conjunction with the coupling.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-34, 44 FR 42973,
July 23, 1979; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-61, 53
FR 36793, Sept. 22, 1988; 58 FR 14521, Mar. 18, 1993; Amdt. 192-78, 61
FR 28784, June 6, 1996]
Sec. 192.283 Plastic pipe: Qualifying joining procedures.
(a) Heat fusion, solvent cement, and adhesive joints. Before any
written procedure established under Sec. 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
made according to the procedure to the following tests:
(1) The burst test requirements of--
(i) In the case of thermoplastic pipe, paragraph 6.6 (sustained
pressure test) or paragraph 6.7 (Minimum Hydrostatic Burst Test) or
paragraph 8.9 ( Sustained Static pressure Test) of ASTM D2513
(incorporated by reference, see Sec. 192.7);
(ii) In the case of thermosetting plastic pipe, paragraph 8.5
(Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static
Pressure Test) of ASTM D2517 (incorporated by reference, see Sec.
192.7); or
(iii) In the case of electrofusion fittings for polyethylene pipe
and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test),
paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength
Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM Designation
F1055 (incorporated by reference, see Sec. 192.7).
(2) For procedures intended for lateral pipe connections, subject a
specimen joint made from pipe sections joined at right angles according
to the procedure to a force on the lateral pipe until failure occurs in
the specimen. If failure initiates outside the joint area, the procedure
qualifies for use; and
(3) For procedures intended for non-lateral pipe connections, follow
the tensile test requirements of ASTM D638 (incorporated by reference,
see Sec. 192.7), except that the test may be conducted at ambient
temperature and humidity If the specimen elongates no less than 25
percent or failure initiates
[[Page 68]]
outside the joint area, the procedure qualifies for use.
(b) Mechanical joints. Before any written procedure established
under Sec. 192.273(b) is used for making mechanical plastic pipe joints
that are designed to withstand tensile forces, the procedure must be
qualified by subjecting 5 specimen joints made according to the
procedure to the following tensile test:
(1) Use an apparatus for the test as specified in ASTM D 638 (except
for conditioning), (incorporated by reference, see Sec. 192.7).
(2) The specimen must be of such length that the distance between
the grips of the apparatus and the end of the stiffener does not affect
the joint strength.
(3) The speed of testing is 0.20 in (5.0 mm) per minute, plus or
minus 25 percent.
(4) Pipe specimens less than 4 inches (102 mm) in diameter are
qualified if the pipe yields to an elongation of no less than 25 percent
or failure initiates outside the joint area.
(5) Pipe specimens 4 inches (102 mm) and larger in diameter shall be
pulled until the pipe is subjected to a tensile stress equal to or
greater than the maximum thermal stress that would be produced by a
temperature change of 100[deg]F (38[deg]C) or until the pipe is pulled
from the fitting. If the pipe pulls from the fitting, the lowest value
of the five test results or the manufacturer's rating, whichever is
lower must be used in the design calculations for stress.
(6) Each specimen that fails at the grips must be retested using new
pipe.
(7) Results obtained pertain only to the specific outside diameter,
and material of the pipe tested, except that testing of a heavier wall
pipe may be used to qualify pipe of the same material but with a lesser
wall thickness.
(c) A copy of each written procedure being used for joining plastic
pipe must be available to the persons making and inspecting joints.
(d) Pipe or fittings manufactured before July 1, 1980, may be used
in accordance with procedures that the manufacturer certifies will
produce a joint as strong as the pipe.
[Amdt. 192-34A, 45 FR 9935, Feb. 14, 1980, as amended by Amdt. 192-34B,
46 FR 39, Jan. 2, 1981; 47 FR 32720, July 29, 1982; 47 FR 49973, Nov. 4,
1982; 58 FR 14521, Mar. 18, 1993; 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. 192-94, 69 FR 54592, Sept. 9, 2004]
Sec. 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:
(1) Appropriate training or experience in the use of the procedure;
and
(2) Making a specimen joint from pipe sections joined according to
the procedure that passes the inspection and test set forth in paragraph
(b) of this section.
(b) The specimen joint must be:
(1) Visually examined during and after assembly or joining and found
to have the same appearance as a joint or photographs of a joint that is
acceptable under the procedure; and
(2) In the case of a heat fusion, solvent cement, or adhesive joint:
(i) Tested under any one of the test methods listed under Sec.
192.283(a) applicable to the type of joint and material being tested;
(ii) Examined by ultrasonic inspection and found not to contain
flaws that would cause failure; or
(iii) Cut into at least 3 longitudinal straps, each of which is:
(A) Visually examined and found not to contain voids or
discontinuities on the cut surfaces of the joint area; and
(B) Deformed by bending, torque, or impact, and if failure occurs,
it must not initiate in the joint area.
(c) A person must be requalified under an applicable procedure, if
during any 12-month period that person:
(1) Does not make any joints under that procedure; or
(2) Has 3 joints or 3 percent of the joints made, whichever is
greater, under that procedure that are found unacceptable by testing
under Sec. 192.513.
(d) Each operator shall establish a method to determine that each
person making joints in plastic pipelines in
[[Page 69]]
the operator's system is qualified in accordance with this section.
[Amdt. 192-34A, 45 FR 9935, Feb. 14, 1980, as amended by Amdt. 192-34B,
46 FR 39, Jan. 2, 1981; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]
Sec. 192.287 Plastic pipe: Inspection of joints.
No person may carry out the inspection of joints in plastic pipes
required by Sec. Sec. 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
Sec. 192.301 Scope.
This subpart prescribes minimum requirements for constructing
transmission lines and mains.
Sec. 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.
Sec. 192.305 Inspection: General.
Each transmission line or main must be inspected to ensure that it
is constructed in accordance with this part.
Sec. 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.
Sec. 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:
(1) The minimum thickness required by the tolerances in the
specification to which the pipe was manufactured; or
(2) The nominal wall thickness required for the design pressure of
the pipeline.
(b) Each of the following dents must be removed from steel pipe to
be operated at a pressure that produces a hoop stress of 20 percent, or
more, of SMYS, unless the dent is repaired by a method that reliable
engineering tests and analyses show can permanently restore the
serviceability of the pipe:
(1) A dent that contains a stress concentrator such as a scratch,
gouge, groove, or arc burn.
(2) A dent that affects the longitudinal weld or a circumferential
weld.
(3) In pipe to be operated at a pressure that produces a hoop stress
of 40 percent or more of SMYS, a dent that has a depth of:
(i) More than \1/4\ inch (6.4 millimeters) in pipe 12\3/4\ inches
(324 millimeters) or less in outer diameter; or
(ii) More than 2 percent of the nominal pipe diameter in pipe over
12\3/4\ inches (324 millimeters) in outer diameter.
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:
(1) The minimum wall thickness required by the tolerances in the
specification to which the pipe was manufactured; or
(2) The nominal wall thickness required for the design pressure of
the pipeline.
(d) A gouge, groove, arc burn, or dent may not be repaired by insert
patching or by pounding out.
(e) Each gouge, groove, arc burn, or dent that is removed from a
length of
[[Page 70]]
pipe must be removed by cutting out the damaged portion as a cylinder.
[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]
Sec. 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]
Sec. 192.313 Bends and elbows.
(a) Each field bend in steel pipe, other than a wrinkle bend made in
accordance with Sec. 192.315, must comply with the following:
(1) A bend must not impair the serviceability of the pipe.
(2) Each bend must have a smooth contour and be free from buckling,
cracks, or any other mechanical damage.
(3) On pipe containing a longitudinal weld, the longitudinal weld
must be as near as practicable to the neutral axis of the bend unless:
(i) The bend is made with an internal bending mandrel; or
(ii) The pipe is 12 inches (305 millimeters) or less in outside
diameter or has a diameter to wall thickness ratio less than 70.
(b) Each circumferential weld of steel pipe which is located where
the stress during bending causes a permanent deformation in the pipe
must be nondestructively tested either before or after the bending
process.
(c) Wrought-steel welding elbows and transverse segments of these
elbows may not be used for changes in direction on steel pipe that is 2
inches (51 millimeters) or more in diameter unless the arc length, as
measured along the crotch, is at least 1 inch (25 millimeters).
[Amdt. No. 192-26, 41 FR 26018, June 24, 1976, as amended by Amdt. 192-
29, 42 FR 42866, Aug. 25, 1977; Amdt. 192-29, 42 FR 60148, Nov. 25,
1977; Amdt. 192-49, 50 FR 13225, Apr. 3, 1985; Amdt. 192-85, 63 FR
37503, July 13, 1998]
Sec. 192.315 Wrinkle bends in steel pipe.
(a) A wrinkle bend may not be made on steel pipe to be operated at a
pressure that produces a hoop stress of 30 percent, or more, of SMYS.
(b) Each wrinkle bend on steel pipe must comply with the following:
(1) The bend must not have any sharp kinks.
(2) When measured along the crotch of the bend, the wrinkles must be
a distance of at least one pipe diameter.
(3) On pipe 16 inches (406 millimeters) or larger in diameter, the
bend may not have a deflection of more than 1\1/2\[deg] for each
wrinkle.
(4) On pipe containing a longitudinal weld the longitudinal seam
must be as near as practicable to the neutral axis of the bend.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503,
July 13, 1998]
Sec. 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.
(b) Each aboveground transmission line or main, not located offshore
or in inland navigable water areas, must be protected from accidental
damage by vehicular traffic or other similar causes, either by being
placed at a safe distance from the traffic or by installing barricades.
(c) Pipelines, including pipe risers, on each platform located
offshore or in inland navigable waters must be protected from accidental
damage by vessels.
[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976, as amended by Amdt. 192-78,
61 FR 28784, June 6, 1996]
Sec. 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.
[[Page 71]]
(b) When a ditch for a transmission line or main is backfilled, it
must be backfilled in a manner that:
(1) Provides firm support under the pipe; and
(2) Prevents damage to the pipe and pipe coating from equipment or
from the backfill material.
(c) All offshore pipe in water at least 12 feet (3.7 meters) deep
but not more than 200 feet (61 meters) deep, as measured from the mean
low tide, except pipe in the Gulf of Mexico and its inlets under 15 feet
(4.6 meters) of water, must be installed so that the top of the pipe is
below the natural bottom unless the pipe is supported by stanchions,
held in place by anchors or heavy concrete coating, or protected by an
equivalent means. Pipe in the Gulf of Mexico and its inlets under 15
feet (4.6 meters) of water must be installed so that the top of the pipe
is 36 inches (914 millimeters) below the seabed for normal excavation or
18 inches (457 millimeters) for rock excavation.
[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]
Sec. 192.321 Installation of plastic pipe.
(a) Plastic pipe must be installed below ground level except as
provided by paragraphs (g) and (h) of this section.
(b) Plastic pipe that is installed in a vault or any other below
grade enclosure must be completely encased in gas-tight metal pipe and
fittings that are adequately protected from corrosion.
(c) Plastic pipe must be installed so as to minimize shear or
tensile stresses.
(d) Thermoplastic pipe that is not encased must have a minimum wall
thickness of 0.090 inch (2.29 millimeters), except that pipe with an
outside diameter of 0.875 inch (22.3 millimeters) or less may have a
minimum wall thickness of 0.062 inch (1.58 millimeters).
(e) Plastic pipe that is not encased must have an electrically
conducting wire or other means of locating the pipe while it is
underground. Tracer wire may not be wrapped around the pipe and contact
with the pipe must be minimized but is not prohibited. Tracer wire or
other metallic elements installed for pipe locating purposes must be
resistant to corrosion damage, either by use of coated copper wire or by
other means.
(f) Plastic pipe that is being encased must be inserted into the
casing pipe in a manner that will protect the plastic. The leading end
of the plastic must be closed before insertion.
(g) Uncased plastic pipe may be temporarily installed above ground
level under the following conditions:
(1) The operator must be able to demonstrate that the cumulative
aboveground exposure of the pipe does not exceed the manufacturer's
recommended maximum period of exposure or 2 years, whichever is less.
(2) The pipe either is located where damage by external forces is
unlikely or is otherwise protected against such damage.
(3) The pipe adequately resists exposure to ultraviolet light and
high and low temperatures.
(h) Plastic pipe may be installed on bridges provided that it is:
(1) Installed with protection from mechanical damage, such as
installation in a metallic casing;
(2) Protected from ultraviolet radiation; and
(3) Not allowed to exceed the pipe temperature limits specified in
Sec. 192.123.
[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]
Sec. 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.
(b) If there is a possibility of water entering the casing, the ends
must be sealed.
(c) If the ends of an unvented casing are sealed and the sealing is
strong enough to retain the maximum allowable operating pressure of the
pipe, the casing must be designed to hold this pressure at a stress
level of not more than 72 percent of SMYS.
[[Page 72]]
(d) If vents are installed on a casing, the vents must be protected
from the weather to prevent water from entering the casing.
Sec. 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.
(b) Each main must be installed with enough clearance from any other
underground structure to allow proper maintenance and to protect against
damage that might result from proximity to other structures.
(c) In addition to meeting the requirements of paragraph (a) or (b)
of this section, each plastic transmission line or main must be
installed with sufficient clearance, or must be insulated, from any
source of heat so as to prevent the heat from impairing the
serviceability of the pipe.
(d) Each pipe-type or bottle-type holder must be installed with a
minimum clearance from any other holder as prescribed in Sec.
192.175(b).
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503,
July 13, 1998]
Sec. 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:
------------------------------------------------------------------------
Normal Consolidated
Location soil 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 36 (914) 24 (610)
crossings....................................
------------------------------------------------------------------------
(b) Except as provided in paragraphs (c) and (d) of this section,
each buried main must be installed with at least 24 inches (610
millimeters) of cover.
(c) Where an underground structure prevents the installation of a
transmission line or main with the minimum cover, the transmission line
or main may be installed with less cover if it is provided with
additional protection to withstand anticipated external loads.
(d) A main may be installed with less than 24 inches (610
millimeters) of cover if the law of the State or municipality:
(1) Establishes a minimum cover of less than 24 inches (610
millimeters);
(2) Requires that mains be installed in a common trench with other
utility lines; and
(3) Provides adequately for prevention of damage to the pipe by
external forces.
(e) Except as provided in paragraph (c) of this section, all pipe
installed in a navigable river, stream, or harbor must be installed with
a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches
(610 millimeters) in consolidated rock between the top of the pipe and
the underwater natural bottom (as determined by recognized and generally
accepted practices).
(f) All pipe installed offshore, except in the Gulf of Mexico and
its inlets, under water not more than 200 feet (60 meters) deep, as
measured from the mean low tide, must be installed as follows:
(1) Except as provided in paragraph (c) of this section, pipe under
water less than 12 feet (3.66 meters) deep, must be installed with a
minimum cover of 36 inches (914 millimeters) in soil or 18 inches (457
millimeters) in consolidated rock between the top of the pipe and the
natural bottom.
(2) Pipe under water at least 12 feet (3.66 meters) deep must be
installed so that the top of the pipe is below the natural bottom,
unless the pipe is supported by stanchions, held in place by anchors or
heavy concrete coating, or protected by an equivalent means.
(g) All pipelines installed under water in the Gulf of Mexico and
its inlets, as defined in Sec. 192.3, must be installed in accordance
with Sec. 192.612(b)(3).
[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]
[[Page 73]]
Sec. 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
Sec. 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 The pipeline segment must meet this
issue: additional construction requirement:
------------------------------------------------------------------------
(a) Quality assurance............ (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.
(2) The quality assurance plan for
applying and testing field applied
coating to girth welds must be:
(i) Equivalent to that required
under Sec. 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 non-
destructively examined in
accordance with Sec. 192.243(b)
and (c).
(c) Depth of cover............... (1) Notwithstanding any lesser depth
of cover otherwise allowed in Sec.
192.327, there must be at least 36
inches (914 millimeters) of cover
or equivalent means to protect the
pipeline from outside force damage.
(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.
(d) Initial strength testing..... (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.
(e) Interference currents........ (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.
------------------------------------------------------------------------
[72 FR 62176, Oct. 17, 2008]
Subpart H_Customer Meters, Service Regulators, and Service Lines
Sec. 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.
Sec. 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.
(b) Each service regulator installed within a building must be
located as near as practical to the point of service line entrance.
(c) Each meter installed within a building must be located in a
ventilated place and not less than 3 feet (914 millimeters) from any
source of ignition or any source of heat which might damage the meter.
(d) Where feasible, the upstream regulator in a series must be
located outside the building, unless it is located in a separate
metering or regulating building.
[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]
Sec. 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
[[Page 74]]
pressure, a device must be installed to protect the system.
(b) Service regulator vents and relief vents. Service regulator
vents and relief vents must terminate outdoors, and the outdoor terminal
must--
(1) Be rain and insect resistant;
(2) Be located at a place where gas from the vent can escape freely
into the atmosphere and away from any opening into the building; and
(3) Be protected from damage caused by submergence in areas where
flooding may occur.
(c) 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.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635,
Jan. 21, 1988]
Sec. 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.
(b) When close all-thread nipples are used, the wall thickness
remaining after the threads are cut must meet the minimum wall thickness
requirements of this part.
(c) Connections made of lead or other easily damaged material may
not be used in the installation of meters or regulators.
(d) Each regulator that might release gas in its operation must be
vented to the outside atmosphere.
Sec. 192.359 Customer meter installations: Operating pressure.
(a) A meter may not be used at a pressure that is more than 67
percent of the manufacturer's shell test pressure.
(b) Each newly installed meter manufactured after November 12, 1970,
must have been tested to a minimum of 10 p.s.i. (69 kPa) gage.
(c) A rebuilt or repaired tinned steel case meter may not be used at
a pressure that is more than 50 percent of the pressure used to test the
meter after rebuilding or repairing.
[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]
Sec. 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.
(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.
(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.
(d) Protection against piping strain and external loading. Each
service line must be installed so as to minimize anticipated piping
strain and external loading.
(e) Installation of service lines into buildings. Each underground
service line installed below grade through the outer foundation wall of
a building must:
(1) In the case of a metal service line, be protected against
corrosion;
(2) In the case of a plastic service line, be protected from
shearing action and backfill settlement; and
(3) Be sealed at the foundation wall to prevent leakage into the
building.
(f) Installation of service lines under buildings. Where an
underground service line is installed under a building:
(1) It must be encased in a gas tight conduit;
(2) The conduit and the service line must, if the service line
supplies the building it underlies, extend into a normally usable and
accessible part of the building; and
(3) The space between the conduit and the service line must be
sealed to prevent gas leakage into the building and, if the conduit is
sealed at both ends, a vent line from the annular space must extend to a
point where gas would not be a hazard, and extend
[[Page 75]]
above grade, terminating in a rain and insect resistant fitting.
(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 Sec. 192.321(e).
[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]
Sec. 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.
(b) A soft seat service line valve may not be used if its ability to
control the flow of gas could be adversely affected by exposure to
anticipated heat.
(c) Each service-line valve on a high-pressure service line,
installed above ground or in an area where the blowing of gas would be
hazardous, must be designed and constructed to minimize the possibility
of the removal of the core of the valve with other than specialized
tools.
Sec. 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.
(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.
(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.
Sec. 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.
(b) Compression-type connection to main. Each compression-type
service line to main connection must:
(1) Be designed and installed to effectively sustain the
longitudinal pull-out or thrust forces caused by contraction or
expansion of the piping, or by anticipated external or internal loading;
and
(2) If gaskets are used in connecting the service line to the main
connection fitting, have gaskets that are compatible with the kind of
gas in the system.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR 18517,
Apr. 26, 1996]
Sec. 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 Sec. 192.273.
(b) If a threaded tap is being inserted, the requirements of Sec.
192.151 (b) and (c) must also be met.
Sec. 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]
Sec. 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.
(b) If cast iron pipe or ductile iron pipe is installed for use as a
service line, the part of the service line which extends through the
building wall must be of steel pipe.
(c) A cast iron or ductile iron service line may not be installed in
unstable soil or under a building.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503,
July 13, 1998]
[[Page 76]]
Sec. 192.375 Service lines: Plastic.
(a) Each plastic service line outside a building must be installed
below ground level, except that--
(1) It may be installed in accordance with Sec. 192.321(g); and
(2) It may terminate above ground level and outside the building,
if--
(i) The above ground level part of the plastic service line is
protected against deterioration and external damage; and
(ii) The plastic service line is not used to support external loads.
(b) Each plastic service line inside a building must be protected
against external damage.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28785,
June 6, 1996]
Sec. 192.377 Service lines: Copper.
Each copper service line installed within a building must be
protected against external damage.
Sec. 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.
(b) A mechanical device or fitting that will prevent the flow of gas
must be installed in the service line or in the meter assembly.
(c) The customer's piping must be physically disconnected from the
gas supply and the open pipe ends sealed.
[Amdt. 192-8, 37 FR 20694, Oct. 3, 1972]
Sec. 192.381 Service lines: Excess flow valve performance standards.
(a) Excess flow valves to be used on single residence service lines
that operate continuously throughout the year at a pressure not less
than 10 p.s.i. (69 kPa) gage must be manufactured and tested by the
manufacturer according to an industry specification, or the
manufacturer's written specification, to ensure that each valve will:
(1) Function properly up to the maximum operating pressure at which
the valve is rated;
(2) Function properly at all temperatures reasonably expected in the
operating environment of the service line;
(3) At 10 p.s.i. (69 kPa) gage:
(i) Close at, or not more than 50 percent above, the rated closure
flow rate specified by the manufacturer; and
(ii) Upon closure, reduce gas flow--
(A) For an excess flow valve designed to allow pressure to equalize
across the valve, to no more than 5 percent of the manufacturer's
specified closure flow rate, up to a maximum of 20 cubic feet per hour
(0.57 cubic meters per hour); or
(B) For an excess flow valve designed to prevent equalization of
pressure across the valve, to no more than 0.4 cubic feet per hour (.01
cubic meters per hour); and
(4) Not close when the pressure is less than the manufacturer's
minimum specified operating pressure and the flow rate is below the
manufacturer's minimum specified closure flow rate.
(b) An excess flow valve must meet the applicable requirements of
Subparts B and D of this part.
(c) An operator must mark or otherwise identify the presence of an
excess flow valve in the service line.
(d) An operator shall locate an excess flow valve as near as
practical to the fitting connecting the service line to its source of
gas supply.
(e) An operator should not install an excess flow valve on a service
line where the operator has prior experience with contaminants in the
gas stream, where these contaminants could be expected to cause the
excess flow valve to malfunction or where the excess flow valve would
interfere with necessary operation and maintenance activities on the
service, such as blowing liquids from the line.
[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]
Sec. 192.383 Excess flow valve customer notification.
(a) Definitions. As used in this section:
Costs associated with installation means the costs directly
connected
[[Page 77]]
with installing an excess flow valve, for example, costs of parts,
labor, inventory and procurement. It does not include maintenance and
replacement costs until such costs are incurred.
Replaced service line means a natural 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 customer means the person who pays the gas bill, or
where service has not yet been established, the person requesting
service.
(b) Which customers must receive notification. Notification is
required on each newly installed service line or replaced service line
that operates continuously throughout the year at a pressure not less
than 68.9 kPa (10 psig) and that serves a single residence. On these
lines an operator of a natural gas distribution system must notify the
service line customer once in writing.
(c) What to put in the written notice. (1) An explanation for the
customer that an excess flow valve meeting the performance standards
prescribed under Sec. 192.381 is available for the operator to install
if the customer bears the costs associated with installation;
(2) An explanation for the customer of the potential safety benefits
that may be derived from installing an excess flow valve. The
explanation must include that an excess flow valve is designed to shut
off flow of natural gas automatically if the service line breaks;
(3) A description of installation, maintenance, and replacement
costs. The notice must explain that if the customer requests the
operator to install an EFV, the customer bears all costs associated with
installation, and what those costs are. The notice must alert the
customer that the costs for maintaining and replacing an EFV may later
be incurred, and what those costs will be, to the extent known.
(d) When notification and installation must be made. (1) After
February 3, 1999 an operator must notify each service line customer set
forth in paragraph (b) of this section:
(i) On new service lines when the customer applies for service.
(ii) On replaced service lines when the operator determines the
service line will be replaced.
(2) If a service line customer requests installation an operator
must install the EFV at a mutually agreeable date.
(e) What records are required. (1) An 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:
(i) A copy of the notice currently in use; and
(ii) Evidence that notice has been sent to the service line
customers set forth in paragraph (b) of this section, within the
previous three years.
(2) [Reserved]
(f) When notification is not required. The notification requirements
do not apply if the operator can demonstrate--
(1) That the operator will voluntarily install an excess flow valve
or that the state or local jurisdiction requires installation;
(2) That excess flow valves meeting the performance standards in
Sec. 192.381 are not available to the operator;
(3) That the operator has prior experience with contaminants in the
gas stream that could interfere with the operation of an excess flow
valve, cause loss of service to a residence, or interfere with necessary
operation or maintenance activities, such as blowing liquids from the
line.
(4) That an emergency or short time notice replacement situation
made it impractical for the operator to notify a service line customer
before replacing a service line. Examples of these situations would be
where an operator has to replace a service line quickly because of--
(i) Third party excavation damage;
(ii) Grade 1 leaks as defined in the Appendix G-192-11 of the Gas
Piping Technology Committee guide for gas transmission and distribution
systems;
(iii) A short notice service line relocation request.
[Amdt.192-82, 63 FR 5471, Feb. 3, 1998; Amdt. 192-83, 63 FR 20135, Apr.
23, 1998]
[[Page 78]]
Subpart I_Requirements for Corrosion Control
Source: Amdt. 192-4, 36 FR 12302, June 30, 1971, unless otherwise
noted.
Sec. 192.451 Scope.
(a) This subpart prescribes minimum requirements for the protection
of metallic pipelines from external, internal, and atmospheric
corrosion.
(b) [Reserved]
[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]
Sec. 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 Sec. 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.
(b) Regulated onshore gathering lines. For any regulated onshore
gathering line under Sec. 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 Sec. 192.9 after
April 14, 2006, because of a change in class location or increase in
dwelling density:
(1) The requirements of this subpart specifically applicable to
pipelines installed before August 1, 1971, apply to the gathering line
regardless of the date the pipeline was actually installed; and
(2) The requirements of this subpart specifically applicable to
pipelines installed after July 31, 1971, apply only if the pipeline
substantially meets those requirements.
[Amdt. 192-30, 42 FR 60148, Nov. 25, 1977, as amended by Amdt. 192-102,
71 FR 13303, Mar. 15, 2006]
Sec. 192.453 General.
The corrosion control procedures required by Sec. 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]
Sec. 192.455 External corrosion control: Buried or submerged pipelines
installed after July 31, 1971.
(a) Except as provided in paragraphs (b), (c), and (f) of this
section, each buried or submerged pipeline installed after July 31,
1971, must be protected against external corrosion, including the
following:
(1) It must have an external protective coating meeting the
requirements of Sec. 192.461.
(2) It must have a cathodic protection system designed to protect
the pipeline in accordance with this subpart, installed and placed in
operation within 1 year after completion of construction.
(b) An operator need not comply with paragraph (a) of this section,
if the operator can demonstrate by tests, investigation, or experience
in the area of application, including, as a minimum, soil resistivity
measurements and tests for corrosion accelerating bacteria, that a
corrosive environment does not exist. However, within 6 months after an
installation made pursuant to the preceding sentence, the operator shall
conduct tests, including pipe-to-soil potential measurements with
respect to either a continuous reference electrode or an electrode using
close spacing, not to exceed 20 feet (6 meters), and soil resistivity
measurements at potential profile peak locations, to adequately evaluate
the potential profile along the entire pipeline. If the tests made
indicate that a corrosive condition exists, the pipeline must be
cathodically protected in accordance with paragraph (a)(2) of this
section.
[[Page 79]]
(c) An operator need not comply with paragraph (a) of this section,
if the operator can demonstrate by tests, investigation, or experience
that--
(1) For a copper pipeline, a corrosive environment does not exist;
or
(2) For a temporary pipeline with an operating period of service not
to exceed 5 years beyond installation, corrosion during the 5-year
period of service of the pipeline will not be detrimental to public
safety.
(d) Notwithstanding the provisions of paragraph (b) or (c) of this
section, if a pipeline is externally coated, it must be cathodically
protected in accordance with paragraph (a)(2) of this section.
(e) Aluminum may not be installed in a buried or submerged pipeline
if that aluminum is exposed to an environment with a natural pH in
excess of 8, unless tests or experience indicate its suitability in the
particular environment involved.
(f) This section does not apply to electrically isolated, metal
alloy fittings in plastic pipelines, if:
(1) For the size fitting to be used, an operator can show by test,
investigation, or experience in the area of application that adequate
corrosion control is provided by the alloy composition; and
(2) The fitting is designed to prevent leakage caused by localized
corrosion pitting.
[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]
Sec. 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.
(b) Except for cast iron or ductile iron, each of the following
buried or submerged pipelines installed before August 1, 1971, must be
cathodically protected in accordance with this subpart in areas in which
active corrosion is found:
(1) Bare or ineffectively coated transmission lines.
(2) Bare or coated pipes at compressor, regulator, and measuring
stations.
(3) Bare or coated distribution lines.
[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]
Sec. 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
Sec. Sec. 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.
[Amdt. 192-87, 64 FR 56981, Oct. 22, 1999]
Sec. 192.461 External corrosion control: Protective coating.
(a) Each external protective coating, whether conductive or
insulating, applied for the purpose of external corrosion control must--
(1) Be applied on a properly prepared surface;
(2) Have sufficient adhesion to the metal surface to effectively
resist underfilm migration of moisture;
(3) Be sufficiently ductile to resist cracking;
(4) Have sufficient strength to resist damage due to handling and
soil stress; and
(5) Have properties compatible with any supplemental cathodic
protection.
[[Page 80]]
(b) Each external protective coating which is an electrically
insulating type must also have low moisture absorption and high
electrical resistance.
(c) Each external protective coating must be inspected just prior to
lowering the pipe into the ditch and backfilling, and any damage
detrimental to effective corrosion control must be repaired.
(d) Each external protective coating must be protected from damage
resulting from adverse ditch conditions or damage from supporting
blocks.
(e) If coated pipe is installed by boring, driving, or other similar
method, precautions must be taken to minimize damage to the coating
during installation.
Sec. 192.463 External corrosion control: Cathodic protection.
(a) Each cathodic protection system required by this subpart must
provide a level of cathodic protection that complies with one or more of
the applicable criteria contained in appendix D of this part. If none of
these criteria is applicable, the cathodic protection system must
provide a level of cathodic protection at least equal to that provided
by compliance with one or more of these criteria.
(b) If amphoteric metals are included in a buried or submerged
pipeline containing a metal of different anodic potential--
(1) The amphoteric metals must be electrically isolated from the
remainder of the pipeline and cathodically protected; or
(2) The entire buried or submerged pipeline must be cathodically
protected at a cathodic potential that meets the requirements of
appendix D of this part for amphoteric metals.
(c) The amount of cathodic protection must be controlled so as not
to damage the protective coating or the pipe.
Sec. 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 Sec. 192.463. However, if tests at those intervals are
impractical for separately protected short sections of mains or
transmission lines, not in excess of 100 feet (30 meters), or separately
protected service lines, these pipelines may be surveyed on a sampling
basis. At least 10 percent of these protected structures, distributed
over the entire system must be surveyed each calendar year, with a
different 10 percent checked each subsequent year, so that the entire
system is tested in each 10-year period.
(b) Each cathodic protection rectifier or other impressed current
power source must be inspected six times each calendar year, but with
intervals not exceeding 2\1/2\ months, to insure that it is operating.
(c) Each reverse current switch, each diode, and each interference
bond whose failure would jeopardize structure protection must be
electrically checked for proper performance six times each calendar
year, but with intervals not exceeding 2\1/2\ months. Each other
interference bond must be checked at least once each calendar year, but
with intervals not exceeding 15 months.
(d) Each operator shall take prompt remedial action to correct any
deficiencies indicated by the monitoring.
(e) After the initial evaluation required by Sec. Sec. 192.455(b)
and (c) and 192.457(b), each operator must, not less than every 3 years
at intervals not exceeding 39 months, reevaluate its unprotected
pipelines and cathodically protect them in accordance with this subpart
in areas in which active corrosion is found. The operator must determine
the areas of active corrosion by electrical survey. However, on
distribution lines and where an electrical survey is impractical on
transmission lines, areas of active corrosion may be determined by other
means that include review and analysis of leak repair and inspection
records, corrosion monitoring records, exposed pipe inspection records,
and the pipeline environment. In this section:
(1) Active corrosion means continuing corrosion which, unless
controlled, could result in a condition that is detrimental to public
safety.
[[Page 81]]
(2) 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.
(3) 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.
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43
FR 39390, Sept. 5, 1978; Amdt. 192-35A, 45 FR 23441, Apr. 7, 1980; Amdt.
192-85, 63 FR 37504, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15,
2003]
Sec. 192.467 External corrosion control: Electrical isolation.
(a) Each buried or submerged pipeline must be electrically isolated
from other underground metallic structures, unless the pipeline and the
other structures are electrically interconnected and cathodically
protected as a single unit.
(b) One or more insulating devices must be installed where
electrical isolation of a portion of a pipeline is necessary to
facilitate the application of corrosion control.
(c) Except for unprotected copper inserted in ferrous pipe, each
pipeline must be electrically isolated from metallic casings that are a
part of the underground system. However, if isolation is not achieved
because it is impractical, other measures must be taken to minimize
corrosion of the pipeline inside the casing.
(d) Inspection and electrical tests must be made to assure that
electrical isolation is adequate.
(e) An insulating device may not be installed in an area where a
combustible atmosphere is anticipated unless precautions are taken to
prevent arcing.
(f) Where a pipeline is located in close proximity to electrical
transmission tower footings, ground cables or counterpoise, or in other
areas where fault currents or unusual risk of lightning may be
anticipated, it must be provided with protection against damage due to
fault currents or lightning, and protective measures must also be taken
at insulating devices.
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43
FR 39390, Sept. 5, 1978]
Sec. 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]
Sec. 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.
(b) Each test lead wire must be attached to the pipeline so as to
minimize stress concentration on the pipe.
(c) Each bared test lead wire and bared metallic area at point of
connection to the pipeline must be coated with an electrical insulating
material compatible with the pipe coating and the insulation on the
wire.
Sec. 192.473 External corrosion control: Interference currents.
(a) Each operator whose pipeline system is subjected to stray
currents shall have in effect a continuing program to minimize the
detrimental effects of such currents.
(b) Each impressed current type cathodic protection system or
galvanic anode system must be designed and installed so as to minimize
any adverse effects on existing adjacent underground metallic
structures.
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43
FR 39390, Sept. 5, 1978]
Sec. 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.
[[Page 82]]
(b) Whenever any pipe is removed from a pipeline for any reason, the
internal surface must be inspected for evidence of corrosion. If
internal corrosion is found--
(1) The adjacent pipe must be investigated to determine the extent
of internal corrosion;
(2) Replacement must be made to the extent required by the
applicable paragraphs of Sec. Sec. 192.485, 192.487, or 192.489; and
(3) Steps must be taken to minimize the internal corrosion.
(c) Gas containing more than 0.25 grain of hydrogen sulfide per 100
cubic feet (5.8 milligrams/m\.3\) at standard conditions (4 parts per
million) may not be stored in pipe-type or bottle-type holders.
[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]
Sec. 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:
(1) Be configured to reduce the risk that liquids will collect in
the line;
(2) Have effective liquid removal features whenever the
configuration would allow liquids to collect; and
(3) Allow use of devices for monitoring internal corrosion at
locations with significant potential for internal corrosion.
(b) Exceptions to applicability. The design and construction
requirements of paragraph (a) of this section do not apply to the
following:
(1) Offshore pipeline; and
(2) Pipeline installed or line pipe, valve, fitting or other line
component replaced before May 23, 2007.
(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.
(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.
[72 FR 20059, Apr. 23, 2007]
Sec. 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 7\1/2\ months.
[Amdt. 192-33, 43 FR 39390, Sept. 5, 1978]
Sec. 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.
(b) Coating material must be suitable for the prevention of
atmospheric corrosion.
(c) Except portions of pipelines in offshore splash zones or soil-
to-air interfaces, the operator need not protect from atmospheric
corrosion any pipeline for which the operator demonstrates by test,
investigation, or experience appropriate to the environment of the
pipeline that corrosion will--
(1) Only be a light surface oxide; or
[[Page 83]]
(2) Not affect the safe operation of the pipeline before the next
scheduled inspection.
[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
Sec. 192.481 Atmospheric corrosion control: Monitoring.
(a) Each operator must inspect each pipeline or portion of pipeline
that is exposed to the atmosphere for evidence of atmospheric corrosion,
as follows:
------------------------------------------------------------------------
Then the frequency of
If the pipeline is located: inspection is:
------------------------------------------------------------------------
Onshore................................ At least once every 3 calendar
years, but with intervals not
exceeding 39 months
Offshore............................... At 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.
(c) If atmospheric corrosion is found during an inspection, the
operator must provide protection against the corrosion as required by
Sec. 192.479.
[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]
Sec. 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 Sec. 192.461.
(b) Each segment of metallic pipe that replaces pipe removed from a
buried or submerged pipeline because of external corrosion must be
cathodically protected in accordance with this subpart.
(c) Except for cast iron or ductile iron pipe, each segment of
buried or submerged pipe that is required to be repaired because of
external corrosion must be cathodically protected in accordance with
this subpart.
Sec. 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.
(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.
(c) Under paragraphs (a) and (b) of this section, the strength of
pipe based on actual remaining wall thickness may be determined by the
procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research
Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply to
corroded regions that do not penetrate the pipe wall, subject to the
limitations prescribed in the procedures.
[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.
192-88, 64 FR 69664, Dec. 14, 1999]
Sec. 192.487 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
[[Page 84]]
strength of the pipe is considered general corrosion for the purpose of
this paragraph.
(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.
[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-88, 64
FR 69665, Dec. 14, 1999]
Sec. 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.
(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.
Sec. 192.490 Direct assessment.
Each operator that uses direct assessment as defined in Sec.
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.
------------------------------------------------------------------------
Threat Standard \1\
------------------------------------------------------------------------
External corrosion....................... Sec. 192.925 \2\
Internal corrosion in pipelines that Sec. 192.927
transport dry gas.
Stress corrosion cracking................ Sec. 192.929
------------------------------------------------------------------------
\1\ For lines not subject to subpart O of this part, the terms ``covered
segment'' and ``covered pipeline segment'' in Sec. Sec. 192.925,
192.927, and 192.929 refer to the pipeline segment on which direct
assessment is performed.
\2\ In Sec. 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]
Sec. 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.
(b) Each record or map required by paragraph (a) of this section
must be retained for as long as the pipeline remains in service.
(c) Each operator shall maintain a record of each test, survey, or
inspection required by this subpart in sufficient detail to demonstrate
the adequacy of corrosion control measures or that a corrosive condition
does not exist. These records must be retained for at least 5 years,
except that records related to Sec. Sec. 192.465 (a) and (e) and
192.475(b) must be retained for as long as the pipeline remains in
service.
[Amdt. 192-78, 61 FR 28785, June 6, 1996]
Subpart J_Test Requirements
Sec. 192.501 Scope.
This subpart prescribes minimum leak-test and strength-test
requirements for pipelines.
Sec. 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--
(1) It has been tested in accordance with this subpart and Sec.
192.619 to substantiate the maximum allowable operating pressure; and
(2) Each potentially hazardous leak has been located and eliminated.
(b) The test medium must be liquid, air, natural gas, or inert gas
that is--
(1) Compatible with the material of which the pipeline is
constructed;
(2) Relatively free of sedimentary materials; and
(3) Except for natural gas, nonflammable.
(c) Except as provided in Sec. 192.505(a), if air, natural gas, or
inert gas is used as the test medium, the following maximum hoop stress
limitations apply:
[[Page 85]]
------------------------------------------------------------------------
Maximum hoop stress allowed as
percentage of SMYS
Class location -------------------------------------
Natural gas Air or inert gas
------------------------------------------------------------------------
1................................. 80 80
2................................. 30 75
3................................. 30 50
4................................. 30 40
------------------------------------------------------------------------
(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.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635,
Jan. 21, 1988; Amdt. 192-60, 53 FR 36029, Sept. 16, 1988; Amdt. 192-60A,
54 FR 5485, Feb. 3, 1989]
Sec. 192.505 Strength test requirements for steel pipeline 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.
(b) In a Class 1 or Class 2 location, each compressor station
regulator station, and measuring station, must be tested to at least
Class 3 location test requirements.
(c) Except as provided in paragraph (e) of this section, the
strength test must be conducted by maintaining the pressure at or above
the test pressure for at least 8 hours.
(d) If a component other than pipe is the only item being replaced
or added to a pipeline, a strength test after installation is not
required, if the manufacturer of the component certifies that--
(1) The component was tested to at least the pressure required for
the pipeline to which it is being added;
(2) The component was manufactured under a quality control system
that ensures that each item manufactured is at least equal in strength
to a prototype and that the prototype was tested to at least the
pressure required for the pipeline to which it is being added; or
(3) The component carries a pressure rating established through
applicable ASME/ANSI, MSS specifications, or by unit strength
calculations as described in Sec. 192.143.
(e) For fabricated units and short sections of pipe, for which a
post installation test is impractical, a preinstallation strength test
must be conducted by maintaining the pressure at or above the test
pressure for at least 4 hours.
[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]
Sec. 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.
(b) If, during the test, the segment is to be stressed to 20 percent
or more of SMYS and natural gas, inert gas, or air is the test medium--
(1) A leak test must be made at a pressure between 100 p.s.i. (689
kPa) gage and the pressure required to produce a hoop stress of 20
percent of SMYS; or
(2) The line must be walked to check for leaks while the hoop stress
is held at approximately 20 percent of SMYS.
[[Page 86]]
(c) The pressure must be maintained at or above the test pressure
for at least 1 hour.
[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]
Sec. 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.
(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.
[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]
Sec. 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.
(b) Each segment of a service line (other than plastic) intended to
be operated at a pressure of at least 1 p.s.i. (6.9 kPa) gage but not
more than 40 p.s.i. (276 kPa) gage must be given a leak test at a
pressure of not less than 50 p.s.i. (345 kPa) gage.
(c) Each segment of a service line (other than plastic) intended to
be operated at pressures of more than 40 p.s.i. (276 kPa) gage must be
tested to at least 90 p.s.i. (621 kPa) gage, except that each segment of
a steel service line stressed to 20 percent or more of SMYS must be
tested in accordance with Sec. 192.507 of this subpart.
[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]
Sec. 192.513 Test requirements for plastic pipelines.
(a) Each segment of a plastic pipeline must be tested in accordance
with this section.
(b) The test procedure must insure discovery of all potentially
hazardous leaks in the segment being tested.
(c) The test pressure must be at least 150 percent of the maximum
operating pressure or 50 p.s.i. (345 kPa) gage, whichever is greater.
However, the maximum test pressure may not be more than three times the
pressure determined under Sec. 192.121, at a temperature not less than
the pipe temperature during the test.
(d) During the test, the temperature of thermoplastic material may
not be more than 100[deg]F (38[deg]C), or the temperature at which the
material's long-term hydrostatic strength has been determined under the
listed specification, whichever is greater.
[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]
Sec. 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.
(b) The operator shall insure that the test medium is disposed of in
a manner that will minimize damage to the environment.
Sec. 192.517 Records.
(a) Each operator shall make, and retain for the useful life of the
pipeline,
[[Page 87]]
a record of each test performed under Sec. Sec. 192.505 and 192.507.
The record must contain at least the following information:
(1) The operator's name, the name of the operator's employee
responsible for making the test, and the name of any test company used.
(2) Test medium used.
(3) Test pressure.
(4) Test duration.
(5) Pressure recording charts, or other record of pressure readings.
(6) Elevation variations, whenever significant for the particular
test.
(7) Leaks and failures noted and their disposition.
(b) Each operator must maintain a record of each test required by
Sec. Sec. 192.509, 192.511, and 192.513 for at least 5 years.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-93, 68 FR 53901,
Sept. 15, 2003]
Subpart K_Uprating
Sec. 192.551 Scope.
This subpart prescribes minimum requirements for increasing maximum
allowable operating pressures (uprating) for pipelines.
Sec. 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:
(1) At the end of each incremental increase, the pressure must be
held constant while the entire segment of pipeline that is affected is
checked for leaks.
(2) Each leak detected must be repaired before a further pressure
increase is made, except that a leak determined not to be potentially
hazardous need not be repaired, if it is monitored during the pressure
increase and it does not become potentially hazardous.
(b) 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.
(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.
(d) Limitation on increase in maximum allowable operating pressure.
Except as provided in Sec. 192.555(c), a new maximum allowable
operating pressure established under this subpart may not exceed the
maximum that would be allowed under Sec. Sec. 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
(Sec. 192.105) is unknown, the MAOP may be increased as provided in
Sec. 192.619(a)(1).
[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]
Sec. 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.
(b) Before increasing operating pressure above the previously
established maximum allowable operating pressure the operator shall:
(1) Review the design, operating, and maintenance history and
previous testing of the segment of pipeline and determine whether the
proposed increase is safe and consistent with the requirements of this
part; and
(2) Make any repairs, replacements, or alterations in the segment of
pipeline that are necessary for safe operation at the increased
pressure.
(c) After complying with paragraph (b) of this section, an operator
may increase the maximum allowable operating pressure of a segment of
pipeline constructed before September 12, 1970, to the highest pressure
that is permitted under Sec. 192.619, using as test
[[Page 88]]
pressure the highest pressure to which the segment of pipeline was
previously subjected (either in a strength test or in actual operation).
(d) After complying with paragraph (b) of this section, an operator
that does not qualify under paragraph (c) of this section may increase
the previously established maximum allowable operating pressure if at
least one of the following requirements is met:
(1) The segment of pipeline is successfully tested in accordance
with the requirements of this part for a new line of the same material
in the same location.
(2) An increased maximum allowable operating pressure may be
established for a segment of pipeline in a Class 1 location if the line
has not previously been tested, and if:
(i) It is impractical to test it in accordance with the requirements
of this part;
(ii) The new maximum operating pressure does not exceed 80 percent
of that allowed for a new line of the same design in the same location;
and
(iii) The operator determines that the new maximum allowable
operating pressure is consistent with the condition of the segment of
pipeline and the design requirements of this part.
(e) Where a segment of pipeline is uprated in accordance with
paragraph (c) or (d)(2) of this section, the increase in pressure must
be made in increments that are equal to:
(1) 10 percent of the pressure before the uprating; or
(2) 25 percent of the total pressure increase,
whichever produces the fewer number of increments.
Sec. 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:
(1) A segment of steel pipeline to an operating pressure that will
produce a hoop stress less than 30 percent of SMYS and that is above the
previously established maximum allowable operating pressure; or
(2) A plastic, cast iron, or ductile iron pipeline segment to an
operating pressure that is above the previously established maximum
allowable operating pressure.
(b) Before increasing operating pressure above the previously
established maximum allowable operating pressure, the operator shall:
(1) Review the design, operating, and maintenance history of the
segment of pipeline;
(2) Make a leakage survey (if it has been more than 1 year since the
last survey) and repair any leaks that are found, except that a leak
determined not to be potentially hazardous need not be repaired, if it
is monitored during the pressure increase and it does not become
potentially hazardous;
(3) Make any repairs, replacements, or alterations in the segment of
pipeline that are necessary for safe operation at the increased
pressure;
(4) Reinforce or anchor offsets, bends and dead ends in pipe joined
by compression couplings or bell and spigot joints to prevent failure of
the pipe joint, if the offset, bend, or dead end is exposed in an
excavation;
(5) Isolate the segment of pipeline in which the pressure is to be
increased from any adjacent segment that will continue to be operated at
a lower pressure; and
(6) If the pressure in mains or service lines, or both, is to be
higher than the pressure delivered to the customer, install a service
regulator on each service line and test each regulator to determine that
it is functioning. Pressure may be increased as necessary to test each
regulator, after a regulator has been installed on each pipeline subject
to the increased pressure.
(c) After complying with paragraph (b) of this section, the increase
in maximum allowable operating pressure must be made in increments that
are equal to 10 p.s.i. (69 kPa) gage or 25 percent of the total pressure
increase, whichever produces the fewer number of increments. Whenever
the requirements of paragraph (b)(6) of this section apply, there must
be at least two approximately equal incremental increases.
[[Page 89]]
(d) If records for cast iron or ductile iron pipeline facilities are
not complete enough to determine stresses produced by internal pressure,
trench loading, rolling loads, beam stresses, and other bending loads,
in evaluating the level of safety of the pipeline when operating at the
proposed increased pressure, the following procedures must be followed:
(1) In estimating the stresses, if the original laying conditions
cannot be ascertained, the operator shall assume that cast iron pipe was
supported on blocks with tamped backfill and that ductile iron pipe was
laid without blocks with tamped backfill.
(2) Unless the actual maximum cover depth is known, the operator
shall measure the actual cover in at least three places where the cover
is most likely to be greatest and shall use the greatest cover measured.
(3) Unless the actual nominal wall thickness is known, the operator
shall determine the wall thickness by cutting and measuring coupons from
at least three separate pipe lengths. The coupons must be cut from pipe
lengths in areas where the cover depth is most likely to be the
greatest. The average of all measurements taken must be increased by the
allowance indicated in the following table:
----------------------------------------------------------------------------------------------------------------
Allowance inches (millimeters)
--------------------------------------------------------
Cast iron pipe
Pipe size inches (millimeters) --------------------------------------
Centrifugally Ductile iron pipe
Pit cast pipe cast pipe
----------------------------------------------------------------------------------------------------------------
3 to 8 (76 to 203)..................................... 0.075 (1.91) 0.065 (1.65) 0.065 (1.65)
10 to 12 (254 to 305).................................. 0.08 (2.03) 0.07 (1.78) 0.07 (1.78)
14 to 24 (356 to 610).................................. 0.08 (2.03) 0.08 (2.03) 0.075 (1.91)
30 to 42 (762 to 1067)................................. 0.09 (2.29) 0.09 (2.29) 0.075 (1.91)
48 (1219).............................................. 0.09 (2.29) 0.09 (2.29) 0.08 (2.03)
54 to 60 (1372 to 1524)................................ 0.09 (2.29) ................. .................
----------------------------------------------------------------------------------------------------------------
(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.
[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