**[New Format]{.smallcaps}**

**For future versions of this manual, changes to the regulations will
show a [highlight]{.mark} for deletions and an underline for
[additions]{.underline}.**

**[Amendment Table of Section Revisions for This Version of Part
192]{.smallcaps}**

  -- ----------------------- ----------------- -------------------------- ------------ ----------------------- ------------------------ -------------------- ----------------------------
     **[Part 192 Amendment                     **[Effective Date of                    **[Paragraph\                                    **[In Refference     
     Number]{.smallcaps}**                     Amendment]{.smallcaps}**                Impact]{.smallcaps}**                            to:]{.smallcaps}**   

                             No Number                                    05/23/07                             192.143, .476                                 [Internal Corrosion --
                                                                                                                                                             Design &
                                                                                                                                                             Construction]{.smallcaps}

                             192-104                                      08/16/07                             192.933                                       [IMP
                                                                                                                                                             Modifications]{.smallcaps}

                             192-\[105\]\*                                01/14/08                             192.616                                       [Public Awareness
                                                                                                                                                             Programs]{.smallcaps}

                             192-\[106\]\*                                04/28/08                             192.7, .727, .949, .951                       [Administrative Procedures,
                                                                                                                                                             Updates and Technical
                                                                                                                                                             Amendments]{.smallcaps}

                             192-\[107\]\*                                11/17/08                             192.7, .112, .328, .611,                      [Standards for Increasing
                                                                                                               .619, .620                                    the Maximum Allowable
                                                                                                                                                             Operating Pressure for Gas
                                                                                                                                                             Transmission
                                                                                                                                                             Pipelines]{.smallcaps}
  -- ----------------------- ----------------- -------------------------- ------------ ----------------------- ------------------------ -------------------- ----------------------------

\*PHMSA quit numbering their new amendments. For the purposes of
tracking, T&Q is maintaining a numbering system.

**Copies of 49 CFR Parts 190 through 199 and Part 40 are available for
download at: *http://www.phmsa.dot.gov.***

**Subpart A--General**

***Section***

192.1 What is the scope of this part?

192.3 Definitions.

192.5 Class locations.

192.7 What documents are incorporated by reference partly or wholly in
this part?

192.8 How are onshore gathering lines and regulated onshore gathering
lines determined?

192.9 What requirements apply to gathering lines?

192.10 Outer Continental Shelf pipelines.

192.11 Petroleum gas systems.

192.13 What general requirements apply to pipelines regulated under this
part?

192.14 Conversion to service subject to this part.

192.15 Rules of regulatory construction.

192.16 Customer notification.

192.17 \[Reserved\]

**Subpart B--Materials**

192.51 Scope.

192.53 General.

192.55 Steel pipe.

192.57 \[Reserved\]

192.59 Plastic pipe.

192.61 \[Reserved\]

192.63 Marking of materials.

192.65 Transportation of pipe.

**Subpart C--Pipe Design**

192.101 Scope.

192.103 General.

192.105 Design formula for steel pipe.

192.107 Yield strength (S) for steel pipe.

192.109 Nominal wall thickness (t) for steel pipe.

192.111 Design factor (F) for steel pipe.

[192.112]{.underline} [Additional design requirements for steel pipe
using alternative maximum allowable operating pressure.]{.underline}

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 pressure relief and limiting devices.

192.201 Required capacity of pressure relieving and limiting stations.

192.203 Instrument, control, and sampling pipe and components.

**Subpart E--Welding of Steel in Pipelines**

192.221 Scope.

192.225 Welding procedures.

192.227 Qualification of welders.

192.229 Limitations on welders.

192.231 Protection from weather.

192.233 Miter joints.

192.235 Preparation for welding.

192.241 Inspection and test of welds.

192.243 Nondestructive testing.

192.245 Repair or removal of defects.

**Subpart F--Joining of Materials Other Than by Welding**

192.271 Scope.

192.273 General.

192.275 Cast iron pipe.

192.277 Ductile iron pipe.

192.279 Copper pipe.

192.281 Plastic pipe.

192.283 Plastic pipe; Qualifying joining procedures.

192.285 Plastic pipe: Qualifying persons to make joints.

192.287 Plastic pipe: Inspection of joints.

**Subpart G--General Construction Requirements for Transmission Lines
and Mains**

192.301 Scope.

192.303 Compliance with specifications or standards.

192.305 Inspection: General.

192.307 Inspection of materials.

192.309 Repair of steel pipe.

192.311 Repair of plastic pipe.

192.313 Bends and elbows.

192.315 Wrinkle bends in steel pipe.

192.317 Protection from hazards.

192.319 Installation of pipe in a ditch.

192.321 Installation of plastic pipe.

192.323 Casing.

192.325 Underground clearance.

327. Cover.

[192.328]{.underline} [Additional construction requirements for steel
pipe using alternative maximum allowable operating
pressure.]{.underline}

**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.

381. Service lines: Excess flow valve performance standards.

192.383 Excess flow valve customer notification

**Subpart I--Requirements for Corrosion Control**

192.451 Scope.

192.452 How does this subpart apply to converted pipelines and regulated
onshore gathering lines?

192.453 General.

192.455 External corrosion control: Buried or submerged pipelines
installed after July 31, 1971.

192.457 External corrosion control: Buried or submerged pipelines
installed before August 1, 1971.

192.459 External corrosion control: Examination of buried pipeline when
exposed.

192.461 External corrosion control: Protective coating.

192.463 External corrosion control: Cathodic protection.

192.465 External corrosion control: Monitoring.

192.467 External corrosion control: Electrical isolation.

192.469 External corrosion control: Test stations.

192.471 External corrosion control: Test leads.

192.473 External corrosion control: Interference currents.

192.475 Internal corrosion control: General.

[192.476]{.underline} [Internal corrosion control: Design and
construction of transmission line.]{.underline}

192.477 Internal corrosion control: Monitoring.

192.479 Atmospheric corrosion control: General.

192.481 Atmospheric corrosion control: Monitoring.

192.483 Remedial measures: General.

192.485 Remedial measures: Transmission lines.

192.487 Remedial measures: Distribution lines other than cast iron or
ductile iron lines.

192.489 Remedial measures: Cast iron and ductile iron pipelines.

192.490 Direct assessment.

192.491 Corrosion control records.

**Subpart J--Test Requirements**

192.501 Scope.

192.503 General requirements.

192.505 Strength test requirements for steel pipeline to operate at a
hoop stress of 30 percent or more of SMYS.

192.507 Test requirements for pipelines to operate at a hoop stress less
than 30 percent of SMYS and above 100 psig.

192.509 Test requirements for pipelines to operate below 100 psig.

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 \[Removed\]

192.609 Change in class location: Required study.

192.611 Change in class location: Confirmation or revision of maximum
allowable operating pressure.

192.612 Underwater inspection and reburial of pipelines in the Gulf of
Mexico and its inlets.

192.613 Continuing surveillance.

192.614 Damage prevention program.

192.615 Emergency plans.

192.616 Public awareness.

192.617 Investigation of failures.

192.619 What is the maximum allowable operating pressure for steel or
plastic pipelines?

[192.620]{.underline} [Alternative maximum allowable operating pressure
for certain steel pipelines.]{.underline}

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 and procedures.

192.725 Test requirements for reinstating service lines.

192.727 Abandonment or deactivation of facilities.

192.729 \[Removed\]

192.731 Compressor stations: Inspection and testing of relief devices.

192.733 \[Removed\]

192.735 Compressor stations: Storage of combustible materials.

192.736 Gas detection and monitoring in compressor station buildings.

192.737 \[Removed\]

192.739 Pressure limiting and regulating stations: Inspection and
testing.

192.741 Pressure limiting and regulating stations: Telemetering or
recording gages.

192.743 Pressure limiting and regulating stations: Capacity of relief
devices.

192.745 Valve maintenance: Transmission lines.

192.747 Valve maintenance: Distribution systems.

192.749 Vault maintenance.

192.751 Prevention of accidental ignition.

192.753 Caulked bell and spigot joints.

192.755 Protecting cast iron pipelines.

**Subpart N--Qualification of Pipeline Personnel**

192.801 Scope.

192.803 Definitions.

192.805 Qualification Program.

192.807 Recordkeeping.

192.809 General.

**Subpart O---Gas Transmission Pipeline Integrity Management**

192.901 What do the regulations in this subpart cover?

192.903 What definitions apply to this subpart?

192.905 How does an operator identify a high consequence area?

192.907 What must an operator do to implement this subpart?

192.909 How can an operator change its integrity management program?

192.911 What are the elements of an integrity management program?

192.913 When may an operator deviate its program from certain
requirements of this subpart?

192.915 What knowledge and training must personnel have to carry out an
integrity management program?

192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?

192.919 What must be in the baseline assessment plan?

192.921 How is the baseline assessment to be conducted?

192.923 How is direct assessment used and for what threats?

192.925 What are the requirements for using External Corrosion Direct
Assessment (ECDA)?

192.927 What are the requirements for using Internal Corrosion Direct
Assessment (ICDA)?

192.929 What are the requirements for using Direct Assessment for Stress
Corrosion Cracking (SCCDA)?

192.931 How may Confirmatory Direct Assessment (CDA) be used?

192.933 What actions must be taken to address integrity issues?

192.935 What additional preventive and mitigative measures must an
operator take?

192.937 What is a continual process of evaluation and assessment to
maintain a pipeline\'s integrity?

192.939 What are the required reassessment intervals?

192.941 What is a low stress reassessment?

192.943 When can an operator deviate from these reassessment intervals?

192.945 What methods must an operator use to measure program
effectiveness?

192.947 What records must an operator keep?

192.949 How does an operator notify OPS?

192.951 Where does an operator file a report?

**Appendix A --** \[Reserved\]

**Appendix B --** Qualification of Pipe.

**Appendix C --** Qualification of Welders for Low Stress Level Pipe.

**Appendix D --** Criteria for Cathodic Protection and Determination of
Measurements.

**Appendix E to Part 192---**Guidance on Determining High Consequence
Areas and on Carrying Out Requirements in the Integrity Management Rule

**Authority:** 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113,
and 60118; and 49 CFR 1.53.

# Subpart A--General

**§192.1 What is the scope of this part?**

\(a\) This part prescribes minimum safety requirements for pipeline
facilities and the transportation of gas, including pipeline facilities
and the transportation of gas within the limits of the outer continental
shelf as that term is defined in the Outer Continental Shelf Lands Act
(43 U.S.C. 1331).

\(b\) This part does not apply to---

\(1\) Offshore gathering of gas in State waters upstream from the outlet
flange of each facility where hydrocarbons are produced or where
produced hydrocarbons are first separated, dehydrated, or otherwise
processed, whichever facility is farther downstream;

\(2\) Pipelines on the Outer Continental Shelf (OCS) that are
producer-operated and cross into State waters without first connecting
to a transporting operator\'s facility on the OCS, upstream (generally
seaward) of the last valve on the last production facility on the OCS.
Safety equipment protecting PHMSA-regulated pipeline segments is not
excluded. Producing operators for those pipeline segments upstream of
the last valve of the last production facility on the OCS may petition
the Administrator, or designee, for approval to operate under PHMSA
regulations governing pipeline design, construction, operation, and
maintenance under 49 CFR 190.9;

\(3\) Pipelines on the Outer Continental Shelf upstream of the point at
which operating responsibility transfers from a producing operator to a
transporting operator;

\(4\) Onshore gathering of gas--

\(i\) Through a pipeline that operates at less than 0 psig (0 kPa);

\(ii\) Through a pipeline that is not a regulated onshore gathering line
(as determined in §192.8); and

\(iii\) Within inlets of the Gulf of Mexico, except for the requirements
in §192.612; or

\(5\) Any pipeline system that transports only petroleum gas or
petroleum gas/air mixtures to---

\(i\) Fewer than 10 customers, if no portion of the system is located in
a public place; or

\(ii\) A single customer, if the system is located entirely on the
customer\'s premises (no matter if a portion of the system is located in
a public place).

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-67, 56 FR 63764, Dec. 5, 1991; Amdt.
192-78, 61 FR 28770, June 6, 1996; Amdt. 192-81, 62 FR 61692, Nov. 19,
1997; Amdt. 192-92, 68 FR 46109, Aug. 5, 2003; 70 FR 11135, Mar. 8,
2005, Amdt. 192-102, 71 FR 13289, Mar. 15, 2006; Amdt. 192-103c, 72 FR
4655, Feb. 1, 2007\]

**§192.3 Definitions.**

As used in this part:

***Abandoned*** means permanently removed from service.

***Administrator*** means the Administrator, Pipeline and Hazardous
Materials Safety Administration or his or her delegate.

***Customer meter*** means the meter that measures the transfer of gas
from an operator to a consumer.

***Distribution Line*** means a pipeline other than a gathering or
transmission line.

***Exposed underwater pipeline*** means an underwater pipeline where the
top of the pipe protrudes above the underwater natural bottom (as
determined by recognized and generally accepted practices) in waters
less than 15 feet (4.6 meters) deep, as measured from mean low water.

***Gas*** means natural gas, flammable gas, or gas which is toxic or
corrosive.

***Gathering Line*** means a pipeline that transports gas from a current
production facility to a transmission line or main.

***Gulf of Mexico and its inlets*** means the waters from the mean high
water mark of the coast of the Gulf of Mexico and its inlets open to the
sea (excluding rivers, tidal marshes, lakes, and canals) seaward to
include the territorial sea and Outer Continental Shelf to a depth of 15
feet (4.6 meters), as measured from the mean low water.

***Hazard to navigation*** means, for the purpose of this part, a
pipeline where the top of the pipe is less than 12 inches (305
millimeters) below the underwater natural bottom (as determined by
recognized and generally accepted practices) in 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.

***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) at 100°F (38°C).

***Pipe*** means any pipe or tubing used in the transportation of gas,
including pipe-type holders.

***Pipeline*** means all parts of those physical facilities through
which gas moves in transportation, including pipe, valves, and other
appurtenance attached to pipe, compressor units, metering stations,
regulator stations, delivery stations, holders, and fabricated
assemblies.

***Pipeline facility*** means new and existing pipeline, rights-of-way,
and any equipment, facility, or building used in the transportation of
gas or in the treatment of gas during the course of transportation.

***Service Line*** means a distribution line that transports gas from a
common source of supply to an individual customer, to two adjacent or
adjoining residential or small commercial customers, or to multiple
residential or small commercial customers served through a meter header
or manifold. A service line ends at the outlet of the customer meter or
at the connection to a customer\'s piping, whichever is further
downstream, or at the connection to customer piping if there is no
meter.

***Service regulator*** means the device on a service line that controls
the pressure of gas delivered from a higher pressure to the pressure
provided to the customer. A service regulator may serve one customer or
multiple customers through a meter header or manifold.

***SMYS*** means specified minimum yield strength is:

\(a\) For steel pipe manufactured in accordance with a listed
specification, the yield strength specified as a minimum in that
specification; or

\(b\) For steel pipe manufactured in accordance with an unknown or
unlisted specification, the yield strength determined in accordance with
§192.107(b)

***State*** means each of the several States, the District of Columbia,
and the Commonwealth of Puerto Rico.

***Transmission line*** means a pipeline, other than a gathering line,
that: (1) transports gas from a gathering line or storage facility to a
gas distribution center, storage facility, or large volume customer that
is not down-stream from a gas distribution center; (2) operates at a
hoop stress of 20 percent or more of SMYS; or (3) transports gas within
a storage field.

**Note:** A large volume customer may receive similar volumes of gas as
a distribution center, and includes factories, power plants, and
institutional users of gas.

***Transportation of gas*** means the gathering, transmission, or
distribution of gas by pipeline or the storage of gas, in or affecting
interstate or foreign commerce.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-13, 38 FR
9084, Apr. 10, 1973; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt.
192-58, 53 FR 1633, Jan. 21, 1988; Amdt. 192-67, 56 FR 63764, Dec. 5,
1991; Amdt. 192-72, 59 FR 17281, May 12, 1994; Amdt. 192-78, 61 FR
28770, June 6, 1996; Amdt. 192-81, 62 FR 61692, Nov. 19, 1997; Amdt.
192-85, 63 FR 37500, July 13, 1998; Amdt. 192-89, 65 FR 54440, Sept. 8,
2000; Amdt. 192-91, 68 FR 11748, Mar. 12, 2003; Amdt. 192-93, 68 FR
53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt.
192-98, 69 FR 48400, Aug. 10, 2004; Amdt. 192-94A, 69 FR 54591, Sept. 9,
2004; Amdt. 192-94B, 70 FR 3147, Amdt. 192-98, 69 FR 48400, Aug. 10,
2004, Jan. 21, 2005; 70 FR 11135, Mar. 8, 2005\]

**§192.5 Class locations.**

\(a\) This section classifies pipeline locations for purposes of this
part. The following criteria apply to classifications under this
section.

\(1\) A \"class location unit\" is an onshore area that extends 220
yards (200 meters) on either side of the centerline of any continuous
1-mile (1.6 kilometers) length of pipeline.

\(2\) Each separate dwelling unit in a multiple dwelling unit building
is counted as a separate building intended for human occupancy.

\(b\) Except as provided in paragraph (c) of this section, pipeline
locations are classified as follows:

\(1\) A Class 1 location is:

\(i\) An offshore area; or

\(ii\) Any class location unit that has 10 or fewer buildings intended
for human occupancy.

\(2\) A Class 2 location is any class location unit that has more than
10 but fewer than 46 buildings intended for human occupancy.

\(3\) A Class 3 location is:

\(i\) Any class location unit that has 46 or more buildings intended for
human occupancy; or

\(ii\) An area where the pipeline lies within 100 yards (91 meters) of
either a building or a small, well-defined outside area (such as a
playground, recreation area, outdoor theater, or other place of public
assembly) that is occupied by 20 or more persons on at least 5 days a
week for 10 weeks in any 12-month period. (The days and weeks need not
be consecutive.)

\(4\) A Class 4 location is any class location unit where buildings with
four or more stories above ground are prevalent.

\(c\) The length of Class locations 2, 3, and 4 may be adjusted as
follows:

\(1\) A Class 4 location ends 220 yards (200 meters) from the nearest
building with four or more stories above ground.

\(2\) When a cluster of buildings intended for human occupancy requires
a Class 2 or 3 location, the class location ends 220 yards (200 meters)
from the nearest building in the cluster.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-56, 52 FR 32924, Sept. 1, 1987; Amdt.
192-78, 61 FR 28770, June 6, 1996; Amdt. 192-78B, 61 FR 35139, July 5,
1996; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.7 What documents are incorporated by reference partly or wholly
in this part?**

\(a\) Any documents or portions thereof incorporated by reference in
this part are included in this part as though set out in full. When only
a portion of a document is referenced, the remainder is not incorporated
in this part.

\(b\) All incorporated materials are available for inspection in the
Pipeline and Hazardous Materials Safety Administration, [400 Seventh
Street, SW]{.mark}[1200 New Jersey Avenue, SE.]{.underline}, Washington,
DC, or at the National Archives and Records Administration (NARA). For
information on the availability of this material at NARA, call
202-741-6030 or go to:
*http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html*.
These materials have been approved for incorporation by reference by the
Director of the Federal Register in accordance with 5 U.S.C. 552(a) and
1 CFR part 51. In addition, the incorporated materials are available
from the respective organizations listed in paragraph (c) (1) of this
section.

\(c\) The full titles of documents incorporated by reference, in whole
or in part, are provided herein. The numbers in parentheses indicate
applicable editions. For each incorporated document, citations of all
affected sections are provided. Earlier editions of currently listed
documents or editions of documents listed in previous editions of 49 CFR
Part 192 may be used for materials and components designed,
manufactured, or installed in accordance with these earlier documents at
the time they were listed. The user must refer to the appropriate
previous edition of 49 CFR Part 192 for a listing of the earlier listed
editions or documents.

\(1\) Incorporated by reference (IBR).

List of Organizations and Addresses.

A. Pipeline Research Council International, Inc. (PRCI), c/o Technical
Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX 77098.

B. American Petroleum Institute (API), 1220 L Street, NW., Washington,
DC 20005.

C. American Society for Testing and Materials (ASTM), 100 Barr Harbor
Drive, West Conshohocken, PA 19428.

D. ASME International (ASME), Three Park Avenue, New York, NY
10016-5990.

E. Manufacturers Standardization Society of the Valve and Fittings
Industry, Inc. (MSS), 127 Park Street, NE., Vienna, VA 22180.

F. National Fire Protection Association (NFPA), 1 Batterymarch Park,
P.O. Box 9101, Quincy, MA 02269-9101.

G. Plastics Pipe Institute, Inc. (PPI), 1825 Connecticut Avenue, NW.,
Suite 680, Washington, DC 20009.

H. NACE International (NACE), 1440 South Creek Drive, Houston, TX 77084.

I. Gas Technology Institute (GTI), 1700 South Mount Prospect Road, Des
Plaines, IL 60018.

\(2\) Documents incorporated by reference.

+---------------------------------------------+------------------------+
| Source and name of referenced material      | 49 CFR reference       |
+---------------------------------------------+------------------------+
| A. Pipeline Research Council International  | §§ 192.933(a);         |
| (PRCI):                                     | 192.485(c).            |
|                                             |                        |
| \(1\) AGA Pipeline Research                 |                        |
| Committee,Project PR-3-805, "A Modified     |                        |
| Criterion for Evaluating the Remaining      |                        |
| Strength of Corroded Pipe,"(December 22,    |                        |
| 1989) .The RSTRENG program may be used for  |                        |
| calculating remaining strength.             |                        |
+---------------------------------------------+------------------------+
| B. American Petroleum Institute (API):      | §§ 192.55(e);          |
|                                             | [192.112]{.underline}, |
| \(1\) API Specification 5L "Specification   | 192.113; Item I of     |
| for Line Pipe" (43rd edition and errata,    | Appendix B.            |
| 2004)).                                     |                        |
+---------------------------------------------+------------------------+
| \(2\) API Recommended Practice 5L1          | §192.65(a).            |
| "Recommended Practice for Railroad          |                        |
| Transportation of Line Pipe" (6th edition,  |                        |
| 2002).                                      |                        |
+---------------------------------------------+------------------------+
| \(3\) API Specification 6D "Pipeline        | §192.145(a).           |
| Valves,\'\' (22nd edition, January 2002).   |                        |
+---------------------------------------------+------------------------+
| \(4\) API Recommended Practice 80 (API RP   | §192.8(a);             |
| 80) "Guidelines for the Definition of       | 192.8(a)(1);           |
| Onshore Gas Gathering Lines\'\' (1st        | 192.8(a)(2);           |
| edition, April 2000)                        | 192.8(a)(3);           |
|                                             | 192.8(a)(4).           |
+---------------------------------------------+------------------------+
| \(5\) API 1104 "Welding of Pipelines and    | §§ 192.227(a);         |
| Related Facilities" (19th edition, 1999,    | 192.229(c)(1);         |
| including Errata October 31, 2001 ).        | 192.241(c); Item II,   |
|                                             | Appendix B .           |
+---------------------------------------------+------------------------+
| \(6\) API Recommended Practice 1162 "Public | §192.616(a)            |
| Awareness Programs for Pipeline Operators," | 192.616(b);            |
| (1st edition, December 2003)                | 192.616(c).            |
+---------------------------------------------+------------------------+
| C. American Society for Testing and         | §§ 192.113;Item I,     |
| Materials (ASTM):                           | Appendix B             |
|                                             |                        |
| \(1\) ASTM Designation: A 53/A53M-04a       |                        |
| (2004) "Standard Specification for Pipe,    |                        |
| Steel, Black and Hot-Dipped, Zinc Coated,   |                        |
| Welded and Seamless" .                      |                        |
+---------------------------------------------+------------------------+
| \(2\) ASTM Designation: A106/A106M-04b      | §192.113; Item I,      |
| (2004) "Standard Specification for Seamless | Appendix B .           |
| Carbon Steel Pipe for High-Temperature      |                        |
| Service" .                                  |                        |
+---------------------------------------------+------------------------+
| \(3\) ASTM Designation: A333/A333M-05       | §192.113; Item I,      |
| (2005) "Standard Specification for Seamless | Appendix B .           |
| and Welded Steel Pipe for Low- Temperature  |                        |
| Service" .                                  |                        |
+---------------------------------------------+------------------------+
| \(4\) ASTM Designation: A372/A372M-03       | §192.177(b)(1).        |
| (2003) "Standard Specification for Carbon   |                        |
| and Alloy Steel Forgings for Thin-Walled    |                        |
| Pressure Vessels" .                         |                        |
+---------------------------------------------+------------------------+
| \(5\) ASTM Designation: A381-96 (Reapproved | §192.113; Item I,      |
| 2001) "Standard Specification for           | Appendix B .           |
| Metal-Arc-Welded Steel Pipe for Use With    |                        |
| High-Pressure Transmission Systems" .       |                        |
+---------------------------------------------+------------------------+
| [(6) ASTM Designation: A 578/A578M-96 (Re-  | [§192.112(c)           |
| approved 2001) "Standard Specification for  | (2)(iii).]{.underline} |
| Straight-Beam Ultrasonic Examination of     |                        |
| Plain and Clad Steel Plates for Special     |                        |
| Applications".]{.underline}                 |                        |
+---------------------------------------------+------------------------+
| ([7]{.underline}[6]{.mark}) ASTM            | §192.113; Item I,      |
| Designation: A671-04 (2004) "Standard       | Appendix B .           |
| Specification for Electric-Fusion-Welded    |                        |
| Steel Pipe for Atmospheric and Lower        |                        |
| Temperatures".                              |                        |
+---------------------------------------------+------------------------+
| ([8]{.underline}[7]{.mark}) ASTM            | §192.113; Item I,      |
| Designation: A672-96 (Reapproved 2001)      | Appendix B .           |
| "Standard Specification for                 |                        |
| Electric-Fusion-Welded Steel Pipe for       |                        |
| High-Pressure Service at Moderate           |                        |
| Temperatures" (A672-1996).                  |                        |
+---------------------------------------------+------------------------+
| ([9]{.underline}[8]{.mark}) ASTM            | §192.113; Item I,      |
| Designation: A691 "Standard Specification   | Appendix B .           |
| for Carbon and Alloy Steel Pipe,            |                        |
| Electric-Fusion-Welded for High- Pressure   |                        |
| Service at High Temperatures" .             |                        |
+---------------------------------------------+------------------------+
| ([10]{.underline}[9]{.mark}) ASTM           | §§ 192.283(a)(3);      |
| Designation: D638-03 "Standard Test Method  | 192.283(b)(1).         |
| for Tensile Properties of Plastics" .       |                        |
+---------------------------------------------+------------------------+
| ([11]{.underline}[10]{.mark}) ASTM          | §192.63(a)(1).         |
| Designation: D2513-87 "Standard             |                        |
| Specification for Thermoplastic Gas         |                        |
| Pressure Pipe, Tubing, and Fittings" .      |                        |
+---------------------------------------------+------------------------+
| ([12]{.underline}[11]{.mark}) ASTM          | §§ 192.191(b);         |
| Designation: D2513-99 "Standard             | 192.281(b)(2);         |
| Specification for Thermoplastic Gas         | 192.283(a)(1)(i); Item |
| Pressure Pipe, Tubing, and Fittings .       | I, Appendix B .        |
+---------------------------------------------+------------------------+
| ([13]{.underline}[12]{.mark}) ASTM          | §§ 192.191(a);         |
| Designation: D 2517-00 "Standard            | 192.281(d)(1);         |
| Specification for Reinforced Epoxy Resin    | 192.283(a)(1)(ii);     |
| Gas Pressure Pipe and Fittings" .           | Item I, Appendix B .   |
+---------------------------------------------+------------------------+
| ([14]{.underline}[13]{.mark}) ASTM          | §192.283(a)(1)(iii).   |
| Designation: F1055-1998 "Standard           |                        |
| Specification for Electrofusion Type        |                        |
| Polyethylene Fittings for Outside Diameter  |                        |
| Controlled Polyethylene Pipe and Tubing" .  |                        |
+---------------------------------------------+------------------------+
| D. ASME International (ASME):               | §192.147(c).           |
|                                             |                        |
| \(1\) ASME B16.1-1998 "Cast Iron Pipe       |                        |
| Flanges and Flanged Fittings" .             |                        |
+---------------------------------------------+------------------------+
| \(2\) ASME B16.5-2003 (October 2004) "Pipe  | §§ 192.147(a);         |
| Flanges and Flanged Fittings" .             | 192.279.               |
+---------------------------------------------+------------------------+
| \(3\) ASME B31G-1991 (Reaffirmed; 2004)     | §§ 192.485(c);         |
| "Manual for Determining the Remaining       | 192.933(a).            |
| Strength of Corroded Pipelines" .           |                        |
+---------------------------------------------+------------------------+
| \(4\) ASME B31.8-2003 (February 2004) "Gas  | §192.619(a)(1)(i).     |
| Transmission and Distribution Piping        |                        |
| Systems" .                                  |                        |
+---------------------------------------------+------------------------+
| \(5\) ASME B31.8S-2004 "Supplement to B31.8 | §§ 192.903(c);         |
| on Managing System Integrity of Gas         | 192.907(b); 192.911,   |
| Pipelines"                                  | Introductory text;     |
|                                             | 192.911(i);            |
|                                             | 192.911(k);            |
|                                             | 192.911(l);            |
|                                             | 192.911(m); 192.913(a) |
|                                             | Introductory text;     |
|                                             | 192.913(b)(1);         |
|                                             | 192.917(a)             |
|                                             | Introductory text;     |
|                                             | 192.917(b);            |
|                                             | 192.917(c);            |
|                                             | 192.917(e)(1);         |
|                                             | 192.917(e)(4);         |
|                                             | 192.921(a)(1);         |
|                                             | 192.923(b)(2);         |
|                                             | 192.923(b)(3);         |
|                                             | 192.925(b)             |
|                                             | Introductory text;     |
|                                             | 192.925(b)(1);         |
|                                             | 192.925(b)(2);         |
|                                             | 192.925(b)(3);         |
|                                             | 192.925(b)(4);         |
|                                             | 192.927(b);            |
|                                             | 192.927(c)(1)(i);      |
|                                             | 192.929(b)(1);         |
|                                             | 192.929(b)(2);         |
|                                             | 192.933(a);            |
|                                             | 192.933(d)(1);         |
|                                             | 192.933(d)(1)(i);      |
|                                             | 192.935(a);            |
|                                             | 192.935(b)(1)(iv);     |
|                                             | 192.937(c)(1);         |
|                                             | 192.939(a)(1)(i);      |
|                                             | 192.939(a)(1)(ii);     |
|                                             | 192.939(a)(3);         |
|                                             | 192.945(a)..           |
+---------------------------------------------+------------------------+
| \(6\) ASME Boiler and Pressure Vessel Code, | §§ 192.153(a).         |
| Section I, "Rules for Construction of Power |                        |
| Boilers," (2004 edition, including addenda  |                        |
| through July 1, 2005).                      |                        |
+---------------------------------------------+------------------------+
| \(7\) ASME Boiler and Pressure Vessel Code, | §§ 192.153(a);         |
| Section VIII, Division 1, "Rules for        | 192.153(b);            |
| Construction of Pressure Vessels," (2004    | 192.153(d);            |
| edition, including addenda through July 1,  | 192.165(b)(3).         |
| 2005).                                      |                        |
+---------------------------------------------+------------------------+
| \(8\) ASME Boiler and Pressure Vessel Code, | §§ 192.153(b);         |
| Section VIII, Division 2, "Rules for        | 192.165(b)(3).         |
| Construction of Pressure Vessels---         |                        |
| Alternative Rules," (2004 edition,          |                        |
| including addenda through July 1, 2005).    |                        |
+---------------------------------------------+------------------------+
| \(9\) ASME Boiler and Pressure Vessel Code, | §192.227(a); Item II,  |
| Section IX, "Welding and Brazing            | Appendix B .           |
| Qualifications," (2004 edition, including   |                        |
| addenda through July 1, 2005).              |                        |
+---------------------------------------------+------------------------+
| E. Manufacturers Standardization Society of | §192.147(a).           |
| the Valve and Fittings Industry, Inc.       |                        |
| (MSS):                                      |                        |
|                                             |                        |
| \(1\) MSS SP44-1996 (Reaffirmed; 2001)      |                        |
| "Steel Pipe Line Flanges"                   |                        |
|                                             |                        |
| \(2\) \[Reserved\]                          |                        |
+---------------------------------------------+------------------------+
| F. National Fire Protection Association     | §192.735(b).           |
| (NFPA):                                     |                        |
|                                             |                        |
| \(1\) NFPA 30 (2003)"Flammable and          |                        |
| Combustible Liquids Code" .                 |                        |
+---------------------------------------------+------------------------+
| \(2\) NFPA 58 (2004) "Liquefied Petroleum   | §192.11(a); 192.11(b); |
| Gas Code (LP-Gas Code)" .                   | 192.11(c).             |
+---------------------------------------------+------------------------+
| \(3\) NFPA 59 (2004) "Utility LP-Gas Plant  | §192.11(a); 192.11(b); |
| Code.\'\'.                                  | 192.11(c).             |
+---------------------------------------------+------------------------+
| \(4\) NFPA 70 (2005) "National Electrical   | §§ 192.163(e);         |
| Code" .                                     | 192.189(c).            |
+---------------------------------------------+------------------------+
| G. Plastics Pipe Institute, Inc. (PPI):     | §192.121.              |
|                                             |                        |
| \(1\) PPI TR-3/2004 (2004) "Policies and    |                        |
| Procedures for Developing Hydrostatic       |                        |
| Design Bases (HDB), Pressure Design Bases   |                        |
| (PDB), Strength Design Basis (SDB), and     |                        |
| Minimum Required Strength (MRS) Ratings for |                        |
| Thermoplastic Piping Materials or Pipe.".   |                        |
+---------------------------------------------+------------------------+
| H. NACE International (NACE):               | §§ 192.923(b)(1);      |
|                                             | 192.925(b)             |
| \(1\) NACE Standard RP-0502-2002 "Pipeline  | Introductory text;     |
| External Corrosion Direct Assessment        | 192.925(b)(1);         |
| Methodology" .                              | 192.925(b)(1)(ii);     |
|                                             | 192.925(b)(2)          |
|                                             | Introductory text;     |
|                                             | 192.925(b)(3)          |
|                                             | Introductory text;     |
|                                             | 192.925(b)(3)(ii);     |
|                                             | 192.925(b)(iv);        |
|                                             | 192.925(b)(4)          |
|                                             | Introductory text;     |
|                                             | 192.925(b)(4)(ii);     |
|                                             | 192.931(d);            |
|                                             | 192.935(b)(1)(iv);     |
|                                             | 192.939(a)(2).         |
+---------------------------------------------+------------------------+
| I. Gas Technology Institute (GTI).          | §§ 192.927(c)(2);      |
| (Formerly Gas Research Institute):          | 192.7.                 |
|                                             |                        |
| \(1\) GRI 02/0057 (2002) "Internal          |                        |
| Corrosion Direct Assessment of Gas          |                        |
| Transmission Pipelines---Methodology" .     |                        |
+---------------------------------------------+------------------------+

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR
10157, Feb. 2, 1981; Amdt. 192-51, 51 FR 15333, Apr. 23, 1986; Amdt.
192-68, 58 FR, 14519, Mar. 18, 1993; Amdt. 192-78, 61 FR 28770, June 6,
1996; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-94A, 69 FR
54591, Sept. 9, 2004; 70 FR 11135, Mar. 8, 2005; Amdt. 192-99, 70 FR
28833, May 19, 2005, Amdt. 192-102, 71 FR 13289, Mar. 15, 2006; Amdt.
192-103, 71 FR 33402, June 8, 2006; Amdt. 192-103c, 72 FR 4655, Feb. 1,
2007[; Amdt. 192-\[106\], 73 FR 16562, Mar. 28, 2008]{.underline};
[Amdt. 192-\[107\], 73 FR 62147, October 17, 2008]{.underline}\]

**§192.8 How are onshore gathering lines and regulated onshore gathering
lines determined?**

\(a\) An operator must use API RP 80 (incorporated by reference, see
§192.7), to determine if an onshore pipeline (or part of a connected
series of pipelines) is an onshore gathering line. The determination is
subject to the limitations listed below. After making this
determination, an operator must determine if the onshore gathering line
is a regulated onshore gathering line under paragraph (b) of this
section.

\(1\) The beginning of gathering, under section 2.2(a)(1) of API RP 80,
may not extend beyond the furthermost downstream point in a production
operation as defined in section 2.3 of API RP 80. This furthermost
downstream point does not include equipment that can be used in either
production or transportation, such as separators or dehydrators, unless
that equipment is involved in the processes of "production and
preparation for transportation or delivery of hydrocarbon gas\'\' within
the meaning of "production operation.\'\'

\(2\) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP
80, may not extend beyond the first downstream natural gas processing
plant, unless the operator can demonstrate, using sound engineering
principles, that gathering extends to a further downstream plant.

\(3\) If the endpoint of gathering, under section 2.2(a)(1)(C) of API RP
80, is determined by the commingling of gas from separate production
fields, the fields may not be more than 50 miles from each other, unless
the Administrator finds a longer separation distance is justified in a
particular case (see 49 CFR §190.9).

\(4\) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP
80, may not extend beyond the furthermost downstream compressor used to
increase gathering line pressure for delivery to another pipeline.

\(b\) For purposes of §192.9, "regulated onshore gathering line\'\'
means:

\(1\) Each onshore gathering line (or segment of onshore gathering line)
with a feature described in the second column that lies in an area
described in the third column; and

\(2\) As applicable, additional lengths of line described in the fourth
column to provide a safety buffer:

+------+--------------------------+-----------------+-----------------+
| Type | Feature                  | Area            | Safety buffer   |
+------+--------------------------+-----------------+-----------------+
| A    | ---Metallic and the MAOP | Class 2, 3, or  | None.           |
|      | produces a hoop stress   | 4 location (see |                 |
|      | of 20 percent or more of | § 192.5).       |                 |
|      | SMYS. If the stress      |                 |                 |
|      | level is unknown, an     |                 |                 |
|      | operator must determine  |                 |                 |
|      | the stress level         |                 |                 |
|      | according to the         |                 |                 |
|      | applicable provisions in |                 |                 |
|      | subpart C of this part.  |                 |                 |
|      |                          |                 |                 |
|      | ---Non-metallic and the  |                 |                 |
|      | MAOP is more than 125    |                 |                 |
|      | psig (862 kPa).          |                 |                 |
+------+--------------------------+-----------------+-----------------+
| B    | ---Metallic and the MAOP | *Area 1*. Class | If the          |
|      | produces a hoop stress   | 3 or 4          | gathering line  |
|      | of less than 20 percent  | location.       | is in Area 2(b) |
|      | of SMYS. If the stress   |                 | or 2(c), the    |
|      | level is unknown, an     | *Area 2.* An    | additional      |
|      | operator must determine  | area within a   | lengths of line |
|      | the stress level         | Class 2         | extend upstream |
|      | according to the         | location the    | and downstream  |
|      | applicable provisions in | operator        | from the area   |
|      | subpart C of this part.  | determines by   | to a point      |
|      |                          | using any of    | where the line  |
|      | ---Non-metallic and the  | the following   | is at least 150 |
|      | MAOP is 125 psig (862    | three methods:  | feet (45.7 m)   |
|      | kPa) or less.            |                 | from the        |
|      |                          | \(a\) A Class 2 | nearest         |
|      |                          | location.       | dwelling in the |
|      |                          |                 | area. However,  |
|      |                          | \(b\) An area   | if a cluster of |
|      |                          | extending 150   | dwellings in    |
|      |                          | feet (45.7 m)   | Area 2 (b) or   |
|      |                          | on each side of | 2(c) qualifies  |
|      |                          | the centerline  | a line as Type  |
|      |                          | of any          | B, the Type B   |
|      |                          | continuous 1    | classification  |
|      |                          | mile (1.6 km)   | ends 150 feet   |
|      |                          | of pipeline and | (45.7 m) from   |
|      |                          | including more  | the nearest     |
|      |                          | than 10 but     | dwelling in the |
|      |                          | fewer than 46   | cluster.        |
|      |                          | dwellings.      |                 |
|      |                          |                 |                 |
|      |                          | \(c\) An area   |                 |
|      |                          | extending 150   |                 |
|      |                          | feet (45.7 m)   |                 |
|      |                          | on each side of |                 |
|      |                          | the centerline  |                 |
|      |                          | of any          |                 |
|      |                          | continous 1000  |                 |
|      |                          | feet (305 m) of |                 |
|      |                          | pipeline and    |                 |
|      |                          | including 5 or  |                 |
|      |                          | more dwellings. |                 |
+------+--------------------------+-----------------+-----------------+

\[Amdt. 192-102, 71 FR 13289, Mar. 15, 2006\]

**§192.9 What requirements apply to gathering lines?**

\(a\) *Requirements.* An operator of a gathering line must follow the
safety requirements of this part as prescribed by this section.

\(b\) *Offshore lines.* An operator of an offshore gathering line must
comply with requirements of this part applicable to transmission lines,
except the requirements in §192.150 and in subpart O of this part.

\(c\) *Type A lines.* An operator of a Type A regulated onshore
gathering line must comply with the requirements of this part applicable
to transmission lines, except the requirements in §192.150 and in
subpart O of this part. However, an operator of a Type A regulated
onshore gathering line in a Class 2 location may demonstrate compliance
with subpart N by describing the processes it uses to determine the
qualification of persons performing operations and maintenance tasks.

\(d\) *Type B lines.* An operator of a Type B regulated onshore
gathering line must comply with the following requirements:

\(1\) If a line is new, replaced, relocated, or otherwise changed, the
design, installation, construction, initial inspection, and initial
testing must be in accordance with requirements of this part applicable
to transmission lines;

\(2\) If the pipeline is metallic, control corrosion according to
requirements of subpart I of this part applicable to transmission lines;

\(3\) Carry out a damage prevention program under §192.614;

\(4\) Establish a public education program under §192.616;

\(5\) Establish the MAOP of the line under §192.619; and

\(6\) Install and maintain line markers according to the requirements
for transmission lines in §192.707.

\(e\) *Compliance deadlines.* An operator of a regulated onshore
gathering line must comply with the following deadlines, as applicable.

\(1\) An operator of a new, replaced, relocated, or otherwise changed
line must be in compliance with the applicable requirements of this
section by the date the line goes into service, unless an exception in
§192.13 applies.

\(2\) If a regulated onshore gathering line existing on April 14, 2006
was not previously subject to this part, an operator has until the date
stated in the second column to comply with the applicable requirement
for the line listed in the first column, unless the Administrator finds
a later deadline is justified in a particular case:

  --------------------------------------- -------------------------------
  Requirement                             Compliance deadline

  Control corrosion according to Subpart  April 15, 2009.
  I requirements for transmission lines.  

  Carry out a damage prevention program   October 15, 2007.
  under §192.614.                         

  Establish MAOP under §192.619           October 15, 2007.

  Install and maintain line markers under April 15, 2008.
  §192.707.                               

  Establish a public education program    April 15, 2008.
  under §192.616.                         

  Other provisions of this part as        April 15, 2009.
  required by paragraph (c) of this       
  section for Type A lines.               
  --------------------------------------- -------------------------------

\(3\) If, after April 14, 2006, a change in class location or increase
in dwelling density causes an onshore gathering line to be a regulated
onshore gathering line, the operator has 1 year for Type B lines and 2
years for Type A lines after the line becomes a regulated onshore
gathering line to comply with this section.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-72, 59 FR
17281, April 12, 1994; Amdt. 192-95B, 69 FR 18227, April 6, 2004, Amdt.
192-102, 71 FR 13289, Mar. 15, 2006\]

**§192.10 Outer continental shelf pipelines.**

Operators of transportation pipelines on the Outer Continental Shelf (as
defined in the Outer Continental Shelf Lands Act (43 U.S.C. 1331) must
identify on all their respective pipelines the specific points at which
operating responsibility transfers to a producing operator. For those
instances in which the transfer points are not identifiable by a durable
marking, each operator will have until September 15, 1998 to identify
the transfer points. If it is not practicable to durably mark a transfer
point and the transfer point is located above water, the operator must
depict the transfer point on a schematic located near the transfer
point. If a transfer point is located subsea, then the operator must
identify the transfer point on a schematic which must be maintained at
the nearest upstream facility and provided to PHMSA upon request. For
those cases in which adjoining operators have not agreed on a transfer
point by September 15, 1998 the Regional Director and the MMS Regional
Supervisor will make a joint determination of the transfer point.

\[Amdt. 192-81, 62 FR 61692, Nov. 19, 1997; 70 FR 11135, Mar. 8, 2005\]

**§192.11 Petroleum gas systems.**

\(a\) Each plant that supplies petroleum gas by pipeline to a natural
gas distribution system must meet the requirements of this part and
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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-68, 58 FR
14519, Mar. 18, 1993; Amdt. 192-75, 61 FR 18512, Apr. 26, 1996; Amdt.
192-78, 61 FR 28770, June 6, 1996\]

**192.12 \[Removed\]**

\[Amdt. 192-10, 37 FR 21638, Oct. 13, 1972 as amended by Amdt. 192-36,
45 FR 10769, Oct. 23, 1980\]

**§192.13 What general requirements apply to pipelines regulated under
this part?**

\(a\) No person may operate a segment of pipeline listed in the first
column that is readied for service after the date in the second column ,
unless:

\(1\) The pipeline has been designed, installed, constructed; initially
inspected, and initially tested in accordance with this part; or

\(2\) The pipeline qualifies for use under this part according to the
requirements in §192.14.

  -------------------------------------------- --------------------------
  Pipeline                                     Date

  Offshore gathering line.                     July 31, 1977.

  Regulated onshore gathering line to which    March 15 2007.
  this part did not apply until April 14,      
  2006.                                        

  All other pipelines.                         March 12, 1971.
  -------------------------------------------- --------------------------

\(b\) No person may operate a segment of pipeline listed in the first
column that is replaced, relocated, or otherwise changed after the date
in the second column , unless the replacement, relocation, or change has
been made according to the requirements in this part.

  -------------------------------------------- --------------------------
  Pipeline                                     Date

  Offshore gathering line.                     July 31, 1977.

  Regulated onshore gathering line to which    March 15 2007.
  this part did not apply until April 14,      
  2006.                                        

  All other pipelines.                         November 12, 1970.
  -------------------------------------------- --------------------------

\(c\) Each operator shall maintain, modify as appropriate, and follow
the plans, procedures, and programs that it is required to establish
under this part.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-30, 42 FR 60146, Nov. 25, 1977, Amdt.
192-102, 71 FR 13289, Mar. 15, 2006\]

**§192.14 Conversion to service subject to this part.**

\(a\) A steel pipeline previously used in service not subject to this
part qualifies for use under this part if the operator prepares and
follows a written procedure to carry out the following requirements:

\(1\) 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
investigations, tests, repairs, replacements, and alterations made under
the requirements of paragraph (a) of this section.

\[Amdt. 192-30, 42 FR 60146, Nov. 25, 1977\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.16 Customer notification.**

\(a\) This section applies to each operator of a service line who does
not maintain the customer's buried piping up to entry of the first
building downstream, or, if the customer's buried piping does not enter
a building, up to the principal gas utilization equipment or the first
fence (or wall) that surrounds that equipment. For the purpose of this
section, "customer buried piping" does not include branch lines that
serve yard lanterns, pool heaters, or other types of secondary
equipment. Also, "maintain" means monitor for corrosion according to
§192.465 if the customer's buried piping is metallic, survey for leaks
according to §192.723, and if an unsafe condition is found, shut off the
flow of gas, advise the customer of the need to repair the unsafe
condition, or repair the unsafe condition.

\(b\) Each operator shall notify each customer once in writing of the
following information:

\(1\) The operator does not maintain the customer's buried piping.

\(2\) If the customer's buried piping is not maintained, it may be
subject to the potential hazards of corrosion and leakage.

\(3\) Buried gas piping should be--

\(i\) Periodically inspected for leaks;

\(ii\) Periodically inspected for corrosion if the piping is metallic;
and

\(iii\) Repaired if any unsafe condition is discovered.

\(4\) When excavating near buried gas piping, the piping should be
located in advance, and the excavation done by hand.

\(5\) The operator (if applicable), plumbing contractors, and heating
contractors can assist in locating, inspecting, and repairing the
customer's buried piping.

\(c\) Each operator shall notify each customer not later than August 14,
1996, or 90 days after the customer first receives gas at a particular
location, whichever is later. However, operators of master meter systems
may continuously post a general notice in a prominent location
frequented by customers.

\(d\) Each operator must make the following records available for
inspection by the Administrator or a State agency participating under 40
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.

\[Amdt. 192-74, 60 FR 41821, Aug. 14, 1995 as amended by Amdt. 192-74A,
60 FR 63450, Dec. 11, 1995; Amdt. 192-84, 63 FR 7721, Feb. 17, 1998\]

**§192.17 \[Reserved\]**

\[Amdt. 192-1, 35 FR 16405, Oct. 21, 1970 as amended by Amdt. 192-38, 48
FR 37250, July 20, 1981\]

**Subpart B--Materials**

**§192.51 Scope.**

This subpart prescribes minimum requirements for the selection and
qualification of pipe and components for use in pipelines.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.55 Steel pipe.**

\(a\) New steel pipe is qualified for use under this part if:

\(1\) It was manufactured in accordance with a listed specification;

\(2\) It meets the requirements of--

\(i\) Section II of Appendix B to this part; or

\(ii\) If it was manufactured before November 12, 1970, either section
II or III of Appendix B to this part; or

\(3\) It is used in accordance with paragraph (c) or (d) of this
section.

\(b\) Used steel pipe is qualified for use under this part if:

\(1\) It was manufactured in accordance with a listed specification and
it meets the requirements of paragraph II-C of Appendix B to this part;

\(2\) It meets the requirements of:

\(i\) Section II of Appendix B to this part; or

\(ii\) If it was manufactured before November 12, 1970, either section
II or III of Appendix B to this part;

\(3\) It has been used in an existing line of the same or higher
pressure and meets the requirements of paragraph II-C of Appendix B to
this part; or

\(4\) It is used in accordance with paragraph (c) of this section.

\(c\) New or used steel pipe may be used at a pressure resulting in a
hoop stress of less than 6,000 psi (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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970; Amdt. 192-12, 38 FR 4760, Feb. 22, 1973; Amdt.
192-51, 51 FR 15333, Apr. 23, 1986; Amdt. 192-68, 58 FR 14519, Mar. 18,
1993; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.57 \[Removed and Reserved\]**

\[5 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5625,
Feb. 6, 1989\]

**§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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-19, 40 FR
10472, Mar. 6, 1975; Amdt. 192-58, 53 FR 1633, Jan. 21, 1988\]

**§192.61 \[Removed and Reserved\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR
5625, Feb. 6, 1989\]

**§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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970; Amdt. 192-31, 43 FR 13883, Apr. 3, 1978; Amdt.
192-61, 53 FR 36793, Sept. 22, 1988; Amdt. 192-61A, 54 FR 32642, Aug. 9,
1989; Amdt. 192-62, 54 FR 5627, Feb. 6, 1989; Amdt. 192-68, 58 FR 14519,
Mar. 18, 1993; Amdt. 192-76, 61 FR 26121, May 25, 1996; Amdt. 192-76A,
61 FR 36825, July 15, 1996\]

**192.65 Transportation of pipe.**

In a pipeline to be operated at a hoop stress of 20 percent or more of
SMYS, an operator may not use pipe having an outer diameter to wall
thickness ratio of 70 to 1, or more, that is transported by railroad
unless:

\(a\) The transportation is performed in accordance with API RP 5L1.

\(b\) In the case of pipe transported before November 12, 1970, the pipe
is tested in accordance with subpart J of this part to at least 1.25
times the maximum allowable operating pressure if it is to be installed
in a class 1 location and to at least 1.5 times the maximum allowable
operating pressure if it is to be installed in a class 2, 3, or 4
location. Notwithstanding any shorter time period permitted under
subpart J of this part, the test pressure must be maintained for at
least 8 hours.

\[Amdt. 192-12, 38 FR 4760, Feb. 22, 1973, as amended by Amdt. 192-17,
40 FR 6346, Feb. 11, 1975; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993\]

**Subpart C--Pipe Design**

**§192.101 Scope.**

This subpart prescribes the minimum requirements for the design of pipe.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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) gage.
>
> ***S*** = Yield strength in pounds per square inch (kPa) determined in
> accordance with §192.107.
>
> ***D*** =Nominal outside diameter of the pipe in inches (millimeters).
>
> ***t*** = Nominal wall thickness of the pipe in inches. If this is
> unknown, it is determined in accordance with §192.109. Additional wall
> thickness required for concurrent external loads in accordance with
> §192.103 may not be included in computing design pressure.
>
> ***F*** =Design factor determined in accordance with §192.111.
>
> ***E*** =Longitudinal joint factor determined in accordance with
> §192.113.
>
> ***T*** = Temperature derating factor determined in accordance with
> §192.115.

\(b\) If steel pipe that has been subjected to cold expansion to meet
the SMYS is subsequently heated, other than by welding or stress
relieving as a part of welding, the design pressure is limited to 75
percent of the pressure determined under paragraph (a) of this section
if the temperature of the pipe exceeds 900°F (482°C) at any time or is
held above 600°F (316°C) for more than one hour.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-47, 49 FR 7569,
May. 1, 1984; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.107 Yield strength (S) for steel pipe.**

\(a\) For pipe that is manufactured in accordance with a specification
listed in section I of Appendix B of this part, the yield strength to be
used in the design formula in §192.105 is the SMYS stated in the listed
specification, if that value is known.

\(b\) For pipe that is manufactured in accordance with a specification
not listed in section I of Appendix B to this part or whose
specification or tensile properties are unknown, the yield strength to
be used in the design formula in §192.105 is one of the following:

\(1\) If the pipe is tensile tested in accordance with section II-D of
Appendix B to this part, the lower of the following:

\(i\) 80 percent of the average yield strength determined by the tensile
tests.

\(ii\) The lowest yield strength determined by the tensile tests.

\(2\) If the pipe is not tensile tested as provided in paragraph (b)(1)
of this section, 24,000 psi (165 Mpa).

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-78, 61 FR
28770, June 6, 1996; Amdt. 192-84, 63 FR 7721, Feb. 17, 1998; Amdt.
192-85, 63 FR 37500, July 13, 1998\]

**§192.109 Nominal wall thickness (t) for steel pipe.**

\(a\) If the nominal wall thickness for steel pipe is not known, it is
determined by measuring the thickness of each piece of pipe at quarter
points on one end.

\(b\) However, if the pipe is of uniform grade, size, and thickness and
there are more than 10 lengths, only 10 percent of the individual
lengths, but not less than 10 lengths, need be measured. The thickness
of the lengths that are not measured must be verified by applying a
gauge set to the minimum thickness found by the measurement. The nominal
wall thickness to be used in the design formula in §192.105 is the next
wall thickness found in commercial specifications that is below the
average of all the measurements taken. However, the nominal wall
thickness used may not be more than 1.14 times the smallest measurement
taken on pipe less than 20 inches (508 millimeters) in outside diameter,
nor more than 1.11 times the smallest measurement taken on pipe 20
inches (508 millimeters) or more in outside diameter.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.111 Design factor (F) for steel pipe.**

\(a\) Except as otherwise provided in paragraphs (b), (c), and (d) of
this section, the design factor to be used in the design formula in
§192.105 is determined in accordance with the following table:

  ---------------------------------- ------------------------------------
  Class location                     Design 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 §192.105 for steel pipe in Class 1 locations that:

\(1\) Crosses the right-of-way of an unimproved public road, without a
casing;

\(2\) Crosses without a casing, or makes a parallel encroachment on, the
right-of-way of either a hard surfaced road, a highway, a public street,
or a railroad;

\(3\) Is supported by a vehicular, pedestrian, railroad, or pipeline
bridge; or

\(4\) Is used in a fabricated assembly, (including separators, mainline
valve assemblies, cross-connections, and river crossing headers) or is
used within five pipe diameters in any direction from the last fitting
of a fabricated assembly, other than a transition piece or an elbow used
in place of a pipe bend which is not associated with a fabricated
assembly.

\(c\) For Class 2 locations, a design factor of 0.50, or less, must be
used in the design formula in §192.105 for uncased steel pipe that
crosses the right-of-way of a hard surfaced road, a highway, a public
street, or a railroad.

\(d\) For Class 1 and Class 2 locations, a design factor of 0.50, or
less, must be used in the design formula in §192.105 for--

\(1\) Steel pipe in a compressor station, regulating station, or
measuring station, and

\(2\) Steel pipe, including a pipe riser, on a platform located offshore
or in inland navigable waters.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976\]

***Editorial Note:** §192.112 is all new material and therefore not
underlined.*

**§192.112 Additional design requirements for steel pipe using
alternative maximum allowable operating pressure.**

For a new or existing pipeline segment to be eligible for operation at
the alternative maximum allowable operating pressure (MAOP) calculated
under §192.620, a segment must meet the following additional design
requirements. Records for alternative MAOP must be maintained, for the
useful life of the pipeline, demonstrating compliance with these
requirements:

+-----------------+----------------------------------------------------+
| To address this | The pipeline segment must meet these additional    |
| design issue:   | requirements:                                      |
+-----------------+----------------------------------------------------+
| \(a\) General   | \(1\) The plate, skelp, or coil used for the pipe  |
| standards for   | must be micro-alloyed, fine grain, fully killed,   |
| the steel pipe. | continuously cast steel with calcium treatment.    |
+-----------------+----------------------------------------------------+
|                 | \(2\) The carbon equivalents of the steel used for |
|                 | pipe must not exceed 0.25 percent by weight, as    |
|                 | calculated by the Ito-Bessyo formula (Pcm formula) |
|                 | or 0.43 percent by weight, as calculated by the    |
|                 | International Institute of Welding (IIW) formula.  |
+-----------------+----------------------------------------------------+
|                 | \(3\) The ratio of the specified outside diameter  |
|                 | of the pipe to the specified wall thickness must   |
|                 | be less than 100. The wall thickness or other      |
|                 | mitigative measures must prevent denting and       |
|                 | ovality anomalies during construction, strength    |
|                 | testing and anticipated operational stresses.      |
+-----------------+----------------------------------------------------+
|                 | \(4\) The pipe must be manufactured using API      |
|                 | Specification 5L, product specification level 2    |
|                 | (incorporated by reference, see § 192.7) for       |
|                 | maximum operating pressures and minimum and        |
|                 | maximum operating temperatures and other           |
|                 | requirements under this section.                   |
+-----------------+----------------------------------------------------+
| \(b\) Fracture  | \(1\) The toughness properties for pipe must       |
| control.        | address the potential for initiation, propagation  |
|                 | and arrest of fractures in accordance with:        |
|                 |                                                    |
|                 | \(i\) API Specification 5L (incorporated by        |
|                 | reference, see §192.7); or                         |
|                 |                                                    |
|                 | \(ii\) American Society of Mechanical Engineers    |
|                 | (ASME) B31.8 (incorporated by reference, see       |
|                 | §192.7); and                                       |
|                 |                                                    |
|                 | \(iii\) Any correction factors needed to address   |
|                 | pipe grades, pressures, temperatures, or gas       |
|                 | compositions not expressly addressed in API        |
|                 | Specification 5L, product specification level 2 or |
|                 | ASME B31.8 (incorporated by reference, see         |
|                 | §192.7).                                           |
+-----------------+----------------------------------------------------+
|                 | \(2\) Fracture control must:                       |
|                 |                                                    |
|                 | \(i\) Ensure resistance to fracture initiation     |
|                 | while addressing the full range of operating       |
|                 | temperatures, pressures, gas compositions, pipe    |
|                 | grade and operating stress levels, including       |
|                 | maximum pressures and minimum temperatures for     |
|                 | shut-in conditions, that the pipeline is expected  |
|                 | to experience. If these parameters change during   |
|                 | operation of the pipeline such that they are       |
|                 | outside the bounds of what was considered in the   |
|                 | design evaluation, the evaluation must be reviewed |
|                 | and updated to assure continued resistance to      |
|                 | fracture initiation over the operating life of the |
|                 | pipeline;                                          |
|                 |                                                    |
|                 | \(ii\) Address adjustments to toughness of pipe    |
|                 | for each grade used and the decompression behavior |
|                 | of the gas at operating parameters;                |
|                 |                                                    |
|                 | \(iii\) Ensure at least 99 percent probability of  |
|                 | fracture arrest within eight pipe lengths with a   |
|                 | probability of not less than 90 percent within     |
|                 | five pipe lengths; and(iv) Include fracture        |
|                 | toughness testing that is equivalent to that       |
|                 | described in supplementary requirements SR5A,      |
|                 | SR5B, and SR6 of API Specification 5L              |
|                 | (incorporated by reference, see § 192.7) and       |
|                 | ensures ductile fracture and arrest with the       |
|                 | following exceptions:                              |
|                 |                                                    |
|                 | \(A\) The results of the Charpy impact test        |
|                 | prescribed in SR5A must indicate at least 80       |
|                 | percent minimum shear area for any single test on  |
|                 | each heat of steel; and                            |
|                 |                                                    |
|                 | \(B\) The results of the drop weight test          |
|                 | prescribed in SR6 must indicate 80 percent average |
|                 | shear area with a minimum single test result of 60 |
|                 | percent shear area for any steel test samples. The |
|                 | test results must ensure a ductile fracture and    |
|                 | arrest.                                            |
+-----------------+----------------------------------------------------+
|                 | \(3\) If it is not physically possible to achieve  |
|                 | the pipeline toughness properties of paragraphs    |
|                 | (b)(1) and (2) of this section, additional design  |
|                 | features, such as mechanical or composite crack    |
|                 | arrestors and/or heavier walled pipe of proper     |
|                 | design and spacing, must be used to ensure         |
|                 | fracture arrest as described in paragraph          |
|                 | (b)(2)(iii) of this section.                       |
+-----------------+----------------------------------------------------+

+-----------------+----------------------------------------------------+
| \(c\)           | \(1\) There must be an internal quality management |
| Plate/coil      | program at all mills involved in producing steel,  |
| quality         | plate, coil, skelp, and/or rolling pipe to be      |
| control.        | operated at alternative MAOP. These programs must  |
|                 | be structured to eliminate or detect defects and   |
|                 | inclusions affecting pipe quality.                 |
+-----------------+----------------------------------------------------+
|                 | \(2\) A mill inspection program or internal        |
|                 | quality management program must include (i) and    |
|                 | either (ii) or (iii):                              |
+-----------------+----------------------------------------------------+
|                 | \(i\) An ultrasonic test of the ends and at least  |
|                 | 35 percent of the surface of the plate/coil or     |
|                 | pipe to identify imperfections that impair         |
|                 | serviceability such as laminations, cracks, and    |
|                 | inclusions. At least 95 percent of the lengths of  |
|                 | pipe manufactured must be tested. For all          |
|                 | pipelines designed after \[the effective date of   |
|                 | the final rule\], the test must be done in         |
|                 | accordance with ASTM A578/A578M Level B, or API 5L |
|                 | Paragraph 7.8.10 (incorporated by reference, see § |
|                 | 192.7) or equivalent method, and either            |
+-----------------+----------------------------------------------------+
|                 | \(ii\) A macro etch test or other equivalent       |
|                 | method to identify inclusions that may form        |
|                 | centerline segregation during the continuous       |
|                 | casting process. Use of sulfur prints is not an    |
|                 | equivalent method. The test must be carried out on |
|                 | the first or second slab of each sequence graded   |
|                 | with an acceptance criteria of one or two on the   |
|                 | Mannesmann scale or equivalent; or                 |
+-----------------+----------------------------------------------------+
|                 | \(iii\) A quality assurance monitoring program     |
|                 | implemented by the operator that includes audits   |
|                 | of: (a) all steelmaking and casting facilities,    |
|                 | (b) quality control plans and manufacturing        |
|                 | procedure specifications, (c) equipment            |
|                 | maintenance and records of conformance, (d)        |
|                 | applicable casting superheat and speeds, and (e)   |
|                 | centerline segregation monitoring records to       |
|                 | ensure mitigation of centerline segregation during |
|                 | the continuous casting process.                    |
+-----------------+----------------------------------------------------+
| \(d\) Seam      | \(1\) There must be a quality assurance program    |
| quality         | for pipe seam welds to assure tensile strength     |
| control.        | provided in API Specification 5L (incorporated by  |
|                 | reference, see §192.7) for appropriate grades.     |
+-----------------+----------------------------------------------------+
|                 | \(2\) There must be a hardness test, using Vickers |
|                 | (Hv10) hardness test method or equivalent test     |
|                 | method, to assure a maximum hardness of 280        |
|                 | Vickers of the following:                          |
|                 |                                                    |
|                 | \(i\) A cross section of the weld seam of one pipe |
|                 | from each heat plus one pipe from each welding     |
|                 | line per day; and                                  |
|                 |                                                    |
|                 | \(ii\) For each sample cross section, a minimum of |
|                 | 13 readings (three for each heat affected zone,    |
|                 | three in the weld metal, and two in each section   |
|                 | of pipe base metal).                               |
+-----------------+----------------------------------------------------+
|                 | \(3\) All of the seams must be ultrasonically      |
|                 | tested after cold expansion and mill hydrostatic   |
|                 | testing.                                           |
+-----------------+----------------------------------------------------+
| \(e\) Mill      | \(1\) All pipe to be used in a new pipeline        |
| hydrostatic     | segment must be hydrostatically tested at the mill |
| test.           | at a test pressure corresponding to a hoop stress  |
|                 | of 95 percent SMYS for 10 seconds. The test        |
|                 | pressure may include a combination of internal     |
|                 | test pressure and the allowance for end loading    |
|                 | stresses imposed by the pipe mill hydrostatic      |
|                 | testing equipment as allowed by API Specification  |
|                 | 5L, Appendix K (incorporated by reference, see §   |
|                 | 192.7).                                            |
+-----------------+----------------------------------------------------+
|                 | \(2\) Pipe in operation prior to November 17,      |
|                 | 2008, must have been hydrostatically tested at the |
|                 | mill at a test pressure corresponding to a hoop    |
|                 | stress of 90 percent SMYS for 10 seconds.          |
+-----------------+----------------------------------------------------+
| \(f\) Coating.  | \(1\) The pipe must be protected against external  |
|                 | corrosion by a non- shielding coating.             |
+-----------------+----------------------------------------------------+
|                 | \(2\) Coating on pipe used for trenchless          |
|                 | installation must be non- shielding and resist     |
|                 | abrasions and other damage possible during         |
|                 | installation.                                      |
+-----------------+----------------------------------------------------+
|                 | \(3\) A quality assurance inspection and testing   |
|                 | program for the coating must cover the surface     |
|                 | quality of the bare pipe, surface cleanliness and  |
|                 | chlorides, blast cleaning, application temperature |
|                 | control, adhesion, cathodic disbondment, moisture  |
|                 | permeation, bending, coating thickness, holiday    |
|                 | detection, and repair.                             |
+-----------------+----------------------------------------------------+

  ------------------ ----------------------------------------------------
  \(g\) Fittings and \(1\) There must be certification records of
  flanges.           flanges, factory induction bends and factory weld
                     ells. Certification must address material properties
                     such as chemistry, minimum yield strength and
                     minimum wall thickness to meet design conditions.

                     \(2\) If the carbon equivalents of flanges, bends
                     and ells are greater than 0.42 percent by weight,
                     the qualified welding procedures must include a
                     pre-heat procedure.

                     \(3\) Valves, flanges and fittings must be rated
                     based upon the required specification rating class
                     for the alternative MAOP.

  \(h\) Compressor   \(1\) A compressor station must be designed to limit
  stations.          the temperature of the nearest downstream segment
                     operating at alternative MAOP to a maximum of 120
                     degrees Fahrenheit (49 degrees Celsius) or the
                     higher temperature allowed in paragraph (h)(2) of
                     this section unless a long-term coating integrity
                     monitoring program is implemented in accordance with
                     paragraph (h)(3) of this section.

                     \(2\) If research, testing and field monitoring
                     tests demonstrate that the coating type being used
                     will withstand a higher temperature in long-term
                     operations, the compressor station may be designed
                     to limit downstream piping to that higher
                     temperature. Test results and acceptance criteria
                     addressing coating adhesion, cathodic disbondment,
                     and coating condition must be provided to each PHMSA
                     pipeline safety regional office where the pipeline
                     is in service at least 60 days prior to operating
                     above 120 degrees Fahrenheit (49 degrees Celsius).
                     An operator must also notify a State pipeline safety
                     authority when the pipeline is located in a State
                     where PHMSA has an interstate agent agreement, or an
                     intrastate pipeline is regulated by that State.

                     \(3\) Pipeline segments operating at alternative
                     MAOP may operate at temperatures above 120 degrees
                     Fahrenheit (49 degrees Celsius) if the operator
                     implements a long-term coating integrity monitoring
                     program. The monitoring program must include
                     examinations using direct current voltage gradient
                     (DCVG), alternating current voltage gradient (ACVG),
                     or an equivalent method of monitoring coating
                     integrity. An operator must specify the periodicity
                     at which these examinations occur and criteria for
                     repairing identified indications. An operator must
                     submit its long- term coating integrity monitoring
                     program to each PHMSA pipeline safety regional
                     office in which the pipeline is located for review
                     before the pipeline segments may be operated at
                     temperatures in excess of 120 degrees Fahrenheit (49
                     degrees Celsius). An operator must also notify a
                     State pipeline safety authority when the pipeline is
                     located in a State where PHMSA has an interstate
                     agent agreement, or an intrastate pipeline is
                     regulated by that State.
  ------------------ ----------------------------------------------------

\[Amdt. 192-\[107\], 73 FR 62147, October 17, 2008\]

**§192.113 Longitudinal joint factor (E) for steel pipe.**

The longitudinal joint factor to be used in the design formula in
§192.105 is determined in accordance with the following

table:

+---------------------+-----------------------------+------------------+
| Specification       | Pipe Class                  | Longitudinal     |
|                     |                             | Joint Factor     |
|                     |                             |                  |
|                     |                             | \(E\)            |
+---------------------+-----------------------------+------------------+
| ASTM A53/A53M       | Seamless                    | 1.00             |
+---------------------+-----------------------------+------------------+
|                     | Electric resistance welded  | 1.00             |
+---------------------+-----------------------------+------------------+
|                     | Furnace butt welded         | 0.60             |
+---------------------+-----------------------------+------------------+
| ASTM A106           | Seamless                    | 1.00             |
+---------------------+-----------------------------+------------------+
| ASTM                | Seamless                    | 1.00             |
|                     |                             |                  |
| A333/A333M          |                             |                  |
+---------------------+-----------------------------+------------------+
|                     | Electric resistance welded  | 1.00             |
+---------------------+-----------------------------+------------------+
| ASTM A381           | Double submerged arc welded | 1.00             |
+---------------------+-----------------------------+------------------+
| ASTM A671           | Electric-fusion welded      | 1.00             |
+---------------------+-----------------------------+------------------+
| ASTM A672           | Electric-fusion welded      | 1.00             |
+---------------------+-----------------------------+------------------+
| ASTM A691           | Electric-fusion welded      | 1.00             |
+---------------------+-----------------------------+------------------+
| API 5L              | Seamless                    | 1.00             |
+---------------------+-----------------------------+------------------+
|                     | Electric resistance welded  | 1.00             |
+---------------------+-----------------------------+------------------+
|                     | Electric flash welded       | 1.00             |
+---------------------+-----------------------------+------------------+
|                     | Submerged arc welded        | 1.00             |
+---------------------+-----------------------------+------------------+
|                     | Furnace butt welded         | 0.60             |
+---------------------+-----------------------------+------------------+
| Other               | Pipe over 4 inches (102     | 0.80             |
|                     | millimeters)                |                  |
+---------------------+-----------------------------+------------------+
| Other               | Pipe 4 inches (102          | 0.60             |
|                     | 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.\"

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR
10157, Feb. 2, 1981; Amdt. 192-51, 51 FR 15333, Apr. 23, 1986; Amdt.
192-62 54 FR 5625, Feb. 6, 1989; Amdt. 192-68, 58 FR 14519, Mar. 18,
1993; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR
32886, June 14, 2004\]

**§192.115 Temperature derating factor (T) for steel pipe.**

The temperature derating factor to be used in the design formula in
§192.105 is determined as follows:

  ---------------------------------- ------------------------------------
  Gas Temperature in degrees         Temperature derating factor (T)
  Fahrenheit (Celsius)               

  250 (121)or less                   1.000

  300 (149)                          0.967

  350 (177)                          0.933

  400 (204)                          0.900

  450 (232)                          0.867
  ---------------------------------- ------------------------------------

For intermediate gas temperatures, the derating factor is determined by
interpolation.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.117 \[Reserved\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR
10157, Feb. 2, 1981 and 46 FR 10706, Feb. 4, 1981, effective Mar. 31,
1981; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989\]

**§192.119 \[Reserved\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR
5625, Feb. 6, 1989\]

**§192.121 Design of plastic pipe.**

Subject to the limitations of §192.123, the design pressure for plastic
pipe is determined in accordance with either of the following formulas:

$$\begin{array}{r}
P = 2S\frac{t}{(D - t)}0\text{.}\text{32} \\
P = \frac{2S}{(\text{SDR} - 1)}0\text{.}\text{32}
\end{array}$$

> ***P*** = Design pressure, gage, kPa (psi).
>
> ***S*** = For thermoplastic pipe, the HDB determined in accordance
> with the listed specification at a temperature equal to 73 ºF (23ºC),
> 100ºF (38ºC), 120ºF (49ºC), or 140ºF (60ºC). In the absence an HDB
> established at the specified temperature, the HDB of a higher
> temperature may be used in determining a design pressure rating at the
> specified temperature by arithmetic interpolation using the procedure
> in Part D.2 of PPI TR-3/2004, HDB/PDB/SDB/MRS Policies", (incorporated
> by reference, *see* §192.7). For reinforced thermosetting plastic
> pipe, 11,000 psig (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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-31, 43 FR
13883, Apr. 3, 1978; 43 FR 43308, Sept. 25, 1978; Amdt. 192-78, 61 FR
28770, June 6, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt.
192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 8,
2006\]

**§192.123 Design limitations for plastic pipe.**

\(a\) Except as provided in paragraph (e) of this section, the design
pressure may not exceed a gauge pressure of 100 psig (689 kPa)for
plastic pipe used in:

\(1\) Distribution systems; or

\(2\) Classes 3 and 4 locations.

\(b\) Plastic pipe may not be used where operating temperatures of the
pipe will be:

\(1\) Below -20°F (-29°C), or -40°F (-40°C) if all pipe and pipeline
components whose operating temperature will be below -20°F (-29°C) have
a temperature rating by the manufacturer consistent with that operating
temperature; or

\(2\) Above the following applicable temperatures:

\(i\) For thermoplastic pipe, the temperature at which the HDB used in
the design formula under §192.121 is determined.

\(ii\) For reinforced thermosetting plastic pipe, 150°F (66°C).

\(c\) The wall thickness for thermoplastic pipe may not be less than
0.062 inch (1.57 millimeters).

\(d\) The wall thickness for reinforced thermosetting plastic pipe may
not be less than that listed in the following table:

+---------------------------------+------------------------------------+
| Normal size in inches           | Minimum wall thickness in inches   |
|                                 | (millimeters)                      |
| (millimeters)                   |                                    |
+---------------------------------+------------------------------------+
| 2 (51)                          | 0.060 (1.52)                       |
+---------------------------------+------------------------------------+
| 3 (76)                          | 0.060 (1.52)                       |
+---------------------------------+------------------------------------+
| 4 (102)                         | 0.070 (1.78)                       |
+---------------------------------+------------------------------------+
| 6 (152)                         | 0.100 (2.54)                       |
+---------------------------------+------------------------------------+

\(e\) The design pressure for thermoplastic pipe produced after July 14,
2004 may exceed a gauge pressure of 100 psig (689 kPa) provided that:

\(1\) The design pressure does not exceed 125 psig (862 kPa);

\(2\) The material is a PE2406 or a PE3408 as specified within ASTM
D2513 (incorporated by reference, *see* §192.7);

\(3\) The pipe size is nominal pipe size (IPS) 12 or less; and

\(4\) The design pressure is determined in accordance with the design
equation defined in §192.121.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-31, 43 FR
13883, Apr. 3, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996; Amdt.
192-85, 63 FR 37500, July 13, 1998; Amdt. 192-93, 68 FR 53895, Sept. 15,
2003; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-94A, 69 FR
54591, Sept. 9, 2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§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 following table:

+----------------+---+-----------------+----------------+-----------------+
| Standard       | N |                 | Wall thickness |                 |
|                | o |                 | (inch)         |                 |
| size           | m |                 | (millimeter)   |                 |
|                | i |                 |                |                 |
|                | n |                 |                |                 |
|                | a |                 |                |                 |
|                | l |                 |                |                 |
|                |   |                 |                |                 |
|                | O |                 |                |                 |
|                | . |                 |                |                 |
|                | D |                 |                |                 |
|                | . |                 |                |                 |
+----------------+---+-----------------+----------------+-----------------+
| (inch)         |   | (inch)          | Nominal        | Tolerance       |
| (millimeter)   |   | (millimeter)    |                |                 |
+----------------+---+-----------------+----------------+-----------------+
| ½ (13)         |   | 0.625 (16)      | .040 (1.06)    | .0035 (.0889)   |
+----------------+---+-----------------+----------------+-----------------+
| 5/8 (16)       |   | 0.750 (19)      | .042 (1.07)    | .0035 (.0889)   |
+----------------+---+-----------------+----------------+-----------------+
| ¾ (19)         |   | 0.875 (22)      | .045 (1.14)    | .0040 (.102)    |
+----------------+---+-----------------+----------------+-----------------+
| 1 (25)         |   | 1.125 (29)      | .050 (1.27)    | .0040 (.102)    |
+----------------+---+-----------------+----------------+-----------------+
| 1¼ (32)        |   | 1.375 (35)      | .055 (1.40)    | .0045 (.1143)   |
+----------------+---+-----------------+----------------+-----------------+
| 1½ (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 psi (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 60ºF and 14.7 psia (15.6ºC and
one atmosphere).

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR
5625, Feb. 6, 1989; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**Subpart D--Design of Pipeline**

**Components**

**§192.141 Scope.**

This subpart prescribes minimum requirements for the design and
installation of pipeline components and facilities. In addition, it
prescribes requirements relating to protection against accidental
overpressuring.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.143 General requirements.**

[(a)]{.underline} Each component of a pipeline must be able to withstand
operating pressures and other anticipated loadings without impairment of
its serviceability with unit stresses equivalent to those allowed for
comparable material in pipe in the same location and kind of service.
However, if design based upon unit stresses is impractical for a
particular component, design may be based upon a pressure rating
established by the manufacturer by pressure testing that component or a
prototype of the component.

[(b) The design and installation of pipeline components and facilities
must meet applicable requirements for corrosion control found in subpart
I of this part.]{.underline}

\[Amdt. 192-48, 49 CFR 19823, May 10, 1984 as amended by 72 FR 20055,
April 23, 2007\]

**§192.144 Qualifying metallic components.**

Notwithstanding any requirement of this subpart which incorporates by
reference an edition of a document listed in §192.7 or Appendix B of
this part, a metallic component manufactured in accordance with any
other edition of that document is qualified for use under this part
if---

\(a\) It can be shown through visual inspection of the cleaned component
that no defect exists which might impair the strength or tightness of
the component; and

\(b\) The edition of the document under which the component was
manufactured has equal or more stringent requirements for the following
as an edition of that document currently or previously listed in §192.7
or Appendix B of this part:

\(1\) Pressure testing;

\(2\) Materials; and,

\(3\) Pressure and temperature ratings.

\[Amdt. 192-45, 48 FR 30637, July 5, 1983; Amdt. 192-94, 69 FR 32886,
June 14, 2004\]

**§192.145 Valves.**

\(a\) Except for cast iron and plastic valves, each valve must meet the
minimum requirements of API 6D (incorporated by reference, *see*
§192.7), or to a national or international standard that provides an
equivalent performance level. A valve may not be used under operating
conditions that exceed the applicable pressure-temperature ratings
contained in those requirements.

\(b\) Each cast iron and plastic valve must comply with the following:

\(1\) The valve must have a maximum service pressure rating for
temperatures that equal or exceed the maximum service temperature.

\(2\) The valve must be tested as part of the manufacturing, as follows:

\(i\) 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 no
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
psi (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.

\[Part 192 - Org., Aug. 19,1970, as amended by Amdt. 192-3, 35 FR 17660,
Nov. 17, 1970; Amdt. 192-22, 41 FR 13590, Mar. 31, 1976; Amdt. 192-37,
46 FR 10159, Feb. 2, 1981; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt.
192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR
5625, Feb. 6, 1989; Amdt. 192-68, 54 FR 14519, Mar. 18, 1993\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.150 Passage of internal inspection devices.**

\(a\) Except as provided in paragraphs (b) and (c) of this section, each
new transmission line and each replacement of line pipe, valve, fitting,
or other line component in a transmission line must be designed and
constructed to accommodate the passage of instrumented internal
inspection devices.

\(b\) This section does not apply to:

\(1\) Manifolds;

\(2\) Station piping such as at compressor stations, meter stations, or
regulator stations;

\(3\) Piping associated with storage facilities, other than a continuous
run of transmission line between a compressor station and storage
facilities;

\(4\) Cross-overs;

\(5\) Sizes of pipe for which an instrumented internal inspection device
is not commercially available;

\(6\) Transmission lines, operated in conjunction with a distribution
system which are installed in Class 4 locations;

\(7\) Offshore transmission lines, except transmission lines 10¾ inches
(273 millimeters) or more in outside diameter on which construction
begins after December 28, 2005, that run from platform to platform or
platform to shore unless---

\(i\) Platform space or configuration is incompatible with launching or
retrieving instrumented internal inspection devices; or

\(ii\) If the design includes taps for lateral connections, the operator
can demonstrate, based on investigation or experience, that there is no
reasonably practical alternative under the design circumstances to the
use of a tap that will obstruct the passage of instrumented internal
inspection devices; and

\(8\) Other piping that, under §190.9 of this chapter, the Administrator
finds in a particular case would be impracticable to design and
construct to accommodate the passage of instrumented internal inspection
devices.

\(c\) An operator encountering emergencies, construction time
constraints or other unforeseen construction problems need not construct
a new or replacement segment of a transmission line to meet paragraph
(a) of this section, if the operator determines and documents why an
impracticability prohibits compliance with paragraph (a) of this
section. Within 30 days after discovering the emergency or construction
problem the operator must petition, under §190.9 of this chapter, for
approval that design and construction to accommodate passage of
instrumented internal inspection devices would be impracticable. If the
petition is denied, within 1 year after the date of the notice of the
denial, the operator must modify that segment to allow passage of
instrumented internal inspection devices.

\[Amdt. 192-72, 59 FR 17275, Apr. 12, 1994as amended by Amdt. 192-85, 63
FR 37500, July 13, 1998; Amdt. 192-97, 69 FR 36024, June 28, 2004\]

**§192.151 Tapping.**

\(a\) Each mechanical fitting used to make a hot tap must be designed
for at least the operating pressure of the pipeline.

\(b\) 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 1¼-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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.153 Components fabricated by welding.**

\(a\) Except for branch connections and assemblies of standard pipe and
fittings joined by circumferential welds, the design pressure of each
component fabricated by welding, whose strength cannot be determined,
must be established in accordance with paragraph 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
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 psi (689 kPa) gage, or
more, or is more than 3 inches (76 millimeters) nominal diameter.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt.
192-85, 63 FR 37500, July 13, 1998 \]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-58, 53 FR 1633, Jan. 21, 1988\]

**§192.163 Compressor stations: Design and construction.**

\(a\) *Location of compressor building.* Except for a compressor
building on a platform located offshore or in inland navigable waters,
each main compressor building of a compressor station must be located on
property under the control of the operator. It must be far enough away
from adjacent property, not under control of the operator, to minimize
the possibility of fire being communicated to the compressor building
from structures on adjacent property. There must be enough open space
around the main compressor building to allow the free movement of
fire-fighting equipment.

\(b\) *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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt.
192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-85, 63 FR 37500, July 13,
1998\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\(c\) 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34605, Aug. 16, 1976; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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, psi (kPa) gage.

***F*** = Design factor as set forth in §192.111 of this part.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.177 Additional provisions for bottle-type holders.**

\(a\) Each bottle-type holder must be--

\(1\) Located on a site entirely surrounded by fencing that prevents
access by unauthorized persons and with minimum clearance from the fence
as follows:

+---------------------------------+------------------------------------+
| Maximum allowable operating     | Minimum                            |
| pressure                        |                                    |
|                                 | clearance (feet) (meters)          |
+---------------------------------+------------------------------------+
| Less than 1,000 p.s.i. (7 Mpa)  | 25 (7.6)                           |
| gage                            |                                    |
+---------------------------------+------------------------------------+
| 1,000 p.s.i. (7 Mpa) gage or    | 100 (31)                           |
| more                            |                                    |
+---------------------------------+------------------------------------+

\(2\) Designed using the design factors set forth in §192.111; and,

\(3\) Buried with a minimum cover in accordance with §192.327.

\(b\) Each bottle-type holder manufactured from steel that is not
weldable under field conditions must comply with the following:

\(1\) A bottle-type holder made from alloy steel must meet the chemical
and tensile requirements for the various grades of steel in ASTM A 372/

A 372M.

\(2\) The actual yield-tensile ratio of the steel may not exceed 0.85.

\(3\) Welding may not be performed on the holder after it has been heat
treated or stress relieved, except that copper wires may be attached to
the small diameter portion of the bottle end closure for cathodic
protection if a localized thermit welding process is used.

\(4\) The holder must be given a mill hydrostatic test at a pressure
that produces a hoop stress at least equal to 85 percent of the SMYS.

\(5\) The holder, connection pipe, and components must be leak tested
after installation as required by Subpart J of this part.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt 192-58, 53 FR 1635,
Jan 21, 1988; Amdt 192-62, 54 FR 5625, Feb. 6, 1989; Amdt 192-68, 58 FR
14519, Mar. 18, 1993; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§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 2½
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 7½
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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-78, 61 FR 28770, June 6, 1996; Amdt.
192-85, 63 FR 37500, July 13, 1998\]

**§192.181 Distribution line valves.**

\(a\) Each high-pressure distribution system must have valves spaced so
as to reduce the time to shut down a section of main in an emergency.
The valve spacing is determined by the operating pressure, the size of
the mains, and the local physical conditions.

\(b\) Each regulator station controlling the flow or pressure of gas in
a distribution system must have a valve installed on the inlet piping at
a distance from the regulator station sufficient to permit the operation
of the valve during an emergency that might preclude access to the
station.

\(c\) Each valve on a main installed for operating or emergency purposes
must comply with the following:

\(1\) The valve must be placed in a readily accessible location so as to
facilitate its operation in an emergency.

\(2\) The operating stem or mechanism must be readily accessible.

\(3\) If the valve is installed in a buried box or enclosure, the box or
enclosure must be installed so as to avoid transmitting external loads
to the main.

\[Part 192 - Org., Aug. 19, 1970\]

**§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 inches (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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.185 Vaults: Accessibility.**

Each vault must be located in an accessible location and, so far as
practical, away from:

\(a\) Street intersections or points where traffic is heavy or dense;

\(b\) 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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.189 Vaults: Drainage and waterproofing.**

\(a\) Each vault must be designed so as to minimize the entrance of
water.

\(b\) A vault containing gas piping may not be connected by means of a
drain connection to any other underground structure.

\(c\) Electrical equipment in vaults must conform to the applicable
requirements of Class 1, Group D, of the National Electrical Code,
ANSI/NFPA 70.

\[Part 192 - Org., Aug. 19, 1970as amended by Amdt. 192-76, 61 FR 26121,
May 24, 1996\]

**§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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970; Amdt. 192-58, 53 FR 1633, Jan. 21, 1988\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.195 Protection against accidental overpressuring.**

\(a\) General requirements. Except as provided in §192.197, each
pipeline that is connected to a gas source so that the maximum allowable
operating pressure could be exceeded as the result of pressure control
failure or of some other type of failure, must have pressure relieving
or pressure limiting devices that meet the requirements of §192.199 and
§192.201.

\(b\) 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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.197 Control of the pressure of gas delivered from high-pressure
distribution systems.**

\(a\) If the maximum actual operating pressure of the distribution
system is 60 psi (414 kPa) gage, or less, and a service regulator having
the following characteristics is used, no other pressure limiting device
is required:

\(1\) A regulator capable of reducing distribution line pressure to
pressures recommended for household appliances.

\(2\) A single port valve with proper orifice for the maximum gas
pressure at the regulator inlet.

\(3\) A valve seat made of resilient material designed to withstand
abrasion of the gas, impurities in gas, cutting by the valve, and to
resist permanent deformation when it is pressed against the valve port.

\(4\) Pipe connections to the regulator not exceeding 2 inches (51
millimeters) in diameter.

\(5\) A regulator that, under normal operating conditions, is able to
regulate the downstream pressure within the necessary limits of accuracy
and to limit the build-up of pressure under no-flow conditions to
prevent a pressure that would cause the unsafe operation of any
connected and properly adjusted gas utilization equipment.

\(6\) A self-contained service regulator with no external static or
control lines.

\(b\) If the maximum actual operating pressure of the distribution
system is 60 p.s.i. (414 kPa) gage or less, and a service regulator that
does not have all of the characteristics listed in paragraph (a) of this
section is used, or if the gas contains materials that seriously
interfere with the operation of service regulators, there must be
suitable protective devices to prevent unsafe overpressuring of the
customer\'s appliances if the service regulator fails.

\(c\) If the maximum actual operating pressure of the distribution
system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods
must be used to regulate and limit, to the maximum safe value, the
pressure of gas delivered to the customer:

\(1\) A service regulator having the characteristics listed in paragraph
(a) of this section, and another regulator located upstream from the
service regulator. The upstream regulator may not be set to maintain a
pressure higher than 60 p.s.i. (414 kPa) gage. A device must be
installed between the upstream regulator and the service regulator to
limit the pressure on the inlet of the service regulator to 60 p.s.i.
(414 kPa) gage or less in case the upstream regulator fails to function
properly. 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 60p.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 pressure, 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 7, 1970; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt.
192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.199 Requirements for design of pressure relief and limiting
devices.**

Except for rupture discs, each pressure relief or pressure limiting
device must:

\(a\) Be constructed of materials such that the operation of a 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970\]

**§192.201 Required capacity of pressure relieving and limiting
stations.**

\(a\) Each pressure relief station or pressure limiting station or group
of those stations installed to protect a pipeline must have enough
capacity, and must be set to operate, to insure the following:

\(1\) In a low pressure distribution system, the pressure may not cause
the unsafe operation of any connected and properly adjusted gas
utilization equipment.

\(2\) In pipelines other than a low pressure distribution system:

\(i\) If the maximum allowable operating pressure is 60 p.s.i. (414 kPa)
gage or more, the pressure may not exceed the maximum allowable
operating pressure plus 10 percent or the pressure that produces a hoop
stress of 75 percent of SMYS, whichever is lower;

\(ii\) If the maximum allowable operating pressure is 12 p.s.i. (83 kPa)
gage or more, but less than 60 p.s.i. (414 kPa) gage, the pressure may
not exceed the maximum allowable operating pressure plus 6 p.s.i. (41
kPa) gage; or

\(iii\) If the maximum allowable operating pressure is less than 12
p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable
operating pressure plus 50 percent.

\(b\) When more than one pressure regulating or compressor station feeds
into a pipeline, relief valves or other protective devices must be
installed at each station to ensure that the complete failure of the
largest capacity regulator or compressor, or any single run of lesser
capacity regulators or compressors in that station, will not impose
pressures on any part of the pipeline or distribution system in excess
of those for which it was designed, or against which it was protected,
whichever is lower.

\(c\) Relief valves or other pressure limiting devices must be installed
at or near each regulator station in a low-pressure distribution system,
with a capacity to limit the maximum pressure in the main to a pressure
that will not exceed the safe operating pressure for any connected and
properly adjusted gas utilization equipment.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-9, 37 FR
20826, Oct. 4, 1972; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.203 Instrument, control, and sampling pipe and components.**

\(a\) Applicability. This section applies to the design of instrument,
control, and sampling pipe and components. It does not apply to
permanently closed systems, such as fluid-filled temperature-responsive
devices.

\(b\) 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°F (204ºC).

\(4\) 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR
28770, June 6, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**Subpart E--Welding of Steel**

**in Pipelines**

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.223 \[Removed\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-52, 51 FR
20294, June 4, 1986\]

**§192.225 Welding** **procedures.**

\(a\) Welding must be performed by a qualified welder in accordance with
welding procedures qualified under section 5 of API 1104 (incorporated
by reference, *see* §192.7) or section IX of the ASME Boiler and
Pressure Vessel Code " Welding and Brazing Qualifications" (incorporated
by reference, *see* §192.7) to produce welds meeting the requirements of
this subpart. The quality of the test welds used to qualify welding
procedures shall be determined by destructive testing in accordance with
the applicable welding standard(s).

\(b\) Each welding procedure must be recorded in detail, including the
results of the qualifying tests. This record must be retained and
followed whenever the procedure is used.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-18, 40 FR
10181, Mar. 5, 1975; Amdt. 192-22, 41 FR 13590, Mar. 31, 1976; Amdt.
192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-52, 51 FR 20297, June 4,
1986; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt. 192-103, 71 FR
33402, June 8, 2006\]

**§192.227 Qualification of welders.**

\(a\) Except as provided in paragraph (b) of this section, each welder
must be qualified in accordance with section 6 of API 1104 (incorporated
by reference, *see* §192.7) or section IX of the ASME Boiler and
Pressure Vessel Code (incorporated by reference, *see* §192.7). However,
a welder qualified under an earlier edition than listed in §192.7 of
this part may weld but may not requalify under that earlier edition.

\(b\) A welder may qualify to perform welding on pipe to be operated at
a pressure that produces a hoop stress of less than 20 percent of SMYS
by performing an acceptable test weld, for the process to be used, under
the test set forth in section I of Appendix C of this part. A welder who
is to make a welded service line connection to a main must also first
perform an acceptable test weld under section II of Appendix C of this
part as a requirement of the qualifying test.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-18, 40 FR
10181, Mar. 5, 1975; Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt.
192-22, 41 FR 13590, Mar. 31, 1976; Amdt. 192-37, 46 FR 10157, Feb. 2,
1981; Amdt. 192-43, 47 FR 46850, Oct. 21, 1982; Amdt. 192-52, 51 FR
20294, June 4, 1986; Amdt. 192-75, 61 FR 18512, Apr. 26, 1996; Amdt.
192-78, 61 FR 28770, June 6, 1996; Amdt. 192-94, 69 FR 32886, June 14,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006; Amdt. 192-103c, 72 FR
4655, Feb. 1, 2007\]

**§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 §192.227(a)--

\(1\) May not weld on pipe to be operated at a pressure that produces a
hoop stress of 20 percent or more of SMYS unless within the preceding 6
calendar months the welder has had one weld tested and found acceptable
under the sections 6 or 9 of API Standard 1104 (incorporated by
reference, *see* §192.7). Alternatively, welders may maintain an ongoing
qualification status by performing welds tested and found acceptable
under the above acceptance criteria at least twice each calendar year,
but at intervals not exceeding 7½ months. A welder qualified under an
earlier edition of a standard listed in §192.7 of this part may weld but
may not requalify under that earlier edition; and

\(2\) May not weld on pipe to be operated at a pressure that produces a
hoop stress of less than 20 percent of SMYS unless the welder is tested
in accordance with paragraph (c)(1) of this section or requalifies under
paragraph (d)(1) or (d)(2) of this section.

\(d\) A welder qualified under §192.227(b) may not weld unless--

\(1\) Within the preceding 15 calendar months, but at least once each
calendar year, the welder has requalified under §192.227(b); or

\(2\) Within the preceding 7½ 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-18, 40 FR
10181, Mar. 5, 1975; Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt.
192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-78, 61 FR 28770, June 6,
1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR
32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.231 Protection from weather.**

The welding operation must be protected from weather conditions that
would impair the quality of the completed weld.

\[Part 192 - Org., Aug. 19, 1970\]

**§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 3º.

\(b\) 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 12½º and must be a distance
equal to one pipe diameter or more away from any other miter joint, as
measured from the crotch of each joint.

\(c\) A miter joint on steel pipe to be operated at a pressure that
produces a hoop stress of 10 percent or less of SMYS may not deflect the
pipe more than 90º.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.237 \[Removed\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR
10157, Feb. 2, 1981; Amdt. 192-52, 51 FR 20294, June 4, 1986\]

**§192.239 \[Removed\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR
10157, Feb. 2, 1981; Amdt. 192-52, 51 FR 20294, June 4, 1986\]

**§192.241 Inspection and test of welds.**

\(a\) Visual inspection of welding must be conducted by an individual
qualified by appropriate training and experience to ensure that:

\(1\) The welding is performed in accordance with the welding procedure;
and

\(2\) The weld is acceptable under paragraph (c) of this section.

\(b\) The welds on a pipeline to be operated at a pressure that produces
a hoop stress of 20 percent or more of SMYS must be nondestructively
tested in accordance with §192.243, except that welds that are visually
inspected and approved by a qualified welding inspector need not be
nondestructively tested if:

\(1\) The pipe has a nominal diameter of less than 6 inches (152
millimeters); or

\(2\) The pipeline is to be operated at a pressure that produces a hoop
stress of less than 40 percent of SMYS and the welds are so limited in
number that nondestructive testing is impractical.

\(c\) The acceptability of a weld that is nondestructively tested or
visually inspected is determined according to the standards in Section 9
of API Standard 1104 (incorporated by reference, *see* §192.7). However,
if a girth weld is unacceptable under those standards for a reason other
than a crack, and if Appendix A to API 1104 applies to the weld, the
acceptability of the weld may be further determined under that appendix.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-18, 40 FR
10181, Mar. 5, 1975; Amdt. 192-18A, 40 FR 27222, June 27, 1975; Amdt.
192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-78, 61 FR 28770, June 6,
1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-94, 69 FR
32886, June 14, 2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§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 §192.241(c).

\(d\) When nondestructive testing is required under §192.241(b), the
following percentages of each day\'s field butt welds, selected at
random by the operator, must be nondestructively tested over their
entire circumference;

\(1\) In Class 1 locations, except offshore, at least 10 percent.

\(2\) In Class 2 locations, at least 15 percent.

\(3\) In Class 3 and Class 4 locations, at crossings of major or
navigable rivers, offshore, and within railroad or public highway
rights-of-way, including tunnels, bridges, and overhead road crossings,
100 percent unless impracticable, in which case at least 90 percent.
Nondestructive testing must be impracticable for each girth weld not
tested.

\(4\) At pipeline tie-ins, including tie-ins of replacement sections,
100 percent.

\(e\) Except for a welder whose work is isolated from the principal
welding activity, a sample of each welder\'s work for each day must be
nondestructively tested, when nondestructive testing is required under
§192.241(b).

\(f\) When nondestructive testing is required under §192.241(b), each
operator must retain, for the life of the pipeline, a record showing by
milepost, engineering station, or by geographic feature, the number of
girth welds made, the number nondestructively tested, the number
rejected, and the disposition of the rejects.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-50, 50 FR 37191, Sept. 12, 1985; Amdt.
192-78, 61 FR 28770, June 6, 1996\]

**192.245 Repair or removal of defects.**

\(a\) Each weld that is unacceptable under §192.241(c) must be removed
or repaired. Except for welds on an offshore pipeline being installed
from a pipeline vessel, a weld must be removed if it has a crack that is
more than 8 percent of the weld length.

\(b\) Each weld that is repaired must have the defect removed down to
sound metal and the segment to be repaired must be preheated if
conditions exist which would adversely affect the quality of the weld
repair. After repair, the segment of the weld that was repaired must be
inspected to ensure its acceptability.

\(c\) Repair of a crack, or of any defect in a previously repaired area
must be in accordance with written weld repair procedures that have been
qualified under §192.225. Repair procedures must provide that the
minimum mechanical properties specified for the welding procedure used
to make the original weld are met upon completion of the final weld
repair.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-46, 48 FR 48669, Oct. 20, 1983\]

**Subpart F--Joining of Materials Other Than by Welding**

**§192.271 Scope.**

\(a\) This subpart prescribes minimum requirements for joining materials
in pipelines, other than by welding.

\(b\) This subpart does not apply to joining during the manufacture of
pipe or pipeline components.

\[Part 192 - Org., Aug. 19, 1970\]

**§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 proved by test or experience to produce strong gas tight
joints.

\(c\) Each joint must be inspected to insure compliance with this
subpart.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\(e\) \[Removed\]

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR
5628, Feb. 6, 1989\]

**§192.277 Ductile iron pipe.**

\(a\) Ductile iron pipe may not be joined by threaded joints.

\(b\) Ductile iron pipe may not be joined by brazing.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR
5628, Feb. 6, 1989, effective Mar. 8, 1989\]

**§192.279 Copper pipe.**

Copper pipe may not be threaded except that copper pipe used for joining
screw fittings or valves may be threaded if the wall thickness is
equivalent to the comparable size of Schedule 40 or heavier wall pipe
listed in Table C1 of ASME/ANSI B16.5.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-62 , 54 FR
5628, Feb. 6, 1989; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993\]

**§192.281 Plastic pipe.**

\(a\) General. A plastic pipe joint that is joined by solvent cement,
adhesive, or heat fusion may not be disturbed until it has properly set.
Plastic pipe may not be joined by a threaded joint or miter joint.

\(b\) 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 detrimental to the joint.

\(2\) The solvent cement must conform to ASTM Designation: D 2513.

\(3\) The joint may not be heated to accelerate the setting of the
cement.

\(c\) Heat-fusion joints. Each heat-fusion joint on plastic pipe must
comply with the following:

\(1\) A butt heat-fusion joint must be joined by a device that holds the
heater element square to the ends of the piping, compresses the heated
ends together, and holds the pipe in proper alignment while the plastic
hardens.

\(2\) A socket heat-fusion joint must be joined by a device that heats
the mating surfaces of the joint uniformly and simultaneously to
essentially the same temperature.

\(3\) An electrofusion joint must be joined utilizing the equipment and
techniques of the fittings manufacturer or equipment and techniques
shown, by testing joints to the requirements of §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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-34, 44 FR
42968, July 23, 1979; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt.
192-61, 53 FR 36793, Sept. 22, 1988; Amdt. 192-68, 58 FR 14519, Mar. 18,
1993; Amdt. 192-78, 61 FR 28770, June 6, 1996\]

**§192.283 Plastic pipe; Qualifying joining procedures.**

\(a\) Heat fusion, solvent cement, and adhesive joints. Before any
written procedure established under §192.273(b) is used for making
plastic pipe joints by a heat fusion, solvent cement, or adhesive
method, the procedure must be qualified by subjecting specimen joints
made according to the procedure to the following tests:

\(1\) The burst test requirements of--

\(i\) In the case of thermoplastic pipe, paragraph 6.6 (sustained
pressure test) or paragraph 6.7 (Minimum Hydrostatic Burst Test) or
paragraph 8.9 ( Sustained Static pressure Test) of ASTM D2513
(incorporated by reference, *see* §192.7);

\(ii\) In the case of thermosetting plastic pipe, paragraph 8.5 (Minimum
Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static Pressure
Test) of ASTM D2517 (incorporated by reference, *see* §192.7); or

\(iii\) In the case of electrofusion fittings for polyethylene pipe and
tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), paragraph
9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength Test), or
paragraph 9.4 (Joint Integrity Tests) of ASTM Designation F1055
(incorporated by reference, *see* §192.7).

\(2\) For procedures intended for lateral pipe connections, subject a
specimen joint made from pipe sections joined at right angles according
to the procedure to a force on the lateral pipe until failure occurs in
the specimen. If failure initiates outside the joint area, the procedure
qualifies for use; and,

\(3\) For procedures intended for non-lateral pipe connections, follow
the tensile test requirements of ASTM D638 (incorporated by reference,
*see* §192.7), except that the test may be conducted at ambient
temperature and humidity. If the specimen elongates no less than 25
percent or failure initiates outside the joint area, the procedure
qualifies for use.

\(b\) Mechanical joints. Before any written procedure established under
§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 five specimen joints made according to the procedure to the
following tensile test:

\(1\) Use an apparatus for the test as specified in ASTM D 638 (except
for conditioning), (incorporated by reference, *see* §192.7).

\(2\) The specimen must be of such length that the distance between the
grips of the apparatus and the end of the stiffener does not affect the
joint strength.

\(3\) The speed of testing is 0.20 in. (5.0 mm) per minute, plus or
minus 25 percent.

\(4\) Pipe specimens less than 4 in. (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 in. (102 mm) and larger in diameter shall be
pulled until the pipe is subjected to a tensile stress equal to or
greater than the maximum thermal stress that would be produced by a
temperature change of 100°F (38°C) or until the pipe is pulled from the
fitting. If the pipe pulls from the fitting, the lowest value of the
five test results or the manufacturer\'s rating, whichever is lower must
be used in the design calculations for stress.

\(6\) Each specimen that fails at the grips must be retested using new
pipe.

\(7\) Results obtained pertain only to the specific outside diameter,
and material of the pipe tested, except that testing of a heavier wall
pipe may be used to qualify pipe of the same material but with a lesser
wall thickness.

\(c\) A copy of each written procedure being used for joining plastic
pipe must be available to the persons making and inspecting joints.

\(d\) Pipe or fittings manufactured before July 1, 1980, may be used in
accordance with procedures that the manufacturer certifies will produce
a joint as strong as the pipe.

\[Amdt. 192-34, 44 FR 42968, July 23, 1979 as amended by Amdt. 192-34A,
45 FR 9931, Feb. 14, 1980; Amdt. 192-34B, 46 FR 39, Jan. 2, 1981; Amdt.
192-34(1), 47 FR 32720, July 29, 1982; Amdt. 192-34(2), 47 FR 49973,
Nov. 4, 1982; Amdt. 192-68, 58 FR 14519, Mar. 18, 1993; Amdt. 192-78, 61
FR 28770, June 6, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt.
192-94, 69 FR 32886, June 14, 2004; Amdt. 192-94A, 69 FR 54591, Sept. 9,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§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 §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 three longitudinal straps, each of which is:

\(A\) Visually examined and found not to contain voids or
discontinuities on the cut surfaces of the joint area; and

\(B\) Deformed by bending, torque, or impact, and if failure occurs, it
must not initiate in the joint area.

\(c\) A person must be requalified under an applicable procedure, if
during any 12-month period that person:

\(1\) Does not make any joints under that procedure; or

\(2\) Has 3 joints or 3 percent of the joints made, whichever is
greater, under that procedure that are found unacceptable by testing
under §192.513.

\(d\) Each operator shall establish a method to determine that each
person making joints in plastic pipelines in the operator\'s is
qualified in accordance with this section.

\[Amdt. 192-34, 44 FR 42968, July 23, 1979 as amended by Amdt. 192-34A,
45 FR 9931, Feb. 14, 1980, Amdt. 192-34B, 46 FR 39, Jan. 2, 1981; Amdt.
192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14,
2004\]

**§192.287 Plastic pipe: Inspection of joints.**

No person may carry out the inspection of joints in plastic pipes
required by §§ 192.273(c) and 192.285(b) unless that person has been
qualified by appropriate training or experience in evaluating the
acceptability of plastic pipe joints made under the applicable joining
procedure.

\[Amdt. 192-34, 44 FR 42968, July 23, 1979; Amdt. 192-94, 69 FR 32886,
June 14, 2004\]

**Subpart G--General Construction Requirements for Transmission Lines
and Mains.**

**§192.301 Scope.**

This subpart prescribes minimum requirements for constructing
transmission lines and mains.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.305 Inspection: General.**

Each transmission line or main must be inspected to ensure that it is
constructed in accordance with this part.

\[Part 192 - Org., Aug. 19, 1970\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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 a least be equal to either:

\(1\) The minimum thickness required by the tolerances in the
specification to which the pipe was manufactured; or

\(2\) The nominal wall thickness required for the design pressure of the
pipeline.

\(b\) Each of the following dents must be removed from steel pipe to be
operated at a pressure that produces a hoop stress of 20 percent, or
more, of SMYS, unless the dent is repaired by a method that reliable
engineering tests and analyses show can permanently restore the
serviceability of the pipe:

\(1\) A dent that contains a stress concentrator such as a scratch,
gouge, groove, or arc burn.

\(2\) A dent that affects the longitudinal weld or a circumferential
weld.

\(3\) In pipe to be operated at a pressure that produces a hoop stress
of 40 percent or more of SMYS, a dent that has a depth of:

\(i\) More than ¼ inch (6.4 millimeters) in pipe 12¾ inches (324
millimeters) or less in outer diameter; or

\(ii\) More than 2 percent of the nominal pipe diameter in pipe over 12¾
inches (324 millimeters) in outer diameter.

For the purposes 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt.
192-88, 64 FR 69660, Dec. 14, 1999\]

**§192.311 Repair of plastic pipe.**

Each imperfection or damage that would impair the serviceability of
plastic pipe must be repaired or removed.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-93, 68 FR
53895, Sept. 15, 2003\]

**§192.313 Bends and elbows.**

\(a\) Each field bend in steel pipe, other than a wrinkle bend made in
accordance with §192.315, must comply with the following:

\(1\) A bend must not impair the serviceability of the pipe.

\(2\) Each bend must have a smooth contour and be free from buckling,
cracks, or any other mechanical damage.

\(3\) On pipe containing a longitudinal weld, the longitudinal weld must
be as near as practicable to the neutral axis of the bend unless:

\(i\) The bend is made with an internal bending mandrel; or

\(ii\) The pipe is 12 inches (305 millimeters) or less in outside
diameter or has a diameter to wall thickness ratio less than 70.

\(b\) Each circumferential weld of steel pipe which is located where the
stress during bending causes a permanent deformation in the pipe must be
nondestructively tested either before or after the bending process.

\(c\) Wrought-steel welding elbows and transverse segments of these
elbows may not be used for changes in direction on steel pipe that is 2
inches (51 millimeters) or more in diameter unless the arc length, as
measured along the crotch, is at least 1 inch (25 millimeters).

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-26, 41 FR
26106, June 24, 1976; Amdt. 192-29, 42 FR 42865, Aug. 25, 1977; Amdt.
192-29C, 42 FR 60148, Nov. 25, 1977; Amdt. 192-49, 50 FR 13225, Apr. 3,
1985; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§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 1½º 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.317 Protection from hazards.**

\(a\) The operator must take all practicable steps to protect each
transmission line or main from washouts, floods, unstable soil,
landslides, or other hazards that may cause the pipeline to move or to
sustain abnormal loads. In addition, the operator must take all
practicable steps to protect offshore pipelines from damage by mud
slides, water currents, hurricanes, ship anchors, and fishing
operations.

\(b\) Each above ground 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-78, 61 FR 28770, June 6, 1996\]

**§192.319 Installation of pipe in a ditch**

\(a\) When installed in a ditch, each transmission line that is to be
operated at a pressure producing a hoop stress of 20 percent or more of
SMYS must be installed so that the pipe fits the ditch so as to minimize
stresses and protect the pipe coating from damage.

\(b\) 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.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-78, 61 FR 28770, June 6, 1996; Amdt.
192-85, 63 FR 37500, July 13, 1998\]

**§192.321 Installation of plastic pipe.**

\(a\) Plastic pipe must be installed below ground level except as
provided by paragraphs (g) and (h) of this section.

\(b\) Plastic pipe that is installed in a vault or any other below grade
enclosure must be completely encased in gas-tight metal pipe and
fittings that are adequately protected from corrosion.

\(c\) Plastic pipe must be installed so as to minimize shear or tensile
stresses.

\(d\) Thermoplastic pipe that is not encased must have a minimum wall
thickness of 0.090 inch (2.29 millimeters), except that pipe with an
outside diameter of 0.875 inch (22.3 millimeters) or less may have a
minimum wall thickness of 0.062 inch (1.58 millimeters).

\(e\) Plastic pipe that is not encased must have an electrically
conducting wire or other means of locating the pipe while it is
underground. Tracer wire may not be wrapped around the pipe and contact
with the pipe must be minimized but is not prohibited. Tracer wire or
other metallic elements installed for pipe locating purposes must be
resistant to corrosion damage, either by use of coated copper wire or by
other means.

\(f\) Plastic pipe that is being encased must be inserted into the
casing pipe in a manner that will protect the plastic. The leading end
of the plastic must be closed before insertion.

\(g\) Uncased plastic pipe may be temporarily installed above ground
level under the following conditions:

\(1\) The operator must be able to demonstrate that the cumulative
aboveground exposure of the pipe does not exceed the manufacturer\'s
recommended maximum period of exposure or 2 years, whichever is less.

\(2\) The pipe either is located where damage by external forces is
unlikely or is otherwise protected against such damage.

\(3\) The pipe adequately resists exposure to ultraviolet light and high
and low temperatures.

\(h\) Plastic pipe may be installed on bridges provided that it is:

\(1\) Installed with protection from mechanical damage, such as
installation in a metallic casing;

\(2\) Protected from ultraviolet radiation; and

\(3\) Not allowed to exceed the pipe temperature limits specified in
§192.123.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR
28770, June 6, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt.
192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-94, 69 FR 32886, June 14,
2004\]

**§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.

\[Part 192 - Org., Aug. 19, 1970\]

**§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 paragraphs (a) or (b)
of this section, each plastic transmission line or main must be
installed with sufficient clearance, or must be insulated, from any
source of heat so as to prevent the heat from impairing the
serviceability of the pipe.

\(d\) Each pipe-type or bottle-type holder must be installed with a
minimum clearance from any other holder as prescribed in §192.175(b).

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.327 Cover.**

\(a\) Except as provided in paragraphs (c), (e), (f), and (g) of this
section, each buried transmission line must be installed with a minimum
cover as follows:

+------------------------------+------------------+--------------------+
| Location                     | Normal           | Consolidated rock  |
|                              |                  |                    |
|                              | soil             |                    |
+------------------------------+------------------+--------------------+
|                              | Inches\          | Inches\            |
|                              | (Millimeters)    | (Millimeters)      |
+------------------------------+------------------+--------------------+
| Class 1 locations            | 30 (762)         | 18 (457)           |
+------------------------------+------------------+--------------------+
| Class 2, 3, and 4            | 36 (914)         | 24 (610)           |
|                              |                  |                    |
| locations                    |                  |                    |
+------------------------------+------------------+--------------------+
| Drainage ditches of public   | 36 (914)         | 24 (610)           |
| roads and railroad crossings |                  |                    |
+------------------------------+------------------+--------------------+

\(b\) Except as provided in paragraphs (c) and (d) of this section, each
buried main must be installed with at least 24 inches (610 millimeters)
of cover.

\(c\) Where an underground structure prevents the installation of a
transmission line or main with the minimum cover, the transmission line
or main may be installed with less cover if it is provided with
additional protection to withstand anticipated external loads.

\(d\) A main may be installed with less than 24 inches (610 millimeters)
of cover if the law of the State or municipality:

\(1\) Establishes a minimum cover of less than 24 inches (610
millimeters);

\(2\) Requires that mains be installed in a common trench with other
utility lines; and,

\(3\) Provides adequately for prevention of damage to the pipe by
external forces.

\(e\) Except as provided in paragraph (c) of this section, all pipe
installed in a navigable river, stream, or harbor must be installed with
a minimum cover of 48 inches (1219 millimeters) in soil or 24 inches
(610 millimeters) in consolidated rock between the top of the pipe and
the underwater natural bottom (as determined by recognized and generally
accepted practices).

\(f\) All pipe installed offshore, except in the Gulf of Mexico and its
inlets, under water not more than 200 feet (60 meters) deep, as measured
from the mean low tide, must be installed as follows:

\(1\) Except as provided in paragraph (c) of this section, pipe under
water less than 12 feet (3.66 meters) deep, must be installed with a
minimum cover of 36 inches (914 millimeters) in soil or 18 inches (457
millimeters) in consolidated rock between the top of the pipe and the
natural bottom.

\(2\) Pipe under water at least 12 feet (3.66 meters) deep must be
installed so that the top of the pipe is below the natural bottom,
unless the pipe is supported by stanchions, held in place by anchors or
heavy concrete coating, or protected by an equivalent means.

\(g\) All pipelines installed under water in the Gulf of Mexico and its
inlets, as defined in §192.3, must be installed in accordance with
§192.612(b)(3).

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-78, 61 FR 28770, June 6, 1996; Amdt.
192-85, 63 FR 37500, July 13, 1998; Amdt. 192-98, 69 FR 48400, Aug. 10,
2004\]

***Editorial Note:** §192.328 is all new material and therefore not
underlined.*

**§192.328 Additional construction requirements for steel pipe using
alternative maximum allowable operating pressure.**

For a new or existing pipeline segment to be eligible for operation at
the alternative maximum allowable operating pressure calculated under
§192.620, a segment must meet the following additional construction
requirements. Records must be maintained, for the useful life of the
pipeline, demonstrating compliance with these requirements:

+-----------------+----------------------------------------------------+
| To address this | The pipeline segment must meet this additional     |
| construction    | construction requirement:                          |
| issue:          |                                                    |
+-----------------+----------------------------------------------------+
| \(a\) Quality   | \(1\) The construction of the pipeline segment     |
| assurance.      | must be done under a quality assurance plan        |
|                 | addressing pipe inspection, hauling and stringing, |
|                 | field bending, welding, non-destructive            |
|                 | examination of girth welds, applying and testing   |
|                 | field applied coating, lowering of the pipeline    |
|                 | into the ditch, padding and backfilling, and       |
|                 | hydrostatic testing.                               |
+-----------------+----------------------------------------------------+
|                 | \(2\) The quality assurance plan for applying and  |
|                 | testing field applied coating to girth welds must  |
|                 | be:                                                |
|                 |                                                    |
|                 | \(i\) Equivalent to that required under            |
|                 | §192.112(f)(3) for pipe; and                       |
|                 |                                                    |
|                 | \(ii\) Performed by an individual with the         |
|                 | knowledge, skills, and ability to assure effective |
|                 | coating application.                               |
+-----------------+----------------------------------------------------+
| \(b\) Girth     | \(1\) All girth welds on a new pipeline segment    |
| welds.          | must be non- destructively examined in accordance  |
|                 | with §192.243(b) and (c).                          |
+-----------------+----------------------------------------------------+
| \(c\) Depth of  | \(1\) Notwithstanding any lesser depth of cover    |
| cover.          | otherwise allowed in §192.327, there must be at    |
|                 | least 36 inches (914 millimeters) of cover or      |
|                 | equivalent means to protect the pipeline from      |
|                 | outside force damage.                              |
+-----------------+----------------------------------------------------+
|                 | \(2\) In areas where deep tilling or other         |
|                 | activities could threaten the pipeline, the top of |
|                 | the pipeline must be installed at least one foot   |
|                 | below the deepest expected penetration of the      |
|                 | soil.                                              |
+-----------------+----------------------------------------------------+
| \(d\) Initial   | \(1\) The pipeline segment must not have           |
| strength        | experienced failures indicative of systemic        |
| testing.        | material defects during strength testing,          |
|                 | including initial hydrostatic testing. A root      |
|                 | cause analysis, including metallurgical            |
|                 | examination of the failed pipe, must be performed  |
|                 | for any failure experienced to verify that it is   |
|                 | not indicative of a systemic concern. The results  |
|                 | of this root cause analysis must be reported to    |
|                 | each PHMSA pipeline safety regional office where   |
|                 | the pipe is in service at least 60 days prior to   |
|                 | operating at the alternative MAOP. An operator     |
|                 | must also notify a State pipeline safety authority |
|                 | when the pipeline is located in a State where      |
|                 | PHMSA has an interstate agent agreement, or an     |
|                 | intrastate pipeline is regulated by that State.    |
+-----------------+----------------------------------------------------+
| \(e\)           | \(1\) For a new pipeline segment, the construction |
| Interference    | must address the impacts of induced alternating    |
| currents.       | current from parallel electric transmission lines  |
|                 | and other known sources of potential interference  |
|                 | with corrosion control.                            |
+-----------------+----------------------------------------------------+

\[Amdt. 192-\[107\], 73 FR 62147, October 17, 2008\]

**Subpart H--Customer Meters, Service Regulators, and Service Lines**

**§192.351 Scope.**

This subpart prescribes minimum requirements for installing customer
meters, service regulators, service lines, service line valves, and
service line connections to mains.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.353 Customer meters and regulators: Location.**

\(a\) Each meter and service regulator, whether inside or outside a
building, must be installed in a readily accessible location and be
protected from corrosion and other damage, including, if installed
outside a building, vehicular damage that may be anticipated. However,
the upstream regulator in a series may be buried.

\(b\) Each service regulator installed within a building must be located
as near as practical to the point of service line entrance.

\(c\) Each meter installed within a building must be located in a
ventilated place and not less than 3 feet (914 millimeters) from any
source of ignition or any source of heat which might damage the meter.

\(d\) Where feasible, the upstream regulator in a series must be located
outside the building, unless it is located in a separate metering or
regulating building.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.355 Customer meters and regulators: Protection from damage.**

\(a\) Protection from vacuum or back pressure. If the customer\'s
equipment might create either a vacuum or a back pressure, a device must
be installed to protect the system.

\(b\) Service regulator vents and relief vents. Service regulator vents
and relief vents must terminate outdoors, and the outdoor terminal must:

\(1\) Be rain and insect resistant;

\(2\) Be located at a place where gas from the vent can escape freely
into the atmosphere and away from any opening into the building; and,

\(3\) Be protected from damage caused by submergence in areas where
flooding may occur.

\(c\) Pits and vaults. Each pit or vault that houses a customer meter or
regulator at a place where vehicular traffic is anticipated, must be
able to support that traffic.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR
1633, Jan. 21, 1988\]

**§192.357 Customer meters and regulators: Installation.**

\(a\) Each meter and each regulator must be installed so as to minimize
anticipated stresses upon the connecting piping and the meter.

\(b\) When close all-thread nipples are used, the wall thickness
remaining after the threads are cut must meet the minimum wall thickness
requirements of this part.

\(c\) Connections made of lead or other easily damaged material may not
be used in the installation of meters or regulators.

\(d\) Each regulator that might release gas in its operation must be
vented to the outside atmosphere.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.359 Customer meter installations: Operating pressure.**

\(a\) A meter may not be used at a pressure that is more than 67 percent
of the manufacturer\'s shell test pressure.

\(b\) Each newly installed meter manufactured after November 12, 1970,
must have been tested to a minimum of 10 p.s.i. (69 kPa) gage.

\(c\) A rebuilt or repaired tinned steel case meter may not be used at a
pressure that is more than 50 percent of the pressure used to test the
meter after rebuilding or repairing.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.361 Service lines: Installation.**

\(a\) Depth. Each buried service line must be installed with at least 12
inches (305 millimeters) of cover in private property and at least 18
inches (457 millimeters) of cover in streets and roads. However, where
an underground structure prevents installation at those depths, the
service line must be able to withstand any anticipated external load.

\(b\) Support and backfill. Each service line must be properly supported
on undisturbed or well-compacted soil, and material used for backfill
must be free of materials that could damage the pipe or its coating.

\(c\) Grading for drainage. Where condensate in the gas might cause
interruption in the gas supply to the customer, the service line must be
graded so as to drain into the main or into drips at the low points in
the service line.

\(d\) Protection against piping strain and external loading. Each
service line must be installed so as to minimize anticipated piping
strain and external loading.

\(e\) Installation of service lines into buildings. Each underground
service line installed below grade through the outer foundation wall of
a building must:

\(1\) In the case of a metal service line, be protected against
corrosion;

\(2\) In the case of a plastic service line, be protected from shearing
action and backfill settlement; and

\(3\) Be sealed at the foundation wall to prevent leakage into the
building.

\(f\) Installation of service lines under buildings. Where an
underground service line is installed under a building:

\(1\) It must be encased in a gas tight conduit;

\(2\) The conduit and the service line must, if the service line
supplies the building it underlies, extend into a normally usable and
accessible part of the building; and,

\(3\) The space between the conduit and the service line must be sealed
to prevent gas leakage into the building and, if the conduit is sealed
at both ends, a vent line from the annular space must extend to a point
where gas would not be a hazard, and extend above grade, terminating in
a rain and insect resistant fitting.

\(g\) Locating underground service lines. Each underground nonmetallic
service line that is not encased must have a means of locating the pipe
that complies with §192.321(e).

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR
18512, Apr. 26, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt.
192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.363 Service lines: Valve requirements.**

\(a\) Each service line must have a service line valve that meets the
applicable requirements of Subparts B and D of this part. A valve
incorporated in a meter bar, that allows the meter to be bypassed, may
not be used as a service line valve.

\(b\) A soft seat service line valve may not be used if its ability to
control the flow of gas could be adversely affected by exposure to
anticipated heat.

\(c\) Each service line valve on a high-pressure service line, installed
above ground or in an area where the blowing of gas would be hazardous,
must be designed and constructed to minimize the possibility of the
removal of the core of the valve with other than specialized tools.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.365 Service lines: Location of valves.**

\(a\) Relation to regulator or meter. Each service line valve must be
installed upstream of the regulator or, if there is no regulator,
upstream of the meter.

\(b\) Outside valves. Each service line must have a shutoff valve in a
readily accessible location that, if feasible, is outside of the
building.

\(c\) Underground valves. Each underground service line valve must be
located in a covered durable curb box or standpipe that allows ready
operation of the valve and is supported independently of the service
lines.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.367 Service lines: General requirements for connections to main
piping.**

\(a\) Location. Each service line connection to a main must be located
at the top of the main or, if that is not practical, at the side of the
main, unless a suitable protective device is installed to minimize the
possibility of dust and moisture being carried from the main into the
service line.

\(b\) Compression-type connection to main. Each compression-type service
line to main connection must:

\(1\) Be designed and installed to effectively sustain the longitudinal
pullout or thrust forces caused by contraction or expansion of the
piping, or by anticipated external or internal loading; and

\(2\) If gaskets are used in connecting the service line to the main
connection fitting, have gaskets that are compatible with the kind of
gas in the system.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR
18512, Apr. 26, 1996\]

**§192.369 Service lines: Connections to cast iron or ductile iron
mains.**

\(a\) Each service line connected to a cast iron or ductile iron main
must be connected by a mechanical clamp, by drilling and tapping the
main, or by another method meeting the requirements of §192.273.

\(b\) If a threaded tap is being inserted, the requirements of
§192.151(b) and (c) must also be met.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.371 Service lines: Steel.**

Each steel service line to be operated at less than 100 p.s.i. (689 kPa)
gage must be constructed of pipe designed for a minimum of 100 p.s.i.
(689 kPa) gage.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17660, Nov. 17, 1970; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.373 Service lines: Cast iron and ductile iron.**

\(a\) Cast or ductile iron pipe less than 6 inches (152 millimeters) in
diameter may not be installed for service lines.

\(b\) If cast iron pipe or ductile iron pipe is installed for use as a
service line, the part of the service line which extends through the
building wall must be of steel pipe.

\(c\) A cast iron or ductile iron service line may not be installed in
unstable soil or under a building.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.375 Service lines: Plastic.**

\(a\) Each plastic service line outside a building must be installed
below ground level, except that--

\(1\) It may be installed in accordance with §192.321(g); and

\(2\) It may terminate above ground level and outside the building, if--

\(i\) The above ground level part of the plastic service line is
protected against deterioration and external damage; and

\(ii\) The plastic service line is not used to support external loads.

\(b\) Each plastic service line inside a building must be protected
against external damage.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR
28770, June 6, 1996\]

**§192.377 Service lines: Coppe**r

Each copper service line installed within a building must be protected
against external damage.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.379 New service lines not in use.**

Each service line that is not placed in service upon completion of
installation must comply with one of the following until the customer is
supplied with gas:

\(a\) The valve that is closed to prevent the flow of gas to the
customer must be provided with a locking device or other means designed
to prevent the opening of the valve by persons other than those
authorized by the operator.

\(b\) A mechanical device or fitting that will prevent the flow of gas
must be installed in the service line or in the meter assembly.

\(c\) The customer\'s piping must be physically disconnected from the
gas supply and the open pipe ends sealed.

\[Amdt. 192-8, 37 FR 20694, Oct. 1972\]

**§192.381 Service lines: Excess flow valve performance standards.**

\(a\) Excess flow valves to be used on single residence service lines
that operate continuously throughout the year at a pressure not less
than 10 p.s.i. (69 kPa) gage must be manufactured and tested by the
manufacturer according to an industry specification, or the
manufacturer\'s written specification, to ensure that each valve will:

\(1\) Function properly up to the maximum operating pressure at which
the valve is rated;

\(2\) Function properly at all temperatures reasonably expected in the
operating environment of the service line;

\(3\) At 10 p.s.i. (69 kPa) gage:

\(i\) Close at, or not more than 50 percent above, the rated closure
flow rate specified by the manufacturer; and

\(ii\) Upon closure, reduce gas flow--

\(A\) For an excess flow valve designed to allow pressure to equalize
across the valve, to no more than 5 percent of the manufacturer\'s
specified closure flow rate, up to a maximum of 20 cubic feet per hour
(0.57 cubic meters per hour); or

\(B\) For an excess flow valve designed to prevent equalization of
pressure across the valve, to no more than 0.4 cubic feet per hour (.01
cubic meters per hour); and

\(4\) Not close when the pressure is less than the manufacturer\'s
minimum specified operating pressure and the flow rate is below the
manufacturer\'s minimum specified closure flow rate.

\(b\) An excess flow valve must meet the applicable requirements of
Subparts B and D of this part.

\(c\) An operator must mark or otherwise identify the presence of an
excess flow valve on the service line.

\(d\) An operator shall locate an excess flow valve as near as practical
to the fitting connecting the service line to its source of gas supply.

\(e\) An operator should not install an excess flow valve on a service
line where the operator has prior experience with contaminants in the
gas stream, where these contaminants could be expected to cause the
excess flow valve to malfunction or where the excess flow valve would
interfere with necessary operation and maintenance activities on the
service, such as blowing liquids from the line.

\[Amdt. 192-79, 61 FR 31449, June 20, 1996 as amended by Amdt. 192-80,
62 FR 2618, Jan. 17, 1997; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.383 Excess flow valve customer notification.**

\(a\) *Definitions*. As used in this section:

***Costs associated with installation*** means the costs directly
connected with installing an excess flow valve, for example, costs of
parts, labor, inventory and procurement. It does not include maintenance
and replacement costs until such costs are incurred.

***Replaced service line*** means a natural gas service line where the
fitting that connects the service line to the main is replaced or the
piping connected to this fitting is replaced.

***Service line customer*** means the person who pays the gas bill, or
where service has not yet been established, the person requesting
service.

\(b\) *Which customers must receive notification.* Notification is
required on each newly installed service line or replaced service line
that operates continuously throughout the year at a pressure not less
than 68.9 m (10 psig) and that serves a single residence. On these lines
an operator of a natural gas distribution system must notify the service
line customer once in writing.

\(c\) *What to put in the written notice.*

\(1\) An explanation for the customer that an excess flow valve meeting
the performance standards prescribed under §192.381 is available for the
operator to install if the customer bears the costs associated with
installation;

\(2\) An explanation for the customer of the potential safety benefits
that may be derived from installing an excess flow valve. The
explanation must include that an excess flow valve is designed to shut
off the flow of natural gas automatically if the service line breaks;

\(3\) A description of installation, maintenance, and replacement costs.
The notice must explain that if the customer requests the operator to
install an EFV, the customer bears all costs associated with
installation, and what those costs are. The notice must alert the
customer that costs for maintaining and replacing an EFV may later be
incurred, and what those costs will be, to the extent known.

\(d\) *When notification and installation must be made.*

\(1\) After February 3, 1999 an operator must notify each service line
customer set forth in paragraph (b) of this section:

\(i\) On new service lines when the customer applies for service.

\(ii\) On replaced service lines when the operator determines the
service line will be replaced.

\(2\) If a service line customer requests installation an operator must
install the EFV at a mutually agreeable date.

\(e\) *What records are required.*

\(1\) An operator must make the following records available for
inspection by the Administrator or a State agency participating under 49
U.S.C. 60105 or 60106:

\(i\) A copy of the notice currently in use, and

\(ii\) Evidence that notice has been sent to the service line customers
set forth in paragraph (b) of this section, within the previous three
years.

\(2\) \[Reserved\]

\(f\) *When notification is not required*.

The notification requirements do not apply if the operator can
demonstrate--

\(1\) That the operator will voluntarily install an excess flow valve or
that the state or local jurisdiction requires installation;

\(2\) That excess flow valves meeting the performance standards of
§192.381 are not available to the operator;

\(3\) That an operator has prior experience with contaminants in the gas
stream that could interfere with the operation of an excess flow valve,
cause loss of service to a residence, or interfere with necessary
operation or maintenance activities, such as blowing liquids from the
line.

\(4\) That an emergency or short time notice replacement situation made
it impractical for the operator to notify a service line customer before
replacing a service line. Examples of these situations would be where an
operator has to replace a service line quickly because of--

\(i\) Third party excavation damage;

\(ii\) Grade 1 leaks as defined in the Appendix G--192-11 of the Gas
Piping Technology Committee guide for gas transmission and distribution
systems;

\(iii\) A short notice service line relocation request.

\[Amdt. 192-83, 63 FR 5464, Feb. 3, 1998\]

**Subpart I--Requirements for Corrosion Control**

**§192.451 Scope.**

\(a\) This subpart prescribes minimum requirements for the protection of
metallic pipelines from external, internal, and atmospheric corrosion.

\(b\) \[Reserved\]

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-27,
41 FR 34598, Aug. 16, 1976; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978\]

**§192.452 How does this subpart apply to converted pipelines and
regulated onshore gathering lines?**

\(a\) *Converted pipelines.* Notwithstanding the date the pipeline was
installed or any earlier deadlines for compliance, each pipeline which
qualifies for use under this part in accordance with §192.14 must meet
the requirements of this subpart specifically applicable to pipelines
installed before August 1, 1971, and all other applicable requirements
within 1 year after the pipeline is readied for service. However, the
requirements of this subpart specifically applicable to pipelines
installed after July 31, 1971, apply if the pipeline substantially meets
those requirements before it is readied for service or it is a segment
which is replaced, relocated, or substantially altered.

\(b\) *Regulated onshore gathering lines.* For any regulated onshore
gathering line under §192.9 existing on April 14, 2006, that was not
previously subject to this part, and for any onshore gathering line that
becomes a regulated onshore gathering line under §192.9 after April 14,
2006, because of a change in class location or increase in dwelling
density:

\(1\) The requirements of this subpart specifically applicable to
pipelines installed before August 1, 1971, apply to the gathering line
regardless of the date the pipeline was actually installed; and

\(2\) The requirements of this subpart specifically applicable to
pipelines installed after July 31, 1971, apply only if the pipeline
substantially meets those requirements.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-30,
42 FR 60146, Nov. 25, 1977, Amdt. 192-102, 71 FR 13289, Mar. 15, 2006\]

**§192.453 General.**

The corrosion control procedures required by §192.605(b)(2), including
those for the design, installation, operation, and maintenance of
cathodic protection systems, must be carried out by, or under the
direction of, a person qualified in pipeline corrosion control methods.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-71,
59 FR 6575, Feb. 11, 1994\]

**§192.455 External corrosion control: Buried or submerged pipelines
installed after July 31, 1971.**

\(a\) Except as provided in paragraphs (b), (c), and (f) of this
section, each buried or submerged pipeline installed after July 31,
1971, must be protected against external corrosion, including the
following:

\(1\) It must have an external protective coating meeting the
requirements of §192.461.

\(2\) It must have a cathodic protection system designed to protect the
pipeline in accordance with this subpart, installed and placed in
operation within 1 year after completion of construction.

\(b\) An operator need not comply with paragraph (a) of this section, if
the operator can demonstrate by tests, investigation, or experience in
the area of application, including, as a minimum, soil resistivity
measurements and tests for corrosion accelerating bacteria, that a
corrosive environment does not exist. However, within 6 months after an
installation made pursuant to the preceding sentence, the operator shall
conduct tests, including pipe-to-soil potential measurements with
respect to either a continuous reference electrode or an electrode using
close spacing, not to exceed 20 feet (6 meters), and soil resistivity
measurements at potential profile peak locations, to adequately evaluate
the potential profile along the entire pipeline. If the tests made
indicate that a corrosive condition exists, the pipeline must be
cathodically protected in accordance with paragraph (a)(2) of this
section.

\(c\) An operator need not comply with paragraph (a) of this section, if
the operator can demonstrate by tests, investigation, or experience
that-

\(1\) For a copper pipeline, a corrosive environment does not exist; or

\(2\) For a temporary pipeline with an operating period of service not
to exceed 5 years beyond installation, corrosion during the 5-year
period of service of the pipeline will not be detrimental to public
safety.

\(d\) Notwithstanding the provisions of paragraph (b) or (c) of this
section, if a pipeline is externally coated, it must be cathodically
protected in accordance with paragraph (a)(2) of this section.

\(e\) Aluminum may not be installed in a buried or submerged pipeline if
that aluminum is exposed to an environment with a natural pH in excess
of 8, unless tests or experience indicate its suitability in the
particular environment involved.

\(f\) This section does not apply to electrically isolated, metal alloy
fittings in plastic pipelines, if:

\(1\) For the size fitting to be used, an operator can show by test,
investigation, or experience in the area of application that adequate
corrosion control is provided by the alloy composition; and

\(2\) The fitting is designed to prevent leakage caused by localized
corrosion pitting.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-28,
42 FR 35654, July 11, 1977; Amdt. 192-39, 47 FR 9842, Mar. 8, 1982;
Amdt. 192-78, 61 FR 28770, June 6, 1996; Amdt. 192-85, 63 FR 37500, July
13, 1998\]

**§192.457 External corrosion control: Buried or submerged pipelines
installed before August 1, 1971.**

\(a\) Except for buried piping at compressor, regulator, and measuring
stations, each buried or submerged transmission line installed before
August 1, 1971, that has an effective external coating must be
cathodically protected along the entire area that is effectively coated,
in accordance with this subpart. For the purposes of this subpart, a
pipeline does not have an effective external coating if its cathodic
protection current requirements are substantially the same as if it were
bare. The operator shall make tests to determine the cathodic protection
current requirements.

\(b\) Except for cast iron or ductile iron, each of the following buried
or submerged pipelines installed before August 1, 1971, must be
cathodically protected in accordance with this subpart in areas in which
active corrosion is found:

\(1\) Bare or ineffectively coated transmission lines.

\(2\) Bare or coated pipes at compressor, regulator, and measuring
stations.

\(3\) Bare or coated distribution lines.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.459 External corrosion control**: **Examination of buried
pipeline when exposed.**

Whenever an operator has knowledge that any portion of a buried pipeline
is exposed, the exposed portion must be examined for evidence of
external corrosion if the pipe is bare, or if the coating is
deteriorated. If external corrosion requiring remedial action under
§§  192.483 through 192.489 is found, the operator shall investigate
circumferentially and longitudinally beyond the exposed portion (by
visual examination, indirect method, or both) to determine whether
additional corrosion requiring remedial action exists in the vicinity of
the exposed portion.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-87,
64 FR 56978, Oct. 22, 1999\]

**§192.461 External corrosion control: Protective coating.**

\(a\) Each external protective coating, whether conductive or
insulating, applied for the purpose of external corrosion control must--

\(1\) Be applied on a properly prepared surface;

\(2\) Have sufficient adhesion to the metal surface to effectively
resist underfilm migration of moisture;

\(3\) Be sufficiently ductile to resist cracking;

\(4\) Have sufficient strength to resist damage due to handling and soil
stress; and,

\(5\) Have properties compatible with any supplemental cathodic
protection.

\(b\) Each external protective coating which is an electrically
insulating type must

also have low moisture absorption and high electrical resistance.

\(c\) Each external protective coating must be inspected just prior to
lowering the pipe into the ditch and backfilling, and any damage
detrimental to effective corrosion control must be repaired.

\(d\) Each external protective coating must be protected from damage
resulting from adverse ditch conditions or damage from supporting
blocks.

\(e\) If coated pipe is installed by boring, driving, or other similar
method, precautions must be taken to minimize damage to the coating
during installation.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971\]

**§192.463 External corrosion control: Cathodic protection.**

\(a\) Each cathodic protection system required by this subpart must
provide a level of cathodic protection that complies with one or more of
the applicable criteria contained in Appendix D of this part. If none of
these criteria is applicable, the cathodic protection system must
provide a level of cathodic protection at least equal to that provided
by compliance with one or more of these criteria.

\(b\) If amphoteric metals are included in a buried or submerged
pipeline containing a metal or different anodic potential--

\(1\) The amphoteric metals must be electrically isolated from the
remainder of the pipeline and cathodically protected; or

\(2\) The entire buried or submerged pipeline must be cathodically
protected at a cathodic potential that meets the requirements of
Appendix D of this part for amphoteric metals.

\(c\) The amount of cathodic protection must be controlled so as not to
damage the protective coating or the pipe.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971\]

**§192.465 External corrosion control: Monitoring.**

\(a\) Each pipeline that is under cathodic protection must be tested at
least once each calendar year, but with intervals not exceeding 15
months, to determine whether the cathodic protection meets the
requirements of §192.463. However, if tests at those intervals are
impractical for separately protected short sections of mains or
transmission lines, not in excess of 100 feet (30 meters), or separately
protected service lines, these pipelines may be surveyed on a sampling
basis. At least 10 percent of these protected structures, distributed
over the entire system must be surveyed each calendar year, with a
different 10 percent checked each subsequent year, so that the entire
system is tested in each 10-year period.

\(b\) Each cathodic protection rectifier or other impressed current
power source must be inspected six times each calendar year, but with
intervals not exceeding 2½ months, to insure that it is operating.

\(c\) Each reverse current switch, each diode, and each interference
bond whose failure would jeopardize structure protection must be
electrically checked for proper performance six times each calendar
year, but with intervals not exceeding 2½ months. Each other
interference bond must be checked at least once each calendar year, but
with intervals not exceeding 15 months.

\(d\) Each operator shall take prompt remedial action to correct any
deficiencies indicated by the monitoring.

\(e\) After the initial evaluation required by §§ 192.455(b) and (c) and
192.457(b), each operator must, not less than every 3 years at intervals
not exceeding 39 months, reevaluate its unprotected pipelines and
cathodically protect them in accordance with this subpart in areas in
which active corrosion is found. The operator must determine the areas
of active corrosion by electrical survey. However, on distribution lines
and where an electrical survey is impractical on transmission lines,
areas of active corrosion may be determined by other means that include
review and analysis of leak repair and inspection records, corrosion
monitoring records, exposed pipe inspection records, and the pipeline
environment. In this section:

\(1\) Active corrosion means continuing corrosion which, unless
controlled, could result in a condition that is detrimental to public
safety.

\(2\) Electrical survey means a series of closely spaced pipe-to-soil
readings over a pipeline that are subsequently analyzed to identify
locations where a corrosive current is leaving the pipeline.

\(3\) Pipeline environment includes soil resistivity (high or low), soil
moisture (wet or dry), soil contaminants that may promote corrosive
activity, and other known conditions that could affect the probability
of active corrosion.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-27,
41 FR 34598, Aug. 16, 1976; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978;
Amdt. 192-35, 44 FR 75381, Dec. 20, 1979; Amdt. 192-35A, 45 FR 23441,
Apr. 7, 1980; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt. 192-93, 68
FR 53895, Sept. 15, 2003\]

**§192.467 External corrosion control: Electrical isolation.**

\(a\) Each buried or submerged pipeline must be electrically isolated
from other underground metallic structures, unless the pipeline and the
other structures are electrically interconnected and cathodically
protected as a single unit.

\(b\) One or more insulating devices must be installed where electrical
isolation of a portion of a pipeline is necessary to facilitate the
application of corrosion control.

\(c\) Except for unprotected copper inserted in a ferrous pipe, each
pipeline must be electrically isolated from metallic casings that are a
part of the underground system. However, if isolation is not achieved
because it is impractical, other measures must be taken to minimize
corrosion of the pipeline inside the casing.

\(d\) Inspection and electrical tests must be made to assure that
electrical isolation is adequate.

\(e\) An insulating device may not be installed in an area where a
combustible atmosphere is anticipated unless precautions are taken to
prevent arcing.

\(f\) Where a pipeline is located in close proximity to electrical
transmission tower footings, ground cables or counterpoise, or in other
areas where fault currents or unusual risk of lightning may be
anticipated, it must be provided with protection against damage due to
fault currents or lightning, and protective measures must also be taken
at insulating devices.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978\]

**§192.469 External corrosion control: Test stations.**

Each pipeline under cathodic protection required by this subpart must
have sufficient test stations or other contact points for electrical
measurement to determine the adequacy of cathodic protection.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-27,
41 FR 34606, Aug. 16, 1976\]

**192.471 External corrosion control: Test leads.**

\(a\) Each test lead wire must be connected to the pipeline so as to
remain mechanically secure and electrically conductive.

\(b\) Each test lead wire must be attached to the pipeline so as to
minimize stress concentration on the pipe.

\(c\) Each bared test lead wire and bared metallic area at point of
connection to the pipeline must be coated with an electrical insulating
material compatible with the pipe coating and the insulation on the
wire.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971\]

**§192.473 External corrosion control: Interference currents.**

\(a\) Each operator whose pipeline system is subjected to stray currents
shall have in effect a continuing program to minimize the detrimental
effects of such currents.

\(b\) Each impressed current type cathodic protection system or galvanic
anode system must be designed and installed so as to minimize any
adverse effects on existing adjacent underground metallic structures.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978\]

**§192.475 Internal corrosion control: General.**

\(a\) Corrosive gas may not be transported by pipeline, unless the
corrosive effect of the gas on the pipeline has been investigated and
steps have been taken to minimize internal corrosion.

\(b\) Whenever any pipe is removed from a pipeline for any reason, the
internal surface must be inspected for evidence of corrosion. If
internal corrosion is found--

\(1\) The adjacent pipe must be investigated to determine the extent of
internal corrosion:

\(2\) Replacement must be made to the extent required by the applicable
paragraphs of §§ 192.485, 192.487, or 192,489; and,

\(3\) Steps must be taken to minimize the internal corrosion.

\(c\) Gas containing more than 0.25 grain of hydrogen sulfide per 100
cubic feet (5.8 milligrams/m^3^) at standard conditions (4 parts per
million) may not be stored in pipe-type or bottle-type holders.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996;
Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**[§192.476 Internal corrosion control: Design and construction of
transmission line.]{.underline}**

[(a) Design and construction. Except as provided in paragraph (b) of
this section, each new transmission line and each replacement of line
pipe, valve, fitting, or other line component in a transmission line
must have features incorporated into its design and construction to
reduce the risk of internal corrosion. At a minimum, unless it is
impracticable or unnecessary to do so, each new transmission line or
replacement of line pipe, valve, fitting, or other line component in a
transmission line must:]{.underline}

[(1) Be configured to reduce the risk that liquids will collect in the
line;]{.underline}

[(2) Have effective liquid removal features whenever the configuration
would allow liquids to collect; and]{.underline}

[(3) Allow use of devices for monitoring internal corrosion at locations
with significant potential for internal corrosion.]{.underline}

[(b) Exceptions to applicability. The design and construction
requirements of paragraph (a) of this section do not apply to the
following:]{.underline}

[(1) Offshore pipeline; and]{.underline}

[(2) Pipeline installed or line pipe, valve, fitting or other line
component replaced before May 23, 2007.]{.underline}

[(c) Change to existing transmission line. When an operator changes the
configuration of a transmission line, the operator must evaluate the
impact of the change on internal corrosion risk to the downstream
portion of an existing onshore transmission line and provide for removal
of liquids and monitoring of internal corrosion as
appropriate.]{.underline}

[(d) Records. An operator must maintain records demonstrating compliance
with this section. Provided the records show why incorporating design
features addressing paragraph (a)(1), (a)(2), or (a)(3) of this section
is impracticable or unnecessary, an operator may fulfill this
requirement through written procedures supported by as-built drawings or
other construction records.]{.underline}

[\[72 FR 20055, April 23, 2007\]]{.underline}

**§192.477 Internal corrosion control: Monitoring.**

If corrosive gas is being transported, coupons or other suitable means
must be used to determine the effectiveness of the steps taken to
minimize internal corrosion. Each coupon or other means of monitoring
internal corrosion must be checked two times each calendar year, but
with interval not exceeding 7½ months.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978\]

**§192.479 Atmospheric corrosion control: General.**

\(a\) Each operator must clean and coat each pipeline or portion of
pipeline that is exposed to the atmosphere, except pipelines under
paragraph (c) of this section.

\(b\) Coating material must be suitable for the prevention of
atmospheric corrosion.

\(c\) Except portions of pipelines in offshore splash zones or
soil-to-air interfaces, the operator need not protect from atmospheric
corrosion any pipeline for which the operator demonstrates by test,
investigation, or experience appropriate to the environment of the
pipeline that corrosion will---

\(1\) Only be a light surface oxide; or

\(2\) Not affect the safe operation of the pipeline before the next
scheduled inspection.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.481 Atmospheric corrosion control: Monitoring.**

\(a\) Each operator must inspect each pipeline or portion of pipeline
that is exposed to the atmosphere for evidence of atmospheric corrosion,
as follows:

+--------------------------+--------------------------------------------+
| If the pipeline is       | Then the frequency of inspection is:       |
|                          |                                            |
| located:                 |                                            |
+--------------------------+--------------------------------------------+
| Onshore                  | At least once every 3 calendar years, but  |
|                          | with intervals not exceeding 39 months     |
+--------------------------+--------------------------------------------+
| Offshore                 | At least once each calendar year, but with |
|                          | intervals not exceeding 15 months          |
+--------------------------+--------------------------------------------+

\(b\) During inspections the operator must give particular attention to
pipe at soil-to-air interfaces, under thermal insulation, under
disbonded coatings, at pipe supports, in splash zones, at deck
penetrations, and in spans over water.

\(c\) If atmospheric corrosion is found during an inspection, the
operator must provide protection against the corrosion as required by
§192.479.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-27,
41 FR 34598, Aug. 16, 1976; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978;
Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.483 Remedial measures: General.**

\(a\) Each segment of metallic pipe that replaces pipe removed from a
buried or submerged pipeline because of external corrosion must have a
properly prepared surface and must be provided with an external
protective coating that meets the requirements of §192.461.

\(b\) Each segment of metallic pipe that replaces pipe removed from a
buried or submerged pipeline because of external corrosion must be
cathodically protected in accordance with this subpart.

\(c\) Except for cast iron or ductile iron pipe, each segment of buried
or submerged pipe that is required to be repaired because of external
corrosion must be cathodically protected in accordance with this
subpart.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971\]

**§192.485 Remedial measures:**

**Transmission lines.**

\(a\) *General corrosion.* Each segment of transmission line with
general corrosion and with a remaining wall thickness less than that
required for the MAOP of the pipeline must be replaced or the operating
pressure reduced commensurate with the strength of the pipe based on
actual remaining wall thickness. However, corroded pipe may be repaired
by a method that reliable engineering tests and analyses show can
permanently restore the serviceability of the pipe. Corrosion pitting so
closely grouped as to affect the overall strength of the pipe is
considered general corrosion for the purpose of this paragraph.

\(b\) *Localized corrosion pitting*. Each segment of transmission line
pipe with localized corrosion pitting to a degree where leakage might
result must be replaced or repaired, or the operating pressure must be
reduced commensurate with the strength of the pipe, based on the actual
remaining wall thickness in the pits.

\(c\) Under paragraphs (a) and (b) of this section, the strength of pipe
based on actual remaining wall thickness may be determined by the
procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research
Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply to
corroded regions that do not penetrate the pipe wall, subject to the
limitations prescribed in the procedures.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996;
Amdt. 192-88, 64 FR 69660, Dec. 14, 1999\]

**§192.487 Remedial measures: Distribution lines other than cast iron or
ductile iron lines.**

\(a\) *General corrosion.* Except for cast iron or ductile iron pipe,
each segment of generally corroded distribution line pipe with a
remaining wall thickness less than that required for the MAOP of the
pipeline, or a remaining wall thickness less than 30 percent of the
nominal wall thickness, must be replaced. However, corroded pipe may be
repaired by a method that reliable engineering tests and analyses show
can permanently restore the serviceability of the pipe. Corrosion
pitting so closely grouped as to affect the overall strength of the pipe
is considered general corrosion for the purpose of this paragraph.

\(b\) Localized corrosion pitting. Except for cast iron or ductile iron
pipe, each segment of distribution line pipe with localized corrosion
pitting to a degree where leakage might result must be replaced or
repaired.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-88,
64 FR 69660, Dec. 14, 1999\]

**§192.489 Remedial measures: Cast iron and ductile iron pipelines.**

\(a\) General graphitization. Each segment of cast iron or ductile iron
pipe on which general graphitization is found to a degree where a
fracture or any leakage might result, must be replaced.

\(b\) Localized graphitization. Each segment of cast iron or ductile
iron pipe on which localized graphitization is found to a degree where
any leakage might result, must be replaced or repaired, or sealed by
internal sealing methods adequate to prevent or arrest any leakage.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971\]

**§192.490 Direct assessment.**

Each operator that uses direct assessment as defined in §192.903 on an
onshore transmission line made primarily of steel or iron to evaluate
the effects of a threat in the first column must carry out the direct
assessment according to the standard listed in the second column. These
standards do not apply to methods associated with direct assessment,
such as close interval surveys, voltage gradient surveys, or examination
of exposed pipelines, when used separately from the direct assessment
process.

  ----------------------------------------------- -----------------------
  Threat                                          Standard1

  External corrosion                              §192.9252

  Internal corrosion in pipelines that transport  §192.927
  dry gas.                                        

  Stress corrosion cracking                       §192.929
  ----------------------------------------------- -----------------------

1For lines not subject to subpart O of this part, the terms "covered
segment\'\' and "covered pipeline segment\'\' in §§ 192.925, 192.927,
and 192.929 refer to the pipeline segment on which direct assessment is
performed.

2In §192.925(b), the provision regarding detection of coating damage
applies only to pipelines subject to subpart O of this part.

\[Amdt. 192-102, 70 FR 61571, Oct. 25, 2005\]

**§192.491 Corrosion control records.**

\(a\) Each operator shall maintain records or maps to show the location
of cathodically protected piping, cathodic protection facilities,
galvanic anodes, and neighboring structures bonded to the cathodic
protection system. Records or maps showing a stated number of anodes,
installed in a stated manner or spacing, need not show specific
distances to each buried anode.

\(b\) Each record or map required by paragraph (a) of this section must
be retained for as long as the pipeline remains in service.

\(c\) Each operator shall maintain a record of each test, survey, or
inspection required by this subpart in sufficient detail to demonstrate
the adequacy of corrosion control measures or that a corrosive condition
does not exist. These records must be retained for at least 5 years,
except that records related to §§ 192.465(a) and (e) and 192.475(b) must
be retained for as long as the pipeline remains in service.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971, as amended by Amdt. 192-33,
43 FR 39389, Sept. 5, 1978; Amdt. 192-78, 61 FR 28770, June 6, 1996\]

**Subpart J--Test Requirements**

**§192.501 Scope.**

This subpart prescribes minimum leak-test and strength-test requirements
for pipelines.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.503 General requirements.**

\(a\) No person may operate a new segment of pipeline, or return to
service a segment of pipeline that has been relocated or replaced,
until--

\(1\) It has been tested in accordance with this subpart and §192.619 to
substantiate the maximum allowable operating pressure; and

\(2\) Each potentially hazardous leak has been located and eliminated.

\(b\) The test medium must be liquid, air, natural gas, or inert gas
that is--

\(1\) Compatible with the material of which the pipeline is constructed;

\(2\) Relatively free of sedimentary materials; and,

\(3\) Except for natural gas, nonflammable.

\(c\) Except as provided in §192.505(a), if air, natural gas, or inert
gas is used as the test medium, the following maximum hoop stress
limitations apply:

+------------------------+---------------------+-----------------------+
| Class                  | Maximum hoop stress |                       |
|                        | allowed as          |                       |
| location               | percentage of SMYS  |                       |
+------------------------+---------------------+-----------------------+
|                        | Natural gas         | Air or inert gas      |
+------------------------+---------------------+-----------------------+
| 1                      | 80                  | 80                    |
+------------------------+---------------------+-----------------------+
| 2                      | 30                  | 75                    |
+------------------------+---------------------+-----------------------+
| 3                      | 30                  | 50                    |
+------------------------+---------------------+-----------------------+
| 4                      | 30                  | 40                    |
+------------------------+---------------------+-----------------------+

\(d\) Each joint used to tie in a test segment of pipeline is excepted
from the specific test requirements of this subpart, but each non-welded
joint must be leak tested at not less than its operating pressure.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR
1633, Jan. 21, 1988; Amdt. 192-60, 53 FR 36028, Sept. 16, 1988; Amdt.
192-60A, 54 FR 5485, Feb. 3, 1989\]

**§192.505 Strength test requirements for steel pipeline to operate at
a** **hoop stress of 30 percent or more of SMYS.**

\(a\) Except for service lines, each segment of a steel pipeline that is
to operate at a hoop stress of 30 percent or more of SMYS must be
strength tested in accordance with this section to substantiate the
proposed maximum allowable operating pressure. In addition, in a Class 1
or Class 2 location, if there is a building intended for human occupancy
within 300 feet (91 meters) of a pipeline, a hydrostatic test must be
conducted to a test pressure of at least 125 percent of maximum
operating pressure on that segment of the pipeline within 300 feet (91
meters) of such a building, but in no event may the test section be less
than 600 feet (183 meters) unless the length of the newly installed or
relocated pipe is less than 600 feet (183 meters). However, if the
buildings are evacuated while the hoop stress exceeds 50 percent of
SMYS, air or inert gas may be used as the test medium.

\(b\) In a Class 1 or Class 2 location, each compressor station,
regulator station, and measuring station, must be tested to at least
Class 3 location test requirements.

\(c\) Except as provided in paragraph (e) of this section, the strength
test must be conducted by maintaining the pressure at or above the test
pressure for at least 8 hours.

\(d\) If a component other than pipe is the only item being replaced or
added to a pipeline, a strength test after installation is not required,
if the manufacturer of the component certifies that--

\(1\) The component was tested to at least the pressure required for the
pipeline to which it is being added;

\(2\) The component was manufactured under a quality control system that
ensures that each item manufactured is at least equal in strength to a
prototype and that the prototype was tested to at least the pressure
required for the pipeline to which it is being added; or

\(3\) The component carries a pressure rating established through
applicable ASME/ANSI, MSS specifications, or by unit strength
calculations as described in §192.143.

\(e\) For fabricated units and short sections of pipe, for which a post
installation test is impractical, a preinstallation strength test must
be conducted by maintaining the pressure for at least 4 hours.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt.
192-94A, 69 FR 54591, Sept. 9, 2004\]

**§192.507 Test requirements for pipelines to operate at a hoop stress
less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa)
gage.**

Except for service lines and plastic pipelines, each segment of a
pipeline that is to be operated at a hoop stress less than 30 percent of
SMYS and at or above 100 p.s.i. (689 kPa) gage must be tested in
accordance with the following:

\(a\) The pipeline operator must use a test procedure that will ensure
discovery of all potentially hazardous leaks in the segment being
tested.

\(b\) If, during the test, the segment is to be stressed to 20 percent
or more of SMYS and natural gas, inert gas, or air is the test medium--

\(1\) A leak test must be made at a pressure between 100 p.s.i. (689
kPa) gage and the pressure required to produce a hoop stress of 20
percent of SMYS; or

\(2\) The line must be walked to check for leaks while the hoop stress
is held at approximately 20 percent of SMYS.

\(c\) The pressure must be maintained at or above the test pressure for
at least 1 hour.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR
1633, Jan. 21, 1988; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.509 Test requirements for pipelines to operate below 100 p.s.i.
(689 kPa) gage.**

Except for service lines and plastic pipelines, each segment of a
pipeline that is to be operated below 100 p.s.i. (689 kPa) gage must be
leak tested in accordance with the following:

\(a\) The test procedure used must ensure discovery of all potentially
hazardous leaks in the segment being tested.

\(b\) Each main that is to be operated at less than 1 p.s.i. (6.9 kPa)
gage must be tested to at least 10 p.s.i. (69 kPa) gage and each main to
be operated at or above 1 p.s.i. (6.9 kPa) gage must be tested to at
least 90 p.s.i. (621 kPa) gage.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR
1633, Jan. 21, 1988; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.511 Test requirements for service lines.**

\(a\) Each segment of a service line (other than plastic) must be leak
tested in accordance with this section before being placed in service.
If feasible, the service line connection to the main must be included in
the test; if not feasible, it must be given a leakage test at the
operating pressure when placed in service.

\(b\) Each segment of a service line (other than plastic) intended to be
operated at a pressure of at least 1 p.s.i. (6.9 kPa) gage but not more
than 40 p.s.i. (276 kPa) gage must be given a leak test at a pressure of
not less than 50 p.s.i. (345 kPa) gage.

\(c\) Each segment of a service line (other than plastic) intended to be
operated at pressures of more than 40 p.s.i. (276 kPa) gage must be
tested to at least 90 p.s.i. (621 kPa) gage, except that each segment of
the steel service line stressed to 20 percent or more of SMYS must be
tested in accordance with §192.507 of this subpart.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR
18512, Apr. 26, 1996; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.513 Test requirements for plastic pipelines.**

\(a\) Each segment of a plastic pipeline must be tested in accordance
with this section.

\(b\) The test procedure must insure discovery of all potentially
hazardous leaks in the segment being tested.

\(c\) The test pressure must be at least 150 percent of the maximum
operating pressure or 50 p.s.i. (345 kPa) gage, whichever is greater.
However, the maximum test pressure may not be more than three times the
pressure determined under §192.121, at a temperature not less than the
pipe temperature during the test.

\(d\) During the test, the temperature of thermoplastic material may not
be more than 100°F (38°C), or the temperature at which the material\'s
long-term hydrostatic strength has been determined under the listed
specification, whichever is greater.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-77, 61 FR
27789, June 3, 1996; Amdt. 192-77A, 61 FR 45905, Aug. 30, 1996; Amdt.
192-85, 63 FR 37500, July 13, 1998 \]

**§192.515 Environmental protection and safety requirements.**

\(a\) In conducting tests under this subpart, each operator shall insure
that every reasonable precaution is taken to protect its employees and
the general public during the testing. Whenever the hoop stress of the
segment of the pipeline being tested will exceed 50 percent of SMYS, the
operator shall take all practicable steps to keep persons not working on
the testing operation outside of the testing area until the pressure is
reduced to or below the proposed maximum allowable operating pressure.

\(b\) The operator shall insure that the test medium is disposed of in a
manner that will minimize damage to the environment.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.517 Records.**

\(a\) Each operator shall make, and retain for the useful life of the
pipeline, a record of each test performed under §§  192.505 and 192.507.
The record must contain at least the following information:

\(1\) The operator\'s name, the name of the operator\'s employee
responsible for making the test, and the name of any test company used.

\(2\) Test medium used.

\(3\) Test pressure.

\(4\) Test duration.

\(5\) Pressure recording charts, or other record of pressure readings.

\(6\) Elevation variations, whenever significant for the particular
test.

\(7\) Leaks and failures noted and their disposition.

\(b\) Each operator must maintain a record of each test required by §§
192.509, 192.511, and 192.513 for at least 5 years.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-93, 68 FR
53895, Sept. 15, 2003\]

**Subpart K--Uprating**

**§192.551 Scope.**

This subpart prescribes minimum requirements for increasing maximum
allowable operating pressures (uprating) for pipelines.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.553 General requirements.**

\(a\) Pressure increases. Whenever the requirements of this subpart
require that an increase in operating pressure be made in increments,
the pressure must be increased gradually, at a rate that can be
controlled, and in accordance with the following:

\(1\) At the end of each incremental increase, the pressure must be held
constant while the entire segment of the pipeline that is affected is
checked for leaks.

\(2\) Each leak detected must be repaired before a further pressure
increase is made, except that a leak determined not to be potentially
hazardous need not be repaired, if it is monitored during the pressure
increase and it does not become potentially hazardous.

\(b\) Records. Each operator who uprates a segment of pipeline shall
retain for the life of the segment a record of each investigation
required by this subpart, of all work performed, and of each pressure
test conducted, in connection with the uprating.

\(c\) Written plan. Each operator who uprates a segment of pipeline
shall establish a written procedure that will ensure that each
applicable requirement of this subpart is complied with.

\(d\) Limitation on increase in maximum allowable operating pressure.
Except as provided in §192.555(c), a new maximum allowable operating
pressure established under this subpart may not exceed the maximum that
would be allowed under §§ 192.619 and 192.621 for a new segment of
pipeline constructed of the same materials in the same location.
However, when uprating a steel pipeline, if any variable necessary to
determine the design pressure under the design formula (§192.105) is
unknown, the MAOP may be increased as provided in §192.619(a)(1).

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR
28770, June 6, 1996; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.555 Uprating to a pressure that will produce a hoop stress of 30
percent or more of SMYS in steel pipelines.**

\(a\) Unless the requirements of this section have been met, no person
may subject any segment of a steel pipeline to an operating pressure
that will produce a hoop stress of 30 percent or more of SMYS and that
is above the established maximum allowable operating pressure.

\(b\) Before increasing operating pressure above the previously
established maximum allowable operating pressure the operator shall:

\(1\) Review the design, operating, and maintenance history and previous
testing of the segment of pipeline and determine whether the proposed
increase is safe and consistent with the requirements of this part; and

\(2\) Make any repairs, replacements, or alterations in the segment of
pipeline that are necessary for safe operation at the increased
pressure.

\(c\) After complying with paragraph (b) of this section, an operator
may increase the maximum allowable operating pressure of a segment of
pipeline constructed before September 12, 1970, to the highest pressure
that is permitted under §192.619, using as test pressure the highest
pressure to which the segment of pipeline was previously subjected
(either in a strength test or in actual operation).

\(d\) After complying with paragraph (b) of this section, an operator
that does not qualify under paragraph (c) of this section may increase
the previously established maximum allowable operating pressure if at
least one of the following requirements is met:

\(1\) The segment of pipeline is successfully tested in accordance with
the requirements of this part for a new line of the same material in the
same location.

\(2\) An increased maximum allowable operating pressure may be
established for a segment of pipeline in a Class 1 location if the line
has not previously been tested, and if:

\(i\) It is impractical to test it in accordance with the requirements
of this part;

\(ii\) The new maximum operating pressure does not exceed 80 percent of
that allowed for a new line of the same design in the same location;
and,

\(iii\) The operator determines that the new maximum allowable operating
pressure is consistent with the condition of the segment of pipeline and
the design requirements of this part.

\(e\) Where a segment of pipeline is uprated in accordance with
paragraph (c) or (d)(2) of this section, the increase in pressure must
be made in increments that are equal to:

\(1\) 10 percent of the pressure before the uprating; or

\(2\) 25 percent of the total pressure increase, whichever produces the
fewer number of increments.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.557 Uprating: Steel pipelines to a pressure that will produce a
hoop stress less than 30 percent of SMYS: plastic, cast iron, and
ductile iron pipelines.**

\(a\) Unless the requirements of this section have been met, no person
may subject:

\(1\) A segment of steel pipeline to an operating pressure that will
produce a hoop stress less than 30 percent of SMYS and that is above the
previously established maximum allowable operating pressure; or

\(2\) A plastic, cast iron, or ductile iron pipeline segment to an
operating pressure that is above the previously established maximum
allowable operating pressure.

\(b\) Before increasing operating pressure above the previously
established maximum allowable operating pressure, the operator shall:

\(1\) Review the design, operating, and maintenance history of the
segment of pipeline;

\(2\) Make a leakage survey (if it has been more than 1 year since the
last survey) and repair any leaks that are found, except that a leak
determined not to be potentially hazardous need not be repaired, if it
is monitored during the pressure increase and it does not become
potentially hazardous;

\(3\) Make any repairs, replacements, or alterations in the segment of
pipeline that are necessary for safe operation at the increased
pressure;

\(4\) Reinforce or anchor offsets, bends and dead ends in pipe joined by
compression couplings or bell and spigot joints to prevent failure of
the pipe joint, if the offset, bend, or dead end is exposed in an
excavation;

\(5\) Isolate the segment of pipeline in which the pressure is to be
increased from any adjacent segment that will continue to be operated at
a lower pressure; and,

\(6\) If the pressure in mains or service lines, or both, is to be
higher than the pressure delivered to the customer, install a service
regulator on each service line and test each regulator to determine that
it is functioning. Pressure may be increased as necessary to test each
regulator, after a regulator has been installed on each pipeline subject
to the increased pressure.

\(c\) After complying with paragraph (b) of this section, the increase
in maximum allowable operating pressure must be made in increments that
are equal to 10 p.s.i. (69 kPa) gage or 25 percent of the total pressure
increase, whichever produces the fewer number of increments. Whenever
the requirements of paragraph (b)(6) of this section apply, there must
be at least two approximately equal incremental increases.

\(d\) If records for cast iron or ductile iron pipeline facilities are
not complete enough to determine stresses produced by internal pressure,
trench loading, rolling loads, beam stresses, and other bending loads,
in evaluating the level of safety of the pipeline when operating at the
proposed increased pressure, the following procedures must be followed:

\(1\) In estimating the stress, if the original laying conditions cannot
be ascertained, the operator shall assume that cast iron pipe was
supported on blocks with tamped backfill and that ductile iron pipe was
laid without blocks with tamped backfill.

\(2\) Unless the actual maximum cover depth is known, the operator shall
measure the actual cover in at least three places where the cover is
most likely to be greatest and shall use the greatest cover measured.

\(3\) Unless the actual nominal wall thickness is known, the operator
shall determine the wall thickness by cutting and measuring coupons from
at least three separate pipe lengths. The coupons must be cut from pipe
lengths in areas where the cover depth is most likely to be the
greatest. The average of all measurements taken must be increased by the
allowance indicated in the following table:

+-------------------------+------------+------------------+------------+
| Allowance (inches)      |            |                  |            |
| (millimeters)           |            |                  |            |
+-------------------------+------------+------------------+------------+
| Pipe size               | Cast iron  |                  | Ductile    |
|                         | pipe       |                  |            |
+-------------------------+------------+------------------+------------+
| (inches)\               | Pit cast   | Centrifugally    | iron pipe  |
| (millimeters)           | pipe       | cast pipe        |            |
+-------------------------+------------+------------------+------------+
| 3 to 8\                 | 0.075      | 0.065\           | 0.065\     |
| (76 to 203)             | (1.91)     | (1.65)           | (1.65)     |
+-------------------------+------------+------------------+------------+
| 10 to 12\               | 0.080      | 0.070\           | 0.070\     |
| (254 to 305)            | (2.03)     | (1.91)           | (1.91)     |
+-------------------------+------------+------------------+------------+
| 14 to 24\               | 0.080      | 0.080 (2.03)     | 0.075      |
| (356 to 610)            | (2.03)     |                  | (1.91)     |
+-------------------------+------------+------------------+------------+
| 30 to 42\               | 0.090      | 0.090 (2.29)     | 0.075      |
| (762 to 1067)           | (2.29)     |                  | (1.91)     |
+-------------------------+------------+------------------+------------+
| 48                      | 0.090      | 0.090 (2.29)     | 0.080\     |
|                         | (2.29)     |                  | (2.03)     |
| \(1219\)                |            |                  |            |
+-------------------------+------------+------------------+------------+
| 54 to 60\               | 0.090      |                  |            |
| (1372 to 1524)          | (2.29)     |                  |            |
+-------------------------+------------+------------------+------------+

(4) For cast iron pipe, unless the pipe manufacturing process is known,
the operator shall assume that the pipe is pit cast pipe with a bursting
tensile strength of 11,000 p.s.i. (76 MPa) gage and a modulus of rupture
of 31,000 p.s.i. (214 MPa) gage.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR
10157, Feb. 2, 1981; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt.
192-85, 63 FR 37500, July 13, 1998\]

**Subpart L--Operations**

**§192.601 Scope.**

This subpart prescribes minimum requirements for the operation of
pipeline facilities.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.603 General provisions**.

\(a\) No person may operate a segment of pipeline unless it is operated
in accordance with this subpart.

\(b\) Each operator shall keep records necessary to administer the
procedures established under §192.605*.*

\(c\) The Administrator or the State Agency that has submitted a current
certification under the pipeline safety laws (49 U.S.C. 60101, *et
seq*.) with respect to the pipeline facility governed by an operator\'s
plans and procedures may, after notice and opportunity for hearing as
provided in 49 CFR 190.237 or the relevant State procedures, require the
operator to amend its plans and procedures as necessary to provide a
reasonable level of safety.

\[Part 192 - Org., Aug. 9, 1970, as amended by 192-66, 56 FR 31087, July
9, 1991; Amdt. 192-71, 59 FR 6575, Feb. 11, 1994; Amdt. 192-75, 61 FR
18512, Apr. 26, 1996\]

**§192.605 Procedural manual for operations, maintenance, and
emergencies**

Each operator shall include the following in its operating and
maintenance plan:

\(a\) General. Each operator shall prepare and follow for each pipeline,
a manual of written procedures for conducting operations and maintenance
activities and for emergency response. For transmission lines, the
manual must also include procedures for handling abnormal operations.
This manual must be reviewed and updated by the operator at intervals
not exceeding 15 months, but at least once each calendar year. This
manual must be prepared before operations of a pipeline system commence.
Appropriate parts of the manual must be kept at locations where
operations and maintenance activities are conducted.

\(b\) Maintenance and normal operations. The manual required by
paragraph (a) of this section must include procedures for the following,
if applicable, to provide safety during maintenance and operations.

\(1\) Operating, maintaining, and repairing the pipeline in accordance
with each of the requirements of this subpart and Subpart M of this
part.

\(2\) Controlling corrosion in accordance with the operations and
maintenance requirements of Subpart I of this part.

\(3\) Making construction records, maps, and operating history available
to appropriate operating personnel.

\(4\) Gathering of data needed for reporting incidents under Part 191 of
this chapter in a timely and effective manner.

\(5\) Starting up and shutting down any part of the pipeline in a manner
designed to assure operation within the MAOP limits prescribed by this
part, plus the build-up allowed for operation of pressure-limiting and
control devices.

\(6\) Maintaining compressor stations, including provisions for
isolating units or sections of pipe and for purging before returning to
service.

\(7\) Starting, operating and shutting down gas compressor units.

\(8\) Periodically reviewing the work done by operator personnel to
determine the effectiveness and adequacy of the procedures used in
normal operation and maintenance and modifying the procedure when
deficiencies are found.

\(9\) Taking adequate precautions in excavated trenches to protect
personnel from the hazards of unsafe accumulations of vapor or gas, and
making available when needed at the excavation, emergency rescue
equipment, including a breathing apparatus and, a rescue harness and
line.

\(10\) Systematic and routine testing and inspection of pipe-type or
bottle-type holders including --

\(i\) Provision for detecting external corrosion before the strength of
the container has been impaired;

\(ii\) Periodic sampling and testing of gas in storage to determine the
dew point of vapors contained in the stored gas which, if condensed,
might cause internal corrosion or interfere with the safe operation of
the storage plant; and,

\(iii\) Periodic inspection and testing of pressure limiting equipment
to determine that it is in safe operating condition and has adequate
capacity.

\(11\) Responding promptly to a report of a gas odor inside or near a
building, unless the operator\'s emergency procedures under
§192.615(a)(3) specifically apply to these reports.

\(c\) Abnormal operation. For transmission lines, the manual required by
paragraph (a) of this section must include procedures for the following
to provide safety when operating design limits have been exceeded:

\(1\) Responding to, investigating, and correcting the cause of:

\(i\) Unintended closure of valves or shutdowns;

\(ii\) Increase or decrease in pressure or flow rate outside normal
operating limits;

\(iii\) Loss of communications;

\(iv\) Operation of any safety device; and,

\(v\) Any other foreseeable malfunction of a component, deviation from
normal operation, or personnel error which may result in a hazard to
persons or property.

\(2\) Checking variations from normal operation after abnormal operation
has ended at sufficient critical locations in the system to determine
continued integrity and safe operation.

\(3\) Notifying responsible operator personnel when notice of an
abnormal operation is received.

\(4\) Periodically reviewing the response of operator personnel to
determine the effectiveness of the procedures controlling abnormal
operation and taking corrective action where deficiencies are found.

\(5\) The requirements of this paragraph (c) do not apply to natural gas
distribution operators that are operating transmission lines in
connection with their distribution system.

\(d\) Safety-related condition reports. The manual required by paragraph
(a) of this section must include instructions enabling personnel who
perform operation and maintenance activities to recognize conditions
that potentially may be safety-related conditions that are subject to
the reporting requirements of §191.23 of this subchapter.

\(e\) Surveillance, emergency response, and accident investigation. The
procedures required by §§ 192.613(a), 192.615, and 192.617 must be
included in the manual required by paragraph (a) of this section

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-59, 53 FR
24942, July 1,1988; Amdt. 192-59C, 53 FR 26560, July 13, 1988; Amdt.
192-71, 59 FR 6579, Feb. 11, 1994; Amdt. 192-71A, 60 FR 14381, Mar. 17,
1995; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.607 \[Removed and Reserved\]**

\[Part 192 - Org., Aug. 10, 1970, as amended by Amdt. 192-5, 36 FR
18194, Sept. 10, 1971; Amdt. 192-78, 61 FR 28770, June 6, 1996\]

**§192.609 Change in class location: Required study.**

Whenever an increase in population density indicates a change in class
location for a segment of an existing steel pipeline operating at a hoop
stress that is more than 40 percent of SMYS, or indicates that the hoop
stress corresponding to the established maximum allowable operating
pressure for a segment of existing pipeline is not commensurate with the
present class location, the operator shall immediately make a study to
determine;

\(a\) The present class location for the segment involved.

\(b\) The design, construction, and testing procedures followed in the
original construction, and a comparison of these procedures with those
required for the present class location by the applicable provisions of
this part.

\(c\) The physical condition of the segment to the extent it can be
ascertained from available records;

\(d\) The operating and maintenance history of the segment;

\(e\) The maximum actual operating pressure and the corresponding
operating hoop stress, taking pressure gradient into account, for the
segment of pipeline involved; and,

\(f\) The actual area affected by the population density increase, and
physical barriers or other factors which may limit further expansion of
the more densely populated area.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.611 Change in class location: Confirmation or revision of maximum
allowable operating pressure.**

\(a\) If the hoop stress corresponding to the established maximum
allowable operating pressure of a segment of pipeline is not
commensurate with the present class location, and the segment is in
satisfactory physical condition, the maximum allowable operating
pressure of that segment of pipeline must be confirmed or revised
according to one of the following requirements:

\(1\) If the segment involved has been previously tested in place for a
period of not less than 8 hours[:]{.underline}

[(i) The maximum allowable operating pressure is 0.8 times the test
pressure in Class 2 locations, 0.667 times the test pressure in Class 3
locations, or 0.555 times the test pressure in Class 4 locations. The
corresponding hoop stress may not exceed 72 percent of the SMYS of the
pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or
50 percent of SMYS in Class 4 locations.]{.underline}

[(ii) The alternative maximum allowable operating pressure is 0.8 times
the test pressure in Class 2 locations and 0.667 times the test pressure
in Class 3 locations. For pipelines operating at alternative maximum
allowable pressure per §192.620, the corresponding hoop stress may not
exceed 80 percent of the SMYS of the pipe in Class 2 locations and 67
percent of SMYS in Class 3 locations.]{.underline}[,]{.mark} [the
maximum allowable operating pressure is 0.8 times the test pressure in
Class 2 locations, 0.667 times the test pressure in Class 3 locations,
or 0.555 times the test pressure in Class 4 locations. The corresponding
hoop stress may not exceed 72 percent of the SMYS of the pipe in Class 2
locations, 60 percent of SMYS in Class 3 locations, or 50 percent of
SMYS in Class 4 locations.]{.mark}

\(2\) The maximum allowable operating pressure of the segment involved
must be reduced so that the corresponding hoop stress is not more than
that allowed by this part for new segments of pipelines in the existing
class location.

\(3\) The segment involved must be tested in accordance with the
applicable requirements of Subpart J of this part, and its maximum
allowable operating pressure must then be established according to the
following criteria:

\(i\) The maximum allowable operating pressure after the requalification
test is 0.8 times the test pressure for Class 2 locations, 0.667 times
the test pressure for Class 3 locations, and 0.555 times the test
pressure for Class 4 locations.

\(ii\) The corresponding hoop stress may not exceed 72 percent of the
SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3
locations, or 50 percent of SMYS in Class 4 locations.

[(iii) For pipeline operating at an alternative maximum allowable
operating pressure per §192.620, the alternative maximum allowable
operating pressure after the requalification test is 0.8 times the test
pressure for Class 2 locations and 0.667 times the test pressure for
Class 3 locations. The corresponding hoop stress may not exceed 80
percent of the SMYS of the pipe in Class 2 locations and 67 percent of
SMYS in Class 3 locations.]{.underline}

\(b\) The maximum allowable operating pressure confirmed or revised in
accordance with this section, may not exceed the maximum allowable
operating pressure established before the confirmation or revision.

\(c\) Confirmation or revision of the maximum allowable operating
pressure of a segment of pipeline in accordance with this section does
not preclude the application of §§ 192.553 and 192.555.

\(d\) Confirmation or revision of the maximum allowable operating
pressure that is required as a result of a study under §192.609 must be
completed within 24 months of the change in class location. Pressure
reduction under paragraph (a) (1) or (2) of this section within the
24-month period does not preclude establishing a maximum allowable
operating pressure under paragraph (a)(3) of this section at a later
date.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-5, 36 FR
18195, Sept. 10, 1971; Amdt. 192-53, 51 FR 34987, Oct. 1, 1986; Amdt.
192-63, 54 FR 24173, June 6, 1989; Amdt. 192-78, 61 FR 28770, June 6,
1996; Amdt. 192-94, 69 FR 32886, June 14, 2004[; Amdt. 192-\[107\], 73
FR 62147, October 17, 2008]{.underline}\]

**§192.612 Underwater inspection and reburial of pipelines in the Gulf
of Mexico and its inlets.**

\(a\) Each operator shall prepare and follow a procedure to identify its
pipelines in the Gulf of Mexico and its inlets in waters less than 15
feet (4.6 meters) deep as measured from mean low water that are at risk
of being an exposed underwater pipeline or a hazard to navigation. The
procedures must be in effect August 10, 2005.

\(b\) Each operator shall conduct appropriate periodic underwater
inspections of its pipelines in the Gulf of Mexico and its inlets in
waters less than 15 feet (4.6 meters) deep as measured from mean low
water based on the identified risk.

\(c\) If an operator discovers that its pipeline is an exposed
underwater pipeline or poses a hazard to navigation, the operator
shall---

\(1\) Promptly, but not later than 24 hours after discovery, notify the
National Response Center, telephone: 1-800-424-8802, of the location
and, if available, the geographic coordinates of that pipeline.

\(2\) Promptly, but not later than 7 days after discovery, mark the
location of the pipeline in accordance with 33 CFR part 64 at the ends
of the pipeline segment and at intervals of not over 500 yards (457
meters) long, except that a pipeline segment less than 200 yards (183
meters) long need only be marked at the center; and

\(3\) Within 6 months after discovery, or not later than November 1 of
the following year if the 6 month period is later than November 1 of the
year of discovery, bury the pipeline so that the top of the pipe is 36
inches (914 millimeters) below the underwater natural bottom (as
determined by recognized and generally accepted practices) for normal
excavation or 18 inches (457 millimeters) for rock excavation.

\(i\) An operator may employ engineered alternatives to burial that meet
or exceed the level of protection provided by burial.

\(ii\) If an operator cannot obtain required state or Federal permits in
time to comply with this section, it must notify OPS; specify whether
the required permit is State or Federal; and, justify the delay.

\[Amdt*.* 192-67, 56 FR 63764, Dec. 5, 1991 as amended by Amdt 192-85,
63 FR 37500, July 13, 1998; Amdt. 192-98, 69 FR 48400, Aug. 10, 2004\]

**§192.613 Continuing Surveillance.**

\(a\) Each operator shall have a procedure for continuing surveillance
of its facilities to determine and take appropriate action concerning
changes in class location, failures, leakage history, corrosion,
substantial changes in cathodic protection requirements, and other
unusual operating and maintenance conditions.

\(b\) If a segment of pipeline is determined to be in unsatisfactory
condition but no immediate hazard exists, the operator shall initiate a
program to recondition or phase out the segment involved, or, if the
segment cannot be reconditioned or phased out, reduce the maximum
allowable operating pressure in accordance with §192.619(a) and (b).

\[Part 192 - Org., Aug. 19, 1970\]

**§192.614 Damage prevention program.**

\(a\) Except as provided in paragraphs (d) and (e) of this section, each
operator of a buried pipeline shall carry out, in accordance with this
section, a written program to prevent damage to that pipeline from
excavation activities. For the purpose of this section, the term
\"excavation activities\" includes excavation, blasting, boring,
tunneling, backfilling, the removal of above ground structures by either
explosive or mechanical means, and other earth moving operations.

\(b\) An operator may comply with any of the requirements of paragraph
(c) of this section through participation in a public service program,
such as a one-call system, but such participation does not relieve the
operator of responsibility for compliance with this section. However, an
operator must perform the duties of paragraph (c)(3) of this section
through participation in a one-call system, if that one-call system is a
qualified one-call system. In areas that are covered by more than one
qualified one-call system, an operator need only join one of the
qualified one-call systems if there is a central telephone number for
excavators to call for excavation activities, or if the one-call systems
in those areas communicate with one another. An operator's pipeline
system must be covered by a qualified one-call system where there is one
in place. For the purpose of this section, a one-call system is
considered a "qualified one-call system" if it meets the requirements of
section (b)(1) or (b)(2) of this section.

\(1\) The state has adopted a one-call damage prevention program under
§198.37 of this chapter, or

\(2\) The one-call system:

\(i\) Is operated in accordance with §198.39 of this chapter;

\(ii\) Provides a pipeline operator an opportunity similar to a
voluntary participant to have a part in management responsibilities; and

\(iii\) Assesses a participating pipeline operator a fee that is
proportionate to the costs of the one-call system's coverage of the
operator's pipeline.

\(c\) The damage prevention program required by paragraph (a) of this
section must, at a minimum:

\(1\) Include the identity, on a current basis, of persons who normally
engage in excavation activities in the area in which the pipeline is
located.

\(2\) Provides for notification of the public in the vicinity of the
pipeline and actual notification of the persons identified in paragraph
(c)(1) of this section of the following as often as needed to make them
aware of the damage prevention program:

\(i\) The program\'s existence and purpose; and

\(ii\) How to learn the location of underground pipelines before
excavation activities are begun.

\(3\) Provide a means of receiving and recording notification of planned
excavation activities.

\(4\) If the operator has buried pipelines in the area of excavation
activity, provide for actual notification of persons who give notice of
their intent to excavate of the type of temporary marking to be provided
and how to identify the markings.

\(5\) Provide for temporary marking of buried pipelines in the area of
excavation activity before, as far as practical, the activity begins.

\(6\) Provide as follows for inspection of pipelines that an operator
has reason to believe could be damaged by excavation activities:

\(i\) The inspection must be done as frequently as necessary during and
after the activities to verify the integrity of the pipeline; and

\(ii\) In the case of blasting, any inspection must include leakage
surveys.

\(d\) A damage prevention program under this section is not required for
the following pipelines:

\(1\) Pipelines located offshore.

\(2\) Pipelines, other than those located offshore, in Class 1 or 2
locations until September 20, 1995.

\(3\) Pipelines to which access is physically controlled by the
operator.

\(e\) Pipelines operated by persons other than municipalities (including
operators of master meters) whose primary activity does not include the
transportation of gas need not comply with the following:

\(1\) The requirement of paragraph (a) of this section that the damage
prevention program be written; and

\(2\) The requirements of paragraphs (c)(1) and (c)(2) of this section.

\[Amdt. 192-40, 47 FR 13818, Apr. 1, 1982; Amdt. 192-57, 52 FR 32798,
Aug. 31, 1987; Amdt. 192-73, 60 FR 14646, Mar. 20, 1995; Amdt. 192-78,
61 FR 28770, June 6, 1996; Amdt. 192-82, 62 FR 61695, Nov. 19, 1997;
Amdt. 192-84, 63 FR 7721, Feb. 17, 1998; Amdt. 192-84A, 63 FR 38757,
July 20, 1998\]

**§192.615 Emergency plans.**

\(a\) Each operator shall establish written procedures to minimize the
hazard resulting from a gas pipeline emergency. At a minimum, the
procedures must provide for the following:

\(1\) Receiving, identifying, and classifying notices of events which
require immediate response by the operator.

\(2\) Establishing and maintaining adequate means of communication with
appropriate fire, police, and other public officials.

\(3\) Prompt and effective response to a notice of each type of
emergency, including the following:

\(i\) Gas detected inside or near a building.

\(ii\) Fire located near or directly involving a pipeline facility.

\(iii\) Explosion occurring near or directly involving a pipeline
facility.

\(iv\) Natural disaster.

\(4\) The availability of personnel, equipment, tools, and materials, as
needed at the scene of an emergency.

\(5\) Actions directed toward protecting people first and then property.

\(6\) Emergency shutdown and pressure reduction in any section of the
operator\'s pipeline system necessary to minimize hazards to life or
property.

\(7\) Making safe any actual or potential hazard to life or property.

\(8\) Notifying appropriate fire, police, and other public officials of
gas pipeline emergencies and coordinating with them both planned
responses and actual responses during an emergency.

\(9\) Safely restoring any service outage.

\(10\) Beginning action under §192.617, if applicable, as soon after the
end of the emergency as possible.

\(b\) Each operator shall:

\(1\) Furnish its supervisors who are responsible for emergency action a
copy of that portion of the latest edition of the emergency procedures
established under paragraph (a) of this section as necessary for
compliance with those procedures.

\(2\) Train the appropriate operating personnel to assure that they are
knowledgeable of the emergency procedures and verify that the training
is effective.

\(3\) Review employee activities to determine whether the procedures
were effectively followed in each emergency.

\(c\) Each operator shall establish and maintain liaison with
appropriate fire, police, and other public officials to:

\(1\) Learn the responsibility and resources of each government
organization that may respond to a gas pipeline emergency;

\(2\) Acquaint the officials with the operator\'s ability in responding
to a gas pipeline emergency;

\(3\) Identify the types of gas pipeline emergencies of which the
operator notifies the officials; and,

\(4\) Plan how the operator and officials can engage in mutual
assistance to minimize hazards to life or property.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-24, 41 FR
13586, Mar. 31, 1976; Amdt. 192-71, 59 FR 6585, Feb. 11, 1994\]

**§192.616 Public awareness.**

\(a\) Except for an operator of a master meter or petroleum gas system
covered under paragraph (j) of this section, each pipeline operator must
develop and implement a written continuing public education program that
follows the guidance provided in the American Petroleum Institute\'s
(API) Recommended Practice (RP) 1162 (IBR, see §192.7).

\(b\) The operator\'s program must follow the general program
recommendations of API RP 1162 and assess the unique attributes and
characteristics of the operator\'s pipeline and facilities.

\(c\) The operator must follow the general program recommendations,
including baseline and supplemental requirements of API RP 1162, unless
the operator provides justification in its program or procedural manual
as to why compliance with all or certain provisions of the recommended
practice is not practicable and not necessary for safety.

\(d\) The operator\'s program must specifically include provisions to
educate the public, appropriate government organizations, and persons
engaged in excavation related activities on:

\(1\) Use of a one-call notification system prior to excavation and
other damage prevention activities;

\(2\) Possible hazards associated with unintended releases from a gas
pipeline facility;

\(3\) Physical indications that such a release may have occurred;

\(4\) Steps that should be taken for public safety in the event of a gas
pipeline release; and

\(5\) Procedures for reporting such an event.

\(e\) The program must include activities to advise affected
municipalities, school districts, businesses, and residents of pipeline
facility locations.

\(f\) The program and the media used must be as comprehensive as
necessary to reach all areas in which the operator transports gas.

\(g\) The program must be conducted in English and in other languages
commonly understood by a significant number and concentration of the
non-English speaking population in the operator\'s area.

\(h\) Operators in existence on June 20, 2005, must have completed their
written programs no later than June 20, 2006. [The operator of a master
meter or petroleum gas system covered under paragraph (j) of this
section must complete development of its written procedure by June 13,
2008.]{.underline} [As an exception, operators of small propane
distribution systems having less than 25 customers and master meter
operators having less than 25 customers must have completed development
and documentation of their programs no later than June 20, 2007.]{.mark}
Upon request, operators must submit their completed programs to PHMSA
or, in the case of an intrastate pipeline facility operator, the
appropriate State agency.

\(i\) The operator\'s program documentation and evaluation results must
be available for periodic review by appropriate regulatory agencies.

[(j) Unless the operator transports gas as a primary activity, the
operator of a master meter or petroleum gas system is not required to
develop a public awareness program as prescribed in paragraphs (a)
through (g) of this section. Instead the operator must develop and
implement a written procedure to provide its customers public awareness
messages twice annually. If the master meter or petroleum gas system is
located on property the operator does not control, the operator must
provide similar messages twice annually to persons controlling the
property. The public awareness message must include:]{.underline}

[(1) A description of the purpose and reliability of the
pipeline;]{.underline}

[(2) An overview of the hazards of the pipeline and prevention measures
used;]{.underline}

[(3) Information about damage prevention;]{.underline}

[(4) How to recognize and respond to a leak; and]{.underline}

[(5) How to get additional information.]{.underline}

\[Amdt. 192-71, 59 FR 6575, Feb. 11, 1994 as amended by Amdt. 192-99, 70
FR 28833, May 19, 2005; Amdt. 192-99A, 70 FR 35041, June 16, 2005[;
Amdt. 192-\[105\], 72 FR 70808, Dec. 13, 2007]{.underline}\]

**§192.617 Investigation of failures.**

Each operator shall establish procedures for analyzing accidents and
failures, including the selection of samples of the failed facility or
equipment for laboratory examination, where appropriate, for the purpose
of determining the causes of the failure and minimizing the possibility
of a recurrence.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.619 What is the maximum allowable operating pressure for steel or
plastic pipelines?**

\(a\) [No person may operate a segment of steel or plastic pipeline at a
pressure that exceeds a maximum allowable operating pressure determined
under paragraph (c) or (d) of this section, or the lowest of the
following:]{.underline}[Except as provided in paragraph (c) of this
section, no person may operate a segment of steel or plastic pipeline at
a pressure that exceeds the lowest of the following:]{.mark}

\(1\) The design pressure of the weakest element in the segment,
determined in accordance with Subparts C and D of this part. However,
for steel pipe in pipelines being converted under §192.14 or uprated
under subpart K of this part, if any variable necessary to determine the
design pressure under the design formula (§192.105) is unknown, one of
the following pressures is to be used as design pressure:

\(i\) Eighty percent of the first test pressure that produces yield
under section N5 of Appendix N of ASME B31.8 (incorporated by reference,
*[see]{.underline}* § 192.7), reduced by the appropriate factor in
paragraph (a)(2)(ii) of this section; or

\(ii\) If the pipe is 12¾ inches (324 mm) or less in outside diameter
and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa)
gage.

\(2\) The pressure obtained by dividing the pressure to which the
segment was tested after construction as follows:

\(i\) For plastic pipe in all locations, the test pressure is divided by
a factor of 1.5.

\(ii\) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, the
test pressure is divided by a factor determined in accordance with the
following table:

+-----------------+-----------------+-----------------+-----------------+
|                 | Factors^1^,     |                 |                 |
|                 | segment         |                 |                 |
+-----------------+-----------------+-----------------+-----------------+
| Class location  | Installed       | Installed       | Covered under   |
|                 |                 |                 | §192.14         |
|                 | before          | after           |                 |
|                 |                 |                 |                 |
|                 | Nov. 12, 1970   | Nov. 11, 1970   |                 |
+-----------------+-----------------+-----------------+-----------------+
| 1               | 1.1             | 1.1             | 1.25            |
+-----------------+-----------------+-----------------+-----------------+
| 2               | 1.25            | 1.25            | 1.25            |
+-----------------+-----------------+-----------------+-----------------+
| 3               | 1.4             | 1.5             | 1.5             |
+-----------------+-----------------+-----------------+-----------------+
| 4               | 1.4             | 1.5             | 1.5             |
+-----------------+-----------------+-----------------+-----------------+

^1^ For offshore segments installed, uprated or converted after July 31,
1977, that are not located on an offshore platform, the factor is 1.25.
For segments installed, uprated or converted after July 31, 1977, that
are located on an offshore platform or on a platform in inland navigable
waters, including a pipe riser, the factor is 1.5.

\(3\) The highest actual operating pressure to which the segment was
subjected during the 5 years preceding the applicable date in the second
column. This pressure restriction applies unless the segment was tested
according to the requirements in paragraph (a)(2) of this section after
the applicable date in the third column or the segment was uprated
according to the requirements in subpart K of this part:

+---------------------------+-------------------------+----------------+
| Pipeline segment          | Pressure date           | Test date      |
+---------------------------+-------------------------+----------------+
| ---Onshore gathering line | March 15, 2006, or date | 5 years        |
| that first became subject | line becomes subject to | preceding      |
| to this part (other than  | this part, whichever is | applicable     |
| §192.612) after April 13, | later.                  | date in second |
| 2006.                     |                         | column.        |
|                           |                         |                |
| ---Onshore transmission   |                         |                |
| line that was a gathering |                         |                |
| line not subject to this  |                         |                |
| part before March 15,     |                         |                |
| 2006.                     |                         |                |
+---------------------------+-------------------------+----------------+
| Offshore gathering lines. | July 1, 1976.           | July 1, 1971.  |
+---------------------------+-------------------------+----------------+
| All other pipelines.      | July 1, 1970.           | July 1, 1965.  |
+---------------------------+-------------------------+----------------+

\(4\) The pressure determined by the operator to be the maximum safe
pressure after considering the history of the segment, particularly
known corrosion and the actual operating pressure.

\(b\) No person may operate a segment to which paragraph (a)(4) of this
section is applicable, unless overpressure protective devices are
installed on the segment in a manner that will prevent the maximum
allowable operating pressure from being exceeded, in accordance with
§192.195.

\(c\) The requirements on pressure restrictions in this section do not
apply in the following instance. An operator may operate a segment of
pipeline found to be in satisfactory condition, considering its
operating and maintenance history, at the highest actual operating
pressure to which the segment was subjected during the 5 years preceding
the applicable date in the second column of the table in paragraph
(a)(3) of this section. An operator must still comply with §192.611.

[(d) The operator of a pipeline segment of steel pipeline meeting the
conditions prescribed in §192.620(b) may elect to operate the segment at
a maximum allowable operating pressure determined under
§192.620(a).]{.underline}

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-3, 35 FR 17559,
Nov. 17, 1970; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt. 192-27A,
41 FR 47252, Oct. 28, 1976; Amdt. 192-30, 42 FR 60146, Nov. 25, 1977;
Amdt. 192-78, 61 FR 28770, June 6, 1996; Amdt 192-85, 63 FR 37500, July
13, 1998, Amdt. 192-102, 71 FR 13289, Mar. 15, 2006; Amdt. 192-103, 71
FR 33402, June 8, 2006[; Amdt. 192-\[107\], 73 FR 62147, October 17,
2008]{.underline}\]

***Editorial Note:** §192.620 is all new material and therefore not
underlined.*

**§192.620 Alternative maximum allowable operating pressure for certain
steel pipelines.**

\(a\) *How does an operator calculate the alternative maximum allowable
operating pressure?* An operator calculates the alternative maximum
allowable operating pressure by using different factors in the same
formulas used for calculating maximum allowable operating pressure under
§192.619(a) as follows:

\(1\) In determining the alternative design pressure under §192.105, use
a design factor determined in accordance with §192.111(b), (c), or (d)
or, if none of these paragraphs apply, in accordance with the following
table:

  ------------------------------- ---------------------------------------
  Class Location                  Alternative design factor (F)

  1                               0.80

  2                               0.67

  3                               0.56
  ------------------------------- ---------------------------------------

\(i\) For facilities installed prior to November 17, 2008, for which
§192.111(b), (c), or (d) apply, use the following design factors as
alternatives for the factors specified in those paragraphs:
§192.111(b)--0.67 or less; 192.111(c) and (d)--0.56 or less.

\(ii\) \[Reserved\]

\(2\) The alternative maximum allowable operating pressure is the lower
of the following:

\(i\) The design pressure of the weakest element in the pipeline
segment, determined under subparts C and D of this part.

\(ii\) The pressure obtained by dividing the pressure to which the
pipeline segment was tested after construction bya factor determined in
the following table:

  --------------------------------- -------------------------------------
  Class Location                    Alternative test factor

  1                                 1.25

  2                                 ^1^1.50

  3                                 1.50
  --------------------------------- -------------------------------------

^1^For Class 2 alternative maximum allowable operating pressure segments
installed prior to November 17, 2008, the alternative test factor is
1.25.

\(b\) *When may an operator use the alternative maximum allowable
operating pressure calculated under paragraph (a) of this section?* An
operator may use an alternative maximum allowable operating pressure
calculated under paragraph (a) of this section if the following
conditions are met:

\(1\) The pipeline segment is in a Class 1, 2, or 3 location;

\(2\) The pipeline segment is constructed of steel pipe meeting the
additional design requirements in §192.112;

\(3\) A supervisory control and data acquisition system provides remote
monitoring and control of the pipeline segment. The control provided
must include monitoring of pressures and flows, monitoring compressor
start-ups and shut-downs, and remote closure of valves;

\(4\) The pipeline segment meets the additional construction
requirements described in §192.328;

\(5\) The pipeline segment does not contain any mechanical couplings
used in place of girth welds;

\(6\) If a pipeline segment has been previously operated, the segment
has not experienced any failure during normal operations indicative of a
systemic fault in material as determined by a root cause analysis,
including metallurgical examination of the failed pipe. The results of
this root cause analysis must be reported to each PHMSA pipeline safety
regional office where the pipeline is in service at least 60 days prior
to operation at the alternative MAOP. An operator must also notify a
State pipeline safety authority when the pipeline is located in a State
where PHMSA has an interstate agent agreement, or an intrastate pipeline
is regulated by that State; and

\(7\) At least 95 percent of girth welds on a segment that was
constructed prior to November 17, 2008, must have been non-destructively
examined in accordance with §192.243(b) and (c).

\(c\) *What is an operator electing to use the alternative maximum
allowable operating pressure required to do?* If an operator elects to
use the alternative maximum allowable operating pressure calculated
under paragraph (a) of this section for a pipeline segment, the operator
must do each of the following:

\(1\) Notify each PHMSA pipeline safety regional office where the
pipeline is in service of its election with respect to a segment at
least 180 days before operating at the alternative maximum allowable
operating pressure. An operator must also notify a State pipeline safety
authority when the pipeline is located in a State where PHMSA has an
interstate agent agreement, or an intrastate pipeline is regulated by
that State.

\(2\) Certify, by signature of a senior executive officer of the
company, as follows:

\(i\) The pipeline segment meets the conditions described in paragraph
(b) of this section; and

\(ii\) The operating and maintenance procedures include the additional
operating and maintenance requirements of paragraph (d) of this section;
and

\(iii\) The review and any needed program upgrade of the damage
prevention program required by paragraph (d)(4)(v) of this section has
been completed.

\(3\) Send a copy of the certification required by paragraph (c)(2) of
this section to each PHMSA pipeline safety regional office where the
pipeline is in service 30 days prior to operating at the alternative
MAOP. An operator must also send a copy to a State pipeline safety
authority when the pipeline is located in a State where PHMSA has an
interstate agent agreement, or an intrastate pipeline is regulated by
that State.

\(4\) For each pipeline segment, do one of the following:

\(i\) Perform a strength test as described in §192.505 at a test
pressure calculated under paragraph (a) of this section or

\(ii\) For a pipeline segment in existence prior to November 17, 2008,
certify, under paragraph (c)(2) of this section, that the strength test
performed under §192.505 was conducted at a test pressure calculated
under paragraph (a) of this section, or conduct a new strength test in
accordance with paragraph (c)(4)(i) of this section.

\(5\) Comply with the additional operation and maintenance requirements
described in paragraph (d) of this section.

\(6\) If the performance of a construction task associated with
implementing alternative MAOP can affect the integrity of the pipeline
segment, treat that task as a "covered task", notwithstanding the
definition in §192.801(b) and implement the requirements of subpart N as
appropriate.

\(7\) Maintain, for the useful life of the pipeline, records
demonstrating compliance with paragraphs (b), (c)(6), and (d) of this
section.

\(8\) A Class 1 and Class 2 pipeline location can be upgraded one class
due to class changes per §192.611(a)(3)(i). All class location changes
from Class 1 to Class 2 and from Class 2 to Class 3 must have all
anomalies evaluated and remediated per: The \`\`original pipeline class
grade\'\' §192.620(d)(11) anomaly repair requirements; and all anomalies
with a wall loss equal to or greater than 40 percent must be excavated
and remediated. Pipelines in Class 4 may not operate at an alternative
MAOP.

\(d\) *What additional operation and maintenance requirements apply to
operation at the alternative maximum allowable operating pressure?* In
addition to compliance with other applicable safety standards in this
part, if an operator establishes a maximum allowable operating pressure
for a pipeline segment under paragraph (a) of this section, an operator
must comply with the additional operation and maintenance requirements
as follows:

+-------------------+--------------------------------------------------+
| To address        | Take the following additional step:              |
| increased risk of |                                                  |
| a maximum         |                                                  |
| allowable         |                                                  |
| operating         |                                                  |
| pressure based on |                                                  |
| higher            |                                                  |
| stresslevels in   |                                                  |
| the following     |                                                  |
| areas:            |                                                  |
+-------------------+--------------------------------------------------+
| \(1\) Identifying | Develop a threat matrix consistent with §        |
| and evaluating    | 192.917 to do the following:                     |
| threats.          |                                                  |
|                   | > \(i\) Identify and compare the increased risk  |
|                   | > of operating the pipeline at the increased     |
|                   | > stress level under this section with           |
|                   | > conventional operation; and                    |
|                   | >                                                |
|                   | > \(ii\) Describe and implement procedures used  |
|                   | > to mitigate the risk                           |
+-------------------+--------------------------------------------------+
| \(2\) Notifying   | \(i\) Recalculate the potential impact circle as |
| the public.       | defined in § 192.903 to reflect use of the       |
|                   | alternative maximum operating pressure           |
|                   | calculated under paragraph (a) of this section   |
|                   | and pipeline operating conditions; and           |
|                   |                                                  |
|                   | \(ii\) In implementing the public education      |
|                   | program required under § 192.616, perform the    |
|                   | following:                                       |
|                   |                                                  |
|                   | \(A\) Include persons occupying property within  |
|                   | 220 yards of the centerline and within the       |
|                   | potential impact circle within the targeted      |
|                   | audience; and                                    |
|                   |                                                  |
|                   | \(B\) Include information about the integrity    |
|                   | management activities performed under this       |
|                   | section within the message provided to the       |
|                   | audience.                                        |
+-------------------+--------------------------------------------------+
| \(3\) Responding  | \(i\) Ensure that the identification of high     |
| to an emergency   | consequence areas reflects the larger potential  |
| in an area        | impact circle recalculated under paragraph       |
| defined as a high | (d)(1)(i) of this section.                       |
| consequence area  |                                                  |
| in §192.903.      | \(ii\) If personnel response time to mainline    |
|                   | valves on either side of the high consequence    |
|                   | area exceeds one hour (under normal driving      |
|                   | conditions and speed limits) from the time the   |
|                   | event is identified in the control room, provide |
|                   | remote valve control through a supervisory       |
|                   | control and data acquisition (SCADA) system,     |
|                   | other leak detection system, or an alternative   |
|                   | method of control.                               |
|                   |                                                  |
|                   | \(iii\) Remote valve control must include the    |
|                   | ability to close and monitor the valve position  |
|                   | (open or closed), and monitor pressure upstream  |
|                   | and downstream.(iv) A line break valve control   |
|                   | system using differential pressure, rate of      |
|                   | pressure drop or other widely-accepted method is |
|                   | an acceptable alternative to remote valve        |
|                   | control.                                         |
+-------------------+--------------------------------------------------+
| \(4\) Protecting  | \(i\) Patrol the right-of-way at intervals not   |
| the right-of-way. | exceeding 45 days, but at least 12 times each    |
|                   | calendar year, to inspect for excavation         |
|                   | activities, ground movement, wash outs, leakage, |
|                   | or other activities or conditions affecting the  |
|                   | safety operation of the pipeline.                |
|                   |                                                  |
|                   | \(ii\) Develop and implement a plan to monitor   |
|                   | for and mitigate occurrences of unstable soil    |
|                   | and ground movement.                             |
|                   |                                                  |
|                   | \(iii\) If observed conditions indicate the      |
|                   | possible loss of cover, perform a depth of cover |
|                   | study and replace cover as necessary to restore  |
|                   | the depth of cover or apply alternative means to |
|                   | provide protection equivalent to the             |
|                   | originally-required depth of cover.              |
|                   |                                                  |
|                   | \(iv\) Use line-of-sight line markers satisfying |
|                   | the requirements of §192.707(d) except in        |
|                   | agricultural areas, large water crossings or     |
|                   | swamp, steep terrain, or where prohibited by     |
|                   | Federal Energy Regulatory Commission orders,     |
|                   | permits, or local law.(v) Review the damage      |
|                   | prevention program under § 192.614(a) in light   |
|                   | of national consensus practices, to ensure the   |
|                   | program provides adequate protection of the      |
|                   | right-of-way. Identify the standards or          |
|                   | practices considered in the review, and meet or  |
|                   | exceed those standards or practices by           |
|                   | incorporating appropriate changes into the       |
|                   | program.(vi) Develop and implement a right-      |
|                   | of-way management plan to protect the pipeline   |
|                   | segment from damage due to excavation            |
|                   | activities.                                      |
+-------------------+--------------------------------------------------+
| \(5\) Controlling | \(i\) Develop and implement a program to monitor |
| internal          | for and mitigate the presence of, deleterious    |
| corrosion.        | gas stream constituents.                         |
|                   |                                                  |
|                   | \(ii\) At points where gas with potentially      |
|                   | deleterious contaminants enters the pipeline,    |
|                   | use filter separators or separators and gas      |
|                   | quality monitoring equipment.                    |
|                   |                                                  |
|                   | \(iii\) Use gas quality monitoring equipment     |
|                   | that includes a moisture analyzer,               |
|                   | chromatograph, and periodic hydrogen sulfide     |
|                   | sampling.                                        |
|                   |                                                  |
|                   | \(iv\) Use cleaning pigs and inhibitors, and     |
|                   | sample accumulated liquids when corrosive gas is |
|                   | present.(v) Address deleterious gas stream       |
|                   | constituents as follows:                         |
|                   |                                                  |
|                   | \(A\) Limit carbon dioxide to 3 percent by       |
|                   | volume;                                          |
|                   |                                                  |
|                   | \(B\) Allow no free water and otherwise limit    |
|                   | water to seven pounds per million cubic feet of  |
|                   | gas; and                                         |
|                   |                                                  |
|                   | \(C\) Limit hydrogen sulfide to 1.0 grain per    |
|                   | hundred cubic feet (16 ppm) of gas, where the    |
|                   | hydrogen sulfide is greater than 0.5 grain per   |
|                   | hundred cubic feet (8 ppm) of gas, implement a   |
|                   | pigging and inhibitor injection program to       |
|                   | address deleterious gas stream constituents,     |
|                   | including follow-up sampling and quality testing |
|                   | of liquids at receipt points.                    |
|                   |                                                  |
|                   | \(vi\) Review the program at least quarterly     |
|                   | based on the gas stream experience and implement |
|                   | adjustments to monitor for, and mitigate the     |
|                   | presence of, deleterious gas stream              |
|                   | constituents.                                    |
+-------------------+--------------------------------------------------+
| \(6\) Controlling | \(i\) Prior to operating an existing pipeline    |
| interference that | segment at an alternate maximum allowable        |
| can impact        | operating pressure calculated under this         |
| external          | section, or within six months after placing a    |
| corrosion.        | new pipeline segment in service at an alternate  |
|                   | maximum allowable operating pressure calculated  |
|                   | under this section, address any interference     |
|                   | currents on the pipeline segment.                |
|                   |                                                  |
|                   | \(ii\) To address interference currents, perform |
|                   | the following:                                   |
|                   |                                                  |
|                   | \(A\) Conduct an interference survey to detect   |
|                   | the presence and level of any electrical current |
|                   | that could impact external corrosion where       |
|                   | interference is suspected;                       |
|                   |                                                  |
|                   | \(B\) Analyze the results of the survey; and     |
|                   |                                                  |
|                   | \(C\) Take any remedial action needed within 6   |
|                   | months after completing the survey to protect    |
|                   | the pipeline segment from deleterious current.   |
+-------------------+--------------------------------------------------+
| \(7\) Confirming  | \(i\) Within six months after placing the        |
| external          | cathodic protection of a new pipeline segment in |
| corrosion control | operation, or within six months after certifying |
| through indirect  | a segment under §192.620(c)(1) of an existing    |
| assessment.       | pipeline segment under this section, assess the  |
|                   | adequacy of the cathodic protection through an   |
|                   | indirect method such as close- interval survey,  |
|                   | and the integrity of the coating using direct    |
|                   | current voltage gradient (DCVG) or alternating   |
|                   | current voltage gradient (ACVG).                 |
|                   |                                                  |
|                   | \(ii\) Remediate any construction damaged        |
|                   | coating with a voltage drop classified as        |
|                   | moderate or severe (IR drop greater than 35% for |
|                   | DCVG or 50 dB\[mu\]v for ACVG) under section 4   |
|                   | of NACE RP-0502-2002 (incorporated by reference, |
|                   | see §192.7).                                     |
|                   |                                                  |
|                   | \(iii\) Within six months after completing the   |
|                   | baseline internal inspection required under      |
|                   | paragraph (8) of this section, integrate the     |
|                   | results of the indirect assessment required      |
|                   | under paragraph (6)(i) of this section with the  |
|                   | results of the baseline internal inspection and  |
|                   | take any needed remedial actions.                |
|                   |                                                  |
|                   | \(iv\) For all pipeline segments in high         |
|                   | consequence areas, perform periodic assessments  |
|                   | as follows:                                      |
|                   |                                                  |
|                   | \(A\) Conduct periodic close interval surveys    |
|                   | with current interrupted to confirm voltage      |
|                   | drops in association with periodic assessments   |
|                   | under subpart O of this part.                    |
|                   |                                                  |
|                   | \(B\) Locate pipe-to-soil test stations at       |
|                   | half-mile intervals within each high consequence |
|                   | area ensuring at least one station is within     |
|                   | each high consequence area, if practicable.      |
|                   |                                                  |
|                   | \(C\) Integrate the results with those of the    |
|                   | baseline and periodic assessments for integrity  |
|                   | done under paragraphs (d)(8) and (d)(9) of this  |
|                   | section.                                         |
+-------------------+--------------------------------------------------+
| \(8\) Controlling | \(i\) If an annual test station reading          |
| external          | indicates cathodic protection below the level of |
| corrosion through | protection required in subpart I of this part,   |
| cathodic          | complete remedial action within six months of    |
| protection.       | the failed reading or notify each PHMSA pipeline |
|                   | safety regional office where the pipeline is in  |
|                   | service demonstrating that the integrity of the  |
|                   | pipeline is not compromised if the repair takes  |
|                   | longer than 6 months. An operator must also      |
|                   | notify a State pipeline safety authority when    |
|                   | the pipeline is located in a State where PHMSA   |
|                   | has an interstate agent agreement, or an         |
|                   | intrastate pipeline is regulated by that State;  |
|                   | and                                              |
|                   |                                                  |
|                   | \(ii\) After remedial action to address a failed |
|                   | reading, confirm restoration of adequate         |
|                   | corrosion control by a close interval survey on  |
|                   | either side of the affected test station to the  |
|                   | next test station.                               |
|                   |                                                  |
|                   | \(iii\) If the pipeline segment has been in      |
|                   | operation, the cathodic protection system on the |
|                   | pipeline segment must have been operational      |
|                   | within 12 months of the completion of            |
|                   | construction.                                    |
+-------------------+--------------------------------------------------+
| \(9\) Conducting  | \(i\) Except as provided in paragraph            |
| a baseline        | (d)(8)(iii) of this section, for a new pipeline  |
| assessment of     | segment operating at the new alternative maximum |
| integrity.        | allowable operating pressure, perform a baseline |
|                   | internal inspection of the entire pipeline       |
|                   | segment as follows:                              |
|                   |                                                  |
|                   | \(A\) Assess using a geometry tool after the     |
|                   | initial hydrostatic test and backfill and within |
|                   | six months after placing the new pipeline        |
|                   | segment in service; and                          |
|                   |                                                  |
|                   | \(B\) Assess using a high resolution magnetic    |
|                   | flux tool within three years after placing the   |
|                   | new pipeline segment in service at the           |
|                   | alternative maximum allowable operating          |
|                   | pressure.                                        |
|                   |                                                  |
|                   | \(ii\) Except as provided in paragraph           |
|                   | (d)(8)(iii) of this section, for an existing     |
|                   | pipeline segment, perform a baseline internal    |
|                   | assessment using a geometry tool and a high      |
|                   | resolution magnetic flux tool before, but within |
|                   | two years prior to, raising pressure to the      |
|                   | alternative maximum allowable operating pressure |
|                   | as allowed under this section.                   |
|                   |                                                  |
|                   | \(iii\) If headers, mainline valve by- passes,   |
|                   | compressor station piping, meter station piping, |
|                   | or other short portion of a pipeline segment     |
|                   | operating at alternative maximum allowable       |
|                   | operating pressure cannot accommodate a geometry |
|                   | tool and a high resolution magnetic flux tool,   |
|                   | use direct assessment (per §192.925, §192.927    |
|                   | and/or §192.929) or pressure testing (per        |
|                   | subpart J of this part) to assess that portion.  |
+-------------------+--------------------------------------------------+
| \(10\) Conducting | \(i\) Determine a frequency for subsequent       |
| periodic          | periodic integrity assessments as if all the     |
| assessments of    | alternative maximum allowable operating pressure |
| integrity.        | pipeline segments were covered by subpart O of   |
|                   | this part and                                    |
|                   |                                                  |
|                   | \(ii\) Conduct periodic internal inspections     |
|                   | using a high resolution magnetic flux tool on    |
|                   | the frequency determined under paragraph         |
|                   | (d)(9)(i) of this section, or                    |
|                   |                                                  |
|                   | \(iii\) Use direct assessment (per § 192.925, §  |
|                   | 192.927 and/ or § 192.929) or pressure testing   |
|                   | (per subpart J of this part) for periodic        |
|                   | assessment of a portion of a segment to the      |
|                   | extent permitted for a baseline assessment under |
|                   | paragraph (d)(8)(iii) of this section.           |
+-------------------+--------------------------------------------------+
| \(11\) Making     | \(i\) Perform the following when evaluating an   |
| repairs.          | anomaly:                                         |
|                   |                                                  |
|                   | \(A\) Use the most conservative calculation for  |
|                   | determining remaining strength or an alternative |
|                   | validated calculation based on pipe diameter,    |
|                   | wall thickness, grade, operating pressure,       |
|                   | operating stress level, and operating            |
|                   | temperature: and                                 |
|                   |                                                  |
|                   | \(B\) Take into account the tolerances of the    |
|                   | tools used for the inspection.                   |
|                   |                                                  |
|                   | \(ii\) Repair a defect immediately if any of the |
|                   | following apply:                                 |
|                   |                                                  |
|                   | \(A\) The defect is a dent discovered during the |
|                   | baseline assessment for integrity under          |
|                   | paragraph (d)(8) of this section and the defect  |
|                   | meets the criteria for immediate repair in       |
|                   | §192.309(b).                                     |
|                   |                                                  |
|                   | \(B\) The defect meets the criteria for          |
|                   | immediate repair in §192.933(d).                 |
|                   |                                                  |
|                   | \(C\) The alternative maximum allowable          |
|                   | operating pressure was based on a design factor  |
|                   | of 0.67 under paragraph (a) of this section and  |
|                   | the failure pressure is less than 1.25 times the |
|                   | alternative maximum allowable operating          |
|                   | pressure.                                        |
|                   |                                                  |
|                   | \(D\) The alternative maximum allowable          |
|                   | operating pressure was based on a design factor  |
|                   | of 0.56 under paragraph (a) of this section and  |
|                   | the failure pressure is less than or equal to    |
|                   | 1.4 times the alternative maximum allowable      |
|                   | operating pressure.                              |
|                   |                                                  |
|                   | \(iii\) If paragraph (d)(10)(ii) of this section |
|                   | does not require immediate repair, repair a      |
|                   | defect within one year if any of the following   |
|                   | apply:                                           |
|                   |                                                  |
|                   | \(A\) The defect meets the criteria for repair   |
|                   | within one year in §192.933(d).                  |
|                   |                                                  |
|                   | \(B\) The alternative maximum allowable          |
|                   | operating pressure was based on a design factor  |
|                   | of 0.80 under paragraph (a) of this section and  |
|                   | the failure pressure is less than 1.25 times the |
|                   | alternative maximum allowable operating          |
|                   | pressure.                                        |
|                   |                                                  |
|                   | \(C\) The alternative maximum allowable          |
|                   | operating pressure was based on a design factor  |
|                   | of 0.67 under paragraph (a) of this section and  |
|                   | the failure pressure is less than 1.50 times the |
|                   | alternative maximum allowable operating          |
|                   | pressure.                                        |
|                   |                                                  |
|                   | \(D\) The alternative maximum allowable          |
|                   | operating pressure was based on a design factor  |
|                   | of 0.56 under paragraph (a) of this section and  |
|                   | the failure pressure is less than or equal to    |
|                   | 1.80 times the alternative maximum allowable     |
|                   | operating pressure.                              |
|                   |                                                  |
|                   | \(iv\) Evaluate any defect not required to be    |
|                   | repaired under paragraph (d)(10)(ii) or (iii) of |
|                   | this section to determine its growth rate, set   |
|                   | the maximum interval for repair or re-           |
|                   | inspection, and repair or re- inspect within     |
|                   | that interval.                                   |
+-------------------+--------------------------------------------------+

\(e\) Is there any change in overpressure protection associated with
operating at the alternative maximum allowable operating pressure?
Notwithstanding the required capacity of pressure relieving and limiting
stations otherwise required by §192.201, if an operator establishes a
maximum allowable operating pressure for a pipeline segment in
accordance with paragraph (a) of this section, an operator must:

\(1\) Provide overpressure protection that limits mainline pressure to a
maximum of 104 percent of the maximum allowable operating pressure; and

\(2\) Develop and follow a procedure for establishing and maintaining
accurate set points for the supervisory control and data acquisition
system.

Amdt. 192-\[107\], 73 FR 62147, October 17, 2008\]

**§192.621 Maximum allowable operating pressure: High-pressure
distribution systems.**

\(a\) No person may operate a segment of a high pressure distribution
system at a pressure that exceeds the lowest of the following pressures,
as applicable:

\(1\) The design pressure of the weakest element in the segment,
determined in accordance with Subparts C and D of this part.

\(2\) 60 p.s.i. (414 kPa) gage, for a segment of a distribution system
otherwise designated to operate at over 60 p.s.i. (414 kPa) gage, unless
the service lines in the segment are equipped with service regulators or
other pressure limiting devices in series that meet the requirements of
§192.197(c).

\(3\) 25 p.s.i. (172 kPa) gage in segments of cast iron pipe in which
there are unreinforced bell and spigot joints.

\(4\) The pressure limits to which a joint could be subjected without
the possibility of its parting.

\(5\) The pressure determined by the operator to be the maximum safe
pressure after considering the history of the segment, particularly
known corrosion and the actual operating pressures.

\(b\) No person may operate a segment of pipeline to which paragraph
(a)(5) of this section applies, unless overpressure protective devices
are installed on the segment in a manner that will prevent the maximum
allowable operating pressure from being exceeded, in accordance with
§192.195.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.623 Maximum and minimum**

**allowable operating pressure:;**

**Low-pressure distribution systems.**

\(a\) No person may operate a low-pressure distribution system at a
pressure high enough to make unsafe the operation of any connected and
properly adjusted low-pressure gas burning equipment.

\(b\) No person may operate a low pressure distribution system at a
pressure lower than the minimum pressure at which the safe and
continuing operation of any connected and properly adjusted low-pressure
gas burning equipment can be assured.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-75, 61 FR
18512, Apr. 26, 1996\]

**§192.625 Odorization of gas.**

\(a\) A combustible gas in a distribution line must contain a natural
odorant or be odorized so that at a concentration in air of one-fifth of
the lower explosive limit, the gas is readily detectable by a person
with a normal sense of smell.

\(b\) After December 31, 1976, a combustible gas in a transmission line
in a Class 3 or Class 4 location must comply with the requirements of
paragraph (a) of this section unless:

\(1\) At least 50 percent of the length of the line downstream from that
location is in a Class 1 or Class 2 location;

\(2\) The line transports gas to any of the following facilities which
received gas without an odorant from that line before May 5, 1975:

\(i\) An underground storage field;

\(ii\) A gas processing plant;

\(iii\) A gas dehydration plant; or

\(iv\) An industrial plant using gas in a process where the presence of
an odorant:

\(A\) Makes the end product unfit for the purpose for which it is
intended;

\(B\) Reduces the activity of a catalyst; or

\(C\) Reduces the percentage completion of a chemical reaction;

\(3\) In the case of a lateral line which transports gas to a
distribution center, at least 50 percent of the length of that line is
in a Class 1 or Class 2 location; or,

\(4\) The combustible gas is hydrogen intended for use as a feedstock in
a manufacturing process.

\(c\) In the concentrations in which it is used, the odorant in
combustible gases must comply with the following:

\(1\) The odorant may not be deleterious to persons, materials, or pipe.

\(2\) The products of combustion from the odorant may not be toxic when
breathed nor may they be corrosive or harmful to those materials to
which the products of combustion will be exposed.

\(d\) The odorant may not be soluble in water to an extent greater than
2.5 parts to 100 parts by weight.

\(e\) Equipment for odorization must introduce the odorant without wide
variations in the level of odorant.

\(f\) To assure the proper concentration of odorant in accordance with
this section, each operator must conduct periodic sampling of
combustible gases using an instrument capable of determining the
percentage of gas in air at which the odor becomes readily detectable.
Operators of master meter systems may comply with this requirement by--

\(1\) Receiving written verification from their gas source that the gas
has the proper concentration of odorant; and

\(2\) Conducting periodic \"sniff\" tests at the extremities of the
system to confirm that the gas contains odorant.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-2, 35 FR 17335,
Nov. 11, 1970; Amdt. 192-6, 36 FR 25423, Dec. 31, 1971; Amdt. 192-7, 37
FR 17970, Sept. 2, 1972; Amdt. 192-14, 38 FR 14943, June 7, 1973; Amdt.
192-15, 38 FR 35471, Dec. 28, 1973; Amdt. 192-16, 39 FR 45253, Dec. 31,
1974; Amdt. 192-21, 40 FR 20279, May 9, 1975; Amdt. 192-58, 53 FR 1633,
Jan. 21, 1988; Amdt. 192-76, 61 FR 26121, May 24, 1996; Amdt. 192-78, 61
FR 28770, June 6, 1996; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.627 Tapping pipelines under pressure.**

Each tap made on a pipeline under pressure must be performed by a crew
qualified to make hot taps.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.629 Purging of pipelines.**

\(a\) When a pipeline is being purged of air by use of gas, the gas must
be released into one end of the line in a moderately rapid and
continuous flow. If gas cannot be supplied in sufficient quantity to
prevent the formation of a hazardous mixture of gas and air, a slug of
inert gas must be released into the line before the gas.

\(b\) When a pipeline is being purged of gas by use of air, the air must
be released into one end of the line in a moderately rapid and
continuous flow. If air cannot be supplied in sufficient quantity to
prevent the formation of a hazardous mixture of gas and air, a slug of
inert gas must be released into the line before the air.

\[Part 192 - Org., Aug. 19, 1970\]

**Subpart M--Maintenance**

**§192.701 Scope.**

This subpart prescribes minimum requirements for maintenance of pipeline
facilities.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.703 General.**

\(a\) No person may operate a segment of pipeline, unless it is
maintained in accordance with this subpart.

\(b\) Each segment of pipeline that becomes unsafe must be replaced,
repaired, or removed from service.

\(c\) Hazardous leaks must be repaired promptly.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.705 Transmission lines: Patrolling.**

\(a\) Each operator shall have a patrol program to observe surface
conditions on and adjacent to the transmission line right-of-way for
indications of leaks, construction activity, and other factors affecting
safety and operation.

\(b\) The frequency of patrols is determined by the size of the line,
the operating pressures, the class location, terrain, weather, and other
relevant factors, but intervals between patrols may not be longer than
prescribed in the following table:

+------------+---------------------------+----------------------------+
| Class      | Maximum interval between  |                            |
|            | patrols                   |                            |
| location   |                           |                            |
| of line    |                           |                            |
+------------+---------------------------+----------------------------+
|            | At highway and railroad   | At all other places        |
|            | crossings                 |                            |
+------------+---------------------------+----------------------------+
| 1, 2       | 7½ months; but at least   | 15 months; but at least    |
|            | twice each calendar year. | once each calendar year.   |
+------------+---------------------------+----------------------------+
| 3          | 4½ months; but at least   | 7½ months; but at least    |
|            | four times each calendar  | twice each calendar year.  |
|            | year.                     |                            |
+------------+---------------------------+----------------------------+
| 4          | 4½ months; but at least   | 4½ months; but at least    |
|            | four times each calendar  | four times each calendar   |
|            | year.                     | year.                      |
+------------+---------------------------+----------------------------+

\(c\) Methods of patrolling include walking, driving, flying or other
appropriate means of traversing the right-of-way.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-21, 40 FR
20283, May 9, 1975; Amdt. 192-43, 47 FR 46850, Oct. 21, 1982; Amdt.
192-78, 61 FR 28770, June 6, 1996\]

**§192.706 Transmission lines: Leakage surveys.**

Leakage surveys of a transmission line must be conducted at intervals
not exceeding 15 months, but at least once each calendar year. However,
in the case of a transmission line which transports gas in conformity
with §192.625 without an odor or odorant, leakage surveys using leak
detector equipment must be conducted--

\(a\) In Class 3 locations, at intervals not exceeding 7½ months, but at
least twice each calendar year; and

\(b\) In Class 4 locations, at intervals not exceeding 4½ months, but at
least four times each calendar year.

\[Amdt. 192-21, 40 FR 20283, May 9, 1975, as amended by Amdt. 192-43, 47
FR 46850, Oct. 21, 1982; Amdt. 192-71, 59 FR 6575, Feb. 11, 1994\]

**§192.707 Line markers for mains and transmission lines.**

\(a\) *Buried pipelines.* Except as provided in paragraph (b) of this
section, a line marker must be placed and maintained as close as
practical over each buried main and transmission line:

\(1\) At each crossing of a public road and railroad; and

\(2\) Wherever necessary to identify the location of the transmission
line or main to reduce the possibility of damage or interference.

\(b\) *Exceptions for buried pipelines.* Line markers are not required
for the following pipelines:

\(1\) Mains and transmission lines located offshore, or at crossings of
or under waterways and other bodies of water.

\(2\) Mains in Class 3 or Class 4 locations where a damage prevention
program is in effect under §192.614.

\(3\) Transmission lines in Class 3 or 4 locations until March 20, 1996.

\(4\) Transmission lines in Class 3 or 4 locations where placement of a
line marker is impractical.

\(c\) *Pipelines above ground.* Line markers must be placed and
maintained along each section of a main and transmission line that is
located above ground in an area accessible to the public.

\(d\) *Marker warning.* The following must be written legibly on a
background of sharply contrasting color on each line marker:

\(1\) The word \"Warning,\" \"Caution,\" or \"Danger\" followed by the
words \"Gas (or name of gas transported) Pipeline\" all of which, except
for markers in heavily developed urban areas, must be in letters at
least 1 inch (25 millimeters) high with ¼ inch (6.4 millimeters) stroke.

\(2\) The name of the operator and telephone number (including area
code) where the operator can be reached at all times.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-20, 40 FR
13505, Mar. 27, 1975; Amdt. 192-20A, 41 FR 56808, Dec. 30, 1976; Amdt.
192-27, 41 FR 39752, Aug. 16, 1976; Amdt. 192-40, 47 FR 13818, Apr. 1,
1982; Amdt. 192-44, 48 FR 25206, June 6, 1983; Amdt. 192-73, 60 FR
14646, Mar. 20, 1995; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.709 Transmission lines: Recordkeeping.**

Each operator shall maintain the following records for transmission
lines for the periods specified:

\(a\) The date, location, and description of each repair made to pipe
(including pipe-to-pipe connections) must be retained for as long as the
pipe remains in service.

\(b\) The date, location, and description of each repair made to parts
of the pipeline system other than pipe must be retained for at least 5
years. However, repairs generated by patrols, surveys, inspections, or
tests required by subparts L and M of this part must be retained in
accordance with paragraph (c) of this section.

\(c\) A record of each patrol, survey, inspection, and test required by
subparts L and M of this part must be retained for at least 5 years or
until the next patrol, survey, inspection, or test is completed,
whichever is longer.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-78, 61 FR
28770, June 6, 1996\]

**§192.711 Transmission lines: General requirements for repair
procedures.**

\(a\) Each operator shall take immediate temporary measures to protect
the public whenever:

\(1\) A leak, imperfection, or damage that impairs its serviceability is
found in a segment of steel transmission line operating at or above 40
percent of the SMYS; and

\(2\) It is not feasible to make a permanent repair at the time of
discovery.

As soon as feasible the operator shall make permanent repairs.

\(b\) Except as provided in §192.717(b)(3), no operator may use a welded
patch as a means of repair.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27B, 45 FR
3272, Jan. 17, 1980; Amdt. 192-88, 64 FR 69660, Dec. 14, 1999\]

**§192.713 Transmission lines: Permanent field repair of imperfections
and damages.**

\(a\) Each imperfection or damage that impairs the serviceability of
pipe in a steel transmission line operating at or above 40 percent of
SMYS must be\--

\(1\) Removed by cutting out and replacing a cylindrical piece of pipe;
or

\(2\) Repaired by a method that reliable engineering tests and analyses
show can permanently restore the serviceability of the pipe.

\(b\) Operating pressure must be at a safe level during repair
operations.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR
34598, Aug. 16, 1976; Amdt. 192-88, 64 FR 69660, Dec. 14, 1999\]

**§192.715 Transmission lines: Permanent field repair of welds.**

Each weld that is unacceptable under §192.241(c) must be repaired as
follows:

\(a\) If it is feasible to take the segment of transmission line out of
service, the weld must be repaired in accordance with the applicable
requirements of §192.245.

\(b\) A weld may be repaired in accordance with §192.245 while the
segment of transmission line is in service if:

\(1\) The weld is not leaking:

\(2\) The pressure in the segment is reduced so that it does not produce
a stress that is more than 20 percent of the SMYS of the pipe; and

\(3\) Grinding of the defective area can be limited so that at least
1/8-inch (3.2 millimeters) thickness in the pipe weld remains.

\(c\) A defective weld which cannot be repaired in accordance with
paragraph (a) or (b) of this section must be repaired by installing a
full encirclement welded split sleeve of appropriate design.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998\]

**§192.717 Transmission lines: Permanent field repair of leaks.**

Each permanent field repair of a leak on a transmission line must be
made by\--

\(a\) Removing the leak by cutting out and replacing a cylindrical piece
of pipe; or

\(b\) Repairing the leak by one of the following methods:

\(1\) Install a full encirclement welded split sleeve of appropriate
design, unless the transmission line is joined by mechanical couplings
and operates at less than 40 percent of SMYS.

\(2\) If the leak is due to a corrosion pit, install a properly designed
bolt-on-leak clamp.

\(3\) If the leak is due to a corrosion pit and on pipe of not more than
40,000 psi (267 Mpa) SMYS, fillet weld over the pitted area a steel
plate patch with rounded corners, of the same or greater thickness than
the pipe, and not more than one-half of the diameter of the pipe in
size.

\(4\) If the leak is on a submerged offshore pipeline or submerged
pipeline in inland navigable waters, mechanically apply a full
encirclement split sleeve of appropriate design.

\(5\) Apply a method that reliable engineering tests and analyses show
can permanently restore the serviceability of the pipe.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-11, 37 FR
21816, Oct. 14, 1972; Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt.
192-85, 63 FR 37500, July 13, 1998; Amdt. 192-88, 64 FR 69660, Dec. 14,
1999\]

**§192.719 Transmission lines:**

**Testing of repairs.**

\(a\) Testing of replacement pipe. If a segment of transmission line is
repaired by cutting out the damaged portion of the pipe as a cylinder,
the replacement pipe must be tested to the pressure required for a new
line installed in the same location. This test may be made on the pipe
before it is installed.

\(b\) Testing of repairs made by welding. Each repair made by welding in
accordance with §§ 192.713, 192.715, and 192.717 must be examined in
accordance with §192.241.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-54, 51 FR
41634, Nov. 18, 1986\]

**§192.721 Distribution systems: Patrolling.**

\(a\) The frequency of patrolling mains must be determined by the
severity of the conditions which could cause failure or leakage, and the
consequent hazards to public safety.

\(b\) Mains in places or on structures where anticipated physical
movement or external loading could cause failure or leakage must be
patrolled--

\(1\) In business districts, at intervals not exceeding 4½ months, but
at least four times each calendar year; and

\(2\) Outside business districts, at intervals not exceeding 7½ months,
but at least twice each calendar year.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; Amdt. 192-78, 61 FR 28770, June 6, 1996\]

**§192.723 Distribution systems: Leakage surveys.**

\(a\) Each operator of a distribution system shall conduct periodic
leakage surveys in accordance with this section*.*

\(b\) The type and scope of the leakage control program must be
determined by the nature of the operations and the local conditions, but
it must meet the following minimum requirements:

\(1\) A leakage survey with leak detector equipment must be conducted in
business districts, including tests of the atmosphere in gas, electric,
telephone, sewer, and water system manholes, at cracks in pavement and
sidewalks, and at other locations providing an opportunity for finding
gas leaks, at intervals not exceeding 15 months, but at least once each
calendar year.

\(2\) A leakage survey with leak detector equipment must be conducted
outside business districts as frequently as necessary, but at least once
every 5 calendar years at intervals not exceeding 63 months. However,
for cathodically unprotected distribution lines subject to §192.465(e)
on which electrical surveys for corrosion are impractical, a leakage
survey must be conducted at least once every 3 calendar years at
intervals not exceeding 39 months.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; Amdt. 192-70, 58 FR 54524, Oct. 22, 1993; Amdt.
192-71, 59 FR 6575, Feb. 11, 1994; Amdt. 192-94, 69 FR 32886, June 14,
2004; Amdt. 192-94A, 69 FR 54591, Sept. 9, 2004\]

**§192.725 Test requirements for reinstating service lines.**

\(a\) Except as provided in paragraph (b) of this section, each
disconnected service line must be tested in the same manner as a new
service line, before being reinstated.

\(b\) Each service line temporarily disconnected from the main must be
tested from the point of disconnection to the service line valve in the
same manner as a new service line, before reconnecting. However, if
provisions are made to maintain continuous service, such as by
installation of a bypass, any part of the original service line used to
maintain continuous service need not be tested.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.727 Abandonment or deactivation of facilities.**

\(a\) Each operator shall conduct abandonment or deactivation of
pipelines in accordance with the requirements of this section.

\(b\) Each pipeline abandoned in place must be disconnected from all
sources and supplies of gas; purged of gas; in the case of offshore
pipelines, filled with water or inert materials; and sealed at the ends.
However, the pipeline need not be purged when the volume of gas is so
small that there is no potential hazard.

\(c\) Except for service lines, each inactive pipeline that is not being
maintained under this part must be disconnected from all sources and
supplies of gas; purged of gas; in the case of offshore pipelines,
filled with water or inert materials; and sealed at the ends. However,
the pipeline need not be purged when the volume of gas is so small that
there is no potential hazard.

\(d\) Whenever service to a customer is discontinued, one of the
following must be complied with:

\(1\) The valve that is closed to prevent the flow of gas to the
customer must be provided with a locking device or other means designed
to prevent the opening of the valve by persons other than those
authorized by the operator.

\(2\) A mechanical device or fitting that will prevent the flow of gas
must be installed in the service line or in the meter assembly.

\(3\) The customer\'s piping must be physically disconnected from the
gas supply and the open pipe ends sealed.

\(e\) If air is used for purging, the operator shall insure that a
combustible mixture is not present after purging.

\(f\) Each abandoned vault must be filled with a suitable compacted
material.

\(g\) For each abandoned offshore pipeline facility or each abandoned
onshore pipeline facility that crosses over, under or through a
commercially navigable waterway, the last operator of that facility must
file a report upon abandonment of that facility.

\(1\) The preferred method to submit data on pipeline facilities
abandoned after October 10, 2000 is to the National Pipeline Mapping
System (NPMS) in accordance with the NPMS "Standards for Pipeline and
Liquefied Natural Gas Operator Submissions.**"** To obtain a copy of the
NPMS Standards, please refer to the NPMS homepage at
www.npms.PHMSA.dot.gov or contact the NPMS National Repository at
703-317-3073. A digital data format is preferred, but hard copy
submissions are acceptable if they comply with the NPMS Standards. In
addition to the NPMS-required attributes, operators must submit the date
of abandonment, diameter, method of abandonment, and certification that,
to the best of the operator\'s knowledge, all of the reasonably
available information requested was provided and, to the best of the
operator\'s knowledge, the abandonment was completed in accordance with
applicable laws. Refer to the NPMS Standards for details in preparing
your data for submission. The NPMS Standards also include details of how
to submit data. Alternatively, operators may submit reports by mail, fax
or e-mail to the Pipeline and Hazardous Materials Safety Administration,
U.S. Department of Transportation, [Room 2103, 400 Seventh Street, SW,
Washington DC 20590; fax (202) 366-4566; e-mail,
roger.little@dot.gov]{.mark}[PHP-10, 1200 New Jersey Avenue, SE.,
Washington, DC 20590; fax (202) 366-4566; e-mail
[*InformationResourcesManager@PHMSA.dot.gov*](mailto:InformationResourcesManager@phmsa.dot.gov)]{.underline}.
The information in the report must contain all reasonably available
information related to the facility, including information in the
possession of a third party. The report must contain the location, size,
date, method of abandonment, and a certification that the facility has
been abandoned in accordance with all applicable laws.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-8, 37 FR
20694, Oct. 3, 1972, Amdt. 192-27, 41 FR 34598, Aug. 16, 1976; Amdt.
192-71, 59 FR 6575, Feb. 11, 1994; Amdt. 192-89, 65 FR 54440, Sept. 8,
2000; Amdt. 192-89A, 65 FR 57861, Sept. 26, 2000; 70 FR 11135, Mar. 8,
2005; Amdt. 192-103c, 72 FR 4655, Feb. 1, 2007[; Amdt. 192-\[106\], 73
FR 16562, Mar. 28, 2008.]{.underline}\]

**§192.729 \[Removed\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-71, 59 FR
6575, Feb. 11, 1994\]

**§192.731 Compressor stations: Inspection and testing of relief
devices.**

\(a\) Except for rupture discs, each pressure relieving device in a
compressor station must be inspected and tested in accordance with
§§ 192.739 and 192.743, and must be operated periodically to determine
that it opens at the correct set pressure.

\(b\) Any defective or inadequate equipment found must be promptly
repaired or replaced.

\(c\) Each remote control shutdown device must be inspected and tested
at intervals not exceeding 15 months, but at least once each calendar
year, to determine that it functions properly.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982\]

**§192.733 \[Removed\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-71, 59 FR
6575, Feb. 11, 1994\]

**§192.735 Compressor stations:**

**Storage of combustible materials.**

\(a\) Flammable or combustible materials in quantities beyond those
required for everyday use, or other than those normally used in
compressor buildings, must be stored a safe distance from the compressor
building.

\(b\) Above ground oil or gasoline storage tanks must be protected in
accordance with National Fire Protection Association Standard No. 30.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.736 Compressor stations: Gas detection.**

\(a\) Not later than September 16, 1996, each compressor building in a
compressor station must have a fixed gas detection and alarm system,
unless the building is--

\(1\) Constructed so that at least 50 percent of its upright side area
is permanently open; or

\(2\) Located in an unattended field compressor station of 1,000
horsepower (746 kilowatts) or less.

\(b\) Except when shutdown of the system is necessary for maintenance
under paragraph (c) of this section, each gas detection and alarm system
required by this section must--

\(1\) Continuously monitor the compressor building for a concentration
of gas in air of not more than 25 percent of the lower explosive limit;
and

\(2\) If that concentration of gas is detected, warn persons about to
enter the building and persons inside the building of the danger.

\(c\) Each gas detection and alarm system required by this section must
be maintained to function properly. The maintenance must include
performance tests.

\[Amdt. 192-69, 58 FR 48460, Sept. 16, 1993 as amended by Amdt. 192-85,
63 FR 37500, July 13, 1998\]

**§192.737 \[Removed\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-71, 59 FR
6575, Feb. 11, 1994\]

**§192.739 Pressure limiting and regulating stations: Inspection and
testing.**

\(a\) Each pressure limiting station, relief device (except rupture
discs), and pressure regulating station and its equipment must be
subjected at intervals not exceeding 15 months, but at least once each
calendar year, to inspections and tests to determine that it is--

\(1\) In good mechanical condition;

\(2\) Adequate from the standpoint of capacity and reliability of
operation for the service in which it is employed;

\(3\) Except as provided in paragraph (b) of this section, set to
control or relieve at the correct pressure consistent with the pressure
limits of §192.201(a); and

\(4\) Properly installed and protected from dirt, liquids, or other
conditions that might prevent proper operation.

\(b\) For steel pipelines whose MAOP is determined under §192.619(c), if
the MAOP is 60 psi (414 kPa) gage or more, the control or relief
pressure limit is as follows:

+--------------------------------+--------------------------------------+
| If the MAOP produces           | Then the pressure limit is:          |
|                                |                                      |
| a hoop stress that is:         |                                      |
+--------------------------------+--------------------------------------+
| Greater than 72 percent of     | MAOP plus 4 percent.                 |
| SMYS                           |                                      |
+--------------------------------+--------------------------------------+
| Unknown as a percentage of     | A pressure that will prevent unsafe  |
| SMYS                           | operation of the pipeline            |
|                                | considering its operating and        |
|                                | maintenance history and MAOP.        |
+--------------------------------+--------------------------------------+

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt.
192-96, 69 FR 27861, May 17, 2004\]

**§192.741 Pressure limiting and regulating stations: Telemetering or
recording gauges.**

\(a\) Each distribution system supplied by more than one district
pressure regulating station must be equipped with telemetering or
recording pressure gauges to indicate the gas pressure in the district.

\(b\) On distribution systems supplied by a single district pressure
regulating station, the operator shall determine the necessity of
installing telemetering or recording gauges in the district, taking into
consideration the number of customers supplied, the operating pressures,
the capacity of the installation, and other operating conditions.

\(c\) If there are indications of abnormally high- or low-pressure, the
regulator and the auxiliary equipment must be inspected and the
necessary measures employed to correct any unsatisfactory operating
conditions.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.743 Pressure limiting and regulating stations: Capacity of relief
devices.**

\(a\) Pressure relief devices at pressure limiting stations and pressure
regulating stations must have sufficient capacity to protect the
facilities to which they are connected. Except as provided in
§192.739(b), the capacity must be consistent with the pressure limits of
§192.201(a). This capacity must be determined at intervals not exceeding
15 months, but at least once each calendar year, by testing the devices
in place or by review and calculations.

\(b\) If review and calculations are used to determine if a device has
sufficient capacity, the calculated capacity must be compared with the
rated or experimentally determined relieving capacity of the device for
the conditions under which it operates. After the initial calculations,
subsequent calculations need not be made if the annual review documents
that parameters have not changed to cause the rated or experimentally
determined relieving capacity to be insufficient.

\(c\) If a relief device is of insufficient capacity, a new or
additional device must be installed to provide the capacity required by
paragraph (a) of this section.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; and Amdt. 192-55, 51 FR 41633. Nov. 18, 1986;
Amdt. 192-93, 68 FR 53895, Sept. 15, 2003; Amdt. 192-96, 69 FR 27861,
May 17, 2004\]

**§192.745 Valve maintenance: Transmission lines.**

\(a\) Each transmission line valve that might be required during any
emergency must be inspected and partially operated at intervals not
exceeding 15 months, but at least once each calendar year.

\(b\) Each operator must take prompt remedial action to correct any
valve found inoperable, unless the operator designates an alternative
valve.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.747 Valve maintenance: Distribution systems.**

\(a\) Each valve, the use of which may be necessary for the safe
operation of a distribution system, must be checked and serviced at
intervals not exceeding 15 months, but at least once each calendar year.

\(b\) Each operator must take prompt remedial action to correct any
valve found inoperable, unless the operator designates an alternative
valve.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; Amdt. 192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.749 Vault maintenance.**

\(a\) Each vault housing pressure regulating and pressure limiting
equipment, and having a volumetric internal content of 200 cubic feet
(5.66 cubic meters) or more, must be inspected at intervals not
exceeding 15 months, but at least once each calendar year, to determine
that it is in good physical condition and adequately ventilated.

\(b\) If gas is found in the vault, the equipment in the vault must be
inspected for leaks, and any leaks found must be repaired.

\(c\) The ventilating equipment must also be inspected to determine that
it is functioning properly.

\(d\) Each vault cover must be inspected to assure that it does not
present a hazard to public safety.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; Amdt. 192-85, 63 FR 37500, July 13, 1998\]

**§192.751 Prevention of accidental ignition.**

Each operator shall take steps to minimize the danger of accidental
ignition of gas in any structure or area where the presence of gas
constitutes a hazard of fire or explosion, including the following:

\(a\) When a hazardous amount of gas is being vented into open air, each
potential source of ignition must be removed from the area and a fire
extinguisher must be provided.

\(b\) Gas or electric welding or cutting may not be performed on pipe or
on pipe components that contain a combustible mixture of gas and air in
the area of work.

\(c\) Post warning signs, where appropriate.

\[Part 192 - Org., Aug. 19, 1970\]

**§192.753 Caulked bell and spigot joints.**

\(a\) Each cast iron caulked bell and spigot joint that is subject to
pressures of more than 25 psi (172kPa) gage must be sealed with:

\(1\) A mechanical leak clamp; or

\(2\) A material or device which:

\(i\) Does not reduce the flexibility of the joint;

\(ii\) Permanently bonds, either chemically or mechanically, or both,
with the bell and spigot metal surfaces or adjacent pipe metal surfaces;
and,

\(iii\) Seals and bonds in a manner that meets the strength,
environmental, and chemical compatibility requirements of §§ 192.53(a)
and (b) and 192.143.

\(b\) Each cast iron caulked bell and spigot joint that is subject to
pressures of 25 psi (172kPa) gage or less and is exposed for any reason
must be sealed by a means other than caulking.

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR
46850, Oct. 21, 1982; Amdt. 192-85, 63 FR 37500, July 13, 1998; Amdt.
192-93, 68 FR 53895, Sept. 15, 2003\]

**§192.755 Protecting cast-iron pipelines.**

When an operator has knowledge that the support for a segment of a
buried cast-iron pipeline is disturbed:

\(a\) That segment of the

pipeline must be protected, as necessary, against damage during the
disturbance by:

\(1\) Vibrations from heavy construction equipment, trains, trucks,
buses, or blasting;

\(2\) Impact forces by vehicles;

\(3\) Earth movement;

\(4\) Apparent future excavations near the pipeline; or

\(5\) Other foreseeable outside forces which may subject that segment of
the pipeline to bending stress.

\(b\) As soon as feasible, appropriate steps must be taken to provide
permanent protection for the disturbed segment from damage that might
result from external loads, including compliance with applicable
requirements of §§ 192.317(a), 192.319, and 192.361 (b)--(d).

\[Amdt. 192-23, 41 FR 13589, Mar. 31, 1976\]

**§192.761 \[Removed\]**

\[Amdt. 192-90, 67 FR 50824, Aug. 6, 2002 as amended by Amdt. 192-95, 16
FR 69778, Dec. 15, 2003\]

**Subpart N--Qualification of Pipeline**

**Personnel**

**§192.801 Scope.**

\(a\) This subpart prescribes the minimum requirements for operator
qualification of individuals performing covered tasks on a pipeline
facility.

\(b\) For the purpose of this subpart, a covered task is an activity,
identified by the operator, that:

\(1\) Is performed on a pipeline facility;

\(2\) Is an operations or maintenance task;

\(3\) Is performed as a requirement of this part; and

\(4\) Affects the operation or integrity of the pipeline.

\[Amdt. 192-86, 64 FR 46853, Aug. 27, 1999\]

**§192.803 Definitions.**

*Abnormal operating condition* means a condition identified by the
operator that may indicate a malfunction of a component or deviation
from normal operations that may:

\(a\) Indicate a condition exceeding design limits; or

\(b\) Result in a hazard(s) to persons, property, or the environment.

*Evaluation* means a process, established and documented by the
operator, to determine an individual\'s ability to perform a covered
task by any of the following:

\(a\) Written examination;

\(b\) Oral examination;

\(c\) Work performance history review;

\(d\) Observation during:

\(1\) Performance on the job,

\(2\) On the job training, or

\(3\) Simulations;

\(e\) Other forms of assessment.

*Qualified* means that an individual has been evaluated and can:

\(a\) Perform assigned covered tasks; and

\(b\) Recognize and react to abnormal operating conditions.

\[Amdt. 192-86, 64 FR 46853, Aug. 27, 1999 as amended by Amdt. 192-86A,
66 FR 43523, Aug. 20, 2001\]

**§192.805 Qualification program.**

Each operator shall have and follow a written qualification program. The
program shall include provisions to:

\(a\) Identify covered tasks;

\(b\) Ensure through evaluation that individuals performing covered
tasks are qualified;

\(c\) Allow individuals that are not qualified pursuant to this subpart
to perform a covered task if directed and observed by an individual that
is qualified;

\(d\) Evaluate an individual if the operator has reason to believe that
the individual\'s performance of a covered task contributed to an
incident as defined in Part 191;

\(e\) Evaluate an individual if the operator has reason to believe that
the individual is no longer qualified to perform a covered task;

\(f\) Communicate changes that affect covered tasks to individuals
performing those covered tasks;

\(g\) Identify those covered tasks and the intervals at which evaluation
of the individual\'s qualifications is needed;

> \(h\) After December 16, 2004, provide training, as appropriate, to
> ensure that individuals performing covered tasks have the necessary
> knowledge and skills to perform the tasks in a manner that ensures the
> safe operation of pipeline facilities; and
>
> \(i\) After December 16, 2004, notify the Administrator or a state
> agency participating under 49 U.S.C. Chapter 601 if the operator
> significantly modifies the program after the Administrator or state
> agency has verified that it complies with this section.

\[Amdt. 192-86, 64 FR 46853, Aug. 27, 1999 as amended by Amdt. 192-100,
70 FR 10322, Mar. 3, 2005\]

**§192.807 Recordkeeping.**

Each operator shall maintain records that demonstrate compliance with
this subpart.

\(a\) Qualification records shall include:

\(1\) Identification of qualified individual(s);

\(2\) Identification of the covered tasks the individual is qualified to
perform;

\(3\) Date(s) of current qualification; and

\(4\) Qualification method(s).

\(b\) Records supporting an individual\'s current qualification shall be
maintained while the individual is performing the covered task. Records
of prior qualification and records of individuals no longer performing
covered tasks shall be retained for a period of five years.

\[Amdt. 192-86, 64 FR 46853, Aug. 27, 1999\]

**§192.809 General.**

\(a\) Operators must have a written qualification program by April 27,
2001. The program must be available for review by the Administrator or
by a state agency participating under 49 U.S.C. Chapter 601 if the
program is under the authority of that state agency.

\(b\) Operators must complete the qualification of individuals
performing covered tasks by October 28, 2002.

\(c\) Work performance history review may be used as a sole evaluation
method for individuals who were performing a covered task prior to
October 26, 1999.

\(d\) After October 28, 2002, work performance history may not be used
as a sole evaluation method.

\(e\) After December 16, 2004, observation of on-the-job performance may
not be used as the sole method of evaluation.

\[Amdt. 192-86, 64 FR 46853, Aug. 27, 1999 as amended by Amdt. 192-86A,
66 FR 43523, Aug. 20, 2001; Amdt. 192-100, 70 FR 10322, Mar. 3, 2005\]

**Subpart O---Gas Transmission Pipeline Integrity Management**

**§192.901 What do the regulations in this subpart cover?**

This subpart prescribes minimum requirements for an integrity management
program on any gas transmission pipeline covered under this part. For
gas transmission pipelines constructed of plastic, only the requirements
in §§ 192.917, 192.921, 192.935 and 192.937 apply.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003\]

**§192.903 What definitions apply to this subpart?**

The following definitions apply to this subpart:

***Assessment*** is the use of testing techniques as allowed in this
subpart to ascertain the condition of a covered pipeline segment.

***Confirmatory direct assessment*** is an integrity assessment method
using more focused application of the principles and techniques of
direct assessment to identify internal and external corrosion in a
covered transmission pipeline segment.

***Covered segment or covered pipeline segment*** means a segment of gas
transmission pipeline located in a high consequence area. The terms gas
and transmission line are defined in §192.3.

***Direct assessment*** is an integrity assessment method that utilizes
a process to evaluate certain threats (i.e., external corrosion,
internal corrosion and stress corrosion cracking) to a covered pipeline
segment\'s integrity. The process includes the gathering and integration
of risk factor data, indirect examination or analysis to identify areas
of suspected corrosion, direct examination of the pipeline in these
areas, and post assessment evaluation.

***High consequence area*** means an area established by one of the
methods described in paragraphs (1) or (2) as follows:

\(1\) An area defined as---

\(i\) A Class 3 location under §192.5; or

\(ii\) A Class 4 location under §192.5; or

\(iii\) Any area in a Class 1 or Class 2 location where the potential
impact radius is greater than 660 feet (200 meters), and the area within
a potential impact circle contains 20 or more buildings intended for
human occupancy; or

\(iv\) Any area in a Class 1 or Class 2 location where the potential
impact circle contains an identified site.

\(2\) The area within a potential impact circle containing---

\(i\) 20 or more buildings intended for human occupancy, unless the
exception in paragraph (4) applies; or

\(ii\) An identified site.

\(3\) Where a potential impact circle is calculated under either method
(1) or (2) to establish a high consequence area, the length of the high
consequence area extends axially along the length of the pipeline from
the outermost edge of the first potential impact circle that contains
either an identified site or 20 or more buildings intended for human
occupancy to the outermost edge of the last contiguous potential impact
circle that contains either an identified site or 20 or more buildings
intended for human occupancy. (See Figure E.I.A. in appendix E.)

\(4\) If in identifying a high consequence area under paragraph (1)(iii)
of this definition or paragraph (2)(i) of this definition, the radius of
the potential impact circle is greater than 660 feet (200 meters), the
operator may identify a high consequence area based on a prorated number
of buildings intended for human occupancy within a distance 660 feet
(200 meters) from the centerline of the pipeline until December 17,
2006. If an operator chooses this approach, the operator must prorate
the number of buildings intended for human occupancy based on the ratio
of an area with a radius of 660 feet (200 meters) to the area of the
potential impact circle (*i.e.*, the prorated number of buildings
intended for human occupancy is equal to \[20 x (660 feet \[or 200
meters \]/potential impact radius in feet \[or meters\])^2^\]).

***Identified site*** means each of the following areas:

\(a\) An outside area or open structure that is occupied by twenty (20)
or more persons on at least 50 days in any twelve (12)-month period.
(The days need not be consecutive.) Examples include but are not limited
to, beaches, playgrounds, recreational facilities, camping grounds,
outdoor theaters, stadiums, recreational areas near a body of water, or
areas outside a rural building such as a religious facility); or

\(b\) A building that is occupied by twenty (20) or more persons on at
least five (5) days a week for ten (10) weeks in any twelve (12)-month
period. (The days and weeks need not be consecutive.) Examples include,
but are not limited to, religious facilities, office buildings,
community centers, general stores, 4-H facilities, or roller skating
rinks); or

\(c\) A facility occupied by persons who are confined, are of impaired
mobility, or would be difficult to evacuate. Examples include but are
not limited to hospitals, prisons, schools, day-care facilities,
retirement facilities or assisted-living facilities.

***Potential impact circle*** is a circle of radius equal to the
potential impact radius (PIR).

***Potential impact radius (PIR**)* means the radius of a circle within
which the potential failure of a pipeline could have significant impact
on people or property. PIR is determined by the formula r = 0.69\*
(square root of (p\*d^2^)), where \`r\' is the radius of a circular area
in feet surrounding the point of failure, \`p\' is the maximum allowable
operating pressure (MAOP) in the pipeline segment in pounds per square
inch and \`d\' is the nominal diameter of the pipeline in inches.

***Note:*** 0.69 is the factor for natural gas. This number will vary
for other gases depending upon their heat of combustion. An operator
transporting gas other than natural gas must use section 3.2 of
ASME/ANSI B31.8S-2001 (Supplement to ASME B31.8; incorporated by
reference, *see* §192.7) to calculate the impact radius formula.

***Remediation*** is a repair or mitigation activity an operator takes
on a covered segment to limit or reduce the probability of an undesired
event occurring or the expected consequences from the event.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-95C, 69 FR 29903, May 26, 2004; Amdt. 192-103, 71 FR
33402, June 8, 2006; Amdt. 192-103c, 72 FR 4655, Feb. 1, 2007\]

**§192.905 How does an operator identify a high consequence area?**

\(a\) *General.* To determine which segments of an operator\'s
transmission pipeline system are covered by this subpart, an operator
must identify the high consequence areas. An operator must use method
(1) or (2) from the definition in §192.903 to identify a high
consequence area. An operator may apply one method to its entire
pipeline system, or an operator may apply one method to individual
portions of the pipeline system. An operator must describe in its
integrity management program which method it is applying to each portion
of the operator\'s pipeline system. The description must include the
potential impact radius when utilized to establish a high consequence
area. (*See* appendix E.I. for guidance on identifying high consequence
areas.)

(b)(1) *Identified sites*. An operator must identify an identified site,
for purposes of this subpart, from information the operator has obtained
from routine operation and maintenance activities and from public
officials with safety or emergency response or planning responsibilities
who indicate to the operator that they know of locations that meet the
identified site criteria. These public officials could include officials
on a local emergency planning commission or relevant Native American
tribal officials.

\(2\) If a public official with safety or emergency response or planning
responsibilities informs an operator that it does not have the
information to identify an identified site, the operator must use one of
the following sources, as appropriate, to identify these sites.

\(i\) Visible marking (*e.g.*, a sign); or

\(ii\) The site is licensed or registered by a Federal, State, or local
government agency; or

\(iii\) The site is on a list (including a list on an internet web site)
or map maintained by or available from a Federal, State, or local
government agency and available to the general public.

\(c\) *Newly identified areas.* When an operator has information that
the area around a pipeline segment not previously identified as a high
consequence area could satisfy any of the definitions in §192.903, the
operator must complete the evaluation using method (1) or (2). If the
segment is determined to meet the definition as a high consequence area,
it must be incorporated into the operator\'s baseline assessment plan as
a high consequence area within one year from the date the area is
identified.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003\]

**§192.907 What must an operator do to implement this subpart?**

\(a\) *General.* No later than December 17, 2004, an operator of a
covered pipeline segment must develop and follow a written integrity
management program that contains all the elements described in §192.911
and that addresses the risks on each covered transmission pipeline
segment. The initial integrity management program must consist, at a
minimum, of a framework that describes the process for implementing each
program element, how relevant decisions will be made and by whom, a time
line for completing the work to implement the program element, and how
information gained from experience will be continuously incorporated
into the program. The framework will evolve into a more detailed and
comprehensive program. An operator must make continual improvements to
the program.

\(b\) *Implementation Standards.* In carrying out this subpart, an
operator must follow the requirements of this subpart and of ASME/ANSI
B31.8S (incorporated by reference, *see* §192.7) and its appendices,
where specified. An operator may follow an equivalent standard or
practice only when the operator demonstrates the alternative standard or
practice provides an equivalent level of safety to the public and
property. In the event of a conflict between this subpart and ASME/ANSI
B31.8S, the requirements in this subpart control.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-103, 71 FR 33402, June 8,
2006\]

**§192.909 How can an operator change its integrity management
program?**

\(a\) *General.* An operator must document any change to its program and
the reasons for the change before implementing the change.

\(b\) *Notification.* An operator must notify OPS, in accordance with
§192.949, of any change to the program that may substantially affect the
program\'s implementation or may significantly modify the program or
schedule for carrying out the program elements. An operator must also
notify a State or local pipeline safety authority when either a covered
segment is located in a State where OPS has an interstate agent
agreement, or an intrastate covered segment is regulated by that State.
An operator must provide the notification within 30 days after adopting
this type of change into its program.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004\]

**§192.911 What are the elements of an integrity management program?**

An operator\'s initial integrity management program begins with a
framework (*see* §192.907) and evolves into a more detailed and
comprehensive integrity management program, as information is gained and
incorporated into the program. An operator must make continual
improvements to its program. The initial program framework and
subsequent program must, at minimum, contain the following elements.
(When indicated, refer to ASME/ANSI B31.8S (incorporated by reference,
*see* §192.7) for more detailed information on the listed element.)

\(a\) An identification of all high consequence areas, in accordance
with §192.905.

\(b\) A baseline assessment plan meeting the requirements of §192.919
and §192.921.

\(c\) An identification of threats to each covered pipeline segment,
which must include data integration and a risk assessment. An operator
must use the threat identification and risk assessment to prioritize
covered segments for assessment (§192.917) and to evaluate the merits of
additional preventive and mitigative measures (§192.935) for each
covered segment.

\(d\) A direct assessment plan, if applicable, meeting the requirements
of §192.923, and depending on the threat assessed, of §§  192.925,
192.927, or 192.929.

\(e\) Provisions meeting the requirements of §192.933 for remediating
conditions found during an integrity assessment.

\(f\) A process for continual evaluation and assessment meeting the
requirements of §192.937.

\(g\) If applicable, a plan for confirmatory direct assessment meeting
the requirements of §192.931.

\(h\) Provisions meeting the requirements of §192.935 for adding
preventive and mitigative measures to protect the high consequence area.

\(i\) A performance plan as outlined in ASME/ANSI B31.8S, section 9 that
includes performance measures meeting the requirements of §192.945.

\(j\) Record keeping provisions meeting the requirements of §192.947.

\(k\) A management of change process as outlined in ASME/ANSI B31.8S,
section 11.

\(l\) A quality assurance process as outlined in ASME/ANSI B31.8S,
section 12.

\(m\) A communication plan that includes the elements of ASME/ANSI
B31.8S, section 10, and that includes procedures for addressing safety
concerns raised by---

\(1\) OPS; and

\(2\) A State or local pipeline safety authority when a covered segment
is located in a State where OPS has an interstate agent agreement.

\(n\) Procedures for providing (when requested), by electronic or other
means, a copy of the operator\'s risk analysis or integrity management
program to---

\(1\) OPS; and

\(2\) A State or local pipeline safety authority when a covered segment
is located in a State where OPS has an interstate agent agreement.

\(o\) Procedures for ensuring that each integrity assessment is being
conducted in a manner that minimizes environmental and safety risks.

\(p\) A process for identification and assessment of newly-identified
high consequence areas. (See §192.905 and §192.921.)

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.913 When may an operator deviate its program from certain
requirements of this subpart?**

\(a\) *General.* ASME/ANSI B31.8S (incorporated by reference, *see*
§192.7) provides the essential features of a performance-based or a
prescriptive integrity management program. An operator that uses a
performance-based approach that satisfies the requirements for
exceptional performance in paragraph (b) of this section may deviate
from certain requirements in this subpart, as provided in paragraph (c)
of this section.

\(b\) *Exceptional performance.* An operator must be able to demonstrate
the exceptional performance of its integrity management program through
the following actions.

\(1\) To deviate from any of the requirements set forth in paragraph (c)
of this section, an operator must have a performance-based integrity
management program that meets or exceed the performance-based
requirements of ASME/ANSI B31.8S and includes, at a minimum, the
following elements---

\(i\) A comprehensive process for risk analysis;

\(ii\) All risk factor data used to support the program;

\(iii\) A comprehensive data integration process;

\(iv\) A procedure for applying lessons learned from assessment of
covered pipeline segments to pipeline segments not covered by this
subpart;

\(v\) A procedure for evaluating every incident, including its cause,
within the operator\'s sector of the pipeline industry for implications
both to the operator\'s pipeline system and to the operator\'s integrity
management program;

\(vi\) A performance matrix that demonstrates the program has been
effective in ensuring the integrity of the covered segments by
controlling the identified threats to the covered segments;

\(vii\) Semi-annual performance measures beyond those required in
§192.945 that are part of the operator\'s performance plan. (See
§192.911(i).) An operator must submit these measures, by electronic or
other means, on a semi-annual frequency to OPS in accordance with
§192.951; and

\(viii\) An analysis that supports the desired integrity reassessment
interval and the remediation methods to be used for all covered
segments.

\(2\) In addition to the requirements for the performance-based plan, an
operator must---

\(i\) Have completed at least two integrity assessments on each covered
pipeline segment the operator is including under the performance-based
approach, and be able to demonstrate that each assessment effectively
addressed the identified threats on the covered segment.

\(ii\) Remediate all anomalies identified in the more recent assessment
according to the requirements in §192.933, and incorporate the results
and lessons learned from the more recent assessment into the operator\'s
data integration and risk assessment.

\(c\) *Deviation.* Once an operator has demonstrated that it has
satisfied the requirements of paragraph (b) of this section, the
operator may deviate from the prescriptive requirements of ASME/ANSI
B31.8S and of this subpart only in the following instances.

\(1\) The time frame for reassessment as provided in §192.939 except
that reassessment by some method allowed under this subpart (e.g.,
confirmatory direct assessment) must be carried out at intervals no
longer than seven years;

\(2\) The time frame for remediation as provided in §192.933 if the
operator demonstrates the time frame will not jeopardize the safety of
the covered segment.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.915 What knowledge and training must personnel have to carry out
an integrity management program?**

\(a\) *Supervisory personnel.* The integrity management program must
provide that each supervisor whose responsibilities relate to the
integrity management program possesses and maintains a thorough
knowledge of the integrity management program and of the elements for
which the supervisor is responsible. The program must provide that any
person who qualifies as a supervisor for the integrity management
program has appropriate training or experience in the area for which the
person is responsible.

\(b\) *Persons who carry out assessments and evaluate assessment
results.* The integrity management program must provide criteria for the
qualification of any person---

\(1\) Who conducts an integrity assessment allowed under this subpart;
or

\(2\) Who reviews and analyzes the results from an integrity assessment
and evaluation; or

\(3\) Who makes decisions on actions to be taken based on these
assessments.

\(c\) *Persons responsible for preventive and mitigative measures.* The
integrity management program must provide criteria for the qualification
of any person---

\(1\) Who implements preventive and mitigative measures to carry out
this subpart, including the marking and locating of buried structures;
or

\(2\) Who directly supervises excavation work carried out in conjunction
with an integrity assessment.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003\]

**§192.917 How does an operator identify potential threats to pipeline
integrity and use the threat identification in its integrity program?**

\(a\) *Threat identification.* An operator must identify and evaluate
all potential threats to each covered pipeline segment. Potential
threats that an operator must consider include, but are not limited to,
the threats listed in ASME/ANSI B31.8S (incorporated by reference, *see*
§192.7), section 2, which are grouped under the following four
categories:

\(1\) Time dependent threats such as internal corrosion, external
corrosion, and stress corrosion cracking;

\(2\) Static or resident threats, such as fabrication or construction
defects;

\(3\) Time independent threats such as third party damage and outside
force damage; and

\(4\) Human error.

\(b\) *Data gathering and integration.* To identify and evaluate the
potential threats to a covered pipeline segment, an operator must gather
and integrate existing data and information on the entire pipeline that
could be relevant to the covered segment. In performing this data
gathering and integration, an operator must follow the requirements in
ASME/ANSI B31.8S, section 4. At a minimum, an operator must gather and
evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S,
and consider both on the covered segment and similar non-covered
segments, past incident history, corrosion control records, continuing
surveillance records, patrolling records, maintenance history, internal
inspection records and all other conditions specific to each pipeline.

\(c\) *Risk assessment.* An operator must conduct a risk assessment that
follows ASME/ANSI B31.8S, section 5, and considers the identified
threats for each covered segment. An operator must use the risk
assessment to prioritize the covered segments for the baseline and
continual reassessments (§§ 192.919, 192.921, 192.937), and to determine
what additional preventive and mitigative measures are needed (§192.935)
for the covered segment.

\(d\) *Plastic transmission pipeline.* An operator of a plastic
transmission pipeline must assess the threats to each covered segment
using the information in sections 4 and 5 of ASME B31.8S, and consider
any threats unique to the integrity of plastic pipe.

\(e\) *Actions to address particular threats*. If an operator identifies
any of the following threats, the operator must take the following
actions to address the threat.

\(1\) *Third party damage.* An operator must utilize the data
integration required in paragraph (b) of this section and ASME/ANSI
B31.8S, Appendix A7 to determine the susceptibility of each covered
segment to the threat of third party damage. If an operator identifies
the threat of third party damage, the operator must implement
comprehensive additional preventive measures in accordance with §192.935
and monitor the effectiveness of the preventive measures. If, in
conducting a baseline assessment under §192.921, or a reassessment under
§192.937, an operator uses an internal inspection tool or external
corrosion direct assessment, the operator must integrate data from these
assessments with data related to any encroachment or foreign line
crossing on the covered segment, to define where potential indications
of third party damage may exist in the covered segment.

An operator must also have procedures in its integrity management
program addressing actions it will take to respond to findings from this
data integration.

\(2\) *Cyclic fatigue.* An operator must evaluate whether cyclic fatigue
or other loading condition (including ground movement, suspension bridge
condition) could lead to a failure of a deformation, including a dent or
gouge, or other defect in the covered segment. An evaluation must assume
the presence of threats in the covered segment that could be exacerbated
by cyclic fatigue. An operator must use the results from the evaluation
together with the criteria used to evaluate the significance of this
threat to the covered segment to prioritize the integrity baseline
assessment or reassessment.

\(3\) *Manufacturing and construction defects.* If an operator
identifies the threat of manufacturing and construction defects
(including seam defects) in the covered segment, an operator must
analyze the covered segment to determine the risk of failure from these
defects. The analysis must consider the results of prior assessments on
the covered segment. An operator may consider manufacturing and
construction related defects to be stable defects if the operating
pressure on the covered segment has not increased over the maximum
operating pressure experienced during the five years preceding
identification of the high consequence area. If any of the following
changes occur in the covered segment, an operator must prioritize the
covered segment as a high risk segment for the baseline assessment or a
subsequent reassessment.

\(i\) Operating pressure increases above the maximum operating pressure
experienced during the preceding five years;

\(ii\) MAOP increases; or

\(iii\) The stresses leading to cyclic fatigue increase.

\(4\) *ERW pipe.* If a covered pipeline segment contains low frequency
electric resistance welded pipe (ERW), lap welded pipe or other pipe
that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices
A4.3 and A4.4, and any covered or noncovered segment in the pipeline
system with such pipe has experienced seam failure, or operating
pressure on the covered segment has increased over the maximum operating
pressure experienced during the preceding five years, an operator must
select an assessment technology or technologies with a proven
application capable of assessing seam integrity and seam corrosion
anomalies. The operator must prioritize the covered segment as a high
risk segment for the baseline assessment or a subsequent reassessment.

\(5\) *Corrosion.* If an operator identifies corrosion on a covered
pipeline segment that could adversely affect the integrity of the line
(conditions specified in §192.933), the operator must evaluate and
remediate, as necessary, all pipeline segments (both covered and
non-covered) with similar material coating and environmental
characteristics. An operator must establish a schedule for evaluating
and remediating, as necessary, the similar segments that is consistent
with the operator\'s established operating and maintenance procedures
under part 192 for testing and repair.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.919 What must be in the baseline assessment plan?**

An operator must include each of the following elements in its written
baseline assessment plan:

\(a\) Identification of the potential threats to each covered pipeline
segment and the information supporting the threat identification. (See
§192.917.);

\(b\) The methods selected to assess the integrity of the line pipe,
including an explanation of why the assessment method was selected to
address the identified threats to each covered segment. The integrity
assessment method an operator uses must be based on the threats
identified to the covered segment. (See §192.917.) More than one method
may be required to address all the threats to the covered pipeline
segment;

\(c\) A schedule for completing the integrity assessment of all covered
segments, including risk factors considered in establishing the
assessment schedule;

\(d\) If applicable, a direct assessment plan that meets the
requirements of §§ 192.923, and depending on the threat to be addressed,
of §192.925, §192.927, or §192.929; and

\(e\) A procedure to ensure that the baseline assessment is being
conducted in a manner that minimizes environmental and safety risks.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003\]

**§192.921 How is the baseline assessment to be conducted?**

\(a\) *Assessment methods.* An operator must assess the integrity of the
line pipe in each covered segment by applying one or more of the
following methods depending on the threats to which the covered segment
is susceptible. An operator must select the method or methods best
suited to address the threats identified to the covered segment (See
§192.917).

\(1\) Internal inspection tool or tools capable of detecting corrosion,
and any other threats to which the covered segment is susceptible. An
operator must follow ASME/ANSI B31.8S (incorporated by reference, *see*
§192.7), section 6.2 in selecting the appropriate internal inspection
tools for the covered segment.

\(2\) Pressure test conducted in accordance with subpart J of this part.
An operator must use the test pressures specified in Table 3 of section
5 of ASME/ANSI B31.8S, to justify an extended reassessment interval in
accordance with §192.939.

\(3\) Direct assessment to address threats of external corrosion,
internal corrosion, and stress corrosion cracking. An operator must
conduct the direct assessment in accordance with the requirements listed
in §192.923 and with, as applicable, the requirements specified in §§
192.925, 192.927 or 192.929;

\(4\) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. An operator
choosing this option must notify the Office of Pipeline Safety (OPS) 180
days before conducting the assessment, in accordance with §192.949. An
operator must also notify a State or local pipeline safety authority
when either a covered segment is located in a State where OPS has an
interstate agent agreement, or an intrastate covered segment is
regulated by that State.

\(b\) *Prioritizing segments.* An operator must prioritize the covered
pipeline segments for the baseline assessment according to a risk
analysis that considers the potential threats to each covered segment.
The risk analysis must comply with the requirements in §192.917.

\(c\) *Assessment for particular threats.* In choosing an assessment
method for the baseline assessment of each covered segment, an operator
must take the actions required in §192.917(e) to address particular
threats that it has identified.

\(d\) *Time period.* An operator must prioritize all the covered
segments for assessment in accordance with §192.917 (c) and paragraph
(b) of this section. An operator must assess at least 50% of the covered
segments beginning with the highest risk segments, by December 17, 2007.
An operator must complete the baseline assessment of all covered
segments by December 17, 2012.

\(e\) *Prior assessment*. An operator may use a prior integrity
assessment conducted before December 17, 2002 as a baseline assessment
for the covered segment, if the integrity assessment meets the baseline
requirements in this subpart and subsequent remedial actions to address
the conditions listed in §192.933 have been carried out. In addition, if
an operator uses this prior assessment as its baseline assessment, the
operator must reassess the line pipe in the covered segment according to
the requirements of §192.937 and §192.939.

\(f\) *Newly identified areas.* When an operator identifies a new high
consequence area (see §192.905), an operator must complete the baseline
assessment of the line pipe in the newly identified high consequence
area within ten (10) years from the date the area is identified.

\(g\) *Newly installed pipe.* An operator must complete the baseline
assessment of a newly-installed segment of pipe covered by this subpart
within ten (10) years from the date the pipe is installed. An operator
may conduct a pressure test in accordance with paragraph (a)(2) of this
section, to satisfy the requirement for a baseline assessment.

\(h\) *Plastic transmission pipeline*. If the threat analysis required
in §192.917(d) on a plastic transmission pipeline indicates that a
covered segment is susceptible to failure from causes other than
third-party damage, an operator must conduct a baseline assessment of
the segment in accordance with the requirements of this section and of
§192.917. The operator must justify the use of an alternative assessment
method that will address the identified threats to the covered segment.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, Apr. 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.923 How is direct assessment used and for what threats?**

\(a\) *General.* An operator may use direct assessment either as a
primary assessment method or as a supplement to the other assessment
methods allowed under this subpart. An operator may only use direct
assessment as the primary assessment method to address the identified
threats of external corrosion (ECDA), internal corrosion (ICDA), and
stress corrosion cracking (SCCDA).

\(b\) *Primary method.* An operator using direct assessment as a primary
assessment method must have a plan that complies with the requirements
in---

\(1\) ASME/ANSI B31.8S (incorporated by reference *see* §192.7), section
6.4; NACE RP0502-2002 (incorporated by reference, *see* §192.7); and
§192.925 if addressing external corrosion (ECDA).

\(2\) ASME/ANSI B31.8S, section 6.4 and appendix B2, and §192.927 if
addressing internal corrosion (ICDA).

\(3\) ASME/ANSI B31.8S, appendix A3, and §192.929 if addressing stress
corrosion cracking (SCCDA).

\(c\) *Supplemental method.* An operator using direct assessment as a
supplemental assessment method for any applicable threat must have a
plan that follows the requirements for confirmatory direct assessment in
§192.931.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-103, 71 FR 33402, June 8,
2006\]

**§192.925 What are the requirements for using External Corrosion Direct
Assessment (ECDA)?**

\(a\) *Definition.* ECDA is a four-step process that combines
preassessment, indirect inspection, direct examination, and post
assessment to evaluate the threat of external corrosion to the integrity
of a pipeline.

\(b\) *General requirements.* An operator that uses direct assessment to
assess the threat of external corrosion must follow the requirements in
this section, in ASME/ANSI B31.8S (incorporated by reference *see*
§192.7), section 6.4, and in NACE RP 0502-2002 (incorporated by
reference *see* §192.7). An operator must develop and implement a direct
assessment plan that has procedures addressing preassessment, indirect
examination, direct examination, and post-assessment. If the ECDA
detects pipeline coating damage, the operator must also integrate the
data from the ECDA with other information from the data integration
(§192.917(b)) to evaluate the covered segment for the threat of third
party damage, and to address the threat as required by §192.917(e)(1).

\(1\) *Preassessment.* In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502-2002, section 3, the plan\'s
procedures for preassessment must include---

\(i\) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment; and

\(ii\) The basis on which an operator selects at least two different,
but complementary indirect assessment tools to assess each ECDA Region.
If an operator utilizes an indirect inspection method that is not
discussed in Appendix A of NACE RP0502-2002, the operator must
demonstrate the applicability, validation basis, equipment used,
application procedure, and utilization of data for the inspection
method.

\(2\) *Indirect examination.* In addition to the requirements in
ASME/ANSI B31.8S section 6.4 and NACE RP 0502-2002, section 4, the
plan\'s procedures for indirect examination of the ECDA regions must
include---

\(i\) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment;

\(ii\) Criteria for identifying and documenting those indications that
must be considered for excavation and direct examination. Minimum
identification criteria include the known sensitivities of assessment
tools, the procedures for using each tool, and the approach to be used
for decreasing the physical spacing of indirect assessment tool readings
when the presence of a defect is suspected;

\(iii\) Criteria for defining the urgency of excavation and direct
examination of each indication identified during the indirect
examination. These criteria must specify how an operator will define the
urgency of excavating the indication as immediate, scheduled or
monitored; and

\(iv\) Criteria for scheduling excavation of indications for each
urgency level.

\(3\) *Direct examination.* In addition to the requirements in ASME/ANSI
B31.8S section 6.4 and NACE RP 0502-2002, section 5, the plan\'s
procedures for direct examination of indications from the indirect
examination must include---

\(i\) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a covered segment;

\(ii\) Criteria for deciding what action should be taken if either:

\(A\) Corrosion defects are discovered that exceed allowable limits
(Section 5.5.2.2 of NACE RP0502-2002), or

\(B\) Root cause analysis reveals conditions for which ECDA is not
suitable (Section 5.6.2 of NACE RP0502-2002);

\(iii\) Criteria and notification procedures for any changes in the ECDA
Plan, including changes that affect the severity classification, the
priority of direct examination, and the time frame for direct
examination of indications; and

\(iv\) Criteria that describe how and on what basis an operator will
reclassify and reprioritize any of the provisions that are specified in
section 5.9 of NACE RP0502-2002.

\(4\) *Post assessment and continuing evaluation.* In addition to the
requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502-2002,
section 6, the plan\'s procedures for post assessment of the
effectiveness of the ECDA process must include---

\(i\) Measures for evaluating the long-term effectiveness of ECDA in
addressing external corrosion in covered segments; and

\(ii\) Criteria for evaluating whether conditions discovered by direct
examination of indications in each ECDA region indicate a need for
reassessment of the covered segment at an interval less than that
specified in § 192.939. (See Appendix D of NACE RP0502-2002.)

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95C, 69 FR 29903, May 26,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.927 What are the requirements for using Internal Corrosion Direct
Assessment (ICDA)?**

\(a\) *Definition.* Internal Corrosion Direct Assessment (ICDA) is a
process an operator uses to identify areas along the pipeline where
fluid or other electrolyte introduced during normal operation or by an
upset condition may reside, and then focuses direct examination on the
locations in covered segments where internal corrosion is most likely to
exist. The process identifies the potential for internal corrosion
caused by microorganisms, or fluid with CO~2~, O~2~, hydrogen sulfide or
other contaminants present in the gas.

\(b\) *General requirements*. An operator using direct assessment as an
assessment method to address internal corrosion in a covered pipeline
segment must follow the requirements in this section and in ASME/ANSI
B31.8S (incorporated by reference, *see* §192.7), section 6.4 and
appendix B2. The ICDA process described in this section applies only for
a segment of pipe transporting nominally dry natural gas, and not for a
segment with electrolyte nominally present in the gas stream. If an
operator uses ICDA to assess a covered segment operating with
electrolyte present in the gas stream, the operator must develop a plan
that demonstrates how it will conduct ICDA in the segment to effectively
address internal corrosion, and must provide notification in accordance
with §192.921 (a)(4) or §192.937(c)(4).

\(c\) *The ICDA plan.* An operator must develop and follow an ICDA plan
that provides for preassessment, identification of ICDA regions and
excavation locations, detailed examination of pipe at excavation
locations, and post-assessment evaluation and monitoring.

\(1\) *Preassessment*. In the preassessment stage, an operator must
gather and integrate data and information needed to evaluate the
feasibility of ICDA for the covered segment, and to support use of a
model to identify the locations along the pipe segment where electrolyte
may accumulate, to identify ICDA regions, and to identify areas within
the covered segment where liquids may potentially be entrained. This
data and information includes, but is not limited to---

\(i\) All data elements listed in appendix A2 of ASME/ANSI B31.8S;

\(ii\) Information needed to support use of a model that an operator
must use to identify areas along the pipeline where internal corrosion
is most likely to occur. (See paragraph (a) of this section.) This
information, includes, but is not limited to, location of all gas input
and withdrawal points on the line; location of all low points on covered
segments such as sags, drips, inclines, valves, manifolds, dead-legs,
and traps; the elevation profile of the pipeline in sufficient detail
that angles of inclination can be calculated for all pipe segments; and
the diameter of the pipeline, and the range of expected gas velocities
in the pipeline;

\(iii\) Operating experience data that would indicate historic upsets in
gas conditions, locations where these upsets have occurred, and
potential damage resulting from these upset conditions; and

\(iv\) Information on covered segments where cleaning pigs may not have
been used or where cleaning pigs may deposit electrolytes.

\(2\) *ICDA region identification*. An operator\'s plan must identify
where all ICDA Regions are located in the transmission system, in which
covered segments are located. An ICDA Region extends from the location
where liquid may first enter the pipeline and encompasses the entire
area along the pipeline where internal corrosion may occur and where
further evaluation is needed. An ICDA Region may encompass one or more
covered segments. In the identification process, an operator must use
the model in GRI 02-0057, "Internal Corrosion Direct Assessment of Gas
Transmission Pipelines---Methodology," (incorporated by reference, *see*
§192.7). An operator may use another model if the operator demonstrates
it is equivalent to the one shown in GRI 02-0057. A model must consider
changes in pipe diameter, locations where gas enters a line (potential
to introduce liquid) and locations down stream of gas draw-offs (where
gas velocity is reduced) to define the critical pipe angle of
inclination above which water film cannot be transported by the gas.

\(3\) *Identification of locations for excavation and direct
examination.* An operator\'s plan must identify the locations where
internal corrosion is most likely in each ICDA region. In the location
identification process, an operator must identify a minimum of two
locations for excavation within each ICDA Region within a covered
segment and must perform a direct examination for internal corrosion at
each location, using ultrasonic thickness measurements, radiography, or
other generally accepted measurement technique. One location must be the
low point (e.g., sags, drips, valves, manifolds, dead-legs, traps)
within the covered segment nearest to the beginning of the ICDA Region.
The second location must be further downstream, within a covered
segment, near the end of the ICDA Region. If corrosion exists at either
location, the operator must---

\(i\) Evaluate the severity of the defect (remaining strength) and
remediate the defect in accordance with §192.933;

\(ii\) As part of the operator\'s current integrity assessment either
perform additional excavations in each covered segment within the ICDA
region, or use an alternative assessment method allowed by this subpart
to assess the line pipe in each covered segment within the ICDA region
for internal corrosion; and

\(iii\) Evaluate the potential for internal corrosion in all pipeline
segments (both covered and non-covered) in the operator\'s pipeline
system with similar characteristics to the ICDA region containing the
covered segment in which the corrosion was found, and as appropriate,
remediate the conditions the operator finds in accordance with §192.933.

\(4\) *Post-assessment evaluation and monitoring.* An operator\'s plan
must provide for evaluating the effectiveness of the ICDA process and
continued monitoring of covered segments where internal corrosion has
been identified. The evaluation and monitoring process includes---

\(i\) Evaluating the effectiveness of ICDA as an assessment method for
addressing internal corrosion and determining whether a covered segment
should be reassessed at more frequent intervals than those specified in
§192.939. An operator must carry out this evaluation within a year of
conducting an ICDA; and

\(ii\) Continually monitoring each covered segment where internal
corrosion has been identified using techniques such as coupons, UT
sensors or electronic probes, periodically drawing off liquids at low
points and chemically analyzing the liquids for the presence of
corrosion products. An operator must base the frequency of the
monitoring and liquid analysis on results from all integrity assessments
that have been conducted in accordance with the requirements of this
subpart, and risk factors specific to the covered segment. If an
operator finds any evidence of corrosion products in the covered
segment, the operator must take prompt action in accordance with one of
the two following required actions and remediate the conditions the
operator finds in accordance with §192.933.

\(A\) Conduct excavations of covered segments at locations downstream
from where the electrolyte might have entered the pipe; or

\(B\) Assess the covered segment using another integrity assessment
method allowed by this subpart.

\(5\) *Other requirements.* The ICDA plan must also include---

\(i\) Criteria an operator will apply in making key decisions (e.g.,
ICDA feasibility, definition of ICDA Regions, conditions requiring
excavation) in implementing each stage of the ICDA process;

\(ii\) Provisions for applying more restrictive criteria when conducting
ICDA for the first time on a covered segment and that become less
stringent as the operator gains experience; and

\(iii\) Provisions that analysis be carried out on the entire pipeline
in which covered segments are present, except that application of the
remediation criteria of §192.933 may be limited to covered segments.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.929 What are the requirements for using Direct Assessment for
Stress Corrosion Cracking (SCCDA)?**

\(a\) *Definition.* Stress Corrosion Cracking Direct Assessment (SCCDA)
is a process to assess a covered pipe segment for the presence of SCC
primarily by systematically gathering and analyzing excavation data for
pipe having similar operational characteristics and residing in a
similar physical environment.

\(b\) *General requirements*. An operator using direct assessment as an
integrity assessment method to address stress corrosion cracking in a
covered pipeline segment must have a plan that provides, at minimum,
for---

\(1\) Data gathering and integration. An operator\'s plan must provide
for a systematic process to collect and evaluate data for all covered
segments to identify whether the conditions for SCC are present and to
prioritize the covered segments for assessment. This process must
include gathering and evaluating data related to SCC at all sites an
operator excavates during the conduct of its pipeline operations where
the criteria in ASME/ANSI B31.8S (incorporated by reference, *see*
§192.7), appendix A3.3 indicate the potential for SCC. This data
includes at minimum, the data specified in ASME/ANSI B31.8S, appendix
A3.

\(2\) Assessment method. The plan must provide that if conditions for
SCC are identified in a covered segment, an operator must assess the
covered segment using an integrity assessment method specified in
ASME/ANSI B31.8S, appendix A3, and remediate the threat in accordance
with ASME/ANSI B31.8S, appendix A3, section A3.4.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.931 How may Confirmatory Direct Assessment (CDA) be used?**

An operator using the confirmatory direct assessment (CDA) method as
allowed in §192.937 must have a plan that meets the requirements of this
section and of §§ 192.925 (ECDA) and §192.927 (ICDA).

\(a\) *Threats.* An operator may only use CDA on a covered segment to
identify damage resulting from external corrosion or internal corrosion.

\(b\) *External corrosion plan.* An operator\'s CDA plan for identifying
external corrosion must comply with §192.925 with the following
exceptions.

\(1\) The procedures for indirect examination may allow use of only one
indirect examination tool suitable for the application.

\(2\) The procedures for direct examination and remediation must provide
that---

\(i\) All immediate action indications must be excavated for each ECDA
region; and

\(ii\) At least one high risk indication that meets the criteria of
scheduled action must be excavated in each ECDA region.

\(c\) *Internal corrosion plan.* An operator\'s CDA plan for identifying
internal corrosion must comply with §192.927 except that the plan\'s
procedures for identifying locations for excavation may require
excavation of only one high risk location in each ICDA region.

\(d\) *Defects requiring near-term remediation.* If an assessment
carried out under paragraph (b) or (c) of this section reveals any
defect requiring remediation prior to the next scheduled assessment, the
operator must schedule the next assessment in accordance with NACE RP
0502-2002 (incorporated by reference *see* §192.7), section 6.2 and 6.3.
If the defect requires immediate remediation, then the operator must
reduce pressure consistent with §192.933 until the operator has
completed reassessment using one of the assessment techniques allowed in
§192.937.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-103, 71 FR 33402, June 8,
2006\]

**§192.933 What actions must be taken to address integrity issues?**

[(a) *General requirements.* An operator must take prompt action to
address all anomalous conditions the operator discovers through the
integrity assessment. In addressing all conditions, an operator must
evaluate all anomalous conditions and remediate those that could reduce
a pipeline\'s integrity. An operator must be able to demonstrate that
the remediation of the condition will ensure the condition is unlikely
to pose a threat to the integrity of the pipeline until the next
reassessment of the covered segment.]{.underline}

[(1) *Temporary pressure reduction*. If an operator is unable to respond
within the time limits for certain conditions specified in this section,
the operator must temporarily reduce the operating pressure of the
pipeline or take other action that ensures the safety of the covered
segment. An operator must determine any temporary reduction in operating
pressure required by this section using ASME/ANSI B31G (incorporated by
reference, see §192.7) or AGA Pipeline Research Committee Project
PR-3-805 ("RSTRENG,\'\' incorporated by reference, see §192.7) or reduce
the operating pressure to a level not exceeding 80 percent of the level
at the time the condition was discovered. (See appendix A to this part
for information on availability of incorporation by reference
information.) An operator must notify PHMSA in accordance with §192.949
if it cannot meet the schedule for evaluation and remediation required
under paragraph (c) of this section and cannot provide safety through
temporary reduction in operating pressure or other action. An operator
must also notify a State pipeline safety authority when either a covered
segment is located in a State where PHMSA has an interstate agent
agreement, or an intrastate covered segment is regulated by that
State.]{.underline}

[(2) *Long-term pressure reduction.* When a pressure reduction exceeds
365 days, the operator must notify PHMSA under §192.949 and explain the
reasons for the remediation delay. This notice must include a technical
justification that the continued pressure reduction will not jeopardize
the integrity of the pipeline. The operator also must notify a State
pipeline safety authority when either a covered segment is located in a
State where PHMSA has an interstate agent agreement, or an intrastate
covered segment is regulated by that State.]{.underline}

[(a) *General requirements.* An operator must take prompt action to
address all anomalous conditions the operator discovers through the
integrity assessment. In addressing all conditions, an operator must
evaluate all anomalous conditions and remediate those that could reduce
a pipeline\'s integrity. An operator must be able to demonstrate that
the remediation of the condition will ensure the condition is unlikely
to pose a threat to the integrity of the pipeline until the next
reassessment of the covered segment.]{.mark}

[(1) *Temporary pressure reduction*. If an operator is unable to respond
within the time limits for certain conditions specified in this section,
the operator must temporarily reduce the operating pressure of the
pipeline or take other action that ensures the safety of the covered
segment. An operator must determine any temporary reduction in operating
pressure required by this section using ASME/ANSI B31G (incorporated by
reference, see §192.7) or AGA Pipeline Research Committee Project
PR-3-805 ("RSTRENG,\'\' incorporated by reference, see §192.7) or reduce
the operating pressure to a level not exceeding 80 percent of the level
at the time the condition was discovered. (See appendix A to this part
for information on availability of incorporation by reference
information.) An operator must notify PHMSA in accordance with §192.949
if it cannot meet the schedule for evaluation and remediation required
under paragraph (c) of this section and cannot provide safety through
temporary reduction in operating pressure or other action. An operator
must also notify a State pipeline safety authority when either a covered
segment is located in a State where PHMSA has an interstate agent
agreement, or an intrastate covered segment is regulated by that
State.]{.mark}

[(2) *Long-term pressure reduction.* When a pressure reduction exceeds
365 days, the operator must notify PHMSA under §192.949 and explain the
reasons for the remediation delay. This notice must include a technical
justification that the continued pressure reduction will not jeopardize
the integrity of the pipeline. The operator also must notify a State
pipeline safety authority when either a covered segment is located in a
State where PHMSA has an interstate agent agreement, or an intrastate
covered segment is regulated by that State.]{.mark}

\(b\) *Discovery of condition.* Discovery of a condition occurs when an
operator has adequate information about a condition to determine that
the condition presents a potential threat to the integrity of the
pipeline. A condition that presents a potential threat includes, but is
not limited to, those conditions that require remediation or monitoring
listed under paragraphs (d)(1) through (d)(3) of this section. An
operator must promptly, but no later than 180 days after conducting an
integrity assessment, obtain sufficient information about a condition to
make that determination, unless the operator demonstrates that the
180-day period is impracticable.

\(c\) *Schedule for evaluation and remediation.* [An operator must
complete remediation of a condition according to a schedule prioritizing
the conditions for evaluation and remediation. Unless a special
requirement for remediating certain conditions applies, as provided in
paragraph (d) of this section, an operator must follow the schedule in
ASME/ANSI B31.8S (incorporated by reference, see §192.7), section 7,
Figure 4. If an operator cannot meet the schedule for any condition, the
operator must explain the reasons why it cannot meet the schedule and
how the changed schedule will not jeopardize public safety.]{.underline}
[An operator must complete remediation of a condition according to a
schedule that prioritizes the conditions for evaluation and remediation.
Unless a special requirement for remediating certain conditions applies,
as provided in paragraph (d) of this section, an operator must follow
the schedule in ASME/ANSI B31.8S (incorporated by reference, *see*
§192.7), section 7, Figure 4. If an operator cannot meet the schedule
for any condition, the operator must justify the reasons why it cannot
meet the schedule and that the changed schedule will not jeopardize
public safety. An operator must notify OPS in accordance with §192.949
if it cannot meet the schedule and cannot provide safety through a
temporary reduction in operating pressure or other action. An operator
must also notify a State or local pipeline safety authority when either
a covered segment is located in a State where OPS has an interstate
agent agreement, or an intrastate covered segment is regulated by that
State.]{.mark}

\(d\) *Special requirements for scheduling remediation*.---(1) Immediate
repair conditions. An operator\'s evaluation and remediation schedule
must follow ASME/ANSI B31.8S, section 7 in providing for immediate
repair conditions. To maintain safety, an operator must temporarily
reduce operating pressure in accordance with paragraph (a) of this
section or shut down the pipeline until the operator completes the
repair of these conditions. An operator must treat the following
conditions as immediate repair conditions:

\(i\) A calculation of the remaining strength of the pipe shows a
predicted failure pressure less than or equal to 1.1 times the maximum
allowable operating pressure at the location of the anomaly. Suitable
remaining strength calculation methods include, ASME/ANSI B31G; RSTRENG;
or an alternative equivalent method of remaining strength calculation.
These documents are incorporated by reference and available at the
addresses listed in appendix A to part 192.

\(ii\) A dent that has any indication of metal loss, cracking or a
stress riser.

\(iii\) An indication or anomaly that in the judgment of the person
designated by the operator to evaluate the assessment results requires
immediate action.

\(2\) *One-year conditions.* Except for conditions listed in paragraph
(d)(1) and (d)(3) of this section, an operator must remediate any of the
following within one year of discovery of the condition:

\(i\) A smooth dent located between the 8 o\'clock and 4 o\'clock
positions (upper ⅔ of the pipe) with a depth greater than 6% of the
pipeline diameter (greater than 0.50 inches in depth for a pipeline
diameter less than Nominal Pipe Size (NPS) 12).

\(ii\) A dent with a depth greater than 2% of the pipeline\'s diameter
(0.250 inches in depth for a pipeline diameter less than NPS 12) that
affects pipe curvature at a girth weld or at a longitudinal seam weld.

\(3\) *Monitored conditions.* An operator does not have to schedule the
following conditions for remediation, but must record and monitor the
conditions during subsequent risk assessments and integrity assessments
for any change that may require remediation:

\(i\) A dent with a depth greater than 6% of the pipeline diameter
(greater than 0.50 inches in depth for a pipeline diameter less than NPS
12) located between the 4 o\'clock position and the 8 o\'clock position
(bottom ⅓ of the pipe).

\(ii\) A dent located between the 8 o\'clock and 4 o\'clock positions
(upper ⅔ of the pipe) with a depth greater than 6% of the pipeline
diameter (greater than 0.50 inches in depth for a pipeline diameter less
than Nominal Pipe Size (NPS) 12), and engineering analyses of the dent
demonstrate critical strain levels are not exceeded.

\(iii\) A dent with a depth greater than 2% of the pipeline\'s diameter
(0.250 inches in depth for a pipeline diameter less than NPS 12) that
affects pipe curvature at a girth weld or a longitudinal seam weld, and
engineering analyses of the dent and girth or seam weld demonstrate
critical strain levels are not exceeded. These analyses must consider
weld properties.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006[; Amdt. 192-104, 72 FR
39012, July 17, 2007]{.underline}\]

**§192.935 What additional preventive and mitigative measures must an
operator take?**

\(a\) *General requirements.* An operator must take additional measures
beyond those already required by Part 192 to prevent a pipeline failure
and to mitigate the consequences of a pipeline failure in a high
consequence area. An operator must base the additional measures on the
threats the operator has identified to each pipeline segment. (*See*
§192.917) An operator must conduct, in accordance with one of the risk
assessment approaches in ASME/ANSI B31.8S (incorporated by reference,
*see* §192.7), section 5, a risk analysis of its pipeline to identify
additional measures to protect the high consequence area and enhance
public safety. Such additional measures include, but are not limited to,
installing Automatic Shut-off Valves or Remote Control Valves,
installing computerized monitoring and leak detection systems, replacing
pipe segments with pipe of heavier wall thickness, providing additional
training to personnel on response procedures, conducting drills with
local emergency responders and implementing additional inspection and
maintenance programs.

\(b\) *Third party damage and outside force damage*---(1) *Third party
damage.* An operator must enhance its damage prevention program, as
required under §192.614 of this part, with respect to a covered segment
to prevent and minimize the consequences of a release due to third party
damage. Enhanced measures to an existing damage prevention program
include, at a minimum---

\(i\) Using qualified personnel (*see* §192.915) for work an operator is
conducting that could adversely affect the integrity of a covered
segment, such as marking, locating, and direct supervision of known
excavation work.

\(ii\) Collecting in a central database information that is location
specific on excavation damage that occurs in covered and non covered
segments in the transmission system and the root cause analysis to
support identification of targeted additional preventative and
mitigative measures in the high consequence areas. This information must
include recognized damage that is not required to be reported as an
incident under part 191.

\(iii\) Participating in one-call systems in locations where covered
segments are present.

\(iv\) Monitoring of excavations conducted on covered pipeline segments
by pipeline personnel. If an operator finds physical evidence of
encroachment involving excavation that the operator did not monitor near
a covered segment, an operator must either excavate the area near the
encroachment or conduct an above ground survey using methods defined in
NACE RP-0502-2002 (incorporated by reference, *see* §192.7). An operator
must excavate, and remediate, in accordance with ANSI/ASME B31.8S and
§192.933 any indication of coating holidays or discontinuity warranting
direct examination.

\(2\) *Outside force damage*. If an operator determines that outside
force (e.g., earth movement, floods, unstable suspension bridge) is a
threat to the integrity of a covered segment, the operator must take
measures to minimize the consequences to the covered segment from
outside force damage. These measures include, but are not limited to,
increasing the frequency of aerial, foot or other methods of patrols,
adding external protection, reducing external stress, and relocating the
line.

\(c\) *Automatic shut-off valves (ASV) or Remote control valves (RCV)*.
If an operator determines, based on a risk analysis, that an ASV or RCV
would be an efficient means of adding protection to a high consequence
area in the event of a gas release, an operator must install the ASV or
RCV. In making that determination, an operator must, at least, consider
the following factors---swiftness of leak detection and pipe shutdown
capabilities, the type of gas being transported, operating pressure, the
rate of potential release, pipeline profile, the potential for ignition,
and location of nearest response personnel.

\(d\) *Pipelines operating below 30% SMYS.* An operator of a
transmission pipeline operating below 30% SMYS located in a high
consequence area must follow the requirements in paragraphs (d)(1) and
(d)(2) of this section. An operator of a transmission pipeline operating
below 30% SMYS located in a Class 3 or Class 4 area but not in a high
consequence area must follow the requirements in paragraphs (d)(1),
(d)(2) and (d)(3) of this section.

\(1\) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) of
this section to the pipeline; and

\(2\) Either monitor excavations near the pipeline, or conduct patrols
as required by §192.705 of the pipeline at bi-monthly intervals. If an
operator finds any indication of unreported construction activity, the
operator must conduct a follow up investigation to determine if
mechanical damage has occurred.

\(3\) Perform semi-annual leak surveys (quarterly for unprotected
pipelines or cathodically protected pipe where electrical surveys are
impractical).

\(e\) *Plastic transmission pipeline*. An operator of a plastic
transmission pipeline must apply the requirements in paragraphs
(b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered
segments of the pipeline.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.937 What is a continual process of evaluation and assessment to
maintain a pipeline\'s integrity?**

\(a\) *General.* After completing the baseline integrity assessment of a
covered segment, an operator must continue to assess the line pipe of
that segment at the intervals specified in §192.939 and periodically
evaluate the integrity of each covered pipeline segment as provided in
paragraph (b) of this section. An operator must reassess a covered
segment on which a prior assessment is credited as a baseline under
§192.921(e) by no later than December 17, 2009. An operator must
reassess a covered segment on which a baseline assessment is conducted
during the baseline period specified in §192.921(d) by no later than
seven years after the baseline assessment of that covered segment unless
the evaluation under paragraph (b) of this section indicates earlier
reassessment.

\(b\) *Evaluation.* An operator must conduct a periodic evaluation as
frequently as needed to assure the integrity of each covered segment.
The periodic evaluation must be based on a data integration and risk
assessment of the entire pipeline as specified in §192.917. For plastic
transmission pipelines, the periodic evaluation is based on the threat
analysis specified in 192.917(d). For all other transmission pipelines,
the evaluation must consider the past and present integrity assessment
results, data integration and risk assessment information (§192.917),
and decisions about remediation (§192.933) and additional preventive and
mitigative actions (§192.935). An operator must use the results from
this evaluation to identify the threats specific to each covered segment
and the risk represented by these threats.

\(c\) *Assessment methods.* In conducting the integrity reassessment, an
operator must assess the integrity of the line pipe in the covered
segment by any of the following methods as appropriate for the threats
to which the covered segment is susceptible (*see* §192.917), or by
confirmatory direct assessment under the conditions specified in
§192.931.

\(1\) Internal inspection tool or tools capable of detecting corrosion,
and any other threats to which the covered segment is susceptible. An
operator must follow ASME/ANSI B31.8S (incorporated by reference, *see*
§192.7), section 6.2 in selecting the appropriate internal inspection
tools for the covered segment.

\(2\) Pressure test conducted in accordance with subpart J of this part.
An operator must use the test pressures specified in Table 3 of section
5 of ASME/ANSI B31.8S, to justify an extended reassessment interval in
accordance with §192.939.

\(3\) Direct assessment to address threats of external corrosion,
internal corrosion, or stress corrosion cracking. An operator must
conduct the direct assessment in accordance with the requirements listed
in §192.923 and with as applicable, the requirements specified in §§
192.925, 192.927 or 192.929;

\(4\) Other technology that an operator demonstrates can provide an
equivalent understanding of the condition of the line pipe. An operator
choosing this option must notify the Office of Pipeline Safety (OPS) 180
days before conducting the assessment, in accordance with §192.949. An
operator must also notify a State or local pipeline safety authority
when either a covered segment is located in a State where OPS has an
interstate agent agreement, or an intrastate covered segment is
regulated by that State.

\(5\) Confirmatory direct assessment when used on a covered segment that
is scheduled for reassessment at a period longer than seven years. An
operator using this reassessment method must comply with §192.931.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.939 What are the required reassessment intervals?**

An operator must comply with the following requirements in establishing
the reassessment interval for the operator\'s covered pipeline segments.

\(a\) *Pipelines operating at or above 30% SMYS.* An operator must
establish a reassessment interval for each covered segment operating at
or above 30% SMYS in accordance with the requirements of this section.
The maximum reassessment interval by an allowable reassessment method is
seven years. If an operator establishes a reassessment interval that is
greater than seven years, the operator must, within the seven-year
period, conduct a confirmatory direct assessment on the covered segment,
and then conduct the follow-up reassessment at the interval the operator
has established. A reassessment carried out using confirmatory direct
assessment must be done in accordance with §192.931. The table that
follows this section sets forth the maximum allowed reassessment
intervals.

\(1\) *Pressure test or internal inspection or other equivalent
technology*. An operator that uses pressure testing or internal
inspection as an assessment method must establish the reassessment
interval for a covered pipeline segment by---

\(i\) Basing the interval on the identified threats for the covered
segment (see §192.917) and on the analysis of the results from the last
integrity assessment and from the data integration and risk assessment
required by §192.917; or

\(ii\) Using the intervals specified for different stress levels of
pipeline (operating at or above 30% SMYS) listed in ASME/ANSI B31.8S,
section 5, Table 3.

\(2\) *External Corrosion Direct Assessment.* An operator that uses ECDA
that meets the requirements of this subpart must determine the
reassessment interval according to the requirements in paragraphs 6.2
and 6.3 of NACE RP0502-2002 (incorporated by reference, *see* §192.7).

\(3\) *Internal Corrosion or SCC Direct Assessment.* An operator that
uses ICDA or SCCDA in accordance with the requirements of this subpart
must determine the reassessment interval according to the following
method. However, the reassessment interval cannot exceed those specified
for direct assessment in ASME/ANSI B31.8S, section 5, Table 3.

\(i\) Determine the largest defect most likely to remain in the covered
segment and the corrosion rate appropriate for the pipe, soil and
protection conditions;

\(ii\) Use the largest remaining defect as the size of the largest
defect discovered in the SCC or ICDA segment; and

\(iii\) Estimate the reassessment interval as half the time required for
the largest defect to grow to a critical size.

\(b\) *Pipelines Operating Below 30% SMYS.* An operator must establish a
reassessment interval for each covered segment operating below 30% SMYS
in accordance with the requirements of this section. The maximum
reassessment interval by an allowable reassessment method is seven
years. An operator must establish reassessment by at least one of the
following---

\(1\) Reassessment by pressure test, internal inspection or other
equivalent technology following the requirements in paragraph (a)(1) of
this section except that the stress level referenced in paragraph
(a)(1)(ii) of this section would be adjusted to reflect the lower
operating stress level. If an established interval is more than seven
years, the operator must conduct by the seventh year of the interval
either a confirmatory direct assessment in accordance with §192.931, or
a low stress reassessment in accordance with §192.941.

\(2\) Reassessment by ECDA following the requirements in paragraph
(a)(2) of this section.

\(3\) Reassessment by ICDA or SCCDA following the requirements in
paragraph (a)(3) of this section.

\(4\) Reassessment by confirmatory direct assessment at 7-year intervals
in accordance with §192.931, with reassessment by one of the methods
listed in paragraphs (b)(1) through (b)(3) of this section by year 20 of
the interval.

\(5\) Reassessment by the low stress assessment method at 7-year
intervals in accordance with §192.941 with reassessment by one of the
methods listed in paragraphs (b)(1) through (b)(3) of this section by
year 20 of the interval.

\(6\) The following table sets forth the maximum reassessment intervals.
Also refer to Appendix E.II for guidance on Assessment Methods and
Assessment Schedule for Transmission Pipelines Operating Below 30% SMYS.
In case of conflict between the rule and the guidance in the Appendix,
the requirements of the rule control. An operator must comply with the
following requirements in establishing a reassessment interval for a
covered segment:

Maximum Reassessment Interval

+-----------------+-----------------+-----------------+-----------------+
| Assessment      | Pipeline        | Pipeline        | Pipeline        |
| Method          | operating at or | operating at or | operating below |
|                 | above 50% SMYS  | above 30% SMYS, | 30% SMYS        |
|                 |                 | up to 50% SMYS  |                 |
+-----------------+-----------------+-----------------+-----------------+
| Internal        | 10 years(\*)    | 15 years(\*)    | 20 years(\*\*)  |
| Inspection      |                 |                 |                 |
| Tool, Pressure  |                 |                 |                 |
| Test or Direct  |                 |                 |                 |
|                 |                 |                 |                 |
| Assessment      |                 |                 |                 |
+-----------------+-----------------+-----------------+-----------------+
| Confirmatory    | 7 years         | 7 years         | 7 years         |
|                 |                 |                 |                 |
| Direct          |                 |                 |                 |
|                 |                 |                 |                 |
| Assessment      |                 |                 |                 |
+-----------------+-----------------+-----------------+-----------------+
| Low Stress      | Not applicable  | Not applicable  | 7 years +       |
|                 |                 |                 | ongoing         |
| Reassessment    |                 |                 |                 |
|                 |                 |                 | actions         |
|                 |                 |                 | specified in    |
|                 |                 |                 | §192.941        |
+-----------------+-----------------+-----------------+-----------------+

(\*) A Confirmatory direct assessment as described in \'192.931 must be
conducted by year 7 in a 10-year interval and years 7 and 14 of a
15-year interval.

(\*\*) A low stress reassessment or Confirmatory direct assessment must
be conducted by years 7 and 14 of the interval.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.941 What is a low stress reassessment?**

\(a\) *General.* An operator of a transmission line that operates below
30% SMYS may use the following method to reassess a covered segment in
accordance with §192.939. This method of reassessment addresses the
threats of external and internal corrosion. The operator must have
conducted a baseline assessment of the covered segment in accordance
with the requirements of §§  192.919 and 192.921.

\(b\) *External corrosion.* An operator must take one of the following
actions to address external corrosion on the low stress covered segment.

\(1\) *Cathodically protected pipe*. To address the threat of external
corrosion on cathodically protected pipe in a covered segment, an
operator must perform an electrical survey (i.e*.* indirect examination
tool/method) at least every 7 years on the covered segment. An operator
must use the results of each survey as part of an overall evaluation of
the cathodic protection and corrosion threat for the covered segment.
This evaluation must consider, at minimum, the leak repair and
inspection records, corrosion monitoring records, exposed pipe
inspection records, and the pipeline environment.

\(2\) *Unprotected pipe or cathodically protected pipe where electrical
surveys are impractical.* If an electrical survey is impractical on the
covered segment an operator must---

\(i\) Conduct leakage surveys as required by §192.706 at 4-month
intervals; and

\(ii\) Every 18 months, identify and remediate areas of active corrosion
by evaluating leak repair and inspection records, corrosion monitoring
records, exposed pipe inspection records, and the pipeline environment.

\(c\) *Internal corrosion.* To address the threat of internal corrosion
on a covered segment, an operator must---

\(1\) Conduct a gas analysis for corrosive agents at least once each
calendar year;

\(2\) Conduct periodic testing of fluids removed from the segment. At
least once each calendar year test the fluids removed from each storage
field that may affect a covered segment; and

\(3\) At least every seven (7) years, integrate data from the analysis
and testing required by paragraphs (c)(1)-(c)(2) with applicable
internal corrosion leak records, incident reports, safety-related
condition reports, repair records, patrol records, exposed pipe reports,
and test records, and define and implement appropriate remediation
actions.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004\]

**§192.943 When can an operator deviate from these reassessment
intervals?**

\(a\) *Waiver from reassessment interval in limited situations.* In the
following limited instances, OPS may allow a waiver from a reassessment
interval required by §192.939 if OPS finds a waiver would not be
inconsistent with pipeline safety.

\(1\) *Lack of internal inspection tools.* An operator who uses internal
inspection as an assessment method may be able to justify a longer
reassessment period for a covered segment if internal inspection tools
are not available to assess the line pipe. To justify this, the operator
must demonstrate that it cannot obtain the internal inspection tools
within the required reassessment period and that the actions the
operator is taking in the interim ensure the integrity of the covered
segment.

\(2\) Maintain product supply. An operator may be able to justify a
longer reassessment period for a covered segment if the operator
demonstrates that it cannot maintain local product supply if it conducts
the reassessment within the required interval.

\(b\) *How to apply.* If one of the conditions specified in paragraph
(a) (1) or (a) (2) of this section applies, an operator may seek a
waiver of the required reassessment interval. An operator must apply for
a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days before
the end of the required reassessment interval, unless local product
supply issues make the period impractical. If local product supply
issues make the period impractical, an operator must apply for the
waiver as soon as the need for the waiver becomes known.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004\]

**§192.945 What methods must an operator use to measure program
effectiveness?**

\(a\) *General.* An operator must include in its integrity management
program methods to measure, on a semi-annual basis, whether the program
is effective in assessing and evaluating the integrity of each covered
pipeline segment and in protecting the high consequence areas. These
measures must include the four overall performance measures specified in
ASME/ANSI B31.8S (incorporated by reference, *see* §192.7), section 9.4,
and the specific measures for each identified threat specified in
ASME/ANSI B31.8S, Appendix A. An operator must submit the four overall
performance measures, by electronic or other means, on a semi-annual
frequency to OPS in accordance with §192.951. An operator must submit
its first report on overall performance measures by August 31, 2004.
Thereafter, the performance measures must be complete through June 30
and December 31 of each year and must be submitted within 2 months after
those dates.

\(b\) *External Corrosion Direct assessment.* In addition to the general
requirements for performance measures in paragraph (a) of this section,
an operator using direct assessment to assess the external corrosion
threat must define and monitor measures to determine the effectiveness
of the ECDA process. These measures must meet the requirements of
§192.925.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004; Amdt. 192-103, 71 FR 33402, June 8, 2006\]

**§192.947 What records must an operator keep?**

An operator must maintain, for the useful life of the pipeline, records
that demonstrate compliance with the requirements of this subpart. At
minimum, an operator must maintain the following records for review
during an inspection.

\(a\) A written integrity management program in accordance with
§192.907;

\(b\) Documents supporting the threat identification and risk assessment
in accordance with §192.917;

\(c\) A written baseline assessment plan in accordance with §192.919;

\(d\) Documents to support any decision, analysis and process developed
and used to implement and evaluate each element of the baseline
assessment plan and integrity management program. Documents include
those developed and used in support of any identification, calculation,
amendment, modification, justification, deviation and determination
made, and any action taken to implement and evaluate any of the program
elements;

\(e\) Documents that demonstrate personnel have the required training,
including a description of the training program, in accordance with
§192.915;

\(f\) Schedule required by §192.933 that prioritizes the conditions
found during an assessment for evaluation and remediation, including
technical justifications for the schedule.

\(g\) Documents to carry out the requirements in §§ 192.923 through
192.929 for a direct assessment plan;

\(h\) Documents to carry out the requirements in §192.931 for
confirmatory direct assessment;

\(i\) Verification that an operator has provided any documentation or
notification required by this subpart to be provided to OPS, and when
applicable, a State authority with which OPS has an interstate agent
agreement, and a State or local pipeline safety authority that regulates
a covered pipeline segment within that State.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-95B, 69 FR 18227, April 6,
2004\]

**§192.949 How does an operator notify OPS?**

An operator must provide any notification required by this subpart by---

\(a\) Sending the notification to the Pipeline and Hazardous Materials
Safety Administration, U.S. Department of Transportation, Room 2103,
[400 Seventh Street, SW]{.mark}[PHP-10, 1200 New Jersey Avenue,
SE]{.underline}., Washington, DC 20590;

\(b\) Sending the notification by fax to (202) 366-4566; or

\(c\) Entering the information directly on the Integrity Management
Database (IMDB) Web site at *http://primis.RSPA.dot.gov/gasimp/*.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-100, 70 FR 11135, Mar. 8,
2005; Amdt. 192-103c, 72 FR 4655, Feb. 1, 2007[; Amdt. 192-\[106\], 73
FR 16562, Mar. 28, 2008.]{.underline}\]

**§192.951 Where does an operator file a report?**

An operator must send any performance report required by this subpart to
the Information Resources Manager---

\(a\) By mail to the Pipeline and Hazardous Materials Safety
Administration, U.S. Department of Transportation, [Room 2103, 400
Seventh Street SW]{.mark}[PHP-10, 1200 New Jersey Avenue,
SE.]{.underline}, Washington, DC 20590;

\(b\) Via fax to (202) 366-4566; or

\(3\) Through the online reporting system provided by PHMSA for
electronic reporting available at the PHMSA Home Page at
*http://[PHMSA]{.underline}.dot.gov*.

\[Amdt. 192-95, 68 FR 69777, December 15, 2003 as amended by Amdt. 192
95A, 69 FR 2307, December 22, 2003; Amdt. 192-100, 70 FR 11135, Mar. 8,
2005; Amdt. 192-103c, 72 FR 4655, Feb. 1, 2007[; Amdt. 192-\[106\], 73
FR 16562, Mar. 28, 2008.]{.underline}\]

**Appendix** **A**--**\[Reserved\]**

\[Part 192 - Org., Aug. 19, 1970, as amended by Amdt. 192-3, 35 FR
17659, Nov. 17, 1970; Amdt. 192-12, 38 FR 4760, Feb. 22, 1973; Amdt.
192-17, 40 FR 6345, Feb. 11, 1975; Amdt. 192-17C, 40 FR 8188, Feb. 26,
1975; Amdt. 192-18, 40 FR 10181, Mar. 5, 1975; Amdt. 192-19, 40 FR
10471, Mar. 6, 1975; Amdt. 192-22, 41 FR 13589, Mar. 31, 1976; Amdt.
192-32, 43 FR 18553, May 1, 1978; Amdt. 192-34, 44 FR 42968, July 23,
1979; Amdt. 192-37, 46 FR 10157, Feb. 2, 1981; Amdt. 192-41, 47 FR
41381, Sept. 20, 1982; Amdt. 192-42, 47 FR 44263, Oct. 7, 1982; Amdt
192-51, 51 FR 15333, Apr. 23, 1986; Amdt. 192-61, 53 FR 36793, Sept. 22,
1988; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989; Amdt. 192-64, 54 FR 27881,
July 3, 1989; Amdt. 192-65, 54 FR 32344, Aug. 7, 1989; Amdt. 192-68, 58
FR 14519, Mar. 18, 1993; Amdt. 192-76, 61 FR 26121, May 24, 1996; Amdt.
192-78, 61 FR 28770, June 6, 1996; Amdt. 192-78C, 61 FR 41019, Aug. 7,
1996; Amdt. 192-84, 63 FR 7721, Feb. 17, 1998; Amdt. 192-84A, 63 FR
38757, July 20, 1998; Amdt. 192-95, 16 FR 69778, Dec. 15, 2003; Amdt.
192-95B, 69 FR 18227, April 6, 2004; Amdt. 192-94, 69 FR 32886, June 14,
2004\]

**Appendix B--Qualification of Pipe**

I*. Listed Pipe Specification*

API 5L---Steel pipe, "API Specification for Line Pipe" (incorporated by
reference, *see* §192.7)

ASTM A 53/A53M---Steel pipe, "Standard Specification for Pipe, Steel
Black and Hot-Dipped, Zinc-Coated, welded and Seamless"(incorporated by
reference, *see* §192.7)

ASTM A 106---Steel pipe, "Standard Specification for Seamless Carbon
Steel Pipe for High temperature Service" (incorporated by reference,
*see* §192.7)

ASTM A 333/A 333M---Steel pipe, "Standard Specification for Seamless and
Welded steel Pipe for Low Temperature Service" (incorporated by
reference, *see* §192.7)

ASTM A 381---Steel pipe, "Standard specification for Metal-Arc-Welded
Steel Pipe for Use with High-Pressure Transmission Systems"
(incorporated by reference, *see* §192.7)

ASTM A 671---Steel pipe, "Standard Specification for
Electric-Fusion-Welded Pipe for Atmospheric and Lower Temperatures"
(incorporated by reference, *see* §192.7)

ASTM A 672---Steel pipe, "Standard Specification for
Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate
Temperatures" (incorporated by reference, *see* §192.7)

ASTM A 691---Steel pipe, "Standard Specification for Carbon and Alloy
Steel Pipe, Electric-Fusion-Welded for High Pressure Service at High
Temperatures" (incorporated by reference, *see* §192.7)

ASTM D 2513 Thermoplastic pipe and tubing, "Standard Specification for
Thermoplastic Gas Pressure Pipe, Tubing, and Fittings" (incorporated by
reference, *see* §192.7)

ASTM D 2517---Thermosetting plastic pipe and tubing, "Standard
Specification Reinforced Epoxy Resin Gas Pressure Pipe and Fittings"
(incorporated by reference, *see* §192.7)

II\. *Steel pipe of unknown or unlisted specification.*

A. *Bending properties.* For pipe 2 inches (51 millimeters) or less in
diameter, a length of pipe must be cold bent through at least 90 degrees
around a cylindrical mandrel that has a diameter 12 times the diameter
of the pipe, without developing cracks at any portion and without
opening the longitudinal weld.

For pipe more than 2 inches (51 millimeters) in diameter, the pipe must
meet the requirements of the flattening tests set forth in ASTM A53,
except that the number of tests must be at least equal to the minimum
required in paragraph II-D of this appendix to determine yield strength.

B. *Weldability.* A girth weld must be made in the pipe by a welder who
is qualified under subpart E of this part. The weld must be made under
the most severe conditions under which welding will be allowed in the
field and by means of the same procedure that will be used in the field.
On pipe more than 4 inches (102 millimeters) in diameter, at least one
test weld must be made for each 100 lengths of pipe. On pipe 4 inches
(102 millimeters) or less in diameter, at least one test weld must be
made for each 400 lengths of pipe. The weld must be tested in accordance
with API Standard 1104 (incorporated by reference, *see* §192.7). If the
requirements of API Standard 1104 cannot be met, weldability may be
established by making chemical tests for carbon and manganese, and
proceeding in accordance with section IX of the ASME Boiler and Pressure
Vessel Code (incorporated by reference, *see* §192.7). The same number
of chemical tests must be made as are required for testing a girth weld.

C. *Inspection.* The pipe must be clean enough to permit adequate
inspection. It must be visually inspected to ensure that it is
reasonably round and straight and there are no defects which might
impair the strength or tightness of the pipe.

D. *Tensile properties.* If the tensile properties of the pipe are not
known, the minimum yield strength may be taken as 24,000 p.s.i. (165
MPa) or less, or the tensile properties may be established by performing
tensile test as set forth in API Specification 5L (incorporated by
reference, *see* §192.7).

  --------------------------- -------------------------------------------
  Number of Tensile Tests-All 
  Sizes                       

  10 lengths or less          1 set of tests for each length.

  11 to 100 lengths           1 set of tests for each 5 lengths, but not
                              less than 10 tests.

  Over 100 lengths            1 set of tests for each 10 lengths but not
                              less than 20 tests.
  --------------------------- -------------------------------------------

If the yield-tensile ratio, based on the properties determined by those
tests, exceeds 0.85, the pipe may be used only as provided in
§192.55(c).

III\. *Steel pipe manufactured before November 12, 1970, to earlier
editions of listed specifications*. Steel pipe manufactured before
November 12, 1970, in accordance with a specification of which a later
edition is listed in section I of this appendix, is qualified for use
under this part if the following requirements are met:

A. *Inspection.* The pipe must be clean enough to permit adequate
inspection. It must be visually inspected to ensure that it is
reasonably round and straight and that there are no defects which might
impair the strength or tightness of the pipe.

B. *Similarity of specification requirements.* The edition of the listed
specification under which the pipe was manufactured must have
substantially the same requirements with respect to the following
properties as a later edition of that specification listed in section I
of this appendix:

\(1\) Physical (mechanical) properties of pipe, including yield and
tensile strength, elongation, and yield to tensile ratio, and testing
requirements to verify those properties.

\(2\) Chemical properties of pipe and testing requirements to verify
those properties.

C. *Inspection or test of welded pipe.* On pipe with welded seams, one
of the following requirements must be met:

\(1\) The edition of the listed specification to which the pipe was
manufactured must have substantially the same requirements with respect
to nondestructive inspection of welded seams and the standards for
acceptance or rejection and repair as a later edition of the
specification listed in section I of this appendix.

\(2\) The pipe must be tested in accordance with Subpart J of this part
to at least 1.25 times the maximum allowable operating pressure if it is
to be installed in a class 1 location and to at least 1.5 times the
maximum allowable operating pressure if it is to be installed in a class
2, 3, or 4 location. Notwithstanding any shorter time period permitted
under Subpart J of this part, the test pressure must be maintained for
at least 8 hours.

\[Part 192 - Org., Aug. 19, 1970; as amended by Amdt. 192-3, 35 FR
17659, Nov. 17, 1970; Amdt. 192-12, 38 FR 4760, Feb. 22, 1973; Amdt.
192-19, 40 FR 10471, Mar. 6, 1975; Amdt. 192-22, 41 FR 13589, Mar. 31,
1976; Amdt. 192-32, 43 FR 18553, May 1, 1978; Amdt. 192-37, 46 FR 10157,
Feb. 2, 1981; Amdt. 192-41, 47 FR 41381, Sept. 20, 1982; Amdt. 192-51,
51 FR 15333, Apr. 23, 1986; Amdt. 192-62, 54 FR 5625, Feb. 6, 1989;
Amdt. 192-65, 54 FR 32344, Aug. 7, 1989; Amdt. 192-68, 58 FR 14519, Mar.
18, 1993; Amdt. 192-76A, 61 FR 36825, July 15, 1996; Amdt. 192-85, 63 FR
37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004; Amdt.
192-103, 71 FR 33402, June 8, 2006\]

**Appendix C--Qualification of**

**Welders for Low Stress Level Pipe**

I*. Basic test*. The test is made on pipe 12 inches (305 millimeters) or
less in diameter. The test weld must be made with the pipe in a
horizontal fixed position so that the test weld includes at least one
section of overhead position welding. The beveling, root opening, and
other details must conform to the specifications of the procedure under
which the welder is being qualified. Upon completion, the test weld is
cut into four coupons and subjected to a root bend test. If, as a result
of this test, two or more of the four coupons develop a crack in the
weld material, or between the weld material and base metal, that is more
than 1/8-inch (3.2 millimeters) long in any direction, the weld is
unacceptable. Cracks that occur on the corner of the specimen during
testing are not considered. A welder who successfully passes a butt-weld
qualification test under this section shall be qualified to weld on all
pipe diameters less than or equal to 12 inches.

II*. Additional tests for welders of service line connections to mains*.
A service line connection fitting is welded to a pipe section with the
same diameter as a typical main. The weld is made in the same position
as it is made in the field. The weld is unacceptable if it shows a
serious undercutting or if it has rolled edges. The weld is tested by
attempting to break the fitting off the run pipe. The weld is
unacceptable if it breaks and shows incomplete fusion, overlap, or poor
penetration at the junction of the fitting and run pipe.

III\. *Periodic tests for welders of small service lines.* Two samples
of the welder\'s work, each about 8 inches (203 millimeters) long with
the weld located approximately in the center, are cut from steel service
line and tested as follows:

\(1\) One sample is centered in a guided bend testing machine and bent
to the contour of the die for a distance of 2 inches (51 millimeters) on
each side of the weld. If the sample shows any breaks or cracks after
removal from the bending machine, it is unacceptable.

\(2\) The ends of the second sample are flattened and the entire joint
subjected to a tensile strength test. If failure occurs adjacent to or
in the weld metal, the weld is unacceptable. If a tensile strength
testing machine is not available, this sample must also pass the bending
test prescribed in subparagraph (1) of this paragraph.

\[Part 192 - Org., Aug. 19, 1970 as amended by Amdt. 192-85, 63 FR
37500, July 13, 1998; Amdt. 192-94, 69 FR 32886, June 14, 2004\]

**Appendix D--Criteria for Cathodic Protection and Determination of
Measurements**

I. *Criteria for cathodic protection*--

A. Steel, cast iron, and ductile iron structures.

\(1\) A negative (cathodic) voltage of at least 0.85 volt, with
reference to a saturated copper-copper sulfate half cell. Determination
of this voltage must be made with the protective current applied, and in
accordance with sections II and IV of this appendix.

\(2\) A negative (cathodic) voltage shift of at least 300 millivolts.
Determination of this voltage shift must be made with the protective
current applied, and in accordance with sections II and IV of this
appendix. This criterion of voltage shift applies to structures not in
contact with metals of different anodic potentials.

\(3\) A minimum negative (cathodic) polarization voltage shift of 100
millivolts. This polarization voltage shift must be determined in
accordance with sections III and IV of this appendix.

\(4\) A voltage at least as negative (cathodic) as that originally
established at the beginning of the Tafel segment of the E-log-I curve.
This voltage must be measured in accordance with section IV of this
appendix.

\(5\) A net protective current from the electrolyte into the structure
surface as measured by an earth current technique applied at
predetermined current discharge (anodic) points of the structure.

B. Aluminum structures.

\(1\) Except as provided in paragraphs (3) and (4) of this paragraph, a
minimum negative (cathodic) voltage shift of 150 millivolts, produced by
the application of protective current. The voltage shift must be
determined in accordance with sections II and IV of this appendix.

\(2\) Except as provided in paragraphs (3) and (4) of this paragraph, a
minimum negative (cathodic) polarization voltage shift of 100
millivolts. This polarization voltage shift must be determined in
accordance with sections III and IV of this appendix.

\(3\) Notwithstanding the alternative minimum criteria in paragraphs (1)
and (2) of this paragraph, aluminum, if cathodically protected at
voltages in excess of 1.20 volts as measured with reference to a
copper-copper sulfate half cell, in accordance with section IV of this
appendix, and compensated for the voltage (IR) drops other than those
across the structure-electrolyte boundary may suffer corrosion resulting
from the build-up of alkali on the metal surface. A voltage in excess of
1.20 volts may not be used unless previous test results indicate no
appreciable corrosion will occur in the particular environment.

\(4\) Since aluminum may suffer from corrosion under high pH conditions,
and since application of cathodic protection tends to increase the pH at
the metal surface, careful investigation or testing must be made before
applying cathodic protection to stop pitting attack on aluminum
structures in environments with a natural pH in excess of 8.

C. Copper structures. A minimum negative (cathodic) polarization voltage
shift of 100 millivolts. This polarization voltage shift must be
determined in accordance with sections III and IV of this appendix.

D. Metals of different anodic potentials. A negative (cathodic) voltage,
measured in accordance with section IV of this appendix, equal to that
required for the most anodic metal in the system must be maintained. If
amphoteric structures are involved that could be damaged by high
alkalinity covered by paragraphs (3) and (4) of paragraph B of this
section, they must be electrically isolated with insulating flanges, or
the equivalent.

II\. *Interpretation of voltage measurement*. Voltage (IR) drops other
than those across the structure electrolyte boundary must be considered
for valid interpretation of the voltage measurement in paragraphs A(1)
and (2) and paragraph B(1) of section I of the appendix.

III\. *Determination of polarization voltage shift*. The polarization
voltage shift must be determined by interrupting the protective current
and measuring the polarization decay. When the current is initially
interrupted, an immediate voltage shift occurs. The voltage reading
after the immediate shift must be used as the base reading from which to
measure polarization decay in paragraphs A(3), B(2), and C of section I
of this appendix.

IV\. *Reference half cells.*

A. Except as provided in paragraphs B and C of this section, negative
(cathodic) voltage must be measured between the structure surface and a
saturated copper-copper sulfate half cell contacting the electrolyte.

B. Other standard reference half cells may be substituted for the
saturated copper-copper sulfate half cell. Two commonly used reference
half cells are listed below along with their voltage equivalent to -0.85
volt as referred to a saturated copper-copper sulfate half cell:

\(1\) Saturated KC1 calomel half cell: -0.78 volt.

\(2\) Silver-silver chloride half cell used in sea water: -0.80 volt.

C. In addition to the standard reference half cells, an alternate
metallic material or structure may be used in place of the saturated
copper-copper sulfate half cell if its potential stability is assured
and if its voltage equivalent referred to a saturated copper-copper
sulfate half cell is established.

\[Amdt. 192-4, 36 FR 12297, June 30, 1971\]

**Appendix E to Part 192---Guidance on Determining High Consequence
Areas and on Carrying Out Requirements in the Integrity Management
Rule**

*I. Guidance on Determining a High Consequence Area*

To determine which segments of an operator\'s transmission pipeline
system are covered for purposes of the integrity management program
requirements, an operator must identify the high consequence areas. An
operator must use method (1) or (2) from the definition in §192.903 to
identify a high consequence area. An operator may apply one method to
its entire pipeline system, or an operator may apply one method to
individual portions of the pipeline system. (Refer to figure E.I.A for a
diagram of a high consequence area)

\[Amdt. 192-95, 16 FR 69778, Dec. 15, 2003, as amended by Amdt. 192-95B,
69 FR 18227, April 6, 2004; Amdt. 192-95C, 69 FR 29903, May 26, 2004\]

![](media/image1.wmf){width="4.125in" height="3.095138888888889in"}

**II. Guidance on Assessment Methods and Additional Preventive and
Mitigative Measures for Transmission Pipelines**

\(a\) Table E.II.1 gives guidance to help an operator implement
requirements on additional preventive and mitigative measures for
addressing time dependent and independent threats for a transmission
pipeline operating below 30% SMYS *not* in an HCA (i.e. outside of
potential impact circle) but located within a Class 3 or Class 4
Location.

\(b\) Table E.II.2 gives guidance to help an operator implement
requirements on assessment methods for addressing time dependent and
independent threats for a transmission pipeline in an HCA.

\(c\) Table E.II.3 gives guidance on preventative & mitigative measures
addressing time dependent and independent threats for transmission
pipelines that operate below 30% SMYS, in HCAs.

\[Amdt. 192-95, 16 FR 69778, Dec. 15, 2003, as amended by Amdt. 192-95B,
69 FR 18227, April 6, 2004\]

***Table E.II.1: Preventative & Mitigative Measures for Transmission
Pipelines Operating Below 30% SMYS not in an HCA but in a Class 3 and 4
Location***

+--------+--------------------+----------+----------------------------+
| Threat | Existing 192       |          | Additional (to 192         |
|        | Requirements       |          | requirements)              |
|        |                    |          |                            |
|        |                    |          | Preventive and Mitigative  |
|        |                    |          | Measures                   |
+--------+--------------------+----------+----------------------------+
|        | Primary            | S        |                            |
|        |                    | econdary |                            |
+--------+--------------------+----------+----------------------------+
| Ex     | 455‑(Gen. Post     | 603‑(Gen | For Cathodically Protected |
| ternal | 1971),             | Oper=n)  | Transmission Pipeline:     |
|        |                    |          |                            |
| Cor    | 457‑(Gen.          | 61       | \$ Perform semi‑annual     |
| rosion | Pre‑1971)          | 3‑(Surve | leak surveys.              |
|        |                    | illance) |                            |
|        | 459‑(Examination), |          | For Unprotected            |
|        |                    |          | Transmission Pipelines or  |
|        | 461‑(Ext. coating) |          | for Cathodically Protected |
|        |                    |          | Pipe where Electrical      |
|        | 463‑(CP),          |          | Surveys are Impractical:   |
|        |                    |          |                            |
|        | 465‑(Monitoring)   |          | \$ Perform quarterly leak  |
|        |                    |          | surveys                    |
|        | 467‑(Elect         |          |                            |
|        | isolation),        |          |                            |
|        |                    |          |                            |
|        | 469‑Test stations) |          |                            |
|        |                    |          |                            |
|        | 471‑(Test leads),  |          |                            |
|        |                    |          |                            |
|        | 473‑(Interference) |          |                            |
|        |                    |          |                            |
|        | 479‑(Atmospheric), |          |                            |
|        |                    |          |                            |
|        | 481‑(Atmospheric)  |          |                            |
|        |                    |          |                            |
|        | 485‑(Remedial),    |          |                            |
|        |                    |          |                            |
|        | 705‑(Patrol)       |          |                            |
|        |                    |          |                            |
|        | 706‑(Leak survey), |          |                            |
|        |                    |          |                            |
|        | 711 (Repair B      |          |                            |
|        | gen.)              |          |                            |
|        |                    |          |                            |
|        | 717‑(Repair B      |          |                            |
|        | perm.)             |          |                            |
+--------+--------------------+----------+----------------------------+
| In     | 475‑(Gen IC),      | 5        | \$ Perform semi‑annual     |
| ternal |                    | 3(a)‑(Ma | leak surveys.              |
|        | 477‑(IC            | terials) |                            |
| Cor    | monitoring)        |          |                            |
| rosion |                    | 603‑(Gen |                            |
|        | 485‑(Remedial),    | Oper=n)  |                            |
|        |                    |          |                            |
|        | 705‑(Patrol)       | 61       |                            |
|        |                    | 3‑(Surve |                            |
|        | 706‑(Leak survey), | illance) |                            |
|        |                    |          |                            |
|        | 711 (Repair B      |          |                            |
|        | gen.)              |          |                            |
|        |                    |          |                            |
|        | 717‑(Repair B      |          |                            |
|        | perm.)             |          |                            |
+--------+--------------------+----------+----------------------------+
| 3^rd^  | 103‑(Gen. Design), | 615      | \$ Participation in state  |
| Party  |                    | B(Emerg. | one‑call system,           |
|        | 111‑(Design        | Plan)    |                            |
| Damage | factor)            |          | \$ Use of qualified        |
|        |                    |          | operator employees and     |
|        | 317‑(Hazard prot), |          | contractors to perform     |
|        |                    |          | marking and locating of    |
|        | 327‑(Cover)        |          | buried structures and in   |
|        |                    |          | direct supervision of      |
|        | 614‑(Dam.          |          | excavation work, AND       |
|        | Prevent),          |          |                            |
|        |                    |          | \$ Either monitoring of    |
|        | 616‑(Public        |          | excavations near           |
|        | education)         |          | operator=s transmission    |
|        |                    |          | pipelines, or bi‑monthly   |
|        | 705‑(Patrol),      |          | patrol of transmission     |
|        |                    |          | pipelines in class 3 and 4 |
|        | 707‑(Line markers) |          | locations. Any indications |
|        |                    |          | of unreported construction |
|        | 711 (Repair B      |          | activity would require a   |
|        | gen.),             |          | follow up investigation to |
|        |                    |          | determine if mechanical    |
|        | 717‑(Repair B      |          | damage occurred.           |
|        | perm.)             |          |                            |
+--------+--------------------+----------+----------------------------+

+--------+------+----------+-----+----------+-----+----------------+
| *      |      |          |     |          |     |                |
| *Table |      |          |     |          |     |                |
| E.II.2 |      |          |     |          |     |                |
| Asse   |      |          |     |          |     |                |
| ssment |      |          |     |          |     |                |
| Requir |      |          |     |          |     |                |
| ements |      |          |     |          |     |                |
| for    |      |          |     |          |     |                |
| Transm |      |          |     |          |     |                |
| ission |      |          |     |          |     |                |
| Pip    |      |          |     |          |     |                |
| elines |      |          |     |          |     |                |
| in     |      |          |     |          |     |                |
| HCAs   |      |          |     |          |     |                |
| (R     |      |          |     |          |     |                |
| e‑asse |      |          |     |          |     |                |
| ssment |      |          |     |          |     |                |
| int    |      |          |     |          |     |                |
| ervals |      |          |     |          |     |                |
| are    |      |          |     |          |     |                |
| m      |      |          |     |          |     |                |
| aximum |      |          |     |          |     |                |
| allo   |      |          |     |          |     |                |
| wed)** |      |          |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        | **R  |          |     |          |     |                |
|        | e‑As |          |     |          |     |                |
|        | sess |          |     |          |     |                |
|        | ment |          |     |          |     |                |
|        | Requ |          |     |          |     |                |
|        | irem |          |     |          |     |                |
|        | ents |          |     |          |     |                |
|        | (see |          |     |          |     |                |
|        | Note |          |     |          |     |                |
|        | 3)** |          |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        | At   |          | At  |          | Be  |                |
|        | or   |          | or  |          | low |                |
|        | a    |          | ab  |          | 30% |                |
|        | bove |          | ove |          | S   |                |
|        | 50%  |          | 30% |          | MYS |                |
|        | SMYS |          | S   |          |     |                |
|        |      |          | MYS |          |     |                |
|        |      |          |     |          |     |                |
|        |      |          | up  |          |     |                |
|        |      |          | to  |          |     |                |
|        |      |          | 50% |          |     |                |
|        |      |          | S   |          |     |                |
|        |      |          | MYS |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
| Ba     | Max  | As       | Max | As       | Max | Assessment     |
| seline |      | sessment |     | sessment |     | Method         |
| Asse   | R    | Method   | R   | Method   | R   |                |
| ssment | e‑As |          | e‑A |          | e‑A |                |
|        | sess |          | sse |          | sse |                |
| Method | ment |          | ssm |          | ssm |                |
| (see   |      |          | ent |          | ent |                |
| Note   | Inte |          |     |          |     |                |
| 3)     | rval |          | In  |          | In  |                |
|        |      |          | ter |          | ter |                |
|        |      |          | val |          | val |                |
+--------+------+----------+-----+----------+-----+----------------+
| Pr     | 7    | CDA      | 7   | CDA      | O   | Preventative & |
| essure |      |          |     |          | ngo | Mitigative     |
| T      |      |          |     |          | ing | (P&M) Measures |
| esting |      |          |     |          |     |                |
|        |      |          |     |          |     | (see Table     |
|        |      |          |     |          |     | E.II.3), (see  |
|        |      |          |     |          |     | Note 2)        |
+--------+------+----------+-----+----------+-----+----------------+
|        | 10   | Pressure |     |          |     |                |
|        |      | Test or  |     |          |     |                |
|        |      | ILI or   |     |          |     |                |
|        |      | DA       |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      | Repeat   | 15( | Pressure |     |                |
|        |      | in       | see | Test or  |     |                |
|        |      | spection | N   | ILI or   |     |                |
|        |      | cycle    | ote |          |     |                |
|        |      |          | 1)  | DA (see  |     |                |
|        |      | every 10 |     | Note 1)  |     |                |
|        |      | years    |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      |          |     | Repeat   | 20  | Pressure Test  |
|        |      |          |     | in       |     | or ILI or DA   |
|        |      |          |     | spection |     |                |
|        |      |          |     | cycle    |     |                |
|        |      |          |     |          |     |                |
|        |      |          |     | every 15 |     |                |
|        |      |          |     | years    |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      |          |     |          |     | Repeat         |
|        |      |          |     |          |     | inspection     |
|        |      |          |     |          |     | cycle every 20 |
|        |      |          |     |          |     | years          |
+--------+------+----------+-----+----------+-----+----------------+
| I      | 7    | CDA      | 7   | CDA      | O   | Preventative & |
| n-Line |      |          |     |          | ngo | Mitigative     |
| Insp   |      |          |     |          | ing | (P&M) Measures |
| ection |      |          |     |          |     |                |
|        |      |          |     |          |     | (see Table     |
|        |      |          |     |          |     | E.II.3), (see  |
|        |      |          |     |          |     | Note 2)        |
+--------+------+----------+-----+----------+-----+----------------+
|        | 10   | ILI or   |     |          |     |                |
|        |      | DA or    |     |          |     |                |
|        |      | Pressure |     |          |     |                |
|        |      | Test     |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      | Repeat   | 15( | ILI or   |     |                |
|        |      | in       | see | DA or    |     |                |
|        |      | spection | N   | Pressure |     |                |
|        |      | cycle    | ote |          |     |                |
|        |      |          | 1)  | est (see |     |                |
|        |      | every 10 |     | Note 1)  |     |                |
|        |      | years    |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      |          |     | Repeat   | 20  | ILI or DA or   |
|        |      |          |     | in       |     | Pressure Test  |
|        |      |          |     | spection |     |                |
|        |      |          |     | cycle    |     |                |
|        |      |          |     |          |     |                |
|        |      |          |     | every 15 |     |                |
|        |      |          |     | years    |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      |          |     |          |     | Repeat         |
|        |      |          |     |          |     | inspection     |
|        |      |          |     |          |     | cycle every 20 |
|        |      |          |     |          |     | years          |
+--------+------+----------+-----+----------+-----+----------------+
| Direct | 7    | CDA      | 7   | CDA      | O   | Preventative & |
| Asse   |      |          |     |          | ngo | Mitigative     |
| ssment |      |          |     |          | ing | (P&M) Measures |
|        |      |          |     |          |     |                |
|        |      |          |     |          |     | (see Table     |
|        |      |          |     |          |     | E.II.3), (see  |
|        |      |          |     |          |     | Note 2)        |
+--------+------+----------+-----+----------+-----+----------------+
|        | 10   | DA or    |     |          |     |                |
|        |      | ILI or   |     |          |     |                |
|        |      | Pressure |     |          |     |                |
|        |      | Test     |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      | Repeat   | 15( | DA or    |     |                |
|        |      | in       | see | ILI or   |     |                |
|        |      | spection | N   | Pressure |     |                |
|        |      | cycle    | ote |          |     |                |
|        |      |          | 1)  | Test     |     |                |
|        |      | every 10 |     | (see     |     |                |
|        |      | years    |     | Note 1)  |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      |          |     | Repeat   | 20  | DA or ILI or   |
|        |      |          |     | in       |     | Pressure Test  |
|        |      |          |     | spection |     |                |
|        |      |          |     | cycle    |     |                |
|        |      |          |     |          |     |                |
|        |      |          |     | every 15 |     |                |
|        |      |          |     | years    |     |                |
+--------+------+----------+-----+----------+-----+----------------+
|        |      |          |     |          |     | Repeat         |
|        |      |          |     |          |     | inspection     |
|        |      |          |     |          |     | cycle every 20 |
|        |      |          |     |          |     | years          |
+--------+------+----------+-----+----------+-----+----------------+
| Note   | Oper |          |     |          |     |                |
| 1:     | ator |          |     |          |     |                |
|        | may  |          |     |          |     |                |
|        | ch   |          |     |          |     |                |
|        | oose |          |     |          |     |                |
|        | to   |          |     |          |     |                |
|        | uti  |          |     |          |     |                |
|        | lize |          |     |          |     |                |
|        | CDA  |          |     |          |     |                |
|        | at   |          |     |          |     |                |
|        | year |          |     |          |     |                |
|        | 14,  |          |     |          |     |                |
|        | then |          |     |          |     |                |
|        | uti  |          |     |          |     |                |
|        | lize |          |     |          |     |                |
|        | ILI, |          |     |          |     |                |
|        | Pres |          |     |          |     |                |
|        | sure |          |     |          |     |                |
|        | T    |          |     |          |     |                |
|        | est, |          |     |          |     |                |
|        | or   |          |     |          |     |                |
|        | DA   |          |     |          |     |                |
|        | at   |          |     |          |     |                |
|        | year |          |     |          |     |                |
|        | 15   |          |     |          |     |                |
|        | as   |          |     |          |     |                |
|        | all  |          |     |          |     |                |
|        | owed |          |     |          |     |                |
|        | u    |          |     |          |     |                |
|        | nder |          |     |          |     |                |
|        | ASME |          |     |          |     |                |
|        | B3   |          |     |          |     |                |
|        | 1.8S |          |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
| Note   | Oper |          |     |          |     |                |
| 2:     | ator |          |     |          |     |                |
|        | may  |          |     |          |     |                |
|        | ch   |          |     |          |     |                |
|        | oose |          |     |          |     |                |
|        | to   |          |     |          |     |                |
|        | uti  |          |     |          |     |                |
|        | lize |          |     |          |     |                |
|        | CDA  |          |     |          |     |                |
|        | at   |          |     |          |     |                |
|        | year |          |     |          |     |                |
|        | 7    |          |     |          |     |                |
|        | and  |          |     |          |     |                |
|        | 14   |          |     |          |     |                |
|        | in   |          |     |          |     |                |
|        | lieu |          |     |          |     |                |
|        | of   |          |     |          |     |                |
|        | P&M  |          |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+
| Note   | Oper |          |     |          |     |                |
| 3:     | ator |          |     |          |     |                |
|        | may  |          |     |          |     |                |
|        | uti  |          |     |          |     |                |
|        | lize |          |     |          |     |                |
|        | "o   |          |     |          |     |                |
|        | ther |          |     |          |     |                |
|        | te   |          |     |          |     |                |
|        | chno |          |     |          |     |                |
|        | logy |          |     |          |     |                |
|        | that |          |     |          |     |                |
|        | an   |          |     |          |     |                |
|        | oper |          |     |          |     |                |
|        | ator |          |     |          |     |                |
|        | demo |          |     |          |     |                |
|        | nstr |          |     |          |     |                |
|        | ates |          |     |          |     |                |
|        | can  |          |     |          |     |                |
|        | pro  |          |     |          |     |                |
|        | vide |          |     |          |     |                |
|        | an   |          |     |          |     |                |
|        | eq   |          |     |          |     |                |
|        | uiva |          |     |          |     |                |
|        | lent |          |     |          |     |                |
|        | u    |          |     |          |     |                |
|        | nder |          |     |          |     |                |
|        | stan |          |     |          |     |                |
|        | ding |          |     |          |     |                |
|        | of   |          |     |          |     |                |
|        | the  |          |     |          |     |                |
|        | c    |          |     |          |     |                |
|        | ondi |          |     |          |     |                |
|        | tion |          |     |          |     |                |
|        | of   |          |     |          |     |                |
|        | line |          |     |          |     |                |
|        | p    |          |     |          |     |                |
|        | ipe" |          |     |          |     |                |
+--------+------+----------+-----+----------+-----+----------------+

**Table E.II.3 Preventative & Mitigative Measures addressing Time
Dependent and**

***Independent Threats for Transmission Pipelines that Operate Below 30%
SMYS , in HCAs***

+------+--------------+----------+-----------------------------------+
| Th   | Existing 192 |          | Additional (to 192 requirements)  |
| reat | Requirements |          | Preventive & Mitigative Measures  |
+------+--------------+----------+-----------------------------------+
|      | Primary      | S        |                                   |
|      |              | econdary |                                   |
+------+--------------+----------+-----------------------------------+
| Exte | 455‑(Gen.    | 603‑(Gen | For Cathodically Protected Trmn.  |
| rnal | Post 1971)   | Oper)    | Pipelines                         |
| C    |              |          |                                   |
| orro | 457‑(Gen.    | 613‑(    | \$ Perform an electrical survey   |
| sion | Pre‑1971)    | Surveil) | (*i.e*. indirect examination      |
|      |              |          | tool/method) at least every 7     |
|      | 459‑(        |          | years. Results are to be utilized |
|      | Examination) |          | as part of an overall evaluation  |
|      |              |          | of the CP system and corrosion    |
|      | 461‑(Ext.    |          | threat for the covered segment.   |
|      | coating)     |          | Evaluation shall include          |
|      |              |          | consideration of leak repair and  |
|      | 463‑(CP)     |          | inspection records, corrosion     |
|      |              |          | monitoring records, exposed pipe  |
|      | 465‑         |          | inspection records, and the       |
|      | (Monitoring) |          | pipeline environment.             |
|      |              |          |                                   |
|      | 467‑(Elect   |          | For Unprotected Trmn. Pipelines   |
|      | isolation)   |          | or for Cathodically Protected     |
|      |              |          | Pipe where Electrical Surveys are |
|      | 469‑Test     |          | Impracticable                     |
|      | stations)    |          |                                   |
|      |              |          | ● Conduct quarterly leak surveys  |
|      | 471‑(Test    |          | AND                               |
|      | leads)       |          |                                   |
|      |              |          | ● Every 1½ years, determine areas |
|      | 473‑(I       |          | of active corrosion by evaluation |
|      | nterference) |          | of leak repair and inspection     |
|      |              |          | records,                          |
|      | 479‑(        |          |                                   |
|      | Atmospheric) |          | corrosion monitoring records,     |
|      |              |          | exposed pipe inspection records,  |
|      | 481‑(        |          | and the pipeline environment.     |
|      | Atmospheric) |          |                                   |
|      |              |          |                                   |
|      | 48           |          |                                   |
|      | 5‑(Remedial) |          |                                   |
|      |              |          |                                   |
|      | 705‑(Patrol) |          |                                   |
|      |              |          |                                   |
|      | 706‑(Leak    |          |                                   |
|      | survey)      |          |                                   |
|      |              |          |                                   |
|      | 711 (Repair  |          |                                   |
|      | B gen.)      |          |                                   |
|      |              |          |                                   |
|      | 717‑(Repair  |          |                                   |
|      | B perm.)     |          |                                   |
+------+--------------+----------+-----------------------------------+
| Inte | 475‑(Gen IC) | 5        | ● Obtain and review gas analysis  |
| rnal |              | 3(a)‑(Ma | data each calendar year for       |
| C    | 477‑(IC      | terials) | corrosive agents from             |
| orro | monitoring)  |          | transmission pipelines in HCAs,   |
| sion |              | 603‑(Gen |                                   |
|      | 48           | Oper)    | ● Periodic testing of fluid       |
|      | 5‑(Remedial) |          | removed from pipelines.           |
|      |              | 613‑(    | Specifically, once each calendar  |
|      | 705‑(Patrol) | Surveil) | year from each storage field that |
|      |              |          | may affect transmission pipelines |
|      | 706‑(Leak    |          | in HCAs, AND                      |
|      | survey)      |          |                                   |
|      |              |          | ● At least every 7 years,         |
|      | 711 (Repair  |          | integrate data obtained with      |
|      | B gen.)      |          | applicable internal corrosion     |
|      |              |          | leak records, incident reports,   |
|      | 717‑(Repair  |          | safety related condition reports, |
|      | B perm.)     |          | repair records,                   |
|      |              |          |                                   |
|      |              |          | patrol records, exposed pipe      |
|      |              |          | reports, and test records.        |
+------+--------------+----------+-----------------------------------+
| 3    | 103‑(Gen.    | 615      | ● Participation in Sate one‑call  |
| ^rd^ | Design)      | B(Emerg  | system                            |
| P    |              | Plan)    |                                   |
| arty | 111‑(Design  |          | ● Use of qualified operator       |
| Da   | factor)      |          | employees and contractors to      |
| mage |              |          | perform marking and locating of   |
|      | 317‑(Hazard  |          | buried structures and in direct   |
|      | prot)        |          | supervision of excavation work,   |
|      |              |          | AND                               |
|      | 327‑(Cover)  |          |                                   |
|      |              |          | ● Either monitoring of            |
|      | 614‑(Dam.    |          | excavations near operator=s       |
|      | Prevent)     |          | transmission pipelines, or        |
|      |              |          | bi‑monthly patrol of transmission |
|      | 616‑(Public  |          | pipelines in HCAs or class 3 and  |
|      | educat)      |          | 4 locations. Any indications of   |
|      |              |          | unreported construction activity  |
|      | 705‑(Patrol) |          | would                             |
|      |              |          |                                   |
|      | 707‑(Line    |          | require a follow up investigation |
|      | markers)     |          | to determine if mechanical damage |
|      |              |          | occurred.                         |
|      | 711 (Repair  |          |                                   |
|      | B gen.)      |          |                                   |
|      |              |          |                                   |
|      | 717‑(Repair  |          |                                   |
|      | B perm.)     |          |                                   |
+------+--------------+----------+-----------------------------------+