[Code of Federal Regulations]
[Title 49, Volume 3, Parts 186 to 199]
[Revised as of October 1, 1999]
From the U.S. Government Printing Office via GPO Access
[CITE: 49CFR192]
[Page 27-91]
TITLE 49--TRANSPORTATION
CHAPTER I--RESEARCH AND SPECIAL PROGRAMS ADMINISTRATION, DEPARTMENT OF
TRANSPORTATION--Continued
PART 192--TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM FEDERAL SAFETY STANDARDS
Subpart A--General
Sec.
192.1 Scope of part.
192.3 Definitions.
192.5 Class locations.
192.7 Incorporation by reference.
192.9 Gathering lines.
192.10 Outer continental shelf pipelines.
192.11 Petroleum gas systems.
192.13 General.
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.
192.113 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.
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.
[[Page 28]]
192.203 Instrument, control, and sampling pipe and components.
Subpart E--Welding of Steel in Pipelines
192.221 Scope.
192.225 Welding--General.
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.
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 Applicability to converted pipelines.
192.453 General.
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.
192.477 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.
192.491 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.
[[Page 29]]
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 re-burial 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 education.
192.617 Investigation of failures.
192.619 Maximum allowable operating pressure: Steel or plastic
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.
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: Testing 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
192.801 Scope.
192.803 Definitions.
192.805 Qualification Program.
192.807 Recordkeeping.
192.809 General.
Appendix A to Part 192--Incorporated by Reference
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
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.
Subpart A--General
Sec. 192.1 Scope of part.
(a) This part prescribes minimum safety requirements for pipeline
facilities and the transportation of gas, including pipeline facilities
and the
[[Page 30]]
transportation of gas within the limits of the outer continental shelf
as that term is defined in the Outer Continental Shelf Lands Act (43
U.S.C. 1331).
(b) This part does not apply to:
(1) Offshore pipelines upstream from the outlet flange of each
facility where hydrocarbons are produced or where produced hydrocarbons
are first separated, dehydrated, or otherwise processed, whichever
facility is farther downstream;
(2) Onshore gathering of gas outside of the following areas:
(i) An area within the limits of any incorporated or unincorporated
city, town, or village.
(ii) Any designated residential or commercial area such as a
subdivision, business or shopping center, or community development.
(3) Onshore gathering of gas within inlets of the Gulf of Mexico
except as provided in Sec. 192.612.
(4) Any pipeline system that transports only petroleum gas or
petroleum gas/air mixtures to--
(i) Fewer than 10 customers, if no portion of the system is located
in a public place; or
(ii) A single customer, if the system is located entirely on the
customer's premises (no matter if a portion of the system is located in
a public place).
(5) On the Outer Continental Shelf upstream of the point at which
operating responsibility transfers from a producing operator to a
transporting operator.
[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]
Sec. 192.3 Definitions.
As used in this part:
Administrator means the Administrator of the Research and Special
Programs Administration or any person to whom authority in the matter
concerned has been delegated by the Secretary of Transportation.
Distribution line means a pipeline other than a gathering or
transmission line.
Exposed pipeline means a pipeline where the top of the pipe is
protruding above the seabed in water less than 15 feet (4.6 meters)
deep, as measured from the 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 purpose of this part, a pipeline
where the top of the pipe is less than 12 inches (305 millimeters) below
the seabed in water less than 15 feet (4.6 meters) deep, as measured
from the mean low water.
High-pressure distribution system means a distribution system in
which the gas pressure in the main is higher than the pressure provided
to the customer.
Line section means a continuous run of transmission line between
adjacent compressor stations, between a compressor station and storage
facilities, between a compressor station and a block valve, or between
adjacent block valves.
Listed specification means a specification listed in section I of
appendix B of this part.
Low-pressure distribution system means a distribution system in
which the gas pressure in the main is substantially the same as the
pressure provided to the customer.
Main means a distribution line that serves as a common source of
supply for more than one service line.
Maximum actual operating pressure means the maximum pressure that
occurs during normal operations over a period of 1 year.
Maximum allowable operating pressure (MAOP) means the maximum
pressure at which a pipeline or segment of a pipeline may be operated
under this part.
Municipality means a city, county, or any other political
subdivision of a State.
[[Page 31]]
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 (1) a customer meter or the connection to a
customer's piping, whichever is farther downstream, or (2) the
connection to a customer's piping if there is no customer meter. A
customer meter is the meter that measures the transfer of gas from an
operator to a consumer.
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:
(a) Transports gas from a gathering line or storage facility to a
distribution center, storage facility, or large volume customer that is
not downstream from a distribution center;
(b) Operates at a hoop stress of 20 percent or more of SMYS; or
(c) Transports gas within a storage field. A large volume customer
may receive similar volumes of gas as a distribution center, and
includes factories, power plants, and institutional users of gas.
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.
[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]
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:
[[Page 32]]
(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 Incorporation by reference.
(a) Any documents or portions thereof incorporated by reference in
this part are included in this part as though set out in full. When only
a portion of a document is referenced, the remainder is not incorporated
in this part.
(b) All incorporated materials are available for inspection in the
Research and Special Programs Administration, 400 Seventh Street, SW.,
Washington, DC, and at the Office of the Federal Register, 800 North
Capitol Street, NW., suite 700, Washington, DC. These materials have
been approved for incorporation by reference by the Director of the
Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51.
In addition, the incorporated materials are available from the
respective organizations listed in appendix A to this part.
(c) The full titles for the publications incorporated by reference
in this part are provided in appendix A to this part. Numbers in
parentheses indicate applicable editions. Earlier editions of documents
listed or editions of documents formerly listed in previous editions of
appendix A may be used for materials and components manufactured,
designed, or installed in accordance with those earlier editions or
earlier documents at the time they were listed. The user must refer to
the appropriate previous edition of 49 CFR for a listing of the earlier
listed editions or documents.
[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]
Sec. 192.9 Gathering lines.
Except as provided in Secs. 192.1 and 192.150, each operator of a
gathering line must comply with the requirements of this part applicable
to transmission lines.
[Amdt. 192-72, 59 FR 17281, Apr. 12, 1994]
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 RSPA upon request. For
those cases in which adjoining operators have not agreed on a
[[Page 33]]
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]
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 General.
(a) No person may operate a segment of pipeline that is readied for
service after March 12, 1971, or in the case of an offshore gathering
line, after July 31, 1977, 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 in accordance
with Sec. 192.14.
(b) No person may operate a segment of pipeline that is replaced,
relocated, or otherwise changed after November 12, 1970, or in the case
of an offshore gathering line, after July 31, 1977, unless that
replacement, relocation, or change has been made in accordance with this
part.
(c) Each operator shall maintain, modify as appropriate, and follow
the plans, procedures, and programs that it is required to establish
under this part.
[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]
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
[[Page 34]]
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 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
[[Page 35]]
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
(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
[[Page 36]]
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) x F x E x T
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.
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
[[Page 37]]
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 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. 192.113 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...................... 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).
[[Page 38]]
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]
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 determined in accordance with either of the following
formulas:
[GRAPHIC] [TIFF OMITTED] TR06JN96.013
Where:
P=Design pressure, gauge, kPa (psig).
S=For thermoplastic pipe, the long-term hydrostatic strength determined
in accordance with the listed specification at a temperature equal to
73 deg.F (23 deg.C), 100 deg.F (38 deg.C), 120 deg.F (49 deg.C), or
140 deg.F (60 deg.C); for reinforced thermosetting plastic pipe, 11,000
psi (75,842 kPa).
t=Specified wall thickness, mm (in).
D=Specified outside diameter, mm (in).
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.
[Amdt. 192-78, 61 FR 28783, June 6, 1996, as amended by Amdt. 192-85, 63
FR 37502, July 13, 1998]
Sec. 192.123 Design limitations for plastic pipe.
(a) The design pressure may not exceed a gauge pressure of 689 kPa
(100 psig) for plastic pipe used in:
(1) Distribution systems; or
(2) Classes 3 and 4 locations.
(b) Plastic pipe may not be used where operating temperatures of the
pipe will be:
(1) Below -20 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 long-term
hydrostatic strength used in the design formula under Sec. 192.121 is
determined. However, if the pipe was manufactured before May 18, 1978
and its long-term hydrostatic strength was determined at 73 deg.F
(23 deg.C), it may be used at temperatures up to 100 deg.F (38 deg.C).
(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).
[[Page 39]]
(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)
------------------------------------------------------------------------
[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]
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.
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.
[Amdt. 48, 49 FR 19824, May 10, 1984]
Sec. 192.144 Qualifying metallic components.
Notwithstanding any requirement of this subpart which incorporates
by reference an edition of a document listed in appendix A of this part,
a metallic component manufactured in accordance with any other edition
of that document is qualified for use under this part if--
(a) It can be shown through visual inspection of the cleaned
component that no defect exists which might impair the strength or
tightness of the component; and
(b) The edition of the document under which the component was
manufactured has equal or more stringent requirements for the following
as an edition of that document currently or previously listed in
appendix A:
(1) Pressure testing;
(2) Materials; and
(3) Pressure and temperature ratings.
[Amdt. 192-45, 48 FR 30639, July 5, 1983]
Sec. 192.145 Valves.
(a) Except for cast iron and plastic valves, each valve must meet
the minimum requirements, or equivalent, of API 6D. A valve may not be
used under operating conditions that exceed the applicable pressure-
temperature ratings contained in those requirements.
(b) Each cast iron and plastic valve must comply with the following:
[[Page 40]]
(1) The valve must have a maximum service pressure rating for
temperatures that equal or exceed the maximum service temperature.
(2) The valve must be tested as part of the manufacturing, as
follows:
(i) With the valve in the fully open position, the shell must be
tested with no leakage to a pressure at least 1.5 times the maximum
service rating.
(ii) After the shell test, the seat must be tested to a pressure not
less than 1.5 times the maximum service pressure rating. Except for
swing check valves, test pressure during the seat test must be applied
successively on each side of the closed valve with the opposite side
open. No visible leakage is permitted.
(iii) After the last pressure test is completed, the valve must be
operated through its full travel to demonstrate freedom from
interference.
(c) Each valve must be able to meet the anticipated operating
conditions.
(d) No valve having shell components made of ductile iron may be
used at pressures exceeding 80 percent of the pressure ratings for
comparable steel valves at their listed temperature. However, a valve
having shell components made of ductile iron may be used at pressures up
to 80 percent of the pressure ratings for comparable steel valves at
their listed temperature, if:
(1) The temperature-adjusted service pressure does not exceed 1,000
p.s.i. (7 Mpa) gage; and
(2) Welding is not used on any ductile iron component in the
fabrication of the valve shells or their assembly.
(e) No valve having pressure containing parts made of ductile iron
may be used in the gas pipe components of compressor stations.
[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]
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 line section of a transmission line
where the line pipe, valve, fitting, or other line component is replaced
must be designed and constructed to accommodate the passage of
instrumented internal inspection devices.
(b) This section does not apply to: (1) Manifolds;
(2) Station piping such as at compressor stations, meter stations,
or regulator stations;
(3) Piping associated with storage facilities, other than a
continuous run of transmission line between a compressor station and
storage facilities;
(4) Cross-overs;
(5) Sizes of pipe for which an instrumented internal inspection
device is not commercially available;
(6) Transmission lines, operated in conjunction with a distribution
system which are installed in Class 4 locations;
[[Page 41]]
(7) Offshore pipelines, other than transmission lines 10 inches (254
millimeters) or greater in nominal diameter, that transport gas to
onshore facilities; and
(8) Other piping that, under 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]
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 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
[[Page 42]]
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 space
around the main compressor
[[Page 43]]
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 44]]
(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=(D x P x F)/48.33) (C=(3D x P x F/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--
[[Page 45]]
(1) Located on a site entirely surrounded by fencing that prevents
access by unauthorized persons and with 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
[[Page 46]]
permit the operation of the valve during an emergency that might
preclude access to the station.
(c) Each valve on a main installed for operating or emergency
purposes must comply with the following:
(1) The valve must be placed in a readily accessible location so as
to facilitate its operation in an emergency.
(2) The operating stem or mechanism must be readily accessible.
(3) If the valve is installed in a buried box or enclosure, the box
or enclosure must be installed so as to avoid transmitting external
loads to the main.
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
[[Page 47]]
National Electrical Code, ANSI/NFPA 70.
[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-76, 61 FR 26122,
May 24, 1996]
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 Secs. 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 under 60 p.s.i. (414 kPa) gage and a service regulator having
the following characteristics is used, no other pressure limiting device
is required:
(1) A regulator capable of reducing distribution line pressure to
pressures recommended for household appliances.
(2) A single port valve with proper orifice for the maximum gas
pressure at the regulator inlet.
(3) A valve seat made of resilient material designed to withstand
abrasion of the gas, impurities in gas, cutting by the valve, and to
resist permanent deformation when it is pressed against the valve port.
(4) Pipe connections to the regulator not exceeding 2 inches (51
millimeters) in diameter.
(5) A regulator that, under normal operating conditions, is able to
regulate the downstream pressure within the necessary limits of accuracy
and to limit the build-up of pressure under no-flow conditions to
prevent a pressure that would cause the unsafe operation of any
connected and properly adjusted gas utilization equipment.
(6) A self-contained service regulator with no external static or
control lines.
(b) If the maximum actual operating pressure of the distribution
system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator
that does not have all of the characteristics listed in paragraph (a) of
this section is used, or if the gas contains materials that seriously
interfere with the operation of service regulators, there must be
suitable protective devices to prevent unsafe overpressuring of the
customer's appliances if the service regulator fails.
(c) If the maximum actual operating pressure of the distribution
system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods
must be used to regulate and limit, to the maximum safe value, the
pressure of gas delivered to the customer:
(1) A service regulator having the characteristics listed in
paragraph (a) of this section, and another regulator located upstream
from the service regulator. The upstream regulator may not be set to
maintain a pressure higher than 60 p.s.i. (414 kPa) gage. A device must
be installed between the upstream regulator and the service regulator to
limit the pressure on the inlet
[[Page 48]]
of the service regulator to 60 p.s.i. (414 kPa) gage or less in case the
upstream regulator fails to function properly. This device may be either
a relief valve or an automatic shutoff that shuts, if the pressure on
the inlet of the service regulator exceeds the set pressure (60 p.s.i.
(414 kPa) gage or less), and remains closed until manually reset.
(2) A service regulator and a monitoring regulator set to limit, to
a maximum safe value, the pressure of the gas delivered to the customer.
(3) A service regulator with a relief valve vented to the outside
atmosphere, with the relief valve set to open so that the pressure of
gas going to the customer does not exceed a maximum safe value. The
relief valve may either be built into the service regulator or it may be
a separate unit installed downstream from the service regulator. This
combination may be used alone only in those cases where the inlet
pressure on the service regulator does not exceed the manufacturer's
safe working pressure rating of the service regulator, and may not be
used where the inlet 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]
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)
[[Page 49]]
gage, the pressure may not exceed the maximum allowable operating
pressure plus 6 p.s.i. (41 kPa) gage; or
(iii) If the maximum allowable operating pressure is less than 12
p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable
operating pressure plus 50 percent.
(b) When more than one pressure regulating or compressor station
feeds into a pipeline, relief valves or other protective devices must be
installed at each station to ensure that the complete failure of the
largest capacity regulator or compressor, or any single run of lesser
capacity regulators or compressors in that station, will not impose
pressures on any part of the pipeline or distribution system in excess
of those for which it was designed, or against which it was protected,
whichever is lower.
(c) Relief valves or other pressure limiting devices must be
installed at or near each regulator station in a low-pressure
distribution system, with a capacity to limit the maximum pressure in
the main to a pressure that will 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--General.
(a) Welding must be performed by a qualified welder in accordance
with welding procedures qualified to
[[Page 50]]
produce welds meeting the requirements of this subpart. The quality of
the test welds used to qualify the procedure shall be determined by
destructive testing.
(b) Each welding procedure must be recorded in detail, including the
results of the qualifying tests. This record must be retained and
followed whenever the procedure is used.
[Amdt. 192-52, 51 FR 20297, June 4, 1986]
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 3 of API Standard 1104 or
section IX of the ASME Boiler and Pressure Vessel Code. However, a
welder qualified under an earlier edition than listed in appendix A may
weld but may not requalify under that earlier edition.
(b) A welder may qualify to perform welding on pipe to be operated
at a pressure that produces a hoop stress of less than 20 percent of
SMYS by performing an acceptable test weld, for the process to be used,
under the test set forth in section I of Appendix C of 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]
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 section 3 or 6 of API Standard 1104, except that a
welder qualified under an earlier edition previously listed in Appendix
A of this part may weld but may not requalify under that earlier
edition; and
(2) May not weld on pipe to be operated at a pressure that produces
a hoop stress of less than 20 percent of SMYS unless the welder is
tested in accordance with paragraph (c)(1) of this section or
requalifies under paragraph (d)(1) or (d)(2) of this section.
(d) A welder qualified under 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]
Sec. 192.231 Protection from weather.
The welding operation must be protected from weather conditions that
would impair the quality of the completed weld.
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
[[Page 51]]
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 to insure that:
(1) The welding is performed in accordance with the welding
procedure; and
(2) The weld is acceptable under paragraph (c) of this section.
(b) The welds on a pipeline to be operated at a pressure that
produces a hoop stress of 20 percent or more of SMYS must be
nondestructively tested in accordance with 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 6
of API Standard 1104. However, if a girth weld is unacceptable under
those standards for a reason other than a crack, and if the Appendix to
API Standard 1104 applies to the weld, the acceptability of the weld may
be further determined under that Appendix.
[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]
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.
(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]
[[Page 52]]
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, 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
[[Page 53]]
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 Pressure
(Quick Burst)) of ASTM D 2513;
(ii) In the case of thermosetting plastic pipe, paragraph 8.5
(Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static
Pressure Test) of ASTM D2517; or
(iii) In the case of electrofusion fittings for polyethylene pipe
and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test),
paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength
Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM Designation
F1055.
(2) For procedures intended for lateral pipe connections, subject a
specimen joint made from pipe sections joined at right angles according
to the procedure to a force on the lateral pipe until failure occurs in
the specimen. If failure initiates outside the joint area, the procedure
qualifies for use; and
(3) For procedures intended for nonlateral pipe connections, follow
the tensile test requirements of ASTM D638, except that the test may be
conducted at ambient temperature and humidity. If the specimen elongates
no less than 25 percent or failure initiates outside the joint area, the
procedure qualifies for use.
(b) 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).
(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
[[Page 54]]
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]
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 his 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]
Sec. 192.287 Plastic pipe: inspection of joints.
No person may carry out the inspection of joints in plastic pipes
required by Secs. 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.
[[Page 55]]
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:
(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 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]
Sec. 192.311 Repair of plastic pipe.
Each imperfection or damage that would impair the serviceability of
plastic pipe must be repaired by a patching saddle or removed.
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
[[Page 56]]
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.
(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 unless
otherwise permitted by paragraph (g) of this section.
(b) Plastic pipe that is installed in a vault or any other below
grade enclosure must be completely encased in gas-tight metal pipe and
fittings that are adequately protected from corrosion.
[[Page 57]]
(c) Plastic pipe must be installed so as to minimize shear or
tensile stresses.
(d) Thermoplastic pipe that is not encased must have a minimum wall
thickness of 0.090 inch (2.29 millimeters), except that pipe with an
outside diameter of 0.875 inch (22.3 millimeters) or less may have a
minimum wall thickness of 0.062 inch (1.58 millimeters).
(e) Plastic pipe that is not encased must have an electrically
conductive wire or other means of locating the pipe while it is
underground.
(f) Plastic pipe that is being encased must be inserted into the
casing pipe in a manner that will protect the plastic. The leading end
of the plastic must be closed before insertion.
(g) Uncased plastic pipe may be temporarily installed above ground
level under the following conditions:
(1) The operator must be able to demonstrate that the cumulative
aboveground exposure of the pipe does not 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.
[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]
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.
(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
--------------------------------------------